Delmarva Power & Light 10-Q 1 May 15 2015 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Mar. 31, 2015	Apr. 20, 2015
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	FALSE
Document Period End Date	31-Mar-15
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Trading Symbol	POM
Entity Registrant Name	PEPCO HOLDINGS INC
Entity Central Index Key	1135971
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		253,072,175
Potomac Electric Power Co [Member]
Document Information [Line Items]
Entity Registrant Name	POTOMAC ELECTRIC POWER CO
Entity Central Index Key	79732
Current Fiscal Year End Date	-19
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		100
Delmarva Power & Light Co/De [Member]
Document Information [Line Items]
Entity Registrant Name	DELMARVA POWER & LIGHT CO /DE/
Entity Central Index Key	27879
Current Fiscal Year End Date	-19
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1,000
Atlantic City Electric Co [Member]
Document Information [Line Items]
Entity Registrant Name	ATLANTIC CITY ELECTRIC CO
Entity Central Index Key	8192
Current Fiscal Year End Date	-19
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		8,546,017

Consolidated_Statements_of_Inc

Consolidated Statements of Income (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Operating Revenue	$1,371	$1,330
Operating Expenses
Fuel and purchased energy	619	614
Other services cost of sales	45	46
Other operation and maintenance	267	216
Depreciation and amortization	159	133
Other taxes	109	104
Deferred electric service costs	30	44
Total Operating Expenses	1,229	1,157
Operating Income	142	173
Other Income (Expenses)
Interest expense	-68	-65
Other income	9	13
Total Other Expenses	-59	-52
Income Before Income Tax Expense	83	121
Income Tax Expense	30	46
Net Income	53	75
Basic and Diluted Share Information
Weighted average shares outstanding - Basic (millions)	253	251
Weighted average shares outstanding - Diluted (millions)	253	251
Basic and Diluted earnings per share	$0.21	$0.30
Potomac Electric Power Co [Member]
Operating Revenue
Operating Revenue	556	535
Operating Expenses
Fuel and purchased energy	221	230
Other operation and maintenance	113	93
Depreciation and amortization	65	56
Other taxes	94	90
Total Operating Expenses	493	469
Operating Income	63	66
Other Income (Expenses)
Interest expense	-30	-27
Other income	5	9
Total Other Expenses	-25	-18
Income Before Income Tax Expense	38	48
Income Tax Expense	12	16
Net Income	26	32
Delmarva Power & Light Co/De [Member]
Operating Revenue
Electric	337	300
Natural gas	86	97
Operating Revenue	423	397
Operating Expenses
Fuel and purchased energy	181	161
Gas purchased	47	58
Other operation and maintenance	82	66
Depreciation and amortization	39	30
Other taxes	12	11
Total Operating Expenses	361	326
Operating Income	62	71
Other Income (Expenses)
Interest expense	-12	-11
Other income	3	2
Total Other Expenses	-9	-9
Income Before Income Tax Expense	53	62
Income Tax Expense	21	25
Net Income	32	37
Atlantic City Electric Co [Member]
Operating Revenue
Operating Revenue	333	340
Operating Expenses
Fuel and purchased energy	169	165
Other operation and maintenance	70	61
Depreciation and amortization	43	38
Other taxes	1	1
Deferred electric service costs	30	44
Total Operating Expenses	313	309
Operating Income	20	31
Other Income (Expenses)
Interest expense	-15	-15
Other income	1
Total Other Expenses	-14	-15
Income Before Income Tax Expense	6	16
Income Tax Expense	2	6
Net Income	$4	$10

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Statement of Comprehensive Income [Abstract]
Net Income	$53	$75
Other Comprehensive Income
Losses on treasury rate locks reclassified into income	0	0
Pension and other postretirement benefit plans	2	1
Other comprehensive income, before income taxes	2	1
Income tax expense related to other comprehensive income	1
Other comprehensive income, net of income taxes	1	1
Comprehensive Income	$54	$76

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
CURRENT ASSETS
Cash and cash equivalents	$141	$14
Restricted cash equivalents	17	25
Accounts receivable, less allowance for uncollectible accounts	978	782
Inventories	148	141
Deferred income tax assets, net	47	50
Income taxes and related accrued interest receivable	13	9
Prepaid expenses and other	67	63
Total Current Assets	1,411	1,084
OTHER ASSETS
Goodwill	1,406	1,407
Regulatory assets	2,291	2,409
Income taxes and related accrued interest receivable	81	81
Restricted cash equivalents	13	14
Other	168	166
Total Other Assets	3,959	4,077
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment	15,546	15,465
Accumulated depreciation	-4,889	-4,959
Net Property, Plant and Equipment	10,657	10,506
TOTAL ASSETS	16,027	15,667
CURRENT LIABILITIES
Short-term debt	803	729
Current portion of long-term debt and project funding	412	431
Accounts payable	206	174
Accrued liabilities	302	313
Capital lease obligations due within one year	10	10
Taxes accrued	43	41
Interest accrued	75	47
Liabilities and accrued interest related to uncertain tax positions	6	6
Other	300	314
Total Current Liabilities	2,157	2,065
DEFERRED CREDITS
Regulatory liabilities	370	343
Deferred income tax liabilities, net	3,294	3,266
Investment tax credits	15	16
Pension benefit obligation	401	396
Other postretirement benefit obligations	264	265
Liabilities and accrued interest related to uncertain tax positions	2	2
Other	194	193
Total Deferred Credits	4,540	4,481
OTHER LONG-TERM LIABILITIES
Long-term debt	4,649	4,441
Transition bonds issued by ACE Funding	159	171
Long-term project funding	8	8
Capital lease obligations	50	50
Total Other Long-Term Liabilities	4,866	4,670
COMMITMENTS AND CONTINGENCIES
PREFERRED STOCK
Series A preferred stock, $.01 par value, 18,000 shares authorized, 14,400 and 12,600 shares outstanding, respectively	147	129
EQUITY
Common stock	3	3
Premium on stock and other capital contributions	3,809	3,800
Accumulated other comprehensive loss	-45	-46
Retained earnings	550	565
Total Equity	4,317	4,322
TOTAL LIABILITIES AND EQUITY	16,027	15,667
Potomac Electric Power Co [Member]
CURRENT ASSETS
Cash and cash equivalents	126	6
Restricted cash equivalents	2	5
Accounts receivable, less allowance for uncollectible accounts	406	315
Inventories	69	62
Deferred income tax assets, net	6	14
Income taxes and related accrued interest receivable	94	94
Prepaid expenses and other	21	21
Total Current Assets	724	517
OTHER ASSETS
Regulatory assets	655	697
Prepaid pension expense	309	316
Investment in trust	34	34
Income taxes and related accrued interest receivable	30	30
Other	75	71
Total Other Assets	1,103	1,148
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment	7,753	7,764
Accumulated depreciation	-2,734	-2,816
Net Property, Plant and Equipment	5,019	4,948
TOTAL ASSETS	6,846	6,613
CURRENT LIABILITIES
Short-term debt		104
Current portion of long-term debt and project funding		12
Accounts payable	101	94
Accrued liabilities	80	91
Accounts payable due to associated companies	51	30
Capital lease obligations due within one year	10	10
Taxes accrued	25	32
Interest accrued	32	19
Customer deposits	43	44
Other	91	102
Total Current Liabilities	433	538
DEFERRED CREDITS
Regulatory liabilities	114	104
Deferred income tax liabilities, net	1,564	1,584
Investment tax credits	2	2
Other postretirement benefit obligations	55	57
Other	71	67
Total Deferred Credits	1,806	1,814
OTHER LONG-TERM LIABILITIES
Long-term debt	2,332	2,124
Capital lease obligations	50	50
Total Other Long-Term Liabilities	2,382	2,174
COMMITMENTS AND CONTINGENCIES
EQUITY
Common stock
Premium on stock and other capital contributions	1,122	1,010
Retained earnings	1,103	1,077
Total Equity	2,225	2,087
TOTAL LIABILITIES AND EQUITY	6,846	6,613
Delmarva Power & Light Co/De [Member]
CURRENT ASSETS
Cash and cash equivalents	7	4
Restricted cash equivalents		5
Accounts receivable, less allowance for uncollectible accounts	266	193
Inventories	54	55
Deferred income tax assets, net	20	16
Income taxes and related accrued interest receivable	34	34
Prepaid expenses and other	9	12
Total Current Assets	390	319
OTHER ASSETS
Goodwill	8	8
Regulatory assets	344	356
Prepaid pension expense	217	220
Income taxes and related accrued interest receivable	4	4
Other	12	12
Total Other Assets	585	600
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment	3,996	3,946
Accumulated depreciation	-1,027	-1,021
Net Property, Plant and Equipment	2,969	2,925
TOTAL ASSETS	3,944	3,844
CURRENT LIABILITIES
Short-term debt	280	211
Current portion of long-term debt and project funding	100	100
Accounts payable	51	39
Accrued liabilities	70	74
Accounts payable due to associated companies	21	17
Taxes accrued	4	3
Interest accrued	14	7
Customer deposits	25	24
Other	42	42
Total Current Liabilities	607	517
DEFERRED CREDITS
Regulatory liabilities	241	225
Deferred income tax liabilities, net	920	893
Investment tax credits	4	4
Other postretirement benefit obligations	20	21
Other	33	35
Total Deferred Credits	1,218	1,178
OTHER LONG-TERM LIABILITIES
Long-term debt	971	971
COMMITMENTS AND CONTINGENCIES
EQUITY
Common stock
Premium on stock and other capital contributions	537	537
Retained earnings	611	641
Total Equity	1,148	1,178
TOTAL LIABILITIES AND EQUITY	3,944	3,844
Atlantic City Electric Co [Member]
CURRENT ASSETS
Cash and cash equivalents	6	2
Restricted cash equivalents	11	10
Accounts receivable, less allowance for uncollectible accounts	204	167
Inventories	25	23
Income taxes and related accrued interest receivable	151	151
Prepaid expenses and other	12	13
Total Current Assets	409	366
OTHER ASSETS
Regulatory assets	377	427
Prepaid pension expense	93	96
Income taxes and related accrued interest receivable	34	34
Restricted cash equivalents	13	14
Other	12	12
Total Other Assets	529	583
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment	3,126	3,073
Accumulated depreciation	-772	-760
Net Property, Plant and Equipment	2,354	2,313
TOTAL ASSETS	3,292	3,262
CURRENT LIABILITIES
Short-term debt	143	127
Current portion of long-term debt and project funding	59	59
Accounts payable	28	20
Accrued liabilities	109	103
Accounts payable due to associated companies	17	15
Taxes accrued	8	1
Interest accrued	19	13
Customer deposits	22	21
Other	22	22
Total Current Liabilities	427	381
DEFERRED CREDITS
Regulatory liabilities	14	14
Deferred income tax liabilities, net	868	865
Investment tax credits	5	5
Other postretirement benefit obligations	36	36
Other	17	16
Total Deferred Credits	940	936
OTHER LONG-TERM LIABILITIES
Long-term debt	888	888
Transition bonds issued by ACE Funding	159	171
Total Other Long-Term Liabilities	1,047	1,059
COMMITMENTS AND CONTINGENCIES
EQUITY
Common stock	26	26
Premium on stock and other capital contributions	651	651
Retained earnings	201	209
Total Equity	878	886
TOTAL LIABILITIES AND EQUITY	$3,292	$3,262

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, except Share data, unless otherwise specified
Accounts receivable, allowance for uncollectible accounts	$56	$40
Series A preferred stock, par value	$0.01	$0.01
Series A preferred stock, shares authorized	18,000	18,000
Series A preferred stock, shares outstanding	14,400	12,600
Common stock, par value	$0.01	$0.01
Common stock, shares authorized	400,000,000	400,000,000
Common stock, shares outstanding	253,043,362	252,728,684
Potomac Electric Power Co [Member]
Accounts receivable, allowance for uncollectible accounts	20	16
Common stock, par value	$0.01	$0.01
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares outstanding	100	100
Delmarva Power & Light Co/De [Member]
Accounts receivable, allowance for uncollectible accounts	18	11
Common stock, par value	$2.25	$2.25
Common stock, shares authorized	1,000	1,000
Common stock, shares outstanding	1,000	1,000
Atlantic City Electric Co [Member]
Accounts receivable, allowance for uncollectible accounts	$13	$9
Common stock, par value	$3	$3
Common stock, shares authorized	25,000,000	25,000,000
Common stock, shares outstanding	8,546,017	8,546,017

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
OPERATING ACTIVITIES
Net Income	$53	$75
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	159	133
Deferred income taxes	49	525
Gain on sale of land		-4
Other		-4
Changes in:
Accounts receivable	-195	-41
Inventories	-7	6
Prepaid expenses	-3	-8
Regulatory assets and liabilities, net	38	22
Accounts payable and accrued liabilities	9	20
Pension benefit obligation, excluding contributions	20	14
Cash collateral related to derivative activities	2	-4
Income tax-related prepayments, receivables and payables	-2	-483
Interest accrued	28	34
Other assets and liabilities	6
Net current assets held for disposition or sale		-1
Net Cash From Operating Activities	157	284
INVESTING ACTIVITIES
Investment in property, plant and equipment	-246	-282
Department of Energy capital reimbursement awards received		3
Proceeds from sale of land		4
Changes in restricted cash equivalents	9	-13
Net other investing activities	2	3
Net Cash Used By Investing Activities	-235	-285
FINANCING ACTIVITIES
Dividends paid on common stock	-68	-68
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan and employee-related compensation	8	13
Issuance of Series A preferred stock	18
Issuances of long-term debt	208	400
Reacquisitions of long-term debt	-22	-10
Changes in restricted cash equivalents		-175
Issuances (repayments) of short-term debt, net	74	-56
Cost of issuances	-4	-7
Net other financing activities	-9	3
Net Cash From (Used by) Financing Activities	205	100
Net Increase in Cash and Cash Equivalents	127	99
Cash and Cash Equivalents at Beginning of Period	14	23
CASH AND CASH EQUIVALENTS AT END OF PERIOD	141	122
SUPPLEMENTAL CASH FLOW INFORMATION
Cash received for income taxes (includes payments from PHI for federal income taxes)	-14	-1
Potomac Electric Power Co [Member]
OPERATING ACTIVITIES
Net Income	26	32
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	65	56
Deferred income taxes	12	39
Gain on sale of land		-4
Changes in:
Accounts receivable	-91	-19
Inventories	-7	1
Prepaid expenses		-2
Regulatory assets and liabilities, net	-3	-18
Accounts payable and accrued liabilities	17	-9
Pension benefit obligation, excluding contributions	7	5
Income tax-related prepayments, receivables and payables	-7	-34
Interest accrued	13	18
Other assets and liabilities	1	1
Net Cash From Operating Activities	33	66
INVESTING ACTIVITIES
Investment in property, plant and equipment	-119	-124
Department of Energy capital reimbursement awards received		3
Proceeds from sale of land		4
Changes in restricted cash equivalents	3	-5
Net other investing activities	3	4
Net Cash Used By Investing Activities	-113	-118
FINANCING ACTIVITIES
Capital contributions from Parent	112	80
Issuances of long-term debt	208	400
Reacquisitions of long-term debt	-12
Changes in restricted cash equivalents		-175
Issuances (repayments) of short-term debt, net	-104	-151
Cost of issuances	-4	-7
Net other financing activities		1
Net Cash From (Used by) Financing Activities	200	148
Net Increase in Cash and Cash Equivalents	120	96
Cash and Cash Equivalents at Beginning of Period	6	9
CASH AND CASH EQUIVALENTS AT END OF PERIOD	126	105
SUPPLEMENTAL CASH FLOW INFORMATION
Cash received for income taxes (includes payments from PHI for federal income taxes)		-2
Delmarva Power & Light Co/De [Member]
OPERATING ACTIVITIES
Net Income	32	37
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	39	30
Deferred income taxes	21	25
Changes in:
Accounts receivable	-72	-13
Inventories	1	5
Regulatory assets and liabilities, net	15	-3
Accounts payable and accrued liabilities	8	2
Income tax-related prepayments, receivables and payables	2	1
Interest accrued	8	7
Other assets and liabilities	3	1
Net Cash From Operating Activities	57	92
INVESTING ACTIVITIES
Investment in property, plant and equipment	-68	-87
Changes in restricted cash equivalents	5	-9
Net other investing activities	2
Net Cash Used By Investing Activities	-61	-96
FINANCING ACTIVITIES
Dividends paid on common stock	-62	-20
Issuances (repayments) of short-term debt, net	69	31
Net Cash From (Used by) Financing Activities	7	11
Net Increase in Cash and Cash Equivalents	3	7
Cash and Cash Equivalents at Beginning of Period	4	2
CASH AND CASH EQUIVALENTS AT END OF PERIOD	7	9
SUPPLEMENTAL CASH FLOW INFORMATION
Cash received for income taxes (includes payments from PHI for federal income taxes)
Atlantic City Electric Co [Member]
OPERATING ACTIVITIES
Net Income	4	10
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	43	38
Deferred income taxes	2	7
Changes in:
Accounts receivable	-37	-5
Regulatory assets and liabilities, net	27	42
Accounts payable and accrued liabilities	9	4
Income tax-related prepayments, receivables and payables	7	5
Other assets and liabilities	8	11
Net Cash From Operating Activities	63	112
INVESTING ACTIVITIES
Investment in property, plant and equipment	-54	-53
Net other investing activities	1
Net Cash Used By Investing Activities	-53	-53
FINANCING ACTIVITIES
Dividends paid on common stock	-12	-26
Reacquisitions of long-term debt	-10	-10
Issuances (repayments) of short-term debt, net	16	-19
Net Cash From (Used by) Financing Activities	-6	-55
Net Increase in Cash and Cash Equivalents	4	4
Cash and Cash Equivalents at Beginning of Period	2	3
CASH AND CASH EQUIVALENTS AT END OF PERIOD	6	7
SUPPLEMENTAL CASH FLOW INFORMATION
Cash received for income taxes (includes payments from PHI for federal income taxes)

Consolidated_Statements_of_Equ

Consolidated Statements of Equity (USD $)	Total	Common Stock [Member]	Premium on Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Potomac Electric Power Co [Member]	Potomac Electric Power Co [Member]	Potomac Electric Power Co [Member]	Potomac Electric Power Co [Member]	Atlantic City Electric Co [Member]	Atlantic City Electric Co [Member]	Atlantic City Electric Co [Member]	Atlantic City Electric Co [Member]	Delmarva Power & Light Co/De [Member]	Delmarva Power & Light Co/De [Member]	Delmarva Power & Light Co/De [Member]	Delmarva Power & Light Co/De [Member]
In Millions, except Share data, unless otherwise specified	USD ($)	USD ($)	USD ($)	USD ($)	USD ($)	USD ($)	Common Stock [Member]	Premium on Stock [Member]	Retained Earnings [Member]	USD ($)	Common Stock [Member]	Premium on Stock [Member]	Retained Earnings [Member]	USD ($)	Common Stock [Member]	Premium on Stock [Member]	Retained Earnings [Member]
								USD ($)	USD ($)		USD ($)	USD ($)	USD ($)			USD ($)	USD ($)
Balance at Dec. 31, 2014	$4,322	$3	$3,800	$565	($46)	$2,087		$1,010	$1,077	$886	$26	$651	$209	$1,178		$537	$641
Balance, Shares at Dec. 31, 2014	252,728,684	252,728,684				100	100			8,546,017	8,546,017			1,000	1,000
Net Income	53			53		26			26	4			4	32			32
Other comprehensive income	1				1
Capital contribution from Parent						112		112
Dividends on common stock	-68			-68						-12			-12	-62			-62
Issuance of common stock:
Original issue shares, net	4		4
Original issue shares, net, shares		153,532
DRP original issue shares	7		7
DRP original issue shares, shares		161,146
Net activity related to stock-based awards	-2		-2
Balance at Mar. 31, 2015	$4,317	$3	$3,809	$550	($45)	$2,225		$1,122	$1,103	$878	$26	$651	$201	$1,148		$537	$611
Balance, Shares at Mar. 31, 2015	253,043,362	253,043,362				100	100			8,546,017	8,546,017			1,000	1,000

Consolidated_Statements_of_Equ1

Consolidated Statements of Equity (Parenthetical) (USD $)	3 Months Ended
	Mar. 31, 2015
Statement of Stockholders' Equity [Abstract]
Dividends on common stock, per share	$0.27

Organization

Organization	3 Months Ended
	Mar. 31, 2015
Organization	(1) ORGANIZATION
	Pepco Holdings, Inc. (PHI or Pepco Holdings), a Delaware corporation incorporated in 2001, is a holding company that, through the following regulated public utility subsidiaries, is engaged primarily in the transmission, distribution and default supply of electricity and the distribution and supply of natural gas (Power Delivery):
		•	Potomac Electric Power Company (Pepco), which was incorporated in Washington, D.C. in 1896 and became a domestic Virginia corporation in 1949,
		•	Delmarva Power & Light Company (DPL), which was incorporated in Delaware in 1909 and became a domestic Virginia corporation in 1979, and
		•	Atlantic City Electric Company (ACE), which was incorporated in New Jersey in 1924.
	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, underground transmission and distribution construction and maintenance services, and steam and chilled water under long-term contracts.
	PHI Service Company, a wholly owned 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 service agreements 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 agreements.
	Agreement and Plan of Merger with Exelon Corporation
	PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect, wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest.
	In connection with entering into the Merger Agreement, as further described in Note (12), “Preferred Stock,” PHI entered into a Subscription Agreement with Exelon dated April 29, 2014 (the Subscription Agreement), pursuant to which PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million on April 30, 2014. Exelon also committed, pursuant to the Subscription Agreement, to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015 and April 27, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for a purchase price of $18 million.
	Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission (DCPSC), the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement). For additional discussion, see Note (7), “Regulatory Matters – Merger Approval Proceedings.”
	On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. On December 22, 2014, the applicable waiting period under the HSR Act expired, and the HSR Act no longer precludes completion of the Merger. Although the Department of Justice (DOJ) allowed the waiting period under the HSR Act to expire without taking any action with respect to the Merger, the DOJ has not advised PHI that it has concluded its investigation. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015. On February 13, 2015, Pepco Holdings, DPL, Exelon, certain of Exelon’s affiliates, the Staff of the DPSC and certain other parties, filed a settlement agreement with the DPSC with respect to the Merger. This settlement agreement is subject to approval by the DPSC.
	On March 10, 2015, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates (Joint Applicants), filed with the MPSC a settlement agreement entered into with The Alliance for Solar Choice, which is one of the stakeholder groups participating in the MPSC approval proceeding. On March 16, 2015, the Joint Applicants filed with the MPSC a settlement agreement entered into with Montgomery and Prince George’s Counties in Maryland, and a number of other parties, including the National Housing Trust, the National Consumer Law Center, other organizations representing low and moderate income interests and a consortium of nine recreational trail advocacy organizations. The MPSC staff, the State of Maryland and the Maryland Energy Administration, and the Office of People’s Counsel have each filed briefs in opposition to the settlement agreements. The settlement agreements, along with the Merger and other issues in the proceeding, are subject to MPSC approval.
	The Merger Agreement may be terminated by each of PHI and Exelon under certain circumstances, including if the Merger is not consummated by July 29, 2015 (subject to extension by PHI or Exelon to October 29, 2015, if all of the conditions to closing, other than the conditions related to obtaining regulatory approvals, have been satisfied). The Merger Agreement also provides for certain termination rights for both PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain such regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), PHI will be able to redeem any issued and outstanding Preferred Stock at par value, and in that case, Exelon will be required to pay all documented out-of-pocket expenses incurred by PHI in connection with the Merger Agreement or the transactions contemplated thereby, up to $40 million. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.
	Power Delivery
	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, the distribution and supply of 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 (SOS) in Delaware, the District of Columbia and Maryland, and Basic Generation Service (BGS) in New Jersey. These supply service obligations are referred to generally as Default Electricity Supply.
	Pepco Energy Services
	Pepco Energy Services is engaged in the following businesses:
		•	Energy savings performance contracting business: designing, constructing and operating energy efficiency projects and distributed generation equipment, including combined heat and power plants, principally for federal, state and local government customers;
		•	Underground transmission and distribution business: providing underground transmission and distribution construction and maintenance services for electric utilities in North America; and
		•	Thermal business: providing steam and chilled water under long-term contracts through systems owned and operated by Pepco Energy Services, primarily to hotels and casinos in Atlantic City, New Jersey.
	During 2012, Pepco Energy Services deactivated its Buzzard Point and Benning Road oil-fired generation facilities. Pepco Energy Services is demolishing the Benning Road generation facility and realizing the scrap metal salvage value of the facility. The demolition of the facility commenced in the fourth quarter of 2013 and is expected to be completed in the second quarter of 2015. Pepco Energy Services is recognizing the salvage proceeds associated with the scrap metals at the facility as realized.
	Corporate and Other
	Corporate and other includes the remaining operations of the former Other Non-Regulated segment, certain parent company transactions (including interest expense on parent company debt and incremental external Merger-related costs) and inter-company eliminations.
Potomac Electric Power Co [Member]
Organization	(1) ORGANIZATION
	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 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).
	PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest.
	In connection with entering into the Merger Agreement, PHI entered into a Subscription Agreement, dated April 29, 2014 (the Subscription Agreement), with Exelon, pursuant to which on April 30, 2014, PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million. Exelon also committed pursuant to the Subscription Agreement to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015 and April 27, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for a purchase price of $18 million. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement.
	Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission (DCPSC), the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement). For additional discussion, see Note (6), “Regulatory Matters – Merger Approval Proceedings.”
	On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. On December 22, 2014, the applicable waiting period under the HSR Act expired, and the HSR Act no longer precludes completion of the Merger. Although the Department of Justice (DOJ) allowed the waiting period under the HSR Act to expire without taking any action with respect to the Merger, the DOJ has not advised PHI that it has concluded its investigation. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015. On February 13, 2015, Pepco Holdings, Delmarva Power & Light Company (DPL), Exelon, certain of Exelon’s affiliates, the Staff of the DPSC and certain other parties, filed a settlement agreement with the DPSC with respect to the Merger. This settlement agreement is subject to approval by the DPSC.
	On March 10, 2015, Exelon, PHI, Pepco and Delmarva Power & Light Company (DPL), and certain of their respective affiliates (Joint Applicants), filed with the MPSC a settlement agreement entered into with The Alliance for Solar Choice, which is one of the stakeholder groups participating in the MPSC approval proceeding. On March 16, 2015, the Joint Applicants filed with the MPSC a settlement agreement entered into with Montgomery and Prince George’s Counties in Maryland, and a number of other parties, including the National Housing Trust, the National Consumer Law Center, other organizations representing low and moderate income interests and a consortium of nine recreational trail advocacy organizations. The MPSC staff, the State of Maryland and the Maryland Energy Administration, and the Office of People’s Counsel have each filed briefs in opposition to the settlement agreements. The settlement agreements, along with the Merger and other issues in the proceeding, are subject to MPSC approval.
	The Merger Agreement may be terminated by each of PHI and Exelon under certain circumstances, including if the Merger is not consummated by July 29, 2015 (subject to extension by PHI or Exelon to October 29, 2015, if all of the conditions to closing, other than the conditions related to obtaining regulatory approvals, have been satisfied). The Merger Agreement also provides for certain termination rights for both PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain regulatory approvals with the respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), PHI will be able to redeem any issued and outstanding Preferred Stock at par value, and in that case, Exelon will be required to pay all documented out-of-pocket expenses incurred by PHI in connection with the Merger Agreement or the transactions contemplated thereby, up to $40 million. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.
Delmarva Power & Light Co/De [Member]
Organization	(1) ORGANIZATION
	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 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 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).
	PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest.
	In connection with entering into the Merger Agreement, PHI entered into a Subscription Agreement, dated April 29, 2014 (the Subscription Agreement), with Exelon, pursuant to which on April 30, 2014, PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million. Exelon also committed pursuant to the Subscription Agreement to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015 and April 27, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for a purchase price of $18 million. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement.
	Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission, the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement). For additional discussion, see Note (7), “Regulatory Matters – Merger Approval Proceedings.”
	On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. On December 22, 2014, the applicable waiting period under the HSR Act expired, and the HSR Act no longer precludes completion of the Merger. Although the Department of Justice (DOJ) allowed the waiting period under the HSR Act to expire without taking any action with respect to the Merger, the DOJ has not advised PHI that it has concluded its investigation. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015. On February 13, 2015, Pepco Holdings, DPL, Exelon, certain of Exelon’s affiliates, the Staff of the DPSC and certain other parties, filed a settlement agreement with the DPSC with respect to the Merger. This settlement agreement is subject to approval by the DPSC.
	On March 10, 2015, Exelon, PHI, Potomac Electric Power Company (Pepco) and DPL, and certain of their respective affiliates (Joint Applicants), filed with the MPSC a settlement agreement entered into with The Alliance for Solar Choice, which is one of the stakeholder groups participating in the MPSC approval proceeding. On March 16, 2015, the Joint Applicants filed with the MPSC a settlement agreement entered into with Montgomery and Prince George’s Counties in Maryland, and a number of other parties, including the National Housing Trust, the National Consumer Law Center, other organizations representing low and moderate income interests and a consortium of nine recreational trail advocacy organizations. The MPSC staff, the State of Maryland and the Maryland Energy Administration, and the Office of People’s Counsel have each filed briefs in opposition to the settlement agreements. The settlement agreements, along with the Merger and other issues in the proceeding, are subject to MPSC approval.
	The Merger Agreement may be terminated by each of PHI and Exelon under certain circumstances, including if the Merger is not consummated by July 29, 2015 (subject to extension by PHI or Exelon to October 29, 2015, if all of the conditions to closing, other than the conditions related to obtaining regulatory approvals, have been satisfied). The Merger Agreement also provides for certain termination rights for both PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), PHI will be able to redeem any issued and outstanding Preferred Stock at par value, and in that case, Exelon will be required to pay all documented out-of-pocket expenses incurred by PHI in connection with the Merger Agreement or the transactions contemplated thereby, up to $40 million. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.
Atlantic City Electric Co [Member]
Organization	(1) ORGANIZATION
	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).
	PHI entered into an Agreement and Plan of Merger, dated April 29, 2014, as amended and restated on July 18, 2014 (the Merger Agreement), with Exelon Corporation, a Pennsylvania corporation (Exelon), and Purple Acquisition Corp., a Delaware corporation and an indirect, wholly owned subsidiary of Exelon (Merger Sub), providing for the merger of Merger Sub with and into PHI (the Merger), with PHI surviving the Merger as an indirect, wholly owned subsidiary of Exelon. Pursuant to the Merger Agreement, at the effective time of the Merger, each outstanding share of common stock, par value $0.01 per share, of PHI (other than (i) shares owned by Exelon, Merger Sub or any other direct or indirect wholly owned subsidiary of Exelon and shares owned by PHI or any direct or indirect wholly owned subsidiary of PHI, and in each case not held on behalf of third parties (but not including shares held by PHI in any rabbi trust or similar arrangement in respect of any compensation plan or arrangement) and (ii) shares that are owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to Delaware law), will be canceled and converted into the right to receive $27.25 in cash, without interest.
	In connection with entering into the Merger Agreement, PHI entered into a Subscription Agreement, dated April 29, 2014 (the Subscription Agreement), with Exelon, pursuant to which on April 30, 2014, PHI issued to Exelon 9,000 originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share (the Preferred Stock), for a purchase price of $90 million. Exelon also committed pursuant to the Subscription Agreement to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following the date of the Subscription Agreement until the Merger closes or is terminated, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015 and April 27, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for a purchase price of $18 million. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement.
	Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (i) the approval of the Merger by the holders of a majority of the outstanding shares of common stock of PHI; (ii) the receipt of regulatory approvals required to consummate the Merger, including approvals from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Delaware Public Service Commission (DPSC), the District of Columbia Public Service Commission, the Maryland Public Service Commission (MPSC), the New Jersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission (VSCC); (iii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act); and (iv) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement (including covenants that may limit, restrict or prohibit PHI and its subsidiaries from taking specified actions during the period between the date of the Merger Agreement and the closing of the Merger or the termination of the Merger Agreement). In addition, the obligations of Exelon and Merger Sub to consummate the Merger are subject to the required regulatory approvals not imposing terms, conditions, obligations or commitments, individually or in the aggregate, that constitute a burdensome condition (as defined in the Merger Agreement). For additional discussion, see Note (6), “Regulatory Matters – Merger Approval Proceedings.”
	On September 23, 2014, the stockholders of PHI approved the Merger, on October 7, 2014, the VSCC approved the Merger, and on November 20, 2014, FERC approved the Merger. On December 22, 2014, the applicable waiting period under the HSR Act expired, and the HSR Act no longer precludes completion of the Merger. Although the Department of Justice (DOJ) allowed the waiting period under the HSR Act to expire without taking any action with respect to the Merger, the DOJ has not advised PHI that it has concluded its investigation. In addition, the transfer of control of certain communications licenses held by certain of PHI’s subsidiaries has been approved by the FCC. The NJBPU approved the Merger on February 11, 2015. On February 13, 2015, Pepco Holdings, Delmarva Power & Light Company (DPL), Exelon, certain of Exelon’s affiliates, the Staff of the DPSC and certain other parties, filed a settlement agreement with the DPSC with respect to the Merger. This settlement agreement is subject to approval by the DPSC.
	On March 10, 2015, Exelon, PHI, Potomac Electric Power Company (Pepco) and Delmarva Power & Light Company (DPL), and certain of their respective affiliates (Joint Applicants), filed with the MPSC a settlement agreement entered into with The Alliance for Solar Choice, which is one of the stakeholder groups participating in the MPSC approval proceeding. On March 16, 2015, the Joint Applicants filed with the MPSC a settlement agreement entered into with Montgomery and Prince George’s Counties in Maryland, and a number of other parties, including the National Housing Trust, the National Consumer Law Center, other organizations representing low and moderate income interests and a consortium of nine recreational trail advocacy organizations. The MPSC staff, the State of Maryland and the Maryland Energy Administration, and the Office of People’s Counsel have each filed briefs in opposition to the settlement agreements. The settlement agreements, along with the Merger and other issues in the proceeding, are subject to MPSC approval.
	The Merger Agreement may be terminated by each of PHI and Exelon under certain circumstances, including if the Merger is not consummated by July 29, 2015 (subject to extension by PHI or Exelon to October 29, 2015, if all of the conditions to closing, other than the conditions related to obtaining regulatory approvals, have been satisfied). The Merger Agreement also provides for certain termination rights for both PHI and Exelon, and further provides that, upon termination of the Merger Agreement under certain specified circumstances, PHI will be required to pay Exelon a termination fee of $259 million or reimburse Exelon for its expenses up to $40 million (which reimbursement of expenses shall reduce on a dollar for dollar basis any termination fee subsequently payable by PHI), provided, however, that if the Merger Agreement is terminated in connection with an acquisition proposal made under certain circumstances by a person who made an acquisition proposal between April 1, 2014 and the date of the Merger Agreement, the termination fee will be $293 million plus reimbursement of Exelon for its expenses up to $40 million (not subject to offset). In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain regulatory approvals with respect to the Merger or the breach by Exelon of its obligations in respect of obtaining such regulatory approvals (a Regulatory Termination), PHI will be able to redeem any issued and outstanding Preferred Stock at par value, and in that case, Exelon will be required to pay all documented out-of-pocket expenses incurred by PHI in connection with the Merger Agreement or the transactions contemplated thereby, up to $40 million. If the Merger Agreement is terminated, other than for a Regulatory Termination, PHI will be required to redeem the Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.

Significant_Accounting_Policie

Significant Accounting Policies	3 Months Ended
	Mar. 31, 2015
Significant Accounting Policies	(2) SIGNIFICANT ACCOUNTING POLICIES
	Financial Statement Presentation
	Pepco Holdings’ unaudited consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted. Therefore, these consolidated financial statements should be read along with the annual consolidated financial statements included in PHI’s annual report on Form 10-K for the year ended December 31, 2014. In the opinion of PHI’s management, the unaudited 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, 2015, in accordance with GAAP. The year-end December 31, 2014 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 months ended March 31, 2015 may not be indicative of PHI’s results that will be realized for the full year ending December 31, 2015.
	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although Pepco Holdings believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.
	Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset and goodwill impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefit assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, 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 loss contingency liabilities for general litigation and auto and other liability claims, accrual of interest related to income taxes, 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.
	Consolidation of Variable Interest Entities
	PHI assesses its contractual arrangements with variable interest entities to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (16), “Variable Interest Entities,” for additional information.
	Goodwill
	Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. PHI 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 (that is, a greater than 50% chance) reduce the estimated 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 significantly below book value, an adverse regulatory action, or an impairment of long-lived assets in the reporting unit. PHI performed its most recent annual impairment test as of November 1, 2014, and its goodwill was not impaired as described in Note (6), “Goodwill.”
	Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
	Taxes included in Pepco Holdings’ gross revenues were $83 million for each of the three months ended March 31, 2015 and 2014.
Potomac Electric Power Co [Member]
Significant Accounting Policies	(2) SIGNIFICANT ACCOUNTING POLICIES
	Financial Statement Presentation
	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, 2014. In the opinion of Pepco’s management, the unaudited 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, 2015, in accordance with GAAP. The year-end December 31, 2014 balance sheet included herein was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2015 may not be indicative of results that will be realized for the full year ending December 31, 2015.
	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the 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 adequacy of the allowance for uncollectible accounts, 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 loss contingency liabilities for general litigation and auto and other 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.
	Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
	Taxes included in Pepco’s gross revenues were $78 million for each of the three months ended March 31, 2015 and 2014.
Delmarva Power & Light Co/De [Member]
Significant Accounting Policies	(2) SIGNIFICANT ACCOUNTING POLICIES
	Financial Statement Presentation
	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, 2014. In the opinion of DPL’s management, the unaudited 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, 2015, in accordance with GAAP. The year-end December 31, 2014 balance sheet included herein was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2015 may not be indicative of DPL’s results that will be realized for the full year ending December 31, 2015.
	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the 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 adequacy of the allowance for uncollectible accounts, 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 loss contingency liabilities for general litigation and auto and other 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.
	Consolidation of Variable Interest Entities
	DPL assesses its contractual arrangements with variable interest entities (VIEs) 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. See Note (15), “Variable Interest Entities,” for additional information.
	Goodwill
	Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. 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 (that is, a greater than 50% chance) reduce the estimated fair value of DPL 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 unit, an adverse change in business conditions, an adverse regulatory action, or an impairment of DPL’s long-lived assets. DPL performed its most recent annual impairment test as of November 1, 2014, and its goodwill was not impaired as described in Note (6), “Goodwill.”
	Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
	Taxes included in DPL’s gross revenues were $5 million and $4 million for the three months ended March 31, 2015 and 2014, respectively.
Atlantic City Electric Co [Member]
Significant Accounting Policies	(2) SIGNIFICANT ACCOUNTING POLICIES
	Financial Statement Presentation
	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, 2014. In the opinion of ACE’s management, the unaudited 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, 2015, in accordance with GAAP. The year-end December 31, 2014 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 months ended March 31, 2015 may not be indicative of ACE’s results that will be realized for the full year ending December 31, 2015.
	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although 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 adequacy of the allowance for uncollectible accounts, 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 loss contingency liabilities for general litigation and auto and other 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.
	Consolidation of Variable Interest Entities
	ACE assesses its contractual arrangements with variable interest entities (VIEs) 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. See Note (13), “Variable Interest Entities,” for additional information.
	Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
	Taxes included in ACE’s gross revenues were zero and $1 million for the three months ended March 31, 2015 and 2014, respectively.

Newly_Adopted_Accounting_Stand

Newly Adopted Accounting Standards	3 Months Ended
	Mar. 31, 2015
Newly Adopted Accounting Standards	(3) NEWLY ADOPTED ACCOUNTING STANDARDS
	Discontinued Operations (ASC 205)
	In April 2014, the FASB issued new guidance on the reporting of discontinued operations that is effective for dispositions that occur after January 1, 2015. In order for dispositions to be presented as discontinued operations, the dispositions must represent a strategic shift that will have a major effect on an entity’s operations and financial results. This guidance did not have an effect on PHI’s consolidated financial statements in the first quarter of 2015.
	Business Combinations (ASC 805)
	In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.
	The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.
	The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014. PHI currently anticipates it may be affected by the new guidance if its Merger with Exelon closes.
Potomac Electric Power Co [Member]
Newly Adopted Accounting Standards	(3) NEWLY ADOPTED ACCOUNTING STANDARDS
	Business Combinations (ASC 805)
	In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.
	The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.
	The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014.
Delmarva Power & Light Co/De [Member]
Newly Adopted Accounting Standards	(3) NEWLY ADOPTED ACCOUNTING STANDARDS
	Business Combinations (ASC 805)
	In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.
	The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.
	The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014.
Atlantic City Electric Co [Member]
Newly Adopted Accounting Standards	(3) NEWLY ADOPTED ACCOUNTING STANDARDS
	Business Combinations (ASC 805)
	In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.
	The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.
	The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014.

Recently_Issued_Accounting_Sta

Recently Issued Accounting Standards, Not Yet Adopted	3 Months Ended
	Mar. 31, 2015
Recently Issued Accounting Standards, Not Yet Adopted	(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
	Revenue from Contracts with Customers (ASC 606)
	In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.
	The new requirements are expected to be effective for PHI beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is expected to be permitted, but not before January 1, 2017. PHI is currently evaluating the potential impact of this new guidance on its consolidated financial statements and which implementation approach to select.
	Presentation of Debt Issuance Costs (ASC 835)
	In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements will be effective for PHI beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented. Early adoption is permitted. PHI is currently evaluating the potential impact of this new guidance on its consolidated financial statements, but the impact is not expected to be material.
Potomac Electric Power Co [Member]
Recently Issued Accounting Standards, Not Yet Adopted	(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
	Revenue from Contracts with Customers (Accounting Standards Codification (ASC) 606)
	In May 2014, the Financial Accounting Standards Board (FASB) issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.
	The new requirements are expected to be effective for Pepco beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is expected to be permitted, but not before January 1, 2017. Pepco is currently evaluating the potential impact of this new guidance on its financial statements and which implementation approach to select.
	Presentation of Debt Issuance Costs (ASC 835)
	In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements will be effective for Pepco beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented. Early adoption is permitted. Pepco is currently evaluating the potential impact of this new guidance on its consolidated financial statements, but the impact is not expected to be material.
Delmarva Power & Light Co/De [Member]
Recently Issued Accounting Standards, Not Yet Adopted	(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
	Revenue from Contracts with Customers (ASC 606)
	In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.
	The new requirements are expected to be effective for DPL beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is expected to be permitted, but not before January 1, 2017. DPL is currently evaluating the potential impact of this new guidance on its financial statements and which implementation approach to select.
	Presentation of Debt Issuance Costs (ASC 835)
	In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements will be effective for DPL beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented. Early adoption is permitted. DPL is currently evaluating the potential impact of this new guidance on its consolidated financial statements, but the impact is not expected to be material.
Atlantic City Electric Co [Member]
Recently Issued Accounting Standards, Not Yet Adopted	(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
	Revenue from Contracts with Customers (ASC 606)
	In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.
	The new requirements are expected to be effective for ACE beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is expected to be permitted, but not before January 1, 2017. ACE is currently evaluating the potential impact of this new guidance on its consolidated financial statements and which implementation approach to select.
	Presentation of Debt Issuance Costs (ASC 835)
	In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements will be effective for ACE beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented. Early adoption is permitted. ACE is currently evaluating the potential impact of this new guidance on its consolidated financial statements, but the impact is not expected to be material.

Segment_Information

Segment Information	3 Months Ended
	Mar. 31, 2015
Segment Information	(5) SEGMENT INFORMATION
	Pepco Holdings’ management has identified its operating segments at March 31, 2015 as Power Delivery and Pepco Energy Services. In the tables below, the Corporate and Other column is included to reconcile the segment data with consolidated data and includes the remaining operations of the former Other Non-Regulated segment, unallocated Pepco Holdings’ (parent company) capital costs, such as financing costs, and inter-company eliminations.
	Segment financial information for the three months ended March 31, 2015 and 2014 is as follows:
			Three Months Ended March 31, 2015
			Power		Pepco			Corporate			PHI
			Delivery		Energy			and			Consolidated
					Services			Other (a)
			(millions of dollars)
	Operating Revenue		$	1,313	$	60		$	(2	)	$	1,371
	Operating Expenses (b)			1,167		61			1			1,229
	Operating Income (Loss)			146		(1	)		(3	)		142
	Interest Expense			58		—			10			68
	Other Income			9		—			—			9
	Income Tax Expense (Benefit)			35		(5	)		—			30
	Net Income (Loss)			62		4			(13	)		53
	Total Assets			14,082		237			1,708			16,027
	Construction Expenditures		$	241	$	—		$	5		$	246
	(a)	Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(2) million for Operating Revenue, $(2) million for Operating Expenses and $(1) million for Interest Expense.
	(b)	Includes depreciation and amortization expense of $159 million, consisting of $147 million for Power Delivery, $1 million for Pepco Energy Services and $11 million for Corporate and Other.
			Three Months Ended March 31, 2014
			Power		Pepco			Corporate			PHI
			Delivery		Energy			and			Consolidated
					Services			Other (a)
			(millions of dollars)
	Operating Revenue		$	1,272	$	60		$	(2	)	$	1,330
	Operating Expenses (b)			1,103		60			(6	)		1,157
	Operating Income			169		—			4			173
	Interest Expense			55		—			10			65
	Other Income			12		—			1			13
	Income Tax Expense (Benefit)			47		—			(1	)		46
	Net Income (Loss)			79		—			(4	)		75
	Total Assets			13,438		287			1,279			15,004
	Construction Expenditures		$	264	$	—		$	18		$	282
	(a)	Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(2) million for Operating Revenue, $(1) million for Operating Expenses and $(1) million for Interest Expense.
	(b)	Includes depreciation and amortization expense of $133 million, consisting of $124 million for Power Delivery, $2 million for Pepco Energy Services and $7 million for Corporate and Other.
Potomac Electric Power Co [Member]
Segment Information	(5) SEGMENT INFORMATION
	Pepco operates its business as one regulated utility segment, which includes all of its services as described above.
Delmarva Power & Light Co/De [Member]
Segment Information	(5) SEGMENT INFORMATION
	DPL operates its business as one regulated utility segment, which includes all of its services as described above.
Atlantic City Electric Co [Member]
Segment Information	(5) SEGMENT INFORMATION
	ACE operates its business as one regulated utility segment, which includes all of its services as described above.

Goodwill

Goodwill	3 Months Ended
	Mar. 31, 2015
Goodwill	(6) GOODWILL
	PHI’s goodwill balance was $1,406 million and $1,407 million as of March 31, 2015 and 2014, respectively. Substantially all of PHI’s goodwill balance was generated by Pepco’s acquisition of Conectiv (now known as Conectiv, LLC, and the parent of DPL and ACE, and referred to herein as 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, 2014 indicated that goodwill was not impaired. For the three months ended March 31, 2015, PHI concluded that there were no events or circumstances requiring it to perform an interim goodwill impairment test. PHI will perform its next annual impairment test as of November 1, 2015.
Delmarva Power & Light Co/De [Member]
Goodwill	(6) GOODWILL
	DPL’s goodwill balance of $8 million was unchanged as of March 31, 2015. 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, 2014 indicated that goodwill was not impaired. For the three months ended March 31, 2015, DPL concluded that there were no events or circumstances requiring it to perform an interim goodwill impairment test. DPL will perform its next annual impairment test as of November 1, 2015.

Regulatory_Matters

Regulatory Matters	3 Months Ended
	Mar. 31, 2015
Regulatory Matters	(7) REGULATORY MATTERS
	Rate Proceedings
	As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of certain proceedings, as described below.
	Bill Stabilization Adjustment
	Each of PHI’s utility subsidiaries proposed in each of its respective jurisdictions the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. A decoupling mechanism, the bill stabilization adjustment (BSA), was approved and implemented for Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia. None of the other jurisdictions have to date adopted decoupling proposals.
	Delaware
	Electric Distribution Base Rates
	In March 2013, DPL submitted an application with the DPSC to increase its electric distribution base rates. The application sought approval of an annual rate increase of approximately $42 million (adjusted by DPL to approximately $39 million on September 20, 2013), based on a requested return on equity (ROE) of 10.25%. The requested rate increase sought to recover expenses associated with DPL’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. In August 2014, the DPSC issued a final order in this proceeding providing for an annual increase in DPL’s electric distribution base rates of approximately $15.1 million, based on an ROE of 9.70%. The new rates became effective on May 1, 2014.
	In September 2014, DPL filed an appeal with the Delaware Superior Court of the DPSC’s August 2014 order in this proceeding, seeking the court’s review of the DPSC’s decision relating to the recovery of costs associated with one component of employee compensation, certain retirement benefits and recovery of credit facility expenses. The Division of the Public Advocate filed a cross-appeal in September 2014, pertaining to the treatment of a prepaid pension expense and other postretirement benefit obligations in base rates. Under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” the parties have agreed to suspend the appeal and, if the Merger is completed, to withdraw the appeal with prejudice.
	Under the Merger Agreement, DPL is not permitted to initiate or file any new electric distribution base rate cases in Delaware without Exelon’s consent.
	Forward Looking Rate Plan
	In October 2013, DPL filed a multi-year rate plan, referred to as the Forward Looking Rate Plan (FLRP). As proposed, the FLRP would provide for annual electric distribution base rate increases over a four-year period in the aggregate amount of approximately $56 million. The FLRP as proposed provides the opportunity to achieve estimated earned ROEs of 7.41% and 8.80% in years one and two, respectively, and 9.75% in both years three and four of the plan.
	In addition, DPL proposed that as part of the FLRP, in order to provide a higher minimum required standard of reliability for DPL’s customers than that to which DPL is currently subject, the standards by which DPL’s reliability is measured would be made more stringent in each year of the FLRP. DPL has also offered to refund an aggregate of $500,000 to customers in each year of the FLRP that it fails to meet the proposed stricter minimum reliability standards.
	In October 2013, the DPSC opened a docket for the purpose of reviewing the details of the FLRP, but stated that it would not address the FLRP until the electric distribution base rate case discussed above was concluded. A schedule for the FLRP docket has not yet been established.
	Under the Merger Agreement, DPL is permitted to pursue this matter; however, under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” DPL has agreed, if the Merger is completed, to withdraw the FLRP without prejudice and may make future filings with the DPSC proposing alternative regulatory methodologies that could include, but are not limited to, a multi-year rate plan.
	Gas Cost Rates
	DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2014, DPL made its 2014 GCR filing in which it proposed a GCR decrease of approximately 7.4%. In September 2014, the DPSC issued an order authorizing DPL to place the new rates into effect on November 1, 2014, subject to refund and pending final DPSC approval.
	Under the Merger Agreement, DPL is permitted and intends to continue to file its required annual GCR cases in Delaware.
	Maryland
	Pepco Electric Distribution Base Rates
	Under the Merger Agreement, Pepco is permitted, and intends to continue, to pursue the conclusion of the following matters. However, Pepco is not permitted to initiate or file any new electric distribution base rate cases in Maryland without Exelon’s consent.
	2011 Base Rate Proceeding
	In December 2011, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $68.4 million (subsequently adjusted by Pepco to approximately $66.2 million), based on a requested ROE of 10.75%. In July 2012, the MPSC issued an order approving an annual rate increase of approximately $18.1 million, based on an ROE of 9.31%. Among other things, the order also authorized Pepco to recover the actual cost of advanced metering infrastructure (AMI) meters installed during the 2011 test year, stating that cost recovery for AMI deployment will be allowed in future rate cases in which Pepco demonstrates that the system is cost effective. The new rates became effective on July 20, 2012. The Maryland Office of People’s Counsel has sought rehearing on the portion of the order allowing Pepco to recover the costs of AMI meters installed during the test year; that motion remains pending.
	2012 Base Rate Proceeding – Phase I
	In November 2012, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $60.8 million, based on a requested ROE of 10.25%. In July 2013, the MPSC issued an order in this proceeding approving an annual rate increase of approximately $27.9 million, based on an ROE of 9.36%. The order excludes the cost of AMI meters from Pepco’s rate base until such time as Pepco demonstrates the cost effectiveness of the AMI system; as a result, costs for AMI meters incurred with respect to the 2012 test year and beyond will be treated as other incremental AMI costs incurred in conjunction with the deployment of the AMI system that are deferred and on which a carrying charge is deferred, but only until such cost effectiveness has been demonstrated and such costs are included in rates. However, MPSC’s July 2012 order issued in connection with Pepco’s 2011 base rate proceeding, which allowed Pepco to recover the costs of meters installed during the 2011 test year for that case, remains in effect.
	The July 2013 order also approved a Grid Resiliency Charge, which went into effect on January 1, 2014, for recovery of costs totaling approximately $24.0 million associated with Pepco’s proposed plan to accelerate investments related to certain priority feeders, provided that, before implementing the surcharge, Pepco (i) provides additional information to the MPSC related to performance objectives, milestones and costs, and (ii) makes annual filings with the MPSC thereafter concerning this project, which will permit the MPSC to establish the applicable Grid Resiliency Charge rider for each following year. The MPSC rejected certain other cost recovery mechanisms, including Pepco’s proposed reliability performance-based mechanism. The new rates were effective on July 12, 2013.
	In July 2013, Pepco filed a notice of appeal of the July 2013 order in the Circuit Court for Baltimore City. Other parties also filed notices of appeal, which were consolidated with Pepco’s appeal. In its appeal, Pepco asserted that the MPSC erred in failing to grant Pepco an adequate ROE, denying a number of other cost recovery mechanisms and limiting Pepco’s test year data to no more than four months of forecasted data in future rate cases. The other parties primarily asserted that the MPSC erred or acted arbitrarily and capriciously in allowing the recovery of certain costs by Pepco, in approving the Grid Resiliency Charge, and in refusing to reduce Pepco’s rate base by known and measurable accumulated depreciation. In November 2014, the Circuit Court issued an order reversing the MPSC’s decision on Pepco’s ROE and directing the MPSC to make more specific findings regarding the impact of improved service reliability and the BSA in calculating Pepco’s ROE. On all other issues appealed, the Circuit Court affirmed the MPSC’s July 2013 order. Other parties to this proceeding have filed notices of appeal of the Circuit Court’s decision to the Court of Special Appeals. Pepco has elected not to appeal this decision.
	2013 Base Rate Proceeding – Phase I
	In December 2013, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $43.3 million (adjusted by Pepco to approximately $37.4 million on April 15, 2014), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with Pepco’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. In July 2014, the MPSC issued an order approving an annual rate increase of approximately $8.75 million, based on an ROE of 9.62%. The new rates became effective on July 4, 2014. In July 2014, Pepco filed a petition for rehearing seeking reconsideration of the recovery of certain expenses, which the MPSC denied by its order issued in November 2014. In December 2014, Pepco filed a petition for judicial review of this MPSC order with the Circuit Court for Baltimore City. A hearing date of May 26, 2015 in this matter has been set.
	2012 and 2013 Base Rate Proceedings – Phase II
	In August 2014, the MPSC issued an order establishing a Phase II proceeding in the 2012 base rate case described above (the 2012 Phase II proceeding) to address the tax implications of Pepco’s net operating loss carryforward (NOLC), which had impacted certain of Pepco’s rate adjustments in the 2012 base rate proceeding. Pepco filed a motion to dismiss the 2012 Phase II proceeding, asserting that the MPSC no longer has jurisdiction over the 2012 base rate case due to appeals having been filed by numerous parties. In September 2014, the MPSC issued an order staying the 2012 Phase II proceeding until further notice. In a similar Phase II proceeding in the 2013 base rate case described above, the MPSC issued an order in November 2014 upholding Pepco’s treatment of the NOLC. Although Pepco believes the November 2014 MPSC order should be dispositive of the issues raised in the 2012 Phase II proceeding, the 2012 Phase II proceeding remains open until the appeal of the 2012 base rate proceeding is resolved, after which the MPSC will have authority to act on Phase II.
	New Jersey
	Update and Reconciliation of Certain Under-Recovered Balances
	In March 2014, ACE submitted its 2014 annual petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the non-utility generators (NUGs), (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and ACE’s uncollected accounts and (iii) operating costs associated with ACE’s residential appliance cycling program. The net impact of adjusting the charges as proposed would have been an overall annual rate decrease of approximately $24.5 million (revised to a rate decrease of approximately $41.1 million on April 16, 2014, based upon an update for actual data through March 2014). In May 2014, the NJBPU approved a stipulation of settlement entered into by the parties in this proceeding providing for an overall annual rate decrease of $41.1 million. The rate decrease was placed into effect provisionally on June 1, 2014, subject to a review by the NJBPU of the final underlying costs for reasonableness and prudence. On January 21, 2015, the NJBPU approved a stipulation of settlement in this proceeding, which made final the provisional rates that were placed into effect on June 1, 2014. The rate decrease will have no effect on ACE’s operating income.
	In March 2015, ACE submitted its 2015 annual petition with the NJBPU seeking to reconcile and update the same categories of charges and costs described in (i) and (ii) in the above paragraph. The net impact of adjusting the charges as proposed is an overall annual rate increase of approximately $52.0 million. The matter is pending at the NJBPU, and the data contained in the petition has been updated for February and March 2015 actual data. ACE has requested that NJBPU place new rates into effect by June 1, 2015.
	These proceedings are not expected to be affected by the Merger Agreement.
	Service Extension Contributions Refund Order
	In July 2013, in compliance with a 2012 Superior Court of New Jersey Appellate Division (Appellate Division) court decision, the NJBPU released an order requiring utilities to issue refunds to persons or entities that paid non-refundable contributions for utility service extensions to certain areas described as “Areas Not Designated for Growth.” The order is limited to eligible contributions paid between March 20, 2005 and December 20, 2009. ACE is processing the refund requests that meet the eligibility criteria established in the order as they are received. Although ACE estimates that it received approximately $11 million of contributions between March 20, 2005 and December 20, 2009, it is currently unable to reasonably estimate the amount that it may be required to refund using the eligibility criteria established by the order. Since the July 2013 order was released, ACE has received less than $1 million in refund claims, the validity of which is being investigated by ACE prior to making any such refunds. In September 2014, the NJBPU commenced a rulemaking proceeding to further implement the directives of the Appellate Division decision and, in December 2014, published a rule proposal for comment. The changes proposed by the NJBPU remove provisions distinguishing between growth areas and not-for-growth areas and provide formulae for allocating extension costs. ACE is participating in the rulemaking proceeding. At this time, ACE does not expect that any such amount refunded will have a material effect on its consolidated financial condition, results of operations or cash flows, as any amounts that may be refunded will generally increase the value of ACE’s property, plant and equipment and may ultimately be recovered through depreciation expense and cost of service in future electric distribution base rate cases.
	Under the Merger Agreement, ACE is permitted to pursue the conclusion of this matter and intends to continue to do so.
	Generic Consolidated Tax Adjustment Proceeding
	In January 2013, the NJBPU initiated a generic proceeding to examine whether a consolidated tax adjustment (CTA) should continue to be used, and if so, how it should be calculated in determining a utility’s cost of service. Under the NJBPU’s current policy, when a New Jersey utility is included in a consolidated group income tax return, an allocated amount of any reduction in the consolidated group’s taxes as a result of losses by affiliates is used to reduce the utility’s rate base, upon which the utility earns a return. This policy has negatively impacted ACE’s electric distribution base rate case outcomes and ACE’s position is that the CTA should be eliminated. In an order issued in October 2014, the NJBPU determined that it is appropriate for affected consolidated groups to continue to include a CTA in New Jersey base rate filings, but that the CTA calculation will be modified to limit the look-back period for the calculation to five years, exclude transmission assets from the calculation and allocate 25 percent of the final CTA amount as a reduction to the distribution revenue requirement. With this revised methodology, ACE anticipates that the negative effects of the CTA in future base rate cases would be significantly reduced.
	In November 2014, the New Jersey Division of Rate Counsel filed an appeal of the NJBPU’s CTA order in the Appellate Division. This appeal remains pending.
	Under the Merger Agreement, ACE is permitted to pursue the conclusion of this matter and intends to continue to do so.
	Federal Energy Regulatory Commission
	Transmission Annual Formula Rate Update Challenges
	In October 2013, FERC issued an order on challenges filed by the Delaware Municipal Electric Corporation, Inc. (DEMEC) to DPL’s 2011 and 2012 annual formula rate updates for transmission service. In 2006, FERC approved a formula rate for DPL that is incorporated into the PJM Interconnection, LLC (PJM) tariff. The formula rate establishes the treatment of costs and revenues and the resulting rates for DPL. Pursuant to the protocols approved by FERC and after a period of discovery, interested parties have an opportunity to file challenges regarding the application of the formula rate. The October 2013 FERC order set various issues in this proceeding for hearing, including challenges regarding formula rate inputs, deferred income items, prepayments of estimated income taxes, rate base reductions, various administrative and general expenses and the inclusion in rate base of construction work in progress related to the Mid-Atlantic Power Pathway project abandoned by PJM. Settlement discussions began in this matter in November 2013 before an administrative law judge at FERC.
	In December 2013, DEMEC filed a formal challenge to the DPL 2013 annual formula rate update for transmission service, which was consolidated with the 2011 and 2012 challenges. On January 9, 2015, FERC issued an order approving a settlement filed in August 2014, thereby resolving all of the issues set for hearing in the proceeding. Pursuant to the settlement, DPL will provide a one-time reduction of $225,000 to DPL’s 2015 annual formula rate update and will make a one-time payment of $258,500 to DEMEC.
	Transmission ROE Challenges
	In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as DEMEC, filed a joint complaint at FERC against Pepco, DPL and ACE, as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that PHI’s utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. PHI, Pepco, DPL and ACE believe the allegations in this complaint are without merit and are vigorously contesting this complaint. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set February 27, 2013 as the refund effective date, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, in November 2014, the settlement judge issued an order terminating the settlement discussions. The matter is now before a hearing judge and a procedural schedule will be established for both the February 2013 complaint and a second complaint (discussed below) that has been consolidated with the February 2013 complaint.
	In June 2014, FERC issued an order in a proceeding in which the PHI utilities were not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, Pepco, DPL and ACE applied an estimated ROE based on the two-step methodology announced by FERC for the period over which each of their transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves in the second quarter of 2014 related to this matter.
	A second complaint against Pepco, DPL and ACE challenging the base ROE was filed at FERC in December 2014 by the same parties. Employing the new ROE methodology referenced above, the complainants contend that the resulting base ROE should be 8.8%. As stated above, this complaint has been consolidated with the February 2013 complaint. Consistent with the prior challenge, Pepco, DPL and ACE applied an estimated ROE based on the two-step methodology described above, and recorded estimated reserves in the fourth quarter of 2014 and in the first quarter of 2015 based on a refund effective date of December 8, 2014.
	To the extent that the final ROE determined by FERC is lower than the ROE used to record the estimated reserves established with respect to the February 2013 and the December 2014 complaints, each ten basis point reduction in the ROE would result in a reduction of PHI’s operating income of $1.9 million.
	Under the Merger Agreement, PHI is permitted to pursue the conclusion of these FERC matters and intends to continue to do so.
	MPSC New Generation Contract Requirement
	In April 2012, the MPSC issued an order that requires Maryland electric distribution companies (EDCs) Pepco, DPL and BGE (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process to build one new power plant in the range of 650 to 700 megawatts (MWs) beginning in 2015, in amounts proportional to their relative SOS loads. Under the terms of the order, the winning bidder will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015, and each of the Contract EDCs will recover its costs associated with the contract through surcharges on its respective SOS customers.
	In response to a complaint filed by a group of generating companies in the PJM region, in September 2013, the U.S. District Court for the District of Maryland issued a ruling that the MPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, in October 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City upheld the MPSC’s orders requiring the Contract EDCs to enter into the contracts.
	In October 2013, the Federal district court issued an order ruling that the contracts are illegal and unenforceable. The Federal district court order and its associated ruling could impact the state circuit court appeal, to which the Contract EDCs are parties, although such impact, if any, cannot be determined at this time. The Contract EDCs, the Maryland Office of People’s Counsel and one generating company have appealed the Maryland Circuit Court’s decision to the Maryland Court of Special Appeals. In addition, in November 2013 both the winning bidder and the MPSC appealed the Federal district court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the lower Federal court ruling. In November 2014, both the winning bidder and the MPSC petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision. The petitions remain pending.
	The Maryland Court of Special Appeals has stayed the appeal of the Baltimore City Circuit Court decision until July 23, 2015.
	Assuming the contracts, as currently written, were to become effective by the expected commercial operation date of June 1, 2015, PHI continues to believe that Pepco and DPL may be required to record their proportional share of the contracts as derivative instruments at fair value and record related regulatory assets of approximately the same amount because Pepco and DPL would recover any payments under the contracts from SOS customers. PHI, Pepco and DPL have concluded that any accounting for these contracts would not be required until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved.
	Under the Merger Agreement, PHI is permitted to pursue the conclusion of this matter and intends to continue to do so.
	ACE Standard Offer Capacity Agreements
	In April 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU, each with a different generation company. ACE and the other New Jersey EDCs entered into the SOCAs under protest, arguing that the EDCs were denied due process and that the SOCAs violated certain of the requirements of the New Jersey law under which the SOCAs were established (the NJ SOCA Law). In October 2013, in light of the decision of the U.S. District Court for the District of New Jersey described below, the state appeals of the NJBPU implementation orders filed by the EDCs and generators were dismissed without prejudice, subject to the parties exercising their appellate rights in the Federal courts.
	In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the NJ SOCA Law on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In October 2013, the Federal district court issued a ruling that the NJ SOCA Law is preempted by the Federal Power Act (FPA) and violates the Supremacy Clause, and is therefore null and void. In October 2013, the Federal district court issued an order ruling that the SOCAs are void, invalid and unenforceable, which order was affirmed by the U.S. Court of Appeals for the Third Circuit in September 2014. In November 2014 and December 2014, respectively, one of the generation companies and the NJBPU petitioned the U.S. Supreme Court to consider hearing an appeal of the Third Circuit decision. The petitions remain pending.
	ACE terminated one of the three SOCAs effective July 1, 2013 due to an event of default of the generation company that was a party to the SOCA. ACE terminated the remaining two SOCAs effective November 19, 2013, in response to the October 2013 Federal district court decision.
In response to the October 2013 Federal district court order, ACE derecognized both the derivative assets (liabilities) for the estimated fair value of the SOCAs and the related regulatory liabilities (assets) in the fourth quarter of 2013.
District of Columbia Power Line Undergrounding Initiative
In May 2014, the Council of the District of Columbia enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provides enabling legislation for the District of Columbia Power Line Undergrounding (DC PLUG) initiative. This $1 billion initiative seeks to selectively place underground some of the District of Columbia’s most outage-prone power lines, which lines and surrounding conduit would be owned and maintained by Pepco.
The Improvement Financing Act provides that: (i) Pepco is to fund approximately $500 million of the estimated cost to complete the DC PLUG initiative, recovering those costs through a surcharge on the electric bills of Pepco District of Columbia customers; (ii) $375 million of the DC PLUG initiative cost is to be financed by the District of Columbia’s issuance of securitized bonds, which bonds will be repaid through a surcharge on the electric bills of Pepco District of Columbia customers that Pepco will collect on behalf of and remit to the District of Columbia; and (iii) the remaining costs up to $125 million are to be covered by the existing capital projects program of the District of Columbia Department of Transportation (DDOT). Pepco will not earn a return on or a return of the cost of the assets funded with the proceeds of the securitized bonds or assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such assets will be transferred to Pepco for a nominal amount.
In June 2014, Pepco and DDOT filed a Triennial Plan related to the construction of selected underground feeders in the District of Columbia and recovery of Pepco’s investment through a volumetric surcharge (the Triennial Plan), all in accordance with the Improvement Financing Act. In August 2014, Pepco filed an application for the issuance of a financing order to provide for the issuance of the District’s bonds and a volumetric surcharge for the District to recover the costs associated with the bond issuance.
In November 2014, the DCPSC issued an order approving the Triennial Plan and Pepco’s volumetric surcharge, and issued the financing order. Together these orders permit (i) Pepco and DDOT to commence proposed construction under the Triennial Plan; (ii) the District of Columbia to issue the necessary bonds to fund the District of Columbia’s portion of the DC PLUG initiative; and (iii) the establishment of the customer surcharges contemplated by the Improvement Financing Act. In December 2014, a party to the proceeding sought reconsideration from the DCPSC of both decisions. Final decisions denying both requests for reconsideration were issued by the DCPSC on January 22, 2015 and February 2, 2015, respectively.
In December 2014, a party filed a petition for review with the District of Columbia Court of Appeals disputing the DCPSC’s denial of its motion to intervene. The case is scheduled to be heard by the District of Columbia Court of Appeals in June 2015. In March 2015, a party filed with the District of Columbia Court of Appeals a petition for review of the orders approving the Triennial Plan and issuing the financing order. The procedural schedule for that appeal has not yet been set.
Under the Merger Agreement, Pepco is permitted to pursue the DC PLUG initiative and intends to continue to do so.
Merger Approval Proceedings
Delaware
On June 18, 2014, Exelon, PHI and DPL, and certain of their respective affiliates, filed an application with the DPSC seeking approval of the Merger. Delaware law requires the DPSC to approve the Merger when it determines that the transaction is in accordance with law, for a proper purpose, and is consistent with the public interest. The DPSC must further find that the successor will continue to provide safe and reliable service, will not terminate or impair existing collective bargaining agreements and will engage in good faith bargaining with organized labor. On February 13, 2015, Exelon, DPL, the DPSC staff, the Division of the Public Advocate and certain other parties filed a settlement agreement with the DPSC. A hearing on the settlement agreement was held on April 7, 2015. On April 16, 2015, the parties to this proceeding requested that hearings regarding DPSC approval of the settlement be postponed until May 2015 and that the decision of the DPSC be issued thereafter on or before June 2, 2015.
District of Columbia
On June 18, 2014, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application with the DCPSC seeking approval of the Merger. To approve the Merger, the DCPSC must find that the Merger is in the public interest. In an order issued August 22, 2014, the DCPSC stated that to make the determination of whether the transaction is in the public interest, it will analyze the transaction in the context of seven factors to determine whether the transaction balances the interests of shareholders and investors with ratepayers and the community, whether the benefits to shareholders do or do not come at the expense of the ratepayers, and whether the transaction produces a direct and tangible benefit to ratepayers. The seven factors identified by the DCPSC are the effects of the transaction on: (i) ratepayers, shareholders, the financial health of the utility standing alone and as merged, and the local economy; (ii) utility management and administrative operations; (iii) the public safety and the safety and reliability of services; (iv) risks associated with all of the affiliated non-jurisdictional business operations, including nuclear operations, of the applicants; (v) the DCPSC’s ability to regulate the utility effectively following the Merger; (vi) competition in the local retail and wholesale markets that impacts the District and District ratepayers; and (vii) conservation of natural resources and preservation of environmental quality. District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger. The DCPSC held evidentiary hearings in March and April 2015.
Maryland
On August 19, 2014, the Joint Applicants filed an application with the MPSC seeking approval of the Merger. Maryland law requires the MPSC to approve a merger subject to its review if it finds that the merger is consistent with the public interest, convenience and necessity, including its benefits to and impact on consumers. In making this determination, the MPSC is required to consider the following 12 criteria: (i) the potential impact of the merger on rates and charges paid by customers and on the services and conditions of operation of the utility; (ii) the potential impact of the merger on continuing investment needs for the maintenance of utility services, plant and related infrastructure; (iii) the proposed capital structure that will result from the merger, including allocation of earnings from the utility; (iv) the potential effects on employment by the utility; (v) the projected allocation between the utility’s shareholders and ratepayers of any savings that are expected; (vi) issues of reliability, quality of service and quality of customer service; (vii) the potential impact of the merger on community investment; (viii) affiliate and cross-subsidization issues; (ix) the use or pledge of utility assets for the benefit of an affiliate; (x) jurisdictional and choice-of-law issues; (xi) whether it is necessary to revise the MPSC’s ring-fencing and affiliate code of conduct regulations in light of the merger; and (xii) any other issues the MPSC considers relevant to the assessment of the merger. Evidentiary hearings were held beginning on January 26, 2015. On March 10, 2015, the Joint Applicants filed with the MPSC a settlement agreement entered into with The Alliance for Solar Choice, which is one of the stakeholder groups participating in the MPSC approval proceeding. On March 16, 2015, the Joint Applicants filed with the MPSC a settlement agreement entered into with Montgomery and Prince George’s Counties in Maryland, and a number of other parties, including the National Housing Trust, the National Consumer Law Center, other organizations representing low and moderate income interests and a consortium of nine recreational trail advocacy organizations. The MPSC staff, the State of Maryland and the Maryland Energy Administration, and the Office of People’s Counsel have each filed briefs in opposition to the settlement agreements. The settlement agreements, along with the Merger and other issues in the proceeding, are subject to MPSC approval.
On March 23, 2015, the MPSC issued a modified procedural schedule, pursuant to which settlement hearings were held in April and the deadline for a decision from the MPSC is May 15, 2015.
New Jersey
On June 18, 2014, Exelon, PHI and ACE, and certain of their respective affiliates, filed a petition with the NJBPU seeking approval of the Merger. To approve the Merger, the NJBPU must find the Merger is in the public interest, and consider the impact of the Merger on (i) competition, (ii) rates of ratepayers affected by the Merger, (iii) ACE’s employees, and (iv) the provision of safe and reliable service at just and reasonable rates. On July 23, 2014, the NJBPU voted to retain this matter, rather than assigning it to an administrative law judge. On January 14, 2015, PHI, ACE, Exelon, certain of Exelon’s affiliates, the Staff of the NJBPU, and the Independent Energy Producers of New Jersey filed a stipulation of settlement (the Stipulation) with the NJBPU in this proceeding. On February 11, 2015, the NJBPU approved the Stipulation and the Merger and on March 6, 2015, the NJBPU issued a written order approving the Stipulation.
Virginia
On June 3, 2014, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates, filed an application with the VSCC seeking approval of the Merger. Virginia law provides that, if the VSCC determines, with or without hearing, that adequate service to the public at just and reasonable rates will not be impaired or jeopardized by granting the application for approval, then the VSCC shall approve a merger with such conditions that the VSCC deems to be appropriate in order to satisfy this standard. On October 7, 2014, the VSCC issued an order approving the Merger.
Federal Energy Regulatory Commission
On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the FPA. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger.
Hart-Scott-Rodino Act
The HSR Act, which is the U.S. federal pre-merger notification statute, and its related rules and regulations provide that acquisition transactions that meet the HSR Act’s coverage thresholds may not be completed until a Notification and Report Form has been furnished to the DOJ and the Federal Trade Commission (FTC), and that the waiting period required by the HSR Act has been terminated or has expired. Pursuant to the HSR Act requirements, Pepco Holdings and Exelon filed the required Notification and Report Forms with the DOJ and the FTC on August 6, 2014. Following informal discussions with the DOJ, effective as of September 5, 2014, Exelon withdrew its Notification and Report Form and refiled it on September 9, 2014, which restarted the waiting period required by the HSR Act. On October 9, 2014, each of Pepco Holdings and Exelon received a request for additional information and documentary material from the DOJ, which had the effect of extending the DOJ review period until 30 days after each of Pepco Holdings and Exelon certified that it had substantially complied with the request. On November 21, 2014, each of Pepco Holdings and Exelon certified that it had substantially complied with the request. Accordingly, the HSR Act waiting period expired on December 22, 2014, and the HSR Act no longer precludes completion of the Merger. Although the DOJ allowed the waiting period under the HSR Act to expire without taking any action with respect to the Merger, the DOJ has not advised Pepco Holdings or Exelon that it has concluded its investigation.
Potomac Electric Power Co [Member]
Regulatory Matters	(6) REGULATORY MATTERS
	Rate Proceedings
	As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of the pending filings indicated below.
	Bill Stabilization Adjustment
	A decoupling mechanism, the bill stabilization adjustment (BSA), was approved and implemented for Pepco electric service in Maryland and in the District of Columbia.
	Maryland
	Pepco Electric Distribution Base Rates
	Under the Merger Agreement, Pepco is permitted, and intends to continue, to pursue the conclusion of the following matters. However, Pepco is not permitted to initiate or file any new electric distribution base rate cases in Maryland without Exelon’s consent.
	2011 Base Rate Proceeding
	In December 2011, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $68.4 million (subsequently adjusted by Pepco to approximately $66.2 million), based on a requested ROE of 10.75%. In July 2012, the MPSC issued an order approving an annual rate increase of approximately $18.1 million, based on an ROE of 9.31%. Among other things, the order also authorized Pepco to recover the actual cost of advanced metering infrastructure (AMI) meters installed during the 2011 test year, stating that cost recovery for AMI deployment will be allowed in future rate cases in which Pepco demonstrates that the system is cost effective. The new rates became effective on July 20, 2012. The Maryland Office of People’s Counsel has sought rehearing on the portion of the order allowing Pepco to recover the costs of AMI meters installed during the test year; that motion remains pending.
	2012 Base Rate Proceeding – Phase I
	In November 2012, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $60.8 million, based on a requested ROE of 10.25%. In July 2013, the MPSC issued an order in this proceeding approving an annual rate increase of approximately $27.9 million, based on an ROE of 9.36%. The order excludes the cost of AMI meters from Pepco’s rate base until such time as Pepco demonstrates the cost effectiveness of the AMI system; as a result, costs for AMI meters incurred with respect to the 2012 test year and beyond will be treated as other incremental AMI costs incurred in conjunction with the deployment of the AMI system that are deferred and on which a carrying charge is deferred, but only until such cost effectiveness has been demonstrated and such costs are included in rates. However, MPSC’s July 2012 order issued in connection with Pepco’s 2011 base rate proceeding, which allowed Pepco to recover the costs of meters installed during the 2011 test year for that case, remains in effect.
	The July 2013 order also approved a Grid Resiliency Charge, which went into effect on January 1, 2014, for recovery of costs totaling approximately $24.0 million associated with Pepco’s proposed plan to accelerate investments related to certain priority feeders, provided that, before implementing the surcharge, Pepco (i) provides additional information to the MPSC related to performance objectives, milestones and costs, and (ii) makes annual filings with the MPSC thereafter concerning this project, which will permit the MPSC to establish the applicable Grid Resiliency Charge rider for each following year. The MPSC rejected certain other cost recovery mechanisms, including Pepco’s proposed reliability performance-based mechanism. The new rates were effective on July 12, 2013.
	In July 2013, Pepco filed a notice of appeal of the July 2013 order in the Circuit Court for Baltimore City. Other parties also filed notices of appeal, which were consolidated with Pepco’s appeal. In its appeal, Pepco asserted that the MPSC erred in failing to grant Pepco an adequate ROE, denying a number of other cost recovery mechanisms and limiting Pepco’s test year data to no more than four months of forecasted data in future rate cases. The other parties primarily asserted that the MPSC erred or acted arbitrarily and capriciously in allowing the recovery of certain costs by Pepco, in approving the Grid Resiliency Charge, and in refusing to reduce Pepco’s rate base by known and measurable accumulated depreciation. In November 2014, the Circuit Court issued an order reversing the MPSC’s decision on Pepco’s ROE and directing the MPSC to make more specific findings regarding the impact of improved service reliability and the BSA in calculating Pepco’s ROE. On all other issues appealed, the Circuit Court affirmed the MPSC’s July 2013 order. Other parties to this proceeding have filed notices of appeal of the Circuit Court’s decision to the Court of Special Appeals. Pepco has elected not to appeal this decision.
	2013 Base Rate Proceeding – Phase I
	In December 2013, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $43.3 million (adjusted by Pepco to approximately $37.4 million on April 15, 2014), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with Pepco’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. In July 2014, the MPSC issued an order approving an annual rate increase of approximately $8.75 million, based on an ROE of 9.62%. The new rates became effective on July 4, 2014. In July 2014, Pepco filed a petition for rehearing seeking reconsideration of the recovery of certain expenses, which the MPSC denied by its order issued in November 2014. In December 2014, Pepco filed a petition for judicial review of this MPSC order with the Circuit Court for Baltimore City. A hearing date of May 26, 2015 in this matter has been set.
	2012 and 2013 Base Rate Proceedings – Phase II
	In August 2014, the MPSC issued an order establishing a Phase II proceeding in the 2012 base rate case described above (the 2012 Phase II proceeding) to address the tax implications of Pepco’s net operating loss carryforward (NOLC), which had impacted certain of Pepco’s rate adjustments in the 2012 base rate proceeding. Pepco filed a motion to dismiss the 2012 Phase II proceeding, asserting that the MPSC no longer has jurisdiction over the 2012 base rate case due to appeals having been filed by numerous parties. In September 2014, the MPSC issued an order staying the 2012 Phase II proceeding until further notice. In a similar Phase II proceeding in the 2013 base rate case described above, the MPSC issued an order in November 2014 upholding Pepco’s treatment of the NOLC. Although Pepco believes the November 2014 MPSC order should be dispositive of the issues raised in the 2012 Phase II proceeding, the 2012 Phase II proceeding remains open until the appeal of the 2012 base rate proceeding is resolved, after which the MPSC will have authority to act on Phase II.
	FERC Transmission ROE Challenges
	In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as DEMEC, filed a joint complaint at FERC against Pepco, and its affiliates DPL and Atlantic City Electric Company (ACE), as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that PHI’s utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. Pepco believes the allegations in this complaint are without merit and is vigorously contesting this complaint. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set February 27, 2013 as the refund effective date, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, in November 2014, the settlement judge issued an order terminating the settlement discussions. The matter is now before a hearing judge and a procedural schedule will be established for both the February 2013 complaint and a second complaint (discussed below) that has been consolidated with the February 2013 complaint.
	In June 2014, FERC issued an order in a proceeding in which Pepco was not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, Pepco applied an estimated ROE based on the two-step methodology announced by FERC for the period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves in the second quarter of 2014 related to this matter.
	A second complaint against Pepco, DPL and ACE challenging the base ROE was filed at FERC in December 2014 by the same parties. Employing the new ROE methodology referenced above, the complainants contend that the resulting base ROE should be 8.8%. As stated above, this complaint has been consolidated with the February 2013 complaint. Consistent with the prior challenge, Pepco applied an estimated ROE based on the two-step methodology described above, and recorded estimated reserves in the fourth quarter of 2014 and in the first quarter of 2015 based on a refund effective date of December 8, 2014.
	To the extent that the final ROE determined by FERC is lower than the ROE used to record the estimated reserves established with respect to the February 2013 and the December 2014 complaints, each ten basis point reduction in the ROE would result in a reduction of Pepco’s operating income of $0.8 million.
	Under the Merger Agreement, Pepco is permitted to pursue the conclusion of these FERC matters and intends to continue to do so.
	MPSC New Generation Contract Requirement
	In April 2012, the MPSC issued an order that requires Maryland electric distribution companies (EDCs) Pepco, DPL and BGE (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process to build one new power plant in the range of 650 to 700 megawatts (MWs) beginning in 2015, in amounts proportional to their relative SOS loads. Under the terms of the order, the winning bidder will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015, and each of the Contract EDCs will recover its costs associated with the contract through surcharges on its respective SOS customers.
	In response to a complaint filed by a group of generating companies in the PJM region, in September 2013, the U.S. District Court for the District of Maryland issued a ruling that the MPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, in October 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City upheld the MPSC’s orders requiring the Contract EDCs to enter into the contracts.
	In October 2013, the Federal district court issued an order ruling that the contracts are illegal and unenforceable. The Federal district court order and its associated ruling could impact the state circuit court appeal, to which the Contract EDCs are parties, although such impact, if any, cannot be determined at this time. The Contract EDCs, the Maryland Office of People’s Counsel and one generating company have appealed the Maryland Circuit Court’s decision to the Maryland Court of Special Appeals. In addition, in November 2013 both the winning bidder and the MPSC appealed the Federal district court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the lower Federal court ruling. In November 2014, both the winning bidder and the MPSC petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision. The petitions remain pending.
	The Maryland Court of Special Appeals has stayed the appeal of the Baltimore City Circuit Court decision until July 23, 2015.
	Assuming the contracts, as currently written, were to become effective by the expected commercial operation date of June 1, 2015, Pepco continues to believe that it may be required to record its proportional share of the contracts as derivative instruments at fair value and record related regulatory assets of approximately the same amount because Pepco would recover any payments under the contracts from SOS customers. Pepco has concluded that any accounting for these contracts would not be required until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved.
	Under the Merger Agreement, Pepco is permitted to pursue the conclusion of this matter and intends to continue to do so.
	District of Columbia Power Line Undergrounding Initiative
	In May 2014, the Council of the District of Columbia enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provides enabling legislation for the District of Columbia Power Line Undergrounding (DC PLUG) initiative. This $1 billion initiative seeks to selectively place underground some of the District of Columbia’s most outage-prone power lines, which lines and surrounding conduit would be owned and maintained by Pepco.
	The Improvement Financing Act provides that: (i) Pepco is to fund approximately $500 million of the estimated cost to complete the DC PLUG initiative, recovering those costs through a surcharge on the electric bills of Pepco District of Columbia customers; (ii) $375 million of the DC PLUG initiative cost is to be financed by the District of Columbia’s issuance of securitized bonds, which bonds will be repaid through a surcharge on the electric bills of Pepco District of Columbia customers that Pepco will collect on behalf of and remit to the District of Columbia; and (iii) the remaining costs up to $125 million are to be covered by the existing capital projects program of the District of Columbia Department of Transportation (DDOT). Pepco will not earn a return on or a return of the cost of the assets funded with the proceeds of the securitized bonds or assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such assets will be transferred to Pepco for a nominal amount.
	In June 2014, Pepco and DDOT filed a Triennial Plan related to the construction of selected underground feeders in the District of Columbia and recovery of Pepco’s investment through a volumetric surcharge (the Triennial Plan), all in accordance with the Improvement Financing Act. In August 2014, Pepco filed an application for the issuance of a financing order to provide for the issuance of the District’s bonds and a volumetric surcharge for the District to recover the costs associated with the bond issuance.
	In November 2014, the DCPSC issued an order approving the Triennial Plan and Pepco’s volumetric surcharge, and issued the financing order. Together these orders permit (i) Pepco and DDOT to commence proposed construction under the Triennial Plan; (ii) the District of Columbia to issue the necessary bonds to fund the District of Columbia’s portion of the DC PLUG initiative; and (iii) the establishment of the customer surcharges contemplated by the Improvement Financing Act. In December 2014, a party to the proceeding sought reconsideration from the DCPSC of both decisions. Final decisions denying both requests for reconsideration were issued by the DCPSC on January 22, 2015 and February 2, 2015, respectively.
	In December 2014, a party filed a petition for review with the District of Columbia Court of Appeals disputing the DCPSC’s denial of its motion to intervene. The case is scheduled to be heard by the District of Columbia Court of Appeals in June 2015. In March 2015, a party filed with the District of Columbia Court of Appeals a petition for review of the orders approving the Triennial Plan and issuing the financing order. The procedural schedule for that appeal has not yet been set.
	Under the Merger Agreement, Pepco is permitted to pursue the DC PLUG initiative and intends to continue to do so.
	Merger Approval Proceedings
	District of Columbia
	On June 18, 2014, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application with the DCPSC seeking approval of the Merger. To approve the Merger, the DCPSC must find that the Merger is in the public interest. In an order issued August 22, 2014, the DCPSC stated that to make the determination of whether the transaction is in the public interest, it will analyze the transaction in the context of seven factors to determine whether the transaction balances the interests of shareholders and investors with ratepayers and the community, whether the benefits to shareholders do or do not come at the expense of the ratepayers, and whether the transaction produces a direct and tangible benefit to ratepayers. The seven factors identified by the DCPSC are the effects of the transaction on: (i) ratepayers, shareholders, the financial health of the utility standing alone and as merged, and the local economy; (ii) utility management and administrative operations; (iii) the public safety and the safety and reliability of services; (iv) risks associated with all of the affiliated non-jurisdictional business operations, including nuclear operations, of the applicants; (v) the DCPSC’s ability to regulate the utility effectively following the Merger; (vi) competition in the local retail and wholesale markets that impacts the District and District ratepayers; and (vii) conservation of natural resources and preservation of environmental quality. District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger. The DCPSC held evidentiary hearings in March and April 2015.
	Maryland
	On August 19, 2014, the Joint Applicants filed an application with the MPSC seeking approval of the Merger. Maryland law requires the MPSC to approve a merger subject to its review if it finds that the merger is consistent with the public interest, convenience and necessity, including its benefits to and impact on consumers. In making this determination, the MPSC is required to consider the following 12 criteria: (i) the potential impact of the merger on rates and charges paid by customers and on the services and conditions of operation of the utility; (ii) the potential impact of the merger on continuing investment needs for the maintenance of utility services, plant and related infrastructure; (iii) the proposed capital structure that will result from the merger, including allocation of earnings from the utility; (iv) the potential effects on employment by the utility; (v) the projected allocation between the utility’s shareholders and ratepayers of any savings that are expected; (vi) issues of reliability, quality of service and quality of customer service; (vii) the potential impact of the merger on community investment; (viii) affiliate and cross-subsidization issues; (ix) the use or pledge of utility assets for the benefit of an affiliate; (x) jurisdictional and choice-of-law issues; (xi) whether it is necessary to revise the MPSC’s ring-fencing and affiliate code of conduct regulations in light of the merger; and (xii) any other issues the MPSC considers relevant to the assessment of the merger. Evidentiary hearings were held beginning on January 26, 2015. On March 10, 2015, the Joint Applicants filed with the MPSC a settlement agreement entered into with The Alliance for Solar Choice, which is one of the stakeholder groups participating in the MPSC approval proceeding. On March 16, 2015, the Joint Applicants filed with the MPSC a settlement agreement entered into with Montgomery and Prince George’s Counties in Maryland, and a number of other parties, including the National Housing Trust, the National Consumer Law Center, other organizations representing low and moderate income interests, and a consortium of nine recreational trail advocacy organizations. The MPSC staff, the State of Maryland and the Maryland Energy Administration, and the Office of People’s Counsel have each filed briefs in opposition to the settlement agreements. The settlement agreements, along with the Merger and other issues in the proceeding, are subject to MPSC approval.
	On March 23, 2015, the MPSC issued a modified procedural schedule, pursuant to which settlement hearings were held in April and the deadline for a decision from the MPSC is May 15, 2015.
	Virginia
	On June 3, 2014, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates, filed an application with the VSCC seeking approval of the Merger. Virginia law provides that, if the VSCC determines, with or without hearing, that adequate service to the public at just and reasonable rates will not be impaired or jeopardized by granting the application for approval, then the VSCC shall approve a merger with such conditions that the VSCC deems to be appropriate in order to satisfy this standard. On October 7, 2014, the VSCC issued an order approving the Merger.
	Federal Energy Regulatory Commission
	On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the Federal Power Act. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger.
Delmarva Power & Light Co/De [Member]
Regulatory Matters	(7) REGULATORY MATTERS
	Rate Proceedings
	As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of the pending filings indicated below.
	Bill Stabilization Adjustment
	A decoupling mechanism, the bill stabilization adjustment (BSA), was approved and implemented for DPL electric service in Maryland. DPL’s decoupling proposal in Delaware has not to date been adopted.
	Delaware
	Electric Distribution Base Rates
	In March 2013, DPL submitted an application with the DPSC to increase its electric distribution base rates. The application sought approval of an annual rate increase of approximately $42 million (adjusted by DPL to approximately $39 million on September 20, 2013), based on a requested return on equity (ROE) of 10.25%. The requested rate increase sought to recover expenses associated with DPL’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. In August 2014, the DPSC issued a final order in this proceeding providing for an annual increase in DPL’s electric distribution base rates of approximately $15.1 million, based on an ROE of 9.70%. The new rates became effective on May 1, 2014.
	In September 2014, DPL filed an appeal with the Delaware Superior Court of the DPSC’s August 2014 order in this proceeding, seeking the court’s review of the DPSC’s decision relating to the recovery of costs associated with one component of employee compensation, certain retirement benefits and recovery of credit facility expenses. The Division of the Public Advocate filed a
	cross-appeal in September 2014, pertaining to the treatment of a prepaid pension expense and other postretirement benefit obligations in base rates. Under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” the parties have agreed to suspend the appeal and, if the Merger is completed, to withdraw the appeal with prejudice.
	Under the Merger Agreement, DPL is not permitted to initiate or file any new electric distribution base rate cases in Delaware without Exelon’s consent.
	Forward Looking Rate Plan
	In October 2013, DPL filed a multi-year rate plan, referred to as the Forward Looking Rate Plan (FLRP). As proposed, the FLRP would provide for annual electric distribution base rate increases over a four-year period in the aggregate amount of approximately $56 million. The FLRP as proposed provides the opportunity to achieve estimated earned ROEs of 7.41% and 8.80% in years one and two, respectively, and 9.75% in both years three and four of the plan.
	In addition, DPL proposed that as part of the FLRP, in order to provide a higher minimum required standard of reliability for DPL’s customers than that to which DPL is currently subject, the standards by which DPL’s reliability is measured would be made more stringent in each year of the FLRP. DPL has also offered to refund an aggregate of $500,000 to customers in each year of the FLRP that it fails to meet the proposed stricter minimum reliability standards.
	In October 2013, the DPSC opened a docket for the purpose of reviewing the details of the FLRP, but stated that it would not address the FLRP until the electric distribution base rate case discussed above was concluded. A schedule for the FLRP docket has not yet been established.
	Under the Merger Agreement, DPL is permitted to pursue this matter; however, under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” DPL has agreed, if the Merger is completed, to withdraw the FLRP without prejudice and may make future filings with the DPSC proposing alternative regulatory methodologies that could include, but
	are not limited to, a multi-year rate plan.
	Gas Cost Rates
	DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2014, DPL made its 2014 GCR filing in which it proposed a GCR decrease of approximately 7.4%. In September 2014, the DPSC issued an order authorizing DPL to place the new rates into effect on November 1, 2014, subject to refund and pending final DPSC approval.
	Under the Merger Agreement, DPL is permitted and intends to continue to file its required annual GCR cases in Delaware.
	Federal Energy Regulatory Commission
	Transmission Annual Formula Rate Update Challenges
	In October 2013, FERC issued an order on challenges filed by the Delaware Municipal Electric Corporation, Inc. (DEMEC) to DPL’s 2011 and 2012 annual formula rate updates for transmission service. In 2006, FERC approved a formula rate for DPL that is incorporated into the PJM Interconnection, LLC (PJM) tariff. The formula rate establishes the treatment of costs and revenues and the resulting rates for DPL. Pursuant to the protocols approved by FERC and after a period of discovery, interested parties have an opportunity to file challenges regarding the application of the formula rate. The October 2013 FERC order set various issues in this proceeding for hearing, including challenges regarding formula rate inputs, deferred income items, prepayments of estimated income taxes, rate base reductions, various administrative and general expenses and the inclusion in rate base of construction work in progress related to the Mid-Atlantic Power Pathway project abandoned by PJM. Settlement discussions began in this matter in November 2013 before an administrative law judge at FERC.
	In December 2013, DEMEC filed a formal challenge to the DPL 2013 annual formula rate update for transmission service, which was consolidated with the 2011 and 2012 challenges. On January 9, 2015, FERC issued an order approving a settlement filed in August 2014, thereby resolving all of the issues set for hearing in the proceeding. Pursuant to the settlement, DPL will provide a one-time reduction of $225,000 to DPL’s 2015 annual formula rate update and will make a one-time payment of $258,500 to DEMEC.
	Transmission ROE Challenges
	In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as DEMEC, filed a joint complaint at FERC against Pepco, DPL and Atlantic City Electric Company (ACE), as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that PHI’s utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. DPL believes the allegations in this complaint are without merit and is vigorously contesting this complaint. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set February 27, 2013 as the refund effective date, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, in November 2014, the settlement judge issued an order terminating the settlement discussions. The matter is now before a hearing judge and a procedural schedule will be established for both the February 2013 complaint and a second complaint (discussed below) that has been consolidated with the February 2013 complaint.
	In June 2014, FERC issued an order in a proceeding in which DPL was not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, DPL applied an estimated ROE based on the two-step methodology announced by FERC for the period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves in the second quarter of 2014 related to this matter.
	A second complaint against Pepco, DPL and ACE challenging the base ROE was filed at FERC in December 2014 by the same parties. Employing the new ROE methodology referenced above, the complainants contend that the resulting base ROE should be 8.8%. As stated above, this complaint has been consolidated with the February 2013 complaint. Consistent with the prior challenge, DPL applied an estimated ROE based on the two-step methodology described above, and recorded estimated reserves in the fourth quarter of 2014 and in the first quarter of 2015 based on a refund effective date of December 8, 2014.
	To the extent that the final ROE determined by FERC is lower than the ROE used to record the estimated reserves established with respect to the February 2013 and the December 2014 complaints, each ten basis point reduction in the ROE would result in a reduction of DPL’s operating income of $0.6 million.
	Under the Merger Agreement, DPL is permitted to pursue the conclusion of these FERC matters and intends to continue to do so.
	MPSC New Generation Contract Requirement
	In April 2012, the MPSC issued an order that requires Maryland electric distribution companies (EDCs) Pepco, DPL and BGE (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process to build one new power plant in the range of 650 to 700 megawatts (MWs) beginning in 2015, in amounts proportional to their relative SOS loads. Under the terms of the order, the winning bidder will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015, and each of the Contract EDCs will recover its costs associated with the contract through surcharges on its respective SOS customers.
	In response to a complaint filed by a group of generating companies in the PJM region, in September 2013, the U.S. District Court for the District of Maryland issued a ruling that the MPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, in October 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City upheld the MPSC’s orders requiring the Contract EDCs to enter into the contracts.
	In October 2013, the Federal district court issued an order ruling that the contracts are illegal and unenforceable. The Federal district court order and its associated ruling could impact the state circuit court appeal, to which the Contract EDCs are parties, although such impact, if any, cannot be determined at this time. The Contract EDCs, the Maryland Office of People’s Counsel and one generating company have appealed the Maryland Circuit Court’s decision to the Maryland Court of Special Appeals. In addition, in November 2013 both the winning bidder and the MPSC appealed the Federal district court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the lower Federal court ruling. In November 2014, both the winning bidder and the MPSC petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision. The petitions remain pending.
	The Maryland Court of Special Appeals has stayed the appeal of the Baltimore City Circuit Court decision until July 23, 2015.
	Assuming the contracts, as currently written, were to become effective by the expected commercial operation date of June 1, 2015, DPL continues to believe that it may be required to record its proportional share of the contracts as derivative instruments at fair value and record related regulatory assets of approximately the same amount because DPL would recover any payments under the contracts from SOS customers. DPL has concluded that any accounting for these contracts would not be required until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved.
	Under the Merger Agreement, DPL is permitted to pursue the conclusion of this matter and intends to continue to do so.
	Merger Approval Proceedings
	Delaware
	On June 18, 2014, Exelon, PHI and DPL, and certain of their respective affiliates, filed an application with the DPSC seeking approval of the Merger. Delaware law requires the DPSC to approve the Merger when it determines that the transaction is in accordance with law, for a proper purpose, and is consistent with the public interest. The DPSC must further find that the successor will continue to provide safe and reliable service, will not terminate or impair existing collective bargaining agreements and will engage in good faith bargaining with organized labor. On February 13, 2015, Exelon, DPL, the DPSC staff, the Division of the Public Advocate and certain other parties filed a settlement agreement with the DPSC. A hearing on the settlement agreement was held on April 7, 2015. On April 16, 2015, the parties to this proceeding requested that hearings regarding DPSC approval of the settlement be postponed until May 2015 and that the decision of the DPSC be issued thereafter on or before June 2, 2015.
	Maryland
	On August 19, 2014, the Joint Applicants filed an application with the MPSC seeking approval of the Merger. Maryland law requires the MPSC to approve a merger subject to its review if it finds that the merger is consistent with the public interest, convenience and necessity, including its benefits to and impact on consumers. In making this determination, the MPSC is required to consider the following 12 criteria: (i) the potential impact of the merger on rates and charges paid by customers and on the services and conditions of operation of the utility; (ii) the potential impact of the merger on continuing investment needs for the maintenance of utility services, plant and related infrastructure; (iii) the proposed capital structure that will result from the merger, including allocation of earnings from the utility; (iv) the potential effects on employment by the utility; (v) the projected allocation between the utility’s shareholders and ratepayers of any savings that are expected; (vi) issues of reliability, quality of service and quality of customer service; (vii) the potential impact of the merger on community investment; (viii) affiliate and cross-subsidization issues; (ix) the use or pledge of utility assets for the benefit of an affiliate; (x) jurisdictional and choice-of-law issues; (xi) whether it is necessary to revise the MPSC’s ring-fencing and affiliate code of conduct regulations in light of the merger; and (xii) any other issues the MPSC considers relevant to the assessment of the merger. Evidentiary hearings were held beginning on January 26, 2015. On March 10, 2015, the Joint Applicants filed with the MPSC a settlement agreement entered into with The Alliance for Solar Choice, which is one of the stakeholder groups participating in the MPSC approval proceeding. On March 16, 2015, the Joint Applicants filed with the MPSC a settlement agreement entered into with Montgomery and Prince George’s Counties in Maryland, and a number of other parties, including the National Housing Trust, the National Consumer Law Center, other organizations representing low and moderate income interests, and a consortium of nine recreational trail advocacy organizations. The MPSC staff, the State of Maryland and the Maryland Energy Administration, and the Office of People’s Counsel have each filed briefs in opposition to the settlement agreements. The settlement agreements, along with the Merger and other issues in the proceeding, are subject to MPSC approval.
	On March 23, 2015, the MPSC issued a modified procedural schedule, pursuant to which settlement hearings were held in April and the deadline for a decision from the MPSC is May 15, 2015.
	Virginia
	On June 3, 2014, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates, filed an application with the VSCC seeking approval of the Merger. Virginia law provides that, if the VSCC determines, with or without hearing, that adequate service to the public at just and reasonable rates will not be impaired or jeopardized by granting the application for approval, then the VSCC shall approve a merger with such conditions that the VSCC deems to be appropriate in order to satisfy this standard. On October 7, 2014, the VSCC issued an order approving the Merger.
	Federal Energy Regulatory Commission
	On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the Federal Power Act. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger.
Atlantic City Electric Co [Member]
Regulatory Matters	(6) REGULATORY MATTERS
	Rate Proceedings
	As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of the pending filings indicated below.
	Bill Stabilization Adjustment
	Although ACE proposed the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers, this decoupling proposal has not to date been adopted.
	New Jersey
	Update and Reconciliation of Certain Under-Recovered Balances
	In March 2014, ACE submitted its 2014 annual petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the non-utility generators (NUGs), (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and ACE’s uncollected accounts and (iii) operating costs associated with ACE’s residential appliance cycling program. The net impact of adjusting the charges as proposed would have been an overall annual rate decrease of approximately $24.5 million (revised to a rate decrease of approximately $41.1 million on April 16, 2014, based upon an update for actual data through March 2014). In May 2014, the NJBPU approved a stipulation of settlement entered into by the parties in this proceeding providing for an overall annual rate decrease of $41.1 million. The rate decrease was placed into effect provisionally on June 1, 2014, subject to a review by the NJBPU of the final underlying costs for reasonableness and prudence. On January 21, 2015, the NJBPU approved a stipulation of settlement in this proceeding, which made final the provisional rates that were placed into effect on June 1, 2014. The rate decrease will have no effect on ACE’s operating income.
	In March 2015, ACE submitted its 2015 annual petition with the NJBPU seeking to reconcile and update the same categories of charges and costs described in (i) and (ii) in the above paragraph. The net impact of adjusting the charges as proposed is an overall annual rate increase of approximately $52.0 million. The matter is pending at the NJBPU, and the data contained in the petition has been updated for February and March 2015 actual data. ACE has requested that NJBPU place new rates into effect by June 1, 2015.
	These proceedings are not expected to be affected by the Merger Agreement.
	Service Extension Contributions Refund Order
	In July 2013, in compliance with a 2012 Superior Court of New Jersey Appellate Division (Appellate Division) court decision, the NJBPU released an order requiring utilities to issue refunds to persons or entities that paid non-refundable contributions for utility service extensions to certain areas described as “Areas Not Designated for Growth.” The order is limited to eligible contributions paid between March 20, 2005 and December 20, 2009. ACE is processing the refund requests that meet the eligibility criteria established in the order as they are received. Although ACE estimates that it received approximately $11 million of contributions between March 20, 2005 and December 20, 2009, it is currently unable to reasonably estimate the amount that it may be required to refund using the eligibility criteria established by the order. Since the July 2013 order was released, ACE has received less than $1 million in refund claims, the validity of which is being investigated by ACE prior to making any such refunds. In September 2014, the NJBPU commenced a rulemaking proceeding to further implement the directives of the Appellate Division decision and, in December 2014, published a rule proposal for comment. The changes proposed by the NJBPU remove provisions distinguishing between growth areas and not-for-growth areas and provide formulae for allocating extension costs. ACE is participating in the rulemaking proceeding. At this time, ACE does not expect that any such amount refunded will have a material effect on its consolidated financial condition, results of operations or cash flows, as any amounts that may be refunded will generally increase the value of ACE’s property, plant and equipment and may ultimately be recovered through depreciation expense and cost of service in future electric distribution base rate cases.
	Under the Merger Agreement, ACE is permitted to pursue the conclusion of this matter and intends to continue to do so.
	Generic Consolidated Tax Adjustment Proceeding
	In January 2013, the NJBPU initiated a generic proceeding to examine whether a consolidated tax adjustment (CTA) should continue to be used, and if so, how it should be calculated in determining a utility’s cost of service. Under the NJBPU’s current policy, when a New Jersey utility is included in a consolidated group income tax return, an allocated amount of any reduction in the consolidated group’s taxes as a result of losses by affiliates is used to reduce the utility’s rate base, upon which the utility earns a return. This policy has negatively impacted ACE’s electric distribution base rate case outcomes and ACE’s position is that the CTA should be eliminated. In an order issued in October 2014, the NJBPU determined that it is appropriate for affected consolidated groups to continue to include a CTA in New Jersey base rate filings, but that the CTA calculation will be modified to limit the look-back period for the calculation to five years, exclude transmission assets from the calculation and allocate 25 percent of the final CTA amount as a reduction to the distribution revenue requirement. With this revised methodology, ACE anticipates that the negative effects of the CTA in future base rate cases would be significantly reduced.
	In November 2014, the New Jersey Division of Rate Counsel filed an appeal of the NJBPU’s CTA order in the Appellate Division. This appeal remains pending.
	Under the Merger Agreement, ACE is permitted to pursue the conclusion of this matter and intends to continue to do so.
	FERC Transmission ROE Challenges
	In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as DEMEC, filed a joint complaint at FERC against Pepco, DPL and ACE, as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that PHI’s utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. ACE believes the allegations in this complaint are without merit and is vigorously contesting this complaint. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set February 27, 2013 as the refund effective date, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, in November 2014, the settlement judge issued an order terminating the settlement discussions. The matter is now before a hearing judge and a procedural schedule will be established for both the February 2013 complaint and a second complaint (discussed below) that has been consolidated with the February 2013 complaint.
	In June 2014, FERC issued an order in a proceeding in which ACE was not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, ACE applied an estimated ROE based on the two-step methodology announced by FERC for the period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves in the second quarter of 2014 related to this matter.
	A second complaint against Pepco, DPL and ACE challenging the base ROE was filed at FERC in December 2014 by the same parties. Employing the new ROE methodology referenced above, the complainants contend that the resulting base ROE should be 8.8%. As stated above, this complaint has been consolidated with the February 2013 complaint. Consistent with the prior challenge, ACE applied an estimated ROE based on the two-step methodology described above, and recorded estimated reserves in the fourth quarter of 2014 and in the first quarter of 2015 based on a refund effective date of December 8, 2014.
	To the extent that the final ROE determined by FERC is lower than the ROE used to record the estimated reserves established with respect to the February 2013 and the December 2014 complaints, each ten basis point reduction in the ROE would result in a reduction of ACE’s operating income of $0.5 million.
	Under the Merger Agreement, ACE is permitted to pursue the conclusion of these FERC matters and intends to continue to do so.
	Standard Offer Capacity Agreements
	In April 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU, each with a different generation company. ACE and the other New Jersey electric distribution companies (EDCs) entered into the SOCAs under protest, arguing that the EDCs were denied due process and that the SOCAs violated certain of the requirements of the New Jersey law under which the SOCAs were established (the NJ SOCA Law). In October 2013, in light of the decision of the U.S. District Court for the District of New Jersey described below, the state appeals of the NJBPU implementation orders filed by the EDCs and generators were dismissed without prejudice, subject to the parties exercising their appellate rights in the Federal courts.
	In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the NJ SOCA Law on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In October 2013, the Federal district court issued a ruling that the NJ SOCA Law is preempted by the Federal Power Act (FPA) and violates the Supremacy Clause, and is therefore null and void. In October 2013, the Federal district court issued an order ruling that the SOCAs are void, invalid and unenforceable, which order was affirmed by the U.S. Court of Appeals for the Third Circuit in September 2014. In November 2014 and December 2014, respectively, one of the generation companies and the NJBPU petitioned the U.S. Supreme Court to consider hearing an appeal of the Third Circuit decision. The petitions remain pending.
	ACE terminated one of the three SOCAs effective July 1, 2013 due to an event of default of the generation company that was a party to the SOCA. ACE terminated the remaining two SOCAs effective November 19, 2013, in response to the October 2013 Federal district court decision.
	In response to the October 2013 Federal district court order, ACE derecognized both the derivative assets (liabilities) for the estimated fair value of the SOCAs and the related regulatory liabilities (assets) in the fourth quarter of 2013.
	Merger Approval Proceedings
	New Jersey
	On June 18, 2014, Exelon, PHI and ACE, and certain of their respective affiliates, filed a petition with the NJBPU seeking approval of the Merger. To approve the Merger, the NJBPU must find the Merger is in the public interest, and consider the impact of the Merger on (i) competition, (ii) rates of ratepayers affected by the Merger, (iii) ACE’s employees, and (iv) the provision of safe and reliable service at just and reasonable rates. On July 23, 2014, the NJBPU voted to retain this matter, rather than assigning it to an administrative law judge. On January 14, 2015, PHI, ACE, Exelon, certain of Exelon’s affiliates, the Staff of the NJBPU, and the Independent Energy Producers of New Jersey filed a stipulation of settlement (the Stipulation) with the NJBPU in this proceeding. On February 11, 2015, the NJBPU approved the Stipulation and the Merger and on March 6, 2015, the NJBPU issued a written order approving the Stipulation.
	Federal Energy Regulatory Commission
	On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the FPA. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger.

Pension_and_Other_Postretireme

Pension and Other Postretirement Benefits	3 Months Ended
	Mar. 31, 2015
Pension and Other Postretirement Benefits	(8) PENSION AND OTHER POSTRETIREMENT BENEFITS
	The table below provides the components of net periodic benefit costs recognized by Pepco Holdings for the three months ended March 31, 2015 and 2014:
		Pension Benefits						Other Postretirement
								Benefits
		2015			2014			2015			2014
		(millions of dollars)
	Service cost	$	14		$	12		$	2		$	2
	Interest cost		27			27			6			7
	Expected return on plan assets		(35	)		(35	)		(6	)		(6	)
	Amortization of prior service cost (benefit)		—			—			(3	)		(3	)
	Amortization of net actuarial loss		16			11			3			3
	Net periodic benefit cost	$	22		$	15		$	2		$	3
	Pension and Other Postretirement Benefits
	Net periodic benefit cost related to continuing operations is included in other operation and maintenance expense, net of the portion of the net periodic benefit cost that is capitalized as part of the cost of labor for internal construction projects. PHI anticipates approximately 36% of annual net periodic pension and other postretirement benefit costs will be capitalized.
	Pension Contributions
	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, as modified by subsequent legislation. In the first quarter of 2015 and 2014, PHI, Pepco, DPL and ACE made no discretionary tax-deductible contributions to the PHI Retirement Plan.
Potomac Electric Power Co [Member]
Pension and Other Postretirement Benefits	(7) PENSION AND OTHER POSTRETIREMENT BENEFITS
	Pepco accounts for its participation in PHI’s single-employer plans, PHI’s noncontributory retirement plan (the PHI Retirement Plan) and its other postretirement benefits plan, the Pepco Holdings, Inc. Welfare Plan for Retirees (the OPEB Plan), as participation in multiemployer plans. PHI’s pension and other postretirement net periodic benefit cost for the three months ended March 31, 2015 and 2014, before intercompany allocations from the PHI Service Company, were $24 million and $18 million, respectively. Pepco’s allocated share was $8 million and $7 million, respectively, for the three months ended March 31, 2015 and 2014.
	In the first quarter of 2015 and 2014, Pepco made no contributions to the PHI Retirement Plan.
Delmarva Power & Light Co/De [Member]
Pension and Other Postretirement Benefits	(8) PENSION AND OTHER POSTRETIREMENT BENEFITS
	DPL accounts for its participation in PHI’s single-employer plans, PHI’s noncontributory retirement plan (the PHI Retirement Plan) and its other postretirement benefits plan, the Pepco Holdings, Inc. Welfare Plan for Retirees (the OPEB Plan), as participation in multiemployer plans. PHI’s pension and other postretirement net periodic benefit cost for the three months ended March 31, 2015 and 2014, before intercompany allocations from the PHI Service Company, were $24 million and $18 million, respectively. DPL’s allocated share was $4 million and $3 million for the three months ended March 31, 2015 and 2014, respectively.
	In the first quarter of 2015 and 2014, DPL made no discretionary tax-deductible contributions to the PHI Retirement Plan.
Atlantic City Electric Co [Member]
Pension and Other Postretirement Benefits	(7) PENSION AND OTHER POSTRETIREMENT BENEFITS
	ACE accounts for its participation in PHI’s single-employer plans, PHI’s noncontributory retirement plan (the PHI Retirement Plan) and its other postretirement benefits plan, the Pepco Holdings, Inc. Welfare Plan for Retirees (the OPEB Plan), as participation in multiemployer plans. PHI’s pension and other postretirement net periodic benefit cost for the three months ended March 31, 2015 and 2014, before intercompany allocations from the PHI Service Company, were $24 million and $18 million, respectively. ACE’s allocated share was $4 million for each of the three months ended March 31, 2015 and 2014.
	In the first quarter of 2015 and 2014, ACE made no discretionary tax-deductible contributions to the PHI Retirement Plan.

Debt

Debt	3 Months Ended
	Mar. 31, 2015
Debt	(9) DEBT
	Credit Facility
	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, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same.
	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 credit sublimit is $750 million for PHI 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 London Interbank Offered Rate (LIBOR) plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.
	In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility as of March 31, 2015.
	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.
	As of March 31, 2015 and December 31, 2014, 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 $916 million and $875 million, respectively. PHI’s utility subsidiaries had combined cash and unused borrowing capacity under the credit facility of $547 million and $413 million at March 31, 2015 and December 31, 2014, respectively.
	Credit Facility Amendment
	On May 20, 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings.
	Commercial Paper
	PHI, Pepco, DPL and ACE maintain on-going commercial paper programs to address short-term liquidity needs. As of March 31, 2015, the maximum capacity available under these programs was $875 million, $500 million, $500 million and $350 million, respectively, subject to available borrowing capacity under the credit facility.
	PHI, Pepco, DPL and ACE had $380 million, zero, $175 million and $143 million, respectively, of commercial paper outstanding at March 31, 2015. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during the three months ended March 31, 2015 was 0.74%, 0.43%, 0.45% and 0.44%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE during the three months ended March 31, 2015 was eight, five, five and five days, respectively.
	Other Financing Activities
	Bond Issuance
	In March 2015, Pepco issued $200 million of 4.15% first mortgage bonds due March 15, 2043, with a 3.9% yield to maturity. Net proceeds from the issuance of the bonds, which included a premium of $8 million, were used by Pepco to repay outstanding commercial paper and for general corporate purposes.
	Bond Payments
	In January 2015, Atlantic City Electric Transition Funding LLC (ACE Funding) made principal payments of $8 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-3.
	Sale of Receivables
	During 2014, Pepco, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project pursuant to a Task Order entered into under a General Services Administration area-wide agreement. The purchase price received by Pepco was $12 million. The energy savings project, which is being performed by Pepco Energy Services, was completed in 2014. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer is entitled to receive the contract payments under the Task Order payable by the customer over approximately 9 years. The energy savings project was accepted during the first quarter of 2015 and the amount was removed from the Current portion of long-term debt and project funding.
	On October 24, 2013, Pepco Energy Services, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project over a period of time pursuant to a Task Order. The purchase price received by Pepco Energy Services was $7 million. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer is entitled to receive the contract payments under the Task Order payable by the customer over approximately 23 years. The energy savings project was accepted during the first quarter of 2015 and the amount was removed from the Current portion of long-term debt and project funding.
	Financing Activities Subsequent to March 31, 2015
	Bond Payments
	In April 2015, ACE Funding made principal payments of $7 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-3.
Potomac Electric Power Co [Member]
Debt	(8) DEBT
	Credit Facility
	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, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same.
	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 credit sublimit is $750 million for PHI 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 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, 2015.
	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.
	As of March 31, 2015 and December 31, 2014, 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 $547 million and $413 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.
	Credit Facility Amendment
	On May 20, 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings.
	Commercial Paper
	Pepco maintains an on-going commercial paper program to address its short-term liquidity needs. As of March 31, 2015, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.
	Pepco had no commercial paper outstanding at March 31, 2015. The weighted average interest rate for commercial paper issued by Pepco during the three months ended March 31, 2015 was 0.43%, and the weighted average maturity of all commercial paper issued by Pepco during the three months ended March 31, 2015 was five days.
	Other Financing Activities
	Bond Issuance
	In March 2015, Pepco issued $200 million of 4.15% first mortgage bonds due March 15, 2043, with a 3.9% yield to maturity. Net proceeds from the issuance of the bonds, which included a premium of $8 million, were used to repay outstanding commercial paper and for general corporate purposes.
	Sale of Receivables
	During 2014, Pepco, as seller, entered into a purchase agreement with a buyer to sell receivables from an energy savings project pursuant to a Task Order entered into under a General Services Administration area-wide agreement. The purchase price to be received by Pepco is approximately $12 million. The energy savings project, which is being performed by Pepco Energy Services, Inc. and its subsidiaries (Pepco Energy Services), was completed in 2014. Pursuant to the purchase agreement, following acceptance of the energy savings project by the buyer, the buyer is entitled to receive the contract payments under the Task Order payable by the customer over approximately 9 years. The energy savings project was accepted during the first quarter of 2015 and the amount was removed from the Current portion of long-term debt and project funding.
Delmarva Power & Light Co/De [Member]
Debt	(9) DEBT
	Credit Facility
	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, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same.
	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 credit sublimit is $750 million for PHI 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 or 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 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, 2015.
	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.
	As of March 31, 2015 and December 31, 2014, 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 $547 million and $413 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.
	Credit Facility Amendment
	On May 20, 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings.
	Commercial Paper
	DPL maintains an on-going commercial paper program to address its short-term liquidity needs. As of March 31, 2015, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.
	DPL had $175 million of commercial paper outstanding at March 31, 2015. The weighted average interest rate for commercial paper issued by DPL during the three months ended March 31, 2015 was 0.45%, and the weighted average maturity of all commercial paper issued by DPL during the three months ended March 31, 2015 was five days.
Atlantic City Electric Co [Member]
Debt	(8) DEBT
	Credit Facility
	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, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same.
	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 credit sublimit is $750 million for PHI 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 or 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 London Interbank Offered Rate (LIBOR) plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.
	In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility at March 31, 2015.
	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.
	As of March 31, 2015 and December 31, 2014, 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 $547 million and $413 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.
	Credit Facility Amendment
	On May 20, 2014, PHI, Pepco, DPL and ACE entered into an amendment of and consent with respect to the credit agreement (the Consent). PHI was required to obtain the consent of certain of the lenders under the credit facility in order to permit the consummation of the Merger. Pursuant to the Consent, certain of the lenders consented to the consummation of the Merger and the subsequent conversion of PHI from a Delaware corporation to a Delaware limited liability company, provided that the Merger and subsequent conversion are consummated on or before October 29, 2015. In addition, the Consent amends the definition of “Change in Control” in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings.
	Commercial Paper
	ACE maintains an on-going commercial paper program to address its short-term liquidity needs. As of March 31, 2015, the maximum capacity available under the program was $350 million, subject to available borrowing capacity under the credit facility.
	ACE had $143 million of commercial paper outstanding at March 31, 2015. The weighted average interest rate for commercial paper issued by ACE during the three months ended March 31, 2015 was 0.44%, and the weighted average maturity of all commercial paper issued by ACE during the three months ended March 31, 2015 was five days.
	Financing Activities
	Bond Payments
	In January 2015, Atlantic City Electric Transition Funding LLC (ACE Funding) made principal payments of $8 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-3.
	Financing Activities Subsequent to March 31, 2015
	Bond Payments
	In April 2015, ACE Funding made principal payments of $7 million on its Series 2002-1 Bonds, Class A-3, and $3 million on its Series 2003-1 Bonds, Class A-3.

Income_Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2015
Income Taxes	(10) INCOME TAXES
	A reconciliation of PHI’s consolidated effective income tax rates from continuing operations is as follows:
		Three Months Ended
		March 31,
		2015					2014
		(millions of dollars)
	Income tax at Federal statutory rate	$	29		35	%	$	42		35	%
	Increases (decreases) resulting from:
	State income taxes, net of Federal effect		6		7.2	%		7		5.8	%
	Asset removal costs		(3	)	(3.6	)%		(2	)	(1.7	)%
	Change in estimates and interest related to uncertain and effectively settled tax positions		—		—			(1	)	(0.8	)%
	Energy efficiency-related tax deductions		(4	)	(4.8	)%		—		—
	Merger-related costs		2		2.4	%		—		—
	Other, net		—		(0.1	)%		—		(0.3	)%
	Consolidated income tax expense	$	30		36.1	%	$	46		38	%
	PHI’s consolidated effective tax rates for the three months ended March 31, 2015 and 2014 were 36.1% and 38.0%, respectively.
	In the first quarter of 2015, PHI recorded a tax benefit of $4 million related to certain energy efficiency tax deductions associated with Pepco Energy Services’ energy savings performance contracting services.
	In connection with the proposed Merger (as further described in Note (1), “Organization”), PHI incurred certain merger-related costs in the first quarter of 2015, which costs are not tax-deductible.
	Changes to the District of Columbia Tax Law
	On February 26, 2015, the District of Columbia Fiscal Year 2015 Budget Support Act of 2014 became law, effective January 1, 2015. The law revised the apportionment methodology for corporate tax and included a phase-down of the corporate tax rate from 9.975% to 8.25% by fiscal year 2019. The change in law required PHI and Pepco to remeasure their net deferred tax liabilities in the first quarter of 2015. This remeasurement resulted in Pepco reducing its deferred tax liabilities by $23 million in the first quarter of 2015 to reflect the initial reduction in the tax rate from 9.975% to 9.4% for 2015. This reduction to the deferred tax liabilities was offset by a corresponding decrease to Pepco’s regulatory assets. Further reductions to the corporate tax rate beyond 2015 will depend upon future revenue projections for the District of Columbia.
Potomac Electric Power Co [Member]
Income Taxes	(9) INCOME TAXES
	A reconciliation of Pepco’s effective income tax rates is as follows:
		Three Months Ended
		March 31,
		2015					2014
		(millions of dollars)
	Income tax at Federal statutory rate	$	13		35	%	$	17		35	%
	Increases (decreases) resulting from:
	State income taxes, net of Federal effect		2		5.3	%		3		6.3	%
	Asset removal costs		(3	)	(7.9	)%		(2	)	(4.2	)%
	Change in estimates and interest related to uncertain and effectively settled tax positions		—		—			(1	)	(2.1	)%
	Other, net		—		(0.8	)%		(1	)	(1.7	)%
	Income tax expense	$	12		31.6	%	$	16		33.3	%
	Pepco’s effective tax rates for the three months ended March 31, 2015 and 2014 and were 31.6% and 33.3%, respectively.
	Changes to the District of Columbia Tax Law
	On February 26, 2015, the District of Columbia Fiscal Year 2015 Budget Support Act of 2014 became law, effective January 1, 2015. The law revised the apportionment methodology for corporate tax and included a phase-down of the corporate tax rate from 9.975% to 8.25% by fiscal year 2019. The change in law required Pepco to remeasure its net deferred tax liabilities in the first quarter of 2015. This remeasurement resulted in Pepco reducing its deferred tax liabilities by $23 million in the first quarter of 2015 to reflect the initial reduction in the tax rate from 9.975% to 9.4% for 2015. This reduction to the deferred tax liabilities was offset by a corresponding decrease to Pepco’s regulatory assets. Further reductions to the corporate tax rate beyond 2015 will depend upon future revenue projections for the District of Columbia.
Delmarva Power & Light Co/De [Member]
Income Taxes	(10) INCOME TAXES
	A reconciliation of DPL’s effective income tax rates is as follows:
		Three Months Ended March 31,
		2015					2014
		(millions of dollars)
	Income tax at Federal statutory rate	$	19		35	%	$	22		35	%
	Increases (decreases) resulting from:
	State income taxes, net of Federal effect		3		5.7	%		3		4.8	%
	Other, net		(1	)	(1.1	)%		—		0.5	%
	Income tax expense	$	21		39.6	%	$	25		40.3	%
	DPL’s effective tax rates for the three months ended March 31, 2015 and 2014 were 39.6% and 40.3%, respectively.
Atlantic City Electric Co [Member]
Income Taxes	(9) INCOME TAXES
	A reconciliation of ACE’s consolidated effective income tax rates is as follows:
		Three Months Ended
		March 31,
		2015					2014
		(millions of dollars)
	Income tax at Federal statutory rate	$	2		35	%	$	6		35	%
	Increases (decreases) resulting from:
	Other, net		—		(1.7	)%		—		2.5	%
	Consolidated income tax expense	$	2		33.3	%	$	6		37.5	%
	ACE’s consolidated effective tax rates for the three months ended March 31, 2015 and 2014 were 33.3% and 37.5%, respectively.

Equity_and_Earnings_Per_Share

Equity and Earnings Per Share	3 Months Ended
	Mar. 31, 2015
Earnings Per Share [Abstract]
Equity and Earnings Per Share	(11) EQUITY AND EARNINGS PER SHARE
	Basic and Diluted Earnings Per Share
	PHI’s basic and diluted earnings per share (EPS) calculations are shown below:
		Three Months Ended
		March 31,
		2015		2014
		(millions of
		dollars, except
		per share data)
	Income (Numerator):
	Net Income	$	53	$	75
	Shares (Denominator) (in millions):
	Weighted average shares outstanding for basic computation:
	Average shares outstanding		253		250
	Adjustment to shares outstanding		—		1
	Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		253		251
	Net effect of potentially dilutive shares		—		—
	Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		253		251
	Basic and Diluted Earnings per Share
	Basic and diluted earnings per share	$	0.21	$	0.3

Preferred_Stock

Preferred Stock	3 Months Ended
	Mar. 31, 2015
Equity [Abstract]
Preferred Stock	(12) PREFERRED STOCK
	In connection with entering into the Merger Agreement (as further described in Note (1), “Organization”), PHI entered into a Subscription Agreement with Exelon, dated April 29, 2014, pursuant to which PHI issued to Exelon 9,000 originally issued shares of Preferred Stock for a purchase price of $90 million on April 30, 2014. In connection with these agreements, Exelon also committed to purchase 1,800 originally issued shares of Preferred Stock for a purchase price of $18 million at the end of each 90-day period following April 29, 2014, up to a maximum of 18,000 shares of Preferred Stock for a maximum aggregate consideration of $180 million. In accordance with the Subscription Agreement, on each of July 29, 2014, October 27, 2014, January 26, 2015 and April 27, 2015, an additional 1,800 shares of Preferred Stock were issued by PHI to Exelon for a purchase price of $18 million. If the Merger closes or terminates for any reason, no additional shares of Preferred Stock will be issued pursuant to the Subscription Agreement. The holders of the Preferred Stock will be entitled to receive a cumulative, non-participating cash dividend of 0.1% per annum, payable quarterly, when, as and if declared by PHI’s board of directors. The proceeds from the issuance of the Preferred Stock are not subject to restrictions and are intended to serve as a prepayment of any applicable reverse termination fee payable from Exelon to PHI. The Preferred Stock will be redeemable on the terms and in the circumstances set forth in the Merger Agreement and the Subscription Agreement.
	If the Merger Agreement is terminated due to a Regulatory Termination, PHI will be able to redeem any issued and outstanding Preferred Stock at par value. If the Merger Agreement is terminated for any other reason, PHI will be required to redeem all issued and outstanding Preferred Stock at the purchase price of $10,000 per share, plus any unpaid accrued and accumulated dividends thereupon.
	PHI has excluded the Preferred Stock from equity at March 31, 2015 and December 31, 2014, since the Preferred Stock contains conditions for redemption that are not solely within the control of PHI. Management determined that the Preferred Stock contains embedded features requiring separate accounting consideration to reflect the potential value to PHI that any issued and outstanding Preferred Stock could be called and redeemed at a nominal par value upon a Regulatory Termination. The embedded call and redemption features on the shares of the Preferred Stock in the event of a Regulatory Termination are separately accounted for as derivatives. The estimated fair value of the derivatives related to the Preferred Stock was $3 million and has been included in current assets (Prepaid expenses and other) with a corresponding increase in Preferred Stock on the consolidated balance sheet at March 31, 2015 and December 31, 2014, representing an increase in the fair value of the Preferred Stock as of each date. These Preferred Stock derivatives are valued at each reporting date using quantitative and qualitative factors, including management’s assessment of the likelihood of a Regulatory Termination. There was no material change in the fair value of these derivatives during the first quarter of 2015. The fair value of these derivatives will be determined quarterly, and any increases or decreases in such fair value in future periods would be recorded as income or loss.

Derivative_Instruments_and_Hed

Derivative Instruments and Hedging Activities	3 Months Ended
	Mar. 31, 2015
Derivative Instruments and Hedging Activities	(13) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
	DPL uses derivative instruments in the form of futures primarily to reduce natural gas commodity price volatility and to limit its customers’ exposure to increases in the market price of natural gas under a hedging program approved by the DPSC. DPL uses these derivatives to manage the commodity price risk associated with its physical natural gas purchase contracts. The natural gas purchase contracts qualify as normal purchases, which are not required to be recorded in the financial statements until settled. All premiums paid and other transaction costs incurred as part of 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. In addition, included in derivative assets are PHI Preferred Stock derivatives which are further described in Note (12), “Preferred Stock.”
	The tables below identify the balance sheet location and fair values of derivative instruments as of March 31, 2015 and December 31, 2014:
			As of March 31, 2015
	Balance Sheet Caption		Derivatives			Other				Gross			Effects of		Net
			Designated			Derivative				Derivative			Cash		Derivative
			as Hedging			Instruments				Instruments			Collateral		Instruments
			Instruments										and
													Netting
			(millions of dollars)
	Derivative assets (current assets)		$	—		$	3			$	3		$	—	$	3
	Derivative liabilities (current liabilities)			—			(2	)			(2	)		2		—
	Net Derivative asset		$	—		$	1			$	1		$	2	$	3
			As of December 31, 2014
	Balance Sheet Caption		Derivatives			Other				Gross			Effects of		Net
			Designated			Derivative				Derivative			Cash		Derivative
			as Hedging			Instruments				Instruments			Collateral		Instruments
			Instruments										and
													Netting
			(millions of dollars)
	Derivative assets (current assets)		$	—		$	3			$	3		$	—	$	3
	Derivative liabilities (current liabilities)			—			(4	)			(4	)		4		—
	Net Derivative (liability) asset		$	—		$	(1	)		$	(1	)	$	4	$	3
	All derivative assets and liabilities available to be offset under master netting arrangements were netted as of March 31, 2015 and December 31, 2014. The amount of cash collateral that was offset against these derivative positions is as follows:
			March 31,			December 31,
			2015			2014
			(millions of dollars)
	Cash collateral pledged to counterparties with the right to reclaim (a)		$	2		$	4
	(a)	Includes cash deposits on commodity brokerage accounts.
	As of March 31, 2015 and December 31, 2014, all PHI cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements.
	Derivatives Designated as Hedging Instruments
	Cash Flow Hedges Included in Accumulated Other Comprehensive Loss
	PHI also may use derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt issued in connection with the operation of its businesses. In June 2002, PHI entered into several treasury rate lock transactions in anticipation of the issuance of several series of fixed-rate debt commencing in August 2002. Upon issuance of the fixed-rate debt in August 2002, the treasury rate locks were terminated at a loss. The loss has been deferred in Accumulated Other Comprehensive Loss (AOCL) and is being recognized in interest expense over the life of the debt issued as interest payments are made.
	The tables below provide details regarding terminated cash flow hedges included in PHI’s consolidated balance sheets as of March 31, 2015 and 2014. The data in the following tables indicate the cumulative net loss after-tax related to terminated 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:
	Contracts		As of March 31, 2015							Maximum
			Accumulated			Portion Expected				Term
			Other			to be Reclassified
			Comprehensive Loss			to Income during
			After-tax			the Next 12 Months
			(millions of dollars)
	Interest rate		$	9		$	1			209 months
	Total		$	9		$	1
	Contracts		As of March 31, 2014							Maximum
			Accumulated			Portion Expected				Term
			Other			to be Reclassified
			Comprehensive Loss			to Income during
			After-tax			the Next 12 Months
			(millions of dollars)
	Interest rate		$	9		$	1			221 months
	Total		$	9		$	1
	Other Derivative Activity
	DPL has certain derivatives that are not in hedge accounting relationships and are not designated as normal purchases or normal sales. These derivatives are recorded at fair value on the consolidated balance sheets with the gain or loss for changes in fair value recorded in income. In addition, in accordance with FASB guidance on regulated operations, regulatory liabilities or regulatory assets of the same amount 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 DPL’s derivatives. The following table shows the net unrealized and net realized derivative gains and losses arising during the period associated with these derivatives that were recognized in the consolidated statements of income (through Fuel and purchased energy expense) and that were also deferred as Regulatory liabilities and Regulatory assets for the three months ended March 31, 2015 and 2014:
			Three Months Ended
			March 31,
			2015			2014
			(millions of dollars)
	Net unrealized (loss) gain arising during the period		$	(1	)	$	2
	Net realized (loss) gain recognized during the period			(3	)		2
	As of March 31, 2015 and December 31, 2014, the quantities and positions of DPL’s net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting were:
			March 31, 2015					December 31, 2014
	Commodity		Quantity			Net Position		Quantity				Net Position
	DPL – Natural gas (One Million British Thermal Units)			2,997,500		Long			3,892,500			Long
	In addition, PHI recorded derivative assets for the embedded call and redemption features on the shares of Preferred Stock as further described in Note (12), “Preferred Stock.”
Delmarva Power & Light Co/De [Member]
Derivative Instruments and Hedging Activities	(11) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
	DPL uses derivative instruments in the form of futures primarily to reduce natural gas commodity price volatility and to limit its customers’ exposure to increases in the market price of natural gas under a hedging program approved by the DPSC. DPL uses these derivatives to manage the commodity price risk associated with its physical natural gas purchase contracts. The natural gas purchase contracts qualify as normal purchases, which are not required to be recorded in the financial statements until settled. All premiums paid and other transaction costs incurred as part of 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, 2015 and December 31, 2014:
			As of March 31, 2015
	Balance Sheet Caption		Derivatives			Other				Gross			Effects of		Net
			Designated			Derivative				Derivative			Cash		Derivative
			as Hedging			Instruments				Instruments			Collateral		Instruments
			Instruments										and
													Netting
			(millions of dollars)
	Derivative liabilities (current liabilities)		$	—		$	(2	)		$	(2	)	$	2	$	—
			As of December 31, 2014
	Balance Sheet Caption		Derivatives			Other				Gross			Effects of		Net
			Designated			Derivative				Derivative			Cash		Derivative
			as Hedging			Instruments				Instruments			Collateral		Instruments
			Instruments										and
													Netting
			(millions of dollars)
	Derivative liabilities (current liabilities)		$	—		$	(4	)		$	(4	)	$	4	$	—
	All derivative assets and liabilities available to be offset under master netting arrangements were netted as of March 31, 2015 and December 31, 2014. The amount of cash collateral that was offset against these derivative positions is as follows:
			March 31,			December 31,
			2015			2014
			(millions of dollars)
	Cash collateral pledged to counterparties with the right to reclaim (a)		$	2		$	4
	(a)	Includes cash deposits on commodity brokerage accounts.
	As of March 31, 2015 and December 31, 2014, all DPL cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements.
	Other Derivative Activity
	DPL has 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 fair value recorded in income. In addition, in accordance with FASB guidance on regulated operations, regulatory liabilities or regulatory assets of the same amount 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. The following table shows the net unrealized and net realized derivative gains and losses arising during the period associated with these derivatives that were recognized in the statements of income (through Purchased energy and Gas purchased expense) and that were also deferred as Regulatory liabilities and Regulatory assets, respectively, for the three months ended March 31, 2015 and 2014:
			Three Months Ended
			March 31,
			2015			2014
			(millions of dollars)
	Net unrealized (loss) gain arising during the period		$	(1	)	$	2
	Net realized (loss) gain recognized during the period			(3	)		2
	As of March 31, 2015 and December 31, 2014, the quantities and positions of DPL’s net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting were:
			March 31, 2015							December 31, 2014
	Commodity		Quantity			Net Position				Quantity			Net Position
	Natural gas (One Million British Thermal Units)			2,997,500			Long				3,892,500			Long

Fair_Value_Disclosures

Fair Value Disclosures	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures	(14) FAIR VALUE DISCLOSURES
	Financial Instruments Measured at Fair Value on a Recurring Basis
	PHI applies FASB guidance on fair value measurement (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 that were accounted for at fair value on a recurring basis as of March 31, 2015 and December 31, 2014. 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, 2015
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1) (a)			(Level 2) (a)
			(millions of dollars)
	ASSETS
	Derivative instruments
	Preferred stock		$	3		$	—		$	—		$	3
	Cash equivalents and restricted cash equivalents
	Treasury fund			143			143			—			—
	Executive deferred compensation plan assets
	Money market funds and short-term investments			35			15			20			—
	Life insurance contracts			46			—			27			19
	Total		$	227		$	158		$	47		$	22
	LIABILITIES
	Derivative instruments (b)
	Natural gas (c)		$	2		$	2		$	—		$	—
	Executive deferred compensation plan liabilities
	Life insurance contracts			30			—			30			—
	Total		$	32		$	2		$	30		$	—
	(a)	There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2015.
	(b)	The fair values of derivative liabilities reflect netting by counterparty before the impact of collateral.
	(c)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.
			Fair Value Measurements at December 31, 2014
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1) (a)			(Level 2) (a)
			(millions of dollars)
	ASSETS
	Derivative instruments
	Preferred stock		$	3		$	—		$	—		$	3
	Restricted cash equivalents
	Treasury fund			38			38			—			—
	Executive deferred compensation plan assets
	Money market funds and short-term investments			35			14			21			—
	Life insurance contracts			46			—			27			19
	Total		$	122		$	52		$	48		$	22
	LIABILITIES
	Derivative instruments (b)
	Natural gas (c)		$	4		$	4		$	—		$	—
	Executive deferred compensation plan liabilities
	Life insurance contracts			30			—			30			—
	Total		$	34		$	4		$	30		$	—
	(a)	There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.
	(b)	The fair values of derivative liabilities reflect netting by counterparty before the impact of collateral.
	(c)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.
	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 Intercontinental Exchange.
	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.
	Executive deferred compensation plan assets and liabilities categorized as level 2 consist of life insurance policies and certain employment agreement obligations. The life insurance policies are categorized as level 2 assets because they are valued based on the assets underlying the policies, which consist of short-term cash equivalents and fixed income securities that are priced using observable market data and can be liquidated for the value of the underlying assets as of March 31, 2015. 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 (which are included with life insurance contracts in the tables above) is derived using a discounted cash flow valuation technique. The discounted cash flow calculations are based on a known and certain stream of payments to be made over time that are discounted to determine their net present value. The primary variable input, the discount rate, is based on market-corroborated and observable published rates. These obligations have been classified as level 2 within the fair value hierarchy because the payment streams represent contractually known and certain amounts and the discount rate is based on published, observable data.
	Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.
	Derivative instruments classified as level 3 include embedded call and redemption features on the Preferred Stock as further discussed in Note (12), “Preferred Stock.”
	Executive deferred compensation plan assets 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 months ended March 31, 2015 and 2014 are shown below:
			Three Months Ended						Three Months Ended
March 31, 2015					March 31, 2014
		Preferred			Life			Life
		Stock			Insurance			Insurance
					Contracts			Contracts
		(millions of dollars)
Beginning balance as of January 1		$	3		$	19		$	19
Total gains (losses) (realized and unrealized):
Included in income			—			1			1
Included in accumulated other comprehensive loss			—			—			—
Included in regulatory liabilities			—			—			—
Purchases			—			—			—
Issuances			—			—			(1	)
Settlements			—			(1	)		—
Transfers in (out) of level 3			—			—			—
Ending balance as of March 31		$	3		$	19		$	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:
		Three Months Ended March 31,
		2015			2014
		(millions of dollars)
Total net gains included in income for the period		$	1		$	1
Change in unrealized gains relating to assets still held at reporting date		$	1		$	1
Other Financial Instruments
The estimated fair values of PHI’s Long-term debt instruments that are measured at amortized cost in PHI’s consolidated financial statements and the associated levels of the estimates within the fair value hierarchy as of March 31, 2015 and December 31, 2014 are shown in the tables 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 and Transition bonds issued by ACE Funding (Transition Bonds) categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers, and PHI reviews the methodologies and results.
The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient. The Long-term project funding represents debt instruments issued by Pepco and Pepco Energy Services related to its energy savings and construction contracts. Long-term project funding is categorized as level 3 because PHI concluded that the amortized cost carrying amounts for these instruments approximates fair value, which does not represent a quoted price in an active market.
		Fair Value Measurements at March 31, 2015
Description		Total			Quoted Prices in			Significant			Significant
					Active Markets			Other			Unobservable
					for Identical			Observable			Inputs
					Instruments			Inputs			(Level 3)
					(Level 1)			(Level 2)
		(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)		$	5,871		$	1,890		$	3,524		$	457
Transition Bonds (b)			224			—			224			—
Long-term project funding			10			—			—			10
Total		$	6,105		$	1,890		$	3,748		$	467
(a)	The carrying amount for Long-term debt was $5,015 million as of March 31, 2015.
(b)	The carrying amount for Transition Bonds, including amounts due within one year, was $203 million as of March 31, 2015.
		Fair Value Measurements at December 31, 2014
Description		Total			Quoted Prices in			Significant			Significant
					Active Markets			Other			Unobservable
					for Identical			Observable			Inputs
					Instruments			Inputs			(Level 3)
					(Level 1)			(Level 2)
		(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)		$	5,583		$	—		$	5,136		$	447
Transition Bonds (b)			235			—			235			—
Long-term project funding			28			—			—			28
Total		$	5,846		$	—		$	5,371		$	475
(a)	The carrying amount for Long-term debt was $4,807 million as of December 31, 2014.
(b)	The carrying amount for Transition Bonds, including amounts due within one year, was $215 million as of December 31, 2014.
The carrying amounts of all other financial instruments in the accompanying consolidated financial statements approximate fair value.
Potomac Electric Power Co [Member]
Fair Value Disclosures	(10) FAIR VALUE DISCLOSURES
	Financial Instruments Measured at Fair Value on a Recurring Basis
	Pepco applies FASB guidance on fair value measurement (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, 2015 and December 31, 2014. 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, 2015
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1) (a)			(Level 2) (a)
			(millions of dollars)
	ASSETS
	Cash equivalents and restricted cash equivalents
	Treasury fund		$	116		$	116		$	—		$	—
	Executive deferred compensation plan assets
	Money market funds and short-term investments			34			14			20			—
	Life insurance contracts			42			—			23			19
	Total		$	192		$	130		$	43		$	19
	LIABILITIES
	Executive deferred compensation plan liabilities
	Life insurance contracts		$	6		$	—		$	6		$	—
	Total		$	6		$	—		$	6		$	—
	(a)	There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2015.
			Fair Value Measurements at December 31, 2014
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1) (a)			(Level 2) (a)
			(millions of dollars)
	ASSETS
	Restricted cash equivalents
	Treasury fund		$	5		$	5		$	—		$	—
	Executive deferred compensation plan assets
	Money market funds and short-term investments			34			13			21			—
	Life insurance contracts			41			—			23			18
	Total		$	80		$	18		$	44		$	18
	LIABILITIES
	Executive deferred compensation plan liabilities
	Life insurance contracts		$	7		$	—		$	7		$	—
	Total		$	7		$	—		$	7		$	—
	(a)	There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.
	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:
	Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
	Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable 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.
	Executive deferred compensation plan assets and liabilities categorized as level 2 consist of life insurance policies and certain employment agreement obligations. The life insurance policies are categorized as level 2 assets because they are valued based on the assets underlying the policies, which consist of short-term cash equivalents and fixed income securities that are priced using observable market data and can be liquidated for the value of the underlying assets as of March 31, 2015. 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 (which are included with life insurance contracts in the tables above) is derived using a discounted cash flow valuation technique. The discounted cash flow calculations are based on a known and certain stream of payments to be made over time that are discounted to determine their net present value. The primary variable input, the discount rate, is based on market-corroborated and observable published rates. These obligations have been classified as level 2 within the fair value hierarchy because the payment streams represent contractually known and certain amounts and the discount rate is based on published, observable data.
	Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.
	Executive deferred compensation plan assets 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 Pepco for reasonableness.
	Reconciliations of the beginning and ending balances of Pepco’s fair value measurements using significant unobservable inputs (level 3) for the three months ended March 31, 2015 and 2014 are shown below:
			Life Insurance Contracts
			Three Months Ended
			March 31,
			2015			2014
			(millions of dollars)
	Beginning balance as of January 1		$	18		$	18
	Total gains (losses) (realized and unrealized):
	Included in income			1			1
	Included in accumulated other comprehensive loss			—			—
	Purchases			—			—
	Issuances			—			(1	)
	Settlements			—			—
	Transfers in (out) of level 3			—			—
	Ending balance as of March 31		$	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,
		2015			2014
		(millions of dollars)
Total gains included in income for the period		$	1		$	1
Change in unrealized gains relating to assets still held at reporting date		$	1		$	1
Other Financial Instruments
The estimated fair values of Pepco’s Long-term debt instruments that are measured at amortized cost in Pepco’s financial statements and the associated levels of the estimates within the fair value hierarchy as of March 31, 2015 and December 31, 2014 are shown in the tables 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 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt 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 Project funding represents debt instruments issued by Pepco related to its construction contracts. Project funding is categorized as level 3 because PHI concluded that the amortized cost carrying amounts for these instruments approximate fair value, which does not represent a quoted price in an active market.
		Fair Value Measurements at March 31, 2015
Description		Total			Quoted Prices in			Significant			Significant
					Active Markets			Other			Unobservable
					for Identical			Observable			Inputs
					Instruments			Inputs			(Level 3)
					(Level 1)			(Level 2)
		(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)		$	2,884		$	1,624		$	1,260		$	—
(a)	The carrying amount for Long-term debt was $2,332 million as of March 31, 2015.
		Fair Value Measurements at December 31, 2014
Description		Total			Quoted Prices in			Significant			Significant
					Active Markets			Other			Unobservable
					for Identical			Observable			Inputs
					Instruments			Inputs			(Level 3)
					(Level 1)			(Level 2)
		(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)		$	2,624		$	—		$	2,624		$	—
Project funding			12			—			—			12
Total		$	2,636		$	—		$	2,624		$	12
(a)	The carrying amount for Long-term debt was $2,124 million as of December 31, 2014.
The carrying amounts of all other financial instruments in the accompanying financial statements approximate fair value.
Delmarva Power & Light Co/De [Member]
Fair Value Disclosures	(12) FAIR VALUE DISCLOSURES
	Financial Instruments Measured at Fair Value on a Recurring Basis
	DPL applies FASB guidance on fair value measurement (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, 2015 and December 31, 2014. 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, 2015
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1) (a)			(Level 2) (a)
			(millions of dollars)
	ASSETS
	Executive deferred compensation plan assets
	Money market funds		$	1		$	1		$	—		$	—
	Total		$	1		$	1		$	—		$	—
	LIABILITIES
	Derivative instruments (b)
	Natural gas (c)		$	2		$	2		$	—		$	—
	Executive deferred compensation plan liabilities
	Life insurance contracts			1			—			1			—
	Total		$	3		$	2		$	1		$	—
	(a)	There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2015.
	(b)	The fair value of derivative liabilities reflect netting by counterparty before the impact of collateral.
	(c)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.
			Fair Value Measurements at December 31, 2014
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1) (a)			(Level 2) (a)
			(millions of dollars)
	ASSETS
	Restricted cash equivalents
	Treasury funds		$	5		$	5		$	—		$	—
	Executive deferred compensation plan assets
	Money market funds			1			1			—			—
	Life insurance contracts			1			—			—			1
	Total		$	7		$	6		$	—		$	1
	LIABILITIES
	Derivative instruments (b)		$	4		$	4		$	—		$	—
	Natural gas (c)
	Executive deferred compensation plan liabilities
	Life insurance contracts			1			—			1			—
	Total		$	5		$	4		$	1		$	—
	(a)	There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.
	(b)	The fair value of derivative liabilities reflect netting by counterparty before the impact of collateral.
	(c)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.
	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:
	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 Intercontinental Exchange.
	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.
	Level 2 executive deferred compensation plan liabilities associated with the life insurance policies represent 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.
	Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.
	Executive deferred compensation plan assets 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 DPL for reasonableness.
	Reconciliations of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (level 3) for the three months ended March 31, 2015 and 2014 are shown below:
			Three Months Ended			Three Months Ended
			March 31, 2015			March 31, 2014
			Life			Life
			Insurance			Insurance
			Contracts			Contracts
			(millions of dollars)
	Balance as of January 1		$	1		$	1
	Total gains (losses) (realized and unrealized):
	Included in income			—			—
	Included in accumulated other comprehensive loss			—			—
Included in regulatory liabilities			—			—
Purchases			—			—
Issuances			—			—
Settlements			(1	)		—
Transfers in (out) of Level 3			—			—
Balance as of March 31		$	—		$	1
Other Financial Instruments
The estimated fair values of DPL’s Long-term debt instruments that are measured at amortized cost in DPL’s financial statements and the associated levels of the estimates within the fair value hierarchy as of March 31, 2015 and December 31, 2014 are shown in the tables 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 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt 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 DPL 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.
		Fair Value Measurements at March 31, 2015
Description		Total			Quoted Prices in			Significant			Significant
					Active Markets			Other			Unobservable
					for Identical			Observable			Inputs
					Instruments			Inputs			(Level 3)
					(Level 1)			(Level 2)
		(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)		$	1,139		$	15		$	1,017		$	107
(a)	The carrying amount for Long-term debt was $1,071 million as of March 31, 2015.
		Fair Value Measurements at December 31, 2014
Description		Total			Quoted Prices in			Significant			Significant
					Active Markets			Other			Unobservable
					for Identical			Observable			Inputs
					Instruments			Inputs			(Level 3)
					(Level 1)			(Level 2)
		(millions of dollars)
LIABILITIES
Debt instruments
Long-term debt (a)		$	1,123		$	—		$	1,016		$	107
(a)	The carrying amount for Long-term debt was $1,071 million as of December 31, 2014.
The carrying amounts of all other financial instruments in the accompanying consolidated financial statements approximate fair value.
Atlantic City Electric Co [Member]
Fair Value Disclosures	(10) FAIR VALUE DISCLOSURES
	Financial Instruments Measured at Fair Value on a Recurring Basis
	ACE applies FASB guidance on fair value measurement (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, 2015 and December 31, 2014. 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, 2015
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1) (a)			(Level 2) (a)
			(millions of dollars)
	ASSETS
	Restricted cash equivalents
	Treasury fund		$	24		$	24		$	—		$	—
	(a)	There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2015.
			Fair Value Measurements at December 31, 2014
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1) (a)			(Level 2) (a)
			(millions of dollars)
	ASSETS
	Restricted cash equivalents
	Treasury fund		$	24		$	24		$	—		$	—
	(a)	There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.
	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:
	Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
	Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable 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.
	Level 3 – Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.
	Other Financial Instruments
	The estimated fair values of ACE’s Long-term debt instruments that are measured at amortized cost in ACE’s consolidated financial statements and the associated levels of the estimates within the fair value hierarchy as of March 31, 2015 and December 31, 2014 are shown in the tables 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 and Transition bonds issued by ACE Funding (Transition Bonds) categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt 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 ACE 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.
			Fair Value Measurements at March 31, 2015
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1)			(Level 2)
			(millions of dollars)
	LIABILITIES
	Debt instruments
	Long-term debt (a)		$	1,049		$	—		$	905		$	144
	Transition Bonds (b)			224			—			224			—
	Total		$	1,273		$	—		$	1,129		$	144
	(a)	The carrying amount for Long-term debt was $903 million as of March 31, 2015.
	(b)	The carrying amount for Transition Bonds, including amounts due within one year, was $203 million as of March 31, 2015.
			Fair Value Measurements at December 31, 2014
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1)			(Level 2)
			(millions of dollars)
	LIABILITIES
	Debt instruments
	Long-term debt (a)		$	1,035		$	—		$	903		$	132
	Transition Bonds (b)			235			—			235			—
	Total		$	1,270		$	—		$	1,138		$	132
	(a)	The carrying amount for Long-term debt was $903 million as of December 31, 2014.
	(b)	The carrying amount for Transition Bonds, including amounts due within one year, was $215 million as of December 31, 2014.
	The carrying amounts of all other financial instruments in the accompanying consolidated financial statements approximate fair value.

Commitments_and_Contingencies

Commitments and Contingencies

3 Months Ended

Mar. 31, 2015

Commitments and Contingencies

(15) COMMITMENTS AND CONTINGENCIES

General Litigation and Other Matters

From time to time, PHI and its subsidiaries are named as defendants in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. PHI and each of its subsidiaries are self-insured against such claims up to a certain self-insured retention amount and maintain insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, PHI’s contracts with its vendors generally require the vendors to name PHI and/or its subsidiaries as additional insureds for the amounts at least equal to PHI’s self-insured retention. Further, PHI’s contracts with its vendors require the vendors to indemnify PHI for various acts and activities that may give rise to claims against PHI. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on PHI’s or its subsidiaries’ financial condition, results of operations or cash flows. At March 31, 2015, PHI had recorded estimated loss contingency liabilities for general litigation totaling approximately $22 million (including amounts related to the matters specifically described below), and the portion of these estimated loss contingency liabilities in excess of the self-insured retention amount was substantially offset by estimated insurance receivables.

Pepco Substation Injury Claim

In May 2013, a worker employed by a subcontractor to erect a scaffold at a Pepco substation came into contact with an energized transformer and suffered serious injuries. In August 2013, the individual filed suit against Pepco in the Circuit Court for Montgomery County, Maryland, seeking damages for past and future medical expenses, past and future lost wages, pain and suffering and the cost of a life care plan. On October 22, 2014, an award of approximately $21.7 million was entered in favor of the plaintiff in this matter. On March 10, 2015, Pepco and the insurers entered into a confidential settlement with the plaintiff for the payment of a lesser amount than the award. Pepco’s insurer and the contractor’s insurer together provided insurance coverage for the entirety of this liability, including coverage of Pepco’s self-insured retention amount.

ACE Asbestos Claim

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. 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 March 31, 2015, ACE has concluded that a loss is probable with respect to this matter and has recorded an estimated loss contingency liability, which is included in the liability for general litigation referred to above as of March 31, 2015. However, due to the inherent uncertainty of litigation, ACE is unable to estimate a maximum amount of possible loss because the damages sought are indeterminate and 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.

Pepco Energy Services Billing Claims

During 2012, Pepco Energy Services received letters on behalf of two school districts in Maryland, which claim that they had paid invoices in connection with electricity supply contracts that included certain allegedly unauthorized charges, totaling approximately $7 million, for which they were entitled to reimbursement. The school districts also claim additional compounded interest totaling approximately $9 million. In August and September 2013, Pepco Energy Services received correspondence from the Superintendent of each of the school districts advising of the intention to render a decision regarding an unresolved dispute between the school district and Pepco Energy Services. Pepco Energy Services has disputed not only the Superintendents’ authority to render decisions on the claims, but also the merits of the allegations regarding unauthorized charges and all claims of entitlement to compounded interest.

With respect to the claim of the first school district, in July 2014 its Superintendent determined that Pepco Energy Services should reimburse the allegedly unauthorized charges related to that district, totaling approximately $3 million, but rejected the school district’s claim for interest (representing $4 million of the $9 million of total compounded interest originally claimed by both school districts), which was sustained in November 2014 by a vote of that district’s Board of Education. In December 2014, Pepco Energy Services appealed the district Board of Education’s decision to the Maryland State Board of Education. By stipulation dated January 21, 2015, the parties agreed that the dispute may be resolved pursuant to provisions of Maryland law allowing full judicial review. This matter has been resolved in April 2015 through a confidential settlement between the parties. The resolution of this matter did not have a material adverse effect on the financial condition, results of operations or cash flows of PHI or Pepco Energy Services.

With respect to the claim of the second school district, the Superintendent of that district has acknowledged the availability of administrative and judicial review of the merits of any decision but has not taken any action on this matter since 2013. As of March 31, 2015, Pepco Energy Services has concluded that a loss is reasonably possible, but the amount of loss, if any, would likely be immaterial.

Environmental Matters

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 described below of PHI and its subsidiaries at March 31, 2015 are summarized as follows:

Legacy Generation

Transmission

Regulated

Non-

Total

and Distribution

Regulated

(millions of dollars)

Beginning balance as of January 1

$

17

$

6

$

5

$

28

Accruals

1

—

—

1

Payments

—

1

—

1

Ending balance as of March 31

18

5

5

28

Less amounts in Other Current Liabilities

3

1

—

4

Amounts in Other Deferred Credits

$

15

$

4

$

5

$

24

Conectiv Energy Wholesale Power Generation Sites

In July 2010, PHI sold the wholesale power generation business of Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries (Conectiv Energy) to Calpine Corporation (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 PHI’s 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 in the column entitled “Legacy Generation – Non-Regulated.”

In September 2011, PHI received a request for data from the U.S. Environmental Protection Agency (EPA) regarding operations at the Deepwater generating facility in New Jersey (which was included in the sale to Calpine) between February 2004 and July 1, 2010, to demonstrate compliance with the Clean Air Act’s new source review permitting program. PHI responded to the data request. Under the terms of the Calpine sale, PHI is obligated to indemnify Calpine for any failure of PHI, on or prior to the closing date of the sale, to comply with environmental laws attributable to the construction of new, or modification of existing, sources of air emissions. At this time, PHI does not expect this inquiry to have a material adverse effect on its consolidated financial condition, results of operations or cash flows.

Franklin Slag Pile Site

In November 2008, ACE received a general notice letter from EPA concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party (PRP) that may have liability for clean-up costs with respect to the site and for the costs of implementing an EPA-mandated remedy. 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’s feasibility study for this site conducted in 2007 identified a range of alternatives for permanent remedial measures with varying cost estimates, and the estimated cost of EPA’s preferred alternative is approximately $6 million.

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.

Peck Iron and Metal Site

EPA informed Pepco in a May 2009 letter that Pepco may be a PRP under CERCLA with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, and for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that the Peck Iron and 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 September 2011, EPA initiated a remedial investigation/feasibility study (RI/FS) for the site using federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with this RI/FS, any remediation activities to be performed at the site or any other costs that EPA might seek to impose on Pepco.

Ward Transformer Site

In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including Pepco, DPL and ACE, based on their alleged sale of transformers to Ward Transformer, with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants’ motion to dismiss. The litigation is moving forward with certain “test case” defendants (not including Pepco, DPL and ACE) filing summary judgment motions regarding liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the Federal district court granted summary judgment for the test case defendant whom plaintiffs alleged was liable based on its sale of transformers to Ward Transformer. The Federal district court’s order addresses only the liability of the test case defendant. Plaintiffs appealed the district court’s order to the U.S. Court of Appeals for the Fourth Circuit. On March 20, 2015, the Fourth Circuit affirmed the district court’s summary judgment decision for the sales test case defendant and on April 17, 2015, the Fourth Circuit denied the plaintiffs’ petition for rehearing en banc. PHI has concluded that a loss is reasonably possible with respect to this matter, but is unable to 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.

Benning Road Site

Contamination of Lower Anacostia River

In September 2010, PHI received a letter from EPA identifying the Benning Road location, consisting of a generation facility formerly operated by Pepco Energy Services, and a transmission and distribution service center facility operated by Pepco, as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. The generation facility was deactivated in June 2012 and the plant structures are being demolished, but the service center remains in operation. The principal contaminants allegedly of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the District of Columbia Department of the Environment (DDOE), which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 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. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DDOE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site.

The remedial investigation field work began in January 2013 and was completed in December 2014. In addition, in conjunction with the power plant demolition activities, Pepco and Pepco Energy Services collected soil samples adjacent to and beneath the concrete basins for the cooling towers previously dismantled and removed from the site of the generating facility. This sampling showed localized areas of soil contamination associated with the cooling tower basins, and Pepco has submitted a plan to DDOE for the removal of contaminated soil in conjunction with the demolition and removal of the concrete basins. Having completed the remedial investigation field sampling, Pepco and Pepco Energy Services currently are drafting RI/FS reports for review and approval by DDOE after solicitation and consideration of public comment. The next status report to the court is due on May 25, 2015.

The remediation costs accrued for this matter are included in the table above in the columns entitled “Transmission and Distribution,” “Legacy Generation – Regulated,” and “Legacy Generation – Non-Regulated.”

NPDES Permit Limit Exceedances

Pepco holds a National Pollutant Discharge Elimination System (NPDES) permit issued by EPA with a June 19, 2009 effective date, which authorizes discharges from the Benning Road facility, including the Pepco Energy Services generating facility that was deactivated in 2012 and is being demolished. The 2009 permit imposed compliance monitoring and storm water best management practices to satisfy the District of Columbia’s Total Maximum Daily Load (TMDL) standards for polychlorinated biphenyls, oil and grease, metals and other substances. As part of the implementation of the TMDL requirements, the permit also imposed numerical limits on certain substances in storm water discharges to the Anacostia River. Quarterly monitoring results since the issuance of the permit have shown consistent exceedances of the limits for copper and zinc, as well as occasional exceedances for iron and lead (and, more recently, pH). As required by the permit, Pepco initiated a study to identify the potential sources or causes of these exceedances at the site and to determine appropriate best management practices for achieving compliance with the permit limits. The initial study was completed in May 2012. Pepco has completed the implementation of the first two phases of the best management practices recommended in the study report (consisting principally of installing metal absorbing filters to capture contaminants from storm water flows, removing stored equipment from areas exposed to the weather, covering and painting exposed metal pipes, and covering and cleaning dumpsters). These measures have been effective in reducing metal concentrations in stormwater discharges; however, additional measures will be required to be implemented by Pepco to reduce the concentrations to levels required by the permit.

The NPDES permit was due to expire on June 19, 2014. Pepco submitted a permit renewal application on December 17, 2013. In November 2014, EPA advised Pepco that it will not renew the permit until the Benning Road facility has come into compliance with the existing permit limits. The current permit remains in effect pending EPA’s action on the renewal application. Pepco has prepared a plan to implement the third phase of the best management practices recommended in the study report with the objective of achieving full compliance with the permit limits by the end of 2015. The plan was submitted to EPA on December 30, 2014, and Pepco has begun implementing those best practices in accordance with the plan. Pepco anticipates that EPA eventually may seek administrative penalties for past noncompliance with the permit limits. Whether such penalties will be imposed and, if so, the amount of any such penalties, is not known or estimable at this time. At present, Pepco expects that compliance with the permit limits can be achieved through a combination of enhanced storm drain inlet controls (filters and metal absorbing booms), enhanced site housekeeping, and enhanced inspection and maintenance of storm water controls. If these measures are not adequate to achieve compliance with the permit limits, however, it is possible that a capital project to install a storm water treatment system may be required. The need for any such capital expenditures will not be known until Pepco has implemented the third phase of the best management practices.

Indian River Oil Release

In 2001, DPL entered into a consent agreement with the Delaware Department of Natural Resources and Environmental Control for remediation, site restoration, natural resource damage compensatory projects and other costs associated with environmental contamination resulting from an oil release at the Indian River generating facility, which was sold in June 2001. The amount of remediation costs accrued for this matter is included in the table above in the column entitled “Legacy Generation – Regulated.”

Potomac River Mineral Oil Release

In January 2011, a coupling failure on a transformer cooler pipe resulted in a release of non-toxic mineral oil at 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.

In March 2014, Pepco and DDOE entered into a consent decree to resolve a threatened DDOE enforcement action, the terms of which include a combination of a civil penalty and a Supplemental Environmental Project (SEP) with a total cost to Pepco of $875,000. The consent decree was approved and entered by the District of Columbia Superior Court on April 4, 2014. Pepco has paid the $250,000 civil penalty imposed under the consent decree and, pursuant to the consent decree, has made a one-time donation in the amount of $25,000 to the Northeast Environmental Enforcement Training Fund, Inc., a non-profit organization that funds scholarships for environmental enforcement training. The consent decree confirmed that no further actions are required by Pepco to investigate, assess or remediate impacts to the river from the mineral oil release. To implement the SEP, Pepco has entered into an agreement with Living Classrooms Foundation, Inc., a non-profit educational organization, to provide $600,000 to fund the design, installation and operation of a trash collection system at a storm water outfall that drains to the Anacostia River. DDOE approved the design for the trash collection system and efforts to secure necessary permits have commenced. Pepco expects that this system will be constructed and placed into operation by the end of 2015, which will satisfy Pepco’s obligations under the consent decree. The next status hearing in this matter has been set for September 18, 2015.

The consent decree does not resolve potential claims under federal law for natural resource damages resulting from the mineral oil release. Pepco has engaged in separate discussions with DDOE and the federal resource trustees regarding the settlement of a possible natural resource damages claim under federal law. The federal trustees are still evaluating the claim and the terms of a possible settlement. At this time, it is uncertain whether or when the settlement discussions may resume or if the trustees will continue to pursue the natural resource damages claim. Based on discussions to date, PHI and Pepco do not believe that the resolution of the federal natural resource damages claim will have a material adverse effect on their respective financial condition, results of operations or cash flows.

As a result of the mineral oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility which involve pumping accumulated storm water to an above-ground 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 has approached DDOE and EPA for approval to commence operation of the new system on a pilot basis to demonstrate its effectiveness in meeting both secondary containment requirements and water quality standards related to the discharge of storm water from the facility, but to date, no such approval has been obtained. In the meantime, Pepco is continuing to use the aboveground holding tank to manage storm water from the secondary containment system. Pepco also is evaluating other technical and regulatory options for managing storm water from the secondary containment system as alternatives to the proposed treatment system currently under discussion with EPA and DDOE.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Metal Bank Site

In the first quarter of 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted Pepco and DPL on behalf of itself and other federal and state trustees to request that Pepco and DPL execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Cottman Avenue Superfund Site located in Philadelphia, Pennsylvania. Pepco and DPL executed a tolling agreement, which has been extended to March 15, 2016, and will continue settlement discussions with the NOAA, the trustees and other PRPs.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Brandywine Fly Ash Disposal Site

In February 2013, Pepco received a letter from the Maryland Department of the Environment (MDE) requesting that Pepco investigate the extent of waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000 agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule.

PHI and Pepco have determined that a loss associated with this matter for PHI and Pepco is probable and have estimated that the costs for implementation of a closure plan and cap on the site are in the range of approximately $3 million to $6 million. PHI and Pepco believe that the costs incurred in this matter will be recoverable from NRG under the 2000 sale agreement.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Virginia Department of Environmental Quality Notice of Violation

On February 3, 2015, the Virginia Department of Environmental Quality (VDEQ) issued a notice of violation (NOV) to DPL in connection with alleged violations of state water control laws and regulations associated with recent construction activities undertaken to replace certain transmission facilities. The NOV informed DPL of information on which VDEQ may rely to institute an administrative or judicial enforcement action, requested a meeting, and stated that DPL may be asked to enter into a consent order to formalize a plan and schedule of corrective action and settle any outstanding issues regarding the matter including the assessment of civil charges. At a February 20, 2015 meeting, VDEQ confirmed that the NOV would be resolved through a consent order, which will require the payment of a penalty, but did not specify the potential penalty amount. DPL will pursue recovery of the restoration costs for this matter from the contractor responsible for the vegetation management activities that gave rise to the alleged violations. PHI and DPL do not believe that the remediation costs to resolve this matter will have a material adverse effect on their respective financial condition, results of operations or cash flows.

PHI’s Cross-Border Energy Lease Investments

PHI held a portfolio of cross-border energy lease investments involving public utility assets located outside of the United States. Each of these investments was comprised of multiple leases and was structured as a sale and leaseback transaction commonly referred to by the Internal Revenue Service (IRS) as a sale-in, lease-out, or SILO, transaction. During the second and third quarters of 2013, PHI terminated early all of its remaining cross-border energy lease investments.

Since 2005, PHI’s former 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 income tax returns, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI for six of the eight lease investments and, in connection with the audits of PHI’s 2003-2005 and 2006-2008 income tax returns, the IRS disallowed such deductions in excess of rental income for all eight of the lease investments. In addition, the IRS has sought to recharacterize each of the leases as a loan transaction in each of the years under audit as to which PHI would be subject to original issue discount income. PHI has disagreed with the IRS’ proposed adjustments to the 2001-2008 income tax returns and has filed protests of these findings for each year 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 for the purpose of commencing litigation associated with this matter 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 refund claims were 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. The 2003-2005 and 2006-2011 income tax return audits continue to be in process with the IRS Office of Appeals and the IRS Exam Division, respectively, and are not presently a part of the U.S. Court of Federal Claims litigation.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which PHI is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. While PHI believed that its tax position with regard to its former cross-border energy lease investments was appropriate, after analyzing the recent U.S. Court of Appeals ruling, PHI determined in the first quarter of 2013 that its tax position with respect to the tax benefits associated with the cross-border energy leases no longer met the more-likely-than-not standard of recognition for accounting purposes. Accordingly, PHI recorded a non-cash after-tax charge of $377 million in the first quarter of 2013 consisting of a charge to reduce the carrying value of the cross-border energy lease investments and a charge to reflect the anticipated additional interest expense related to changes in PHI’s estimated federal and state income tax obligations for the period over which the tax benefits ultimately may be disallowed. PHI had also previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. During the first quarter of 2013, management believed that its conclusions regarding these business assumptions were no longer supportable, and the tax effects of this change in conclusion were included in the charge. While the IRS could require PHI to pay a penalty of up to 20% of the amount of additional taxes due, PHI believes that it is more likely than not that no such penalty will be incurred, and therefore no amount for any potential penalty has been recorded.

In the event that the IRS were to be successful in disallowing 100% of the tax benefits associated with these lease investments and recharacterize these lease investments as loans, PHI estimated that, as of March 31, 2013, it would have been obligated to pay approximately $192 million in additional federal taxes (net of the $74 million tax payment described above) and approximately $50 million of interest on the additional federal taxes. These amounts, totaling $242 million, were estimated after consideration of certain tax benefits arising from matters unrelated to the leases that would offset the taxes and interest due, including PHI’s best estimate of the expected resolution of other uncertain and effectively settled tax positions, the carrying back and carrying forward of any existing net operating losses, and the application of certain amounts paid in advance to the IRS. In order to mitigate PHI’s ongoing interest costs associated with the $242 million estimate of additional taxes and interest, PHI made an advanced payment to the IRS of $242 million in the first quarter of 2013. This advanced payment was funded from currently available sources of liquidity and short-term borrowings. A portion of the proceeds from lease terminations effected during the second and third quarters of 2013 was used to repay the short-term borrowings utilized to fund the advanced payment.

In order to mitigate the cost of continued litigation related to the cross-border energy lease investments, PHI and its subsidiaries have entered into discussions with the IRS with the intention of seeking a settlement of all tax issues for open tax years 2001 through 2011, including the cross-border energy lease issue. PHI currently believes that it is possible that a settlement with the IRS may be reached in 2015. If a settlement of all tax issues or a standalone settlement on the leases is not reached, PHI may move forward with its litigation with the IRS. Further discovery in the case is stayed until June 18, 2015, pursuant to an order issued by the court on March 19, 2015.

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

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, 2015, 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 were as follows:

Guarantor

PHI

Pepco

DPL

ACE

Total

(millions of dollars)

Guarantees associated with disposal of Conectiv Energy assets (a)

$

13

$

—

$

—

$

—

$

13

Guaranteed lease residual values (b)

3

5

6

5

19

Total

$

16

$

5

$

6

$

5

$

32

(a)

Represents guarantees by PHI of Conectiv Energy’s derivatives portfolio transferred in connection with the disposition of Conectiv Energy’s wholesale business. The derivative portfolio guarantee is currently $13 million and covers Conectiv Energy’s performance prior to the assignment. This guarantee will remain in effect until the end of 2015.

(b)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $52 million, $11 million of which is a guaranty by PHI, $13 million by Pepco, $15 million by DPL and $13 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

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.

Energy Services Performance Contracts

Pepco Energy Services has a diverse portfolio of energy savings 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 it installs will generate a specified amount of energy savings on an annual basis over a multi-year period. As of March 31, 2015 the remaining notional amount of Pepco Energy Services’ energy savings guarantees over the life of the multi-year performance contracts on: (i) completed projects was $318 million with the longest guarantee having a remaining term of 23 years; and, (ii) projects under construction was $60 million with the longest guarantee having a term of 15 years after completion of construction. 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, 2015, Pepco Energy Services had a performance guarantee contract associated with the production at a combined heat and power facility that is under construction totaling $15 million in notional value over 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, 2015, Pepco Energy Services had an accrued liability of $1 million for its energy savings contracts that it established during 2012. There was no significant change in the type of contracts issued during the three months ended March 31, 2015 as compared to the three months ended March 31, 2014.

Dividends

On April 23, 2015, Pepco Holdings’ Board of Directors declared a dividend (the Second Quarter Dividend) of $0.27 per share, payable June 30, 2015 to holders of common stock of record on the close of business on June 10, 2015. The Board of Directors also declared a pro-rata dividend payable in lieu of the Second Quarter Dividend in the event the Merger is completed before the close of business on June 10, 2015. The pro-rata dividend is payable 20 days after the Merger is completed to holders of common stock of record as of the day immediately prior to the day the Merger is completed, at a rate of $0.002967 per share per day beginning March 11, 2015 and ending the day before the Merger is completed.

If the Merger closes after June 10, 2015, but before the close of business on the record date for the next anticipated quarterly dividend, then, in addition to the Second Quarter Dividend, Pepco Holdings’ Board of Directors declared a pro-rata dividend of $0.002967 per share per day, payable 20 days after the Merger is completed, to holders of common stock of record as of the day immediately prior to the date the Merger is completed. This pro-rata dividend will be paid for the number of days beginning on June 11, 2015 and ending on the day before the Merger is completed.

Potomac Electric Power Co [Member]

Commitments and Contingencies

(11) COMMITMENTS AND CONTINGENCIES

General Litigation

From time to time, Pepco is named as a defendant in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. Pepco is self-insured against such claims up to a certain self-insured retention amount and maintains insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, Pepco’s contracts with its vendors generally require the vendors to name Pepco as an additional insured for the amount at least equal to Pepco’s self-insured retention. Further, Pepco’s contracts with its vendors require the vendors to indemnify Pepco for various acts and activities that may give rise to claims against Pepco. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on Pepco’s financial condition, results of operations or cash flows. At March 31, 2015, Pepco had recorded estimated loss contingency liabilities for general litigation totaling approximately $14 million (including amounts related to the matter specifically described below), and the portion of these estimated loss contingency liabilities in excess of the self-insured retention amount was substantially offset by estimated insurance receivables.

Substation Injury Claim

In May 2013, a worker employed by a subcontractor to erect a scaffold at a Pepco substation came into contact with an energized transformer and suffered serious injuries. In August 2013, the individual filed suit against Pepco in the Circuit Court for Montgomery County, Maryland, seeking damages for past and future medical expenses, past and future lost wages, pain and suffering and the cost of a life care plan. On October 22, 2014, an award of approximately $21.7 million was entered in favor of the plaintiff in this matter. On March 10, 2015, Pepco and the insurers entered into a confidential settlement with the plaintiff for the payment of a lesser amount than the award. Pepco’s insurer and the contractor’s insurer together provided insurance coverage for the entirety of this liability, including coverage of Pepco’s self-insured retention amount.

Environmental Matters

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 customers of Pepco, 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, 2015 are summarized as follows:

Transmission

Legacy

Total

and

Generation -

Distribution

Regulated

(millions of dollars)

Beginning balance as of January 1

$

16

$

3

$

19

Accruals

—

—

—

Payments

—

—

—

Ending balance as of March 31

16

3

19

Less amounts in Other Current Liabilities

2

—

2

Amounts in Other Deferred Credits

$

14

$

3

$

17

Peck Iron and Metal Site

The U.S. Environmental Protection Agency (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 the Peck Iron and 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 September 2011, EPA initiated a remedial investigation/feasibility study (RI/FS) for the site using federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with this RI/FS, any remediation activities to be performed at the site or any other costs that EPA might seek to impose on Pepco.

Ward Transformer Site

In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including Pepco, based on their alleged sale of transformers to Ward Transformer, with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants’ motion to dismiss. The litigation is moving forward with certain “test case” defendants (not including Pepco) filing summary judgment motions regarding liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the Federal district court granted summary judgment for the test case defendant whom plaintiffs alleged was liable based on its sale of transformers to Ward Transformer. The Federal district court’s order addresses only the liability of the test case defendant. Plaintiffs appealed the district court’s order to the U.S. Court of Appeals for the Fourth Circuit. On March 20, 2015, the Fourth Circuit affirmed the district court’s summary judgment decision for the sales test case defendant and on April 17, 2015, the Fourth Circuit denied the plaintiffs’ petition for rehearing en banc. Pepco has concluded that a loss is reasonably possible with respect to this matter, but is unable to 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.

Benning Road Site

Contamination of Lower Anacostia River

In September 2010, PHI received a letter from EPA identifying the Benning Road location, consisting of a generation facility formerly operated by Pepco Energy Services, and a transmission and distribution service center facility operated by Pepco, as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. The generation facility was deactivated in June 2012 and the plant structures are being demolished, but the service center remains in operation. The principal contaminants allegedly of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the District of Columbia Department of the Environment (DDOE), which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 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. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DDOE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site.

The remedial investigation field work began in January 2013 and was completed in December 2014. In addition, in conjunction with the power plant demolition activities, Pepco and Pepco Energy Services collected soil samples adjacent to and beneath the concrete basins for the cooling towers previously dismantled and removed from the site of the generating facility. This sampling showed localized areas of soil contamination associated with the cooling tower basins, and Pepco has submitted a plan to DDOE for the removal of contaminated soil in conjunction with the demolition and removal of the concrete basins. Having completed the remedial investigation field sampling, Pepco and Pepco Energy Services currently are drafting RI/FS reports for review and approval by DDOE after solicitation and consideration of public comment. The next status report to the court is due on May 25, 2015.

The remediation costs accrued for this matter are included in the table above in the columns entitled “Transmission and Distribution” and “Legacy Generation – Regulated.”

NPDES Permit Limit Exceedances

Pepco holds a National Pollutant Discharge Elimination System (NPDES) permit issued by EPA with a June 19, 2009 effective date, which authorizes discharges from the Benning Road facility, including the Pepco Energy Services generating facility that was deactivated in 2012 and is being demolished. The 2009 permit imposed compliance monitoring and storm water best management practices to satisfy the District of Columbia’s Total Maximum Daily Load (TMDL) standards for polychlorinated biphenyls, oil and grease, metals and other substances. As part of the implementation of the TMDL requirements, the permit also imposed numerical limits on certain substances in storm water discharges to the Anacostia River. Quarterly monitoring results since the issuance of the permit have shown consistent exceedances of the limits for copper and zinc, as well as occasional exceedances for iron and lead (and, more recently, pH). As required by the permit, Pepco initiated a study to identify the potential sources or causes of these exceedances at the site and to determine appropriate best management practices for achieving compliance with the permit limits. The initial study was completed in May 2012. Pepco has completed the implementation of the first two phases of the best management practices recommended in the study report (consisting principally of installing metal absorbing filters to capture contaminants from storm water flows, removing stored equipment from areas exposed to the weather, covering and painting exposed metal pipes, and covering and cleaning dumpsters). These measures have been effective in reducing metal concentrations in stormwater discharges; however, additional measures will be required to be implemented by Pepco to reduce the concentrations to levels required by the permit.

The NPDES permit was due to expire on June 19, 2014. Pepco submitted a permit renewal application on December 17, 2013. In November 2014, EPA advised Pepco that it will not renew the permit until the Benning Road facility has come into compliance with the existing permit limits. The current permit remains in effect pending EPA’s action on the renewal application. Pepco has prepared a plan to implement the third phase of the best management practices recommended in the study report with the objective of achieving full compliance with the permit limits by the end of 2015. The plan was submitted to EPA on December 30, 2014, and Pepco has begun implementing those best practices in accordance with the plan. Pepco anticipates that EPA eventually may seek administrative penalties for past noncompliance with the permit limits. Whether such penalties will be imposed and, if so, the amount of any such penalties, is not known or estimable at this time. At present, Pepco expects that compliance with the permit limits can be achieved through a combination of enhanced storm drain inlet controls (filters and metal absorbing booms), enhanced site housekeeping, and enhanced inspection and maintenance of storm water controls. If these measures are not adequate to achieve compliance with the permit limits, however, it is possible that a capital project to install a storm water treatment system may be required. The need for any such capital expenditures will not be known until Pepco has implemented the third phase of the best management practices.

Potomac River Mineral Oil Release

In January 2011, a coupling failure on a transformer cooler pipe resulted in a release of non-toxic mineral oil at 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.

In March 2014, Pepco and DDOE entered into a consent decree to resolve a threatened DDOE enforcement action, the terms of which include a combination of a civil penalty and a Supplemental Environmental Project (SEP) with a total cost to Pepco of $875,000. The consent decree was approved and entered by the District of Columbia Superior Court on April 4, 2014. Pepco has paid the $250,000 civil penalty imposed under the consent decree and, pursuant to the consent decree, has made a one-time donation in the amount of $25,000 to the Northeast Environmental Enforcement Training Fund, Inc., a non-profit organization that funds scholarships for environmental enforcement training. The consent decree confirmed that no further actions are required by Pepco to investigate, assess or remediate impacts to the river from the mineral oil release. To implement the SEP, Pepco has entered into an agreement with Living Classrooms Foundation, Inc., a non-profit educational organization, to provide $600,000 to fund the design, installation and operation of a trash collection system at a storm water outfall that drains to the Anacostia River. DDOE approved the design for the trash collection system and efforts to secure necessary permits have commenced. Pepco expects that this system will be constructed and placed into operation by the end of 2015, which will satisfy Pepco’s obligations under the consent decree. The next status hearing in this matter has been set for September 18, 2015.

The consent decree does not resolve potential claims under federal law for natural resource damages resulting from the mineral oil release. Pepco has engaged in separate discussions with DDOE and the federal resource trustees regarding the settlement of a possible natural resource damages claim under federal law. The federal trustees are still evaluating the claim and the terms of a possible settlement. At this time, it is uncertain whether or when the settlement discussions may resume or if the trustees will continue to pursue the natural resource damages claim. Based on discussions to date, Pepco does not believe that the resolution of the federal natural resource damages claim will have a material adverse effect on its financial condition, results of operations or cash flows.

As a result of the mineral oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility which involve pumping accumulated storm water to an above-ground 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 has approached DDOE and EPA for approval to commence operation of the new system on a pilot basis to demonstrate its effectiveness in meeting both secondary containment requirements and water quality standards related to the discharge of storm water from the facility, but to date, no such approval has been obtained. In the meantime, Pepco is continuing to use the aboveground holding tank to manage storm water from the secondary containment system. Pepco also is evaluating other technical and regulatory options for managing storm water from the secondary containment system as alternatives to the proposed treatment system currently under discussion with EPA and DDOE.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Metal Bank Site

In the first quarter of 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted Pepco on behalf of itself and other federal and state trustees to request that Pepco execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Cottman Avenue Superfund Site located in Philadelphia, Pennsylvania. Pepco executed a tolling agreement, which has been extended to March 15, 2016, and will continue settlement discussions with the NOAA, the trustees and other PRPs.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Brandywine Fly Ash Disposal Site

In February 2013, Pepco received a letter from the Maryland Department of the Environment (MDE) requesting that Pepco investigate the extent of waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000 agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule.

PHI and Pepco have determined that a loss associated with this matter for PHI and Pepco is probable and have estimated that the costs for implementation of a closure plan and cap on the site are in the range of approximately $3 million to $6 million. PHI and Pepco believe that the costs incurred in this matter will be recoverable from NRG under the 2000 sale agreement.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Delmarva Power & Light Co/De [Member]

Commitments and Contingencies

(13) COMMITMENTS AND CONTINGENCIES

From time to time, DPL is named as a defendant in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. DPL is self-insured against such claims up to a certain self-insured retention amount and maintains insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, DPL’s contracts with its vendors generally require the vendors to name DPL as an additional insured for the amount at least equal to DPL’s self-insured retention. Further, DPL’s contracts with its vendors require the vendors to indemnify DPL for various acts and activities that may give rise to claims against DPL. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on DPL’s financial condition, results of operations or cash flows. At March 31, 2015, DPL had recorded estimated loss contingency liabilities for general litigation totaling approximately $2 million.

Environmental Matters

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, 2015 are summarized as follows:

Transmission

Legacy

Total

and Distribution

Generation -

Regulated

(millions of dollars)

Beginning balance as of January 1

$

1

$

2

$

3

Accruals

1

—

1

Payments

—

1

1

Ending balance as of March 31

2

1

3

Less amounts in Other Current Liabilities

1

1

2

Amounts in Other Deferred Credits

$

1

$

—

$

1

Ward Transformer Site

In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including DPL, based on their alleged sale of transformers to Ward Transformer, with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants’ motion to dismiss. The litigation is moving forward with certain “test case” defendants (not including DPL) filing summary judgment motions regarding liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the Federal district court granted summary judgment for the test case defendant whom plaintiffs alleged was liable based on its sale of transformers to Ward Transformer. The Federal district court’s order addresses only the liability of the test case defendant. Plaintiffs appealed the district court’s order to the U.S. Court of Appeals for the Fourth Circuit. On March 20, 2015, the Fourth Circuit affirmed the district court’s summary judgment decision for the sales test case defendant and on April 17, 2015, the Fourth Circuit denied the plaintiffs’ petition for rehearing en banc. DPL has concluded that a loss is reasonably possible with respect to this matter, but is unable to 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.

Indian River Oil Release

In 2001, DPL entered into a consent agreement with the Delaware Department of Natural Resources and Environmental Control for remediation, site restoration, natural resource damage compensatory projects and other costs associated with environmental contamination resulting from an oil release at the Indian River generating facility, which was sold in June 2001. The amount of remediation costs accrued for this matter is included in the table above in the column entitled “Legacy Generation – Regulated.”

Metal Bank Site

In the first quarter of 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted DPL on behalf of itself and other federal and state trustees to request that DPL execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Cottman Avenue Superfund Site located in Philadelphia, Pennsylvania. DPL executed a tolling agreement, which has been extended to March 15, 2016, and will continue settlement discussions with the NOAA, the trustees and other PRPs.

The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”

Virginia Department of Environmental Quality Notice of Violation

On February 3, 2015, the Virginia Department of Environmental Quality (VDEQ) issued a notice of violation (NOV) to DPL in connection with alleged violations of state water control laws and regulations associated with recent construction activities undertaken to replace certain transmission facilities. The NOV informed DPL of information on which VDEQ may rely to institute an administrative or judicial enforcement action, requested a meeting, and stated that DPL may be asked to enter into a consent order to formalize a plan and schedule of corrective action and settle any outstanding issues regarding the matter including the assessment of civil charges. At a February 20, 2015 meeting, VDEQ confirmed that the NOV would be resolved through a consent order, which will require the payment of a penalty, but did not specify the potential penalty amount. DPL will pursue recovery of the restoration costs for this matter from the contractor responsible for the vegetation management activities that gave rise to the alleged violations. DPL does not believe that the remediation costs to resolve this matter will have a material adverse effect on its financial condition, results of operations or cash flows.

Atlantic City Electric Co [Member]

Commitments and Contingencies

(11) COMMITMENTS AND CONTINGENCIES

General Litigation

From time to time, ACE is named as a defendant in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. ACE is self-insured against such claims up to a certain self-insured retention amount and maintains insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, ACE’s contracts with its vendors generally require the vendors to name ACE as an additional insured for the amount at least equal to ACE’s self-insured retention. Further, ACE’s contracts with its vendors require the vendors to indemnify ACE for various acts and activities that may give rise to claims against ACE. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on ACE’s financial condition, results of operations or cash flows. At March 31, 2015, ACE had recorded estimated loss contingency liabilities for general litigation totaling approximately $6 million (including amounts related to the matters specifically described below).

Asbestos Claim

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. 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 March 31, 2015, ACE has concluded that a loss is probable with respect to this matter and has recorded an estimated loss contingency liability, which is included in the liability for general litigation referred to above as of March 31, 2015. However, due to the inherent uncertainty of litigation, ACE is unable to estimate a maximum amount of possible loss because the damages sought are indeterminate and 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.

Environmental Matters

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 customers of ACE, 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, 2015 are summarized as follows:

Legacy Generation -

Regulated

(millions of dollars)

Beginning balance as of January 1

$

1

Accruals

—

Payments

—

Ending balance as of March 31

1

Less amounts in Other Current Liabilities

—

Amounts in Other Deferred Credits

$

1

Franklin Slag Pile Site

In November 2008, ACE received a general notice letter from EPA concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party (PRP) that may have liability for clean-up costs with respect to the site and for the costs of implementing an EPA-mandated remedy. 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’s feasibility study for this site conducted in 2007 identified a range of alternatives for permanent remedial measures with varying cost estimates, and the estimated cost of EPA’s preferred alternative is approximately $6 million.

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.

Ward Transformer Site

In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including ACE, based on their alleged sale of transformers to Ward Transformer, with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants’ motion to dismiss. The litigation is moving forward with certain “test case” defendants (not including ACE) filing summary judgment motions regarding liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the Federal district court granted summary judgment for the test case defendant whom plaintiffs alleged was liable based on its sale of transformers to Ward Transformer. The Federal district court’s order addresses only the liability of the test case defendant. Plaintiffs appealed the district court’s order to the U.S. Court of Appeals for the Fourth Circuit. On March 20, 2015, the Fourth Circuit affirmed the district court’s summary judgment decision for the sales test case defendant and on April 17, 2015, the Fourth Circuit denied the plaintiffs’ petition for rehearing en banc. ACE has concluded that a loss is reasonably possible with respect to this matter, but is unable to 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.

Variable_Interest_Entities

Variable Interest Entities	3 Months Ended
	Mar. 31, 2015
Variable Interest Entities	(16) VARIABLE INTEREST ENTITIES
	PHI is required to consolidate a variable interest entity (VIE) in accordance with FASB ASC 810 if PHI or a subsidiary is the primary beneficiary of the VIE. The primary beneficiary of a VIE is typically the entity with both the power to direct activities most significantly impacting economic performance of the VIE and the obligation to absorb losses or receive benefits of the VIE that could potentially be significant to the VIE. PHI performs a qualitative analysis to determine whether a variable interest provides a controlling financial interest in any of the VIEs in which PHI or its subsidiaries have an interest. Set forth below are the relationships with respect to which PHI conducted a VIE analysis as of March 31, 2015.
	DPL Renewable Energy Transactions
	DPL is subject to Renewable Energy Portfolio Standards (RPS) in the state of Delaware that require it to obtain renewable energy credits (RECs) for energy delivered to its customers. DPL’s costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its customers by law. As of March 31, 2015, DPL is a party to three land-based wind power purchase agreements (PPAs) in the aggregate amount of 128 MWs, one solar PPA with a 10 MW facility, and a PPA with the Delaware Sustainable Energy Utility (DSEU) to purchase solar renewable energy credits (SRECs). Each of the facilities associated with these PPAs is operational, and DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and SRECs from the solar facility and DSEU, up to certain amounts (as set forth below) at rates that are primarily fixed under the respective agreements. PHI and DPL have concluded that while VIEs exist under these contracts, consolidation is not required under FASB ASC 810 as DPL is not the primary beneficiary. DPL has not provided financial or other support under these arrangements that it was not previously contractually required to provide during the periods presented, and DPL does not have any intention to provide such additional support.
	Because DPL has no equity or debt interest in these renewable energy transactions, the maximum exposure to loss relates primarily to any above-market costs incurred for power, RECs or SRECs. Due to unpredictability in the amount of MWs ultimately purchased under the agreements for purchased renewable energy, RECs and SRECs, PHI and DPL are unable to quantify the maximum exposure to loss, however, the power purchase, REC and SREC costs are recoverable from DPL’s customers through regulated rates.
	Wind PPAs
	DPL is obligated to purchase energy and RECs from the first wind facility through 2024 in amounts not to exceed 50 MWs, from the second wind facility through 2031 in amounts not to exceed 40 MWs, and from the third wind facility through 2031 in amounts not to exceed 38 MWs. DPL’s aggregate purchases under the three wind PPAs totaled $10 million for each of the three months ended March 31, 2015 and 2014.
	Solar PPAs
	The term of the PPA with the solar facility is through 2030 and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. The DSEU may enter into 20-year contracts with solar facilities to purchase SRECs for resale to DPL. Under the DSEU PPA, DPL is obligated to purchase in amounts not to exceed 19 MWs of SRECs at annually determined auction rates. DPL’s purchases under these solar PPAs totaled $1 million for each of the three months ended March 31, 2015 and 2014.
	Fuel Cell Facilities
	On October 18, 2011, the DPSC approved a tariff submitted by DPL in accordance with the requirements of the RPS specific to fuel cell facilities totaling 30 MWs to be constructed by a qualified fuel cell provider. The tariff and the RPS establish that DPL acts solely as an agent to collect payments in advance from its distribution customers and remit them to the qualified fuel cell provider for each MW hour of energy produced by the fuel cell facilities through 2033. The RPS provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. PHI and DPL have concluded that while a VIE exists as a result of this relationship, consolidation is not required under FASB ASC 810 as DPL is not the primary beneficiary. For the three months ended March 31, 2015 and 2014, 56,318 and 53,609 megawatt hours, respectively, were produced from fuel cell facilities placed in service under the tariff. DPL billed $10 million and $9 million to distribution customers with respect to energy produced by these facilities for the three months ended March 31, 2015 and 2014, respectively.
	ACE Power Purchase Agreements
	ACE is a party to three PPAs with unaffiliated non-utility generators (NUGs) totaling 459 MWs. One of the agreements ends in 2016 and the other two end in 2024. PHI and ACE have no equity or debt invested in these entities. In performing its VIE analysis, PHI has been 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 has applied the scope exemption from the consolidation guidance.
	Because ACE has no equity or debt invested in the NUGs, the maximum exposure to loss relates primarily to any above-market costs incurred for power. Due to unpredictability in the pricing for purchased energy under the PPAs, PHI and ACE are unable to quantify the maximum exposure to loss. The power purchase costs are recoverable from ACE’s customers through regulated rates. Purchase activities with the NUGs, including excess power purchases not covered by the PPAs, for the three months ended March 31, 2015 and 2014, were approximately $62 million and $72 million, respectively, of which approximately $56 million and $59 million, respectively, consisted of power purchases under the PPAs.
	ACE Funding
	In 2001, ACE established ACE Funding solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. The proceeds of the sale of each series of Transition Bonds were transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable Transition Bond Charge (representing revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees) from ACE customers pursuant to bondable stranded costs rate orders issued by the 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). 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 Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding, and PHI and ACE consolidate ACE Funding in their consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.
Delmarva Power & Light Co/De [Member]
Variable Interest Entities	(15) VARIABLE INTEREST ENTITIES
	DPL is required to consolidate a VIE in accordance with FASB ASC 810 if DPL is the primary beneficiary of the VIE. The primary beneficiary of a VIE is typically the entity with both the power to direct activities most significantly impacting economic performance of the VIE and the obligation to absorb losses or receive benefits of the VIE that could potentially be significant to the VIE. DPL performed a qualitative analysis to determine whether a variable interest provided a controlling financial interest in any of the VIE’s in which DPL has an interest at March 31, 2015, as described below.
	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 March 31, 2015, DPL is a party to three land-based wind PPAs in the aggregate amount of 128 MWs, one solar power purchase agreement (PPA) with a 10 MW facility, and a PPA with the Delaware Sustainable Energy Utility (DSEU) to purchase solar renewable energy credits (SRECs). Each of the facilities associated with these PPAs is operational, and DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and SRECs from the solar facility and DSEU, up to certain amounts (as set forth below) at rates that are primarily fixed under the respective agreements. DPL has concluded that while VIEs exist under these contracts, consolidation is not required under FASB ASC 810 as DPL is not the primary beneficiary. DPL has not provided financial or other support under these arrangements that it was not previously contractually required to provide during the periods presented, and DPL does not have any intention to provide such additional support.
	Because DPL has no equity or debt interest in these renewable energy transactions, the maximum exposure to loss relates primarily to any above-market costs incurred for power, RECs or SRECs. Due to unpredictability in the amount of MWs ultimately purchased under the agreements for purchased renewable energy, RECs and SRECs, DPL is unable to quantify the maximum exposure to loss, however, the power purchase, REC and SREC costs are recoverable from DPL’s customers through regulated rates.
	Wind PPAs
	DPL is obligated to purchase energy and RECs from the first wind facility through 2024 in amounts not to exceed 50 MWs, from the second wind facility through 2031 in amounts not to exceed 40 MWs, and from the third wind facility through 2031 in amounts not to exceed 38 MWs. DPL’s aggregate purchases under the three wind PPAs totaled $10 million for each of the three months ended March 31, 2015 and 2014.
	Solar PPAs
	The term of the PPA with the solar facility is through 2030 and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. The DSEU may enter into 20-year contracts with solar facilities to purchase SRECs for resale to DPL. Under the DSEU PPA, DPL is obligated to purchase SRECs in amounts not to exceed 19 MWs at annually determined auction rates. DPL’s purchases under these solar PPAs totaled $1 million for each of the three months ended March 31, 2015 and 2014.
	Fuel Cell Facilities
	On October 18, 2011, the DPSC approved a tariff submitted by DPL in accordance with the requirements of the RPS specific to fuel cell facilities totaling 30 MWs to be constructed by a qualified fuel cell provider. The tariff and the RPS establish that DPL acts solely as an agent to collect payments in advance from its distribution customers and remit them to the qualified fuel cell provider for each MW hour of energy produced by the fuel cell facilities through 2033. The RPS provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. DPL has concluded that while a VIE exists as a result of this relationship, consolidation is not required under FASB ASC 810 as DPL is not the primary beneficiary. For the three months ended March 31, 2015 and 2014, 56,318 and 53,609 megawatt hours, respectively, were produced from fuel cell facilities placed in service under the tariff. DPL billed $10 million and $9 million to distribution customers with respect to energy provided by these facilities for the three months ended March 31, 2015, and 2014, respectively.
Atlantic City Electric Co [Member]
Variable Interest Entities	(13) VARIABLE INTEREST ENTITIES
	ACE is required to consolidate a VIE in accordance with FASB ASC 810 if ACE or a subsidiary is the primary beneficiary of the VIE. The primary beneficiary of a VIE is typically the entity with both the power to direct activities most significantly impacting economic performance of the VIE and the obligation to absorb losses or receive benefits of the VIE that could potentially be significant to the VIE. ACE performed a qualitative analysis to determine whether a variable interest provided a controlling financial interest in any of the VIE’s in which ACE has an interest at March 31, 2015, as described below.
	Power Purchase Agreements
	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 has no equity or debt invested in these entities. In performing its VIE analysis, ACE has been 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 has applied the scope exemption from the consolidation guidance.
	Because ACE has no equity or debt invested in the NUGs, the maximum exposure to loss relates primarily to any above-market costs incurred for power. Due to unpredictability in the pricing for purchased energy under the PPAs, ACE is unable to quantify the maximum exposure to loss. The power purchase costs are recoverable from ACE’s customers through regulated rates. Purchase activities with the NUGs, including excess power purchases not covered by the PPAs, for the three months ended March 31, 2015 and 2014, were approximately $62 million and $72 million, respectively, of which approximately $56 million and $59 million, respectively, consisted of power purchases under the PPAs.
	ACE Funding
	In 2001, ACE established ACE Funding solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. The proceeds of the sale of each series of Transition Bonds were transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable Transition Bond Charge (representing revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees) from ACE customers pursuant to bondable stranded costs rate orders issued by the 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). 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 Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding, and PHI and ACE consolidate ACE Funding in their consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Loss	3 Months Ended
	Mar. 31, 2015
Equity [Abstract]
Accumulated Other Comprehensive Loss	(17) ACCUMULATED OTHER COMPREHENSIVE LOSS
	The components of Pepco Holdings’ AOCL are as follows. For additional information, see the consolidated statements of comprehensive income.
		Three Months Ended
		March 31,
		2015			2014
		(millions of dollars)
	Balance as of January 1	$	(46	)	$	(34	)
	Treasury Lock
	Balance as of January 1		(9	)		(9	)
	Amount of pre-tax loss reclassified to Interest expense		—			—
	Income tax benefit		—			—
	Balance as of March 31		(9	)		(9	)
	Pension and Other Postretirement Benefits
	Balance as of January 1		(37	)		(25	)
	Amount of amortization of net prior service cost and actuarial loss reclassified to Other operation and maintenance expense		2			1
	Income tax expense		1			—
	Balance as of March 31		(36	)		(24	)
	Balance as of March 31	$	(45	)	$	(33	)

Related_Party_Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2015
Potomac Electric Power Co [Member]
Related Party Transactions	(12) RELATED PARTY TRANSACTIONS
	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, 2015 and 2014 were approximately $64 million and $53 million, respectively.
	Pepco Energy Services performs utility maintenance services and high voltage underground transmission cabling, 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, 2015 and 2014 were approximately $4 million and $5 million, respectively.
	As of March 31, 2015 and December 31, 2014, Pepco had the following balances on its balance sheets due to related parties:
			March 31,			December 31,
			2015			2014
			(millions of dollars)
	Payable to Related Party (current) (a)
	PHI Service Company		$	(34	)	$	(27	)
	Pepco Energy Services (b)			(4	)		(2	)
	Other			(13	)		(1	)
	Total		$	(51	)	$	(30	)
	(a)	Included in Accounts payable due to associated companies.
	(b)	Pepco bills customers on behalf of Pepco Energy Services where Pepco Energy Services has performed work for certain government agencies under a General Services Administration area-wide agreement. Amount also includes charges for utility work performed by Pepco Energy Services on behalf of Pepco.
Delmarva Power & Light Co/De [Member]
Related Party Transactions	(14) RELATED PARTY TRANSACTIONS
	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, 2015 and 2014 were approximately $48 million and $39 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:
			Three Months Ended
			March 31,
			2015			2014
			(millions of dollars)
	Intercompany lease transactions (a)		$	1		$	1
	(a)	Included in Electric revenue.
	As of March 31, 2015 and December 31, 2014, DPL had the following balances on its balance sheets due to related parties:
			March 31,			December 31,
			2015			2014
			(millions of dollars)
	Payable to Related Party (current) (a)
	PHI Service Company		$	(21	)	$	(18	)
	Other			—			1
	Total		$	(21	)	$	(17	)
	(a)	Included in Accounts payable due to associated companies.
Atlantic City Electric Co [Member]
Related Party Transactions	(12) RELATED PARTY TRANSACTIONS
	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, 2015 and 2014 were approximately $38 million and $29 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,
			2015			2014
			(millions of dollars)
	Meter reading services provided by Millennium Account Services LLC (an ACE affiliate) (a)		$	(1	)	$	(1	)
	(a)	Included in Other operation and maintenance expense.
	As of March 31, 2015 and December 31, 2014, ACE had the following balances on its consolidated balance sheets due to related parties:
			March 31,			December 31,
			2015			2014
			(millions of dollars)
	Payable to Related Party (current) (a)
	PHI Service Company		$	(15	)	$	(14	)
	Other			(2	)		(1	)
	Total		$	(17	)	$	(15	)
	(a)	Included in Accounts payable due to associated companies.

Significant_Accounting_Policie1

Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2015
Financial Statement Presentation	Financial Statement Presentation
	Pepco Holdings’ unaudited consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted. Therefore, these consolidated financial statements should be read along with the annual consolidated financial statements included in PHI’s annual report on Form 10-K for the year ended December 31, 2014. In the opinion of PHI’s management, the unaudited 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, 2015, in accordance with GAAP. The year-end December 31, 2014 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 months ended March 31, 2015 may not be indicative of PHI’s results that will be realized for the full year ending December 31, 2015.
Use of Estimates	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although Pepco Holdings believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.
	Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset and goodwill impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefit assumptions, the assessment of the adequacy of the allowance for uncollectible accounts, 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 loss contingency liabilities for general litigation and auto and other liability claims, accrual of interest related to income taxes, 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.
Consolidation of Variable Interest Entities	Consolidation of Variable Interest Entities
	PHI assesses its contractual arrangements with variable interest entities to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (16), “Variable Interest Entities,” for additional information.
Goodwill	Goodwill
	Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. PHI 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 (that is, a greater than 50% chance) reduce the estimated 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 significantly below book value, an adverse regulatory action, or an impairment of long-lived assets in the reporting unit. PHI performed its most recent annual impairment test as of November 1, 2014, and its goodwill was not impaired as described in Note (6), “Goodwill.”
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions	Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
	Taxes included in Pepco Holdings’ gross revenues were $83 million for each of the three months ended March 31, 2015 and 2014.
Business Combinations	Business Combinations (ASC 805)
	In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.
	The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.
	The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014. PHI currently anticipates it may be affected by the new guidance if its Merger with Exelon closes.
Discontinued Operations	Discontinued Operations (ASC 205)
	In April 2014, the FASB issued new guidance on the reporting of discontinued operations that is effective for dispositions that occur after January 1, 2015. In order for dispositions to be presented as discontinued operations, the dispositions must represent a strategic shift that will have a major effect on an entity’s operations and financial results. This guidance did not have an effect on PHI’s consolidated financial statements in the first quarter of 2015.
Revenue from Contracts with Customers	Revenue from Contracts with Customers (ASC 606)
	In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.
	The new requirements are expected to be effective for PHI beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is expected to be permitted, but not before January 1, 2017. PHI is currently evaluating the potential impact of this new guidance on its consolidated financial statements and which implementation approach to select.
Presentation of Debt Issuance Costs	Presentation of Debt Issuance Costs (ASC 835)
	In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements will be effective for PHI beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented. Early adoption is permitted. PHI is currently evaluating the potential impact of this new guidance on its consolidated financial statements, but the impact is not expected to be material.
Potomac Electric Power Co [Member]
Financial Statement Presentation	Financial Statement Presentation
	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, 2014. In the opinion of Pepco’s management, the unaudited 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, 2015, in accordance with GAAP. The year-end December 31, 2014 balance sheet included herein was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2015 may not be indicative of results that will be realized for the full year ending December 31, 2015.
Use of Estimates	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the 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 adequacy of the allowance for uncollectible accounts, 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 loss contingency liabilities for general litigation and auto and other 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.
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions	Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
	Taxes included in Pepco’s gross revenues were $78 million for each of the three months ended March 31, 2015 and 2014.
Business Combinations	Business Combinations (ASC 805)
	In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.
	The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.
	The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014.
Revenue from Contracts with Customers	Revenue from Contracts with Customers (Accounting Standards Codification (ASC) 606)
	In May 2014, the Financial Accounting Standards Board (FASB) issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.
	The new requirements are expected to be effective for Pepco beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is expected to be permitted, but not before January 1, 2017. Pepco is currently evaluating the potential impact of this new guidance on its financial statements and which implementation approach to select.
Presentation of Debt Issuance Costs	Presentation of Debt Issuance Costs (ASC 835)
	In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements will be effective for Pepco beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented. Early adoption is permitted. Pepco is currently evaluating the potential impact of this new guidance on its consolidated financial statements, but the impact is not expected to be material.
Delmarva Power & Light Co/De [Member]
Financial Statement Presentation	Financial Statement Presentation
	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, 2014. In the opinion of DPL’s management, the unaudited 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, 2015, in accordance with GAAP. The year-end December 31, 2014 balance sheet included herein was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three months ended March 31, 2015 may not be indicative of DPL’s results that will be realized for the full year ending December 31, 2015.
Use of Estimates	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the 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 adequacy of the allowance for uncollectible accounts, 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 loss contingency liabilities for general litigation and auto and other 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.
Consolidation of Variable Interest Entities	Consolidation of Variable Interest Entities
	DPL assesses its contractual arrangements with variable interest entities (VIEs) 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. See Note (15), “Variable Interest Entities,” for additional information.
Goodwill	Goodwill
	Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. 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 (that is, a greater than 50% chance) reduce the estimated fair value of DPL 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 unit, an adverse change in business conditions, an adverse regulatory action, or an impairment of DPL’s long-lived assets. DPL performed its most recent annual impairment test as of November 1, 2014, and its goodwill was not impaired as described in Note (6), “Goodwill.”
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions	Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
	Taxes included in DPL’s gross revenues were $5 million and $4 million for the three months ended March 31, 2015 and 2014, respectively.
Business Combinations	Business Combinations (ASC 805)
	In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.
	The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.
	The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014.
Revenue from Contracts with Customers	Revenue from Contracts with Customers (ASC 606)
	In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.
	The new requirements are expected to be effective for DPL beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is expected to be permitted, but not before January 1, 2017. DPL is currently evaluating the potential impact of this new guidance on its financial statements and which implementation approach to select.
Presentation of Debt Issuance Costs	Presentation of Debt Issuance Costs (ASC 835)
	In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements will be effective for DPL beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented. Early adoption is permitted. DPL is currently evaluating the potential impact of this new guidance on its consolidated financial statements, but the impact is not expected to be material.
Atlantic City Electric Co [Member]
Financial Statement Presentation	Financial Statement Presentation
	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, 2014. In the opinion of ACE’s management, the unaudited 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, 2015, in accordance with GAAP. The year-end December 31, 2014 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 months ended March 31, 2015 may not be indicative of ACE’s results that will be realized for the full year ending December 31, 2015.
Use of Estimates	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although 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 adequacy of the allowance for uncollectible accounts, 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 loss contingency liabilities for general litigation and auto and other 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.
Consolidation of Variable Interest Entities	Consolidation of Variable Interest Entities
	ACE assesses its contractual arrangements with variable interest entities (VIEs) 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. See Note (13), “Variable Interest Entities,” for additional information.
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions	Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
	Taxes included in ACE’s gross revenues were zero and $1 million for the three months ended March 31, 2015 and 2014, respectively.
Business Combinations	Business Combinations (ASC 805)
	In November 2014, the FASB issued new recognition and disclosure requirements related to pushdown accounting. The new recognition requirements grant an acquired entity (or its subsidiaries) the option to elect whether and when a new accounting and reporting basis (pushdown accounting) will be applied when an acquirer obtains control of the acquired entity. This election may be made by the acquired entity (or its subsidiaries) for future change-in-control events or for its most recent change-in-control event, and the acquired entity will be required to determine whether pushdown accounting will be applied in the reporting period in which the change-in-control event occurs or in a subsequent reporting period.
	The new required disclosures include information that enables financial statement users to evaluate the effects of pushdown accounting. Disclosures are required to be made in the period in which pushdown accounting is applied and are expected to include both qualitative and quantitative information.
	The new recognition and disclosure requirements became effective on a prospective basis on November 18, 2014.
Revenue from Contracts with Customers	Revenue from Contracts with Customers (ASC 606)
	In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard.
	The new requirements are expected to be effective for ACE beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is expected to be permitted, but not before January 1, 2017. ACE is currently evaluating the potential impact of this new guidance on its consolidated financial statements and which implementation approach to select.
Presentation of Debt Issuance Costs	Presentation of Debt Issuance Costs (ASC 835)
	In April 2015, the FASB issued new guidance for the presentation of debt issuance costs on the balance sheet. Debt issuance costs are currently required to be presented on the balance sheet as assets. However, under the new requirements, these debt issuance costs will be offset against the debt to which the costs relate. The new requirements will be effective for ACE beginning January 1, 2016, and are required to be implemented on a retrospective basis for all periods presented. Early adoption is permitted. ACE is currently evaluating the potential impact of this new guidance on its consolidated financial statements, but the impact is not expected to be material.

Segment_Information_Tables

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2015
Segment Reporting [Abstract]
Segment Financial Information	Segment financial information for the three months ended March 31, 2015 and 2014 is as follows:
			Three Months Ended March 31, 2015
			Power		Pepco			Corporate			PHI
			Delivery		Energy			and			Consolidated
					Services			Other (a)
			(millions of dollars)
	Operating Revenue		$	1,313	$	60		$	(2	)	$	1,371
	Operating Expenses (b)			1,167		61			1			1,229
	Operating Income (Loss)			146		(1	)		(3	)		142
	Interest Expense			58		—			10			68
	Other Income			9		—			—			9
	Income Tax Expense (Benefit)			35		(5	)		—			30
	Net Income (Loss)			62		4			(13	)		53
	Total Assets			14,082		237			1,708			16,027
	Construction Expenditures		$	241	$	—		$	5		$	246
	(a)	Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(2) million for Operating Revenue, $(2) million for Operating Expenses and $(1) million for Interest Expense.
	(b)	Includes depreciation and amortization expense of $159 million, consisting of $147 million for Power Delivery, $1 million for Pepco Energy Services and $11 million for Corporate and Other.
			Three Months Ended March 31, 2014
			Power		Pepco			Corporate			PHI
			Delivery		Energy			and			Consolidated
					Services			Other (a)
			(millions of dollars)
	Operating Revenue		$	1,272	$	60		$	(2	)	$	1,330
	Operating Expenses (b)			1,103		60			(6	)		1,157
	Operating Income			169		—			4			173
	Interest Expense			55		—			10			65
	Other Income			12		—			1			13
	Income Tax Expense (Benefit)			47		—			(1	)		46
	Net Income (Loss)			79		—			(4	)		75
	Total Assets			13,438		287			1,279			15,004
	Construction Expenditures		$	264	$	—		$	18		$	282
	(a)	Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(2) million for Operating Revenue, $(1) million for Operating Expenses and $(1) million for Interest Expense.
	(b)	Includes depreciation and amortization expense of $133 million, consisting of $124 million for Power Delivery, $2 million for Pepco Energy Services and $7 million for Corporate and Other.

Pension_and_Other_Postretireme1

Pension and Other Postretirement Benefits (Tables)	3 Months Ended
	Mar. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Components of Net Periodic Benefit Costs	The table below provides the components of net periodic benefit costs recognized by Pepco Holdings for the three months ended March 31, 2015 and 2014:
		Pension Benefits						Other Postretirement
								Benefits
		2015			2014			2015			2014
		(millions of dollars)
	Service cost	$	14		$	12		$	2		$	2
	Interest cost		27			27			6			7
	Expected return on plan assets		(35	)		(35	)		(6	)		(6	)
	Amortization of prior service cost (benefit)		—			—			(3	)		(3	)
	Amortization of net actuarial loss		16			11			3			3
	Net periodic benefit cost	$	22		$	15		$	2		$	3

Income_Taxes_Tables

Income Taxes (Tables)	3 Months Ended
	Mar. 31, 2015
Reconciliation of Consolidated Income Tax Expense from Continuing Operations	A reconciliation of PHI’s consolidated effective income tax rates from continuing operations is as follows:
		Three Months Ended
		March 31,
		2015					2014
		(millions of dollars)
	Income tax at Federal statutory rate	$	29		35	%	$	42		35	%
	Increases (decreases) resulting from:
	State income taxes, net of Federal effect		6		7.2	%		7		5.8	%
	Asset removal costs		(3	)	(3.6	)%		(2	)	(1.7	)%
	Change in estimates and interest related to uncertain and effectively settled tax positions		—		—			(1	)	(0.8	)%
	Energy efficiency-related tax deductions		(4	)	(4.8	)%		—		—
	Merger-related costs		2		2.4	%		—		—
	Other, net		—		(0.1	)%		—		(0.3	)%
	Consolidated income tax expense	$	30		36.1	%	$	46		38	%
Delmarva Power & Light Co/De [Member]
Reconciliation of Consolidated Income Tax Expense from Continuing Operations	A reconciliation of DPL’s effective income tax rates is as follows:
		Three Months Ended March 31,
		2015					2014
		(millions of dollars)
	Income tax at Federal statutory rate	$	19		35	%	$	22		35	%
	Increases (decreases) resulting from:
	State income taxes, net of Federal effect		3		5.7	%		3		4.8	%
	Other, net		(1	)	(1.1	)%		—		0.5	%
	Income tax expense	$	21		39.6	%	$	25		40.3	%
Atlantic City Electric Co [Member]
Reconciliation of Consolidated Income Tax Expense from Continuing Operations	A reconciliation of ACE’s consolidated effective income tax rates is as follows:
		Three Months Ended
		March 31,
		2015					2014
		(millions of dollars)
	Income tax at Federal statutory rate	$	2		35	%	$	6		35	%
	Increases (decreases) resulting from:
	Other, net		—		(1.7	)%		—		2.5	%
	Consolidated income tax expense	$	2		33.3	%	$	6		37.5	%
Potomac Electric Power Co [Member]
Reconciliation of Consolidated Income Tax Expense from Continuing Operations	A reconciliation of Pepco’s effective income tax rates is as follows:
		Three Months Ended
		March 31,
		2015					2014
		(millions of dollars)
	Income tax at Federal statutory rate	$	13		35	%	$	17		35	%
	Increases (decreases) resulting from:
	State income taxes, net of Federal effect		2		5.3	%		3		6.3	%
	Asset removal costs		(3	)	(7.9	)%		(2	)	(4.2	)%
	Change in estimates and interest related to uncertain and effectively settled tax positions		—		—			(1	)	(2.1	)%
	Other, net		—		(0.8	)%		(1	)	(1.7	)%
	Income tax expense	$	12		31.6	%	$	16		33.3	%

Equity_and_Earnings_Per_Share_

Equity and Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2015
Earnings Per Share [Abstract]
Calculation of Earnings Per Share of Common Stock	PHI’s basic and diluted earnings per share (EPS) calculations are shown below:
		Three Months Ended
		March 31,
		2015		2014
		(millions of
		dollars, except
		per share data)
	Income (Numerator):
	Net Income	$	53	$	75
	Shares (Denominator) (in millions):
	Weighted average shares outstanding for basic computation:
	Average shares outstanding		253		250
	Adjustment to shares outstanding		—		1
	Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		253		251
	Net effect of potentially dilutive shares		—		—
	Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		253		251
	Basic and Diluted Earnings per Share
	Basic and diluted earnings per share	$	0.21	$	0.3

Derivative_Instruments_and_Hed1

Derivative Instruments and Hedging Activities (Tables)	3 Months Ended
	Mar. 31, 2015
Fair Values of Derivative Instruments by Balance Sheet Location	The tables below identify the balance sheet location and fair values of derivative instruments as of March 31, 2015 and December 31, 2014:
			As of March 31, 2015
	Balance Sheet Caption		Derivatives			Other				Gross			Effects of		Net
			Designated			Derivative				Derivative			Cash		Derivative
			as Hedging			Instruments				Instruments			Collateral		Instruments
			Instruments										and
													Netting
			(millions of dollars)
	Derivative assets (current assets)		$	—		$	3			$	3		$	—	$	3
	Derivative liabilities (current liabilities)			—			(2	)			(2	)		2		—
	Net Derivative asset		$	—		$	1			$	1		$	2	$	3
			As of December 31, 2014
	Balance Sheet Caption		Derivatives			Other				Gross			Effects of		Net
			Designated			Derivative				Derivative			Cash		Derivative
			as Hedging			Instruments				Instruments			Collateral		Instruments
			Instruments										and
													Netting
			(millions of dollars)
	Derivative assets (current assets)		$	—		$	3			$	3		$	—	$	3
	Derivative liabilities (current liabilities)			—			(4	)			(4	)		4		—
	Net Derivative (liability) asset		$	—		$	(1	)		$	(1	)	$	4	$	3
Schedule of Cash Collateral Offset Against Derivative Positions	The amount of cash collateral that was offset against these derivative positions is as follows:
			March 31,			December 31,
			2015			2014
			(millions of dollars)
	Cash collateral pledged to counterparties with the right to reclaim (a)		$	2		$	4
	(a)	Includes cash deposits on commodity brokerage accounts.
Cash Flow Hedges Included in Accumulated Other Comprehensive Loss	The data in the following tables indicate the cumulative net loss after-tax related to terminated 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:
	Contracts		As of March 31, 2015							Maximum
			Accumulated			Portion Expected				Term
			Other			to be Reclassified
			Comprehensive Loss			to Income during
			After-tax			the Next 12 Months
			(millions of dollars)
	Interest rate		$	9		$	1			209 months
	Total		$	9		$	1
	Contracts		As of March 31, 2014							Maximum
			Accumulated			Portion Expected				Term
			Other			to be Reclassified
			Comprehensive Loss			to Income during
			After-tax			the Next 12 Months
			(millions of dollars)
	Interest rate		$	9		$	1			221 months
	Total		$	9		$	1
Net Unrealized and Realized Derivative Gains (Losses) Deferred as Regulatory Liabilities and Regulatory Assets	The following table shows the net unrealized and net realized derivative gains and losses arising during the period associated with these derivatives that were recognized in the consolidated statements of income (through Fuel and purchased energy expense) and that were also deferred as Regulatory liabilities and Regulatory assets for the three months ended March 31, 2015 and 2014:
			Three Months Ended
			March 31,
			2015			2014
			(millions of dollars)
	Net unrealized (loss) gain arising during the period		$	(1	)	$	2
	Net realized (loss) gain recognized during the period			(3	)		2
Net Outstanding Commodity Forward Contracts That Did Not Qualify for Hedge Accounting	As of March 31, 2015 and December 31, 2014, the quantities and positions of DPL’s net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting were:
			March 31, 2015					December 31, 2014
	Commodity		Quantity			Net Position		Quantity				Net Position
	DPL – Natural gas (One Million British Thermal Units)			2,997,500		Long			3,892,500			Long
Delmarva Power & Light Co/De [Member]
Fair Values of Derivative Instruments by Balance Sheet Location	The tables below identify the balance sheet location and fair values of derivative instruments as of March 31, 2015 and December 31, 2014:
			As of March 31, 2015
	Balance Sheet Caption		Derivatives			Other				Gross			Effects of		Net
			Designated			Derivative				Derivative			Cash		Derivative
			as Hedging			Instruments				Instruments			Collateral		Instruments
			Instruments										and
													Netting
			(millions of dollars)
	Derivative liabilities (current liabilities)		$	—		$	(2	)		$	(2	)	$	2	$	—
			As of December 31, 2014
	Balance Sheet Caption		Derivatives			Other				Gross			Effects of		Net
			Designated			Derivative				Derivative			Cash		Derivative
			as Hedging			Instruments				Instruments			Collateral		Instruments
			Instruments										and
													Netting
			(millions of dollars)
	Derivative liabilities (current liabilities)		$	—		$	(4	)		$	(4	)	$	4	$	—
Schedule of Cash Collateral Offset Against Derivative Positions	The amount of cash collateral that was offset against these derivative positions is as follows:
			March 31,			December 31,
			2015			2014
			(millions of dollars)
	Cash collateral pledged to counterparties with the right to reclaim (a)		$	2		$	4
	(a)	Includes cash deposits on commodity brokerage accounts.
Net Unrealized and Realized Derivative Gains (Losses) Deferred as Regulatory Liabilities and Regulatory Assets	The following table shows the net unrealized and net realized derivative gains and losses arising during the period associated with these derivatives that were recognized in the statements of income (through Purchased energy and Gas purchased expense) and that were also deferred as Regulatory liabilities and Regulatory assets, respectively, for the three months ended March 31, 2015 and 2014:
			Three Months Ended
			March 31,
			2015			2014
			(millions of dollars)
	Net unrealized (loss) gain arising during the period		$	(1	)	$	2
	Net realized (loss) gain recognized during the period			(3	)		2
Net Outstanding Commodity Forward Contracts That Did Not Qualify for Hedge Accounting	As of March 31, 2015 and December 31, 2014, the quantities and positions of DPL’s net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting were:
			March 31, 2015							December 31, 2014
	Commodity		Quantity			Net Position				Quantity			Net Position
	Natural gas (One Million British Thermal Units)			2,997,500			Long				3,892,500			Long

Fair_Value_Disclosures_Tables

Fair Value Disclosures (Tables)	3 Months Ended
	Mar. 31, 2015
Fair Value of Financial Assets and Liabilities Measured on Recurring Basis	The following tables set forth, by level within the fair value hierarchy, PHI’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2015 and December 31, 2014. 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, 2015
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1) (a)			(Level 2) (a)
			(millions of dollars)
	ASSETS
	Derivative instruments
	Preferred stock		$	3		$	—		$	—		$	3
	Cash equivalents and restricted cash equivalents
	Treasury fund			143			143			—			—
	Executive deferred compensation plan assets
	Money market funds and short-term investments			35			15			20			—
	Life insurance contracts			46			—			27			19
	Total		$	227		$	158		$	47		$	22
	LIABILITIES
	Derivative instruments (b)
	Natural gas (c)		$	2		$	2		$	—		$	—
	Executive deferred compensation plan liabilities
	Life insurance contracts			30			—			30			—
	Total		$	32		$	2		$	30		$	—
	(a)	There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2015.
	(b)	The fair values of derivative liabilities reflect netting by counterparty before the impact of collateral.
	(c)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.
			Fair Value Measurements at December 31, 2014
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1) (a)			(Level 2) (a)
			(millions of dollars)
	ASSETS
	Derivative instruments
	Preferred stock		$	3		$	—		$	—		$	3
	Restricted cash equivalents
	Treasury fund			38			38			—			—
	Executive deferred compensation plan assets
	Money market funds and short-term investments			35			14			21			—
	Life insurance contracts			46			—			27			19
	Total		$	122		$	52		$	48		$	22
	LIABILITIES
	Derivative instruments (b)
	Natural gas (c)		$	4		$	4		$	—		$	—
	Executive deferred compensation plan liabilities
	Life insurance contracts			30			—			30			—
	Total		$	34		$	4		$	30		$	—
	(a)	There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.
	(b)	The fair values of derivative liabilities reflect netting by counterparty before the impact of collateral.
	(c)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.
Reconciliations of Fair Value Measurements Using Significant Unobservable Inputs (Level 3)	Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (Level 3) for the three months ended March 31, 2015 and 2014 are shown below:
			Three Months Ended						Three Months Ended
			March 31, 2015						March 31, 2014
			Preferred			Life			Life
			Stock			Insurance			Insurance
						Contracts			Contracts
			(millions of dollars)
	Beginning balance as of January 1		$	3		$	19		$	19
	Total gains (losses) (realized and unrealized):
	Included in income			—			1			1
	Included in accumulated other comprehensive loss			—			—			—
	Included in regulatory liabilities			—			—			—
	Purchases			—			—			—
	Issuances			—			—			(1	)
	Settlements			—			(1	)		—
	Transfers in (out) of level 3			—			—			—
	Ending balance as of March 31		$	3		$	19		$	19
Gains on Level 3 Instruments Included in Income	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:
			Three Months Ended March 31,
			2015			2014
			(millions of dollars)
	Total net gains included in income for the period		$	1		$	1
	Change in unrealized gains relating to assets still held at reporting date		$	1		$	1
Fair Value of Financial Liabilities Measured on Recurring Basis
			Fair Value Measurements at March 31, 2015
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1)			(Level 2)
			(millions of dollars)
	LIABILITIES
	Debt instruments
	Long-term debt (a)		$	5,871		$	1,890		$	3,524		$	457
	Transition Bonds (b)			224			—			224			—
	Long-term project funding			10			—			—			10
	Total		$	6,105		$	1,890		$	3,748		$	467
	(a)	The carrying amount for Long-term debt was $5,015 million as of March 31, 2015.
	(b)	The carrying amount for Transition Bonds, including amounts due within one year, was $203 million as of March 31, 2015.
			Fair Value Measurements at December 31, 2014
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1)			(Level 2)
			(millions of dollars)
	LIABILITIES
	Debt instruments
	Long-term debt (a)		$	5,583		$	—		$	5,136		$	447
	Transition Bonds (b)			235			—			235			—
	Long-term project funding			28			—			—			28
	Total		$	5,846		$	—		$	5,371		$	475
	(a)	The carrying amount for Long-term debt was $4,807 million as of December 31, 2014.
	(b)	The carrying amount for Transition Bonds, including amounts due within one year, was $215 million as of December 31, 2014.
Delmarva Power & Light Co/De [Member]
Fair Value of Financial Assets and Liabilities Measured on Recurring Basis	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, 2015 and December 31, 2014. 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, 2015
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1) (a)			(Level 2) (a)
			(millions of dollars)
	ASSETS
	Executive deferred compensation plan assets
	Money market funds		$	1		$	1		$	—		$	—
	Total		$	1		$	1		$	—		$	—
	LIABILITIES
	Derivative instruments (b)
	Natural gas (c)		$	2		$	2		$	—		$	—
	Executive deferred compensation plan liabilities
	Life insurance contracts			1			—			1			—
	Total		$	3		$	2		$	1		$	—
	(a)	There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2015.
	(b)	The fair value of derivative liabilities reflect netting by counterparty before the impact of collateral.
	(c)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.
			Fair Value Measurements at December 31, 2014
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1) (a)			(Level 2) (a)
			(millions of dollars)
	ASSETS
	Restricted cash equivalents
	Treasury funds		$	5		$	5		$	—		$	—
	Executive deferred compensation plan assets
	Money market funds			1			1			—			—
	Life insurance contracts			1			—			—			1
	Total		$	7		$	6		$	—		$	1
	LIABILITIES
	Derivative instruments (b)		$	4		$	4		$	—		$	—
	Natural gas (c)
	Executive deferred compensation plan liabilities
	Life insurance contracts			1			—			1			—
	Total		$	5		$	4		$	1		$	—
	(a)	There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.
	(b)	The fair value of derivative liabilities reflect netting by counterparty before the impact of collateral.
	(c)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.
Reconciliations of Fair Value Measurements Using Significant Unobservable Inputs (Level 3)	Reconciliations of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (level 3) for the three months ended March 31, 2015 and 2014 are shown below:
			Three Months Ended			Three Months Ended
			March 31, 2015			March 31, 2014
			Life			Life
			Insurance			Insurance
			Contracts			Contracts
			(millions of dollars)
	Balance as of January 1		$	1		$	1
	Total gains (losses) (realized and unrealized):
	Included in income			—			—
	Included in accumulated other comprehensive loss			—			—
	Included in regulatory liabilities			—			—
	Purchases			—			—
	Issuances			—			—
	Settlements			(1	)		—
	Transfers in (out) of Level 3			—			—
	Balance as of March 31		$	—		$	1
Fair Value of Financial Liabilities Measured on Recurring Basis
			Fair Value Measurements at March 31, 2015
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1)			(Level 2)
			(millions of dollars)
	LIABILITIES
	Debt instruments
	Long-term debt (a)		$	1,139		$	15		$	1,017		$	107
	(a)	The carrying amount for Long-term debt was $1,071 million as of March 31, 2015.
			Fair Value Measurements at December 31, 2014
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1)			(Level 2)
			(millions of dollars)
	LIABILITIES
	Debt instruments
	Long-term debt (a)		$	1,123		$	—		$	1,016		$	107
	(a)	The carrying amount for Long-term debt was $1,071 million as of December 31, 2014.
Atlantic City Electric Co [Member]
Fair Value of Financial Assets and Liabilities Measured on Recurring Basis	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, 2015 and December 31, 2014. 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, 2015
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1) (a)			(Level 2) (a)
			(millions of dollars)
	ASSETS
	Restricted cash equivalents
	Treasury fund		$	24		$	24		$	—		$	—
	(a)	There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2015.
			Fair Value Measurements at December 31, 2014
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1) (a)			(Level 2) (a)
			(millions of dollars)
	ASSETS
	Restricted cash equivalents
	Treasury fund		$	24		$	24		$	—		$	—
	(a)	There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.
Fair Value of Financial Liabilities Measured on Recurring Basis
			Fair Value Measurements at March 31, 2015
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1)			(Level 2)
			(millions of dollars)
	LIABILITIES
	Debt instruments
	Long-term debt (a)		$	1,049		$	—		$	905		$	144
	Transition Bonds (b)			224			—			224			—
	Total		$	1,273		$	—		$	1,129		$	144
	(a)	The carrying amount for Long-term debt was $903 million as of March 31, 2015.
	(b)	The carrying amount for Transition Bonds, including amounts due within one year, was $203 million as of March 31, 2015.
			Fair Value Measurements at December 31, 2014
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1)			(Level 2)
			(millions of dollars)
	LIABILITIES
	Debt instruments
	Long-term debt (a)		$	1,035		$	—		$	903		$	132
	Transition Bonds (b)			235			—			235			—
	Total		$	1,270		$	—		$	1,138		$	132
	(a)	The carrying amount for Long-term debt was $903 million as of December 31, 2014.
	(b)	The carrying amount for Transition Bonds, including amounts due within one year, was $215 million as of December 31, 2014.
Potomac Electric Power Co [Member]
Fair Value of Financial Assets and Liabilities Measured on Recurring Basis	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, 2015 and December 31, 2014. 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, 2015
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1) (a)			(Level 2) (a)
			(millions of dollars)
	ASSETS
	Cash equivalents and restricted cash equivalents
	Treasury fund		$	116		$	116		$	—		$	—
	Executive deferred compensation plan assets
	Money market funds and short-term investments			34			14			20			—
	Life insurance contracts			42			—			23			19
	Total		$	192		$	130		$	43		$	19
	LIABILITIES
	Executive deferred compensation plan liabilities
	Life insurance contracts		$	6		$	—		$	6		$	—
	Total		$	6		$	—		$	6		$	—
	(a)	There were no transfers of instruments between level 1 and level 2 valuation categories during the three months ended March 31, 2015.
			Fair Value Measurements at December 31, 2014
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1) (a)			(Level 2) (a)
			(millions of dollars)
	ASSETS
	Restricted cash equivalents
	Treasury fund		$	5		$	5		$	—		$	—
	Executive deferred compensation plan assets
	Money market funds and short-term investments			34			13			21			—
	Life insurance contracts			41			—			23			18
	Total		$	80		$	18		$	44		$	18
	LIABILITIES
	Executive deferred compensation plan liabilities
	Life insurance contracts		$	7		$	—		$	7		$	—
	Total		$	7		$	—		$	7		$	—
	(a)	There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2014.
Reconciliations of Fair Value Measurements Using Significant Unobservable Inputs (Level 3)	Reconciliations of the beginning and ending balances of Pepco’s fair value measurements using significant unobservable inputs (level 3) for the three months ended March 31, 2015 and 2014 are shown below:
			Life Insurance Contracts
			Three Months Ended
			March 31,
			2015			2014
			(millions of dollars)
	Beginning balance as of January 1		$	18		$	18
	Total gains (losses) (realized and unrealized):
	Included in income			1			1
	Included in accumulated other comprehensive loss			—			—
	Purchases			—			—
	Issuances			—			(1	)
	Settlements			—			—
	Transfers in (out) of level 3			—			—
	Ending balance as of March 31		$	19		$	18
Gains on Level 3 Instruments Included in Income	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,
			2015			2014
			(millions of dollars)
	Total gains included in income for the period		$	1		$	1
	Change in unrealized gains relating to assets still held at reporting date		$	1		$	1
Fair Value of Financial Liabilities Measured on Recurring Basis
			Fair Value Measurements at March 31, 2015
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1)			(Level 2)
			(millions of dollars)
	LIABILITIES
	Debt instruments
	Long-term debt (a)		$	2,884		$	1,624		$	1,260		$	—
	(a)	The carrying amount for Long-term debt was $2,332 million as of March 31, 2015.
			Fair Value Measurements at December 31, 2014
	Description		Total			Quoted Prices in			Significant			Significant
						Active Markets			Other			Unobservable
						for Identical			Observable			Inputs
						Instruments			Inputs			(Level 3)
						(Level 1)			(Level 2)
			(millions of dollars)
	LIABILITIES
	Debt instruments
	Long-term debt (a)		$	2,624		$	—		$	2,624		$	—
	Project funding			12			—			—			12
	Total		$	2,636		$	—		$	2,624		$	12
	(a)	The carrying amount for Long-term debt was $2,124 million as of December 31, 2014.

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	3 Months Ended
	Mar. 31, 2015
Schedule of Accrued Liabilities for Environmental Exposures	The total accrued liabilities for the environmental contingencies described below of PHI and its subsidiaries at March 31, 2015 are summarized as follows:
					Legacy Generation
			Transmission		Regulated		Non-		Total
			and Distribution				Regulated
					(millions of dollars)
	Beginning balance as of January 1		$	17	$	6	$	5	$	28
	Accruals			1		—		—		1
	Payments			—		1		—		1
	Ending balance as of March 31			18		5		5		28
	Less amounts in Other Current Liabilities			3		1		—		4
	Amounts in Other Deferred Credits		$	15	$	4	$	5	$	24
Schedule of Commitments and Obligations	As of March 31, 2015, 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 were as follows:
			Guarantor
			PHI		Pepco		DPL		ACE		Total
			(millions of dollars)
	Guarantees associated with disposal of Conectiv Energy assets (a)		$	13	$	—	$	—	$	—	$	13
	Guaranteed lease residual values (b)			3		5		6		5		19
	Total		$	16	$	5	$	6	$	5	$	32
	(a)	Represents guarantees by PHI of Conectiv Energy’s derivatives portfolio transferred in connection with the disposition of Conectiv Energy’s wholesale business. The derivative portfolio guarantee is currently $13 million and covers Conectiv Energy’s performance prior to the assignment. This guarantee will remain in effect until the end of 2015.
	(b)	Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $52 million, $11 million of which is a guaranty by PHI, $13 million by Pepco, $15 million by DPL and $13 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.
Delmarva Power & Light Co/De [Member]
Schedule of Accrued Liabilities for Environmental Exposures	The total accrued liabilities for the environmental contingencies of DPL described below at March 31, 2015 are summarized as follows:
			Transmission		Legacy		Total
			and Distribution		Generation -
					Regulated
					(millions of dollars)
	Beginning balance as of January 1		$	1	$	2	$	3
	Accruals			1		—		1
	Payments			—		1		1
	Ending balance as of March 31			2		1		3
	Less amounts in Other Current Liabilities			1		1		2
	Amounts in Other Deferred Credits		$	1	$	—	$	1
Atlantic City Electric Co [Member]
Schedule of Accrued Liabilities for Environmental Exposures	The total accrued liabilities for the environmental contingencies of ACE described below at March 31, 2015 are summarized as follows:
			Legacy Generation -
			Regulated
			(millions of dollars)
	Beginning balance as of January 1		$	1
	Accruals			—
	Payments			—
	Ending balance as of March 31			1
	Less amounts in Other Current Liabilities			—
	Amounts in Other Deferred Credits		$	1
Potomac Electric Power Co [Member]
Schedule of Accrued Liabilities for Environmental Exposures	The total accrued liabilities for the environmental contingencies of Pepco described below at March 31, 2015 are summarized as follows:
			Transmission		Legacy		Total
			and		Generation -
			Distribution		Regulated
			(millions of dollars)
	Beginning balance as of January 1		$	16	$	3	$	19
	Accruals			—		—		—
	Payments			—		—		—
	Ending balance as of March 31			16		3		19
	Less amounts in Other Current Liabilities			2		—		2
	Amounts in Other Deferred Credits		$	14	$	3	$	17

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Loss (Tables)	3 Months Ended
	Mar. 31, 2015
Equity [Abstract]
Schedule of Components of Other Comprehensive Loss	The components of Pepco Holdings’ AOCL are as follows. For additional information, see the consolidated statements of comprehensive income.
		Three Months Ended
		March 31,
		2015			2014
		(millions of dollars)
	Balance as of January 1	$	(46	)	$	(34	)
	Treasury Lock
	Balance as of January 1		(9	)		(9	)
	Amount of pre-tax loss reclassified to Interest expense		—			—
	Income tax benefit		—			—
	Balance as of March 31		(9	)		(9	)
	Pension and Other Postretirement Benefits
	Balance as of January 1		(37	)		(25	)
	Amount of amortization of net prior service cost and actuarial loss reclassified to Other operation and maintenance expense		2			1
	Income tax expense		1			—
	Balance as of March 31		(36	)		(24	)
	Balance as of March 31	$	(45	)	$	(33	)

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2015
Delmarva Power & Light Co/De [Member]
Schedule of Related Party Transactions Included in Financial Statements	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:
			Three Months Ended
			March 31,
			2015			2014
			(millions of dollars)
	Intercompany lease transactions (a)		$	1		$	1
	(a)	Included in Electric revenue.
	As of March 31, 2015 and December 31, 2014, DPL had the following balances on its balance sheets due to related parties:
			March 31,			December 31,
			2015			2014
			(millions of dollars)
	Payable to Related Party (current) (a)
	PHI Service Company		$	(21	)	$	(18	)
	Other			—			1
	Total		$	(21	)	$	(17	)
	(a)	Included in Accounts payable due to associated companies.
Atlantic City Electric Co [Member]
Schedule of Related Party Transactions Included in Financial Statements	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,
			2015			2014
			(millions of dollars)
	Meter reading services provided by Millennium Account Services LLC (an ACE affiliate) (a)		$	(1	)	$	(1	)
	(a)	Included in Other operation and maintenance expense.
	As of March 31, 2015 and December 31, 2014, ACE had the following balances on its consolidated balance sheets due to related parties:
			March 31,			December 31,
			2015			2014
			(millions of dollars)
	Payable to Related Party (current) (a)
	PHI Service Company		$	(15	)	$	(14	)
	Other			(2	)		(1	)
	Total		$	(17	)	$	(15	)
	(a)	Included in Accounts payable due to associated companies.
Potomac Electric Power Co [Member]
Schedule of Related Party Transactions Included in Financial Statements	As of March 31, 2015 and December 31, 2014, Pepco had the following balances on its balance sheets due to related parties:
			March 31,			December 31,
			2015			2014
			(millions of dollars)
	Payable to Related Party (current) (a)
	PHI Service Company		$	(34	)	$	(27	)
	Pepco Energy Services (b)			(4	)		(2	)
	Other			(13	)		(1	)
	Total		$	(51	)	$	(30	)
	(a)	Included in Accounts payable due to associated companies.
	(b)	Pepco bills customers on behalf of Pepco Energy Services where Pepco Energy Services has performed work for certain government agencies under a General Services Administration area-wide agreement. Amount also includes charges for utility work performed by Pepco Energy Services on behalf of Pepco.

Organization_Additional_Inform

Organization - Additional Information (Detail) (USD $)	0 Months Ended	3 Months Ended	0 Months Ended
	Apr. 29, 2014	Mar. 31, 2015	Jan. 26, 2015	Oct. 27, 2014	Jul. 29, 2014	Apr. 30, 2014	Apr. 27, 2015	Dec. 31, 2014
Reorganization [Line Items]
Common stock, par value	$0.01	$0.01						$0.01
Right to receive cash under cancellation of shares	$27.25
Non-voting Series A Preferred Stock, maximum number of shares issued			1,800	1,800	1,800
Amount Of Non Voting Series A Preferred Stock Purchase price		$18,000,000
Non-voting Series A Preferred Stock, maximum aggregate consideration	180,000,000
Termination fee	259,000,000
Reimbursement of termination related expenses	40,000,000
Redemption of preferred stock at purchase price		$10,000
Potomac Electric Power Co [Member]
Reorganization [Line Items]
Common stock, par value	$0.01	$0.01						$0.01
Right to receive cash under cancellation of shares	$27.25
Non-voting Series A Preferred Stock, maximum number of shares issued			1,800	1,800	1,800
Non-voting Series A Preferred Stock, maximum aggregate consideration	180,000,000
Termination fee	259,000,000
Reimbursement of termination related expenses	40,000,000
Redemption of preferred stock at purchase price		$10,000
Delmarva Power & Light Co/De [Member]
Reorganization [Line Items]
Common stock, par value	$0.01	$2.25						$2.25
Right to receive cash under cancellation of shares	$27.25
Non-voting Series A Preferred Stock, maximum number of shares issued			1,800	1,800	1,800
Non-voting Series A Preferred Stock, maximum aggregate consideration	180,000,000
Termination fee	259,000,000
Reimbursement of termination related expenses	40,000,000
Redemption of preferred stock at purchase price		$10,000
Atlantic City Electric Co [Member]
Reorganization [Line Items]
Common stock, par value	$0.01	$3						$3
Right to receive cash under cancellation of shares	$27.25
Non-voting Series A Preferred Stock, maximum number of shares issued			1,800	1,800	1,800
Non-voting Series A Preferred Stock, maximum aggregate consideration	180,000,000
Termination fee	259,000,000
Reimbursement of termination related expenses	40,000,000
Redemption of preferred stock at purchase price		$10,000
Non-Voting Series A Preferred Stock [Member]
Reorganization [Line Items]
Issuance of non-voting Series A Preferred Stock, shares issued						9,000
Non-voting Series A Preferred Stock, par value						$0.01
Non-voting Series A Preferred Stock, shares purchased price						90,000,000
Amount Of Non Voting Series A Preferred Stock Purchase price			18,000,000	18,000,000	18,000,000
Non-voting Series A Preferred Stock, cumulative, non-participating cash dividend						0.10%
Non-Voting Series A Preferred Stock [Member] | Potomac Electric Power Co [Member]
Reorganization [Line Items]
Issuance of non-voting Series A Preferred Stock, shares issued						9,000
Non-voting Series A Preferred Stock, par value						$0.01
Non-voting Series A Preferred Stock, shares purchased price						90,000,000
Amount Of Non Voting Series A Preferred Stock Purchase price			18,000,000	18,000,000	18,000,000
Non-voting Series A Preferred Stock, cumulative, non-participating cash dividend						0.10%
Non-Voting Series A Preferred Stock [Member] | Delmarva Power & Light Co/De [Member]
Reorganization [Line Items]
Issuance of non-voting Series A Preferred Stock, shares issued						9,000
Non-voting Series A Preferred Stock, par value						$0.01
Non-voting Series A Preferred Stock, shares purchased price						90,000,000
Amount Of Non Voting Series A Preferred Stock Purchase price			18,000,000	18,000,000	18,000,000
Non-voting Series A Preferred Stock, cumulative, non-participating cash dividend						0.10%
Non-Voting Series A Preferred Stock [Member] | Atlantic City Electric Co [Member]
Reorganization [Line Items]
Issuance of non-voting Series A Preferred Stock, shares issued						9,000
Non-voting Series A Preferred Stock, par value						$0.01
Non-voting Series A Preferred Stock, shares purchased price						90,000,000
Amount Of Non Voting Series A Preferred Stock Purchase price			18,000,000	18,000,000	18,000,000
Non-voting Series A Preferred Stock, cumulative, non-participating cash dividend						0.10%
Terminations Due to New Acquisition Proposal [Member]
Reorganization [Line Items]
Termination fee	293,000,000
Terminations Due to New Acquisition Proposal [Member] | Potomac Electric Power Co [Member]
Reorganization [Line Items]
Termination fee	293,000,000
Terminations Due to New Acquisition Proposal [Member] | Delmarva Power & Light Co/De [Member]
Reorganization [Line Items]
Termination fee	293,000,000
Terminations Due to New Acquisition Proposal [Member] | Atlantic City Electric Co [Member]
Reorganization [Line Items]
Termination fee	293,000,000
Subsequent Event [Member]
Reorganization [Line Items]
Non-voting Series A Preferred Stock, maximum number of shares issued							1,800
Subsequent Event [Member] | Potomac Electric Power Co [Member]
Reorganization [Line Items]
Non-voting Series A Preferred Stock, maximum number of shares issued							1,800
Subsequent Event [Member] | Delmarva Power & Light Co/De [Member]
Reorganization [Line Items]
Non-voting Series A Preferred Stock, maximum number of shares issued							1,800
Subsequent Event [Member] | Atlantic City Electric Co [Member]
Reorganization [Line Items]
Non-voting Series A Preferred Stock, maximum number of shares issued							1,800
Subsequent Event [Member] | Non-Voting Series A Preferred Stock [Member]
Reorganization [Line Items]
Amount Of Non Voting Series A Preferred Stock Purchase price							18,000,000
Subsequent Event [Member] | Non-Voting Series A Preferred Stock [Member] | Potomac Electric Power Co [Member]
Reorganization [Line Items]
Amount Of Non Voting Series A Preferred Stock Purchase price							18,000,000
Subsequent Event [Member] | Non-Voting Series A Preferred Stock [Member] | Delmarva Power & Light Co/De [Member]
Reorganization [Line Items]
Amount Of Non Voting Series A Preferred Stock Purchase price							18,000,000
Subsequent Event [Member] | Non-Voting Series A Preferred Stock [Member] | Atlantic City Electric Co [Member]
Reorganization [Line Items]
Amount Of Non Voting Series A Preferred Stock Purchase price							18,000,000
Maximum [Member]
Reorganization [Line Items]
Non-voting Series A Preferred Stock, maximum number of shares issued	18,000
Maximum [Member] | Potomac Electric Power Co [Member]
Reorganization [Line Items]
Non-voting Series A Preferred Stock, maximum number of shares issued	18,000
Maximum [Member] | Delmarva Power & Light Co/De [Member]
Reorganization [Line Items]
Non-voting Series A Preferred Stock, maximum number of shares issued	18,000
Maximum [Member] | Atlantic City Electric Co [Member]
Reorganization [Line Items]
Non-voting Series A Preferred Stock, maximum number of shares issued	18,000
Maximum [Member] | Exelon [Member]
Reorganization [Line Items]
Out-of-pocket expenses, connection with the Merger Agreement	40,000,000
Maximum [Member] | Exelon [Member] | Potomac Electric Power Co [Member]
Reorganization [Line Items]
Out-of-pocket expenses, connection with the Merger Agreement	40,000,000
Maximum [Member] | Exelon [Member] | Delmarva Power & Light Co/De [Member]
Reorganization [Line Items]
Out-of-pocket expenses, connection with the Merger Agreement	40,000,000
Maximum [Member] | Exelon [Member] | Atlantic City Electric Co [Member]
Reorganization [Line Items]
Out-of-pocket expenses, connection with the Merger Agreement	$40,000,000

Significant_Accounting_Policie2

Significant Accounting Policies - Additional Information (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Significant Accounting Policies [Line Items]
Estimated fair value of an asset	Greater than 50%
Taxes included in gross revenues	$83	$83
Potomac Electric Power Co [Member]
Significant Accounting Policies [Line Items]
Taxes included in gross revenues	78	78
Delmarva Power & Light Co/De [Member]
Significant Accounting Policies [Line Items]
Estimated fair value of an asset	Greater than 50%
Taxes included in gross revenues	5	4
Atlantic City Electric Co [Member]
Significant Accounting Policies [Line Items]
Taxes included in gross revenues	$0	$1

Segment_Information_Segment_Fi

Segment Information - Segment Financial Information (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Segment Reporting Information [Line Items]
Operating Revenue	$1,371	$1,330
Operating Expenses	1,229	1,157
Operating Income	142	173
Interest Expense	68	65
Other Income	9	13
Income Tax Expense (Benefit)	30	46
Net Income	53	75
Total Assets	16,027	15,004	15,667
Construction Expenditures	246	282
Operating Segments [Member] | Power Delivery [Member]
Segment Reporting Information [Line Items]
Operating Revenue	1,313	1,272
Operating Expenses	1,167	1,103
Operating Income	146	169
Interest Expense	58	55
Other Income	9	12
Income Tax Expense (Benefit)	35	47
Net Income	62	79
Total Assets	14,082	13,438
Construction Expenditures	241	264
Operating Segments [Member] | Pepco Energy Services [Member]
Segment Reporting Information [Line Items]
Operating Revenue	60	60
Operating Expenses	61	60
Operating Income	-1
Income Tax Expense (Benefit)	-5
Net Income	4
Total Assets	237	287
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating Revenue	-2	-2
Operating Expenses	1	-6
Operating Income	-3	4
Interest Expense	10	10
Other Income		1
Income Tax Expense (Benefit)		-1
Net Income	-13	-4
Total Assets	1,708	1,279
Construction Expenditures	$5	$18

Segment_Information_Segment_Fi1

Segment Information - Segment Financial Information (Parenthetical) (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Segment Reporting Information [Line Items]
Goodwill	$1,406	$1,407	$1,407
Operating Revenue	1,371	1,330
Operating Expenses	1,229	1,157
Interest Expense	68	65
Depreciation and amortization	159	133
Operating Segments [Member] | Power Delivery [Member]
Segment Reporting Information [Line Items]
Goodwill	1,400	1,400
Operating Revenue	1,313	1,272
Operating Expenses	1,167	1,103
Interest Expense	58	55
Depreciation and amortization	147	124
Operating Segments [Member] | Pepco Energy Services [Member]
Segment Reporting Information [Line Items]
Operating Revenue	60	60
Operating Expenses	61	60
Depreciation and amortization	1	2
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating Revenue	-2	-2
Operating Expenses	1	-6
Interest Expense	10	10
Depreciation and amortization	11	7
Corporate and Other [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating Revenue	-2	-2
Operating Expenses	-2	-1
Interest Expense	($1)	($1)

Goodwill_Additional_Informatio

Goodwill - Additional Information (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014
In Millions, unless otherwise specified
Goodwill [Line Items]
Goodwill	$1,406	$1,407	$1,407
Delmarva Power & Light Co/De [Member]
Goodwill [Line Items]
Goodwill	$8	$8

Regulatory_Matters_Additional_

Regulatory Matters - Additional Information (Detail) (USD $)

0 Months Ended

1 Months Ended

3 Months Ended

1 Months Ended

0 Months Ended

1 Months Ended

Apr. 15, 2014

Sep. 20, 2013

Oct. 31, 2014

Aug. 31, 2014

31-May-14

Jul. 31, 2012

Dec. 31, 2011

Mar. 31, 2015

Dec. 31, 2014

Jul. 31, 2014

Dec. 31, 2013

Oct. 31, 2013

Mar. 31, 2013

Feb. 28, 2013

Jul. 31, 2013

Nov. 30, 2012

Feb. 28, 2013

Apr. 16, 2014

Mar. 31, 2015

Mar. 31, 2014

Apr. 30, 2012

MW

Public Utilities, General Disclosures [Line Items]

Requested rate change

$39,000,000

$18,100,000

Return on equity, percentage

9.31%

10.75%

Effect of proposed change on Gas Cost Rate

7.40%

Adjusted rate change

37,400,000

Consolidated tax adjustment calculation review period

5 years

Percentage of revenue requirement related to consolidated tax adjustment calculation

25.00%

New power plant output

661

Undergrounding project cost

1,000,000,000

Bear estimated complete project

500,000,000

Merger agreement

Following informal discussions with the DOJ, effective as of September 5, 2014, Exelon withdrew its Notification and Report Form and refiled it on September 9, 2014, which restarted the waiting period required by the HSR Act. On October 9, 2014, each of Pepco Holdings and Exelon received a request for additional information and documentary material from the DOJ, which had the effect of extending the DOJ review period until 30 days after each of Pepco Holdings and Exelon certified that it has substantially complied with the request.

Federal Energy Regulatory Commission Return On Equity Complaint [Member]

Public Utilities, General Disclosures [Line Items]

Return on equity, percentage

8.80%

One-time reduction on settlement

225,000

One-time payment on settlement

258,500

ROE determined, description

Each ten basis point reduction in the ROE would result in a reduction of PHI's operating income of $1.9 million.

Reduction in operating income

1,900,000

Expected [Member]

Public Utilities, General Disclosures [Line Items]

Requested rate change

68,400,000

8,750,000

43,300,000

Return on equity, percentage

9.62%

10.25%

Actual [Member]

Public Utilities, General Disclosures [Line Items]

Requested rate change

66,200,000

District of Columbia [Member] | DC Undergrounding Task Force [Member]

Public Utilities, General Disclosures [Line Items]

Underground project cost

375,000,000

Minimum [Member]

Public Utilities, General Disclosures [Line Items]

New power plant output

650

Maximum [Member]

Public Utilities, General Disclosures [Line Items]

New power plant output

700

Maximum [Member] | District of Columbia [Member] | Department of Transportation [Member]

Public Utilities, General Disclosures [Line Items]

Under grounding project costs covered by existing capital projects program

125,000,000

Delmarva Power & Light Co/De [Member]

Public Utilities, General Disclosures [Line Items]

Requested rate change

39,000,000

15,100,000

56,000,000

42,000,000

Return on equity, percentage

9.70%

10.80%

10.25%

Increased distribution base period

4 years

Estimated return on equity, year one

7.41%

Estimated return on equity, year two

8.80%

Estimated return on equity, year three

9.75%

Estimated return on equity, year four

9.75%

Customer refundable fees

500,000

Effect of proposed change on Gas Cost Rate

7.40%

Basis-point

50.00%

50.00%

New power plant output

661

Additional interim rate increase implemented

15,100,000

Delmarva Power & Light Co/De [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member]

Public Utilities, General Disclosures [Line Items]

Return on equity, percentage

11.30%

8.80%

8.70%

One-time reduction on settlement

225,000

One-time payment on settlement

258,500

ROE determined, description

Each ten basis point reduction in the ROE would result in a reduction of DPL's operating income of $0.6 million.

Reduction in operating income

600,000

Delmarva Power & Light Co/De [Member] | Minimum [Member]

Public Utilities, General Disclosures [Line Items]

New power plant output

650

Delmarva Power & Light Co/De [Member] | Minimum [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member]

Public Utilities, General Disclosures [Line Items]

Return on equity, percentage

6.78%

Delmarva Power & Light Co/De [Member] | Maximum [Member]

Public Utilities, General Disclosures [Line Items]

New power plant output

700

Delmarva Power & Light Co/De [Member] | Maximum [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member]

Public Utilities, General Disclosures [Line Items]

Return on equity, percentage

10.33%

Potomac Electric Power Co [Member]

Public Utilities, General Disclosures [Line Items]

Requested rate change

18,100,000

68,400,000

Return on equity, percentage

9.31%

10.75%

10.80%

9.36%

10.25%

Requested rate change

27,900,000

Charges on cost of recovery

24,000,000

Adjusted rate change

37,400,000

Basis-point

50.00%

50.00%

New power plant output

661

Undergrounding project cost

1,000,000,000

Bear estimated complete project

500,000,000

Return on equity, percentage

9.36%

Potomac Electric Power Co [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member]

Public Utilities, General Disclosures [Line Items]

Return on equity, percentage

11.30%

8.80%

8.70%

8.70%

ROE determined, description

Each ten basis point reduction in the ROE would result in a reduction of Pepco's operating income of $0.8 million.

Reduction in operating income

800,000

Potomac Electric Power Co [Member] | Expected [Member]

Public Utilities, General Disclosures [Line Items]

Requested rate change

8,750,000

43,300,000

60,800,000

Return on equity, percentage

9.62%

10.25%

Potomac Electric Power Co [Member] | Actual [Member]

Public Utilities, General Disclosures [Line Items]

Requested rate change

66,200,000

Potomac Electric Power Co [Member] | District of Columbia [Member] | DC Undergrounding Task Force [Member]

Public Utilities, General Disclosures [Line Items]

Underground project cost

375,000,000

Potomac Electric Power Co [Member] | Minimum [Member]

Public Utilities, General Disclosures [Line Items]

New power plant output

650

Potomac Electric Power Co [Member] | Minimum [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member]

Public Utilities, General Disclosures [Line Items]

Return on equity, percentage

6.78%

6.78%

Potomac Electric Power Co [Member] | Maximum [Member]

Public Utilities, General Disclosures [Line Items]

New power plant output

700

Potomac Electric Power Co [Member] | Maximum [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member]

Public Utilities, General Disclosures [Line Items]

Return on equity, percentage

10.33%

10.33%

Potomac Electric Power Co [Member] | Maximum [Member] | District of Columbia [Member] | Department of Transportation [Member]

Public Utilities, General Disclosures [Line Items]

Under grounding project costs covered by existing capital projects program

125,000,000

Atlantic City Electric Co [Member]

Public Utilities, General Disclosures [Line Items]

Return on equity, percentage

10.80%

Overall annual rate decrease as net impact of adjusting charges

41,100,000

41,100,000

52,000,000

24,500,000

Contributions received by ACE

11,000,000

11,000,000

Consolidated tax adjustment calculation review period

5 years

Percentage of revenue requirement related to consolidated tax adjustment calculation

25.00%

Basis-point

50.00%

50.00%

Atlantic City Electric Co [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member]

Public Utilities, General Disclosures [Line Items]

Return on equity, percentage

11.30%

8.80%

8.70%

ROE determined, description

Each ten basis point reduction in the ROE would result in a reduction of ACE's operating income of $0.5 million.

Reduction in operating income

500,000

Atlantic City Electric Co [Member] | Minimum [Member]

Public Utilities, General Disclosures [Line Items]

Contributions received by ACE

1,000,000

1,000,000

Atlantic City Electric Co [Member] | Minimum [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member]

Public Utilities, General Disclosures [Line Items]

Return on equity, percentage

6.78%

Atlantic City Electric Co [Member] | Maximum [Member]

Public Utilities, General Disclosures [Line Items]

Contributions received by ACE

1,000,000

$1,000,000

Atlantic City Electric Co [Member] | Maximum [Member] | Federal Energy Regulatory Commission Return On Equity Complaint [Member]

Public Utilities, General Disclosures [Line Items]

Return on equity, percentage

10.33%

Pension_and_Other_Postretireme2

Pension and Other Postretirement Benefits - Components of Net Periodic Benefit Costs (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$14	$12
Interest cost	27	27
Expected return on plan assets	-35	-35
Amortization of net actuarial loss	16	11
Net periodic benefit cost	22	15
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	2	2
Interest cost	6	7
Expected return on plan assets	-6	-6
Amortization of prior service cost (benefit)	-3	-3
Amortization of net actuarial loss	3	3
Net periodic benefit cost	$2	$3

Pension_and_Other_Postretireme3

Pension and Other Postretirement Benefits - Additional Information (Detail) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
PHI Service Company [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of postretirement benefit costs	36.00%
PHI Service Company [Member] | Retiree [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension contributions	$0	$0
Potomac Electric Power Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension contributions	0	0
Pension and other postretirement net periodic benefit cost	24,000,000	18,000,000
Pension and other postretirement net periodic benefit cost, allocated portion	8,000,000	7,000,000
Potomac Electric Power Co [Member] | Retiree [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension contributions	0	0
Delmarva Power & Light Co/De [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension contributions	0	0
Pension and other postretirement net periodic benefit cost	24,000,000	18,000,000
Pension and other postretirement net periodic benefit cost, allocated portion	4,000,000	3,000,000
Delmarva Power & Light Co/De [Member] | Retiree [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension contributions	0	0
Atlantic City Electric Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension contributions	0	0
Pension and other postretirement net periodic benefit cost	24,000,000	18,000,000
Pension and other postretirement net periodic benefit cost, allocated portion	4,000,000	4,000,000
Atlantic City Electric Co [Member] | Retiree [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension contributions	$0	$0

Debt_Additional_Information_De

Debt - Additional Information (Detail) (USD $)	3 Months Ended	12 Months Ended	0 Months Ended	1 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Oct. 24, 2013	Apr. 30, 2015	Jan. 31, 2015
	Sublimit
Debt Instrument [Line Items]
Credit facility, termination date	1-Aug-18
Line of credit facility maximum borrowing capacity	$1,500,000,000
Parent company credit facility letter of credit, maximum	500,000,000
Same day borrowings maximum percentage amount	10.00%
Swingline loan repayment period	14 days
Credit facility borrowing capacity	750,000,000
Maximum amount of credit available to parent	1,250,000,000
Subsidiary borrowing limit under parent's credit facility	500,000,000
Maximum number of sublimit reallocations per year	8
Debt instrument variable interest rate in addition to one month LIBOR's effective rate	1.00%
Borrowing capacity under the credit facility	916,000,000	875,000,000
Utility subsidiaries combined cash and borrowing capacity	547,000,000	413,000,000
Amended description of Change in Control	The Consent amends the definition of "Change in Control" in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings.
Ownership percentage of outstanding voting stock for Change in Control		100.00%
On-going commercial paper	875,000,000
Commercial paper outstanding	803,000,000	729,000,000
Commercial paper weighted average maturity, in days	8 days
Purchase price		12,000,000
Contract payment period		9 years
Pepco Energy Services [Member]
Debt Instrument [Line Items]
Purchase price			7,000,000
Contract payment period			23 years
Federal Funds Effective Rate [Member]
Debt Instrument [Line Items]
Debt instrument variable interest rate in addition to the federal funds effective rate	0.50%
Commercial Paper [Member]
Debt Instrument [Line Items]
Commercial paper weighted average interest rate	0.74%
Bonds and Debentures [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Debt instrument periodical principal payments				7,000,000
Bonds and Notes [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Debt instrument periodical principal payments				3,000,000
First Mortgage Bonds [Member] | 4.15% Due 2043 [Member]
Debt Instrument [Line Items]
Debt instrument, face amount	200,000,000
Debt instruments maturity date	15-Mar-43
Debt instrument, interest percentage	4.15%
Debt instrument, yield to maturity rate	3.90%
Debt instrument, premium	8,000,000
Maximum [Member]
Debt Instrument [Line Items]
Ratio of indebtedness to total capitalization	65.00%
Ratio of deferrable interest subordinated debt to total capitalization	15.00%
Potomac Electric Power Co [Member]
Debt Instrument [Line Items]
Credit facility, termination date	1-Aug-18
Line of credit facility maximum borrowing capacity	1,500,000,000
Parent company credit facility letter of credit, maximum	500,000,000
Same day borrowings maximum percentage amount	10.00%
Swingline loan repayment period	14 days
Credit facility borrowing capacity	250,000,000
Maximum amount of credit available to parent	1,250,000,000
Subsidiary borrowing limit under parent's credit facility	500,000,000
Maximum number of sublimit reallocations per year	8
Debt instrument variable interest rate in addition to one month LIBOR's effective rate	1.00%
Utility subsidiaries combined cash and borrowing capacity	547,000,000	413,000,000
Amended description of Change in Control	The Consent amends the definition of "Change in Control" in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings.
Ownership percentage of outstanding voting stock for Change in Control		100.00%
On-going commercial paper	500,000,000
Commercial paper outstanding		104,000,000
Commercial paper weighted average maturity, in days	5 days
Purchase price		12,000,000
Contract payment period		9 years
Potomac Electric Power Co [Member] | Federal Funds Effective Rate [Member]
Debt Instrument [Line Items]
Debt instrument variable interest rate in addition to the federal funds effective rate	0.50%
Potomac Electric Power Co [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Commercial paper outstanding	0
Commercial paper weighted average interest rate	0.43%
Potomac Electric Power Co [Member] | First Mortgage Bonds [Member] | 4.15% Due 2043 [Member]
Debt Instrument [Line Items]
Debt instrument, face amount	200,000,000
Debt instruments maturity date	15-Mar-43
Debt instrument, interest percentage	4.15%
Debt instrument, yield to maturity rate	3.90%
Debt instrument, premium	8,000,000
Potomac Electric Power Co [Member] | Maximum [Member]
Debt Instrument [Line Items]
Ratio of indebtedness to total capitalization	65.00%
Ratio of deferrable interest subordinated debt to total capitalization	15.00%
Delmarva Power & Light Co/De [Member]
Debt Instrument [Line Items]
Credit facility, termination date	1-Aug-18
Line of credit facility maximum borrowing capacity	1,500,000,000
Parent company credit facility letter of credit, maximum	500,000,000
Same day borrowings maximum percentage amount	10.00%
Swingline loan repayment period	14 days
Credit facility borrowing capacity	250,000,000
Maximum amount of credit available to parent	1,250,000,000
Subsidiary borrowing limit under parent's credit facility	500,000,000
Maximum number of sublimit reallocations per year	8
Debt instrument variable interest rate in addition to one month LIBOR's effective rate	1.00%
Utility subsidiaries combined cash and borrowing capacity	547,000,000	413,000,000
Amended description of Change in Control	The Consent amends the definition of "Change in Control" in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings.
Ownership percentage of outstanding voting stock for Change in Control		100.00%
On-going commercial paper	500,000,000
Commercial paper outstanding	280,000,000	211,000,000
Commercial paper weighted average maturity, in days	5 days
Delmarva Power & Light Co/De [Member] | Federal Funds Effective Rate [Member]
Debt Instrument [Line Items]
Debt instrument variable interest rate in addition to the federal funds effective rate	0.50%
Delmarva Power & Light Co/De [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Commercial paper outstanding	175,000,000
Commercial paper weighted average interest rate	0.45%
Delmarva Power & Light Co/De [Member] | Maximum [Member]
Debt Instrument [Line Items]
Ratio of indebtedness to total capitalization	65.00%
Ratio of deferrable interest subordinated debt to total capitalization	15.00%
Atlantic City Electric Co [Member]
Debt Instrument [Line Items]
Credit facility, termination date	1-Aug-18
Line of credit facility maximum borrowing capacity	1,500,000,000
Parent company credit facility letter of credit, maximum	500,000,000
Same day borrowings maximum percentage amount	10.00%
Swingline loan repayment period	14 days
Credit facility borrowing capacity	250,000,000
Maximum amount of credit available to parent	1,250,000,000
Subsidiary borrowing limit under parent's credit facility	500,000,000
Maximum number of sublimit reallocations per year	8
Utility subsidiaries combined cash and borrowing capacity	547,000,000	413,000,000
Amended description of Change in Control	The Consent amends the definition of "Change in Control" in the credit agreement to mean, following consummation of the Merger, an event or series of events by which Exelon no longer owns, directly or indirectly, 100% of the outstanding shares of voting stock of Pepco Holdings.
Ownership percentage of outstanding voting stock for Change in Control		100.00%
On-going commercial paper	350,000,000
Commercial paper outstanding	143,000,000	127,000,000
Commercial paper weighted average maturity, in days	5 days
Atlantic City Electric Co [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Commercial paper outstanding	143,000,000
Commercial paper weighted average interest rate	0.44%
Atlantic City Electric Co [Member] | Bonds and Debentures [Member]
Debt Instrument [Line Items]
Debt instrument periodical principal payments					8,000,000
Atlantic City Electric Co [Member] | Bonds and Debentures [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Debt instrument periodical principal payments				7,000,000
Atlantic City Electric Co [Member] | Bonds and Notes [Member]
Debt Instrument [Line Items]
Debt instrument periodical principal payments					3,000,000
Atlantic City Electric Co [Member] | Bonds and Notes [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Debt instrument periodical principal payments				3,000,000
Atlantic City Electric Co [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt instrument variable interest rate in addition to one month LIBOR's effective rate	1.00%
Ratio of indebtedness to total capitalization	65.00%
Ratio of deferrable interest subordinated debt to total capitalization	15.00%
Atlantic City Electric Co [Member] | Maximum [Member] | Federal Funds Effective Rate [Member]
Debt Instrument [Line Items]
Debt instrument variable interest rate in addition to the federal funds effective rate	0.50%
PHI [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Commercial paper outstanding	$380,000,000

Income_Taxes_Reconciliation_of

Income Taxes - Reconciliation of Consolidated Income Tax Expense from Continuing Operations (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Income Tax Rate Reconciliation [Line Items]
Income tax at Federal statutory rate	$29	$42
State income taxes, net of federal effect	6	7
Asset removal costs	-3	-2
Change in estimates and interest related to uncertain and effectively settled tax positions		-1
Energy efficiency-related tax deductions	-4
Merger-related costs	2
Consolidated income tax expense	30	46
Income tax at Federal statutory rate, percentage	35.00%	35.00%
State income taxes, net of federal effect, percentage	7.20%	5.80%
Asset removal costs, percentage	-3.60%	-1.70%
Change in estimates and interest related to uncertain and effectively settled tax positions, percentage		-0.80%
Energy efficiency-related tax deductions	-4.80%
Merger-related costs, percentage	2.40%
Other, net, percentage	-0.10%	-0.30%
Consolidated income tax expense (benefit), percentage	36.10%	38.00%
Potomac Electric Power Co [Member]
Income Tax Rate Reconciliation [Line Items]
Income tax at Federal statutory rate	13	17
State income taxes, net of federal effect	2	3
Asset removal costs	-3	-2
Change in estimates and interest related to uncertain and effectively settled tax positions		-1
Other, net		-1
Consolidated income tax expense	12	16
Income tax at Federal statutory rate, percentage	35.00%	35.00%
State income taxes, net of federal effect, percentage	5.30%	6.30%
Asset removal costs, percentage	-7.90%	-4.20%
Change in estimates and interest related to uncertain and effectively settled tax positions, percentage		-2.10%
Other, net, percentage	-0.80%	-1.70%
Consolidated income tax expense (benefit), percentage	31.60%	33.30%
Delmarva Power & Light Co/De [Member]
Income Tax Rate Reconciliation [Line Items]
Income tax at Federal statutory rate	19	22
State income taxes, net of federal effect	3	3
Other, net	-1
Consolidated income tax expense	21	25
Income tax at Federal statutory rate, percentage	35.00%	35.00%
State income taxes, net of federal effect, percentage	5.70%	4.80%
Other, net, percentage	-1.10%	0.50%
Consolidated income tax expense (benefit), percentage	39.60%	40.30%
Atlantic City Electric Co [Member]
Income Tax Rate Reconciliation [Line Items]
Income tax at Federal statutory rate	2	6
Consolidated income tax expense	$2	$6
Income tax at Federal statutory rate, percentage	35.00%	35.00%
Other, net, percentage	-1.70%	2.50%
Consolidated income tax expense (benefit), percentage	33.30%	37.50%

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Detail) (USD $)	3 Months Ended		0 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Feb. 26, 2015
Schedule of Income Tax [Line Items]
Consolidated effective tax rates	36.10%	38.00%
Tax benefit related to certain energy efficiency tax deductions	$4
Reduction in deferred tax liabilities	23
District of Columbia [Member]
Schedule of Income Tax [Line Items]
Corporate tax rate			9.98%
District of Columbia [Member] | 2019 [Member]
Schedule of Income Tax [Line Items]
Corporate tax rate			8.25%
District of Columbia [Member] | 2015 [Member]
Schedule of Income Tax [Line Items]
Corporate tax rate			9.40%
Potomac Electric Power Co [Member]
Schedule of Income Tax [Line Items]
Consolidated effective tax rates	31.60%	33.30%
Reduction in deferred tax liabilities	$23
Potomac Electric Power Co [Member] | District of Columbia [Member]
Schedule of Income Tax [Line Items]
Corporate tax rate			9.98%
Potomac Electric Power Co [Member] | District of Columbia [Member] | 2019 [Member]
Schedule of Income Tax [Line Items]
Corporate tax rate			8.25%
Potomac Electric Power Co [Member] | District of Columbia [Member] | 2015 [Member]
Schedule of Income Tax [Line Items]
Corporate tax rate			9.40%
Delmarva Power & Light Co/De [Member]
Schedule of Income Tax [Line Items]
Consolidated effective tax rates	39.60%	40.30%
Atlantic City Electric Co [Member]
Schedule of Income Tax [Line Items]
Consolidated effective tax rates	33.30%	37.50%

Equity_and_Earnings_Per_Share_1

Equity and Earnings Per Share - Calculation of Earnings Per Share of Common Stock (Detail) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Income (Numerator):
Net Income	$53	$75
Weighted average shares outstanding for basic computation:
Average shares outstanding	253	250
Adjustment to shares outstanding		1
Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock	253	251
Net effect of potentially dilutive shares	0	0
Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock	253	251
Basic and Diluted Earnings per Share
Basic and Diluted earnings per share	$0.21	$0.30

Preferred_Stock_Additional_Inf

Preferred Stock - Additional Information (Detail) (USD $)	3 Months Ended	0 Months Ended
	Mar. 31, 2015	Jan. 26, 2015	Oct. 27, 2014	Jul. 29, 2014	Apr. 30, 2014	Apr. 27, 2015	Apr. 29, 2014	Dec. 31, 2014
Class of Stock [Line Items]
Amount Of Non Voting Series A Preferred Stock Purchase price	$18,000,000
Non-voting Series A Preferred Stock, number of shares issued		1,800	1,800	1,800
Non-voting Series A Preferred Stock, maximum aggregate consideration							180,000,000
Redemption of preferred stock at purchase price	$10,000
Maximum [Member]
Class of Stock [Line Items]
Non-voting Series A Preferred Stock, number of shares issued							18,000
Non-Voting Series A Preferred Stock [Member]
Class of Stock [Line Items]
Issuance of non-voting Series A Preferred Stock, shares issued					9,000
Additional shares issued		1,800	1,800	1,800
Non-voting Series A Preferred Stock, shares purchased price					90,000,000
Amount Of Non Voting Series A Preferred Stock Purchase price		18,000,000	18,000,000	18,000,000
Non-voting Series A Preferred Stock, cumulative, non-participating cash dividend					0.10%
Subsequent Event [Member]
Class of Stock [Line Items]
Non-voting Series A Preferred Stock, number of shares issued						1,800
Subsequent Event [Member] | Non-Voting Series A Preferred Stock [Member]
Class of Stock [Line Items]
Additional shares issued						1,800
Amount Of Non Voting Series A Preferred Stock Purchase price						18,000,000
Preferred Stock [Member]
Class of Stock [Line Items]
Estimated fair value of derivatives	$3,000,000							$3,000,000

Derivative_Instruments_and_Hed2

Derivative Instruments and Hedging Activities - Fair Values of Derivative Instruments by Balance Sheet Location (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Gross Derivative Instruments [Member]
Derivative [Line Items]
Derivative assets (current assets)	$3	$3
Derivative liabilities (current liabilities)	-2	-4
Net Derivative (liability) asset	1	-1
Net Derivative Instruments [Member]
Derivative [Line Items]
Derivative assets (current assets)	3	3
Net Derivative (liability) asset	3	3
Other Derivative Instruments [Member]
Derivative [Line Items]
Derivative assets (current assets)	3	3
Derivative liabilities (current liabilities)	-2	-4
Net Derivative (liability) asset	1	-1
Delmarva Power & Light Co/De [Member] | Gross Derivative Instruments [Member]
Derivative [Line Items]
Derivative liabilities (current liabilities)	-2	-4
Delmarva Power & Light Co/De [Member] | Other Derivative Instruments [Member]
Derivative [Line Items]
Derivative liabilities (current liabilities)	-2	-4
Effects of Cash Collateral and Netting [Member]
Derivative [Line Items]
Derivative liabilities (current liabilities)	2	4
Net Derivative (liability) asset	2	4
Effects of Cash Collateral and Netting [Member] | Delmarva Power & Light Co/De [Member]
Derivative [Line Items]
Derivative liabilities (current liabilities)	$2	$4

Derivative_Instruments_and_Hed3

Derivative Instruments and Hedging Activities - Schedule of Cash Collateral Offset Against Derivative Positions (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Derivative [Line Items]
Cash collateral pledged to counterparties with the right to reclaim	$2	$4
Delmarva Power & Light Co/De [Member]
Derivative [Line Items]
Cash collateral pledged to counterparties with the right to reclaim	$2	$4

Derivative_Instruments_and_Hed4

Derivative Instruments and Hedging Activities - Cash Flow Hedges Included in Accumulated Other Comprehensive Loss (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated Other Comprehensive Loss After-tax	$9	$9
Portion Expected to be Reclassified to Income during the Next 12 Months	1	1
Interest Rate [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated Other Comprehensive Loss After-tax	9	9
Portion Expected to be Reclassified to Income during the Next 12 Months	$1	$1
Maximum Term	209 months	221 months

Derivative_Instruments_and_Hed5

Derivative Instruments and Hedging Activities - Net Unrealized and Realized Derivative Gains (Losses) Deferred as Regulatory Liabilities and Regulatory Assets (Detail) (Other Derivative Activity [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Net unrealized (loss) gain arising during the period	($1)	$2
Net realized (loss) gain recognized during the period	-3	2
Delmarva Power & Light Co/De [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Net unrealized (loss) gain arising during the period	-1	2
Net realized (loss) gain recognized during the period	($3)	$2

Derivative_Instruments_and_Hed6

Derivative Instruments and Hedging Activities - Net Outstanding Commodity Forward Contracts That Did Not Qualify For Hedge Accounting (Detail) (Natural Gas [Member])	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
	MMBTU	MMBTU
Derivative [Line Items]
Quantity	2,997,500	3,892,500
Net Position	Long
Delmarva Power & Light Co/De [Member]
Derivative [Line Items]
Quantity	2,997,500	3,892,500
Net Position	Long
2014 [Member]
Derivative [Line Items]
Net Position	Long
2014 [Member] | Delmarva Power & Light Co/De [Member]
Derivative [Line Items]
Net Position	Long

Fair_Value_Disclosures_Fair_Va

Fair Value Disclosures - Fair Value of Financial Assets and Liabilities Measured on Recurring Basis (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets	$227	$122
Financial instruments, liabilities	32	34
Preferred Stock [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	3	3
Natural Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, liabilities	2	4
Treasury Fund [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash equivalents and restricted cash equivalents	143
Restricted cash equivalents		38
Money Market Funds and Short-term Investments [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	35	35
Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	46	46
Executive deferred compensation plan liabilities	30	30
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets	158	52
Financial instruments, liabilities	2	4
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Natural Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, liabilities	2	4
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Treasury Fund [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash equivalents and restricted cash equivalents	143
Restricted cash equivalents		38
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Money Market Funds and Short-term Investments [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	15	14
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets	47	48
Financial instruments, liabilities	30	30
Significant Other Observable Inputs (Level 2) [Member] | Money Market Funds and Short-term Investments [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	20	21
Significant Other Observable Inputs (Level 2) [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	27	27
Executive deferred compensation plan liabilities	30	30
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets	22	22
Significant Unobservable Inputs (Level 3) [Member] | Preferred Stock [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	3	3
Significant Unobservable Inputs (Level 3) [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	19	19
Potomac Electric Power Co [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets	192	80
Financial instruments, liabilities	6	7
Potomac Electric Power Co [Member] | Treasury Fund [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash equivalents and restricted cash equivalents	116
Restricted cash equivalents		5
Potomac Electric Power Co [Member] | Money Market Funds and Short-term Investments [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	34	34
Potomac Electric Power Co [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	42	41
Executive deferred compensation plan liabilities	6	7
Potomac Electric Power Co [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets	130	18
Potomac Electric Power Co [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Treasury Fund [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash equivalents and restricted cash equivalents	116
Restricted cash equivalents		5
Potomac Electric Power Co [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Money Market Funds and Short-term Investments [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	14	13
Potomac Electric Power Co [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets	43	44
Financial instruments, liabilities	6	7
Potomac Electric Power Co [Member] | Significant Other Observable Inputs (Level 2) [Member] | Money Market Funds and Short-term Investments [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	20	21
Potomac Electric Power Co [Member] | Significant Other Observable Inputs (Level 2) [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	23	23
Executive deferred compensation plan liabilities	6	7
Potomac Electric Power Co [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets	19	18
Potomac Electric Power Co [Member] | Significant Unobservable Inputs (Level 3) [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	19	18
Delmarva Power & Light Co/De [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets	1	7
Financial instruments, liabilities	3	5
Delmarva Power & Light Co/De [Member] | Natural Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, liabilities	2	4
Delmarva Power & Light Co/De [Member] | Treasury Fund [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Restricted cash equivalents		5
Delmarva Power & Light Co/De [Member] | Money Market Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	1	1
Delmarva Power & Light Co/De [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets		1
Executive deferred compensation plan liabilities	1	1
Delmarva Power & Light Co/De [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets	1	6
Financial instruments, liabilities	2	4
Delmarva Power & Light Co/De [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Natural Gas [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, liabilities	2	4
Delmarva Power & Light Co/De [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Treasury Fund [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Restricted cash equivalents		5
Delmarva Power & Light Co/De [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Money Market Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets	1	1
Delmarva Power & Light Co/De [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, liabilities	1	1
Delmarva Power & Light Co/De [Member] | Significant Other Observable Inputs (Level 2) [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan liabilities	1	1
Delmarva Power & Light Co/De [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial instruments, assets		1
Delmarva Power & Light Co/De [Member] | Significant Unobservable Inputs (Level 3) [Member] | Life Insurance Contracts [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Executive deferred compensation plan assets		1
Atlantic City Electric Co [Member] | Treasury Fund [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Restricted cash equivalents	24	24
Atlantic City Electric Co [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member] | Treasury Fund [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Restricted cash equivalents	$24	$24

Fair_Value_Disclosures_Reconci

Fair Value Disclosures - Reconciliations of Fair Value Measurements Using Significant Unobservable Inputs (Level 3) (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Preferred Stock [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	$3
Included in accumulated other comprehensive loss	0
Included in regulatory liabilities and regulatory assets	0
Purchases	0
Transfers in (out) of Level 3	0
Ending balance	3
Life Insurance Contracts [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	19	19
Included in income	1	1
Included in accumulated other comprehensive loss	0	0
Included in regulatory liabilities and regulatory assets	0	0
Purchases	0	0
Issuances		-1
Settlements	-1
Transfers in (out) of Level 3	0	0
Ending balance	19	19
Life Insurance Contracts [Member] | Potomac Electric Power Co [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	18	18
Included in income	1	1
Included in accumulated other comprehensive loss	0	0
Purchases	0	0
Issuances		-1
Transfers in (out) of Level 3	0	0
Ending balance	19	18
Life Insurance Contracts [Member] | Delmarva Power & Light Co/De [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	1	1
Included in accumulated other comprehensive loss	0	0
Included in regulatory liabilities and regulatory assets	0	0
Purchases	0	0
Settlements	-1
Transfers in (out) of Level 3	0	0
Ending balance		$1

Fair_Value_Disclosures_Gains_o

Fair Value Disclosures - Gains on Level 3 Instruments Included in Income (Detail) (Other Income [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total gains included in income for the period	$1	$1
Change in unrealized gains relating to assets still held at reporting date	1	1
Potomac Electric Power Co [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total gains included in income for the period	1	1
Change in unrealized gains relating to assets still held at reporting date	$1	$1

Fair_Value_Disclosures_Fair_Va1

Fair Value Disclosures - Fair Value of Financial Liabilities Measured on Recurring Basis (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	$5,871	$5,583
Transition Bonds, Fair Value	224	235
Long-term project funding, Fair Value	10	28
Total Liabilities, Fair Value	6,105	5,846
Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	1,890
Total Liabilities, Fair Value	1,890
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	3,524	5,136
Transition Bonds, Fair Value	224	235
Total Liabilities, Fair Value	3,748	5,371
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	457	447
Long-term project funding, Fair Value	10	28
Total Liabilities, Fair Value	467	475
Potomac Electric Power Co [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	2,884	2,624
Long-term project funding, Fair Value		12
Total Liabilities, Fair Value		2,636
Potomac Electric Power Co [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	1,624
Potomac Electric Power Co [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	1,260	2,624
Total Liabilities, Fair Value		2,624
Potomac Electric Power Co [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term project funding, Fair Value		12
Total Liabilities, Fair Value		12
Delmarva Power & Light Co/De [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	1,139	1,123
Delmarva Power & Light Co/De [Member] | Quoted Prices in Active Markets for Identical Instruments (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	15
Delmarva Power & Light Co/De [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	1,017	1,016
Delmarva Power & Light Co/De [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	107	107
Atlantic City Electric Co [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	1,049	1,035
Transition Bonds, Fair Value	224	235
Total Liabilities, Fair Value	1,273	1,270
Atlantic City Electric Co [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	905	903
Transition Bonds, Fair Value	224	235
Total Liabilities, Fair Value	1,129	1,138
Atlantic City Electric Co [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Fair Value	144	132
Total Liabilities, Fair Value	$144	$132

Fair_Value_Disclosures_Fair_Va2

Fair Value Disclosures - Fair Value of Financial Liabilities Measured on Recurring Basis (Parenthetical) (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, carrying amount	$5,015	$4,807
Transition bonds, carrying amount	203	215
Potomac Electric Power Co [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, carrying amount	2,332	2,124
Delmarva Power & Light Co/De [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, carrying amount	1,071	1,071
Atlantic City Electric Co [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, carrying amount	903	903
Transition bonds, carrying amount	$203	$215

Commitments_and_Contingencies_1

Commitments and Contingencies - Retained Environmental Exposures - Additional Information (Detail) (USD $)	1 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Jul. 31, 2010	Jul. 31, 2014	Dec. 31, 2012	Mar. 31, 2015	Oct. 22, 2014
Commitments and Contingencies [Line Items]
Loss contingency liabilities				$22	$21.70
Environmental remediation expense minimum	7
Environmental remediation expense maximum	18
Pepco Energy Services [Member]
Commitments and Contingencies [Line Items]
Certain allegedly unauthorized charges			7
Additional compounded interest			9
Litigation claim value, sought		3
Litigation claim value, interest disallowed		4
Conectiv Energy [Member]
Commitments and Contingencies [Line Items]
Third party maximum and seller floor for environmental remediation costs	10
Number of facility locations	9
PHI [Member]
Commitments and Contingencies [Line Items]
Third party maximum and seller floor for environmental remediation costs	10
Potomac Electric Power Co [Member]
Commitments and Contingencies [Line Items]
Loss contingency liabilities				14	21.7
Delmarva Power & Light Co/De [Member]
Commitments and Contingencies [Line Items]
Loss contingency liabilities				2
Atlantic City Electric Co [Member]
Commitments and Contingencies [Line Items]
Loss contingency liabilities				$6

Commitments_and_Contingencies_2

Commitments and Contingencies - Schedule of Accrued Liabilities for Environmental Exposures (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015
Commitments and Contingencies [Line Items]
Beginning balance	$28
Accruals	1
Payments	1
Ending balance	28
Less amounts in Other Current Liabilities	4
Amounts in Other Deferred Credits	24
Potomac Electric Power Co [Member]
Commitments and Contingencies [Line Items]
Beginning balance	19
Ending balance	19
Less amounts in Other Current Liabilities	2
Amounts in Other Deferred Credits	17
Delmarva Power & Light Co/De [Member]
Commitments and Contingencies [Line Items]
Beginning balance	3
Accruals	1
Payments	1
Ending balance	3
Less amounts in Other Current Liabilities	2
Amounts in Other Deferred Credits	1
Transmission and Distribution [Member]
Commitments and Contingencies [Line Items]
Beginning balance	17
Accruals	1
Ending balance	18
Less amounts in Other Current Liabilities	3
Amounts in Other Deferred Credits	15
Transmission and Distribution [Member] | Potomac Electric Power Co [Member]
Commitments and Contingencies [Line Items]
Beginning balance	16
Ending balance	16
Less amounts in Other Current Liabilities	2
Amounts in Other Deferred Credits	14
Transmission and Distribution [Member] | Delmarva Power & Light Co/De [Member]
Commitments and Contingencies [Line Items]
Beginning balance	1
Accruals	1
Ending balance	2
Less amounts in Other Current Liabilities	1
Amounts in Other Deferred Credits	1
Legacy Generation Regulated [Member]
Commitments and Contingencies [Line Items]
Beginning balance	6
Payments	1
Ending balance	5
Less amounts in Other Current Liabilities	1
Amounts in Other Deferred Credits	4
Legacy Generation Regulated [Member] | Potomac Electric Power Co [Member]
Commitments and Contingencies [Line Items]
Beginning balance	3
Ending balance	3
Amounts in Other Deferred Credits	3
Legacy Generation Regulated [Member] | Delmarva Power & Light Co/De [Member]
Commitments and Contingencies [Line Items]
Beginning balance	2
Payments	1
Ending balance	1
Less amounts in Other Current Liabilities	1
Legacy Generation Regulated [Member] | Atlantic City Electric Co [Member]
Commitments and Contingencies [Line Items]
Beginning balance	1
Ending balance	1
Amounts in Other Deferred Credits	1
Legacy Generation Non-Regulated [Member]
Commitments and Contingencies [Line Items]
Beginning balance	5
Ending balance	5
Amounts in Other Deferred Credits	$5

Commitments_and_Contingencies_3

Commitments and Contingencies - Environmental Matters - Additional Information (Detail) (USD $)	1 Months Ended			3 Months Ended
	Mar. 31, 2014	Jan. 31, 2011	Nov. 30, 2008	Mar. 31, 2013	Mar. 31, 2015
		gal
Commitments and Contingencies [Line Items]
EPA costs to date to clean up site			$6,000,000
Estimated costs remaining to remediate the site			6,000,000
Quantity of mineral oil spill		4,500
Cost of litigation	875,000
Civil penalty payment	250,000
Donation for training fund	25,000
Fund provided for installation and operation of the trash collection SEP	600,000
Tax payment made		74,000,000		74,000,000
Income tax penalties		1,000,000		0
Interest expense assessed relating to disallowed deductions		28,000,000
Non-cash charge (after-tax)				377,000,000
Maximum tax penalty percentage				20.00%
Percentage of disallowed tax benefits associated with leases				100.00%
Federal income tax benefits				192,000,000
Potential interest on potential tax liability related to disallowed tax benefits				50,000,000
Deposit of additional taxes and related interest				242,000,000
PHI [Member] | Minimum [Member]
Commitments and Contingencies [Line Items]
Cost of implementation of a closure plan and cap					3,000,000
PHI [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Cost of implementation of a closure plan and cap					6,000,000
Potomac Electric Power Co [Member]
Commitments and Contingencies [Line Items]
Quantity of mineral oil spill		4,500
Cost of litigation	875,000
Civil penalty payment	250,000
Donation for training fund	25,000
Fund provided for installation and operation of the trash collection SEP	600,000
Potomac Electric Power Co [Member] | Minimum [Member]
Commitments and Contingencies [Line Items]
Cost of implementation of a closure plan and cap					3,000,000
Potomac Electric Power Co [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Cost of implementation of a closure plan and cap					6,000,000
Atlantic City Electric Co [Member]
Commitments and Contingencies [Line Items]
EPA costs to date to clean up site			6,000,000
Estimated costs remaining to remediate the site			$6,000,000

Commitments_and_Contingencies_4

Commitments and Contingencies - Schedule of Commitments and Obligations (Detail) (USD $)	Mar. 31, 2015
In Millions, unless otherwise specified
Commitments and Contingencies [Line Items]
Guarantees associated with disposal of Conectiv Energy assets	$13
Guaranteed lease residual values	19
Total	32
PHI [Member]
Commitments and Contingencies [Line Items]
Guarantees associated with disposal of Conectiv Energy assets	13
Guaranteed lease residual values	3
Total	16
Potomac Electric Power Co [Member]
Commitments and Contingencies [Line Items]
Guaranteed lease residual values	5
Total	5
Delmarva Power & Light Co/De [Member]
Commitments and Contingencies [Line Items]
Guaranteed lease residual values	6
Total	6
Atlantic City Electric Co [Member]
Commitments and Contingencies [Line Items]
Guaranteed lease residual values	5
Total	$5

Commitments_and_Contingencies_5

Commitments and Contingencies - Schedule of Commitments and Obligations (Parenthetical) (Detail) (USD $)	3 Months Ended
	Mar. 31, 2015
Commitments and Contingencies [Line Items]
Derivative portfolio guarantee	$13,000,000
Obligations under guarantee	52,000,000
PHI [Member]
Commitments and Contingencies [Line Items]
Obligations under guarantee	11,000,000
Potomac Electric Power Co [Member]
Commitments and Contingencies [Line Items]
Obligations under guarantee	13,000,000
Delmarva Power & Light Co/De [Member]
Commitments and Contingencies [Line Items]
Obligations under guarantee	15,000,000
Atlantic City Electric Co [Member]
Commitments and Contingencies [Line Items]
Obligations under guarantee	13,000,000
Leased Equipment and Fleet Vehicles [Member]
Commitments and Contingencies [Line Items]
Fair value of leased equipment and vehicles	$0
Minimum [Member]
Commitments and Contingencies [Line Items]
Lease term range	1 to 4 years
Maximum [Member]
Commitments and Contingencies [Line Items]
Lease term range	3 to 8 years

Commitments_and_Contingencies_6

Commitments and Contingencies - Tax Legislation, Guarantees, Indemnifications, and Performance Contracts - Additional Information (Detail) (USD $)	3 Months Ended	0 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015	Apr. 23, 2015	Mar. 31, 2015
Commitment and Contingencies [Line Items]
Pro-rata dividend payable, description	The Board of Directors also declared a pro-rata dividend payable in lieu of the Second Quarter Dividend in the event the Merger is completed before the close of business on June 10, 2015. The pro-rata dividend is payable 20 days after the Merger is completed to holders of common stock of record as of the day immediately prior to the day the Merger is completed, at a rate of $0.002967 per share per day beginning March 11, 2015 and ending the day before the Merger is completed.
Subsequent Event [Member]
Commitment and Contingencies [Line Items]
Dividend declared on common stock, per share		$0.27
Dividend declared date		23-Apr-15
Dividend declared, payment date		30-Jun-15
Dividends payable, date of record		10-Jun-15
Pro-rata dividend payable, period		20 days
Pro-rata dividend rate, per day		0.30%
Pepco Energy Services [Member] | Energy Savings or Combined Heat and Power Performance [Member]
Commitment and Contingencies [Line Items]
Contract life, maximum remaining term			20 years
Value of guarantees under construction projects	15		$15
Accrued liability on contracts	1		1
Pepco Energy Services [Member] | Completed Performance Contracts Associated With Savings Guarantees [Member]
Commitment and Contingencies [Line Items]
Value of guarantees completed projects	318		318
Contract life, maximum remaining term			23 years
Pepco Energy Services [Member] | Uncompleted Performance Contracts Associated With Savings Guarantees [Member]
Commitment and Contingencies [Line Items]
Value of guarantees on projects under construction	60		$60
Maximum term of project under construction			15 years

Variable_Interest_Entities_Add

Variable Interest Entities - Additional Information (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Oct. 18, 2011
			MW
Delmarva Power & Light Co/De [Member]
Variable Interest Entity [Line Items]
Power producted by fuel cell facility	56,318	53,609	30
Delmarva Power & Light Co/De [Member] | Fuel Cell Facility [Member]
Variable Interest Entity [Line Items]
Amount billed to distribution customers, respect to energy produced by these facilities	$10	$9
Delmarva Power & Light Co/De [Member] | Fuel Cell Facility [Member] | October 18, 2011 [Member]
Variable Interest Entity [Line Items]
Term of agreement	Through 2033
Delmarva Power & Light Co/De [Member] | Land-Based Wind PPA [Member]
Variable Interest Entity [Line Items]
Megawatts received from power purchase agreements (PPAs)	128
Number of purchase power agreements	3
Delmarva Power & Light Co/De [Member] | Solar PPA [Member]
Variable Interest Entity [Line Items]
Megawatts received from power purchase agreements (PPAs)	10
Number of purchase power agreements	1
Energy purchase maximum to be purchased	19
Term of agreement, years	20 years
Term of agreement	Through 2030
Obligated purchase amount of energy produced at the facility	70.00%
Solar energy purchases	1	1
Delmarva Power & Light Co/De [Member] | Wind PPA [Member]
Variable Interest Entity [Line Items]
Purchased energy	10	10
Delmarva Power & Light Co/De [Member] | Wind PPA [Member] | Wind Facility One [Member]
Variable Interest Entity [Line Items]
Energy purchase maximum to be purchased	50
Delmarva Power & Light Co/De [Member] | Wind PPA [Member] | Wind Facility Two [Member]
Variable Interest Entity [Line Items]
Energy purchase maximum to be purchased	40
Delmarva Power & Light Co/De [Member] | Wind PPA [Member] | Wind Facility Three [Member]
Variable Interest Entity [Line Items]
Energy purchase maximum to be purchased	38
Atlantic City Electric Co [Member]
Variable Interest Entity [Line Items]
Purchased energy	62	72
Equity ownership percentage	100.00%
Atlantic City Electric Co [Member] | Non-Utility Generators [Member]
Variable Interest Entity [Line Items]
Megawatts received from power purchase agreements (PPAs)	459
Number of purchase power agreements	3
Purchase activities with non utility generators per power purchase agreements	$56	$59

Accumulated_Other_Comprehensiv2

Accumulated Other Comprehensive Loss - Schedule of Components of Other Comprehensive Loss (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance at beginning of period	($46)	($34)
Amount of amortization of net prior service cost and actuarial loss reclassified to Other operation and maintenance expense	2	1
Income tax expense (benefit)	1
Balance at end of period	-45	-33
Pension and Other Postretirement Benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance at beginning of period	-37	-25
Amount of amortization of net prior service cost and actuarial loss reclassified to Other operation and maintenance expense	2	1
Income tax expense (benefit)	1
Balance at end of period	-36	-24
Treasury Lock [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance at beginning of period	-9	-9
Income tax expense (benefit)	0	0
Balance at end of period	-9	-9
Treasury Lock [Member] | Interest Expense [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amount of pre-tax loss reclassified to Interest expense	$0	$0

Segment_Information_Additional

Segment Information - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2015
	Segment
Potomac Electric Power Co [Member]
Segment Reporting Information [Line Items]
Number of operating segments	1
Delmarva Power & Light Co/De [Member]
Segment Reporting Information [Line Items]
Number of operating segments	1
Atlantic City Electric Co [Member]
Segment Reporting Information [Line Items]
Number of operating segments	1

Related_Party_Transactions_Add

Related Party Transactions - Additional Information (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Potomac Electric Power Co [Member] | PHI Service Company [Member]
Related Party Transaction [Line Items]
Costs directly charged or allocated	$64	$53
Potomac Electric Power Co [Member] | Pepco Energy Services [Member]
Related Party Transaction [Line Items]
Maintenance services	4	5
Delmarva Power & Light Co/De [Member] | PHI Service Company [Member]
Related Party Transaction [Line Items]
Costs directly charged or allocated	48	39
Atlantic City Electric Co [Member] | PHI Service Company [Member]
Related Party Transaction [Line Items]
Costs directly charged or allocated	$38	$29

Related_Party_Transactions_Sch

Related Party Transactions - Schedule of Related Party Transactions Included in Balance Sheet (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Potomac Electric Power Co [Member]
Related Party Transaction [Line Items]
Payable to Related Party, Total	($51)	($30)
Potomac Electric Power Co [Member] | PHI Service Company [Member]
Related Party Transaction [Line Items]
Payable to Related Party, Total	-34	-27
Potomac Electric Power Co [Member] | Pepco Energy Services [Member]
Related Party Transaction [Line Items]
Payable to Related Party, Total	-4	-2
Potomac Electric Power Co [Member] | Other [Member]
Related Party Transaction [Line Items]
Payable to Related Party, Total	-13	-1
Delmarva Power & Light Co/De [Member]
Related Party Transaction [Line Items]
Payable to Related Party, Total	-21	-17
Delmarva Power & Light Co/De [Member] | PHI Service Company [Member]
Related Party Transaction [Line Items]
Payable to Related Party, Total	-21	-18
Delmarva Power & Light Co/De [Member] | Other [Member]
Related Party Transaction [Line Items]
Payable to Related Party, Total		1
Atlantic City Electric Co [Member]
Related Party Transaction [Line Items]
Payable to Related Party, Total	-17	-15
Atlantic City Electric Co [Member] | PHI Service Company [Member]
Related Party Transaction [Line Items]
Payable to Related Party, Total	-15	-14
Atlantic City Electric Co [Member] | Other [Member]
Related Party Transaction [Line Items]
Payable to Related Party, Total	($2)	($1)

Related_Party_Transactions_Sch1

Related Party Transactions - Schedule of Related Party Transactions Included in Income Statement (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Delmarva Power & Light Co/De [Member]
Related Party Transaction [Line Items]
Intercompany lease transactions	$1	$1
Atlantic City Electric Co [Member]
Related Party Transaction [Line Items]
Meter reading services provided by Millennium Account Services LLC (an ACE affiliate)	($1)	($1)