Regulatory Matters (Details) (USD $)	3 Months Ended						0 Months Ended	1 Months Ended	12 Months Ended				1 Months Ended			0 Months Ended	3 Months Ended	0 Months Ended			3 Months Ended	0 Months Ended		3 Months Ended			0 Months Ended				0 Months Ended			3 Months Ended	12 Months Ended		3 Months Ended					0 Months Ended	3 Months Ended		12 Months Ended									0 Months Ended							0 Months Ended				1 Months Ended		3 Months Ended		0 Months Ended	1 Months Ended	3 Months Ended	0 Months Ended	3 Months Ended		0 Months Ended		0 Months Ended
	Mar. 31, 2014 entities	Mar. 31, 2013	Mar. 31, 2014 FES	Mar. 31, 2013 FES	Dec. 31, 2013 AE Supply	Dec. 31, 2013 M P	Apr. 30, 2014 MP and PE Subsequent Event	Apr. 30, 2007 FERC kv	Dec. 31, 2013 FERC	Mar. 31, 2014 FERC	Jan. 21, 2010 FERC issues	Sep. 04, 2013 FERC Hydroelectric Asset Sale MW plant	May 31, 2013 FERC MOPR Reform	Dec. 07, 2012 FERC MOPR Reform exemption	Mar. 31, 2014 FERC PJM	Aug. 24, 2012 FERC PATH	Mar. 31, 2014 FERC PATH kv	Aug. 24, 2012 FERC PATH-Allegheny	Aug. 24, 2012 FERC Path-WV	Sep. 28, 2012 FERC Path-WV challenge	Mar. 31, 2014 FERC FES and AE Supply FTR Underfunding Complaint Minimum	Sep. 03, 2013 MARYLAND	Dec. 22, 2011 MARYLAND	Mar. 31, 2014 MARYLAND	Aug. 31, 2011 MARYLAND	Oct. 06, 2009 MARYLAND	Jun. 14, 2013 NEW JERSEY	Mar. 31, 2014 NEW JERSEY bgs component	Feb. 22, 2013 NEW JERSEY	Nov. 30, 2012 NEW JERSEY	Jun. 14, 2013 NEW JERSEY JCP&L	Aug. 07, 2013 OHIO	Jan. 31, 2013 OHIO Party	Mar. 31, 2014 OHIO plan	Dec. 31, 2009 OHIO	Dec. 12, 2012 OHIO questions	Mar. 31, 2014 OHIO Year 2012 MWh	Mar. 31, 2014 OHIO Year 2013 MWh	Mar. 31, 2014 OHIO Year 2014 MWh	Mar. 31, 2014 OHIO Annually Through 2025 MWh	Mar. 31, 2014 OHIO Annually Through 2018	Oct. 10, 2013 PENNSYLVANIA proposals	Mar. 31, 2014 PENNSYLVANIA	Sep. 30, 2013 PENNSYLVANIA	Dec. 31, 2010 PENNSYLVANIA	Dec. 12, 2013 PENNSYLVANIA issues	Dec. 02, 2013 PENNSYLVANIA smart_meter	Feb. 15, 2013 PENNSYLVANIA workgroup comment	Jan. 16, 2013 PENNSYLVANIA issues Party	May 31, 2011 PENNSYLVANIA	Apr. 29, 2011 PENNSYLVANIA questions	Mar. 31, 2014 PENNSYLVANIA Pennsylvania Companies	Mar. 31, 2014 PENNSYLVANIA Year 2013	Oct. 10, 2013 PENNSYLVANIA Three Month Period	Oct. 10, 2013 PENNSYLVANIA Twelve Month Period	Oct. 10, 2013 PENNSYLVANIA Twenty-Four Month Period	Oct. 10, 2013 PENNSYLVANIA Forty-Eight Month Period	Mar. 31, 2014 PENNSYLVANIA Unfavorable Regulatory Action	Dec. 31, 2013 PENNSYLVANIA Unfavorable Regulatory Action	Feb. 06, 2013 PENNSYLVANIA Unfavorable Regulatory Action	Apr. 21, 2014 PENNSYLVANIA Unfavorable Regulatory Action WP Subsequent Event	Mar. 06, 2014 PENNSYLVANIA Unfavorable Regulatory Action Pennsylvania Companies	Apr. 21, 2014 PENNSYLVANIA Unfavorable Regulatory Action Pennsylvania Companies Subsequent Event	Apr. 30, 2014 WEST VIRGINIA	Oct. 31, 2013 WEST VIRGINIA	Apr. 30, 2010 WEST VIRGINIA	Mar. 31, 2014 WEST VIRGINIA MW	Oct. 22, 2012 WEST VIRGINIA hearing	Apr. 30, 2014 WEST VIRGINIA MP and PE Subsequent Event	Oct. 31, 2006 California Claims Matters FERC Proceedings	Mar. 31, 2014 California Claims Matters FERC	Jan. 27, 2014 Division Of Rate Counsel NEW JERSEY JCP&L	Dec. 31, 2013 Public Utilities Commission Of Ohio OHIO	Aug. 07, 2013 Public Utilities Commission Of Ohio OHIO auctions	Jan. 27, 2014 Board Of Public Utilities NEW JERSEY JCP&L	Feb. 24, 2014 Board Of Public Utilities NEW JERSEY JCP&L	Feb. 12, 2014 Hydroelectric Power Plant Projects
Regulatory Matters [Line Items]
Proposed electric consumption reduction percentage																								10.00%
Proposed electric demand reduction percentage																								15.00%
Expenditures for cost recovery program																									$ 66,000,000	$ 101,000,000
Recovery period for expenditures for cost recovery program																							5 years	3 years
Public Utilities, Requested Recovery of Deferred Costs, Allowed Amount																																																																												736,000,000
Public Utilities, Requested Recovery of Deferred Costs																																																																												744,000,000
Public Utilities, Requested Recovery Costs, Disallowed Amount																																																																											8,000,000
Public Utilities, Renewable Energy Auctions																																																																										1
Amortization (deferral) of regulatory assets, net	(28,000,000)	59,000,000																																																																							51,000,000
Maximum penalty assessed, in dollars per day per violation																								25,000
Expected increase in cost due to proposed plan																								106,000,000
Expected Infrastructure Investments																						2,700,000,000
Expected Infrastructure Investments, Period																						15 years
Number of Supply Components																												2
Number of Basic Generation Services																												1
Requested increase in revenues																													603,000,000	31,500,000
Increase (Decrease) in Revenue Recovery Request																													112,000,000
Load cap percentage minimum																																		80.00%
Maximum trance award to a single supplier																																		80.00%
Generation discount for low income customers																																		6.00%
Recovery Period																																		5 years
Costs avoided by customers																																		360,000,000
Fund to assist low income customers																																		12,000,000
ESP Extension Term																																		2 years
Loss Contingency, New Claims Filed, Number																																	2
Generation supply auction period, after approval																																		3 years
Generation supply auction period, before approval																																		1 year
Annual energy savings																																					1,211,000	1,726,000	2,306,000	2,903,000
Increase (decrease) in annual energy savings																																					416,000
Utilities required to reduce peak demand																																			1.00%
Utilities required to additionally reduce peak demand																																									0.75%
Number of plans																																		3
Portfolio Plan, Estimated Cost																																		250,000,000
Portion of Revenue Obtained to be Received																																		20.00%
Credit to Non-Shopping Customers																																43,300,000
Credit to Non-Shopping Customers, Implementation Period																																60 days
Marginal Transmission Refund Period																																											29 months
Marginal transmission losses																																													254,000,000
Asset Impairment Charges																																												254,000,000																					322,000,000
Regulatory Liabilities																																																																			23,000,000
Cash Consideration received in Asset Swap Transaction					1,100,000,000
Minimum reduction in Utilities reduce energy consumption																																																		1.00%			3.00%
Minimum reduction in Utilities peak demand																																																					4.50%
Maximum range of possible loss																																																										20,000,000		234,000,000
Number of parties not settled																																																	1
Number of issues not settled																																														1			1
Public Utilities, Requested Rate Increase (Decrease), Percentage							14.00%																																																									14.00%					9.30%
Public Utilities, Requested Surcharge, Amount																																																																					48,000,000
Public Utilities, Requested Rate Increase (Decrease), Total Amount																																																																					144
Energy Contract, Term																																																						3 months	12 months	24 months	48 months
Number of Requests For Proposal																																										1
Request for Proposal, Project Term																																										2 years
Loss Contingency, Damages Sought, Value																																																													11,400,000	5,100,000
Period to File Amendment to the Deployment Plan																																																														30 days
Expedited Procedural Schedule to Rule on Filing																																																														90 days
Period to Respond to Complaint																																																															20 days
Loss Contingency, Range of Possible Loss, Minimum																																																											1,000,000
Number Of Smart Meters Requested To Be Installed																																															170,000
Number Of Smart Meters Originally Proposed To Be Installed																																															60,000
Annualized base rate increase																																																																		40,000,000
Storm Restoration Deferral Period																																																																		5 years
Number of public hearings held																																																																				2
Public Utilities, Requested Rate Increase (Decrease), Amount																																																																					96,000,000
Period of time to implement plan																																																																			6 months
Additional base rate increase																											20,600,000																																							20,000,000
Recommend Reduction in Base Rates for Electric Service																															202,800,000																																									214,900,000			207,400,000
Decrease in ENEC rates																																																																		20,000,000
Noncash or Part Noncash Acquisition, Debt Assumed					73,500,000
Equity contribution from parent			500,000,000	0		527,000,000
Loans to affiliated companies, net			(215,000,000)	276,000,000		573,000,000
Power threshold for cost methodology								500
Compliance Filing, Hybrid Methodology, Beneficiary Pays Cost Allocation															50.00%
Denied Recovery Charges of Exit Fees										78,800,000
Identified issues for written comments											9
Annual Revenue requirements in Zone									16,000,000
Settlement proposal claims																																																																							190,000,000
Court proceedings from filed claims																																																																						1
New Voltage transmission facilities across PJM and a zonal transmission rate (In KV)																	765
Cost recovery, PP&E reclassified to Regulatory Assets																		62,000,000	59,000,000
Number of Formal Challenges																				3
Proceeds from Divestiture of Businesses																																																																													394,000,000
Auctioned Energy Price													59
Application to Sell Power Plant Projects, Number												11
Application to Sell Power Plant Projects, Combined Power												527
Number of Exemptions Added														2
Percent of Meters to be Installed																																																				98.50%
Expected Cost of Meter Installations																																																				1,250,000,000
Directed Questions for Investigation																																				22															11
Number of Workgroups Established																																																5
Number of Comments Established																																																1
Regulatory Asset, Cost Recovery, Proposed Return on Equity																10.90%
Base Return On Equity																10.40%
Return On Equity Granted For Regional Transmission Organization Participation																0.50%
Remaining Recovery Period of Regulatory Assets																5 years
Revenues Lost of Which the Entity is Entitled																					$ 87,000,000
Resource Plan, Proposed Transfer																																																																			1,476
Compliance Filing, Hybrid Methodology, Postage Stamp Cost Allocation															50.00%
Regional Enforcement Entities	8
Requirement to File Update with FERC Showing Market-Based Rate Authority Requirements Met, Period	3 years