Regulatory Matters (Details) (USD $)	3 Months Ended	9 Months Ended		3 Months Ended	9 Months Ended		1 Months Ended			9 Months Ended			1 Months Ended		3 Months Ended			0 Months Ended	9 Months Ended	0 Months Ended			9 Months Ended	0 Months Ended		9 Months Ended			0 Months Ended				0 Months Ended			1 Months Ended	3 Months Ended	9 Months Ended	12 Months Ended		9 Months Ended					3 Months Ended	9 Months Ended	12 Months Ended						0 Months Ended		0 Months Ended						1 Months Ended	9 Months Ended			1 Months Ended	3 Months Ended	1 Months Ended			9 Months Ended
	Jun. 30, 2013	Sep. 30, 2013 entities	Sep. 30, 2012	Jun. 30, 2013 FES	Sep. 30, 2013 FES	Sep. 30, 2012 FES	Oct. 31, 2013 AE Supply Subsequent Event	Oct. 31, 2013 M P [Member] Subsequent Event	Apr. 30, 2007 FERC kv	Sep. 30, 2013 FERC class	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	Sep. 30, 2013 FERC Synchronous Condensers	Dec. 20, 2012 FERC Synchronous Condensers	Sep. 30, 2013 FERC PJM	Aug. 24, 2012 FERC PATH	Sep. 30, 2013 FERC PATH kv	Aug. 24, 2012 FERC PATH-Allegheny	Aug. 24, 2012 FERC Path-WV	Sep. 28, 2012 FERC Path-WV challenge	Sep. 30, 2013 FERC FES and AE Supply FTR Underfunding Complaint Minimum	Sep. 03, 2013 MARYLAND	Dec. 22, 2011 MARYLAND	Sep. 30, 2013 MARYLAND	Aug. 31, 2011 MARYLAND	Oct. 06, 2009 MARYLAND	Jun. 14, 2013 NEW JERSEY	Sep. 30, 2013 NEW JERSEY component bgs	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	Aug. 31, 2011 OHIO proposals	Oct. 31, 2009 OHIO proposals	Sep. 30, 2013 OHIO plan	Dec. 31, 2009 OHIO	Dec. 12, 2012 OHIO questions	Sep. 30, 2013 OHIO Year 2012 MWh	Sep. 30, 2013 OHIO Year 2013 MWh	Sep. 30, 2013 OHIO Year 2014 MWh	Sep. 30, 2013 OHIO Annually Through 2025 MWh	Sep. 30, 2013 OHIO Annually Through 2018	Sep. 30, 2013 PENNSYLVANIA	Sep. 30, 2013 PENNSYLVANIA	Dec. 31, 2010 PENNSYLVANIA	Apr. 04, 2013 PENNSYLVANIA enhancement	Feb. 15, 2013 PENNSYLVANIA choice workgroup comment	Jan. 16, 2013 PENNSYLVANIA Party issues	May 31, 2011 PENNSYLVANIA	Apr. 29, 2011 PENNSYLVANIA questions	Oct. 10, 2013 PENNSYLVANIA Subsequent Event proposals	Sep. 30, 2013 PENNSYLVANIA Year 2013	Oct. 10, 2013 PENNSYLVANIA Three Month Period Subsequent Event	Oct. 10, 2013 PENNSYLVANIA Twelve Month Period Subsequent Event	Oct. 10, 2013 PENNSYLVANIA Twenty-Four Month Period Subsequent Event	Oct. 10, 2013 PENNSYLVANIA Forty-Eight Month Period Subsequent Event	Sep. 30, 2013 PENNSYLVANIA Unfavorable Regulatory Action	Feb. 06, 2013 PENNSYLVANIA Unfavorable Regulatory Action	Apr. 30, 2010 WEST VIRGINIA	Sep. 30, 2013 WEST VIRGINIA MW	Oct. 22, 2012 WEST VIRGINIA hearing	Feb. 28, 2011 WEST VIRGINIA Facilities	Oct. 31, 2013 WEST VIRGINIA Subsequent Event	Sep. 30, 2013 WEST VIRGINIA Subsequent Event	Feb. 28, 2011 WEST VIRGINIA City of New Martinsville entities	Feb. 28, 2011 WEST VIRGINIA Morgantown Energy entities	Oct. 31, 2006 California Claims Matters FERC Proceedings	Sep. 30, 2013 California Claims Matters FERC	Sep. 30, 2013 The Seneca Pumped Storage Project FERC MW	Sep. 30, 2013 The Seneca Pumped Storage Project Relicensing
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
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
Number of cost recovery choices																																																		2
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%
Request for proposals conducted																																				2	3
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	473,000,000	473,000,000	0																																											254,000,000																				330,000,000
Regulatory Liabilities																																																																			23,000,000
Minimum reduction in Utilities reduce energy consumption																																																				1.00%			3.00%
Minimum reduction in Utilities peak demand																																																							4.50%
Loss Contingency, Range of Possible Loss, Maximum																																																												20,000,000	234,000,000
Number of parties not settled																																																			1
Number of issues not settled																																																			1
Energy Contract, Term																																																								3 months	12 months	24 months	48 months
Number of Requests For Proposal																																																						1
Request for Proposal, Project Term																																																						2 years
Annualized base rate increase																																																														40,000,000
Storm Restoration Deferral Period																																																														5 years
Number of public hearings held																																																																2
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
Decrease in ENEC rates																																																														20,000,000
Number of electric generation facilities																																																																	3
Number of electric generation facilities, owned by third party																																																																				1	1
Cash Consideration received in Asset Swap Transaction							1,100,000,000
Noncash or Part Noncash Acquisition, Debt Assumed							73,500,000
Cash Consideration provided in Asset Swap Transaction								1,100,000,000
Equity contribution from parent				1,500,000,000	1,500,000,000	0		527,000,000
Proceeds from Collection of (Payments to Fund) Long-term Loans to Related Parties					22,000,000	(55,000,000)		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
Number of classes of regulatory proceedings										2
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
Auctioned Energy Price													59
Hydroelectric project																																																																								451
Application to Sell Power Plant Projects, Number												11
Application to Sell Power Plant Projects, Combined Power												527
Application to Sell Power Plant Projects, Price												400,000,000
Asset Transfer, Price																21,500,000
Period of cycle																																																																									5 years
Number of Exemptions Added														2
Estimated Conversion Costs																60,000,000
Asset Transfer, Recognized Gain															17,000,000
Percent of Meters to be Installed																																														98.50%	98.50%
Expected Cost of Meter Installations																																														1,250,000,000	1,250,000,000
Directed Questions for Investigation																																								22													11
Number of Workgroups Established																																																		5
Number of Comments Established																																																		1
Number of Retail Market Enhancements																																																	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																							$ 64,000,000
Resource Plan, Proposed Transfer																																																															1,476
Annual Load Growth Rate																																																															1.40%
Compliance Filing, Hybrid Methodology, Postage Stamp Cost Allocation																	50.00%
Period of Time to File Case																																																															6 months
Regional Enforcement Entities		8