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•	The speed and nature of increased competition in the electric utility industry, in general, and the retail sales market in particular.

•	The impact of the regulatory process on the pending matters before FERC and in the various states in which we do business including, but not limited to, matters related to rates and pending rate cases.

•	The uncertainties of various cost recovery and cost allocation issues resulting from ATSI's realignment into PJM.

•	Economic or weather conditions affecting future sales and margins.

•	Regulatory outcomes associated with storm restoration, including but not limited to Hurricane Sandy, Hurricane Irene and the October snowstorm of 2011.

•	Changing energy, capacity and commodity market prices including, but not limited to, coal, natural gas and oil, and availability and their impact on retail margins.

•	The continued ability of our regulated utilities to recover their costs.

•	Costs being higher than anticipated and the success of our policies to control costs and to mitigate low energy, capacity and market prices.

•	Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission, water discharge, water intake and coal combustion residual regulations, the potential impacts of CSAPR, CAIR, and/or any laws, rules or regulations that ultimately replace CAIR, and the effects of the EPA's MATS rules including our estimated costs of compliance.

•	The uncertainty of the timing and amounts of the capital expenditures that may arise in connection with any litigation, including NSR litigation or potential regulatory initiatives or rulemakings (including that such expenditures could result in our decision to deactivate or idle certain generating units).

•	The uncertainties associated with the deactivation of certain older regulated and competitive fossil units including the impact on vendor commitments, and the timing thereof as they relate to, among other things, RMR arrangements and the reliability of the transmission grid.

•	Adverse regulatory or legal decisions and outcomes with respect to our nuclear operations (including, but not limited to the revocation or non-renewal of necessary licenses, approvals or operating permits by the NRC or as a result of the incident at Japan's Fukushima Daiichi Nuclear Plant).

•	Issues arising from the indications of cracking in the shield building at Davis-Besse.

•	The impact of future changes to the operational status or availability of our generating units.

•	The risks and uncertainties associated with litigation, arbitration, mediation and like proceedings, including, but not limited to, any such proceedings related to vendor commitments.

•	Replacement power costs being higher than anticipated or not fully hedged.

•	The ability to comply with applicable state and federal reliability standards and energy efficiency and peak demand reduction mandates.

•	Changes in customers' demand for power, including but not limited to, changes resulting from the implementation of state and federal energy efficiency and peak demand reduction mandates.

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The ability to accomplish or realize anticipated benefits from strategic and financial goals including, but not limited to, the ability to reduce costs and to successfully complete our announced financial plans designed to improve our credit metrics and strengthen our balance sheet, including but not limited to, proposed capital raising and debt reduction initiatives, and the proposed sale of non-core hydro assets.

•	Our ability to improve electric commodity margins and the impact of, among other factors, the increased cost of fuel and fuel transportation on such margins.

•	The ability to experience growth in the Regulated Distribution and Regulated Transmission segments and to continue to successfully implement our direct retail sales strategy in the Competitive Energy Services segment.

•	Changing market conditions that could affect the measurement of liabilities and the value of assets held in our NDTs, pension trusts and other trust funds, and cause us and our subsidiaries to make additional contributions sooner, or in amounts that are larger than currently anticipated.

•	The impact of changes to material accounting policies.

•	The ability to access the public securities and other capital and credit markets in accordance with our announced financial plan, the cost of such capital and overall condition of the capital and credit markets affecting us and our subsidiaries.

•	Actions that may be taken by credit rating agencies that could negatively affect us and our subsidiaries' access to financing, increase the costs thereof, and increase requirements to post additional collateral to support outstanding commodity positions, LOCs and other financial guarantees.

•	Changes in national and regional economic conditions affecting us, our subsidiaries and our major industrial and commercial customers, and other counterparties including fuel suppliers, with which we do business.

•	Issues concerning the stability of domestic and foreign financial institutions and counterparties with which we do business.

•	The risks and other factors discussed from time to time in our SEC filings, and other similar factors.

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*	Includes excise tax collections of $117 million and $123 million in the three months ended September 30, 2013 and 2012, respectively, and $346 million and $351 million in the nine months ended September 30, 2013 and 2012, respectively.

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(1)	See Note 16, Discontinued Operations and Assets Held for Sale.

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(1)	For the three months and nine ended September 30, 2013, 2 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. For the three and nine months ended September 30, 2012, less than 1 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

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(1)	The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.2 billion.

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(1)	NUG and LCAPP contracts are generally subject to regulatory accounting treatment and do not impact earnings.

(2)	NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index.

(3)	Primarily consists of short-term cash investments.

(4)	Excludes $13 million and $110 million as of September 30, 2013 and December 31, 2012, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

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(1)	Changes in the fair value of NUG and LCAPP contracts are generally subject to regulatory accounting treatment and do not impact earnings.

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(1)	NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index.

(2)	Primarily consists of short-term cash investments.

(3)	Excludes $12 million and $94 million as of September 30, 2013 and December 31, 2012, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.

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(1)	Excludes short-term cash investments: FE Consolidated - $106 million; FES - $55 million.

(2)	Excludes short-term cash investments: FE Consolidated - $326 million; FES - $196 million.

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•	Generation supplied through a CBP;

•	A load cap of no less than 80%, so that no single supplier is awarded more than 80% of the tranches, which also applies to tranches assigned post-auction;

•	A 6% generation discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies);

•	No increase in base distribution rates through May 31, 2014; and

•	A new distribution rider, Rider DCR, to recover a return of, and on, capital investments in the delivery system.

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•	Continuing the current base distribution rate freeze through May 31, 2016;

•	Continuing to provide economic development and assistance to low-income customers for the two-year plan period at levels established in the existing ESP;

•	A 6% generation rate discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies);

•	Continuing to provide power to non-shopping customers at a market-based price set through an auction process; and

•	Continuing Rider DCR that allows continued investment in the distribution system for the benefit of customers.

•	Securing generation supply for a longer period of time by conducting an auction for a three-year period rather than a one-year period, in each of October 2012 and January 2013, to mitigate any potential price spikes for the Ohio Companies' utility customers who do not switch to a competitive generation supplier; and

•	Extending the recovery period for costs associated with purchasing RECs mandated by SB221 through the end of the new ESP 3 period. This is expected to initially reduce the monthly renewable energy charge for all non-shopping utility customers of the Ohio Companies by spreading out the costs over the entire ESP period.

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•	$40 million annualized base rate increases effective June 29, 2010;

•	Deferral of February 2010 storm restoration expenses over a maximum five-year period;

•	Additional $20 million annualized base rate increase effective in January 2011;

•	Decrease of $20 million in ENEC rates effective January 2011, providing for deferral of related costs for later recovery in 2012; and

•	Moratorium on filing for further increases in base rates before December 1, 2011, except under specified circumstances.

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•

On August 21, 2013, MP and PE, along with the majority of the parties to the companies' generation transaction proceedings involving the Harrison Power Station, filed a comprehensive settlement agreement with the WVPSC. On October 7, 2013, the WVPSC issued an Order authorizing the transaction with certain conditions and on October 9, 2013, MP sold its approximate 8% share of Pleasants at its fair market value of $73 million to AE Supply, and AE Supply sold its approximate 80% share of Harrison to MP at its book value of $1.2 billion. The transaction resulted in AE Supply receiving net consideration of $1.1 billion and MP's assumption of a $73.5 million pollution control note. Currently, the $1.1 billion net consideration was financed by MP through an equity infusion from FE of approximately $527 million and a note payable to AE Supply of approximately $573 million. In connection with the closing, in the fourth quarter of 2013, MP recorded a pre-tax impairment charge of approximately $330 million to reduce the net book value of the Harrison Power Station to the amount that was permitted to be included in jurisdictional rate base. Additionally, MP recognized a regulatory liability of approximately $23 million in the fourth quarter of 2013 representing refunds to customers associated with the excess purchase price received by MP above the net book value of MP's minority interest in the Pleasants Power Station.

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On September 4, 2013, FESC, on behalf of FG, AE Supply and Green Valley Hydro LLC applied for authorization from the FERC to sell eleven hydroelectric power stations in Pennsylvania, Virginia and West Virginia to subsidiaries of Harbor Hydro, a subsidiary of LS Power, for approximately $400 million. The hydroelectric power stations included in this proposed sale have a total generating capacity of approximately 527 MW, which represents less than 3 percent of FirstEnergy's competitive generation fleet output. An asset purchase agreement was entered into on August 23, and amended and restated as of September 4, 2013. Subject to receiving the required regulatory authorizations and the resolution of the potential competing license application and other claims and matters regarding the Seneca Pumped Storage Project, the proposed transaction is expected to close in the fourth quarter of 2013.

•	On September 25, 2013, FE filed a registration statement with the SEC to register 4 million shares of common stock to be issued to registered shareholders and its employees and the employees of its subsidiaries under its Stock Investment Plan. In addition, FE expects to also begin fulfilling certain share-based benefit plan obligations through the issuance of authorized but unissued common stock.

•	On August 21, 2013, JCP&L issued $500 million of 4.7% fixed-rate unsecured taxable long-term debt. The proceeds were used to pay down a portion if its short-term debt obligations.

•	On August 28, 2013, the Ohio Companies redeemed $660 million of long-term debt. In addition, approximately $120 million was paid in make-whole premiums which was deferred as a regulatory asset and will be amortized over the original life of the redeemed debt.

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On October 31, 2013, FE amended its existing $2.5 billion multi-year syndicated revolving credit facility to exclude certain after-tax, non-cash write-downs and non-cash charges of approximately $1.4 billion from the debt to total capitalization ratio calculations incurred through September 30, 2013. Additionally, the amendment provides for a future allowance of approximately $1.35 billion for after-tax non-cash write-downs and non-cash charges over the remaining life of the facility.

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(1)	Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses and the elimination of intersegment transactions.

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•	Fuel expense was $12 million higher in 2013 primarily related to increased generation at the Fort Martin plant during third quarter of 2013.

•	Purchased power costs were $100 million lower in 2013 primarily due to a decrease in volumes required as a result of increased customer shopping, higher generation and reduced NUG purchases, partially offset by higher energy and capacity unit cost.

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•	Other operating expenses increased $6 million primarily due to:

•	higher transmission expenses of $26 million primarily due to PJM transmission costs associated with RMR units, partially offset by

•	lower distribution operating and maintenance expenses of $8 million primarily due to lower storm related maintenance activities during the third quarter of 2013, partially offset by more work allocated to capital in the third quarter of 2012 associated with integrating Allegheny's work management system,

•	lower Pennsylvania state reimbursed program costs of $6 million, which are recovered through rates, and

•	decreased regulated generation operating and maintenance expenses of $6 million primarily related to a forced outage at Fort Martin in the third quarter of 2012.

•	Depreciation expense increased by $17 million due to a higher asset base and an adjustment in the third quarter of 2012 to reduce depreciation rates for WP that was approved by the PPUC in September 2012.

•	Net regulatory asset amortization increased $250 million primarily due to a regulatory asset impairment associated with the recovery of marginal transmission losses at ME and PN, lower storm cost deferrals and higher default generation service costs recovery in Pennsylvania, partially offset by a reduction of NUG cost recovery at ME and PN and higher transmission cost deferrals in Ohio.

•	General taxes decreased by $14 million primarily due to lower gross receipts and payroll taxes, partially offset by higher property taxes.

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Fuel costs increased $9 million due primarily to settlements associated with past damages on various coal and transportation contracts, partially offset by lower unit prices associated with new and restructured coal contracts. Volumes increased as a result of higher fossil generation driven by increased economic generation and the W.H. Sammis Plant being temporarily idled in September 2012, partially offset by lower nuclear generation due to unplanned outages.

•	Purchased power costs increased $143 million due to higher capacity expenses ($43 million), higher volumes ($64 million) and increased prices ($46 million), partially offset by reduced losses on financially settled contracts ($10 million). The

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•	Fossil operating costs decreased by $10 million due primarily to lower labor costs resulting from previously deactivated units and lower compensation and benefit expenses based on plan changes.

•	Nuclear operating costs decreased by $10 million due primarily to lower labor costs and lower compensation and benefit expenses based on plan changes.

•	Transmission expenses increased $20 million due primarily to higher rates associated with higher congestion, network and line loss costs and additional retail load, partially offset by lower ancillary costs and a credit received in the third quarter of 2013 for previously incurred PJM transmission costs associated with RMR units in the ATSI zone.

•	General taxes decreased by $3 million due primarily to lower payroll taxes as a result of lower labor costs noted above, partially offset by higher property taxes.

•	Depreciation expense increased $23 million primarily due to a higher asset base and accelerated depreciation associated with the deactivation of two unregulated coal-fired generating plants.

•	Other operating expenses decreased by $11 million primarily due to reduced lease costs from the sale and leaseback repurchases and lower corporate support costs.

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•	Fuel expense was $77 million higher in 2013 primarily related to increased generation at Fort Martin as a result of planned and forced outages in the first nine months of 2012.

•	Purchased power costs were $440 million lower in 2013 primarily due to a decrease in volumes required from increased customer shopping, higher generation, reduced NUG purchases and lower unit power supply costs during the first nine months of 2013 compared to the same period of 2012.

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•	Other operating expenses decreased $89 million primarily due to:

•	a decrease in energy efficiency program expenses of $45 million resulting from the completion of certain initiatives in Ohio and Pennsylvania, which are recovered through rates,

•	lower distribution operating and maintenance expenses of $58 million primarily due to lower storm related maintenance activities during the first nine months of 2013, and

•	decreased regulated generation operating and maintenance expenses of $22 million primarily related to planned and forced outages at Fort Martin in the first nine months of 2012, partially offset by

•	higher transmission expenses of $36 million primarily due to PJM transmission costs associated with RMR units.

•	Depreciation expense increased by $25 million due to a higher asset base.

•	Net regulatory asset amortization increased $239 million primarily due to a regulatory asset impairment associated with the recovery of marginal transmission losses at ME and PN, lower storm cost deferrals and higher default generation service costs recovery in Pennsylvania, partially offset by a reduction of NUG cost recovery at ME and PN and higher transmission cost deferrals in Ohio.

•	General taxes decreased by $16 million primarily due to a decrease in gross receipt taxes, payroll taxes and West Virginia's business and occupation tax, partially offset by an increase in property taxes.

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Fuel costs increased $5 million due primarily to settlements associated with past damages on various coal and transportation contracts, partially offset by lower unit prices associated with new and restructured coal contracts. Volumes decreased as a result of lower nuclear generation due to unplanned outages, partially offset by higher fossil generation driven by increased economic generation and the W.H. Sammis Plant being temporarily idled in September 2012.

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Purchased power costs decreased $91 million due to reduced capacity expenses ($170 million) and lower losses on financially settled contracts ($218 million) partially offset by higher volumes ($218 million) and prices ($79 million). The increase in purchased power volumes relates to lower generation primarily from the plants that were deactivated in 2012 and those under RMR arrangements, lower nuclear generation and the overall increase in sales volumes.

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Fossil operating costs decreased by $9 million due primarily to lower labor costs resulting from previously deactivated units and lower compensation and benefit expenses based on plan changes. The lower labor costs were partially offset by higher contractor, materials and equipment costs resulting from an increase in planned generating unit outages in the first nine months of 2013 as compared to the same period in 2012.

•	Nuclear operating costs decreased by $27 million due primarily to lower contractor, materials and equipment costs. In 2013, there was a single refueling outage at Perry while there were two refueling outages during the same period of 2012. Additionally, compensation and benefit expenses were lower as a result of plan changes in 2013.

•	Transmission expenses increased $79 million due primarily to higher rates associated with higher ancillary, network and line loss costs and additional retail load, partially offset by lower congestion costs and a credit received in the third quarter of 2013 for previously incurred PJM transmission costs associated with RMR units.

•	Impairments of long-lived assets increased by $473 million due to the decision to deactivate two unregulated, coal-fired generating plants in the second quarter of 2013.

•	Depreciation expense increased $44 million primarily due to the absence of credits in 2013 from a 2012 settlement with the DOE, higher asset base, and accelerated depreciation associated with deactivation noted above.

•	General taxes decreased by $3 million due primarily to lower payroll taxes as a result of lower labor costs noted above, partially offset by higher property taxes.

•	Other operating expenses increased by $87 million primarily due to an increase in mark-to-market expense on commodity contract positions ($99 million) and increased retail expenses ($13 million), partially offset by reduced lease costs from sale and leaseback repurchases ($25 million).

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(1)	These PCRBs are classified as currently payable long-term debt because the applicable interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity.

(1)	FE and the Utilities.

(2)	Includes FET, ATSI and TrAIL.

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(1)	No limitations.

(2)	No limitation based upon blanket financing authorization from the FERC under existing open market tariffs.

(3)	Includes amounts which may be borrowed under the regulated companies' money pool.

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(1)	Excludes approximately $9 million of applicable interest coverage.

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•	$473 million increase from impairment of long-lived assets due to the Hatfield's Ferry and Mitchell plant deactivations.

•	$132 million increase from the loss on debt redemptions associated with the completion of the FES/AE Supply tender offers and the $400 million FES debt redemption described below.

•	$153 million increase from lower deferred purchased power and other costs primarily due to the expiration of certain NUG agreements.

•	$40 million increase from higher deferred rents and market lease valuation as a result of increased net amortization of lease expense.

•	$245 million increase in amortization of regulatory assets primarily due to a regulatory asset impairment charge at ME and PN associated with the recovery of marginal transmission losses.

•	$104 million increase due to net commodity derivative transactions.

•	$598 million decrease in deferred income taxes and investment tax credits. Of the decrease, $156 million was the result of the reversal of deferred income tax liabilities associated with the impairment of Hatfield's Ferry and Mitchell.

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(1)	Issued for open-ended terms, with a 10-day termination right by FirstEnergy.

(2)	Reflects the interest coverage portion of LOCs issued in support of floating rate PCRBs with various maturities. The principal amount of floating-rate PCRBs of $809 million is reflected in currently payable long-term debt on FirstEnergy's consolidated balance sheets.

(3)	Includes guarantees of $136 million for nuclear decommissioning funding assurances, $161 million supporting OE’s sale and leaseback arrangements, and $21 million for railcar leases.

(4)	Includes $7 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facilities, $97 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $28 million pledged in connection with the sale and leaseback of Perry by OE.

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(1)	Represents exchange traded New York Mercantile Exchange futures and options.

(2)	Primarily represents contracts based on broker and ICE quotes.

(3)	Includes $(376) million in non-hedge derivative contracts that are primarily related to NUG and LCAPP contracts. NUG and LCAPP contracts are generally subject to regulatory accounting and do not materially impact earnings.

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•	Generation supplied through a CBP;

•	A load cap of no less than 80%, so that no single supplier is awarded more than 80% of the tranches, which also applies to tranches assigned post-auction;

•	A 6% generation discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies);

•	No increase in base distribution rates through May 31, 2014; and

•	A new distribution rider, Rider DCR, to recover a return of, and on, capital investments in the delivery system.

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•	Continuing the current base distribution rate freeze through May 31, 2016;

•	Continuing to provide economic development and assistance to low-income customers for the two-year plan period at levels established in the existing ESP;

•	A 6% generation rate discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies);

•	Continuing to provide power to non-shopping customers at a market-based price set through an auction process; and

•	Continuing Rider DCR that allows continued investment in the distribution system for the benefit of customers.

•	Securing generation supply for a longer period of time by conducting an auction for a three-year period rather than a one-year period, in each of October 2012 and January 2013, to mitigate any potential price spikes for the Ohio Companies' utility customers who do not switch to a competitive generation supplier; and

•	Extending the recovery period for costs associated with purchasing RECs mandated by SB221 through the end of the new ESP 3 period. This is expected to initially reduce the monthly renewable energy charge for all non-shopping utility customers of the Ohio Companies by spreading out the costs over the entire ESP period.

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•	$40 million annualized base rate increases effective June 29, 2010;

•	Deferral of February 2010 storm restoration expenses over a maximum five-year period;

•	Additional $20 million annualized base rate increase effective in January 2011;

•	Decrease of $20 million in ENEC rates effective January 2011, providing for deferral of related costs for later recovery in 2012; and

•	Moratorium on filing for further increases in base rates before December 1, 2011, except under specified circumstances.

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•	Fossil operating costs decreased by $31 million due primarily to lower labor costs resulting from previously deactivated units and lower compensation and benefit expenses based on plan changes.

•	Nuclear operating costs decreased by $27 million due primarily to lower contractor, materials and equipment costs. In 2013, there was a single refueling outage at Perry while there were two refueling outages during the same period of 2012. Additionally, compensation and benefit expenses were lower as a result of plan changes in 2013.

•	Transmission expenses increased $71 million due primarily to higher rates associated with higher ancillary, network and line loss costs and additional retail load, partially offset by lower congestion costs and a credit received in the third quarter of 2013 for previously incurred PJM transmission costs associated with RMR units.

•	Other operating expenses increased by $64 million primarily due to an increase in mark-to-market expense on commodity contract positions ($88 million) partially offset by reduced lease expense ($24 million) from repurchasing interests in sale and leaseback transactions during 2012.

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ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4.	CONTROLS AND PROCEDURES

(1)

Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock for some or all of the following: 2007 Incentive Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan, Director Compensation, Allegheny Energy, Inc., 1998 Long-Term Incentive Plan, Allegheny Energy, Inc., 2008 Long-Term Incentive Plan, Allegheny Energy, Inc., Non-Employee Director Stock Plan, Allegheny Energy, Inc., Amended and Restated Revised Plan for Deferral of Compensation of Directors, and Stock Investment Plan.

(2)	FirstEnergy does not currently have any publicly announced plan or program for share purchases.

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(1)	the $2.5 billion Credit Agreement, dated as of June 17, 2011, as amended, among FirstEnergy, CEI, ME, OE, Penn, TE, JCP&L, MP, PN, PE and WP, as borrowers, The Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein (FirstEnergy Facility); and

(2)	the $2.5 billion Credit Agreement, dated as of June 17, 2011, as amended, among FES and AE Supply, as borrowers, and JPMorgan Chase Bank, N.A., as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein (FES/AE Supply Facility).

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