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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 Hurricane Sandy.

•	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.

•	Operation and maintenance costs being higher than anticipated.

•	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 CAIR, and 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 unscrubbed regulated and competitive fossil units, including the impact on vendor commitments, and the timing thereof as they relate to, among other things, the 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).

•	Adverse legal decisions and outcomes related to ME's and PN's ability to recover certain transmission costs through their TSC riders.

•	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 inadequately 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, the proposed West Virginia asset transfer and potential 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 segment 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 $114 million and $121 million in the three months ended March 31, 2013 and 2012, respectively.

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(1)	The number of potentially dilutive securities not included in the calculation of diluted shares outstanding due to their antidilutive effect were not significant for the three months ended March 31, 2013 and 2012.

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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.

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

(4)	Excludes $(10) million and $110 million as of March 31, 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.

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

(3)	Excludes $(6) million and $94 million as of March 31, 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 - $266 million; FES - $133 million.

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

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(1)	Changes in the fair value of certain contracts are deferred for future recovery from (or credited to) customers.

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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.

•	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 extension 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 shopping and to non-shopping customers as part of the 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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(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 $48 million higher in 2013 primarily related to increased generation at Fort Martin as a result of a planned outage in the first quarter of 2012 to perform routine maintenance work.

•	Purchased power costs were $207 million lower in 2013 primarily due to a decrease in volumes required from increased customer shopping and lower unit power supply costs during the first quarter of 2013 compared to the same period of 2012 as a result of lower auction prices, partially offset by higher weather-related usage.

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•	Other operating expenses decreased $52 million due to:

•	a decrease in energy efficiency program expenses of $27 million, resulting from the absence of commercial and industrial lighting rebates in Ohio during the first quarter of 2012, which are recovered through rates,

•	lower distribution operating and maintenance expenses of $27 million primarily due to a greater focus on capital work during the first quarter of 2013 and cost savings initiatives, including staffing reductions and benefit plan changes, implemented subsequent to the first quarter of 2012,

•	decreased regulated generation operating and maintenance expenses of $6 million due to the elimination of costs related to certain deactivated units, partially offset by

•	transmission expenses that increased by $8 million primarily due to PJM charges to the Ohio Companies, which are recovered through the NMB transmission rider discussed above.

•	Depreciation expense increased by $3 million due to a higher asset base.

•	Net regulatory asset amortization decreased $17 million primarily due to a reduction in NUG cost recovery at JCP&L and ME and a decrease in the Pennsylvania Companies' default generation service cost recovery, partially offset by a decrease in deferred energy efficiency program costs.

•	General taxes decreased by $8 million primarily due to a decrease in gross receipt taxes and West Virginia's business and occupation tax, partially offset by an increase in property taxes.

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•	Fuel costs increased $41 million due to higher unit prices ($22 million) and higher volumes consumed ($19 million). Volumes increased as a result of higher fossil generation, partially offset by lower nuclear generation.

•	Purchased power costs decreased $159 million due to reduced capacity expenses ($135 million), lower losses on financially settled contracts ($106 million), partially offset by higher volumes ($74 million) and prices ($8 million). The increase in purchased power volumes primarily relates to the overall increase in sales volumes.

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Fossil operating costs increased by $6 million due primarily to higher contractor, materials and equipment costs resulting from an increase in planned generating unit outages in the first quarter of 2013 as compared to the same period in 2012. These increases were partially offset by the elimination of costs from the deactivated units. While the number of planned outages increased from the previous year, fossil generation volumes were higher as the capacity factor increased in the first three months of 2013 compared to the same period in 2012.

•	Nuclear operating costs increased by $14 million due primarily to higher contractor, materials and equipment costs. In 2013, there was a refueling outage at Perry while there were no refueling outages during the first quarter of 2012.

•	Transmission expenses increased $41 million due primarily to higher ancillary, network and line loss costs, partially offset by lower congestion costs.

•	General taxes decreased by $1 million due primarily to a favorable property tax valuation settlement.

•	Depreciation expense increased $11 million primarily due to the absence of credits in 2013 from a 2012 settlement with the DOE and a higher depreciable base as a result of repurchasing of interests in the 1987 Bruce Mansfield and Beaver Valley Unit 2 sale and leaseback transactions during 2012.

•	Other operating expenses increased by $59 million primarily due to an increase in mark-to-market expense on commodity contract positions ($66 million), partially offset by reduced lease costs from the sale and leaseback repurchases noted above.

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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.

(2)	Earlier of 6 months from drawing or the LOC termination date.

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•	$119 million increase from the loss on debt redemption associated with the completion of the FES/AE Supply tender offer.

•	$82 million increase from lower deferred purchased power and other costs primarily due to the expiration of certain NUG agreements.

•	$60 million increase from higher deferred rents and market lease valuation as a result of increased net amortization of lease expense.

•	$131 million decrease in deferred income taxes and investment tax credits.

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•	$25 million decrease in accrued retirement benefits.

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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 $106 million for nuclear decommissioning funding assurances, $161 million supporting OE’s sale and leaseback arrangements, and $24 million for railcar leases.

(4)	Includes $31 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facilities, $102 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $31 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 $(359) 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.

•	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 extension 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 shopping and to non-shopping customers as part of the 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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•	Transmission expenses increased $30 million due primarily to higher ancillary, network and line loss costs, partially offset by lower congestion costs.

•	Nuclear operating costs increased by $14 million as a result of higher contractor, materials and equipment costs. In 2013, there was a refueling outage at Perry while there were no refueling outages during the first quarter of 2012.

•

Fossil operating costs decreased by $4 million reflecting lower costs from the deactivated units, partially offset by higher contractor, materials and equipment costs resulting from an increase in forced generating unit outages in the first quarter of 2013 as compared to the prior year. While forced outages increased from the previous year, fossil generation volumes were higher as the capacity factor of the baseload units increased in the first three months of 2013 compared to the same period in 2012.

•	Other operating expenses increased by $45 million primarily due to an increase in mark-to-market expense on commodity contract positions ($50 million) partially offset by reduced lease expense from repurchasing interests in the 1987 Bruce Mansfield and Beaver Valley Unit 2 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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*

Users of this data are advised in accordance with Rule 406T of Regulation S-T promulgated by the SEC that this Interactive Data Files of FES are deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

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