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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 ability to experience growth in the Regulated Distribution and Regulated Transmission segments and to successfully implement our revised sales strategy in the Competitive Energy Services segment.

•	The accomplishment of our regulatory and operational goals in connection with our transmission plan and pending distribution rate cases and the effectiveness of our repositioning strategy.

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

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The impact of the federal regulatory process on FERC-regulated entities and transactions, in particular FERC regulation of wholesale energy and capacity markets, including PJM markets and also FERC-jurisdictional wholesale transactions, FERC regulation of cost-of-service rates, including FERC Opinion No. 531’s revised ROE methodology for FERC-jurisdictional wholesale generation and transmission utility service, and FERC’s compliance and enforcement activity, including compliance and enforcement activity related to NERC’s mandatory reliability standards.

•	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 such as a polar vortex or other significant weather events, and all associated regulatory events or actions.

•	Regulatory outcomes associated with storm restoration costs, 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 their availability and impact on 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, but not limited to, possible GHG emission, water discharge, and CCR regulations, the potential impacts of CSAPR, 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.

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

•	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 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.

•

The ability to accomplish or realize anticipated benefits from strategic and financial goals, including, but not limited to, the ability to continue to reduce costs and successfully execute our announced financial plans designed to improve our credit metrics and strengthen our balance sheet through, among other actions, our previously-implemented dividend reduction and our other proposed capital raising initiatives.

•	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.

•	Changing market conditions that could affect the measurement of certain liabilities and the value of assets held in our NDTs, pension trusts and other trust funds, and cause us and/or 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 plans, the cost of such capital and overall condition of the capital and credit markets affecting us and our subsidiaries.

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•	Actions that may be taken by credit rating agencies that could negatively affect us and/or 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/or our major industrial and commercial customers and other counterparties with which we do business, including fuel suppliers.

•	The impact of any changes in tax laws or regulations or adverse tax audit results or rulings.

•	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 $105 million and $117 million in the three months ended September 30, 2014 and 2013, respectively, and $321 million and $346 million in the nine months ended September 30, 2014 and 2013, respectively.

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(1)

For the three months ended September 30, 2014 and September 30, 2013, 1 million and 2 million shares, respectively, were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. For the nine months ended September 30, 2014 and September 30, 2013, 2 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

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(1)	NUG contracts are 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 $(45) million and $10 million as of September 30, 2014 and December 31, 2013, 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 contracts are generally subject to regulatory accounting treatment and do not impact earnings.

(2)	See Note 9, Derivative Instruments

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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 $(36) million and $9 million as of September 30, 2014 and December 31, 2013, 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 - $87 million; FES - $54 million.

(2)	Excludes short-term cash investments: FE Consolidated - $204 million; FES - $135 million.

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(1)	During the fourth quarter of 2013, all LCAPP contracts were terminated as discussed above.

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(1)	During the fourth quarter of 2013, all LCAPP contracts were terminated as discussed above.

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

•	Continues collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;

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

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

•	Continuing commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of the five-year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million, subject to the outcome of certain FERC proceedings;

•	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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•	Continuing a base distribution rate freeze through May 31, 2019;

•	Continues collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;

•	Providing economic development and assistance to low-income customers for the three-year plan period;

•	An Economic Stability Program providing for a retail rate stability rider to flow through charges or credits representing the net result of the costs paid to FES through a proposed 15-year purchase power agreement for the output of Sammis, Davis-Besse and FES’ share of OVEC against the revenues received from selling the output into the PJM markets over the same period;

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

•	Continuing Rider DCR with increased revenue caps of approximately $30 million per year that allows continued investment supporting the distribution system for the benefit of customers;

•

A commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of the five-year period from June 1, 2011 through May 31, 2016 or when the amount of such costs avoided by customers for certain types of products totals $360 million, including appropriately such costs from MISO along with such costs from PJM, subject to the outcome of certain FERC proceedings; and

•	General updates to electric service regulations and tariffs to reflect regulatory orders, administrative rule changes, and current practices.

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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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•	Lower deliveries to residential and commercial customers primarily reflecting decreased weather-related usage from cooling degree days that were 15% below last year. Sales to the industrial sector increased more than 3% primarily related to shale gas, steel and petroleum customers.

•	Increased regulated generation earnings primarily associated with the Harrison/Pleasants asset transfer in October of 2013. Currently a return on and of Harrison Plant costs are included as a temporary surcharge billed to all retail customers.

•	Lower Regulatory charges of $253 million (pre-tax) primarily resulting from a 2013 regulatory asset impairment associated with deferred marginal transmission losses at ME and PN.

•	Higher ATSI revenues reflecting incremental cost of service and rate base recovery resulting from its annual rate filing effective June 2014.

•	Increased operating and maintenance expenses, property taxes and depreciation associated with a higher asset base.

•	Reduced revenues resulting from lower customer counts as the segment aligns its sales portfolio to more effectively hedge its generation, partially offset by higher capacity revenues resulting from higher capacity rates.

•	Higher capacity expenses associated with its retail sales obligations resulting from higher capacity rates.

•	Lower expenses for fuel, depreciation and operations primarily as a result of plant deactivations and the Harrison/Pleasants asset transfer.

•	Other items impacting the Competitive Energy Services segment's earnings include the following pre-tax charges and gains:

•	Losses related to commodity mark-to-market adjustments were $20 million in the third quarter of 2014. There were mark-to-market gains of $3 million in the third quarter of 2013.

•	Impairments on securities held in NDT were $6 million in the third quarter of 2014 compared to $21 million in the third quarter of 2013.

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•	Fuel expense was $71 million higher in the third quarter of 2014 primarily related to increased generation as a result of the Harrison/Pleasants asset transfer in October of 2013.

•	Purchased power costs were $37 million lower primarily due to a decrease in volumes resulting from lower weather-related usage, partially offset by increased capacity expense and higher unit prices due to higher auction clearing prices.

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•	Other operating expenses increased $16 million primarily due to:

•	Higher vegetation management expenses of $14 million in West Virginia, which are deferred for future recovery,

•	Increased regulated generation operating and maintenance expenses of $10 million, reflecting increased costs associated with the Harrison/Pleasants asset transfer,

•	Higher pension and OPEB costs of $8 million primarily associated with lower amortization of prior service cost credits,

•	Higher transmission expenses of $5 million due to higher congestion and network transmission costs primarily at MP related to the Harrison/Pleasants asset transfer partially offset by lower PJM charges to the Ohio Companies, and

•	Lower energy efficiency expenses and other regulatory program costs of $17 million, which are recovered through rates.

•	Depreciation expense increased $14 million due to a higher asset base, including $7 million associated with the Harrison/Pleasants asset transfer.

•	Net amortization of regulatory assets decreased $276 million primarily due to a 2013 regulatory asset impairment associated with the recovery of marginal transmission losses at ME and PN and the deferral of vegetation management expenses in West Virginia.

•	General taxes increased $2 million due to higher property taxes and West Virginia Business and Occupation taxes, partially offset by lower revenue related taxes.

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Fuel costs decreased $184 million primarily due to lower volumes associated with the Harrison/Pleasants asset transfer and the deactivation of certain power plants in 2013, partially offset by a slight increase in nuclear generation. Lower fossil unit prices and lower nuclear unit prices, as a result of the suspension of the DOE disposal fee, which became effective May 16, 2014, also contributed to the decrease. Additionally, fuel costs in the third quarter of 2013 were impacted by settlement and termination costs related to coal and transportation contracts of $27 million.

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Purchased power costs increased $102 million due to higher capacity expenses ($107 million) and losses on financially settled contracts ($46 million), partially offset by lower prices ($45 million) and lower volumes ($6 million) resulting from lower contract sales net of additional volume required as a result of the Harrison/Pleasants asset transfer. The increase in capacity expense was the result of higher capacity rates.

•	Fossil operating costs decreased $22 million primarily due to lower contractor, labor and materials and equipment costs resulting from previously deactivated units and the Harrison/Pleasants asset transfer.

•	Nuclear operating costs decreased $9 million as a result of pre-outage activities associated with the fall refueling outage in the third quarter of 2013. There were no fall refueling outages in the third quarter of 2014.

•	Transmission expenses decreased $22 million primarily due to lower ancillary and network costs resulting from decreased retail sales and lower congestion prices, partially offset by a credit received in the third quarter of 2013 for previously incurred PJM transmission costs associated with RMR units in the ATSI zone.

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•	General taxes decreased $9 million primarily due to lower gross receipts taxes associated with decreased retail sales volumes and lower property taxes due to the Harrison/Pleasants asset transfer.

•	Depreciation expense decreased $25 million primarily due to a reduction in the asset base as a result of plant deactivations and the Harrison/Pleasants asset transfer noted above, partially offset by capital assets placed in service.

•	Other operating expenses increased $28 million primarily due to an increase in mark-to-market expenses on commodity contract positions.

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•	Fuel expense was $191 million higher in the first nine months of 2014 primarily related to increased generation as a result of the Harrison/Pleasants asset transfer in October of 2013.

•	Purchased power costs were $53 million higher primarily due to increased unit prices reflecting higher auction clearing prices and increased capacity expense during the first nine months of 2014 compared to the same period of 2013, partially offset by a decrease in volumes required.

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•	Other operating expenses increased $306 million primarily due to:

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Higher transmission expenses of $137 million primarily due to PJM transmission costs associated with higher congestion rates at MP as a result of market conditions related to extreme weather events in January 2014 and higher PJM transmission costs resulting from the Harrison/Pleasants asset transfer. The differences between current transmission revenues and transmission costs incurred are deferred for future recovery, resulting in no material impact on current period earnings.

•	Higher distribution operating and maintenance expenses of $73 million primarily due to higher maintenance activities and storm-related restoration costs, including $22 million associated with Winter Storm Nika during the first quarter of 2014, of which $15 million was deferred for future recovery.

•	Higher vegetation management expenses in West Virginia of $21 million, which were deferred for future recovery.

•	Higher pension and OPEB costs of $27 million primarily associated with lower amortization of prior service cost credits.

•	Increased regulated generation operating and maintenance expenses of $40 million, reflecting increased costs associated with the Harrison/Pleasants asset transfer and a planned outage at Fort Martin.

•	Depreciation expense increased $45 million due to a higher asset base, including $21 million associated with the Harrison/Pleasants asset transfer.

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Net amortization of regulatory assets decreased $418 million primarily due to a 2013 regulatory asset impairment associated with the recovery of marginal transmission losses at ME and PN ($254 million), higher storm cost deferrals, lower Pennsylvania default generation service and NUG cost recovery, increased deferred vegetation management expenses in West Virginia and decreased energy efficiency amortization reflecting a rate decrease associated with certain programs for the Pennsylvania Companies.

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Fuel costs decreased $395 million primarily due to lower generation volumes resulting from the Harrison/Pleasants asset transfer, the deactivation of certain power plants in 2013 and increased outages as compared to the same period of 2013. Higher unit prices, primarily driven by increased peaking generation, was partially offset by the suspension of the DOE nuclear disposal fee, which became effective May 16, 2014. Additionally, fuel costs were impacted by an increase in settlement and termination costs related to coal and transportation contracts. In the first nine months of 2014, fuel supply agreements were terminated for approximately $85 million, while settlements associated with damages on coal and transportation contracts were $61 million in the first nine months of 2013.

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Purchased power costs increased $777 million due to higher volumes ($466 million), increased prices ($515 million), and higher capacity expenses ($221 million), partially offset by lower losses on financially settled contracts ($425 million). Higher purchased volumes were primarily due to lower available generation due to outages, the Harrison/Pleasants asset transfer and the deactivation of certain power plants in 2013, partially offset by lower contract sales. The increase in prices was primarily a result of market conditions related to extreme weather events in January 2014, partially offset by lower losses on financially settled contracts. Increased customer demand that was unhedged and replacement power requirements due to the timing of unplanned outages and derates contributed to purchasing additional volumes at these higher prices. The increase in capacity expense was primarily the result of higher capacity rates.

•	Fossil operating costs decreased $96 million primarily due to lower contractor, labor and materials and equipment costs resulting from previously deactivated units and the Harrison/Pleasants asset transfer.

•	Nuclear operating costs increased $25 million as a result of higher contractor, materials and equipment costs associated with refueling outages. There were two refueling outages in the first nine months of 2014 as compared to one outage in the first nine months of 2013.

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Transmission expenses increased $105 million primarily due to higher operating reserve and market-based ancillary costs associated with market conditions related to extreme weather events in January 2014, of which a portion were passed through to commercial and industrial customers, as discussed above. Additionally, effective June 1, 2013, network expenses associated with POLR sales in Pennsylvania became the responsibility of suppliers.

•	General taxes decreased $25 million primarily due to lower gross receipts taxes resulting from reduced retail sales volumes, lower payroll taxes as a result of lower labor costs noted above, lower property taxes due to the Harrison/Pleasants asset transfer, and reduced Ohio personal property taxes.

•	Impairments of long-lived assets decreased $473 million due to the impairment of two unregulated, coal-fired generating plants in the second quarter of 2013. The units were deactivated in October of 2013.

•	Depreciation expense decreased $60 million primarily due to a reduction in the asset base as a result of the plant deactivations and the Harrison/Pleasants asset transfer noted above.

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•	Other operating expenses increased $74 million primarily due to an increase in mark-to-market expenses on commodity contract positions and an impairment of deferred advertising costs of $22 million associated with the elimination of future selling efforts in the Mass Market and Medium Commercial-Industrial sales channels.

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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.

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(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 $1 million of applicable interest coverage.

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•	a $416 million decrease in the amortization of regulatory assets as discussed above, and

•	a $473 million impairment of long-lived assets recognized in 2013 resulting from the Hatfield's Ferry and Mitchell plant deactivations.

•	lower payments to vendors of approximately $232 million primarily resulting from payments in 2013 related to restoration costs associated with Hurricane Sandy,

•	lower tax and other payments of approximately $101 million,

•	increased retail receipts of approximately $97 million associated with higher weather related usage primarily in the first quarter of 2014, and

•	higher accrued interest of approximately $37 million associated with issuances of long-term debt, and

•	make whole premiums paid during 2013 of approximately $181 million, partially offset by

•	higher materials and supplies inventory purchases of approximately $136 million.

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

(2)	Includes guarantees of $16 million supporting railcar leases, $8 million for various leases and $9 million of other guarantees.

(3)	Includes Energy and Energy-Related Contracts associated with FES of approximately $113 million.

(4)

Upon acceptance by the NRC, these guarantees of $174 million replace guarantees of $136 million for nuclear decommissioning funding assurances previously provided only by FE. The increase of $38 million over the prior guarantees relates primarily to a $30 million shortfall of estimated nuclear decommissioning funding and a new guaranty of $8 million relating to spent fuel storage facilities at Beaver Valley.

(5)	Reflects the interest coverage portion of LOCs issued in support of floating rate PCRBs with maturities in 2015 and the principal amount of floating-rate PCRBs of $92 million, all of which is reflected in currently payable long-term debt on FirstEnergy's consolidated balance sheets.

(6)	Includes $54 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facilities, $12 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $22 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 $(155) million in non-hedge derivative contracts related to NUG contracts. NUG contracts are subject to regulatory accounting and do not impact earnings.

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

•	Continues collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;

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

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

•	Continuing commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of the five-year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million, subject to the outcome of certain FERC proceedings;

•	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

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•	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.

•	Continuing a base distribution rate freeze through May 31, 2019;

•	Continues collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;

•	Providing economic development and assistance to low-income customers for the three-year plan period;

•	An Economic Stability Program providing for a retail rate stability rider to flow through charges or credits representing the net result of the costs paid to FES through a proposed 15-year purchase power agreement for the output of Sammis, Davis-Besse and FES’ share of OVEC against the revenues received from selling the output into the PJM markets over the same period;

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

•	Continuing Rider DCR with increased revenue caps of approximately $30 million per year that allows continued investment supporting the distribution system for the benefit of customers;

•

A commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of the five-year period from June 1, 2011 through May 31, 2016 or when the amount of such costs avoided by customers for certain types of products totals $360 million, including appropriately such costs from MISO along with such costs from PJM, subject to the outcome of certain FERC proceedings; and

•	General updates to electric service regulations and tariffs to reflect regulatory orders, administrative rule changes, and current practices.

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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 $7 million primarily due to lower contractor, labor and materials and equipment costs as the amount of planned outages for the nine months ended September 2014 declined from the previous year.

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•	Nuclear operating costs increased $25 million as a result of higher contractor, materials and equipment costs associated with refueling outages. There were two refueling outages in the first nine months of 2014 as compared to one outage in the first nine months of 2013.

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Transmission expenses increased $87 million primarily due to higher operating reserve and market-based ancillary costs associated with market conditions related to extreme weather events in January 2014. These ancillary charges from PJM were for system reliability and a portion of which are able to be passed through to commercial and industrial customers. Additionally, effective June 1, 2013, network expenses associated with POLR sales in Pennsylvania became the responsibility of suppliers.

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Other operating expenses increased $66 million primarily due to an increase in mark-to-market expenses of $46 million on commodity contract positions, an impairment of deferred advertising costs associated with the elimination of future selling efforts in the mass market and medium commercial-industrial sales channels, partially offset by lower leasehold costs from the Ohio Companies and retail and marketing related costs.

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4.	CONTROLS AND PROCEDURES

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