FirstEnergy (FE) 8-K Regulation FD Disclosure

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

UNAUDITED INTERIM CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2013 AND 2012

GLOSSARY OF TERMS

The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries.

AE	Allegheny Energy, Inc., a Maryland utility holding company that merged with a subsidiary of FirstEnergy on February 25, 2011
AE Supply	Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary of AE
AGC	Allegheny Generating Company, a generation subsidiary of AE Supply
FE	FirstEnergy Corp., a publicly owned holding company
FESC	FirstEnergy Service Company, which provides legal, financial and other corporate support services
FirstEnergy	FirstEnergy Corp., together with its consolidated subsidiaries
MP	Monongahela Power Company, a West Virginia electric utility operating subsidiary of AE
PE	The Potomac Edison Company, an electric utility operating subsidiary of AE providing distribution and transmission service in Maryland and West Virginia and transmission service in Virginia
The following abbreviations and acronyms are used to identify frequently used terms in this report.
Anker WV	Anker West Virginia Mining Company, Inc.
Anker Coal	Anker Coal Group, Inc.
ARR	Auction Revenue Right
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CFR	Code of Federal Regulations
CO2	Carbon Dioxide
CSAPR	Cross-State Air Pollution Rule
CWA	Clean Water Act
ENEC	Expanded Net Energy Cost
EPA	United States Environmental Protection Agency
ERO	Electric Reliability Organization
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
FTR	Financial Transmission Right
GAAP	Accounting Principles Generally Accepted in the United States of America
GHG	Greenhouse Gases
HCL	Hydrochloric Acid
ICG	International Coal Group Inc.
kV	Kilovolt
KWH	Kilowatt-hour
LOC	Letter of Credit
LSE	Load Serving Entity
MATS	Mercury and Air Toxics Standards
MISO	Midcontinent Independent System Operator, Inc.
mmBTU	One Million British Thermal Units
Moody's	Moody's Investors Service, Inc.
MW	Megawatt
MWH	Megawatt-hour
NERC	North American Electric Reliability Corporation
NGO	Non-Governmental Organization
NOV	Notice of Violation

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GLOSSARY OF TERMS, Continued
NOx	Nitrogen Oxide
NPDES	National Pollutant Discharge Elimination System
NSR	New Source Review
NUG	Non-Utility Generation
OPEB	Other Post-Employment Benefits
PA DEP	Pennsylvania Department of Environmental Protection
PJM	PJM Interconnection LLC
PM	Particulate Matter
PSD	Prevention of Significant Deterioration
PURPA	Public Utility Regulatory Policies Act of 1978
REC	Renewable Energy Credit
RFC	ReliabilityFirst Corporation
RGGI	Regional Greenhouse Gas Initiative
RTEP	Regional Transmission Expansion Plan
RTO	Regional Transmission Organization
S&P	Standard & Poor's Ratings Service
SIP	State Implementation Plan(s) Under the Clean Air Act
SO2	Sulfur Dioxide
TDS	Total Dissolved Solid
TMDL	Total Maximum Daily Load
WVDEP	West Virginia Department of Environmental Protection
WVPSC	Public Service Commission of West Virginia

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30						Nine Months Ended September 30
(In thousands)	2013			2012			2013			2012
STATEMENTS OF INCOME
REVENUES:
Electric sales	$	271,953		$	285,437		$	833,522		$	889,479
Excise tax collections	2,055			1,938			6,040			5,721
Total revenues	274,008			287,375			839,562			895,200
OPERATING EXPENSES:
Fuel	87,875			76,367			249,562			173,056
Purchased power	50,281			72,973			167,148			306,770
Other operating expenses	54,295			72,436			162,739			205,264
Provision for depreciation	20,788			19,065			61,945			59,325
Amortization (deferral) of regulatory assets, net	(74		)	(27,509		)	1,629			(27,406		)
General taxes	9,847			10,496			24,058			32,954
Total operating expenses	223,012			223,828			667,081			749,963
OPERATING INCOME	50,996			63,547			172,481			145,237
OTHER INCOME (EXPENSE):
Interest expense	(9,732		)	(9,909		)	(29,364		)	(29,866		)
Capitalized interest	806			1,004			1,919			2,294
Miscellaneous income	3,630			2,360			13,874			9,614
Total other expense	(5,296		)	(6,545		)	(13,571		)	(17,958		)
INCOME BEFORE INCOME TAXES	45,700			57,002			158,910			127,279
INCOME TAXES	15,937			20,017			56,059			46,692
NET INCOME	$	29,763		$	36,985		$	102,851		$	80,587
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	29,763		$	36,985		$	102,851		$	80,587
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service benefits (costs)	(602		)	(475		)	(970		)	18,689
Other comprehensive income (loss)	(602		)	(475		)	(970		)	18,689
Income taxes (benefits) on other comprehensive income (loss)	(236		)	—			(401		)	7,703
Other comprehensive income (loss), net of tax	(366		)	(475		)	(569		)	10,986
COMPREHENSIVE INCOME	$	29,397		$	36,510		$	102,282		$	91,573

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share amounts)	September 30, 2013		December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,008	$	1,359
Receivables-
Customers, net of allowance for uncollectible accounts of $2,281 in 2013 and $2,783 in 2012	91,587		98,009
Affiliated companies	121,115		89,661
Other, net of allowance for uncollectible accounts of $331 in 2012	3,986		2,704
Notes receivable from affiliates	48,092		—
Prepaid taxes	2,268		2,366
Accumulated deferred income taxes	28,000		17,677
Materials and supplies	38,806		50,691
Restricted funds	25,907		31,593
Other	23,019		18,711
	383,788		312,771
UTILITY PLANT:
In service	2,388,742		2,308,036
Less — Accumulated provision for depreciation	142,240		76,316
	2,246,502		2,231,720
Construction work in progress	113,911		116,147
	2,360,413		2,347,867
INVESTMENTS:
Investment in AGC	61,465		54,551
Other	1,335		1,351
	62,800		55,902
DEFERRED CHARGES AND OTHER ASSETS:
Intangible assets	174,825		190,084
Other	29,101		48,717
	203,926		238,801
	$	3,010,927	$	2,955,341
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	446,079	$	316,377
Short-term borrowings - affiliated companies	—		78,805
Accounts payable-
Affiliated companies	123,174		56,991
Other	32,176		45,942
Accrued taxes	66,334		50,211
Accrued interest	15,283		13,276
Other	26,444		28,569
	709,490		590,171
CAPITALIZATION:
Common stockholder's equity-
Common stock, $50 par value, 7,000,000 shares authorized and 5,891,000 shares outstanding	294,550		294,550
Other paid-in capital	262,968		262,742
Accumulated other comprehensive income	12,741		13,310
Retained earnings	111,636		8,785
Total common stockholder's equity	681,895		579,387
Long-term debt and other long-term obligations	577,514		743,458
	1,259,409		1,322,845
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	481,622		411,542
Regulatory liabilities	258,127		287,158
Retirement benefits	88,360		88,875
Asset retirement obligations	15,872		15,010
Purchased power liability	118,294		127,432
Other	79,753		112,308
	1,042,028		1,042,325
COMMITMENTS AND CONTINGENCIES (Note 6)
	$	3,010,927	$	2,955,341

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30
(In thousands)	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	102,851		$	80,587
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	61,945			59,325
Amortization (deferral) of regulatory assets, net	1,629			(27,406		)
Amortization of purchase accounting adjustments	(18,682		)	(18,736		)
Deferred purchased power and other costs, net	2,761			32,987
Deferred income taxes and investment tax credits, net	37,871			33,626
Decrease (increase) in operating assets-
Accounts receivable	(6,714		)	(50,437		)
Materials and supplies	11,885			884
Prepayments and other current assets	(4,613		)	(3,083		)
Increase in operating liabilities-
Accounts payable	82,417			21,276
Accrued taxes	24,123			6,423
Accrued interest	2,007			1,841
Cash collateral, net	(5,296		)	8,300
Other	(23,423		)	(7,512		)
Net cash provided from operating activities	268,761			138,075
CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and repayments - long-term debt	(12,841		)	(12,223		)
Short term borrowings, net	(78,805		)	57,407
Common stock dividend payments	—			(15,000		)
Other	(2,848		)	(2,825		)
Net cash (used for) provided from financing activities	(94,494		)	27,359
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(116,653		)	(160,557		)
Loans to affiliated companies	(48,092		)	—
Decrease in restricted funds	5,686			11,316
Asset removal cost	(15,350		)	(16,316		)
Other	(209		)	(132		)
Net cash used for investing activities	(174,618		)	(165,689		)
Net change in cash and cash equivalents	(351		)	(255		)
Cash and cash equivalents at beginning of period	1,359			1,783
Cash and cash equivalents at end of period	$	1,008		$	1,528

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note Number		Page Number
1	Organization and Basis of Presentation	5
2	Taxes	5
3	Fair Value Measurements	5
4	Derivative Instruments	7
5	Regulatory Matters	7
6	Commitments and Contingencies	9

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

1. ORGANIZATION AND BASIS OF PRESENTATION

MP, together with its consolidated subsidiaries, is a wholly owned subsidiary of AE and is incorporated in Ohio. AE is a wholly owned subsidiary of FE. MP operates an electric transmission and distribution system in West Virginia and also generates power from the Fort Martin and Harrison generating units for its West Virginia customers. MP is subject to regulation by the WVPSC and the FERC.

MP's investment in unconsolidated affiliate consisted of a 41% ownership of AGC, which is accounted for under the equity method of accounting. AGC holds an undivided 40% interest (1,200 MW) in a 3,003 MW pumped-storage hydroelectric station in Bath County, Virginia. This station is operated by the 60% owner, Virginia Electric and Power Company, a non-affiliated utility.

Certain information and disclosures normally included in financial statements and notes prepared in accordance with GAAP have been condensed or omitted. These interim financial statements should be read in conjunction with the financial statements and notes included in MP's audited financial statements for the year ended December 31, 2012.

The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period. MP has evaluated events and transactions for potential recognition or disclosure through November 19, 2013, the issuance date of the financial statements.

NEW ACCOUNTING PRONOUNCEMENTS

New accounting pronouncements not yet effective are not expected to have a material effect on MP's financial statements.

2. TAXES

MP's effective tax rate for the three and nine months ended September 30, 2013 was 34.9% and 35.3%, a decrease of approximately 0.2% and 1.4%, respectively, compared to the same periods in 2012. The decrease in the nine months ended September 30, 2013 effective tax rate is primarily due to a tax expense recorded in the second quarter of 2012 associated with the remeasurement of accumulated deferred income taxes for pension and other benefits related timing differences that had previously been recorded on Allegheny Service Company.

3. FAIR VALUE MEASUREMENTS

CASH AND CASH EQUIVALENTS

All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value.

RECURRING FAIR VALUE MEASUREMENTS

Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques are as follows:

Level 1	-	Quoted prices for identical instruments in active market
Level 2	-	Quoted prices for similar instruments in active market
	-	Quoted prices for identical or similar instruments in markets that are not active
	-	Model-derived valuations for which all significant inputs are observable market data

Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.

Level 3 - Valuation inputs are unobservable and significant to the fair value measurement

FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast, which has

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

been reviewed and approved by FirstEnergy's Risk Policy Committee (see Note 4, Derivative Instruments), are used to measure fair value. A more detailed description of MP's valuation process for FTRs is as follows:

FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term RTO auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than objective sources, are the most recent RTO auction clearing prices and the FTRs' remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement.

MP primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, MP maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of September 30, 2013, from those used as of December 31, 2012. The determination of the fair value measures takes into consideration various factors, including but not limited to, nonperformance risk, counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of these forms of risk was not significant to the fair value measurements.

Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the nine months ended September 30, 2013. The following tables provide a reconciliation of changes in the fair value of FTRs held by MP and classified as Level 3 in the fair value hierarchy during the periods ended September 30, 2013 and December 31, 2012. MP has no level 1 or 2 assets or liabilities that are measured at fair value on the balance sheet.

(In millions)	Net Derivative Asset (Liability) FTRs
January 1, 2012 Balance	$	(8	)
Total unrealized gains included in regulatory assets	1
Settlements	7
December 31, 2012 Balance	$	—
Total unrealized gains included in regulatory assets	5
Purchases	(3		)
Settlements	(2		)
September 30, 2013 Balance	$	—

LONG-TERM DEBT

The following table provides the approximate fair value and related carrying amounts of long-term debt, excluding capital lease obligations and net unamortized premiums and discounts as of September 30, 2013 and December 31, 2012.

	September 30, 2013				December 31, 2012
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	1,012	$	1,033	$	1,046	$	1,128

The fair values of long-term debt reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of MP. MP classified long-term debt as Level 2 in the fair value hierarchy as of September 30, 2013 and December 31, 2012.

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

4. DERIVATIVE INSTRUMENTS

MP is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FirstEnergy’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy, including MP. FirstEnergy's Risk Policy Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice.

MP holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with MP’s load obligations. MP acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of ARRs allocated to members of an RTO that have load serving obligations. The future obligations for the FTRs acquired at auction are reflected on the Consolidated Balance Sheets on a gross basis and have not been designated as cash flow hedge instruments. MP initially records these FTRs at the auction price less the obligation due to the RTO, and subsequently adjusts the carrying value of remaining FTRs to their estimated fair value at the end of each accounting period prior to settlement. Changes in the fair value of FTRs held by MP are recorded as regulatory assets or liabilities. MP held no other derivative assets or liabilities as of September 30, 2013 or December 31, 2012.

MP had FTR assets of $1 million and FTR liabilities of $1 million in other current assets and other current liabilities on its Consolidated Balance Sheets as of September 30, 2013. As of December 31, 2012, MP had FTR assets of $2 million and FTR liabilities of $2 million in other current assets and other current liabilities. The potential effect of offsetting the derivative assets and liabilities related to FTRs is immaterial as of September 30, 2013 and December 31, 2012. MP will purchase 8 million megawatt-hours based on outstanding FTR contracts in future periods.

The counterparty to these contracts does not require collateral to mitigate credit exposure. The unrealized gains on MP's FTRs for the three months and nine months ended September 30, 2013 were $2 million and $5 million, respectively, which are subject to regulatory accounting and did not impact earnings.

5. REGULATORY MATTERS

WEST VIRGINIA

MP and PE currently operate under a Joint Stipulation and Agreement of Settlement reached with the other parties and approved by the WVPSC in June 2010 that provided for:

• $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.

In February 2011, MP and PE filed a petition with the WVPSC seeking an order declaring that MP owns all RECs associated with the energy and capacity that MP is required to purchase pursuant to electric energy purchase agreements between MP and three NUG facilities in West Virginia. The City of New Martinsville and Morgantown Energy Associates, each the owner of one of the contracted resources, opposed the petition. On November 22, 2011, the WVPSC granted ownership of all RECs produced by the facilities to MP, and held that an electric utility that purchases electric energy and capacity under an electric power purchase agreement with a Qualifying Facility under PURPA owns the RECs associated with that purchase. The West Virginia Supreme Court upheld the WVPSC's decision. The City of New Martinsville and Morgantown Energy Associates filed petitions at FERC alleging the WVPSC order violated PURPA and requested that FERC initiate an enforcement action. On April 24, 2012, FERC issued an order declining to act on the petitions and instead noted that the City of New Martinsville and Morgantown Energy Associates could file complaints in the U.S. District Court. MP and PE filed for rehearing of FERC's order, which was denied on September 20, 2012. The City of New Martinsville filed a complaint in the U.S. District Court for the Southern District of West Virginia on June 1, 2012, alleging that the WVPSC order violates PURPA. Morgantown Energy Associates has joined in filing a similar complaint and requesting damages in the same U.S. District Court. MP and PE filed for judgment on the pleadings in both cases on January 25, 2013. The WVPSC filed a motion to dismiss on June 28, 2013. On September 30, 2013, the District Court ruled in favor of MP and PE and the WVPSC and dismissed the proceedings with prejudice.

The WVPSC opened a general investigation into the June 29, 2012, derecho windstorm with data requests for all utilities. A public meeting for presentations on utility responses and restoration efforts was held on October 22, 2012 and two public input hearings have been held. The WVPSC issued an Order in this matter on January 23, 2013 closing the proceeding and directing electric utilities to file a vegetation management plan within six months and to propose a cost recovery mechanism. This Order also requires MP and PE to file a status report regarding improvements to their storm response procedures by the same date. On July 23, 2013,

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

MP and PE filed their vegetation management plans, which provided for recovery of costs through a surcharge mechanism. On October 3, 2013, the WVPSC issued a procedural schedule for the vegetation management plan proceeding and scheduled a hearing for December 3, 2013.

MP and PE filed their Resource Plan with the WVPSC in August 2012 detailing both supply and demand forecasts and noting a substantial capacity deficiency. MP and PE have filed a Petition for approval of a Generation Resource Transaction with the WVPSC in November 2012 that proposes a net ownership transfer of 1,476 MW of coal-fired generation capacity to MP. The proposed transfer would involve MP's acquisition of the remaining ownership of the Harrison Power Station from AE Supply and the sale of MP's minority interest in the Pleasants Power Station to AE Supply. The proposed transfer would implement a cost-effective plan to assist MP in meeting its energy and capacity obligations with its own generation resources, eliminating the need to make unhedged electricity and capacity purchases from the spot market, which is expected to result in greater rate stability for MP's customers. The plan is expected to remedy MP's capacity and energy shortfalls, which are projected to worsen due to a projected increase in annual load growth of approximately 1.4%. On February 11, 2013, the WVPSC issued an order adopting a procedural schedule for this matter and testimony and briefing has followed. MP and PE also filed with FERC for authorization to effect these transfers and on April 23, 2013, FERC issued an order authorizing the transfers. MP's application for FERC authorization to effect the financing was approved on May 13, 2013. Hearings were held at the WVPSC in late May and briefs and reply briefs have been submitted. A Joint Settlement Agreement was filed by the majority of parties on August 21, 2013. On October 7, 2013, WVPSC issued an order authorizing the transaction, with certain conditions and on October 9, 2013, the transaction closed resulting in MP recording a pre-tax impairment charge of approximately $330 million in the fourth quarter of 2013 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. 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. 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.

On November 6, 2013, the WVCAG filed a petition with the Supreme Court of Appeals of West Virginia appealing the WVPSC’s October 7, 2013 order approving the Generation Resource Transaction. The petition requests that the Court both grant a suspension of the WVPSC order and enter an order vacating the WVPSC order in its entirety. The Court scheduled a hearing on the matter for March 2014. We intend to defend vigorously the approval order before the Court, but we are unable to predict the outcome of this appeal. We also are unable to predict the effect of any unfavorable outcome that might result from this appeal, but such an outcome could have a material adverse effect on our business, results of operations, cash flows and financial condition.

RELIABILITY MATTERS

Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on MP. NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of MP's facilities are located within the RFC region. MP actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC.

MP believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, MP occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, MP develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to RFC. Moreover, it is clear that the NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on MP's part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties that could have a material adverse effect on its financial condition, results of operations and cash flows.

FERC MATTERS

PJM Transmission Rate

PJM and its stakeholders have been debating the proper method to allocate costs for new transmission facilities. While FirstEnergy and other parties advocated for a traditional "beneficiary pays" (or usage based) approach, others advocate for “socializing” the costs on a load-ratio share basis - each customer in the zone would pay based on its total usage of energy within PJM. On August 6, 2009, the U.S. Court of Appeals for the Seventh Circuit found that FERC had not supported a prior FERC decision to allocate costs for new 500 kV and higher voltage facilities on a load ratio share basis and, based on that finding, remanded the rate design issue to FERC. In an order dated January 21, 2010, FERC set this matter for a “paper hearing” and requested parties to submit written comments. FERC identified nine separate issues for comment and directed PJM to file the first round of comments. PJM filed certain studies with FERC on April 13, 2010, which demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain LSEs in PJM bearing the majority of the costs. FirstEnergy and a number of other

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

utilities, industrial customers and state utility commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Other utilities and state utility commissions supported continued socialization of these costs on a load ratio share basis. On March 30, 2012, FERC issued an order on remand reaffirming its prior decision that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp (or socialized) rate based on the amount of load served in a transmission zone and concluding that such methodology is just and reasonable and not unduly discriminatory or preferential. On April 30, 2012, FirstEnergy requested rehearing of FERC's March 30, 2012 order and on March 22, 2013, FERC denied rehearing. On March 29, 2013, FirstEnergy filed its Petition for Review with the U.S. Court of Appeals for the Seventh Circuit, and the case subsequently was consolidated for briefing and disposition before that court. Briefing commenced on September 11, 2013, and is expected to continue into early 2014. Thereafter, the case will be scheduled for oral argument, with a decision currently expected in 2014.

Order No. 1000, issued by FERC on July 21, 2011, required the submission of a compliance filing by PJM or the PJM transmission owners demonstrating that the cost allocation methodology for new transmission projects directed by the PJM Board of Managers satisfied the principles set forth in the order. To demonstrate compliance with the regional cost allocation principles of the order, the PJM transmission owners, including FirstEnergy, submitted a filing to FERC on October 11, 2012, proposing a hybrid method of 50% beneficiary pays and 50% postage stamp to be effective for RTEP projects approved by the PJM Board of Managers on, and after, the effective date of the compliance filing. On January 31, 2013, FERC conditionally accepted the hybrid method to be effective on February 1, 2013, subject to refund and to a future order on PJM's separate Order No. 1000 compliance filing. On March 22, 2013, FERC granted final acceptance of the hybrid method. Certain parties have sought rehearing of parts of FERC's March 22, 2013 order. These requests for rehearing are pending before FERC. On July 10, 2013, the PJM transmission owners, including FirstEnergy, submitted filings to FERC setting forth the cost allocation method for projects that cross the borders between: (1) the PJM region and the New York Independent System Operator region and; (2) the PJM region and the FERC-jurisdictional members of the Southeastern Regional Transmission Planning region. These filings propose to allocate the cost of these interregional transmission projects based on the costs of projects that otherwise would have been constructed separately in each region. On the same date, also in response to Order No. 1000, the PJM transmission owners, including FirstEnergy, also submitted to FERC a filing stating that the cost allocation provisions for interregional transmission projects provided in the Joint Operating Agreement between PJM and MISO comply with the requirements of Order No. 1000. The July 10, 2013 filings are pending before FERC.

6. COMMITMENTS AND CONTINGENCIES

ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate MP with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on MP's earnings and competitive position to the extent that MP competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations.

Clean Air Act Compliance

MP is required to meet federally-approved SO₂ and NOx emissions regulations under the CAA. MP complies with SO₂ and NOx reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls, generating more electricity from lower or non-emitting plants and/or using emission allowances.

In August 2000, AE received an information request pursuant to section 114(a) of the CAA from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten coal-fired plants, which collectively include 22 electric generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island to determine compliance with the NSR provisions under the CAA, which can require the installation of additional air emission control equipment when a major modification of an existing facility results in an increase in emissions. In September 2007, AE received an NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin and Willow Island plants in West Virginia. On June 29, 2012, January 31, 2013, and March 27, 2013, EPA issued additional CAA section 114 requests for the Harrison coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2007. MP intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the possible loss or range of loss.

National Ambient Air Quality Standards

The EPA's CAIR requires reductions of NOx and SO₂ emissions in two phases (2009/2010 and 2015), ultimately capping SO₂ emissions in affected states to 2.5 million tons annually and NOx emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia decided that CAIR violated the CAA but allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court's decision. In July 2011, the EPA finalized CSAPR, to replace CAIR, requiring reductions of NOx and SO₂ emissions in two phases (2012 and 2014), ultimately capping SO₂ emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO₂ emission allowances between power plants located in the same state and interstate trading of NOx and

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SO₂ emission allowances with some restrictions. On December 30, 2011, CSAPR was stayed by the U.S. Court of Appeals for the District of Columbia Circuit and was ultimately vacated by the Court on August 21, 2012. The Court has ordered EPA to continue administration of CAIR until it finalizes a valid replacement for CAIR. On January 24, 2013, EPA and intervenors' petitions seeking rehearing or rehearing en banc were denied by the U.S. Court of Appeals for the District of Columbia Circuit. On June 24, 2013, the Supreme Court of the United States agreed to review the decision vacating CSAPR. Oral argument is scheduled for December 10, 2013. Depending on the outcome of these proceedings and how any final rules are ultimately implemented, MP's future cost of compliance may be substantial and changes to its operations may result.

Hazardous Air Pollutant Emissions

On December 21, 2011, the EPA finalized the MATS imposing emission limits for mercury, PM, and HCL for all existing and new coal-fired electric generating units effective in April 2015 with averaging of emissions from multiple units located at a single plant. Under the CAA, state permitting authorities can grant an additional compliance year through April 2016, as needed, including instances when necessary to maintain reliability where electric generating units are being closed. On December 28, 2012, the WVDEP granted a conditional exemption through April 16, 2016 for MATS compliance at the Fort Martin, Harrison and Pleasants stations. On March 20, 2013, the PA DEP granted an exemption through April 16, 2016 for MATS compliance at the Hatfield's Ferry and Mansfield stations. In addition, an EPA enforcement policy document contemplates up to an additional year to achieve compliance, through April 2017, under certain circumstances for reliability critical units. MATS has been challenged in the U.S. Court of Appeals for the District of Columbia Circuit by various entities, including FirstEnergy's challenge of the PM emission limit imposed on petroleum coke boilers, such as Bay Shore Unit 1. Oral argument is scheduled for December 10, 2013. FirstEnergy and other entities have also petitioned EPA to reconsider and revise various regulatory requirements under MATS. Depending on the outcome of these proceedings and how the MATS are ultimately implemented, MP's future cost of compliance with MATS, including the result of the Generation Resource Transaction, is currently estimated to be approximately $225 million.

On April 25, 2012, PJM concluded its initial analysis of the reliability impacts from the previously announced plant deactivations. As of September 1, 2012, Albright, Rivesville and Willow Island have been deactivated.

Climate Change

There are a number of initiatives to reduce GHG emissions under consideration at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California have implemented programs to control emissions of certain GHGs. In his 2013 State of the Union address, President Obama called for Congressional action on GHG emissions indicating his administration will take action in the event Congress fails to act. In June 2013, the President's Climate Action Plan outlined Executive action to: (1) cut carbon pollution in America, including EPA carbon pollution standards for both new and existing power plants by 17% by 2020 (from 2005 levels), (2) prepare the United States for the impacts of climate change, and (3) lead international efforts to combat global climate change and prepare for its impacts.

In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that required the measurement and reporting of GHG emissions commencing in 2010. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA's finding concludes that concentrations of several key GHGs increase the threat of climate change and may be regulated as “air pollutants” under the CAA. In April 2010, the EPA finalized new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles and clarified that GHG regulation under the CAA would not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest. In May 2010, the EPA finalized new thresholds for GHG emissions that define when NSR pre-construction permits would be required including an emissions applicability threshold of 75,000 tons per year of CO₂ equivalents for existing facilities under the CAA's PSD program. On April 13, 2012, the EPA proposed new source performance standards for GHG emissions from newly constructed fossil fuel generating units that are larger than 25 MW, which were ultimately withdrawn. On June 25, 2013, a Presidential memorandum directed EPA to complete, in a timely fashion, proposed new source performance standards for GHG emissions from newly constructed fossil fuel generating units, starting with re-proposal by September 20, 2013, and propose by June 1, 2014 and complete by June 1, 2015, GHG emission standards for existing fossil fuel generating units. On October 15, 2013, the U.S. Supreme Court agreed to review a June 2012 D.C. Circuit Court of Appeals decision upholding EPA's May 2010 regulations to decide a single narrow question: "Whether EPA permissibly determined that its regulation of greenhouse gas emissions from new motor vehicles triggered permitting requirements under the CAA for stationary sources that emit greenhouse gases?" On September 20, 2013, EPA proposed a new source performance standard of 1,000 lbs. CO2/MWH for large natural gas fired units (> 850 mmBTU/hr), and 1,100 lbs. CO2/MWH for other natural gas fired units (≤ 850 mmBTU/hr), and 1,100 lbs. CO₂/MWH for fossil fuel fired units which would require partial carbon capture and storage. Depending on the outcome of these proceedings and how any final rules are ultimately implemented, future cost of compliance may be substantial and changes to MP's operations may result.

At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of man-made GHG, including CO₂, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement that recognized the scientific view that the increase in global temperature should be below two degrees Celsius; includes a commitment by developed countries to

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provide funds, approaching $30 billion over three years with a goal of increasing to $100 billion by 2020; and establishes the “Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. To the extent that they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia and the United States, would commit to quantified economy-wide emissions targets by 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification. In December 2010, the U.N. Climate Change Conference in Cancun, Mexico resulted in an acknowledgment to reduce emissions from industrialized countries by 25 to 40 percent from 1990 emissions by 2020 and support enhanced action on climate change in the developing world. In December 2011 the U.N. Climate Change Conference in Durban, South Africa, established a negotiating process to develop a new post-2020 climate change protocol, called the “Durban Platform for Enhanced Action”. This negotiating process contemplates developed countries, as well as developing countries such as China, India, Brazil, and South Africa, to undertake legally binding commitments post-2020. In addition, certain countries agreed to extend the Kyoto Protocol for a second commitment period, commencing in 2013 and expiring in 2018 or 2020. In December 2012, the U.N. Climate Change Conference in Doha, Qatar, resulted in countries agreeing to a new commitment period under the Kyoto Protocol beginning in 2020. The new Doha Amendment to establish a second commitment period requires the ratification of three-quarters of the parties to the Kyoto Protocol before it becomes effective.

MP cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO₂ emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO₂ emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO₂ emitting gas-fired and nuclear generators.

Clean Water Act

Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to MP's plants. In addition, the states in which MP operates have water quality standards applicable to MP's operations.

In 2004, the EPA established new performance standards under Section 316(b) of the CWA for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). In 2007, the U.S. Court of Appeals for the Second Circuit invalidated portions of the Section 316(b) performance standards and the EPA has taken the position that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. In April 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit's opinion and decided that Section 316(b) of the CWA authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. On March 28, 2011, the EPA released a new proposed regulation under Section 316(b) of the CWA to reduce fish impingement to a 12% annual average and determine site-specific controls, if any, to reduce entrainment of aquatic life following studies to be provided to permitting authorities. The period for finalizing the Section 316(b) regulation has been extended to January 14, 2014 under a Settlement Agreement between EPA and certain NGOs. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant's water intake channel to divert fish away from the plant's water intake system. Depending on the results of such studies and the EPA's further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

On April 19, 2013, the EPA proposed regulatory changes to the waste water effluent limitations guidelines and standards for the Steam Electric Power Generating category (40 CFR Part 423). The EPA proposed eight treatment options for waste water discharges from electric power plants, of which four are "preferred" by the Agency. The preferred options range from more stringent chemical and biological treatment requirements to zero discharge requirements. The EPA is required to finalize this rulemaking by May 22, 2014, under a consent decree entered by a U.S. District Court and the treatment obligations are proposed to phase-in as waste water discharge permits are renewed on a 5-year cycle from 2017 to 2022. Depending on the content of the EPA's final rule, the future costs of compliance with these standards may require material capital expenditures.

In October 2009, the WVDEP issued an NPDES water discharge permit for the Fort Martin Plant, which imposes TDS, sulfate concentrations and other effluent limitations for heavy metals, as well as temperature limitations. Concurrent with the issuance of the Fort Martin NPDES permit, WVDEP also issued an administrative order setting deadlines for MP to meet certain of the effluent limits that were effective immediately under the terms of the NPDES permit. MP appealed, and a stay of certain conditions of the NPDES permit and order have been granted pending a final decision on the appeal and subject to WVDEP moving to dissolve the stay. The Fort Martin NPDES permit could require an initial capital investment in excess of $150 million in order to install technology to meet the TDS and sulfate limits, which technology may also meet certain of the other effluent limits. Additional technology may be needed to meet certain other limits in the Fort Martin NPDES permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals or estimate the possible loss or range of loss.

In December 2010, PA DEP submitted its CWA 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately 68 mile stretch of the Monongahela River north of the West Virginia border. In May 2011, the EPA agreed with PA

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DEP's recommended sulfate impairment designation which requires the development of a TMDL limit for the river, a process that will take PA DEP approximately five years. However, the Hatfield's Ferry and Mitchell Plants in Pennsylvania that discharge into the Monongahela River were deactivated on October 9, 2013.

MP intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the possible loss or range of loss.

OTHER LEGAL PROCEEDINGS

ICG Litigation

On December 28, 2006, AE Supply and MP filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against ICG, Anker WV, and Anker Coal. Anker WV entered into a long term Coal Sales Agreement with AE Supply and MP for the supply of coal to the Harrison generating facility. Prior to the time of trial, ICG was dismissed as a defendant by the Court, which issue can be the subject of a future appeal. As a result of defendants' past and continued failure to supply the contracted coal, AE Supply and MP have incurred and will continue to incur significant additional costs for purchasing replacement coal. A non-jury trial was held from January 10, 2011 through February 1, 2011. At trial, AE Supply and MP presented evidence that they have incurred in excess of $80 million in damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of $150 million for future shortfalls. Defendants primarily claim that their performance is excused under a force majeure clause in the coal sales agreement and presented evidence at trial that they will continue to not provide the contracted yearly tonnage amounts. On May 2, 2011, the court entered a verdict in favor of AE Supply and MP for $104 million ($90 million in future damages and $14 million for replacement coal / interest). On August 25, 2011, the Allegheny County Court denied all Motions for Post-Trial relief and the May 2, 2011 verdict became final. On August 26, 2011, the defendants posted bond and filed a Notice of Appeal with the Superior Court. On August 13, 2012, the Superior Court affirmed the $14 million past damages award but vacated the $90 million future damages award. While the Superior Court found that the defendants still owed future damages, it remanded the calculation of those damages back to the trial court. The specific amount of those future damages is not known at this time, but they are expected to be calculated at a market price of coal that is significantly lower than the price used by the trial court. On August 27, 2012, AE Supply and MP filed an Application for Reargument En Banc with the Superior Court, which was denied on October 19, 2012. AE Supply and MP filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court on November 19, 2012. On July 2, 2013, the Petition for Allowance of Appeal was denied and in the second quarter of 2013 the now final past damage award of $15.5 million (MP - $3.2 million), including interest, was recognized. The case was sent back to the trial court to recalculate the future damages only and is currently in the discovery phase.

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to MP's normal business operations pending against MP and its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 5, Regulatory Matters of the Notes to Consolidated Financial Statements.

MP accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where MP determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that MP or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on MP's or its subsidiaries' financial condition, results of operations and cash flows.

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