FIRSTENERGY CORP - FORM 8-K - EX-99.1 - EXHIBIT 99.1

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8-K - 8-K - FIRSTENERGY CORP	a8-kdated05092017.htm

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

UNAUDITED INTERIM CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2017 and 2016

GLOSSARY OF TERMS

The following abbreviations and acronyms are used in this report to identify Monongahela Power Company and its affiliated companies:



AE Supply	Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary
AGC	Allegheny Generating Company, a generation subsidiary of AE Supply and equity method investee of MP.
ATSI	American Transmission Systems, Incorporated, formerly a direct subsidiary of FE that became a subsidiary of FirstEnergy Transmission, LLC in April 2012, which owns and operates transmission facilities.
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
FE	FirstEnergy Corp., a public utility holding company
FES	FirstEnergy Solutions Corp., which provides energy-related products and services
FESC	FirstEnergy Service Company, which provides legal, financial and other corporate support services
FirstEnergy	FirstEnergy Corp., together with its consolidated subsidiaries
JCP&L	Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
ME	Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
MP	Monongahela Power Company, a West Virginia electric utility operating subsidiary
OE	Ohio Edison Company, an Ohio electric utility operating subsidiary
PE	The Potomac Edison Company, a Maryland and West Virginia electric utility operating subsidiary
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
PN	Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
Utilities	OE, CEI, TE, Penn, JCP&L, ME, PN, MP, PE and WP
WP	West Penn Power Company, a Pennsylvania electric utility operating subsidiary

The following abbreviations and acronyms are used to identify frequently used terms in this report.
AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income
ARO	Asset Retirement Obligation
ARR	Auction Revenue Right
ASU	Accounting Standards Update
CAA	Clean Air Act
CCR	Coal Combustion Residuals
CFR	Code of Federal Regulations
CO₂	Carbon Dioxide
CPP	Clean Power Plan
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
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FPA	Federal Power Act
FTR	Financial Transmission Right
GAAP	Accounting Principles Generally Accepted in the United States of America
GHG	Greenhouse Gases
HCl	Hydrochloric Acid

GLOSSARY OF TERMS, Continued

IRS	Internal Revenue Service
ISO	Independent System Operator
kV	Kilovolt
KWH	Kilowatt-hour
LOC	Letter of Credit
MATS	Mercury and Air Toxics Standards
MISO	Midcontinent Independent System Operator, Inc.
mmBTU	One Million British Thermal Units
MW	Megawatt
MWH	Megawatt-hour
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NOx	Nitrogen Oxide
NPDES	National Pollutant Discharge Elimination System
OPEB	Other Post-Employment Benefits
PJM	PJM Interconnection, L.L.C.
PJM Tariff	PJM Open Access Transmission Tariff
PM	Particulate Matter
PPB	Parts Per Billion
PSD	Prevention of Significant Deterioration
RFC	ReliabilityFirst Corporation
RGGI	Regional Greenhouse Gas Initiative
ROE	Return on Equity
RPM	Reliability Pricing Model
RTEP	Regional Transmission Expansion Plan
RTO	Regional Transmission Organization
Seventh Circuit	United States Court of Appeals for the Seventh Circuit
SIP	State Implementation Plan(s) Under the Clean Air Act
SO₂	Sulfur Dioxide
TDS	Total Dissolved Solid
TO	Transmission Owner
U.S. Court of Appeals for the D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
U.S. Supreme Court	United States Supreme Court
VIE	Variable Interest Entity
WVDEP	West Virginia Department of Environmental Protection
WVPSC	Public Service Commission of West Virginia

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)



	For the Three Months Ended March 31
(In millions)	2017			2016
STATEMENTS OF INCOME

REVENUES:
Electric sales	$	418		$	423
Excise tax collections	2			2
Total revenues	420			425

OPERATING EXPENSES:
Fuel	141			139
Purchased power from non-affiliates	77			69
Purchased power from affiliates	6			6
Other operating expenses	79			86
Provision for depreciation	32			31
Amortization of regulatory liabilities, net	12			13
General taxes	12			8
Total operating expenses	359			352

OPERATING INCOME	61			73

OTHER INCOME (EXPENSE):
Miscellaneous income	2			2
Interest expense	(19		)	(20		)
Total other expense	(17		)	(18		)

INCOME BEFORE INCOME TAXES	44			55

INCOME TAXES	17			21

NET INCOME	$	27		$	34

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	27		$	34

OTHER COMPREHENSIVE LOSS:
Pension and OPEB prior service costs	(1		)	—
Other comprehensive loss	(1		)	—
Income tax benefits on other comprehensive loss	—			—
Other comprehensive loss, net of tax	(1		)	—

COMPREHENSIVE INCOME	$	26		$	34

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

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions, except share amounts)	March 31, 2017		December 31, 2016
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1	$	1
Receivables-
Customers, net of allowance for uncollectible accounts of $4 in 2017 and 2016	127		134
Affiliated companies	71		54
Other, net of allowance for uncollectible accounts	8		5
Materials and supplies, at average cost	88		107
Restricted funds	12		19
Other current assets	30		28
	337		348
UTILITY PLANT:
In service	3,962		3,949
Less — Accumulated provision for depreciation	431		422
	3,531		3,527
Construction work in progress	80		75
	3,611		3,602
INVESTMENTS:
Investment in AGC	68		66
Other	1		1
	69		67
DEFERRED CHARGES AND OTHER ASSETS:
Intangible assets	110		113
Other	16		23
	126		136
	$	4,143	$	4,153

LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	19	$	169
Short-term borrowings - affiliated companies	297		195
Accounts payable-
Affiliated companies	37		41
Other	71		59
Accrued taxes	30		26
Accrued interest	20		15
Other current liabilities	32		33
	506		538
CAPITALIZATION:
Common stockholder's equity-
Common stock, $50 par value, 7,000,000 shares authorized and 5,891,000 shares outstanding	295		295
Other paid-in capital	823		822
Accumulated other comprehensive income	5		6
Retained earnings	61		59
Total common stockholder's equity	1,184		1,182
Long-term debt and other long-term obligations	1,343		1,351
	2,527		2,533
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	705		693
Regulatory liabilities	112		86
Retirement benefits	75		75
Asset retirement obligations	39		38
Purchased power liability	95		96
Other	84		94
	1,110		1,082
COMMITMENTS AND CONTINGENCIES (NOTE 9)
	$	4,143	$	4,153

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

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	For the Three Months Ended March 31
(In millions)	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	27		$	34
Adjustments to reconcile net income to net cash from operating activities-
Depreciation and amortization of regulatory liabilities, net	44			44
Deferred purchased power and other costs, net	22			3
Deferred income taxes and investment tax credits, net	13			19
Changes in current assets and liabilities -
Receivables	(13		)	22
Materials and supplies	19			(4		)
Other current assets	(5		)	(5		)
Accounts payable	8			(2		)
Accrued interest	5			6
Accrued taxes	4			(2		)
Other	(6		)	(4		)
Net cash provided from operating activities	118			111

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	102			—
Redemptions and repayments-
Short-term borrowings, net	—			(69		)
Long-term debt	(157		)	(7		)
Common stock dividend payments	(25		)	—
Other	(1		)	(1		)
Net cash used for financing activities	(81		)	(77		)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(39		)	(40		)
Change in restricted funds	7			9
Asset removal costs	(5		)	(3		)
Net cash used for investing activities	(37		)	(34		)

Net change in cash and cash equivalents	—			—
Cash and cash equivalents at beginning of period	1			1
Cash and cash equivalents at end of period	$	1		$	1

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

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)



Note Number		Page Number
1	Organization and Basis of Presentation	5
2	Pension and other Postemployment Benefits	6
3	Accumulated Other Comprehensive Income	7
4	Taxes	7
5	Fair Value Measurements	8
6	Derivative Instruments	9
7	Variable Interest Entities	9
8	Regulatory Matters	10
9	Commitments and Contingencies	11

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. ORGANIZATION AND BASIS OF PRESENTATION

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

MP's investment in unconsolidated affiliate consists 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 and its connecting transmission facilities in Bath County, Virginia. This station is operated by the 60% owner, Virginia Electric and Power Company, a non-affiliated utility. AGC provides the generation capacity from this station to AE Supply and MP.

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, 2016.

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 May 9, 2017, the issuance date of the financial statements.

New Accounting Pronouncements

In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers". Subsequent accounting standards updates have been issued which amend and/or clarify the application of ASU 2014-09. The core principle of the new guidance is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. More detailed disclosures will also be required to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. For public business entities, the new revenue recognition guidance will be effective for annual and interim reporting periods beginning after December 15, 2017. Earlier adoption is permitted for annual and interim reporting periods beginning after December 15, 2016. MP will not early adopt the standards. The standards shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. MP has evaluated its revenues and expects limited impacts to current revenue recognition practices, dependent on the resolution of industry issues. MP continues to assess the impact on its financial statements and disclosures as well as which transition method it will select to adopt the guidance.

In January 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities", which primarily affects the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, the FASB clarified guidance related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities. The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption for certain provisions can be elected for all financial statements of fiscal years and interim periods that have not yet been issued or that have not yet been made available for issuance. MP is currently evaluating the impact on its financial statements of adopting this standard.

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)", which will require organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets. In addition, new qualitative and quantitative disclosures of the amounts, timing, and uncertainty of cash flows arising from leases will be required. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. Lessors and lessees will be required to apply a modified retrospective transition approach, which requires adjusting the accounting for any leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require any accounting adjustment. MP is currently evaluating the impact on its financial statements of adopting this standard.

In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments”, which removes all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that the company expects to collect over the instrument’s contractual life. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted for fiscal years beginning after December 15, 2018. MP is currently evaluating the impact on its financial statements of adopting this standard.

In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments". The standard is intended to eliminate diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows, including the presentation of debt prepayment or debt extinguishment costs,

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

all of which will be classified as financing activities. The guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. MP early adopted this ASU as of January 1, 2017. There was no impact to prior periods.

In November 2016, the FASB issued ASU 2016-18, "Restricted Cash" that will require entities to show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows. As a result, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. When cash, cash equivalents, restricted cash and restricted cash equivalents are presented in more than one line item on the balance sheet, the new guidance requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. The guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2019. Early adoption in an interim period is permitted, but any adjustments must be reflected as of the beginning of the fiscal year that includes that interim period. MP does not expect this ASU to have a material effect on its financial statements.

On March 10, 2017, the FASB issued ASU 2017-07, "Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost", which amends the requirements related to the presentation of the components of net periodic benefit cost for an entity’s sponsored defined benefit pension and other postretirement plans. ASU 2017-07 requires entities to (1) disaggregate the current-service-cost component from the other components of net benefit cost (the “other components”) and present it with other current compensation costs for related employees in the income statement and (2) present the other components elsewhere in the income statement and outside of income from operations if such a subtotal is presented. In addition, only service costs are eligible for capitalization. The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. MP is currently evaluating the impact on its financial statements of adopting this standard.

Additionally, during 2017, the FASB issued the following ASUs:


•	ASU 2017-04, "Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment,”


•	ASU 2017-05, "Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets" and


•	ASU 2017-08, "Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities."

MP does not expect these ASUs to have a material effect on its financial statements.

2. PENSION AND OTHER POSTEMPLOYMENT BENEFITS

MP's net periodic pension costs and OPEB credits (before adjusting for amounts to be capitalized) were as follows:



	For the Three Months Ended March 31
(In millions)	2017			2016
Pensions	$	—		$	1
OPEB	$	(1	)	$	(1	)

The net periodic pension costs and OPEB credits (net of amounts capitalized) recognized in earnings by MP was less than $1 million for the three month periods ended March 31, 2017 and 2016.

As of March 31, 2017 and December 31, 2016, MP had $56 million of affiliated non-current liabilities related to allocated pension and OPEB mark-to-market costs.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

3. ACCUMULATED OTHER COMPREHENSIVE INCOME

The changes in AOCI, net of tax, for the three months ended March 31, 2017 for MP are shown in the following tables:



	Defined Benefit Pension & OPEB Plans*
	(In millions)
AOCI Balance, January 1, 2017	$	6

Amounts reclassified from AOCI	(1		)
Income tax benefits on other comprehensive loss	—
Net other comprehensive loss	(1		)

AOCI Balance, March 31, 2017	$	5

* There were no amounts reclassified from AOCI in the first quarter of 2016.

The following amounts were reclassified from AOCI in the three months ended March 31, 2017 for MP:



	For The Three Months Ended March 31, 2017			Affected Line Item in the Statement of Net Income
Reclassifications out of AOCI⁽²⁾	For The Three Months Ended March 31, 2017			Affected Line Item in the Statement of Net Income
	(In millions)
Defined Benefit Pension and OPEB Plans
Prior-service costs	$	(1	)	⁽¹⁾
	—			Income taxes
	$	(1	)	Net of tax

⁽¹⁾These AOCI components are included in the computation of net periodic pension cost. See Note 2, Pension and Other Postemployment Benefits for additional details.
⁽²⁾ Amounts in parenthesis represent credits to the Consolidated Statements of Income from AOCI. There were no amounts reclassified from AOCI in the first quarter of 2016.

4. TAXES

MP's interim effective tax rates reflect the estimated annual effective tax rates for 2017 and 2016. These tax rates are affected by estimated annual permanent items, as well as discrete items that may occur in any given period, but are not consistent from period to period.

MP's effective tax rate for the three months ended March 31, 2017 and 2016 was 38.6% and 38.2%, respectively.

For federal income tax purposes, MP files as a member of the FE consolidated group. In February 2017, the IRS completed its examination of FE’s 2015 federal income tax return and issued a Full Acceptance Letter with no changes or adjustments to MP’s taxable income or effective tax rate.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

5. 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 been reviewed and approved by FirstEnergy's Risk Policy Committee (see Note 6, Derivative Instruments), are used to measure fair value. A more detailed description of MP's valuation process for FTRs 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 MP in the annual, monthly and long-term PJM 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 PJM 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 March 31, 2017, from those used as of December 31, 2016. 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.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the three months ended March 31, 2017. The following table provides 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 March 31, 2017 and December 31, 2016. MP has no level 1 or level 2 assets or liabilities that are measured at fair value on the balance sheet.



(In millions)	Net Derivative Asset FTRs
January 1, 2016 Balance	$	1
Total unrealized losses included in net regulatory liabilities	(3		)
Purchases	4
December 31, 2016 Balance	2
Total unrealized losses included in net regulatory liabilities	(1		)
Settlements	(3		)
March 31, 2017 Balance	$	(2	)

LONG-TERM DEBT

The following table provides the approximate fair value and related carrying amounts of long-term debt, which excludes capital lease obligations and net unamortized debt issuance costs, premiums and discounts:



	March 31, 2017				December 31, 2016
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	1,370	$	1,545	$	1,529	$	1,692

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 March 31, 2017 and December 31, 2016.

6. 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 PJM, 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 March 31, 2017 or December 31, 2016.

MP had FTR liabilities of $2 million in other current liabilities on its Consolidated Balance Sheet as of March 31, 2017. As of December 31, 2016, MP had FTR assets of $3 million in other current assets and FTR liabilities of $1 million in other current liabilities. The potential effect of offsetting the derivative assets and liabilities related to FTRs is immaterial as of March 31, 2017 and December 31, 2016. MP will purchase 2 million MWHs based on outstanding FTR contracts in future periods.

The counterparty to these contracts does not require collateral to mitigate credit exposure. The unrealized losses on MP's FTRs for the three months ended March 31, 2017 and March 31, 2016 were $1 million, respectively, which are subject to regulatory accounting and do not impact earnings.

7. VARIABLE INTEREST ENTITY

MP performs qualitative analyses based on control and economics to determine whether a variable interest classifies MP as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. MP consolidates a VIE when it is determined that it is the primary beneficiary.

VIEs in which MP is the primary beneficiary consist of the following (included in MP’s consolidated financial statements):

•

MP Environmental Funding Company - The consolidated financial statements of MP include environmental control bonds issued by a bankruptcy remote, special purpose limited liability company that is an indirect subsidiary of MP. Proceeds from the bonds were used to construct environmental control facilities. The special purpose limited liability company owns the irrevocable right to collect non-bypassable environmental control charges from all customers who receive electric delivery service in MP's West Virginia service territories. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. Creditors of MP, other than the special purpose limited liability company, have no recourse to any assets or revenues of the special purpose limited liability company. As of March 31, 2017 and December 31, 2016, $286 million and $293 million of environmental control bonds were outstanding, respectively.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. REGULATORY MATTERS

STATE REGULATION

MP's retail rates, conditions of service, issuance of securities and other matters are subject to regulation in West Virginia by the WVPSC.

WEST VIRGINIA

MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP's and PE's ENEC rate is updated annually.

On September 23, 2016, the WVPSC approved the Phase II energy efficiency program for MP and PE as reflected in a unanimous settlement by the parties to the proceeding, which includes three energy efficiency programs to meet the Phase II requirement of energy efficiency reductions of 0.5% of 2013 distribution sales for the January 1, 2017 through May 31, 2018 period, which was approved by the WVPSC in the 2012 proceeding approving the transfer of ownership of Harrison Power Station to MP. The costs for the Phase II program are expected to be $10.4 million and are eligible for recovery through the existing energy efficiency rider which is reviewed in the fuel (ENEC) case each year.

On December 9, 2016, the WVPSC approved the annual ENEC case for MP and PE as reflected in a unanimous settlement by the parties to the proceeding, resulting in an increase in the ENEC rate of $25 million annually beginning January 1, 2017. In addition, ENEC rates will be maintained at the same level for a two year period.

On December 30, 2015, MP and PE filed an IRP with the WVPSC identifying a capacity shortfall starting in 2016 and exceeding 700 MWs by 2020 and 850 MWs by 2027. On June 3, 2016, the WVPSC accepted the IRP. On December 16, 2016, MP issued an RFP to address its generation shortfall, along with issuing a second RFP to sell its interest in Bath County. Bids were received by an independent evaluator in February 2017 for both RFPs. AE Supply was the winning bidder of the RFP to address MP’s generation shortfall and on March 6, 2017, MP and AE Supply signed an asset purchase agreement for MP to acquire AE Supply’s Pleasants Power Station (1,300 MW) for approximately $195 million, subject to customary and other closing conditions, including regulatory approvals. In addition, on March 7, 2017, MP and PE filed applications with the WVPSC and MP and AE Supply filed with FERC requesting authorization for such purchase. The WVPSC has scheduled a hearing on this matter and an order is anticipated in the fourth quarter of 2017. With respect to the Bath County RFP, MP does not plan to move forward with the sale of its ownership interest. In the future, MP may re-evaluate its options with respect to its interest in Bath County.

FEDERAL REGULATION

With respect to its wholesale services and rates, MP is subject to regulation by FERC. Under the FPA, FERC regulates rates for interstate wholesale sales, transmission of electric power, accounting and other matters. FERC regulations require MP to provide open access transmission service at FERC-approved rates, terms and conditions. MP's transmission facilities are subject to functional control by PJM, and transmission service using MP's transmission facilities is provided by PJM under the PJM Tariff. See FERC Matters below.

FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. MP has been authorized by FERC to sell wholesale power in interstate commerce and has a market-based rate tariff on file with FERC; although major wholesale purchases remain subject to regulation by the WVPSC. As a condition to selling electricity on a wholesale basis at market-based rates, MP, like other entities granted market-based rate authority, must file electronic quarterly reports with FERC listing its sales transactions for the prior quarter.

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 FirstEnergy's facilities, including those of MP, are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies, including MP, in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC.

FirstEnergy 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, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including

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in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy's part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, and obligations to upgrade or build transmission facilities, that could have a material adverse effect on MP's financial condition, results of operations and cash flows.

FERC MATTERS

PJM Transmission Rates

PJM and its stakeholders have been debating the proper method to allocate costs for certain transmission facilities. While FirstEnergy and other parties advocate for a traditional "beneficiary pays" (or usage based) approach, others advocate for “socializing” the costs on a load-ratio share basis, where each customer in the zone would pay based on its total usage of energy within PJM. This question has been the subject of extensive litigation before FERC and the appellate courts, including before the Seventh Circuit. On June 25, 2014, a divided three-judge panel of the Seventh Circuit ruled that FERC had not quantified the benefits that western PJM utilities would derive from certain new 500 kV or higher lines and thus had not adequately supported its decision to socialize the costs of these lines. The majority found that eastern PJM utilities are the primary beneficiaries of the lines, while western PJM utilities are only incidental beneficiaries, and that, while incidental beneficiaries should pay some share of the costs of the lines, that share should be proportionate to the benefit they derive from the lines, and not on load-ratio share in PJM as a whole. The court remanded the case to FERC, which issued an order setting the issue of cost allocation for hearing and settlement proceedings. On June 15, 2016, various parties, including ATSI and the Utilities, filed a settlement agreement at FERC agreeing to apply a combined usage based/socialization approach to cost allocation for charges to transmission customers in the PJM region for transmission projects operating at or above 500 kV. Certain other parties in the proceeding did not agree to the settlement and filed protests to the settlement seeking, among other issues, to strike certain of the evidence advanced by FirstEnergy and certain of the other settling parties in support of the settlement, as well as provided further comments in opposition to the settlement. FirstEnergy and certain of the other parties responded to such opposition. The settlement is pending before FERC.

The outcome of these proceedings and their impact, if any, on MP cannot be predicted at this time.

MP Generation Acquisition

On March 7, 2017, MP and AE Supply filed an application with FERC requesting authorization for MP to purchase AE Supply’s Pleasants power station (1,300 MW) for approximately $195 million. The transaction is the result of MP’s selection of AE Supply’s bid of the Pleasants power station pursuant to a RFP to address MP’s generation shortfall identified in an IRP filed with the WVPSC in December 2015. MP and AE Supply may submit additional filings to implement the transaction including, for example, the transfer of the interconnection service agreement and reactive service revenue requirement that are associated with the Pleasants power station. The parties expect to close the transaction in the third quarter of 2017. See “Regulatory Matters - West Virginia” above.

Market-Based Rate Authority, Triennial Update

MP holds authority from FERC to sell electricity at market-based rates. One condition for retaining this authority is that every three years MP must file an update with FERC that demonstrates that it continues to meet FERC’s requirements for holding market-based rate authority. On December 23, 2016, FESC, on behalf of its affiliates with market-based rate authority, including MP, submitted to FERC the most recent triennial market power analysis filing for MP for the current cycle of this filing requirement. The filing remains pending before FERC.

9. 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

MP complies with SO₂ and NOx emission 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.

CSAPR requires reductions of NOx and SO2 emissions in two phases (2015 and 2017), 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

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emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. The U.S. Court of Appeals for the D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO2 emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This follows the 2014 U.S. Supreme Court ruling generally upholding EPA’s regulatory approach under CSAPR, but questioning whether EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. EPA issued a CSAPR update rule on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR update rule to the D.C. Circuit in November and December 2016. Depending on the outcome of the appeals and on how the EPA and the states implement CSAPR, the future cost of compliance may be material and changes to FirstEnergy's and FES' operations may result.

The EPA tightened the primary and secondary NAAQS for ozone from the 2008 standard levels of 75 PPB to 70 PPB on October 1, 2015. The EPA stated the vast majority of U.S. counties will meet the new 70 PPB standard by 2025 due to other federal and state rules and programs but the EPA will designate those counties that fail to attain the new 2015 ozone NAAQS by October 1, 2017. States will then have roughly three years to develop implementation plans to attain the new 2015 ozone NAAQS. Depending on how the EPA and the states implement the new 2015 ozone NAAQS, the future cost of compliance may be material and changes to FirstEnergy’s and FES’ operations may result. In August 2016, the State of Delaware filed a CAA Section 126 petition with the EPA alleging that the Harrison generating facility's NOx emissions significantly contribute to Delaware's inability to attain the ozone NAAQS. The petition seeks a short term NOx emission rate limit of 0.125 lb/mmBTU over an averaging period of no more than 24 hours. On September 27, 2016, the EPA extended the time frame for acting on the State of Delaware's CAA Section 126 petition by six months to April 7, 2017. In November 2016, the State of Maryland filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 36 EGUs, including Harrison Units 1, 2 and 3, Mansfield Unit 1 and Pleasants Units 1 and 2, significantly contribute to Maryland's inability to attain the ozone NAAQS. The petition seeks NOx emission rate limits for the 36 EGUs by May 1, 2017. On January 3, 2017, the EPA extended the time frame for acting on the CAA Section 126 petition by six months to July 15, 2017. MP is unable to predict the outcome of these matters or estimate the loss or range of loss.

MATS imposed emission limits for mercury, PM, and HCl for all existing and new fossil fuel fired electric generating units effective in April 2015 with averaging of emissions from multiple units located at a single plant. The majority of MP's MATS compliance program and related costs have been completed.

Climate Change

FirstEnergy has established a goal to reduce CO2 emissions by 90% below 2005 levels by 2045. There are a number of initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.

The EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act” in December 2009, concluding that concentrations of several key GHGs constitutes an "endangerment" and may be regulated as "air pollutants" under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. On June 23, 2014, the United States Supreme Court decided that CO2 or other GHG emissions alone cannot trigger permitting requirements under the CAA, but that air emission sources that need PSD permits due to other regulated air pollutants can be required by the EPA to install GHG control technologies. The EPA released its final regulations in August 2015 (which have been stayed by the U.S. Supreme Court), to reduce CO2 emissions from existing fossil fuel fired electric generating units that would require each state to develop SIPs by September 6, 2016, to meet the EPA’s state specific CO2 emission rate goals. The EPA’s CPP allows states to request a two-year extension to finalize SIPs by September 6, 2018. If states fail to develop SIPs, the EPA also proposed a federal implementation plan that can be implemented by the EPA that included model emissions trading rules which states can also adopt in their SIPs. The EPA also finalized separate regulations imposing CO2 emission limits for new, modified, and reconstructed fossil fuel fired electric generating units. Numerous states and private parties filed appeals and motions to stay the CPP with the U.S. Court of Appeals for the D.C. Circuit in October 2015. On January 21, 2016, a panel of the D.C. Circuit denied the motions for stay and set an expedited schedule for briefing and argument. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court. On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. Depending on the outcomes of the review pursuant to the executive order, of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material.

At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020. The Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide GHG emissions by 26 to 28 percent below 2005 levels by 2025 and joined in adopting the agreement reached on December 12, 2015 at the United Nations Framework Convention on Climate Change meetings in Paris. The Paris Agreement was ratified by the requisite number of countries (i.e. at least 55 countries representing at least 55% of global GHG emissions) in October 2016 and its non-binding

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obligations to limit global warming to well below two degrees Celsius are effective on November 4, 2016. It remains unclear whether and how the results of the 2016 United States election could impact the regulation of GHG emissions at the federal and state level. FirstEnergy 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 material 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.

The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore plant's cooling water intake channel to divert fish away from the plant's cooling water intake system. Depending on the results of such studies and any final action taken by the states based on those studies, the future capital costs of compliance with these standards may be material.

On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations will phase-in as permits are renewed on a five-year cycle from 2018 to 2023. The final rule also allows plants to commit to more stringent effluent limits for wet scrubber systems based on evaporative technology and in return have until the end of 2023 to meet the more stringent limits. On April 13, 2017, EPA granted a Petition for Reconsideration of the ELG Rule and administratively stayed (effective upon publication in the Federal Register) all deadlines in the Rule pending a new rulemaking. Depending on the outcome of appeals and how any final rules are ultimately implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy's and FES' operations may result.

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 ranging from $150 million to $300 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 the appeal or estimate the possible loss or range of loss.

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

Regulation of Waste Disposal

Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain coal combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation.

In December 2014, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards regarding landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. Based on an assessment of the finalized regulations, the future cost of compliance and expected timing of spend had no significant impact on MP's existing AROs associated with CCRs. Although not currently expected, any changes in timing and closure plan requirements in the future could materially and adversely impact MP's AROs.

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OTHER LEGAL PROCEEDINGS

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 loss or range of loss in these matters is not expected to be material to MP or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 8, 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 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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