UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarter ended June 30, 2010

Commission File Number 1-267

ALLEGHENY ENERGY, INC.

(Name of Registrant)

Maryland	13-5531602
(State of Incorporation)	(IRS Employer Identification Number)
800 Cabin Hill Drive, Greensburg, Pennsylvania	15601
(Address of Principal Executive Offices)	(Zip Code)

(724) 837-3000

(Telephone Number)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  þ	Accelerated filer	¨
Non-accelerated filer  ¨	Smaller reporting company	¨
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  þ

As of July 31, 2010, 169,615,021 shares of the common stock, par value of $1.25 per share, of the registrant were outstanding.

TABLE OF CONTENTS

		Page No.
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements (unaudited)	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”)	50
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	89
Item 4.	Controls and Procedures	90
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	91
Item 1A.	Risk Factors	91
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	91
Item 3.	Defaults Upon Senior Securities	91
Item 4.	Reserved	91
Item 5.	Other Information	91
Item 6.	Exhibits	92
	Signature	93

2

GLOSSARY

I. The following abbreviations and names are used in this report to identify Allegheny Energy, Inc. and its subsidiaries:

AE	Allegheny Energy, Inc., a diversified utility holding company
AESC	Allegheny Energy Service Corporation, a subsidiary of AE
AE Supply	Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary of AE
AGC	Allegheny Generating Company, a generation subsidiary of AE Supply and Monongahela
Allegheny	Allegheny Energy, Inc., together with its consolidated subsidiaries
Distribution Companies	Monongahela, Potomac Edison and West Penn, which collectively do business as Allegheny Power
Monongahela	Monongahela Power Company, a regulated subsidiary of AE
PATH, LLC	Potomac-Appalachian Transmission Highline, LLC, a joint venture between Allegheny and a subsidiary of American Electric Power Company, Inc.
PATH Allegheny	PATH Allegheny Transmission Company, LLC
PATH Allegheny MD	PATH Allegheny Maryland Transmission Company, LLC
PATH Allegheny VA	PATH Allegheny Virginia Transmission Corporation
PATH WV	PATH West Virginia Transmission Company, LLC
Potomac Edison	The Potomac Edison Company, a regulated subsidiary of AE
TrAIL Company	Trans-Allegheny Interstate Line Company
West Penn	West Penn Power Company, a regulated subsidiary of AE

II. The following abbreviations and acronyms are used in this report to identify entities and terms relevant to Allegheny’s business and operations:

CDD	Cooling Degree-Days
Clean Air Act	Clean Air Act of 1970
CO2	Carbon dioxide
EPA	United States Environmental Protection Agency
Exchange Act	Securities Exchange Act of 1934, as amended
ENEC	Expanded Net Energy Clause in West Virginia
FERC	Federal Energy Regulatory Commission
FirstEnergy	FirstEnergy Corp.
FPA	Federal Power Act
FTRs	Financial Transmission Rights
GAAP	Generally accepted accounting principles used in the United States of America
HDD	Heating Degree-Days
kW	Kilowatt, which is equal to 1,000 watts
kWh	Kilowatt-hour, a unit of electric energy equivalent to one kW operating for one hour
Maryland PSC	Maryland Public Service Commission
MW	Megawatt, which is equal to 1,000,000 watts
MWh	Megawatt-hour, a unit of electric energy equivalent to one MW operating for one hour
NERC	North American Electric Reliability Corporation
NOX	Nitrogen Oxide
NSR	The New Source Performance Review Standards, or “New Source Review,” applicable to facilities deemed “new” sources of emissions by the EPA
PATH	Potomac-Appalachian Transmission Highline
Pennsylvania PUC	Pennsylvania Public Utility Commission
PJM	PJM Interconnection, L.L.C., a regional transmission organization
PLR	Provider-of-last-resort
PURPA	Public Utility Regulatory Policies Act of 1978
RPM	Reliability Pricing Model, which is PJM’s capacity market
RTEP	Regional Transmission Expansion Plan
RTO	Regional Transmission Organization
Scrubbers	Flue-gas desulfurization equipment
SEC	Securities and Exchange Commission
SO2	Sulfur dioxide
SOS	Standard Offer Service
T&D	Transmission and distribution
TrAIL	Trans-Allegheny Interstate Line
Virginia SCC	Virginia State Corporation Commission
West Virginia PSC	Public Service Commission of West Virginia

3

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions, except per share amounts)	2010			2009			2010			2009
Operating revenues	$	945.7		$	814.7		$	1,994.5		$	1,771.9
Operating expenses:
Fuel		295.7			216.8			613.7			475.7
Purchased power and transmission		126.3			112.2			275.2			246.1
Deferred energy costs, net		2.3			(7.6	)		10.4			(24.6	)
Gain on sale of Virginia distribution business		(45.1	)		0			(45.1	)		0
Operations and maintenance		158.6			200.5			377.1			367.8
Depreciation and amortization		80.6			67.2			160.4			135.7
Taxes other than income taxes		56.6			46.5			113.7			102.3
Total operating expenses		675.0			635.6			1,505.4			1,303.0
Operating income		270.7			179.1			489.1			468.9
Other income (expense), net		2.9			1.8			5.3			4.2
Interest expense		79.6			59.1			156.4			116.3
Income before income taxes		194.0			121.8			338.0			356.8
Income tax expense		73.8			48.9			129.6			149.8
Net income		120.2			72.9			208.4			207.0
Net income attributable to noncontrolling interest		0			(0.3	)		0			(0.5	)
Net income attributable to Allegheny Energy, Inc.	$	120.2		$	72.6		$	208.4		$	206.5
Earnings per common share attributable to Allegheny Energy, Inc.:
Basic	$	0.71		$	0.43		$	1.23		$	1.22
Diluted	$	0.71		$	0.43		$	1.23		$	1.22
Average common shares outstanding:
Basic		169.7			169.5			169.7			169.5
Diluted		170.1			169.9			170.1			169.9
Dividends per common share	$	0.15		$	0.15		$	0.30		$	0.30

See accompanying Notes to Consolidated Financial Statements.

4

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

	Six Months Ended June 30,
(In millions)	2010			2009
Cash Flows From Operating Activities:
Net income	$	208.4		$	207.0
Adjustments for non-cash items included in income:
Depreciation and amortization		160.4			135.7
Amortization of debt related costs		13.0			5.6
Amortization of liability for adverse power purchase commitment		(9.0	)		(8.7	)
Gain on sale of Virginia distribution business		(45.1	)		0
Provision for uncollectible accounts		5.5			7.2
Deferred income taxes and investment tax credit, net		111.2			135.8
Deferred energy costs, net		10.4			(24.6	)
Stock-based compensation expense		8.9			8.6
Unrealized losses (gains) on derivative contracts, net		11.2			(35.6	)
Pension and other postretirement employee benefit plan expense		33.1			20.1
Contributions to pension and other postretirement plans		(3.8	)		(4.2	)
Deferred revenue—Fort Martin scrubber project		(1.9	)		4.8
Deferred revenue recognized—Virginia		0			(28.3	)
Deferred revenue—energy efficiency programs		8.7			0
Uncollected transmission revenue		(31.4	)		(7.2	)
Other, net		(6.1	)		4.2
Changes in certain assets and liabilities:
Accounts receivable, net		(54.3	)		(26.6	)
Materials, supplies and fuel		43.7			(75.2	)
Prepaid taxes		(9.7	)		(11.6	)
Collateral deposits		(16.8	)		(0.7	)
Accounts payable		(17.3	)		(12.7	)
Accrued taxes		(17.6	)		(66.1	)
Accrued interest		5.3			(1.5	)
Regulatory assets and liabilities		(21.6	)		26.9
Deferred income taxes		0.8			(22.5	)
Distributions from equity method investee		0			1.3
Assets and liabilities held for sale		(8.6	)		3.0
Other operating assets and liabilities		(13.4	)		6.3
Net cash provided by operating activities		364.0			241.0

See accompanying Notes to Consolidated Financial Statements.

5

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)

(unaudited)

	Six Months Ended June 30,
(In millions)	2010			2009
Cash Flows From Investing Activities:
Capital expenditures		(511.0	)		(550.2	)
Proceeds from sale of Virginia distribution business		317.2			0
Decrease in restricted funds		25.1			104.6
Deconsolidation of PATH WV		(3.4	)		0
Other		1.3			(1.2	)
Net cash used in investing activities		(170.8	)		(446.8	)
Cash Flows From Financing Activities:
Issuance of long-term debt		917.1			277.1
Repayment of long-term debt		(863.3	)		(167.4	)
Equity contribution to PATH, LLC by the joint venture partner		0			0.5
Return of capital, PATH, LLC		0			(0.2	)
Payments on capital lease obligations		(5.6	)		(4.4	)
Share-based excess tax benefits		0			19.7
Proceeds from exercise of employee stock options		0.5			1.2
Cash dividends paid on common stock		(50.9	)		(50.8	)
Net cash provided by (used in) financing activities		(2.2	)		75.7
Net increase (decrease) in cash and cash equivalents		191.0			(130.1	)
Cash and cash equivalents at beginning of period		286.6			362.1
Cash and cash equivalents at end of period	$	477.6		$	232.0
Supplemental Cash Flow Information:
Cash paid during the period for interest (net of amounts capitalized)	$	137.9		$	112.0
Accounts payable at June 30 relating to capital expenditures	$	132.1		$	165.8

See accompanying Notes to Consolidated Financial Statements.

6

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(unaudited)

(In millions)	June 30, 2010			December 31, 2009
ASSETS
Current Assets:
Cash and cash equivalents	$	477.6		$	286.6
Accounts receivable:
Customer		237.7			188.2
Unbilled utility revenue		97.9			116.4
Wholesale and other		87.5			64.4
Allowance for uncollectible accounts		(14.7	)		(14.0	)
Materials and supplies		111.8			110.6
Fuel		165.1			206.4
Deferred income taxes		0			81.5
Prepaid taxes		58.2			48.4
Collateral deposits		22.1			20.8
Derivative assets		12.6			4.6
Restricted funds		24.9			25.9
Regulatory assets		128.6			132.7
Assets held for sale		0			32.4
Other		38.2			40.4
Total current assets		1,447.5			1,345.3
Property, Plant and Equipment:
Generation		7,536.9			7,469.4
Transmission		1,403.9			1,313.2
Distribution		3,856.6			3,784.4
Other		444.4			440.7
Accumulated depreciation		(5,232.6	)		(5,104.9	)
Subtotal		8,009.2			7,902.8
Construction work in progress		982.7			800.6
Property, plant and equipment held for sale, net		0			253.7
Total property, plant and equipment, net		8,991.9			8,957.1
Other Noncurrent Assets:
Regulatory assets		736.0			717.3
Goodwill		367.3			367.3
Restricted funds		36.0			60.2
Investments in unconsolidated affiliates		44.8			26.7
Derivative assets		4.0			0
Other		103.4			115.2
Total other noncurrent assets		1,291.5			1,286.7
Total Assets	$	11,730.9		$	11,589.1

See accompanying Notes to Consolidated Financial Statements.

7

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Continued)

(unaudited)

	June  30, 2010			December 31, 2009
(In millions, except share amounts)
LIABILITIES AND EQUITY
Current Liabilities:
Long-term debt due within one year	$	165.6		$	140.8
Accounts payable		357.8			411.4
Accrued taxes		66.1			87.3
Payable to PJM for FTRs		2.0			31.7
Derivative liabilities		7.6			24.4
Regulatory liabilities		18.8			37.4
Accrued interest		73.6			68.3
Security deposits		53.1			51.0
Liabilities associated with assets held for sale		0			10.1
Deferred income taxes		8.5			0
Other		108.1			123.2
Total current liabilities		861.2			985.6
Long-term Debt		4,463.2			4,417.0
Deferred Credits and Other Liabilities:
Derivative liabilities		5.6			6.7
Income taxes payable		116.5			85.7
Investment tax credit		60.1			61.6
Deferred income taxes		1,509.4			1,501.3
Regulatory liabilities		470.3			461.2
Pension and other postretirement employee benefit plan liabilities		627.5			597.4
Adverse power purchase commitment		105.4			114.4
Liabilities associated with assets held for sale		0			53.1
Other		205.8			177.0
Total deferred credits and other liabilities		3,100.6			3,058.4
Commitments and Contingencies (Note 17)
Equity:
Common stock—$1.25 par value per share, 260,000,000 shares authorized and 169,666,019 and 169,620,917 shares issued at June 30, 2010 and December 31, 2009, respectively		212.1			212.0
Other paid-in capital		1,979.6			1,970.2
Retained earnings		1,180.2			1,022.7
Treasury stock at cost—51,313 shares at June 30, 2010 and December 31, 2009, respectively		(1.8	)		(1.8	)
Accumulated other comprehensive loss		(64.2	)		(89.9	)
Total Allegheny Energy, Inc. common stockholders’ equity		3,305.9			3,113.2
Noncontrolling interest		0			14.9
Total equity		3,305.9			3,128.1
Total Liabilities and Equity	$	11,730.9		$	11,589.1

See accompanying Notes to Consolidated Financial Statements.

8

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(unaudited)

(In millions, except shares)	Shares outstanding	Common stock		Other paid-in capital			Retained earnings			Treasury stock			Accumulated other comprehensive loss			Total Allegheny Energy, Inc. common stockholders’ equity			Noncontrolling interest			Total equity
Balance at March 31, 2010	169,578,004	$	212.0	$	1,974.1		$	1,085.5		$	(1.8	)	$	(43.8	)	$	3,226.0		$	—		$	3,226.0
Net income	—		—		—			120.2			—			—			120.2			—			120.2
Defined benefit pension and other benefit plan amortization, net of tax of $0.6	—		—		—			—			—			0.8			0.8			—			0.8
Cash flow hedges, net of tax of $(13.3)	—		—		—			—			—			(21.2	)		(21.2	)		—			(21.2	)
Dividends on common stock	—		—		—			(25.5	)		—			—			(25.5	)		—			(25.5	)
Stock-based compensation expense:
Non-employee director stock awards	3,000		—		0.2			—			—			—			0.2			—			0.2
Stock options	—		—		1.2			—			—			—			1.2			—			1.2
Performance shares	—		—		3.7			—			—			—			3.7			—			3.7
Exercise of stock options	33,702		0.1		0.4			—			—			—			0.5			—			0.5
Balance at June 30, 2010	169,614,706	$	212.1	$	1,979.6		$	1,180.2		$	(1.8	)	$	(64.2	)	$	3,305.9		$	—		$	3,305.9
(In millions, except shares)	Shares outstanding	Common stock		Other paid-in capital			Retained earnings			Treasury stock			Accumulated other comprehensive loss			Total Allegheny Energy, Inc. common stockholders’ equity			Noncontrolling interest			Total equity
Balance at March 31, 2009	169,399,045	$	211.8	$	1,976.0		$	840.1		$	(1.8	)	$	(21.4	)	$	3,004.7		$	5.1		$	3,009.8
Net income	—		—		—			72.6			—			—			72.6			0.3			72.9
Defined benefit pension and other benefit plan amortization, net of tax of $0.6	—		—		—			—			—			0.8			0.8			—			0.8
Cash flow hedges, net of tax of $(8.5)	—		—		—			—			—			(13.0	)		(13.0	)		—			(13.0	)
PATH, LLC return of capital	—		—		—			—			—			—			—			(0.3	)		(0.3	)
Equity contribution to PATH, LLC by AEP	—		—		—			—			—			—			—			0.5			0.5
Dividends on common stock	—		—		—			(25.4	)		—			—			(25.4	)		—			(25.4	)
Stock-based compensation expense:
Non-employee director stock awards	2,706		—		0.2			—			—			—			0.2			—			0.2
Stock options	—		—		2.3			—			—			—			2.3			—			2.3
Performance shares	—		—		2.5			—			—			—			2.5			—			2.5
Exercise of stock options	80,840		0.1		1.1			—			—			—			1.2			—			1.2
Other	—		—		(0.2	)		—			—			—			(0.2	)		—			(0.2	)
Balance at June 30, 2009	169,482,591	$	211.9	$	1,981.9		$	887.3		$	(1.8	)	$	(33.6	)	$	3,045.7		$	5.6		$	3,051.3

See accompanying Notes to Consolidated Financial Statements.

9

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(unaudited)

(In millions, except shares)	Shares outstanding	Common stock		Other paid-in capital		Retained earnings			Treasury stock			Accumulated other comprehensive loss			Total Allegheny Energy, Inc. common stockholders’ equity			Noncontrolling interest			Total equity
Balance at December 31, 2009	169,569,604	$	212.0	$	1,970.2	$	1,022.7		$	(1.8	)	$	(89.9	)	$	3,113.2		$	14.9		$	3,128.1
Net income	—		—		—		208.4			—			—			208.4			—			208.4
Defined benefit pension and other benefit plans:
Net loss during period, net of tax of $(0.3)	—		—		—		—			—			(0.4	)		(0.4	)		—			(0.4	)
Amortization, net of tax of $1.2	—		—		—		—			—			1.6			1.6			—			1.6
Cash flow hedges, net of tax of $15.6	—		—		—		—			—			24.5			24.5			—			24.5
Deconsolidation of PATH WV	—		—		—		—			—			—			—			(14.9	)		(14.9	)
Dividends on common stock	—		—		—		(50.9	)		—			—			(50.9	)		—			(50.9	)
Stock-based compensation expense:
Non-employee director stock awards	6,000		—		0.4		—			—			—			0.4			—			0.4
Stock options	—		—		2.7		—			—			—			2.7			—			2.7
Performance shares	—		—		5.7		—			—			—			5.7			—			5.7
Restricted shares	—		—		0.1		—			—			—			0.1			—			0.1
Exercise of stock options	39,102		0.1		0.5		—			—			—			0.6			—			0.6
Balance at June 30, 2010	169,614,706	$	212.1	$	1,979.6	$	1,180.2		$	(1.8	)	$	(64.2	)	$	3,305.9		$	—		$	3,305.9
(In millions, except shares)	Shares outstanding	Common stock		Other paid-in capital		Retained earnings			Treasury stock			Accumulated other comprehensive loss			Total Allegheny Energy, Inc. common stockholders’ equity			Noncontrolling interest			Total equity
Balance at December 31, 2008	169,364,394	$	211.8	$	1,952.5	$	731.6		$	(1.8	)	$	(43.3	)	$	2,850.8		$	4.9		$	2,855.7
Net income	—		—		—		206.5			—			—			206.5			0.5			207.0
Defined benefit pension and other benefit plan amortization, net of tax of $1.1	—		—		—		—			—			1.7			1.7			—			1.7
Cash flow hedges, net of tax of $4.9	—		—		—		—			—			8.0			8.0			—			8.0
PATH, LLC return of capital	—		—		—		—			—			—			—			(0.3	)		(0.3	)
Equity contribution to PATH, LLC by AEP	—		—		—		—			—			—			—			0.5			0.5
Dividends on common stock	—		—		—		(50.8	)		—			—			(50.8	)		—			(50.8	)
Stock-based compensation expense:
Non-employee director stock awards	15,907		—		0.4		—			—			—			0.4			—			0.4
Stock options	—		—		4.0		—			—			—			4.0			—			4.0
Performance shares	—		—		4.1		—			—			—			4.1			—			4.1
Restricted shares	17,850		—		—		—			—			—			—			—			—
Exercise of stock options	84,440		0.1		1.2		—			—			—			1.3			—			1.3
Share-based excess tax benefits	—		—		19.7		—			—			—			19.7			—			19.7
Balance at June 30, 2009	169,482,591	$	211.9	$	1,981.9	$	887.3		$	(1.8	)	$	(33.6	)	$	3,045.7		$	5.6		$	3,051.3

See accompanying Notes to Consolidated Financial Statements.

10

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note		Page Number
1	Business and Basis of Presentation	12
2	Merger Agreement	13
3	Recently Adopted and Recently Issued Accounting Standards	13
4	Sale of Virginia Distribution Business	14
5	Rates and Regulation	15
6	Regulatory Assets and Liabilities	17
7	Income Taxes	17
8	Common Stock and Debt	18
9	Segment Information	21
10	Fair Value Measurements, Derivative Instruments and Hedging Activities	23
11	Stock-Based Compensation	30
12	Pension Benefits and Postretirement Benefits Other Than Pensions	33
13	Financial Instruments	35
14	Comprehensive Income and Accumulated Other Comprehensive Loss	36
15	Earnings Per Share	37
16	Variable Interest Entities	37
17	Commitments and Contingencies	39

11

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

NOTE 1: BUSINESS AND BASIS OF PRESENTATION

Business Description

Allegheny Energy, Inc. (“AE” and, together with its subsidiaries, “Allegheny”) is an integrated energy business. Allegheny owns and operates electric generation facilities primarily in Pennsylvania, West Virginia and Maryland. Additionally, Allegheny owns transmission assets in Pennsylvania, West Virginia, Maryland and Virginia and provides distribution services to customers in Pennsylvania, West Virginia and Maryland. Allegheny manages its operations through two business segments: Merchant Generation and Regulated Operations. These business segments are also referred to as reportable segments.

The Merchant Generation segment includes Allegheny’s unregulated electric generation operations including Allegheny Energy Supply Company, LLC (“AE Supply”) and AE Supply’s interest in Allegheny Generating Company (“AGC”). AE Supply owns, operates and controls electric generation capacity and supplies and trades energy and energy-related commodities. AGC owns and sells generation capacity to AE Supply and Monongahela Power Company (“Monongahela”), which own approximately 59% and 41% of AGC, respectively. The Merchant Generation segment is subject to federal and state regulation but, unlike the Regulated Operations segment, is not generally subject to state regulation of rates.

The Regulated Operations segment includes the operations of Monongahela, The Potomac Edison Company (“Potomac Edison”) and West Penn Power Company (“West Penn” and, together with Monongahela and Potomac Edison, the “Distribution Companies”), which primarily operate electric transmission and distribution (“T&D”) systems in Pennsylvania, West Virginia and Maryland, as well as transmission in Virginia. Monongahela also owns and operates electric generation facilities in West Virginia and has a 41% interest in AGC. The Distribution Companies are subject to federal and state regulation, including state regulation of rates.

The Regulated Operations segment also includes the operations of Trans-Allegheny Interstate Line Company (“TrAIL Company”) and Allegheny’s interests in Potomac-Appalachian Transmission Highline, LLC (“PATH, LLC”). These entities were created to construct or facilitate the construction of high voltage transmission lines and other transmission facilities, including the Trans-Allegheny Interstate Line (“TrAIL”) and the Potomac-Appalachian Transmission Highline (“PATH”). TrAIL Company and PATH, LLC are subject to the regulation of rates by the Federal Energy Regulatory Commission (“FERC”). PATH, LLC is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of AE owns 100% of the Allegheny Series and 50% of the West Virginia Series (“PATH WV”), which is a joint venture with a subsidiary of American Electric Power Company, Inc. (“AEP”). Allegheny accounts for its interest in PATH WV using the equity method of accounting, effective January 1, 2010. See Note 3, “Recently Adopted and Recently Issued Accounting Standards” for additional information.

On June 1, 2010, Potomac Edison sold its electric distribution business in Virginia. See Note 4, “Sale of Virginia Distribution Business” for additional information.

Allegheny Energy Service Corporation (“AESC”) is a wholly-owned subsidiary of AE that employs substantially all of Allegheny’s personnel.

Financial Statement Presentation

As permitted by the rules and regulations of the Securities and Exchange Commission (the “SEC”), Allegheny’s accompanying unaudited Consolidated Financial Statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited consolidated financial

12

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”). These unaudited Consolidated Financial Statements should be read in conjunction with Allegheny’s Consolidated Financial Statements and Notes in its Annual Report on Form 10-K for the year ended December 31, 2009.

The accompanying unaudited Consolidated Financial Statements contain all adjustments, including normal recurring accruals, necessary to present fairly Allegheny’s financial position, results of operations, cash flows and changes in equity for the periods presented therein. The results of operations for the interim periods are not necessarily indicative of the results expected for the full year. Information for quarterly periods is affected by seasonal variations in revenues, fuel and energy purchases and other factors. The year-end 2009 balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. Certain amounts in previously issued financial statements have been reclassified to conform to the current presentation, including a change in the composition of reportable segments made during the fourth quarter of 2009.

NOTE 2: MERGER AGREEMENT

On February 10, 2010, AE entered into an Agreement and Plan of Merger (as amended on June 4, 2010, the “Merger Agreement”) with FirstEnergy Corp. (“FirstEnergy”) and Element Merger Sub, Inc. (“Merger Sub”), a wholly owned subsidiary of FirstEnergy. Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into AE (the “Merger”), with AE becoming a wholly owned subsidiary of FirstEnergy. The Merger is intended to qualify as a tax-free reorganization under the Internal Revenue Code of 1986, as amended, and be tax-free to AE stockholders. Pursuant to the Merger Agreement, upon completion of the Merger, each issued and outstanding share of AE’s common stock, including grants of restricted stock, will automatically be converted into the right to receive 0.667 of a share of the common stock of FirstEnergy. This ratio is fixed, and the Merger Agreement does not provide for any adjustment to reflect stock price changes prior to completion of the Merger.

Completion of the Merger is subject to various customary conditions, including, among others, (i) requisite approvals of AE and FirstEnergy stockholders, (ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, (iii) receipt of all required regulatory approvals, including approvals from FERC and certain state public service and utility commissions, (iv) the absence of any governmental action challenging or seeking to prohibit the Merger, and (v) the absence of any material adverse effect with respect to either Allegheny or FirstEnergy.

FirstEnergy’s S-4 registration statement regarding the proposed Merger was declared effective by the SEC on July 16, 2010, and AE and FirstEnergy will each hold a special stockholder meeting on September 14, 2010 to consider and vote on proposals related to the Merger. AE and FirstEnergy currently anticipate completing the Merger in the first half of 2011.

NOTE 3: RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS

Consolidations and Variable Interest Entities

Allegheny adopted Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) 2009-17 (Consolidations Topic 810), “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” on January 1, 2010. Under this new guidance, consolidation of a variable interest entity (“VIE”) is required by an enterprise (the “primary beneficiary”), if any, that is determined qualitatively to have both the power to direct the activities that most significantly impact the VIE’s economic success and the

13

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. Under the prior guidance, the primary beneficiary (consolidator) of a VIE was the party that absorbed a majority of the expected losses or the majority of the expected residual returns of the VIE using a quantitative analysis.

Through December 31, 2009, Allegheny consolidated PATH WV for financial statement purposes, because Allegheny determined that PATH WV was a VIE and that Allegheny was its primary beneficiary under the prior accounting standard. Under the new accounting standard, Allegheny determined that it is not the primary beneficiary of PATH WV, and therefore deconsolidated PATH WV for financial statement purposes, effective January 1, 2010. Allegheny did not retrospectively apply this new guidance by deconsolidating PATH WV in its financial statements for periods prior to January 1, 2010. The deconsolidation of PATH WV did not impact retained earnings or net income attributable to Allegheny Energy, Inc. See Note 16, “Variable Interest Entities,” for additional information.

Fair Value Measurements and Disclosures

Allegheny adopted the FASB’s ASU on “Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value Measurements” in January 2010. The ASU added new requirements for disclosures about transfers into and out of fair value Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. The ASU also clarified existing fair value disclosures about the level of disaggregation and about inputs and valuation techniques used to measure fair value. Allegheny’s adoption of this ASU did not affect its results of operations or financial position.

NOTE 4: SALE OF VIRGINIA DISTRIBUTION BUSINESS

On June 1, 2010, Potomac Edison sold its electric distribution business in Virginia (the “Virginia distribution business”) to Rappahannock Electric Cooperative and Shenandoah Valley Electric Cooperative. Cash proceeds from the sale were approximately $317 million, resulting in a pre-tax gain of approximately $45 million. In connection with the sale, Potomac Edison agreed to contribute $27.5 million between July 1, 2011 and July 1, 2014 to reduce the impact of any future rate increases, the present value of which was included in the calculation of the $45 million pre-tax gain. In addition, on June 1, 2010, Potomac Edison entered into an agreement to purchase Shenandoah Valley Electric Cooperative’s West Virginia distribution business for approximately $13 million, subject to certain adjustments through the closing date.

14

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

The Virginia distribution business was included in the Regulated Operations segment. Assets and liabilities relating to the Virginia distribution business were classified as “held for sale” in Allegheny’s consolidated balance sheet, and depreciation expense on those assets ceased as of May 1, 2009. The operating results of the Virginia distribution business have not been reported as discontinued operations, because AE Supply will continue to provide the majority of the power to serve the customers of this business under a power sales agreement through June 30, 2011. Assets held for sale and liabilities associated with assets held for sale at December 31, 2009 were as follows:

(In millions)	December 31, 2009
Current Assets:
Accounts receivable	$	31.2
Materials and supplies		0.7
Regulatory assets		0.5
Total current assets		32.4
Property, Plant and Equipment:
Distribution property, plant and equipment		344.9
Accumulated depreciation		(91.2	)
Property, plant and equipment, net		253.7
Total assets held for sale	$	286.1
Current Liabilities:
Customer deposits	$	5.5
Regulatory liabilities		3.7
Other		0.9
Total current liabilities		10.1
Deferred Credits and Other Liabilities:
Regulatory liabilities		51.8
Other		1.3
Total deferred credits and other liabilities		53.1
Total liabilities associated with assets held for sale	$	63.2

NOTE 5: RATES AND REGULATION

Rate Case

On April 2, 2010, Monongahela and Potomac Edison filed with the Public Service Commission of West Virginia (“West Virginia PSC”) a Joint Stipulation and Agreement of Settlement (the “West Virginia Stipulation”) reached with the other parties in a rate case filed by Monongahela and Potomac Edison in August 2009. The West Virginia Stipulation provides for:

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

• the deferral of February 2010 storm restoration expenses in West Virginia over a maximum five-year period;

• an additional $20 million annualized base rate increase effective January 2011;

15

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

• a decrease of $20 million in the Expanded Net Energy Clause (“ENEC”) rates effective January 2011, which amount is deferred for later recovery in 2012; and

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

The West Virginia PSC conducted a hearing on the West Virginia Stipulation on April 6, 2010 and approved the stipulation on June 25, 2010.

Transmission Expansion

PATH Project. PATH is a 765 kV transmission line that is proposed to extend through West Virginia and into Maryland. PJM Interconnection, L.L.C. (“PJM”), which is a regional transmission organization, initially authorized the construction of PATH in June 2007. A subsidiary of AE and a subsidiary of AEP formed PATH, LLC to build PATH, and in December 2007, PATH, LLC submitted a filing to FERC under Section 205 of the Federal Power Act (the “FPA”) to implement a formula rate tariff effective March 1, 2008. The filing also included a request for certain incentive rate treatments. In February 2008, FERC issued an order setting the cost of service formula rate to calculate annual revenue requirements for the project and authorizing: a return on equity of 14.3%; a return on construction work in progress (“CWIP”); recovery of prudently incurred start-up business and administrative costs incurred prior to the time the rates go into effect; and recovery of prudently incurred development and construction costs if all or any portion of PATH is abandoned as a result of factors beyond the control of PATH, LLC.

In December 2008, PATH, LLC submitted to FERC a settlement of the formula rate and protocols with the active parties. FERC approval of the settlement is pending. Rehearing of the February 29, 2008 order with respect to return on equity remains pending before FERC.

In December 2009, PJM conducted certain sensitivity analyses as directed by a Virginia State Corporation Commission (the “Virginia SCC”) Hearing Examiner and advised that, based on these analyses, the PATH Project might not be needed in 2014 as previously expected as a result of a reduction in the scope and severity of observed NERC reliability violations. PJM advised that, consistent with PJM processes, the PATH Project would be considered in the 2010 Regional Transmission Expansion Plan (“RTEP”) to determine when it would be needed to resolve NERC reliability violations. On June 17, 2010, in connection with the 2010 RTEP, PJM requested that PATH, LLC proceed with all efforts related to the PATH Project, including state regulatory proceedings, assuming a required in-service date for the project of June 1, 2015.

16

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

NOTE 6: REGULATORY ASSETS AND LIABILITIES

Allegheny’s regulated utility operations are subject to regulated industry-specific accounting provisions. Regulatory assets represent probable future revenues associated with incurred costs that are expected to be recovered in the future from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited or refunded to customers through the rate-making process or amounts collected for costs not yet incurred. Regulatory assets and regulatory liabilities reflected in the Consolidated Balance Sheets were as follows:

(In millions)	June 30, 2010		December 31, 2009
Regulatory assets, including current portion:
Income taxes (a)(b)	$	230.2	$	234.9
Pension benefits and postretirement benefits other than pensions (a)(c)		385.4		396.5
Deferred ENEC charges (d)		88.3		109.5
Transmission revenue requirement (e)		62.0		29.8
Unamortized loss on reacquired debt (a)(f)		35.8		26.8
Unrealized loss on financial transmission rights (a)		0		1.7
Other (g)		62.9		50.8
Subtotal		864.6		850.0
Regulatory liabilities, including current portion:
Net asset removal costs (h)		380.6		374.2
Income taxes		28.4		29.3
SO2 allowances		12.5		12.8
Fort Martin Scrubber project—environmental control surcharge		38.2		40.1
Maryland rate stabilization and transition plan surcharge		12.2		30.1
Unrealized gain on financial transmission rights		6.1		0
Other		11.1		12.1
Subtotal		489.1		498.6
Net regulatory assets	$	375.5	$	351.4

(a) Does not earn a return.

(b) Amount is being recovered over various periods associated with the remaining useful life of related regulated utility property, plant and equipment.

(c) Amount is being recovered over various periods up to 13 years.

(d) Includes amounts that do not earn a return with recovery periods through 2012.

(e) Amount earns interest at the approved FERC interest rate and will be recovered through 2012.

(f) Amount is being recovered over various periods through 2025, based upon the maturities of reacquired debt.

(g) Includes amounts that do not earn a return with various recovery periods through 2027.

(h) Net asset removal costs of $51.0 million are included in liabilities associated with assets held for sale at December 31, 2009 in the consolidated balance sheet.

NOTE 7: INCOME TAXES

Allegheny records income taxes under the liability method of accounting. Deferred income tax balances are generally determined based on the difference between the financial statement and tax basis of assets and liabilities using the statutory income tax rates in effect for years in which the differences are expected to reverse. Investment tax credits are amortized over the estimated useful life of the related property. Tax benefits are

17

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

recognized in the financial statements when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. Such tax positions are measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts.

Allegheny allocates federal income tax expense (benefit) among its subsidiaries pursuant to its consolidated tax sharing agreement.

The following is a reconciliation of reported income tax expense to income tax expense calculated by applying the federal statutory rate of 35% to income before income taxes:

	Three Months Ended June 30,										Six Months Ended June 30,
	2010					2009					2010					2009
(In millions, except percentages)	Amount			%		Amount			%		Amount			%		Amount			%
Income before income taxes	$	194.0				$	121.8				$	338.0				$	356.8
Income tax expense calculated at the federal statutory rate of 35%		67.9		35.0	%		42.6		35.0	%		118.3		35.0	%		124.9		35.0	%
Increases (reductions) resulting from:
Rate-making effects of depreciation differences and removal costs		0.9		0.5			0.7		0.6			1.8		0.5			1.4		0.4
Other state income tax, net of federal income tax benefit		6.2		3.2			4.3		3.5			10.5		3.1			12.5		3.5
Amortization of deferred investment tax credits		(0.8	)	(0.4	)		(0.9	)	(0.7	)		(1.7	)	(0.5	)		(1.8	)	(0.5	)
Change in estimated Pennsylvania net operating loss benefits		0		0			0		0			0		0			9.5		2.7
Changes in tax reserves related to uncertain tax positions and audit settlements		0.6		0.3			1.5		1.2			2.2		0.6			3.2		0.9
Other, net		(1.0	)	(0.6	)		0.7		0.5			(1.5	)	(0.4	)		0.1		0
Income tax expense	$	73.8		38.0	%	$	48.9		40.1	%	$	129.6		38.3	%	$	149.8		42.0	%

The Commonwealth of Pennsylvania limits the amount of net operating loss carryforwards that may be used to reduce current year taxable income to the greater of $3 million or 15% of taxable income per year for 2010 and the greater of $3 million or 20% of taxable income for years after 2010.

During the six months ended June 30, 2009, a charge of $9.5 million was recorded, net of applicable federal income tax, to adjust the recorded Pennsylvania net operating loss carryforward asset to reflect current estimates of future Pennsylvania taxable income during the carryforward period.

NOTE 8: COMMON STOCK AND DEBT

Common Stock

On June 21, 2010 and March 22, 2010, AE paid cash dividends on its common stock of $0.15 per share to shareholders of record at the close of business on June 7, 2010 and March 8, 2010, respectively. On July 8, 2010, AE’s Board of Directors authorized a cash dividend on its common stock of $0.15 per share payable on September 27, 2010 to shareholders of record on September 13, 2010.

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ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

Debt

Outstanding debt and scheduled debt repayments at June 30, 2010 were as follows:

(In millions)	July 1, 2010 through December 31, 2010			2011			2012			2013			2014			Thereafter			Total
AE Supply:
Medium-Term Notes	$	0		$	150.5		$	503.2		$	0		$	0		$	600.0		$	1,253.7
Pollution Control Bonds		0			0			1.3			0			15.4			251.7			268.4
Exempt Facilities Revenue Bonds		0			0			0			0			0			235.0			235.0
Debentures-AGC		0			0			0			0			0			100.0			100.0
Total AE Supply		0			150.5			504.5			0			15.4			1,186.7			1,857.1
Monongahela:
Environmental Control Bonds (a)		5.7			11.6			12.2			12.8			13.5			322.1			377.9
First Mortgage Bonds		0			0			0			300.0			120.0			220.0			640.0
Pollution Control Bonds		0			0			6.0			7.1			0			57.1			70.2
Total Monongahela		5.7			11.6			18.2			319.9			133.5			599.2			1,088.1
West Penn:
First Mortgage Bonds		0			0			0			0			0			420.0			420.0
Medium-Term Notes		0			0			80.0			0			0			0			80.0
Revolving Credit Facility		0			0			0			15.0			0			0			15.0
Total West Penn		0			0			80.0			15.0			0			420.0			515.0
Potomac Edison:
First Mortgage Bonds		0			0			0			0			175.0			245.0			420.0
Environmental Control Bonds (a)		2.0			3.9			4.1			4.3			4.5			107.5			126.3
Total Potomac Edison		2.0			3.9			4.1			4.3			179.5			352.5			546.3
TrAIL Company:
Medium-Term Notes		0			0			0			0			0			450.0			450.0
Revolving Loan		0			0			0			195.0			0			0			195.0
Total TrAIL		0			0			0			195.0			0			450.0			645.0
Unamortized debt discounts		(0.8	)		(1.5	)		(1.2	)		(1.1	)		(0.9	)		(2.8	)		(8.3	)
Eliminations (b)		0			0			(1.3	)		0			0			(13.1	)		(14.4	)
Total consolidated debt	$	6.9		$	164.5		$	604.3		$	533.1		$	327.5		$	2,992.5		$	4,628.8

(a) Amounts represent repayments based upon estimated surcharge collections from customers.

(b) Amounts represent the elimination of certain pollution control bonds, for which Monongahela and AE Supply are co-obligors.

The environmental control bonds shown in the table above were issued by two bankruptcy remote, special purpose limited liability companies (the “Funding Companies”) that are indirect subsidiaries of Monongahela and Potomac Edison, respectively. Proceeds from the bonds were used to construct environmental control facilities. The Funding Companies own the irrevocable right to collect non-bypassable environmental control charges (the “Environmental Control Charge”) from all customers who receive electric delivery service in Monongahela’s and Potomac Edison’s West Virginia service territories. Principal and interest owing on the environmental control bonds is secured by and payable solely from the proceeds of the Environmental Control

19

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

Charge. The right to collect Environmental Control Charges is not included on Allegheny’s consolidated balance sheets. Creditors of AE and its subsidiaries other than the Funding Companies have no recourse to any assets or revenues of the Funding Companies.

Certain of Allegheny’s properties are subject to liens of various relative priorities securing debt.

2010 Debt Activity

Borrowings and principal repayments on debt during the six months ended June 30, 2010 were as follows:

(In millions)	Issuances		Repayments
AE:
AE Revolving Credit Facility	$	130.1	$	130.1
TrAIL Company:
Medium-Term Notes		450.0		0
New TrAIL Company Credit Facility—Revolver		195.0		0
TrAIL Company Credit Facility—Term Loan (a)		30.0		465.0
TrAIL Company Credit Facility—Revolver (a)		0		20.0
West Penn:
Transition Bonds		0		16.0
Revolving Credit Facility		20.0		5.0
Monongahela:
Medium-Term Notes		0		110.0
Environmental Control Bonds		0		5.5
Potomac Edison:
Environmental Control Bonds		0		1.7
Revolving Credit Facility		110.0		110.0
Consolidated Total	$	935.1	$	863.3

(a) Represents debt under TrAIL Company’s previous credit facility, which was repaid and replaced in January 2010 by a new revolving credit facility, which is described below.

On January 15, 2010, Monongahela repaid its $110 million 7.36% medium-term notes.

On January 25, 2010, TrAIL Company issued $450 million aggregate principal amount of 4.0% senior unsecured notes due in 2015 and also entered into a new $350 million senior unsecured revolving credit facility with a three-year maturity. Borrowings under the new facility bear interest at a rate that is calculated based on the London Interbank Offered Rate (“LIBOR”), plus a margin based on TrAIL Company’s senior unsecured credit rating. TrAIL Company used the net proceeds from the sale of the notes, together with funds from its new credit facility, to repay all amounts outstanding under the $550 million senior unsecured credit facility that it had entered into in 2008.

On May 3, 2010, Potomac Edison and West Penn entered into new $150 million and $200 million senior unsecured revolving credit facilities, respectively. On May 4, 2010, AE entered into a new $250 million senior unsecured revolving credit facility. The new AE revolving credit facility replaces AE’s previous $376 million revolving credit facility, which was scheduled to mature in May 2011. The AE and West Penn facilities mature April 30, 2013. The Potomac Edison facility matures on December 31, 2011, but it will be automatically extended to April 30, 2013, subject to Potomac Edison securing necessary authorization under Virginia law.

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ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

Loans under all three new facilities generally bear interest that is calculated based on LIBOR, plus a margin based on such entity’s senior unsecured credit rating. Currently, the margins are 3.0% for AE and 2.75% for Potomac Edison and West Penn. Allegheny capitalized approximately $5.6 million in debt issuance costs related to the three new facilities.

On July 16, 2010, AE Supply redeemed all $150.5 million of its outstanding 7.80% Medium Term Notes due 2011 and expensed approximately $7.2 million in redemption premiums associated with the notes.

NOTE 9: SEGMENT INFORMATION

The following tables summarize the results of operations for Allegheny’s two reportable segments. The information for the Regulated Operations segment includes the operations of the Virginia distribution business through the date of its sale on June 1, 2010. See Note 4, “Sale of Virginia Distribution Business,” for additional information.

Allegheny changed the composition of its reportable segments during the fourth quarter of 2009, consistent with changes made to its management structure and the internal financial reporting used by its chief operating decision maker to regularly assess the performance of the business and allocate resources. Segment information for the three and six months ended June 30, 2009 has been reclassified to conform to the 2010 presentation included below.

	Three Months Ended June 30, 2010												Three Months Ended June 30, 2009
(In millions)	Merchant Generation			Regulated Operations			Eliminations (a)			Total			Merchant Generation			Regulated Operations			Eliminations (a)			Total
Operating revenues:
External operating revenues	$	151.7		$	794.0		$	0		$	945.7		$	93.7		$	721.0		$	0		$	814.7
Internal operating revenues		306.2			1.3			(307.5	)		0			280.5			1.4			(281.9	)		0
Total operating revenues		457.9			795.3			(307.5	)		945.7			374.2			722.4			(281.9	)		814.7
Operating expenses:
Fuel		230.1			65.6			0			295.7			153.6			63.2			0			216.8
Purchased power and transmission		9.2			423.3			(306.2	)		126.3			8.8			383.9			(280.5	)		112.2
Deferred energy costs, net		0			2.3			0			2.3			0			(7.6	)		0			(7.6	)
Gain on sale of Virginia distribution business		0			(45.1	)		0			(45.1	)		0			0			0			0
Operations and maintenance		52.5			107.4			(1.3	)		158.6			88.7			113.2			(1.4	)		200.5
Depreciation and amortization		32.4			48.6			(0.4	)		80.6			24.0			43.7			(0.5	)		67.2
Taxes other than income taxes		12.9			43.7			0			56.6			8.5			38.0			0			46.5
Total operating expenses		337.1			645.8			(307.9	)		675.0			283.6			634.4			(282.4	)		635.6
Operating income		120.8			149.5			0.4			270.7			90.6			88.0			0.5			179.1
Other income (expense), net		0.8			5.4			(3.3	)		2.9			0.4			4.2			(2.8	)		1.8
Interest expense		36.4			44.1			(0.9	)		79.6			20.0			39.3			(0.2	)		59.1
Income before income taxes		85.2			110.8			(2.0	)		194.0			71.0			52.9			(2.1	)		121.8
Income tax expense		30.0			43.8			0			73.8			26.8			22.1			0			48.9
Net income		55.2			67.0			(2.0	)		120.2			44.2			30.8			(2.1	)		72.9
Net income attributable to noncontrolling interest		(2.2	)		0			2.2			0			(2.3	)		(0.3	)		2.3			(0.3	)
Net income attributable to Allegheny Energy, Inc.	$	53.0		$	67.0		$	0.2		$	120.2		$	41.9		$	30.5		$	0.2		$	72.6

(a) Represents elimination of transactions between reportable segments.

21

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

	Six Months Ended June 30, 2010												Six Months Ended June 30, 2009
(In millions)	Merchant Generation			Regulated Operations			Eliminations (a)			Total			Merchant Generation			Regulated Operations			Eliminations (a)			Total
Operating revenues:
External operating revenues	$	241.0		$	1,753.5		$	0		$	1,994.5		$	196.0		$	1,575.9		$	0		$	1,771.9
Internal operating revenues		679.5			2.8			(682.3	)		0			633.7			4.5			(638.2	)		0
Total operating revenues		920.5			1,756.3			(682.3	)		1,994.5			829.7			1,580.4			(638.2	)		1,771.9
Operating expenses:
Fuel		464.6			149.1			0			613.7			338.9			136.8			0			475.7
Purchased power and transmission		18.8			935.9			(679.5	)		275.2			18.2			863.3			(635.4	)		246.1
Deferred energy costs, net		0			10.4			0			10.4			0			(24.6	)		0			(24.6	)
Gain on sale of Virginia distribution business		0			(45.1	)		0			(45.1	)		0			0			0			0
Operations and maintenance		118.5			261.4			(2.8	)		377.1			150.8			219.8			(2.8	)		367.8
Depreciation and amortization		64.5			96.7			(0.8	)		160.4			47.7			88.9			(0.9	)		135.7
Taxes other than income taxes		26.1			87.6			0			113.7			21.3			81.0			0			102.3
Total operating expenses		692.5			1,496.0			(683.1	)		1,505.4			576.9			1,365.2			(639.1	)		1,303.0
Operating income		228.0			260.3			0.8			489.1			252.8			215.2			0.9			468.9
Other income (expense), net		1.4			10.5			(6.6	)		5.3			1.0			8.7			(5.5	)		4.2
Interest expense		72.5			85.6			(1.7	)		156.4			37.8			78.9			(0.4	)		116.3
Income before income taxes		156.9			185.2			(4.1	)		338.0			216.0			145.0			(4.2	)		356.8
Income tax expense		57.0			72.6			0			129.6			89.6			60.2			0			149.8
Net income		99.9			112.6			(4.1	)		208.4			126.4			84.8			(4.2	)		207.0
Net income attributable to noncontrolling interest		(4.5	)		0			4.5			0			(4.6	)		(0.5	)		4.6			(0.5	)
Net income attributable to Allegheny Energy, Inc.	$	95.4		$	112.6		$	0.4		$	208.4		$	121.8		$	84.3		$	0.4		$	206.5

(a) Represents elimination of transactions between reportable segments.

22

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

NOTE 10: FAIR VALUE MEASUREMENTS, DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Allegheny’s assets and liabilities measured at fair value on a recurring basis at June 30, 2010 consisted of the following:

(In millions)	Assets		Liabilities
Cash equivalents (a)	$	484.0	$	0
Derivative instruments (b):
Current		266.8		(7.6	)
Non-current		4.0		(9.8	)
Total derivative instruments		270.8		(17.4	)
Total recurring fair value measurements	$	754.8	$	(17.4	)

(a) Cash equivalents represent amounts invested in money market mutual funds and are valued using Level 1 inputs.

(b) Before netting of cash collateral and financial transmission right (“FTR”) obligation.

The following table disaggregates the net fair values of derivative assets and liabilities by class, before netting of cash collateral and FTR obligation, based on their level within the fair value hierarchy at June 30, 2010. This table excludes derivatives that have been designated as normal purchases or normal sales.

	Fair Value at June 30, 2010 Using
(In millions)	Level 1			Level 2			Level 3		Total
Derivative assets:
Power contracts futures	$	(0.8	)	$	0		$	0	$	(0.8	)
Power contracts forwards		0			13.7			0		13.7
Gas contracts futures		15.9			0			0		15.9
Gas contracts forwards		0			0.3			0		0.3
FTRs		0			0			241.7		241.7
Total derivative assets		15.1			14.0			241.7		270.8
Derivative liabilities:
Power contracts futures		(5.9	)		0			0		(5.9	)
Power contracts forwards		0			(6.3	)		0		(6.3	)
Gas contracts forwards		0			(0.1	)		0		(0.1	)
Interest rate swaps		0			(5.1	)		0		(5.1	)
Total derivative liabilities		(5.9	)		(11.5	)		0		(17.4	)
Net derivative assets	$	9.2		$	2.5		$	241.7	$	253.4

23

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

The following table shows the expected settlement year for derivative assets and liabilities outstanding before netting of cash collateral and FTR obligation at June 30, 2010. This table excludes derivatives that have been designated as normal purchases or normal sales:

(In millions)	2010			2011			2012			2013		Total
Level 1	$	15.8		$	(0.1	)	$	(6.5	)	$	0	$	9.2
Level 2		(6.4	)		15.5			(6.6	)		0		2.5
Level 3		141.3			100.4			0			0		241.7
Net derivative assets (liabilities)	$	150.7		$	115.8		$	(13.1	)	$	0	$	253.4

The following table disaggregates the net fair values of derivative assets and liabilities, before netting of cash collateral and FTR obligation, based on their level within the fair value hierarchy at December 31, 2009. This table excludes derivatives that have been designated as normal purchases or normal sales.

	December 31, 2009
(In millions)	Derivative Assets		Derivative Liabilities			Net Derivative Assets
Level 1	$	31.9	$	(4.7	)	$	27.2
Level 2		0.2		(29.5	)		(29.3	)
Level 3		96.2		0			96.2
Total	$	128.3	$	(34.2	)	$	94.1

Derivative assets and liabilities included in Level 1 primarily consist of exchange-traded futures and other exchange-traded transactions that are valued using closing prices for identical instruments in active markets. Derivative assets and liabilities included in Level 2 primarily consist of commodity forward contracts and interest rate swaps. Derivatives included in Level 2 are valued using a pricing model with inputs that are observable in the market, such as quoted forward prices of commodities, or that can be derived from or corroborated by observable market data. Derivative assets included in Level 3 consist of FTRs and are valued using an internal model based on data from PJM annual and monthly FTR auctions.

The following tables provide a reconciliation of the beginning and ending balance of FTR derivative assets measured at fair value (Level 3):

	Three Months Ended June 30,
(In millions)	2010		2009
Balance at April 1	$	26.8	$	55.5
Total realized and unrealized gains (losses):
Included in earnings, in operating revenues		16.0		(64.2	)
Included in regulatory assets or liabilities		8.3		(32.4	)
Purchases, issuances and settlements		190.6		291.6
Transfers in / out of Level 3		0		0
Balance at June 30	$	241.7	$	250.5
Amount of total gains (losses) included in earnings attributable to the change in unrealized gains (losses) related to Level 3 assets held at June 30	$	11.5	$	(9.3	)

24

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

	Six Months Ended June 30,
(In millions)	2010		2009
Balance at January 1	$	96.2	$	189.8
Total realized and unrealized gains (losses):
Included in earnings, in operating revenues		23.9		(102.1	)
Included in regulatory assets or liabilities		12.5		(50.8	)
Purchases, issuances and settlements		109.1		213.6
Transfers in / out of Level 3		0		0
Balance at June 30	$	241.7	$	250.5
Amount of total gains (losses) included in earnings attributable to the change in unrealized gains (losses) related to Level 3 assets held at June 30	$	11.5	$	(9.3	)

There were no transfers between Level 1 and Level 2, and no transfers into or out of Level 3, of the fair value hierarchy for the six months ended June 30, 2010. To the extent that Allegheny has transfers between these levels, Allegheny accounts for the transfers at the end of the reporting period.

The volume and expiration of Allegheny’s derivative contracts at June 30, 2010 that did not qualify under the normal purchase or normal sale exemption were as follows:

(In millions)	2010		2011		2012		2013		Total
Electricity contracts (MWh):
Forward and future sales of power		1.9		7.7		2.4		0		12.0
Forward and future purchases of power		0.5		0.1		0.6		0		1.2
FTRs (MWh)		32.5		26.7		0		0		59.2
Gas contracts—Kern River (decatherms):
Forward and future sales of gas		13.8		0		0		0		13.8
Forward and future purchases of gas		14.4		0		0		0		14.4
Interest rate swaps (notional dollars):
Interest rate swap agreements (fixed rate to floating rate)	$	143.0	$	200.0	$	0	$	0	$	343.0
Interest rate swap agreements (floating rate to fixed rate)	$	143.0	$	200.0	$	0	$	0	$	343.0

Allegheny enters into derivative contracts for the sale or purchase of power to hedge the variable price risks related to forecasted sales or purchases of power. To the extent that such contracts qualify and are designated as cash flow hedging instruments, the effective portion of unrealized gain or loss on the derivative contract is reported as a component of OCI and is subsequently reclassified into earnings in the period during which the hedged forecasted transaction affects earnings. Changes in the fair value of derivative power contracts that are not qualifying cash flow hedge instruments are reported in revenues on a mark-to-market basis.

Allegheny entered into derivative contracts for the forward purchase and sale of gas to hedge a portion of the value of a capacity contract related to the Kern River pipeline that do not qualify for cash flow hedge accounting. Interest rate swaps at June 30, 2010 include three interest rate swap agreements with an aggregate notional value of $343 million that were entered into during 2003 to substantially offset three existing interest rate swaps with the same counterparty. The 2003 agreements effectively locked in a net liability and substantially eliminated future income volatility from the interest rate swap positions but do not qualify for cash flow hedge accounting.

25

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

Allegheny also holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with Allegheny’s load obligations. These future obligations are not reflected on Allegheny’s Consolidated Balance Sheets, and the FTRs have not been designated as cash flow hedge instruments. As a result, the timing of recognition of gains or losses on FTRs will differ from the timing of power purchases, including incurred congestion charges. Allegheny acquires its FTRs in an annual auction through a self-scheduling process involving the use of auction revenue rights (“ARRs”) allocated to members of PJM that have load serving obligations. Allegheny initially records FTRs and an FTR obligation payable to PJM at the annual FTR auction price, 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 Allegheny’s unregulated subsidiaries are included in operating revenues as unrealized gains or losses. Unrealized gains or losses on FTRs held by Allegheny’s regulated subsidiaries are recorded as regulatory assets or liabilities.

Derivative contracts that have been designated as normal purchases or normal sales are not subject to mark-to-market accounting treatment, and their effects are included in earnings at the time of contract performance.

The recorded fair values of derivatives at June 30, 2010 were as follows:

	Power Contracts						Gas Contracts -Kern River			Interest Rate Swaps			FTRs		Gross Derivatives			Netting			Net Derivatives			FTR Obligation (a)			Collateral			Balance Sheet Derivatives
(In millions)	Sales			Purchases
Derivatives designated as hedging instruments:
Derivative assets:
Current	$	17.0		$	0		$	0		$	0		$	0	$	17.0		$	(6.7	)	$	10.3		$	0		$	0		$	10.3
Long-term		9.7			0			0			0			0		9.7			(5.9	)		3.8			0			0			3.8
Total derivative assets		26.7			0			0			0			0		26.7			(12.6	)		14.1			0			0			14.1
Derivative liabilities:
Current		(3.4	)		0			0			0			0		(3.4	)		6.0			2.6			0			0			2.6
Long-term		(4.8	)		0			0			0			0		(4.8	)		3.5			(1.3	)		0			4.2			2.9
Total derivative liabilities		(8.2	)		0			0			0			0		(8.2	)		9.5			1.3			0			4.2			5.5
Total designated		18.5			0			0			0			0		18.5			(3.1	)		15.4			0			4.2			19.6
Derivatives not designated as hedging instruments:
Derivative assets:
Current		3.3			0			19.6			0			241.7		264.6			(8.1	)		256.5			(241.7	)		(12.5	)		2.3
Long-term		0.1			0			0			0			0		0.1			0.1			0.2			0			0			0.2
Total derivative assets		3.4			0			19.6			0			241.7		264.7			(8.0	)		256.7			(241.7	)		(12.5	)		2.5
Derivative liabilities:
Current		(5.5	)		(5.9	)		(3.5	)		(4.1	)		0		(19.0	)		8.8			(10.2	)		0			0			(10.2	)
Long-term		(2.1	)		(7.7	)		0			(1.0	)		0		(10.8	)		2.3			(8.5	)		0			0			(8.5	)
Total derivative liabilities		(7.6	)		(13.6	)		(3.5	)		(5.1	)		0		(29.8	)		11.1			(18.7	)		0			0			(18.7	)
Total not designated		(4.2	)		(13.6	)		16.1			(5.1	)		241.7		234.9			3.1			238.0			(241.7	)		(12.5	)		(16.2	)
Total derivatives	$	14.3		$	(13.6	)	$	16.1		$	(5.1	)	$	241.7	$	253.4		$	0		$	253.4		$	(241.7	)	$	(8.3	)	$	3.4

(a) The FTR obligation at June 30, 2010 was $243.7 million and is payable to PJM in approximately equal weekly amounts beginning June 1, 2010 through the PJM planning year ending May 31, 2011. Of this obligation, $241.7 million has been netted against the FTR derivative asset balance and the remaining $2.0 million is included in non-derivative current liabilities on the consolidated balance sheet.

26

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

The recorded fair values of derivatives at December 31, 2009 were as follows:

	Power Contracts						Gas Contracts -Kern River			Interest Rate Swaps			FTRs		Gross Derivatives			Netting			Net Derivatives			FTR Obligation (a)			Collateral			Balance Sheet Derivatives
(In millions)	Sales			Purchases
Derivatives designated as hedging instruments:
Derivative assets:
Current	$	0.3		$	0		$	0		$	0		$	0	$	0.3		$	(0.3	)	$	0		$	0		$	0		$	0
Long-term		0.6			0			0			0			0		0.6			(0.6	)		0			0			0			0
Total derivative assets		0.9			0			0			0			0		0.9			(0.9	)		0			0			0			0
Derivative liabilities:
Current		(12.1	)		(4.8	)		0			0			0		(16.9	)		(1.4	)		(18.3	)		0			0.1			(18.2	)
Long-term		(1.5	)		(5.9	)		0			0			0		(7.4	)		(0.3	)		(7.7	)		0			3.0			(4.7	)
Total derivative liabilities		(13.6	)		(10.7	)		0			0			0		(24.3	)		(1.7	)		(26.0	)		0			3.1			(22.9	)
Total designated		(12.7	)		(10.7	)		0			0			0		(23.4	)		(2.6	)		(26.0	)		0			3.1			(22.9	)
Derivatives not designated as hedging instruments:
Derivative assets:
Current		0.9			0			44.4			0			96.2		141.5			(13.2	)		128.3			(96.2	)		(27.5	)		4.6
Long-term		0			0			0			0			0		0			0			0			0			0			0
Total derivative assets		0.9			0			44.4			0			96.2		141.5			(13.2	)		128.3			(96.2	)		(27.5	)		4.6
Derivative liabilities:
Current		(0.9	)		(1.7	)		(12.4	)		(6.1	)		0		(21.1	)		14.9			(6.2	)		0			0			(6.2	)
Long-term		0			(0.9	)		0			(2.0	)		0		(2.9	)		0.9			(2.0	)		0			0			(2.0	)
Total derivative liabilities		(0.9	)		(2.6	)		(12.4	)		(8.1	)		0		(24.0	)		15.8			(8.2	)		0			0			(8.2	)
Total not designated		0			(2.6	)		32.0			(8.1	)		96.2		117.5			2.6			120.1			(96.2	)		(27.5	)		(3.6	)
Total derivatives	$	(12.7	)	$	(13.3	)	$	32.0		$	(8.1	)	$	96.2	$	94.1		$	0		$	94.1		$	(96.2	)	$	(24.4	)	$	(26.5	)

(a) The FTR obligation at December 31, 2009 was $127.9 million and was payable to PJM in approximately equal weekly amounts through the PJM planning year ending May 31, 2010. Of this obligation, $96.2 million has been netted against the FTR derivative asset balance and the remaining $31.7 million is included in non-derivative current liabilities on the consolidated balance sheet.

27

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

The following table provides details on the changes in accumulated other comprehensive income (“OCI”) relating to derivative assets and liabilities that qualified for cash flow hedge accounting:

	Three Months Ended June 30,
(In millions)	2010			2009
Accumulated OCI derivative gain at April 1 (before tax effect of $18.2 million and $31.1 million, respectively)	$	47.1		$	80.2
Effective portion of changes in fair value (before tax effect of $(14.7) million and $3.5 million, respectively)		(38.0	)		9.2
Reclassifications of (gains) losses from accumulated OCI to earnings (before tax effect of $1.4 million and $(12.0) million, respectively)		3.5			(30.7	)
Accumulated OCI derivative gain at June 30 (before tax effect of $4.9 million and $22.6 million, respectively)	$	12.6		$	58.7

	Six Months Ended June 30,
(In millions)	2010			2009
Accumulated OCI derivative gain (loss) at January 1 (before tax effect of $(10.7) million and $17.7 million, respectively)	$	(27.6	)	$	45.8
Effective portion of changes in fair value (before tax effect of $14.3 million and $16.8 million, respectively)		36.9			43.4
Reclassifications of (gains) losses from accumulated OCI to earnings (before tax effect of $1.3 million and $(11.9) million, respectively)		3.3			(30.5	)
Accumulated OCI derivative gain at June 30 (before tax effect of $4.9 million and $22.7 million, respectively)	$	12.6		$	58.7

Derivative gains included in accumulated OCI in the amount of $8.2 million, before tax, are expected to be reclassified to earnings over the next twelve months.

The following table shows the location and amounts of gains (losses) relating to derivative assets and liabilities that qualified for cash flow hedge accounting:

	Three Months Ended June 30,					Six Months Ended June 30,
(In millions)	2010			2009		2010			2009
Gain (loss) recognized in OCI (effective portion)	$	(38.0	)	$	9.2	$	36.9		$	43.4
Gains (losses) reclassified from accumulated OCI into operating revenues (effective portion)	$	(3.5	)	$	30.7	$	(3.3	)	$	30.5
Gain (loss) recognized in operating revenues (ineffective portion)	($	7.0	)	$	1.4	$	(12.2	)	$	(1.7	)

28

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

Unrealized gains (losses) on derivative instruments not designated or qualifying as cash flow hedge instruments were as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2010			2009			2010			2009
Recorded in operating revenues:
Interest rate swaps	$	0		$	(0.1	)	$	3.0		$	3.0
Mark-to-market power contracts		(1.3	)		(0.9	)		(1.2	)		(7.3	)
Gas contracts—Kern River		(10.1	)		(2.4	)		(15.9	)		18.0
FTRs		15.0			6.3			15.1			27.5
Recorded in fuel expense:
Coal purchase contracts—PRB		0			(1.8	)		0			(3.9	)
Recorded in regulatory liabilities (assets):
FTRs		7.9			2.7			7.9			13.0
Coal purchase contracts—PRB		0			(2.0	)		0			(3.9	)
Total	$	11.5		$	1.8		$	8.9		$	46.4

Credit Related Contingent Features

Certain of Allegheny’s derivative contracts contain collateral posting requirements tied to its credit ratings that would require posting of additional collateral in the event of a credit rating downgrade. The aggregate fair value of derivative contracts that were in a liability position, disregarding any contractual netting arrangements, at June 30, 2010 was $11.5 million, for which Allegheny had posted $1.8 million collateral. A one level downgrade in AE Supply’s senior unsecured credit rating at June 30, 2010 would have required the posting of a total of $9.1 million of additional collateral for such derivative contracts in a liability position. A downgrade in AE Supply’s senior unsecured credit rating at June 30, 2010 to below Standard & Poor’s BB- or Moody’s Ba3 would have required the posting of a total of $13.1 million of additional collateral for such derivative contracts in a liability position.

Credit Exposure

Allegheny and its subsidiaries have credit exposure to energy trading counterparties. The majority of these exposures are the fair value of multi-year contracts for energy sales and purchases. If these counterparties fail to perform their obligations under such contracts, Allegheny and its subsidiaries would experience lower revenues or higher costs to the extent that replacement sales or purchases could not be made at the same prices as those under the defaulted contracts.

Allegheny’s wholesale credit risk is the replacement cost for outstanding contracts and amounts owed to or due from counterparties for completed transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses in circumstances in which Allegheny has a legally enforceable right of setoff. Allegheny and its subsidiaries have credit policies to manage credit risk, including the use of an established credit approval process, daily monitoring of counterparty positions and the use of master netting agreements. These agreements include credit mitigation provisions, such as margin, prepayment or other form of collateral acceptable to the counterparty. Allegheny may request additional credit assurance in the event that a counterparty’s credit ratings fall below investment grade or its exposures exceed an established credit limit.

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(unaudited)

NOTE 11: STOCK-BASED COMPENSATION

The following table summarizes stock-based compensation expense included in operations and maintenance expenses:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2010		2009		2010		2009
Performance shares	$	3.7	$	2.5	$	5.7	$	4.1
Stock options		1.2		2.3		2.7		4.0
Non-employee director stock awards		0.2		0.2		0.4		0.4
Restricted shares		0		0		0.1		0
Stock units		0		0		0		0.1
Total stock-based compensation expense		5.1		5.0		8.9		8.6
Income tax benefit		2.1		2.0		3.6		3.5
Total stock-based compensation expense, net of tax	$	3.0	$	3.0	$	5.3	$	5.1

Stock-based compensation expense recognized in the Consolidated Statements of Income is based on awards ultimately expected to vest, using an estimated annual forfeiture rate of 5%. No stock-based compensation cost was capitalized during the six months ended June 30, 2010 and 2009.

Stock Options

Allegheny records compensation expense for employee stock options based on the estimated fair value of the options on the date of grant under the Black-Scholes option-pricing model. No stock options were granted during the three and six months ended June 30, 2010. The following were the weighted-average assumptions for stock options granted during the three and six months ended June 30, 2009:

	Three Months Ended June 30, 2009			Six Months Ended June 30, 2009
Annual risk-free interest rate		3.46	%		2.86	%
Expected term of the option (in years)		6.00			6.00
Expected annual dividend yield		2.30	%		2.53	%
Expected stock price volatility		35.0	%		36.4	%
Grant date fair value per stock option	$	8.08		$	7.14

The annual risk-free interest rate is based on the United States Treasury yield curve at the date of the grant for a period equal to the expected term of the options granted. The expected term for the 2009 stock option grants was calculated using the “simplified” method. AE used the simplified method for its calculation of expected term due to its lack of sufficient historical exercise data to provide a reasonable basis upon which to estimate expected term and because AE has granted stock options in prior years with varying vesting terms, which also made it difficult to evaluate historical exercise data. The expected annual dividend yield assumption was based on AE’s current dividend rate at the time of each grant. For stock options granted during 2009, the expected stock price volatility was based on both historical stock volatility and the volatility levels implied on the grant date by actively traded option contracts on AE’s common stock.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

Stock option activity during the three and six months ended June 30, 2010 was as follows:

	Stock Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (in millions)
Outstanding at March 31, 2010	2,845,717		$	27.63
Exercised (a)	(33,702	)	$	13.35
Forfeited	(5,078	)	$	29.12
Outstanding at June 30, 2010	2,806,937		$	27.80	$	5.2	(b)
Exercisable at June 30, 2010	1,773,595		$	26.71	$	5.2	(b)

	Stock Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (in millions)
Outstanding at December 31, 2009	2,852,942		$	27.62
Exercised (a)	(39,102	)	$	13.35
Forfeited/Expired	(6,903	)	$	35.61
Outstanding at June 30, 2010	2,806,937		$	27.80	$	5.2	(b)
Exercisable at June 30, 2010	1,773,595		$	26.71	$	5.2	(b)

(a) Proceeds to AE from stock option exercises were $0.4 million and $0.5 million for the three and six months ended June 30, 2010. AE issued new shares of its common stock to satisfy these stock option exercises.

(b) Represents the total pre-tax intrinsic value based on the difference between the exercise price of stock options that have an exercise price lower than AE’s closing stock price and AE’s closing stock price of $20.68 on June 30, 2010.

As of June 30, 2010, Allegheny had approximately $4.3 million of unrecognized compensation cost related to non-vested outstanding stock options, which is expected to be recognized over a weighted-average period of approximately 1.6 years.

At June 30, 2010, Allegheny had approximately $63.0 million in excess tax benefits related to share based awards that had not yet been credited to other paid-in capital because of Allegheny’s federal income tax net operating loss carryforward position. During the six months ended June 30, 2009, Allegheny recorded a credit to other paid-in capital in the amount of approximately $19.7 million representing estimated share-based excess income tax benefits to be realized during 2009. This credit to other paid-in capital was reversed during the third quarter of 2009 as a result of a change in estimated taxable income.

Performance Shares

AE has granted equity-based performance shares to key employees pursuant to which award recipients may earn shares of AE common stock based on AE’s Total Shareholder Return (“TSR”) and AE’s performance with respect to its Annual Incentive Plan (“AIP”) goals.

For performance shares linked to TSR, the TSR of AE’s common stock is compared to the TSR of the companies in the Dow Jones U.S. Electric Utilities Index over a three-year performance period. Based upon AE’s percentile rank within the peer group, shares earned can range from 0% to 250% of each participant’s target

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

award. The grant date fair value will be recognized as compensation expense over the requisite service period on a straight-line basis for awards ultimately expected to vest, using an estimated annual forfeiture rate of 5%. At June 30, 2010, AE had 242,432 target performance shares linked to TSR outstanding. As of June 30, 2010, there was approximately $1.7 million of unrecognized compensation cost related to non-vested outstanding performance shares linked to TSR, which is expected to be recognized over a weighted average period of approximately 1.3 years. No performance shares linked to TSR were granted in 2010.

For performance shares linked to AE’s AIP goals, the number of AE common shares to be earned and distributed is based on AE’s performance compared to annual performance targets for a three-year period. The annual performance targets are established at the beginning of each individual year. Compensation expense is recognized over the remaining portion of the three-year performance period as if the awards were separate annual awards, using an estimated annual forfeiture rate of 5%. The percentage of target shares earned can range from 0% to 200%. Activity in target performance shares linked to the AIP for the three and six months ended June 30, 2010 was as follows:

	Number of Shares
Performance shares outstanding at March 31, 2010	1,008,059
Forfeited	(5,220	)
Performance shares outstanding at June 30, 2010	1,002,839

	Number of Shares
Performance shares outstanding at December 31, 2009	244,010
Granted	764,049
Forfeited	(5,220	)
Performance shares outstanding at June 30, 2010	1,002,839

As of June 30, 2010, there was approximately $9.9 million of unrecognized compensation cost related to non-vested outstanding performance shares linked to the AIP relating to performance goals, which is expected to be recognized over a weighted average period of approximately 1.4 years.

Non-Employee Director Stock Awards

Non-employee director stock awards activity for the three and six months ended June 30, 2010 was as follows:

	Number of Shares
Shares earned but not issued at March 31, 2010	93,243
Granted	9,000
Issued	(3,000	)
Dividends on earned but not issued shares	633
Shares earned but not issued at June 30, 2010	99,876

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

	Number of Shares
Shares earned but not issued at December 31, 2009	86,689
Granted	18,000
Issued	(6,000	)
Dividends on earned but not issued shares	1,187
Shares earned but not issued at June 30, 2010	99,876

Restricted Shares

As of June 30, 2010, Allegheny had 11,900 non-vested restricted shares outstanding. These shares had approximately $0.2 million of unrecognized compensation cost, which is expected to be recognized over a weighted average period of approximately 1.5 years.

Change in Control

Employee stock options and other stock-based employee awards granted prior to the execution of the Merger Agreement become fully vested and exercisable upon a change in control. Approval by Allegheny’s stockholders of Allegheny’s proposed Merger with FirstEnergy would constitute a change in control under the relevant stock-based compensation plan provisions. Performance shares granted after execution of the Merger Agreement generally vest over three years, and such vesting will not be accelerated upon either stockholder approval of the Merger Agreement or completion of the Merger. See Note 2, “Merger Agreement,” for additional information.

NOTE 12: PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

Substantially all of Allegheny’s personnel, including officers, are employed by AESC and are covered by a noncontributory, defined benefit pension plan. Allegheny also maintains a Supplemental Executive Retirement Plan (the “SERP”) for executive officers and other senior executives.

Allegheny also provides subsidies for medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the postretirement benefits other than pensions, have retiree premiums based upon an age and years-of-service vesting schedule, include other plan provisions that limit future benefits and take into account certain collective bargaining arrangements. Subsidized medical coverage is not provided in retirement to employees hired on or after January 1, 1993, with the exception of certain union employees who were hired or became members before May 1, 2006. The provisions of the postretirement health care plans and certain collective bargaining arrangements limit Allegheny’s costs for eligible retirees and dependents.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

The components of the net periodic cost for pension benefits for employees and covered dependents by Allegheny were as follows:

	Pension Benefits
	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2010			2009			2010			2009
Components of net periodic cost:
Service cost	$	6.6		$	5.6		$	13.1		$	11.1
Interest cost		17.9			17.7			35.8			35.5
Expected return on plan assets		(18.5	)		(18.5	)		(36.9	)		(37.1	)
Amortization of unrecognized transition obligation		0.1			0.1			0.2			0.2
Amortization of prior service cost		0.8			0.8			1.6			1.6
Recognized actuarial loss		4.6			2.8			9.1			5.6
Net periodic cost	$	11.5		$	8.5		$	22.9		$	16.9

The components of the net periodic cost for postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents by Allegheny were as follows:

	Postretirement Benefits Other than Pensions
	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2010			2009			2010			2009
Components of net periodic cost:
Service cost	$	1.1		$	1.1		$	2.1		$	2.2
Interest cost		3.9			4.3			7.8			8.5
Expected return on plan assets		(1.5	)		(1.3	)		(3.0	)		(2.6	)
Amortization of unrecognized transition obligation		1.4			1.4			2.9			2.8
Recognized actuarial loss		0			0.5			0			1.0
Net periodic cost	$	4.9		$	6.0		$	9.8		$	11.9

For the three months ended June 30, 2010 and 2009, Allegheny capitalized $5.0 million and $4.4 million, respectively, and for the six months ended June 30, 2010 and 2009, Allegheny capitalized $9.8 million and $8.7 million, respectively, of the above net periodic cost amounts to CWIP a component of “Property, plant and equipment, net.”

During the first quarter of 2010, Allegheny determined that its benefit obligation of $264.2 million at December 31, 2009 for postretirement benefits other than pensions was understated by approximately $14.9 million. Allegheny increased its recorded benefit obligation for this matter during the first quarter of 2010, and recorded an additional charge to expense of approximately $10.4 million and a charge to CWIP in the amount of approximately $4.5 million.

In March 2010, the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act were signed into law. This legislation effectively changes the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to prescription drug benefits provided under Medicare Part D. Beginning in 2013, an employer’s income tax deduction for the cost of providing Medicare Part D equivalent prescription drug benefits

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

will be reduced by the amount of the federal subsidy. The impact of this change in tax treatment of the federal subsidy did not have a significant impact on Allegheny’s deferred income tax assets or income tax expense because Allegheny expects that the majority of the prescription drug benefits provided under its health benefit plans will not be actuarially equivalent to Medicare Part D benefits for periods after 2011.

Contributions

Allegheny makes cash contributions to its qualified pension plan to meet the minimum funding requirements of employee benefit and tax laws and may make additional discretionary contributions to increase the funded level of the plan. During the six months ended June 30, 2010, Allegheny contributed $0.2 million to its SERP and did not make any contributions to its qualified pension plan. Allegheny made approximately $3.6 million in contributions to its postretirement benefits other than pension plans during the six months ended June 30, 2010. During the remainder of 2010, Allegheny expects to contribute approximately $80.0 million to its qualified pension plan and approximately $2.0 million to fund postretirement benefits other than pensions.

Allegheny made cash-matching contributions to its Employee Stock Ownership and Savings Plan in the amount of $2.1 million and $1.9 million for the three months ended June 30, 2010 and 2009, respectively, and $4.7 million and $4.5 million for the six months ended June 30, 2010 and 2009, respectively. These contributions, less amounts capitalized in CWIP, were expensed. The capitalized portions of these costs were $0.7 million for each of the three months ended June 30, 2010 and 2009, respectively, and $1.4 million and $1.5 million for the six months ended June 30, 2010 and 2009, respectively.

NOTE 13: FINANCIAL INSTRUMENTS

As of June 30, 2010 and December 31, 2009, the carrying amounts of accounts receivable and accounts payable are representative of fair value because of their short-term nature. The carrying amounts and estimated fair values of long-term debt, including long-term debt due within one year, net of unamortized debt discounts of $8.3 million and $7.4 million at June 30, 2010 and December 31, 2009, respectively were as follows:

	June 30, 2010				December 31, 2009
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	4,628.8	$	4,905.0	$	4,557.8	$	4,729.1

The fair value of long-term debt was estimated based on actual market prices or market prices of similar debt issues.

NOTE 14: COMPREHENSIVE INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS

Comprehensive income consisted of the following:

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2010			2009			2010		2009
Net income	$	120.2		$	72.9		$	208.4	$	207.0
Other comprehensive income (loss), net of tax:
Cash flow hedges, net of tax of $(13.3), $(8.5), $15.6 and $4.9, respectively		(21.2	)		(13.0	)		24.5		8.0
Defined benefit pension and other benefit plan amortization, net of tax of $0.6, $0.6, $0.9 and $1.1, respectively		0.8			0.8			1.2		1.7
Comprehensive income		99.8			60.7			234.1		216.7
Less comprehensive income attributable to noncontrolling interest		0			(0.3	)		0		(0.5	)
Comprehensive income attributable to Allegheny Energy, Inc.	$	99.8		$	60.4		$	234.1	$	216.2

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

The components of accumulated other comprehensive loss, included in the shareholders’ equity section of the Consolidated Balance Sheets, were as follows:

(In millions)	June 30, 2010			December 31, 2009
Cash flow hedges, net of tax of $4.9 million and $(10.7) million, respectively	$	7.7		$	(16.8	)
Net unrecognized pension and other benefit plan costs, net of tax of $(48.9) million and $(49.7) million, respectively		(71.9	)		(73.1	)
Total	$	(64.2	)	$	(89.9	)

NOTE 15: EARNINGS PER SHARE

The reconciliation of the basic and diluted earnings per common share calculation is as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions, except share and per share amounts)	2010		2009		2010		2009
Basic Income per Share:
Numerator:
Net income attributable to Allegheny Energy, Inc.	$	120.2	$	72.6	$	208.4	$	206.5
Denominator:
Weighted average common shares outstanding		169,682,482		169,505,918		169,669,967		169,472,787
Basic earnings per share attributable to Allegheny Energy, Inc.	$	0.71	$	0.43	$	1.23	$	1.22
Diluted Income per Share:
Numerator:
Net income attributable to Allegheny Energy, Inc.	$	120.2	$	72.6	$	208.4	$	206.5
Denominator:
Weighted average common shares outstanding		169,682,482		169,505,918		169,669,967		169,472,787
Effect of dilutive securities:
Stock options (a)		279,625		378,173		299,291		392,938
Performance shares		106,008		19,558		100,261		18,378
Stock units		0		4,255		0		4,262
Total shares		170,068,115		169,907,904		170,069,519		169,888,365
Diluted earnings per share attributable to Allegheny Energy, Inc.	$	0.71	$	0.43	$	1.23	$	1.22

(a) The dilutive share calculations exclude 1,971,805 shares and 1,999,148 shares for the three months ended June 30, 2010 and 2009, respectively, and 1,974,096 shares and 1,621,827 shares for the six months ended June 30, 2010 and 2009, respectively, relating to stock options because the inclusion of these amounts would have been antidilutive under the treasury stock method.

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ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

NOTE 16: VARIABLE INTEREST ENTITIES

GAAP requires the primary beneficiary of a Variable Interest Entity (“VIE”) to consolidate the entity and also requires majority and significant variable interest investors to provide certain disclosures. A VIE is an entity in which the equity investors do not have a controlling financial interest or in which the equity investment at risk is insufficient to finance the entity’s activities without receiving subordinated financial support from the other parties.

Independent Power Producer (“IPP”) contracts. Potomac Edison and West Penn each have a long-term electricity purchase contract with unrelated IPPs. Allegheny periodically requests from these IPPs the information necessary to determine whether these entities are VIEs and whether Allegheny is the primary beneficiary. Allegheny has been unable to obtain the requested information, which was determined by the IPPs to be proprietary.

Potomac Edison purchased power from its IPP in the amount of $29.0 million and $15.6 million for the three months ended June 30, 2010 and 2009, respectively, and $60.1 million and $46.0 million for the six months ended June 30, 2010 and 2009, respectively. West Penn purchased power from its IPP in the amount of $9.9 million and $12.7 million for the three months ended June 30, 2010 and 2009, respectively and $18.4 million and $24.0 million for the six months ended June 30, 2010 and 2009, respectively. Neither Potomac Edison nor West Penn is subject to any risk of loss associated with the applicable potential VIE, because neither has any obligation to the applicable IPP other than to purchase the power that the IPP produces according to the terms of the applicable electricity purchase contract.

APS Constellation, LLC (“APS Constellation”). Allegheny Ventures, Inc., a non-utility subsidiary of AE, formed a partnership in 1995 with an unregulated business of Constellation Energy in a joint venture energy services company named APS Constellation. The business purpose of APS Constellation is the marketing, development, and implementation of energy conservation projects. APS Constellation, working under an Engineer/Procure/Construct agreement as a subcontractor for Potomac Edison, completed multiple energy conservation projects for Potomac Edison’s government customers at Ft. Detrick, Maryland. The projects resulted in performance payments and other fees remitted to APS Constellation. APS Constellation securitized the future revenue streams from the projects through several financings and made a partnership distribution of the proceeds. Some of the project financings required Potomac Edison to provide ongoing guarantees. In 2005, the joint venture operating agreement was amended to limit Allegheny’s obligations and participation in APS Constellation. The accounts of APS Constellation are not included in Allegheny’s Consolidated Financial Statements because Allegheny does not have the power to direct activities that most significantly impact APS Constellation’s economic performance.

At June 30, 2010, Allegheny’s maximum exposure to loss related to APS Constellation consisted of a $0.7 million equity investment in APS Constellation, a letter of credit guarantee of $3.1 million and recourse guarantees of $6.2 million. These guarantees are not recorded on Allegheny’s Consolidated Balance Sheet.

PATH WV. As described in Note 1, “Business and Basis of Presentation,” PATH WV is owned equally by Allegheny and AEP. As described in Note 3, “Recently Adopted and Recently Issued Accounting Standards,” Allegheny deconsolidated PATH WV from its financial statements effective January 1, 2010, and accounts for its investment in PATH WV under the equity method. Allegheny and AEP provide certain services to PATH WV and make capital contributions to PATH WV as needed. At June 30, 2010, Allegheny’s consolidated balance sheet included Allegheny’s investment in PATH WV on the equity method of accounting in the amount of $18.3 million. At December 31, 2009, Allegheny’s consolidated balance sheet included property, plant and equipment of PATH WV in the amount of approximately $35.8 million, cash and cash equivalents of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

$3.4 million and noncontrolling interest related to AEP’s ownership of approximately $14.9 million. Allegheny’s consolidated statement of income for the three and six months ended June 30, 2010 included other income of $0.9 million and $1.8 million, respectively, representing Allegheny’s 50% equity in the pre-tax earnings of PATH WV. Allegheny’s consolidated statement of income for the three and six months ended June 30, 2009 included revenues of $2.6 million and $4.5 million, respectively, pretax income of $0.9 million and $1.4 million, respectively and net income attributable to noncontrolling interest of $0.3 million and $0.5 million, respectively.

Allegheny expects to make capital contributions to PATH WV to support its construction projects. Because of the nature of PATH WV’s operations and its FERC-approved rate mechanism, Allegheny’s maximum exposure to loss consists of its advances to, and investment in, PATH WV, which were $0.5 million and $18.3 million, respectively, at June 30, 2010.

Energy Insurance Services, Inc. Allegheny has entered into an insurance arrangement with Energy Insurance Services, Inc. (“EIS”) whereby EIS writes policies for Allegheny in a segregated cell, referred to as Mutual Business Program No. 2 (the “Program”). The Program is governed by a Participation Agreement that limits claims paid on policies that are not reinsured to premium payments made by Allegheny, contributions to surplus and any investment returns on those premiums less expenses. The accounts of EIS are included in Allegheny’s Consolidated Financial Statements because Allegheny is the sole beneficiary of the Program. At June 30, 2010, total assets were $17.7 million, consisting primarily of investments, and total liabilities were $13.4 million, consisting primarily of claim reserves.

NOTE 17: COMMITMENTS AND CONTINGENCIES

Allegheny is involved in a number of significant legal proceedings. In certain cases, plaintiffs seek to recover large and sometimes unspecified damages, and some matters may be unresolved for several years. Allegheny cannot currently determine the outcome of the proceedings described below or the ultimate amount of potential losses. Management provides for estimated losses to the extent that information becomes available indicating that losses are probable and that the amounts are reasonably estimable. Additional losses may have an adverse effect on Allegheny’s results of operations, cash flows and financial condition.

Environmental Matters and Litigation

The operations of Allegheny’s owned facilities, including its generation facilities, are subject to various federal, state and local laws, rules and regulations as to air and water quality, hazardous and solid waste disposal and other environmental matters, some of which may be uncertain. Compliance may require Allegheny to incur substantial additional costs to modify or replace existing and proposed equipment and facilities.

Global Climate Change. The United States relies on coal-fired power plants for more than 45% of its energy. However, coal-fired power plants have come under scrutiny due to their emission of gases implicated in climate change, primarily carbon dioxide, or “CO₂ .”

Allegheny produces approximately 95% of its electricity at coal-fired facilities and currently produces approximately 45 million tons of CO₂ annually through its energy production. While there are many unknowns concerning the final regulation of greenhouse gases in the United States, federal and/or state legislation and implementing regulations addressing climate change, including limits on emissions of CO₂, likely will be adopted some time in the future. Thus, CO ₂ legislation and regulation, if not reasonably designed, could have a significant impact on Allegheny’s operations. The U.S. House of Representatives passed the American Clean Energy and Security Act in June 2009, and the U.S. Senate is still working on a comparable bill. However, the most recent draft

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ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

by Senators Kerry (D-MA) and Lieberman (I-CT), known as the American Power Act, does not currently appear to have the necessary support to pass the Senate. The American Power Act is an economy-wide climate change bill that would employ a sector-by-sector approach, with the electricity sector being subject to a cap and trade program set to be implemented as early as 2013. A bill applying only to electric generation is also being discussed.

Concurrently, the U.S. Environmental Protection Agency (the “EPA”) is moving to regulate greenhouse gas emissions under the Clean Air Act of 1970 (the “Clean Air Act”). On December 7, 2009, the EPA announced its Greenhouse Gas Endangerment Finding, stating that greenhouse gas emissions from cars and light trucks, when mixed in the atmosphere, endanger public health. The finding provides the EPA with a basis on which to regulate greenhouse gas emissions from vehicle tailpipes under the provisions of the Clean Air Act. Once a pollutant is regulated under the Clean Air Act for one source category, the EPA has authority to apply similar regulations to other source categories. On April 1, 2010, the EPA and the Department of Transportation’s National Highway Traffic Safety Administration (“NHTSA”) announced a joint final rule that applies to passenger cars, light-duty trucks and medium-duty passenger vehicles, covering model years 2012 through 2016. Under the Clean Air Act, regulation of greenhouse gas emissions from vehicles also triggers requirements for new and modified stationary sources to control greenhouse gas emissions under the Prevention of Significant Deterioration (“PSD”) program. Regulation of the stationary sources will be implemented through the final version of the “tailoring rule” issued on June 3, 2010. The tailoring rule will become effective on January 2, 2011. For six months, only new and modified sources already required to control emissions of other air pollutants will be required to control greenhouse gas emissions. Beginning July 2, 2011, new sources above 100,000 tons per year and modified existing sources with emissions above 75,000 tons per year will be required to control emissions.

There is a gap between desired reduction levels in the current proposed legislation and the current capabilities of technology; no current commercial-scale technology exists to enable many of the reduction levels in national, regional and state proposals. Such technology may not become available within a timeframe consistent with the implementation of any future climate control legislation or at all. To the extent that such technology does become available, Allegheny can provide no assurance that it will be suitable for installation at Allegheny’s generation facilities on a cost effective basis or at all. Based on estimates from a 2007 Department of Energy National Electric Technology Laboratory report and recently announced projects by other entities, it could cost as much as $5,500 per kW to replace existing coal-based power generation with fossil fuel stations capable of capturing and sequestering CO₂ emissions. However, exact estimates are difficult because of the variance in the legislative proposals and the current lack of deployable technology.

Regardless of the eventual mechanism for limiting CO₂ emissions, compliance will be a major and costly challenge for Allegheny, its customers and the region in which it operates. Most notable will be the potential impact on customer bills and disproportionate increases in energy cost in areas that have built their energy and industrial infrastructure over the past century based on coal-fired electric generation.

Because the legislative process and applicable technology each is in its infancy, it is difficult for Allegheny to aggressively implement greenhouse gas emission expenditures until the exact nature and requirements of any regulation are known and the capabilities of control or reduction technologies are more fully understood. Allegheny’s current strategy in response to climate change initiatives focuses on:

• maintaining an accurate CO₂ emissions database;

• improving the efficiency of its existing coal-burning generation facilities;

• following developing technologies for clean-coal energy and for CO₂ emission controls at coal-fired power plants, including carbon sequestration;

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• analyzing options for future energy investment (e.g. , renewables, clean-coal, etc.); and

• improving demand-side efficiency programs, as evidenced by customer conservation outreach plans and Allegheny’s Watt Watchers initiatives.

Allegheny’s energy portfolio also includes approximately 1,180 MWs of renewable hydroelectric and pumped storage power generation. Allegheny obtained a permit to allow for a limited use of bio-mass (wood chips and saw dust) at one of its coal-fired power stations in West Virginia and currently has approval to use waste-tire derived fuel at another of its coal-based power stations in West Virginia.

Allegheny is participating in the dialogue that will shape the regulatory landscape surrounding CO₂ emissions. Additionally, Allegheny intends to pursue proven and cost-effective measures to manage its emissions while maintaining an affordable and reliable supply of electricity for its customers.

Clean Air Act Compliance and State Air Quality Initiatives. Allegheny currently meets applicable standards for particulate matter emissions at its generation facilities through the use of high-efficiency electrostatic precipitators, cleaned coal, flue-gas conditioning, optimization software, fuel combustion modifications and, at times, through other means. From time to time, minor excursions of stack emission opacity that are normal to fossil fuel operations are experienced and are accommodated by the regulatory process.

Allegheny’s compliance with the Clean Air Act has required, and may require in the future, that Allegheny install control technologies on many of its generation facilities at significant cost. The proposed Clean Air Transport Rule (“CATR”) released by the EPA on July 6, 2010 may accelerate the need to install this equipment by phasing out a portion of the currently available allowances, limiting trading and accelerating federal emission reduction goals. The proposed CATR replaces certain portions of the Clean Air Interstate Rule that were invalidated by the U.S. Court of Appeals for the District of Columbia Circuit.

On March 15, 2005, the EPA issued the Clean Air Mercury Rule (“CAMR”), establishing a cap and trade system designed to reduce mercury emissions from coal-fired power plants. On February 8, 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the rule in its entirety. The State of West Virginia subsequently suspended its rule for implementing CAMR. Pennsylvania and Maryland, however, took the position that their mercury rules, which are discussed below, survived this ruling. In addition, the EPA has announced plans to propose a new maximum achievable control technology rule for hazardous air pollutant emissions from electric utility steam generating units in the first half of 2011. The EPA plans to finalize the new rule by November 2011. Allegheny is monitoring the EPA’s efforts to promulgate hazardous air pollutant rules that will include, but will not be limited to, mercury limits. To establish these standards, the EPA must identify the best performing 12% of sources in each source category and, to that end, has issued an information request to members of the fossil fuel-fired generating industry that includes a requirement to conduct extensive stack emissions testing on selected generating units. Allegheny is required to conduct stack testing for eight of its generating units. Depending on the final hazardous air pollution limits set by the EPA, Allegheny could incur significant costs for additional control equipment.

The Pennsylvania Department of Environmental Protection (the “PA DEP”) promulgated a more aggressive mercury control rule in February 2007; however, in December 2009, the Pennsylvania Supreme Court affirmed a Commonwealth Court’s holding that the rule is invalid.

Additionally, Maryland passed the Healthy Air Act in early 2006. This legislation imposes state-wide emission caps on SO₂ and NO_x, requires greater reductions in mercury emissions more quickly than required by CAMR and mandates that Maryland join the Regional Greenhouse Gas Initiative (“RGGI”) and participate in

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that coalition’s regional efforts to reduce CO₂ emissions. On April 20, 2007, Maryland’s governor signed on to RGGI, as a result of which Maryland became the 10th state to join the Northeast regional climate change and energy efficiency program. The Healthy Air Act provides a conditional exemption for the R. Paul Smith power station for NO_x, SO₂ and mercury, based on a PJM declaration that the station is vital to reliability in the Baltimore/Washington DC metropolitan area, which PJM determined in 2006. Pursuant to the legislation, the Maryland Department of the Environment (the “MDE”) passed alternate NO_x and SO₂ limits for R. Paul Smith, which became effective in April 2009. However, R. Paul Smith is still required to meet the Healthy Air Act mercury reductions of 80% beginning in 2010. The statutory exemption does not extend to R. Paul Smith’s CO₂ emissions. Maryland issued final regulations to implement RGGI requirements in February 2008. Among other things, under RGGI, the MDE now auctions 100% of CO₂ allowances associated with Maryland’s power plants, and Allegheny is participating in RGGI auctions. Through the second quarter of 2010, eight RGGI auctions have been held. RGGI allowances are also readily available in the allowance markets, affording another mechanism by which to secure necessary allowances.

AE Supply and Monongahela comply with current SO₂ emission standards through a system-wide plan, combining the use of emission controls, low sulfur fuel and emission allowances. Allegheny continues to evaluate and implement options for compliance. It completed the elimination of a partial bypass of Scrubbers at its Pleasants generation facility in December 2007 and the construction of Scrubbers at its Hatfield’s Ferry and Fort Martin generating facilities in 2009. Allegheny now has Scrubbers installed and operating on all ten of the units at its four supercritical generating facilities and at Mitchell Unit 3.

Allegheny’s NO_x compliance plan functions on a system-wide basis, similar to its SO₂ compliance plan. Pending finalization of the CATR, AE Supply and Monongahela also have the option, in some cases, to purchase alternate fuels or NO_x allowances, if needed, to supplement their compliance strategies. Allegheny currently has installed selective non-catalytic reduction equipment at its Fort Martin and Hatfield’s Ferry generating stations and selective catalytic reduction equipment at its Harrison and Pleasants generating stations, together with other NO_x controls at these supercritical generating facilities, as well as its other generating facilities.

On January 8, 2010, the West Virginia Department of Environmental Protection (“WVDEP”) issued a Notice of Violation for opacity emissions at Allegheny’s Pleasants generating facility. Allegheny is evaluating certain control system options for opacity reduction. Although a system has not yet been selected, the cost to install any such system could be significant.

Clean Water Act Compliance. In 2004, the EPA issued a final rule requiring all existing power plants with once-through cooling water systems withdrawing more than 50 million gallons of water per day to meet certain standards to reduce mortality of aquatic organisms pinned against the water intake screens or, in some cases, drawn through the cooling water system. The standards varied based on the type and size of the water bodies from which the plants draw their cooling water.

In January 2007, the Second Circuit Court of Appeals issued a decision on appeal that remanded a significant portion of the rule to the EPA. As a result, the EPA suspended the rule, except for a requirement, which existed prior to the EPA’s adoption of the 2004 rule, that permitting agencies use best professional judgment (“BPJ”) to determine the best technology available for minimizing adverse environmental impacts for existing facility cooling water intakes. Pending re-issuance of the 2004 rule by the EPA, permitting agencies thus will rely on BPJ determinations during permit renewal at existing facilities.

On April 1, 2009, the U.S. Supreme Court reversed the appeals court decision and upheld EPA’s authority to use cost/benefit analysis. The EPA has indicated that it plans to issue a proposed rule addressing the issues

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remanded by the Court by mid-2010 and to issue a final rule in 2012. Depending on the standards set by the EPA when it reissues this rule, Allegheny could incur significant costs for additional control equipment.

Monongahela River Water Quality. In late 2008, the PA DEP imposed water quality criteria for certain effluents, including total dissolved solid (“TDS”) and sulfate concentrations in the Monongahela River, on new and modified sources, including the Scrubber project at the Hatfield’s Ferry generation facility. These criteria are reflected in the current PA DEP water discharge permit for that project. AE Supply has appealed the PA DEP’s permitting decision, which would require it to incur significant costs or negatively affect its ability to operate the Scrubbers as designed. Preliminary studies indicate an initial capital investment of approximately $62 million in order to install technology to meet the TDS and sulfate limits in the permit. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council who seek to impose more stringent technology-based effluent limitations. Those same parties have intervened in the appeal filed by AE Supply, and both appeals have been consolidated for discovery purposes. An order has been entered that stays the permit limits that AE Supply has challenged while the appeal is pending. No hearing date has been set. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals. On November 7, 2009, the PA DEP published proposed amendments to the PA Chapter 95 rules that include an end-of-pipe limit for TDS for new and modified sources. The PA DEP’s proposed rule was open for public comment until February 12, 2010. The PA DEP issued a final rule on April 30, 2010, and the Pennsylvania Environmental Quality Board authorized the final rule on May 17, 2010. The PA DEP expects to issue the final rule by the end of August 2010. Allegheny could incur significant costs for additional control equipment to meet the requirements of this rule, although its provisions do not apply to electric generating units until the end of 2018, and then only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.

In October 2009, the WVDEP issued the water discharge permit for the Fort Martin generation facility. Similar to the Hatfield’s Ferry water discharge permit issued for the Scrubber project, the Fort Martin permit imposes effluent limitations for TDS and sulfate concentrations. The permit also imposes temperature limitations and other effluent limits for heavy metals that are not contained in the Hatfield’s Ferry water permit. Concurrent with the issuance of the Fort Martin permit, WVDEP also issued an administrative order that sets deadlines for Monongahela to meet certain of the effluent limits that are effective immediately under the terms of the permit. Monongahela has appealed the Fort Martin permit and the administrative order. The appeal includes a request to stay certain of the conditions of the permit and order while the appeal is pending. The request to stay has been granted pending a final decision on appeal and subject to WVDEP moving to dissolve the stay. The appeals have been consolidated and a hearing has been scheduled for August 2010. The current terms of the Fort Martin permit would require Monongahela to incur significant costs or negatively impact operations at Fort Martin. Preliminary information indicates an initial capital investment in excess of the capital investment that may be needed at Hatfield’s Ferry in order to install technology to meet the TDS and sulfate limits in the Fort Martin permit, which technology may also meet certain of the other effluent limits in the permit. Additional technology may be needed to meet certain other limits in the permit. Monongahela intends to vigorously pursue these issues but cannot predict the outcome of these appeals.

Solid Waste. The EPA is reviewing its waste regulations relating to coal combustion residuals (“CCR”) partly in response to a Tennessee Valley Authority ash spill in Kingston, Tennessee in December 2008. CCR includes bottom ash, boiler slag, fly ash and Scrubber byproducts including gypsum. CCR has historically been designated and managed as a non-hazardous waste, and the EPA has twice determined that it is not appropriate to regulate it as a hazardous waste under the Resource Conservation and Recovery Act (“RCRA”). The EPA is reconsidering those earlier determinations and intends to issue new regulations for the management and disposal of CCR in 2010. The EPA has not yet reached a final decision on whether to regulate CCR as a hazardous or

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special waste (RCRA Title C) or as a non-hazardous waste (RCRA Title D) and on May 4, 2010 released a draft proposed rule which contained both options for public comment. Should the EPA elect to designate CCR as hazardous or special waste at any point in its generation, storage, transportation or disposal cycle, it could significantly increase Allegheny’s cost of managing CCR materials and could also drive additional monitoring and corrective action at legacy disposal sites. In addition to potential additional management costs for CCR disposal, Allegheny might expect to see a reduction in options for beneficial reuse of CCR in applications such as mine reclamation, cement manufacture and agriculture, further increasing costs, as such materials will then enter landfills rather than beneficial reuse. While EPA’s proposed rule appears to attempt to protect beneficial CCR reuse whatever the CCR designation, we are still reviewing the rule and assessing its effect on Allegheny in that regard. The proposed rule also provides options for the management and closure of wet CCR storage and disposal impoundments. Even if EPA elects the non-hazardous CCR option in a final rule, reducing Allegheny’s potential waste management exposure, closure of wet disposal impoundments could be a source of significant costs. Allegheny is assessing the draft proposal and working with various trade groups and associations to determine potential costs and effects under either CCR option.

Potential Impact of Recent EPA and Climate Change Initiatives. Implementation of the EPA’s current proposals with regard to air quality, water quality and CCR, as described above, would, together with potential climate change legislation, require extensive and costly changes to the nation’s electric generation fleet, including the installation of new pollution controls, retirement of many existing generating facilities and construction of new generating capacity. Some industry participants have estimated that, if implementation of these initiatives proceeds according to currently proposed schedules, the combined national cost, through 2015, associated with required retrofitting of existing facilities and construction of new facilities could be as high as $400 billion. Additionally, it is estimated that nearly 25% of the nation’s existing coal-fired generation capacity may be retired. While these estimates are based on complex models incorporating many variables and assumptions and are thus highly subject to change, it is clear that timely compliance would be challenging and require very significant investment, both at the industry level and for Allegheny, which could be required to install a variety a additional pollution controls at a number of its generating facilities and could be compelled to retire certain of its subcritical facilities.

Clean Air Act Litigation. In August 2000, AE received a letter from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten electric generation facilities, which collectively include 22 generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island. AE Supply and/or Monongahela own these generation facilities. The letter requested information under Section 114 of the Clean Air Act to determine compliance with the Clean Air Act and related requirements, including potential application of the New Source Review (“NSR”), standards under the Clean Air Act, which can require the installation of additional air emission control equipment when the major modification of an existing facility results in an increase in emissions. AE has provided responsive information to this and a subsequent request.

If NSR requirements are imposed on Allegheny’s generation facilities, in addition to the possible imposition of fines, compliance would entail significant capital investments in emission control technology.

On May 20, 2004, AE, AE Supply, Monongahela and West Penn received a Notice of Intent to Sue Pursuant to Clean Air Act §7604 (the “Notice”) from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP. The Notice alleged that Allegheny made major modifications to some of its West Virginia facilities in violation of the PSD provisions of the Clean Air Act at the following coal-fired facilities: Albright Unit No. 3; Fort Martin Units No. 1 and 2; Harrison Units No. 1, 2 and 3; Pleasants Units No. 1 and 2 and

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Willow Island Unit No. 2. The Notice also alleged PSD violations at the Armstrong, Hatfield’s Ferry and Mitchell generation facilities in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. On September 8, 2004, AE, AE Supply, Monongahela and West Penn received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.

On January 6, 2005, AE Supply and Monongahela filed a declaratory judgment action against the Attorneys General of New York, Connecticut and New Jersey in federal District Court in West Virginia (“West Virginia DJ Action”). This action requests that the court declare that AE Supply’s and Monongahela’s coal-fired generation facilities in Pennsylvania and West Virginia comply with the Clean Air Act. The Attorneys General filed a motion to dismiss the West Virginia DJ Action that has not been ruled upon by the Court. The Court held a status conference on May 6, 2010.

On June 28, 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply and the Distribution Companies in the United States District Court for the Western District of Pennsylvania (the “PA Enforcement Action”). This action alleges NSR violations under the federal Clean Air Act and the Pennsylvania Air Pollution Control Act at the Hatfield’s Ferry, Armstrong and Mitchell facilities in Pennsylvania. The PA Enforcement Action appears to raise the same issues regarding Allegheny’s Pennsylvania generation facilities that are before the federal District Court in the West Virginia DJ Action, except that the PA Enforcement Action also includes the PA DEP and the Maryland Attorney General. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. On May 30, 2006, the District Court denied Allegheny’s motion to dismiss the amended complaint. On July 26, 2006, at a status conference, the Court determined that discovery would proceed regarding liability issues, but not remedies. Discovery on the liability phase closed on December 31, 2007, and summary judgment briefing was completed during the first quarter of 2008. On November 18, 2008, the District Court issued a Memorandum Order denying all motions for summary judgment and establishing certain legal standards to govern at trial. In December 2009, a new trial judge was assigned to the case who then entered an order granting a motion to reconsider the rulings in the November 2008 Memorandum Order. On April 18, 2010, the new judge issued an opinion, again denying all motions for summary judgment and establishing certain legal standards to govern at trial. Trial has been tentatively scheduled to begin on September 13, 2010.

In addition to this lawsuit, on September 21, 2007, Allegheny received a Notice of Violation (“NOV”) from the EPA alleging NSR and PSD violations under the federal Clean Air Act, as well as Pennsylvania and West Virginia state laws. The NOV, which was directed to AE, Monongahela and West Penn, alleges violations at the Hatfield’s Ferry and Armstrong generation facilities in Pennsylvania and the Fort Martin and Willow Island generation facilities in West Virginia. The projects identified in the NOV are essentially the same as the projects at issue for these four facilities in the May 20, 2004 Notice, the West Virginia DJ Action and the PA Enforcement Action.

Allegheny intends to vigorously pursue and defend against the Clean Air Act matters described above but cannot predict their outcomes.

Global Warming Class Action. On April 9, 2006, AE, along with numerous other companies with coal-fired generation facilities and companies in other industries, was named as a defendant in a class action lawsuit in the United States District Court for the Southern District of Mississippi. On behalf of a purported class of residents and property owners in Mississippi who were harmed by Hurricane Katrina, the named plaintiffs allege that the emission of greenhouse gases by the defendants contributed to global warming, thereby causing Hurricane Katrina and plaintiffs’ damages. The plaintiffs seek unspecified damages. On December 6, 2006, AE filed a motion to dismiss plaintiffs’ complaint on jurisdictional grounds and then joined a motion filed by other

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defendants to dismiss the complaint for failure to state a claim. At a hearing on August 30, 2007, the Court granted the motion to dismiss that AE had joined and dismissed all of the plaintiffs’ claims against all defendants. Plaintiffs appealed that ruling to the United States Court of Appeals for the Fifth Circuit. On October 6, 2009, the assigned panel of the appellate court issued a written opinion that reversed the judgment entered by the District Court in favor of the defendants with respect to certain of the plaintiffs’ claims and remanded the case to the District Court for further proceedings. On November 25, 2009, AE and others filed a petition to have all of the judges of the Fifth Circuit rehear the issues addressed in the panel’s October 6, 2009 opinion. That petition was granted and oral argument was set for May 24, 2010. However, the parties were notified on April 30, 2010 that the Court was unable to empanel the necessary nine judges to hear the merits of the appeal due to recusals. The Court then entered an order on May 28, 2010, reinstating the ruling of the lower court that entered judgment in favor of the defendants and dismissing plaintiffs’ appeal. AE intends to vigorously defend against this action but cannot predict its outcome.

Other Litigation

Shareholder Actions. In connection with AE’s proposed Merger with a subsidiary of FirstEnergy, purported AE shareholders filed in the first quarter of 2010 several separate putative shareholder class action and/or derivative lawsuits in Pennsylvania and Maryland state courts, as well as in the United States District Court for the Western District of Pennsylvania against AE, its directors and certain of its officers (the “AE Defendants”), FirstEnergy and Merger Sub. The lawsuits allege, among other things, that the AE directors breached their fiduciary duties by approving the Merger Agreement and that AE, FirstEnergy and Merger Sub aided and abetted in these alleged breaches of fiduciary duty. The lawsuits also alleged that the Merger consideration is unfair, that certain other terms in the Merger Agreement are unfair and that certain individual defendants are financially interested in the Merger. Among other remedies, the lawsuits sought to enjoin the Merger, or in the event that an injunction was not awarded, money damages. While AE believes the lawsuits are without merit and has defended vigorously against the claims, in order to avoid the costs associated with the litigation, the defendants have agreed to the terms of a disclosure-based settlement of the lawsuits. The defendants reached an agreement with counsel for all of the plaintiffs concerning fee applications, but a formal stipulation of settlement has not yet been filed with any court. In exchange for AE’s agreement with plaintiffs’ counsel to include additional disclosure in the joint proxy statement/prospectus mailed to AE’s and FirstEnergy’s shareholders in connection with the Merger, and subject to court approval, AE anticipates dismissal of all claims asserted in the lawsuits and a release of all defendants. If the parties are unable to obtain final approval of the settlement, then litigation will proceed, and the outcome of any such litigation is inherently uncertain. If a dismissal is not granted or a settlement is not reached, these lawsuits could prevent or delay the completion of the Merger and result in substantial costs to AE. The defense or settlement of any lawsuit or claim that remains unresolved at the time the Merger closes may adversely affect AE’s business, financial condition or results of operations.

PJM Calculation Error. On March 8, 2010, the Midwest ISO filed two complaints at FERC against PJM. Both complaints are related to a modeling error that PJM discovered in September 2009. PJM reported that a modeling error in its system impacted the manner in which market-to-market power flow calculations were made between PJM and the Midwest ISO. Since April 2005, PJM had incorrectly modeled the ownership of certain generation resources in its system. The generation resources in question had an impact on power flows across the PJM/Midwest ISO border, and therefore the ownership of those resources (i.e., whether they were owned by a PJM company or a Midwest ISO company) had an impact on the way in which PJM and the Midwest ISO should have been compensated for market-to-market transactions. The Midwest ISO claims that this error resulted in PJM underpaying the Midwest ISO by approximately $130 million over the time period in question. The first complaint seeks a refund by PJM to the Midwest ISO of $130 million plus interest. The

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second complaint alleges that PJM did not properly trigger market-to-market settlements between PJM and the Midwest ISO during times when it was required to do so under the Joint Operating Agreement between the two companies. The Midwest ISO claims that PJM’s failure to act as required may have cost the Midwest ISO $5 million or more. The second complaint requests refunds of this additional amount. As PJM market participants, AE Supply and Monongahela may be liable for a portion of any refunds ordered in this case. PJM, Allegheny and other PJM market participants filed responses to the Midwest ISO complaints at FERC on April 12, 2010 denying any liability. In its response, Allegheny argued that, even if PJM had in fact committed an error that impacted market-to-market settlements, there were both legal and equitable reasons for which FERC should decline to order any refunds be paid. Also on April 12, PJM filed a related complaint at FERC against the Midwest ISO claiming that the Midwest ISO improperly called for market-to-market settlements several times during the same time period covered by the two Midwest ISO complaints filed against PJM. PJM claims these improper actions by the Midwest ISO may have cost the PJM market participants $25 million or more. On June 29, 2010, FERC issued an initial order on the complaints. FERC’s order consolidated all three of the pending complaints and set all disputed issues for hearing. The June 29th order did not resolve any of the legal issues in the dispute. The hearings required by the June 29th order will be held in abeyance while parties engage in FERC sponsored settlement discussions. A full evidentiary hearing on the substance of the complaints will be held if settlement cannot be achieved. Allegheny intends to participate in the FERC ordered settlement discussions and any subsequent hearings. Allegheny intends to vigorously pursue these matters but cannot predict their outcome.

Nevada Power Contracts. On December 7, 2001, Nevada Power Company (“NPC”) filed a complaint with the FERC against AE Supply seeking action by the FERC to modify prices payable to AE Supply under three trade confirmations between Merrill Lynch and NPC. NPC’s claim was based, in part, on the assertion that dysfunctional California spot markets had an adverse effect on the prices NPC was able to negotiate with Merrill Lynch under the contracts. NPC filed substantially identical complaints against a number of other energy suppliers. On December 19, 2002, the Administrative Law Judge (“ALJ”) issued findings that no contract modification was warranted. The ALJ determined in favor of NPC that AE Supply, rather than Merrill Lynch, was a proper subject of NPC’s complaint. On June 26, 2003, the FERC affirmed the ALJ’s decision upholding the long-term contracts negotiated between NPC and Merrill Lynch, among others. The FERC did not decide whether AE Supply, rather than Merrill Lynch, was the real party in interest. On November 10, 2003, the FERC issued an order, on rehearing, affirming its conclusion that the long-term contracts should not be modified. Snohomish County, NPC and other parties filed petitions for review of the FERC’s June 26, 2003 order with the United States Court of Appeals for the Ninth Circuit (the “NPC Petitions”). The NPC Petitions were consolidated in the Ninth Circuit. On December 19, 2006, the Ninth Circuit issued an opinion remanding the case to the FERC to determine, in accordance with the guidance set forth in the Ninth Circuit’s opinion, whether the FERC utilized the appropriate standard of review in deciding various claims, including NPC’s complaint. On May 3, 2007, AE Supply and others filed a petition to appeal the Ninth Circuit’s ruling to the United States Supreme Court. On June 26, 2008, the United States Supreme Court issued an opinion that rejected the Ninth Circuit’s reasoning, with instructions that the case be remanded to the FERC for amplification or clarification of its findings on two issues set forth in the opinion. The case was remanded to the FERC, and the FERC issued an order on December 18, 2008 that provides for a paper hearing on the two issues identified by the United States Supreme Court, with initial filings due within 90 days and reply submissions within 90 days thereafter. However, the order holds those deadlines in abeyance, contingent upon settlement discussions between the parties, and a subsequent order lifting that stay has not been entered. The parties have reached a settlement, pursuant to which Allegheny has made no financial commitment and that, if approved, would result in dismissal of the case. The parties are in the process of memorializing the agreed upon settlement, which will be submitted to FERC for approval.

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Claims by California Parties. On October 5, 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the California Department of Water Resources (“CDWR”) during 2001. The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was made in the context of mediation efforts by the FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remanded one of those proceedings to the FERC, which arises out of claims previously filed with the FERC by the California Attorney General on behalf of certain California parties against various sellers in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers filed motions to dismiss the Lockyer case. On March 18, 2010, the judge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and other sellers and dismissed the claims of the California Parties. On April 19, 2010, the California Parties filed exceptions to the judge’s rulings with FERC, and briefing is complete on those exceptions. The parties are awaiting a ruling from FERC on the exceptions.

On June 2, 2009, the California Attorney General, on behalf of certain California parties, filed a second lawsuit with FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for the joining of AE Supply in this new lawsuit. AE Supply has filed a motion to dismiss the Brown case that is pending before FERC. No scheduling order has been entered in the Brown case. Allegheny intends to vigorously defend against these claims but cannot predict their outcome.

Claims Related to Alleged Asbestos Exposure. The Distribution Companies have been named as defendants, along with multiple other defendants, in pending asbestos cases alleging bodily injury involving multiple plaintiffs and multiple sites. These suits have been brought mostly by seasonal contractors’ employees and do not involve allegations of the manufacture, sale or distribution of asbestos-containing products by Allegheny. These asbestos suits arise out of historical operations and are related to the installation and removal of asbestos-containing materials at Allegheny’s generation facilities. Allegheny’s historical operations were insured by various foreign and domestic insurers, including Lloyd’s of London. Certain insurers have contested their obligations to pay for the future defense and settlement costs relating to the asbestos suits. Allegheny is currently involved in two asbestos and/or environmental insurance-related actions, Certain Underwriters at Lloyd’s, London et al. v. Allegheny Energy, Inc. et al., Case No. 21-C-03-16733 (Washington County, Md.) and Monongahela Power Company et al. v. Certain Underwriters at Lloyd’s London and London Market Companies, et al ., Civil Action No. 03-C-281 (Monongalia County, W.Va.). The parties are seeking a declaration of coverage under the policies for asbestos-related and environmental claims.

Allegheny does not believe that the existence or pendency of either the asbestos suits or the actions involving its insurance will have a material impact on its consolidated financial position, results of operations or cash flows. As of June 30, 2010, Allegheny’s total number of claims alleging exposure to asbestos was 868 in West Virginia and eight in Pennsylvania. Allegheny intends to vigorously pursue these matters but cannot predict their outcomes.

Ordinary Course of Business. AE and its subsidiaries are from time to time involved in litigation and other legal disputes in the ordinary course of business.

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ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

Leases

Allegheny has capital and operating lease agreements with various terms and expiration dates, primarily for vehicles, computer equipment, communication lines and buildings. Allegheny’s estimated future minimum lease payments for capital and operating leases, with annual payments exceeding $100,000 and initial or remaining lease terms in excess of one year are:

(In millions)	July 1 through December 31, 2010		2011		2012		2013		2014		Thereafter		Total		Less: amount representing interest and fees		Present value of net minimum capital lease payments
Capital Leases	$	6.6	$	13.7	$	10.8	$	8.8	$	6.9	$	10.6	$	57.4	$	13.2	$	44.2
Operating Leases	$	3.5	$	6.3	$	5.7	$	5.5	$	5.4	$	8.5	$	34.9	$	0	$	0

PURPA

The Energy Policy Act of 2005 (the “Energy Policy Act”) amended PURPA significantly. Most notably, as of the effective date of the Energy Policy Act on August 8, 2005, electric utilities are no longer required to enter into any new contractual obligation to purchase energy from a qualifying facility if FERC finds that the facility has non-discriminatory access to a functioning wholesale market and open access transmission. This amendment has no impact on Allegheny’s current long-term power purchase agreements under PURPA.

The table below reflects Allegheny’s estimated commitments for energy and capacity purchases under PURPA contracts as of June 30, 2010. The commitments were calculated based on expected PURPA purchased power prices at June 30, 2010, without giving effect to possible price changes that could occur as a result of any future emissions regulation or legislation. Actual values can vary substantially depending upon future conditions.

(In millions)	kWhs	Amount
July 1 through December 31, 2010	1,764	$	127.0
2011	3,568		253.1
2012	3,590		258.3
2013	3,580		263.7
2014	3,489		260.7
Thereafter	46,574		3,658.2
Total	62,565	$	4,821.0

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ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

Fuel Purchase and Transportation Commitments

Allegheny has entered into various long-term commitments for the procurement and transportation of fuel (primarily coal) and lime to supply its generation facilities. Total estimated long-term fuel purchase and transportation commitments at June 30, 2010 were as follows:

(In millions)	Total
July 1 through December 31, 2010	$	489.6
2011		1,045.2
2012		741.2
2013		709.0
2014		713.4
Thereafter		1,842.0
Total	$	5,540.4

Other Purchase Obligations

AE has a Professional Service Agreement with Electronic Data Systems Corporation and EDS Information Services, LLC related to certain of Allegheny’s technology functions that will expire on December 31, 2012. Expected cash payments relating to the Professional Service Agreement are as follows:

(In millions)	July 1 through December 31, 2010		2011		2012		2013		Total
Other purchase obligations	$	12.5	$	23.8	$	22.9	$	0	$	59.2

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the Financial Statements and Notes to Financial Statements included in this report, as well as the Financial Statements, Notes to Financial Statements and Supplementary Data and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in Allegheny’s Annual Report on Form 10-K for the year ended December 31, 2009 (the “2009 Annual Report on Form 10-K”).

Forward-Looking Statements

In addition to historical information, this report contains a number of forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve estimates, expectations and projections and, as a result, are subject to risks and uncertainties. Forward-looking statements often may be identified by the use of words such as anticipate, expect, project, intend, plan, believe and words and terms of similar substance used in connection with any discussion of future plans, actions or events. However, the absence of these or similar words does not mean that any particular statement is not forward-looking. Forward-looking statements herein may relate to, among other matters:

• regulatory issues, including, but not limited to, environmental regulation and state rate regulation;

• financing plans;

• market demand and prices for energy, capacity, coal and natural gas;

• the cost and availability of raw materials, including coal, and Allegheny’s ability to enter into, modify and enforce long-term fuel purchase agreements;

• power supply contracts;

• results of litigation;

• results of operations;

• internal controls and procedures;

• capital expenditures;

• status and condition of plants and equipment;

• changes in technology and their effects on the competitiveness of Allegheny’s generation facilities;

• work stoppages by Allegheny’s unionized employees;

• capacity purchase commitments; and

• AE’s proposed Merger with FirstEnergy.

There can be no assurance that actual results will not differ materially from expectations. Actual results have varied materially and unpredictably from past expectations. Factors that could cause actual results to differ materially include, among others, the following:

• the results of regulatory proceedings, including proceedings related to rates;

• plant performance and unplanned outages;

• volatility and changes in the price and demand for energy and capacity and changes in the value of FTRs;

• volatility and changes in the price of coal, natural gas and other energy-related commodities, as well as transportation costs;

• Allegheny’s ability to enter into, modify and enforce long-term fuel purchase agreements;

• the effectiveness of Allegheny’s risk management policies and procedures;

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• the ability and willingness of counterparties to satisfy their financial and performance obligations;

• changes in the weather and other natural phenomena;

• changes in Allegheny’s requirements for, and the availability and price of, emission allowances;

• changes in industry capacity, development and other activities by Allegheny’s competitors;

• changes in market rules, including changes to PJM’s participant rules and tariffs, and defaults by other market participants;

• the loss of any significant customers or suppliers;

• changes in both customer usage and customer switching behavior and their resulting effects on existing and future load requirements;

• the impact of government-mandated energy consumption initiatives and renewable requirements, as well as general trends in resource conservation;

• dependence on other electric transmission and gas transportation systems and their constraints on availability;

• the reliability of Allegheny’s own transmission system and its ongoing compliance with NERC reliability standards;

• environmental regulations;

• changes in other laws and regulations applicable to Allegheny, its markets or its activities;

• changes in the underlying inputs and assumptions, including market conditions, used to estimate the fair values of commodity contracts;

• the effect of accounting pronouncements issued periodically by accounting standard-setting bodies;

• the likelihood and timing of the completion of the proposed Merger with FirstEnergy, the terms and conditions of any required regulatory approvals of the proposed Merger, the impact of the proposed Merger on Allegheny’s employees and potential diversion of management’s time and attention from ongoing business during this time period;

• difficulties in obtaining regulatory authorizations on a timely basis;

• disruptions in the financial markets and changes in access to capital markets;

• the availability of credit;

• actions of rating agencies;

• inflationary or deflationary trends and interest rate trends;

• general economic and business conditions, including the effects of the recent recession; and

• other risks, including the effects of global instability, terrorism and war.

A detailed discussion of certain factors affecting Allegheny’s risk profile is provided under Item 1A, “Risk Factors,” in the 2009 Annual Report on Form 10-K.

The primary purpose of Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is to provide information regarding Allegheny’s past and expected future performance in implementing its strategies and managing its risks and challenges. Allegheny’s MD&A includes the following sections:

• “Overview” includes a discussion of overall challenges and recent developments and initiatives;

• “Results of Operations” provides an overview of Allegheny’s operating results for the three and six months ended June 30, 2010 and 2009, including a review of earnings and results by reportable segment;

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• “Financial Condition-Liquidity and Capital Resources” provides an analysis of Allegheny’s liquidity position and credit profile, including its sources of cash (including bank credit facilities and sources of operating cash flow) and uses of cash (including contractual obligations and capital expenditure requirements) and the key risks and uncertainties that impact Allegheny’s past and future liquidity position and financial condition; and

• “Regulatory Framework Affecting Allegheny” provides a background and update of the various state and federal regulatory matters impacting Allegheny.

Overview

Allegheny is an integrated energy business that owns and operates electric generation facilities primarily in Pennsylvania, West Virginia and Maryland. Additionally, Allegheny owns transmission assets in Pennsylvania, West Virginia, Maryland and Virginia and and provides distribution services to customers in Pennsylvania, West Virginia and Maryland. See Note 1, “Business and Basis of Presentation,” to Allegheny’s consolidated financial statements for more information.

Allegheny’s operations are aligned in two reportable segments, the Merchant Generation segment and the Regulated Operations segment. Allegheny changed the composition of its reportable segments during the fourth quarter of 2009, consistent with changes made to its management structure and the internal financial reporting used by its chief operating decision maker to regularly assess the performance of the business and allocate resources. See Note 9, “Segment Information,” to Allegheny’s consolidated financial statements for additional information.

Pending Merger

On February 10, 2010, AE entered into an Agreement and Plan of Merger (as amended on June 4, 2010, the “Merger Agreement”) with FirstEnergy Corp. (“FirstEnergy”) and Element Merger Sub, Inc. (“Merger Sub”), a wholly owned subsidiary of FirstEnergy. Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into AE (the “Merger”), with AE becoming a wholly owned subsidiary of FirstEnergy. The Merger is intended to qualify as a tax-free reorganization under the Internal Revenue Code of 1986, as amended, and be tax-free to AE stockholders. Pursuant to the Merger Agreement, upon completion of the Merger, each issued and outstanding share of AE’s common stock, including grants of restricted stock, will automatically be converted into the right to receive 0.667 of a share of the common stock of FirstEnergy. This ratio is fixed, and the Merger Agreement does not provide for any adjustment to reflect stock price changes prior to completion of the Merger.

Completion of the Merger is subject to various customary conditions, including, among others, (i) requisite approvals of AE and FirstEnergy stockholders, (ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, (iii) receipt of all required regulatory approvals, including approvals from FERC and certain state public service and utility commissions, (iv) the absence of any governmental action challenging or seeking to prohibit the Merger, and (v) the absence of any material adverse effect with respect to either Allegheny or FirstEnergy.

AE and FirstEnergy currently anticipate completing the Merger in the first half of 2011. Although AE and FirstEnergy believe that they will receive the required authorizations, approvals and consents to complete the Merger, there can be no assurance as to the timing of these authorizations, approvals and consents or as to AE’s and FirstEnergy’s ultimate ability to obtain such authorizations, consents or approvals (or any additional authorizations, approvals or consents which may otherwise become necessary) or that such authorizations, approvals or consents will be obtained on terms and subject to conditions satisfactory to AE and FirstEnergy. See Note 2, “Merger Agreement” and Note 11, “Stock-based Compensation” to Allegheny’s consolidated financial statements, as well as “Regulatory Framework Affecting Allegheny” below for more information. Further information concerning the proposed Merger also is included in the Registration Statement filed by FirstEnergy with the SEC in connection with the Merger.

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FERC

On May 11, 2010, AE and FirstEnergy filed an application with the FERC for approval of their proposed Merger. Under the Federal Power Act, FERC has 180 days to rule on the merger application. AE and FirstEnergy submitted additional information regarding the merger application on June 21, 2010 in response to a request by FERC. Interventions and protests were filed with the FERC on July 12, 2010.

State Regulatory Merger Filings

On May 14 and May 18, 2010, AE and FirstEnergy filed applications with the Pennsylvania PUC and the West Virginia PSC, respectively, for approval of their proposed Merger. Pennsylvania and West Virginia laws impose no statutory timeframe for their commissions’ consideration of a merger application, but procedural schedules have been established, and final decisions are anticipated early in 2011. On May 27, 2010, AE and FirstEnergy filed an application for approval of the proposed Merger with the Maryland PSC. The Maryland PSC is required to issue an order no later than 180 days after an application is filed, but under good cause Maryland PSC may give itself a 45-day extension, which it did when it issued its initial order in the matter. An order from the Maryland PSC is therefore expected by January 7, 2011. On June 14, 2010, AE and FirstEnergy completed their application with the Virginia SCC. The Virginia SCC is required to rule on the merger application in 60 days, subject to up to a 120-day extension. In its order issued June 25, 2010, the Virginia SCC extended the period for its review by 30 days; therefore, the companies expect a decision by September 13, 2010.

Hart-Scott-Rodino (HSR) Act Filings

On May 25, 2010, AE and FirstEnergy made HSR filings with the U.S. Department of Justice (the “DOJ”) and Federal Trade Commission. On June 24, 2010, AE and FirstEnergy each received a request for additional information from the DOJ, which extends the HSR Act waiting period for an additional 30 days from the date that the requested information is supplied to the DOJ.

Form S-4 Registration Statement

On July 16, 2010, FirstEnergy’s registration statement on Form S-4 containing a joint proxy statement/prospectus relating to the proposed Merger was declared effective by the SEC. The joint proxy statement/prospectus contained in the registration statement was mailed to AE and FirstEnergy shareholders on or about July 23, 2010. AE and FirstEnergy will each hold a special meeting of shareholders on September 14, 2010 to consider and vote on proposals related to the proposed Merger.

Business Challenges

Allegheny faces a number of challenges and risks in its generation business, including electricity and capacity price risk, fuel supply and price risk, electricity demand, competition from other electricity suppliers, other generating plant performance and evolving environmental and other regulations and requirements.

Allegheny has executed and continues to enter into contracts for power sales and fuel supply purchase at varying prices and duration within established policies and guidelines. Allegheny’s future profitability will be affected by prevailing market conditions and the extent to and prices at which it has entered into intermediate or long-term power sales and fuel purchase agreements.

Allegheny manages the risks described above through various means, including risk-management programs that are designed to monitor and measure exposure to earnings and cash flow volatility related to changes in energy and fuel prices, counterparty credit quality and the operating performance of its generating units.

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Allegheny also faces a number of challenges in its regulated business, including the challenge to maintain high quality customer service and reliability in a cost-effective manner. In addition, these operations are subject to regulatory risk with respect to costs that may be recovered and investment returns that may be collected through regulated customer rates in each of its operating jurisdictions. See “Risk Factors” in Allegheny’s 2009 Annual Report on Form 10-K for additional information regarding these and other risks that Allegheny faces in its business.

Although Allegheny observed increased customer demand and increased market prices for power during the first half of 2010, Allegheny continues to face the ongoing effects of an economic downturn that began during the second half of 2008, including lower market prices for electricity, which have reduced realized revenues from the sale of unhedged generation output and, at times, caused Allegheny’s coal-fired plants to be placed in reserve status when they were otherwise available to generate power.

Recent Events

On June 1, 2010, Potomac Edison sold its Virginia electric distribution business for cash proceeds of approximately $317 million. See Note 4, “Sale of Virginia Distribution Business,” to Allegheny’s consolidated financial statements and “Regulatory Framework Affecting Allegheny” below for additional information.

On June 25, 2010, the West Virginia PSC approved a settlement of the base rate case in West Virginia with Monongahela, Potomac Edison, the Staff of the West Virginia PSC, the West Virginia Consumer Advocate Division and other parties. See Note 5, “Rates and Regulation,” to Allegheny’s consolidated financial statements and “Regulatory Framework Affecting Allegheny” below for additional information.

Liquidity

Allegheny does not have any significant debt scheduled to mature during 2010. In addition, Allegheny, AE Supply, Monongahela, West Penn, Potomac Edison and TrAIL Company each have in place revolving credit facilities. Total available capacity under these revolving credit facilities was $1,846.9 million at June 30, 2010. See “Financial Condition-Liquidity and Capital Resources” below for additional information.

RESULTS OF OPERATIONS

Earnings attributable to AE by segment for the three and six months ended June 30, were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2010		2009		2010		2009
Earnings by Segment:
Merchant Generation	$	53.0	$	41.9	$	95.4	$	121.8
Regulated Operations		67.0		30.5		112.6		84.3
Elimination of intercompany transactions		0.2		0.2		0.4		0.4
Consolidated net income attributable to Allegheny Energy, Inc.	$	120.2	$	72.6	$	208.4	$	206.5
Basic earnings per share	$	0.71	$	0.43	$	1.23	$	1.22
Diluted earnings per share	$	0.71	$	0.43	$	1.23	$	1.22

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Summary of Operating Results

Financial results for each segment were as follows:

	Three Months Ended June 30, 2010												Three Months Ended June 30, 2009
(In millions)	Merchant Generation			Regulated Operations			Eliminations (a)			Total			Merchant Generation			Regulated Operations			Eliminations (a)			Total
Operating revenues	$	457.9		$	795.3		$	(307.5	)	$	945.7		$	374.2		$	722.4		$	(281.9	)	$	814.7
Operating expenses:
Fuel		230.1			65.6			0			295.7			153.6			63.2			0			216.8
Purchased power and transmission		9.2			423.3			(306.2	)		126.3			8.8			383.9			(280.5	)		112.2
Deferred energy costs, net		0			2.3			0			2.3			0			(7.6	)		0			(7.6	)
Gain on sale of Virginia distribution business		0			(45.1	)		0			(45.1	)		0			0			0			0
Operations and maintenance		52.5			107.4			(1.3	)		158.6			88.7			113.2			(1.4	)		200.5
Depreciation and amortization		32.4			48.6			(0.4	)		80.6			24.0			43.7			(0.5	)		67.2
Taxes other than income taxes		12.9			43.7			0			56.6			8.5			38.0			0			46.5
Total operating expenses		337.1			645.8			(307.9	)		675.0			283.6			634.4			(282.4	)		635.6
Operating income		120.8			149.5			0.4			270.7			90.6			88.0			0.5			179.1
Other income (expense), net		0.8			5.4			(3.3	)		2.9			0.4			4.2			(2.8	)		1.8
Interest expense		36.4			44.1			(0.9	)		79.6			20.0			39.3			(0.2	)		59.1
Income before income taxes		85.2			110.8			(2.0	)		194.0			71.0			52.9			(2.1	)		121.8
Income tax expense		30.0			43.8			0			73.8			26.8			22.1			0			48.9
Net income		55.2			67.0			(2.0	)		120.2			44.2			30.8			(2.1	)		72.9
Net income attributable to noncontrolling interest		(2.2	)		0			2.2			0			(2.3	)		(0.3	)		2.3			(0.3	)
Net income attributable to Allegheny Energy, Inc.	$	53.0		$	67.0		$	0.2		$	120.2		$	41.9		$	30.5		$	0.2		$	72.6

(a) Represents elimination of transactions between reportable segments.

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	Six Months Ended June 30, 2010												Six Months Ended June 30, 2009
(In millions)	Merchant Generation			Regulated Operations			Eliminations (a)			Total			Merchant Generation			Regulated Operations			Eliminations (a)			Total
Operating revenues	$	920.5		$	1,756.3		$	(682.3	)	$	1,994.5		$	829.7		$	1,580.4		$	(638.2	)	$	1,771.9
Operating expenses:
Fuel		464.6			149.1			0			613.7			338.9			136.8			0			475.7
Purchased power and transmission		18.8			935.9			(679.5	)		275.2			18.2			863.3			(635.4	)		246.1
Deferred energy costs, net		0			10.4			0			10.4			0			(24.6	)		0			(24.6	)
Gain on sale of Virginia distribution business		0			(45.1	)		0			(45.1	)		0			0			0			0
Operations and maintenance		118.5			261.4			(2.8	)		377.1			150.8			219.8			(2.8	)		367.8
Depreciation and amortization		64.5			96.7			(0.8	)		160.4			47.7			88.9			(0.9	)		135.7
Taxes other than income taxes		26.1			87.6			0			113.7			21.3			81.0			0			102.3
Total operating expenses		692.5			1,496.0			(683.1	)		1,505.4			576.9			1,365.2			(639.1	)		1,303.0
Operating income		228.0			260.3			0.8			489.1			252.8			215.2			0.9			468.9
Other income (expense), net		1.4			10.5			(6.6	)		5.3			1.0			8.7			(5.5	)		4.2
Interest expense		72.5			85.6			(1.7	)		156.4			37.8			78.9			(0.4	)		116.3
Income before income taxes		156.9			185.2			(4.1	)		338.0			216.0			145.0			(4.2	)		356.8
Income tax expense		57.0			72.6			0			129.6			89.6			60.2			0			149.8
Net income		99.9			112.6			(4.1	)		208.4			126.4			84.8			(4.2	)		207.0
Net income attributable to noncontrolling interest		(4.5	)		0			4.5			0			(4.6	)		(0.5	)		4.6			(0.5	)
Net income attributable to Allegheny Energy, Inc.	$	95.4		$	112.6		$	0.4		$	208.4		$	121.8		$	84.3		$	0.4		$	206.5

(a) Represents elimination of transactions between reportable segments.

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MERCHANT GENERATION SEGMENT

Selected financial results for the Merchant Generation segment were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2010		2009		2010		2009
Operating revenues	$	457.9	$	374.2	$	920.5	$	829.7
Operating income	$	120.8	$	90.6	$	228.0	$	252.8
Income before income taxes	$	85.2	$	71.0	$	156.9	$	216.0

The following is a summary of certain statistical information relating to the Merchant Generation segment that is regularly reviewed by its management:

	Three Months Ended June  30,						Change		Six Months Ended June 30,						Change
	2010			2009					2010			2009
Market prices:
Round-the-clock energy price ($/MWh, PJM Western Hub) (a)	$	43.59		$	33.68		29.4	%	$	45.71		$	41.84		9.2	%
Round-the-clock energy price ($/MWh, PJM AD Hub) (a)	$	35.50		$	31.44		12.9	%	$	37.22		$	35.60		4.6	%
Natural gas price-Henry Hub NYMEX ($/MMBtu)	$	4.30		$	3.69		16.5	%	$	4.72		$	4.13		14.3	%
Allegheny operating statistics:
Realized energy price ($/MWh) (b)	$	36.16		$	32.98		9.6	%	$	37.10		$	38.81		(4.4	)%
Supercritical Coal Units:
kWhs generated (in millions)		7,317			5,492		33.2	%		14,475			11,943		21.2	%
Equivalent Availability Factor (EAF) (d)		88.3	%		70.1	%	18.2	%		84.8	%		74.8	%	10.0	%
Net Capacity Factor (NCF) (e)		76.1	%		57.1	%	19.0	%		75.0	%		61.9	%	13.1	%
Station O&M (in millions) (f):
Base and operations	$	21.0		$	23.0		(8.7	)%	$	40.5		$	43.1		(6.0	)%
Special maintenance		2.9			33.0		(91.2	)%		14.5			48.1		(69.9	)%
Total Station O&M	$	23.9		$	56.0		(57.3	)%	$	55.0		$	91.2		(39.7	)%
All Generating Units:
kWhs generated (in millions) (c)		8,575			6,078		41.1	%		16,983			13,465		26.1	%
EAF (d)		89.0	%		75.3	%	13.7	%		86.0	%		78.5	%	7.5	%
NCF (e)		54.8	%		38.8	%	16.0	%		54.3	%		43.2	%	11.1	%
Station O&M (in millions):
Base and operations	$	30.8		$	33.4		(7.8	)%	$	59.4		$	63.3		(6.2	)%
Special maintenance		2.9			37.2		(92.2	)%		16.2			52.9		(69.4	)%
Total Station O&M	$	33.7		$	70.6		(52.3	)%	$	75.6		$	116.2		(34.9	)%

(a) Represents the historical round-the-clock energy prices for the PJM Western Hub and PJM AEP-Dayton Hub, which management periodically considers when reviewing price trends within Allegheny’s region of PJM.

(b) Represents the weighted average actual price received at the generation facility for power sold into PJM by Allegheny’s Merchant Generation plants.

(c) Excludes kWhs consumed by pumping at the Bath County, Virginia hydroelectric station.

(d) EAF represents the average available generating capacity expressed as a percentage of total generating capacity. This measure is commonly less than 100%, primarily due to planned and unplanned outages and derates.

(e) NCF is a measure of actual net electricity generated compared to the amount of electricity that could have been generated at maximum operating capacity. This measure is less than 100% due to periods during which generating capacity is not available as a result of planned and unplanned outages, as well as periods during which generating capacity is available, but is not dispatched because of the availability in the market of lower cost generation in amounts sufficient to meet demand.

(f) Station O&M includes base, operations and special maintenance costs. Base and operations costs consist of normal recurring expenses related to the ongoing operation of the generation facilities. Special maintenance costs include costs associated with outage-related maintenance and projects that relate to the generation facilities.

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Forward prices for certain commodities in Allegheny’s region were as follows:

	Forward Market Prices (a)
	Six Months Ending December 31, 2010		2011		2012
Round-the-clock energy price-PJM Western Hub ($/MWh)	$	45.49	$	45.55	$	47.01
Round-the-clock energy price-PJM AD Hub ($/MWh)	$	37.10	$	37.90	$	40.21
Natural gas price-Henry Hub NYMEX ($/MMBtu)	$	4.82	$	5.34	$	5.68

(a) Based on average prices at June 30, 2010.

The performance of Allegheny’s Merchant Generation segment is significantly impacted by changes in prices for power and for commodities that underlie the generation of electric power, such as coal and natural gas. Market prices for power and related commodities are volatile and difficult to predict. Changes in such prices result from changes in supply and demand, fuel costs, market liquidity, weather, environmental regulation and other factors. In lower power price environments, Allegheny may generate less power because of the increased amount of time during which it is not economical to run its generating units.

To manage exposure to market price changes, Allegheny sells and purchases physical energy at the wholesale and retail level and enters into various economic hedges within established risk management objectives and policies, some of which do not qualify for cash flow hedge accounting treatment. The following table shows the percentages of Allegheny’s estimated future power sales and coal purchases that were hedged as of June 30, 2010:

	Six Months Ending December 31, 2010		2011		2012
Percentage of expected coal-fired generation sales hedged	87	%	57	%	22	%
Percentage of expected coal purchases hedged	98	%	66	%	63	%

Operating Revenues

Merchant Generation operating revenues were as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2010			2009			2010			2009
PJM energy revenue (all generation)	$	309.5		$	200.1		$	629.3		$	521.8
PJM capacity revenue		103.2			79.4			205.8			144.6
Power hedge revenue, net:
Power sale revenue-affiliated contracts		299.7			273.7			666.5			620.3
Power sale revenue-nonaffiliated contracts		30.2			18.3			43.6			37.8
Power purchased from PJM to serve affiliated and nonaffiliated contracts		(295.1	)		(254.1	)		(638.8	)		(605.3	)
Realized gains (losses) on financial hedges		(4.3	)		33.0			(4.3	)		39.0
Power hedge revenue, net		30.5			70.9			67.0			91.8
Other, including unrealized gains on hedge instruments		14.7			23.8			18.4			71.5
Total operating revenues	$	457.9		$	374.2		$	920.5		$	829.7

Total operating revenues increased $83.7 million in the three months ended June 30, 2010 compared to the three months ended June 30, 2009, primarily due to a $109.4 million increase in PJM energy revenue and a $23.8 million increase in PJM capacity revenue, partially offset by a $40.4 million decrease in power hedge revenue, net and a $9.1 million decrease in other revenues, including unrealized gains on hedge instruments.

Total operating revenues increased $90.8 million in the six months ended June 30, 2010 compared to the six months ended June 30, 2009, primarily due to a $107.5 million increase in PJM energy revenue and a $61.2

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million increase in PJM capacity revenue, partially offset by a $53.1 million decrease in other revenues, including unrealized gains on hedge instruments and a $24.8 million decrease in power hedge revenue, net.

PJM Energy Revenue

PJM energy revenue represents the sale of all power produced by the Merchant Generation segment. PJM energy revenue increased $109.4 million in the three months ended June 30, 2010 compared to the three months ended June 30, 2009, primarily due to higher generation output and higher prices.

PJM energy revenue increased $107.5 million in the six months ended June 30, 2010 compared to the six months ended June 30, 2009, primarily due to higher generation output, partially offset by lower prices.

PJM Capacity Revenue

PJM capacity revenue. PJM capacity revenue represents payments received from PJM based on Allegheny’s available generation capacity and capacity prices as determined under the PJM RPM auction process. PJM capacity revenue increased $23.8 million and $61.2 million in the three and six months ended June 30, 2010, respectively, compared to the three and six months ended June 30, 2009, as a result of increased capacity prices.

PJM RPM capacity auctions have been conducted through the planning year ending May 31, 2014. For Allegheny’s region of PJM, average capacity prices per MW-day for the planning years ending May 31, 2010, 2011, 2012, 2013 and 2014 were $157, $174, $110, $16 and $28, respectively.

Power Hedge Revenue, Net

Power sale revenue—affiliated contracts. Power sale revenue—affiliated contracts represents sales of power by the Merchant Generation segment to West Penn and Potomac Edison under power sales contracts. Power sale revenue—affiliated contracts increased $26.0 million and $46.2 million in the three and six months ended June 30, 2010, respectively, compared to the three and six months ended June 30, 2009, primarily due to increased revenues in Pennsylvania resulting from higher generation rates charged to Pennsylvania customers, which are passed on to AE Supply under the terms of the power supply contract between West Penn and AE Supply. These increases in revenue were partially offset by a reduction in affiliated power sale revenue due to the June 1, 2010 sale of Potomac Edison’s Virginia distribution business to Rappahannock Electric Cooperative and Shenandoah Valley Electric Cooperative (together, the “Cooperatives”). Beginning June 1, 2010, power sales between the Merchant Generation segment and the Cooperatives is being recorded in power sale revenue—nonaffiliated contracts. Prior to the sale of the Virginia distribution business, these sales were classified as affiliated revenue.

Power sale revenue—nonaffiliated contracts. Power sale revenue—nonaffiliated contracts represents sales of power by the Merchant Generation segment to third parties under power sales contracts. Power sale revenue – nonaffiliated contracts increased $11.9 million and $5.8 million in the three and six months ended June 30, 2010, respectively, compared to the three and six months ended June 30, 2009, primarily due to the June 1, 2010 sale of Potomac Edison’s Virginia distribution business. Beginning June 1, 2010, power sales between the Merchant Generation segment and the Cooperatives are being recorded in power sale revenue—nonaffiliated contracts. Prior to the sale of the Virginia distribution business, these sales were classified as affiliated revenue.

Power purchased from PJM to serve affiliated and nonaffiliated contracts. Power purchased from PJM to serve affiliated and nonaffiliated contracts increased $41.0 million and $33.5 million in the three and six months ended June 30, 2010 compared to the three and six months ended June 30, 2009, primarily due to higher power prices.

Realized gains (losses) on financial hedges. Realized gains (losses) on financial hedges decreased $37.3 million and $43.3 million in the three and six months ended June 30, 2010, respectively, compared to the three and six months ended June 30, 2009, primarily due to reduced gains on power sales hedges resulting from lower margins, partially offset by a reduction in losses on power purchase hedges.

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Other Revenues

Other revenues decreased $9.1 million in the three months ended June 30, 2010 compared to the three months ended June 30, 2009, primarily due to unrealized losses related to pipeline capacity economic hedges that did not qualify for hedge accounting and unrealized losses on the ineffective portion of cash flow hedges, partially offset by increased unrealized gains on FTRs

Other revenues decreased $53.1 million in the six months ended June 30, 2010 compared to the six months ended June 30, 2009, primarily due to unrealized losses related to pipeline capacity economic hedges that did not qualify for hedge accounting, decreased unrealized gains on FTRs and increased unrealized losses on the ineffective portion of cash flow hedges.

Operating Expenses

Fuel: Fuel expense represents the cost of coal, natural gas, oil, lime and other materials consumed in the generation of power, as well as emission allowances, fuel handling and residual disposal costs. Fuel expense was as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2010		2009		2010		2009
Fuel	$	230.1	$	153.6	$	464.6	$	338.9

Fuel expense increased $76.5 million in the three months ended June 30, 2010 compared to the three months ended June 30, 2009, primarily due to a 41.2% increase in tons of coal consumed and an 8.6% increase in the average cost of coal per ton.

Fuel expense increased $125.7 million in the six months ended June 30, 2010 compared to the six months ended June 30, 2009, primarily due to a 24.7% increase in tons of coal consumed and an 11.0% increase in the average cost of coal per ton.

Operations and Maintenance: Operations and maintenance expenses include salaries and wages, employee benefits, materials and supplies, contract work, outside services and other expenses. Operations and maintenance expenses were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2010		2009		2010		2009
Operations and maintenance	$	52.5	$	88.7	$	118.5	$	150.8

Operations and maintenance expenses decreased $36.2 million and $32.3 million in the three and six months ended June 30, 2010, respectively, compared to the three and six months ended June 30, 2009, primarily due to decreased costs associated with the timing of special maintenance.

Allegheny expects to incur approximately $35 million of special maintenance expenditures during the remainder of 2010 compared to $9 million during the same period in 2009.

Depreciation and Amortization: Depreciation and amortization expenses were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2010		2009		2010		2009
Depreciation and amortization	$	32.4	$	24.0	$	64.5	$	47.7

Depreciation and amortization expenses increased $8.4 million and $16.8 million in the three and six months ended June 30, 2010, respectively, compared to the three and six months ended June 30, 2009, primarily due to the depreciation of Scrubber equipment that was placed into service during 2009 at the Hatfield’s Ferry generating facility.

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Taxes Other Than Income Taxes: Taxes other than income taxes primarily includes business and occupation taxes, payroll taxes and property taxes. Taxes other than income taxes were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2010		2009		2010		2009
Taxes other than income taxes	$	12.9	$	8.5	$	26.1	$	21.3

Taxes other than income taxes increased $4.4 million and $4.8 million for the three and six months ended June 30, 2010, respectively, compared to the three and six months ended June 30, 2009, primarily due to a tax refund received during 2009.

Interest Expense

Interest expense was as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2010		2009		2010		2009
Interest expense	$	36.4	$	20.0	$	72.5	$	37.8

Interest expense increased $16.4 million and $34.7 million in the three and six months ended June 30, 2010, respectively, compared to the three and six months ended June 30, 2009, primarily due to decreased capitalized interest expense resulting from capital projects that were completed and placed into service, including the Scrubber equipment at the Hatfield’s Ferry generating facility and an increase in the average interest rate on outstanding debt.

See Note 8, “Common Stock and Debt” to Allegheny’s consolidated financial statements for additional information.

Income Tax Expense

Income tax expense of $30.0 million for the three months ended June 30, 2010 resulted in an effective tax rate of 35.3%. Income tax expense for the three months ended June 30, 2010 was higher than the income tax expense calculated at the federal statutory tax rate of 35%, primarily due to state income taxes, which increased the effective rate by 1.4% and increases in tax reserves, which increased the effective rate by 1.3%. These increases were partially offset by the segment’s share of consolidated savings, which decreased the effective rate by 2.0%.

Income tax expense of $26.8 million for the three months ended June 30, 2009 resulted in an effective tax rate of 37.8%. Income tax expense for the three months ended June 30, 2009 was higher than the income tax expense calculated at the federal statutory tax rate of 35%, primarily due to state income taxes, which increased the effective rate by 2.9%.

Income tax expense of $57.0 million for the six months ended June 30, 2010 resulted in an effective tax rate of 36.3%. Income tax expense for the six months ended June 30, 2010 was higher than the income tax expense calculated at the federal statutory tax rate of 35%, primarily due to state income taxes, which increased the effective rate by 1.3%.

Income tax expense of $89.6 million for the six months ended June 30, 2009 resulted in an effective tax rate of 41.5%. Income tax expense for the six months ended June 30, 2009 was higher than the income tax expense calculated at the federal statutory tax rate of 35%, primarily due to state taxes, which increased the rate by 2.9% and an adjustment to the Pennsylvania net operating loss carryforward deferred tax asset, which increased the effective rate by 4.4%.

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REGULATED OPERATIONS SEGMENT

Selected financial results for the Regulated Operations segment were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2010		2009		2010		2009
Operating revenues	$	795.3	$	722.4	$	1,756.3	$	1,580.4
Operating income	$	149.5	$	88.0	$	260.3	$	215.2
Income before income taxes	$	110.8	$	52.9	$	185.2	$	145.0

The performance of Allegheny’s Regulated Operations segment is significantly impacted by customer demand for electricity, regulatory ratemaking actions and the progress of transmission expansion projects. Retail electricity sales, including sales by Potomac Edison’s Virginia distribution business, which was sold June 1, 2010, were as follows:

	Three Months Ended June 30,		Change		Six Months Ended June 30,		Change
	2010	2009			2010	2009
Retail electricity sales (million kWhs)	9,822	9,725	1.0	%	21,622	21,256	1.7	%

Retail electricity sales, excluding sales by Potomac Edison’s Virginia distribution business, which was sold on June 1, 2010, were as follows:

	Three Months Ended June 30,		Change		Six Months Ended June 30,		Change
	2010	2009			2010	2009
Retail electricity sales (million kWhs)—excluding Virginia distribution business	9,369	9,052	3.5	%	20,342	19,772	2.9	%

In addition to retail electricity sales, management monitors the performance of the Regulated Operations segment based in part on certain statistical information including the following:

	Three Months Ended June 30,				Change		Six Months Ended June 30,				Change
	2010		2009				2010		2009
Revenue per MWh sold (a)	$	77.43	$	72.37	7.0	%	$	78.75	$	73.22	7.6	%
O&M per MWh sold (b)	$	10.54	$	11.29	(6.6	)%	$	11.75	$	10.05	16.9	%
HDD (c)		381		529	(28.0	)%		3,147		3,289	(4.3	)%
CDD (c)		384		262	46.6	%		384		264	45.5	%
kWhs generated (million kWhs) (d)		2,267		2,225	1.9	%		5,088		4,944	2.9	%

(a) This measure is calculated by dividing total revenues from retail sales of electricity by retail electricity sales.

(b) This measure is calculated by dividing total O&M, excluding O&M related to transmission expansion, which is recovered in formula rates, by retail electricity sales measured in MWhs.

(c) Heating degree-days (“HDD”) and cooling degree-days (“CDD”). The operations of the Distribution Companies are weather sensitive. Weather conditions directly influence the volume of electricity delivered by the Distribution Companies, representing one of several factors that impact the volume of electricity delivered. Accordingly, deviations in weather from normal levels can affect Allegheny’s financial performance. Degree-day data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit, and CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one cooling

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degree-day, and each degree of temperature below 65° Fahrenheit is counted as one heating degree-day. HDD and CDD are most likely to impact the usage of Allegheny’s residential and commercial customers. Industrial customers are less weather sensitive. Normal HDD for the three and six months ended June 30, 2010 and 2009 were 639 and 3,439 respectively. Normal CDD for the three and six months ended June 30, 2010 and 2009 were 214 and 215, respectively.

(d) Represents kWhs generated by Monongahela’s regulated generation facilities.

Capital expenditures on Allegheny’s PATH, TrAIL and other transmission expansion projects are continuing. Increased capital spending on these projects directly impacts earnings. Income before income tax relating to transmission expansion increased $10.7 million and $23.5 million in the three and six months ended June 30, 2010, respectively, compared to the three and six months ended June 30, 2009, and net income attributable to AE relating to transmission expansion increased $6.3 million and $14.9 million in the three and six months ended June 30, 2010, respectively, compared to the three and six months ended June 30, 2009.

Operating Revenues

Regulated Operation revenues were as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2010			2009			2010			2009
Retail electric:
Generation and ancillary	$	579.5		$	527.3		$	1,294.1		$	1,162.3
Transmission		27.2			27.2			61.1			60.2
Distribution		153.8			149.3			347.6			333.8
Total retail electric		760.5			703.8			1,702.8			1,556.3
Transmission services and bulk power:
PJM revenue, net		(35.8	)		(24.4	)		(80.5	)		(66.4	)
Warrior Run generation revenue		15.5			8.2			34.6			27.1
Transmission and other		43.3			23.1			79.8			42.8
Total transmission services and bulk power		23.0			6.9			33.9			3.5
Other		11.8			11.7			19.6			20.6
Total operating revenues	$	795.3		$	722.4		$	1,756.3		$	1,580.4

Total operating revenues increased $72.9 million in the three months ended June 30, 2010 compared to the three months ended June 30, 2009, primarily due to a $56.7 million increase in retail electric revenues and a $16.1 million increase in transmission services and bulk power revenues.

Total operating revenues increased $175.9 million in the six months ended June 30, 2010 compared to the six months ended June 30, 2009, primarily due to a $146.5 million increase in retail electric revenues and a $30.4 million increase in transmission services and bulk power revenues.

Retail Electric

Retail electric revenues increased $56.7 million in the three months ended June 30, 2010 compared to the three months ended June 30, 2009, primarily due to:

• a $32.2 million increase resulting from higher generation rates charged to Pennsylvania customers,

• a $24.2 million increase related to a January 1, 2010 fuel and purchased power costs rate adjustment in West Virginia and

• a 3.5% increase in MWhs sold, excluding MWhs sold relating the Virginia distribution business,

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• partially offset by a decrease in MWhs sold as a result of the June 1, 2010 sale of Potomac Edison’s Virginia distribution business.

Retail electric revenues increased $146.5 million in the six months ended June 30, 2010 compared to the six months ended June 30, 2009, primarily due to:

• a $68.4 million increase resulting from higher generation rates charged to Pennsylvania customers,

• a $54.8 million increase related to a January 1, 2010 fuel and purchased power costs rate adjustment in West Virginia and

• a 2.9% increase in MWhs sold, excluding MWhs sold relating the Virginia distribution business,

• partially offset by a decrease in MWhs sold as a result of the June 1, 2010 sale of Potomac Edison’s Virginia distribution business.

Transmission Services and Bulk Power

Transmission services and bulk power revenues increased $16.1 million and $30.4 million in the three and six months ended June 30, 2010, respectively, compared to the three and six months ended June 30, 2009, primarily due to returns earned on construction work in progress on transmission expansion projects and increased sales of electricity related to the Warrior Run PURPA generation facility.

Operating Expenses

Fuel: Fuel expense represents the cost of coal, natural gas, oil, lime and other materials consumed in the generation of power, as well as emission allowances, fuel handling and residual disposal costs. Fuel expense was as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2010		2009		2010		2009
Fuel	$	65.6	$	63.2	$	149.1	$	136.8

Fuel expense increased $2.4 million in the three months ended June 30, 2010 compared to the three months ended June 30, 2009, primarily resulting from a 4.4% increase in the average cost of coal per ton, partially offset by a 2.0% decrease in tons of coal consumed, as well as a $1.0 million increase in lime and other fuel expenses resulting from operation of the Fort Martin Scrubbers, which were placed into service during the fourth quarter of 2009.

Fuel expense increased $12.3 million in the six months ended June 30, 2010 compared to the six months ended June 30, 2009, primarily resulting from a 6.8% increase in the average cost of coal per ton and a $3.2 million increase in lime and other fuel expenses resulting from operation of the Fort Martin Scrubbers, which were placed into service during the fourth quarter of 2009.

Purchased Power and Transmission: Purchased power and transmission expense represents power purchased from AE Supply and third-party suppliers, including purchases from qualifying facilities under PURPA. Purchased power and transmission expense was as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2010		2009		2010		2009
Purchased power and transmission	$	423.3	$	383.9	$	935.9	$	863.3

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Purchased power and transmission expense increased $39.4 million and $72.6 million in the three and six months ended June 30, 2010, respectively, compared to the three and six months ended June 30, 2009, primarily due to higher generation rates paid under the terms of a power supply agreement between West Penn and AE Supply and higher customer demand, partially offset by decreased purchased power resulting from the June 1, 2010 sale of Potomac Edison’s Virginia distribution business.

Deferred Energy Costs, net: Deferred energy costs, net represent an adjustment of actual costs incurred during the period for amounts that are expected to be charged or credited to customers in rates in a future period under a regulatory mechanism. The components of deferred energy costs were as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2010			2009			2010			2009
ENEC related costs	$	9.2		$	(10.6	)	$	20.6		$	(22.7	)
AES Warrior Run PURPA generation		(2.5	)		(1.0	)		(1.0	)		(4.5	)
Market-based generation and other costs		(4.4	)		4.0			(9.2	)		2.6
Deferred energy costs, net	$	2.3		$	(7.6	)	$	10.4		$	(24.6	)

ENEC Costs. Under the annual ENEC method of recovering net power supply costs in West Virginia, including fuel costs, purchased power costs and other related expenses, net of related revenue and interest earnings on the Fort Martin Scrubber project escrow fund, Monongahela and Potomac Edison track actual costs and revenues for under and/or over recoveries, and generally file requests for revised ENEC rates on an annual basis. Any under-recovery and/or over-recovery of costs, net of related revenues, is deferred, for subsequent recovery or refund, as a regulatory asset or regulatory liability, with the corresponding impact on the consolidated statements of income reflected in “Deferred energy costs, net.”

AES Warrior Run PURPA Generation. To satisfy certain of its obligations under PURPA, Potomac Edison entered into a long-term contract beginning July 1, 2000 to purchase capacity and energy from the AES Warrior Run PURPA generation facility through the beginning of 2030. Potomac Edison is authorized by the Maryland PSC to recover all contract costs from the AES Warrior Run PURPA generation facility, net of any revenues received from the sale of AES Warrior Run output into the wholesale energy market, by means of a retail revenue surcharge. Any under-recovery or over-recovery of net costs is being deferred pending subsequent recovery from, or return to, customers through adjustments to this surcharge.

Market-based Generation and Other Costs. Potomac Edison is authorized by the Maryland PSC to recover the costs of the generation component of power sold to certain residential, commercial and industrial customers that did not choose a third-party alternative generation provider. A regulatory asset or liability is recorded on Potomac Edison’s balance sheet for any under-recovery or over-recovery of the generation component of costs charged to these customers. In addition, under an order by the Virginia PSC, Potomac Edison was permitted a rate adjustment to recover a portion of any increased purchased power costs. Following the June 1, 2010 sale of Potomac Edison’s Virginia distribution business, the Cooperatives became responsible for providing power to customers in Virginia. See Note 4, “Sale of Virginia Distribution Business” to Allegheny’s consolidated financial statements for additional information.

Gain on Sale of Virginia distribution business: The June 1, 2010 sale of Potomac Edison’s Virginia distribution business resulted in a $45.1 million pre-tax gain. See Note 4, “Sale of Virginia Distribution Business” to Allegheny’s consolidated financial statements for additional information.

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Operations and Maintenance: Operations and maintenance expenses primarily include salaries and wages, employee benefits, materials and supplies, contract work, outside services and other expenses. Operations and maintenance expenses were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2010		2009		2010		2009
Operations and maintenance	$	107.4	$	113.2	$	261.4	$	219.8

Operations and maintenance expenses decreased $5.8 million in the three months ended June 30, 2010 compared to the three months ended June 30, 2009, primarily due to a credit to expense recorded during the second quarter of 2010 in the amount of $8.9 million representing the deferral of winter storm costs incurred in West Virginia during the first quarter of 2010 that were permitted to be recovered under the June 25, 2010 West Virginia rate order, partially offset by expenses related to AE’s proposed Merger with FirstEnergy. See Note 5, “Rates and Regulation” to Allegheny’s consolidated financial statements for additional information related to the June 25, 2010 West Virginia rate order.

Operations and maintenance expenses increased $41.6 million in the six months ended June 30, 2010 compared to the six months ended June 30, 2009, primarily due to an $11 million net increase in restoration costs due to severe storm costs incurred during the first quarter of 2010, net of the $8.9 million credit recorded during the second quarter of 2010 for West Virginia storm costs that are permitted to be recovered under the June 25, 2010 West Virginia rate order, a $7.2 million charge due to an adjustment to the OPEB liability during the first quarter of 2010 and expenses related to AE’s proposed Merger with FirstEnergy.

Depreciation and Amortization: Depreciation and amortization expenses were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2010		2009		2010		2009
Depreciation and amortization	$	48.6	$	43.7	$	96.7	$	88.9

Depreciation and amortization expenses increased $4.9 million and $7.8 million in the three and six months ended June 30, 2010, respectively, compared to the three and six months ended June 30, 2009, primarily due to the depreciation of Fort Martin Scrubbers, which were placed into service during the fourth quarter of 2009.

Taxes Other Than Income Taxes: Taxes other than income taxes primarily includes business and occupation taxes, payroll taxes, gross receipts taxes and property taxes. Taxes other than income taxes were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2010		2009		2010		2009
Taxes other than income taxes	$	43.7	$	38.0	$	87.6	$	81.0

Taxes other than income taxes increased $5.7 million and $6.6 million for the three and six months ended June 30, 2010, respectively, compared to the three and six months ended June 30, 2009, primarily due to increased gross receipts taxes in Pennsylvania resulting from higher taxable revenues during 2010 and a tax refund received during 2009.

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Other Income (Expense), net

Other income (expense), net was as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2010		2009		2010		2009
Other income (expense), net	$	5.4	$	4.2	$	10.5	$	8.7

Other income (expense), net increased $1.2 million and $1.8 million for the three and six months ended June 30, 2010, respectively, compared to the three and six months ended June 30, 2009, primarily due to equity earnings related to Allegheny’s investment in PATH WV.

Interest Expense

Interest expense was as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2010		2009		2010		2009
Interest expense	$	44.1	$	39.3	$	85.6	$	78.9

Interest expense increased $4.8 million and $6.7 million in the three and six months ended June 30, 2010, respectively, compared to the three and six months ended June 30, 2009, primarily due to increased net borrowings by TrAIL Company, partially offset by lower interest expense related to the repayment of $110 million of medium-term notes by Monongahela during January 2010. See Note 8, “Common Stock and Debt” to Allegheny’s consolidated financial statements for additional information.

Income Tax Expense

Income tax expense of $43.8 million for the three months ended June 30, 2010 resulted in an effective tax rate of 39.5%. Income tax expense for the three months ended June 30, 2010 was higher than the income tax expense calculated at the federal statutory tax rate of 35%, primarily due to state taxes, which increased the effective rate by 3.6% and the segment’s share of consolidated liability, which increased the effective rate by 1.5%.

Income tax expense of $22.1 million for the three months ended June 30, 2009 resulted in an effective tax rate of 41.7%. Income tax expense for the three months ended June 30, 2009 was higher than the income tax expense calculated at the federal statutory tax rate of 35%, primarily due to state taxes, which increased the effective rate by 3.7%, the ratemaking effects of depreciation, which increased the effective rate by 3.7% and changes in tax reserves related to uncertain tax positions, which increased the effective rate by 1%. These increases were partially offset by the ratemaking effects of investment tax credits, which decreased the effective rate by 1.1%.

Income tax expense of $72.6 million for the six months ended June 30, 2010 resulted in an effective tax rate of 39.2%. Income tax expense for the six months ended June 30, 2010 was higher than the income tax expense calculated at the federal statutory tax rate of 35%, primarily due to state income taxes, which increased the effective rate by 4.2%.

Income tax expense of $60.2 million for the six months ended June 30, 2009 resulted in an effective tax rate of 41.5%. Income tax expense for the six months ended June 30, 2009 was higher than the income tax expense calculated at the federal statutory tax rate of 35%, primarily due to state taxes, which increased the effective rate by 3.9%, the ratemaking effects of depreciation, which increased the effective rate by 2.5%, and changes in tax reserves related to uncertain tax positions, which increased the effective rate by 1.2%.

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Transmission Expansion

The Regulated Operations segment includes the operations of TrAIL Company and PATH Allegheny, as well as Allegheny’s interest in PATH-WV. TrAIL Company and PATH, LLC are subject to regulation of rates by FERC for amounts billed through PJM. FERC has approved the use of a formula rate methodology for recovery of all prudently incurred operations and maintenance expenses and a return on debt and equity for all capital expenditures in connection with TrAIL and PATH based on a hypothetical 50% debt and 50% equity capital structure until the transmission facilities are placed into service, as well as an income tax allowance. The actual capital structure for each company will be reflected in the formula rate once the transmission facilities are placed into service. TrAIL Company and PATH, LLC recognize revenue based on allowable costs incurred and return earned. Therefore, revenues and operating income are expected to increase as the projects progress. The results of operations and selected balance sheet information related to transmission expansion were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2010		2009		2010		2009
Results of operations:
Operating revenues	$	37.0	$	18.8	$	69.2	$	32.2
Operations and maintenance		4.1		3.6		8.1		6.6
Depreciation and amortization		1.3		1.0		2.2		2.0
Taxes other than income taxes		0.5		0.2		1.1		0.4
Total operating expenses		5.9		4.8		11.4		9.0
Operating income		31.1		14.0		57.8		23.2
Other income (expense), net		1.7		0.5		3.1		1.0
Interest expense, net of capitalized interest		9.0		1.4		15.7		2.5
Income before income taxes		23.8		13.1		45.2		21.7
Income tax expense		10.0		5.3		17.9		8.9
Net income		13.8		7.8		27.3		12.8
Net income attributable to noncontrolling interest		0		0.3		0		0.4
Net income attributable to Allegheny Energy, Inc.	$	13.8	$	7.5	$	27.3	$	12.4

(In millions)	June 30, 2010		December 31, 2009
Balance sheet information:
Property, plant and equipment, net	$	1,058.3	$	825.3
Total assets	$	1,231.3	$	922.5
Long-term debt	$	643.5	$	455.0

As described in Note 16, “Variable Interest Entities,” effective January 1, 2010 Allegheny began to account for its investment in PATH WV using the equity method of accounting in place of its prior consolidation method of accounting. At December 31, 2009, Allegheny’s consolidated balance sheet included property, plant and equipment of PATH WV in the amount of $35.8 million, cash and cash equivalents of $3.4 million and noncontrolling interest related to AEP’s ownership of approximately $14.9 million. At June 30, 2010, Allegheny’s consolidated balance sheet included Allegheny’s investment in PATH WV on the equity method of accounting in the amount of $18.3 million. Allegheny’s pre-tax income from its investment in PATH WV was approximately $0.9 million and $0.4 million for the three months ended June 30, 2010 and 2009, respectively, and was $1.8 million and $0.7 million for the six months ended June 30, 2010 and 2009, respectively.

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Liquidity and Capital Requirements

To meet cash needs for operating expenses, the payment of interest, pension contributions, retirement of debt and construction programs, Allegheny has historically used internally generated funds (net cash provided by operations less common dividends) and external financings, including the sale of common and preferred stock, debt instruments and lease arrangements.

At June 30, 2010 and December 31, 2009, Allegheny had cash and cash equivalents of $477.6 million and $286.6 million, respectively, and current restricted funds of $24.9 million and $25.9 million, respectively. Current restricted funds were comprised of funds collected from West Virginia customers to service Fort Martin Scrubber bonds and intangible transition charges collected from West Penn customers. In addition, at June 30, 2010 and December 31, 2009, Allegheny had long-term restricted funds of $36.0 million and $60.2 million, respectively. Long-term restricted funds primarily related to proceeds remaining from the issuance of Fort Martin Scrubber bonds.

See Note 8, “Common Stock and Debt,” to Allegheny’s consolidated financial statements for a summary of Allegheny’s debt at June 30, 2010. AE, AE Supply, Monongahela, Potomac Edison, West Penn and TrAIL Company each have in place revolving credit facilities. At June 30, 2010, borrowing capacity under these credit facilities was as follows:

(Dollar amounts in millions)	Matures		Total Capacity		Borrowed		Letters of Credit Issued		Available Capacity
AE	2013		$	250.0	$	0	$	3.1	$	246.9
AE Supply	2012			1,000.0		0		0		1,000.0
Monongahela	2012			110.0		0		0		110.0
Potomac Edison	2011	(a)		150.0		0		0		150.0
West Penn	2013			200.0		15.0		0		185.0
TrAIL Company	2013			350.0		195.0		0		155.0
Total			$	2,060.0	$	210.0	$	3.1	$	1,846.9

(a) Potomac Edison’s credit facility will mature at the end of 2011. However, Potomac Edison may elect to extend the final maturity date to April 2013, if certain conditions are met.

Allegheny posts collateral with counterparties, including PJM, for certain transactions and transmission and transportation tariffs. Approximately $22.1 million and $20.8 million of cash collateral deposits were included in current assets at June 30, 2010 and December 31, 2009, respectively. Approximately $4.2 million and $3.1 million of cash collateral deposits were netted against derivative liabilities on the Consolidated Balance Sheet at June 30, 2010 and December 31, 2009, respectively. If Allegheny’s credit ratings were to decline, it may be required to deposit additional cash or cash-equivalent collateral with its hedging counterparties. See Note 10, “Fair Value Measurements, Derivative Instruments and Hedging Activities,” to Allegheny’s consolidated financial statements for additional information regarding potential additional collateral that would have been required for derivative contracts in a net liability position at June 30, 2010.

A downgrade of AE, AE Supply and the Distribution Companies at June 30, 2010 below Standard & Poor’s BB- or Moody’s Ba3, would have required Allegheny to post an additional $89 million of collateral to counterparties, including PJM, for both derivative and non-derivative contracts.

Allegheny’s consolidated capital structure was as follows:

	June 30, 2010			December 31, 2009
(In millions)	Amount		%	Amount		%
Long-term debt	$	4,628.8	58.3	$	4,557.8	59.4
Allegheny Energy, Inc. common stockholders’ equity		3,305.9	41.7		3,113.2	40.6
Total	$	7,934.7	100.0	$	7,671.0	100.0

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2010 Debt Activity

Borrowings and principal repayments on debt during the six months ended June 30, 2010 were as follows:

(In millions)	Issuances		Repayments
AE:
AE Revolving Credit Facility	$	130.1	$	130.1
TrAIL Company:
Medium-Term Notes		450.0		0
New TrAIL Company Credit Facility—Revolver		195.0		0
TrAIL Company Credit Facility—Term Loan (a)		30.0		465.0
TrAIL Company Credit Facility – Revolver (a)		0		20.0
West Penn:
Transition Bonds		0		16.0
Revolving credit facility		20.0		5.0
Monongahela:
Medium-Term Notes		0		110.0
Environmental Control Bonds		0		5.5
Potomac Edison:
Environmental Control Bonds		0		1.7
Revolving credit facility		110.0		110.0
Consolidated Total	$	935.1	$	863.3

(a) Represents debt under TrAIL Company’s previous credit facility, which was repaid and replaced in January 2010 by a new revolving credit facility, which is described below.

During January 2010, Monongahela repaid $110 million aggregate principal amount of its 7.36% medium-term notes.

On January 25, 2010, TrAIL Company issued $450 million aggregate principal amount of 4.0% senior unsecured notes due in 2015 and also entered into a new $350 million senior unsecured revolving credit facility with a three-year maturity. Borrowings under the new facility bear interest that is calculated based on the London Interbank Offered Rate, plus a margin based on TrAIL Company’s senior unsecured credit rating. TrAIL Company used the net proceeds from the sale of the notes, together with funds from its new credit facility, to repay all amounts outstanding under the $550 million senior unsecured credit facility that it entered into in 2008.

On May 3, 2010, Potomac Edison and West Penn entered into new $150 million and $200 million senior unsecured revolving credit facilities, respectively. On May 4, 2010, AE entered into a new $250 million senior unsecured revolving credit facility. The new AE revolving credit facility replaces AE’s previous $376 million revolving credit facility, which was scheduled to mature in May 2011. The AE and West Penn facilities mature April 30, 2013. The Potomac Edison facility matures on December 31, 2011, but it will be automatically extended to April 30, 2013, subject to Potomac Edison securing necessary authorization under Virginia law. Loans under all three new facilities generally bear interest that is calculated based on the London Interbank Offered Rate, plus a margin based on such entity’s senior unsecured credit rating. Currently, the margins are 3.0% for AE and 2.75% for Potomac Edison and West Penn. Allegheny capitalized approximately $5.6 million in debt issuance costs related to the three new facilities.

On July 16, 2010, AE Supply redeemed all $150.5 million of its outstanding 7.80% Medium Term Notes due 2011 and expensed approximately $7.2 million in redemption premiums associated with the notes.

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Dividends

On June 21, 2010 and March 22, 2010, AE paid cash dividends on its common stock of $0.15 per share to shareholders of record at the close of business on June 7, 2010 and March 8, 2010, respectively. On July 8, 2010, AE’s Board of Directors authorized a cash dividend on its common stock of $0.15 per share payable on September 27, 2010 to shareholders of record on September 13, 2010.

Capital Expenditures

Actual capital expenditures for 2009 and estimated capital expenditures for 2010 and 2011 are shown on a cash basis in the following table. The scope, amounts and timing of capital projects and related expenditures are subject to continuing review and adjustment, and actual capital expenditures may vary from these estimates.

	Actual 2009		Projected
(in millions)			2010		2011
Transmission and distribution:
TrAIL and TrAIL Company projects (a)	$	455	$	429	$	144
PATH (b)		44		32		132
Smart meter procurement and installation (c)		24		174		103
Other transmission and distribution		211		213		300
Total transmission and distribution		734		848		679
Environmental:
Fort Martin Scrubbers		161		34		0
Hatfield Scrubbers		135		21		0
Other environmental		39		88		155
Total environmental		335		143		155
Generation projects, excluding environmental projects included above		82		93		62
Other		1		5		3
Total capital expenditures	$	1,152	$	1,089	$	899

(a) TrAIL has a target completion date of 2011 and an estimated cost, excluding AFUDC, of approximately $925 million. TrAIL Company is also engaged in other transmission projects.

(b) Allegheny’s share of the estimated cost of the PATH project is approximately $1.4 billion. The PJM in-service deadline for the PATH project is June 1, 2015.

(c) Consists of expenditures related to Allegheny’s procurement and installation of smart meters to comply with Pennsylvania’s Act 129. Allegheny currently is re-evaluating its Act 129 compliance strategy, including both its plans with respect to smart meter deployment and certain smart meter-dependent aspects of its Energy Efficiency and Conservation Plan, with a view toward developing a less costly alternative to meet the 2011 and 2013 energy consumption and demand reduction requirements. See “Regulatory Framework Affecting Allegheny” for additional information.

Other Matters Concerning Liquidity and Capital Requirements

Allegheny makes cash contributions to its qualified pension plan to meet the minimum funding requirements of employee benefit and tax laws and may make additional discretionary contributions to increase the funded level of the plan. Allegheny expects to contribute approximately $80.0 million to its qualified pension plan during the remainder of 2010 and expects to contribute approximately $2.0 million during the remainder of 2010 to fund postretirement benefits other than pensions.

Allegheny has various obligations and commitments to make future cash payments under debt instruments, lease arrangements, fuel and transportation agreements and other contracts. See Note 17, “Commitments and Contingencies,” to Allegheny’s consolidated financial statements for additional information.

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Off-Balance Sheet Arrangements

AE has no off-balance sheet arrangements that have, or are reasonably likely to have, a current or future material effect on its financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources.

Cash Flows

Operating Activities

Allegheny’s cash flows from operating activities result primarily from the generation, sale and delivery of electricity. Future cash flows will be affected by the economy, weather, customer choice, future regulatory proceedings and future demand and market prices for energy, as well as Allegheny’s ability to produce and supply its customers with power at competitive prices. Cash flows from operating activities are summarized as follows:

(In millions)	Six Months Ended June 30,
	2010			2009
Net income	$	208.4		$	207.0
Non-cash items included in income		268.9			217.6
Contributions to pension and other postretirement plans		(3.8	)		(4.2	)
Changes in certain assets and liabilities		(109.5	)		(179.4	)
Net cash provided by operating activities	$	364.0		$	241.0

The non-cash items included in income for the six months ended June 30, 2010 primarily consisted of depreciation and amortization of $160.4 million and deferred income taxes of $111.2 million. Changes in certain assets and liabilities primarily consisted of changes in receivables and payables of $71.6 million, resulting from normal working capital activity, and changes in prepaid and accrued taxes of $27.3 million, primarily as a result of timing differences associated with the payments of certain tax obligations.

The non-cash items included in income for the six months ended June 30, 2009 primarily consisted of depreciation and amortization of $135.7 million and deferred income taxes of $135.8 million. Changes in certain assets and liabilities primarily consisted of changes in accrued taxes and prepaid taxes of $77.7 million, primarily as a result of timing differences associated with the payments of certain tax obligations, and an increase in materials, supplies and fuel inventories of $75.2 million, primarily as a result of increased fuel inventory levels and higher prices.

Investing Activities

Cash flows from investing activities are summarized as follows:

(In millions)	Six Months Ended June 30,
	2010			2009
Capital expenditures	$	(511.0	)	$	(550.2	)
Proceeds from sale of Virginia distribution business		317.2			0
Decrease in restricted funds		25.1			104.6
Deconsolidation of PATH WV		(3.4	)		0
Other investments		1.3			(1.2	)
Net cash used in investing activities	$	(170.8	)	$	(446.8	)

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Cash flows used in investing activities for the six months ended June 30, 2010 were $170.8 million and primarily consisted of $511.0 million of capital expenditures, partially offset by the $317.2 million in proceeds received from the sale of Potomac Edison’s Virginia distribution business.

Cash flows used in investing activities for the six months ended June 30, 2009 were $446.8 million and primarily consisted of $550.2 million of capital expenditures, partially offset by a $104.6 million decrease in restricted funds, primarily due to the use of restricted funds associated with the Fort Martin Scrubber project to pay for construction costs.

Financing Activities

Cash flows from financing activities are summarized as follows:

(In millions)	Six Months Ended June 30,
	2010			2009
Issuance of long-term debt	$	917.1		$	277.1
Repayment of long-term debt		(863.3	)		(167.4	)
Equity contribution to PATH, LLC by a joint venture partner		0			0.5
Return of capital, PATH, LLC		0			(0.2	)
Payments on capital lease obligations		(5.6	)		(4.4	)
Share-based excess tax benefits		0			19.7
Proceeds from exercise of employee stock options		0.5			1.2
Cash dividends paid on common stock		(50.9	)		(50.8	)
Net cash provided by (used in) financing activities	$	(2.2	)	$	75.7

Cash flows used in financing activities for the six months ended June 30, 2010 were $2.2 million and primarily consisted of $863.3 million in various debt repayments, and $50.9 million of cash dividends paid on common stock, partially offset by $917.1 million from borrowings primarily under TrAIL Company’s Medium-Term Notes and the revolving credit facilities for AE, TrAIL Company and Potomac Edison.

Cash flows provided by financing activities for the six months ended June 30, 2009 were $75.7 million and primarily consisted of $277.1 million from borrowings primarily under credit facilities for TrAIL Company and AE Supply and $19.7 million from share-based excess tax benefits, partially offset by $167.4 million in various debt repayments, and $50.8 million of cash dividends paid on common stock.

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OTHER MATTERS

Critical Accounting Policies

A summary of critical accounting policies is included under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in the 2009 Annual Report on Form 10-K. Allegheny’s critical accounting policies have not changed materially from those reported in the 2009 Annual Report on Form 10-K.

Recent Accounting Pronouncements

See Note 3, “Recently Adopted and Recently Issued Accounting Standards” in Allegheny’s Notes to Consolidated Financial Statements, included herein for a summary of recently adopted and recently issued accounting standards that will impact Allegheny.

REGULATORY FRAMEWORK AFFECTING ALLEGHENY

The interstate transmission services and wholesale power sales of the Distribution Companies, TrAIL Company, PATH, LLC, AE Supply and AGC are regulated by FERC under the FPA. The Distribution Companies’ local distribution service and sales at the retail level are subject to state regulation. In addition, Allegheny is subject to numerous other local, state and federal laws, regulations and rules. See Item 1A, “Risk Factors,” in the 2009 Annual Report on Form 10-K and Part II, Item 1A, “Risk Factors,” in this report.

Federal Regulation and Rate Matters

FERC, Competition and RTOs

Allegheny’s generation and transmission businesses are significantly influenced by the actions of FERC through policies, regulations and orders issued pursuant to the FPA. The FPA gives FERC exclusive jurisdiction over the rates, terms and conditions of wholesale sales and transmission of electricity in interstate commerce. Entities, such as the Distribution Companies, TrAIL Company, the operating subsidiaries of PATH, LLC, AE Supply and AGC, that sell electricity at wholesale or own or operate transmission facilities are subject to FERC jurisdiction and must file their rates, terms and conditions for such sales or services with FERC. Rates for wholesale sales of electricity may be either cost-based or market-based. Rates for use of transmission facilities are determined on a cost basis.

FERC’s authority under the FPA, as it pertains to Allegheny’s generation and transmission businesses, also includes, but is not limited to: licensing of hydroelectricity projects; transmission interconnections with other electric facilities; transfers of public utility property; mergers, acquisitions and consolidation of public utility systems and companies; issuance of certain securities and assumption of certain liabilities; accounting and methods of depreciation; transmission reliability; siting of certain transmission facilities; allocation of transmission rights; relationships between holding companies and their public utility affiliates; availability of books and records; and holding of a director or officer position at more than one public utility or specified company.

FERC’s policies, regulations and orders encourage competition among wholesale sellers of electricity. To support competition, FERC requires public utilities that own transmission facilities to make such facilities available on a non-discriminatory, open-access basis and to comply with standards of conduct that prevent transmission-owning utilities from giving their affiliated sellers of electricity preferential access to the transmission system and to transmission information. To further competition, FERC encourages transmission-owning utilities to participate in RTOs such as PJM, by transferring functional control over their transmission facilities to RTOs.

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All of Allegheny’s generation assets and power supply obligations are located within the PJM market, and PJM maintains functional control over the transmission facilities owned by the Distribution Companies and TrAIL Company. PJM operates a competitive wholesale electricity market and coordinates the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. PJM is also responsible for developing and implementing the RTEP for the PJM region to ensure reliability of the electric grid and promote market efficiency. In addition, PJM determines the requirements for, and manages the process of, interconnecting new and expanded generation facilities to the grid. Changes in the PJM tariff, operating agreement, policies and/or market rules could adversely affect Allegheny’s financial results. See Item 1A, “Risk Factors,” in the 2009 Annual Report on Form 10-K.

Transmission Rate Design. FERC actions with respect to the transmission rate design within PJM may impact the Distribution Companies. Beginning in July 2003, FERC issued a series of orders related to transmission rate design for the PJM and Midwest Independent Transmission System Operator, Inc. (the “Midwest ISO”) regions. Specifically, FERC ordered the elimination of multiple and additive (i.e., “pancaked”) rates and called for the implementation of a long-term rate design for these regions. In November 2004, FERC rejected long-term regional rate proposals, concluding that neither the rate design proposals nor the existing PJM rate design had been shown to be just and reasonable. FERC ordered the continuation of the existing PJM zonal “license plate” rate design and the implementation of a transition charge for these regions during a 16-month transition period commencing on December 1, 2004 and ending on March 31, 2006. On May 21, 2010, FERC denied all requests for rehearing with regard to transmission rate design within the PJM region. A petition for review of this order and the underlying orders has been filed with the United States Court of Appeals for the District of Columbia Circuit. Allegheny cannot predict the outcome of this proceeding or whether it will have a material impact on its business or financial position.

During the now-expired transition period, the Distribution Companies were both payers and payees of transition charges. These charges resulted in the payment by the Distribution Companies of $13.3 million and payments to the Distribution Companies of $3.5 million during the transition period. Following the evidentiary hearing, an administrative law judge issued an initial decision finding the methodologies used to develop the transition charges to be deficient. On May 21, 2010, FERC issued an order on the initial decision, which reversed in part and affirmed in part the initial decision and requires the submission of a compliance filing by August 19, 2010 to reflect certain adjustments in the transition charges. Allegheny is currently determining the extent to which these adjustments may require the Distribution Companies to refund some portion of the amounts received from these transition charges, entitle them to receive additional revenue from these charges, require them to pay additional amounts as a result of increases in the transition charges previously billed, or entitle them to receive refunds of transition charges previously billed. Prior to the issuance of the May 21st order, the Distribution Companies entered into nine partial settlements with regard to the transition charges, and FERC has approved all of the settlements. Several parties have requested rehearing of the May 21st order on the initial decision. Allegheny cannot predict the outcome of this proceeding or whether it will have a material impact on its business or financial position.

In April 2007, FERC issued an order addressing transmission rate design within the PJM region. In the order, FERC directed the continuation of the zonal “license plate” rate design for all existing transmission facilities within the PJM region, the allocation of costs of new, centrally-planned transmission facilities operating at or above 500 kV on a region-wide “postage stamp” or “socialized” basis, and the development of a detailed “beneficiary pays” methodology for the allocation of costs of new transmission facilities below 500 kV. Subsequently, FERC approved a detailed “beneficiary pays” methodology developed through settlement discussions among several parties to the underlying FERC proceedings. On August 6, 2009, the U. S. Court of Appeals for the Seventh Circuit remanded this decision to FERC for further justification with regard to the allocation of costs for new 500 kV and above transmission facilities but denied petitions for review relating to FERC’s decision with regard to the pricing of existing transmission facilities. On January 21, 2010, FERC issued an order establishing a paper hearing in response to the Seventh Circuit’s remand. On April 13, 2010, PJM

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submitted to FERC information required by the order. The Distribution Companies submitted comments in response to the information provided by PJM on May 28, 2010. Allegheny cannot predict the outcome of this proceeding or whether it will have a material impact on its business or financial position.

Under the zonal “license plate” rate design for existing transmission facilities, costs associated with such facilities are allocated on a load ratio share basis to load serving entities, such as local distribution utilities, located within the transmission owner’s PJM transmission zone. As a result of this rate design, the load serving entity does not pay for the cost of transmission facilities located in other PJM transmission zones even if the load serving entity engages in transactions that rely on transmission facilities located in other zones. The region-wide “postage stamp” or “socialized” rate design for new, centrally-planned transmission facilities operating at or above 500 kV results in charging all load serving entities within the PJM region a uniform rate based on the aggregated costs of such transmission facilities within the PJM region irrespective of whether the transmission service provided to the load serving entity requires the actual use of such facilities. For the “beneficiary pays” methodology, the costs of new facilities under 500 kV are allocated to load serving entities based on a methodology that considers several factors but is not premised upon the proximity of the load serving entity to the new facilities or the zone in which the new facilities are located.

In January 2008, FERC accepted a compliance filing submitted by certain PJM and Midwest ISO transmission owners establishing the transmission pricing methodology for transactions involving transmission service originating in the PJM region or the Midwest ISO region and terminating in the other region. The methodology maintains the existing rate design for such transactions under which PJM and Midwest ISO treat transactions that source in one region and sink in the other region the same as transactions that source and sink entirely in one of the regions. These inter-regional transactions are assessed only the applicable zonal charge of the zone in which the transaction sinks and no charge is assessed in the zone of the region where the transaction originates. Judicial review of FERC’s order in this matter is pending. Allegheny cannot predict the outcome of these proceedings or whether they will have a material impact on its business or financial position.

Wholesale Markets. In August 2005, PJM filed at FERC to replace its capacity market with a new Reliability Pricing Model, or “RPM,” to address reliability concerns. On April 20, 2006, FERC issued an initial order that found PJM’s capacity market to be unjust and unreasonable and set a process to resolve features of the RPM that needed to be analyzed further before it could determine whether the RPM is a just and reasonable capacity market process. FERC ordered the implementation of settlement procedures in this proceeding, and AE Supply and the Distribution Companies joined in a settlement agreement that was filed with the FERC on September 29, 2006. The settlement agreement created a locational capacity market in PJM, in which PJM procures needed capacity resources through auctions held three years in advance at prices and in quantities determined by an administratively established demand curve. Under the settlement agreement, capacity needs in PJM are met either through purchases made in the proposed auctions or through commitments by load serving entities (“LSEs”) to self-supply their capacity needs. On December 22, 2006, FERC conditionally approved the settlement agreement, the implementation of which began with the 2007-2008 PJM planning year. Base year capacity auctions were held in April, July and October of 2007 and January and May of 2008, 2009 and 2010. On June 25, 2007 and again on November 11, 2007, FERC issued orders denying pending requests for rehearing of the December 22, 2006 order and affirming its acceptance of the RPM settlement agreement. Several parties have appealed FERC’s orders approving the RPM settlement, and those appeals are currently pending at the United States Court of Appeals for the District of Columbia Circuit. On May 30, 2008, several parties naming themselves the “RPM Buyers” filed a complaint at FERC seeking a retroactive reduction in the RPM clearing prices for several RPM auctions that have already been conducted. On September 19, 2008, FERC issued an order denying the RPM Buyers’ complaint. In June 2009, FERC denied requests for rehearing of the September 19, 2008 order. The Maryland PSC and New Jersey Board of Public Utilities have appealed FERC’s order denying the RPM Buyers’ complaint to the United States Court of Appeals for the District of Columbia Circuit, which appeal remains pending.

PJM Calculation Error. On March 8, 2010, the Midwest ISO filed two complaints against PJM. Both complaints are related to a modeling error that PJM discovered in September 2009. PJM reported that a modeling

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error in its system impacted the manner in which market-to-market power flow calculations were made between PJM and the Midwest ISO. Since April 2005, PJM had incorrectly modeled the ownership of certain generation resources in its system. The generation resources in question had an impact on power flows across the PJM/Midwest ISO border, and therefore the ownership of those resources (i.e., whether they were owned by a PJM company or a Midwest ISO company) had an impact on the way in which PJM and the Midwest ISO should have been compensated for market-to-market transactions. The Midwest ISO claims that this error resulted in PJM underpaying the Midwest ISO by approximately $130 million over the time period in question. The first complaint seeks a refund by PJM to the Midwest ISO of $130 million plus interest. The second complaint alleges that PJM did not properly trigger market-to-market settlements between PJM and the Midwest ISO during times when it was required to do so under the Joint Operating Agreement between the two companies. The Midwest ISO claims that PJM’s failure to act as required may have cost the Midwest ISO $5 million or more. The second complaint requests refunds of this additional amount. As PJM market participants, AE Supply and Monongahela may be liable for a portion of any refunds ordered in this case. PJM, Allegheny and other PJM market participants filed responses to the Midwest ISO complaints on April 12, 2010 denying any liability. In its response Allegheny argued that even if PJM had in fact committed an error that impacted market-to-market settlements there were both legal and equitable reasons why FERC should decline to order any refunds be paid. Also on April 12, PJM filed a related complaint against the Midwest ISO claiming that the Midwest ISO improperly called for market-to-market settlements several times during the same time period covered by the two Midwest ISO complaints. PJM claims these improper actions by the Midwest ISO may have cost the PJM market participants $25 million or more. On June 29, 2010, FERC issued an initial order on the complaints. FERC’s order consolidated all three of the pending complaints and set all disputed issues for hearing. The June 29th order did not resolve any of the issues in dispute. The hearings required by the June 29 order will be held in abeyance while parties engage in FERC sponsored settlement discussions. A full evidentiary hearing on the substance of the complaints will be held if settlement cannot be achieved. Allegheny intends to participate in the FERC ordered settlement discussions and any subsequent hearings but cannot predict their outcome.

Reliability Standards. The Energy Policy Act amended the FPA to, among other matters, provide FERC with the authority to oversee the establishment and enforcement of mandatory reliability standards designed to assure the reliable operation of the bulk power system. FERC certified NERC as the Electric Reliability Organization responsible for developing and enforcing continent-wide reliability standards. NERC has established, and the FERC has approved, reliability standards that impose certain operating, record-keeping and reporting requirements on the Distribution Companies, TrAIL Company, PATH, LLC, AE Supply and AGC.

While NERC is charged with establishing and enforcing appropriate reliability standards, it has delegated its day-to-day implementation and enforcement to eight regional oversight entities, including ReliabilityFirst Corporation (“ReliabilityFirst”). These regional oversight entities are responsible for developing regional reliability standards that are consistent with NERC’s standards. Each regional entity has its own compliance program designed to monitor, assess and enforce compliance with the applicable reliability standards through compliance audits, self-reporting and exception reporting mechanisms, self certifications, compliance violation investigations, periodic data submissions and complaint processes. Allegheny is a member of ReliabilityFirst, participates in the NERC and ReliabilityFirst stakeholder processes and monitors and manages its operations in response to the ongoing development, implementation and enforcement of relevant reliability standards. Allegheny has been, and will continue to be, subject to routine audits with respect to its compliance with applicable reliability standards and has settled certain related issues. In addition, ReliabilityFirst is currently conducting several violation investigations that have been self-reported by Allegheny. The results of these proceedings and investigations have not had, and are not expected to have, any material impact on Allegheny’s operations or the results thereof. See Item 1A, “Risk Factors,” in the 2009 Annual Report on Form 10-K.

Transmission Expansion

TrAIL Project. TrAIL is a new, 500 kV transmission line currently under construction that will extend from southwest Pennsylvania through West Virginia and into northern Virginia. TrAIL is scheduled to be completed and placed in service no later than June 2011. PJM, which is an RTO, directed the construction of TrAIL

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pursuant to its 2006 RTEP to assure the continued reliability of the transmission grid and reduce congestion in the PJM region. FERC authorized a return on equity of 12.7% for TrAIL and the static volt-ampere reactive power compensator at the Black Oak substation and 11.7% for all other TrAIL Company transmission projects for which an incentive rate of return was not requested; a return on CWIP for most components of TrAIL prior to completion of construction and placement into service; and recovery of prudently incurred development and construction costs if TrAIL is abandoned as a result of factors beyond TrAIL Company’s control.

PATH Project. PATH is a 765 kV transmission line that is proposed to extend through West Virginia and into Maryland. PJM initially authorized the construction of PATH in June 2007. Allegheny and a subsidiary of AEP formed PATH, LLC to build PATH, and in December 2007, PATH, LLC submitted a filing to FERC under Section 205 of the FPA to implement a formula rate tariff effective March 1, 2008. The filing also included a request for certain incentive rate treatments. In February 2008, FERC issued an order setting the cost of service formula rate to calculate annual revenue requirements for the project and authorizing: a return on equity of 14.3%; a return on CWIP; recovery of prudently incurred start-up business and administrative costs incurred prior to the time the rates go into effect; and recovery of prudently incurred development and construction costs if PATH is abandoned as a result of factors beyond the control of PATH, LLC.

In December 2008, PATH, LLC submitted to FERC a settlement of the formula rate and protocols with the active parties. FERC approval of the settlement is pending. Rehearing of the February 29, 2008 order with respect to return on equity remains pending before FERC.

In December 2009, PJM conducted certain sensitivity analyses as directed by a Virginia SCC Hearing Examiner and advised that, based on these analyses, the PATH Project might not be needed in 2014 as initially expected as a result of a reduction in the scope and severity of observed NERC reliability violations. PJM advised that, consistent with PJM processes, the PATH Project would be considered in the 2010 RTEP to determine when it would be needed to resolve NERC reliability violations. On June 17, 2010, PJM, as part of the 2010 RTEP, requested that PATH, LLC proceed with all efforts related to the PATH Project, including state regulatory proceedings, assuming a required in-service date for the project of June 1, 2015.

PURPA

The Public Utility Regulatory Policies Act of 1978 (“PURPA”) requires electric utility companies, such as the Distribution Companies, to interconnect with, provide back-up electric service to and purchase electric capacity and energy from qualifying small power production and cogeneration facilities. However, as a result of changes in the FPA arising out of the Energy Policy Act, electric utilities are no longer required to enter into any new contractual obligation to purchase energy from a qualifying facility if FERC finds that the facility has non-discriminatory access to a functioning wholesale market and open-access transmission.

For 2009, the Distribution Companies committed to purchase 479 MWs of qualifying PURPA capacity, and PURPA expense pursuant to these contracts totaled approximately $230.6 million. The average cost to the Distribution Companies of these power purchases was 6.8 cents/kWh. In December 2009, AE Supply purchased Allegheny Lock and Dam Nos. 5 & 6, which together supply a total of 13 MWs. Previously, the Distribution Companies had purchased power generated by these facilities pursuant to PURPA contracts. Consequently, the Distribution Companies have committed to purchase 466 MWs of qualifying PURPA capacity for 2010. The Distribution Companies are currently authorized to recover substantially all of these costs in their retail rates. The Distribution Companies’ obligations to purchase power from qualified PURPA projects in the future may exceed amounts they are authorized to recover from their customers, which could result in losses related to the PURPA contracts.

State Rate Regulation

Pennsylvania

Pennsylvania’s Electricity Generation Customer Choice and Competition Act (the “Customer Choice Act”), which was enacted in 1996, gave all retail electricity customers in Pennsylvania the right to choose their

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electricity generation supplier as of January 2, 2000. Under the Customer Choice Act and a subsequent restructuring settlement (the “1998 Restructuring Settlement”) approved by the Pennsylvania PUC, West Penn transferred its generation assets to AE Supply. West Penn retained its T&D assets. Under the 1998 Restructuring Settlement, West Penn is the default provider for those customers who do not choose an alternate supplier, whose alternate supplier does not deliver, or who have chosen to return to West Penn service, in each case at rates that are capped at various levels during the applicable transition period. West Penn’s T&D assets are subject to traditional regulated utility ratemaking (i.e., cost-based rates).

Merger. On May 14, 2010, West Penn and TrAIL Company filed a joint application with FirstEnergy requesting authorization for a change of control of West Penn and TrAIL Company as the result of the proposed Merger.

Joint Petition and Extension of Generation Rate Caps. By order entered on May 11, 2005, the Pennsylvania PUC approved a Joint Petition for Settlement and for Modification of the 1998 Restructuring Settlement, as amended, among West Penn, the Pennsylvania Office of Consumer Advocate, the Office of Small Business Advocate, The West Penn Power Industrial Intervenors and certain other parties (the “2004 Joint Petition”). The 2004 Joint Petition extended generation rate caps for most customers from 2008 to 2010 and provided for increases in generation rates in 2007, 2009 and 2010, in addition to previously approved rate cap increases for 2006 and 2008. The order approving the 2004 Joint Petition also extended distribution rate caps from 2005 through 2007, with an additional rate cap in place for 2009 at the rate in effect on January 1, 2009. The intent of this transition plan is to gradually move generation rates closer to market prices. Rate caps on transmission services expired on December 31, 2005.

Default Service Regulations. In May 2007, the Pennsylvania PUC entered a Final Rulemaking Order (the “May 2007 Order”) promulgating regulations defining the obligations of electric distribution companies (“EDCs”), such as West Penn, to provide generation default service to retail electric customers who do not or cannot choose service from a licensed electric generation supplier (“EGS”) at the conclusion of the EDCs’ restructuring transition periods. West Penn’s transition period will end for the majority of its customers on December 31, 2010, when its generation rate caps expire.

The regulations promulgated by the May 2007 Order provide that the incumbent EDC will be the default service provider (“DSP”) in its service territory, although the Pennsylvania PUC may reassign the default service obligation to one or more alternative DSPs when necessary for the accommodation, safety and convenience of the public. The DSP is required to file a default service plan not later than 12 months prior to the end of the applicable generation rate cap. The default service plan must identify the DSP’s generation supply acquisition strategy and include a rate design plan to recover all reasonable costs of default service. The default service plan must be designed to acquire generation supply at prevailing market prices to meet the DSP’s anticipated default service obligation at reasonable costs. A DSP’s affiliate generation supplier may participate in the DSP’s competitive bid solicitations for generation service. DSPs will use an automatic energy adjustment clause to recover all reasonable costs of obtaining alternative energy pursuant to the Alternative Energy Portfolio Standards Act, and the DSP may use an automatic adjustment clause to recover non-alternative energy default service costs. Automatic adjustment clauses will be subject to annual review and audit by the Pennsylvania PUC. Default service rates will be adjusted on a quarterly basis, or more frequently, for customer classes with a peak load up to 500 kW, and on a monthly basis, or more frequently, for customer classes with peak loads greater than 500 kW.

In October 2007, West Penn filed a default service plan with the Pennsylvania PUC. The Pennsylvania PUC administrative law judge entered a final order on July 25, 2008 that largely approved West Penn’s proposed default service plan, including its full requirements procurement approach and rate mitigation plan. West Penn filed tariff supplements implementing the default service plan in September 2008 and January 2009. On February 6, 2009, West Penn filed a petition with the Pennsylvania PUC requesting approval to advance the first series of default service procurements for residential customers from June 2009 to April 2009 to take advantage

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of a downturn in market prices for power. West Penn’s petition was approved by the Pennsylvania PUC in March 2009, and West Penn began to conduct advanced procurements in April 2009. Also in April 2009, West Penn petitioned the Pennsylvania PUC for approval to further accelerate default service procurements increasing by 550 MWs the amount of power that it planned to procure in June 2009. By Order entered May 14, 2009, the Pennsylvania PUC approved the request to advance the procurement of 550 MWs, and the procurement occurred in June 2009. West Penn has procured over 70% of the generation supply needed to serve its residential customers and small and medium non-residential customers in 2011.

Advanced Metering and Demand-Side Management Initiatives. In October 2008, Pennsylvania adopted Act 129, which includes a number of measures relating to conservation, demand-side management and power procurement processes. Act 129 requires each EDC with more than 100,000 customers to adopt a plan, approved by the Pennsylvania PUC, to reduce, by May 31, 2011, electric consumption by at least one percent of its expected consumption for June 1, 2009 through May 31, 2010. By May 31, 2013, the total annual weather-normalized consumption is to be reduced by a minimum of three percent, and peak demand is to be reduced by a minimum of four and one-half percent of the EDC’s annual system peak demand. Act 129 also:

• directed the Pennsylvania PUC to adopt an energy conservation and efficiency program to require EDCs to develop and file, by July 1, 2009, plans to reduce energy demand and consumption; and

• required EDCs to file a plan for “smart meter” technology procurement and installation in August 2009.

West Penn expects to incur significant capital expenditures in 2010 and beyond to comply with these requirements.

Act 129 also requires EDCs to obtain energy through a prudent mix of contracts, with an emphasis on competitive procurement. The Act includes a “grandfather” provision for West Penn’s procurement and rate mitigation plan, which was previously approved by the Pennsylvania PUC.

On June 30, 2009 West Penn filed its Energy Efficiency and Conservation Plan (the “EE&C Plan”) containing 22 programs to meet its Act 129 demand and consumption reduction obligations. The proposed programs cover most energy-consuming devices of residential, commercial and industrial customers. The EE&C Plan also proposes a reconcilable surcharge mechanism to obtain full and current cost recovery of the EE&C Plan costs as provided in Act 129. The EE&C Plan projected an aggregated cost of the energy efficiency measures in the amount of approximately $94.3 million through mid 2013. A hearing concerning West Penn’s EE&C Plan was held August 19, 2009.

The Pennsylvania PUC approved West Penn’s EE&C Plan, in large part, by Opinion and Order entered October 23, 2009. The new programs approved by the Pennsylvania PUC include: rebates for customers who purchase high efficiency appliances, lighting and heating and cooling systems; residential home audits and rebates toward implementing audit recommendations; home audit, weatherization and air conditioner replacement programs for low-income customers; new rate options that will provide financial incentives for customers to lower their demand for electricity or shift their usage to lower-priced times; incentives for customers who install in-home devices that reduce electric usage when demand is highest; and various programs for commercial, industrial, government and non-profit customers to increase energy efficiency and conservation. The Pennsylvania PUC also approved West Penn’s proposal to recover its EE&C Plan costs on a full and current basis via an automatic surcharge to customers’ bills, subject to an annual reconciliation mechanism.

The Pennsylvania PUC declined to approve West Penn’s proposed distributed generation program and West Penn’s proposed contract demand response program and encouraged West Penn to submit revisions to both programs. On December 21, 2009, West Penn filed an amended EE&C Plan as directed by the Pennsylvania PUC, in which it added a new customer resources demand response program intended to replace the previously proposed distributed generation and contract demand programs. The Pennsylvania PUC entered an order on March 1, 2010, approving in part and rejecting in part West Penn’s revised plan and directing West Penn to

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include additional detail on the costs associated with the previously approved customer load response program and the new customer resources demand response program. On April 29, 2010, West Penn filed its amended plan, which the Pennsylvania PUC approved by order entered on June 23, 2010.

On August 14, 2009, West Penn filed its Smart Meter Technology Procurement and Installation Plan (the “SMI Plan”). As proposed, the SMI Plan provided for extensive deployment of smart meter infrastructure with replacement of all of West Penn’s approximately 725,000 meters by the end of 2014. West Penn estimated at that time that the total cost of implementing smart meter infrastructure as proposed would be approximately $620 million. A hearing on the SMI Plan was held on November 8, 2009. On December 18, 2009, West Penn filed a motion to reopen the evidentiary record to submit an alternative smart meter plan proposing, among other things, a less rapid deployment of smart meters. On January 13, 2010, the Pennsylvania PUC granted the motion to reopen the record and remanded the proceeding to the administrative law judge (the “ALJ”). The Pennsylvania PUC also waived the January 2010 deadline by which the ALJ’s recommended decision would have been required. The hearing was held on March 16, 2010. On May 6, 2010, the ALJ issued a decision finding that West Penn’s alternative smart meter deployment plan, which contemplates deployment of 375,000 smart meters by May 2012, complies with the requirements of Act 129 and recommending approval of the alternative plan, including West Penn’s proposed cost recovery mechanism.

However, in light of the significant expenditures that would be associated with its smart meter deployment plans and related infrastructure upgrades as previously proposed, as well as its evaluation of recent Pennsylvania PUC decisions approving less rapid deployment proposals by other EDCs, West Penn currently is re-evaluating its Act 129 compliance strategy, including both its plans with respect to smart meter deployment and certain smart meter dependent aspects of its Energy Efficiency and Conservation Plan, with a view toward developing a less costly alternative to meet the 2011 and 2013 energy consumption and demand reduction requirements. On July 21, 2010, the PA PUC issued an order, in response to West Penn’s request, to stay West Penn’s smart meter implementation proceedings for a period of 90 days.

West Penn’s actual cost to implement smart meter infrastructure may vary from any previous estimate as a result of changes in its SMI Plan as ultimately approved by the Pennsylvania PUC and the timing of that approval, among other factors. In accordance with Act 129, West Penn’s SMI Plan requests a cost recovery surcharge for the full and current recovery of the expenditures from customers.

Transmission Expansion. By order entered on December 12, 2008, the Pennsylvania PUC authorized TrAIL Company to construct a 1.2 mile portion of TrAIL in Pennsylvania from the proposed 502 Junction Substation in Greene County to the Pennsylvania-West Virginia state line. In the same order, the Pennsylvania PUC also approved an agreement among TrAIL Company, West Penn and Greene County, Pennsylvania in which, among other provisions, TrAIL Company agreed to engage in a collaborative process to identify possible solutions to reliability problems in the Washington County, Pennsylvania area in lieu of the Prexy Facilities that had been a part of the original TrAIL proposal. The Commonwealth Court of Pennsylvania has affirmed the decision of the Pennsylvania PUC with regard to its authorization for the construction of the 1.2 mile portion of TrAIL. With respect to the reliability problems in the Washington County, Pennsylvania area, a proposed settlement and an amendment to the application based on a consensus of participants in the collaborative process are pending before the Pennsylvania PUC for approval.

Alternative Energy Portfolio Standard. Legislation enacted in 2004 requires the implementation of an alternative energy portfolio standard in Pennsylvania. This legislation requires EDCs and retail electric suppliers in Pennsylvania to obtain certain percentages of their energy supplies from alternative sources. However, the legislation includes an exemption from this requirement for companies, such as West Penn, that are operating within a transition period under the current regulations governing the transition to market competition in Pennsylvania. The full requirement will apply to those companies when their respective transition periods end. West Penn’s compliance period begins on January 1, 2011. The legislation also includes a provision that will allow the Pennsylvania PUC to modify or eliminate these obligations if alternative sources are not reasonably available. The law directs that all costs related to the purchase of electricity from alternative energy sources and

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payments for alternative energy credits will be fully recovered pursuant to an automatic energy adjustment clause. The Pennsylvania PUC entered a final rulemaking order on September 28, 2008, adopting regulations for implementation and enforcement of the legislation.

Reliability Benchmarks. In May 2004, the Pennsylvania PUC modified its utility specific benchmarks and performance standards for electric distribution system reliability. The benchmarks were set too low for West Penn, resulting in required reliability levels that were unattainable. West Penn appealed the benchmarks to the Pennsylvania PUC. In 2005, the parties to the proceeding, including the Consumer Advocate, the Utility Workers Union of America Local 102, and the Rural Electric Association entered into an agreement settling the proceeding and providing West Penn with attainable reliability benchmarks. The Pennsylvania PUC approved the settlement in an Order issued July 27, 2006. According to the Pennsylvania PUC’s Electric Service Reliability in Pennsylvania 2008 report, West Penn’s overall performance in 2008 was substantially better than its performance during 2007. In 2007 and 2008, West Penn’s System Average Interruption Frequency Index, Customer Average Interruption Duration Index and System Average Interruption Duration Index values were better than the applicable standards. As of March 2010, West Penn is satisfying all of the reliability benchmarks and standards approved by the Pennsylvania PUC in its July 2006 order.

West Virginia

In 1998, the West Virginia legislature passed legislation directing the West Virginia PSC to determine whether retail electric competition was in the best interests of West Virginia and its citizens. In response, the West Virginia PSC submitted a plan to introduce full retail competition on January 1, 2001. The West Virginia legislature approved, but never implemented, this plan. In March 2003, the West Virginia legislature passed a bill that clarified the jurisdiction of the West Virginia PSC over electric generation facilities. In 2000, Potomac Edison received approval to transfer its West Virginia generation assets to AE Supply. However, the West Virginia PSC never acted on a similar petition by Monongahela, and Monongahela agreed to withdraw its petition. Based on these actions, Allegheny has concluded that retail competition and the deregulation of generation is no longer likely in West Virginia.

Merger. On May 18, 2010, Monongahela, Potomac Edison and TrAIL Company filed a joint application with FirstEnergy requesting authorization for a change of control of Monongahela, Potomac Edison and TrAIL Company as the result of the proposed Merger.

Rate Case. On August 13, 2009, Monongahela and Potomac Edison filed with the West Virginia PSC a request to increase retail rates by approximately $122.1 million annually, effective June 10, 2010. On January 12, 2010, Monongahela and Potomac Edison filed supplemental testimony discussing a tax treatment change that would result in a revenue requirement that is approximately $7.7 million lower than the requirement included in the original filing. In addition, in December 2009, subsidiaries of Monongahela and Potomac Edison completed a securitization transaction to finance certain costs associated with the installation of Scrubbers at the Fort Martin generating station, which costs would otherwise have been included in the request for rate recovery. Monongahela and Potomac Edison ultimately requested an increase in retail rates of approximately $95 million, rather than $122.1 million, annually. An evidentiary hearing on this matter was scheduled to begin April 5, 2010. However, on April 2, 2010, Monongahela and Potomac Edison filed with the West Virginia PSC a Joint Stipulation and Agreement of Settlement (the “West Virginia Stipulation”) reached with the other parties in the proceeding. The West Virginia Stipulation provides for:

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

• the deferral of February 2010 storm restoration expenses in West Virginia over a maximum five-year period;

• an additional $20 million annualized base rate increase effective January, 2011;

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• a decrease of $20 million in ENEC rates effective January 2011, which amount is deferred for later recovery in 2012; and

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

The West Virginia PSC conducted a hearing on the West Virginia Stipulation on April 6, 2010 and approved the stipulation on June 25, 2010.

Annual Adjustment of Fuel and Purchased Power Cost Rates. On August 29, 2008, Monongahela and Potomac Edison filed with the West Virginia PSC a request to increase retail rates by approximately $173 million annually to reflect expected increases in fuel and purchased power costs during 2009 and under-recovery of past costs through June 2008. The new rates, proposed to become effective January 1, 2009, were submitted pursuant to the schedule for annual fuel and purchased power cost reviews in connection with Monongahela’s and Potomac Edison’s purchased power cost recovery clause in West Virginia. On December 29, 2008, the West Virginia PSC issued an order approving a settlement agreement among Allegheny, the Consumer Advocate Division, the Staff of the West Virginia PSC and the West Virginia Energy Users Group, pursuant to which Allegheny’s rates in West Virginia were increased by $142.5 million annually beginning on January 1, 2009.

On September 1, 2009, Monongahela and Potomac Edison filed their annual fuel adjustment request with the West Virginia PSC, requesting a rate increase of $143.2 million to reflect increases in their unrecovered balances of fuel and purchased power costs that have accrued through June 2009 and projected increases through June 2010. The new rates were submitted pursuant to the schedule for annual fuel and purchased power cost reviews. On December 2, 2009, the parties to the proceeding filed a Joint Stipulation providing that Monongahela and Potomac Edison would receive an increase of $118 million, effective January 1, 2010, plus deferred recovery of an additional $23.1 million effective January 1, 2011, with carrying charges of 6% on the deferred amount. The West Virginia PSC approved the Joint Stipulation on December 29, 2009.

Securitization and Scrubber Project. In May 2005, the state of West Virginia adopted legislation permitting securitization financing for the construction of certain types of pollution control equipment at facilities owned by public utilities that are regulated by the West Virginia PSC, subject to the satisfaction of certain criteria. In April 2006, the West Virginia PSC approved a settlement agreement among Monongahela, Potomac Edison and certain other interested parties relating to Allegheny’s plans to construct Scrubbers at the Fort Martin generation facility in West Virginia. Concurrently, the West Virginia PSC granted Monongahela and Potomac Edison a certificate of public convenience and necessity authorizing the construction and operation of the Scrubbers, approved an intra-company transfer of assets that realigned generation ownership and contractual obligations within the Allegheny system, and issued a related financing order (the “Financing Order”) approving a proposal by Monongahela and Potomac Edison to finance $338 million of project costs using the securitization mechanism provided for by the legislation adopted in May 2005. Specifically, Monongahela and Potomac Edison received approval to issue environmental control bonds secured by the right to collect a surcharge from West Virginia retail customers dedicated to the repayment of the bonds. In October 2006, Monongahela and Potomac Edison filed with the West Virginia PSC a Petition to Reopen Proceedings and to Amend Financing Order (“Petition”), informing the West Virginia PSC that the current estimate for constructing the Scrubbers at Fort Martin had increased from $338 million to an amount up to $550 million. In December 2006, Allegheny reached a settlement agreement with all parties in the reopened cases and filed the agreement with the West Virginia PSC. The West Virginia PSC approved the settlement agreement, authorizing Allegheny to securitize up to $450 million of the estimated construction costs, plus $16.5 million of upfront financing costs and certain other costs. On April 11, 2007, Allegheny completed the securitization with the sale by two indirect subsidiaries of an aggregate of $459.3 million in environmental control bonds.

On July 2, 2009, Monongahela and Potomac Edison requested authority from the West Virginia PSC to finance the remaining costs associated with the Fort Martin Scrubber project through the issuance of additional environmental control bonds. On September 30, 2009, the West Virginia PSC issued a financing order granting

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Monongahela and Potomac Edison the authority, subject to the terms and conditions of the financing order, to issue the bonds and impose the related environmental control charge. On December 23, 2009, MP Environmental Funding LLC, an indirect wholly owned subsidiary of Monongahela, and PE Environmental Funding LLC, an indirect wholly owned subsidiary of Potomac Edison, issued $85,890,000 aggregate principal amount of Senior Secured ROC Bonds, Environmental Control Series B.

Transmission Expansion. On May 15, 2009, PATH WV, PATH Allegheny and certain other related entities (the “PATH Entities”) filed an application with the West Virginia PSC for certificates of public convenience and necessity to construct portions of the PATH Project in West Virginia. On June 3, 2010, the West Virginia PSC granted a motion by the PATH Entities to modify the procedural schedule to provide for an evidentiary hearing commencing on January 10, 2011, with a decision date on May 16, 2011.

Purchase of Distribution Assets. In connection with Potomac Edison’s agreement to sell its Virginia distribution assets, Allegheny has executed an agreement to purchase Shenandoah Valley Electric Cooperative’s West Virginia distribution business. The agreement is expected to be filed for approval by the West Virginia PSC in the third quarter of 2010 for approximately $13 million, subject to certain adjustments through the closing date.

Maryland

In 1999, Maryland adopted electric industry restructuring legislation, which gave Potomac Edison’s Maryland retail electric customers the right to choose their electricity generation suppliers. In 2000, Potomac Edison transferred its Maryland generation assets to AE Supply but remained obligated to provide standard offer generation service (“SOS”) at capped rates to residential and non-residential customers for various periods. The longest such period, for residential customers, expired on December 31, 2008. As discussed below, Potomac Edison has implemented a rate stabilization plan to transition customers from capped generation rates to rates based on market prices. Potomac Edison retained its T&D assets. Potomac Edison’s T&D rates for all customers were capped through 2004 and are otherwise subject to traditional regulated utility ratemaking (i.e., cost-based rates).

Merger. On May 27, 2010, Potomac Edison filed a joint application with FirstEnergy requesting authorization for a change of control of Potomac Edison as the result of the proposed Merger. Under the current schedule, the Maryland PSC is expected to issue its decision by January 7, 2011.

Standard Offer Service. In 2003, the Maryland PSC approved two state-wide settlements relating to the future of PLR and SOS. The settlements extended Potomac Edison’s obligation to provide SOS after the expiration of the generation rate cap periods established for Potomac Edison as part of the 1999 restructuring of Maryland’s electric market. The settlements provided that, after expiration of the generation rate caps, SOS would be provided through 2012 for residential customers, through 2008 for smaller commercial and industrial customers and through 2006 for Potomac Edison’s medium-sized commercial customers. Potomac Edison’s obligation to provide SOS for its largest industrial customers expired at the end of 2005. A 2005 settlement extended Potomac Edison’s SOS obligations to its medium-sized commercial customers through May 2007, and a further order of the Maryland PSC issued on August 28, 2006 extended that obligation through at least the end of May 2009. The Maryland PSC issued an order on November 8, 2006, and a report to the Maryland legislature on December 31, 2006, that would continue SOS to small and medium-sized commercial customers with changes in procurement durations. In another proceeding, the Maryland PSC ordered the utilities to issue a request for proposal for possible acquisition of demand response resources for the period from 2011 to 2016 and to participate in a working group on the development of distributed generation resources. The request for proposal was issued on January 16, 2009. The Maryland PSC issued an order on March 11, 2009 approving the purchase of most of the resources offered, and the utilities have made the purchases.

By statute enacted in 2007, the obligation of Maryland utilities to provide SOS to residential and small commercial customers, in exchange for recovery of their costs plus a reasonable profit, was extended

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indefinitely. The legislation also established a five-year cycle (to begin in 2008) for the Maryland PSC to report to the legislature on the status of SOS. The other Maryland electric utilities providing SOS, all of whose initial settlement obligations have expired, continue to do so essentially in accordance with the terms of the 2003 settlements as modified by the Maryland PSC orders discussed immediately above, as does Potomac Edison. The terms on which Potomac Edison will provide SOS to residential customers after the settlement covering that initial obligation expires in 2012 depend on developments with respect to SOS in Maryland between now and then, including but not limited to possible Maryland PSC decisions in the proceedings discussed below.

The Maryland PSC opened a new docket in August 2007 (Case No. 9117) to consider matters relating to possible “managed portfolio” approaches to SOS, the aggregation of low income SOS customers, and a retail supplier proposal for the utility “purchase” of all retailer receivables (“POR”) at no discount and with no recourse. “Phase II” of the case addressed utility purchases or construction of generation, bidding for procurement of demand response resources and possible alternatives if the TrAIL and PATH projects are delayed or defeated. Hearings on Phase I and II were held in October and November 2007 and in January 2008. The issue regarding POR was ultimately resolved in another proceeding, and the Maryland electric utilities’ tariffs implementing POR went into effect in July 2010. It is unclear when the Maryland PSC will issue its findings on the other issues in this and other related pending proceedings discussed below.

On July 3, 2008, the Maryland PSC issued a further order requiring the utilities to prepare detailed studies of alternatives for possible managed portfolios, with a time horizon out to fifteen years, and to file those studies by October 1, 2008. The Maryland PSC expressly stated that the order “should not be construed… as a decision to modify in any way, the current SOS procurement practice.” Potomac Edison filed its study with the Maryland PSC on October 1, 2008, and the Maryland PSC held hearings on the matter in December 2008. No order has been issued.

Also, on September 29, 2009, the Maryland PSC opened another new proceeding to receive and consider proposals for construction of new generation resources in Maryland. Proposals were initially due to be filed by December 16, 2009, but the Maryland PSC has indefinitely postponed that deadline while it considers recommendations as to what the filings should be required to contain. Also, on December 18, 2009, Governor Martin O’Malley filed a letter in this proceeding in which he characterized the electricity market in Maryland as a “failure” and urged the Maryland PSC to use its existing authority to order the construction of new generation in Maryland, vary the means used by utilities to procure generation and include more renewables in the generation mix.

In August 2007, Potomac Edison filed a plan for seeking bids to serve its Maryland residential load for the period after the expiration of rate caps on December 31, 2008. The Maryland PSC approved the plan in a series of orders issued between September 2007 and September 2008. Potomac Edison will continue to conduct rolling auctions to procure the power supply necessary to serve its customer load going forward.

Rate Stabilization. In special session on June 23, 2006, the Maryland legislature passed emergency legislation directing the Maryland PSC to, among other things, investigate options available to Potomac Edison to implement a rate mitigation or rate stabilization plan for SOS to protect its residential customers from rate shock in connection with the January 1, 2009 expiration of generation rate caps.

In December 2006, Potomac Edison filed with the Maryland PSC a proposed Rate Stabilization Ramp-Up Transition Plan designed to transition residential customers from capped generation rates to rates based on market prices. Under the plan as approved by the Maryland PSC, residential customers who did not elect to opt out of the program began paying a surcharge in June 2007. The application of the surcharge resulted in an overall rate increase of approximately 15% in 2007 and 13% in 2008. With the expiration of the residential generation rate caps and the move to generation rates based on market prices on January 1, 2009, the surcharge converted to a credit on customers’ bills. Funds collected through the surcharge during 2007 and 2008, plus interest, are being returned to customers as a credit on their electric bills, thereby reducing the effect of the rate cap expiration. The

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credit will continue, with adjustments, to maintain rate stability until December 31, 2010 or until all monies collected from customers plus interest are returned. The resulting rate increase in 2009 was 11.3%, and the rate change approved in 2009 for 2010 was actually a decrease of 2.5%. Of Potomac Edison’s approximately 219,000 residential customers in Maryland, as of March 31, 2010, approximately 16.2%, elected to opt-out of, or are not eligible for, Potomac Edison’s plan.

Advanced Metering and Demand Side Management Initiatives. On September 28, 2007, the Maryland PSC issued an order that required the utilities to file detailed plans for how they will meet a proposal-“EmPOWER Maryland”-that in Maryland electric consumption be reduced by 15% by 2015. On October 26, 2007, Potomac Edison filed its initial report on energy efficiency, conservation and demand reduction plans in connection with this order. The Maryland PSC conducted hearings on Potomac Edison’s and other utilities’ plans in November 2007 and further hearings on May 7, 2008.

In a related development, the Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals and setting a deadline of September 1, 2008 for the utilities to file comprehensive plans for attempting to achieve those goals. Potomac Edison filed its proposals on August 29, 2008, asking the Maryland PSC to approve seven programs for residential customers, five programs for commercial, industrial, and governmental customers, a customer education program, and a pilot deployment of Advanced Utility Infrastructure (“AUI”) that Allegheny has previously been testing in West Virginia. On December 31, 2008, the Maryland PSC issued an order approving some of Potomac Edison’s programs and directing that others be redesigned. Potomac Edison filed its revised programs on March 31, 2009, with new cost and benefit information. The Maryland PSC approved the programs on August 6, 2009, and approved cost recovery for the programs on October 6, 2009. Expenditures are expected to be approximately $101 million and will be recovered over the next six years. Meanwhile, the AUI pilot was placed on a separate track and is currently being re-examined after discussion with the Staff of the Maryland PSC and other stakeholders.

Renewable Energy Portfolio Standard. Legislation enacted in 2004 (and supplemented with respect to solar power in 2007 and again in 2010) requires the implementation of a renewable energy portfolio standard in Maryland. Beginning upon the later of the expiration of the transition period for any particular customer class served by a supplier or January 1, 2006, retail electricity suppliers in Maryland must obtain certain percentages of their energy supplies from renewable energy resources. The law provides that if renewable resources are too expensive, or are not available in quantities sufficient to meet the standard in any given year, suppliers can instead opt to pay a “compliance fee.” The law directs the Maryland PSC to allow electric suppliers to recover their costs from customers, including any compliance fees that they incur.

Moratorium on Service Terminations. On March 11, 2009, the Maryland PSC issued an order suspending until further notice the right of all electric and gas utilities in the state to terminate service to residential customers for non-payment of bills. The order directed the utilities and other interested parties to meet and devise proposals for offering payment plans to all residential customers, not just low-income customers. On April 1, 2009, the Staff of the Maryland PSC and utilities filed a plan providing for additional and longer payment plans and for a temporary suspension of requests to customers for increased deposits. The Maryland PSC held a hearing on the matter on April 7, 2009, and subsequently issued an order making various rule changes relating to terminations, payment plans, and customer deposits that make it more difficult for Maryland utilities to collect deposits or to terminate service for non-payment. Potomac Edison and several other utilities filed requests for reconsideration of various parts of the order on May 26, 2009, which motions were denied on September 23, 2009. Potomac Edison filed a notice of appeal of that order on October 23, 2009, but withdrew the appeal when the Maryland PSC issued a further order on November 23, 2009 that clarified the limited scope and duration of the rule changes. The Maryland PSC is continuing to conduct hearings and collect data on payment plans and related issues, and has adopted a set of proposed regulations that expand the summer and winter “severe weather” termination moratoria when temperatures are very high or very low, from one day, as provided by statute, to three days on each occurrence.

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Transmission Expansion. On December 21, 2009, Potomac Edison filed a new application with the Maryland PSC for a certificate of public convenience and necessity to construct the Maryland portions of the PATH Project. The project in Maryland will be owned by PATH Allegheny MD, which is owned by Potomac Edison and PATH Allegheny. The Maryland PSC determined that Potomac Edison is a proper applicant to seek authorization to construct the PATH project in Maryland and has issued a notice stating that it will not deem the application as accepted for filing until the pre-filed testimony is supplemented. Potomac Edison filed supplemental testimony on July 16, 2010.

Virginia

Merger. On June 14, 2010, the joint application filed by Potomac Edison and TrAIL Company along with FirstEnergy requesting authorization for a change of control of Potomac Edison and TrAIL Company as the result of the proposed Merger was deemed complete. Under the current schedule, the Virginia SCC is expected to issue its decision by September 13, 2010.

Sale of Distribution Operations. On June 1, 2010, Potomac Edison sold its electric distribution operations in Virginia (the “Virginia distribution business”) to Rappahannock Electric Cooperative and Shenandoah Valley Electric Cooperative. Cash proceeds from the sale were approximately $317 million, resulting in a pre-tax gain of approximately $45 million. In connection with the sale, Potomac Edison agreed to contribute $27.5 million between July 1, 2011 and July 1, 2014 to reduce the impact of any future rate increases on its former customers, the present value of which was included in the calculation of the $45 million pre-tax gain. In addition, on June 1, 2010 Potomac Edison entered into an agreement to purchase Shenandoah Valley Electric Cooperative’s West Virginia distribution business for approximately $13 million, subject to certain adjustments through the closing date.

Purchased Power Cost Recovery. Until July 1, 2007, Potomac Edison had a power purchase agreement with AE Supply to provide Potomac Edison with the power necessary to serve its retail customers in Virginia at rates that were consistent with generation rate caps in effect pursuant to the Virginia Electric Utility Restructuring Act of 1999 (the “Restructuring Act”). Effective with the expiration of that power purchase agreement on July 1, 2007, Potomac Edison began to purchase the power necessary to serve its Virginia customers through the wholesale market at market prices, through a competitive wholesale bidding process. In April 2007 and again in March 2008, Potomac Edison conducted a competitive bidding process to purchase power requirements from the wholesale market for its retail customer service in Virginia, and AE Supply was the successful bidder with respect to a substantial portion of these requirements.

The Restructuring Act initially capped generation rates until July 1, 2007. In 2004, it was amended to extend capped rates to 2010, but also provided that Virginia utilities that had divested their generation, such as Potomac Edison, could begin to recover purchased power costs on July 1, 2007. In 2007, the law was revised again to provide for generation rate caps to end on December 31, 2008. The market prices at which Potomac Edison has purchased power since the expiration in 2007 of its power purchase agreement with AE Supply were significantly higher than the capped generation rates initially set under the Restructuring Act.

Although the Restructuring Act did provide for generation rate caps through December 31, 2008, it was amended to provide, among other things, that Virginia utilities, such as Potomac Edison, could begin to recover purchased power costs, such that the rates a utility would be permitted to charge Virginia customers beginning on July 1, 2007 would be based on the utility’s cost of purchased power.

In an April 2007 filing with the Virginia SCC, Potomac Edison requested to adjust its fuel factor and to implement a rate stabilization plan, including an increase in retail rates of approximately $103 million to be phased in over three years beginning July 1, 2007, to offset the impact of increased purchased power costs. In June 2007, the Virginia SCC issued an order that denied Potomac Edison’s application and motion to establish interim rates,

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cancelled evidentiary hearings and dismissed the case, ruling that recovery was barred by a Memorandum of Understanding (the “MOU”) that Potomac Edison entered into with the Staff of the Virginia SCC in 2000 in connection with the transfer of its Virginia generating assets to AE Supply. Under the MOU, Potomac Edison agreed to forego fuel cost adjustments otherwise permitted under the Restructuring Act during the capped rate period, which, at the time that the MOU was entered into, was scheduled to expire as of July 1, 2007.

On December 20, 2007, the Virginia SCC granted Potomac Edison partial ($9.5 million) recovery of increased purchased power costs, following a second application by Potomac Edison for rate recovery of $42.3 million. On May 15, 2008, following a third application by Potomac Edison, the Virginia SCC issued an order allowing Potomac Edison to increase its rates effective July 1, 2008, on an interim basis subject to refund, to collect $73 million of purchased power costs. Revenues were recognized based on the method under which the rates were developed and not the amounts collected. As a result, a portion of the amounts collected from July 1, 2008 to December 31, 2008 was deferred as a regulatory liability and was recognized as revenue from January through June 2009.

On July 18, 2008, the Virginia SCC issued an order finding that the rate making provisions of the MOU would expire on December 31, 2008. On November 26, 2008, the Virginia SCC approved a comprehensive rate settlement agreed to with the Staff of the Virginia SCC, the Consumers Counsel of the Virginia Office of the Attorney General and a group of Potomac Edison’s industrial customers that transitions all customers to rates that allow for full recovery of purchased power costs no later than July 1, 2011. Key provisions of the settlement were that:

• the $73 million rate increase approved on a temporary basis on May 15, 2008 would remain in effect through June 30, 2009;

• for the period from July 1, 2009 through December 31, 2009, half of any further increase in purchased power costs for service to large non-residential customers will be forgone, up to $15 million;

• for the period from July 1, 2009 through June 30, 2010, the total rate increase for all other customers will be capped at 15%; and

• during the period from July 1, 2009 through June 30, 2011, 100 MW of the power procured by Potomac Edison will be deemed for rate purposes to have been procured at the lesser of actual cost or $55 per MWh.

Potomac Edison successfully procured power in December 2008 to cover load for the settlement period through 2011, and AE Supply was the successful bidder with respect to a substantial portion of these requirements.

On May 15, 2009, the Virginia SCC issued an order concerning a request by Potomac Edison to recover purchased power costs to serve its Virginia customers. The Virginia SCC’s order granted an interim rate increase of approximately $19.4 million, subject to refund, effective July 1, 2009. In October 2009, Potomac Edison and the Staff of the Virginia SCC filed a joint stipulation, pursuant to which the rate increase would be reduced by $3.2 million to approximately $16.2 million. On October 30, 2009, the Virginia SCC issued an order that approved the joint stipulation.

On May 14, 2010, Potomac Edison filed a request for a rate increase of 1.5 % for the second year of the settlement period. However, as a result of the closing of the sale to the Cooperatives discussed in “Sale of Distribution Operations,” above, the Cooperatives have succeeded to the rights and responsibilities of Potomac Edison under the November 2008 settlement, and by order dated June 11, 2010, the Virginia SCC granted the Cooperatives’ motion to substitute themselves for Potomac Edison with respect to the May 14, 2010 rate request.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See Item 7a, “Quantitative and Qualitative Disclosures About Market Risk,” in the 2009 Annual Report on Form 10-K for information relating to market risk.

Commodity Price Risk

Allegheny is exposed to market risks associated with changes in commodity prices resulting from changes in supplies, demands, fuel costs, market liquidity, weather, environmental regulation and other factors. To manage these risks, Allegheny uses derivatives and physical transactions to reduce its exposure to commodity prices.

Of its commodity-driven risks, Allegheny is primarily exposed to risks associated with the wholesale and retail electricity markets, including generation, coal and other fuel procurement, power marketing and the purchase and sale of electricity. Allegheny’s wholesale and retail activities principally consist of bilateral forward contracts for the purchase and sale of electricity. The majority of these contracts represent commitments to purchase or sell electricity at fixed prices in the future. These forward contracts can require either physical or financial settlement.

One way to measure Allegheny’s exposure to the commodity risk is using the percentage of expected coal-fired generation hedged. These percentages represent the estimated amount of equivalent sales divided by the amount of energy purchases contracted and estimated to be generated by our coal plants in such periods. As of June 30, 2010, the percentage of expected coal-fired generation hedged was approximately 87%, 57% and 22% for balance of 2010, 2011, and 2012, respectively.

Allegheny measures the sensitivity of its contracts and positions to potential changes in commodity prices using high-level sensitivity analysis and Value at Risk (“VaR”).

Allegheny performed a high-level sensitivity analysis of the impact of changes in power and coal prices on its future pre-tax income. The estimated market price exposure for Allegheny’s coal-fired generation portfolio associated with a $10 per MWh decrease in energy prices based on June 30, 2010 market conditions and hedged position would be a decrease in pre-tax income of approximately $21 million, $142 million and $259 million for the balance of 2010, 2011 and 2012, respectively. The estimated market price exposure for Allegheny’s coal-fired generation portfolio associated with a $10 per ton increase in coal prices based on June 30, 2010 market conditions and hedged position would be a decrease in pre-tax income of approximately $2 million, $47 million and $51 million for 2010, 2011, and 2012, respectively. These power and coal price sensitivities were estimated by individually adjusting power price assumptions and coal price assumptions, respectively, while in each case holding all other variables constant. Actual results could differ based on changes in load volumes, plant performance, dispatch changes and basis changes relative to PJM Western Hub power prices, among other factors.

VaR is a statistical model that measures the variability of value and predicts the risk of loss based on historical market price and volatility data over a given period of time. The quantification of market risk using VaR provides a consistent measure of risk across diverse energy markets and products with different risk factors to set the overall corporate risk tolerance and determine risk targets. Allegheny calculates VaR using the Monte-Carlo technique by simulating thousands of scenarios sampling from the probability distribution of uncertain market variables. In addition to VaR, Allegheny routinely performs stress and scenario analyses to measure extreme losses due to exceptional events. FTRs are excluded from Allegheny’s calculation of VaR due to the absence of liquid spot and forward markets.

AE Supply calculated the VaR of a 1-day holding period at a 95% confidence level using the full term of all remaining wholesale energy market positions that are accounted for on a mark-to-market basis. These wholesale energy market positions consist of derivatives in power, emissions and natural gas excluding FTRs. The FTRs

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are excluded from the VaR measurement as they are generally considered to be economic hedges of congestion in meeting Allegheny’s load obligation. As of June 30, 2010 and December 31, 2009, this calculation yielded a VaR of less than $1 million.

The value of FTRs generally represents an economic hedge of future congestion charges incurred to serve Allegheny’s load obligations. The related load obligations, however, are not reflected in Allegheny’s consolidated balance sheets. As a result, the timing of recognition of gains or losses on FTRs will differ from the timing of power purchases, including incurred congestion charges. The fair value of FTRs has been determined using an internal model based on data from PJM annual and monthly FTR auctions. These monthly auction results can change significantly over time and may differ from the final settlement amounts. See Note 10, “Fair Value Measurements, Derivative Instruments and Hedging Activities,” to the Consolidated Financial Statements for information regarding unrealized gains (losses) attributable to FTRs during the three months ended June 30, 2010.

Interest Rate Risk

Excluding variable rate debt relating to the TrAIL project, for which Allegheny recovers interest costs in formula rates, Allegheny had $15 million of variable rate debt outstanding at June 30, 2010. AE did not have any debt subject to variable interest rates at December 31, 2009.

ITEM 4. CONTROLS AND PROCEDURES

See, Item 9a. “Controls and Procedures,” in the 2009 Annual Report on Form 10-K for additional information relating to Controls and Procedures.

Disclosure Controls and Procedures. AE maintains disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the chief executive officer (“CEO”) and chief financial officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosures.

As of the end of the period covered by this report, our management, with the participation of our CEO and CFO, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13(a)-15(e) and 15(d)-15(e) of the Exchange Act. This evaluation included consideration of the various processes carried out under the direction of our disclosure committee. Based on this evaluation, our CEO and CFO concluded that AE’s disclosure controls and procedures were effective, at the reasonable assurance level, to ensure that material information relating to AE is (a) accumulated and made known to its management, including our CEO and CFO, to allow timely decisions regarding required disclosure and (b) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Changes in Internal Control over Financial Reporting: During the quarter ended June 30, 2010, there have been no changes in AE’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time, Allegheny is involved in litigation and other legal disputes in the ordinary course of business. See Note 17, “Commitments and Contingencies” to Allegheny’s consolidated financial statements for information regarding legal proceedings.

ITEM 1A. RISK FACTORS

There have been no material changes to the risk factors disclosed in Item 1A of Part 1 of the 2009 Annual report on form 10-K.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. RESERVED

ITEM 5. OTHER INFORMATION

None.

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ITEM 6. EXHIBITS

EXHIBIT INDEX

	Documents
10.1	Credit Agreement, dated as of April 30, 2010, among Allegheny Energy, Inc., as Borrower, certain banks, financial institutions and other institutional lenders as the Initial Lenders, The Bank of Nova Scotia, Union Bank, N.A., Bank of America, N.A. and Credit Agricole Corporate and Investment Bank as the Initial Issuing Banks for the letters of credit issued or to be issued, and Union Bank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to Allegheny Energy, Inc.’s Current Report on Form 8-K filed on May 6, 2010).
10.2	Credit Agreement, dated as of April 30, 2010, among The Potomac Edison Company, as Borrower, certain banks, financial institutions and other institutional lenders as the Initial Lenders, Commerzbank AG, New York and Grand Cayman Branches, BNP Paribas and The Bank of Nova Scotia as the Initial Issuing Banks for the letters of credit issued or to be issued, and Commerzbank AG, New York and Cayman Islands Branches, as Administrative Agent (incorporated by reference to Exhibit 10.2 to Allegheny Energy, Inc.’s Current Report on Form 8-K filed on May 6, 2010).
10.3	Credit Agreement, dated as of April 30, 2010, among West Penn Power Company, as Borrower, certain banks, financial institutions and other institutional lenders as the Initial Lenders, PNC Bank, National Association and The Bank of Nova Scotia as the Initial Issuing Banks for the letters of credit issued or to be issued, and PNC Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.3 to Allegheny Energy, Inc.’s Current Report on Form 8-K filed on May 6, 2010).
10.4	Amendment No. 1, dated as of June 4, 2010, to the Agreement and Plan of Merger, dated as of February 10, 2010, by and among FirstEnergy Corp., Element Merger Sub, Inc., and Allegheny Energy, Inc. (incorporated by reference to Exhibit 10.1 to Allegheny Energy, Inc.’s Current Report on Form 8-K filed on June 9, 2010).
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	ALLEGHENY ENERGY, INC.
Date: August 6, 2010	By:	/s/ Kirk R. Oliver
		Kirk R. Oliver Senior Vice President and Chief Financial Officer

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