Allegheny Energy (AYE) 10-Q 2009 Q3 Quarterly report

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 September 30, 2009

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 October 31, 2009, 169,562,824 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”)	51
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	98
Item 4.	Controls and Procedures	99
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	100
Item 1A.	Risk Factors	100
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	102
Item 3.	Defaults Upon Senior Securities	102
Item 4.	Submission of Matters to a Vote of Security Holders	102
Item 5.	Other Information	102
Item 6.	Exhibits	103
	Signatures	104

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
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 LAC	PATH-Allegheny Land Acquisition Company
PATH-VA	PATH Allegheny Virginia Transmission Corporation
PATH-WV	PATH West Virginia Transmission Company, LLC
PATH-WV LAC	PATH-WV Land Acquisition Company
Potomac Edison	The Potomac Edison Company, a regulated subsidiary of AE
TrAIL Company	Trans-Allegheny Interstate Line Company, a regulated subsidiary of AE
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
DOE	United States Department of Energy
EPA	United States Environmental Protection Agency
Exchange Act	Securities Exchange Act of 1934, as amended
FERC	Federal Energy Regulatory Commission, an independent commission within the DOE
EAF	Equivalent Availability Factor
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, which is 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, which is a unit of electric energy equivalent to one MW operating for one hour
NCF	Net Capacity Factor
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
OVEC	Ohio Valley Electric Corporation
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
RTO	Regional Transmission Organization
Scrubbers	Flue-gas desulfurization equipment
SEC	Securities and Exchange Commission
SERP	Supplemental Executive Retirement Plan
SO2	Sulfur dioxide
SOS	Standard Offer Service
T&D	Transmission and distribution
TrAIL	Trans-Allegheny Interstate Line
Virginia SCC	Virginia State Corporate Commission
West Virginia PSC	Public Service Commission of West Virginia

3

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions, except per share amounts)	2009			2008			2009			2008
Operating revenues	$	793.7		$	849.6		$	2,565.7		$	2,678.1
Operating expenses:
Fuel		188.0			299.2			663.8			794.2
Purchased power and transmission		134.2			108.1			380.4			302.7
Deferred energy costs, net		(14.3	)		(18.7	)		(38.9	)		(28.1	)
Operations and maintenance		151.2			152.3			518.9			511.0
Depreciation and amortization		71.3			67.4			207.0			206.5
Taxes other than income taxes		57.4			54.4			159.7			159.7
Total operating expenses		587.8			662.7			1,890.9			1,946.0
Operating income		205.9			186.9			674.8			732.1
Other income (expense), net		1.9			4.5			6.1			15.3
Interest expense		85.1			57.9			201.5			175.0
Income before income taxes		122.7			133.5			479.4			572.4
Income tax expense		45.3			44.3			195.1			192.5
Net income		77.4			89.2			284.3			379.9
Less net income attributable to noncontrolling interest		(0.4	)		(0.2	)		(0.8	)		(0.7	)
Net income attributable to Allegheny Energy, Inc.	$	77.0		$	89.0		$	283.5		$	379.2
Earnings per share attributable to Allegheny Energy, Inc.:
Basic	$	0.45		$	0.53		$	1.67		$	2.25
Diluted	$	0.45		$	0.52		$	1.67		$	2.23
Average shares outstanding:
Basic		169.6			168.9			169.5			168.2
Diluted		170.0			170.0			169.9			170.0
Dividends per share	$	0.15		$	0.15		$	0.45		$	0.45

See accompanying Notes to Consolidated Financial Statements.

4

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

	Nine Months Ended September 30,
(In millions)	2009			2008
Cash Flows From Operating Activities:
Net income	$	284.3		$	379.9
Adjustments for non-cash items included in income:
Depreciation and amortization		207.0			206.5
Amortization of debt related costs		9.5			8.2
Amortization of liability for adverse power purchase commitment		(13.1	)		(12.9	)
Amortization of Pennsylvania stranded costs		—			8.6
Provision for uncollectible accounts		12.3			13.3
Deferred income taxes and investment tax credit, net		188.5			177.0
Deferred energy costs, net		(38.9	)		(28.1	)
Stock-based compensation expense		11.9			9.8
Unrealized gains on derivative contracts, net		(16.1	)		(136.9	)
Pension and other postretirement employee benefit plan expense		30.0			23.5
Pension and other postretirement employee benefit plan contributions		(45.1	)		(45.4	)
Deferred revenue — Fort Martin scrubber project		8.1			9.3
Deferred revenue — Virginia		(28.3	)		14.0
Uncollected transmission revenue		(14.6	)		(4.3	)
Other, net		12.9			10.8
Changes in certain assets and liabilities:
Accounts receivable, net		1.0			(28.3	)
Materials, supplies and fuel		(85.2	)		(43.3	)
Prepaid taxes		(12.2	)		21.5
Collateral deposits		32.7			31.2
Accounts payable		(45.3	)		(62.1	)
Accrued taxes		(55.7	)		(35.0	)
Accrued interest		9.1			(2.5	)
Regulatory assets		47.5			26.3
Deferred income taxes		(2.6	)		(2.5	)
Regulatory liabilities		(24.0	)		41.1
Distributions from equity method investee		1.3			—
Assets and liabilities held for sale		3.1			—
Other operating assets and liabilities		5.6			9.4
Net cash provided by operating activities		483.7			589.1

See accompanying Notes to Consolidated Financial Statements.

5

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)

(unaudited)

	Nine Months Ended September 30,
(In millions)	2009			2008
Cash Flows From Investing Activities:
Capital expenditures		(870.1	)		(714.3	)
Proceeds from asset sales		0.2			0.4
Purchase of Merrill Lynch interest in subsidiary		—			(50.0	)
Decrease in restricted funds		131.0			177.6
Other investments		(3.8	)		(4.1	)
Net cash used in investing activities		(742.7	)		(590.4	)
Cash Flows From Financing Activities:
Repayment of note payable		—			(10.0	)
Issuance of long-term debt		709.2			305.6
Repayment of long-term debt		(438.3	)		(384.6	)
Costs associated with AE Supply revolving credit facility refinancing		(21.6	)		—
Equity contribution to PATH, LLC by the joint venture partner		6.9			4.5
Payments on capital lease obligations		(6.4	)		(6.8	)
Proceeds from exercise of employee stock options		1.6			21.5
Cash dividends paid on common stock		(76.2	)		(75.7	)
Net cash provided by (used in) financing activities		175.2			(145.5	)
Net decrease in cash and cash equivalents		(83.8	)		(146.8	)
Cash and cash equivalents at beginning of period		362.1			258.8
Cash and cash equivalents at end of period	$	278.3		$	112.0
Supplemental Cash Flows Information:
Cash paid during the period for interest (net of amounts capitalized)	$	182.5		$	169.2
Accounts payable at September 30 relating to capital expenditures	$	136.3		$	76.3

See accompanying Notes to Consolidated Financial Statements.

6

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(unaudited)

(In millions)	September 30, 2009			December 31, 2008
ASSETS
Current Assets:
Cash and cash equivalents	$	278.3		$	362.1
Accounts receivable:
Customer		180.2			188.3
Unbilled utility revenue		87.8			122.7
Wholesale and other		59.3			61.5
Allowance for uncollectible accounts		(13.3	)		(13.3	)
Materials and supplies		109.8			115.1
Fuel		218.0			128.2
Deferred income taxes		22.5			69.6
Prepaid taxes		56.9			44.8
Collateral deposits		24.7			33.5
Derivative assets		40.4			113.1
Regulatory assets		153.0			158.8
Assets held for sale		30.4			—
Other		124.6			111.3
Total current assets		1,372.6			1,495.7
Property, Plant and Equipment:
Generation		6,641.1			6,107.3
Transmission		1,239.3			1,171.7
Distribution		3,732.4			3,944.1
Other		461.4			463.4
Accumulated depreciation		(5,048.9	)		(4,994.1	)
Subtotal		7,025.3			6,692.4
Construction work in progress		1,447.2			1,309.8
Property, plant and equipment held for sale, net		250.1			—
Total property, plant and equipment, net		8,722.6			8,002.2
Other Noncurrent Assets:
Regulatory assets		659.3			687.7
Goodwill		367.3			367.3
Restricted funds—Fort Martin scrubber project		—			133.3
Investments in unconsolidated affiliates		27.2			28.0
Derivative assets		0.7			9.8
Other		113.4			87.0
Total other noncurrent assets		1,167.9			1,313.1
Total Assets	$	11,263.1		$	10,811.0

See accompanying Notes to Consolidated Financial Statements.

7

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Continued)

(unaudited)

(In millions, except share amounts)	September 30, 2009			December 31, 2008
LIABILITIES AND EQUITY
Current Liabilities:
Long-term debt due within one year	$	160.7		$	93.9
Accounts payable		346.1			374.2
Accrued taxes		69.6			119.4
Payable to PJM for FTRs		80.9			110.8
Derivative liabilities		13.8			22.2
Regulatory liabilities		39.3			69.2
Accrued interest		67.1			58.1
Security deposits		48.8			46.2
Liabilities associated with assets held for sale		9.3			—
Other		116.4			109.6
Total current liabilities		952.0			1,003.6
Long-term Debt, Excluding Amounts Due Within One Year		4,327.4			4,115.9
Deferred Credits and Other Liabilities:
Derivative liabilities		19.2			11.9
Income taxes payable		84.7			75.7
Investment tax credit		62.8			65.8
Deferred income taxes		1,397.6			1,277.4
Regulatory liabilities		469.8			528.9
Pension and other postretirement employee benefit plan liabilities		559.4			578.4
Adverse power purchase commitment		118.9			132.3
Liabilities associated with assets held for sale		53.1			—
Other		157.2			165.4
Total deferred credits and other liabilities		2,922.7			2,835.8
Commitments and Contingencies (Note 17)
Equity:
Common stock—$1.25 par value per share, 260 million shares authorized and 169,571,717 and 169,413,887 shares issued at September 30, 2009 and December 31, 2008, respectively		211.9			211.8
Other paid-in capital		1,965.9			1,952.5
Retained earnings		938.9			731.6
Treasury stock at cost—49,493 shares		(1.8	)		(1.8	)
Accumulated other comprehensive loss		(66.5	)		(43.3	)
Total Allegheny Energy, Inc. common stockholders’ equity		3,048.4			2,850.8
Noncontrolling interest		12.6			4.9
Total equity		3,061.0			2,855.7
Total Liabilities and Equity	$	11,263.1		$	10,811.0

See accompanying Notes to Consolidated Financial Statements.

8

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS 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 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
Net income	—		—		—			77.0			—			—			77.0			0.4		77.4
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 $21.2	—		—		—			—			—			(33.7	)		(33.7	)		—		(33.7	)
Equity contribution to PATH, LLC by the joint venture partner	—		—		—			—			—			—			—			6.6		6.6
Dividends on common stock	—		—		—			(25.4	)		—			—			(25.4	)		—		(25.4	)
Stock-based compensation expense:
Non-employee director stock awards	3,000		—		0.2						—			—			0.2			—		0.2
Stock options	—		—		1.7			—			—			—			1.7			—		1.7
Performance shares	—		—		1.4			—			—			—			1.4			—		1.4
Exercise of stock options	33,060		—		0.4			—			—			—			0.4			—		0.4
Settlement of stock units	3,573		—		—			—			—			—			—			—		—
Share-based excess tax benefit	—		—		(19.7	)		—			—			—			(19.7	)		—		(19.7	)
Balance at September 30, 2009	169,522,224	$	211.9	$	1,965.9		$	938.9		$	(1.8	)	$	(66.5	)	$	3,048.4		$	12.6	$	3,061.0

(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 June 30, 2008	168,709,253	$	211.0	$	1,937.7	$	683.9		$	(1.8	)	$	(109.5	)	$	2,721.3		$	5.0	$	2,726.3
Net income	—		—		—		89.0			—			—			89.0			0.2		89.2
Defined benefit pension and other benefit plan amortization, net of tax of $0.3	—		—		—		—			—			0.4			0.4			—		0.4
Cash flow hedges, net of tax of $51.0	—		—		—		—			—			80.5			80.5			—		80.5
Dividends on common stock	—		—		—		(25.3	)		—			—			(25.3	)		—		(25.3	)
Stock-based compensation expense:
Non-employee director stock awards	1,632		—		0.2		—			—			—			0.2			—		0.2
Stock options	—		—		2.1		—			—			—			2.1			—		2.1
Performance shares	—		—		1.1		—			—			—			1.1			—		1.1
Exercise of stock options	339,322		0.4		4.3		—			—			—			4.7			—		4.7
Settlement of stock units	3,500		—		—		—			—			—			—			—		—
Balance at September 30, 2008	169,053,707	$	211.4	$	1,945.4	$	747.6		$	(1.8	)	$	(28.6	)	$	2,874.0		$	5.2	$	2,879.2

See accompanying Notes to Consolidated Financial Statements.

9

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Continued)

(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, 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	—		—		—		283.5			—			—			283.5			0.8		284.3
Defined benefit pension and other benefit plan amortization, net of tax of $1.7	—		—		—		—			—			2.5			2.5			—		2.5
Cash flow hedges, net of tax of $16.4	—		—		—		—			—			(25.7	)		(25.7	)		—		(25.7	)
Equity contribution to PATH, LLC by the joint venture partner	—		—		—		—			—			—			—			6.9		6.9
Dividends on common stock	—		—		—		(76.2	)		—			—			(76.2	)		—		(76.2	)
Stock-based compensation expense:
Non-employee director stock awards	18,907		—		0.7		—			—			—			0.7			—		0.7
Stock options	—		—		5.6		—			—			—			5.6			—		5.6
Performance shares	—		—		5.5		—			—			—			5.5			—		5.5
Restricted shares	17,850		—		0.1		—			—			—			0.1			—		0.1
Exercise of stock options	117,500		0.1		1.5		—			—			—			1.6			—		1.6
Settlement of stock units	3,573		—		—		—			—			—			—			—		—
Balance at September 30, 2009	169,522,224	$	211.9	$	1,965.9	$	938.9		$	(1.8	)	$	(66.5	)	$	3,048.4		$	12.6	$	3,061.0

(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, 2007	167,223,576	$	209.1	$	1,924.1		$	444.2		$	(1.8	)	$	(40.2	)	$	2,535.4		$	13.2		$	2,548.6
Net income	—		—		—			379.2			—			—			379.2			0.7			379.9
Defined benefit pension and other benefit plan amortization, net of tax of $0.9	—		—		—			—			—			1.0			1.0			—			1.0
Cash flow hedges, net of tax of $6.7	—		—		—			—			—			10.6			10.6			—			10.6
Purchase of minority interest in AE Supply	—		—		—			—			—			—			—			(13.2	)		(13.2	)
Equity contribution to PATH, LLC by the joint venture partner	—		—		—			—			—			—			—			4.5			4.5
Dividends on common stock	—		—		—			(75.7	)		—			—			(75.7	)		—			(75.7	)
Stock-based compensation expense:
Stock units	—		—		0.6			—			—			—			0.6			—			0.6
Non-employee director stock awards	19,097		—		0.8						—			—			0.8			—			0.8
Stock options	—		—		6.9			—			—			—			6.9			—			6.9
Performance shares	—		—		1.5			—			—			—			1.5			—			1.5
Exercise of stock options	1,558,452		2.0		19.5			—			—			—			21.5			—			21.5
Settlement of stock units	252,582		0.3		(8.1	)		—			—			—			(7.8	)		—			(7.8	)
Dividends on stock units	—		—		0.1			(0.1	)		—			—			—			—			—
Balance at September 30, 2008	169,053,707	$	211.4	$	1,945.4		$	747.6		$	(1.8	)	$	(28.6	)	$	2,874.0		$	5.2		$	2,879.2

See accompanying Notes to Consolidated Financial Statements.

10

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note		Page Number
1	Basis of Presentation	12
2	Recently Adopted and Recently Issued Accounting Standards	13
3	Assets Held for Sale	15
4	Rates and Regulation	16
5	Regulatory Assets and Liabilities	17
6	Income Taxes	18
7	Common Stock and Debt	20
8	Business Segments	22
9	Fair Value Measurements, Derivative Instruments and Hedging Activities	25
10	Stock-Based Compensation	31
11	Pension Benefits and Postretirement Benefits Other Than Pensions	35
12	Financial Instruments	37
13	Comprehensive Income and Accumulated Other Comprehensive Loss	37
14	Earnings Per Share	38
15	Variable Interest Entities	38
16	Other Income (Expense), Net	40
17	Commitments and Contingencies	40
18	Subsequent Events	49

11

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

NOTE 1: BASIS OF PRESENTATION

Business Description

Allegheny Energy, Inc. (“AE” and, together with its subsidiaries, “Allegheny”) is an integrated energy business that owns and operates electric generation facilities and delivers electric services to customers in Pennsylvania, West Virginia, Maryland and Virginia. Allegheny’s two business segments are the Delivery and Services segment and the Generation and Marketing segment. These reportable segments are strategic business units that offer different products and services and are managed separately.

The Delivery and Services segment primarily consists of Allegheny’s regulated transmission and distribution operations conducted by Monongahela Power Company (“Monongahela”), The Potomac Edison Company (“Potomac Edison”) and West Penn Power Company (“West Penn” and, together with Monongahela and Potomac Edison, the “Distribution Companies”). The Distribution Companies operate electric transmission and distribution (“T&D”) systems in Pennsylvania, West Virginia, Maryland and Virginia. The Delivery and Services segment also includes the operations of Trans-Allegheny Interstate Line Company (“TrAIL Company”) and Potomac-Appalachian Transmission Highline, LLC (“PATH, LLC”). TrAIL Company was formed in 2006 in connection with the management and financing of transmission expansion projects, including the Trans-Allegheny Interstate Line (“TrAIL”), a 500 kV transmission line to extend from southwestern Pennsylvania through West Virginia and into northern Virginia. PATH, LLC, which is a series limited liability company, was formed in 2007 with a subsidiary of American Electric Power Company, Inc. (“AEP”) to build the Potomac-Appalachian Transmission Highline (“PATH”), a high-voltage transmission line that is proposed to extend across West Virginia and into Maryland.

In May 2009, Potomac Edison signed definitive agreements to sell its electric distribution operations in Virginia. See Note 3 “Assets Held for Sale” for additional information.

The Generation and Marketing segment primarily consists of Allegheny’s electric generation operations conducted by Allegheny Energy Supply Company, LLC (“AE Supply”) and Monongahela’s regulated generation operations, as well as the operations of Allegheny Generating Company (“AGC”). AGC owns and sells generation capacity to AE Supply and Monongahela, which own approximately 59% and 41% of AGC, respectively.

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 (“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 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, 2008.

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

12

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

seasonal variations in revenues, fuel and energy purchases and other factors. The year-end 2008 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, and the provisions of SFAS 160 (FASB Codification Topic 810) have been retrospectively applied as described in Note 2, “Recently Adopted and Recently Issued Accounting Standards.” Events occurring subsequent to the date of the balance sheet have been evaluated for potential recognition or disclosure in the consolidated financial statements through November 6, 2009, the date of the filing of the consolidated financial statements with the SEC.

Allegheny performed an annual goodwill impairment test as of August 31, 2009 and determined that there was no impairment of recorded goodwill at that date.

NOTE 2: RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS

In June 2009, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance that replaced the previous hierarchy of GAAP and established the FASB Accounting Standards Codification (“FASB Codification”) as the single source of authoritative U.S. GAAP recognized by the FASB to be applied to the financial statements of nongovernmental entities for periods ending after September 15, 2009. SEC rules and interpretive releases are also sources of authoritative GAAP for SEC registrants. This guidance modifies the GAAP hierarchy to include only two levels of GAAP: authoritative and nonauthoritative. The FASB Codification was not intended to change or alter existing GAAP, and Allegheny’s adoption of this guidance did not impact its results of operations, cash flows or financial position.

Consolidation of Variable Interest Entities

In June 2009, the FASB issued SFAS No. 167,“Amendments to FASB Interpretation No. 46(R)” (“SFAS 167”). SFAS 167 amends FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities – an interpretation of ARB No. 51,” (“FIN 46(R)”), (FASB Codification Topic 805) to require: an enterprise to perform an analysis to determine whether the enterprise’s variable interests give it a controlling financial interest in a variable interest entity; ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity; and enhanced disclosures with more transparent information about an enterprise’s involvement in a variable interest entity. It is possible that the application of SFAS 167 will change both Allegheny’s prior assessment of certain entities as variable interest entities and the determination of which variable interest entities are required to be consolidated, including an evaluation of PATH-WV. SFAS 167 will be effective for Allegheny on January 1, 2010. Allegheny is currently evaluating the potential impact of SFAS 167 on its financial statements.

Subsequent Events

On June 16, 2009, Allegheny adopted SFAS No. 165,“Subsequent Events” (“SFAS 165”), (FASB Codification Topic 810). SFAS 165 establishes general standards of accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued. Specifically, SFAS 165 sets forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, the circumstances

13

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements, and the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. Its adoption had no effect on Allegheny’s financial statements.

Fair Value Measurements and Disclosures

On January 1, 2009, Allegheny adopted FSP FAS No. 157-2, “Effective Date of FASB Statement 157” (“FSP FAS 157-2”), (FASB Codification Topic 820), which permitted a one-year deferral of the application of SFAS 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Allegheny adopted SFAS 157, effective January 1, 2008 for financial assets and liabilities, and deferred application of SFAS 157 for non-financial assets and liabilities that are not recognized at fair value on a recurring basis until January 1, 2009. The application of SFAS 157 to non-financial assets and liabilities effective January 1, 2009 did not have a material impact on Allegheny’s results of operations or financial position.

On April 1, 2009, Allegheny adopted FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” (“FSP FAS 157-4”), (FASB Codification Topic 820). FSP FAS 157-4 provides additional guidance for estimating fair value in accordance with issued SFAS No. 157, “Fair Value Measurements” when the volume and level of activity for the asset or liability have significantly decreased and includes guidance for identifying circumstances that indicate a transaction is not orderly. The adoption of FSP FAS 157-4 had no impact on Allegheny’s financial statements.

On April 1, 2009, Allegheny adopted FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” (“FSP FAS 107-1/APB 28-1”), (FASB Codification Topic 825). FSP FAS 107-1/APB 28-1 requires disclosures by publicly traded companies about fair value of financial instruments for interim reporting periods consistent with those currently required in annual financial statements. The adoption affected Allegheny’s disclosure but did not impact Allegheny’s results of operations or financial position.

Derivative Instrument and Hedging Disclosures

On January 1, 2009, Allegheny adopted SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133” (“SFAS 161”), (FASB Codification Topic 815). SFAS 161 requires entities to provide qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of derivative contracts and the gains and losses on derivative contracts, and details of credit-risk-related contingent features in their hedged positions. SFAS 161 also requires disclosure of the location of the derivative contracts and their related gains and losses in an entity’s financial statements. Allegheny’s adoption of SFAS 161 affected Allegheny’s derivative disclosures but did not impact Allegheny’s results of operations or financial position.

Noncontrolling Interests

On January 1, 2009, Allegheny adopted SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS 160”), (FASB Codification Topic 810). SFAS 160 establishes accounting and reporting standards for the non-controlling interest in a subsidiary (formerly “minority interest”) and for the deconsolidation of a subsidiary. It also amends certain consolidation procedures for consistency with SFAS No. 141 (revised 2007), “Business Combinations.” Under SFAS 160, non-controlling

14

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

interests are reported in the consolidated statement of financial position as a separate component within equity, and consolidated net income and consolidated comprehensive income are adjusted to include amounts attributable to the noncontrolling interest. Allegheny’s adoption of SFAS 160 affected its financial statement presentation but did not materially affect Allegheny’s results of operations or financial position.

Postretirement Benefit Plan Asset Disclosures

In December 2008, the FASB issued FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (“FSP FAS 132(R)-1”), (FASB Codification Topic 710). This pronouncement amends SFAS No. 132 to require disclosure of the fair value of categories of plan assets based on the types of assets held in the plan, disclosures about the nature and amounts of concentrations of risk within categories of plan assets, and disclosures about the fair value measurement inputs, similar to SFAS 157. FSP FAS 132(R)-1 will become effective for Allegheny beginning with annual disclosures as of December 31, 2009 and will affect Allegheny’s financial statement disclosure but will not impact Allegheny’s results of operations or financial position.

NOTE 3: ASSETS HELD FOR SALE

On May 4, 2009, Potomac Edison signed definitive agreements to sell its electric distribution operations in Virginia (“VA Distribution Business”) to Rappahannock Electric Cooperative and Shenandoah Valley Electric Cooperative (the “Buyers”). The agreements are subject to state regulatory approval in Virginia and West Virginia, as well as federal approval and certain third-party consents. Under the terms of the agreements, Potomac Edison will transfer its Virginia distribution assets and certain related liabilities to the Buyers in exchange for cash proceeds of approximately $340 million, subject to adjustment for changes in assets and liabilities through the closing date. As part of their agreement, Monongahela will purchase certain West Virginia distribution operations from Shenandoah Valley Electric Cooperative for approximately $15 million. The sale is expected to close following the completion of applicable regulatory proceedings. Hearings before the Virginia State Corporation Commission (the “Virginia SCC”) are scheduled to commence March 2, 2010. The VA Distribution Business is included in the Delivery and Services segment.

15

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

For periods after May 4, 2009, assets and liabilities relating to the VA Distribution Business are classified as “held for sale” in Allegheny’s consolidated balance sheets, and depreciation expense on such assets ceased. Assets held for sale and liabilities associated with assets held for sale at September 30, 2009 were as follows:

(In millions)	Amounts
Current Assets:
Accounts receivable	$	28.9
Materials and supplies		0.9
Regulatory assets		0.6
Total current assets		30.4
Property, Plant and Equipment:
Distribution property, plant and equipment		342.0
Accumulated depreciation		(91.9	)
Property, plant and equipment, net		250.1
Total assets held for sale	$	280.5
Current Liabilities:
Customer deposits	$	5.3
Regulatory liabilities		2.9
Other		1.1
Total current liabilities		9.3
Deferred Credits and Other Liabilities:
Regulatory liabilities		52.9
Other		0.2
Total deferred credits and other liabilities		53.1
Total liabilities associated with assets held for sale	$	62.4

NOTE 4: RATES AND REGULATION

State Regulation and Rate Matters

West Virginia

Rates. In August 2009, Monongahela and Potomac Edison filed a request with the West Virginia Public Service Commission (the “West Virginia PSC”) for a base rate increase of $122.1 million, with rates anticipated to be effective June 2010. Base rates reflect the utilities’ non-fuel costs. Fuel costs are recovered through a separate regulatory proceeding.

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, proposed to become effective January 1, 2010, were submitted pursuant to the schedule for annual fuel and purchased power cost reviews.

Environmental Project Financing.In July 2009, Monongahela and Potomac Edison filed a request with the West Virginia PSC for authority to issue approximately $105 million of environmental control bonds to fund the

16

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

remaining portion of its flue gas desulfurization (“Scrubber”) project at Fort Martin generating station. The bonds would be repaid using funds collected from West Virginia customers through an environmental control charge. In September 2009, the West Virginia PSC issued a financing order granting Monongahela and Potomac Edison the authority, subject to the terms and conditions of the financing order, to issue the environmental control bonds and impose a related environmental control charge.

Virginia

Rates.In April 2009, Potomac Edison filed a request with the Virginia SCC for a rate increase of approximately $19.4 million over current rates for the 12-month period beginning July 1, 2009. The request reflects the results of a power auction in December 2008. In May 2009, the Virginia SCC issued an order granting 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 and adopted the joint stipulation.

NOTE 5: REGULATORY ASSETS AND LIABILITIES

Allegheny’s regulated utility operations are subject to utility 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)	September 30, 2009		December 31, 2008
Regulatory assets, including current portion:
Income taxes (a)(b)	$	222.7	$	231.3
Pension benefits and postretirement benefits other than pensions (a)(c)		377.6		390.4
Pennsylvania Competitive Transition Charge (“CTC”) reconciliation (d)		21.5		73.6
Unamortized loss on reacquired debt (a)(e)		27.9		31.1
Unrealized loss on decreased fair value of financial transmission rights (f)		7.8		17.8
Deferred ENEC charges (f)		90.9		52.0
Other (g)		63.9		50.3
Subtotal		812.3		846.5
Regulatory liabilities, including current portion:
Net asset removal costs – Virginia (h)		—		50.6
Net asset removal costs – other than Virginia		372.3		356.8
Income taxes		33.1		35.2
SO2 allowances		12.9		13.3
Virginia collections for costs not yet incurred		—		28.3
Fort Martin Scrubber project – environmental control surcharge		37.2		29.1
Maryland rate stabilization and transition plan surcharge		37.2		61.7
Other		16.4		23.1
Subtotal		509.1		598.1
Net regulatory assets	$	303.2	$	248.4

17

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

(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 a period up to 13 years.

(d) Recorded amount includes an 11% return earned through 2005. No additional return will be earned through the 2010 recovery period.

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

(f) Includes amounts that do not earn a return with recovery periods up to two years.

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

(h) Net asset removal costs of $52.8 million are included in liabilities associated with assets held for sale at September 30, 2009 in the consolidated balance sheet.

NOTE 6: INCOME TAXES

Allegheny computes income taxes under the liability method. Deferred income tax balances are generally determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse. Tax benefits are 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.

18

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

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 September 30,										Nine Months Ended September 30,
	2009					2008					2009					2008
(In millions, except percent)	Amount			%		Amount			%		Amount			%		Amount			%
Income before income taxes	$	122.7				$	133.5				$	479.4				$	572.4
Income tax expense calculated at the federal statutory rate of 35%		42.9		35.0			46.7		35.0			167.8		35.0			200.3		35.0
Increases (reductions) resulting from:
Rate-making effects of depreciation differences		1.7		1.4			2.0		1.5			5.2		1.1			5.9		1.0
Plant removal costs		(1.0	)	(0.8	)		(1.3	)	(1.0	)		(3.1	)	(0.7	)		(3.9	)	(0.7	)
State income tax, net of federal income tax benefit		4.1		3.3			2.3		1.7			16.8		3.5			13.5		2.4
Amortization of deferred investment tax credits		(0.9	)	(0.7	)		(1.0	)	(0.7	)		(2.7	)	(0.6	)		(2.7	)	(0.5	)
Change in estimated Pennsylvania net operating loss benefits		—		—			—		—			9.5		2.0			(3.0	)	(0.5	)
March 2008 West Virginia state income tax rate change		—		—			—		—			—		—			(6.7	)	(1.2	)
Changes in tax reserves related to uncertain tax positions and audit settlements		(0.9	)	(0.7	)		(2.7	)	(2.0	)		2.4		0.5			(7.7	)	(1.3	)
Other, net		(0.6	)	(0.5	)		(1.7	)	(1.3	)		(0.8	)	(0.1	)		(3.2	)	(0.6	)
Income tax expense	$	45.3		37.0		$	44.3		33.2		$	195.1		40.7		$	192.5		33.6

Through December 31, 2008, Allegheny had not recorded approximately $65.2 million in excess tax benefits related to share-based awards because of its federal income tax net operating loss carryforward position. During the quarter ended March 31, 2009, Allegheny recorded approximately $20.0 million of excess tax benefits as a credit to other paid-in-capital based on the estimated amount of net operating loss carryforwards that it expected to utilize in its 2009 federal income tax return. During the quarter ended September 30, 2009, Allegheny reversed the $20.0 million benefit and credit to other paid-in-capital based on current estimates of taxable income for the year ending December 31, 2009.

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 12.5% of apportioned Pennsylvania taxable income per year. During the quarter ended March 31, 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.

On October 9, 2009, Pennsylvania enacted H.B. 1531, which modified the corporate net operating loss utilization rules and made minor modifications to apportionment provisions. Under H.B. 1531, the annual net operating loss carryforward limitation was increased to 15% of taxable income for 2010 and 20% thereafter. Allegheny expects that it will adjust its recorded tax benefit relating to Pennsylvania net operating loss carryforwards to reflect estimated benefits from such loss carryforwards resulting from the increased utilization caps under H.B. 1531 during the fourth quarter of 2009.

19

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

NOTE 7: COMMON STOCK AND DEBT

Common Stock

On September 28, 2009, June 22, 2009 and March 23, 2009, AE paid cash dividends on its common stock of $0.15 per share to shareholders of record at the close of business on September 14, 2009, June 8, 2009 and March 9, 2009, respectively. On October 15, 2009, AE’s Board of Directors authorized a cash dividend on its common stock of $0.15 per share payable on December 28, 2009 to shareholders of record on December 14, 2009.

Debt

Outstanding debt and scheduled debt repayments at September 30, 2009 were as follows:

(In millions)	2009			2010			2011			2012			2013			Thereafter			Total
AE:
AE Revolving Credit Facility	$	—		$	—		$	120.0		$	—		$	—		$	—		$	120.0
Total AE		—			—			120.0			—			—			—			120.0
AE Supply:
Medium-Term Notes		—			—			302.5			503.2			—			—			805.7
AE Supply Credit Facility:
Term Loan		—			—			447.0			—			—			—			447.0
Pollution Control Bonds		—			—			—			1.3			—			267.2			268.5
Exempt Facilities Revenue Bonds		—			—			—			—			—			235.0			235.0
Debentures-AGC		—			—			—			—			—			100.0			100.0
Total AE Supply		—			—			749.5			504.5			—			602.2			1,856.2
Monongahela:
Environmental Control Bonds (a)		—			11.1			11.6			12.2			12.8			271.2			318.9
First Mortgage Bonds		—			—			—			—			300.0			340.0			640.0
Medium-Term Notes		—			110.0			—			—			—			—			110.0
Pollution Control Bonds		—			—			—			6.0			7.1			57.2			70.3
Total Monongahela		—			121.1			11.6			18.2			319.9			668.4			1,139.2
West Penn:
First Mortgage Bonds		—			—			—			—			—			420.0			420.0
Transition Bonds (a)		19.9			16.0			—			—			—			—			35.9
Medium-Term Notes		—			—			—			80.0			—			—			80.0
Total West Penn		19.9			16.0			—			80.0			—			420.0			535.9
Potomac Edison:
First Mortgage Bonds		—			—			—			—			—			420.0			420.0
Environmental Control Bonds (a)		—			3.7			3.9			4.1			4.3			90.5			106.5
Total Potomac Edison		—			3.7			3.9			4.1			4.3			510.5			526.5
TrAIL Company:
Term Loan		—			—			—			—			—			310.0			310.0
Revolving Loan		—			—			—			—			—			20.0			20.0
Total TrAIL		—			—			—			—			—			330.0			330.0
Unamortized debt discounts		(0.3	)		(1.3	)		(1.1	)		(0.7	)		(0.6	)		(1.2	)		(5.2	)
Eliminations (b)		—			—			—			(1.3	)		—			(13.2	)		(14.5	)
Total consolidated debt	$	19.6		$	139.5		$	883.9		$	604.8		$	323.6		$	2,516.7		$	4,488.1

(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.

20

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

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

2009 Debt Activity

Borrowings and principal repayments on debt during the nine months ended September 30, 2009 were as follows:

(In millions)	Issuances		Repayments
AE:
AE Revolving Credit Facility	$	120.0	$	—
AE Supply:
AE Supply Credit Facility—Revolving Loan		120.0		120.0
Exempt Facilities Revenue Bonds		235.0		—
Medium-Term Notes		—		244.3
TrAIL Company:
TrAIL Company Credit Facility—Term Loan		240.0		—
West Penn:
Transition Bonds		—		59.9
Monongahela:
Environmental Control Bonds		—		10.6
Potomac Edison:
Environmental Control Bonds		—		3.5
Consolidated Total	$	715.0	$	438.3

On July 6, 2009, the Pennsylvania Economic Development Financing Authority issued $235 million of 7.0% tax-exempt bonds that mature in 2039 and loaned the proceeds therefrom to AE Supply to finance a portion of the cost of constructing and installing Scrubbers at AE Supply’s Hatfield’s Ferry generation facility. AE Supply capitalized $2.4 million in debt issuance costs associated with this transaction.

On September 4, 2009, AE Supply repurchased $97.5 million and $146.8 million, respectively, of its 7.80% Notes due 2011 and its 8.25% Notes due 2012 pursuant to a cash tender offer, at an aggregate premium of $18.1 million. AE Supply expensed the $18.1 million premium, $0.6 million in unamortized debt costs, and $0.6 million in fees associated with the tender offer during the three months ended September 30, 2009.

On September 24, 2009, AE Supply entered into a new $1 billion senior unsecured revolving credit facility with a three-year maturity. The new revolving credit facility replaces AE Supply’s previous $400 million revolving credit facility, which was scheduled to mature in May 2011. Loans under the new facility generally will bear interest that is calculated based on the London Interbank Offered Rate, plus a margin based on AE Supply’s senior unsecured credit rating. AE Supply capitalized $22.1 million in debt costs related to this facility.

On October 1, 2009, AE Supply issued $600 million aggregate principal amount of senior unsecured notes, consisting of $350 million of 5.75% Notes due 2019 and $250 million of 6.75% Notes due 2039. AE Supply used a portion of the net proceeds from the sale of these notes to repay in full its existing $447 million term loan on October 2, 2009. AE Supply capitalized $5.3 million in debt issuance costs associated with this new debt issuance and expensed $0.6 million of unamortized debt costs associated with the extinguished term loan.

21

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

On October 21, 2009, AE Supply used the remaining proceeds of its senior secured note offering to repurchase approximately $152 million aggregate principal amount of its 7.80% Medium Term Notes due 2011 pursuant to a cash tender offer at an aggregate premium of $12.7 million. AE Supply plans to expense the $12.7 million premium, $0.3 million in unamortized debt costs, and $0.4 million in fees related to this tender offer during the three months ending December 31, 2009.

NOTE 8: BUSINESS SEGMENTS

Allegheny manages and evaluates its operations in two business segments, the Delivery and Services segment and the Generation and Marketing segment. The Delivery and Services segment includes the operations of Potomac Edison, West Penn, TrAIL Company, PATH, LLC and Monongahela’s electric T&D business. The Generation and Marketing segment includes the operations of AE Supply, AGC and Monongahela’s West Virginia generating assets.

The Generation and Marketing segment includes an unregulated component and a regulated component. The unregulated component primarily consists of AE Supply’s power generation and marketing operations, including the results of operations related to AGC on a fully consolidated basis. The regulated component consists of Monongahela’s regulated West Virginia generation operations and Monongahela’s interest in AGC under the equity method of accounting.

22

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

The following tables summarize results of operations for Allegheny’s two reportable segments. The information for the Delivery and Services segment includes the operations of the VA Distribution Business. See Note 3, “Assets Held for Sale,” for additional information.

	Three Months Ended September 30, 2009
	Generation and Marketing												Delivery and Services
(In millions)	Unregulated			Regulated			Eliminations			Total						Eliminations			Total
External operating revenues										$	12.3		$	781.4		$	—		$	793.7
Internal operating revenues											437.7			2.1			(439.8	)		—
Total operating revenues	$	358.3		$	98.4		$	(6.7	)		450.0			783.5			(439.8	)		793.7
Fuel		151.2			36.8			—			188.0			—			—			188.0
Purchased power and transmission		9.1			24.4			(6.7	)		26.8			545.1			(437.7	)		134.2
Deferred energy costs, net		—			(9.3	)		—			(9.3	)		(5.0	)		—			(14.3	)
Operations and maintenance		50.1			17.8			0.1			68.0			85.3			(2.1	)		151.2
Depreciation and amortization		28.5			5.3			(0.5	)		33.3			38.0			—			71.3
Taxes other than income taxes		12.4			5.6			—			18.0			39.4			—			57.4
Total operating expenses		251.3			80.6			(7.1	)		324.8			702.8			(439.8	)		587.8
Operating income		107.0			17.8			0.4			125.2			80.7			—			205.9
Other income (expense), net		0.2			3.0			(2.7	)		0.5			1.4			—			1.9
Interest expense		46.6			12.6			—			59.2			25.9			—			85.1
Income before income taxes		60.6			8.2			(2.3	)		66.5			56.2			—			122.7
Income tax expense		20.4			0.7			(0.1	)		21.0			24.3			—			45.3
Net income		40.2			7.5			(2.2	)		45.5			31.9			—			77.4
Less: net income attributable to noncontrolling interest		(2.2	)		—			2.2			—			(0.4	)		—			(0.4	)
Net income attributable to Allegheny Energy, Inc.	$	38.0		$	7.5		$	—		$	45.5		$	31.5		$	—		$	77.0
	Three Months Ended September 30, 2008
	Generation and Marketing												Delivery and Services
(In millions)	Unregulated			Regulated			Eliminations			Total						Eliminations			Total
External operating revenues										$	158.8		$	690.8		$	—		$	849.6
Internal operating revenues											430.5			1.9			(432.4	)		—
Total operating revenues	$	468.2		$	133.1		$	(12.0	)		589.3			692.7			(432.4	)		849.6
Fuel		223.4			75.8			—			299.2			—			—			299.2
Purchased power and transmission		7.9			29.8			(12.0	)		25.7			512.9			(430.5	)		108.1
Deferred energy costs, net		—			(20.2	)		—			(20.2	)		1.5			—			(18.7	)
Operations and maintenance		49.0			21.5			0.1			70.6			83.6			(1.9	)		152.3
Depreciation and amortization		23.7			5.0			(0.5	)		28.2			39.2			—			67.4
Taxes other than income taxes		12.8			6.6			—			19.4			35.0			—			54.4
Total operating expenses		316.8			118.5			(12.4	)		422.9			672.2			(432.4	)		662.7
Operating income		151.4			14.6			0.4			166.4			20.5			—			186.9
Other income (expense), net		1.2			3.4			(3.0	)		1.6			3.1			(0.2	)		4.5
Interest expense		23.8			9.6			(0.1	)		33.3			24.8			(0.2	)		57.9
Income (loss) before income taxes		128.8			8.4			(2.5	)		134.7			(1.2	)		—			133.5
Income tax expense (benefit)		47.6			2.5			(0.1	)		50.0			(5.7	)		—			44.3
Net income		81.2			5.9			(2.4	)		84.7			4.5			—			89.2
Less: net income attributable to noncontrolling interest		(2.4	)		—			2.4			—			(0.2	)		—			(0.2	)
Net income attributable to Allegheny Energy, Inc.	$	78.8		$	5.9		$	—		$	84.7		$	4.3		$	—		$	89.0

23

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

	Nine Months Ended September 30, 2009
	Generation and Marketing												Delivery and Services
(In millions)	Unregulated			Regulated			Eliminations			Total						Eliminations			Total
External operating revenues										$	153.9		$	2,411.8		$	—		$	2,565.7
Internal operating revenues											1,377.6			5.8			(1,383.4	)		—
Total operating revenues	$	1,188.0		$	365.3		$	(21.8	)		1,531.5			2,417.6			(1,383.4	)		2,565.7
Fuel		490.2			173.6			—			663.8			—			—			663.8
Purchased power and transmission		27.2			81.4			(21.8	)		86.8			1,671.2			(1,377.6	)		380.4
Deferred energy costs, net		—			(33.0	)		—			(33.0	)		(5.9	)		—			(38.9	)
Operations and maintenance		201.2			60.0			0.4			261.6			263.1			(5.8	)		518.9
Depreciation and amortization		76.3			15.7			(1.4	)		90.6			116.4			—			207.0
Taxes other than income taxes		33.7			12.9			—			46.6			113.1			—			159.7
Total operating expenses		828.6			310.6			(22.8	)		1,116.4			2,157.9			(1,383.4	)		1,890.9
Operating income		359.4			54.7			1.0			415.1			259.7			—			674.8
Other income (expense), net		1.2			9.1			(8.2	)		2.1			4.0			—			6.1
Interest expense		84.5			38.4			—			122.9			78.6			—			201.5
Income before income taxes		276.1			25.4			(7.2	)		294.3			185.1			—			479.4
Income tax expense		109.9			6.6			(0.4	)		116.1			79.0			—			195.1
Net income		166.2			18.8			(6.8	)		178.2			106.1			—			284.3
Less: net income attributable to noncontrolling interest		(6.8	)		—			6.8			—			(0.8	)		—			(0.8	)
Net income attributable to Allegheny Energy, Inc.	$	159.4		$	18.8		$	—		$	178.2		$	105.3		$	—		$	283.5
	Nine Months Ended September 30, 2008
	Generation and Marketing												Delivery and Services
(In millions)	Unregulated			Regulated			Eliminations			Total						Eliminations			Total
External operating revenues										$	544.5		$	2,133.6		$	—		$	2,678.1
Internal operating revenues											1,297.5			6.0			(1,303.5	)		—
Total operating revenues	$	1,460.3		$	416.1		$	(34.4	)		1,842.0			2,139.6			(1,303.5	)		2,678.1
Fuel		578.3			215.9			—			794.2			—			—			794.2
Purchased power and transmission		22.3			89.8			(34.4	)		77.7			1,522.5			(1,297.5	)		302.7
Deferred energy costs, net		—			(35.9	)		—			(35.9	)		7.8			—			(28.1	)
Operations and maintenance		168.6			80.6			0.4			249.6			267.4			(6.0	)		511.0
Depreciation and amortization		70.8			14.6			(1.5	)		83.9			122.6			—			206.5
Taxes other than income taxes		35.1			19.1			—			54.2			105.5			—			159.7
Total operating expenses		875.1			384.1			(35.5	)		1,223.7			2,025.8			(1,303.5	)		1,946.0
Operating income		585.2			32.0			1.1			618.3			113.8			—			732.1
Other income (expense), net		6.3			10.2			(8.9	)		7.6			10.1			(2.4	)		15.3
Interest expense		78.0			28.9			(0.2	)		106.7			70.7			(2.4	)		175.0
Income before income taxes		513.5			13.3			(7.6	)		519.2			53.2			—			572.4
Income tax expense		179.7			3.2			(0.4	)		182.5			10.0			—			192.5
Net income		333.8			10.1			(7.2	)		336.7			43.2			—			379.9
Less: net income attributable to noncontrolling interest		(7.2	)		—			7.2			—			(0.7	)		—			(0.7	)
Net income attributable to Allegheny Energy, Inc.	$	326.6		$	10.1		$	—		$	336.7		$	42.5		$	—		$	379.2

24

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

NOTE 9: FAIR VALUE MEASUREMENTS, DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Allegheny’s assets and liabilities measured at fair value on a recurring basis at September 30, 2009 consisted of the following:

(In millions)	Assets		Liabilities
Cash equivalents (a)	$	243.6	$	—
Derivative instruments (b):
Current		188.2		(13.7	)
Non-current		4.2		(22.1	)
Total derivative instruments		192.4		(35.8	)
Total recurring fair value measurements	$	436.0	$	(35.8	)

(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, before netting of cash collateral and FTR obligation, based on their level within the fair value hierarchy. This table excludes derivatives that have been designated as normal purchases or normal sales.

	September 30, 2009							December 31, 2008
(In millions)	Derivative Assets		Derivative Liabilities			Net Derivative Assets		Derivative Assets		Derivative Liabilities			Net Derivative Assets
Level 1	$	31.6	$	(2.9	)	$	28.7	$	10.5	$	—		$	10.5
Level 2		35.9		(32.9	)		3.0		112.4		(34.3	)		78.1
Level 3		124.9		—			124.9		189.8		—			189.8
Total	$	192.4	$	(35.8	)	$	156.6	$	312.7	$	(34.3	)	$	278.4

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 and 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 Interconnection, L.L.C. (“PJM”) annual and monthly FTR auctions.

The following table shows the expected settlement year for derivative assets and liabilities outstanding before netting of cash collateral and FTR obligation at September 30, 2009:

(In millions)	2009		2010			2011			2012			Total
Level 1	$	1.0	$	31.7		$	(1.6	)	$	(2.4	)	$	28.7
Level 2		44.5		(26.3	)		(14.3	)		(0.9	)		3.0
Level 3		38.9		86.0			—			—			124.9
Net derivative assets (liabilities)	$	84.4	$	91.4		$	(15.9	)	$	(3.3	)	$	156.6

25

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

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 September 30,
(In millions)	2009			2008
Balance at July 1	$	250.5		$	958.4
Total realized and unrealized gains (losses):
Included in earnings, in operating revenues		(69.5	)		(154.2	)
Included in regulatory assets or liabilities		(36.0	)		(74.8	)
Purchases, issuances and settlements		(20.1	)		(204.8	)
Transfers in / out of Level 3		—			—
Balance at September 30	$	124.9		$	524.6
Amount of total gains (losses) included in earnings attributable to the change in unrealized gains (losses) related to Level 3 assets held at September 30	$	(33.7	)	$	(63.2	)
	Nine Months Ended September 30,
(In millions)	2009			2008
Balance at January 1	$	189.8		$	150.0
Total realized and unrealized gains (losses):
Included in earnings, in operating revenues		(171.7	)		161.0
Included in regulatory assets or liabilities		(86.7	)		77.8
Purchases, issuances and settlements		193.5			135.8
Transfers in / out of Level 3		—			—
Balance at September 30	$	124.9		$	524.6
Amount of total gains (losses) included in earnings attributable to the change in unrealized gains (losses) related to Level 3 assets held at September 30	$	(15.5	)	$	94.4

26

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

The following table shows the volume of derivative contracts held by Allegheny at September 30, 2009 and their respective contract expiration dates, excluding contracts designated as normal purchase or normal sale:

(In millions)	2009		2010		2011		2012		Total
Forward sales of electricity (MWh):
Designated as cash flow hedges		1.0		3.2		3.3		—		7.5
Not designated as cash flow hedges		1.3		—		—		—		1.3
Forward purchases of electricity (MWh):
Designated as cash flow hedges		0.2		0.2		0.1		0.5		1.0
Not designated as cash flow hedges		1.2		0.1		—		0.1		1.4
FTRs (MWh)		15.9		26.0		—		—		41.9
Coal purchase contracts — PRB (tons)		0.7		—		—		—		0.7
Gas contracts — Kern River (decatherms):
Forward sales of gas		8.3		20.5		—		—		28.8
Forward purchases of gas		8.6		21.4		—		—		30.0
Interest rate swaps (notional dollars):
Interest rate swap agreements (fixed rate to floating rate)	$	—	$	143.0	$	200.0	$	—	$	343.0
Interest rate swap agreements (floating rate to fixed rate)	$	—	$	143.0	$	200.0	$	—	$	343.0

At September 30, 2009, Allegheny held derivative contracts for the sale or purchase of power that were entered into to hedge the variable price risk related to forecasted sales and purchases of power and were designated as cash flow hedging instruments for accounting purposes. Changes in the fair value of these hedging instruments representing the effective portion of the hedge are reported in accumulated other comprehensive income (loss) and subsequently reclassified into earnings when the forecasted transaction is settled and impacts earnings. Allegheny also held derivative contracts at September 30, 2009 that were not designated as part of a cash flow hedge relationship or as normal purchase normal sale. Changes in the fair value of these contracts are reported in revenues on a mark-to-market basis. These derivatives include contracts for the forward purchase and sale of gas that settle in 2009 and 2010 and that were entered into to hedge a portion of the value of a capacity contract related to the Kern River Pipeline but that do not qualify for cash flow hedge accounting. Interest rate swaps 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.

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 are not designated for cash flow hedge accounting. 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.

27

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

The recorded fair values of derivatives at September 30, 2009 were as follows:

	Power Contracts						Gas Contracts -Kern River			Coal Purchase Contracts - PRB			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	$	41.3		$	(0.1	)	$	—		$	—		$	—		$	—	$	41.2		$	(16.8	)	$	24.4		$	—		$	—		$	24.4
Total derivative assets		41.3			(0.1	)		—			—			—			—		41.2			(16.8	)		24.4			—			—			24.4
Derivative liabilities:
Current		(10.5	)		(8.8	)		—			—			—			—		(19.3	)		17.0			(2.3	)		—			—			(2.3	)
Long-term		(14.5	)		(5.4	)		—			—			—			—		(19.9	)		(0.1	)		(20.0	)		—			2.8			(17.2	)
Total derivative liabilities		(25.0	)		(14.2	)		—			—			—			—		(39.2	)		16.9			(22.3	)		—			2.8			(19.5	)
Total designated		16.3			(14.3	)		—			—			—			—		2.0			0.1			2.1			—			2.8			4.9
Derivatives not designated as hedging instruments:
Derivative assets:
Current		23.5			(0.1	)		44.2			1.9			—			124.9		194.4			(30.6	)		163.8			(124.9	)		(22.9	)		16.0
Long-term		—			—			7.4			—			—			—		7.4			(3.2	)		4.2			—			(3.5	)		0.7
Total derivative assets		23.5			(0.1	)		51.6			1.9			—			124.9		201.8			(33.8	)		168.0			(124.9	)		(26.4	)		16.7
Derivative liabilities:
Current		(0.9	)		(23.1	)		(10.0	)		(1.8	)		(6.1	)		—		(41.9	)		30.4			(11.5	)		—			—			(11.5	)
Long-term					(1.4	)		(1.9	)					(2.0	)				(5.3	)		3.3			(2.0	)		—			—			(2.0	)
Total derivative liabilities		(0.9	)		(24.5	)		(11.9	)		(1.8	)		(8.1	)				(47.2	)		33.7			(13.5	)		—			—			(13.5	)
Total not designated		22.6			(24.6	)		39.7			0.1			(8.1	)		124.9		154.6			(0.1	)		154.5			(124.9	)		(26.4	)		3.2
Total derivatives	$	38.9		$	(38.9	)	$	39.7		$	0.1		$	(8.1	)	$	124.9	$	156.6		$	—		$	156.6		$	(124.9	)	$	(23.6	)	$	8.1

(a) The FTR obligation at September 30, 2009 was $205.8 million and is payable to PJM in approximately equal weekly amounts through the PJM planning year ending May 31, 2010. Of this obligation, $124.9 million has been netted against the FTR derivative asset balance and the remaining $80.9 million is included in non-derivative current liabilities on the consolidated balance sheet. Prior to June 1, 2009, FTR obligations were payable to PJM in monthly installments.

28

ALLEGHENY ENERGY, INC.

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 September 30,
(In millions)	2009			2008
Accumulated OCI derivative gain (loss) at July 1 (before tax effect of $22.6 million and $46.9 million, respectively)	$	58.7		$	(121.1	)
Effective portion of changes in fair value (before tax effect of $6.1 million and $44.8 million, respectively)		(15.8	)		115.5
Reclassifications of (gains) losses from accumulated OCI to earnings (before tax effect of $15.1 million and $6.1 million, respectively)		(39.3	)		16.0
Accumulated OCI derivative gain at September 30 (before tax effect of $1.4 million and $4.1 million, respectively)	$	3.6		$	10.4

	Nine Months Ended September 30,
(In millions)	2009			2008
Accumulated OCI derivative gain (loss) at January 1 (before tax effect of $17.8 million and $2.7 million, respectively)	$	45.8		$	(7.0	)
Effective portion of changes in fair value (before tax effect of $10.7 million and $7.4 million, respectively)		27.6			(19.5	)
Reclassifications of (gains) losses from accumulated OCI to earnings (before tax effect of $27.0 million and $14.2 million, respectively)		(69.8	)		36.9
Accumulated OCI derivative gain at September 30 (before tax effect of $1.4 million and $4.1 million, respectively)	$	3.6		$	10.4

Derivative gains included in accumulated OCI in the amount of $21.9 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) on derivatives designated as cash flow hedges:

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2009			2008			2009			2008
Gain (loss) recognized in OCI (effective portion)	$	(15.8	)	$	115.5		$	27.6		$	(19.5	)
Gains (losses) reclassified from accumulated OCI into operating revenues (effective portion)	$	39.3		$	(16.0	)	$	69.8		$	(36.9	)
Gain or (loss) recognized in operating revenues (ineffective portion)	$	(1.2	)	$	21.8		$	(2.9	)	$	4.8

29

ALLEGHENY ENERGY, INC.

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 September 30,						Nine Months Ended September 30,
(In millions)	2009			2008			2009			2008
Recorded in operating revenues:
Interest rate swaps	$	3.0		$	2.9		$	6.0		$	5.6
Mark-to-market power contracts		(4.4	)		43.5			(11.5	)		14.2
Gas contracts – Kern River		(6.8	)		21.5			11.2			8.4
FTRs		(6.2	)		(106.6	)		21.3			94.4
Recorded in fuel expense:
Coal purchase contracts – PRB		(3.9	)		(0.8	)		(7.8	)		9.6
Recorded in regulatory liabilities (assets):
FTRs		(3.3	)		(51.6	)		9.7			46.1
Coal purchase contracts – PRB		(3.6	)		(0.6	)		(7.5	)		8.0
Total	$	(25.2	)	$	(91.7	)	$	21.4		$	186.3

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 September 30, 2009 was $22.0 million, for which Allegheny had posted collateral of $7.9 million. A one level downgrade in AE Supply’s senior unsecured credit rating at September 30, 2009 would have required the posting of $7.3 million of collateral, in addition to the $7.9 million of posted collateral, for such derivative contracts in a liability position. A downgrade in AE Supply’s senior unsecured credit rating at September 30, 2009 to below Standard & Poor’s BB- or Moody’s Ba3 would have required the posting of $11.9 million of collateral, in addition to the $7.9 million of posted 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 those 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.

30

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

NOTE 10: STOCK-BASED COMPENSATION

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Stock options	$	1.7	$	2.1	$	5.6	$	6.9
Performance shares		1.4		1.1		5.5		1.5
Non-employee director shares		0.3		0.3		0.7		0.8
Stock units		—		—		0.1		0.6
Total stock-based compensation expense		3.4		3.5		11.9		9.8
Income tax benefit		1.4		1.4		4.8		3.9
Total stock-based compensation expense, net of tax	$	2.0	$	2.1	$	7.1	$	5.9

Stock-based compensation expense 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 nine months ended September 30, 2009 and 2008.

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 using the following weighted-average assumptions for stock options granted during the periods indicated:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009	2008			2009			2008
Annual risk-free interest rate	—		3.58	%		2.86	%		3.18	%
Expected term of the option (in years)	—		6.36			6.00			6.04
Expected annual dividend yield	—		1.31	%		2.53	%		1.12	%
Expected stock price volatility	—		27.0	%		36.4	%		27.3	%
Grant date fair value per stock option	—	$	13.50		$	7.14		$	15.27

No stock options were granted during the three months ended September 30, 2009.

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 of the stock option grants was calculated in accordance with Staff Accounting Bulletin 107, using the “simplified” method. AE continues to use 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 makes 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 and 2008, 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.

31

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

Stock option activity during the three and nine months ended September 30, 2009 was as follows:

	Stock Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (in millions)
Outstanding at June 30, 2009	2,973,413		$	27.31
Exercised (a)	(33,060	)	$	13.35
Forfeited/Expired	(6,089	)	$	33.67
Outstanding at September 30, 2009	2,934,264		$	27.45	$	14.6	(b)
Exercisable at September 30, 2009	1,269,955		$	23.51	$	11.1	(b)

	Stock Options			Weighted Average Exercise Price		Aggregate Intrinsic Value (in millions)
Outstanding at December 31, 2008	1,870,509			$	29.08
Granted (aggregate grant date fair value of $8.6 million)	1,204,965			$	23.68
Exercised (a)	(117,500	)		$	14.17
Forfeited/Expired	(23,710	)		$	29.51
Outstanding at September 30, 2009	2,934,264			$	27.45	$	14.6	(b)
Exercisable at September 30, 2009	1,269,955			$	23.51	$	11.1	(b)
			��

(a) Proceeds to AE from option exercises were $0.4 million and $1.6 million for the three and nine months ended September 30, 2009. Allegheny 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 of $26.52 on September 30, 2009.

As of September 30, 2009, Allegheny had approximately $9.7 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.

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.

32

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

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 the three-year performance period. Based upon AE’s percentile rank within the peer group, shares earned will range from 0% to 250% of each participant’s target 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%. Activity in target performance shares linked to TSR for the three and nine months ended September 30, 2009 was as follows:

	Number of Shares
Performance shares outstanding at June 30, 2009	246,742
Forfeited	(452	)
Performance shares outstanding at September 30, 2009	246,290

	Number of Shares
Performance shares outstanding at December 31, 2008	75,555
Granted (aggregate grant date fair value of $4.6 million)	172,075
Forfeited	(1,340	)
Performance shares outstanding at September 30, 2009	246,290

As of September 30, 2009, there was approximately $4.1 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 1.6 years.

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 nine months ended September 30, 2009 was as follows:

	Number of Shares
Performance shares outstanding at June 30, 2009	247,022
Forfeited	(454	)
Performance shares outstanding at September 30, 2009	246,568

	Number of Shares
Performance shares outstanding at December 31, 2008	75,693
Granted	172,220
Forfeited	(1,345	)
Performance shares outstanding at September 30, 2009	246,568

As of September 30, 2009, there was approximately $2.3 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 1.2 years.

33

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

Stock Units

Stock unit activity for the three and nine months ended September 30, 2009 was as follows:

	Number of Stock Units		Weighted-Average Grant Date Fair Value		Aggregate Intrinsic Value (a) (in millions)
Outstanding at June 30, 2009	5,147		$	15.31	$	0.1
Units converted into 3,573 common shares	(5,147	)	$	15.31
Outstanding at September 30, 2009	—		$	—	$	—

	Number of Stock Units		Weighted-Average Grant Date Fair Value		Aggregate Intrinsic Value (a) (in millions)
Outstanding at December 31, 2008	5,087		$	15.19	$	0.2
Units converted into 3,573 common shares	(5,147	)	$	15.31
Dividend on unvested units	60		$	25.47
Outstanding at September 30, 2009	—		$	—	$	—

(a) Represents the total pre-tax intrinsic value based on stock units outstanding multiplied by AE’s closing stock price on each respective date.

AE issued new shares of its common stock in connection with the stock unit conversions. The actual number of common shares issued upon conversion of stock units was net of shares withheld to meet minimum income tax withholding requirements.

Non-Employee Director Shares

Non-employee director share activity for the three and nine months ended September 30, 2009 was as follows:

	Number of Shares
Shares earned but not issued at June 30, 2009	73,781
Granted	9,000
Issued	(3,000	)
Dividends on earned but not issued shares	411
Shares earned but not issued at September 30, 2009	80,192

	Number of Shares
Shares earned but not issued at December 31, 2008	71,221
Granted	27,000
Issued	(19,201	)
Dividends on earned but not issued shares	1,172
Shares earned but not issued at September 30, 2009	80,192

34

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

Restricted Shares

In the first quarter of 2009, AE granted 17,850 restricted shares with an aggregate fair value of $0.4 million and a three-year vesting period.

As of September 30, 2009, Allegheny had approximately $0.3 million of unrecognized compensation cost related to non-vested restricted shares, which is expected to be recognized over a weighted average period of approximately 2.3 years.

NOTE 11: 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.

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 September 30,						Nine Months Ended September 30,
(In millions)	2009			2008			2009			2008
Components of net periodic cost:
Service cost	$	5.6		$	5.3		$	16.8		$	15.9
Interest cost		17.7			17.1			53.2			51.4
Expected return on plan assets		(18.5	)		(19.2	)		(55.7	)		(57.6	)
Amortization of unrecognized transition obligation		0.1			0.1			0.3			0.3
Amortization of prior service cost		0.8			0.8			2.4			2.4
Recognized actuarial loss		2.8			1.8			8.4			5.4
Net periodic cost	$	8.5		$	5.9		$	25.4		$	17.8

35

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

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 September 30,						Nine Months Ended September 30,
(In millions)	2009			2008			2009			2008
Components of net periodic cost:
Service cost	$	1.1		$	1.1		$	3.3		$	3.3
Interest cost		4.3			4.3			12.9			12.8
Expected return on plan assets		(1.3	)		(1.8	)		(4.0	)		(5.4	)
Amortization of unrecognized transition obligation		1.4			1.4			4.3			4.3
Recognized actuarial loss		0.5			0.2			1.4			0.5
Net periodic cost	$	6.0		$	5.2		$	17.9		$	15.5

For the three months ended September 30, 2009 and 2008, Allegheny capitalized $4.6 million and $3.4 million, respectively, and for the nine months ended September 30, 2009 and 2008, Allegheny capitalized $13.3 million and $9.8 million, respectively, of the above net periodic cost amounts to “Construction work in progress,” a component of “Property, plant and equipment, net.”

Contributions

Allegheny makes cash contributions to its qualified pension plan to meet the minimum funding requirements of employee benefit and tax laws and may include additional discretionary contributions to increase the funded level of the plan. During the three and nine months ended September 30, 2009, Allegheny contributed $37.5 million to its qualified pension plan and $0.1 million and $0.4 million, respectively, to its SERP. Allegheny made approximately $3.3 million and $7.2 million in contributions to its postretirement benefits other than pension plans during the three and nine months ended September 30, 2009. Allegheny does not anticipate making any additional contributions to its qualified pension plan during the remainder of 2009. Allegheny currently anticipates that it will contribute an additional $3.0 million to $4.0 million during the remainder of 2009 to fund postretirement benefits other than pensions.

Allegheny made Employee Stock Ownership and Savings Plan matching contributions in cash in the amount of $2.3 million and $2.2 million for the three months ended September 30, 2009 and 2008, respectively, and $6.8 million and $6.7 million for each of the nine months ended September 30, 2009 and 2008, respectively. These contributions, less amounts capitalized in “Construction work in progress,” were expensed. The capitalized portions of these costs were $0.7 million for the three months ended September 30, 2009 and 2008, and $2.2 million and $1.9 million for the nine months ended September 30, 2009 and 2008, respectively.

36

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

NOTE 12: FINANCIAL INSTRUMENTS

As of September 30, 2009 and December 31, 2008, the carrying amounts of accounts receivable, accounts payable and short-term debt 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, were as follows:

	September 30, 2009				December 31, 2008
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	4,488.1	$	4,647.4	$	4,209.8	$	3,951.7

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

NOTE 13: COMPREHENSIVE INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS

Comprehensive income consisted of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2009			2008			2009			2008
Net income	$	77.4		$	89.2		$	284.3		$	379.9
Other comprehensive income, net of tax:
Cash flow hedges, net of tax of $21.2, $51.0, $16.4 and $6.7, respectively		(33.7	)		80.5			(25.7	)		10.6
Defined benefit pension and other benefit plan amortization, net of tax of $0.6, $0.3, $1.7 and $0.9, respectively		0.8			0.4			2.5			1.0
Comprehensive income		44.5			170.1			261.1			391.5
Less comprehensive income attributable to noncontrolling interest		(0.4	)		(0.2	)		(0.8	)		(0.7	)
Comprehensive income attributable to Allegheny Energy, Inc.	$	44.1		$	169.9		$	260.3		$	390.8

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

(In millions)	September 30, 2009			December 31, 2008
Cash flow hedges, net of tax of $1.5 and $17.8, respectively	$	2.4		$	28.1
Net unrecognized pension and other benefit plan costs, net of tax of $(47.0) and $(48.7), respectively		(68.9	)		(71.4	)
Total	$	(66.5	)	$	(43.3	)

37

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

NOTE 14: EARNINGS PER SHARE

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions, except share and per share amounts)	2009		2008		2009		2008
Basic Income per Share:
Numerator:
Net income attributable to Allegheny Energy, Inc.	$	77.0	$	89.0	$	283.5	$	379.2
Denominator:
Weighted average common shares outstanding		169,565,262		168,894,148		169,503,916		168,232,547
Basic earnings per share attributable to Allegheny Energy, Inc.	$	0.45	$	0.53	$	1.67	$	2.25
Diluted Income per Share:
Numerator:
Net income attributable to Allegheny Energy, Inc.	$	77.0	$	89.0	$	283.5	$	379.2
Denominator:
Weighted average common shares outstanding		169,565,262		168,894,148		169,503,916		168,232,547
Effect of dilutive securities:
Stock options (a)		412,767		1,003,600		399,548		1,450,503
Stock units		2,262		36,766		3,595		276,238
Non-employee stock awards		—		58,887		—		55,084
Performance shares		17,261		12,448		18,005		8,573
Total shares		169,997,552		170,005,849		169,925,064		170,022,945
Diluted earnings per share attributable to Allegheny Energy, Inc.	$	0.45	$	0.52	$	1.67	$	2.23

(a) The dilutive share calculations exclude 2,007,513 shares and 637,846 shares for the three months ended September 30, 2009 and 2008, respectively, and 1,750,389 shares and 491,388 shares for the nine months ended September 30, 2009 and 2008, respectively, relating to stock options because the inclusion of these amounts would have been antidilutive under the treasury stock method.

NOTE 15: 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 interest or in which the equity investment at risk is insufficient to finance the entity’s activities without receiving financial support from the other parties.

38

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

Independent Power Producer Contracts. Potomac Edison purchased power from an independent power producer (an “IPP”) under a long-term power purchase agreement at a cost of $19.5 million and $30.3 million for the three months ended September 30, 2009 and 2008, respectively, and $65.6 million and $85.0 million for the nine months ended September 30, 2009 and 2008, respectively. West Penn purchased power from another IPP under a long-term power purchase agreement at a cost of $11.6 million and $9.3 million for the three months ended September 30, 2009 and 2008, respectively, and $35.7 million and $25.6 million for the nine months ended September 30, 2009 and 2008, respectively.

Allegheny has requested, but has been unable to obtain, information necessary to determine whether the IPPs are VIEs and whether Allegheny is the primary beneficiary, because the IPPs have determined that such information is proprietary.

Potomac Edison recovers the full amount, and West Penn recovers a portion, of the cost of the applicable power contract in their respective rates charged to consumers or through customer surcharges. Neither Potomac Edison nor West Penn is subject to any risk of loss associated with the applicable potential VIE, because neither of them 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 in the early 2000s. Some of the project financings required Potomac Edison to provide ongoing guarantees.

In 2005, the joint venture operating agreement was amended based on Allegheny’s desire to limit its obligations and participation in APS Constellation, such as non-voluntary capital contributions and economic participation in future projects. In 2007, APS Constellation, at Constellation Energy’s request, began a new project without Allegheny’s involvement.

The accounts of APS Constellation are not included in Allegheny’s Consolidated Financial Statements because Allegheny does not expect to absorb a majority of the expected losses and/or residual returns based on an analysis of the services being provided under the joint venture operating agreement.

At September 30, 2009, 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 $3.2 million and recourse guarantees of $6.5 million. These guarantees are not recorded on Allegheny’s Consolidated Balance Sheet.

PATH, LLC. In September 2007, Allegheny and AEP formed PATH, LLC to construct and operate PATH.

The accounts of PATH, LLC and its operating subsidiaries are included in Allegheny’s Consolidated Financial Statements. Allegheny consolidated PATH, LLC because, based on an analysis of the services being provided and possible cash flow scenarios under the PATH, LLC agreement and other related agreements, Allegheny would absorb a majority of the expected losses and/or residual returns.

39

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

Allegheny’s Consolidated Balance Sheet at September 30, 2009 primarily reflected property, plant and equipment associated with the construction of PATH of approximately $67.5 million, cash and cash equivalents of $6.2 million, noncontrolling interest related to AEP’s ownership of approximately $12.6 million, $4.7 million in net regulatory liabilities and $51.0 million in accounts payable associated with the construction of PATH.

Allegheny has certain risks related to its involvement in PATH related to successfully obtaining necessary approvals, securing the necessary rights of way and the completion of the construction of the line and related facilities. In addition, certain regulatory risks exist regarding the recovery of the costs associated with the project, including a fair return on the investment. PATH, LLC earns its revenues through a FERC approved formula rate mechanism that provides for recovery of all allowable expenses and a return on its allowable investment in PATH on a dollar-for-dollar basis.

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 September 30, 2009, total assets of EIS were $17.7 million, consisting primarily of investments, and total liabilities of EIS were $13.3 million, consisting primarily of claim reserves. At September 30, 2009, Allegheny’s maximum exposure to loss related to EIS consisted of a $4.4 million equity investment in EIS recorded on Allegheny’s Consolidated Balance Sheet.

NOTE 16: OTHER INCOME (EXPENSE), NET

Other income (expense), net, consisted of the following:

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Equity component of AFUDC	$	1.6	$	1.0	$	4.0	$	2.4
Interest and dividend income		0.3		1.4		1.5		5.4
Cash received from a former trading executive’s forfeited assets		—		—		—		1.6
Other		—		2.1		0.6		5.9
Total	$	1.9	$	4.5	$	6.1	$	15.3

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.

40

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

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 48% 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, CO₂ legislation and regulation, if not reasonably designed, could have a significant impact on Allegheny’s operations. On June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act. The U.S. Senate released its draft of the bill, the Clean Energy Jobs and American Power Act, on September 30, 2009. Allegheny can provide no assurance that limits on CO₂ emissions, if imposed by legislation or otherwise, will be set at levels that can accommodate its generation facilities absent the installation of controls.

Moreover, 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 U.S. Department of Energy (“DOE”) National Electric Technology Laboratory report and 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.

Allegheny supports federal legislation and believes that the United States must commit to a response to climate change that both encourages the development of technology and creates a workable control system. Regardless of the eventual mechanism for limiting CO₂ emissions, however, 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 six tasks:

• maintaining an accurate CO₂ emissions data base;

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

41

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

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

• participating in CO₂ sequestration efforts (e.g. reforestation projects) both domestically and abroad;

• 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 1,142 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, currently has approval to use waste-tire derived fuel at another of its coal-based power stations in West Virginia, and is actively exploring the economics of installing additional renewable generation capacity.

Allegheny intends to engage 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. 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. The Clean Air Interstate Rule (“CAIR”) promulgated by the U.S. Environmental Protection Agency (the “EPA”) on March 10, 2005 may accelerate the need to install this equipment by phasing out a portion of the currently available allowances. The EPA is revising certain portions of CAIR that were invalidated by the U.S. Court of Appeals for the District of Columbia Circuit. The EPA has cautioned that it is reviewing whether or not to have an annual NOx trading program (non-Ozone Season) beyond 2010.

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. The EPA is expected to finalize the new rule by November 2011.

The Pennsylvania Department of Environmental Protection (the “PA DEP”) promulgated a more aggressive mercury control rule on February 17, 2007. Pennsylvania’s proposed shortened compliance schedule and more aggressive emissions limits might result in the installation of additional emission controls at any of Allegheny’s three Pennsylvania coal-fired facilities or in a change in fuel specifications. Controls might include additional Scrubbers, activated carbon injection, selective catalytic reduction or other currently emerging technologies. On September 15, 2008, PPL Corporation filed a challenge to the PA DEP’s mercury rule in Pennsylvania Commonwealth Court. The Commonwealth Court overturned the Pennsylvania mercury rule on January 30,

42

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

2009. However, the PA DEP has filed an appeal with the Pennsylvania Supreme Court. In addition, regardless of the ultimate disposition of the case, the PA DEP may adopt new, possibly more aggressive mercury control rules. Allegheny is continuing to monitor the PA DEP’s actions in this regard.

Additionally, Maryland passed the Healthy Air Act in early 2006. This legislation imposes state-wide emission caps on SO₂ and NOx, 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 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 NOx, SO₂ and mercury, provided that PJM declares the station vital to reliability in the Baltimore/Washington DC metropolitan area. In response to Allegheny’s request and after conducting a reliability evaluation, PJM, by letter dated November 8, 2006, determined that R. Paul Smith is vital to the regional reliability of power flow. Pursuant to the legislation, the Maryland Department of the Environment (the “MDE”) has passed, on an emergency basis and effective April 11, 2009, specific regulations for R. Paul Smith to comply with alternate NOx and SO₂ limits. MDE still expects R. Paul Smith 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, and Allegheny is participating in RGGI auctions. Allegheny is continuing to monitor and assess the reach and affect of these regulations on its Maryland operations.

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 generation facility in October 2009. Additionally, Allegheny expects to complete the construction of Scrubbers at its Fort Martin generating facility by the end of 2009, although it is possible that an equipment problem may delay completion for one of the units at that facility until 2010.

Allegheny’s NOx compliance plan functions on a system-wide basis, similar to its SO₂ compliance plan. AE Supply and Monongahela also have the option, in some cases, to purchase alternate fuels or NOx allowances, if needed, to supplement their compliance strategies.

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 NSR standards of 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

43

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

and from the PA DEP. The Notice alleged that Allegheny made major modifications to some of its West Virginia facilities in violation of the Prevention of Significant Deterioration (“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 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.

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. No trial date has been set at this time, but the District Court indicated that a trial date may be set for 2009.

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 was directed to AE, Monongahela and West Penn and 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.

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,

44

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

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 remanded by the Court by mid-2010 and to issue a final rule in 2012.

Monongahela River Water Quality. In late 2008, the PA DEP imposed water quality criteria for certain effluents, including total dissolved solid 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 impact its ability to operate the Scrubbers. Preliminary studies indicate an initial capital investment of approximately $62 million in order to install technology to meet the total dissolved solid 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.

In October, 2009, the West Virginia Department of Environmental Protection (“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 total dissolved solid 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 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 total dissolved solid 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 byproducts (“CCB”) partly in response to a Tennessee Valley Authority ash spill in Kingston, Tennessee on December 22, 2008. CCB includes bottom ash, boiler slag, fly ash and Scrubber byproducts including gypsum. CCB has historically been designated and managed as a non-hazardous waste and the EPA has twice determined 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 CCB. The EPA has not yet reached a final decision on whether to regulate CCB as hazardous (RCRA Title C) or non-hazardous (RCRA Title D) or as a hybrid, but hopes to reach that decision by the end of 2009. Should the EPA

45

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

elect to designate CCB as hazardous at any point in its generation, storage, transportation or disposal cycle, it could significantly increase Allegheny’s cost of managing CCB materials. In addition to potential additional management costs, CCB generators could expect to see a reduction in options for beneficial reuse of CCB in applications such as mine reclamation, cement manufacture and agriculture, further increasing costs, as such materials will then enter landfills rather than beneficial reuse. The EPA might also designate CCB as hazardous only when it is destined for wet storage impoundments, which would reduce Allegheny’s potential waste management exposure.

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 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 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. AE intends to vigorously defend against this action but cannot predict its outcome.

Other Litigation

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 has been 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.

46

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

Allegheny intends to vigorously defend against this action but cannot predict its outcome.

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). The FERC issued an order on October 6, 2008 regarding the scope of those remand proceedings that expanded the relevant time period for the remand proceedings through June 20, 2001. AE Supply engaged in trading activity during the time period covered by this remand order. The presiding judge in the Lockyer case entered a scheduling order on May 1, 2009 that, among other things, established an initial hearing date of February 9, 2010 and set an initial decision date of July 6, 2010. 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. Asbestos-related litigation expenses have to date been reimbursed in full by recoveries from these historical insurers, and Allegheny believes that it has sufficient insurance to respond fully to the asbestos suits. Certain insurers, however, have contested their obligations to pay for the future defense and settlement costs relating to the asbestos suits. Allegheny is currently involved in three 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.), 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.) and Allegheny Energy, Inc. et al. v. Liberty Mutual Insurance Company, Civil Action No. 07-3168-BLS (Suffolk Superior Court, MA). Allegheny and Liberty Mutual Insurance Company resolved their dispute and, therefore, Civil Action No. 07-3168-BLS was voluntarily dismissed. The parties in the remaining actions 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 September 30, 2009, Allegheny’s total number of claims alleging exposure to asbestos was 856 in West Virginia, four in Pennsylvania and one in Illinois. Allegheny intends to vigorously pursue these matters but cannot predict their outcomes.

47

ALLEGHENY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(unaudited)

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.

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)	October 1 through December 31, 2009		2010		2011		2012		2013		Thereafter		Total		Less: amount representing interest and fees		Present value of net minimum capital lease payments
Capital Leases	$	2.7	$	10.8	$	8.7	$	6.3	$	4.6	$	6.7	$	39.8	$	11.0	$	28.8
Operating Leases	$	1.7	$	6.5	$	5.9	$	5.4	$	5.5	$	14.0	$	39.0	$	—	$	—

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 September 30, 2009. The commitments were calculated based on expected PURPA purchased power prices at September 30, 2009, without giving effect to possible price changes that could occur as a result of any future CO₂ emissions regulation or legislation. Actual values can vary substantially depending upon future conditions.

(In millions)	kWhs	Amount
October 1 through December 31, 2009	993.0	$	68.4
2010	3,826.2		275.7
2011	3,825.3		279.1
2012	3,843.9		280.0
2013	3,834.0		285.7
Thereafter	54,370.5		4,260.9
Total	70,692.9	$	5,449.8

48

ALLEGHENY ENERGY, INC.

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 September 30, 2009 were as follows:

(In millions)	Total
October 1 through December 31, 2009	$	210.2
2010		919.9
2011		1,023.7
2012		725.4
2013		691.2
Thereafter		2,329.5
Total	$	5,899.9

Other Purchase Obligations

Electronic Data Systems Corporation and EDS Information Services, LLC perform certain technology functions for Allegheny under a contract that expires on December 31, 2012. Expected cash payments under this contract are as follows:

(In millions)	October 1 through December 31, 2009		2010		2011		2012		Total
EDS contract services	$	6.5	$	25.7	$	23.8	$	23.0	$	79.0

NOTE 18: SUBSEQUENT EVENTS

On October 1, 2009, AE Supply issued $600 million aggregate principal amount of senior unsecured notes, consisting of $350 million of 5.75% Notes due 2019 and $250 million of 6.75% Notes due 2039. AE Supply used a portion of the net proceeds from the sale of these notes to repay in full its existing $447 million term loan on October 2, 2009. AE Supply capitalized $5.3 million in debt issuance costs associated with this new debt issuance and expensed $0.6 million of unamortized debt costs associated with the extinguished term loan.

On October 6, 2009, Allegheny agreed to the sale and long-term lease of the majority of the assets of its fiber optic network subsidiary, Allegheny Communications Connect, Inc. (“ACC”), for $27 million to NTELOS Holdings Corp. ACC owns and manages a fiber optic network of more than 2,200 route miles, primarily in Pennsylvania and West Virginia, with portions in several adjoining states. The transaction consists of the sale, lease and assignment of approximately 75% of the network. Allegheny will continue to maintain the lines that are leased. ACC will retain the remaining assets to serve the needs of Allegheny’s electric utility subsidiaries, including Smart Grid initiatives. Allegheny expects to close the transaction by the end of 2009. The agreement is subject to regulatory approvals and customary closing conditions.

On October 7, 2009, AE Supply signed definitive agreements to purchase two hydro generation facilities with a capacity of approximately 11 MWs and to settle a related power purchase contract, for a cash purchase

49

price of approximately $2.0 million. The purchase is subject to approval by FERC. AE Supply expects to complete the transaction by the end of 2009.

On October 21, 2009, AE Supply used the remaining proceeds of its senior secured note offering to repurchase approximately $152 million aggregate principal amount of its 7.80% Medium Term Notes due 2011 pursuant to a cash tender offer at an aggregate premium of $12.7 million. AE Supply plans to expense the $12.7 million premium, $0.3 million in unamortized debt costs, and $0.4 million in fees related to this tender offer during the three months ending December 31, 2009.

50

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 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, 2008 (the “2008 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 identify forward-looking statements. 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, state rate regulation, and the status of retail generation service supply competition in states served by the Distribution Companies;

• 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;

• provider-of-last-resort (“PLR”) and 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; and

• capacity purchase commitments.

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 financial transmission rights (“FTRs”);

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

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

51

• changes in the weather and other natural phenomena;

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

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

• changes in market rules, including changes to the participant rules and tariffs for PJM Interconnection, L.L.C. (“PJM”);

• the loss of any significant customers or suppliers;

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

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

• 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;

• complications or other factors that make it difficult or impossible to obtain necessary lender consents or regulatory authorizations on a timely basis;

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

• the availability of credit;

• actions of rating agencies;

• inflationary and deflationary trends and interest rate trends;

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

• entry into, any failure to consummate, or any delay in the consummation of, contemplated asset sales or other strategic transactions;

• general economic and business conditions; 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 2008 Annual Report on Form 10-K.

52

Overview

Allegheny is an integrated energy business that owns and operates electric generation facilities and delivers electric services to customers in Pennsylvania, West Virginia, Maryland and Virginia. Allegheny operates its business primarily through AE’s various directly and indirectly owned subsidiaries. These operations are aligned in two operating segments, the Delivery and Services segment and the Generation and Marketing segment. Selected financial measures for each segment for the three and nine months ended September 30, 2009 and 2008 were as follows:

	Three Months Ended September 30, 2009									Three Months Ended September 30, 2008
(In millions)	Delivery and Services		Generation and Marketing		Eliminations			Total		Delivery and Services			Generation and Marketing		Eliminations			Total
Operating revenues	$	783.5	$	450.0	$	(439.8	)	$	793.7	$	692.7		$	589.3	$	(432.4	)	$	849.6
Operating income	$	80.7	$	125.2	$	—		$	205.9	$	20.5		$	166.4	$	—		$	186.9
Income (loss) before income taxes	$	56.2	$	66.5	$	—		$	122.7	$	(1.2	)	$	134.7	$	—		$	133.5
	Nine Months Ended September 30, 2009									Nine Months Ended September 30, 2008
(In millions)	Delivery and Services		Generation and Marketing		Eliminations			Total		Delivery and Services			Generation and Marketing		Eliminations			Total
Operating revenues	$	2,417.6	$	1,531.5	$	(1,383.4	)	$	2,565.7	$	2,139.6		$	1,842.0	$	(1,303.5	)	$	2,678.1
Operating income	$	259.7	$	415.1	$	—		$	674.8	$	113.8		$	618.3	$	—		$	732.1
Income before income taxes	$	185.1	$	294.3	$	—		$	479.4	$	53.2		$	519.2	$	—		$	572.4

The information for the Delivery and Services segment includes the operations of the Virginia distribution business, which is expected to be sold following the completion of applicable regulatory proceedings, as described in Note 3, “Assets Held For Sale” to the Consolidated Financial Statements.

The performance of Allegheny’s Delivery and Services segment is significantly impacted by customer demand for electricity, regulatory ratemaking actions and the progress of transmission expansion projects. Retail electricity sales for the three and nine months ended September 30, 2009 and 2008 were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009	2008	Change		2009	2008	Change
Retail electricity sales (million kWhs)	10,277	10,749	(4.4	)%	31,533	33,023	(4.5	)%

The decreases in retail electricity sales shown in the table above are due largely to significant decreases in industrial demand relating to the weak economic climate and, to a lesser degree, decreases in residential demand. These trends continued through September 30, 2009, and future retail electricity sales will continue to be affected by economic conditions, load fluctuations, conservation measures and weather.

During the three and nine months ended September 30, 2008, Potomac Edison’s Virginia distribution operations reported significant losses due to increased costs of purchased power that could not be passed on to its customers. As a result of rate making decisions, Potomac Edison began to recover the majority of its actual purchased power costs in Virginia beginning January 1, 2009, and this resulted in increased pre-tax earnings of $38.4 million and $95.5 million for the three and nine months ended September 30, 2009, respectively, compared to the corresponding periods in the prior year.

Capital expenditures on Allegheny’s PATH, TrAIL and other expansion transmission projects are continuing. Accumulated accrual-basis expenditures for these projects were $656.3 million at September 30,

53

2009 and $244.8 million at December 31, 2008. Increased capital spending on these projects directly impacts earnings and resulted in increases in pre-tax income, excluding the amount of such income attributable to our joint venture partner’s noncontrolling interest in PATH, of $7.3 million and $14.2 million for the three and nine months ended September 30, 2009, respectively, compared to the corresponding periods in the prior year.

The performance of Allegheny’s Generation and Marketing 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. Changes in such prices result from changes in supply and demand, fuel costs, market liquidity, weather, environmental regulation and other factors. Market prices for power and related commodities are volatile and difficult to predict. Trends in reduced demand and significantly lower market prices for electricity and related commodities that began during the third quarter of 2008 have continued to date. Allegheny cannot predict when economic conditions will improve and to what extent an economic recovery will impact future energy and commodity prices. The following table shows market prices for certain commodities in Allegheny’s region:

	Average Actual Market Prices				Forward Market Prices
	Year Ended December 31, 2008		Nine Months Ended September 30, 2009		Three Months Ending December 31, 2009			Year Ending December 31, 2010
Round-the-clock energy price - PJM Western Hub ($/MWh)	$	69.81	$	39.12	$	36.97	(a)	$	48.38	(a)
Natural gas price - Henry Hub NYMEX ($/MM Btu)	$	8.84	$	3.80	$	4.73	(a)	$	6.21	(a)

(a) Based on forward market prices as of September 30, 2009.

Certain operating statistics for Allegheny’s generation operations for the three and nine months ended September 30, 2009 and 2008 were as follows:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2009			2008			Change		2009			2008			Change
Round-the-clock energy price (PJM Western Hub)	$	33.78		$	76.89		(56.1	)%	$	39.12		$	75.40		(48.1	)%
All coal-fired unit kWhs generated (in millions)		6,308			11,462		(45.0	)%		23,951			33,690		(28.9	)%
Supercritical Coal Units:
kWhs generated (in millions) (a)		5,791			10,115		(42.7	)%		22,231			29,303		(24.1	)%
Equivalent Availability Factor (EAF) (b)		88.9	%		90.2	%	(1.3	)%		81.4	%		86.1	%	(4.7	)%
Net Capacity Factor (NCF) (c)		44.1	%		77.1	%	(33.0	)%		56.4	%		74.0	%	(17.6	)%
All Generating Units:
kWhs generated (in millions) (a)		7,008			11,904		(41.1	)%		25,417			35,048		(27.5	)%
Equivalent Availability Factor (EAF) (b)		89.6	%		90.5	%	(0.9	)%		83.1	%		86.4	%	(3.3	)%
Net Capacity Factor (NCF) (c)		35.2	%		62.0	%	(26.8	)%		43.5	%		60.3	%	(16.8	)%

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

(b) 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.

(c) 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 due to planned and unplanned outages as well as periods during which generating capacity is available but is not dispatched because of the availability of lower cost generation in amounts sufficient to meet demand.

Decreased demand for power and lower prices for power significantly impacted Allegheny’s Generation and Marketing segment during the three and nine months ended September 30, 2009. Decreases in Allegheny’s

54

power output reflect, among other things, reduced demand for power and the displacement of certain of Allegheny’s coal-fired units by gas-fired units due to low natural gas prices. In lower power price environments, Allegheny generates less power because of the increased amount of time during which it is not economical to run its generating units and utilizes the flexibility afforded in certain of its coal purchase contracts to cancel or defer coal deliveries.

To manage exposure to market price changes, Allegheny sells and purchases physical energy at the wholesale level and enters into financial contracts within established risk management objectives and policies. The impacts of weak demand and low commodity prices on operating performance during the three and nine months ended September 30, 2009 were partially mitigated by power sale hedges, including Allegheny’s PLR contracts and financial hedges. The following table shows the percentages of Allegheny’s estimated future power sales and coal purchases that were hedged as of September 30, 2009:

	Three Months Ending December 31, 2009		Year Ending December 31, 2010		Year Ending December 31, 2011
Percentage of expected coal-fired generation sales hedged	85.0	%	85.0	%	20.0	%
Percentage of expected coal purchases hedged	100.0	%	99.0	%	67.0	%

Allegheny relies on access to the financial markets as a source of liquidity. Allegheny strengthened its liquidity position and significantly reduced its intermediate term refinancing risk during September and early October 2009. Approximately $843 million of debt due in 2011 and 2012 was refinanced with debt due in 10 and 30 years. In addition, AE Supply entered into a new, $1 billion revolving credit facility that matures in 2012, which replaced its previous $400 million revolving credit facility that was scheduled to mature in 2011.

Current priorities include continued management of the expiration of generation rate caps in Pennsylvania, seeking equitable rate treatment in the various jurisdictions in which Allegheny operates, additional hedging of expected power output, particularly for 2011 and 2012, as deemed appropriate, completing the Scrubber project at the Fort Martin generating facility, addressing the potential impacts on Allegheny of environmental legislation and regulation, continued progress on the TrAIL and PATH projects and controlling or reducing costs.

55

RESULTS OF OPERATIONS

Income Summary

	Three Months Ended September 30, 2009												Three Months Ended September 30, 2008
(In millions)	Delivery and Services			Generation and Marketing			Eliminations			Total			Delivery and Services			Generation and Marketing			Eliminations			Total
Operating revenues	$	783.5		$	450.0		$	(439.8	)	$	793.7		$	692.7		$	589.3		$	(432.4	)	$	849.6
Fuel		—			188.0			—			188.0			—			299.2			—			299.2
Purchased power and transmission		545.1			26.8			(437.7	)		134.2			512.9			25.7			(430.5	)		108.1
Deferred energy costs, net		(5.0	)		(9.3	)		—			(14.3	)		1.5			(20.2	)		—			(18.7	)
Operations and maintenance		85.3			68.0			(2.1	)		151.2			83.6			70.6			(1.9	)		152.3
Depreciation and amortization		38.0			33.3			—			71.3			39.2			28.2			—			67.4
Taxes other than income taxes		39.4			18.0			—			57.4			35.0			19.4			—			54.4
Total operating expenses		702.8			324.8			(439.8	)		587.8			672.2			422.9			(432.4	)		662.7
Operating income		80.7			125.2			—			205.9			20.5			166.4			—			186.9
Other income (expense), net		1.4			0.5			—			1.9			3.1			1.6			(0.2	)		4.5
Interest expense		25.9			59.2			—			85.1			24.8			33.3			(0.2	)		57.9
Income (loss) before income taxes		56.2			66.5			—			122.7			(1.2	)		134.7			—			133.5
Income tax expense (benefit)		24.3			21.0			—			45.3			(5.7	)		50.0			—			44.3
Net income		31.9			45.5			—			77.4			4.5			84.7			—			89.2
Less: net income attributable to noncontrolling interest		(0.4	)		—			—			(0.4	)		(0.2	)		—			—			(0.2	)
Net income attributable to Allegheny Energy, Inc.	$	31.5		$	45.5		$	—		$	77.0		$	4.3		$	84.7		$	—		$	89.0

	Nine Months Ended September 30, 2009												Nine Months Ended September 30, 2008
(In millions)	Delivery and Services			Generation and Marketing			Eliminations			Total			Delivery and Services			Generation and Marketing			Eliminations			Total
Operating revenues	$	2,417.6		$	1,531.5		$	(1,383.4	)	$	2,565.7		$	2,139.6		$	1,842.0		$	(1,303.5	)	$	2,678.1
Fuel		—			663.8			—			663.8			—			794.2			—			794.2
Purchased power and transmission		1,671.2			86.8			(1,377.6	)		380.4			1,522.5			77.7			(1,297.5	)		302.7
Deferred energy costs, net		(5.9	)		(33.0	)		—			(38.9	)		7.8			(35.9	)		—			(28.1	)
Operations and maintenance		263.1			261.6			(5.8	)		518.9			267.4			249.6			(6.0	)		511.0
Depreciation and amortization		116.4			90.6			—			207.0			122.6			83.9			—			206.5
Taxes other than income taxes		113.1			46.6			—			159.7			105.5			54.2			—			159.7
Total operating expenses		2,157.9			1,116.4			(1,383.4	)		1,890.9			2,025.8			1,223.7			(1,303.5	)		1,946.0
Operating income		259.7			415.1			—			674.8			113.8			618.3			—			732.1
Other income (expense), net		4.0			2.1			—			6.1			10.1			7.6			(2.4	)		15.3
Interest expense		78.6			122.9			—			201.5			70.7			106.7			(2.4	)		175.0
Income before income taxes		185.1			294.3			—			479.4			53.2			519.2			—			572.4
Income tax expense		79.0			116.1			—			195.1			10.0			182.5			—			192.5
Net income		106.1			178.2			—			284.3			43.2			336.7			—			379.9
Less: net income attributable to noncontrolling interest		(0.8	)		—			—			(0.8	)		(0.7	)		—			—			(0.7	)
Net income attributable to Allegheny Energy, Inc.	$	105.3		$	178.2		$	—		$	283.5		$	42.5		$	336.7		$	—		$	379.2

56

CONSOLIDATED RESULTS

This section provides a discussion of Allegheny’s consolidated results of operations. A more detailed discussion of results for each business segment follows this consolidated discussion.

The following tables reconcile income before income taxes for the three and nine months ended September 30, 2008 to income before income taxes for the three and nine months ended September 30, 2009.

(In millions)
Consolidated income before income taxes for the three months ended September 30, 2008			$	133.5
Decrease in operating revenues				(55.9	)
Decreases (increases) in operating expenses:
Fuel	111.2
Purchased power and transmission	(26.1	)
Deferred energy costs, net	(4.4	)
Other operating expenses	(5.8	)
Decrease in operating expenses				74.9
Decrease in other income (expense), net				(2.6	)
Increase in interest expense				(27.2	)
Consolidated income before income taxes for the three months ended September 30, 2009			$	122.7

(In millions)
Consolidated income before income taxes for the nine months ended September 30, 2008			$	572.4
Decrease in operating revenues				(112.4	)
Decreases (increases) in operating expenses:
Fuel	130.4
Purchased power and transmission	(77.7	)
Deferred energy costs, net	10.8
Operations and maintenance	(7.9	)
Depreciation and amortization	(0.5	)
Decrease in operating expenses				55.1
Decrease in other income (expense), net				(9.2	)
Increase in interest expense				(26.5	)
Consolidated income before income taxes for the nine months ended September 30, 2009			$	479.4

Operating Revenues

Operating revenues decreased $55.9 million for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, primarily due to:

• a $176.6 million decrease, due primarily to a 41.1% reduction in total MWhs generated resulting from decreased demand, lower commodity prices and, to a lesser degree, planned outages to complete the installation of Scrubbers at the Hatfield’s Ferry generation facility,

• increased unrealized losses of $86.4 million on economic power hedges that did not qualify for hedge accounting and

• increased unrealized losses of $28.3 million related to pipeline capacity economic hedges that did not qualify for hedge accounting.

These operating revenue decreases were partially offset by:

• decreased unrealized losses of $100.4 million relating to FTRs,

57

• a $103.5 million increase resulting from increased rates charged to Pennsylvania customers, ratemaking settlements in Virginia and market-based generation pricing for Maryland residential customers and

• a $33.9 million increase primarily due to increased sales of power to non-affiliates that is offset by a corresponding increase in purchased power expense.

Operating revenues decreased $112.4 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to:

• a $359.1 million decrease, due primarily to a 27.5% reduction in total MWhs generated resulting from decreased demand, lower commodity prices and, to a lesser degree, planned outages to complete the installation of Scrubbers at the Hatfield’s Ferry generation facility,

• decreased unrealized gains of $73.1 million relating to FTRs,

• increased unrealized losses of $31.8 million on economic power hedges that did not qualify for hedge accounting and

• a $35.8 million decrease due to the expiration of an earnings benefit related to stranded cost recovery in Pennsylvania.

These operating revenue decreases were partially offset by:

• a $298.7 million increase resulting from increased rates charged to Pennsylvania customers, ratemaking settlements in Virginia and market-based generation pricing for Maryland residential customers and

• a $92.3 million increase primarily due to increased sales of power to non-affiliates that is offset by a corresponding increase in purchased power expense.

See “Regulatory Matters” for additional rate information and Note 9, “Fair Value Measurements, Derivative Instruments and Hedging Activities,” to the Consolidated Financial Statements for information regarding the recognition of unrealized gains and losses on FTRs and power sale hedges.

Operating Expenses

Fuel expense decreased $111.2 million and $130.4 million for the three and nine months ended September 30, 2009, respectively, compared to the three and nine months ended September 30, 2008, primarily due to decreased coal expense, which is described in greater detail within the Generation and Marketing segment results discussed below.

Purchased power and transmission expense increased $26.1 million and $77.7 million for the three and nine months ended September 30, 2009, respectively, compared to the three and nine months ended September 30, 2008, primarily due to Potomac Edison’s increased purchases from non-affiliates to serve residential customer load. Prior to 2009, Potomac Edison purchased such power from affiliates, and the purchased power and related affiliate revenues were eliminated in the consolidated financial statements.

Deferred energy costs, net changed $4.4 million and $10.8 million for the three and nine months ended September 30, 2009, respectively, compared to the three and nine months ended September 30, 2008, due to differences between actual costs incurred and the recovery of such costs, which are permitted to be included in customer rates, in West Virginia, Maryland and Virginia. See the segment results discussed below for additional information regarding changes in deferred energy costs, net.

Operations and maintenance expense increased $7.9 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily related to increased compensation and benefits expense and increased costs due to the timing of plant outages, partially offset by decreased costs associated with restoring customer service.

58

Other Income (Expense), net

Other income (expense), net decreased $2.6 million for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, primarily due to lower interest income resulting from decreased average investments at lower rates.

Other income (expense), net decreased $9.2 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to lower interest income resulting from decreased average investments at lower rates and cash received from a former trading executive during the first quarter of 2008.

Interest Expense

Interest expense increased $27.2 million and $26.5 million for the three and nine months ended September 30, 2009, respectively, compared to the three and nine months ended September 30, 2008, primarily due to costs associated with AE Supply’s September 2009 purchase of a portion of its outstanding medium-term notes, AE Supply’s July 2009 tax exempt bond financing, increased borrowings under the AE and TrAIL credit facilities and Monongahela’s December 2008 issuance of $300 million of first mortgage bonds, partially offset by increased capitalized interest on capital projects. See Note 7, “Common Stock and Debt,” for additional information.

Income Tax Expense

See Note 6, “Income Taxes,” to the Consolidated Financial Statements for a reconciliation of income tax expense to income tax expense calculated at the federal statutory rate of 35%.

59

DELIVERY AND SERVICES SEGMENT

Key Indicators and Performance Factors

Allegheny reviews the financial and operating performance of its Delivery and Services segment using a number of indicators and performance statistics, including the following:

Revenue per megawatt-hour (“MWh”) sold. This measure is calculated by dividing total revenues from retail sales of electricity by retail electricity sales. Revenue per MWh sold during the three and nine months ended September 30, 2009 and 2008 was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Revenue per MWh sold	$	71.09	$	60.09	$	71.99	$	60.60

Operations and maintenance costs (“O&M”).Management monitors and manages O&M in absolute terms, as well as in relation to total MWhs sold. 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 MWhs delivered. O&M per MWh delivered during the three and nine months ended September 30, 2009 and 2008 was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
O&M per MWh delivered	$	7.89	$	7.58	$	8.00	$	7.90

Capital expenditures.Management prioritizes and manages capital expenditures to meet operational needs and regulatory requirements within available cash flow constraints.

Retail electricity sales.The following table provides retail electricity sales information:

	Three Months Ended September 30,					Nine Months Ended September 30,
	Normal	2009	2008	2008 / 2009     Change		Normal	2009	2008	2008 / 2009     Change
Retail electricity sales (million kWhs)	N/A	10,277	10,749	(4.4)	%	N/A	31,533	33,023	(4.5)	%
HDD (a)	93	54	37	45.9	%	3,532	3,343	3,292	1.5	%
CDD (a)	587	549	537	2.2	%	802	813	767	6.0	%

(a) 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 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.

60

DELIVERY AND SERVICES SEGMENT

Operating Revenues

Operating revenues were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Retail electric:
Generation	$	544.6	$	453.6	$	1,690.1	$	1,406.6
Transmission		28.5		30.0		88.8		92.8
Distribution		157.5		162.3		491.3		501.9
Total retail electric		730.6		645.9		2,270.2		2,001.3
Transmission services and bulk power		39.8		37.0		108.0		107.1
Other affiliated and nonaffiliated energy services		13.1		9.8		39.4		31.2
Total operating revenues	$	783.5	$	692.7	$	2,417.6	$	2,139.6

Total operating revenues increased $90.8 million for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, primarily due to an $84.7 million increase in retail revenues, which resulted from:

• a $43.3 million increase resulting from higher generation rates charged to Pennsylvania customers,

• a $34.9 million increase, primarily due to an ENEC-related rate increase in West Virginia that went into effect on January 1, 2009,

• a $29.7 million increase in Maryland generation revenues primarily resulting from market-based generation pricing for residential customers effective January 1, 2009 and

• an $18.1 million increase due to higher rates under ratemaking settlements in Virginia.

These operating revenue increases were partially offset by:

• a $27.7 million decrease in generation revenue related to customer demand and

• a $6.3 million decrease in T&D revenues, primarily due to decreased customer demand.

See “Regulatory Matters,” for additional rate information.

61

DELIVERY AND SERVICES SEGMENT

Total operating revenues increased $278.0 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to a $268.9 million increase in retail revenues, which resulted from:

• a $130.4 million increase resulting from higher generation rates charged to Pennsylvania customers,

• a $111.0 million increase primarily due to an ENEC-related rate increase in West Virginia that went into effect on January 1, 2009,

• an $84.3 million increase in Maryland generation revenues primarily resulting from market-based generation pricing for residential customers effective January 1, 2009 and

• an $80.7 million increase due to higher rates under ratemaking settlements in Virginia.

These operating revenue increases were partially offset by:

• a $77.5 million decrease in generation revenue related to reduced customer demand,

• a $35.8 million decrease due to the expiration of an earnings benefit related to stranded cost recovery in Pennsylvania and

• a $14.6 million decrease in T&D revenues, primarily due to decreased customer demand.

See “Regulatory Matters,” for additional rate information.

Operating Expenses

Purchased Power and Transmission:Purchased power and transmission expense represents power purchased from AE Supply, Monongahela’s Generation and Marketing segment and third-party suppliers, including purchases from qualifying facilities under the Public Utilities Regulatory Policies Act of 1978 (“PURPA”). Purchased power and transmission expense was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Purchased power and transmission	$	545.1	$	512.9	$	1,671.2	$	1,522.5

Purchased power and transmission expense increased $32.2 million for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, primarily due to:

• a $35.7 million increase, primarily due to an ENEC-related rate increase in West Virginia that went into effect on January 1, 2009,

• a $39.0 million increase due to higher generation rates charged to West Penn’s Pennsylvania customers under the terms of a power supply agreement between West Penn and AE Supply and

• a $30.0 million increase, primarily due to higher rates under market-based generation pricing for Maryland residential customers effective January 1, 2009.

These increases were partially offset by:

• a $32.5 million decrease related to reduced customer demand,

• a $15.8 million decrease primarily due to lower market-based generation rates for Virginia residential customers,

• a $12.2 million decrease related to the expiration of an intercompany market rate adjustment in Pennsylvania and

62

DELIVERY AND SERVICES SEGMENT

• a $7.8 million decrease in purchased power from PURPA facilities, primarily resulting from the timing of maintenance outages at the Warrior Run PURPA generation facility.

See “Regulatory Matters” for additional information.

Purchased power and transmission expense increased $148.7 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to:

• a $108.5 million increase due to higher generation rates charged to West Penn’s Pennsylvania customers under the terms of a power supply agreement between West Penn and AE Supply,

• a $99.6 million increase, primarily due to an ENEC-related rate increase in West Virginia that went into effect on January 1, 2009 and

• a $97.5 million increase, primarily due to higher rates under market-based generation pricing for Maryland residential customers effective January 1, 2009.

These increases were partially offset by:

• an $81.9 million decrease related to reduced customer demand,

• a $36.7 million decrease related to the expiration of an intercompany market rate adjustment in Pennsylvania,

• a $10.3 million decrease primarily due to lower market-based generation rates for Virginia residential customers and

• a $7.7 million decrease in purchased power from PURPA facilities, primarily resulting from the timing of maintenance outages at the Warrior Run PURPA generation facility.

See “Regulatory Matters” for additional information.

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. Deferred energy costs related to the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2009			2008			2009			2008
AES Warrior Run PURPA generation	$	(2.0	)	$	3.0		$	(6.5	)	$	9.7
Market-based generation and other costs		(3.0	)		(1.5	)		0.6			(1.9	)
Deferred energy costs, net	$	(5.0	)	$	1.5		$	(5.9	)	$	7.8

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 (the “AES Warrior Run Surcharge”). Any under-recovery or over-recovery of net costs is being deferred pending subsequent recovery from, or return to, customers through adjustments to the AES Warrior Run Surcharge.

63

DELIVERY AND SERVICES SEGMENT

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 commercial and industrial customers who 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 of the Virginia SCC, Potomac Edison was granted a rate adjustment to recover a portion of its increased purchased power costs. The order directed Potomac Edison to defer any under- or over-recovery of purchased power costs approved. See “Regulatory Matters” for additional information.

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 September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Operations and maintenance	$	85.3	$	83.6	$	263.1	$	267.4

Operations and maintenance expenses increased $1.7 million for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, primarily due to increased loss accruals.

Operations and maintenance expenses decreased $4.3 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to decreased costs associated with restoring customer service.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Depreciation and amortization	$	38.0	$	39.2	$	116.4	$	122.6

Depreciation and amortization expenses decreased $1.2 million and $6.2 million for the three and nine months ended September 30, 2009, respectively, compared to the three and nine months ended September 30, 2008, primarily due to decreased amortization related to regulatory assets.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Taxes other than income taxes	$	39.4	$	35.0	$	113.1	$	105.5

Taxes other than income taxes increased $4.4 million and $7.6 million for the three and nine months ended September 30, 2009, respectively, compared to the three and nine months ended September 30, 2008, primarily due to increased gross receipts tax resulting from an increase in taxable regulated utility revenues, increased business and occupation tax and an estimated audit assessment.

64

DELIVERY AND SERVICES SEGMENT

Interest Expense

Interest expense was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Interest expense	$	25.9	$	24.8	$	78.6	$	70.7

Interest expense increased $1.1 million and $7.9 million for the three and nine months ended September 30, 2009, respectively, compared to the three and nine months ended September 30, 2008, primarily due to Monongahela’s December 2008 issuance of $300 million of first mortgage bonds and borrowings under the TrAIL credit facility. See Note 7, “Common Stock and Debt,” for additional information.

Income Tax Expense

The effective tax rate for the three months ended September 30, 2009 was 43.2%. Income tax expense for the three months ended September 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 5.6% and the rate making effects of depreciation, which increased the rate by 2.8%. These increases were partially offset by permanent differences, which decreased the rate by 1.2% and the ratemaking effects of investment tax credits, which decreased the rate by 0.8%.

The effective tax rate for the three months ended September 30, 2008 was 445.0% due to the small pretax loss of the segment for the quarter, which substantially increased the percentage effect of the dollar amounts of items affecting the effective rate. Income tax expense for the three months ended September 30, 2008 was higher than the income tax expense calculated at the federal statutory tax rate of 35%, primarily due to state income taxes, adjustments to reserves for uncertain tax positions and the Delivery and Services segment’s share of consolidated tax savings.

The effective tax rate for the nine months ended September 30, 2009 was 42.6%. Income tax expense for the nine months ended September 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 5.6%, the rate making effects of depreciation, which increased the rate by 2.6% and changes in tax reserves related to uncertain tax positions, which increased the rate by 0.9%. These increases were partially offset by the ratemaking effects of investment tax credits, which decreased the rate by 0.8%.

The effective tax rate for the nine months ended September 30, 2008 was 18.7%. Income tax expense for the nine months ended September 30, 2008 was lower than the income tax expense calculated at the federal statutory tax rate of 35%, primarily due to adjustments to reserves for uncertain tax positions that decreased the rate by 14.9%, and the Delivery and Services segment’s share of consolidated tax savings, which decreased the rate by 1.5%.

65

DELIVERY AND SERVICES SEGMENT

Transmission Expansion

The Delivery and Services segment includes TrAIL, Allegheny’s ownership interest in PATH and other transmission expansion projects. The combined results from these projects were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Operating revenues	$	24.8	$	8.0	$	57.0	$	26.5
Operating income	$	18.5	$	4.7	$	41.8	$	16.5
Income before income taxes	$	17.4	$	4.7	$	39.4	$	15.2

TrAIL Company and PATH, LLC are subject to the jurisdiction of FERC for the recovery of rates through PJM. FERC has approved the use of a formula rate methodology for recovery of all prudently incurred expenses and a return on debt and equity on all capital expenditures in connection with TrAIL and PATH based on a hypothetical capital structure, until the transmission facilities are placed into service. The actual capital structure will be reflected in the formula rate once the transmission facilities are placed into service. Revenues and operating income are expected to increase as the projects move forward from the planning and approval stages through development and construction.

TrAIL Company and PATH, LLC recognize revenue based on allowable costs incurred and return earned. See “Regulatory Matters” and Item 8, Note 4, “Transmission Expansion,” to the Consolidated Financial Statements in the 2008 Annual Report on Form 10-K for additional details and discussion regarding TrAIL Company and PATH, LLC.

66

GENERATION AND MARKETING SEGMENT

Key Indicators and Performance Factors

Allegheny reviews the financial and operating performance of its Generation and Marketing segment using a number of indicators and performance statistics, including kWhs generated, EAF and NCF, which are further described within the “Overview” section above as well as station operations and maintenance costs described below.

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

Generation Performance Factors

	Three Months Ended September 30,								Nine Months Ended September 30,
	2009			2008			Change		2009			2008			Change
Supercritical Units:
kWhs generated (in millions) (a)		5,791			10,115		(42.7	)%		22,231			29,303		(24.1	)%
EAF		88.9	%		90.2	%	(1.3	)%		81.4	%		86.1	%	(4.7	)%
NCF		44.1	%		77.1	%	(33.0	)%		56.4	%		74.0	%	(17.6	)%
Station O&M (in millions):
Base and operations	$	25.4		$	26.3		(3.4	)%	$	83.2		$	81.0		2.7	%
Special maintenance		4.3			8.4		(48.8	)%		58.3			43.6		33.7	%
Total Station O&M	$	29.7		$	34.7		(14.4	)%	$	141.5		$	124.6		13.6	%
All Generation Units:
Total kWhs generated (in millions) (a)		7,008			11,904		(41.1	)%		25,417			35,048		(27.5	)%
EAF		89.6	%		90.5	%	(0.9	)%		83.1	%		86.4	%	(3.3	)%
NCF		35.2	%		62.0	%	(26.8	)%		43.5	%		60.3	%	(16.8	)%
Station O&M (in millions):
Base and operations	$	39.4		$	40.2		(2.0	)%	$	125.9		$	123.8		1.7	%
Special maintenance		5.2			9.8		(46.9	)%		64.5			57.1		13.0	%
Total Station O&M	$	44.6		$	50.0		(10.8	)%	$	190.4		$	180.9		5.3	%

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

67

GENERATION AND MARKETING SEGMENT

The Generation and Marketing segment includes an unregulated component and a regulated component. The unregulated component primarily consists of AE Supply’s power generation and marketing operations, including the results of operations related to AGC on a fully consolidated basis. The regulated component consists of Monongahela’s regulated West Virginia generation operations and Monongahela’s interest in AGC under the equity method of accounting. Component information for the Generation and Marketing segment is summarized below.

	Three Months Ended September 30, 2009												Three Months Ended September 30, 2008
(In millions)	Unregulated			Regulated			Eliminations			Total			Unregulated			Regulated			Eliminations			Total
Operating revenues	$	358.3		$	98.4		$	(6.7	)	$	450.0		$	468.2		$	133.1		$	(12.0	)	$	589.3
Fuel		151.2			36.8			—			188.0			223.4			75.8			—			299.2
Purchased power and transmission		9.1			24.4			(6.7	)		26.8			7.9			29.8			(12.0	)		25.7
Deferred energy costs, net		—			(9.3	)		—			(9.3	)		—			(20.2	)		—			(20.2	)
Operations and maintenance		50.1			17.8			0.1			68.0			49.0			21.5			0.1			70.6
Depreciation and amortization		28.5			5.3			(0.5	)		33.3			23.7			5.0			(0.5	)		28.2
Taxes other than income taxes		12.4			5.6			—			18.0			12.8			6.6			—			19.4
Total operating expenses		251.3			80.6			(7.1	)		324.8			316.8			118.5			(12.4	)		422.9
Operating income		107.0			17.8			0.4			125.2			151.4			14.6			0.4			166.4
Other income (expense), net		0.2			3.0			(2.7	)		0.5			1.2			3.4			(3.0	)		1.6
Interest expense		46.6			12.6			—			59.2			23.8			9.6			(0.1	)		33.3
Income before income taxes		60.6			8.2			(2.3	)		66.5			128.8			8.4			(2.5	)		134.7
Income tax expense		20.4			0.7			(0.1	)		21.0			47.6			2.5			(0.1	)		50.0
Net income		40.2			7.5			(2.2	)		45.5			81.2			5.9			(2.4	)		84.7
Less net income attributable to noncontrolling interest		(2.2	)		—			2.2			—			(2.4	)		—			2.4			—
Net income attributable to Allegheny Energy, Inc.	$	38.0		$	7.5		$	—		$	45.5		$	78.8		$	5.9		$	—		$	84.7
	Nine Months Ended September 30, 2009												Nine Months Ended September 30, 2008
(In millions)	Unregulated			Regulated			Eliminations			Total			Unregulated			Regulated			Eliminations			Total
Operating revenues	$	1,188.0		$	365.3		$	(21.8	)	$	1,531.5		$	1,460.3		$	416.1		$	(34.4	)	$	1,842.0
Fuel		490.2			173.6			—			663.8			578.3			215.9			—			794.2
Purchased power and transmission		27.2			81.4			(21.8	)		86.8			22.3			89.8			(34.4	)		77.7
Deferred energy costs, net		—			(33.0	)		—			(33.0	)		—			(35.9	)		—			(35.9	)
Operations and maintenance		201.2			60.0			0.4			261.6			168.6			80.6			0.4			249.6
Depreciation and amortization		76.3			15.7			(1.4	)		90.6			70.8			14.6			(1.5	)		83.9
Taxes other than income taxes		33.7			12.9			—			46.6			35.1			19.1			—			54.2
Total operating expenses		828.6			310.6			(22.8	)		1,116.4			875.1			384.1			(35.5	)		1,223.7
Operating income		359.4			54.7			1.0			415.1			585.2			32.0			1.1			618.3
Other income (expense), net		1.2			9.1			(8.2	)		2.1			6.3			10.2			(8.9	)		7.6
Interest expense		84.5			38.4			—			122.9			78.0			28.9			(0.2	)		106.7
Income before income taxes		276.1			25.4			(7.2	)		294.3			513.5			13.3			(7.6	)		519.2
Income tax expense		109.9			6.6			(0.4	)		116.1			179.7			3.2			(0.4	)		182.5
Net income		166.2			18.8			(6.8	)		178.2			333.8			10.1			(7.2	)		336.7
Less net income attributable to noncontrolling interest		(6.8	)		—			6.8			—			(7.2	)		—			7.2			—
Net income attributable to Allegheny Energy, Inc.	$	159.4		$	18.8		$	—		$	178.2		$	326.6		$	10.1		$	—		$	336.7

68

GENERATION AND MARKETING SEGMENT

This section is an overview of the Generation and Marketing segment’s results of operations, which are discussed in greater detail by component under the headings “Generation and Marketing Segment—Unregulated” and “Generation and Marketing Segment—Regulated” below.

The following tables reconcile “Income before income taxes” for the three and nine months ended September 30, 2008 to the three and nine months ended September 30, 2009.

(In millions)
Income before income taxes for the three months ended September 30, 2008			$	134.7
Decrease in operating revenues				(139.3	)
Decreases (increases) in operating expenses:
Fuel	111.2
Deferred energy costs, net	(10.9	)
Other operating expenses	(2.2	)
Decrease in operating expenses				98.1
Decrease in other income (expense), net				(1.1	)
Increase in interest expense				(25.9	)
Income before income taxes for the three months ended September 30, 2009			$	66.5

(In millions)
Income before income taxes for the nine months ended September 30, 2008			$	519.2
Decrease in operating revenues				(310.5	)
Decreases (increases) in operating expenses:
Fuel	130.4
Purchased power and transmission	(9.1	)
Operations and maintenance	(12.0	)
Other operating expenses	(2.0	)
Decrease in operating expenses				107.3
Decrease in other income (expense), net				(5.5	)
Increase in interest expense				(16.2	)
Income before income taxes for the nine months ended September 30, 2009			$	294.3

Operating Revenues

Operating revenues decreased $139.3 million for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, primarily due to:

• a $176.6 million decrease due primarily to a 41.1% reduction in total MWhs generated resulting from decreased demand, lower commodity prices and, to a lesser degree, planned outages to complete the installation of Scrubbers at the Hatfield’s Ferry generation facility,

• increased unrealized losses of $86.4 million on economic power hedges that did not qualify for hedge accounting and

• increased unrealized losses of $28.3 million related to pipeline capacity economic hedges that did not qualify for hedge accounting.

These operating revenue decreases were partially offset by:

• decreased unrealized losses of $100.4 million relating to FTRs and

69

GENERATION AND MARKETING SEGMENT

• a $57.8 million net increase in revenues due to rate increases under power sales contracts, including higher generation rates charged to Pennsylvania customers and market-based generation pricing for Maryland residential customers (see “Regulatory Matters” for additional information), partially offset by reduced revenues due to lower customer demand in Pennsylvania.

Operating revenues decreased $310.5 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to:

• a $359.1 million decrease due primarily to a 27.5% reduction in total MWhs generated resulting from decreased demand, lower commodity prices and, to a lesser degree, planned outages to complete the installation of Scrubbers at the Hatfield’s Ferry generation facility,

• decreased unrealized gains of $73.1 million relating to FTRs and

• increased unrealized losses of $31.8 million on economic power hedges that did not qualify for hedge accounting.

These operating revenue decreases were partially offset by a $151.3 million net increase in revenues due to rate increases under power sales contracts, including higher generation rates charged to Pennsylvania customers and market-based generation pricing for Maryland residential customers (see “Regulatory Matters” for additional information), partially offset by reduced revenues due to lower customer demand in Pennsylvania.

Operating Expenses

Fuel expense decreased $111.2 million for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, primarily due to an $89.0 million decrease in coal expense. The decrease in coal expense was the result of a 45.2% decrease in tons of coal consumed at Allegheny’s coal-fired generation facilities, partially offset by a 15.1% increase in the average cost of coal per ton.

Fuel expense decreased $130.4 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to a $104.9 million decrease in coal expense. The decrease in coal expense was the result of a 28.8% decrease in tons of coal consumed at Allegheny’s coal-fired generation facilities, partially offset by an 18.3% increase in the average cost of coal per ton.

Purchased power and transmission increased $9.1 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to:

• �� a $7.2 million increase in natural gas purchases related to the hedge strategy associated with a transportation agreement between AE Supply and Kern River Gas Transmission Company and

• a $4.2 million increase in power purchased from PURPA facilities as a result of increased PURPA generation.

Deferred energy costs, net increased $10.9 million for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, primarily due to a decrease in the under-recovery of fuel and purchased power costs in West Virginia, which are permitted to be recovered in rates under the ENEC.

Operations and maintenance expense increased $12.0 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to a $6.4 million increase in costs resulting from the timing of plant outages and increased compensation and benefits expense.

70

GENERATION AND MARKETING SEGMENT

Interest Expense

Interest expense increased $25.9 million and $16.2 million for the three and nine months ended September 30, 2009, respectively, compared to the three and nine months ended September 30, 2008, primarily due to costs associated with AE Supply’s September 2009 purchase of a portion of its outstanding medium-term notes, AE Supply’s July 2009 tax exempt bond financing and Monongahela’s December 2008 issuance of $300 million of first mortgage bonds, partially offset by lower average debt outstanding at lower interest rates under AE Supply’s credit facility and increased capitalized interest on capital projects. See Note 7, “Common Stock and Debt,” for additional information.

Income Tax Expense

The effective tax rate for the three months ended September 30, 2009 was 31.6%. Income tax expense for the three months ended September 30, 2009 was lower than the income tax expense calculated at the federal statutory tax rate of 35%, primarily due to state income taxes, which decreased the rate by 0.2%, adjustments to reserves for uncertain tax positions and audit settlements, which decreased the rate by 1.4% and permanent differences including ratemaking effects of investment tax credits, which decreased the rate by 1.9%.

The effective tax rate for the three months ended September 30, 2008 was 37.1%. Income tax expense for the three months ended September 30, 2008 was higher than the income tax expense calculated at the federal statutory tax rate of 35%, primarily due to state income taxes that increased the rate by 2.9%, partially offset by the rate-making effects of depreciation differences, which decreased the rate by 0.4%.

The effective tax rate for the nine months ended September 30, 2009 was 39.5%. Income tax expense for the nine months ended September 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 rate by 2.2% and an adjustment to the Pennsylvania net operating loss carryforward deferred tax asset, which increased the rate by 3.2%. These increases were partially offset by the ratemaking effects of investment tax credits, which decreased the rate by 0.4%.

The effective tax rate for the nine months ended September 30, 2008 was 35.1%. Income tax expense for the nine months ended September 30, 2008 was higher than the income tax expense calculated at federal statutory tax rate of 35%, primarily due to state income taxes, which increased the rate by 2.5%, partially offset by an adjustment to deferred taxes related to the West Virginia corporate net income tax rate change, which decreased the rate by 1.5% and permanent benefits, which decreased the rate by 0.6%.

71

GENERATION AND MARKETING SEGMENT—UNREGULATED

Generation and Marketing Segment—Unregulated

The following table provides electricity generation information for Allegheny’s unregulated plants, excluding kWhs consumed by pumping at the Bath County, Virginia hydroelectric station:

	Three Months Ended September 30,		Change		Nine Months Ended September 30,		Change
	2009	2008			2009	2008
kWhs generated (in millions)	5,646	8,834	(36.1	)%	19,111	25,683	(25.6	)%

Operating Revenues

Operating revenues were as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
(In millions)	2009		2008			2009		2008
Revenue from affiliates	$	292.3	$	312.6		$	926.0	$	930.7
PJM revenue, net		23.4		184.2			114.1		442.4
Other operating revenues, including risk management and trading activities, net		42.6		(28.6	)		147.9		87.2
Unregulated revenue	$	358.3	$	468.2		$	1,188.0	$	1,460.3

Revenue from affiliates

AE Supply provides Potomac Edison and West Penn with a portion of the power necessary to meet their obligations under power sales agreements that have both fixed-price and market-based pricing components.

Revenue from affiliates decreased $20.3 million and $4.7 million for the three and nine months ended September 30, 2009, respectively, compared to the three and nine months ended September 30, 2008, primarily due to decreased sales volumes and the expiration of an intercompany market rate adjustment, partially offset by rate increases under certain of AE Supply’s affiliate power sales contracts.

PJM revenue, net:PJM revenue, net was as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2009			2008			2009			2008
Generation sold into PJM	$	291.7		$	614.1		$	962.5		$	1,653.4
Power purchased from PJM		(268.3	)		(429.9	)		(848.4	)		(1,211.0	)
PJM revenue, net	$	23.4		$	184.2		$	114.1		$	442.4

PJM revenue, net decreased $160.8 million and $328.3 million for the three and nine months ended September 30, 2009, respectively, compared to the three and nine months ended September 30, 2008, primarily due to lower revenues from generation sold into PJM, partially offset by a decrease in power purchased from PJM. Revenues from generation sold into PJM were lower, primarily due to a decrease in MWhs generated and a decrease in the market price of power. MWhs generated decreased as a result of lower plant availability and decreases in demand. Power purchased from PJM decreased due to a decrease in the market price of power and decreased customer demand.

72

GENERATION AND MARKETING SEGMENT—UNREGULATED

Other Operating Revenues:

Other operating revenues increased $71.2 million for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, primarily due to decreased unrealized losses relating to FTRs and realized gains on power hedges, partially offset by unrealized losses related to power sale hedges and pipeline capacity economic hedges that did not qualify for hedge accounting.

Other operating revenues increased $60.7 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to realized gains on power hedges, partially offset by decreased unrealized gains relating to FTRs and unrealized losses related to power sale hedges that did not qualify for hedge accounting.

Operating Expenses

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Unregulated fuel	$	151.2	$	223.4	$	490.2	$	578.3

Fuel expense decreased $72.2 million for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, primarily due to:

• a $56.6 million decrease in coal expense, primarily due to a 39.8% decrease in tons of coal consumed at Allegheny’s unregulated coal-fired generation facilities, partially offset by a 12.7% increase in the average cost of coal per ton and

• a $3.3 million decrease in natural gas expense, primarily due to a 65.8% decrease in the average price of natural gas per decatherm, partially offset by a 116.8% increase in decatherms of natural gas consumed at Allegheny’s natural gas-fired generation facilities.

Fuel expense decreased $88.1 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to a $70.2 million decrease in coal expense, resulting from a 27.0% decrease in tons of coal consumed resulting from decreased MWhs generated at Allegheny’s coal-fired generation facilities, partially offset by a 16.7% increase in the average cost of coal per ton.

Purchased Power and Transmission: Purchased power and transmission expenses were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Unregulated purchased power and transmission	$	9.1	$	7.9	$	27.2	$	22.3

Purchased power and transmission increased $1.2 million and $4.9 million for the three and nine months ended September 30, 2009, respectively, compared to the three and nine months ended September 30, 2008, primarily due to the hedge strategy associated with a transportation agreement between AE Supply and Kern River Gas Transmission Company.

73

GENERATION AND MARKETING SEGMENT—UNREGULATED

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 September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Unregulated operations and maintenance	$	50.1	$	49.0	$	201.2	$	168.6

Operations and maintenance expenses increased $1.1 million for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, primarily due to increased compensation and benefits expense.

Operations and maintenance expenses increased $32.6 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to a $24.1 million increase in costs resulting from the timing of plant outages and increased compensation and benefits expense.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Unregulated depreciation and amortization	$	28.5	$	23.7	$	76.3	$	70.8

Depreciation and amortization expenses increased $4.8 million and $5.5 million for the three and nine months ended September 30, 2009, respectively, compared to the three and nine months ended September 30, 2008, primarily due to Scrubber equipment at the Hatfield’s Ferry generating facility that was placed into service during June 2009.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Unregulated taxes other than income taxes	$	12.4	$	12.8	$	33.7	$	35.1

Taxes other than income taxes decreased $1.4 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to favorable tax settlements.

Other Income (Expense), net

Other income (expense), net was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Unregulated other income (expense), net	$	0.2	$	1.2	$	1.2	$	6.3

Other income (expense), net decreased $1.0 million for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, primarily due to lower interest income resulting from decreased average investments at lower rates.

74

GENERATION AND MARKETING SEGMENT—UNREGULATED

Other income (expense), net decreased $5.1 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to lower interest income resulting from decreased average investments at lower rates and cash received from a former trading executive during 2008.

Interest Expense

Interest expense was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Unregulated interest expense	$	46.6	$	23.8	$	84.5	$	78.0

Interest expense increased $22.8 million and $6.5 million for the three and nine months ended September 30, 2009, respectively, compared to the three and nine months ended September 30, 2008, primarily due to costs associated with AE Supply’s September 2009 purchase of a portion of its outstanding medium-term notes and AE Supply’s July 2009 tax exempt bond financing, partially offset by lower average debt outstanding at lower interest rates under AE Supply’s credit facility and increased capitalized interest on capital projects.

75

GENERATION AND MARKETING SEGMENT—REGULATED

Generation and Marketing Segment—Regulated

The following table provides electricity generation information for Allegheny’s regulated plants, excluding kWhs consumed by pumping at the Bath County, Virginia hydroelectric station:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009	2008	Change		2009	2008	Change
kWhs generated (in millions)	1,363	3,071	(55.6	)%	6,306	9,366	(32.7	)%

Operating Revenues

Operating revenues were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2009			2008			2009			2008
Revenue from affiliates	$	152.1		$	129.9		$	473.5		$	401.1
PJM revenue, net		(59.6	)		(3.0	)		(126.0	)		(5.4	)
Fort Martin scrubber surcharge		5.9			6.1			17.8			18.1
Other operating revenues		—			0.1			—			2.3
Regulated revenue	$	98.4		$	133.1		$	365.3		$	416.1

Revenue from affiliates

Monongahela sells the power that it generates from its West Virginia jurisdictional assets into the PJM market and purchases from the PJM market the power necessary to meet its West Virginia jurisdictional customer load and its contractual obligations, which include supplying power to serve Potomac Edison’s West Virginia load. The net revenue from these PJM purchases and sales is reflected in PJM revenue, net.

Potomac Edison purchases the power necessary to serve its West Virginia customers from Monongahela’s Generation and Marketing segment at a prorated share of overall Monongahela generation costs and associated revenue.

Revenues from affiliates increased $22.2 million and $72.4 million for the three and nine months ended September 30, 2009, respectively, compared to the three and nine months ended September 30, 2008, primarily due to an ENEC-related rate increase in West Virginia that went into effect on January 1, 2009, partially offset by decreased sales volumes. See “Regulatory Matters” for additional information.

PJM revenue, net:PJM revenue, net was as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2009			2008			2009			2008
Generation sold into PJM	$	96.6		$	229.7		$	368.2		$	654.9
Power purchased from PJM		(156.2	)		(232.7	)		(494.2	)		(660.3	)
PJM revenue, net	$	(59.6	)	$	(3.0	)	$	(126.0	)	$	(5.4	)

PJM revenue, net decreased $56.6 million and $120.6 million for the three and nine months ended September 30, 2009, respectively, compared to the three and nine months ended September 30, 2008, primarily due to lower revenues from generation sold into PJM, partially offset by a decrease in power purchased from PJM. Revenues from generation sold into PJM were lower primarily due to a decrease in MWhs generated and a decrease in the market price of power. MWhs generated decreased as a result of decreased demand. Power purchased from PJM decreased due to a decrease in the market price of power and decreased customer demand.

76

GENERATION AND MARKETING SEGMENT—REGULATED

Other Operating Revenues:

Other operating revenues decreased $2.3 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to 2008 emission allowance strategies.

Operating Expenses

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

Fuel expense was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Regulated fuel	$	36.8	$	75.8	$	173.6	$	215.9

Fuel expense decreased $39.0 million for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, primarily due to a $32.4 million decrease in coal expense. Coal expense decreased as a result of a 60.4% decrease in tons of coal consumed resulting from decreased MWhs generated at Allegheny’s regulated coal-fired generation facilities, partially offset by a 25.3% increase in the average cost of coal per ton.

Fuel expense decreased $42.3 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to a $34.6 million decrease in coal expense. Coal expense decreased as a result of a 33.4% decrease in tons of coal consumed resulting from decreased MWhs generated at Allegheny’s regulated coal-fired generation facilities, partially offset by a 23.1% increase in the average cost of coal per ton.

Purchased Power and Transmission:Purchased power and transmission expenses were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Regulated purchased power and transmission	$	24.4	$	29.8	$	81.4	$	89.8

Purchased power and transmission decreased $5.4 million for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, primarily due to decreased purchased power from OVEC as a result of Monongahela’s February 2009 assignment to AE Supply of the right to receive a portion of the output from OVEC.

Purchased power and transmission decreased $8.4 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to a $12.1 million decrease in purchased power from OVEC as a result of Monongahela’s February 2009 assignment to AE Supply of the right to receive a portion of the output from OVEC, partially offset by a $4.2 million increase in purchased power from PURPA facilities as a result of increased West Virginia PURPA generation.

77

GENERATION AND MARKETING SEGMENT—REGULATED

Deferred Energy Costs, Net:Deferred energy costs, net represent the deferral of certain energy costs incurred to the period in which such costs are recovered in rates. Deferred energy costs, net were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2009			2008			2009			2008
Regulated deferred energy costs, net	$	(9.3	)	$	(20.2	)	$	(33.0	)	$	(35.9	)

The $10.9 million and $2.9 million changes in deferred energy costs, net for the three and nine months ended September 30, 2009, respectively, compared to the three and nine months ended September 30, 2008 represent the change in the deferral of certain costs due to the under-recovery of fuel and purchased power costs in West Virginia, which are permitted to be recovered in rates under the ENEC. See “Regulatory Matters” for additional information.

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 September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Regulated operations and maintenance	$	17.8	$	21.5	$	60.0	$	80.6

Operations and maintenance expenses decreased $3.7 million for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, primarily due to decreased costs resulting from the timing of plant outages.

Operations and maintenance expenses decreased $20.6 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily due to a $17.7 million decrease in costs resulting from the timing of plant outages and decreased compensation and benefits expense.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Regulated taxes other than income taxes	$	5.6	$	6.6	$	12.9	$	19.1

Taxes other than income taxes decreased $1.0 million and $6.2 million for the three and nine months ended September 30, 2009, respectively, compared to the three and nine months ended September 30, 2008, primarily due to favorable tax settlements and tax credits related to the Fort Martin Scrubbers.

Interest Expense

Interest expense was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2009		2008		2009		2008
Regulated interest expense	$	12.6	$	9.6	$	38.4	$	28.9

Interest expense increased $3.0 million and $9.5 million for the three and nine months ended September 30, 2009, respectively, compared to the three and nine months ended September 30, 2008, primarily due to Monongahela’s December 2008 issuance of $300 million of first mortgage bonds.

78

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.

Allegheny manages short-term funding needs with cash on hand and amounts available under revolving credit facilities. AE manages excess cash through Allegheny’s internal money pool. The money pool provides funds to approved AE subsidiaries at the lower of the Federal Reserve’s federal funds effective interest rate for the previous day, or the Federal Reserve’s seven day commercial paper rate for the previous day, less four basis points. AE and AE Supply can only place money into the money pool. Monongahela, West Penn and Potomac Edison can either place money into, or borrow money from, the money pool. AGC can only borrow money from the money pool.

At September 30, 2009 and December 31, 2008, Allegheny had cash and cash equivalents of $278.3 million and $362.1 million, respectively, and current restricted funds of $39.1 million and $36.8 million, respectively. These restricted funds include both funds collected from West Virginia customers to service the environmental control bonds as well as intangible transition charges collected from West Penn customers.

In addition, AE and AE Supply each have in place revolving credit facilities that mature in 2011 and 2012, respectively. At September 30, 2009, borrowing capacity under AE’s and AE Supply’s revolving credit facilities was as follows:

(In millions)	Total Capacity		Borrowed		Letters of Credit Issued		Available Capacity
AE Revolving Credit Facility	$	376.0	$	120.0	$	3.3	$	252.7
AE Supply Revolving Facility		1,000.0		—		—		1,000.0
Total	$	1,376.0	$	120.0	$	3.3	$	1,252.7

Allegheny posts collateral with counterparties, including PJM, for certain transactions and transmission and transportation tariffs. Approximately $24.7 million and $33.4 million of cash collateral deposits were included in current assets at September 30, 2009 and December 31, 2008, respectively. Approximately $2.8 million and $0.2 million of cash collateral deposits were netted against derivative liabilities on the Consolidated Balance Sheet at September 30, 2009 and December 31, 2008, 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 9, “Fair Value Measurements, Derivative Instruments and Hedging Activities” to the Consolidated Financial Statements for additional information regarding potential additional collateral that would have been required for derivative contracts in a net liability position at September 30, 2009. At September 30, 2009, if credit ratings for AE, AE Supply and the Distribution Companies had been below Standard & Poor’s BB- or Moody’s Ba3, Allegheny would have been required to post an additional $119 million of collateral to counterparties, including PJM, for both derivative and non-derivative contracts.

Allegheny’s consolidated capital structure, excluding short-term debt and noncontrolling interest, as of September 30, 2009 and December 31, 2008, was as follows:

	September 30, 2009			December 31, 2008
(In millions)	Amount		%	Amount		%
Long-term debt	$	4,488.1	59.6	$	4,209.8	59.6
Allegheny Energy, Inc. common stockholders’ equity		3,048.4	40.4		2,850.8	40.4
Total	$	7,536.5	100.0	$	7,060.6	100.0

79

2009 Debt Activity

Borrowings and principal repayments on debt during the nine months ended September 30, 2009 were as follows:

(In millions)	Issuances		Repayments
AE:
AE Revolving Credit Facility	$	120.0	$	—
AE Supply:
AE Supply Credit Facility—Revolving Loan		120.0		120.0
Exempt Facilities Revenue Bonds		235.0
Medium-Term Notes		—		244.3
TrAIL Company:
TrAIL Company Credit Facility—Term Loan		240.0		—
West Penn:
Transition Bonds		—		59.9
Monongahela:
Environmental Control Bonds		—		10.6
Potomac Edison:
Environmental Control Bonds		—		3.5
Consolidated Total	$	715.0	$	438.3

See Note 7, “Common Stock and Debt,” to the Consolidated Financial Statements for additional information and details regarding Allegheny’s debt. See also Item 8, Note 7, “Capitalization and Short-Term Debt,” to the Consolidated Financial Statements in the 2008 Annual Report on Form 10-K for additional information.

On July 6, 2009, the Pennsylvania Economic Development Financing Authority issued $235 million of 7.0% tax-exempt bonds that mature in 2039 and loaned the proceeds therefrom to AE Supply to finance a portion of the cost of constructing and installing Scrubbers at AE Supply’s Hatfield’s Ferry generation facility. AE Supply capitalized $2.4 million in debt costs associated with this transaction.

On September 4, 2009, AE Supply repurchased $97.5 million and $146.8 million, respectively, of its 7.80% Notes due 2011 and its 8.25% Notes due 2012 pursuant to a cash tender offer, at an aggregate premium of $18.1 million. AE Supply expensed the $18.1 million premium, $0.6 million in unamortized debt costs, and $0.6 million in fees associated with the tender offer during the three months ended September 30, 2009.

On September 24, 2009, AE Supply obtained a new $1 billion senior unsecured revolving credit facility with a three-year maturity. The new revolving credit facility replaces AE Supply’s previous $400 million revolving credit facility, which was scheduled to mature in May 2011. Loans under the new facility generally will bear interest that is calculated based on the London Interbank Offered Rate, plus a margin based on AE Supply’s senior unsecured credit rating. AE Supply capitalized $22.1 million in debt costs related to this facility.

On October 1, 2009, AE Supply issued $600 million aggregate principal amount of senior unsecured notes, consisting of $350 million of 5.75% Notes due 2019 and $250 million of 6.75% Notes due 2039. AE Supply used a portion of the net proceeds from the sale of these notes to repay in full its existing $447 million term loan on October 2, 2009. AE Supply capitalized $5.3 million in debt issuance costs associated with this new debt issuance and expensed $0.6 million of unamortized debt costs associated with the extinguished term loan.

On October 21, 2009, AE Supply used the remaining proceeds of its senior secured note offering to repurchase approximately $152 million aggregate principal amount of its 7.80% Medium Term Notes due 2011

pursuant to a cash tender offer at an aggregate premium of $12.7 million. AE Supply plans to expense the $12.7 million premium, $0.3 million in unamortized debt costs, and $0.4 million in fees related to this tender offer during the three months ending December 31, 2009.

80

Dividends

On September 28, 2009, June 22, 2009 and March 23, 2009, AE paid cash dividends on its common stock of $0.15 per share to shareholders of record at the close of business on September 14, 2009, June 8, 2009 and March 9, 2009, respectively. On October 15, 2009, AE’s Board of Directors authorized a cash dividend on its common stock of $0.15 per share payable on December 28, 2009 to shareholders of record on December 14, 2009.

Capital Expenditures

Capital projects are subject to continuing review and revision in light of legislative and regulatory developments, changing environmental standards, economic conditions and other factors. Allegheny currently estimates that its total cash-basis capital expenditures will approximate $355 million, $1,095 million and $1,475 million for the remainder of 2009, 2010, and 2011, respectively. These amounts include expenditures for PATH attributable to AEP as well as capital expenditures associated with Act 129 compliance, which is discussed within “State Rate Regulation.”

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.

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 include additional discretionary contributions to increase the funded level of the plan. During the three and nine months ended September 30, 2009, Allegheny contributed $37.5 million to its qualified pension plan and $0.1 million and $0.4 million, respectively, to its SERP. Allegheny made approximately $3.3 million and $7.2 million in contributions to its postretirement benefits other than pension plans during the three and nine months ended September 30, 2009. Allegheny does not anticipate making any additional contributions to its qualified pension plan during the remainder of 2009. Allegheny currently anticipates that it will contribute an additional $3.0 million to $4.0 million during the remainder of 2009 to fund postretirement benefits other than pensions.

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:

	Nine Months Ended September 30,
(In millions)	2009			2008
Net income	$	284.3		$	379.9
Non-cash items included in income		369.2			298.8
Pension and other postretirement employee benefit plan contributions		(45.1	)		(45.4	)
Changes in certain assets and liabilities		(124.7	)		(44.2	)
Net cash provided by operating activities	$	483.7		$	589.1

81

The non-cash items included in income for the nine months ended September 30, 2009 primarily consisted of depreciation and amortization of $207.0 million and deferred income taxes of $188.5 million. Changes in certain assets and liabilities primarily consisted of an increase in materials, supplies and fuel inventories of $85.2 million, primarily as a result of increased fuel inventory levels and higher prices, changes in accrued taxes and prepaid taxes of $67.9 million, primarily as a result of timing differences associated with the payments of certain tax obligations, and $44.3 million in changes in receivables and payables resulting from normal working capital activity. These amounts were partially offset by a reduction to regulatory assets of $47.5 million, mostly as a result of the recovery of West Penn’s previously earned revenues, and a reduction in collateral deposits of $32.7 million, primarily due to reduced collateral requirements with various counterparties to Allegheny’s power contracts.

Cash flows provided by operating activities for the nine months ended September 30, 2008 primarily consisted of depreciation and amortization of $206.5 million and deferred income taxes of $177.0 million, partially offset by unrealized gains on derivatives, net of $136.9 million. Changes in certain assets and liabilities primarily consisted of $90.4 million in changes in receivables and payables resulting from normal working capital activity and an increase in materials, supplies and fuel of $43.3 million, primarily as a result of increased fuel inventory levels and higher prices. These amounts were partially offset by an increase in regulatory liabilities of $41.1 million relating to Allegheny receiving payments from its customers in advance of providing service, a reduction in collateral deposits of $31.2 million, primarily due to reduced collateral requirements with various counterparties to Allegheny’s power contracts and a reduction in regulatory assets of $26.3 million resulting from the recovery of previously earned revenue related to West Penn restructuring.

Investing Activities

Cash flows from investing activities are summarized as follows:

	Nine Months Ended September 30,
(In millions)	2009			2008
Capital expenditures	$	(870.1	)	$	(714.3	)
Proceeds from asset sales		0.2			0.4
Purchase of Merrill Lynch interest in subsidiary		—			(50.0	)
Decrease in restricted funds		131.0			177.6
Other investments		(3.8	)		(4.1	)
Net cash used in investing activities	$	(742.7	)	$	(590.4	)

Cash flows used in investing activities for the nine months ended September 30, 2009 were $742.7 million and primarily consisted of $870.1 million of capital expenditures, partially offset by a $131.0 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 associated with that ongoing project.

Cash flows used in investing activities for the nine months ended September 30, 2008 were $590.4 million and primarily consisted of $714.3 million of capital expenditures and $50.0 million relating to the acquisition of Merrill Lynch’s non-controlling interest in AE Supply, partially offset by a $177.6 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 associated with that ongoing project.

82

Financing Activities

Cash flows from financing activities are summarized as follows:

	Nine Months Ended September 30,
(In millions)	2009			2008
Repayment of note payable	$	—		$	(10.0	)
Issuance of long-term debt		709.2			305.6
Repayment of long-term debt		(438.3	)		(384.6	)
Costs associated with a new AE Supply revolving credit facility		(21.6	)		—
Equity contribution to PATH, LLC by a joint venture partner		6.9			4.5
Payments on capital lease obligations		(6.4	)		(6.8	)
Proceeds from exercise of employee stock options		1.6			21.5
Cash dividends paid on common stock		(76.2	)		(75.7	)
Net cash provided by (used in) financing activities	$	175.2		$	(145.5	)

Cash flows provided by financing activities for the nine months ended September 30, 2009 were $175.2 million and primarily consisted of $709.2 million from borrowings primarily under TrAIL Company’s term loan and AE Supply’s credit facility, partially offset by $438.3 million in various debt repayments, and $76.2 million of cash dividends paid on common stock.

Cash flows used in financing activities for the nine months ended September 30, 2008 were $145.5 million and included $384.6 million in various debt repayments, including a $285 million debt repayment under AE Supply’s Term credit facility, and $75.7 million of cash dividends paid on common stock, partially offset by $305.6 million primarily related to borrowings under AE Supply’s credit facility.

83

CREDIT RATINGS

The following table lists Allegheny’s credit ratings, as of November 6, 2009:

	Moody’s	S & P	Fitch
AE:
Outlook	Stable	Stable	Stable
Corporate Credit Rating	Not Rated	BBB-	BBB-(a)
Senior Unsecured Debt	Ba1	BB+	BBB-
AE Supply:
Senior Secured Debt	Baa2	BBB	BBB
Senior Unsecured Debt	Baa3	BBB-	BBB-
Monongahela:
First Mortgage Bonds	Baa1	BBB+	BBB+
Senior Unsecured Debt	Baa3	BBB-	BBB-
Environmental Control Bonds	Aaa	AAA	AAA
Potomac Edison:
First Mortgage Bonds	Baa1	BBB+	BBB+
Environmental Control Bonds	Aaa	AAA	AAA
West Penn:
Transition Bonds	Aaa	AAA	AAA
First Mortgage Bonds	Baa2	BBB+	BBB+
Senior Unsecured Debt	Baa3	BBB-	BBB-
AGC:
Senior Unsecured Debt	Baa3	BBB-	BBB-

(a) Issuer Default Rating

84

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 2008 Annual Report on Form 10-K. Allegheny’s critical accounting policies have not changed materially from those reported in the 2008 Annual Report on Form 10-K.

Recent Accounting Pronouncements

See Note 2, “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 MATTERS

The interstate transmission services and wholesale power sales of the Distribution Companies, AE Supply and AGC are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Federal Power Act (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 “Risk Factors.”

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 transmission facilities are subject to FERC jurisdiction and must file their rates, terms and conditions for such sales 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 transmission information. To further competition, FERC encourages transmission-owning utilities to participate in regional transmission organizations (“RTOs”) such as PJM, by transferring functional control over their transmission facilities to RTOs.

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

85

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 regional transmission expansion plan 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 “Risk Factors.”

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 (“MISO”) 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. Subsequently, transition charge proposals were submitted by transmission owners and accepted by FERC subject to an evidentiary hearing to determine if the amount of the charges was just and reasonable. Rehearing of the November 2004 order is pending before FERC and will be subject to possible judicial review. 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. The initial decision is now before FERC for review and may be accepted, rejected or modified by FERC. Based on its review of the initial decision, FERC may require the Distribution Companies to refund some portion of the amounts received from these transition charges or entitle the Distribution Companies to receive additional revenue from these charges. In addition, the Distribution Companies may be required to pay additional amounts as a result of increases in the transition charges previously billed to them, or they may receive refunds of transition charges previously billed. Allegheny cannot predict the outcome of this proceeding or whether it will have a material impact on its business or financial position.

The Distribution Companies have entered into nine partial settlements with regard to the transition charges. FERC has approved eight of these settlements. FERC action is pending for the remaining partial settlement.

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.

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

86

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 MISO transmission owners establishing the transmission pricing methodology for transactions involving transmission service originating in the PJM region or the MISO region and terminating in the other region. The methodology maintains the existing rate design for such transactions under which PJM and MISO 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.

In January 2009, PJM and MISO filed a proposal for the allocation of costs and new “cross-border” transmission facilities required for market efficiency or economic purposes within the PJM and MISO regions. The proposed cost allocation among the RTOs for such facilities is based upon a determination of the relative benefit to each RTO of the new facilities. On November 3, 2009, FERC approved the proposal.

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, in January and May of 2008 and May of 2009. 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. Requests for rehearing of the September 19, 2008 order were denied by FERC on June 18, 2009. The Maryland Public Service Commission and New Jersey Board of Public Utilities have appealed FERC’s order denying the RPM Buyer’s complaint to the United States Court of Appeals for the Fourth Circuit. The appeal remains pending in the Court of Appeals.

PJM Calculation Error.In September 2009, PJM reported that it had discovered a modeling error in the market-to-market power flow calculations between PJM and the Midwest ISO. The error, which dates back to April, 2005, was a result of the incorrect modeling of certain generation resources that have an impact on power

87

flows across the PJM/Midwest ISO border. PJM’s preliminary estimate of the market-wide magnitude of the error is approximately $77 million, dating back to 2005. FERC settlement discussions on this issue have commenced, and Allegheny is participating in these discussions. The amount and timing of any payment by PJM to the Midwest ISO relating to this modeling error is uncertain at this time, as is the method by which PJM would allocate any such payment to PJM participants, including Allegheny.

Transmission Expansion

PATH Project.In April 2009, PJM completed further studies relating to the PATH project and established the in-service date for PATH as June 1, 2014. Total project costs are expected to be approximately $1.8 billion, of which Allegheny’s share is expected to be approximately $1.2 billion.

On December 28, 2007, PATH, LLC submitted a filing to FERC under Section 205 of the FPA to implement a formula rate tariff to be effective March 1, 2008. The filing also included a request for certain incentive rate treatments. On February 29, 2008, FERC issued an order granting certain rate incentives and setting the cost of service formula rate that will be used to calculate annual revenue requirements for the project. In December 2008, PATH 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.

On June 1 of each year, PATH posts on PJM’s website its annual true-up for the annual transmission revenue requirements for the prior rate year. On September 1 of each year, PATH posts on PJM’s website its annual update to establish its annual transmission revenue requirements for the following rate year, to become effective January 1 of the following year.

National Interest Electric Transmission Corridor (“NIETC”).In October 2007, the DOE issued a NIETC designation for the Mid-Atlantic corridor that includes the areas where TrAIL and PATH are proposed to be sited. Challenges by several entities to the Mid-Atlantic corridor designation are pending in the United States Court of Appeals for the Ninth Circuit. Briefing has concluded in this proceeding, in which AE and certain of its subsidiaries are intervenors. Allegheny cannot predict the outcome of this proceeding or whether it will have a material impact on its business or financial position.

In February 2009, the United States Circuit Court for the Fourth Circuit ruled on challenges to FERC rules promulgated for siting transmission lines within a NIETC. The Court held, among other things, that a state’s outright denial of a transmission siting application within one year does not constitute withholding of approval within one year, rejecting FERC’s interpretation of the relevant provision of the FPA. FERC, the Distribution Companies, TrAIL Company and other parties have filed a petition for a writ of certiorari with the United States Supreme Court with respect to the Fourth Circuit’s decision.

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, although 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.

The Distribution Companies have committed to purchase 479 MWs of qualifying PURPA capacity annually. In 2008, PURPA expense pursuant to these contracts totaled approximately $222.2 million. The average cost to the Distribution Companies of these power purchases was 6.3 cents/kWh. 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.

88

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 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 Public Utility Commission (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 PLR 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).

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 with the Pennsylvania PUC a default service plan. After hearings and an initial decision of a Pennsylvania PUC administrative law judge, in July 2008, the Pennsylvania PUC issued a final order largely approving 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

89

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 of the recent downturn in market prices for power. West Penn’s petition was approved by the Pennsylvania PUC in March 2009 and it began to conduct advanced procurements in April 2009. Also in April 2009, West Penn petitioned to Pennsylvania PUC for approval to further accelerate default service procurements increasing by 550 MW 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 MW, and the procurement occurred in June 2009.

Act 129. 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, 2010, 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:

• directs 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

• requires EDCs to file a plan for “smart meter” 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 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 Plan also proposes a reconcilable surcharge mechanism to obtain full and current cost recovery of the Plan costs as provided in Act 129. The 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 Energy Efficiency and Conservation Plan was held August 19, 2009. Due to the short time-frame for a Pennsylvania PUC decision under Act 129, the Pennsylvania PUC dispensed with the procedural step of a recommended decision from the presiding administrative law judge.

The Pennsylvania PUC approved West Penn’s Energy Efficiency and Conservation 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 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.

The Pennsylvania PUC approved West Penn’s proposal to recover its Energy Efficiency and Conservation Plan costs on a full and current basis via an automatic surcharge to customers’ bills, subject to an annual reconciliation mechanism.

90

On August 14, 2009, West Penn filed its Smart Meter Implementation Plan. The Plan provides for extensive deployment of smart meter infrastructure with replacement of all of West Penn’s approximately 725,000 meters by the end of 2014. To support two-way communications with the new meters the Company will build a new and secure telecommunications network. To support time of use and real time pricing as required by Act 129 the Company will purchase and install a new customer information system. The total cost of implementing smart metering infrastructure in the Pennsylvania service territory of West Penn is expected to be approximately $620 million. In accord with Act 129 the Company’s Plan institutes a cost recovery surcharge for the full and current recovery of the expenditures from customers. The surcharge anticipates a flat per-customer customer charge, varying by customer class, because the expenditures are not energy or demand related charges. The Commission’s most recent timetable for the proceeding has a hearing occurring on November 8 and 9, 2009, with a recommended decision by the presiding administrative law judge by late January, 2010, followed by a final decision of the Commission.

Transmission Expansion. By order entered on December 12, 2008, the Pennsylvania PUC authorized TrAIL Company to construct a 1.2 mile portion of the TrAIL project 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. Judicial review is pending in the Commonwealth Court of Pennsylvania with regard to the authorization to construct the 1.2 mile portion of the TrAIL project. 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. 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 payments for alternative energy credits will be fully recovered pursuant to an automatic energy adjustment clause. The Pennsylvania PUC initiated a proceeding in January 2005 regarding 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 PA PUC Electric Service Reliability in Pennsylvania 2008 report, Allegheny’s overall performance in 2008 was substantially better than its performance during 2007. In 2007, Allegheny’s SAIFI, CAIDI, and SAIDI values were all higher than the adjusted performance standards. In comparison, Allegheny’s 2008 SAIFI, CAIDI and SAIDI values were better than the standards by 7.9%, 17.6%, and 24.1%, respectively. The CAIDI value was 1.2% below the benchmark. The CAIDI three-year average was equal to the standard of 187 minutes, and SAIFI remained at .9% below the three-year standard of 1.16. As of July 2009, West Penn is satisfying all of the reliability benchmarks and standards approved by the Pennsylvania PUC in its July 2006 order.

91

West Virginia

In 1998, the West Virginia legislature passed legislation directing the Public Service Commission of West Virginia (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.

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. An evidentiary hearing on this matter is scheduled for March 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 that was approved by the West Virginia PSC when it reinstated a fuel and purchased power cost recovery clause in the rate case described above. 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, proposed to become effective January 1, 2010, were submitted pursuant to the schedule for annual fuel and purchased power cost reviews.

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 the Asset Swap, 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

92

upfront financing costs and certain other costs. Allegheny also is permitted to recover a return on actual construction costs exceeding the $450 million during the period prior to placing the project into commercial service and may file for recovery of any costs exceeding the $450 million once the Scrubber is in commercial service. As discussed below, Monongahela and Potomac Edison have subsequently received approval to finance the amounts in excess of $450 million through securitization, in the alternative.

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 approximately $105 million in additional environmental control bonds. On September 30, 2009, the West Virginia PSC issued a financing order granting 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.

Transmission Expansion. On May 15, 2009, PATH-WV, PATH-Allegheny, PATH-WV LAC and PATH-Allegheny LAC 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. The procedural schedule established by the West Virginia PSC provides for an evidentiary hearing in this case in February 2010 and a final commission decision by June 21, 2010. On October 28, 2009, the Staff of the West Virginia PSC filed a motion to dismiss the application on the basis that, because there is no application pending before any regulatory agency for approval of the Maryland portion of the PATH Project, there is no identified eastern terminus of the project. Other parties have filed similar motions or statements in support of the Staff motion. On November 4, 2009, PATH-WV, PATH-Allegheny, PATH-WV LAC and PATH-Allegheny LAC filed a response in which they opposed the Staff motion but agreed to toll the statutory decision due date in West Virginia until January 25, 2011 if the West Virginia PSC extends its current procedural schedule in the manner proposed in the response.

On September 10, 2009, TrAIL Company filed a petition to amend its certificate for the TrAIL Project requesting authorization of the West Virginia PSC to make minor adjustments in the approved route in 21 locations. The West Virginia PSC has not yet acted on the petition.

On October 19, 2009, four individuals filed a complaint with the West Virginia PSC regarding TrAIL Company’s right-of-way clearing practices for the TrAIL Project that requested, among other things, a limit on right of way clearing for TrAIL. TrAIL Company responded to the complaint, denying each of its allegations. The West Virginia PSC has not acted on the complaint.

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).

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

93

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 Public Service Commission (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. The Maryland PSC then 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 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. It is unclear when the Maryland PSC will issue its findings in these proceedings.

In the meantime, on April 4, 2008, the Maryland PSC released a report reaffirming, based on review by outside counsel and consultants, that the current procurement methods used for SOS have been competitive, fair and free from evidence of collusion. In October and November 2008 and in January 2009, bids for some residential load were rejected in the SOS process due to the operation of a price cap called the Price Anomaly Threshold (“PAT”). The Maryland PSC’s outside consultant monitoring the bidding opined that the PAT was triggered due to the then-current disruptions in the credit markets. The Maryland PSC issued orders on January 16 and January 23, 2009 directing short-term measures to be taken to fill unfilled load, which measures were successful in filling the load.

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. In another proceeding, however, the Maryland PSC ordered the utilities to issue an RFP for possible acquisition of demand response resources for the period from 2011 to 2016 and to participate in a working group on development of distributed generation resources. The RFP was issued on January 16, 2009, the Commission issued an order on March 11 approving purchase of most of the resources offered, and the utilities have made the purchases. Also, on September 29, 2009, the Maryland PSC opened a new proceeding to receive and consider proposals for construction of new generation resources in Maryland. Proposals are due to be filed by December 16, 2009.

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 replenish 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 when capped generation rates end on January 1, 2009.

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

94

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% annually in 2007 and 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 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 and the rate increase anticipated for 2010 each are less than 5%. Of Potomac Edison’s approximately 219,000 residential customers in Maryland, as of June 30, 2009, approximately 21,600, or 9.9%, elected to opt-out of Potomac Edison’s plan.

Advanced Metering and Demand Side Management Initiatives. On June 8, 2007, the Maryland PSC established a new case to consider advanced meters and demand side management programs. The Staff of the Maryland PSC filed its report on these matters on July 6, 2007. On September 28, 2007, the Maryland PSC issued an order in this case that required the utilities to file detailed plans for how they will meet a proposal-“EmPOWER Maryland”-that electric usage in Maryland 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 is being examined on a separate track and is currently under discussion with the Staff of the Maryland PSC.

Renewable Energy Portfolio Standard. Legislation enacted in 2004 (and supplemented with respect to solar power in 2007) 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, the Commission Staff 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 Commission 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. The Maryland PSC is continuing to conduct hearings on related issues.

95

Transmission Expansion. On May 19, 2009, Potomac Edison on behalf of PATH-Allegheny filed an application with the Maryland PSC for a certificate of public convenience and necessity to construct portions of the PATH Project in Maryland. The Maryland PSC requested briefs on certain preliminary legal issues and heard oral argument on the issues. On September 9, 2009, the Maryland PSC issued an order determining that Potomac Edison could not file an application for a certificate of public convenience and necessity on behalf of PATH-Allegheny but could file such an application on behalf of itself and directed Potomac Edison to advise the Maryland PSC of its decision to file such an application within 30 days. On October 9, 2009, Potomac Edison advised the Maryland PSC that it continues to consider its filing options, including whether to re-file an application with the Maryland PSC, and intends to inform the Maryland PSC of its decision as soon as possible.

Virginia

Sale of Distribution Operations.On May 4, 2009, Potomac Edison signed definitive agreements to sell its electric distribution operations in Virginia to Rappahannock Electric Cooperative and Shenandoah Valley Electric Cooperative (together, the “Cooperatives”) for cash proceeds of approximately $340 million, subject to state and federal regulatory approval, certain third-party consents and applicable price adjustments. See Note 3, “Assets Held for Sale” to the Consolidated Financial Statements for additional information. On September 15, 2009, Potomac Edison and the Cooperatives filed with the Virginia SCC a joint request for approval of the transaction. The Virginia SCC issued a procedural order scheduling an evidentiary hearing on the matter for March 2, 2010.

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 does 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, 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.

96

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 18, 2008, Potomac Edison filed with the Virginia SCC 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. The Virginia SCC held a hearing on the settlement on November 18 and approved it without alteration or condition on November 26, 2008. Key provisions of the settlement include:

• The $73 million rate increase approved on a temporary basis on May 15, 2008 will 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 mid-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 June 5, 2009, Potomac Edison filed a request for a transmission rate adjustment clause to collect $1.0 million of third-party transmission costs that it expects to incur between January 1, 2009 and August 31, 2010, as permitted by the settlement. Potomac Edison has proposed to recover this amount from its retail customers over the rate period from September 1, 2009 through August 31, 2010. The Virginia SCC approved recovery of all but an insignificant portion of this amount in an order issued on August 28, 2009.

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.

Transmission Expansion. On October 7, 2008, the Virginia State Corporate Commission (the “Virginia SCC”) issued an order authorizing construction of the TrAIL project in Virginia, and on November 5, 2009, the Virginia Supreme Court affirmed the Virginia SCC’s order.

On May 19, 2009, PATH-VA filed an application with the Virginia SCC for a certificate of public convenience and necessity to construct portions of the PATH Project in Virginia. The Virginia SCC has established a procedural schedule that provides for an evidentiary hearing commencing on January 19, 2010.

97

On October 19, 2009, the Staff of the Virginia SCC filed a motion to dismiss the application on the basis that, because there is no application pending before any regulatory agency for approval of the Maryland portion of the PATH Project, there is no identified eastern terminus of the project. Other parties filed similar motions or statements in support of the Staff motion. PATH-VA filed a response opposing the Virginia SCC’s motion. The Virginia SCC has not acted on the motion.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See Item 7a, “Quantitative and Qualitative Disclosures About Market Risk,” in the 2008 Annual Report on Form 10-K for information relating to market risk.

Commodity Price Risk

Allegheny has commodity price risk to the extent that the amount of energy it generates and contracts to purchase differs from the amount of energy it has contracted to sell. Allegheny is also exposed to market risks associated with changes in commodity prices resulting from changes in supply and demand, fuel costs, market liquidity, weather, environmental regulation and other factors.

To manage its exposure to market price changes relating to its energy related assets, liabilities and other contractual arrangements, Allegheny sells and purchases physical energy at the wholesale level and enters into financial exchange-traded and over the counter derivative contracts. See Note 9 “Fair Value Measurements, Derivative Instruments and Hedging Activities,” for information regarding Allegheny’s derivative positions held at September 30, 2009.

In general, increases in forward market prices for power have a positive impact, and decreases in forward market prices have a negative impact, on Allegheny’s owned and contracted generation positions that have not been hedged. As of September 30, 2009, the percentage of expected coal-fired generation hedged was approximately 85%, 85% and 20% for the remainder of 2009, 2010 and 2011, respectively. 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.

Allegheny measures the sensitivity of the portfolio to potential changes in market prices using high-level sensitivity analysis and Value at Risk.

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 September 30, 2009 market conditions and hedged position would be a decrease in pre-tax income of approximately $12 million, $48 million and $264 million for the last three months of 2009, full year 2010 and full year 2011, 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 September 30, 2009 market conditions and hedged position would be a decrease in pre-tax income of approximately $0, $1 million and $45 million for the last three months of 2009, full year 2010 and full year 2011, 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, basis changes relative to PJM Western Hub power prices, among other factors.

Derivatives not designated as part of a cash flow hedge relationship or as normal purchase normal sale (“NPNS”) contracts are reported in revenues on a mark-to-market basis. The VaR for such mark-to-market derivative contracts other than FTRs at September 30, 2009 and December 31, 2008 was $1 million and $3 million, respectively. VaR represents a calculated statistical measure of potential loss based on a one-day holding period at a 95% confidence level over the remaining term of the positions. FTRs are excluded from Allegheny’s calculation of VaR due to the absence of liquid spot and forward markets.

98

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. As described in Note 9, “Fair Value Measurements, Derivative Instruments and Hedging Activities,” to the Consolidated Financial Statements, Allegheny recorded $(6.2) million and $21.3 million of unrealized gains (losses) attributable to FTRs during the three and nine months ended September 30, 2009, respectively.

Credit Risk

Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. Allegheny evaluates the credit standing of a prospective counterparty based on the prospective counterparty’s financial condition. Where deemed necessary, Allegheny may impose specified collateral requirements and use standardized agreements that facilitate netting of cash flows. Allegheny’s internal risk management group monitors the financial conditions of existing counterparties on an ongoing basis.

See Item 7a, “Quantitative and Qualitative Disclosures About Market Risk,” in the 2008 Annual Report on Form 10-K and Note 9, “Fair Value Measurements, Derivative Instruments and Hedging Activities” to the Consolidated Financial Statements for additional information relating to credit risk.

Interest Rate Risk

Allegheny is subject to interest rate risk with respect to its variable rate debt and with respect to prevailing interest rates at the time existing debt is refinanced. At September 30, 2009 Allegheny’s outstanding debt subject to variable interest rate was $120 million, excluding $330 million of variable rate debt relating to the TrAIL project for which interest expense is fully recoverable and excluding AE Supply’s $447 million term loan that was repaid on October 2, 2009 in connection with the issuance of fixed rate debt. See Note 7, “Common Stock and Debt,” for additional information regarding Allegheny’s debt.

ITEM 4. CONTROLS AND PROCEDURES

See, Item 9a. “Controls and Procedures,” in the 2008 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 September 30, 2009, 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.

99

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 the Consolidated Financial Statements for information regarding legal proceedings.

ITEM 1A. RISK FACTORS

Except for the risk factors set forth below, there have been no material changes to the risk factors disclosed in Item 1A of Part 1 of the 2008 Annual report on form 10-K. Certain of the risk factors set forth below were disclosed in the 2008 Annual Report on Form 10-K and have been updated to provide additional information.

Decreasing demand for electric power, as well as for certain commodities underlying the production of electric power and the related decline in market prices for power are adversely affecting Allegheny’s business.

In recent months, customer demand for electric power in Allegheny’s region has fallen significantly as a result of the ongoing economic recession and mild summer weather, among other factors. Overall demand for some of the commodities that underlie the production of electricity, and as a result the prevailing prices for those commodities, have also declined. Although power prices may be influenced by many factors, weakening demand for electricity, together with significantly lower commodity prices, have contributed to sharp declines in market prices for power over the previous 12 months. Partly as a consequence of these declines, AE Supply generated significantly less power in the first six months of 2009 than in the comparable portion of 2008. AE Supply generated a total of approximately 25 million MWhs in the first nine months of 2009 compared to approximately 35 million MWhs in the first nine months of 2008, representing an approximately 27.5% decrease in generation. This trend, combined with other factors, led to a decline in Allegheny’s revenues for the nine months ended September 30, 2009, compared to the same period in the prior year.

Allegheny can make no assurances regarding the impact of any economic recovery on demand and market prices for power. Improvements in demand and market prices for power, if any, may lag any future improvements in overall economic conditions, and it is also possible that the current economic climate could result in long-term reduction of demand for power in our region, particularly among large industrial consumers.

Allegheny’s coal inventories are growing beyond desirable levels as a result of recent decreases in our power production resulting from declines in demand and market prices for power.

AE Supply and Monongahela have various longer term coal supply contracts in place that are intended to partially mitigate our exposure to negative fluctuations in coal prices. In some cases, these contracts may require that AE Supply or Monongahela purchase a minimum volume of coal over a given time period. However, as a result of falling demand and market prices for power, Allegheny has experienced declines in the frequency with which its coal burning power plants are operating. As a result, Allegheny’s recent coal consumption has decreased significantly, and it has been required to purchase coal in excess of immediate needs, resulting in coal inventories at some of its facilities that exceed what it considers to be optimal levels, which could have an adverse impact on its business. If current trends continue, Allegheny may be unable to accept future deliveries at one or more of its facilities and may need to pursue alternative arrangements, including third party sales of inventory at levels below its cost, arrangements for third-party storage of a portion of its coal inventory, and modifications to its existing coal supply agreements.

100

Shifting state and federal regulatory policies impose risks on Allegheny’s operations. Compliance with emerging regulatory initiatives could require Allegheny to incur significant costs. Delays, discontinuations or reversals of electricity market restructurings in the markets in which Allegheny operates could have an adverse effect on its business.

Allegheny’s operations are subject to evolving regulatory policies, including initiatives regarding deregulation and re-regulation of the production and sale of electricity, the restructuring of transmission regulation and energy efficiency and conservation. Any new requirements arising from these actions could lead to increased operating expenses and capital expenditures, the full amount of which cannot be predicted at this time.

Some deregulated electricity markets in which Allegheny operates have experienced price volatility. In some of these markets, government agencies and other interested parties have made proposals to delay market restructuring or even re-regulate areas of these markets that have previously been deregulated. Although it is possible that, in an economic downturn, price increases resulting from the transition to market rates could be smaller than previously anticipated, the heightened public and political concern over the transition to market rates could nevertheless be exacerbated by the current deteriorating national economic climate and its potential effects on consumers.

In Pennsylvania, many of the state’s electric utilities, including Allegheny, are scheduled to transition to market rates in 2010 and 2011, when applicable generation rate caps expire. Significant price increases in other states following the end of such regulatory transition periods have created a heightened political concern regarding price volatility in Pennsylvania following the expiration of its rate caps. In September 2007, a special legislative session was convened in Pennsylvania to consider various energy proposals. During the special session, several proposed bills involving the extension of rate caps were introduced. Currently, generation rate caps for Allegheny’s Pennsylvania customers expire at the end of 2010. While the Pennsylvania General Assembly adopted legislation in October 2008 that includes a number of conservation and demand-side management measures and procurement procedures, it does not address rate mitigation or the transition to market rates. However, there can be no assurance that the Pennsylvania legislature will not adopt such measures in the future. See “Regulatory Matters.”

Other proposals to re-regulate the industry may be made, and legislative or other action affecting the electric power restructuring process may cause the process to be delayed, discontinued or reversed in the states in which Allegheny operates. Delays, discontinuations or reversals of electricity market restructurings in the markets in which Allegheny operates could have an adverse effect on its business, results of operations, cash flows and financial condition. At a minimum, these types of actions raise uncertainty concerning the continued development of competitive power markets. Given Allegheny’s multi-state operations and asset base, re-regulation of restructured obligations could prove intricate, time-consuming and costly to ongoing operations.

In addition, as a result of FERC’s efforts to implement a long-term rate design for the Midwest and Mid-Atlantic regions, the Distribution Companies may not fully recover their transmission costs and may have costs shifted to them from other transmission owners. Due to capped rates and the timing of state rate cases, the Distribution Companies may not be able to pass through increased transmission costs to these retail customers for some period of time. See “Regulatory Matters.”

Furthermore, some of the states in which Allegheny operates have enacted or are considering various energy efficiency and conservation programs, which could prove costly for Allegheny. In 2008, for example, Pennsylvania adopted Act 129, which includes a number of provisions relating to conservation, demand-side management and power procurement processes. Maryland has adopted some similar measures as part of its EmPOWER Maryland initiative. Among other things, Act 129 requires the implementation of smart meter technology, in connection with which Allegheny expects to incur substantial costs. Although Act 129 includes cost recovery provisions, any delay in or denial of cost recovery could adversely affect Allegheny. Additionally, failure to comply with Act 129 could result in significant penalties. See “Regulatory Matters.”

101

Allegheny is currently involved in capital intensive projects that may involve various implementation and financial risks.

Allegheny currently is involved in a number of capital intensive projects, including the TrAIL Project, the PATH Project, the installation of Scrubbers at the Fort Martin and Hatfield’s Ferry generation facilities and the implementation of smart meter and other information technology necessary to comply with Pennsylvania’s recently-enacted Act 129. Allegheny’s ability to successfully complete these projects in a timely manner, within established budgets and without significant operational disruptions is contingent upon many variables, many of which are outside of its control. Failure to complete these projects as planned may have an adverse effect on Allegheny’s business, results of operations, cash flow and financial condition.

Additionally, Allegheny has contracted with specialized vendors in connection with these projects, and may in the future enter into additional such contracts with respect to these and other capital projects. As such, Allegheny is exposed to the risk that these contractors may not perform as required under their contracts. Such a failure could occur for any number of reasons. Among other things, it is possible that the prevailing constrained credit markets and overall negative economic conditions may affect the ability of Allegheny’s contractors, subcontractors, suppliers and vendors to access the capital markets and maintain adequate liquidity to sustain their respective businesses. Should this occur, Allegheny may be forced to find alternate arrangements, which may cause delay and/or increased costs. Allegheny can provide no assurance that it would be able to make such alternate arrangements on terms acceptable to it or at all. Any inability to make such alternate arrangements or any substantial delays or increases in costs associated therewith may have an adverse effect on Allegheny’s business, results of operations, cash flow and financial condition. For additional information regarding Act 129, see “Regulatory Matters.”

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5. OTHER INFORMATION

Effective January 1, 2009, Allegheny adopted SAFS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51” (“SFAS 160”), (FASB Codification Topic 810). The adoption of SFAS 160 did not have a material impact on Allegheny’s financial condition, results of operations or cash flows, although it did impact the presentation and disclosure of noncontrolling interests (previously referred to as minority interests) in Allegheny’s consolidated financial statements. Under SFAS 160, noncontrolling interests are reported in the consolidated statement of financial position as a separate component within equity, and consolidated net income and consolidated comprehensive income are adjusted to include amounts attributable to the noncontrolling interest. In accordance with the retrospective presentation and disclosure requirements of SFAS 160, Allegheny reflected the change in presentation and disclosure for all periods presented in its quarterly reports on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009 and in this quarterly report on Form 10-Q for the quarter ended September 30, 2009.

Allegheny will also reflect the change in presentation and disclosure for annual periods included in its annual report on Form 10-K for the year ending December 31, 2009. Amounts previously reported as minority interests in Allegheny’s consolidated balance sheets ($13.2 million and $10.7 million at December 31, 2007 and 2006, respectively) will be reported under SFAS 160 as noncontrolling interests, a component of equity. In addition, $0.4 million, $3.1 million and $2.6 million previously reported as minority interest expense for the years ended December 31, 2008, 2007 and 2006, respectively, will be reported under SFAS 160 as net income attributable to noncontrolling interests, a component of net income.

102

EXHIBIT INDEX

	Documents
10.1	Second Supplemental Indenture, dated as of October 1, 2009, between Allegheny Energy Supply Company, LLC and Wells Fargo Bank, N.A.
10.2	Third Supplemental Indenture, dated as of October 1, 2009, between Allegheny Energy Supply Company, LLC and Wells Fargo Bank, N.A.
10.3	Exempt Facilities Loan Agreement, dated as of July 1, 2009, between Pennsylvania Economic Development Financing Authority and Allegheny Energy Supply Company, LLC
10.4	Credit Agreement, dated as of September 24, 2009, among Allegheny Energy Supply Company, LLC, Bank of America, as Administrative Agent, and the Lenders party thereto
10.5	Credit Agreement, dated as of May 2, 2006, among Allegheny Energy Supply Company, LLC, Citicorp USA, Inc., as Administrative Agent, and the Lenders party thereto
10.6	Amendment No. 1 to that certain Credit Agreement, dated as of May 2, 2006, among Allegheny Energy Supply Company, LLC, Citicorp USA, Inc., as Administrative Agent, and the Lenders party thereto
10.7	Amendment No. 3 to that certain Credit Agreement, dated as of May 2, 2006, among Allegheny Energy Supply Company, LLC, Citicorp USA, Inc., as Administrative Agent, and the Lenders party thereto
10.8	Credit Agreement, dated as of May 22, 2006, among Allegheny Energy, Inc., Allegheny Energy Supply Company, LLC, Citicorp North America, Inc., as Administrative Agent, and the Lenders party thereto
10.9	Amended and Restated Credit Agreement, dated as of August 15, 2008, among Trans-Allegheny Interstate Line Company, Citibank, N.A., as Administrative Agent, and the Lenders party thereto
10.10	Equity Commitment Agreement, dated as of August 15, 2008, between Allegheny Energy, Inc. and Union Bank of California, as Collateral Agent
10.11	Pledge Agreement, dated as of August 15, 2008, between Allegheny Energy Transmission, LLC and Union Bank of California, as Collateral Agent
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

103

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: November 6, 2009	By:	/s/ Kirk R. Oliver
		Kirk R. Oliver Senior Vice President and Chief Financial Officer

104