Allegheny Energy (AYE) 10-Q 2008 Q1 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 March 31, 2008

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
(Address of Principal Executive	15601
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. Yesþ Noo

      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 filerþ	Accelerated filero	Non-accelerated filero	Smaller reporting companyo
		(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). Yeso Noþ

As of April 30, 2008, 168,030,669 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”)		34
Item 3. Quantitative and Qualitative Disclosures About Market Risk		65
Item 4. Controls and Procedures		65
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		66
Item 1A. Risk Factors		66
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		68
Item 3. Defaults Upon Senior Securities		68
Item 4. Submission of Matters to a Vote of Security Holders		68
Item 5. Other Information		68
Item 6. Exhibits		69
Signatures		70
EX-31.1
EX-31.2
EX-32.1
EX-32.2

2

GLOSSARY

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

AE	Allegheny Energy, Inc., a diversified utility holding company
Allegheny Ventures	Allegheny Ventures, Inc., a nonutility, unregulated subsidiary of AE
AE Supply	Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary of AE
AGC	Allegheny Generating Company, an unregulated 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.
Potomac Edison	The Potomac Edison Company, a regulated subsidiary of AE
TrAIL Company	Trans-Allegheny Interstate Line Company
West Penn	West Penn Power Company, a regulated subsidiary of AE

3

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(unaudited)

	Three Months Ended
	March 31,
(In thousands, except per share amounts)	2008			2007
Operating revenues	$	875,026		$	847,625
Operating expenses:
Fuel		249,826			232,225
Purchased power and transmission		97,380			93,266
Deferred energy costs, net		(10,454	)		(1,455	)
Operations and maintenance		168,700			160,544
Depreciation and amortization		70,289			71,981
Taxes other than income taxes		52,439			55,890
Total operating expenses		628,180			612,451
Operating income		246,846			235,174
Other income and expenses, net		6,209			5,862
Interest expense and preferred dividends of subsidiary		58,431			59,529
Income before income taxes and minority interest		194,624			181,507
Income tax expense		58,293			71,378
Minority interest in net income of subsidiaries		206			387
Net income	$	136,125		$	109,742
Common share data:
Weighted average common shares outstanding:
Basic		167,560			165,494
Diluted		169,950			169,181
Basic income per common share	$	0.81		$	0.66
Diluted income per common share	$	0.80		$	0.65

See accompanying Notes to Consolidated Financial Statements.

4

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)

	Three Months Ended
	March 31,
(In thousands)	2008			2007
Cash Flows From Operating Activities:
Net income	$	136,125		$	109,742
Adjustments for non-cash items included in income:
Depreciation and amortization		70,289			71,981
Amortization of debt related costs		2,861			2,695
Amortization of power sale liability related to Ohio sale		—			(9,100	)
Amortization of liability for adverse power purchase commitment		(4,284	)		(4,322	)
Amortization of Pennsylvania stranded cost recovery asset		5,427			4,664
(Gain) loss on disposal or retirement of assets		(358	)		17
Minority interest in net income of subsidiaries		206			387
Deferred income taxes and investment tax credit, net		41,435			74,955
Deferred energy costs, net		(10,454	)		(1,455	)
Stock-based compensation expense		2,735			2,823
Unrealized gains on commodity contracts, net		(1,320	)		(2,450	)
Pension and other postretirement employee benefit plan expense		7,995			9,414
Pension and other postretirement employee benefit plan contributions		(39,055	)		(39,322	)
Deferred revenue — Fort Martin Scrubber project		5,437			—
Other, net		3,875			930
Changes in certain assets and liabilities:
Accounts receivable, net		(54,734	)		(44,519	)
Materials, supplies and fuel		(1,952	)		851
Prepaid taxes		(34,809	)		(34,542	)
Collateral deposits		12,489			(8,333	)
Prepaid assets		(1,017	)		(1,304	)
Other current assets		977			10,668
Accounts payable		(45,496	)		24,958
Accrued taxes		(10,201	)		(11,433	)
Accrued interest		(2,244	)		8,189
Other current liabilities		8,631			92
Regulatory asset — PATH		(582	)		—
Other assets		454			(2,076	)
Deferred income taxes		(752	)		(12,262	)
Regulatory liabilities		16,283			—
Other liabilities		(1,901	)		2,599
Net cash provided by operating activities		106,060			153,847
Cash Flows From Investing Activities:
Capital expenditures		(239,816	)		(168,439	)
Proceeds from asset sales		400			260
Purchase of Merrill Lynch interest in subsidiary		(50,000	)		—
Decrease in restricted funds		64,777			1,322
Other investments		(1,575	)		(992	)
Net cash used in investing activities		(226,214	)		(167,849	)
Cash Flows From Financing Activities:
Issuance of long-term debt		124,347			—
Repayment of long-term debt		(159,393	)		(36,073	)
Equity contribution to PATH, LLC by AEP		3,070			—
Proceeds from exercise of employee stock options		8,256			4,580
Cash dividends paid on common stock		(25,161	)		—
Other		—			(1	)
Net cash used in financing activities		(48,881	)		(31,494	)
Net decrease in cash and cash equivalents		(169,035	)		(45,496	)
Cash and cash equivalents at beginning of period		258,750			114,138
Cash and cash equivalents at end of period	$	89,715		$	68,642
Supplemental Cash Flow Information:
Cash paid during the period for:
Interest (net of amounts capitalized)	$	57,763		$	48,493
Income taxes, net	$	624		$	2,365

See accompanying Notes to Consolidated Financial Statements.

5

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(unaudited)

	March 31,			December 31,
(In thousands)	2008			2007
ASSETS
Current Assets:
Cash and cash equivalents	$	89,715		$	258,750
Accounts receivable:
Customer		234,347			195,545
Unbilled utility revenue		87,808			110,569
Wholesale and other		92,693			57,626
Allowance for uncollectible accounts		(15,132	)		(14,252	)
Materials and supplies		104,353			103,075
Fuel		78,783			72,506
Deferred income taxes		223,194			286,440
Prepaid taxes		83,152			48,343
Collateral deposits `		44,609			59,527
Derivative assets		5,266			29
Restricted funds		29,553			47,501
Regulatory assets		78,408			73,299
Other		63,936			16,001
Total current assets		1,200,685			1,314,959
Property, Plant and Equipment, Net:
Generation		6,028,017			5,992,919
Transmission		1,133,197			1,126,657
Distribution		3,808,384			3,761,438
Other		463,304			452,525
Accumulated depreciation		(4,837,615	)		(4,795,925	)
Subtotal		6,595,287			6,537,614
Construction work in progress		792,722			658,966
Total property, plant and equipment, net		7,388,009			7,196,580
Investments and Other Assets:
Restricted funds — Fort Martin scrubber project		302,574			347,023
Goodwill		367,287			367,287
Investments in unconsolidated affiliates		27,811			27,875
Other		17,552			15,974
Total investments and other assets		715,224			758,159
Deferred Charges:
Regulatory assets		559,042			601,603
Other		57,519			35,288
Total deferred charges		616,561			636,891
Total Assets	$	9,920,479		$	9,906,589

See accompanying Notes to Consolidated Financial Statements.

6

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(unaudited)

	March 31,			December 31,
(In thousands, except share amounts)	2008			2007
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	10,000		$	10,000
Long-term debt due within one year (Note 8)		89,561			95,367
Accounts payable		296,731			380,688
Accrued taxes		70,100			83,580
Derivative liabilities		76,862			14,117
Accrued interest		63,339			65,583
Security deposits		39,939			38,976
Other		150,826			99,192
Total current liabilities		797,358			787,503
Long-term Debt (Note 8)		3,917,135			3,943,947
Deferred Credits and Other Liabilities:
Derivative liabilities		21,391			12,815
Income taxes payable		70,007			68,050
Investment tax credit		68,540			69,353
Deferred income taxes		1,299,490			1,345,953
Obligations under capital leases		44,409			38,765
Regulatory liabilities		505,375			488,393
Adverse power purchase commitment		145,433			149,799
Other		429,285			453,418
Total deferred credits and other liabilities		2,583,930			2,626,546
Commitments and Contingencies (Note 16)
Minority Interest		3,279			13,241
Common Stockholders’ Equity:
Common stock—$1.25 par value per share, 260 million shares authorized and 167,896,292 and 167,273,069 shares issued at March 31, 2008 and December 31, 2007, respectively		209,870			209,091
Other paid-in capital		1,934,346			1,924,072
Retained earnings		555,065			444,177
Treasury stock at cost—49,493 shares		(1,756	)		(1,756	)
Accumulated other comprehensive loss		(78,748	)		(40,232	)
Total common stockholders’ equity		2,618,777			2,535,352
Total Liabilities and Stockholders’ Equity	$	9,920,479		$	9,906,589

See accompanying Notes to Consolidated Financial Statements.

7

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF COMMON STOCKHOLDERS’ EQUITY
For the Three Months Ended March 31, 2008
(unaudited)

													Accumulated
					Other								other			Total common
	Shares		Common		paid-in		Retained			Treasury			comprehensive			stockholders’
(In thousands, except shares)	outstanding		stock		capital		earnings			stock			loss			equity
Balance at December 31, 2007		167,223,576	$	209,091	$	1,924,072	$	444,177		$	(1,756	)	$	(40,232	)	$	2,535,352
Net income		—		—		—		136,125			—			—			136,125
Defined benefit pension and other benefit plan amortization:
Net actuarial loss, net of tax of $42		—		—		—		—			—			41			41
Net transition obligation, net of tax of $197		—		—		—		—			—			192			192
Net prior service cost, net of tax of $95		—		—		—		—			—			94			94
Unrealized losses on available-for-sale securities, net of tax of $1		—		—		—		—			—			(1	)		(1	)
Cash flow hedges, net of tax of $24,386		—		—		—		—			—			(38,842	)		(38,842	)
Dividends on common stock		—		—		—		(25,161	)		—			—			(25,161	)
Stock-based compensation expense:
Stock units		—		—		342		—			—			—			342
Non-employee director stock awards		16,267		20		257		(8	)		—			—			269
Stock options		—		—		2,110		—			—			—			2,110
Exercise of stock options		606,902		759		7,497		—			—			—			8,256
Settlement of stock units		54		—		—		—			—			—			—
Dividends on stock units		—		—		68		(68	)		—			—			—
Balance at March 31, 2008		167,846,799	$	209,870	$	1,934,346	$	555,065		$	(1,756	)	$	(78,748	)	$	2,618,777

See accompanying Notes to Consolidated Financial Statements.

8

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

Note No.	Page No.
1 Basis of Presentation		10
2 Recent Accounting Pronouncements		11
3 Transmission Expansion Projects		11
4 Acquisition of Minority Interest in AE Supply		12
5 Rates and Regulation		13
6 Regulatory Assets and Liabilities		16
7 Income Taxes		17
8 Capitalization and Short-Term Debt		18
9 Business Segments		19
10 Derivative Instruments and Hedging Activities		20
11 Stock-Based Compensation		23
12 Pension Benefits and Postretirement Benefits Other Than Pensions		25
13 Comprehensive Income and Accumulated Other Comprehensive Loss		26
14 Income Per Common Share		27
15 Other Income and Expenses, Net		27
16 Commitments and Contingencies		28

9

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

NOTE 1: BASIS OF PRESENTATION

Business Description

     Allegheny Energy, Inc. (“AE” and together with its directly and indirectly owned 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.

     The Delivery and Services segment primarily consists of Allegheny’s regulated utility subsidiaries. These subsidiaries include Monongahela Power Company (“Monongahela”), excluding its generation operations, The Potomac Edison Company (“Potomac Edison”) and West Penn Power Company (“West Penn”) (collectively, the “Distribution Companies”). The Distribution Companies primarily operate electric transmission and distribution (“T&D”) systems in Pennsylvania, West Virginia, Maryland and Virginia. The Distribution Companies are subject to federal and state regulation, including regulation of rates. The Delivery and Services segment also includes Allegheny Ventures, Inc. (“Allegheny Ventures”), 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 proposed 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 proposed 290-mile, high-voltage transmission line. See Note 3, “Transmission Expansion Projects,” for additional information.

     The Generation and Marketing segment primarily consists of Allegheny’s electric generation subsidiaries, Allegheny Energy Supply Company, LLC (“AE Supply”) and Allegheny Generating Company (“AGC”), as well as Monongahela’s generation operations. AE Supply owns, operates and controls electric generation capacity and supplies and trades energy and energy-related commodities. AGC owns and sells generation capacity to AE Supply and Monongahela, which own approximately 59% and 41% of AGC, respectively. The Generation and Marketing segment is subject to federal and state regulation but, unlike the Delivery and Services segment, is not generally subject to state regulation of rates, except that Monongahela’s generation is subject to state regulation of its rates in West Virginia.

     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, 2007.

     The accompanying unaudited Consolidated Financial Statements contain all adjustments, including normal recurring accruals, necessary to present fairly Allegheny’s financial position as of March 31, 2008, and its results of operations and cash flows for the three months ended March 31, 2008 and 2007. The results of operations for the interim periods are not necessarily indicative of the results expected for the full year. Information for quarterly periods is affected by seasonal variations in revenues, fuel and energy purchases and other factors. The year-end 2007 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.

10

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

NOTE 2: RECENT ACCOUNTING PRONOUNCEMENTS

     In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements” (“SFAS 157”). In February 2008, the FASB issued FSP FAS No. 157-2, “Effective Date of FASB Statement 157” (“FSP FAS 157-2”), which permits 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 and FSP FAS 157-2 effective January 1, 2008 and will defer application of SFAS 157 for non-financial assets and liabilities until January 1, 2009. Allegheny does not expect that the adoption of SFAS 157 for non-financial assets and liabilities will have a material impact on its financial statements.

     SFAS 157 defines fair value and establishes a framework for measuring fair value when fair value is required for recognition or disclosure purposes under GAAP. The standard also expands financial statement disclosures about fair value measurements including a three-level fair value hierarchy showing the inputs an entity uses to develop its fair value measurements. SFAS 157 does not require any new fair value measurements. See Note 10 “Derivative Instruments and Hedging Activities,” for information related to Allegheny’s adoption of SFAS 157.

     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 permits entities to choose to measure at fair value certain financial instruments and other items that are not currently required to be measured at fair value. SFAS 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. As of March 31, 2008, Allegheny had not elected the fair value option for any eligible items. As a result, the provisions of SFAS 159 have not impacted Allegheny’s results of operations or financial condition.

     In April 2007, the FASB issued Interpretation No. 39-1, “Amendment of Interpretation 39” (“FIN 39-1”). FIN 39-1 permits entities that are party to master netting arrangements to offset cash collateral receivables or payables with net derivatives positions. FIN 39-1 requires entities that choose to offset fair values of derivatives with the same party under a netting agreement to also net the fair values of related cash collateral against the derivative values. FIN 39-1 also requires that entities disclose whether or not they offset fair value of derivatives and related cash collateral and disclose the amounts recognized for cash collateral payable and receivable at the end of such reporting period. FIN 39-1 requires retrospective application for all periods presented. Allegheny adopted FIN 39-1 effective January 1, 2008 and changed its method of netting certain balance sheet amounts by an immaterial amount.

NOTE 3: TRANSMISSION EXPANSION PROJECTS

Trans-Allegheny Interstate Line

     In February 2006, Allegheny announced plans to construct the TrAIL project, a new approximately 185-mile, 500 kV extra-high voltage line extending from the Prexy substation in southwestern Pennsylvania east to a point of interconnection with Dominion Virginia Power (“Dominion”) in northern Virginia. In addition, if approved by the Virginia State Corporation Commission (the “Virginia SCC”), Allegheny and Dominion will jointly own a 30-mile 500 kV line segment that Dominion will construct and that will extend from the point of interconnection with the new Allegheny line to Loudoun, VA. The TrAIL project also includes new 138 kV transmission lines and related substations. In June 2006, the board of directors of PJM Interconnection, L.L.C. (“PJM”) approved a new transmission line extending from southwestern Pennsylvania through West Virginia into northern Virginia, and designated Allegheny to build the AP Zone portion of the line. PJM, which is a regional transmission operator, is responsible for the operation of and reliability planning for the transmission network in the PJM region and included the new line in its 2006 regional transmission expansion plan.

     On July 20, 2006, the Federal Energy Regulatory Commission (“FERC”) approved incentive rate treatments for TrAIL. On February 21, 2007, TrAIL Company submitted to FERC a filing to implement a formula tariff rate, with a proposed effective date of June 1, 2007, that included the incentive rate treatments approved by FERC. On May 31, 2007, FERC issued an order permitting the formula tariff rate to become effective on June 1, 2007, subject to refund and hearing.

     On January 24, 2008, TrAIL Company filed a motion to suspend FERC’s procedural schedule stating that all active participants in the proceeding have reached a settlement in principle that resolves all issues set for hearing, and the procedural schedule for the hearing was suspended pending finalization of the settlement agreement. On March 17, 2008, TrAIL Company filed a settlement agreement with FERC for the formula rate treatment for the proposed TrAIL line and other transmission-related projects. The settlement agreement, which requires FERC approval, provides for (a) an incentive return on equity of 12.7% for the TrAIL project

11

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

and the static VAR compensator installed at the Black Oak Substation and (b) a return on equity of 11.7% for any other projects TrAIL Company may undertake for which no incentive return on equity has been requested. The Administrative Law Judge certified the settlement to FERC on April 25, 2008.

     See Note 5, “Rates and Regulation” for additional information.

Potomac-Appalachian Transmission Highline

     In April 2007, Allegheny announced plans to construct PATH, a 290-mile, high-voltage transmission line project. PJM directed the construction of PATH in June 2007. In September 2007, Allegheny entered into a joint venture agreement with a subsidiary of AEP to construct PATH. The joint venture, PATH, LLC, is a series limited liability company. The “West Virginia Series” is owned equally by Allegheny and AEP, and through an operating subsidiary, will build, own and operate approximately 244 miles of 765 kV transmission line from AEP’s Amos substation near St. Albans, West Virginia to Allegheny’s Bedington substation near Martinsburg, West Virginia. The “Allegheny Series” is 100% owned by Allegheny and, through an operating subsidiary, will build, own and operate approximately 46 miles of twin-circuit 500 kV lines from Bedington to a new substation near Kemptown, Maryland, to be built and owned by Allegheny.

     On December 28, 2007, PATH, LLC submitted, on behalf of PATH West Virginia Transmission Company, LLC and PATH Allegheny Transmission Company, LLC, a filing to FERC under Section 205 of the Federal Power Act to implement a formula tariff rate 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 that accepted the rate filing made by PATH, LLC. In accepting the filing, among other things, FERC granted PATH, LLC (a) a return on equity of 14.3%, (b) recovery of a return on 100% of prudently incurred construction work in progress prior to the project’s in-service date, (c) recovery of all costs incurred prior to the time the rates go into effect and (d) authorization to recover all prudently incurred development and construction costs if the PATH project is abandoned as a result of factors beyond the control of PATH, LLC or its owners. In addition, the order set the cost of service formula for hearing and settlement procedures.

     The accounts of PATH, LLC and its operating subsidiaries are included in Allegheny’s Consolidated Financial Statements, in accordance with the provisions of FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities.”

NOTE 4: ACQUISITION OF MINORITY INTEREST IN AE SUPPLY

     As discussed in Note 16, “Commitments and Contingencies,” on January 25, 2008, Allegheny and Merrill Lynch entered into a settlement agreement that resolved litigation between the two parties. The case related to a dispute regarding Allegheny’s purchase of Merrill Lynch’s energy marketing and trading business in 2001. As a result of this settlement, Allegheny reversed its previously recorded accrued interest liability of $54.7 million through a credit to interest expense during the fourth quarter of 2007.

     On March 31, 2008, in accordance with the settlement agreement, Allegheny made a cash payment to Merrill Lynch in the amount of $50 million, and Merrill Lynch conveyed to Allegheny its approximately 1.5% equity interest in AE Supply. Allegheny recorded the acquisition of Merrill Lynch’s non-controlling interest in AE Supply using the purchase method of accounting in accordance with SFAS No. 141, “Business Combinations.” Under the purchase method of accounting, the purchase price was allocated to individual assets acquired and liabilities assumed based on the fair values of such assets and liabilities. The purchase accounting adjustments will be amortized against income over the estimated lives of the individual assets and liabilities, ranging from 3 years to 30 years. No goodwill was recorded. When finalized, the effects of the purchase accounting adjustments are not expected to materially impact Allegheny’s financial results for any period. Allegheny ceased the recognition of minority interest in the net income of AE Supply as of January 1, 2008.

12

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

NOTE 5: RATES AND REGULATION

West Virginia

     On May 22, 2007, the West Virginia Public Service Commission (the “West Virginia PSC”) issued a rate order (the “West Virginia Rate Order”) effective May 23, 2007 that will reduce Allegheny’s annual revenues by approximately $6 million and will decrease annual depreciation expense by approximately $16 million, resulting in an annual net pre-tax benefit of approximately $10 million. The $6 million revenue decrease is comprised of a decrease in base rates of approximately $132 million and an increase in revenues related to fuel and purchased power costs of approximately $126 million. The West Virginia Rate Order established an annual Expanded Net Energy Cost (“ENEC”) method of recovering net power supply costs, including fuel costs, purchased power costs and other related expenses, net of related revenue. Under the ENEC, actual costs and revenues are tracked for under and/or over recoveries, and new ENEC rate filings will be made on an annual basis. Any under and/or over recovery of costs, net of related revenues, is deferred as a regulatory asset or regulatory liability, for subsequent recovery and/or refund, with the corresponding impact on the Consolidated Statements of Income reflected within “Deferred energy costs, net.”

     On March 30, 2007, TrAIL Company filed an application with the West Virginia PSC for authorization to construct the TrAIL project in West Virginia. An evidentiary hearing on this matter was held during a two-week period in January 2008. On April 15, 2008, TrAIL Company filed with the West Virginia PSC a settlement regarding the TrAIL project among TrAIL Company, the staff of the West Virginia PSC, the Consumer Advocate Division of the West Virginia PSC and the West Virginia Energy Users Group (the “WVEUG”). The settlement provides that:

• Monongahela, Potomac Edison and TrAIL Company will locate 100 to 150 managerial, professional, technical and administrative jobs in north-central West Virginia no later than the in-service date of the West Virginia segment of TrAIL, which will involve construction of a new facility in the state with an estimated cost of approximately $50 million;

• Monongahela and Potomac Edison will not seek recovery in West Virginia of transmission charges associated with TrAIL for the period from January 2007 through the latest of December 31, 2013, the date which is two and one-half years following the in-service date of TrAIL’s West Virginia segment or the month in which Allegheny’s new West Virginia facility is placed in service;

• TrAIL Company will contribute $5 million to fund energy conservation programs and assistance plans for low-income customers in West Virginia over a five year period;

• Monongahela and Potomac Edison will provide rate relief in the form of credits totaling approximately $5.7 million in the aggregate to industrial customers in West Virginia in 2010 and 2011;

• The West Virginia segment of TrAIL should follow the route set forth in TrAIL Company’s application to the West Virginia PSC, except for certain modifications south of Morgantown, West Virginia, which will more closely follow existing transmission corridors;

• The Consumer Advocate, the staff of the West Virginia PSC and the WVEUG will support the need for the portion of TrAIL that is proposed to run from Allegheny’s 502 Junction in Greene County, Pennsylvania through West Virginia to Loudoun, Virginia; and

• Each landowner on the right-of-way will be provided with transmission credits that can be used for up to 12,000 kWh of power per year.

     In addition, TrAIL Company has accepted, with certain modifications, many of the West Virginia PSC staff’s proposed conditions. For example, TrAIL Company will provide West Virginia homeowners the option to sell to TrAIL Company residences that are located within 400 feet of TrAIL and will follow various proposed guidelines pertaining to pre-construction and construction activities associated with TrAIL. See Note 3, “Transmission Expansion Projects” for additional information.

     Although the West Virginia PSC is otherwise required by statute to issue an order regarding this matter by May 5, 2008, TrAIL Company filed a motion with the West Virginia PSC to toll the statutory decision deadline until June 2, 2008. On April 17, 2008, the West Virginia PSC issued an order requesting that TrAIL Company file a revised motion requesting that the West Virginia PSC toll the statutory decision deadline until August 2, 2008, which TrAIL Company filed with the West Virginia PSC on April 18, 2008. The

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ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

West Virginia PSC issued an order tolling the statutory deadline to August 2, 2008. A hearing on the settlement is expected to occur during the last week of May 2008.

Virginia

     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, in each case, AE Supply was the successful bidder with respect to a substantial portion of these requirements.

     As amended, the Restructuring Act, which initially capped generation rates until July 1, 2007, currently provides for generation rate caps through December 31, 2008. The market prices at which Potomac Edison now purchases power are, and since the expiration in 2007 of its power purchase agreement with AE Supply have been, significantly higher than the capped generation rates prevailing under the Restructuring Act that Potomac Edison may charge its Virginia retail customers.

     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. Additionally, Potomac Edison filed a Motion for Interim Rates with the Virginia SCC on May 10, 2007. In connection with Potomac Edison’s application, the Virginia SCC requested briefing on the “continuing legal viability” of a Memorandum of Understanding (the “MOU”) that Potomac Edison entered into with the Staff of the Virginia PSC 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. 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.

     On July 6, 2007, Potomac Edison filed with the Virginia SCC a Motion for Suspension of Order and Motion for Interim Rates, which the Virginia SCC denied on August 7, 2007. On July 26, 2007, Potomac Edison filed an appeal of the decision denying Potomac Edison’s application and motion to establish interim rates to the Virginia Supreme Court and also asked the Virginia Supreme Court for relief pending appeal. The Court denied Potomac Edison’s motions and set the matter for review in the ordinary course.

     On September 11, 2007, Potomac Edison filed a new application for rate recovery of purchased power costs for load above 367 MW with the Virginia SCC, while continuing to pursue its appeal for full cost recovery. The new application requested an increase of approximately $42.3 million (as revised) in Potomac Edison’s Virginia retail electric rates to allow Potomac Edison to recover a portion of its projected purchased power costs arising from the provision of service to its Virginia jurisdictional customers from July 1, 2007 through June 30, 2008. On December 20, 2007, the Virginia SCC issued an order granting only partial recovery of increased purchased power costs.

     The Virginia SCC’s order:

• granted a rate adjustment effective immediately that would permit Potomac Edison to collect an additional $9.5 million (pre-tax) on an annualized basis through June 30, 2008, a substantially lower amount than the $42.3 million requested;

• directed Potomac Edison to implement deferred accounting effective immediately with respect to the over- or under-recovery of the increased purchase power costs approved in the order; and

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ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

• directed Potomac Edison to file an application with the Virginia SCC on or before July 1, 2008, for proposed recovery of purchased power costs for the 12-month period beginning July 1, 2008, including for treatment of any over- or under-recovery incurred for service rendered prior to July 1, 2008 and whether and how its proposed recovery of purchased power costs for service rendered on and after January 1, 2009 would be consistent with the MOU and certain amendments to the Restructuring Act.

     Potomac Edison appealed the December 20, 2007 order on January 16, 2008.

     On April 11, 2008, the Virginia Supreme Court denied Potomac Edison’s appeal of the Virginia SCC’s June 2007 order, on the ground that the statute that the Virginia SCC cited as controlling did not require the Virginia SCC to grant the relief requested, but also stated that recovery on other grounds was not being addressed. Potomac Edison’s appeal of the December 20, 2007 order is still pending.

     On April 30, 2008, Potomac Edison filed an application with the Virginia SCC to recover at least $73 million, and as much as $132.9 million, of purchased power costs for service rendered to its Virginia jurisdictional customers from July 1, 2008 through June 30, 2009. Absent rate relief, Potomac Edison currently estimates that it will incur a shortfall of approximately $132.9 million for the provision of generation service in Virginia for the period from July 1, 2008 through June 30, 2009. As of March 31, 2008, Potomac Edison had total stockholders’ equity of approximately $419 million .

     As detailed in Potomac Edison’s April 2008 application to the Virginia SCC, Potomac Edison is currently experiencing substantial, unsustainable negative cash flows as a result of the Virginia SCC’s denial of recovery of the large majority of the increase in Potomac Edison’s purchased power costs that began on July 1, 2007. Although Potomac Edison believes that the MOU will no longer be in effect, and that it thus should be permitted to recover all of its purchased power costs as of January 1, 2009, the Virginia SCC may determine otherwise. As a result, there can be no assurance that Potomac Edison will be able to recover the cost of power purchases in excess of the capped generation rates that it is currently permitted to charge its Virginia customers in a timely fashion or at all. The inability to recover such costs has had and, absent a change in current circumstances, is expected to continue to have a materially negative effect on Potomac Edison’s cash flow, results of operations, financial condition and overall business. Based on its current customer rates, Potomac Edison’s revenues are not sufficient to fund its ongoing operations and maintenance costs and necessary capital expenditures. Furthermore, absent a change in circumstances, it is anticipated that the under-recovery to which Potomac Edison’s Virginia operations are subject will exhaust its capacity to borrow additional funds to support its operations by the third quarter of 2009. Potomac Edison is requesting further rate relief, as noted above. In addition, absent adequate rate relief, Potomac Edison may postpone or eliminate some or all planned capital and other expenditures. However, such cost saving measures would not be sufficient to fully address Potomac Edison’s negative cash flows described above and Potomac Edison is, therefore, evaluating other alternatives available to it in response to the unsustainable negative impact of these regulatory decisions.

15

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

NOTE 6: REGULATORY ASSETS AND LIABILITIES

     Certain of Allegheny’s regulated utility operations are subject to the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”. Regulatory assets represent probable future revenues associated with currently incurred costs that are expected to be recovered in the future from customers through the rate-making process. Regulatory liabilities generally represent probable future reductions in revenues associated with amounts that are to be credited or refunded to customers through the rate-making process. Regulatory assets and regulatory liabilities reflected in the Consolidated Balance Sheets related to:

	March 31,		December 31,
(In millions)	2008		2007
Regulatory assets, including current portion:
Income taxes (a)(b)	$	232.1	$	251.4
Pension benefits and postretirement benefits other than pensions (a)(c)		199.4		202.7
Pennsylvania stranded cost recovery		7.1		17.6
Pennsylvania Competitive Transition Charge (“CTC”) reconciliation		120.5		117.7
Unamortized loss on reacquired debt (a)(d)		34.2		35.3
Deferred ENEC charges (e)(f)		3.6		9.4
Other (g)		40.5		40.8
Subtotal		637.4		674.9
Regulatory liabilities, including current portion:
Net asset removal costs		402.0		396.4
Income taxes		36.3		36.8
SO2 allowances		13.7		13.8
Fort Martin scrubber project—environmental control surcharge (e)		23.8		33.4
Maryland rate stabilization and transition plan surcharge		23.3		6.9
Other		6.8		1.6
Subtotal		505.9		488.9
Net regulatory assets	$	131.5	$	186.0

(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)	Amount is being recovered over various periods through 2025, based upon the maturities of reacquired debt.
(e)	Interest earnings on the Fort Martin scrubber project escrow fund represented an offset to regulatory assets at March 31, 2008 and a regulatory liability at December 31, 2007. By order dated January 14, 2008, the West Virginia PSC approved a modification to the ENEC directing the interest earnings to be applied to the ENEC.
(f)	Includes certain amounts that do not earn a return with recovery periods up to one year.
(g)	Includes certain amounts that do not earn a return with recovery periods through 2027.

16

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

NOTE 7: 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.

     The following table reconciles income tax expense calculated by applying the federal statutory income tax rate of 35% to “income before income taxes and minority interest” to “income tax expense”:

	Three Months Ended March 31,
	2008						2007
(In millions, except percent)	Amount			%			Amount			%
Income before income taxes and minority interest	$	194.6					$	181.5
Income tax expense calculated at the federal statutory rate of 35%		68.1			35.0			63.5			35.0
Increases (reductions) resulting from:
Rate-making effects of depreciation differences		2.0			1.0			1.9			1.0
Plant removal costs		(1.4	)		(0.7	)		(0.6	)		(0.3	)
State income tax, net of federal income tax benefit		5.8			3.0			5.3			2.9
Amortization of deferred investment tax credits		(0.8	)		(0.4	)		(0.9	)		(0.5	)
March 2008 West Virginia state income tax rate change		(6.7	)		(3.4	)		—			—
January 2007 West Virginia state income tax rate change		—			—			(0.7	)		(0.4	)
Changes in tax reserves related to uncertain tax positions and resolution of audit issues		(7.6	)		(3.9	)		2.6			1.4
Other, net		(1.1	)		(0.6	)		0.3			0.2
Income tax expense	$	58.3			30.0		$	71.4			39.3

     On March 31, 2008, the state of West Virginia enacted a change in its income tax law that implemented combined reporting along with a reduction in its income tax rate that phases-in during 2009 through 2014. During the three months ended March 31, 2008, Allegheny recognized a benefit of approximately $6.7 million representing an adjustment of its deferred tax assets and liabilities to reflect the effects of the reduction in tax rates enacted by West Virginia.

     Allegheny records certain reserves on its books related to uncertain tax positions. The IRS is currently auditing Allegheny’s income tax returns for the tax years 1998 through 2003. Allegheny changed its method of applying the inventory capitalization rules from its traditional method to the simplified service cost method during the audit period. The IRS had proposed adjustments related to the change in method that were strictly timing in nature. During the three months ended March 31, 2008, Allegheny came to a tentative settlement with the IRS on this matter which resulted in a benefit of approximately $6.1 million.

17

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

NOTE 8: CAPITALIZATION AND SHORT-TERM DEBT

Common Stock

     On March 24, 2008, AE paid a cash dividend of $0.15 per share to shareholders of record on March 10, 2008.

Debt

     Outstanding debt and scheduled debt repayments at March 31, 2008 were as follows:

(In millions)	2008			2009			2010			2011			2012			Thereafter			Total
AE Supply:
Medium-Term Notes	$	—		$	—		$	—		$	400.0		$	650.0		$	—		$	1,050.0
AE Supply Credit Facility:
Term Loan		—			—			—			447.0			—			—			447.0
Revolving Loan		—			—			—			125.0			—			—			125.0
Pollution Control Bonds		—			—			—			—			1.3			267.2			268.5
Debentures-AGC		—			—			—			—			—			100.0			100.0
Total AE Supply	$	—		$	—		$	—		$	972.0		$	651.3		$	367.2		$	1,990.5
Monongahela:
Environmental Control Bonds (a)	$	5.5		$	10.6		$	11.1		$	11.6		$	12.2		$	284.0		$	335.0
First Mortgage Bonds		—			—			—			—			—			340.0			340.0
Medium-Term Notes		—			—			110.0			—			—			—			110.0
Pollution Control Bonds		—			—			—			—			6.0			64.3			70.3
Total Monongahela	$	5.5		$	10.6		$	121.1		$	11.6		$	18.2		$	688.3		$	855.3
West Penn:
First Mortgage Bonds	$	—		$	—		$	—		$	—		$	—		$	420.0		$	420.0
Transition Bonds (a)		55.0			79.8			16.0			—			—			—			150.8
Medium-Term Notes		—			—			—			—			80.0			—			80.0
Total West Penn	$	55.0		$	79.8		$	16.0		$	—		$	80.0		$	420.0		$	650.8
Potomac Edison:
First Mortgage Bonds	$	—		$	—		$	—		$	—		$	—		$	420.0		$	420.0
Environmental Control Bonds (a)		1.9			3.5			3.7			3.9			4.1			94.8			111.9
Total Potomac Edison	$	1.9		$	3.5		$	3.7		$	3.9		$	4.1		$	514.8		$	531.9
TrAIL Company:
Short-Term Promissory Note	$	10.0		$	—		$	—		$	—		$	—		$	—		$	10.0
Total TrAIL	$	10.0		$	—		$	—		$	—		$	—		$	—		$	10.0
Unamortized debt discounts		(1.1	)		(1.5	)		(1.3	)		(1.0	)		(0.6	)		(1.9	)		(7.4	)
Eliminations (b)		—			—			—			—			(1.3	)		(13.1	)		(14.4	)
Total consolidated debt	$	71.3		$	92.4		$	139.5		$	986.5		$	751.7		$	1,975.3		$	4,016.7

(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.

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

18

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

2008 Debt Activity

     Issuances and repayments of indebtedness, during the three months ended March 31, 2008 were as follows:

(In millions)	Issuances		Repayments
Monongahela:
Environmental Control Bonds	$	—	$	9.4
Potomac Edison:
Environmental Control Bonds		—		2.9
West Penn:
Transition Bonds		1.4		22.0
AE Supply:
AE Supply Credit Facility:
Term Loan		—		125.0
Revolving Loan		125.0		—
Consolidated Total	$	126.4	$	159.3

NOTE 9: BUSINESS SEGMENTS

     Allegheny manages and evaluates its operations in two business segments, the Delivery and Services segment and the Generation and Marketing segment. Business segment information for Allegheny is summarized below. Significant transactions between reportable segments are shown as eliminations to reconcile the segment information to consolidated amounts. The majority of the eliminations relate to power sold by the Generation and Marketing segment to the Delivery and Services segment.

	Three Months Ended March 31, 2008
	Delivery		Generation
	and		and
(In millions)	Services		Marketing		Eliminations			Total
External operating revenues	$	772.4	$	102.6	$	—		$	875.0
Internal operating revenues		2.1		465.6		(467.7	)		—
Total operating revenues	$	774.5	$	568.2	$	(467.7	)	$	875.0
Depreciation	$	37.4	$	27.5	$	—		$	64.9
Amortization	$	5.3	$	0.1	$	—		$	5.4
Operating income	$	65.2	$	181.6	$	—		$	246.8
Interest expense	$	21.9	$	37.9	$	(1.4	)	$	58.4
Income tax expense	$	12.8	$	45.5	$	—		$	58.3
Net income	$	33.7	$	102.4	$	—		$	136.1

	Three Months Ended March 31, 2007
	Delivery		Generation
	and		and
(In millions)	Services		Marketing		Eliminations			Total
External operating revenues	$	754.8	$	92.8	$	—		$	847.6
Internal operating revenues		3.1		431.7		(434.8	)		—
Total operating revenues	$	757.9	$	524.5	$	(434.8	)	$	847.6
Depreciation	$	35.3	$	31.8	$	—		$	67.1
Amortization	$	4.9	$	—	$	—		$	4.9
Operating income	$	96.6	$	138.6	$	—		$	235.2
Interest expense	$	18.4	$	42.0	$	(1.2	)	$	59.2
Income tax expense	$	35.5	$	35.9	$	—		$	71.4
Net income	$	45.4	$	64.3	$	—		$	109.7

19

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

NOTE 10: DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

     Effective January 1, 2008, Allegheny adopted SFAS 157 for assets and liabilities measured at fair value on a recurring basis. The adoption of SFAS 157 did not have a material impact on Allegheny’s fair value measurements. SFAS 157 establishes a new framework for measuring fair value and expands related disclosures. Broadly, the SFAS 157 framework requires fair value to be determined based on the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants. SFAS 157 clarifies that fair value should be based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties and the impact of credit enhancements, but also the impact of Allegheny’s own nonperformance risk on its liabilities. The standard establishes a fair value hierarchy based on whether the inputs to valuation techniques are observable or unobservable. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect the company’s own assumptions about the assumptions that market participants would use. The fair value hierarchy includes three levels of inputs that may be used to measure fair value as described below.

Level 1 — Quoted prices for identical instruments in active markets.

Level 2 — Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations for which all significant inputs are observable market data.

Level 3 — Unobservable inputs significant to the fair value measurement supported by little or no market activity.

     In some cases, the inputs used to measure fair value may meet the definition of more than one level of fair value hierarchy. The lowest level input that is significant to the fair value measurement in its totality determines the applicable level in the fair value hierarchy.

     Allegheny uses closing prices to value derivatives that are traded on exchanges (Level 1). Derivatives included in Level 2 are valued using a pricing model with inputs that are observable in the market, such as quoted forward prices of commodities, or that can be derived from or corroborated by observable market data. Derivative assets and liabilities included in Level 2 primarily represent commodity forward contracts and interest rate swaps. Derivative assets included in Level 3 represent financial transmission rights (“FTRs”) and are valued using an internal model based on data from annual and monthly FTR auctions.

     During the three months ended March 31, 2008, Allegheny changed the manner in which it estimates and presents in its financial statements the fair value of FTRs. Allegheny acquired its FTRs in an annual PJM auction through a self-scheduling process involving the use of auction revenue rights (“ARRs”) allocated to PJM members. During the three months ended March 31, 2008, Allegheny recorded an unrealized gain in the amount of $4.4 million, before income tax effect, representing an increase in the estimated fair value of its FTRs. Allegheny’s Consolidated Balance Sheet at March 31, 2008 includes a current FTR obligation to PJM of $38.3 million, net of FTR derivative assets in the amount of $51.4 million. In addition, the Consolidated Balance Sheet includes an ARR-related asset of $44.8 million at March 31, 2008.

20

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

     Other than derivative assets and derivative liabilities, Allegheny had no significant financial or non-financial assets or liabilities recognized or disclosed at fair value in its financial statements on a recurring basis at March 31, 2008. The recorded fair values of derivatives at March 31, 2008 were as follows:

	March 31, 2008
(In millions)	Current			Long-term
Derivative assets:
Power transaction cash flow hedges	$	(0.2	)	$	—
Power transaction mark-to-market		5.5			—
FTRs (a)		51.4			—
Total derivative assets		56.7			—
Cash collateral		—			—
Total derivative assets, net of cash collateral		56.7			—
Derivative liabilities:
Interest rate swaps		(6.0	)		(10.7	)
Power transaction cash flow hedges		(65.6	)		(7.2	)
Power transaction mark-to-market		(5.5	)		(3.5	)
Total derivative liabilities		(77.1	)		(21.4	)
Cash collateral		0.2			—
Total derivative liabilities, net of cash collateral		(76.9	)		(21.4	)
Net derivative assets and liabilities, net of cash collateral	$	(20.2	)	$	(21.4	)

(a) The FTR derivative assets have been netted against the related FTR obligation of $89.7 million included in other current liabilities in the Consolidated Balance Sheet.

     The following table disaggregates the net fair values of derivative assets and liabilities, based on their level within the fair value hierarchy at March 31, 2008. The table excludes derivatives that have been designated as normal purchases or normal sales under SFAS 133.

(In millions)	Level 1			Level 2			Level 3		Total
Derivative assets	$	0.3		$	5.0		$	51.4	$	56.7
Derivative liabilities		(1.2	)		(97.3	)		—		(98.5	)
Net derivative asset (liability)	$	(0.9	)	$	(92.3	)	$	51.4	$	(41.8	)

     The following table shows the expected settlement year for derivative assets and liabilities outstanding at March 31, 2008:

(In millions)	2008			2009			2010			2011			2012		Total
Level 1	$	(2.0	)	$	1.1		$	—		$	—		$	—	$	(0.9	)
Level 2		(69.4	)		(15.7	)		(5.3	)		(1.9	)		—		(92.3	)
Level 3		51.4			—			—			—			—		51.4
Net derivative liability	$	(20.0	)	$	(14.6	)	$	(5.3	)	$	(1.9	)	$	—	$	(41.8	)

21

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

     The following table provides a reconciliation of the beginning and ending balance of FTR derivative assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the period.

(In millions)
Balance at January 1, 2008	$	150.0
Total gains or losses (realized/unrealized):
Included in earnings		38.3
Included in regulatory assets or liabilities		18.3
Purchases, issuances, and settlements		(155.2	)
Transfers in and/or out of Level 3		—
Balance at March 31, 2008	$	51.4
Amount of total gains (losses) included in earnings attributable to the change in unrealized gains (losses) related to Level 3 assets held at March 31, 2008	$	4.4

     Realized / unrealized gains and losses of $38.3 million included in earnings for Level 3 assets measured at fair value during the three months ended March 31, 2008 were reported in operating revenues in the Consolidated Statement of Income.

     Allegheny believes that any analysis of its derivative assets classified as Level 3 (FTRs) should consider that Allegheny’s FTRs generally represent an economic hedge of congestion charges that are not included in the above table and that the timing of recognition of gains or losses on FTRs could differ from the timing of incurred congestion charges.

     The following table includes the activity in accumulated other comprehensive income (loss) for derivative assets and liabilities that qualified as cash flow hedges. These cash flow hedges expire at various dates through 2010. Accumulated other comprehensive loss in the amount of $38.5 million is expected to be reclassified to earnings over the next twelve months. The ineffective portion of the power transaction hedges for the three months ended March 31, 2008 and 2007 was $3.0 million and $0.2 million, respectively and was reflected as a charge to operating revenues.

(In millions, net of tax)
Balance at January 1, 2008	$	(4.3	)
Changes in fair value		(43.8	)
Reclassifications from accumulated other comprehensive loss to net earnings		5.0
Balance at March 31, 2008	$	(43.1	)

22

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

NOTE 11: STOCK-BASED COMPENSATION

     Allegheny records compensation expense for share-based payments to employees and non-employee directors, including grants of employee stock options and stock units, over the requisite service period based on their estimated fair value on the date of grant.

     The following table summarizes stock-based compensation expense:

	Three Months Ended
	March 31,
(In millions)	2008		2007
Stock options	$	2.1	$	1.6
Stock units		0.3		0.8
Other		0.3		0.4
Stock-based compensation expense included in operations and maintenance expense		2.7		2.8
Income tax benefit		1.1		1.1
Total stock-based compensation expense, net of tax	$	1.6	$	1.7

     No stock-based compensation cost was capitalized during the three months ended March 31, 2008 and 2007.

Stock Options

     Effective January 1, 2006, Allegheny records compensation expense for employee stock options based on the estimated fair value of the options on the date of grant using the Black-Scholes option-pricing model with the assumptions included in the table below. The annual risk-free interest rate was based on the United States Treasury yield curve at the time of the grant for a period equal to the expected term of the options granted. The expected term of the 2008 stock option grants was calculated in accordance with Staff Accounting Bulletin 107, Share-Based Payment, using the “simplified” method. The expected annual dividend yield assumption was based on AE’s current dividend rate. The expected volatility was based on both historical stock volatility and the volatility levels implied on the grant date by actively traded option contracts on Allegheny’s common stock. The following weighted-average assumptions were used to estimate the fair value of options granted during the first quarter of 2008 and 2007.

	2008			2007
Annual risk-free interest rate		3.14	%		4.60	%
Expected term of the option (in years)		6.00			5.75
Expected annual dividend yield		1.11	%		—	%
Expected stock price volatility		27.39	%		24.17	%
Grant date fair value per stock option	$	15.50		$	16.34

     Stock-based compensation expense recognized in the Consolidated Statement of Income for the first quarter of 2008 in operations and maintenance expense was based on awards ultimately expected to vest, using an estimated annual forfeiture rate of 5%.

     Stock option activity for the three months ended March 31, 2008 was as follows:

						Aggregate
				Weighted-		Intrinsic
	Number of			Average		Value (a)
	Stock Options			Exercise Price		(in millions)
Outstanding at December 31, 2007		3,191,409		$	16.10
Granted		547,852		$	53.56
Exercised		(606,902	)	$	13.60
Outstanding at March 31, 2008		3,132,359		$	23.14	$	87.5
Exercisable at March 31, 2008		1,539,188		$	16.29	$	52.7

(a) Represents the total pre-tax intrinsic value based on stock options with an exercise price less than AE’s closing stock price of $50.50 on March 31, 2008.

23

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

     The grant date fair value of stock options granted during the three months ended March 31, 2008 and 2007 was $8.5 million and $0.2 million, respectively.

     The total pre-tax intrinsic value of stock options exercised during the three months ended March 31, 2008 and 2007 was $25.0 million and $3.3 million, respectively, representing the difference between the market value of Allegheny’s stock at exercise and the exercise price of the options. Cash received by Allegheny from option exercises totaled $8.3 million and $4.6 million for the three months ended March 31, 2008 and 2007, respectively. Allegheny issued new shares of its common stock to satisfy these stock option exercises. There was no cash tax benefit realized from tax deductions on stock options exercised during the first quarters of 2008 and 2007 because of existing tax net operating loss carryforwards.

     As of March 31, 2008, there was approximately $14.8 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 1.3 years.

     Allegheny records windfall tax benefits associated with share-based awards directly to stockholders’ equity only when realized. Accordingly, deferred tax assets have not been recognized for net operating loss carryforwards resulting from windfall tax benefits subsequent to January 1, 2006.

Stock Units

     Stock unit activity for the three months ended March 31, 2008 was as follows:

				Weighted-		Aggregate
				Average		Intrinsic
	Number of			Grant Date		Value (a)
	Stock Units			Fair Value		(in millions)
Outstanding at December 31, 2007		451,055		$	15.40
Units converted into common shares		(54	)	$	60.66
Dividend on unvested units		1,385		$	48.84
Outstanding at March 31, 2008		452,386		$	15.50	$	22.8

(a) Represents the total pre-tax intrinsic value based on stock units outstanding multiplied by AE’s closing stock price of $50.50 on March 31, 2008.

     There were no stock units that were vested and convertible into common shares at March 31, 2008.

     Allegheny 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.

     As of March 31, 2008, there was approximately $0.3 million of unrecognized compensation cost related to non-vested outstanding stock units, which is expected to be recognized over a weighted average period of approximately three months.

Non-Employee Director Stock Plan

     Non-employee director stock plan share activity for the three months ended March 31, 2008 was as follows:

	Number of
	Shares
Shares earned but not issued at December 31, 2007		65,177
Granted		5,346
Issued		(16,267	)
Dividends on earned but not issued shares		154
Shares earned but not issued at March 31, 2008		54,410

24

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

NOTE 12: PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

     Substantially all of Allegheny’s employees, including officers, are employed by AESC and are covered by a noncontributory, defined benefit pension plan. Allegheny also maintains the Supplemental Executive Retirement Plan (“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 and 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
	Pension Benefits						Than Pensions
	Three Months Ended						Three Months Ended
	March 31,						March 31,
(In millions)	2008			2007			2008			2007
Components of net periodic cost:
Service cost	$	5.3		$	5.3		$	1.1		$	1.1
Interest cost		17.1			16.2			4.3			4.3
Expected return on plan assets		(19.2	)		(18.3	)		(1.8	)		(1.7	)
Amortization of unrecognized transition obligation		0.1			0.1			1.4			1.4
Amortization of prior service cost		0.8			0.8			—			—
Recognized actuarial loss		1.8			2.7			0.2			0.6
Net periodic cost	$	5.9		$	6.8		$	5.2		$	5.7

     For the three months ended March 31, 2008 and 2007, Allegheny capitalized $3.0 million and $3.1 million, respectively, of the above net periodic cost amounts to “Construction work in progress,” a component of “Property, plant and equipment, net.”

     Allegheny contributed $35.1 million to its pension plans during the three months ended March 31, 2008, including contributions to the SERP of $0.1 million. Allegheny also contributed $4.0 million to fund its postretirement benefits plans other than pension plans during the three months ended March 31, 2008. Allegheny does not anticipate making any significant contributions to the pension plans during the remainder of 2008. Allegheny also currently anticipates that it will contribute a total amount in 2008 ranging from $15.0 million to $18.0 million to fund postretirement benefits other than pensions.

     Allegheny made Employee Stock Ownership and Savings Plan matching contributions in cash in the amount of $2.6 million and $2.3 million for the three months ended March 31, 2008 and 2007, respectively. The fair value of these contributions was expensed, less amounts capitalized in “Construction work in progress.” The capitalized portions of these costs were $0.6 million and $0.5 million for the three months ended March 31, 2008 and 2007, respectively.

25

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

NOTE 13: COMPREHENSIVE INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS

     Comprehensive income consisted of the following:

	Three Months Ended
	March 31,
(In millions)	2008			2007
Net income	$	136.1		$	109.7
Defined benefit pension and other benefit plan amortization, net of tax		0.3			1.6
Cash flow hedges, net of tax		(38.8	)		(3.3	)
Comprehensive income	$	97.6		$	108.0

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

	March 31,			December 31,
(In millions)	2008			2007
Cash flow hedges, net of tax	$	(43.1	)	$	(4.3	)
Net unrecognized pension and other benefit plan costs, net of tax		(35.6	)		(35.9	)
Total	$	(78.7	)	$	(40.2	)

26

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

NOTE 14: INCOME PER COMMON SHARE

     The following table provides a reconciliation of the numerator and the denominator for the basic and diluted earnings per common share computations:

	Three Months Ended
	March 31,
(In millions, except share and per share amounts)	2008		2007
Basic Income per Common Share:
Numerator:
Net income	$	136.1	$	109.7
Denominator:
Weighted average common shares outstanding		167,560,075		165,494,332
Basic income per common share	$	0.81	$	0.66
Diluted Income per Common Share:
Numerator:
Net income	$	136.1	$	109.7
Denominator:
Weighted average common shares outstanding		167,560,075		165,494,332
Effect of dilutive securities:
Stock options (a)		1,895,355		2,721,411
Stock units		442,194		885,176
Non-employee stock awards		51,894		54,559
Performance shares		—		25,497
Total shares		169,949,518		169,180,975
Diluted income per common share	$	0.80	$	0.65

(a) The dilutive share calculations for the three months ended March 31, 2008 and 2007 exclude 265,442 shares and 86,500 shares, respectively, relating to stock options because the inclusion of these amounts would have been antidilutive under the treasury stock method.

NOTE 15: OTHER INCOME AND EXPENSES, NET

     Other income and expenses, net, consisted of the following:

	Three Months Ended
	March 31,
(In millions)	2008			2007
Interest and dividend income	$	2.7		$	3.5
Cash received from a former trading executive’s forfeited assets		1.6			—
Tax reimbursement on contributions in aid of construction		0.9			1.1
Equity component of AFUDC		0.7			0.7
Gain on the sale of real estate		0.4			—
Premium services		0.4			0.4
Other		(0.5	)		0.2
Total	$	6.2		$	5.9

27

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

NOTE 16: COMMITMENTS AND CONTINGENCIES

Environmental Matters and Litigation

     The operations of Allegheny’s owned facilities, including its generation facilities, are subject to various federal, state and local laws, regulations and uncertainties as to air and water quality, hazardous and solid waste disposal and other environmental matters. Compliance may require Allegheny to incur substantial additional costs to modify or replace existing and proposed equipment and facilities. These costs may adversely affect the cost of Allegheny’s future operations.

     Global Climate Change.The United States relies on coal-fired plants for more than 50 percent 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 more than 95 percent 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 likely will be adopted some time in the future, and may include limits on emissions of CO₂. Thus, CO₂ legislation and regulation, if not reasonably designed, could have a significant impact on Allegheny’s operations. Allegheny can provide no assurance that limits on CO₂ emissions, if imposed, 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 being proposed 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, it could cost as much as $3,000 per kW to replace existing coal-based power generation with fossil fuel stations capable of capturing and sequestering CO₂ emissions, and recent project announcements suggest that these costs could be substantially higher. 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 seven tasks:

• developing an accurate CO₂ emissions inventory;

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

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

• following developing technologies for 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 more than 1,090 MWs of renewable hydroelectric and pumped storage power generation. Allegheny is also pursuing permits to allow for a limited use of bio-mass (wood chips and saw dust) and waste-tire derived fuel at two of its coal-based power stations in West Virginia, and is actively exploring the economics of installing additional renewable generation capacity.

28

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

     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 meets current emission standards for sulfur dioxide (“SO₂”) by using emission controls, burning low-sulfur coal, purchasing cleaned coal (which has lower sulfur content), blending low-sulfur coal with higher sulfur coal and utilizing emission allowances.

     Allegheny’s compliance with the Clean Air Act of 1990 (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 United States Environmental Protection Agency (the “EPA”) on March 10, 2005 may accelerate the need to install this equipment by phasing out a portion of currently available allowances.

     The Clean Air Act mandates annual reductions of SO₂ and created a SO₂ emission allowance trading program. 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’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities, as well as the implementation of environmental controls. Allegheny continues to evaluate and implement options for compliance; it completed the elimination of a partial Scrubber bypass at its Pleasants generation facility in December 2007, and current plans include the installation of Scrubbers at its Hatfield’s Ferry and Fort Martin generation facilities during 2009.

     Allegheny meets current emission standards for nitrogen oxides (“NOx”) by using low NOx burners, Selective Catalytic Reduction, Selective Non-Catalytic Reduction and over-fire air and optimization software, as well as through the use of emission allowances. Allegheny is currently evaluating its options for CAIR compliance.

     The NOx compliance plan functions on a system-wide basis, similar to the 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. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities.

     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 in two phases during 2010 and 2018. This rule will be implemented through state implementation plans. On February 8, 2008, the U.S. Court of Appeals for the District of Columbia vacated the rule in its entirety. The State of West Virginia subsequently suspended its rule for implementing CAMR. Pennsylvania and Maryland, however, have taken the position that their mercury rules survive this ruling.

     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.

     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 emission. On April 20, 2007, Maryland’s governor signed on to RGGI, as a result of which Maryland became the 10th state to join the Northeast regional climate change and energy efficiency program. The Healthy Air Act provides a conditional exemption for the R. Paul Smith power station for NO_X, SO₂ and mercury, 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”) will now create specific regulations for R. Paul Smith to comply with alternate NO_X, SO₂ and mercury limits. The statutory exemption does not extend to R. Paul Smith’s CO₂ emissions, and Maryland issued draft

29

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

regulations to implement RGGI requirements in December 2007, with final regulations due by December 2008. Allegheny is also assessing the reach and impact of those regulations on its Maryland operations.

     Clean Air Act Litigation.In August 2000, AE received a letter from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten electric generation facilities, which collectively include 22 generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island. AE Supply and/or Monongahela own these generation facilities. The letter requested information under Section 114 of the Clean Air Act to determine compliance with the Clean Air Act and related requirements, including potential application of the New Source Review (“NSR”) standards 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 April 2, 2007, the United States Supreme Court issued a decision in the Duke Energy case vacating the Fourth Circuit’s decision that had supported the industry’s understanding of NSR requirements and remanded the case to the lower court. The Supreme Court rejected the industry’s position on an hourly emissions standard and adopted an annual emissions standard favored by environmental groups. However, the Supreme Court did not specify a testing standard for how to calculate annual emissions and otherwise provided little clarity on whether the industry’s or the government’s interpretation of other aspects of the NSR regulations will prevail.

     On May 20, 2004, AE, AE Supply, Monongahela and West Penn received a Notice of Intent to Sue Pursuant to Clean Air Act §7604 (the “Notice”) from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP. The Notice alleged that Allegheny made major modifications to some of its West Virginia facilities in violation of the 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. It is possible that the EPA and other state authorities may join or move to transfer 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 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.

30

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

     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 filed a notice of appeal of that ruling on September 17, 2007, and the case has been fully briefed to the United States Court of Appeals for the Fifth Circuit. AE intends to vigorously defend against this action but cannot predict its 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 (Suffolk Superior Court, MA). The parties in these 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 March 31, 2008, Allegheny’s total number of claims alleging exposure to asbestos was 838 in West Virginia and three in Pennsylvania.

     Allegheny intends to vigorously pursue these matters but cannot predict their outcomes.

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 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, FERC affirmed the ALJ’s decision upholding the long-term contracts negotiated between NPC and Merrill Lynch, among others. FERC did not decide whether AE Supply, rather than Merrill Lynch, was the real party in interest. On November 10, 2003, 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 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 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. The Supreme Court agreed to hear the appeal, briefing by all parties was completed by February 6, 2008, and oral argument before the Supreme Court was held on February 19, 2008.

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

     Sierra/Nevada.On April 2, 2003, NPC and Sierra Pacific Resources, Inc. (together, “Sierra/Nevada”) initiated a lawsuit in United States District Court in Nevada against AE and AE Supply, together with Merrill Lynch & Co. and Merrill Lynch Capital Services, Inc. (together, “Merrill”). Sierra/Nevada has alleged that AE, AE Supply and Merrill engaged in actionable conduct in connection with

31

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

NPC’s application to the Public Utilities Commission of Nevada (the “Nevada PUC”) for a deferred energy accounting adjustment, which allegedly caused the Nevada PUC to disallow $180 million of NPC’s deferred energy expenses in March 2002. Sierra/Nevada has asserted claims against AE and AE Supply for: (a) wrongful hiring and supervision; (b) tortious interference with Sierra/Nevada’s contractual and prospective economic advantages; (c) conspiracy and (d) violations of the Nevada state Racketeer Influenced and Corrupt Organization (“RICO”) Act. Sierra/Nevada’s most recent complaint seeks damages in excess of $850 million, including compensatory damages, punitive damages, attorneys’ fees and treble damages. The lawsuit had been stayed since 2005, pending the outcome of certain state court proceedings in which Sierra/Nevada was seeking to reverse the Nevada PUC’s disallowance of expenses. On July 20, 2006, the Nevada Supreme Court reversed the Nevada PUC’s disallowance of the $180 million in deferred energy expenses, which formed the basis of the plaintiffs’ claims. An announcement was made on March 23, 2007 that the Nevada PUC approved two settlements relating to the requested disallowance, and those state court proceedings that were the focus of the prior stay have been closed. A scheduling order was then entered in this lawsuit that, among other things, set a trial date of July 8, 2008. AE and AE Supply filed a motion to dismiss the most recent complaint that was scheduled for oral argument on May 5, 2008.

     On April 28, 2008, Allegheny and Sierra/Nevada entered into a settlement agreement that is subject to court approval. In exchange for the payment of a non-material amount by Allegheny, Sierra/Nevada has agreed to release its claims against Allegheny and dismiss Allegheny from the lawsuit. Subsequently, Sierra/Nevada entered into a settlement agreement with Merrill Lynch. The settlements should result in the dismissal of the lawsuit in its entirety.

     Claim 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 demand to AE Supply in the amount of approximately $190 million was made in the context of mediation efforts by FERC and the United States Court of Appeals for the Ninth Circuit to resolve all outstanding claims of alleged price manipulation in the California energy markets during 2000 and 2001. No complaint has been filed against Allegheny. Allegheny believes that all issues in connection with AE Supply sales to CDWR were resolved by a settlement in 2003 and otherwise believes that the California parties’ demand is without merit.

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

     Litigation Involving Merrill Lynch.AE and AE Supply entered into an asset purchase agreement with Merrill Lynch and affiliated parties in 2001, under which AE and AE Supply purchased Merrill Lynch’s energy marketing and trading business for approximately $489 million and an equity interest in AE Supply of nearly 2%. The asset purchase agreement provided that Merrill Lynch would have the right to require AE to purchase Merrill Lynch’s equity interest in AE Supply for $115 million plus interest calculated from March 16, 2001 in the event that certain conditions were not met.

     On September 24, 2002, certain Merrill Lynch entities filed a complaint against AE in the United States District Court for the Southern District of New York, alleging that AE breached the asset purchase agreement by failing to repurchase the equity interest in AE Supply from Merrill Lynch and seeking damages in excess of $125 million. On May 29, 2003, the District Court ordered that AE and AE Supply assert their claims against Merrill Lynch, which were initially brought in New York state court, as counterclaims in Merrill Lynch’s federal court action. As a result, AE and AE Supply filed an answer and asserted affirmative defenses and counterclaims against Merrill Lynch in the District Court. The counterclaims, as amended, alleged that Merrill Lynch fraudulently induced AE and AE Supply to enter into the purchase agreement, that Merrill Lynch breached certain representations and warranties contained in the purchase agreement, that Merrill Lynch negligently misrepresented certain facts relating to the purchase agreement and that Merrill Lynch breached fiduciary duties owed to AE and AE Supply. The counterclaims sought damages in excess of $605 million, among other relief.

     On April 15, 2005, the District Court granted Merrill Lynch’s motion for summary judgment with respect to its breach of contract claim and the counterclaims for breach of fiduciary duty and negligent misrepresentation, but denied the motion with respect to the counterclaims for fraudulent inducement and breach of warranty. In May and June of 2005, the District Court conducted a trial with respect to the damages owed Merrill Lynch on its breach of contract claim and with respect to AE and AE Supply’s counterclaims for fraudulent inducement and breach of warranty. Following the trial, on July 18, 2005, the District Court entered an order: (a) ruling against AE and AE Supply on their fraudulent inducement and breach of contract claims; (b) requiring AE to pay $115 million plus interest to Merrill Lynch; and (c) requiring Merrill Lynch to return its equity interest in AE Supply to AE. On August 26, 2005, the District Court entered its final judgment in accordance with its July 18, 2005 rulings. As a result of the District Court’s ruling, AE recorded a charge during the first quarter of 2005 in the amount of $38.5 million, representing interest from March 16, 2001 through March 31, 2005.

32

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(unaudited)

     AE and AE Supply appealed the District Court’s judgment to the United States Court of Appeals for the Second Circuit. On August 31, 2007, the Second Circuit issued an opinion that reversed the award of $115 million plus interest to Merrill Lynch, reversed the ruling against AE on its counterclaims for fraudulent inducement and breach of warranty, and remanded the case back to the District Court for reconsideration of both parties’ claims consistent with the appellate court’s opinion. The Second Circuit also dismissed AE Supply as a party to the case on jurisdictional grounds.

     On January 25, 2008, AE and AE Supply entered into a settlement agreement with Merrill Lynch. Under the settlement agreement, Merrill Lynch conveyed to AE its minority equity interest in AE Supply and AE made a cash payment of $50 million to Merrill Lynch on March 31, 2008. In addition, the litigation was dismissed and the parties released their respective claims in the litigation.

     See Note 4, “Acquisition of Minority Interest in AE Supply,” for additional information regarding the settlement agreement with Merrill Lynch.

     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. Allegheny is of the belief that there are no other legal proceedings that could have a material adverse effect on its business or financial condition.

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

     The following discussion and analysis should be read in conjunction with the Financial Statements and Notes to Financial Statements included in this report, as well as the Financial Statements and Supplementary Data and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Annual Report on Form 10-K for the year ended December 31, 2007 (the “2007 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. 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. These include statements with respect to:

• regulatory matters, 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 and capacity;

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

• 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.

     Forward-looking statements involve estimates, expectations and projections and, as a result, are subject to risks and uncertainties. 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;

• volatility and changes in the price of coal, natural gas and other energy-related commodities and Allegheny’s ability to enter into and enforce supplier performance under long term fuel purchase agreements;

• changes in the weather and other natural phenomena;

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

• changes in market rules, including changes to PJM’s participant rules and tariffs;

• 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;

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• changes in access to capital markets, the availability of credit and actions of rating agencies;

• inflationary and interest rate trends;

• the effect of accounting pronouncements issued periodically by accounting standard-setting bodies and accounting issues facing Allegheny;

• 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 the caption Item 1A, “Risk Factors,” in the 2007 Annual Report on Form 10-K. Additionally, certain risk factors with respect to which material changes have occurred since their disclosure in the 2007 Annual Report on Form 10-K are discussed under Item 1A, “Risk Factors,” below.

35

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. Additional information regarding the composition and activities of these segments is included in the 2007 Annual Report on Form 10-K.

Key Indicators and Performance Factors

The Delivery and Services Segment

     Allegheny monitors 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 total MWhs sold to retail customers. Revenue per MWh sold during the three months ended March 31, 2008 and 2007 was as follows:

	Three Months Ended
	March 31,
	2008		2007
Revenue per MWh sold	$	61.83	$	60.50

     Operations and maintenance costs (“O&M”).Management closely monitors and manages O&M in absolute terms, as well as in relation to total MWhs sold. O&M per MWh sold during the three months ended March 31, 2008 and 2007 was as follows:

	Three Months Ended
	March 31,
	2008		2007
O&M per MWh sold	$	7.79	$	7.37

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

     The following table provides retail electricity sales information.

	Three Months Ended March 31,
	Normal		2008		2007		Change
Retail electricity sales (million kWhs)		N/A		11,796		11,712		0.7	%
HDD (a)		2,834		2,714		2,744		(1.1	)%

(a) Heating degree-days (“HDD”).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. HDD are most likely to impact the usage of Allegheny’s residential and commercial customers. Industrial customers are less weather sensitive. 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. Each degree of temperature below 65° Fahrenheit is counted as one heating degree-day.

36

The Generation and Marketing Segment

     Allegheny monitors the financial and operating performance of its Generation and Marketing segment using a number of indicators and performance statistics, including the following:

     kWhs generated.This is a measure of the total physical quantity of electricity generated and is monitored at the individual generating unit level, as well as by various unit groupings.

     Equivalent Availability Factor (“EAF”).The EAF measures the percentage of time that a generation unit is available to generate electricity if called upon in the marketplace. A unit’s availability is commonly less than 100%, primarily as a result of scheduled outages for planned maintenance or unplanned outages. Allegheny monitors the EAF by individual unit, as well as by various unit groupings. One such grouping is all “supercritical” units. A supercritical unit utilizes steam pressure in excess of 3,200 pounds per square inch, which enables these units to be larger and more efficient than other generation units. Fort Martin, Harrison, Hatfield’s Ferry and Pleasants are supercritical generation facilities that have supercritical units. These units generally operate at high capacity for extended periods of time.

     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 facility. Special maintenance costs include costs associated with outage-related maintenance and projects that relate to all of the generation facilities.

     The following table shows kWhs generated, excluding kWhs consumed by pumping at the Bath County, Virginia hydroelectric station, EAFs and Station O&M related to the Generation and Marketing segment:

	Three Months Ended March 31,
	2008			2007			Change
Supercritical Units:
kWhs generated (in millions)		10,363			10,748			(3.6	)%
EAF		89.2	%		89.5	%		(0.3	)%
Station O&M (in millions):
Base and operations	$	27.4		$	25.0			9.6	%
Special maintenance		11.1			10.4			6.7	%
Total Station O&M	$	38.5		$	35.4			8.8	%
All Generation Units:
kWhs generated (in millions)		12,541			13,092			(4.2	)%
EAF		88.6	%		89.1	%		(0.5	)%
Station O&M (in millions):
Base and operations	$	41.6		$	38.0			9.5	%
Special maintenance		14.1			11.4			23.7	%
Total Station O&M	$	55.7		$	49.4			12.8	%

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RESULTS OF OPERATIONS

Income Summary

	Three months ended March 31, 2008
	Delivery		Generation
	and		and
(In millions)	Services		Marketing			Eliminations			Total
Operating revenues	$	774.5	$	568.2		$	(467.7	)	$	875.0
Fuel		—		249.8			—			249.8
Purchased power and transmission		535.5		27.5			(465.6	)		97.4
Deferred energy costs, net		3.1		(13.6	)		—			(10.5	)
Operations and maintenance		91.9		78.9			(2.1	)		168.7
Depreciation and amortization		42.7		27.6			—			70.3
Taxes other than income taxes		36.1		16.4			—			52.5
Total operating expenses		709.3		386.6			(467.7	)		628.2
Operating income		65.2		181.6			—			246.8
Other income and expenses, net		3.4		4.2			(1.4	)		6.2
Interest expense		21.9		37.9			(1.4	)		58.4
Income before income taxes and minority interest		46.7		147.9			—			194.6
Income tax expense		12.8		45.5			—			58.3
Minority interest in net income of subsidiaries		0.2		—			—			0.2
Net income	$	33.7	$	102.4		$	—		$	136.1

	Three months ended March 31, 2007
	Delivery			Generation
	and			and
(In millions)	Services			Marketing		Eliminations			Total
Operating revenues	$	757.9		$	524.5	$	(434.8	)	$	847.6
Fuel		—			232.2		—			232.2
Purchased power and transmission		500.8			24.2		(431.7	)		93.3
Deferred energy costs, net		(1.5	)		—		—			(1.5	)
Operations and maintenance		86.3			77.3		(3.1	)		160.5
Depreciation and amortization		40.2			31.8		—			72.0
Taxes other than income taxes		35.5			20.4		—			55.9
Total operating expenses		661.3			385.9		(434.8	)		612.4
Operating income		96.6			138.6		—			235.2
Other income and expenses, net		3.0			4.1		(1.2	)		5.9
Interest expense and preferred dividends		18.7			42.1		(1.2	)		59.6
Income before income taxes and minority interest		80.9			100.6		—			181.5
Income tax expense		35.5			35.9		—			71.4
Minority interest in net income of subsidiaries		—			0.4		—			0.4
Net income	$	45.4		$	64.3	$	—		$	109.7

38

CONSOLIDATED RESULTS

     This section is an overview of AE’s consolidated results of operations, which are discussed in greater detail by segment under the heading “Allegheny Energy, Inc.—Discussion of Segment Results of Operations” below.

     The following table reconciles “Income before income taxes and minority interest” for the three months ended March 31, 2007 to the three months ended March 31, 2008.

(In millions)
Income before income taxes and minority interest for the three months ended March 31, 2007			$	181.5
Increase in operating revenues				27.4
Decreases (increases) in operating expenses:
Fuel	(17.6	)
Deferred energy costs, net	9.0
Operations and maintenance	(8.2	)
Other operating expenses	1.0
Operating expenses				(15.8	)
Increase in other income and expenses, net				0.3
Decrease in interest expense and preferred dividends				1.2
Income before income taxes and minority interest for the three months ended March 31, 2008			$	194.6

Operating Revenues

     Operating revenues increased $27.4 million, primarily due to the following increases and decreases:

• a $25.4 million increase, primarily resulting from higher market prices including marketing and hedging activities,

• a $16.8 million increase due to higher generation rates charged to Pennsylvania customers,

• a $6.8 million increase due to increased recoverable expenses and return on investment, primarily related to TrAIL Company,

• a $5.9 million increase due to the collection of an environmental control surcharge from the West Virginia retail customers of Monongahela and Potomac Edison, which began in April 2007,

• a $5.1 million increase due to the expiration of a Maryland customer choice credit and

• increased customer load,

• partially offset by a $27.8 million decrease due to a 4.2% decrease in total MWhs generated.

Operating Expenses

     Fuel expense increased $17.6 million, primarily due to a $17.1 million increase in coal expense. The increase in coal expense was due to an increase of $3.97 in the average price of coal per ton, partially offset by a 1.5% decrease in tons of coal consumed resulting from decreased MWhs generated at Allegheny’s coal-fired generation facilities.

     Deferred energy costs, net decreased $9.0 million, primarily due to the May 23, 2007 implementation of the Expanded Net Energy Cost (“ENEC”), which is discussed in greater detail within the Generation and Marketing segment results under “Regulated Results — Deferred Energy Costs, Net” below and the over-recovery of net costs related to the AES Warrior Run Public Utility Regulatory Policies Act of 1978 (“PURPA”) generation facility, which is discussed in greater detail in the Delivery and Services segment within “Deferred Energy Costs, Net” below.

     Operations and maintenance expense increased $8.2 million, primarily due to:

• increased labor and overhead expense, primarily due to increased employee costs related to service outages as a result of storm activity and

39

• increased contractor services expense and materials and supplies expense due to the timing of special generation maintenance and work related to service outages as a result of storm activity.

Interest Expense and Preferred Dividends

     Interest expense and preferred dividends decreased $1.2 million, primarily due to lower average debt outstanding at lower rates.

Income Tax Expense

     See Note 7, “Income Taxes,” for a reconciliation of income tax expense to income tax expense calculated at the federal statutory rate of 35%.

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DISCUSSION OF SEGMENT RESULTS OF OPERATIONS

Delivery and Services Segment Results

     The following table provides retail electricity sales information.

	Three Months Ended March 31,
	Normal		2008		2007		Change
Retail electricity sales (million kWhs)		N/A		11,796		11,712		0.7	%
HDD		2,834		2,714		2,744		(1.1	)%

Operating Revenues

     Operating revenues were as follows:

	Three Months Ended
	March 31,
(In millions)	2008		2007
Retail electric:
Generation	$	501.0	$	471.6
Transmission		44.4		43.8
Distribution		184.0		193.2
Total retail electric		729.4		708.6
Transmission services and bulk power		34.8		38.5
Other affiliated and nonaffiliated energy services		10.3		10.8
Operating revenues	$	774.5	$	757.9

     Retail electric revenues increased $20.8 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007, primarily due to:

• a $29.4 million increase in generation revenues,

• partially offset by an $8.6 million decrease in T&D revenues.

     Generation revenues increased primarily due to a $16.8 million increase resulting from higher generation rates charged to Pennsylvania customers, an $8.8 million net increase from the West Virginia Rate Order, which resulted in an increase in generation rates related to fuel and purchased power and a decrease in base rates, and increased customer load as a result of a 0.8% increase in customer growth, partially offset by the impact of weather.

     T&D revenues decreased primarily due to a $13.4 million decrease as a result of the West Virginia Rate Order, which decreased T&D base rates charged to customers, partially offset by a $5.1 million increase due to the expiration of a Maryland customer choice credit.

     Transmission services and bulk power revenues decreased by $3.7 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007, primarily due to:

• an $18.4 million decrease due to the May 2007 expiration of a fixed price power supply agreement to serve Monongahela’s former Ohio service territory,

• partially offset by:

§	an $8.3 million increase related to the Warrior Run PURPA generation facility output being sold into PJM at market prices effective January 1, 2008 and
§	a $6.8 million increase due to increased recoverable expenses and return on investment, primarily related to TrAIL Company. See Note 3, “Transmission Expansion Projects” and “Regulatory Matters” below for additional information.

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Operating Expenses

     Purchased Power and Transmission:Purchased power and transmission represents the Distribution Companies’ power purchases from other companies (primarily AE Supply and Monongahela), as well as purchases from qualifying facilities under PURPA. Purchased power and transmission consisted of the following items:

	Three Months Ended
	March 31,
(In millions)	2008		2007
Other purchased power and transmission	$	495.7	$	461.6
From PURPA generation		39.8		39.2
Purchased power and transmission	$	535.5	$	500.8

     West Penn and Potomac Edison currently have power purchase agreements with AE Supply, under which AE Supply provides West Penn and Potomac Edison with the majority of the power necessary to meet their provider-of-last-resort (“PLR”) obligations. These agreements have both fixed-price and market-based pricing components. Potomac Edison purchases the power necessary to service its West Virginia customers from Monongahela’s Generation and Marketing segment at a prorated share of overall Monongahela generation costs and associated revenue. Effective with the institution under the May 2007 West Virginia Rate Order of the ENEC method of recovering net power supply costs for Allegheny’s West Virginia service territory, the amount charged to Potomac Edison reflects the adjustment for over and/or under recovery. See Note 5, “Rates and Regulation,” and “Regulatory Matters” below for additional information.

     Other purchased power and transmission increased $34.1 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007, primarily due to:

• a $24.6 million increase due to market-based rates in Virginia beginning July 1, 2007 (see Note 5, “Rates and Regulation,” “Regulatory Matters” and “Risk Factors” below for additional information regarding market-based rates in Virginia) and

• a $16.8 million increase due to higher generation rates charged to Pennsylvania customers, which is passed on to AE Supply under the terms of a power supply agreement between West Penn and AE Supply,

• partially offset by a $9.3 million decrease due to the expiration in May 2007 of a fixed price supply agreement to serve Monongahela’s former Ohio service territory.

     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 relate to the following:

     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 Public Service Commission (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.

     Market-based Maryland Generation 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 relative to any under-recovery or over-recovery for the generation component of costs charged to Maryland commercial and industrial customers. Deferred energy costs, net relate, in part, to the recovery from or payment to customers related to these generation costs, to the extent amounts paid for generation costs differ from prices currently charged to customers.

42

     Deferred energy costs, net were as follows:

	Three Months Ended
	March 31,
(In millions)	2008			2007
AES Warrior Run PURPA generation	$	5.2		$	0.8
Market-based Maryland generation and other costs		(2.1	)		(2.3	)
Deferred energy costs, net	$	3.1		$	(1.5	)

     The $4.6 million change in deferred energy costs, net for the three months ended March 31, 2008 compared to the three months ended March 31, 2007 represents a net increase in expense, primarily related to the AES Warrior Run PURPA generation facility.

     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
	March 31,
(In millions)	2008		2007
Operations and maintenance	$	91.9	$	86.3

     Operations and maintenance expenses increased $5.6 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007, primarily due to:

• a $2.9 million increase in contractor services due to work related to service outages as a result of storm activity and

• a $2.5 million increase in uncollectible expense, primarily due to increased accounts receivable reserves resulting from higher average accounts receivable.

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

	Three Months Ended
	March 31,
(In millions)	2008		2007
Depreciation and amortization	$	42.7	$	40.2

     Depreciation and amortization expenses increased $2.5 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007, primarily due to increased depreciation resulting from net property, plant and equipment additions and the West Virginia Rate Order, which shortened the depreciable lives of certain T&D assets.

Interest Expense and Preferred Dividends

     Interest expense and preferred dividends were as follows:

	Three Months Ended
	March 31,
(In millions)	2008		2007
Interest expense and preferred dividends	$	21.9	$	18.7

     Interest expense and preferred dividends increased $3.2 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007, primarily due to the December 2007 issuance of $275 million of first mortgage bonds by West Penn.

Income Tax Expense

     The effective tax rate for the three months ended March 31, 2008 was 27.4%. Income tax expense for the three months ended March 31, 2008 was lower than the income tax expense calculated at federal statutory tax rate of 35%, primarily due to changes in tax reserves related to uncertain tax positions and resolution of audit issues that decreased the rate by 15.0%, state taxes that increased the rate by 2.8%, rate-making effects of depreciation and amortization of deferred investment tax credit that increased the rate by 2.3% and adjustments to net deferred tax assets for a West Virginia corporate net income tax rate decrease that increased the rate by 2.7%.

43

     The effective tax rate for the three months ended March 31, 2007 was 43.9%. Income tax expense for the three months ended March 31, 2007 was higher than income tax expense calculated at the federal statutory tax rate, primarily due to state income taxes, the rate-making effects of depreciation and changes in tax reserves related to uncertain tax positions and resolution of audit issues.

Transmission Expansion

     Included in the Delivery and Services segment are the results of TrAIL Company and PATH, LLC. The combined results of operations for TrAIL Company and PATH, LLC are as follows:

Income Summary

	Three Months Ended
	March 31,
(In millions)	2008		2007
Operating revenues	$	8.3	$	1.8
Operating income	$	5.7	$	0.4
Income before income taxes	$	4.7	$	0.5
Net income	$	2.6	$	0.3

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The Generation and Marketing Segment

     The Generation and Marketing segment includes Allegheny’s power generation operations. The Generation and Marketing segment is comprised of two components: an Unregulated component consisting of AE Supply and its consolidated subsidiaries and other power generation operations and a Regulated component consisting of Monongahela’s regulated West Virginia generation assets.

     The unregulated, regulated and consolidated Generation and Marketing segment income (loss) summary is as follows:

	Three months ended March 31, 2008
						Eliminations
(In millions)	Unregulated		Regulated			and other			Total
Operating revenues	$	442.5	$	137.0		$	(11.3	)	$	568.2
Fuel		180.9		68.9			—			249.8
Purchased power and transmission		9.4		29.4			(11.3	)		27.5
Deferred energy costs, net		—		(13.6	)		—			(13.6	)
Operations and maintenance		49.7		28.9			0.3			78.9
Depreciation and amortization		23.3		4.8			(0.5	)		27.6
Taxes other than income taxes		10.3		6.1			—			16.4
Total operating expenses		273.6		124.5			(11.5	)		386.6
Operating income		168.9		12.5			0.2			181.6
Other income and expenses, net		3.7		3.5			(3.0	)		4.2
Interest expense		28.2		10.0			(0.3	)		37.9
Income before income taxes and minority interest		144.4		6.0			(2.5	)		147.9
Income tax expense		44.2		2.1			(0.8	)		45.5
Minority interest in net income of subsidiaries		2.4		—			(2.4	)		—
Net income	$	97.8	$	3.9		$	0.7		$	102.4

	Three months ended March 31, 2007
						Eliminations
(In millions)	Unregulated		Regulated			and other			Total
Operating revenues	$	417.9	$	117.2		$	(10.6	)	$	524.5
Fuel		171.8		60.4			—			232.2
Purchased power and transmission		6.1		28.6			(10.5	)		24.2
Operations and maintenance		47.0		30.6			(0.3	)		77.3
Depreciation and amortization		22.4		10.0			(0.6	)		31.8
Taxes other than income taxes		13.4		7.0			—			20.4
Total operating expenses		260.7		136.6			(11.4	)		385.9
Operating income (loss)		157.2		(19.4	)		0.8			138.6
Other income and expenses, net		3.5		3.7			(3.1	)		4.1
Interest expense and preferred dividends		38.4		4.0			(0.3	)		42.1
Income (loss) before income taxes and minority interest		122.3		(19.7	)		(2.0	)		100.6
Income tax expense (benefit)		44.7		(8.8	)		—			35.9
Minority interest in net income of subsidiaries		2.5		—			(2.1	)		0.4
Net income (loss)	$	75.1	$	(10.9	)	$	0.1		$	64.3

45

Generation and Marketing Segment Results

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

     The following table provides electricity generation information, excluding kWhs consumed by pumping at the Bath County, Virginia hydroelectric station:

	Three Months Ended
	March 31,
	2008		2007		Change
kWhs generated (in millions)		12,541		13,092		(4.2	)%

     The following table reconciles “Income before income taxes and minority interest” for the three months ended March 31, 2007 to the three months ended March 31, 2008.

(In millions)
Income before income taxes and minority interest for the three months ended March 31, 2007			$	100.6
Increase in operating revenues				43.7
Decreases (increases) in operating expenses:
Fuel	(17.6	)
Deferred energy costs, net	13.6
Other operating expenses	3.3
Operating expenses				(0.7	)
Increase in other income and expenses, net				0.1
Decrease in interest expense				4.2
Income before income taxes and minority interest for the three months ended March 31, 2008			$	147.9

Operating Revenues

     Operating revenues increased $43.7 million, primarily due to:

• a $33.8 million increase in revenues from affiliates, primarily due to higher prices under a new power sales agreement between AE Supply and Potomac Edison effective July 1, 2007, as well as higher generation rates charged to Pennsylvania customers, which are passed on to AE Supply under the terms of a power supply agreement between West Penn and AE Supply and

• a $9.3 million increase in PJM revenue, net, primarily due to an increase in the weighted average “round-the-clock” price for power in Allegheny’s region of PJM, the APS Zone, from $53.88 per MWh for 2007 to $67.38 per MWh for 2008, partially offset by a 4.2% decrease in total MWhs generated.

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Operating Expenses

     Fuel expense increased $17.6 million, primarily due to a $17.1 million increase in coal expense. The increase in coal expense was due to an increase in the average price of coal of $3.97 per ton, partially offset by a 1.5% decrease in tons of coal consumed resulting from decreased MWhs generated by Allegheny’s coal-fired generation facilities.

     Deferred energy costs, net decreased $13.6 million, primarily due to the May 23, 2007 implementation of the ENEC, which is discussed in greater detail within “Regulated Results - Deferred Energy Costs, Net” below.

Interest Expense

     Interest expense decreased $4.2 million, primarily due to lower average debt outstanding as a result of payments made on the AE Supply Credit Facility and increased capitalized interest due to capital projects that were partially funded using cash from operations, partially offset by increased interest expense associated with an April 2007 issuance of environmental control bonds.

Income Tax Expense

     The effective tax rate for the three months ended March 31, 2008 was 30.8%. Income tax expense for the three months ended March 31, 2008 was lower than the income tax expense calculated at federal statutory tax rate of 35%, primarily due to an adjustment of deferred tax liabilities relating to a decrease in the West Virginia corporate net income tax rate decreasing the rate by 5.3%, changes to reserves for uncertain tax positions and resolution of audit issues that decreased the rate by 0.9%, partially offset by state taxes that increased the rate by 3.0%.

     The effective tax rate for the three months ended March 31, 2007 was 35.7%. Income tax expense for the three months ended March 31, 2007 was higher than income tax expense calculated at the federal statutory tax rate of 35%, primarily due to state income taxes, partially offset by an adjustment to deferred taxes for a West Virginia corporate net income tax rate change.

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Generation and Marketing Segment — Unregulated Results

     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
	March 31,
	2008		2007		Change
kWhs generated (in millions)		9,113		9,858		(7.6	)%

Operating Revenues

     Operating revenues were as follows:

	Three Months Ended
	March 31,
(In millions)	2008			2007
Revenue from affiliates	$	333.0		$	297.6
PJM revenue, net		114.3			117.2
Other operating revenues, including risk management and trading activities, net		(4.8	)		3.1
Unregulated revenue	$	442.5		$	417.9

     Revenue from affiliates

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

     Revenue from affiliates increased $35.4 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007, primarily due to:

• a $21.0 million increase due to a new power sales agreement in Virginia between AE Supply and Potomac Edison at market-based rates, effective July 1, 2007 and

• a $16.8 million increase due to higher generation rates charged to Pennsylvania customers, which are passed on to AE Supply under the terms of a power supply agreement between West Penn and AE Supply,

• partially offset by a $7.4 million decrease related to lower sales volumes for certain of Potomac Edison’s customers in Maryland.

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

	Three Months Ended
	March 31,
(In millions)	2008			2007
Generation sold into PJM	$	546.8		$	464.3
Power purchased from PJM		(432.5	)		(347.1	)
Net unregulated PJM revenue	$	114.3		$	117.2

     PJM revenue, net decreased $2.9 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007, primarily due to an increase in power purchased from PJM, partially offset by higher revenues from generation sold into PJM. Power purchased from PJM increased due to an increase in the market price of power, partially offset by a decrease in customer load. Revenues from generation sold into PJM were higher, primarily due to an increase in the market price of power, partially offset by a decrease in MWhs generated.

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     Other Operating Revenues:

     Other operating revenues decreased $7.9 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007, primarily due to losses on risk management and trading activities, including cash flow hedges, partially offset by derivative gains associated with financial transmission rights (“FTRs”) and emission allowance strategies. See Note 10, “Derivative Instruments and Hedging Activities,” for additional information.

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
	March 31,
(In millions)	2008		2007
Unregulated fuel	$	180.9	$	171.8

     Total fuel expense increased $9.1 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007, primarily due to a $9.0 million increase in coal expense. The increase in coal expense was due to an increase in the average price of coal of $4.29 per ton, partially offset by a 4.5% decrease in tons of coal consumed resulting from decreased MWhs generated by AE Supply’s coal-fired generation facilities.

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

	Three Months Ended
	March 31,
(In millions)	2008		2007
Unregulated purchased power and transmission	$	9.4	$	6.1

     Purchased power and transmission expenses increased $3.3 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007, primarily due to a $2.6 million charge incurred from PJM related to defaults by several member companies. Member company defaults are socialized by PJM and paid on a proportional basis by all PJM member companies.

     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
	March 31,
(In millions)	2008		2007
Unregulated operations and maintenance	$	49.7	$	47.0

     Operations and maintenance expenses increased $2.7 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007, primarily due to a $2.5 million increase in contractor services expense as a result of the timing of plant maintenance.

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     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
	March 31,
(In millions)	2008		2007
Unregulated taxes other than income taxes	$	10.3	$	13.4

     Taxes other than income taxes decreased $3.1 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007, primarily due to a tax refund.

Interest Expense

     Interest expense was as follows:

	Three Months Ended
	March 31,
(In millions)	2008		2007
Unregulated interest expense	$	28.2	$	38.4

     Interest expense decreased $10.2 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007, primarily due to lower average debt outstanding as a result of payments made on the AE Supply Credit Facility and increased capitalized interest due to capital projects that were partially funded using cash from operations.

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Generation and Marketing Segment — Regulated Results

     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
	March 31,
	2008		2007		Change
kWhs generated (in millions)		3,428		3,234		6.0	%

Operating Revenues

     Operating revenues were as follows:

	Three Months Ended
	March 31,
(In millions)	2008			2007
Revenue from affiliates	$	144.0		$	144.7
PJM revenue, net		(14.9	)		(27.1	)
Fort Martin scrubber surcharge		5.9			—
Other operating revenues		2.0			(0.4	)
Regulated revenue	$	137.0		$	117.2

     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.

     Potomac Edison purchases the power necessary to service its West Virginia customers from Monongahela at a prorated share of overall Monongahela generation costs and associated revenue. Effective with the institution of the ENEC under the 2007 West Virginia Rate Order for Allegheny’s West Virginia service territory, the amount charged to Potomac Edison reflects an adjustment for over and/or under recovery. See Note 5, “Rates and Regulation” and “Regulatory Matters” below for additional information.

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

	Three Months Ended
	March 31,
(In millions)	2008			2007
Generation sold into PJM	$	220.1		$	165.2
Power purchased from PJM		(235.0	)		(192.3	)
PJM revenue, net	$	(14.9	)	$	(27.1	)

     PJM revenue, net increased $12.2 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007, primarily due to higher revenues from generation sold into PJM, partially offset by an increase in power purchased from PJM. Revenues from generation sold into PJM were higher, primarily due to an increase in the market price of power and increased MWhs generated at Allegheny’s regulated plants. Power purchased from PJM increased due to an increase in the market price of power and increased customer load.

     Fort Martin scrubber surcharge:

     The $5.9 million Fort Martin scrubber surcharge revenue relates to an environmental control surcharge that Monongahela and Potomac Edison impose on their West Virginia retail customers following the April 2007 Fort Martin securitization financings. This surcharge is intended to recover a portion of the specific costs to construct scrubbers at Fort Martin and certain related financing costs and will result in no net income or loss. A regulatory liability is recorded for amounts billed in excess of costs incurred.

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     Other Operating Revenues:

     Other operating revenues increased $2.4 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007, primarily due to 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
	March 31,
(In millions)	2008		2007
Regulated fuel	$	68.9	$	60.4

     Total fuel expense increased $8.5 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007, primarily due to an $8.2 million increase in coal expense. The increase in coal expense was due to an increase in the average price of coal of $2.94 per ton and a 7% increase in tons of coal consumed resulting from increased MWhs generated by Monongahela’s coal-fired generation facilities.

     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 relate to the following:

     Expanded Net Energy Cost (“ENEC”).The May 22, 2007 West Virginia Rate Order re-established an annual ENEC method of recovering net power supply costs, including fuel costs, purchased power costs and other related expenses, net of related revenue. Under the ENEC, actual costs and revenues will be tracked for under and/or over recoveries, and revised ENEC rate filings will be made on an annual basis. Any under and/or over recovery of costs, net of related revenues, will be deferred, for subsequent recovery or refund, as a regulatory asset or regulatory liability with the corresponding impact on the Consolidated Statements of Income reflected within “Deferred energy costs, net.” By order dated January 14, 2008, the West Virginia PSC approved a modification to the ENEC directing interest earnings on the Fort Martin scrubber project escrow fund to be applied to the ENEC. See “Regulatory Matters” below and Note 5, “Rates and Regulation,” for additional information.

     Deferred energy costs, net were as follows:

	Three Months Ended
	March 31,
(In millions)	2008			2007
Regulated deferred energy costs, net	$	(13.6	)	$	—

     The $13.6 million change in deferred energy costs, net for the three months ended March 31, 2008 compared to the three months ended March 31, 2007 represents a net credit to expense, related to the implementation of the ENEC.

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     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
	March 31,
(In millions)	2008		2007
Regulated operations and maintenance	$	28.9	$	30.6

     Operations and maintenance expenses decreased $1.7 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007, primarily due to a $1.7 million decrease in contractor services expense as a result of a planned outage during the three months ended March 31, 2007 that did not recur during the three months ended March 31, 2008.

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

	Three Months Ended
	March 31,
(In millions)	2008		2007
Regulated depreciation and amortization	$	4.8	$	10.0

     Depreciation and amortization expenses decreased $5.2 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007, primarily due to the West Virginia Rate Order, which extended the depreciable lives of regulated generating assets.

Interest Expense

     Interest expense was as follows:

	Three Months Ended
	March 31,
(In millions)	2008		2007
Regulated interest expense	$	10.0	$	4.0

     Interest expense increased $6.0 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007, primarily due to higher average debt outstanding as a result of the April 2007 issuance of environmental control bonds.

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Liquidity and Capital Requirements

     To meet cash needs for operating expenses, the payment of interest, retirement of debt and construction programs, Allegheny has historically used internally generated funds (net cash provided by operations less common and preferred dividends) and external financings, including the sale of common and preferred stock, debt instruments, installment loans and lease arrangements. The timing and amount of external financings depend primarily upon economic and financial market conditions and Allegheny’s cash needs and capital structure objectives. The availability and cost of external financings depend upon the financial condition of the companies seeking those funds and upon market conditions.

     Allegheny manages short-term obligations 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, AE Supply and AGC 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.

     At March 31, 2008, Allegheny’s total borrowing capacity under AE’s and AE Supply’s respective revolving credit facilities and the use of this borrowing capacity were as follows:

	Total				LOCs			Available
(In millions)	Capacity		Borrowed		Issued			Capacity
AE Revolving Credit Facility	$	400.0	$	—	$	6.7	(a)	$	393.3
AE Supply Revolving Facility		400.0		125.0		—			275.0
Total	$	800.0	$	125.0	$	6.7		$	668.3

(a) This amount represents a letter of credit issued in connection with a contractual obligation of Allegheny Ventures that expires in July 2008.

     In addition to the amounts shown in the table above, AE Supply has a $3.0 million letter of credit outstanding that expires in February 2009 and was not issued under either AE’s revolving credit facility or AE Supply’s revolving credit facility.

     Allegheny’s consolidated capital structure, excluding short-term debt and minority interest, as of March 31, 2008 and December 31, 2007, was as follows:

	March 31, 2008				December 31, 2007
(In millions)	Amount		%		Amount		%
Long-term debt	$	4,006.7		60.5	$	4,039.3		61.4
Stockholders’ equity		2,618.8		39.5		2,535.4		38.6
Total	$	6,625.5		100.0	$	6,574.7		100.0

2008 Debt Activity

     Issuances and repayments of indebtedness, during the three months ended March 31, 2008 were as follows:

(In millions)	Issuances		Repayments
Monongahela:
Environmental Control Bonds	$	—	$	9.4
Potomac Edison:
Environmental Control Bonds		—		2.9
West Penn:
Transition Bonds		1.4		22.0
AE Supply:
AE Supply Credit Facility:
Term Loan		—		125.0
Revolving Loan		125.0		—
Consolidated Total	$	126.4	$	159.3

54

     See Note 8, “Capitalization and Short-Term Debt,” for additional information and details regarding Allegheny’s debt. See also Item 8, Note 11, “Capitalization and Short-Term Debt,” in the 2007 Annual Report on Form 10-K for additional details and discussion regarding debt covenants, refinancings and other debt issuances and repayments.

     AE has various obligations and commitments to make future cash payments under debt instruments, lease arrangements, fuel and transportation agreements and other contracts. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in the 2007 Annual Report on Form 10-K for additional information.

Dividends

     On March 24, 2008, AE paid a cash dividend of $0.15 per share to shareholders of record on March 10, 2008.

Off-Balance Sheet Arrangements

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

Cash Flows

Operating Activities

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

	Three Months Ended
	March 31,
(In millions)	2008			2007
Net income	$	136.1		$	109.7
Non-cash items included in income		123.9			150.5
Pension and other postretirement employee benefit plan contributions		(39.1	)		(39.3	)
Changes in certain assets and liabilities		(114.8	)		(67.1	)
Net cash provided by operating activities	$	106.1		$	153.8

     Cash flows provided by operating activities for the three months ended March 31, 2008 were $106.1 million and primarily consisted of net income of $136.1 million and non-cash charges of $123.9 million that reduced net income but did not result in the outlay of cash, partially offset by changes in certain assets and liabilities of $114.8 million and payments to Allegheny’s pension and other postretirement benefit plans of $39.1 million. The non-cash charges primarily consisted of depreciation and amortization of $70.3 million and deferred income taxes of $41.4 million. Changes in certain assets and liabilities primarily consisted of $100.2 million in changes in receivables and payables resulting from normal working capital activity and a $34.8 million increase in prepaid taxes, primarily as a result of timing differences associated with the payment of certain tax obligations.

     Cash flows provided by operating activities for the three months ended March 31, 2007 were $153.8 million and primarily consisted of net income of $109.7 million, non-cash charges of $150.5 million that reduced net income but did not result in the outlay of cash, partially offset by payments to Allegheny’s pension and other postretirement benefit plans of $39.3 million and changes in certain assets and liabilities of $67.1 million. The non-cash charges primarily consisted of depreciation and amortization of $72.0 million and deferred income taxes of $75.0 million. Changes in certain assets and liabilities primarily consisted of a $44.5 million increase in accounts receivable, net, primarily due to the timing and volume of unbilled utility revenues and a $34.5 million increase in prepaid taxes, primarily as a result of timing differences associated with the payment of certain tax obligations, partially offset by a $25.0 million increase in accounts payable due to accelerated vendor payments at the end of 2006 prior to the implementation of new enterprise resource planning software.

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Investing Activities

     Cash flows from investing activities are summarized as follows:

	Three Months Ended
	March 31,
(In millions)	2008			2007
Capital expenditures	$	(239.8	)	$	(168.4	)
Proceeds from asset sales		0.4			0.3
Purchase of Merrill Lynch interest in subsidiary		(50.0	)		—
Decrease in restricted funds		64.8			1.3
Other investments		(1.6	)		(1.0	)
Net cash used in investing activities	$	(226.2	)	$	(167.8	)

     Cash flows used in investing activities for the three months ended March 31, 2008 were $226.2 million and primarily consisted of $239.8 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 $64.8 million decrease in restricted funds, primarily due to the use of restricted funds associated with the Fort Martin scrubber project to pay for ongoing construction costs associated with that project.

     Cash flows used in investing activities for the three months ended March 31, 2007 were $167.8 million and primarily consisted of $168.4 million of capital expenditures.

Financing Activities

     Cash flows from financing activities are summarized as follows:

		Three Months Ended
		March 31,
(In millions)		2008			2007
Issuance of long-term debt		$	124.3		$	—
Repayment of long-term debt	��		(159.4	)		(36.1	)
Non-controlling interest contribution to joint venture			3.1			—
Proceeds from exercise of employee stock options			8.3			4.6
Cash dividends paid on common stock			(25.2	)		—
Net cash used in financing activities		$	(48.9	)	$	(31.5	)

     Cash flows used in financing activities for the three months ended March 31, 2008 were $48.9 million and primarily consisted of $159.4 million in various debt repayments and $25.2 million relating to cash dividends paid on common stock, partially offset by $124.3 million borrowing on AE Supply’s revolving loan.

     Cash flows used in financing activities for the three months ended March 31, 2007 were $31.5 million and primarily consisted of $36.1 million of repayments of long-term debt, primarily related to periodic payments on amounts outstanding under West Penn’s 2005 Transition Bonds and AE Supply’s pollution control bonds, partially offset by $4.6 million of proceeds from the exercise of employee stock options.

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CREDIT RATINGS

     The following table lists Allegheny’s credit ratings, as of May 7, 2008:

	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:
Outlook	Stable	Stable	Stable
Senior Secured Debt	Baa2	BBB	BBB
Senior Unsecured Debt	Ba1	BB+	BBB-
Monongahela:
Outlook	Stable	Stable	Stable
First Mortgage Bonds	Baa2	BBB+	BBB+
Senior Unsecured Debt	Baa3	BB+	BBB-
Environmental Control Bonds	Aaa	AAA	AAA
Potomac Edison:
Outlook	Negative	Stable	Negative
First Mortgage Bonds	Baa2	BBB+	BBB
Environmental Control Bonds	Aaa	AAA	AAA
West Penn:
Outlook	Stable	Stable	Stable
First Mortgage Bonds	Baa2	BBB+	BBB+
Senior Unsecured Debt	Baa3	BBB-	BBB-
Transition Bonds	Aaa	AAA	AAA
AGC:
Outlook	Stable	Stable	Stable
Senior Unsecured Debt	Baa3	BBB-	BBB-

(a) Issuer default rating

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OTHER MATTERS

Critical Accounting Policies

     A summary of critical accounting policies is included under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in the 2007 Annual Report on Form 10-K. Allegheny’s critical accounting policies have not changed materially from those reported in the 2007 Annual Report on Form 10-K.

Recent Accounting Pronouncements

     See Note 2, “Recent Accounting Pronouncements” in Allegheny’s Notes to Consolidated Financial Statements, included herein for a summary of significant recent accounting pronouncements issued or implemented during 2008 that relate to Allegheny’s operations.

REGULATORY MATTERS

     See Item 1, “Regulatory Framework Affecting Allegheny” in the 2007 Annual Report on Form 10-K for a summary of regulatory matters.

Federal Regulation and Rate Matters

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 from the Distribution Companies and others. FERC concluded that neither the rate design proposals nor the existing PJM rate design had been shown to be just and reasonable. However, FERC ordered the continuation of the existing PJM rate design and the implementation of a transition charge for these regions through March 31, 2006 through filings made by transmission owners in both regions. In February 2005, FERC accepted these transition charges, effective December 1, 2004, subject to an evidentiary hearing. FERC’s February 2005 order remains subject to multiple rehearing requests and, potentially, appellate review. Allegheny cannot predict the outcome of these proceedings or whether they 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 $13.7 million, and payments to the Distribution Companies of $3.5 million, for the 16-month period ended March 31, 2006. Following the evidentiary hearing, on August 10, 2006, an administrative law judge issued an initial decision that generally found fault with the methodologies used to develop the transition charges. That decision is now subject to review by FERC. The order that will be issued by FERC on review of the initial decision 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 these proceedings. The Distribution Companies have entered into nine partial settlements with regard to the transition charges, and may enter into additional settlements in the future. FERC has approved seven of these settlements, and approval is pending for the remaining partial settlements.

     In a May 2005 order, FERC again determined that the existing PJM rate design may not be just and reasonable. On September 30, 2005, the Distribution Companies, together with another PJM transmission owner, filed a proposed rate design with FERC to replace the existing rate design within PJM, effective April 1, 2006. Two other PJM transmission owners also filed a separate proposed rate design. A hearing was held in April 2006 to determine whether the rate design is unjust and unreasonable and whether it should be replaced by either of the proposed rate designs. On July 13, 2006, the administrative law judge issued an initial decision, finding that the existing PJM rate design for existing transmission facilities is not just and reasonable. The administrative law judge found that the rate design for existing transmission facilities proposed by the Distribution Companies is just and reasonable, but ruled that the rate design proposed by FERC staff is also just and reasonable, is superior and should be made effective as of April 1, 2006. The initial decision also found that the Distribution Companies’ proposal for rate recovery for new transmission facilities had not demonstrated that the existing rate recovery mechanism for such facilities is unjust and unreasonable but adopted the Distribution Companies’ position that the implementation of a new rate design does not necessitate a change in the allocation of auction revenue rights and financial transmission rights. On April 19, 2007, FERC issued an order on the initial decision that (a) retained the current license plate rate design for existing facilities, (b) requires that the parties develop a detailed “beneficiary pays” methodology for new facilities below 500 kV that would be set forth in the PJM tariff, and (c) allocates on a region-wide basis the costs of new, centrally-planned facilities that operate at or above 500 kV. The Distribution Companies participated as settling parties in a settlement currently pending

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before FERC with regard to the “beneficiary pays” methodology. If approved, the settlement will continue the application of intra-zonal netting and distribution factors for the determination of cost allocations for new facilities below 500 kV. On January 31, 2008, FERC denied requests for rehearing of its April 19, 2007 order on the initial decision.

     On August 1, 2007, the Distribution Companies joined in a filing with other PJM and MISO transmission owners proposing a rate design for transmission transactions crossing the border between PJM and MISO. The proposal provides that customers will pay the rates applicable in the transmission zone where such transmission transactions end. Several parties filed protests of the proposal. On January 31, 2008, FERC rejected the protests and accepted the proposal as filed. FERC’s January 2008 decision is currently pending on appeal to the U.S. Court of Appeals.

     On September 17, 2007, AEP filed a complaint with FERC against MISO and PJM alleging that the rate designs underlying the MISO and PJM open access transmission tariffs are unjust, unreasonable and unduly discriminatory and, therefore, must be revised. AEP requested that FERC establish a refund-effective date of October 1, 2007 with respect to any such revisions. The Distribution Companies intervened in this proceeding, and on January 31, 2008, FERC denied AEP’s request. A rehearing request by AEP of FERC’s January 31, 2008 order is pending.

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 though 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. Capacity auctions were held in April, July and October of 2007 and in January 2008, and an additional auction is expected to be conducted in May 2008. 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 and the United States Court of Appeals for the Third Circuit.

     On July 3, 2006, PJM filed at FERC a proposal to implement a process for allocating long-term transmission rights (“LTTRs”). The PJM proposal would allocate a ten-year financial transmission right to PJM LSEs based on each LSE’s zonal base load. The PJM proposal created a link between PJM’s long-term transmission planning process and the LTTR allocation process to ensure that the transmission system is being upgraded as necessary to maintain the availability of the LTTRs that PJM will allocate. On November 22, 2006, FERC issued an order accepting PJM’s proposal, subject to modifications. On January 22, 2007, PJM filed a related settlement agreement, as well as a proposal to allocate any costs to fund LTTRs fully to holders of financial transmission rights on a pro-rata basis. FERC accepted this settlement agreement and related cost allocation proposal in an order issued on May 17, 2007. On October 22, 2007, FERC denied requests for rehearing of the May 17, 2007 order. FERC also ordered the creation of a stakeholder process to determine whether the PJM proposed full funding mechanism that was accepted by FERC should be changed subsequent to the 2007-2008 PJM planning year. Stakeholders did not reach consensus on revisions to the existing full funding mechanism, but there was agreement that the allocation of transmission rights uplift charges and the allocation of excess congestion revenue credits should be aligned. AE Supply and the Distribution Companies filed comments in support of PJM’s proposal, which is pending at FERC.

Transmission Expansion

     TrAIL Project.In June 2006, the PJM Board of Managers approved a Regional Transmission Expansion Plan (“RTEP”) that directed the Distribution Companies and Virginia Electric and Power Company to cause the construction of a 240-mile 500 kV transmission line project from southwestern Pennsylvania through northern West Virginia and into northern Virginia to address potential electric reliability issues caused by increased customer load in the mid-Atlantic area that could have adverse effects within the service territories of the Distribution Companies. Approximately 185 miles of the project are located in the Distribution Companies’ PJM zone. In October 2006, Allegheny formed TrAIL Company as the entity responsible for financing, constructing, owning, operating and maintaining this project, which has been named “Trans-Allegheny Interstate Line” and is referred to as “TrAIL.” The project includes the construction of approximately 51 miles of 500 kV and 138 kV lines in southwestern Pennsylvania to address electric reliability issues in that area. Total project costs are expected to be approximately $820 million.

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     On July 20, 2006, FERC approved incentive rate treatments for TrAIL. On February 21, 2007, TrAIL Company submitted to FERC a filing under Section 205 of the FPA to implement a formula tariff rate, with a proposed effective date of June 1, 2007, that includes the incentive rate treatments approved by FERC. On May 31, 2007, FERC issued an order permitting the formula tariff rate to become effective on June 1, 2007, subject to refund and hearing. One of the issues set for hearing was the level of the incentive return on equity for TrAIL. On March 14, 2008, TrAIL Company filed a settlement in this case with FERC. The settlement, which requires FERC approval, provides for an incentive return on equity for the TrAIL project and the Black Oak SVC of 12.7% and a return on equity of 11.7% for non-incentive projects. On April 25, 2008, the Administrative Law Judge certified the settlement to FERC.

     PATH Project.On June 22, 2007, the PJM Board of Managers directed the construction of a 290-mile, high-voltage transmission line, named the Potomac-Appalachian Transmission Highline, or “PATH.” The project will include approximately 244 miles of 765 kV transmission line from AEP’s substation near St. Albans, West Virginia to Allegheny’s Bedington substation near Martinsburg, West Virginia, and will also include approximately 46 miles of twin-circuit 500 kV lines from Bedington to a new substation to be built and owned by Allegheny near Kemptown, Maryland. On September 1, 2007, Allegheny entered into a joint venture agreement with a subsidiary of AEP to build PATH. 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 tariff rate 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 the following rate incentives:

• a return on equity of 14.3 percent;

• inclusion of 100 percent of construction work in progress in rate base;

• recovery of prudently incurred start-up business and administrative costs incurred prior to the time the rates go into effect; and

• recovery of prudently incurred development and construction costs if PATH is abandoned as a result of factors beyond the control of PATH, LLC or its parent companies.

     FERC set for hearing the cost of service formula rate that will be used to calculate annual revenue requirements for the project.

     National Interest Electric Transmission Corridor.The Energy Policy Act amended the FPA to, among other things, direct the Secretary of Energy to conduct a nationwide study of electric transmission congestion by August 2006 and to update the study every three years thereafter. Based on its congestion study and other relevant factors, the Secretary may designate any geographic area experiencing electric energy transmission capacity constraints or congestion that adversely affects customers a national interest transmission corridor (“NIETC”). Within a NIETC, transmission proposals could potentially be reviewed by FERC, which would have siting authority supplementing existing state authority and may consider whether to issue a permit and authorize construction of a proposed transmission project within the NIETC in the event that the relevant state authorities do not approve siting of the project within the NIETC. Under certain circumstances, a federal permit could empower the permit holder to exercise the right of eminent domain to acquire necessary property rights to construct the proposed transmission project.

     On August 8, 2006, the DOE published its initial congestion study in which a portion of the Mid-Atlantic region was classified as a “critical congestion area” meriting further federal attention. On October 2, 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; with exception of a substation to be located in Putnam County, West Virginia. The DOE denied requests for rehearing of its October 2, 2007 NIETC designation. Several entities, including the Pennsylvania PUC and the Commonwealth of Virginia, have initiated various proceedings in the federal courts challenging the NIETC designations and the FERC rules promulgated for siting transmission lines within a NIETC. Allegheny has moved to intervene in proceedings pending in the United States Courts of Appeals for the Second and Ninth Circuits. The cases pending in various circuits of the United States Courts of Appeals have been consolidated in the Ninth Circuit pursuant to an order of the United States Judicial Panel on Multidistrict Litigation.

State Rate Regulation

Pennsylvania

     Default Service Regulations.On May 10, 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

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(“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. On October 25, 2007, West Penn filed with the Pennsylvania PUC a default service plan, which was referred to a Pennsylvania PUC administrative law judge for hearings. Hearings were held on March 31 and April 1, 2008. A decision is expected from the Pennsylvania PUC in late July 2008.

     Transmission Expansion.On April 13, 2007, TrAIL Company filed an application with the Pennsylvania PUC for authorization to construct the TrAIL project in Pennsylvania. The evidentiary hearing on this matter concluded on April 3, 2008. Issuance of an order in this matter is expected by the end of September 2008.

     Management Efficiency Audit.In 2006 and 2007, the Pennsylvania PUC’s Bureau of Audits conducted an audit of the management efficiency of West Penn, as it is required by state law to do every five to eight years for all major Pennsylvania utilities. The last such audit of West Penn was completed in 2000. The Pennsylvania PUC’s Bureau of Audits has concluded its audit and fact finding, and its conclusions, along with West Penn’s response, became public upon the issuance of the Bureau of Audit’s report to the Pennsylvania PUC. The audit recommendations accepted in full or in part by West Penn include recommendations to:

• Develop an improvement plan to meet the Pennsylvania PUC’s three-year distribution reliability standards:

• Conduct a study to determine utilization practices for contractors and company line workers;

• Enforce an underground damage prevention program;

• Charge affiliate pole attachment fees consistent with the fees charged to non-affiliates;

• Intensify efforts toward attaining representation of women and minorities.

     For each of the next three years, West Penn will be required to provide the PA PUC with annual reports on its implementation of, and progress with respect to, these recommendations. West Penn rejected recommendations to: limit its dividend payments to AE; achieve higher returns on final customer accounts that are referred to outside collection agencies; reorganize the reporting relationship of the internal audit function; and periodically change its independent accounting firm. The PA PUC did not order West Penn to implement the recommendations that it rejected.

West Virginia

     Transmission Expansion.On March 30, 2007, TrAIL Company filed an application with the West Virginia PSC for authorization to construct the TrAIL project in West Virginia. An evidentiary hearing on this matter was held during a two-week period in January 2008. On April 15, 2008, TrAIL Company filed with the West Virginia PSC a settlement regarding the TrAIL project among TrAIL Company, the Staff of the West Virginia PSC, the Consumer Advocate Division and the West Virginia Energy Users Group (the “WVEUG”). The settlement provides that:

• Monongahela, Potomac Edison and TrAIL Company will locate 100 to 150 managerial, professional, technical and administrative jobs in north-central West Virginia no later than the in-service date of the West Virginia segment of TrAIL, which will involve construction of a new facility in the state with an estimated cost of approximately $50 million;

• Monongahela and Potomac Edison will not seek recovery in West Virginia of transmission charges associated with TrAIL for the period from January 2007 through the latest of December 31, 2013, the date which is two and one-half

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	years following the in-service date of TrAIL’s West Virginia segment or the month in which Allegheny’s new West Virginia facility is placed in service;
•	TrAIL Company will contribute $5 million to fund energy conservation programs and assistance plans for low-income customers in West Virginia over a five year period;
•	Monongahela and Potomac Edison will provide rate relief in the form of credits totaling approximately $5.7 million in the aggregate to industrial customers in West Virginia in 2010 and 2011;
•	The West Virginia segment of TrAIL should follow the route set forth in TrAIL Company’s application to the West Virginia PSC, except for certain modifications south of Morgantown, West Virginia, which will more closely follow existing transmission corridors;
•	The Consumer Advocate, the Staff of the West Virginia PSC and the WVEUG will support the need for the portion of TrAIL that is proposed to run from Allegheny’s 502 Junction in Greene County, Pennsylvania through West Virginia to Loudoun, Virginia; and
•	Landowners on the right-of-way will be provided with transmission credits that can be used for up to 12,000 kWh of power per year.

     In addition, TrAIL Company has accepted, with certain modifications, many of the West Virginia PSC staff’s proposed conditions. For example, TrAIL Company will provide West Virginia homeowners the option to sell to TrAIL Company residences that are located within 400 feet of TrAIL and will follow various proposed guidelines pertaining to pre-construction and construction activities associated with TrAIL.

     Although the West Virginia PSC is otherwise required by statute to issue an order regarding this matter by May 5, 2008, TrAIL Company filed a motion with the West Virginia PSC to toll the statutory decision deadline until June 2, 2008. On April 17, 2008, the West Virginia PSC issued an order requesting that TrAIL Company file a revised motion requesting that the West Virginia PSC toll the statutory decision deadline until August 2, 2008, which TrAIL Company filed with the West Virginia PSC on April 18, 2008. The West Virginia PSC issued an order tolling the statutory deadline to August 2, 2008. A hearing on the settlement is expected to occur during the last week of May 2008.

     Rate Case.On July 26, 2006, Monongahela and Potomac Edison filed with the West Virginia PSC a request to raise their West Virginia retail rates by approximately $100 million annually, effective on August 25, 2006. The request included a $126 million increase in rates related to fuel and purchased power costs, including reinstatement of a fuel cost recovery clause, adjustable annually, to reflect upward or downward changes in the cost of fuel and purchased power, and a $26 million decrease in base rates. On May 22, 2007, the West Virginia PSC issued a final order directing Monongahela and Potomac Edison to reduce overall rates by approximately $6 million effective May 23, 2007, by increasing fuel and purchased power cost-related rates by $126 million and reducing base rates by approximately $132 million, which includes changes in authorized depreciation rates that will reduce annual depreciation expense by approximately $16 million. The order approved the request by Monongahela and Potomac Edison to reinstate a fuel cost recovery clause. On June 15, 2007, Monongahela and Potomac Edison filed a Petition for Reconsideration and Clarification (“Petition for Reconsideration”) of certain findings in the order. Other parties in the proceeding submitted responses in opposition to the Petition for Reconsideration on July 9, 2007. The West Virginia PSC has no procedural deadline for ruling on the Petition for Reconsideration. See Note 5, “Rates and Regulation” to the Consolidated Financial Statements.

Maryland

     Standard Offer Service.In 2003, the Maryland PSC approved two state-wide settlements relating to the future of PLR and SOS. The settlement extended Potomac Edison’s obligation to provide SOS after the expiration of the generation rate cap periods established for Potomac Edison as part of the 1999 restructuring of Maryland’s electric market. The settlement provided that, after expiration of the generation rate caps, SOS would be provided through 2012 for residential customers, through 2008 for smaller commercial and industrial customers and through 2006 for Potomac Edison’s medium-sized commercial customers. Potomac Edison’s obligation to provide SOS for its largest industrial customers expired at the end of 2005. A 2005 settlement extended Potomac Edison’s SOS obligations to its medium-sized commercial customers through May 2007, and a further order of the Maryland PSC issued on August 28, 2006 extended that obligation through at least the end of May 2009. The Maryland PSC issued an order on November 8, 2006, and a report to the Maryland legislature on December 31, 2006, that would continue SOS to small and medium-sized commercial customers with changes in procurement durations. The November 8, 2006 order is subject to a motion for rehearing filed by the Maryland Office of People’s Counsel, and neither the Maryland PSC nor the Maryland legislature has taken further action on the subject of the December 31, 2006 report to the Maryland legislature. Allegheny cannot predict when a final resolution of these matters will be forthcoming.

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     The Maryland PSC opened a new docket in August 2007 (Case No. 9117) to consider matters relating to possible “managed portfolio” approaches to SOS, the aggregation of low income SOS customers, and a retail supplier proposal for the utility “purchase” of all retailer receivables at no discount and with no recourse. Testimony was filed in September 2007. On September 25, 2007, the Maryland PSC opened “Phase II” of the case on utility purchases or construction of generation, bidding for procurement of DSM 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.

     Potomac Edison developed a plan for seeking bids to serve its Maryland residential load for the period after the rate cap expires on December 31, 2008. Potomac Edison filed the proposal with the Maryland PSC on August 3, 2007. On September 12, 2007, the Maryland PSC directed Potomac Edison to proceed with an initial partial procurement in October 2007, but to file a modified plan for the rest of the procurement after the resolution of Case No. 9117. On November 22, 2007, Potomac Edison filed a second partial procurement plan, for bidding in January 2008, which the Maryland PSC approved on December 19, 2007. On April 10, 2008, Potomac Edison filed a third bid plan covering the remaining bidding for 2008, which the Maryland PSC approved on April 11, 2008.

     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 that electric demand 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 has scheduled further hearings on May 7, 2008. The Maryland PSC has also initiated a series of workshops to coordinate the utilities’ plans, the first of which was held on January 4, 2008.

     In September 2007, the Maryland PSC approved a fast-track compact fluorescent light (“CFL”) and education campaign that included recovery of $2.5 million in costs through a special, one-year surcharge on customers’ distribution bills. The Maryland PSC held further hearings on the program in January 2008, at which Allegheny agreed, among other things, to refund cost recovery for the program. The Maryland PSC also ordered Potomac Edison and three other Maryland utilities to file, by February 15, 2008, a Demand Response Service Program, which is intended to be a plan for mandatory load reduction during times of peak usage through the installation of technology in customers’ homes. Potomac Edison’s filing made on February 15, 2008 and reviewed with the Maryland PSC at a hearing on March 19, 2008 concluded that such a program would not be cost-effective for Potomac Edison to implement at this time. The Maryland PSC issued an order accepting that conclusion on April 15, 2008.

Virginia

     Transmission Expansion.On April 19, 2007, TrAIL Company filed an application with the Virginia SCC for authorization to construct the TrAIL project in Virginia. The evidentiary hearing in this matter concluded on March 18, 2008. Issuance of an order in this matter is expected by the end of September 2008.

     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, in each case, AE Supply was the successful bidder with respect to a substantial portion of these requirements.

     As amended, the Restructuring Act, which initially capped generation rates until July 1, 2007, currently provides for generation rate caps through December 31, 2008. The market prices at which Potomac Edison now purchases power are, and since the expiration in 2007 of its power purchase agreement with AE Supply have been, significantly higher than the capped generation rates prevailing under the Restructuring Act that Potomac Edison may charge its Virginia retail customers.

     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.

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     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. Additionally, Potomac Edison filed a Motion for Interim Rates with the Virginia SCC on May 10, 2007. In connection with Potomac Edison’s application, the Virginia SCC requested briefing on the “continuing legal viability” of a Memorandum of Understanding (the “MOU”) that Potomac Edison entered into with the Staff of the Virginia PSC 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. 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.

     On July 6, 2007, Potomac Edison filed with the Virginia SCC a Motion for Suspension of Order and Motion for Interim Rates, which the Virginia SCC denied on August 7, 2007. On July 26, 2007, Potomac Edison filed an appeal of the decision denying Potomac Edison’s application and motion to establish interim rates to the Virginia Supreme Court and also asked the Virginia Supreme Court for relief pending appeal. The Court denied Potomac Edison’s motions and set the matter for review in the ordinary course.

     On September 11, 2007, Potomac Edison filed a new application for rate recovery of purchased power costs for load above 367 MW with the Virginia SCC, while continuing to pursue its appeal for full cost recovery. The new application requested an increase of approximately $42.3 million (as revised) in Potomac Edison’s Virginia retail electric rates to allow Potomac Edison to recover a portion of its projected purchased power costs arising from the provision of service to its Virginia jurisdictional customers from July 1, 2007 through June 30, 2008. On December 20, 2007, the Virginia SCC issued an order granting only partial recovery of increased purchased power costs.

     The commission’s order:

• granted a rate adjustment effective immediately that would permit Potomac Edison to collect an additional $9.5 million (pre-tax) on an annualized basis through June 30, 2008, a substantially lower amount than the $42.3 million requested;

• directed Potomac Edison to implement deferred accounting effective immediately with respect to the over- or under-recovery of the increased purchase power costs approved in the order; and

• directed Potomac Edison to file an application with the Virginia SCC on or before July 1, 2008, for proposed recovery of purchased power costs for the 12-month period beginning July 1, 2008, including for treatment of any over- or under-recovery incurred for service rendered prior to July 1, 2008 and whether and how its proposed recovery of purchased power costs for service rendered on and after January 1, 2009 would be consistent with the MOU and certain amendments to the Restructuring Act.

Potomac Edison appealed the December 20, 2007 order on January 16, 2008.

     On April 11, 2008, the Virginia Supreme Court denied Potomac Edison’s appeal of the Virginia SCC’s June 2007 order, on the ground that the statute that the Virginia SCC cited as controlling did not require the Virginia SCC to grant the relief requested, but also stated that recovery on other grounds was not being addressed. Potomac Edison’s appeal of the December 20, 2007 order is still pending.

     On April 30, 2008, Potomac Edison filed an application with the Virginia SCC to recover at least $73 million, and as much as $132.9 million, of purchased power costs for service rendered to its Virginia jurisdictional customers from July 1, 2008 through June 30, 2009. Absent rate relief, Potomac Edison currently estimates that it will incur a shortfall of approximately $132.9 million for the provision of generation service in Virginia for the period from July 1, 2008 through June 30, 2009. As of March 31, 2008, Potomac Edison had total stockholders’ equity of approximately $419 million.

     As detailed in Potomac Edison’s April 2008 application to the Virginia SCC, Potomac Edison is currently experiencing substantial, unsustainable negative cash flows as a result of the Virginia SCC’s denial of recovery of the large majority of the increase in Potomac Edison’s purchased power costs that began on July 1, 2007. Although Potomac Edison believes that the MOU will no longer be in effect, and that it thus should be permitted to recover all of its purchased power costs as of January 1, 2009, the Virginia SCC may determine otherwise. As a result, there can be no assurance that Potomac Edison will be able to recover the cost of power purchases in excess of the capped generation rates that it is currently permitted to charge its Virginia customers in a timely fashion or at all. The inability to recover such costs has had and, absent a change in current circumstances, is expected to continue to have a materially negative effect on Potomac Edison’s cash flow, results of operations,

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financial condition and overall business. Based on its current customer rates, Potomac Edison’s revenues are not sufficient to fund its ongoing operations and maintenance costs and necessary capital expenditures. Furthermore, absent a change in circumstances, it is anticipated that the under-recovery to which Potomac Edison’s Virginia operations are subject will exhaust its capacity to borrow additional funds to support its operations by the third quarter of 2009. Potomac Edison is requesting further rate relief, as noted above. In addition, absent adequate rate relief, Potomac Edison may postpone or eliminate some or all planned capital and other expenditures. However, such cost saving measures would not be sufficient to fully address Potomac Edison’s negative cash flows described above and Potomac Edison is, therefore, evaluating other alternatives available to it in response to the unsustainable negative impact of these regulatory decisions.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     See, Item 7a, “Quantitative and Qualitative Disclosures About Market Risk,” in the 2007 Annual Report on Form 10-K for additional information relating to market risk.

     Market risk arises from the changes in the value of energy related to price and volatility in the market. Allegheny reduces these risks by using its generation assets to back positions on physical transactions. Allegheny monitors market risk exposure and credit risk limits within the guidelines of its Corporate Risk Management Business Practices. Allegheny evaluates commodity price risk, operational risk and credit risk in establishing the fair value of commodity contracts.

     Allegheny and AE Supply use various methods to measure their exposure to market risk on a daily basis, including a value at risk model (“VaR”). VaR is a statistical model that measures the variability of value and predicts the risk of loss based on historical market price and volatility data over a given period of time. The quantification of market risk using VaR provides a consistent measure of risk across diverse energy markets and products with different risk factors to set the overall corporate risk tolerance, determine risk targets and monitor positions. Allegheny and AE Supply calculate VaR using the Monte-Carlo technique by simulating thousands of scenarios sampling from the probability distribution of uncertain market variables. In addition to VaR, Allegheny and AE Supply routinely perform stress and scenario analyses to measure extreme losses due to exceptional events. Allegheny and AE Supply review the VaR and stress test results to determine the maximum expected reduction in the fair value of the entire energy markets portfolio.

     AE Supply calculated the VaR of a 1-day holding period at a 95% confidence level using the full term of all remaining wholesale energy market positions that are accounted for as marked-to-market. This calculation is based upon management’s best estimates and modeling assumptions, which could materially differ from actual results. As of March 31, 2008 and December 31, 2007, this calculation yielded a VaR of $0.9 million and $0, respectively.

ITEM 4. CONTROLS AND PROCEDURES

     See, Item 9a, “Controls and Procedures,” in the 2007 Annual Report on Form 10-K for additional information relating to Controls and Procedures.

     Disclosure Controls and Procedures.AE carried out an evaluation, under the supervision and with the participation of its management, including its principal executive officer and principal financial officer, of the effectiveness of its disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, as of March 31, 2008 (the “Evaluation Date”). These disclosure controls and procedures are designed to provide reasonable assurance to AE’s management and board of directors that information required to be disclosed by AE in reports filed under the Exchange Act is accumulated and communicated to management as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, the principal executive officer and principal financial officer of AE have concluded that its applicable disclosure controls and procedures as of March 31, 2008 were effective, at the reasonable assurance level, to ensure that (a) material information relating to AE is accumulated and made known to its management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure and (b) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

     Changes in Internal Control over Financial Reporting:There have been no changes in AE’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15(d)-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, internal control over financial reporting during the three months ended March 31, 2008.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

     United Coals. On April 28, 2008, United Coals, Inc. (“United Coals”) initiated a lawsuit in the Circuit Court of Harrison County, West Virginia against AE Supply, Monongahela and Allegheny Energy Service Corporation. United Coals claims that it is owed approximately $1.4 million for coal previously delivered under of the terms of a long term coal supply agreement (the “Agreement”) and also seeks to terminate the Agreement. The Agreement obligates United Coals to provide to Allegheny approximately one million tons of coal per year through 2015. Allegheny denies that United Coals is entitled to any of the relief sought and intends to explore all legal options to enforce the terms of the Agreement. Allegheny intends to vigorously defend against this action but cannot predict its outcome.

     See Note 16, “Commitments and Contingencies” to the Consolidated Financial Statements of AE for information regarding other 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 2007 Annual Report on Form 10-K. The risk factors set forth below were disclosed in the 2007 Annual Report on Form 10-K and have been updated to provide additional information.

State rate regulation may delay or deny full recovery of costs and impose risks on Allegheny’s operations. Any denial of, or delay in, cost recovery could have an adverse effect on Allegheny’s business.

     The retail rates in the states in which Allegheny operates are set by each state’s regulatory body. As a result, in certain states, Allegheny may not be able to recover increased, unexpected or necessary costs and, even if Allegheny is able to do so, there may be a significant delay between the time Allegheny incurs such costs and the time Allegheny is allowed to recover them. Any denial of, or delay in, cost recovery could have an adverse effect on Allegheny’s results of operations, cash flows and financial condition.

Virginia

     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 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, in each case, AE Supply was the successful bidder with respect to a substantial portion of these requirements.

     As amended, the Restructuring Act, which initially capped generation rates until July 1, 2007, currently provides for generation rate caps through December 31, 2008. The market prices at which Potomac Edison now purchases power are, and since the expiration in 2007 of its power purchase agreement with AE Supply have been, significantly higher than the capped generation rates prevailing under the Restructuring Act that Potomac Edison may charge its Virginia retail customers.

     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. Additionally, Potomac Edison filed a Motion for Interim Rates with the Virginia SCC on May 10, 2007. In connection with Potomac Edison’s application, the Virginia SCC requested briefing on the “continuing legal viability” of the MOU that Potomac Edison entered into with the Staff of the Virginia PSC 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. 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.

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     On July 6, 2007, Potomac Edison filed with the Virginia SCC a Motion for Suspension of Order and Motion for Interim Rates, which the Virginia SCC denied on August 7, 2007. On July 26, 2007, Potomac Edison filed an appeal of the decision denying Potomac Edison’s application and motion to establish interim rates to the Virginia Supreme Court and also asked the Virginia Supreme Court for relief pending appeal. The Court denied Potomac Edison’s motions and set the matter for review in the ordinary course.

     On September 11, 2007, Potomac Edison filed a new application for rate recovery of purchased power costs for load above 367 MW with the Virginia SCC, while continuing to pursue its appeal for full cost recovery. The new application requested an increase of approximately $42.3 million (as revised) in Potomac Edison’s Virginia retail electric rates to allow Potomac Edison to recover a portion of its projected purchased power costs arising from the provision of service to its Virginia jurisdictional customers from July 1, 2007 through June 30, 2008. On December 20, 2007, the Virginia SCC issued an order granting only partial recovery of increased purchased power costs.

     The commission’s order:

• granted a rate adjustment effective immediately that would permit Potomac Edison to collect an additional $9.5 million (pre-tax) on an annualized basis through June 30, 2008, a substantially lower amount than the $42.3 million requested;

• directed Potomac Edison to implement deferred accounting effective immediately with respect to the over- or under-recovery of the increased purchase power costs approved in the order; and

• directed Potomac Edison to file an application with the Virginia SCC on or before July 1, 2008, for proposed recovery of purchased power costs for the 12-month period beginning July 1, 2008, including for treatment of any over- or under-recovery incurred for service rendered prior to July 1, 2008 and whether and how its proposed recovery of purchased power costs for service rendered on and after January 1, 2009 would be consistent with the MOU and certain amendments to the Restructuring Act.

Potomac Edison appealed the December 20, 2007 order on January 16, 2008.

     On April 11, 2008, the Virginia Supreme Court denied Potomac Edison’s appeal of the Virginia SCC’s June 2007 order, on the ground that the statute that the Virginia SCC cited as controlling did not require the Virginia SCC to grant the relief requested, but also stated that recovery on other grounds was not being addressed. Potomac Edison’s appeal of the December 20, 2007 order is still pending.

     On April 30, 2008, Potomac Edison filed an application with the Virginia SCC to recover at least $73 million, and as much as $132.9 million, of purchased power costs for service rendered to its Virginia jurisdictional customers from July 1, 2008 through June 30, 2009. Absent rate relief, Potomac Edison currently estimates that it will incur a shortfall of approximately $132.9 million for the provision of generation service in Virginia for the period from July 1, 2008 through June 30, 2009. As of March 31, 2008, Potomac Edison had total stockholders’ equity of approximately $419 million.

     As detailed in Potomac Edison’s April 2008 application to the Virginia SCC, Potomac Edison is currently experiencing substantial, unsustainable negative cash flows as a result of the Virginia SCC’s denial of recovery of the large majority of the increase in Potomac Edison’s purchased power costs that began on July 1, 2007. Although Potomac Edison believes that the MOU will no longer be in effect, and that it thus should be permitted to recover all of its purchased power costs as of January 1, 2009, the Virginia SCC may determine otherwise. As a result, there can be no assurance that Potomac Edison will be able to recover the cost of power purchases in excess of the capped generation rates that it is currently permitted to charge its Virginia customers in a timely fashion or at all. The inability to recover such costs has had and, absent a change in current circumstances, is expected to continue to have a materially negative effect on Potomac Edison’s cash flow, results of operations, financial condition and overall business. Based on its current customer rates, Potomac Edison’s revenues are not sufficient to fund its ongoing operations and maintenance costs and necessary capital expenditures. Furthermore, absent a change in circumstances, it is anticipated that the under-recovery to which Potomac Edison’s Virginia operations are subject will exhaust its capacity to borrow additional funds to support its operations by the third quarter of 2009. Potomac Edison is requesting further rate relief, as noted above. In addition, absent adequate rate relief, Potomac Edison may postpone or eliminate some or all planned capital and other expenditures. However, such cost saving measures would not be sufficient to fully address Potomac Edison’s negative cash flows described above and Potomac Edison is, therefore, evaluating other alternatives available to it in response to the unsustainable negative impact of these regulatory decisions.

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West Virginia

     The West Virginia PSC sets Monongahela’s and Potomac Edison’s rates in West Virginia through traditional, cost-based regulated utility ratemaking.

     On July 26, 2006, Potomac Edison and Monongahela filed a request with the West Virginia PSC to increase their West Virginia retail rates by approximately $99.8 million annually, effective on August 25, 2006. The request included a $126 million increase in rates related to fuel and purchased power costs, including reinstatement of a cost recovery clause, adjustable annually, to reflect upward or downward changes in the cost of fuel and purchased power, and a $26 million decrease in transmission, distribution and generation (non-fuel) rates.

     On May 22, 2007, the West Virginia PSC issued a final order directing Monongahela and Potomac Edison to reduce overall rates by approximately $6.2 million effective May 23, 2007, by increasing fuel and purchased power cost-related rates by $126 million and reducing base rates by approximately $132 million. The order approved the request by Monongahela and Potomac Edison to reinstate a fuel cost recovery clause. On June 15, 2007, Monongahela and Potomac Edison filed a Petition for Reconsideration and Clarification (“Petition for Reconsideration”) of certain findings in the order. Other parties in the proceeding submitted responses in opposition to the Petition for Reconsideration on July 9, 2007. The West Virginia PSC has no procedural deadline for responding to the Petition for Reconsideration. Allegheny can provide no assurance that the Petition for Reconsideration will succeed in whole or in part or that the decrease in base rates embodied in the final Order will not have an adverse effect on Allegheny’s business, results of operations, cash flows and financial condition. See “Regulatory Matters” above.

The supply and price of fuel may impact Allegheny’s financial results.

     Allegheny is dependent on coal for much of its electric generation capacity. Allegheny has coal supply contracts in place that partially mitigate its exposure to negative fluctuations in coal prices. However, Allegheny can provide no assurance that the counterparties to these agreements will fulfill their obligations to supply coal. The suppliers under these agreements may experience financial, legal or technical problems that inhibit their ability to fulfill their obligations. Various industry and operational factors, including increased costs, transportation constraints, safety issues and operational difficulties may have negative effects on coal supplier performance. During periods of rising coal prices, the factors impacting supplier performance could have a more pronounced financial impact. Furthermore, the suppliers under these agreements may not be required to supply coal to Allegheny under certain circumstances, such as in the event of a natural disaster. If Allegheny is unable to obtain its coal requirements under these contracts, it may be required to purchase coal at higher prices. In addition, although these agreements generally contain specified prices, they also provide for price adjustments related to changes in specified cost indices, as well as specific event, such as changes in regulations affecting the coal industry. Changes in the supply and price of coal could have a material adverse effect on Allegheny’s business, results of operations, cash flow and financial condition.

     On April 28, 2008, United Coals initiated a lawsuit in the Circuit Court of Harrison County, West Virginia against AE Supply, Monongahela and Allegheny Energy Service Corporation. United Coals claims that it is owed approximately $1.4 million for coal previously delivered under of the terms of a long term coal supply agreement and also seeks to terminate the Agreement. The Agreement obligates United Coals to provide to Allegheny approximately one million tons of coal per year through 2015. Allegheny denies that United Coals is entitled to any of the relief sought and intends to explore all legal options to enforce the terms of the Agreement. Allegheny intends to vigorously defend against this action but cannot predict its outcome.

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

     None.

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ITEM 6. EXHIBITS

EXHIBIT INDEX

	Documents
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

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SIGNATURE

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

	ALLEGHENY ENERGY, INC.
Date: May 7, 2008	By:	/s/ Philip L. Goulding
		Philip L. Goulding
		Senior Vice President and Chief Financial Officer

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