Allegheny Energy 10Q 2008 Q3 Quarterly report

Allegheny Energy (AYE) Inactive 10-Q2008 Q3 Quarterly report

Content analysis

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarter ended September 30, 2008

Commission File Number 1-267

ALLEGHENY ENERGY, INC.

(Name of Registrant)


Maryland (State of Incorporation) 800 Cabin Hill Drive, Greensburg,		13-5531602 (IRS Employer Identification Number)

Pennsylvania		15601
(Address of Principal Executive		(Zip Code)
Offices)

(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):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yeso Noþ

As of October 31, 2008, 169,053,707 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”)		47
Item 3. Quantitative and Qualitative Disclosures About Market Risk		93
Item 4. Controls and Procedures		94
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		95
Item 1A. Risk Factors		95
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		104
Item 3. Defaults Upon Senior Securities		104
Item 4. Submission of Matters to a Vote of Security Holders		104
Item 5. Other Information		104
Item 6. Exhibits		105
Signatures		106
EX-3.1
EX-10.1
EX-10.2
EX-10.3
EX-31.1
EX-31.2
EX-32.1
EX-32.2

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

AE Supply		Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary of AE

AGC		Allegheny Generating Company, a regulated generation subsidiary of AE Supply and Monongahela

Allegheny		Allegheny Energy, Inc., together with its consolidated subsidiaries

Allegheny Ventures		Allegheny Ventures, Inc., a nonutility, unregulated subsidiary of AE

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

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


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(In thousands, except per share amounts)	2008			2007		2008			2007
Operating revenues	$	849,554		$	846,592	$	2,678,080		$	2,520,699
Operating expenses:
Fuel		299,164			245,503		794,242			709,057
Purchased power and transmission		108,149			93,923		302,735			293,597
Deferred energy costs, net		(18,706	)		3,651		(28,056	)		(6,049	)
Operations and maintenance		152,261			154,856		510,893			505,915
Depreciation and amortization		67,384			66,748		206,466			209,455
Taxes other than income taxes		54,364			53,497		159,682			158,254

Total operating expenses		662,616			618,178		1,945,962			1,870,229

Operating income		186,938			228,414		732,118			650,470
Other income (expense), net		4,474			14,822		15,343			27,590
Interest expense and preferred dividends of subsidiary		57,960			59,582		175,094			182,323

Income before income taxes and minority interest		133,452			183,654		572,367			495,737
Income tax expense		44,305			67,223		192,417			191,481
Minority interest in net income of subsidiaries		158			1,413		710			2,452

Net income	$	88,989		$	115,018	$	379,240		$	301,804


Common share data:
Weighted average common shares outstanding:
Basic		168,894			166,101		168,233			165,799
Diluted		170,006			169,456		170,023			169,371

Basic income per common share	$	0.53		$	0.69	$	2.25		$	1.81

Diluted income per common share	$	0.52		$	0.67	$	2.23		$	1.78

Dividends per common share	$	0.15		$	—	$	0.45		$	—

See accompanying Notes to Consolidated Financial Statements.

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


	Nine Months Ended
	September 30,
(In thousands)	2008			2007
Cash Flows From Operating Activities:
Net income	$	379,240		$	301,804
Adjustments for non-cash items included in income:
Depreciation and amortization		206,466			209,455
Amortization of debt related costs		8,187			7,602
Amortization of power sale liability related to Ohio sale		—			(10,500	)
Amortization of liability for adverse power purchase commitment		(12,853	)		(12,965	)
Amortization of Pennsylvania stranded cost recovery asset		8,555			14,641
Gain on asset sales and disposals		(279	)		(15,439	)
Provision for uncollectible accounts		13,304			13,042
Minority interest in net income of subsidiaries		710			2,452
Deferred income taxes and investment tax credit, net		177,033			188,791
Deferred energy costs, net		(28,056	)		(6,049	)
Stock-based compensation expense		9,850			8,090
Unrealized gains on derivatives, net		(136,918	)		(4,348	)
Pension and other postretirement employee benefit plan expense		23,496			26,972
Pension and other postretirement employee benefit plan contributions		(45,409	)		(46,521	)
Deferred revenue – Fort Martin scrubber project		9,292			11,321
Deferred revenue – Virginia July 1, 2008 rate increase		13,999			—
Other, net		11,075			8,053
Changes in certain assets and liabilities:
Accounts receivable, net		(32,574	)		(37,079	)
Materials, supplies and fuel		(43,343	)		(210	)
Taxes receivable / accrued		(34,990	)		(14,746	)
Prepaid taxes		21,506			19,215
Collateral deposits		31,177			16,459
Prepaid assets		(4,220	)		(8,869	)
Other current assets		1,082			11,740
Accounts payable		(62,146	)		33,673
Accrued interest		(2,459	)		21,462
Other current liabilities		12,967			3,192
Regulatory assets		26,355			(3,233	)
Other assets		4,608			(1,935	)
Deferred income taxes		(2,498	)		(12,288	)
Regulatory liabilities		41,066			2,163
Other liabilities		(5,080	)		(3,745	)

Net cash provided by operating activities		589,143			722,200

See accompanying Notes to Consolidated Financial Statements.

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


	Nine Months Ended
	September 30,
(In thousands)	2008			2007
Cash Flows From Investing Activities:
Capital expenditures		(714,349	)		(590,305	)
Proceeds from asset sales		400			1,764
Purchase of Merrill Lynch interest in subsidiary		(50,000	)		—
Decrease (increase) in restricted funds		177,639			(388,541	)
Other investments		(4,054	)		(3,951	)

Net cash used in investing activities		(590,364	)		(981,033	)


Cash Flows From Financing Activities:
Repayment of note payable		(10,000	)		—
Issuance of long-term debt		305,638			450,577
Repayment of long-term debt		(384,589	)		(91,974	)
Redemption of preferred stock of subsidiary		—			(25,148	)
Equity contribution to PATH, LLC by a joint venture partner		4,460			—
Payments on capital lease obligations		(6,667	)		(6,032	)
Proceeds from exercise of employee stock options		21,448			10,335
Cash dividends paid on common stock		(75,748	)		—

Net cash provided by (used in) financing activities		(145,458	)		337,758


Net increase (decrease) in cash and cash equivalents		(146,679	)		78,925
Cash and cash equivalents at beginning of period		258,750			114,138

Cash and cash equivalents at end of period	$	112,071		$	193,063


Supplemental Cash Flow Information:
Cash paid for interest (net of amount capitalized)	$	169,175		$	152,361

See accompanying Notes to Consolidated Financial Statements.

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


	September 30,			December 31,
(In thousands)	2008			2007
ASSETS
Current Assets:
Cash and cash equivalents	$	112,071		$	258,750
Accounts receivable:
Customer		184,820			195,545
Unbilled utility revenue		85,652			110,569
Wholesale and other		80,171			57,626
Allowance for uncollectible accounts		(14,346	)		(14,252	)
Materials and supplies		112,639			103,075
Fuel		111,888			72,506
Deferred income taxes		119,137			286,440
Prepaid taxes		54,217			48,343
Collateral deposits		54,827			59,527
Derivative assets		90,343			29
Restricted funds		28,432			47,501
Regulatory assets		117,213			73,299
Other		120,397			16,001

Total current assets		1,257,461			1,314,959

Property, Plant and Equipment, Net:
Generation		6,062,100			5,992,919
Transmission		1,158,848			1,126,657
Distribution		3,900,275			3,761,438
Other		463,745			452,525
Accumulated depreciation		(4,943,999	)		(4,795,925	)

Subtotal		6,640,969			6,537,614
Construction work in progress		1,114,862			658,966

Total property, plant and equipment, net		7,755,831			7,196,580

Investments and Other Assets:
Goodwill		367,287			367,287
Restricted funds — Fort Martin scrubber project		194,715			347,023
Investments in unconsolidated affiliates		28,001			27,875
Other		20,103			15,974

Total investments and other assets		610,106			758,159

Deferred Charges:
Regulatory assets		491,987			601,603
Other		73,702			35,288

Total deferred charges		565,689			636,891

Total Assets	$	10,189,087		$	9,906,589

See accompanying Notes to Consolidated Financial Statements.

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


	September 30,			December 31,
(In thousands, except share amounts)	2008			2007
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	—		$	10,000
Long-term debt due within one year (Note 8)		92,479			95,367
Accounts payable		303,803			380,688
Accrued taxes		65,308			83,580
Derivative liabilities		11,498			14,117
Regulatory liabilities		55,726			4,029
Accrued interest		63,124			65,583
Security deposits		44,162			38,976
Other		124,109			95,163

Total current liabilities		760,209			787,503

Long-term Debt (Note 8)		3,881,085			3,943,947
Deferred Credits and Other Liabilities:
Derivative liabilities		8,501			12,815
Income taxes payable		76,620			68,050
Investment tax credit		66,913			69,353
Deferred income taxes		1,357,163			1,345,953
Obligations under capital leases		41,867			38,765
Regulatory liabilities		543,737			488,393
Adverse power purchase commitment		136,700			149,799
Other		437,078			453,418

Total deferred credits and other liabilities		2,668,579			2,626,546

Commitments and Contingencies (Note 17)
Minority Interest		5,173			13,241
Common Stockholders’ Equity:
Common stock—$1.25 par value per share, 260 million shares authorized and 169,103,200 and 167,273,069 shares issued at September 30, 2008 and December 31, 2007, respectively		211,379			209,091
Other paid-in capital		1,945,420			1,924,072
Retained earnings		747,564			444,177
Treasury stock at cost—49,493 shares		(1,756	)		(1,756	)
Accumulated other comprehensive loss		(28,566	)		(40,232	)

Total common stockholders’ equity		2,874,041			2,535,352

Total Liabilities and Stockholders’ Equity	$	10,189,087		$	9,906,589

See accompanying Notes to Consolidated Financial Statements.

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF COMMON STOCKHOLDERS’ EQUITY
For the Nine Months Ended September 30, 2008
(unaudited)


														Accumulated			Total
					Other									other			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		—		—		—			379,240			—			—			379,240
Defined benefit pension and other benefit plan amortization:
Net actuarial loss, net of tax of $112		—		—		—			—			—			138			138
Net transition obligation, net of tax of $524		—		—		—			—			—			644			644
Net prior service cost, net of tax of $255		—		—		—			—			—			312			312
Unrealized losses on available-for-sale securities, net of tax of $3		—		—		—			—			—			5			5
Cash flow hedges, net of tax of $6,741		—		—		—			—			—			10,567			10,567
Dividends on common stock		—		—		—			(75,748	)		—			—			(75,748	)
Stock-based compensation expense:
Stock units		—		—		638			—			—			—			638
Non-employee director stock awards		19,097		24		811			(26	)		—			—			809
Stock options		—		—		6,901			—			—			—			6,901
Performance shares		—		—		1,497			—			—			—			1,497
Exercise of stock options		1,558,452		1,948		19,500			—			—			—			21,448
Settlement of stock units		252,582		316		(8,078	)		—			—			—			(7,762	)
Dividends on stock units		—		—		79			(79	)		—			—			—


Balance at September 30, 2008		169,053,707	$	211,379	$	1,945,420		$	747,564		$	(1,756	)	$	(28,566	)	$	2,874,041

See accompanying Notes to Consolidated Financial Statements.

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


Note No.		Page No.
1	Basis of Presentation	11

2	Recent Accounting Pronouncements	12

3	Transmission Expansion Projects	13

4	Acquisition of Minority Interest in AE Supply	14

5	Rates and Regulation	14

6	Regulatory Assets and Liabilities	23

7	Income Taxes	24

8	Common Stock and Debt	25

9	Business Segments	28

10	Fair Value Measurements, Derivative Instruments and Hedging Activities	29

11	Stock-Based Compensation	31

12	Pension Benefits and Postretirement Benefits Other Than Pensions	35

13	Comprehensive Income and Accumulated Other Comprehensive Loss	37

14	Income Per Common Share	38

15	Other Income (Expense), Net	39

16	Guarantees and Letters of Credit	40

17	Commitments and Contingencies	41

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

NOTE 1: BASIS OF PRESENTATION

Business Description

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

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” and, together with Monongahela and Potomac Edison, 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 Trans-Allegheny Interstate Line Company (“TrAIL Company”), Potomac-Appalachian Transmission Highline, LLC (“PATH, LLC”) and Allegheny Ventures, Inc. (“Allegheny Ventures”). 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 high-voltage transmission line to extend through West Virginia and into Maryland. See Note 3, “Transmission Expansion Projects.”

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 September 30, 2008, its results of operations for the three and nine months ended September 30, 2008 and 2007 and its cash flows for the nine months ended September 30, 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.

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

Allegheny performed an annual goodwill impairment test as of August 31, 2008 in accordance with the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) 142, “Goodwill and Other Intangible Assets” and determined that there was no impairment of recorded goodwill at that date.

NOTE 2: RECENT ACCOUNTING PRONOUNCEMENTS

SFAS 157

In September 2006, the FASB issued 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 application 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 “Fair Value Measurements, Derivative Instruments and Hedging Activities,” for information related to Allegheny’s adoption of SFAS 157.

FSP FAS 157-3

In October 2008, the FASB issued FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active” (“FSP FAS 157-3”). FSP FAS 157-3 clarifies the application of SFAS 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. FSP FAS 157-3 was effective upon its issuance, including prior periods for which financial statements have not been issued. Allegheny’s adoption of FSP FAS 157-3 did not have a material impact on its financial statements.

SFAS 159

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 September 30, 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.

FIN 39-1

In April 2007, the FASB issued Interpretation No. 39-1, “Amendment of Interpretation 39” (“FIN 39-1”). FIN 39-1 permits entities that are parties 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.

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

SFAS 161

In March 2008, the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities -an amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 requires entities to provide qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of derivative contracts and the gains and losses on derivative contracts, and details of credit-risk-related contingent features in their hedged positions. SFAS 161 also requires disclosure of the location of the derivative contracts and their related gains and losses in an entity’s financial statements. SFAS 161 is effective for Allegheny beginning January 1, 2009, and will have no impact on Allegheny’s results of operations or financial condition.

NOTE 3: TRANSMISSION EXPANSION PROJECTS

Trans-Allegheny Interstate Line

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. In October 2006, Allegheny formed TrAIL Company as the entity responsible for financing, constructing, owning, operating and maintaining the new line, which is named the Trans-Allegheny Interstate Line, or “TrAIL.” TrAIL is a 500 kV high voltage line that currently is proposed to extend from southwestern Pennsylvania through West Virginia to a point of interconnection with Virginia Electric and Power Company (“Dominion”) in northern Virginia. In addition, TrAIL Company and Dominion will jointly own a 30-mile 500 kV line segment that Dominion will construct in Virginia. In addition to the TrAIL project, other TrAIL Company projects include a new static VAR compensator at the Black Oak substation, upgrades and/or replacements of transformers and/or buses at six other substations and the construction of a new transmission operations center to be located in West Virginia. See Note 5, “Rates and Regulation” for additional information regarding these transmission expansion projects.

Potomac-Appalachian Transmission Highline

In June 2007, the board of PJM directed the construction of PATH, a high-voltage transmission line project that originally was proposed to 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 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. In September 2007, Allegheny entered into a joint venture agreement with AEP to construct PATH. The joint venture, PATH, LLC, is a series limited liability company.

On October 15, 2008, PJM announced a reconfiguration of PATH. The reconfiguration is a result of constraints identified from comprehensive siting studies; interaction with government agencies; public input; and a desire to identify a solution that reduces line mileage and minimizes the impact on communities and the environment. The new configuration will consist of a single 765 kV line from the AEP substation near St. Albans, West Virginia to a new substation near Kemptown, Maryland; eliminate the connection with the Bedington substation and the twin-circuit 500 kV lines from Bedington to Kemptown; and include a new midpoint substation in West Virginia in the vicinity of eastern Grant County, northern Hardy County, or southern Hampshire County. PJM has confirmed that the reconfigured project addresses its reliability concerns. On October 31, 2008, PJM released the results of studies that change the required in-service date for PATH to June 2013. See Note 5, “Rates and Regulation” for additional information regarding these transmission expansion projects.

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.”

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

NOTE 4: ACQUISITION OF MINORITY INTEREST IN AE SUPPLY

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 recording expense relating to the minority interest in AE Supply as of January 1, 2008.

NOTE 5: RATES AND REGULATION

FERC

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

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

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 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 for the Seventh Circuit.

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 through commitments by load serving entities (“LSEs”) to self-supply their capacity needs. On December 22, 2006, FERC conditionally approved the settlement agreement, the implementation of which began with the 2007-2008 PJM planning year. Capacity auctions were held in April, July and October of 2007 and in January and May of 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 May 30, 2008, several parties naming themselves the “RPM Buyers” filed a complaint at FERC seeking a retroactive reduction in the RPM clearing prices for several RPM auctions that have already been conducted. On September 19, 2008, FERC issued an order denying the RPM Buyers complaint. Requests for rehearing of the September 19, 2008 order are pending at FERC.

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

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 at FERC, which was accepted on May 15, 2008.

TrAIL Project.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 Federal Power Act (the “FPA”) 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. 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 with FERC a settlement in this case. The settlement, which was approved by FERC on July 21, 2008, provides for an incentive return on equity for TrAIL and the Black Oak SVC of 12.7 percent and a return on equity of 11.7 percent for non-incentive projects.

PATH Project.On December 28, 2007, PATH, LLC submitted a filing to FERC under Section 205 of the FPA to implement a formula rate tariff to be effective March 1, 2008. The filing also included a request for certain incentive rate treatments. On February 29, 2008, FERC issued an order granting 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 start-up business and administrative costs prudently 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 and settlement discussions on this issue are underway. Several parties have requested rehearing of the February 29, 2008 order.

Pennsylvania

Default Service Regulation.Rate caps on transmission services in Pennsylvania expired on December 31, 2005. Distribution rate caps also were scheduled to expire on December 31, 2005, and generation rate caps were scheduled to expire on December 31, 2008. By order entered May 11, 2005, the Pennsylvania Public Utility Commission (the “Pennsylvania PUC”) approved an extension of generation rate caps from 2008 to 2010 and provided for increases in generation rates in 2007, 2009 and 2010, in addition to previously approved rate cap increases for 2006 and 2008. The order also extended distribution rate caps from 2005 to 2007, with an additional rate cap in place for 2009 at the rate in effect on January 1, 2009. The intent of this transition plan is to gradually move generation rates closer to market prices.

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 (“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.

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

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. The administrative law judge issued an initial decision on May 21, 2008, adopting the majority of West Penn’s proposed default service plan, including procurements through full requirements contracts with bid selections based on price and a rate mitigation plan under which residential and small commercial customers may opt to defer rate increases of over 25 percent, based on the customer’s total bill, for a period of up to three years at an interest rate of six percent. On July 25, 2008, the Pennsylvania PUC issued a final order largely approving West Penn’s proposed procurement approach and rate mitigation plan. On September 23, 2008, West Penn filed a tariff supplement implementing the default service plan.

On October 15, 2008, Pennsylvania’s H.B. 2200, which includes a number of measures relating to conservation, demand-side management and power procurement processes, was signed into law. Among other things, the bill:

	•		directs the Pennsylvania PUC to adopt an energy conservation and efficiency program to require EDCs to submit and implement plans to reduce energy demand and consumption;

	•		requires EDCs to file a plan for “smart meter” procurement and installation; and

	•		requires EDC’s to obtain energy through a prudent mix of contracts, with an emphasis on competitive procurement.

The bill includes a “grandfather” provision for West Penn’s procurement and rate mitigation plan that was previously approved by the Pennsylvania PUC.

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. On August 21, 2008, the Administrative Law Judges issued a Recommended Decision recommending rejection of TrAIL Company’s application. On September 10, 2008, TrAIL Company filed exceptions to the Recommended Decision. In addition, TrAIL Company filed a motion requesting a partial stay of action on the portion of the application relating to a new substation to be constructed in Washington County, Pennsylvania (the “Prexy Substation”), the portion of TrAIL (the “Prexy Segment”) extending from the Prexy Substation to, but excluding, a new substation to be constructed in Greene County, Pennsylvania (the “502 Junction Substation”) and three 138 kV transmission lines originating at the Prexy Substation and connecting to the Allegheny Power transmission system (the “Prexy 138 kV Lines” and, together with the Prexy Substation and the Prexy Segment, the “Prexy Facilities”) and further requesting the Pennsylvania PUC to direct TrAIL Company and the other active parties in the proceeding to engage in a collaborative process to identify new alternatives to the proposed Prexy Facilities. Most other active parties opposed the motion. On September 25, 2008, TrAIL Company filed with the Pennsylvania PUC an agreement entered into with the Greene County, Pennsylvania Board of Commissioners (“Greene County”). Among other provisions, TrAIL Company agreed to engage in a collaborative process to identify possible solutions to reliability problems in the Washington County area in lieu of the proposed Prexy Facilities, West Penn agreed to release certain easements that would have been used for the Prexy Facilities,

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

and Greene County agreed that the Pennsylvania PUC should approve the portion of the application pertaining to the proposed 502 Junction Substation and the portion of TrAIL extending from the 502 Junction Substation to the Pennsylvania/West Virginia border (together, the “Pennsylvania 502 Junction Facilities”). Except for the portion of the agreement relating to the release of certain easements, the agreement is not effective until approved by the Pennsylvania PUC and the issuance of an order authorizing construction of the Pennsylvania 502 Junction Facilities.

West Virginia

Rate Case.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 reduces Allegheny’s annual revenues by approximately $6 million and decreases 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 are being 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 in “Deferred energy costs, net.” 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.

Annual Adjustment of Fuel and Purchased Power Cost Rates.On August 29, 2008, Monongahela and Potomac Edison filed with the West Virginia PSC a request to increase retail rates by approximately $173 million annually to reflect expected increases in fuel and purchased power costs during 2009. The new rates, proposed to become effective January 1, 2009, were submitted pursuant to the schedule for annual fuel and purchased power cost reviews that was approved by the West Virginia PSC when it reinstated a fuel cost recovery clause in the rate case described above. Hearings on the proposed rates are scheduled for December 1 and 2, 2008.

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 of the West Virginia PSC and the West Virginia Energy Users Group (the “WVEUG”). The settlement provided 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 transmission operations 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;

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

	•		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 the 502 Junction Substation through West Virginia to northern 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 was 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 was held on May 30, 2008. On August 1, 2008, the West Virginia PSC issued an order authorizing construction of the TrAIL project in West Virginia subject to certain conditions, including indicia of state commission approval to construct the portion of the TrAIL project from the 502 Junction Substation to the Loudoun Substation in Pennsylvania and Virginia. TrAIL Company and other parties have requested reconsideration of certain aspects of the order. An order on reconsideration has not been issued.

Maryland

In December 2006, Potomac Edison proposed a rate stabilization and market transition plan (the “Transition Plan”) for its Maryland residential customers, in accordance with a bill passed by the Maryland legislature in 2006. The Maryland Public Service Commission approved the Transition Plan on March 30, 2007. The Transition Plan provides for a gradual transition of Potomac Edison’s residential customers in Maryland from capped generation rates to market-based generation rates, while at the same time preserving for customers the benefit of rate caps.

Under the Transition Plan, Potomac Edison’s customers in Maryland who did not opt out of the Transition Plan began paying a non-bypassable surcharge (the “Rate Stabilization Surcharge”) in June 2007, which will result in an overall rate increase of approximately 15%, after taking into account the expiration of a prior customer choice rate credit with the initiation of the new surcharge. On January 1, 2008, the surcharge increased residential rates an additional 15%.

Beginning January 1, 2009, coincident with the expiration of the residential generation rate cap and implementation of market-based generation pricing, the Rate Stabilization Surcharge will convert from a charge to a credit on customers’ bills. Funds collected through the Rate Stabilization Surcharge during 2007 and 2008, plus interest, will be returned to customers as a credit on their electric bills, thereby reducing the impact of the rate cap expiration. The credit will continue, with adjustments, to maintain rate stability until approximately December 31, 2010.

The Rate Stabilization Surcharge is being recorded directly to a regulatory liability as it is billed to customers. In addition, interest on amounts collected from customers is recognized as a component of the regulatory liability for future refund to customers. This interest is recorded as interest expense on the Consolidated Statements of Income. As amounts are returned to customers as a surcharge credit in future periods, these customer credits will be charged directly to the regulatory liability.

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

Standard Offer Service.In 2003, the Maryland PSC approved two state-wide settlements relating to the future of PLR and standard offer service (“SOS”). The settlements extended Potomac Edison’s obligation to provide SOS after the expiration of the generation rate cap periods established for Potomac Edison as part of the 1999 restructuring of Maryland’s electric market. The settlements provided that, after expiration of the generation rate caps, SOS would be provided through 2012 for residential customers, through 2008 for smaller commercial and industrial customers and through 2006 for Potomac Edison’s medium-sized commercial customers. Potomac Edison’s obligation to provide SOS for its largest industrial customers expired at the end of 2005. A 2005 settlement extended Potomac Edison’s SOS obligations to its medium-sized commercial customers through May 2007, and a further order of the Maryland PSC issued on August 28, 2006 extended that obligation through at least the end of May 2009.

The Maryland PSC issued an order on November 8, 2006, and a report to the Maryland legislature on December 31, 2006, that would continue SOS to small and medium-sized commercial customers with changes in procurement durations. The Maryland PSC then opened a new docket in August 2007 (Case No. 9117) to consider matters relating to possible “managed portfolio” approaches to SOS, the aggregation of low income SOS customers, and a retail supplier proposal for the utility “purchase” of all retailer receivables at no discount and with no recourse. “Phase II” of the case addressed utility purchases or construction of generation, bidding for procurement of 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.

On July 3, 2008, the Maryland PSC issued a further order requiring the utilities to prepare detailed studies of alternatives for possible managed portfolios, with a time horizon out to fifteen years, and to file those studies by October 1, 2008. The Maryland PSC expressly stated that the order, “should not be construed ... as a decision to modify in any way, the current SOS procurement practice.” Potomac Edison filed its study with the Maryland PSC on October 1, 2008.

In August 2007, Potomac Edison filed a plan for seeking bids to serve its Maryland residential load for the period after the rate cap expires on December 31, 2008. The Maryland PSC approved the plan in a series of orders issued between September 2007 and September 2008.

Virginia

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

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.

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

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 State Corporation Commission (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 purchased 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. On October 31, 2008, the Virginia Supreme Court affirmed the Virginia SCC’s December 20, 2007 order.

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

developed and not on the amounts collected. As a result, a portion of the amounts collected subsequent to July 1, 2008 is being deferred pending a final order in this matter. The amount deferred at September 30, 2008 was approximately $14 million.

The Virginia SCC set the application for an evidentiary hearing on the merits on October 21, 2008, and later postponed the hearing to November 18, 2008 at the request of the Virginia Consumers Counsel. In the meantime, on July 3, 2008, the Virginia SCC held a hearing on the meaning of “financial distress” under Virginia’s utility laws and other legal issues, including a motion by the Staff of the Virginia SCC to bar Potomac Edison from paying a dividend to its corporate parent. Potomac Edison has not paid any dividends since the first adverse order of the Virginia SCC was issued in June 2007. On July 18, 2008, the Virginia SCC issued an order finding that the ratemaking provisions of the MOU expire on December 31, 2008 and requiring additional evidence and legal argument to set rates for 2008 and 2009. The Virginia SCC’s order also directed Potomac Edison to file a plan for meeting its projected load obligations in Virginia, including alternatives for placing generation in its rate base to serve Virginia customers, which filing Potomac Edison made on August 1. The July 18th order deferred action on the Staff’s motion to bar Potomac Edison from paying dividends. On July 28, 2008, Potomac Edison filed a motion to amend and supplement the April 30, 2008 application seeking to recover an additional $5.0 million for the period July 1, 2007 through December 19, 2007. The motion to amend was granted, but the Virginia SCC has not yet ruled on the merits of whether Potomac Edison may recover the additional revenue.

If Potomac Edison is not granted rate relief, including if the interim rate increase is revoked, 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 September 30, 2008, Potomac Edison’s total stockholder’s equity was approximately $401 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 the MOU will no longer be in effect, and Potomac Edison 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 its full 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, in the absence of rate relief, would continue to have a materially negative effect on Potomac Edison’s cash flow, results of operations, financial condition and overall business. Without the ability to recover its purchased power costs, Potomac Edison’s revenues would not be sufficient to fund its ongoing operations and maintenance costs and necessary capital expenditures, and the under-recovery to which Potomac Edison’s Virginia operations are subject would exhaust its capacity to borrow additional funds to support its operations by the third quarter of 2009. Absent adequate rate relief, Potomac Edison may postpone or eliminate some or all planned capital and other expenditures, although 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.

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 on this matter concluded on March 18, 2008, but was reopened on July 8, 2008 to receive additional evidence. On October 7, 2008, the Virginia SCC issued an order authorizing construction of the TrAIL project in Virginia. The order is conditioned upon receipt of state commission authorization of the West Virginia and Pennsylvania portions of the project extending from the 502 Junction Substation to the Loudoun Substation.

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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 probable of being recovered in the future from customers through the ratemaking process. Regulatory liabilities generally represent probable future reductions in revenues associated with amounts that are to be credited or refunded to customers through the ratemaking process. Regulatory assets and regulatory liabilities in the Consolidated Balance Sheets were comprised of the following:

	��
	September 30,		December 31,
(In millions)	2008		2007
Regulatory assets, including current portion:
Income taxes (a)(b)	$	225.6	$	251.4
Pension benefits and postretirement benefits other than pensions (a)(c)		192.8		202.7
Pennsylvania stranded cost recovery		—		13.7
Pennsylvania Competitive Transition Charge (“CTC”) reconciliation		93.2		117.7
Unamortized loss on reacquired debt (a)(d)		32.1		35.3
Deferred ENEC charges (e)(f)		25.1		9.4
Other (g)		40.4		44.7

Subtotal		609.2		674.9

Regulatory liabilities, including current portion:
Net asset removal costs		406.2		396.4
Unrealized gain on increased fair value of financial transmission rights		46.1		—
Income taxes		35.3		36.8
SO₂ allowances		13.4		13.8
Fort Martin scrubber project—environmental control surcharge (e)		27.6		33.4
Maryland rate stabilization and transition plan surcharge		48.4		6.9
Other		22.5		5.1

Subtotal		599.5		492.4

Net regulatory assets	$	9.7	$	182.5


(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 September 30, 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 amounts that do not earn a return with recovery periods up to one year.

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

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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												Nine Months Ended
	September 30,												September 30,
	2008						2007						2008						2007
(In millions, except percent)	Amount			%			Amount			%			Amount			%			Amount			%
Income before income taxes and minority interest	$	133.5					$	183.7					$	572.4					$	495.7
Preferred dividends of subsidiary		—						0.1						—						0.7

Subtotal		133.5						183.8						572.4						496.4

Income tax expense calculated using the federal statutory rate of 35%		46.7			35.0			64.3			35.0			200.3			35.0			173.7			35.0
Increases (reductions) resulting from:
Rate-making effects of depreciation differences		2.0			1.5			1.9			1.0			5.9			1.0			5.8			1.2
Plant removal costs		(1.3	)		(1.0	)		(0.6	)		(0.3	)		(3.9	)		(0.7	)		(1.8	)		(0.4	)
State income tax, net of federal income tax benefit		2.3			1.7			6.4			3.5			13.5			2.4			15.7			3.2
Amortization of deferred investment tax credit		(1.0	)		(0.7	)		(0.9	)		(0.5	)		(2.7	)		(0.5	)		(2.7	)		(0.6	)
Estimated Pennsylvania net operating loss benefits		—			—			(4.2	)		(2.3	)		(3.0	)		(0.5	)		(4.2	)		(0.8	)
West Virginia state income tax change		—			—			—			—			(6.7	)		(1.2	)		—			—
Changes in tax reserves related to uncertain tax positions		(2.7	)		(2.0	)		(1.2	)		(0.6	)		(7.7	)		(1.3	)		3.5			0.7
Other, net		(1.7	)		(1.3	)		1.5			0.8			(3.3	)		(0.6	)		1.5			0.3

Total income tax expense	$	44.3			33.2		$	67.2			36.6		$	192.4			33.6		$	191.5			38.6

On July 2, 2006, the Commonwealth of Pennsylvania budget for fiscal year 2006-2007 was enacted. The budget included a provision that raised the annual limit on the amount of net operating loss carryforwards that may be used to reduce current year taxable income from $2 million per year to the greater of $3 million or 12.5% of apportioned

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

Pennsylvania state taxable income per year, effective January 1, 2007. The carryforward limitation period remained unchanged at 20 years. From time to time since the law was amended in 2006, Allegheny has recorded additional benefits to reflect the estimated portion of the loss carryforwards that will be realized during the carryforward period. During the three months ended June 30, 2008, an additional benefit of $3.0 million, net of federal income tax, was recorded as a result of estimated additional Pennsylvania taxable income.

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 from 2009 through 2014. During the three months ended March 31, 2008, Allegheny recognized a benefit of approximately $6.7 million, net of federal income tax, representing an adjustment of its deferred tax assets and liabilities to reflect the effects of this reduction.

Allegheny records certain reserves related to uncertain tax positions. The Internal Revenue Service (“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. Allegheny reached a tentative settlement with the IRS on this matter, which resulted in a benefit of approximately $6.1 million recorded during the three months ended March 31, 2008.

Allegheny’s IRS audits for the years 1998-2003 are currently under review by the Joint Committee on Taxation. In October 2008, the Joint Committee made certain inquiries regarding a settlement Allegheny reached with the Appeals Division in 2006 relating to contributions to capital, based on a court decision regarding another tax payer rendered in 2008. It is possible that the Joint Committee review could reopen the Appeals Division settlement on this issue. Should the settlement be reversed in its entirety, the estimated charge to Allegheny’s earnings, including tax and interest, would be $12.0 to $15.0 million.

NOTE 8: COMMON STOCK AND DEBT

Common Stock

On September 29, 2008, June 23, 2008 and March 24, 2008, AE paid cash dividends on its common stock of $0.15 per share to shareholders of record on September 15, 2008, June 9, 2008 and March 10, 2008, respectively. On October 2, 2008, AE’s Board of Directors authorized a cash dividend on its common stock of $0.15 per share payable on December 29, 2008 to shareholders of record on December 15, 2008.

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

Debt

Outstanding debt and scheduled debt repayments at September 30, 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		—			—			—			90.0			—			—			90.0
Pollution Control Bonds		—			—			—			—			1.3			267.2			268.5
Debentures-AGC		—			—			—			—			—			100.0			100.0

Total AE Supply	$	—		$	—		$	—		$	937.0		$	651.3		$	367.2		$	1,955.5

Monongahela:
Environmental Control Bonds (a)	$	—		$	10.6		$	11.1		$	11.6		$	12.2		$	284.0		$	329.5
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	$	—		$	10.6		$	121.1		$	11.6		$	18.2		$	688.3		$	849.8

West Penn:
First Mortgage Bonds	$	—		$	—		$	—		$	—		$	—		$	420.0		$	420.0
Transition Bonds (a)		18.6			79.8			16.0			—			—			—			114.4
Medium-Term Notes		—			—			—			—			80.0			—			80.0

Total West Penn	$	18.6		$	79.8		$	16.0		$	—		$	80.0		$	420.0		$	614.4

Potomac Edison:
First Mortgage Bonds	$	—		$	—		$	—		$	—		$	—		$	420.0		$	420.0
Environmental Control Bonds (a)		—			3.5			3.7			3.9			4.1			94.8			110.0

Total Potomac Edison	$	—		$	3.5		$	3.7		$	3.9		$	4.1		$	514.8		$	530.0

TrAIL Company:
Term Loan	$	—		$	—		$	—		$	—		$	—		$	45.0		$	45.0

Total TrAIL	$	—		$	—		$	—		$	—		$	—		$	45.0		$	45.0

Unamortized debt discounts		(0.4	)		(1.5	)		(1.3	)		(1.1	)		(0.6	)		(1.8	)		(6.7	)
Eliminations (b)		—			—			—			—			(1.3	)		(13.1	)		(14.4	)

Total consolidated debt	$	18.2		$	92.4		$	139.5		$	951.4		$	751.7		$	2,020.4		$	3,973.6


(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.

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

2008 Debt Activity

Issuances of indebtedness and repayments of principal on indebtedness, during the nine months ended September 30, 2008 were as follows:


(In millions)	Issuances		Repayments
AE Supply:
AE Supply Credit Facility:
Term Loan	$	—	$	125.0
Revolving Loan		250.0		160.0
TrAIL Company:
Short-Term Promissory Note		—		10.0
TrAIL Company Credit Facility:
Term Loan		45.0		—
Revolving Loan		20.0		20.0
West Penn:
Transition Bonds		2.8		59.8
Monongahela:
Environmental Control Bonds		—		14.9
Potomac Edison:
Environmental Control Bonds		—		4.9

Consolidated Total	$	317.8	$	394.6

On August 15, 2008, TrAIL Company entered into a $550 million senior secured credit facility with a seven-year maturity in connection with its proposed construction of the TrAIL project. The facility includes a $530 million construction loan and a $20 million revolving facility, both with an initial borrowing rate equal to the London Interbank Offered Rate plus 1.875 percent.

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

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 September 30, 2008										Three Months Ended September 30, 2007
	Delivery			Generation							Delivery		Generation
	and			and							and		and
(In millions)	Services			Marketing		Eliminations			Total		Services		Marketing		Eliminations			Total
External operating revenues	$	690.8		$	158.8	$	—		$	849.6	$	690.2	$	156.4	$	—		$	846.6
Internal operating revenues		1.9			430.5		(432.4	)		—		2.2		424.7		(426.9	)		—

Total operating revenues	$	692.7		$	589.3	$	(432.4	)	$	849.6	$	692.4	$	581.1	$	(426.9	)	$	846.6
Depreciation	$	38.2		$	28.1	$	—		$	66.3	$	35.7	$	26.3	$	—		$	62.0
Amortization	$	1.0		$	0.1	$	—		$	1.1	$	4.7	$	—	$	—		$	4.7
Operating income	$	20.5		$	166.4	$	—		$	186.9	$	37.1	$	191.4	$	—		$	228.5
Interest expense	$	24.8		$	33.3	$	(0.2	)	$	57.9	$	18.1	$	43.1	$	(1.8	)	$	59.4
Income tax expense (benefit)	$	(5.7	)	$	50.0	$	—		$	44.3	$	9.1	$	58.1	$	—		$	67.2
Net income	$	4.3		$	84.7	$	—		$	89.0	$	12.8	$	102.2	$	—		$	115.0


	Nine Months Ended September 30, 2008									Nine Months Ended September 30, 2007
	Delivery		Generation							Delivery		Generation
	and		and							and		and
(In millions)	Services		Marketing		Eliminations			Total		Services		Marketing		Eliminations			Total
External operating revenues	$	2,133.6	$	544.5	$	—		$	2,678.1	$	2,121.3	$	399.4	$	—		$	2,520.7
Internal operating revenues		6.0		1,297.5		(1,303.5	)		—		7.5		1,231.5		(1,239.0	)		—

Total operating revenues	$	2,139.6	$	1,842.0	$	(1,303.5	)	$	2,678.1	$	2,128.8	$	1,630.9	$	(1,239.0	)	$	2,520.7
Depreciation	$	113.4	$	83.7	$	—		$	197.1	$	107.7	$	87.7	$	—		$	195.4
Amortization	$	9.2	$	0.2	$	—		$	9.4	$	14.0	$	—	$	—		$	14.0
Operating income	$	113.8	$	618.3	$	—		$	732.1	$	203.6	$	446.9	$	—		$	650.5
Interest expense	$	70.7	$	106.7	$	(2.4	)	$	175.0	$	55.0	$	131.2	$	(4.6	)	$	181.6
Income tax expense	$	10.0	$	182.5	$	—		$	192.5	$	66.9	$	124.6	$	—		$	191.5
Net income	$	42.5	$	336.7	$	—		$	379.2	$	91.7	$	210.1	$	—		$	301.8

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

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

Effective January 1, 2008, Allegheny adopted SFAS 157 for assets and liabilities measured at fair value. 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.

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

Allegheny acquires its FTRs in an annual PJM auction through a self-scheduling process involving the use of auction revenue rights (“ARRs”) allocated to PJM members that have load serving obligations. During the first quarter of 2008, Allegheny changed the way it estimates and presents the fair value of FTRs in its financial statements. Prior to January 1, 2008 Allegheny recorded realized gains or losses each month as the FTRs settled and as the cost of power purchased from PJM was recorded for that month.

Allegheny’s FTRs have not been designated in hedge accounting relationships. As a result, changes in the fair value of FTRs, other than FTRs held by Allegheny’s regulated subsidiaries, are reflected in earnings. Allegheny recorded unrealized losses of $106.6 million and unrealized gains of $94.4 million in the three and nine months ended September 30, 2008, respectively, before income tax effects, representing changes in the estimated fair value of its FTRs. Derivative assets at September 30, 2008 include FTRs in the amount of $524.6 million less an FTR obligation to PJM in the amount of $483.9 million. The FTR obligation is payable to PJM in approximately equal monthly amounts through the PJM planning year ending May 31, 2009.

Allegheny’s FTRs generally represent an economic hedge of future congestion charges that will be incurred in future periods to serve Allegheny’s load obligations, and these obligations are not reflected on its consolidated

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

balance sheets. As a result, the timing of recognition of gains or losses on FTRs will differ from the timing of power purchases, including incurred congestion charges.

A portion of Allegheny’s power derivatives used for economic hedging purposes have not been designated in hedge accounting relationships. The portion of changes in the fair value of derivatives included in hedge accounting relationships representing hedge ineffectiveness, as well as changes in the fair value of derivatives not included in hedge accounting relationships, are reflected in earnings in periods prior to their settlement.

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


	Three Months Ended			Nine Months Ended
(Pre-tax amounts, in millions)	September 30, 2008			September 30, 2008
Accumulated OCI derivative loss at July 1, 2008 and January 1, 2008, respectively	$	(121.1	)	$	(7.0	)
Effective portion of changes in fair value		150.9			57.6
Reclassifications from accumulated OCI derivative loss to earnings		(19.4	)		(40.2	)

Accumulated OCI derivative gain at September 30, 2008	$	10.4		$	10.4

Derivative contracts included in commodity cash flow hedges at September 30, 2008 expire at various dates through May 2011. Accumulated other comprehensive income in the amount of $5.8 million is expected to be reclassified to earnings over the next twelve months.

The ineffective portion of changes in derivative fair values relating to power transaction cash flow hedges for the three months ended September 30, 2008 and 2007 were $21.8 million and $(0.2) million, respectively, and for the nine months ended September 30, 2008 and 2007 were $4.8 million and $(0.1) million, respectively. These amounts were recorded as increases (charges) to operating revenues.

The recorded fair values of derivatives at September 30, 2008 were as follows:


						Mark-to-
			Cash flow			market			Interest			Total			FTR			Cash			Net
(In millions)	FTRs		hedges			contracts (a)			rate swaps			derivatives			obligation			collateral			derivatives
Derivative assets:
Current	$	524.6	$	18.7		$	36.4		$	—		$	579.7		$	(483.9	)	$	(5.5	)	$	90.3
Long-term		—		7.5			7.1			—			14.6			—			0.3			14.9
Derivative liabilities:
Current		—		(10.6	)		(3.4	)		(5.9	)		(19.9	)		—			8.4			(11.5	)
Long-term		—		(0.5	)		(0.7	)		(7.8	)		(9.0	)		—			0.5			(8.5	)

Total derivatives	$	524.6	$	15.1		$	39.4		$	(13.7	)	$	565.4		$	(483.9	)	$	3.7		$	85.2



(a)		Includes economic gas hedges and unrealized changes in value for power contracts previously not designated in cash flow hedge accounting relationships.

Other than derivative assets and derivative liabilities, Allegheny had no significant financial or non-financial assets or liabilities recognized at fair value in its financial statements at September 30, 2008.

The following table disaggregates the net fair values of derivative assets and liabilities, before netting of cash collateral and FTR obligation, based on their level within the fair value hierarchy at September 30, 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	$	5.2		$	64.5		$	524.6	$	594.3
Derivative liabilities		(6.7	)		(22.2	)		—		(28.9	)

Net derivative assets (liabilities)	$	(1.5	)	$	42.3		$	524.6	$	565.4

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

The following table shows the expected settlement year for derivative assets and liabilities outstanding at September 30, 2008 before netting of cash collateral and FTR obligation:


(In millions)	2008			2009			2010			2011			2012		Total
Level 1	$	(0.1	)	$	(2.4	)	$	1.3		$	(0.3	)	$	—	$	(1.5	)
Level 2		13.8			37.3			(6.6	)		(2.2	)		—		42.3
Level 3		182.4			342.2			—			—			—		524.6

Net derivative assets (liabilities)	$	196.1		$	377.1		$	(5.3	)	$	(2.5	)	$	—	$	565.4

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


	Three Months Ended			Nine Months Ended
(In millions)	September 30, 2008			September 30, 2008
Balance at July 1, 2008 and January 1, 2008, respectively	$	958.4		$	150.0
Total realized and unrealized gains (losses):
Included in earnings, in operating revenues		(154.2	)		161.0
Included in regulatory assets or liabilities		(74.8	)		77.8
Purchases, issuances and settlements		(204.8	)		135.8
Transfers in / out of Level 3		—			—

Balance at September 30, 2008	$	524.6		$	524.6

Amount of total gains (losses) included in earnings attributable to the change in unrealized gains related to Level 3 assets held at September 30, 2008	$	(63.2	)	$	94.4

NOTE 11: STOCK-BASED COMPENSATION

On May 15, 2008, AE’s stockholders approved the Allegheny Energy, Inc. 2008 Long-Term Incentive Plan (the “2008 LTIP”). The 2008 LTIP authorized the grant of equity-based compensation to AE’s directors and to its executives and other key employees in the form of performance awards, stock options and stock appreciation rights, restricted shares, and restricted stock units. The purpose of the 2008 LTIP is to attract, motivate and retain AE’s executive officers and key employees who are expected to contribute to its future success and to align their interests with the interests of AE’s stockholders. AE also has outstanding stock options issued under its 1998 Long-Term Incentive Plan and outstanding stock units issued under its Stock Unit Plan.

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

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

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Stock options	$	2.1	$	1.9	$	6.9	$	5.3
Performance shares		1.1		—		1.5		—
Stock units		—		0.5		0.6		2.0
Other		0.3		0.1		0.8		0.8

Total stock-based compensation expense		3.5		2.5		9.8		8.1
Income tax benefit		1.4		1.0		3.9		3.3

Total stock-based compensation expense, net of tax	$	2.1	$	1.5	$	5.9	$	4.8

Stock-based compensation expense recognized for stock options and performance share awards for the three and nine months ended September 30, 2008 was based on awards ultimately expected to vest, using an estimated annual forfeiture rate of 5%. No stock-based compensation cost was capitalized during the nine months ended September 30, 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 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 stock price volatility was based on both historical stock volatility and the volatility levels implied on the grant date by actively traded option contracts on AE’s common stock. The following weighted-average assumptions were used to estimate the fair value of options granted during the three and nine months ended September 30, 2008 and 2007, respectively.


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Annual risk-free interest rate		3.58	%		4.58	%		3.18	%		4.66	%
Expected term of the option (in years)		6.36			5.63			6.04			5.62
Expected annual dividend yield		1.31	%		1.09	%		1.12	%		0.16	%
Expected stock price volatility		27.0	%		26.2	%		27.3	%		24.7	%
Grant date fair value per stock option	$	13.50		$	15.83		$	15.27		$	17.18

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

Stock option activity for the three months ended September 30, 2008 was as follows:


				Weighted-		Aggregate
				Average		Intrinsic
	Number of			Exercise		Value (a)
	Stock Options			Price		(in millions)
Outstanding at June 30, 2008		2,511,867		$	25.38
Granted		69,127		$	45.82
Exercised		(339,322	)	$	13.85
Forfeited/expired		(25,267	)	$	47.89

Outstanding at September 30, 2008		2,216,405		$	27.53	$	31.0

Exercisable at September 30, 2008		996,838		$	18.54	$	18.9


(a)		Represents the total pre-tax intrinsic value based on stock options with an exercise price less than AE’s closing stock price of $36.77 on September 30, 2008.

The grant date fair value of stock options granted during the three months ended September 30, 2008 and 2007 was $0.9 million and $0.1 million, respectively.

The total pre-tax intrinsic value of stock options exercised during the three months ended September 30, 2008 and 2007 was $10.2 million and $2.3 million, respectively, representing the difference between the market value of AE’s common stock at exercise and the exercise price of the options. Cash received by Allegheny from option exercises totaled $4.7 million and $1.3 million for the three months ended September 30, 2008 and 2007, respectively. AE issued new shares of its common stock to satisfy these stock option exercises.

Stock option activity for the nine months ended September 30, 2008 was as follows:


				Weighted-		Aggregate
				Average		Intrinsic
	Number of			Exercise		Value (a)
	Stock Options			Price		(in millions)
Outstanding at December 31, 2007		3,191,409		$	16.10
Granted		620,473		$	52.69
Exercised		(1,558,452	)	$	13.76
Forfeited/expired		(37,025	)	$	44.05

Outstanding at September 30, 2008		2,216,405		$	27.53	$	31.0

Exercisable at September 30, 2008		996,838		$	18.54	$	18.9


(a)		Represents the total pre-tax intrinsic value based on stock options with an exercise price less than AE’s closing stock price of $36.77 on September 30, 2008.

The grant date fair value of stock options granted during the nine months ended September 30, 2008 and 2007 was $9.5 million and $0.5 million, respectively.

The total pre-tax intrinsic value of stock options exercised during the nine months ended September 30, 2008 and 2007 was $59.1 million and $12.4 million, respectively, representing the difference between the market value of AE’s common stock at exercise and the exercise price of the options. Cash received by Allegheny from option exercises totaled $21.4 million and $10.3 million for the nine months ended September 30, 2008 and 2007, respectively. AE issued new shares of its common stock to satisfy these stock option exercises.

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.

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

As of September 30, 2008, there was approximately $10.2 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.

Stock Units

Stock unit activity for the three months ended September 30, 2008 was as follows:


				Weighted-		Aggregate
				Average		Intrinsic
	Number of			Grant Date		Value (a)
	Stock Units			Fair Value		(in millions)
Outstanding at June 30, 2008		40,336		$	15.47
Units settled (3,500 common shares issued)		(5,042	)	$	15.02
Dividend on unvested units		149		$	35.50

Outstanding at September 30, 2008		35,443		$	15.62	$	1.3


(a)		Represents the total pre-tax intrinsic value based on stock units outstanding multiplied by AE’s closing stock price of $36.77 on September 30, 2008.

Stock unit activity for the nine months ended September 30, 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 settled (252,582 common shares issued)		(417,260	)	$	15.51
Dividend on unvested units		1,648		$	47.91

Outstanding at September 30, 2008		35,443		$	15.62	$	1.3


(a)		Represents the total pre-tax intrinsic value based on stock units outstanding multiplied by AE’s closing stock price of $36.77 on September 30, 2008.

There were no stock units that were vested and convertible into common shares at September 30, 2008.

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

Performance Share Awards

During the nine months ended September 30, 2008, AE granted equity-based performance awards to key employees under which AE’s common shares may be earned based on AE’s performance compared to short-term incentive goals and on AE’s total shareholder return for a three-year period compared to the total shareholder return of companies in the Dow Jones US Electric Utilities Index. The grant-date fair value of these awards for the three and nine months ended September 30, 2008 was $0.2 million and $8.1 million, respectively. No performance share awards were granted in 2007.

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

Non-Employee Director Stock Plan

Non-employee director stock plan share activity for the three months ended September 30, 2008 was as follows:


	Number of
	Shares
Shares earned but not issued at June 30, 2008		58,757
Granted		7,344
Issued		(1,632	)
Dividends on earned but not issued shares		245

Shares earned but not issued at September 30, 2008		64,714

Non-employee director stock plan share activity for the nine months ended September 30, 2008 was as follows:


	Number of
	Shares
Shares earned but not issued at December 31, 2007		65,177
Granted		18,081
Issued		(19,097	)
Dividends on earned but not issued shares		553

Shares earned but not issued at September 30, 2008		64,714

NOTE 12: PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

Substantially all of Allegheny’s personnel, including officers, are employed by AESC and are covered by a noncontributory, defined benefit pension plan. Allegheny also maintains 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 for employees and covered dependents by Allegheny were as follows:


	Pension Benefits
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2008			2007			2008			2007
Components of net periodic cost:
Service cost	$	5.3		$	5.3		$	15.9		$	16.1
Interest cost		17.1			16.2			51.4			48.5
Expected return on plan assets		(19.2	)		(18.3	)		(57.6	)		(54.8	)
Amortization of unrecognized transition obligation		0.1			0.1			0.3			0.3
Amortization of prior service cost		0.8			0.8			2.4			2.4
Recognized actuarial loss		1.8			2.7			5.4			8.0

Net periodic cost	$	5.9		$	6.8		$	17.8		$	20.5

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

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


	Postretirement Benefits Other than Pensions
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2008			2007			2008			2007
Components of net periodic cost:
Service cost	$	1.1		$	1.1		$	3.3		$	3.4
Interest cost		4.3			4.3			12.8			12.7
Expected return on plan assets		(1.8	)		(1.7	)		(5.4	)		(5.0	)
Amortization of unrecognized transition obligation		1.4			1.4			4.3			4.2
Recognized actuarial loss		0.2			0.6			0.5			1.8

Net periodic cost	$	5.2		$	5.7		$	15.5		$	17.1

For the three months ended September 30, 2008 and 2007, Allegheny capitalized $3.4 million and $3.7 million, respectively, and for the nine months ended September 30, 2008 and 2007, Allegheny capitalized $9.8 million and $10.6 million, respectively, of the above net periodic cost amounts to “Construction work in progress,” a component of “Property, plant and equipment, net.”

Allegheny contributed $0.1 million and $35.2 million to its pension plans during the three and nine months ended September 30, 2008, respectively, including contributions to the SERP of $0.1 million and $0.2 million during the three and nine months ended September 30, 2008, respectively. Allegheny also contributed $3.3 million and $10.2 million to fund its postretirement benefit plans other than pension plans during the three and nine months ended September 30, 2008, respectively. Allegheny does not anticipate making any significant contributions to the pension plans during the remainder of 2008. Allegheny currently anticipates that it will contribute a total amount in 2008 ranging from $13.0 million to $15.0 million to fund postretirement benefits other than pensions.

Allegheny made matching cash contributions to the Employee Stock Ownership and Savings Plan in the amount of $2.2 million for each of the three months ended September 30, 2008 and 2007, and $6.7 million and $6.3 million for the nine months ended September 30, 2008 and 2007, respectively. These contributions were expensed, less amounts capitalized in “Construction work in progress.” The capitalized portions of these costs were $0.7 million and $0.6 million for the three months ended September 30, 2008 and 2007, respectively, and $1.9 million and $1.6 million for the nine months ended September 30, 2008 and 2007, respectively.

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

NOTE 13: COMPREHENSIVE INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS

Comprehensive income consisted of the following:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(In millions)	2008		2007			2008		2007
Net income	$	89.0	$	115.0		$	379.2	$	301.8
Cash flow hedges and other, net of tax of $51.0, $(1.6), $6.7 and $0.4, respectively		80.5		(2.5	)		10.6		0.7
Defined benefit pension and other benefit plan amortization, net of tax of $0.3, $0.6, $0.9 and $1.7, respectively		0.4		0.9			1.0		2.7
West Virginia Rate Order – establishment of regulatory asset related to pension obligation, net of tax of $35.7		—		—			—		52.3

Comprehensive income	$	169.9	$	113.4		$	390.8	$	357.5

The components of accumulated other comprehensive loss included in common stockholders’ equity were as follows:


	September 30,			December 31,
(In millions)	2008			2007
Cash flow hedges and other, net of tax of $4.1 and $(2.7), respectively	$	6.3		$	(4.3	)
Net unrecognized pension and other benefit plan costs, net of tax of $(23.6) and $(24.5), respectively		(34.9	)		(35.9	)

Total	$	(28.6	)	$	(40.2	)

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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					Nine Months Ended
	September 30,					September 30,
(In millions, except share and per share amounts)	2008		2007			2008		2007
Basic Income per Common Share:
Numerator:
Net income	$	89.0	$	115.0		$	379.2	$	301.8
Redemption of preferred stock (a)		—		(1.1	)		—		(1.1	)

Net income available for common shareholders	$	89.0	$	113.9		$	379.2	$	300.7


Denominator:
Weighted average common shares outstanding		168,894,148		166,101,169			168,232,547		165,798,727

Basic income per common share	$	0.53	$	0.69		$	2.25	$	1.81


Diluted Income per Common Share:
Numerator:
Net income	$	89.0	$	115.0		$	379.2	$	301.8
Redemption of preferred stock (a)		—		(1.1	)		—		(1.1	)

Net income available for common shareholders	$	89.0	$	113.9		$	379.2	$	300.7


Denominator:
Weighted average common shares outstanding		168,894,148		166,101,169			168,232,547		165,798,727
Effect of dilutive securities:
Stock options (b)		1,003,600		2,770,502			1,450,503		2,758,665
Stock units		36,766		493,652			276,238		728,057
Non-employee stock awards		58,887		64,715			55,084		59,938
Performance shares		12,448		25,497			8,573		25,497

Total shares		170,005,849		169,455,535			170,022,945		169,370,884

Diluted income per common share	$	0.52	$	0.67		$	2.23	$	1.78


(a)		On September 4, 2007, Monongahela redeemed its 4.40% Cumulative Preferred Stock, $100 par value, its 4.80% Cumulative Preferred Stock, Series B, $100 par value, its 4.50% Cumulative Preferred Stock, Series C, $100 par value and its $6.28 Cumulative Preferred Stock, Series D, $100 par value with an aggregate carrying value of $24.0 million. In connection with the cash redemption, Monongahela paid accrued dividends at the redemption date plus a redemption premium of approximately $1.1 million that was charged against other paid-in capital.

(b)		The dilutive share calculations exclude 637,846 shares and 35,696 shares for the three months ended September 30, 2008 and 2007, respectively, and 491,388 shares and 56,981 shares for the nine months ended September 30, 2008 and 2007, respectively, relating to stock options, because the inclusion of these amounts would have been antidilutive under the treasury stock method.

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

NOTE 15: OTHER INCOME (EXPENSE), NET

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


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(In millions)	2008		2007			2008			2007
Interest and dividend income	$	1.4	$	3.5		$	5.4		$	10.9
Gain on equity investment		—		—			1.3			—
Tax reimbursement on contributions in aid of construction		1.0		1.7			3.0			4.5
Gain on the sale or exchange of real estate		—		8.9			0.4			8.9
Cash received from a former trading executive’s forfeited assets		—		—			1.6			—
Equity component of AFUDC		1.0		0.7			2.4			1.9
Premium services		0.8		(0.4	)		1.4			0.7
Other		0.3		0.4			(0.2	)		0.7

Total	$	4.5	$	14.8		$	15.3		$	27.6

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

NOTE 16: GUARANTEES AND LETTERS OF CREDIT

In connection with certain sales, acquisitions and financings, and in the normal course of business, AE and its subsidiaries enter into various agreements that may include guarantees or require the issuance of letters of credit. AE has a $400 million revolving credit facility, any unutilized portion of which is available to AE for the issuance of letters of credit. Additionally, subject to certain conditions, AE Supply is permitted to require letters of credit of up to $50 million in the aggregate, and AE is permitted to request, on behalf of AE Supply and its subsidiaries, letters of credit of up to $125 million in the aggregate, under AE’s revolving credit facility. The revolving credit facility includes $24.0 million of commitments from Lehman Brothers Commercial Paper, Inc., which filed for bankruptcy in October 2008. AE Supply has a separate $400 million revolving credit facility, which can be used, if availability exists, to issue letters of credit.


	September 30, 2008				December 31, 2007
	Amounts		Total		Amounts		Total
	Recorded on		Guarantees		Recorded on		Guarantees
	the Consolidated		and Letters		the Consolidated		and Letters
(In millions)	Balance Sheet		of Credit		Balance Sheet		of Credit
Guarantees:
Purchase, sale, exchange or transportation of wholesale natural gas, electric power and related services	$	—	$	62.0	$	—	$	41.0
Loans and other financing-related matters		—		6.9		—		10.2
Lease agreement		—		5.0		—		4.9
Other		0.2		0.2		0.2		0.2

Total Guarantees	$	0.2	$	74.1	$	0.2	$	56.3

Letters of Credit:
Under AE’s Revolving Facility (a)	$	—	$	3.3	$	—	$	6.7
Other (b)		—		3.0		—		2.5

Total Letters of Credit	$	—	$	6.3	$	—	$	9.2

Total Guarantees and Letters of Credit	$	0.2	$	80.4	$	0.2	$	65.5


(a)		These amounts were comprised of a letter of credit issued in connection with a contractual obligation of Allegheny Ventures that will expire in July 2009.

(b)		These amounts were not issued under either AE’s credit facility or AE Supply’s credit facility.

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

NOTE 17: 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 power 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 “CO_2.”

Allegheny produces more than 90 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:

	•		maintaining an accurate CO₂ emissions data base;

	•		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;

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
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	•		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.

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 U.S. Environmental Protection Agency (the “EPA”) on March 10, 2005 was overturned by the U.S. Court of Appeals for the District of Columbia Circuit on July 11, 2008. The Court issued a unanimous decision overturning the entire CAIR and the associated Federal Implementation Plan and remanded both to the EPA. If the rule is vacated, Allegheny’s nitrogen oxide (“NOx”) and SO₂ compliance requirements would revert to the Clean Air Act Acid Rain Program and the NO_x SIP Call. The Court has not yet issued a mandate to vacate the rule and is holding that decision in abeyance until it reaches a decision on the motion for reconsiderationen banc, which was filed by the EPA and other parties to the litigation on September 24, 2008. On October 21, 2008, the Court requested additional briefing from the parties on the issue of whether to vacate the rule or remand the rule to the EPA, which will have a bearing on CAIR’s status. Allegheny intends to closely monitor the developments regarding this issue, along with its implications on a state level, as the EPA appeals the ruling and also prepares a new set of regulations.

The Clean Air Act Acid Rain Program 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 SO₂allowance 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 bypass of flue-gas desulfurization equipment (“Scrubbers”) 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.

The NOx SIP Call rule requires ozone season (May 1 through September 30) NOx reductions equivalent to a 1.5 lb/MMBtu emission rate. Allegheny meets current emission standards for 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 compliance now that CAIR has been overturned and may be vacated.

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

The majority of Allegheny’s emission allowances were allocated to Allegheny by the EPA at zero cost. Although there has been a substantial decline in the market price of certain emission allowances, the market prices of allowances were still well above Allegheny’s average cost per allowance after the date of the court decision overturning CAIR. Allegheny will continue to monitor this situation. The recorded value of Allegheny’s annual NOx allowances was approximately $3.1 million at September 30, 2008.

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 was to be implemented through state implementation plans. On February 8, 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the rule in its entirety. The State of West Virginia subsequently suspended its rule for implementing CAMR. Pennsylvania and Maryland, however, 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. On September 15, 2008, PPL Corporation filed a challenge to the PA DEP’s mercury rule in Pennsylvania Commonwealth Court, and Allegheny is monitoring the status of that litigation.

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 NOx, SO₂ and mercury, provided that PJM declares the station vital to reliability in the Baltimore/Washington DC metropolitan area. In response to Allegheny’s request and after conducting a reliability evaluation, PJM, by letter dated November 8, 2006, determined that R. Paul Smith is vital to the regional reliability of power flow. Pursuant to the legislation, the Maryland Department of the Environment (the “MDE”) will now create specific regulations for R. Paul Smith to comply with alternate NOx, SO₂ and mercury limits. The statutory exemption does not extend to R. Paul Smith’s CO₂ emissions. Maryland issued final regulations to implement RGGI requirements in February 2008. Allegheny is continuing to monitor and assess 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.

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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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 2, 2008, the Magistrate Judge issued a Report and Recommendation that all parties’ motions for summary judgment be denied. Objections to this report and responses to those objections have been filed by all parties. The District Court Judge will hear oral argument and then decide whether to accept, reject or modify the Report and Recommendation. A trial date has yet to be scheduled.

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

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.

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

Global Warming Class Action:On April 9, 2006, AE, along with numerous other companies with coal-fired generation facilities and companies in other industries, was named as a defendant in a class action lawsuit in the United States District Court for the Southern District of Mississippi. On behalf of a purported class of residents and property owners in Mississippi who were harmed by hurricane Katrina, the named plaintiffs allege that the emission of greenhouse gases by the defendants contributed to global warming, thereby causing hurricane Katrina and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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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. The case has been fully briefed to the United States Court of Appeals for the Fifth Circuit, and oral argument took place on August 6, 2008. Before a decision was issued, the parties were notified that one of the presiding judges had disqualified himself from participating in the decision. Oral argument before a new panel took place on November 3, 2008, but no decision was recorded at that time. 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. 07-3168-BLS (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 September 30, 2008, Allegheny’s total number of claims alleging exposure to asbestos was 845 in West Virginia and five 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. On June 26, 2008, the United States Supreme Court issued an opinion that rejected the Ninth Circuit’s reasoning and the case will be remanded to FERC with instructions that FERC amplify or clarify

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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its findings on two issues set forth in the opinion. The parties are awaiting the remand of the proceedings to FERC and a ruling from FERC on the scope and nature of those remand proceedings.

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

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 the California Parties’ demand is without merit.

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

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.

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

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

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

	•		results of litigation;

	•		results of operations;

	•		internal controls and procedures;

	•		capital expenditures;

	•		status and condition of plants and equipment;

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

	•		work stoppages by Allegheny’s unionized employees; and

	•		capacity purchase commitments.

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 and changes in the value of FTRs;

	•		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;

	•		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.

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 and nine months ended September 30, 2008 and 2007 was as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
Revenue per MWh sold	$	60.09	$	59.56	$	60.60	$	59.80

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 and nine months ended September 30, 2008 and 2007 was as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
O&M per MWh sold	$	7.78	$	7.68	$	8.10	$	7.65

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

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


	Three Months Ended September 30,									Nine Months Ended September 30,
	Normal		2008		2007		Change			Normal		2008		2007		Change
Delivery and Services:
Retail electricity sales (million kWhs)		N/A		10,749		11,164		(3.7	)%		N/A		33,023		33,540		(1.5	)%
HDD (a)		95		37		60		(38.3	)%		3,570		3,292		3,397		(3.1	)%
CDD (a)		585		537		686		(21.7	)%		798		767		968		(20.8	)%


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

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 given amount of MWs from 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 and derates. The EAF is calculated based upon availability data reported to NERC and PJM. 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.

kWhs generated and Station O&M.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									Nine Months Ended
	September 30, 2008									September 30, 2008
	2008			2007			Change			2008			2007			Change
Supercritical Units:
kWhs generated (in millions)		10,115			10,226			(1.1	)%		29,303			30,285			(3.2	)%
EAF		90.2	%		87.5	%		2.7	%		86.1	%		85.5	%		0.6	%
Station O&M (in millions):
Base and operations	$	26.3		$	23.5			11.9	%	$	81.0		$	78.1			3.7	%
Special maintenance		8.4			14.9			(43.6	)%		43.6			57.0			(23.5	)%

Total Station O&M	$	34.7		$	38.4			(9.6	)%	$	124.6		$	135.1			(7.8	)%


All Generation Units:
kWhs generated (in millions)		11,904			12,640			(5.8	)%		35,049			37,491			(6.5	)%
EAF		90.7	%		86.5	%		4.2	%		86.5	%		85.9	%		0.6	%
Station O&M (in millions):
Base and operations	$	40.2		$	36.7			9.5	%	$	123.8		$	120.1			3.1	%
Special maintenance		9.8			16.5			(40.6	)%		57.1			65.8			(13.2	)%

Total Station O&M	$	50.0		$	53.2			(6.0	)%	$	180.9		$	185.9			(2.7	)%

RESULTS OF OPERATIONS

Income Summary


	Three Months Ended												Three Months Ended
	September 30, 2008												September 30, 2007
	Delivery			Generation									Delivery		Generation
	and			and									and		and
(In millions)	Services			Marketing			Eliminations			Total			Services		Marketing		Eliminations			Total
Operating revenues	$	692.7		$	589.3		$	(432.4	)	$	849.6		$	692.4	$	581.1	$	(426.9	)	$	846.6

Fuel		—			299.2			—			299.2			—		245.5		—			245.5
Purchased power and transmission		512.9			25.7			(430.5	)		108.1			493.0		25.6		(424.7	)		93.9
Deferred energy costs, net		1.5			(20.2	)		—			(18.7	)		2.3		1.3		—			3.6
Operations and maintenance		83.6			70.6			(1.9	)		152.3			85.7		71.3		(2.2	)		154.8
Depreciation and amortization		39.2			28.2			—			67.4			40.4		26.3		—			66.7
Taxes other than income taxes		35.0			19.4			—			54.4			33.9		19.7		—			53.6

Total operating expenses		672.2			422.9			(432.4	)		662.7			655.3		389.7		(426.9	)		618.1

Operating income		20.5			166.4			—			186.9			37.1		191.4		—			228.5
Other income (expense), net		3.1			1.6			(0.2	)		4.5			3.0		13.6		(1.8	)		14.8
Interest expense and preferred dividends of subsidiary		24.8			33.3			(0.2	)		57.9			18.2		43.3		(1.8	)		59.7

Income (loss) before income taxes and minority interest		(1.2	)		134.7			—			133.5			21.9		161.7		—			183.6
Income tax expense (benefit)		(5.7	)		50.0			—			44.3			9.1		58.1		—			67.2
Minority interest		0.2			—			—			0.2			—		1.4		—			1.4

Net income	$	4.3		$	84.7		$	—		$	89.0		$	12.8	$	102.2	$	—		$	115.0


	Nine Months Ended											Nine Months Ended
	September 30, 2008											September 30, 2007
	Delivery		Generation									Delivery			Generation
	and		and									and			and
(In millions)	Services		Marketing			Eliminations			Total			Services			Marketing			Eliminations			Total
Operating revenues	$	2,139.6	$	1,842.0		$	(1,303.5	)	$	2,678.1		$	2,128.8		$	1,630.9		$	(1,239.0	)	$	2,520.7

Fuel		—		794.2			—			794.2			—			709.1			—			709.1
Purchased power and transmission		1,522.5		77.7			(1,297.5	)		302.7			1,447.9			77.2			(1,231.5	)		293.6
Deferred energy costs, net		7.8		(35.9	)		—			(28.1	)		(0.5	)		(5.6	)		—			(6.1	)
Operations and maintenance		267.4		249.6			(6.0	)		511.0			256.6			256.8			(7.5	)		505.9
Depreciation and amortization		122.6		83.9			—			206.5			121.7			87.7			—			209.4
Taxes other than income taxes		105.5		54.2			—			159.7			99.5			58.8			—			158.3

Total operating expenses		2,025.8		1,223.7			(1,303.5	)		1,946.0			1,925.2			1,184.0			(1,239.0	)		1,870.2

Operating income		113.8		618.3			—			732.1			203.6			446.9			—			650.5
Other income (expense), net		10.1		7.6			(2.4	)		15.3			10.4			21.8			(4.6	)		27.6
Interest expense and preferred dividends of subsidiary		70.7		106.7			(2.4	)		175.0			55.4			131.6			(4.6	)		182.4

Income before income taxes and minority interest		53.2		519.2			—			572.4			158.6			337.1			—			495.7
Income tax expense		10.0		182.5			—			192.5			66.9			124.6			—			191.5
Minority interest		0.7		—			—			0.7			—			2.4			—			2.4

Net income	$	42.5	$	336.7		$	—		$	379.2		$	91.7		$	210.1		$	—		$	301.8

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 tables reconcile “Income before income taxes and minority interest” for the three and nine months ended September 30, 2007 to the three and nine months ended September 30, 2008.


(In millions)
Income before income taxes and minority interest for the three months ended September 30, 2007			$	183.6
Increase in operating revenues				3.0
Decreases (increases) in operating expenses:
Fuel	(53.7	)
Purchased power and transmission	(14.2	)
Deferred energy costs, net	22.3
Other operating expenses	1.0

Operating expenses				(44.6	)
Decrease in other income (expense), net				(10.3	)
Decrease in interest expense and preferred dividends of subsidiary				1.8

Income before income taxes and minority interest for the three months ended September 30, 2008			$	133.5


(In millions)
Income before income taxes and minority interest for the nine months ended September 30, 2007			$	495.7
Increase in operating revenues				157.4
Decreases (increases) in operating expenses:
Fuel	(85.1	)
Purchased power and transmission	(9.1	)
Deferred energy costs, net	22.0
Operations and maintenance	(5.1	)
Other operating expenses	1.5

Operating expenses				(75.8	)
Decrease in other income (expense), net				(12.3	)
Decrease in interest expense and preferred dividends of subsidiary				7.4

Income before income taxes and minority interest for the nine months ended September 30, 2008			$	572.4

Operating Revenues

Operating revenues increased $3.0 million for the three months ended September 30, 2008 compared to the three months ended September 30, 2007, primarily due to:

	•		an $81.1 million increase resulting primarily from increased unrealized gains on economic power sale hedges that did not qualify for hedge accounting,

	•		a $21.5 million increase resulting from unrealized gains related to pipeline capacity economic hedges that did not qualify for hedge accounting,

	•		a $15.8 million increase due to higher generation rates charged to Pennsylvania customers,

	•		an $18.6 million increase, relating to higher market prices, including marketing, hedging and trading activities,

	•		an $11.0 million increase due to increased sales of power to third parties and

	•		a $6.2 million increase due to increased recoverable expenses and return on investment that are related to transmission expansion.

These operating revenue increases were partially offset by:

	•		$106.6 million in unrealized losses relating to financial transmission rights (“FTRs”),

	•		a $19.4 million decrease due to a 5.8% decrease in total MWhs generated and

	•		an $18.1 million decrease due to the expiration of an earnings benefit related to stranded cost recovery.

Additionally, milder weather and reduced customer consumption negatively impacted operating revenues.

Operating revenues increased $157.4 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to:

	•		a $94.4 million increase in unrealized gains relating to FTRs,

	•		a $70.8 million increase, relating to higher market prices, including marketing, hedging and trading activities,

	•		a $48.1 million increase due to higher generation rates charged to Pennsylvania customers,

	•		a $21.5 million increase due to increased recoverable expenses and return on investment that are related to transmission expansion,

	•		an $18.0 million increase resulting primarily from increased unrealized gains on economic power sale hedges that did not qualify for hedge accounting and

	•		an $8.4 million increase resulting from unrealized gains related to pipeline capacity economic hedges that did not qualify for hedge accounting.

These operating revenue increases were partially offset by:

	•		a $92.6 million decrease due to a 6.5% decrease in total MWhs generated and

	•		a $26.1 million decrease due to the expiration of an earnings benefit related to stranded cost recovery.

Additionally, milder weather and reduced customer consumption negatively impacted operating revenues.

See Note 10, “Fair Value Measurements, Derivative Instruments and Hedging Activities,” for information regarding the recognition of unrealized gains and losses on FTRs and economic power sale hedges. The majority of the unrealized gains (losses) are associated with FTRs and power sale hedges entered into during the second half of 2007 and the first quarter of 2008.

Operating Expenses

Fuel expense increased $53.7 million for the three months ended September 30, 2008 compared to the three months ended September 30, 2007, primarily due to a $42.6 million increase in coal expense, which is discussed in greater detail in “Discussion of Segment Results of Operations – Generation and Marketing Segment Results” below.

Purchased power and transmission expense increased $14.2 million for the three months ended September 30, 2008 compared to the three months ended September 30, 2007, primarily due to increased purchases from third parties.

Purchased power and transmission expense increased $9.1 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to increased purchases from third parties, partially offset by the expiration in May 2007 of a fixed price supply agreement to serve Monongahela’s former Ohio service territory.

Deferred energy costs, net decreased $22.3 million and $22.0 million for the three and nine months ended September 30, 2008, respectively, compared to the three and nine months ended September 30, 2007, primarily due to the Expanded Net Energy Cost (“ENEC”) method of recovering net power supply costs in West Virginia, which is discussed in greater detail in the Generation and Marketing segment results under “Regulated Results — Deferred Energy Costs, Net” below.

Operations and maintenance expense increased $5.1 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to increased maintenance activities.

Other Income (Expense), net

Other income (expense), net decreased $10.3 million and $12.3 million for the three and nine months ended September 30, 2008, respectively, compared to the three and nine months ended September 30, 2007, primarily due to an $8.4 million gain relating to an exchange transaction involving real estate in La Paz, Arizona that was recorded during the three months ended September 30, 2007, as well as lower interest income resulting from decreased average investments at lower rates.

Interest Expense and Preferred Dividends of Subsidiary

Interest expense and preferred dividends of subsidiary decreased $1.8 million and $7.4 million for the three and nine months ended September 30, 2008, respectively, compared to the three and nine months ended September 30, 2007, primarily due to lower average interest rates and increased capitalized interest resulting from capital projects that were partially funded using cash from operations.

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%.

DISCUSSION OF SEGMENT RESULTS OF OPERATIONS

Delivery and Services Segment Results

The following table provides retail electricity sales information.


	Three Months Ended September 30,									Nine Months Ended September 30,
	Normal		2008		2007		Change			Normal		2008		2007		Change
Delivery and Services:
Retail electricity sales (million kWhs)		N/A		10,749		11,164		(3.7	)%		N/A		33,023		33,540		(1.5	)%
HDD		95		37		60		(38.3	)%		3,570		3,292		3,397		(3.1	)%
CDD		585		537		686		(21.7	)%		798		767		968		(20.8	)%

Operating Revenues

Operating revenues were as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Retail electric:
Generation	$	444.1	$	454.5	$	1,377.2	$	1,354.9
Transmission		39.5		41.0		122.2		123.9
Distribution		162.3		169.4		501.9		527.0

Total retail electric		645.9		664.9		2,001.3		2,005.8

Transmission services and bulk power		37.0		17.5		107.1		91.8
Other affiliated and nonaffiliated energy services		9.8		10.0		31.2		31.2

Total operating revenues	$	692.7	$	692.4	$	2,139.6	$	2,128.8

Retail electric revenues decreased $19.0 million for the three months ended September 30, 2008 compared to the three months ended September 30, 2007, primarily due to:

	•		a $10.4 million decrease in generation revenues due to an $18.1 million decrease resulting from the expiration of an earnings benefit related to stranded cost recovery, as well as milder weather and reduced customer consumption, partially offset by a $15.8 million increase due to higher generation rates charged to Pennsylvania customers and

	•		an $8.6 million decrease in transmission and distribution (“T&D”) revenues due to milder weather and reduced customer consumption.

Retail electric revenues decreased $4.5 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to:

	•		a $26.8 million decrease in T&D revenues,

	•		partially offset by a $22.3 million increase in generation revenues.

T&D revenues decreased primarily due to an $18.0 million decrease as a result of the West Virginia Rate Order, which decreased T&D base rates charged to customers, and a decrease due to milder weather and reduced customer consumption, partially offset by a $5.1 million increase due to the expiration of a Maryland customer choice credit.

Generation revenues increased primarily due to a $48.1 million increase primarily resulting from higher generation rates charged to Pennsylvania customers and a $15.7 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, partially offset by a $26.1 million decrease resulting from the expiration of an earnings benefit related to stranded cost recovery, milder weather and reduced customer consumption. See Note 5, “Rates and Regulation” and the “Regulatory Matters” discussion below.

Transmission services and bulk power revenues increased $19.5 million for the three months ended September 30, 2008 compared to the three months ended September 30, 2007, primarily due to a $12.7 million increase related to the Warrior Run PURPA generation facility output being sold into PJM at market prices effective January 1, 2008, which are higher than prices under a prior fixed price contract, and a $7.0 million increase in PJM administration revenues, primarily due to increased recoverable expenses and return on investment that are related to transmission expansion. See Note 3, “Transmission Expansion Projects” for additional information.

Transmission services and bulk power revenues increased $15.3 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to a $27.6 million increase related to the Warrior Run PURPA generation facility output being sold into PJM at market prices effective January 1, 2008, which are higher than prices under a prior fixed price contract and a $20.4 million increase in PJM administration revenues, primarily due to increased recoverable expenses and return on investment that are related to transmission expansion. These increases in revenue were partially offset by a $31.5 million decrease due to the May 2007 expiration of a fixed price power supply agreement to serve Monongahela’s former Ohio service territory. See “Regulatory Matters” below and Note 3, “Transmission Expansion Projects” for additional information.

Operating Expenses

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Other purchased power and transmission	$	473.0	$	457.4	$	1,403.7	$	1,330.0
From PURPA generation		39.9		35.6		118.8		117.9

Purchased power and transmission	$	512.9	$	493.0	$	1,522.5	$	1,447.9

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 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 “Regulatory Matters” below and Note 5, “Rates and Regulation,” for additional information.

Other purchased power and transmission increased $15.6 million for the three months ended September 30, 2008 compared to the three months ended September 30, 2007, primarily due to an increase in market rates under a power sales agreement in Virginia between AE Supply and Potomac Edison.

Other purchased power and transmission increased $73.7 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to:

	•		a $57.3 million increase due to a new power sales agreement in Virginia between AE Supply and Potomac Edison at market-based rates (see “Regulatory Matters” and “Risk Factors” below and Note 5, “Rates and Regulation,” for additional information regarding market-based rates in Virginia) and

	•		a $48.1 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 $21.7 million decrease due to the expiration in May 2007 of a fixed price supply agreement to serve Monongahela’s former Ohio service territory.

Purchased power and transmission from PURPA increased $4.3 million for the three months ended September 30, 2008 compared to the three months ended September 30, 2007, primarily due to increased purchased power from the Warrior Run PURPA generation facility as a result of an outage at that facility during the three months ended September 30, 2007.

Deferred Energy Costs, net:Deferred energy costs, net represent the deferral of certain energy costs from the period in which they were 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 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. In addition, under an order of the Virginia State Corporation Commission (the “Virginia SCC”), Potomac Edison was granted a rate adjustment subject to hearing and refund to recover a portion of its increased purchased power costs. The order directed Potomac Edison to defer any under- or over-recovery of purchased power costs approved. See “Regulatory Matters” below and Note 5, “Rates and Regulation” for additional information.

Deferred energy costs, net were as follows:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(In millions)	2008			2007		2008			2007
AES Warrior Run PURPA generation	$	3.0		$	1.6	$	9.7		$	(1.1	)
Market-based generation and other costs		(1.5	)		0.7		(1.9	)		0.6

Deferred energy costs, net	$	1.5		$	2.3	$	7.8		$	(0.5	)

The $8.3 million change in deferred energy costs, net for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007 represents a net increase in expense, primarily related to the over-recovery of net costs 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				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Operations and maintenance	$	83.6	$	85.7	$	267.4	$	256.6

Operations and maintenance expenses decreased $2.1 million for the three months ended September 30, 2008 compared to the three months ended September 30, 2007, primarily due to a decrease in tax consulting fees, partially offset by an increase in right-of-way vegetation expense resulting from increased maintenance activities and storm activity.

Operations and maintenance expenses increased $10.8 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to:

	•		a $4.3 million increase in contract work due to service outages as a result of storm activity and

	•		a $4.5 million increase in right-of-way vegetation expense resulting from increased maintenance activities and storm activity.

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Depreciation and amortization	$	39.2	$	40.4	$	122.6	$	121.7

Depreciation and amortization expenses decreased $1.2 million for the three months ended September 30, 2008 compared to the three months ended September 30, 2007, primarily due to decreased amortization related to regulatory assets, partially offset by increased depreciation resulting from net property, plant and equipment additions.

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Taxes other than income taxes	$	35.0	$	33.9	$	105.5	$	99.5

Taxes other than income taxes increased $1.1 million for the three months ended September 30, 2008 compared to the three months ended September 30, 2007, primarily due to increased gross receipts tax resulting from an increase in taxable regulated utility revenues.

Taxes other than income taxes increased $6.0 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to an increase in gross receipts tax, resulting from an increase in taxable regulated utility revenues.

Interest Expense and Preferred Dividends of Subsidiary

Interest expense and preferred dividends of subsidiary were as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Interest expense	$	24.8	$	18.1	$	70.7	$	55.0
Preferred dividends of subsidiary		—		0.1		—		0.4

Interest expense and preferred dividends of subsidiary	$	24.8	$	18.2	$	70.7	$	55.4

Interest expense and preferred dividends of subsidiary increased $6.6 million and $15.3 million for the three and nine months ended September 30, 2008, respectively, compared to the three and nine months ended September 30, 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 Delivery and Services segment for the three months ended September 30, 2008 was 445.0% due to the fact that the segment generated a small pretax loss for the quarter, which substantially increased the percentage effect of the dollar amounts of items affecting the effective rate. The effective tax rate was higher than the federal statutory tax rate of 35%, primarily due to state income taxes, adjustments to reserves for uncertain tax positions and the Delivery and Services segment’s share of consolidated tax savings.

The effective tax rate for the three months ended September 30, 2007 was 41.2% and was higher than the federal statutory tax rate of 35%, primarily due to state income taxes, which accounted for an increase of approximately 2.2% and the rate-making effects of depreciation differences, which accounted for an increase of approximately 4.0%.

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

The effective tax rate for the nine months ended September 30, 2007 was 42.1% and was higher than the federal statutory tax rate of 35%, primarily due to state income taxes, which accounted for an increase of approximately 2.9%, the rate-making effects of depreciation differences, which accounted for an increase of approximately 2.6% and additional reserves booked for uncertain tax positions under FIN 48, which accounted for an increase of approximately 1.2%.

Transmission Expansion

The Delivery and Services segment includes 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				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Operating revenues	$	8.0	$	1.6	$	26.5	$	4.7
Operating income	$	4.7	$	1.0	$	16.5	$	1.2
Income before income taxes and minority interest	$	4.7	$	1.3	$	15.2	$	2.2
Net income	$	2.7	$	0.7	$	8.4	$	1.3

TrAIL Company and PATH, LLC are subject to the jurisdiction of FERC for the recovery of rates through PJM. FERC has approved the use of a formula rate methodology for recovery of all prudently incurred expenses and a return on debt and equity on all capital expenditures in connection with TrAIL and PATH based on a hypothetical capital structure, whether the transmission facilities are in service or in the process of construction.

Therefore, revenues and operating income are expected to increase as the projects move forward from the planning and approval stages through development and construction.

TrAIL Company and PATH, LLC began recognizing revenue on January 1, 2007 and March 1, 2008, respectively, based on allowable costs incurred and return earned. For more information regarding TrAIL and PATH, see “Regulatory Matters” below, Note 3, “Transmission Expansion Projects” and Note 5, “Rates and Regulation.”

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’s power generation and marketing operations and a regulated component consisting of Monongahela’s regulated West Virginia generation operations.

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


	Three Months Ended											Three Months Ended
	September 30, 2008											September 30, 2007
(In millions)	Unregulated		Regulated			Eliminations			Total			Unregulated		Regulated		Eliminations			Total
Operating revenues	$	468.2	$	133.1		$	(12.0	)	$	589.3		$	447.9	$	144.7	$	(11.5	)	$	581.1

Fuel		223.4		75.8			—			299.2			174.8		70.7		—			245.5
Purchased power and transmission		7.9		29.8			(12.0	)		25.7			8.6		28.5		(11.5	)		25.6
Deferred energy costs, net		—		(20.2	)		—			(20.2	)		—		1.3		—			1.3
Operations and maintenance		49.0		21.5			0.1			70.6			49.2		22.0		0.1			71.3
Depreciation and amortization		23.7		5.0			(0.5	)		28.2			22.2		4.7		(0.6	)		26.3
Taxes other than income taxes		12.8		6.6			—			19.4			12.7		7.0		—			19.7

Total operating expenses		316.8		118.5			(12.4	)		422.9			267.5		134.2		(12.0	)		389.7

Operating income		151.4		14.6			0.4			166.4			180.4		10.5		0.5			191.4
Other income (expense), net		1.2		3.4			(3.0	)		1.6			13.0		3.6		(3.0	)		13.6
Interest expense and preferred dividends		23.8		9.6			(0.1	)		33.3			33.2		10.2		(0.1	)		43.3

Income (loss) before income taxes and minority interest		128.8		8.4			(2.5	)		134.7			160.2		3.9		(2.4	)		161.7
Income tax expense (benefit)		47.6		2.5			(0.1	)		50.0			56.9		1.3		(0.1	)		58.1
Minority interest		2.4		—			(2.4	)		—			3.7		—		(2.3	)		1.4

Net income	$	78.8	$	5.9		$	—		$	84.7		$	99.6	$	2.6	$	—		$	102.2


	Nine Months Ended											Nine Months Ended
	September 30, 2008											September 30, 2007
(In millions)	Unregulated		Regulated			Eliminations			Total			Unregulated		Regulated			Eliminations			Total
Operating revenues	$	1,460.3	$	416.1		$	(34.4	)	$	1,842.0		$	1,261.0	$	403.2		$	(33.3	)	$	1,630.9

Fuel		578.3		215.9			—			794.2			515.4		193.7			—			709.1
Purchased power and transmission		22.3		89.8			(34.4	)		77.7			22.5		87.9			(33.2	)		77.2
Deferred energy costs, net		—		(35.9	)		—			(35.9	)		—		(5.6	)		—			(5.6	)
Operations and maintenance		168.6		80.6			0.4			249.6			170.5		86.1			0.2			256.8
Depreciation and amortization		70.8		14.6			(1.5	)		83.9			67.2		22.3			(1.8	)		87.7
Taxes other than income taxes		35.1		19.1			—			54.2			37.8		21.0			—			58.8

Total operating expenses		875.1		384.1			(35.5	)		1,223.7			813.4		405.4			(34.8	)		1,184.0

Operating income (loss)		585.2		32.0			1.1			618.3			447.6		(2.2	)		1.5			446.9
Other income (expense), net		6.3		10.2			(8.9	)		7.6			20.0		11.1			(9.3	)		21.8
Interest expense and preferred dividends		78.0		28.9			(0.2	)		106.7			108.4		23.3			(0.1	)		131.6

Income (loss) before income taxes and minority interest		513.5		13.3			(7.6	)		519.2			359.2		(14.4	)		(7.7	)		337.1
Income tax expense (benefit)		179.7		3.2			(0.4	)		182.5			131.5		(6.6	)		(0.3	)		124.6
Minority interest		7.2		—			(7.2	)		—			9.8		—			(7.4	)		2.4

Net income (loss)	$	326.6	$	10.1		$	—		$	336.7		$	217.9	$	(7.8	)	$	—		$	210.1

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							Nine Months Ended
	September 30,							September 30,
	2008		2007		Change			2008		2007		Change
Generation (million kWhs)		11,904		12,640		(5.8	)%		35,049		37,491		(6.5	)%

The following tables reconcile “Income before income taxes and minority interest” for the three and nine months ended September 30, 2007 to the three and nine months ended September 30, 2008.


(In millions)
Income before income taxes and minority interest for the three months ended September 30, 2007			$	161.7
Increase in operating revenues				8.2
Decreases (increases) in operating expenses:
Fuel	(53.7	)
Deferred energy costs, net	21.5
Other operating expenses	(1.0	)

Operating expenses				(33.2	)
Decrease in other income (expense), net				(12.0	)
Decrease in interest expense				10.0

Income before income taxes and minority interest for the three months ended September 30, 2008			$	134.7


(In millions)
Income before income taxes and minority interest for the nine months ended September 30, 2007			$	337.1
Increase in operating revenues				211.1
Decreases (increases) in operating expenses:
Fuel	(85.1	)
Deferred energy costs, net	30.3
Operations and maintenance	7.2
Depreciation and amortization	3.8
Taxes other than income taxes	4.6
Other operating expenses	(0.5	)

Operating expenses				(39.7	)
Decrease in other income (expense), net				(14.2	)
Decrease in interest expense				24.9

Income before income taxes and minority interest for the nine months ended September 30, 2008			$	519.2

Operating Revenues

Operating revenues increased $8.2 million for the three months ended September 30, 2008 compared to the three months ended September 30, 2007, primarily due to:

	•		an $81.1 million increase resulting primarily from increased unrealized gains on economic power sale hedges that did not qualify for hedge accounting,

	•		a $21.5 million increase resulting from unrealized gains related to pipeline capacity economic hedges that did not qualify for hedge accounting,

	•		a $26.6 million increase relating to higher market prices, including marketing, hedging and trading activities and

	•		a $15.8 million increase in revenues 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.

These operating revenue increases were partially offset by:

	•		$106.6 million in unrealized losses relating to FTRs and

	•		a $19.4 million decrease due to a 5.8% decrease in total MWhs generated.

Additionally, milder weather and reduced customer consumption negatively impacted operating revenues.

Operating revenues increased $211.1 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to:

	•		a $94.4 million increase in unrealized gains relating to FTRs,

	•		a $91.4 million increase, relating to higher market prices, including marketing, hedging and trading activities,

	•		a $57.3 million increase in revenues from affiliates due to a new power sales agreement in Virginia between AE Supply and Potomac Edison at market-based rates, effective July 1, 2007,

	•		a $48.1 million increase, primarily 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,

	•		an $18.0 million increase resulting primarily from increased unrealized gains on economic power sale hedges that did not qualify for hedge accounting and

	•		an $8.4 million increase resulting from unrealized gains related to pipeline capacity economic hedges that did not qualify for hedge accounting.

These operating revenue increases were partially offset by a $92.6 million decrease due to a 6.5% decrease in total MWhs generated. Additionally, milder weather and reduced customer consumption negatively impacted operating revenues.

Operating Expenses

Fuel expense increased $53.7 million for the three months ended September 30, 2008 compared to the three months ended September 30, 2007, primarily due to a $42.6 million increase in coal expense. The increase in coal expense was due to an increase of $8.40 in the average price of coal per ton consumed, partially offset by a 0.9% decrease in tons of coal consumed resulting from decreased MWhs generated at Allegheny’s coal-fired generation facilities.

Fuel expense increased $85.1 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to a $91.6 million increase in coal expense and a $7.6 million increase in emission allowance expense, partially offset by a $25.5 million decrease in natural gas expense. The increase in coal expense was due to an increase of $6.21 in the average price of coal per ton consumed, partially offset by a 2.4% decrease in tons of coal consumed resulting from decreased MWhs generated at Allegheny’s coal-fired generation facilities. Natural gas expense decreased due to a 61.9% decrease in decatherms of natural gas consumed resulting from decreased MWhs generated at Allegheny’s natural gas generation facilities, partially offset by an increase of $4.17 in the average price of natural gas per decatherm consumed.

Deferred energy costs, net decreased $21.5 million and $30.3 million for the three and nine months ended September 30, 2008, respectively, compared to the three and nine months ended September 30, 2007, primarily due to changes in the deferral of certain costs related to the ENEC in West Virginia, which is discussed in greater detail in “Regulated Results — Deferred Energy Costs, Net” below.

Operations and maintenance expense decreased $7.2 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to decreased contract work resulting from the timing of plant maintenance.

Depreciation and amortization expense decreased $3.8 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to the West Virginia Rate Order, which extended the depreciable lives of regulated generating assets, partially offset by increased depreciation expense resulting from net property, plant and equipment additions. See “Regulatory Matters” below and Note 5, “Rates and Regulation.”

Taxes other than income taxes decreased $4.6 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to a tax refund.

Other Income (Expense), net

Other income (expense), net decreased $12.0 million and $14.2 million for the three and nine months ended September 30, 2008, respectively, compared to the three and nine months ended September 30, 2007, primarily due to an $8.4 million gain relating to an exchange transaction involving real estate in La Paz, Arizona that was recorded during the three months ended September 30, 2007, as well as lower interest income resulting from decreased average investments at lower rates.

Interest Expense and Preferred Dividends

Interest expense and preferred dividends decreased $10.0 million for the three months ended September 30, 2008 compared to the three months ended September 30, 2007, primarily due to lower average debt outstanding under AE Supply’s credit facility, lower average interest rates and increased capitalized interest resulting from capital projects that were partially funded using cash from operations.

Interest expense and preferred dividends decreased $24.9 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to lower average debt outstanding under AE Supply’s credit facility, lower average interest rates and increased capitalized interest resulting from capital projects

that were partially funded using cash from operations, partially offset by increased interest expense associated with the April 2007 issuance of environmental control bonds.

Income Tax Expense

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

The effective tax rate for the three months ended September 30, 2007 was 36.0% and was higher than the federal statutory tax rate of 35%, primarily due to state income taxes, which increased the rate by 3.0%, partially offset by an additional benefit for Pennsylvania net operating losses recorded in the third quarter of 2007, which reduced the rate by 2.0%.

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

The effective tax rate for the nine months ended September 30, 2007 was 37.0% and was higher than the federal statutory tax rate of 35%, primarily due to state income taxes, which increased the rate by 3.3%, partially offset by an additional benefit for Pennsylvania net operating losses recorded in the third quarter, which reduced the rate by 1.3%.

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							Nine Months Ended
	September 30,							September 30,
	2008		2007		Change			2008		2007		Change
kWhs generated (in millions)		8,834		9,154		(3.5	)%		25,683		27,561		(6.8	)%

Operating Revenues

Operating revenues were as follows:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(In millions)	2008			2007		2008		2007
Revenue from affiliates	$	312.6		$	300.1	$	930.7	$	855.6
PJM revenue, net		184.2			133.4		442.4		383.6
Other operating revenues, including risk management and trading activities, net		(28.6	)		14.4		87.2		21.8

Unregulated revenue	$	468.2		$	447.9	$	1,460.3	$	1,261.0

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 $12.5 million for the three months ended September 30, 2008 compared to the three months ended September 30, 2007, primarily due to:

	•		a $10.8 million increase due to an increase in market rates under a power sales agreement in Virginia between AE Supply and Potomac Edison and

	•		a $15.8 million increase resulting from 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 an $8.1 million decrease related to lower sales volumes for certain of Potomac Edison’s customers in Maryland.

Revenue from affiliates increased $75.1 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to:

	•		a $57.3 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 $48.1 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 $23.4 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						Nine Months Ended
	September 30,						September 30,
(In millions)	2008			2007			2008			2007
Generation sold into PJM	$	614.1		$	446.5		$	1,653.4		$	1,346.0
Power purchased from PJM		(429.9	)		(313.1	)		(1,211.0	)		(962.4	)

PJM revenue, net	$	184.2		$	133.4		$	442.4		$	383.6

PJM revenue, net increased $50.8 million and $58.8 million for the three and nine months ended September 30, 2008, respectively, compared to the three and nine months ended September 30, 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, partially offset by a decrease in MWhs generated. Power purchased from PJM increased due to an increase in the market price of power, partially offset by decreased customer load.

Other Operating Revenues:

Other operating revenues decreased $43.0 million for the three months ended September 30, 2008 compared to the three months ended September 30, 2007, primarily due to unrealized losses relating to FTRs, partially offset by increased net realized and unrealized gains on marketing, hedging and trading activities.

Other operating revenues increased $65.4 million for the nine months ended September 30, 2008 compared to nine months ended September 30, 2007, primarily due to unrealized gains relating to FTRs, partially offset by increased net realized and unrealized losses on marketing, hedging and trading activities.

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				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Unregulated fuel	$	223.4	$	174.8	$	578.3	$	515.4

Fuel expense increased $48.6 million for the three months ended September 30, 2008 compared to the three months ended September 30, 2007, primarily due to a $37.3 million increase in coal expense and a $5.1 million increase in emission allowance expense. The increase in coal expense was due to an increase of $8.90 in the average price of coal per ton consumed and a 1.9% increase in tons of coal consumed.

Fuel expense increased $62.9 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to a $71.4 million increase in coal expense and a $7.2 million increase in emission allowance expense, partially offset by a $25.7 million decrease in natural gas expense. The increase in coal expense was due to an increase of $6.35 in the average price of coal per ton consumed, partially offset by a 1.9% decrease in tons of coal consumed resulting from decreased MWhs generated at Allegheny’s unregulated coal-fired generation facilities. Natural gas expense decreased due to a 62.5% decrease in decatherms of natural gas consumed resulting from decreased MWhs generated at Allegheny’s natural gas generation facilities, partially offset by an increase of $4.17 in the average price of natural gas per decatherm consumed.

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				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Unregulated operations and maintenance	$	49.0	$	49.2	$	168.6	$	170.5

Operations and maintenance expenses decreased $1.9 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to decreased contract work resulting from the timing of plant maintenance.

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Unregulated depreciation and amortization	$	23.7	$	22.2	$	70.8	$	67.2

Depreciation and amortization expenses increased $1.5 million and $3.6 million for the three and nine months ended September 30, 2008, respectively, compared to the three and nine months ended September 30, 2007, primarily due to increased depreciation resulting from net property, plant and equipment additions.

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				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Unregulated taxes other than income taxes	$	12.8	$	12.7	$	35.1	$	37.8

Taxes other than income taxes decreased $2.7 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to a tax refund.

Other Income (Expense), net

Other income (expense), net were as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Unregulated other income (expense), net	$	1.2	$	13.0	$	6.3	$	20.0

Other income (expense), net decreased $11.8 million and $13.7 million for the three and nine months ended September 30, 2008, respectively, compared to the three and nine months ended September 30, 2007, primarily due to an $8.4 million gain relating to an exchange transaction involving real estate in La Paz, Arizona that was recorded during the three months ended September 30, 2007, as well as lower interest income resulting from decreased average investments at lower rates.

Interest Expense

Interest expense was as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Unregulated interest expense	$	23.8	$	33.2	$	78.0	$	108.4

Interest expense decreased $9.4 million and $30.4 million for the three and nine months ended September 30, 2008, respectively, compared to the three and nine months ended September 30, 2007, primarily due to lower average debt outstanding under AE Supply’s credit facility, lower average interest rates and increased capitalized interest resulting from capital projects that were partially funded using cash from operations.

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							Nine Months Ended
	September 30,							September 30,
	2008		2007		Change			2008		2007		Change
kWhs generated (in millions)		3,071		3,485		(11.9	)%		9,366		9,930		(5.7	)%

Operating Revenues

Operating revenues were as follows:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(In millions)	2008			2007		2008			2007
Revenue from affiliates	$	129.9		$	136.1	$	401.1		$	409.1
PJM revenue, net		(3.0	)		2.5		(5.4	)		(17.4	)
Fort Martin Scrubber surcharge		6.1			6.1		18.1			11.5
Other operating revenues		0.1			—		2.3			—

Regulated revenue	$	133.1		$	144.7	$	416.1		$	403.2

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 “Regulatory Matters” below and Note 5, “Rates and Regulation” for additional information.

Revenues from affiliates decreased $6.2 million and $8.0 million for the three and nine months ended September 30, 2008, respectively, compared to the three and nine months ended September 30, 2007, primarily due to milder weather and reduced customer consumption.

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2008			2007			2008			2007
Generation sold into PJM	$	229.7		$	176.9		$	654.9		$	516.1
Power purchased from PJM		(232.7	)		(174.4	)		(660.3	)		(533.5	)

PJM revenue, net	$	(3.0	)	$	2.5		$	(5.4	)	$	(17.4	)

PJM revenue, net decreased $5.5 million for the three months ended September 30, 2008 compared to the three months ended September 30, 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. Revenues from generation sold into PJM were higher, primarily due to an increase in the market price of power, partially offset by decreased MWhs generated at Allegheny’s regulated plants.

PJM revenue, net increased $12.0 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 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, partially offset by decreased MWhs generated at Allegheny’s regulated plants. Power purchased from PJM increased due to an increase in the market price of power.

Fort Martin Scrubber surcharge:

Fort Martin Scrubber surcharge revenue increased $6.6 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, because the surcharge, which was implemented in April 2007, only generated revenue for a portion of the nine months ended September 30, 2007. Fort Martin Scrubber surcharge revenue results from 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 certain 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, and the surcharge is adjusted periodically to reflect over or under recovery of the amount necessary to service the bonds issued in connection with the securitization financing order.

Other Operating Revenues:

Other operating revenues increased $2.3 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 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				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Regulated fuel	$	75.8	$	70.7	$	215.9	$	193.7

Fuel expense increased $5.1 million for the three months ended September 30, 2008 compared to the three months ended September 30, 2007, primarily due to a $5.3 million increase in coal expense. The increase in coal

expense was due to an increase of $7.86 in the average price of coal per ton consumed, partially offset by a 7.7% decrease in tons of coal consumed resulting from decreased MWhs generated at Allegheny’s regulated coal-fired generation facilities.

Fuel expense increased $22.2 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to a $20.2 million increase in coal expense. The increase in coal expense was due to an increase of $6.04 in the average price of coal per ton consumed, partially offset by a 3.7% decrease in tons of coal consumed resulting from decreased MWhs generated at Allegheny’s regulated coal-fired generation facilities.

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Regulated purchased power and transmission	$	29.8	$	28.5	$	89.8	$	87.9

Purchased power and transmission increased $1.3 million and $1.9 million for the three and nine months ended September 30, 2008, respectively, compared to the three and nine months ended September 30, 2007, primarily due to increased purchased power from PURPA as a result of increased PURPA generation.

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


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(In millions)	2008			2007		2008			2007
Regulated deferred energy costs, net	$	(20.2	)	$	1.3	$	(35.9	)	$	(5.6	)

The $21.5 million and $30.3 million changes in deferred energy costs, net for the three and nine months ended September 30, 2008, respectively, compared to the three and nine months ended September 30, 2007 represent the change in the deferral of certain costs related to the ENEC. See “Regulatory Matters” below and Note 5, “Rates and Regulation,” for additional information.


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Regulated operations and maintenance	$	21.5	$	22.0	$	80.6	$	86.1

Operations and maintenance expenses decreased $5.5 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to decreased contract work resulting from the timing of plant maintenance.

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Regulated depreciation and amortization	$	5.0	$	4.7	$	14.6	$	22.3

Depreciation and amortization expenses decreased $7.7 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to the West Virginia Rate Order, which extended the depreciable lives of regulated generating assets.

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				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Regulated taxes other than income taxes	$	6.6	$	7.0	$	19.1	$	21.0

Taxes other than income taxes decreased $1.9 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to a tax refund.

Interest Expense and Preferred Dividends

Interest expense and preferred dividends was as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Regulated interest expense and preferred dividends	$	9.6	$	10.2	$	28.9	$	23.3

Interest expense and preferred dividends increased $5.6 million for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, primarily due to higher average debt outstanding as a result of the April 2007 issuance of environmental control bonds.

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 dividends) and external financings, including the sale of common and preferred stock, debt instruments and lease arrangements.

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

As widely reported, the financial markets and overall economies in the United States and abroad are currently undergoing a period of significant uncertainty and volatility. As a result of recent events, Allegheny’s management has placed increased emphasis on monitoring the risks associated with the current environment. At this point in time, there has not been a materially negative impact on Allegheny’s liquidity. While the impact of continued market volatility and the extent and impacts of any economic downturn cannot be predicted, Allegheny’s management currently believes that Allegheny has sufficient operating flexibility and access to funding sources to maintain adequate amounts of liquidity.

At September 30, 2008, Allegheny had cash and cash equivalents of approximately $112 million and, as described in Note 8, “Common Stock and Debt”, Allegheny has no significant maturities of existing debt until 2011.

In addition, AE and AE Supply each have in place $400 million revolving credit facilities that mature in 2011. At September 30, 2008, Allegheny’s borrowing capacity under AE’s and AE Supply’s revolving credit facilities were as follows:


					Letters of
	Total				Credit		Available
(In millions)	Capacity		Borrowed		Issued		Capacity
AE Revolving Credit Facility	$	400.0	$	—	$	3.3	$	396.7
AE Supply Revolving Facility		400.0		90.0		—		310.0

Total	$	800.0	$	90.0	$	3.3	$	706.7

Lehman Commercial Paper, Inc. (“Lehman”), which filed for bankruptcy in October 2008, is one of the lenders under AE’s revolving credit facility, with a commitment of $24 million of the $400 million facility. At this time, it is not certain whether Lehman will participate in any future requests by AE for funding under its revolving credit facility.

AE’s and AE Supply’s revolving credit facilities currently are well-diversified, including more than 20 lenders at September 30, 2008. Allegheny currently anticipates that these lenders, other than Lehman, will participate in future requests for funding. However, there can be no assurance that further deterioration in the credit markets and overall economy will not affect the ability of Allegheny’s lenders to meet their funding commitments. Allegheny’s lenders have the ability to transfer their commitments to other institutions, and the risk that committed funds may not be available under distressed market conditions could be exacerbated if consolidation of the commitments under these facilities or among Allegheny’s lenders were to occur. Also see Item 1A, “Risk Factors” below.

In addition to the revolving credit facilities described above, Allegheny has secured financing for the majority of anticipated costs associated with two of its large capital projects, through TrAIL Company’s $550 million senior

secured credit facility and Allegheny’s $450 million securitization financing associated with the construction of Scrubbers at its Fort Martin generating facility.

In addition to these existing facilities, AE and its subsidiaries may, in the future, access the capital markets, as appropriate, to fund capital projects or otherwise meet funding needs. The timing and amount of future external financings by AE or its subsidiaries will be driven by cash needs and capital structure objectives. The availability and cost of external financings will be affected by the financial condition of the company seeking funds and credit market conditions. There can be no assurance that the cost or availability of future borrowings, if any, will not be impacted by recent or future capital market disruptions. See Item 1A, “Risk Factors” below.

Allegheny’s consolidated capital structure, excluding short-term debt and minority interest, as of September 30, 2008 and December 31, 2007, was as follows:


	September 30, 2008				December 31, 2007
(In millions)	Amount		%		Amount		%
Long-term debt	$	3,973.6		58.0	$	4,039.3		61.4
Stockholders’ equity		2,874.0		42.0		2,535.4		38.6

Total	$	6,847.6		100.0	$	6,574.7		100.0

2008 Debt Activity

Issuances of indebtedness and repayments of principle on indebtedness, during the nine months ended September 30, 2008 were as follows:


(In millions)	Issuances		Repayments
AE Supply:
AE Supply Credit Facility:
Term Loan	$	—	$	125.0
Revolving Loan		250.0		160.0
TrAIL Company:
Short-Term Promissory Note		—		10.0
TrAIL Company Credit Facility:
Term Loan		45.0		—
Revolving Loan		20.0		20.0
West Penn:
Transition Bonds		2.8		59.8
Monongahela:
Environmental Control Bonds		—		14.9
Potomac Edison:
Environmental Control Bonds		—		4.9

Consolidated Total	$	317.8	$	394.6

See Note 8, “Common Stock and 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

Capital Expenditures

Capital projects are subject to continuing review and revision in light of legislative and regulatory developments, changing environmental standards, economic conditions and other factors. Allegheny currently estimates that its total cash-basis capital expenditures will approximate $1.1 billion for 2008 and $1 billion for 2009. These estimates are $250 million and $175 million lower than Allegheny’s projected capital expenditures for 2008 and 2009, respectively, as reported in its 2007 Annual Report on Form 10-K, reflecting, among other things, revisions to the timing of planned expenditures for Allegheny’s transmission expansion projects and environmental Scrubber projects. See “Regulatory Matters” and Item 1A, “Risk Factors” below, as well as Notes 3, “Transmission Expansion Projects” and Note 5, “Rates and Regulation,” for additional information.

In addition to the capital expenditures included in these estimates, it is possible that Allegheny may incur additional capital expenditures beginning as early as 2009 in order to comply with state regulations that may apply to Allegheny to the extent that the Clean Air Interstate Rule, or “CAIR,” is vacated and which may, in that case, compel Allegheny to operate additional control technologies at some of its facilities by as early as 2013. See Item 1A, “Risk Factors” below and Note 17, “Commitments and Contingencies.”

Other Matters Concerning Liquidity and Capital Requirements

Allegheny has obligations and commitments to make future cash payments under fuel agreements and other contracts. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Requirements in the 2007 Annual Report on Form 10-K, for information related to these obligations and commitments as of December 31, 2007. Allegheny’s fuel purchase and transportation commitments have changed from the amounts reported in its 2007 Annual Report on Form 10-K. The table below summarizes the payments due by period for these commitments, as of September 30, 2008.

Payments

from

January 1,

Payments from

Payments by

2009 to

2011 to

January 1,

December 31,

2013 and

(In millions)

2008

2010

2012

beyond

Total

Fuel purchase and transportation commitments

240.1

1,326.1

1,314.4

3,685.4

6,566.0

Coal Agreement

In July 2008, Allegheny entered into a coal purchase agreement and a modified agreement to lease Allegheny’s coal reserves in Washington County, Pennsylvania with an affiliate of Alliance Resource Partners, L.P. The coal purchase agreement will provide Allegheny with a total of approximately 20 million tons of coal through 2020, with deliveries that are scheduled to begin in 2010 and are expected to reach two million tons per year in 2011. Under the modified lease agreement, Alliance will continue to lease Allegheny’s coal reserves in Washington County,

while seeking the permits necessary to mine the coal. Allegheny will receive royalty payments from any production of coal from these coal reserves.

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:


	Nine Months Ended
	September 30,
(In millions)	2008			2007
Net income	$	379.2		$	301.8
Non-cash items included in income		303.9			441.1
Pension and other postretirement employee benefit plan contributions		(45.4	)		(46.5	)
Changes in certain assets and liabilities		(48.6	)		25.8

Net cash provided by operating activities	$	589.1		$	722.2

Cash flows provided by operating activities for the nine months ended September 30, 2008 were $589.1 million and primarily consisted of net income of $379.2 million and non-cash items of $303.9 million that reduced net income but did not result in the outlay of cash, partially offset by changes in certain assets and liabilities of $48.6 million and payments to Allegheny’s pension and other postretirement benefit plans of $45.4 million. The non-cash items primarily consisted of depreciation and amortization of $206.5 million and deferred income taxes of $177.0 million, partially offset by unrealized gains on derivatives, net of $136.9 million. Changes in certain assets and liabilities primarily consisted of $94.7 million in changes in receivables and payables resulting from normal working capital activity and an increase in materials, supplies and fuel of $43.3 million, primarily as a result of increased fuel inventory levels and higher prices. These amounts were partially offset by a change in regulatory liabilities of $41.1 million relating to Allegheny receiving payments from its customers in advance of providing service in the future, in order to mitigate the impact of the transition to market-based generation rates, at which time the advanced payments will be credited to the customers, a reduction in collateral deposits of $31.2 million, primarily due to reduced collateral requirements with various counterparties to Allegheny’s power contracts and a change in regulatory assets of $26.4 million resulting from the recovery of previously deferred and earned revenue related to West Penn restructuring.

Cash flows provided by operating activities for the nine months ended September 30, 2007 were $722.2 million, primarily as a result of net income of $301.8 million and non-cash charges of $441.1 million that reduced net income but did not result in the outlay of cash. The non-cash charges primarily consisted of depreciation and amortization of $209.5 million and deferred income taxes of $188.8 million. In addition, cash flows of $25.8 million were provided as a result of changes in certain assets and liabilities. These amounts were partially offset by contributions made to pension and other postretirement employee benefit plans of $46.5 million. The changes in certain assets and liabilities of $25.8 million primarily consisted of a change in accrued interest of $21.5 million from the timing of cash payments, and a reduction in collateral deposits of $16.5 million due primarily to reduced

collateral requirements, partially offset by a $12.3 million change in deferred income tax liabilities, primarily as a result of the implementation of FIN 48.

Investing Activities

Cash flows from investing activities are summarized as follows:


	Nine Months Ended
	September 30,
(In millions)	2008			2007
Capital expenditures	$	(714.3	)	$	(590.3	)
Proceeds from asset sales		0.4			1.8
Purchase of Merrill Lynch interest in subsidiary		(50.0	)		—
Decrease (increase) in restricted funds		177.6			(388.5	)
Other investments		(4.1	)		(4.0	)

Net cash used in investing activities	$	(590.4	)	$	(981.0	)

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

Cash flows used in investing activities for the nine months ended September 30, 2007 were $981.0 million and primarily consisted of $590.3 million of capital expenditures and a $388.5 million increase in restricted funds primarily as a result of the receipt and investment of the funds for the bonds relating to the Fort Martin Scrubber construction.

Financing Activities

Cash flows from financing activities are summarized as follows:


	Nine Months Ended
	September 30,
(In millions)	2008			2007
Issuance of long-term debt	$	305.6		$	450.6
Repayment of long-term debt		(384.6	)		(92.0	)
Repayment of note payable		(10.0	)		—
Redemption of preferred stock of subsidiary		—			(25.1	)
Equity contribution to PATH, LLC by AEP		4.5			—
Payments on capital lease obligations		(6.7	)		(6.0	)
Proceeds from exercise of employee stock options		21.4			10.3
Cash dividends paid on common stock		(75.7	)		—

Net cash provided by (used in) financing activities	$	(145.5	)	$	337.8

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

Cash flows provided by financing activities for the nine months ended September 30, 2007 were $337.8 million and consisted primarily of the issuance of long-term debt for the construction of the Scrubbers at Fort Martin of $450.6 million, partially offset by the repayment of certain long term debt of $92.0 million and a redemption of preferred stock of $25.1 million.

CREDIT RATINGS

The following table lists Allegheny’s credit ratings, as of November 5, 2008:

Moody’s

S & P

Fitch

AE:

Outlook

Stable

Corporate Credit Rating

Not Rated

BBB-

BBB-(a)

Senior Unsecured Debt

Ba1

BB+

BBB-

AE Supply:

Outlook

Stable

Senior Secured Debt

Baa2

BBB

Senior Unsecured Debt

Ba1

BBB-

Monongahela:

Outlook

Stable

First Mortgage Bonds

Baa2

BBB+

Senior Unsecured Debt

Baa3

BB+

BBB-

Environmental Control Bonds

Aaa

AAA

Potomac Edison:

Outlook

Negative

Stable

Negative

First Mortgage Bonds

Baa2

BBB+

BBB

Environmental Control Bonds

Aaa

AAA

West Penn:

Outlook

Stable

Transition Bonds

Aaa

AAA

First Mortgage Bonds

Baa2

BBB+

Senior Unsecured Debt

Baa3

BBB-

AGC:

Outlook

Stable

Senior Unsecured Debt

Baa3

BBB-


(a)		Issuer Default Rating

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.

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 to 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.

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 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.

Wholesale Markets

In August 2005, PJM filed at FERC to replace its capacity market with a new Reliability Pricing Model, or “RPM,” to address reliability concerns. On April 20, 2006, FERC issued an initial order that found PJM’s capacity market to be unjust and unreasonable and set a process to resolve features of the RPM that needed to be analyzed further before it could determine whether the RPM is a just and reasonable capacity market process. FERC ordered the implementation of settlement procedures in this proceeding, and AE Supply and the Distribution Companies joined in a settlement agreement that was filed with the FERC on September 29, 2006. The settlement agreement created a locational capacity market in PJM, in which PJM procures needed capacity resources through auctions held three years in advance at prices and in quantities determined by an administratively established demand curve. Under the settlement agreement, capacity needs in PJM are met either through purchases made in the proposed auctions or through commitments by load serving entities (“LSEs”) to self-supply their capacity needs. On December 22, 2006, FERC conditionally approved the settlement agreement, the implementation of which began with the 2007-2008 PJM planning year. Capacity auctions were held in April, July and October of 2007 and in January and May of 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 May 30, 2008, several parties naming themselves the “RPM Buyers” filed a complaint at FERC seeking a retroactive reduction in the RPM clearing prices for several RPM auctions that

have already been conducted. On September 19, 2008, FERC issued an order denying the RPM Buyers’ complaint. Requests for rehearing of the September 19, 2008 order are pending at FERC.

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 at FERC, which was accepted on May 15, 2008.

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 500 kV transmission line to extend from southwestern Pennsylvania through northern West Virginia and into northern Virginia to address potential electric reliability issues.

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.” In addition to the TrAIL project, other TrAIL Company projects include a new static VAR compensator at the Black Oak substation (the “Black Oak SVC”), upgrades and/or replacements of transformers and/or buses at six other substations and the construction of a new transmission operations center to be located in West Virginia. Total costs for these initiatives are expected to be approximately $1.2 billion, including approximately $820 million for construction of TrAIL.

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 Federal Power Act (the “FPA”) 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. 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 with FERC a settlement in this case. The settlement, which was approved by FERC on July 21, 2008, provides for an incentive return on equity for TrAIL and the Black Oak SVC of 12.7 percent and a return on equity of 11.7 percent for non-incentive projects.

PATH Project.On June 22, 2007, the PJM Board of Managers directed the construction of a high-voltage transmission line. The project, named the Potomac-Appalachian Transmission Highline, or “PATH,” originally was proposed to 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, as well as 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.

On October 15, 2008, PJM announced a reconfiguration of PATH. The reconfiguration is a result of constraints identified as a result of comprehensive siting studies; interaction with government agencies; public input; and a

desire to identify a solution that reduces line mileage and minimizes the impact on communities and the environment. The new configuration will consist of a single 765 kV line from the AEP substation near St. Albans, West Virginia to the new substation near Kemptown, Maryland; eliminate the connection with the Bedington substation and the twin-circuit 500 kV lines from Bedington to Kemptown, and include a new midpoint substation in West Virginia in the vicinity of eastern Grant County, northern Hardy County, or southern Hampshire County. PJM has confirmed that the reconfigured project addresses its reliability concerns. On October 31, 2008, PJM released the results of studies that change the required in-service date for PATH to June 2013. Total project costs are expected to be approximately $1.8 billion, of which Allegheny’s share is expected to be approximately $1.2 billion.

On December 28, 2007, PATH, LLC submitted a filing to FERC under Section 205 of the FPA to implement a formula rate tariff to be effective March 1, 2008. The filing also included a request for certain incentive rate treatments. On February 29, 2008, FERC issued an order granting 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 start-up business and administrative costs prudently 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.

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. The DOE denied requests for rehearing of its October 2, 2007 NIETC designation. Several entities 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. Briefing is expected to conclude in May 2009.

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 (“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.

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. The administrative law judge issued an initial decision on May 21, 2008, adopting the majority of West Penn’s proposed default service plan, including procurements through full requirements contracts with bid selections based on price, and a rate mitigation plan under which residential and small commercial customers may opt to defer rate increases of over 25 percent, based on the customer’s total bill, for a period up to three years at an interest rate of six percent. On July 25, 2008, the Pennsylvania PUC issued a final order largely approving West Penn’s proposed procurement approach and rate mitigation plan. On September 23, 2008, West Penn filed a tariff supplement implementing the default service plan.

	•		directs the Pennsylvania PUC to adopt an energy conservation and efficiency program to require EDCs to submit and implement plans to reduce energy demand and consumption;

	•		requires EDCs to file a plan for “smart meter” procurement and installation; and

	•		requires EDC’s to obtain energy through a prudent mix of contracts, with an emphasis on competitive procurement.

The bill includes a “grandfather” provision for West Penn’s previously Pennsylvania PUC approved procurement and rate mitigation plan.

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. On August 21, 2008, the Administrative Law Judges issued a Recommended Decision recommending rejection of TrAIL Company’s application. On September 10, 2008, TrAIL Company filed exceptions to the Recommended Decision. In addition, TrAIL Company filed a motion requesting a partial stay of action on the portion of the application relating to a new substation to be constructed in Washington County,

Pennsylvania (the “Prexy Substation”), the portion of TrAIL (the “Prexy Segment”) extending from the Prexy Substation to, but excluding, a new substation to be constructed in Greene County, Pennsylvania (the “502 Junction Substation”) and three 138 kV transmission lines originating at the Prexy Substation and connecting to the Allegheny Power transmission system (the “Prexy 138 kV Lines” and, together with the Prexy Substation and the Prexy Segment, the “Prexy Facilities”) and further requesting the Pennsylvania PUC to direct TrAIL Company and the other active parties in the proceeding to engage in a collaborative process to identify new alternatives to the proposed Prexy Facilities. Most other active parties opposed the motion. On September 25, 2008, TrAIL Company filed with the Pennsylvania PUC an agreement entered into with the Greene County, Pennsylvania Board of Commissioners (“Greene County”). Among other provisions, TrAIL Company agreed to engage in a collaborative process to identify possible solutions to reliability problems in the Washington County area in lieu of the proposed Prexy Facilities, West Penn agreed to release certain easements that would have been used for the Prexy Facilities, and Greene County agreed that the Pennsylvania PUC should approve the portion of the application pertaining to the proposed 502 Junction Substation and the portion of TrAIL extending from the 502 Junction Substation to the Pennsylvania/West Virginia border (together, the “Pennsylvania 502 Junction Facilities”). Except for the portion of the agreement relating to the release of certain easements, the agreement is not effective until approved by the Pennsylvania PUC and the issuance of an order authorizing construction of the Pennsylvania 502 Junction Facilities.

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 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 the 502 Junction Substation through West Virginia to northern 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 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 was 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 was held on May 30, 2008. On August 1, 2008, the West Virginia PSC issued an order authorizing construction of the TrAIL project in West Virginia subject to certain conditions, including indicia of state commission approval to construct the portion of the TrAIL project from 502 Junction Substation to Loudoun Substation in Pennsylvania and Virginia. The order also approved the settlement filed on April 15, 2008 with certain modifications. TrAIL Company and other parties have requested reconsideration of certain aspects of the order. An order on reconsideration has not been issued.

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

Advanced Metering and Demand Side Management Initiatives.On June 8, 2007, the Maryland PSC established a new case to consider advanced meters and demand side management programs.

The Staff of the Maryland PSC filed its report on these matters on July 6, 2007. On September 28, 2007, the Maryland PSC issued an order in this case that required the utilities to file detailed plans for how they will meet a proposal – “EmPOWER Maryland” — that electric usage in Maryland be reduced by 15% by 2015. On October 26, 2007, Potomac Edison filed its initial report on energy efficiency, conservation and demand reduction plans in connection with this order. The Maryland PSC conducted hearings on Potomac Edison’s and other utilities’ plans in November 2007 and further hearings on May 7, 2008. The Maryland PSC and the Maryland Energy Administration have also initiated a series of workshops to coordinate the utilities’ plans, the first of which was held on January 4, 2008. In a related development, the Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals, and setting a deadline of September 1, 2008, for the utilities to file comprehensive plans for attempting to achieve those goals. Potomac Edison filed its proposals on August 29, 2008, asking the Maryland PSC to approve seven programs for residential customers, five programs for commercial, industrial, and governmental customers, a customer education program, and a pilot deployment of Advanced Utility Infrastructure that Allegheny has previously been testing in West Virginia.

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 but was reopened on July 8, 2008 to receive additional evidence regarding the impact of the May 2008 RPM auction on the need for the TrAIL project. On October 7, 2008, the Virginia SCC issued an order authorizing construction of the TrAIL project in Virginia. The order is conditioned upon receipt of state commission authorization of the West Virginia and Pennsylvania portions of the project extending from the 502 Junction Substation to the Loudoun Substation.

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.

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 purchased 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 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.

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.

Allegheny is exposed to market risk related to changes in commodity prices. To manage these risks, Allegheny uses derivatives and physical transactions to reduce risk in physical assets. To ensure prudent risk management practices and compliance with corporate risk policies, Allegheny assesses, monitors and mitigates market risk exposure in accordance with the guidelines of the Company’s Corporate Risk Management Business Practices.

Allegheny uses various methods to measure its 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 calculates VaR using the Monte-Carlo technique by simulating thousands of scenarios sampling from the probability distribution of uncertain market variables. In addition to VaR, Allegheny routinely performs stress and scenario analyses to measure extreme losses due to exceptional events. In addition, VaR models are back-tested to ensure accuracy and reliability.

Allegheny calculated the VaR of a 1-day holding period at a 95% confidence level using the full term of all remaining wholesale energy market positions that are accounted for on a mark-to-market basis, excluding FTRs. The FTRs are excluded from the VaR measurement because they generally represent an economic hedge of future congestion charges that will be incurred in future periods to serve Allegheny’s load obligations. These mark-to-market wholesale energy market positions consist of derivatives in power and natural gas. As of September 30, 2008 and December 31, 2007, this calculation yielded a VaR of $4 million and $0, respectively. This VaR increase is primarily due to an increase in derivative contracts being accounted for on a mark-to-market basis since the beginning of the year.

The value of FTRs generally represents an economic hedge of future congestion charges incurred to serve Allegheny’s load obligations. The related load obligations, however, are not reflected in Allegheny’s Consolidated Balance Sheets. As a result, the timing of recognition of gains or losses on FTRs will differ from the timing of power purchases, including incurred congestion charges. The fair value of FTRs has been determined using an internal model based on data from PJM annual and monthly FTR auctions. These monthly auction results can change significantly over time. As described in Note 10 “Fair Value Measurements, Derivative Instruments and Hedging Activities,” Allegheny recorded $(106.6) million and $94.4 million in unrealized gains (losses) attributable to FTRs during the three and nine months ended September 30, 2008, respectively.

Credit risk related to Allegheny’s wholesale marketing operations is the loss that may result from counterparties’ nonperformance. Allegheny measures the credit risk of its wholesale marketing and risk management operations as the replacement cost for open energy commodity and derivative transactions adjusted for amounts owed to or due from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, with respect to which Allegheny has a legally enforceable right of setoff. Allegheny monitors and manages the credit risk of its wholesale marketing and risk management operations through credit policies and procedures that include an established credit approval process, daily monitoring of counterparty credit limits, the use of credit mitigation measures such as margin, collateral, or prepayment arrangements, and the use of master netting agreements. At September 30, 2008, Allegheny held $40.7 million of FTR assets net of the related obligation to PJM, an investment grade counterparty. At September 30, 2008, Allegheny also held $47.0 million of net derivative assets with five investment grade counterparties and $17.6 million of net derivative assets with two non-investment grade counterparties.

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 maintains disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed in reports filed under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the chief executive officer (“CEO”) and chief financial officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosures.

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

As previously reported, management concluded that our disclosure controls and procedures were not effective at a reasonable assurance level as of June 30, 2008 because of the identification of a material weakness in internal control over financial reporting relating to controls surrounding information used to manually calculate the fair value of certain derivative contracts for purposes of determining the amounts recorded in accumulated comprehensive income (loss) that should be subsequently reclassified into earnings.

In order to remediate this material weakness, management expanded and formalized AE’s review and validation controls and procedures relating to manual inputs and calculations of the fair value of certain derivative contracts. As of September 30, 2008, management concluded that AE has fully remediated this material weakness in internal control over financial reporting.

Changes in Internal Control over Financial Reporting.During the quarter ended September 30, 2008, there have been no changes in AE’s internal control over financial reporting, other than the changes discussed in the preceding paragraph, that have materially effected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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 claimed that it was owed approximately $1.4 million for coal previously delivered under the terms of a long term coal supply agreement (the “Agreement”) and also sought to terminate the Agreement. Allegheny denied that United Coals was entitled to any of the relief sought and filed counterclaims to enforce the terms of the Agreement and recover damages. The parties subsequently entered into a global resolution of their dispute under which United Coals will continue to supply coal to Allegheny and the case will be dismissed with prejudice.

See Note 17, “Commitments and Contingencies” to the Consolidated Financial Statements 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.

Allegheny’s costs to comply with environmental laws are significant. New environmental laws and regulations, or new interpretations of existing laws and regulations, could impose more stringent limitations on Allegheny’s generation operations or require it to incur significant additional costs. The cost of compliance with present and future environmental laws could have an adverse effect on Allegheny’s business.

Allegheny’s operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and site remediation. Compliance with these laws and regulations may require Allegheny to expend significant financial resources to, among other things, meet air emission standards, conduct site remediation, perform environmental monitoring, purchase emission allowances, use alternative fuels and modulate operations of its generation facilities in order to reduce emissions. If Allegheny fails to comply with applicable environmental laws and regulations, even if it is unable to do so due to factors beyond its control, it may be subject to civil liabilities or criminal penalties and may be required to incur significant expenditures to come into compliance. In addition, any alleged violations of environmental laws and regulations may require Allegheny to expend significant resources defending itself against such alleged violations. Either result could have an adverse effect on Allegheny’s business, results of operations, cash flows and financial condition.

Potential Climate Change Legislation.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 greenhouse gases implicated in climate change, primarily CO₂. Allegheny produces more than 90 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.

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.

Because the legislative process and applicable technology each is in its infancy, it is difficult for Allegheny to aggressively implement greenhouse gas emission expenditures, or to fully evaluate the magnitude and impact of potential expenditures, until the exact nature and requirements of any regulation are known and the capabilities of control or reduction technologies are more fully understood. In any event, compliance with any federal or other legislation or regulations regarding CO₂ emissions is likely to require significant expenditures by Allegheny and may have an adverse effect on its business, results of operations, cash flows and financial condition.

Clean Air Act Compliance.Allegheny’s compliance with the Clean Air Act has required, and may require in the future, that Allegheny install post-combustion control technologies on many of its generation facilities. The Clean Air Interstate Rule, or “CAIR,” promulgated by the EPA on March 10, 2005, was overturned by the U.S. Court of Appeals for the District of Columbia Circuit on July 11, 2008. Pursuant to its procedural rules, however, the Court has not yet issued the order vacating CAIR pending a decision on the EPA’s September 24, 2008 motion for a rehearing by the full Court. On October 21, 2008, the Court requested additional briefing from the parties on whether to vacate the rule or remand the rule to the EPA, which will have a bearing on CAIR’s status. If CAIR is reinstated or another similar rule is adopted, it may accelerate the need to install control equipment by phasing out a portion of currently available emission allowances. However, if CAIR is vacated by the full Court, then the need to install control technologies will be driven by other regulations, including the Clean Air Visibility Act and the Pennsylvania mercury rule, among others. Unlike CAIR, which incorporated a cap and trade system, these regulations are source-specific. As a consequence, compliance with these regulations may be more costly to Allegheny, because it may require that Allegheny install control technologies at a greater number of its generating units. Furthermore, these regulations may require reductions in emissions more quickly than would have been required under CAIR, which may compel Allegheny to operate control technologies at some generating facilities by as early as 2013.

Applicable standards under the EPA’s NSR initiatives remain in flux. Under the Clean Air Act, modification of Allegheny’s generation facilities in a manner that causes increased emissions could subject Allegheny’s existing facilities to the far more stringent NSR standards applicable to new facilities. The EPA has taken the view that many companies, including many energy producers, have been modifying emissions sources in violation of NSR standards in connection with work believed by the companies to be routine maintenance. Allegheny currently is involved in litigation concerning alleged violations of the PSD provisions of the Clean Air Act at certain of its facilities in West Virginia and violations of the Pennsylvania Air Pollution Control Act and NSR provisions of the Clean Air Act at certain of its facilities in Pennsylvania. Allegheny intends to vigorously pursue and defend against the environmental matters described above but cannot predict their outcomes. If NSR and similar requirements are imposed on Allegheny’s generation facilities, in addition to the possible imposition of fines, compliance would entail significant capital investments in pollution control technology, which could have an adverse impact on Allegheny’s business, results of operations, cash flows and financial condition.

In March 2005, the EPA issued the Clean Air Mercury Rule, or “CAMR,” establishing a cap and trade system designed to reduce mercury emissions from coal-fired power plants. Pennsylvania and Maryland proposed more aggressive, independent mercury control rules later in 2006, while West Virginia opted to adopt CAMR. On February 8, 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated CAMR. 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. Allegheny is currently assessing the impact that these rules may have on its operations. Pennsylvania’s 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 Scrubbers, activated carbon injection, selective catalytic reduction or other currently emerging technologies. Installation of such controls or other compliance efforts could entail significant costs, which could have an adverse impact on Allegheny’s business, results of operations, cash flows and financial condition. See “Environmental Matters” above.

Other Environmental Compliance Matters.In addition, Allegheny incurs costs to obtain and comply with a variety of environmental permits, licenses, inspections and other approvals. If there is a delay in obtaining any required environmental regulatory approval, or if Allegheny fails to obtain, maintain or comply with any required approval, operations at affected facilities could be halted, curtailed or subjected to additional costs, which could have an adverse impact on Allegheny’s business, results of operations, cash flows and financial condition.

Shifting state and federal regulatory policies impose risks on Allegheny’s operations. Delays, discontinuations or reversals of electricity market restructurings in the markets in which Allegheny operates could have an adverse effect on its business.

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

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

During its 2007 session, the Virginia General Assembly amended the Virginia Electric Utility Restructuring Act of 1999 to re-regulate the provision of electric generation services in the Commonwealth beginning January 1, 2009.

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

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

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

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

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.

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 purchased 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 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. On May 15, 2008, the Virginia SCC issued an order allowing Potomac Edison to increase its rates effective July 1, 2008, on an interim basis subject to refund, to collect $73 million of purchased power costs. The Virginia SCC set the application for an evidentiary hearing on October 21, 2008, and later postponed the hearing to November 18 at the request of the Virginia Consumers Counsel. In the meantime, on July 18, 2008, the Virginia SCC held a hearing on selected issues on July 3, 2008. On July 18, 2008, the Virginia SCC issued an order finding that the ratemaking provisions of the MOU expire on December 31, 2008 and requiring additional evidence and legal argument to set rates for 2008 and 2009. The Virginia SCC’s order also directed Potomac Edison to file plans for meeting its projected load obligations in Virginia, including alternatives for placing

generation in its rate base to serve Virginia customers, which filing Potomac Edison made on August 1. On July 28, 2008, Potomac Edison filed a motion to amend and supplement the April 30, 2008 application seeking to recover an additional $5.0 million for the period July 1, 2007 through December 19, 2007. The motion to amend was granted, but the Virginia SCC has not yet ruled on the merits of whether Potomac Edison may recover the additional revenue.

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 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 TrAIL project and the PATH project are subject to permitting and state regulatory approvals, and the failure to obtain any of these permits or approvals could have an adverse effect on Allegheny’s business.

The construction of both the TrAIL project and the PATH project are subject to the prior approval of various state regulatory bodies. Allegheny is in the process of pursuing the necessary approvals for the TrAIL project, but has met with substantial political opposition, as well as opposition from environmental, community and other groups. Similar opposition may be encountered with regard to the PATH project. There can be no assurance that Allegheny will be able to obtain the regulatory approvals required in connection with these projects on a timely

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basis or at all. The inability to obtain any required state approval or other regulatory approval as a result of such opposition or otherwise may have an adverse affect on Allegheny’s business, results of operations, cash flows and financial condition.

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, as a general matter, experience financial, legal or technical problems that inhibit their ability to fulfill their obligations. Among other circumstances, the prevailing constrained credit markets and overall negative economic conditions may affect the ability of Allegheny’s suppliers to access the capital markets and maintain adequate liquidity to sustain their respective businesses. 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.

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

Allegheny currently is involved in a number of capital intensive projects, including the TrAIL project, the PATH project and the installation of Scrubbers at the Fort Martin and Hatfield’s Ferry generation facilities. Allegheny’s ability to successfully complete these projects in a timely manner within established budgets is contingent upon many variables. Failure to complete these projects as planned may have an adverse effect on Allegheny’s business, results of operations, cash flow and financial condition.

Additionally, Allegheny has contracted with specialized vendors to acquire some of the necessary materials and construction related services in order to accomplish the installation of Scrubbers at the Fort Martin and Hatfield’s Ferry generation facilities and in connection with the TrAIL and PATH projects, and may in the future enter into additional such contracts with respect to these and other capital projects, including the PATH project. As such, Allegheny is exposed to the risk that these contractors may not perform as required under their contracts. Such a failure could occur for any number of reasons. Among other things, it is possible that the prevailing constrained credit markets and overall negative economic conditions may affect the ability of Allegheny’s contractors, subcontractors, suppliers and vendors to access the capital markets and maintain adequate liquidity to sustain their respective businesses. Should this occur, Allegheny may be forced to find alternate arrangements, which may cause delay and/or increased costs. Allegheny can provide no assurance that it would be able to make such alternate arrangements on terms acceptable to it or at all. Any inability to make such alternate arrangements or any substantial delays or increases in cost associated therewith could have an adverse effect on Allegheny’s business, results of operations, cash flow and financial condition.

Adverse investment returns and other factors may increase Allegheny’s pension liability and pension funding requirements.

Substantially all of Allegheny’s employees are covered by a defined benefit pension plan. At present, the pension plan is underfunded in that the projected pension benefit obligation exceeds the aggregate fair value of plan assets. The funded status of the plan can be affected by investment returns on plan assets, discount rates, mortality rates of plan participants, pension reform legislation and a number of other factors. There can be no assurance that the value of Allegheny’s pension plan assets will be sufficient to cover future liabilities. Although Allegheny has

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made significant contributions to its pension plan in recent years, it is possible that Allegheny could incur a significant pension liability adjustment, or could be required to make significant additional cash contributions to its plan, which would reduce the cash available for business and other needs.

Allegheny is dependent on its ability to successfully access capital markets. Any inability to access capital may adversely affect Allegheny’s business.

Allegheny relies on access to the capital markets as a source of liquidity and to satisfy any of its capital requirements that are not met by the cash flow from its operations. Capital market disruptions, decreases in market liquidity or the availability of credit, a downgrade in Allegheny’s credit ratings or other negative developments affecting Allegheny’s access to capital markets, could increase Allegheny’s cost of borrowing or could adversely affect its ability to access one or more financial markets. Causes of disruption to the capital markets could include, but are not limited to:

	•		a recession or an economic slowdown;

	•		the bankruptcy of one or more energy companies or highly-leveraged companies;

	•		significant increases in the prices for oil or other fuel;

	•		a terrorist attack or threatened attacks;

	•		a significant transmission failure; or

	•		changes in technology.

As widely reported, the financial markets and overall economies in the United States and abroad are currently undergoing a period of significant uncertainty and volatility. As a result of recent events, Allegheny’s management has placed increased emphasis on monitoring the risks associated with the current environment. At this point in time, there has not been a materially negative impact on Allegheny’s liquidity. However, there can be no assurance that the cost or availability of future borrowings, if any, in the debt markets will not be impacted by the ongoing or future capital market disruptions.

Lehman Commercial Paper, Inc. (“Lehman”), which filed for bankruptcy in October 2008, is one of the lenders under AE’s revolving credit facility, with a commitment of $24 million of the $400 million available under the facility. At this time, it is not certain whether Lehman will participate in any future requests by AE for funding under its revolving credit facility.

AE’s and AE Supply’s revolving credit facilities currently are well-diversified, including more than 20 lenders at September 30, 2008. Allegheny currently anticipates that these lenders, other than Lehman, will participate in future requests for funding. However, there can be no assurance that further deterioration in the credit markets and overall economy will not affect the ability of Allegheny’s lenders to meet their funding commitments. Additionally, Allegheny’s lenders have the ability to transfer their commitments to other institutions, and the risk that committed funds may not be available under distressed market conditions could be exacerbated to the extent that consolidation of the commitments under Allegheny’s facilities or among its lenders were to occur.

Changes in prevailing market conditions or in Allegheny’s access to commodities markets may make it difficult for Allegheny to hedge its physical power supply commitments and resource requirements.

In the past, unfavorable market conditions, coupled with Allegheny’s credit position, made it difficult for Allegheny to hedge its power supply obligations and fuel requirements. Although substantial improvements have been made in Allegheny’s market positions over the past few years, significant unanticipated changes in commodity market liquidity and/or Allegheny’s access to the commodity markets could adversely impact Allegheny’s ability to hedge its portfolio of physical generation assets and load obligations. In the absence of effective hedges for these purposes, Allegheny must balance its portfolio in the spot markets, which are volatile and can yield different results than expected.

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As widely reported, the financial markets and overall economies in the United States and abroad are currently undergoing a period of significant uncertainty and volatility. These conditions can adversely impact the liquidity of the commodity markets in which Allegheny may wish to transact. This, in turn, could inhibit Allegheny’s ability to transact in the desired timeframe or at a satisfactory price.

Allegheny’s risk management, wholesale marketing, fuel procurements and energy trading activities, including its decisions to enter into power sales or purchase agreements, rely on models that depend on the judgments and assumptions regarding factors such as generation facility availability, future market prices, weather and the demand for electricity and other energy-related commodities. Even when Allegheny’s policies and procedures are followed and decisions are made based on these models, Allegheny’s financial position and results of operations may be adversely affected if the judgments and assumptions underlying those models prove to be inaccurate.

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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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EXHIBIT INDEX


		Documents

3.1		Allegheny Energy, Inc. Articles of Restatement

10.1		Amended and Restated Credit Agreement, dated as of August 15, 2008, among Trans-Allegheny Interstate Line Company and the Lenders party thereto.

10.2		Equity Commitment Agreement, dated as of August 15, 2007, between Allegheny Energy, Inc. and Union Bank of California, N.A., as Collateral Agent

10.3		Pledge Agreement, dated as of August 15, 2008, between Allegheny Energy Transmission, LLC and Union Bank of California, N.A., as Collateral Agent

31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934

31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934

32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350

32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350

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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: November 5, 2008	By:	/s/ Kirk R. Oliver
		Kirk R. Oliver
		Senior Vice President and Chief Financial Officer

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Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. sophomore Avg

Large accelerated filerþ

Accelerated filero

Non-accelerated filero

Smaller reporting companyo

(Do not check if a smaller reporting company)