Allegheny Energy 10Q 2007 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarter ended September 30, 2007

Commission File Number 1-267

ALLEGHENY ENERGY, INC.

(Name of Registrant)


Maryland (State of Incorporation)		13-5531602 (IRS Employer Identification Number)

800 Cabin Hill Drive, Greensburg, Pennsylvania (Address of Principal Executive Offices)		15601 (Zip Code)

(724) 837-3000
(Telephone Number)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer See definition of “accelerated filer and large filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filerþ Accelerated filero Non-accelerated filero

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, 2007, 166,237,057 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”)		38
Item 3. Quantitative and Qualitative Disclosures About Market Risk		73
Item 4. Controls and Procedures		73

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		74
Item 1A. Risk Factors		74
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		76
Item 3. Defaults Upon Senior Securities		76
Item 4. Submission of Matters to a Vote of Security Holders		76
Item 5. Other Information		76
Item 6. Exhibits		77
Signatures		78
Exhibit 10.1
Exhibit 10.2
Exhibit 10.3
Exhibit 10.4
Exhibit 10.5
Exhibit 10.6
Exhibit 10.7
Exhibit 10.8
Exhibit 10.9
Exhibit 10.10
Exhibit 10.11
Exhibit 10.12
Exhibit 10.13
Exhibit 10.14
Exhibit 10.15
Exhibit 10.16
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 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
Allegheny Ventures		Allegheny Ventures, Inc., an unregulated subsidiary of AE
AE Supply		Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary of AE
AGC		Allegheny Generating Company, an unregulated generation subsidiary of AE Supply and Monongahela
Allegheny		AE, together with its consolidated subsidiaries
Distribution Companies		Monongahela, Potomac Edison and West Penn, which collectively do business as “Allegheny Power”
Monongahela		Monongahela Power Company, a regulated subsidiary of AE
PATH		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, an indirect subsidiary of AE
West Penn		West Penn Power Company, a regulated subsidiary of AE

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


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(In thousands, except per share data)	2007		2006			2007			2006
Operating revenues	$	846,592	$	816,645		$	2,520,699		$	2,384,526

Operating expenses:
Fuel		245,503		231,025			709,057			641,479
Purchased power and transmission		93,923		101,972			293,597			298,301
Gain on sale of OVEC power agreement and shares		—		—			—			(6,124	)
Deferred energy costs, net		3,651		(181	)		(6,049	)		5,225
Operations and maintenance		154,856		150,594			505,915			507,266
Depreciation and amortization		66,748		68,308			209,455			204,319
Taxes other than income taxes		53,497		53,762			158,254			159,630

Total operating expenses		618,178		605,480			1,870,229			1,810,096


Operating income		228,414		211,165			650,470			574,430

Other income and expenses, net		14,822		7,841			27,590			25,770

Interest expense and preferred dividends:
Interest expense		59,468		66,073			181,623			209,886
Preferred dividends of subsidiary		114		293			700			879

Total interest expense and preferred dividends		59,582		66,366			182,323			210,765

Income from continuing operations before income taxes and minority interest		183,654		152,640			495,737			389,435

Income tax expense		67,223		40,883			191,481			130,128

Minority interest in net income of subsidiaries		1,413		1,011			2,452			2,380

Income from continuing operations		115,018		110,746			301,804			256,927

Loss from discontinued operations, net of tax (Note 13)		—		(539	)		—			(2,203	)

Net income	$	115,018	$	110,207		$	301,804		$	254,724

Common share data:
Weighted average common shares outstanding:
Basic		166,101		164,813			165,799			163,813
Diluted		169,456		168,629			169,371			168,587

Basic income (loss) per common share:
Income from continuing operations	$	0.69	$	0.67		$	1.81		$	1.56
Loss from discontinued operations		—		—			—			(0.01	)

Basic income per common share	$	0.69	$	0.67		$	1.81		$	1.55


Diluted income (loss) per common share:
Income from continuing operations	$	0.67	$	0.65		$	1.78		$	1.52
Loss from discontinued operations		—		—			—			(0.01	)

Diluted income per common share	$	0.67	$	0.65		$	1.78		$	1.51

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)	2007			2006
Cash Flows From Operating Activities:
Net income	$	301,804		$	254,724
Loss from discontinued operations, net of tax		—			2,203
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		209,455			204,319
Amortization of debt issuance costs		7,602			20,504
Amortization of power sale liability related to Ohio sale		(10,500	)		(22,700	)
Amortization of liability for adverse power purchase commitment		(12,965	)		(12,866	)
Amortization of Pennsylvania stranded cost recovery asset		14,641			11,457
Gain on disposal or retirement of assets		(15,439	)		(1,205	)
Minority interest in net income of subsidiaries		2,452			2,380
Deferred income taxes and investment tax credit, net		188,791			109,524
Deferred energy costs, net		(6,049	)		5,225
Stock-based compensation expense		8,090			10,988
Unrealized gains on commodity contracts, net		(4,348	)		(26,831	)
Pension and other postretirement employee benefit plan expense		26,972			31,419
Pension and other postretirement employee benefit plan contributions		(46,521	)		(75,255	)
Deferred revenue — Fort Martin Scrubber project		11,321			—
Other, net		11,833			15,493
Changes in certain assets and liabilities:
Accounts receivable, net		(37,079	)		50,770
Materials, supplies and fuel		(210	)		2,446
Prepaid taxes		19,215			17,513
Collateral deposits		16,459			127,350
Prepaid assets		(7,277	)		(2,439	)
Other current assets		11,740			2,601
Accounts payable		33,673			(123,299	)
Accrued taxes		(14,746	)		(16,155	)
Accrued interest		21,462			20,707
Other current liabilities		3,192			1,435
Other assets		(3,527	)		3,574
Deferred income taxes		(12,288	)		5,489
Regulatory liabilities		2,163			—
Other liabilities		(3,745	)		(293	)
Net cash used in operating activities of discontinued operations		—			(3,406	)

Net cash provided by operating activities		716,171			615,672


Cash Flows From Investing Activities:
Capital expenditures		(590,305	)		(310,590	)
Proceeds from sale of assets		1,764			2,308
Purchase of minority interest in Hunlock Creek Energy Ventures		—			(13,900	)
Increase in restricted funds		(388,541	)		(140,247	)
Other investments		(3,951	)		(4,181	)
Net cash provided by investing activities of discontinued operations		—			27,795

Net cash used in investing activities		(981,033	)		(438,815	)


Cash Flows From Financing Activities:
Issuance of long-term debt		450,577			1,433,115
Repayment of long-term debt		(91,974	)		(1,644,261	)
Redemption of preferred stock of subsidiary		(25,148	)		—
Payments on capital lease obligations		(3	)		(45	)
Exercise of stock options		10,335			22,110
Cash dividends paid to minority shareholder in Hunlock Creek Energy Ventures		—			(400	)

Net cash provided by (used in) financing activities		343,787			(189,481	)


Net increase (decrease) in cash and cash equivalents		78,925			(12,624	)
Cash and cash equivalents at beginning of period		114,138			262,212

Cash and cash equivalents at end of period	$	193,063		$	249,588

Supplemental Cash Flow Information:
Cash paid for interest (net of amount capitalized)	$	152,361		$	170,879

See accompanying Notes to Consolidated Financial Statements.

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


	September 30,			December 31,
(In thousands)	2007			2006
ASSETS
Current Assets:
Cash and cash equivalents	$	193,063		$	114,138
Accounts receivable:
Customer		206,239			167,792
Unbilled utility revenue		80,766			117,977
Wholesale and other		86,116			63,894
Allowance for uncollectible accounts		(14,012	)		(14,591	)
Materials and supplies		101,467			96,117
Fuel		69,811			74,951
Deferred income taxes		133,718			127,531
Prepaid taxes		52,123			44,603
Collateral deposits		36,344			39,399
Commodity contracts		1,763			1,430
Restricted funds		33,193			12,923
Regulatory assets		61,301			39,128
Other		23,286			24,130

Total current assets		1,065,178			909,422


Property, Plant and Equipment, Net:
Generation		5,863,492			5,820,278
Transmission		1,062,585			1,056,759
Distribution		3,721,410			3,597,405
Other		439,515			412,894
Accumulated depreciation		(4,783,481	)		(4,636,972	)

Subtotal		6,303,521			6,250,364
Construction work in progress		636,393			262,529

Total property, plant and equipment, net		6,939,914			6,512,893


Investments and Other Assets:
Restricted funds — Fort Martin Scrubber project		378,491			—
Goodwill		367,287			367,287
Investments in unconsolidated affiliates		28,221			28,259
Other		16,179			27,932

Total investments and other assets		790,178			423,478


Deferred Charges:
Regulatory assets		709,026			674,095
Commodity contracts		5,196			—
Other		34,850			32,558

Total deferred charges		749,072			706,653

Total Assets	$	9,544,342		$	8,552,446

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)	2007			2006
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Long-term debt due within one year (Note 6)	$	184,555		$	201,189
Accounts payable		301,609			236,706
Accrued taxes		127,101			136,216
Commodity contracts		11,354			5,984
Accrued interest		121,316			99,854
Other		134,667			140,830

Total current liabilities		880,602			820,779


Long-term Debt (Note 6)		3,773,096			3,383,986

Deferred Credits and Other Liabilities:
Commodity contracts		12,829			17,982
Income taxes payable		61,639			—
Investment tax credit		70,250			72,938
Deferred income taxes		1,131,371			936,911
Obligations under capital leases		35,640			26,007
Regulatory liabilities		470,257			464,092
Adverse power purchase commitment		154,084			166,937
Other		521,245			547,706

Total deferred credits and other liabilities		2,457,315			2,232,573


Commitments and Contingencies (Note 19)

Minority Interest		12,573			10,713

Preferred Stock of Subsidiary		—			24,000

Common Stockholders’ Equity:
Common stock—$1.25 par value per share, 260 million shares authorized and 166,202,217 and 165,409,908 shares issued at September 30, 2007 and December 31, 2006, respectively		207,753			206,762
Other paid-in capital		1,907,525			1,907,879
Retained earnings		358,778			74,698
Treasury stock at cost—49,493 shares		(1,756	)		(1,756	)
Accumulated other comprehensive loss		(51,544	)		(107,188	)

Total common stockholders’ equity		2,420,756			2,080,395

Total Liabilities and Stockholders’ Equity	$	9,544,342		$	8,552,446

See accompanying Notes to Consolidated Financial Statements.

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF COMMON STOCKHOLDERS’ EQUITY
AND COMPREHENSIVE INCOME
For the Nine Months Ended September 30, 2007
(unaudited)


														Accumulated
					Other									other			Total common
	Shares		Common		paid-in			Retained			Treasury			comprehensive			stockholders’			Comprehensive
(In thousands, except shares)	outstanding		stock		capital			earnings			stock			loss			equity			income
Balance at December 31, 2006		165,360,415	$	206,762	$	1,907,879		$	74,698		$	(1,756	)	$	(107,188	)	$	2,080,395
Net income		—		—		—			301,804			—			—			301,804		$	301,804
Adoption of FIN 48		—		—		—			(17,722	)		—			—			(17,722	)
Pension and other postretirement employee benefit amortization, net of tax of $1,736		—		—		—			—			—			2,676			2,676			2,676
Unrealized losses on available-for-sale securities, net of tax of $3		—		—		—			—			—			(4	)		(4	)		(4	)
Unrealized gains on cash flow hedges for the period, net of tax of $423		—		—		—			—			—			666			666			666
Stock-based compensation expense:
Stock units		—		—		1,971			—			—			—			1,971
Non-employee stock awards		14,462		18		804			—			—			—			822
Stock options		—		—		5,296			—			—			—			5,296
Exercise of stock options		445,315		557		9,778			—			—			—			10,335
Conversion of stock units		332,532		416		(8,749	)		—			—			—			(8,333	)
Effects of West Virginia Rate Order:
Establishment of regulatory asset related to pension obligation, net of tax of $35,663		—		—		—			—			—			52,306			52,306			52,306
Adjustment related to 2005 SO₂ allowance sale, net of tax of $5,777		—		—		(8,306	)		—			—			—			(8,306	)
Premium on redemption of preferred stock of Monongahela		—		—		(1,148	)		—			—			—			(1,148	)
Other		—		—		—			(2	)		—			—			(2	)

Balance at September 30, 2007		166,152,724	$	207,753	$	1,907,525		$	358,778		$	(1,756	)	$	(51,544	)	$	2,420,756		$	357,448

See accompanying Notes to Consolidated Financial Statements.

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

NOTE 1: BASIS OF PRESENTATION

Business Description

Allegheny Energy, Inc. (“AE”) operates primarily through directly and indirectly owned subsidiaries (together with AE, “Allegheny”). Allegheny’s two business segments are the Delivery and Services segment and the Generation and Marketing segment.

The Delivery and Services segment primarily consists of Allegheny’s regulated utility subsidiaries. These subsidiaries include Monongahela Power Company (“Monongahela”), excluding its generation operations, The Potomac Edison Company (“Potomac Edison”) and West Penn Power Company (“West Penn”) (collectively, the “Distribution Companies”). The Distribution Companies primarily operate electric transmission and distribution (“T&D”) systems in Pennsylvania, West Virginia, Maryland and Virginia. The Distribution Companies are subject to federal and state regulation. The Delivery and Services segment also includes Allegheny Ventures, Inc. (“Allegheny Ventures”), Trans-Allegheny Interstate Line Company (“TrAIL Company”) and Allegheny’s interest in the Potomac-Appalachian Transmission Highline (“PATH”) project, through its ownership of the West Virginia Series and the Allegheny Series of Potomac-Appalachian Transmission Highline, LLC, a series LLC. TrAIL Company was formed in 2006 in connection with the construction, management and financing of transmission expansion projects, including Allegheny’s proposed 210-mile 500 kV transmission line (the “Trans-Allegheny Interstate Line” or “TrAIL”). PATH is a joint venture formed in 2007 between Allegheny and a subsidiary of American Electric Power (“AEP”) consisting of a 765 kV transmission line, which will be built and owned jointly by AEP and Allegheny and operated under PATH West Virginia Transmission Company LLC, and certain 500 kV facilities and substations to be owned 100% by Allegheny, and operated under PATH Allegheny Transmission Company, LLC.

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 regulation but 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

The accompanying unaudited interim financial statements should be read in conjunction with the Combined Annual Report on Form 10-K of AE, Monongahela and AGC for the year ended December 31, 2006 (the “2006 Annual Report on Form 10-K”).

These unaudited interim financial statements have been prepared by Allegheny pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles used in the United States of America (“GAAP”) have been condensed or omitted. These financial statements include all adjustments, consisting of normal recurring adjustments, considered necessary by management to fairly state the results of operations, financial position and cash flows. The results reported in these consolidated interim financial statements are not necessarily indicative of the results that may be expected for the entire year. The year-end 2006 balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.

During the fourth quarter of 2006, Allegheny changed its classification of fuel handling and residual disposal costs within its Consolidated Statements of Operations from “Operations and maintenance” expenses to “Fuel”

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

expenses to improve comparability with other energy and utility companies and facilitate a better understanding of operating costs. Accordingly, Allegheny reclassified such costs previously reported in the amount of $7.2 million and $18.3 million for the three and nine months ended September 30, 2006, respectively, to conform to the financial statement presentation for the current period.

In addition, certain other amounts in previously issued financial statements have been reclassified to conform to the current presentation.

Deferred Energy Costs, Net.See Item 8, Note 1, “Basis of Presentation,” in the 2006 Annual Report on Form 10-K for a description of Allegheny’s deferred energy accounting. See also Note 8, “Rates and Regulation,” for the accounting resulting from a May 22, 2007 rate order that established an annual Expanded Net Energy Cost (“ENEC”) method of recovering net power and related costs in West Virginia.

Restricted Funds.As described in Note 6, “Debt,” in April 2007, MP Environmental Funding LLC and PE Environmental Funding LLC issued an aggregate of $459 million in Senior Secured Sinking Fund Environmental Control Bonds, Series A. Net proceeds from the sale of the bonds represent non-current restricted funds and will be used to fund the majority of costs to construct and install flue-gas desulfurization equipment (“Scrubbers”) at Monongahela’s Fort Martin generation facility in West Virginia (“Fort Martin”).

Annual Goodwill Impairment Test.Allegheny performed its annual goodwill impairment test as of August 31, 2007 and determined that there was no impairment of recorded goodwill at August 31, 2007.

NOTE 2: POTOMAC-APPALACHIAN TRANSMISSION HIGHLINE PROJECT

On September 1, 2007 Allegheny entered into an agreement with a subsidiary of AEP to build a 290-mile, high-voltage transmission line, named the Potomac-Appalachian Transmission Highline or PATH Project through a series LLC named the Potomac-Appalachian Transmission Highline LLC (“PATH, LLC”). The West Virginia Series is owned equally by Allegheny and AEP and will build, own and operate approximately 244 miles of 765-kV transmission line from AEP’s Amos substation near St. Albans, West Virginia to Allegheny’s Bedington substation near Martinsburg, West Virginia, though an operating subsidiary. The Allegheny Series is 100% owned by Allegheny and will build, own and operate approximately 46 miles of twin-circuit 500-kV lines from Bedington to a new substation near Kemptown, Maryland, though an operating subsidiary.

Total project costs are expected to be approximately $1.8 billion. Allegheny’s share of the estimated costs is expected to be approximately $1.2 billion. PJM Interconnection, LLC (“PJM”), the regional transmission organization, has specified June 2012 as the in-service date for the project.

The operating subsidiaries of PATH, LLC will operate as transmission utilities and will be subject to the rules and regulations of the Federal Energy Regulatory Commission (“FERC”), PJM and state regulatory authorities of West Virginia and Maryland.

The West Virginia and Allegheny series of PATH, LLC and their operating subsidiaries will be consolidated by Allegheny, in accordance with the provisions of Financial Accounting Standards Board (“FASB”) Interpretation 46(R), Consolidation of Variable Interest Entities.

NOTE 3: RECENT ACCOUNTING PRONOUNCEMENTS

In April 2007, the FASB issued Interpretation No. 39-1, Amendment of Interpretation No. 39 (“FIN 39-1”). FIN 39-1 permits entities that are party to master netting arrangements to offset cash collateral receivables or payables that approximate fair values with net derivatives positions. FIN 39-1 is effective for Allegheny beginning on January 1, 2008. Management has not completed the process of determining the effect of FIN 39-1 on Allegheny’s financial

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

statements, but does not expect that its adoption will have a material impact on Allegheny’s consolidated results of operations or financial position.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS No. 159”). SFAS No. 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 No. 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. SFAS No. 159 is effective for Allegheny beginning on January 1, 2008. Management has not completed the process of determining the effect of SFAS No. 159 on Allegheny’s financial statements. However, at this time, the adoption of SFAS No. 159 is not expected to have a material impact on Allegheny’s consolidated results of operations or financial position.

In June 2006, the Emerging Issues Tax Force (“EITF”) reached a consensus on EITF Issue No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (“EITF 06-3”). EITF 06-3 provides guidance on disclosing the accounting policy for the income statement presentation of any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer on either a gross (included in revenues and costs) or a net (excluded from revenues and costs) basis. Allegheny records taxes collected from customers that are assessed on those customers on a net basis. That is, in instances in which Allegheny acts as a collection agent for a taxing authority by collecting taxes that are the responsibility of the customer, Allegheny records the amount collected as a liability and relieves such liability upon remittance to the taxing authority without impacting revenues or expenses. Therefore, the January 1, 2007 implementation of EITF 06-3 did not have a material impact on Allegheny’s financial statements.

In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109 (“FIN 48”). On May 2, 2007, the FASB issued Interpretation No. 48-1, Definition of Settlement in FASB Interpretation No. 48 (“FIN 48-1”), which provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. Allegheny adopted the provisions of FIN 48 and FIN 48-1 as of January 1, 2007 and May 2, 2007, respectively. See Note 5, “Income Taxes,” for additional information related to FIN 48 and its impact on Allegheny’s consolidated financial position.

On September 8, 2006, the FASB issued FSP AUG AIR-1, Accounting for Planned Major Maintenance Activities (the “FSP”). The FSP permits the following methods for accounting for planned major maintenance activities: direct expense, built-in overhaul and deferral. The FSP requires entities to disclose the method of accounting for planned major maintenance activities, as well as the impact of any change in method required as a result of the adoption of the FSP. The FSP prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities. Allegheny adopted the FSP on January 1, 2007. It is Allegheny’s policy to account for planned major maintenance activities using the direct expense method. Therefore, the adoption of the FSP did not have an impact on Allegheny’s consolidated results of operations, financial position or cash flows.

In September 2006, the FASB issued Statement of Financial Accounting Standard (“SFAS”) No. 157, Fair Value Measurements (“SFAS No. 157”). SFAS No. 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 disclosure about fair value measurement but does not require any new fair value measurements. SFAS No. 157 is effective for Allegheny beginning on January 1, 2008. Management has not completed the process of determining the effect of SFAS No. 157 on Allegheny’s financial statements. However, at this time, the adoption of SFAS No. 157 is not expected to have a material impact on Allegheny’s consolidated results of operations or financial position.

NOTE 4: ASSET SWAP

On January 1, 2007, AE Supply and Monongahela completed an intercompany exchange of assets (the “Asset Swap”) that realigned generation ownership and contractual arrangements within the Allegheny system. The Asset Swap was substantially a non-cash transaction and was recorded at the net book value of the assets, liabilities and interest transferred, with certain adjustments. There was no change in Allegheny’s consolidated stockholders’ equity

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

as a result of the Asset Swap. After the Asset Swap, Monongahela owns 100% of Fort Martin, which allowed Allegheny to finance the construction of flue-gas desulfurization equipment (“Scrubbers”) at Fort Martin through the securitization of an environmental control charge that Monongahela and Potomac Edison impose on their retail customers in West Virginia. See Note 6, “Debt,” for additional information.

After the Asset Swap, Monongahela also owns 100% of the Albright, Rivesville and Willow Island generation facilities in West Virginia and is contractually entitled to a greater proportion of the generation from the Bath County, Virginia generation facility. In addition, AE Supply owns 100% of the Hatfield’s Ferry generation facility, which, prior to the Asset Swap, was jointly owned by AE Supply and Monongahela, and has a greater ownership interest in the Harrison and Pleasants generation facilities in West Virginia. AE Supply also received contractual rights to generation from OVEC. The Asset Swap resulted in a net transfer of 660 MWs of generation capacity from AE Supply to Monongahela. Additionally, Monongahela assumed from AE Supply the contractual obligation to provide power to serve Potomac Edison’s West Virginia load obligations.

In connection with the Asset Swap, AE Supply assumed approximately $6 million in debt associated with outstanding pollution control bonds. Monongahela also will remain obligated to the note holders for the repayment of this debt. Additionally, on July 2, 2007, AE Supply paid approximately $16 million in the aggregate in connection with the redemption of certain pollution control bonds that, by their terms, had to be redeemed in advance of their scheduled maturities as a result of the change in ownership of Fort Martin. The $6 million of outstanding pollution control bond debt assumed by AE Supply was refinanced in October 2007. See Note 6, “Debt,” for additional information.

NOTE 5: INCOME TAXES

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

The following table reconciles total income tax expense from continuing operations and the amount that would be calculated by applying the federal statutory income tax rate of 35% to income from continuing operations before income taxes and minority interest:


				Three Months Ended											Nine Months Ended
	September 30,											September 30,
	2007						2006					2007						2006
(In millions, except percent)	Amount						Amount					Amount						Amount
Income from continuing operations before income taxes and minority interest	$	183.7					$	152.6				$	495.7					$	389.4
Preferred dividends of subsidiary		0.1						0.3					0.7						0.9

Subtotal		183.8						152.9					496.4						390.3


Income tax expense calculated using the federal statutory rate of 35%		64.3			35.0	%		53.5		35.0	%		173.7			35.0	%		136.6		35.0	%
Increases (reductions) resulting from:
Rate-making effects of depreciation differences		1.3			0.7	%		0.5		0.3	%		4.0			0.8	%		3.8		1.0	%
State income tax, net of federal income tax benefit		6.4			3.5	%		4.8		3.1	%		15.7			3.2	%		12.4		3.2	%
Amortization of deferred investment tax credit		(0.9	)		(0.5	)%		(1.1	)	(0.7	)%		(2.7	)		(0.6	)%		(4.3	)	(1.1	)%
Estimated Pennsylvania net operating loss benefits		(4.2	)		(2.3	)%		(16.7	)	(11.0	)%		(4.2	)		(0.8	)%		(16.7	)	(4.3	)%
Changes in tax reserves related to uncertain tax positions		(1.2	)		(0.6	)%		—		—	%		3.5			0.7	%		—		—	%
Other, net		1.5			0.8	%		(0.1	)	—	%		1.5			0.3	%		(1.7	)	(0.5	)%

Total income tax expense	$	67.2			36.6	%	$	40.9		26.7	%	$	191.5			38.6	%	$	130.1		33.3	%

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

In June 2006, the FASB issued FIN 48, which prescribes a comprehensive model for how companies should recognize, measure, present and disclose in their financial statements uncertain tax positions taken or expected to be taken on an income tax return. Under FIN 48, tax benefits should be recognized in the financial statements when it is more likely than not that the position will be sustained upon examination by the tax authorities based on the technical merits of the position. Such tax positions should be 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 adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation, Allegheny recognized a $17.7 million reduction to its January 1, 2007 balance of retained earnings.

Allegheny records interest and penalties associated with uncertain tax positions as a component of income tax expense. Accrued interest, net of tax, related to uncertain tax positions was $11.1 million and $11.8 million at September 30, 2007 and January 1, 2007, respectively.

The total gross FIN 48 reserve at September 30, 2007 was $76.3 million (net of state tax benefits of $53.2 million). Approximately $61.6 million of this reserve will not be resolved in the next 12 months and, therefore, has been classified as long term income taxes payable on the accompanying Consolidated Balance Sheet at September 30, 2007.

Unrecognized tax benefits were approximately $101.0 million and $107.6 million at September 30, 2007 and January 1, 2007, respectively. If recognized, the portion of these amounts that would reduce Allegheny’s effective tax rate was $42.3 million and $38.7 million at September 30, 2007 and January 1, 2007, respectively ($67.0 million and $58.9 million, respectively, before the federal income tax effects on state income tax positions).

The unrecognized tax benefit balance also included approximately $34.0 million and $48.7 million of tax positions at September 30, 2007 and January 1, 2007, respectively, for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would impact the timing of cash payments to the taxing authorities.

The major jurisdictions in which Allegheny is subject to income tax are U.S. Federal, Pennsylvania, West Virginia, Maryland and Virginia. Allegheny files consolidated federal income tax returns, and those returns are currently under audit by the Internal Revenue Service (“IRS”) for the tax years 1998 through 2003. The 2004 through 2006 federal returns have been filed and are still subject to review. Several of Allegheny’s subsidiaries file returns in Pennsylvania. Returns filed with the Pennsylvania Department of Revenue for the tax years 2002 through 2005 are subject to review. Allegheny also files a consolidated West Virginia return. The consolidated West Virginia returns have been audited through 2004. The 2005 and 2006 returns remain subject to review. Several of Allegheny’s subsidiaries are also subject to tax in the state of Maryland. The Maryland returns for the tax years 2004 through 2006 remain subject to review. Additionally, certain Allegheny subsidiaries are subject to tax in Virginia. The Virginia returns for tax years 2004 through 2006 remain subject to review.

As stated above, the IRS is currently auditing Allegheny’s income tax returns for the tax years 1998 through 2003. These audits are anticipated to be completed by December 31, 2007. During the audit period, Allegheny changed its method of applying the inventory capitalization rules from its traditional method to the simplified service cost method. The IRS has proposed adjustments related to the change in method that are strictly timing in nature. Interest accrued on this position was $11.7 million, net of tax, at September 30, 2007. It is reasonably

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

possible that a portion of this interest accrual will reverse in the next 12 months. However, should the IRS’s position prevail, the adjustments would not result in a material charge to Allegheny’s results of operations. Also, Allegheny has filed various refund claims with the IRS primarily related to property type items. These items were effectively settled with the IRS during the quarter ended September 30, 2007 and resulted in a net benefit of $3.3 million. Additionally, Allegheny has liabilities for uncertain positions taken on various state income tax returns that it files. The statute of limitations for some of these returns expired during the quarter ended September 30, 2007 and resulted in a benefit of approximately $0.8 million. Additionally, some of the state tax returns containing these positions are currently under audits that are likely to be resolved within the next 12 months. Should these audits be resolved in a favorable manner, they could result in benefits of up to $4.3 million.

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 Pennsylvania state taxable income per year, effective January 1, 2007. The carryforward limitation period remained unchanged at 20 years. Allegheny recorded a benefit during the third quarter of 2006 in the amount of $16.7 million for the state income tax effect, net of applicable federal income tax, reflecting the estimated portion of the loss carryforwards that will be realized during the carryforward period. During the three months ended September 30, 2007, an additional benefit of $4.2 million, net of applicable federal income tax, was recorded as a result of estimated additional Pennsylvania taxable income.

NOTE 6: DEBT

In September 2007, AE Supply amended its credit facility to increase the size of its revolving credit facility from $200 million to $400 million.

In April 2007, MP Environmental Funding LLC, an indirect subsidiary of Monongahela, and PE Environmental Funding LLC, an indirect subsidiary of Potomac Edison, issued $344 million and $115 million, respectively, of Senior Secured Sinking Fund Environmental Control Bonds, Series A. These bonds securitize the right to collect an environmental control surcharge that Monongahela and Potomac Edison impose on their retail customers in West Virginia. The bonds were issued in several tranches with interest rates ranging from 4.98% to 5.52% and final maturities ranging from July 2014 to July 2027. Net proceeds from the sale of the bonds represent non-current restricted funds and will be used to fund the majority of costs to construct and install Scrubbers at Fort Martin.

Issuances and repayments of indebtedness, by entity, during the nine months ended September 30, 2007 were as follows:


	Nine Months Ended
	September 30, 2007
(In millions)	Issuances			Repayments
Monongahela:
Environmental Control Bonds	$	344.5		$	—
Pollution Control Bonds		—			1.0
Potomac Edison:
Environmental Control Bonds		114.8			—
West Penn:
Transition Bonds (a)		4.1			60.2
AE Supply:
Pollution Control Bonds		7.0			32.0

Eliminations (b)		(7.0	)		(1.2	)

Consolidated Total	$	463.4		$	92.0


(a)		The issuance amounts represent interest that was accrued and added to the principal amount of certain of the bonds.

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

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

Long-Term Debt

At September 30, 2007, maturities of long-term debt for the remainder of 2007 and for full years thereafter were as follows:


(In millions)	2007			2008			2009			2010			2011			Thereafter			Total
AE Supply:
Medium—Term Notes	$	—		$	—		$	—		$	—		$	400.0		$	650.0		$	1,050.0
AE Supply Credit Facility		—			—			—			—			747.0			—			747.0
Pollution Control Bonds		79.1			—			—			—			—			179.0			258.1
Debentures—AGC		—			—			—			—			—			100.0			100.0

Total AE Supply	$	79.1		$	—		$	—		$	—		$	1,147.0		$	929.0		$	2,155.1


Monongahela:
First Mortgage Bonds	$	—		$	—		$	—		$	—		$	—		$	340.0		$	340.0
Medium—Term Notes		—			—			—			110.0			—			—			110.0
Environmental Control Bonds (a)		—			15.0			10.5			11.1			11.6			296.3			344.5
Pollution Control Bonds		14.5			—			—			—			—			70.2			84.7

Total Monongahela	$	14.5		$	15.0		$	10.5		$	121.1		$	11.6		$	706.5		$	879.2


Potomac Edison:
First Mortgage Bonds	$	—		$	—		$	—		$	—		$	—		$	420.0		$	420.0
Environmental Control Bonds (a)		—			4.9			3.5			3.7			3.8			98.9			114.8

Total Potomac Edison	$	—		$	4.9		$	3.5		$	3.7		$	3.8		$	518.9		$	534.8


West Penn:
Transition Bonds (a)	$	19.8		$	77.2		$	77.2		$	15.5		$	—		$	—		$	189.7
First Mortgage Bonds		—			—			—			—			—			145.0			145.0
Medium—Term Notes		—			—			—			—			—			80.0			80.0

Total West Penn	$	19.8		$	77.2		$	77.2		$	15.5		$	—		$	225.0		$	414.7


AGC:
Debentures	$	—		$	—		$	—		$	—		$	—		$	100.0		$	100.0

Total AGC	$	—		$	—		$	—		$	—		$	—		$	100.0		$	100.0


Unamortized debt discounts, premiums and terminated interest rate swaps		(0.4	)		(1.4	)		(1.3	)		(1.3	)		(1.0	)		(2.2	)		(7.6	)
Eliminations (b)		(4.1	)		—			—			—			—			(114.4	)		(118.5	)

Total consolidated debt	$	108.9		$	95.7		$	89.9		$	139.0		$	1,161.4		$	2,362.8		$	3,957.7


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

(b)		Represents the elimination of AGC’s $100 million 6 7/8% Debentures due 2023, which are also included above under AE Supply, and $18.5 million in the aggregate of 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. For additional information regarding property liens, see Item 2, “Properties” in the 2006 Annual Report on Form 10-K.

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

On October 22, 2007, at the request of AE Supply, Pleasants County, West Virginia and Harrison County, West Virginia issued $142 million of tax-exempt pollution control refunding bonds and $73.5 million of tax-exempt solid waste disposal refunding bonds, respectively (collectively, the “2007 AE Supply Bonds”). The 2007 AE Supply Bonds were issued to provide funds to repay pollution control and solid waste disposal bonds previously issued by these counties to finance certain facilities at Allegheny’s Pleasants and Harrison generating facilities. Each series of 2007 AE Supply Bonds has a 30-year maturity and a 10-year call provision, and the weighted average interest rate of the 2007 AE Supply Bonds is 5.34%. Each series of 2007 AE Supply Bonds will be payable solely from payments to be made under a corresponding note from AE Supply.

NOTE 7: PREFERRED STOCK REDEMPTION

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. This premium also reduced income per common share. See Note 16, “Income (Loss) Per Common Share,” for additional details.

NOTE 8: RATES AND REGULATION

West Virginia

In a July 26, 2006 filing with the Public Service Commission of West Virginia (the “West Virginia PSC”), Monongahela and Potomac Edison requested a decrease in base rates of approximately $26 million and an increase in revenues related to fuel and purchased power costs of approximately $126 million. On May 22, 2007, the West Virginia PSC issued a rate order (the “West Virginia Rate Order”) effective May 23, 2007 that will reduce Allegheny’s annual revenues by approximately $6 million and will decrease annual depreciation expense by approximately $16 million, resulting in an annual net pre-tax benefit of approximately $10 million. The $6 million revenue decrease is comprised of a decrease in base rates of approximately $132 million and an increase in revenues related to fuel and purchased power costs of approximately $126 million.

The following is a summary of additional significant provisions and accounting impacts of the West Virginia Rate Order:

	•		The West Virginia Rate Order established the annual ENEC method of recovering net power supply costs, including fuel costs, purchased power costs and other related expenses, net of related revenue. Under the ENEC, actual costs and revenues are tracked for under and/or over recoveries, and new ENEC rate filings will be made on an annual basis. Any under and/or over recovery of costs, net of related revenues, is deferred as a regulatory asset or regulatory liability, for subsequent recovery and/or refund, with the corresponding impact on the Consolidated Statements of Operations reflected within “Deferred energy costs, net.”

	•		In December 2005, Monongahela sold sulfur dioxide (“SO₂”) allowances to AE Supply for $14.8 million in cash and recorded the $14.7 million difference between the carrying value of the allowances and the cash received as a credit to “Other paid-in capital” in the amount of $8.8 million, net of the income tax effects of $5.9 million. The West Virginia Rate Order requires Monongahela to reduce its rate base by $14.7 million, and requires the subsequent amortization of this amount, net of amortization for the period from the December 2005 sale date through the effective date of the West Virginia Rate Order, as a credit to cost of service over a period of approximately 29 years. As a result, Monongahela reclassified $14.0 million, $8.3 million net of tax, from other paid-in capital to a “Regulatory liability.” In addition, Monongahela recorded a related deferred tax asset in the amount of $5.8 million during the second quarter of 2007. The regulatory liability will be amortized to revenue, and the deferred tax asset will be amortized to income tax expense over a period of approximately 29 years.

	•		The West Virginia Rate Order provides for the recovery of pension expense on an accrual basis. Monongahela and Potomac Edison previously recovered pension costs on a cash basis in West Virginia, and,

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

therefore, Allegheny did not record a regulatory asset related to the portion of pension obligations allocable to the West Virginia jurisdiction when it adopted SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106 and 132R (“SFAS No. 158”) on December 31, 2006. As a result of the West Virginia Rate Order, in the second quarter of 2007, Allegheny’s service subsidiary, AESC, established a regulatory asset related to pension obligations recorded upon adoption of SFAS No. 158, in the amount of $88.0 million, with a corresponding credit to “Other comprehensive income,” net of income tax effect.

As discussed in Note 6, “Debt,” in April 2007, MP Environmental Funding LLC, an indirect subsidiary of Monongahela, and PE Environmental Funding LLC, an indirect subsidiary of Potomac Edison, issued $344 million and $115 million, respectively, of Senior Secured Sinking Fund Environmental Control Bonds, Series A. These bonds securitize the right to collect an environmental control surcharge from customers of Monongahela and Potomac Edison.

The West Virginia regulatory orders that authorized the environmental control surcharge provide that the surcharge revenues will recover the principal, interest and financing costs associated with the majority of the Fort Martin Scrubber construction costs over the period of April 2007 through July 2027.

Allegheny expects that the Scrubbers will be completed and placed in service by late 2009. The Scrubbers will be depreciated over their estimated useful lives, which may be a greater period than the duration of the environmental control surcharge and related environmental control bonds.

Allegheny will account for the Fort Martin Scrubber project in a manner that results in no net income or loss from the securitized portion of project costs as follows:

	•		Environmental control surcharge revenues will be recorded as billed;

	•		Interest expense on the bonds will be recorded as incurred;

	•		Depreciation will be recorded over the estimated useful life of the Scrubbers after they are placed in service; and

	•		A regulatory liability will be recognized with an offsetting charge against revenues to the extent that environmental control surcharge revenue exceeds interest and depreciation expense. This liability will decrease, with an offsetting credit to revenue over the remaining useful life of the Scrubbers, after the environmental control surcharge ends and the bonds have been repaid.

Virginia

During the 2007 session, the Virginia General Assembly amended the Virginia Electric Utility Restructuring Act of 1999 (the “Restructuring Act”), to re-regulate the provision of electric generation services in the Commonwealth beginning January 1, 2009. Until that time, Potomac Edison’s retail electric customers in Virginia have the right to choose their electricity generation supplier. Until December 31, 2008, Potomac Edison is the provider-of-last-resort (“PLR”) for those customers who do not choose an alternate generation supplier or whose alternate generation supplier does not deliver. After January 1, 2009, Potomac Edison will provide generation services to all its customers in Virginia at regulated rates.

Potomac Edison had a power purchase agreement with AE Supply to provide it with the amount of electricity necessary to meet its PLR retail obligations through June 30, 2007 at the capped generation rates. In April 2007, Potomac Edison conducted a competitive bidding process to purchase its PLR requirements from the wholesale market for service beginning July 1, 2007, and AE Supply was the successful bidder with respect to a substantial portion of those requirements. Market prices for purchased power resulting from that bidding process, at which Potomac Edison began to purchase its PLR requirements on July 1, 2007, currently are higher, and likely will continue to be higher, than the rates Potomac Edison is currently allowed to recover from its retail customers. These higher market prices for power resulted in increased purchased power costs by Potomac Edison and increased revenues to AE Supply since July 1, 2007.

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

In an April 2007 filing with the State Corporation Commission of Virginia (“Virginia SCC”), Potomac Edison requested to adjust its fuel factor and to implement a rate stabilization plan, including an increase in retail rates beginning July 1, 2007, to moderate 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 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. Potomac Edison then filed a new application for rate recovery of purchased power costs for load above 367 MW with the Virginia SCC on September 11, 2007, and is continuing to pursue its appeal for full cost recovery. On October 10, 2007, the Virginia SCC issued an order setting Potomac Edison’s new application for hearing on December 4, 2007.

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 effective June 7, 2007. The Transition Plan provides for a gradual transition of Potomac Edison’s residential customers 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 who did not opt out of the Transition Plan began paying a non-bypassable distribution 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 and the initiation of the new surcharge. On January 1, 2008, the distribution surcharge will increase 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 would 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 statement of operations. As amounts are returned to customers as a surcharge credit in future periods, these customer credits will be charged directly to the regulatory liability.

See Note 6, “Debt,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Regulatory Matters,” and “Risk Factors,” below and Item 8, Note 14, “Rates and Regulation” in the 2006 Annual Report on Form 10-K for additional information regarding certain rate and regulatory matters.

NOTE 9: 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 (“SFAS No. 71”). Regulatory assets represent probable future revenues associated with currently incurred costs that are expected to be recovered in the future from customers through the rate-making process. Regulatory liabilities generally represent probable future reductions in revenues associated with amounts that are to be credited or refunded to customers through the rate-making process. Regulatory assets and regulatory liabilities reflected in the Consolidated Balance Sheets at September 30, 2007 and December 31, 2006 relate to:

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


	September 30,		December 31,
(In millions)	2007		2006
Regulatory assets, including current portion:
Income taxes	$	298.3	$	300.4
Pension benefits and postretirement benefits other than pension		253.8		178.2
Pennsylvania stranded cost recovery		27.1		55.6
Pennsylvania Competitive Transition Charge (“CTC”) reconciliation		115.1		107.4
Unamortized loss on reacquired debt		36.4		39.6
Deferred ENEC charges		7.3		—
Other		32.3		32.0

Subtotal		770.3		713.2

Regulatory liabilities, including current portion:
Net asset removal costs		392.9		421.4
Income taxes		37.4		38.9
SO₂ allowances		13.9		—
Fort Martin Scrubber project		21.5		—
Other		5.1		4.5

Subtotal		470.8		464.8

Net regulatory assets	$	299.5	$	248.4

The Consolidated Balance Sheets include the amounts listed below for generating assets not subject to SFAS No. 71.


	September 30,			December 31,
(In millions)	2007			2006
Property, plant and equipment	$	5,337.2		$	5,188.5
Amounts under construction included above	$	423.6		$	143.8
Accumulated depreciation	$	(2,333.9	)	$	(2,382.7	)

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

NOTE 10: STOCK-BASED COMPENSATION

Allegheny maintains certain stock-based compensation arrangements for employees and non-employee directors, which are described in greater detail in Item 8, Note 2, “Stock-Based Compensation,” in the 2006 Annual Report on Form 10-K. Allegheny records compensation expense for share-based payments to employees, including grants of employee stock options and stock units, over the requisite service period based on their estimated fair value on the date of grant.

The following table summarizes stock-based compensation expense:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2007		2006		2007		2006
Stock options	$	1.9	$	1.8	$	5.3	$	5.8
Stock units		0.5		1.0		2.0		4.3
Other		0.1		0.3		0.8		0.9

Stock-based compensation expense included in operations and maintenance expense		2.5		3.1		8.1		11.0
Income tax benefit		1.0		1.3		3.3		4.5

Total stock-based compensation expense, net of tax	$	1.5	$	1.8	$	4.8	$	6.5

No stock-based compensation cost was capitalized during the nine months ended September 30, 2007 and 2006.

Stock Options

Stock option activity for the three months ended September 30, 2007 was as follows:


						Aggregate
				Weighted-		Intrinsic
	Number of			Average		Value
	Stock Options			Exercise Price		(in millions)
Outstanding at June 30, 2007		4,262,958		$	16.092
Granted		4,000		$	52.230
Exercised		(67,262	)	$	19.184
Forfeited		(2,400	)	$	13.350

Outstanding at September 30, 2007		4,197,296		$	16.079	$	151.9

Exercisable at September 30, 2007		2,671,094		$	15.628	$	97.8

Stock option activity for the nine months ended September 30, 2007 was as follows:


						Aggregate
				Weighted-		Intrinsic
	Number of			Average		Value
	Stock Options			Exercise Price		(in millions)
Outstanding at December 31, 2006		4,670,338		$	16.504
Granted		29,000		$	51.850
Exercised		(445,315	)	$	23.207
Forfeited		(56,727	)	$	13.386

Outstanding at September 30, 2007		4,197,296		$	16.079	$	151.9

Exercisable at September 30, 2007		2,671,094		$	15.628	$	97.8

The intrinsic value in the tables above represents the difference between the current market value of Allegheny’s stock and the exercise price of the options.

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

Allegheny received cash from option exercises totaling $1.3 million and $10.3 million for the three and nine months ended September 30, 2007, respectively. Allegheny issued new shares of its common stock to satisfy these stock option exercises.

As of September 30, 2007, there was approximately $10.8 million of unrecognized compensation cost related to non-vested outstanding stock options, which is expected to be recognized over a weighted-average period of approximately 1.4 years.

Stock Units

Stock unit activity for the three and nine months ended September 30, 2007 was as follows:


	Number of
	Stock Units
Outstanding at December 31, 2006		1,045,966
Units converted into 68,477 common shares		(107,220	)

Outstanding at March 31, 2007		938,746
Units converted into 247,530 common shares		(409,888	)

Outstanding at June 30, 2007		528,858
Units converted into 16,525 common shares		(26,985	)

Outstanding at September 30, 2007		501,873

There were 21,985 stock units convertible at September 30, 2007.

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

As of September 30, 2007, there was $1.0 million of total unrecognized compensation cost related to non-vested outstanding stock units, which is expected to be recognized over a weighted average period of approximately five months.

Non-Employee Director Stock Plan

Non-employee director stock plan share activity for the three and nine months ended September 30, 2007 was as follows:


	Number of
	Shares
Shares earned but not issued at December 31, 2006		64,893
Granted		8,000
Issued		(12,400	)

Shares earned but not issued at March 31, 2007		60,493
Granted		5,600
Issued		(1,400	)

Shares earned but not issued at June 30, 2007		64,693
Granted		2,648
Issued		(662	)

Shares earned but not issued at September 30, 2007		66,679

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

NOTE 11: PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

Substantially all of Allegheny’s employees, including officers, are employed by AESC and are covered by a noncontributory, defined benefit pension plan. Allegheny also maintains a 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, are based upon an age and years-of-service vesting schedule, other plan provisions and 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.

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

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


	Pension Benefits
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2007			2006			2007			2006
Components of net periodic cost:
Service cost	$	5.3		$	5.4		$	16.1		$	16.3
Interest cost		16.2			15.4			48.5			46.1
Expected return on plan assets		(18.3	)		(17.4	)		(54.8	)		(52.2	)
Amortization of unrecognized transition obligation		0.1			0.1			0.3			0.3
Amortization of prior service cost		0.8			0.8			2.4			2.6
Recognized actuarial loss		2.7			3.2			8.0			9.4

Net periodic cost	$	6.8		$	7.5		$	20.5		$	22.5


Allocation of net periodic cost:
Monongahela	$	2.2		$	1.9		$	6.5		$	5.8
AE Supply		1.6			2.3			4.9			6.8
West Penn		1.7			1.8			5.1			5.5
Potomac Edison		1.2			1.4			3.8			4.1
AE		0.1			0.1			0.2			0.3

Net periodic cost	$	6.8		$	7.5		$	20.5		$	22.5


	Postretirement Benefits Other Than Pensions
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2007			2006			2007			2006
Components of net periodic cost:
Service cost	$	1.1		$	1.2		$	3.4		$	3.8
Interest cost		4.3			4.2			12.7			12.6
Expected return on plan assets		(1.7	)		(1.7	)		(5.0	)		(5.2	)
Amortization of unrecognized transition obligation		1.4			1.4			4.2			4.3
Recognized actuarial loss		0.6			1.0			1.8			2.9

Net periodic cost	$	5.7		$	6.1		$	17.1		$	18.4


Allocation of net periodic cost:
Monongahela	$	1.7		$	1.7		$	5.2		$	5.1
West Penn		1.6			1.6			4.7			5.0
Potomac Edison		1.3			1.4			3.8			4.0
AE Supply		1.1			1.4			3.3			4.2
AE		—			—			0.1			0.1

Net periodic cost	$	5.7		$	6.1		$	17.1		$	18.4

For the three months ended September 30, 2007 and 2006, Allegheny allocated net periodic cost of $3.7 million and $3.4 million, respectively, and, for the nine months ended September 30, 2007 and 2006, Allegheny allocated net periodic cost of $10.6 million and $9.4 million, respectively, to “Construction work in progress,” a component of “Property, plant and equipment, net.”

Allegheny contributed $0.1 million and $35.7 million to its pension plans during the three and nine months ended September 30, 2007, respectively, including contributions to the SERP of $0.1 million and $0.2 million during the three and nine months ended September 30, 2007, respectively. Allegheny also contributed $4.3 million and $10.8 million to fund its postretirement benefits plans other than pension plans during the three and nine months

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

ended September 30, 2007, respectively. Allegheny estimates that its total contributions to the pension plans during 2007 will be between $36 and $50 million. Allegheny currently anticipates contributing a total amount in 2007 ranging from $13.0 million to $15.0 million to fund its postretirement benefits plans other than pension plans.

Allegheny made matching cash contributions to the Employee Stock Ownership and Savings Plan of $2.2 million and $6.3 million for the three and nine months ended September 30, 2007, respectively.

The Pension Protection Act of 2006 may affect the manner in which many companies, including Allegheny, administer their pension plans. It is effective January 1, 2008 and will require many companies to more fully fund their pension plans according to new funding targets, potentially resulting in greater annual contributions. Allegheny is currently assessing the impact that the new legislation will have on its pension funding in future years.

NOTE 12: DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Allegheny has designated certain contracts as cash flow hedges of forecasted sales of electricity. Changes in the fair value of these contracts upon such designation and thereafter are reflected in “Accumulated other comprehensive loss” until the hedged item is realized. These contracts expire at various dates through December 2008. The pre-tax accumulated other comprehensive income for the contracts was $2.2 million at September 30, 2007 and $1.3 million at December 31, 2006. The increase in accumulated other comprehensive income related to cash flow hedges is a result of the change in the fair value of these contracts due to changes in market prices and settlements and additional cash flow hedge contracts. The entire accumulated other comprehensive income balance is expected to be completely recorded as an increase to earnings over the next fifteen months, with $3.2 million recorded as a decrease to earnings over the next twelve months. Certain contracts have been de-designated as hedges during the second and third quarters as a result of entering into physical marketing contracts. The related other comprehensive income amount of $1.0 million will be recorded to income over the next quarter. The ineffective portion of cash flow hedges reflected in earnings was $0.2 million and $0.1 million for the three and nine months ended September 30, 2007, respectively, and $0.3 million and $1.2 million for the three and nine months ended September 30, 2006, respectively.

Derivative contracts that are not designated as cash flow hedges or normal purchase and normal sale contracts are accounted for on a mark-to-market basis with changes in fair value reflected in earnings. The recorded net fair value of mark-to-market and cash flow hedge derivative commodity contracts was a net liability of $17.2 million and $22.5 million at September 30, 2007 and December 31, 2006, respectively.

Operating revenues included net unrealized gains related to trading activities and net realized gains (losses) related to cash flow hedges and trading activities as follows:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(In millions)	2007		2006			2007		2006
Amounts included in operating revenues:
Net realized gains (losses)	$	5.4	$	(14.1	)	$	4.3	$	(18.7	)
Net unrealized gains	$	2.8	$	8.5		$	4.4	$	26.8

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

NOTE 13: DISCONTINUED OPERATIONS

The components of the 2006 loss from discontinued operations, which related entirely to AE Supply’s Gleason generating facility, were as follows:


	Three Months			Nine Months
	Ended			Ended
(In millions)	September 30, 2006			September 30, 2006
Operating revenues	$	—		$	—
Operating expenses		(0.4	)		(1.2	)
Interest expense		(0.4	)		(2.2	)

Loss before income taxes		(0.8	)		(3.4	)
Income tax benefit		0.3			1.3
Impairment charge, net of tax		—			(0.1	)

Loss from discontinued operations, net of tax	$	(0.5	)	$	(2.2	)

AE Supply completed the sale of the Gleason generating facility to the Tennessee Valley Authority in December 2006.

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

NOTE 14: 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, 2007									Three Months Ended September 30, 2006
	Delivery		Generation							Delivery		Generation
	and		and							and		and
(In millions)	Services		Marketing		Eliminations			Total		Services		Marketing			Eliminations			Total
External operating revenues	$	690.2	$	156.4	$	—		$	846.6	$	700.4	$	116.2		$	—		$	816.6
Internal operating revenues		2.2		424.7		(426.9	)		—		1.8		372.4			(374.2	)		—

Total operating revenues	$	692.4	$	581.1	$	(426.9	)	$	846.6	$	702.2	$	488.6		$	(374.2	)	$	816.6
Depreciation and amortization	$	40.4	$	26.3	$	—		$	66.7	$	37.7	$	30.6		$	—		$	68.3
Operating income	$	37.1	$	191.4	$	—		$	228.5	$	80.7	$	130.4		$	—		$	211.1
Interest expense	$	18.1	$	43.1	$	(1.8	)	$	59.4	$	20.1	$	46.8		$	(0.8	)	$	66.1
Income from continuing operations	$	12.8	$	102.2	$	—		$	115.0	$	43.8	$	66.9		$	—		$	110.7
Loss from discontinued operations, net of tax	$	—	$	—	$	—		$	—	$	—	$	(0.5	)	$	—		$	(0.5	)
Net income	$	12.8	$	102.2	$	—		$	115.0	$	43.8	$	66.4		$	—		$	110.2


	Nine Months Ended September 30, 2007									Nine Months Ended September 30, 2006
	Delivery		Generation							Delivery		Generation
	and		and							and		and
(In millions)	Services		Marketing		Eliminations			Total		Services		Marketing			Eliminations			Total
External operating revenues	$	2,121.3	$	399.4	$	—		$	2,520.7	$	2,031.8	$	352.7		$	—		$	2,384.5
Internal operating revenues		7.5		1,231.5		(1,239.0	)		—		5.5		1,057.1			(1,062.6	)		—

Total operating revenues	$	2,128.8	$	1,630.9	$	(1,239.0	)	$	2,520.7	$	2,037.3	$	1,409.8		$	(1,062.6	)	$	2,384.5
Depreciation and amortization	$	121.7	$	87.7	$	—		$	209.4	$	113.3	$	91.0		$	—		$	204.3
Operating income	$	203.6	$	446.9	$	—		$	650.5	$	227.1	$	347.3		$	—		$	574.4
Interest expense	$	55.0	$	131.2	$	(4.6	)	$	181.6	$	61.9	$	150.2		$	(2.2	)	$	209.9
Income from continuing operations	$	91.7	$	210.1	$	—		$	301.8	$	113.5	$	143.4		$	—		$	256.9
Loss from discontinued operations, net of tax	$	—	$	—	$	—		$	—	$	—	$	(2.2	)	$	—		$	(2.2	)
Net income	$	91.7	$	210.1	$	—		$	301.8	$	113.5	$	141.2		$	—		$	254.7

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

NOTE 15: COMPREHENSIVE INCOME

Comprehensive income consisted of the following:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(In millions)	2007			2006		2007		2006
Net income	$	115.0		$	110.2	$	301.8	$	254.7
Other comprehensive income:
West Virginia Rate Order – establishment of regulatory asset related to pension obligation, net of tax		—			—		52.3		—
Unrealized gains (losses) on cash flow hedges, net of tax		(2.5	)		6.0		0.7		29.9
Pension and other postretirement employee benefit amortization, net of tax		0.9			—		2.7		—

Comprehensive income	$	113.4		$	116.2	$	357.5	$	284.6

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


	September 30,			December 31,
(In millions)	2007			2006
Cash flow hedges, net of tax	$	0.9		$	0.2
Net unrecognized pension and other postretirement benefit costs, net of tax		(52.4	)		(107.4	)

Total	$	(51.5	)	$	(107.2	)

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

NOTE 16: INCOME (LOSS) PER COMMON SHARE

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions, except share and per share amounts)	2007			2006			2007			2006
Basic Income (Loss) per Common Share:
Numerator:
Income from continuing operations	$	115.0		$	110.7		$	301.8		$	256.9
Redemption of preferred stock(a)		(1.1	)		—			(1.1	)		—

Income from continuing operations available for common shareholders		113.9			110.7			300.7			256.9
Loss from discontinued operations		—			(0.5	)		—			(2.2	)

Net income available for common shareholders	$	113.9		$	110.2		$	300.7		$	254.7


Denominator:
Weighted average common shares outstanding		166,101,169			164,813,343			165,798,727			163,812,973


Basic Income (Loss) per Common Share:
Income from continuing operations	$	0.69		$	0.67		$	1.81		$	1.56
Loss from discontinued operations		—			—			—			(0.01	)

Basic income per common share	$	0.69		$	0.67		$	1.81		$	1.55


Diluted Income (Loss) per Common Share:
Numerator:
Income from continuing operations	$	115.0		$	110.7		$	301.8		$	256.9
Redemption of preferred stock (a)		(1.1	)		—			(1.1	)		—

Income from continuing operations available for common shareholders		113.9			110.7			300.7			256.9
Loss from discontinued operations		—			(0.5	)		—			(2.2	)

Net income available for common shareholders	$	113.9		$	110.2		$	300.7		$	254.7


Denominator:
Weighted average common shares outstanding		166,101,169			164,813,343			165,798,727			163,812,973
Effect of dilutive securities:
Stock options		2,770,502			2,692,136			2,758,665			2,619,057
Stock units		493,652			1,050,672			728,057			2,081,523
Non-employee stock awards		64,715			47,676			59,938			40,677
Performance shares		25,497			25,497			25,497			32,391

Total shares		169,455,535			168,629,324			169,370,884			168,586,621


Diluted Income (Loss) per Common Share:
Income from continuing operations	$	0.67		$	0.65		$	1.78		$	1.52
Loss from discontinued operations		—			—			—			(0.01	)

Diluted income per common share	$	0.67		$	0.65		$	1.78		$	1.51


(a)		See Note 7, “Preferred Stock Redemption,” for information related to Monongahela’s redemption of preferred stock.

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

NOTE 17: GUARANTEES AND LETTERS OF CREDIT

In connection with certain sales, acquisitions and financings, and in the normal course of business, AE and certain of its subsidiaries enter into various agreements that may include guarantees or letters of credit. AE’s credit facility includes a $400 million revolving facility, any unutilized portion of which is available for the issuance of letters of credit. In addition, AE Supply’s credit facility includes a $400 million revolving credit facility, which can be used, if availability exists, to issue letters of credit. Guarantees and letters of credit were as follows:


	September 30, 2007				December 31, 2006
	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:
Loans and other financing-related matters	$	—	$	10.2	$	—	$	8.4
Lease agreement		—		4.9		—		4.7
Purchase, sale, exchange or transportation of wholesale natural gas, electric power and related services		—		36.5		—		20.4
Other		0.2		0.2		0.2		0.2

Total Guarantees	$	0.2	$	51.8	$	0.2	$	33.7


Letters of Credit:
Under AE’s Revolving Facility (a)	$	—	$	6.7	$	—	$	131.8
Other (b)		—		2.5		—		2.1

Total Letters of Credit		—		9.2		—		133.9

Total Guarantees and Letters of Credit	$	0.2	$	61.0	$	0.2	$	167.6


(a)		The September 30, 2007 amount is comprised of a letter of credit for $6.7 million issued in connection with a contractual obligation of Allegheny Ventures that expires in July 2008. The December 31, 2006 amount also included a letter of credit for $125.0 million on behalf of Allegheny as collateral to stay enforcement of the judgment in Allegheny’s litigation against Merrill Lynch. The $125.0 million letter of credit was released during the quarter ended September 30, 2007 as the result of an August 31, 2007 federal appellate court ruling. See Note 19, “Commitments and Contingencies” for additional information.

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

NOTE 18: OTHER INCOME AND EXPENSES, NET

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


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(In millions)	2007			2006		2007		2006
Interest and dividend income	$	3.5		$	4.2	$	10.9	$	15.0
Gain on the sale or exchange of real estate		8.9			0.2		8.9		1.0
Tax reimbursement on contributions in aid of construction		1.7			1.8		4.5		4.9
Premium services		(0.4	)		0.7		0.7		2.7
Coal brokering income		—			0.4		—		1.3
Other		1.1			0.6		2.6		0.9

Total	$	14.8		$	7.9	$	27.6	$	25.8

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

NOTE 19: COMMITMENTS AND CONTINGENCIES

Environmental Matters and Litigation

Allegheny is subject to various laws, regulations and uncertainties as to environmental matters. Compliance may require Allegheny to incur substantial additional costs to modify or replace existing and proposed equipment and facilities that may adversely affect the cost of future operations.

Global Climate Change.Allegheny’s generation facilities are primarily coal-fired facilities and, therefore, emit carbon dioxide as coal is consumed. Carbon dioxide, or “CO₂,” is one of the greenhouse gases implicated in global climate change. There is no current technology that enables control of such emissions from existing pulverized, coal-fired power plants, which constitute the majority of Allegheny’s generation fleet. At the same time, Allegheny takes its responsibility for environmental stewardship seriously and recognizes its obligation to its shareholders to address the issue of climate change. Despite the regulatory actions of some states and regional groups in 2006, Allegheny believes that the challenge presented by global climate change can only be resolved with global solutions. In addition, Allegheny believes that the United States must commit to a response that both encourages the development of technology and creates a workable control system. The United States Congress is moving towards the development of national legislation, yet the process is still in its infancy. As such, it is difficult for Allegheny to aggressively implement greenhouse gas emission expenditures until the exact nature and requirements of a national regulation are known, and the capabilities of control or reduction technologies are more fully understood. Allegheny recognizes that federal legislation and implementation regulations addressing climate change will likely be adopted some time in the future and supports federal legislation. Allegheny’s current strategy focuses on:

	•		developing an accurate CO₂ emissions inventory;

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

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

	•		following developing technologies for carbon sequestration;

	•		participating in carbon dioxide 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.

To the extent that legislation is introduced and programs are developed, Allegheny will advocate for a national approach that recognizes the importance of its generating fleet and investments, enhances the environment and ensures continued energy supply for its customers. Allegheny’s management is following this issue closely and will take further appropriate action as the economics and legislation unfold.

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 SO₂ by using emission controls, burning low-sulfur coal, purchasing cleaned coal (which has lower sulfur content), blending low-sulfur coal with higher sulfur coal and utilizing emission allowances.

Allegheny’s compliance with the Clean Air Act of 1990 (the “Clean Air Act”) has required, and may require in the future, that Allegheny install control technologies on many of its generation facilities. The Clean Air Interstate Rule (“CAIR”) promulgated by the United States Environmental Protection Agency (the “EPA”) on March 10, 2005, may accelerate the need to install this equipment by phasing out a portion of currently available allowances.

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

The Clean Air Act mandates annual reductions of SO₂ and created a SO₂ emission allowance trading program. AE Supply and Monongahela comply with current SO₂ emission standards through a system-wide plan combining the use of emission controls, low sulfur fuel and emission allowances. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities, as well as the implementation of environmental controls. Allegheny continues to evaluate options for compliance, and current plans include the installation of Scrubbers at its Hatfield’s Ferry and Fort Martin generating facilities by 2009 and the elimination of a Scrubber bypass at its Pleasants generation facility by 2008. AE Supply has entered into construction contracts with The Babcock & Wilcox Company (“B&W”) and Washington Group International (“WGI”) in connection with its plans to install Scrubbers at its Hatfield’s Ferry generation facility. Monongahela has entered into construction contracts with B&W and WGI in connection with its plans to install Scrubbers at Fort Martin.

Allegheny meets current emission standards for nitrogen oxides (“NOx”) by using low NOx burners, Selective Catalytic Reduction, Selective Non-Catalytic Reduction and over-fire air and optimization software, as well as through the use of emission allowances. Allegheny is currently evaluating its options for CAIR compliance. In 1998, the EPA finalized its NOx State Implementation Plan (“SIP”) call rule (known as the “NOx SIP call”), which addressed the regional transport of ground-level ozone and required the equivalent of a uniform 0.15 lb/mmBtu emission rate throughout a 22-state region, including Pennsylvania, Maryland and West Virginia.

AE Supply and Monongahela have completed installation of NOx controls to meet the Pennsylvania, Maryland and West Virginia SIP calls. The NOx compliance plan functions on a system-wide basis, similar to the SO₂ compliance plan. AE Supply and Monongahela also have the option, in some cases, to purchase alternate fuels or NOx allowances, if needed, to supplement their compliance strategies. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities.

On March 15, 2005, the EPA issued the Clean Air Mercury Rule (“CAMR”), establishing a cap and trade system designed to reduce mercury emissions from coal-fired power plants in two phases during 2010 and 2018. This rule will be implemented through state implementation plans currently under development. The rule has been challenged by several parties. Allegheny is currently assessing CAMR and developing its strategy for compliance, but it will include the emission reduction projects discussed above for the Hatfield’s Ferry, Fort Martin and Pleasants generating facilities, as they will have a co-benefit effect and also remove mercury from plant emissions. The Pennsylvania Department of Environmental Protection (the “PA DEP”) promulgated a more aggressive mercury control rule on February 17, 2007. Pennsylvania’s proposed shortened compliance schedule and more aggressive emissions limits might result in the installation of additional emission controls at any of Allegheny’s three Pennsylvania coal-fired facilities or in a change in fuel specifications. Controls might include additional Scrubbers, activated carbon injection, selective catalytic reduction or other, currently emerging technologies.

Additionally, Maryland passed the Healthy Air Act in early 2006. This legislation imposes state-wide emission caps on SO₂ and NOx, requires greater reductions in mercury emissions more quickly than required by CAMR and mandates that Maryland join the Regional Greenhouse Gas Initiative (“RGGI”) and participate in that coalition’s regional efforts to reduce CO₂ emission. On April 20, 2007, Maryland’s governor signed the 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 does provide a conditional exemption for the R. Paul Smith power station, 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 in 2007 to comply with both the Healthy Air Act and the federal CAIR. Allegheny is assessing the new legislation and upcoming implementing regulations to determine the full extent of the impacts on Allegheny’s Maryland operations and is working with the MDE on the R. Paul Smith-specific regulations. The statutory exemption does not extend to R. Paul Smith’s CO₂ emissions, and Maryland is in the process of developing its response to the statute’s RGGI requirements.

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

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 pollution 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 pollution control technology.

On April 2, 2007, the United States Supreme Court issued a decision in the Duke Energy case vacating the Fourth Circuit’s decision that had supported the industry’s understanding of NSR requirements and remanded the case to the lower court. The Supreme Court rejected the industry’s position on an hourly emissions standard and adopted an annual emissions standard favored by environmental groups. However, the Supreme Court did not specify a testing standard for how to calculate annual emissions and otherwise provided little clarity on whether the industry’s or the government’s interpretation of other aspects of the NSR regulations will prevail.

On May 20, 2004, AE, AE Supply, Monongahela and West Penn received a Notice of Intent to Sue Pursuant to Clean Air Act §7604 (the “Notice”) from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP. The Notice alleged that Allegheny made major modifications to some of its West Virginia facilities in violation of the Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act at the following coal-fired facilities: Albright Unit No. 3; Fort Martin Units No. 1 and 2; Harrison Units No. 1, 2 and 3; Pleasants Units No. 1 and 2 and Willow Island Unit No. 2. The Notice also alleged PSD violations at the Armstrong, Hatfield’s Ferry and Mitchell generation facilities in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. On September 8, 2004, AE, AE Supply, Monongahela and West Penn received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.

On January 6, 2005, AE Supply and Monongahela filed a declaratory judgment action against the Attorneys General of New York, Connecticut and New Jersey in federal District Court in West Virginia (“West Virginia DJ Action”). This action requests that the court declare that AE Supply’s and Monongahela’s coal-fired generation facilities in Pennsylvania and West Virginia comply with the Clean Air Act. The Attorneys General filed a motion to dismiss the West Virginia DJ Action. It is possible that the EPA and other state authorities may join or move to transfer the West Virginia DJ Action.

On June 28, 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply and the Distribution Companies in the United States District Court for the Western District of Pennsylvania (the “PA Enforcement Action”). This action alleges NSR violations under the federal Clean Air Act and the Pennsylvania Air Pollution Control Act at the Hatfield’s Ferry, Armstrong and Mitchell facilities in Pennsylvania. The PA Enforcement Action appears to raise the same issues regarding Allegheny’s Pennsylvania generation facilities that are before the federal District Court in the West Virginia DJ Action, except that the PA Enforcement Action also includes the PA DEP and the Maryland Attorney General. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. On May 30, 2006, the District Court denied Allegheny’s motion to dismiss the amended complaint. On July 26, 2006, at a status conference, the Court determined that discovery would proceed regarding liability issues, but not remedies. On June 27, 2007, the Court extended discovery on the liability phase until December 31, 2007.

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

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

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

Canadian Toxic-Tort Class Action:On June 30, 2005, AE Supply, Monongahela and AGC, along with 18 other companies with coal-fired generation facilities, were named as defendants in a toxic-tort, purported class action lawsuit filed in the Ontario Superior Court of Justice. On behalf of a purported class comprised of all persons residing in Ontario within the past six years (and/or their family members or heirs), the named plaintiffs allege that the defendants negligently failed to prevent their generation facilities from emitting air pollutants in such a manner as to cause death and multiple adverse health effects, as well as economic damages, to the plaintiff class. The plaintiffs seek damages in the approximate amount of Canadian $49.1 billion (approximately US $50.0 billion, assuming an exchange rate of 0.9811 Canadian dollars per US dollar), along with continuing damages in the amount of Canadian $4.1 billion per year and punitive damages of Canadian $1.0 billion (approximately US $4.2 billion and US $1.0 billion, respectively, assuming an exchange rate of 0.9811 Canadian dollars per US dollar) along with such other relief as the court deems just. Allegheny has not yet been served with this lawsuit, and the time for service of the original lawsuit has expired. Allegheny intends to vigorously defend against this action but cannot predict its outcome.

Global Warming Class Action:On April 9, 2006, AE, along with numerous other companies with coal-fired generation facilities and companies in other industries, was named as a defendant in a class action lawsuit in the United States District Court for the Southern District of Mississippi. On behalf of a purported class of residents and property owners in Mississippi who were harmed by hurricane Katrina, the named plaintiffs allege that the emission of greenhouse gases by the defendants contributed to global warming, thereby causing Hurricane Katrina and plaintiffs’ damages. The plaintiffs seek unspecified damages. On December 6, 2006, AE filed a motion to dismiss plaintiffs’ complaint on jurisdictional grounds and then joined a motion filed by other defendants to dismiss the complaint for failure to state a claim. At a hearing on August 30, 2007, the Court granted the motion to dismiss that AE had joined and dismissed all of the plaintiffs’ claims against all defendants. Plaintiffs filed a notice of appeal of that ruling on September 17, 2007, and the appeal will now proceed before the United States Court of Appeals for the Fifth Circuit. AE intends to vigorously defend against this action but cannot predict its outcome.

Claims Related to Alleged Asbestos Exposure:The Distribution Companies have been named as defendants, along with multiple other defendants, in pending asbestos cases alleging bodily injury involving multiple plaintiffs and multiple sites. These suits have been brought mostly by seasonal contractors’ employees and do not involve allegations of the manufacture, sale or distribution of asbestos-containing products by Allegheny. These asbestos suits arise out of historical operations and are related to the installation and removal of asbestos-containing materials at Allegheny’s generation facilities. Allegheny’s historical operations were insured by various foreign and domestic insurers, including Lloyd’s of London. Asbestos-related litigation expenses have to date been reimbursed in full by recoveries from these historical insurers, and Allegheny believes that it has sufficient insurance to respond fully to the asbestos suits. Certain insurers, however, have contested their obligations to pay for the future defense and settlement costs relating to the asbestos suits. Allegheny is currently involved in two asbestos and environmental insurance-related actions, Certain Underwriters at Lloyd’s, London et al. v. Allegheny Energy, Inc. et al.,Case No. 21-C-03-16733 (Washington County, Md.), and Monongahela Power Company et al. v. Certain Underwriters at Lloyd’s London and London Market Companies, et al., Civil Action No. 03-C-281 (Monongalia County, W.Va.). The parties 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. Allegheny believes that it has recorded appropriate liabilities to cover existing and future asbestos claims. As of September 30, 2007, Allegheny’s total number of claims alleging exposure to asbestos was 826 in West Virginia, two in Pennsylvania and one in Illinois.

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

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

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, Nevada 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 September 25, 2007, the Supreme Court announced that it has agreed to hear the case on appeal. A briefing schedule has been set by the Supreme Court, and briefing by all parties is expected to be completed by February 6, 2008, at the latest.

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

Sierra/Nevada.On April 2, 2003, NPC and Sierra Pacific Resources, Inc. (together, “Sierra/Nevada”) initiated a lawsuit in United States District Court in Nevada against AE and AE Supply, together with Merrill Lynch & Co. and Merrill Lynch Capital Services, Inc. (together, “Merrill”). Sierra/Nevada has alleged that AE, AE Supply and Merrill engaged in fraudulent conduct in connection with NPC’s application to the Public Utilities Commission of Nevada (the “Nevada PUC”) for a deferred energy accounting adjustment, which allegedly caused the Nevada PUC to disallow $180 million of NPC’s deferred energy expenses. Sierra/Nevada has asserted claims against AE and AE Supply for: (a) wrongful hiring and supervision; (b) tortious interference with Sierra/Nevada’s contractual and prospective economic advantages; (c) conspiracy and (d) violations of the Nevada state Racketeer Influenced and Corrupt Organization (“RICO”) Act. Sierra/Nevada’s most recent complaint seeks damages in excess of $850 million, including compensatory damages, punitive damages, attorneys’ fees and treble damages. AE and AE Supply have filed motions to dismiss the lawsuit, which have been pending since 2003. The lawsuit had been stayed since 2005, pending the outcome of certain state court proceedings in which Sierra/Nevada was seeking to reverse the Nevada PUC’s disallowance of expenses. On July 20, 2006, the Nevada Supreme Court reversed the Nevada PUC’s disallowance of the $180 million in deferred energy expenses, which formed the basis of the plaintiffs’ claims. An announcement was made on March 23, 2007 that the Nevada PUC approved two settlements relating to the requested disallowance, and those state court proceedings that were the focus of the prior stay have been closed. A scheduling order was then entered in this lawsuit that, among other things, sets a trial date of July 8, 2008. The parties are engaged in the discovery process and awaiting a ruling from the District Court on the previously filed motions to dismiss.

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 all issues in connection with AE Supply sales to CDWR were resolved by a settlement in 2003 and otherwise believes that the California parties’ demand is without merit. Allegheny intends to vigorously defend against this claim but cannot predict its outcome.

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

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

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

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

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

Allegheny intends to vigorously pursue this matter but cannot predict its outcome.

Based on the developments discussed above, Allegheny determined during the third quarter 2007 that it was appropriate to cease the accrual of additional interest in this matter, but that it was not appropriate to reverse the accrued interest liability of approximately $55 million at this time, given the current status and history of this litigation.

Ordinary Course of Business.AE and its subsidiaries are from time to time involved in litigation and other legal disputes in the ordinary course of business. Allegheny is of the belief that there are no other legal proceedings that could have a material adverse effect on its business or financial condition.

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

NOTE 20: SUBSEQUENT EVENTS

On October 4, 2007, the Board of Directors of AE declared a cash dividend of $0.15 per share on AE’s common stock. The dividend is payable on December 17, 2007 to shareholders of record on December 3, 2007.

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

ITEM 2.

The following discussion and analysis should be read in conjunction with the Financial Statements and Notes to Financial Statements included in this report, as well as the Financial Statements and Supplementary Data and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Annual Report on Form 10-K for the year ended December 31, 2006 (the “2006 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:

	•		rate regulation and the status of retail generation service supply competition in states served by the Distribution Companies;

	•		financing plans;

	•		demand for energy and the cost and availability of raw materials, including coal;

	•		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;

	•		capacity purchase commitments and

	•		regulatory matters.

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:

	•		plant performance and unplanned outages;

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

	•		general economic and business conditions;

	•		changes in access to capital markets and actions of rating agencies;

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

	•		environmental regulations;

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

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

	•		changes in industry capacity, development and other activities by competitors of AE and its consolidated subsidiaries;

	•		changes in the weather and other natural phenomena;

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

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

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

	•		the loss of any significant customers or suppliers;

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

	•		inflationary and interest rate trends;

	•		changes in the market rules, including changes to participant rules and tariffs in the energy market operated by PJM Interconnection, LLC (“PJM”), which is a regional transmission organization;

	•		the effect of accounting pronouncements issued periodically by accounting standard-setting bodies and accounting issues facing our organization; 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 2006 Annual Report on Form 10-K. Additionally, certain risk factors with respect to which material changes have occurred since their disclosure in the 2006 Annual Report on Form 10-K are discussed under Item 1A, “Risk Factors.”

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

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. AE, Allegheny’s parent holding company, was incorporated in Maryland in 1925. 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 2006 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 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, 2007 and 2006 was as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Revenue per MWh sold	$	59.56	$	59.01	$	59.80	$	58.78

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, 2007 and 2006 was as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
O&M per MWh sold	$	7.68	$	7.65	$	7.65	$	8.19

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

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

The following table provides retail electricity sales information.


	Three Months Ended									Nine Months Ended
	September 30,									September 30,
	Normal		2007		2006		Change			Normal		2007		2006		Change
Retail electricity sales (million kWhs)		N/A		11,164		11,026		1.3	%		N/A		33,540		32,257		4.0	%
HDD		97		62		113		(45.1	)%		3,594		3,437		3,069		12.0	%
CDD		561		666		606		9.9	%		767		944		778		21.3	%


(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. HDD and CDD are most likely to impact the usage of Allegheny’s residential and commercial customers. Industrial customers are less weather sensitive. Degree-day data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit, 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.

The Generation and Marketing Segment

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

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

Equivalent Availability Factor (“EAF”).The EAF measures the percentage of time that a generation unit is available to generate electricity if called upon in the marketplace. A unit’s availability is commonly less than 100%, primarily as a result of unplanned outages or scheduled outages for planned maintenance. 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 maintenance costs consist of normal recurring expenses related to the day-to-day on-going operation of the generation facility. Special maintenance includes outage related maintenance and projects that relate to all of the generating facilities.

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

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,									September 30,
	2007			2006			Change			2007			2006			Change
Supercritical Units:
kWhs generated (in millions)		10,226			10,535			(2.9	)%		30,285			30,269			0.1	%
EAF		87.5	%		89.6	%		(2.1	)%		85.5	%		86.2	%		(0.7	)%
Station O&M (in millions):
Base operations (a)	$	23.5		$	24.0			(2.1	)%	$	78.1		$	74.3			5.1	%
Special		14.9			14.2			4.9	%		57.0			54.9			3.8	%

Total Station O&M	$	38.4		$	38.2			0.5	%	$	135.1		$	129.2			4.6	%


All Generation Units:
kWhs generated (in millions)		12,640			12,798			(1.2	)%		37,491			37,050			1.2	%
EAF		86.5	%		91.9	%		(5.4	)%		85.9	%		88.8	%		(2.9	)%
Station O&M (in millions):
Base operations (a)	$	36.7		$	38.0			(3.4	)%	$	120.1		$	116.6			3.0	%
Special		16.5			15.6			5.8	%		65.8			63.9			3.0	%

Total Station O&M	$	53.2		$	53.6			(0.7	)%	$	185.9		$	180.5			3.0	%


(a)		Reflects the reclassification of certain fuel handling and residual disposal costs as described in Note 1, “Basis of Presentation,” to Allegheny’s Consolidated Financial Statements.

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

CONSOLIDATED RESULTS OF OPERATIONS

Income Summary


	Three Months Ended									Three Months Ended
	September 30, 2007									September 30, 2006
	Delivery		Generation							Delivery			Generation
	and		and							and			and
(In millions)	Services		Marketing		Eliminations			Total		Services			Marketing			Eliminations			Total
Operating revenues	$	692.4	$	581.1	$	(426.9	)	$	846.6	$	702.2		$	488.6		$	(374.2	)	$	816.6
Fuel		—		245.5		—			245.5		—			231.0			—			231.0
Purchased power and transmission		493.0		25.6		(424.7	)		93.9		466.2			8.2			(372.4	)		102.0
Deferred energy costs, net		2.3		1.3		—			3.6		(0.2	)		—			—			(0.2	)
Operations and maintenance		85.7		71.3		(2.2	)		154.8		84.3			68.2			(1.8	)		150.7
Depreciation and amortization		40.4		26.3		—			66.7		37.7			30.6			—			68.3
Taxes other than income taxes		33.9		19.7		—			53.6		33.5			20.2			—			53.7

Total operating expenses		655.3		389.7		(426.9	)		618.1		621.5			358.2			(374.2	)		605.5

Operating income		37.1		191.4		—			228.5		80.7			130.4			—			211.1
Other income and expenses, net		3.0		13.6		(1.8	)		14.8		5.3			3.4			(0.8	)		7.9
Interest expense and preferred dividends		18.2		43.3		(1.8	)		59.7		20.2			47.0			(0.8	)		66.4

Income from continuing operations before income taxes and minority interest		21.9		161.7		—			183.6		65.8			86.8			—			152.6
Income tax expense from continuing operations		9.1		58.1		—			67.2		22.0			18.9			—			40.9
Minority interest		—		1.4		—			1.4		—			1.0			—			1.0

Income from continuing operations		12.8		102.2		—			115.0		43.8			66.9			—			110.7
Loss from discontinued operations, net of tax		—		—		—			—		—			(0.5	)		—			(0.5	)

Net income	$	12.8	$	102.2	$	—		$	115.0	$	43.8		$	66.4		$	—		$	110.2


	Nine Months Ended												Nine Months Ended
	September 30, 2007												September 30, 2006
	Delivery			Generation									Delivery		Generation
	and			and									and		and
(In millions)	Services			Marketing			Eliminations			Total			Services		Marketing			Eliminations			Total
Operating revenues	$	2,128.8		$	1,630.9		$	(1,239.0	)	$	2,520.7		$	2,037.3	$	1,409.8		$	(1,062.6	)	$	2,384.5
Fuel		—			709.1			—			709.1			—		641.5			—			641.5
Purchased power and transmission		1,447.9			77.2			(1,231.5	)		293.6			1,328.8		26.6			(1,057.1	)		298.3
Gain on sale of OVEC power agreement and shares		—			—			—			—			—		(6.1	)		—			(6.1	)
Deferred energy costs, net		(0.5	)		(5.6	)		—			(6.1	)		5.2		—			—			5.2
Operations and maintenance		256.6			256.8			(7.5	)		505.9			264.2		248.6			(5.5	)		507.3
Depreciation and amortization		121.7			87.7			—			209.4			113.3		91.0			—			204.3
Taxes other than income taxes		99.5			58.8			—			158.3			98.7		60.9			—			159.6

Total operating expenses		1,925.2			1,184.0			(1,239.0	)		1,870.2			1,810.2		1,062.5			(1,062.6	)		1,810.1

Operating income		203.6			446.9			—			650.5			227.1		347.3			—			574.4
Other income and expenses, net		10.4			21.8			(4.6	)		27.6			16.5		11.5			(2.2	)		25.8
Interest expense and preferred dividends		55.4			131.6			(4.6	)		182.4			62.4		150.6			(2.2	)		210.8

Income from continuing operations before income taxes and minority interest		158.6			337.1			—			495.7			181.2		208.2			—			389.4
Income tax expense from continuing operations		66.9			124.6			—			191.5			67.7		62.4			—			130.1
Minority interest		—			2.4			—			2.4			—		2.4			—			2.4

Income from continuing operations		91.7			210.1			—			301.8			113.5		143.4			—			256.9
Loss from discontinued operations, net of tax		—			—			—			—			—		(2.2	)		—			(2.2	)

Net income	$	91.7		$	210.1		$	—		$	301.8		$	113.5	$	141.2		$	—		$	254.7

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

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.

Operating Revenues

Operating revenues increased $30.0 million for the three months ended September 30, 2007 compared to the three months ended September 30, 2006, primarily due to:

	•		higher generation rates charged to Pennsylvania customers,

	•		an increase in the weighted average “round-the-clock” price for power in Allegheny’s region of PJM Interconnection, LLC (“PJM”), the APS Zone, from $53.43 per MWh for the three months ended September 30, 2006 to $55.76 per MWh for the three months ended September 30, 2007 and increased net PJM capacity market revenues,

	•		increased revenues related to the collection of an environmental control surcharge from the West Virginia retail customers of Monongahela and Potomac Edison, which began in April 2007,

	•		increased transmission and distribution revenues due to increased CDD, increased customer load and the expiration of a Maryland customer choice credit,

	•		partially offset by a 1.2% decrease in total MWhs generated and the settlement of certain existing cash flow hedges in 2006.

Operating revenues increased $136.2 million for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006, primarily due to:

	•		higher generation rates charged to Pennsylvania customers,

	•		an increase in the weighted average “round-the-clock” price for power in Allegheny’s region of PJM, the APS Zone, from $49.72 per MWh for the nine months ended September 30, 2006 to $54.81 per MWh for the nine months ended September 30, 2007 and increased net PJM capacity market revenues,

	•		increased revenues related to the collection of the environmental control surcharge from the West Virginia retail customers of Monongahela and Potomac Edison, which began in April 2007,

	•		increased transmission and distribution revenues due to increases in HDD and CDD, increased customer load and the expiration of a Maryland customer choice credit and

	•		a 1.2% increase in total MWhs generated.

Operating Income

��Operating income increased $17.4 million for the three months ended September 30, 2007 compared to the three months ended September 30, 2006, primarily due to:

	•		the $30.0 million increase in operating revenues discussed above and

	•		an $8.1 million decrease in purchased power and transmission expense, primarily due to the May 2007 expiration of a power sale agreement related to the sale of the Ohio service territory that was partially offset by increased costs to purchase power at market-based rates to serve Virginia customers,

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

•

partially offset by a $14.5 million increase in fuel expense and a $4.1 million increase in operations and maintenance expense due to a $4.6 million contingent fee relating to a consulting project.

Fuel expense increased primarily due to higher coal and natural gas costs and an increase in emission allowance expense. The higher coal costs were primarily due to an increase in the average price of coal that was partially offset by a decrease in the amount of coal burned and a $6.7 million increase in the annual physical inventory adjustment. The amount of coal burned was lower due to lower total MWhs generated. The higher natural gas costs resulted from an increase in the amount of natural gas burned. The increase in the amount of gas burned was due to an increase in the dispatch of Allegheny’s gas-fired generation facilities.

Operating income increased $76.1 million for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006, primarily due to:

	•		the $136.2 million increase in operating revenues discussed above and

	•		an $11.3 million change in deferred energy costs, net, representing a net credit to expense for energy costs incurred but not yet recovered in rates, related primarily to the May 22, 2007 Public Service Commission of West Virginia (the “West Virginia PSC”) rate order (the “West Virginia Rate Order”), which, effective May 23, 2007, allows certain costs to be deferred and recovered in future customer rates, and a greater net credit to expense for deferred energy costs related to the AES Warrior Run Maryland generation facility,

	•		partially offset by a $67.6 million increase in fuel expense.

Fuel expense increased primarily due to higher coal and natural gas costs. The higher coal costs were primarily due to an increase in the average price of coal that was partially offset by a $6.7 million increase in the annual physical inventory adjustment. The higher natural gas costs resulted from an increase in the amount of natural gas burned. The increase in the amount of gas burned was due to an increase in the dispatch of Allegheny’s gas-fired generation facilities.

For additional information regarding the West Virginia Rate Order, see the “Regulatory Matters” section of Management’s Discussion and Analysis (“MD&A”) below and Note 8, “Rates and Regulation.” For additional information regarding deferred costs related to the AES Warrior Run generation facility see “Deferred Energy Costs, Net,” below.

Income from Continuing Operations Before Income Taxes and Minority Interest

Income from continuing operations before income taxes and minority interest increased $31.0 million for the three months ended September 30, 2007 compared to the three months ended September 30, 2006, primarily due to:

	•		the $17.4 million increase in operating income discussed above,

	•		a $6.9 million increase in other income and expenses, net, primarily due to an $8.4 million gain relating to an exchange transaction involving La Paz, Arizona real estate and

	•		a $6.7 million decrease in interest expense and preferred dividends of Monongahela, primarily due to lower average debt outstanding, increased capitalization of interest and the discontinuance of interest expense related to the Merrill Lynch litigation as a result of a favorable appellate court ruling, partially offset by increased interest expense associated with the April 2007 issuance of environmental control bonds.

Income from continuing operations before income taxes and minority interest increased $106.3 million for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006, primarily due to:

•

the $76.1 million increase in operating income discussed above and

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

•

a $28.4 million decrease in interest expense and preferred dividends of Monongahela, primarily due to lower average debt outstanding, increased capitalization of interest and the discontinuance of interest expense related to the Merrill Lynch litigation as a result of a favorable appellate court ruling partially offset by increased interest expense associated with the April 2007 issuance of environmental control bonds.

See Note 19, “Commitments and Contingencies,” for additional information on the appellate court ruling.

Income Tax Expense

See Note 5, “Income Taxes,” for a reconciliation of income tax expense to income tax expense calculated at the federal statutory rate of 35%.

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

DISCUSSION OF SEGMENT RESULTS OF OPERATIONS:

Delivery and Services

The following table provides retail electricity sales information.


	Three Months Ended									Nine Months Ended
	September 30,									September 30,
	Normal		2007		2006		Change			Normal		2007		2006		Change
Retail electricity sales (million kWhs)		N/A		11,164		11,026		1.3	%		N/A		33,540		32,257		4.0	%
HDD		97		62		113		(45.1	)%		3,594		3,437		3,069		12.0	%
CDD		561		666		606		9.9	%		767		944		778		21.3	%

Operating Revenues

Operating revenues were as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2007		2006		2007		2006
Retail electric:
Generation	$	454.5	$	435.5	$	1,354.9	$	1,266.8
Transmission		41.0		40.7		123.9		119.9
Distribution		169.4		174.4		527.0		509.3

Total retail electric		664.9		650.6		2,005.8		1,896.0

Transmission services and bulk power		17.5		41.8		91.8		115.7
Other affiliated and nonaffiliated energy services		10.0		9.8		31.2		25.6

Total operating revenues	$	692.4	$	702.2	$	2,128.8	$	2,037.3

Retail electric revenues increased $14.3 million for the three months ended September 30, 2007 compared to the three months ended September 30, 2006, primarily due to:

	•		a $19.0 million increase in generation revenues, primarily due to a $13.4 million increase resulting from higher generation rates charged to Pennsylvania customers and a $9.6 million increase related to the West Virginia Rate Order, which approved an increase in generation rates charged to customers,

	•		partially offset by a $4.7 million decrease in transmission and distribution (“T&D”) revenues, primarily due to a $12.4 million decrease related to rates resulting from the West Virginia Rate Order, which was partially offset by a $4.2 million increase due to the expiration of a Maryland customer choice credit and a $3.9 million increase due to increased customer load.

Retail electric revenues increased $109.8 million for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006, primarily due to:

	•		an $88.1 million increase in generation revenues, primarily due to a $39.0 million increase resulting from higher generation rates charged to Pennsylvania customers, a $13.7 million increase from the West Virginia Rate Order, which approved an increase in generation rates charged to customers, and a $26.5 million increase due to increased customer load from increases in HDD and CDD and

	•		a $21.7 million increase in T&D revenues, primarily due to a $32.6 million increase from increased customer load and a $4.5 million increase due to the expiration of a Maryland customer choice credit, partially offset by a $19.1 million decrease as a result of the West Virginia Rate Order.

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

Transmission services and bulk power revenues decreased $24.3 million and $23.9 million for the three and nine months ended September 30, 2007, respectively, compared to the three and nine months ended September 30, 2006, primarily due to the May 2007 expiration of a fixed price power supply agreement to serve Monongahela’s former Ohio service territory.

Other affiliated and nonaffiliated energy services revenues increased $5.6 million for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006, primarily due to the deferral of revenue on certain fiber optic agreements during the first quarter of 2006 and the impact of regulatory activities related to certain transmission contracts.

Operating Expenses

Purchased Power and Transmission:Purchased power and transmission represents the Distribution Companies’ power purchases from other companies (primarily AE Supply), as well as purchases from Monongahela and qualifying facilities under the Public Utility Regulatory Policies Act of 1978 (“PURPA”). Purchased power and transmission consists of the following items:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2007		2006		2007		2006
Other purchased power and transmission	$	457.4	$	412.5	$	1,330.0	$	1,175.9
From PURPA generation		35.6		53.7		117.9		152.9

Total purchased power and transmission	$	493.0	$	466.2	$	1,447.9	$	1,328.8

West Penn and Potomac Edison 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. In addition, through December 31, 2006, Potomac Edison had a power purchase agreement with AE Supply under which AE Supply provided Potomac Edison with the power necessary to meet its West Virginia load obligation at a fixed rate. In connection with the Asset Swap, Monongahela assumed the obligation to supply power to serve Potomac Edison’s West Virginia load. Thus, effective January 1, 2007, 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 2007 West Virginia Rate Order of the Expanded Net Energy Cost (“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 the “Regulatory Matters” section of MD&A below and Note 8, “Rates and Regulation,” for additional information.

Through December 31, 2006, to facilitate the economic dispatch of its generation, Monongahela sold the power that it generated from its West Virginia jurisdictional assets to AE Supply at PJM market prices and purchased from AE Supply, at PJM market prices, the power necessary to meet its West Virginia jurisdictional customer load. Effective January 1, 2007, 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. The net revenue from these PJM purchases and sales is reflected in wholesale and other revenues, net within the Generation and Marketing segment. See Note 4, “Asset Swap,” for additional information.

Other purchased power and transmission increased $44.9 million for the three months ended September 30, 2007 compared to the three months ended September 30, 2006, primarily due to:

	•		a $35.2 million increase due to market-based rates in Virginia beginning July 1, 2007 (See Note 8, “Rates and Regulation,” for additional information regarding market-based rates in Virginia),

	•		a $13.4 million increase, primarily due to a net increase in the price of purchased power from AE Supply for Pennsylvania customers and

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

	•		an $8.1 million increase due to the West Virginia Rate Order, which approved an increase in generation rates charged to customers (such increases result in greater costs to the Delivery and Services segment and greater revenues to the Generation and Marketing segment),

	•		partially offset by a $14.7 million decrease due to the expiration of a contract to supply power for Monongahela’s former Ohio electric service territory through May 2007.

Other purchased power and transmission increased $154.1 million for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006, primarily due to:

	•		a $61.8 million increase, primarily due to increased purchased power volume as a result of increases in HDD and CDD and increased customer load,

	•		a $39.0 million increase, primarily due to a net increase in the price of purchased power from AE Supply for Pennsylvania customers, which is passed on to AE Supply under the terms of a power supply agreement between West Penn and AE Supply,

	•		a $35.2 million increase due to market-based rates in Virginia beginning July 1, 2007 (See Note 8, “Rates and Regulation,” for additional information regarding market-based rates in Virginia),

	•		a $16.6 million increase due to the January 1, 2007 power supply agreement between Potomac Edison and Monongahela discussed above (Monongahela’s revenues relating to this agreement are included in the Generation and Marketing segment) and

	•		an $11.6 million increase due to the West Virginia Rate Order, which approved an increase in generation rates charged to customers (such increases result in greater costs to the Delivery and Services segment and greater revenues to the Generation and Marketing segment),

	•		partially offset by a $9.9 million decrease due to the expiration of a contract to supply power for Monongahela’s former Ohio electric service territory through May 2007.

Purchased power and transmission from PURPA generation decreased $18.1 million for the three months ended September 30, 2007 compared to the three months ended September 30, 2006, primarily due to a $14.8 million decrease in purchased power from PURPA as a result of a January 1, 2007 transfer of Monongahela’s PURPA contracts from the Delivery and Services segment to the Generation and Marketing segment.

Purchased power and transmission from PURPA generation decreased $35.0 million for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006, primarily due to a $48.8 million decrease in purchased power from PURPA as a result of a January 1, 2007 transfer of Monongahela’s PURPA contracts from the Delivery and Services segment to the Generation and Marketing segment, partially offset by an increase in purchased power due to outages at the AES Warrior Run generation facility during the nine months ended September 30, 2006 that did not recur during the nine months ended September 30, 2007.

Deferred Energy Costs, Net:Deferred energy costs, net represents a component of expense to reconcile the period in which increases or decreases in certain energy costs are incurred to the period in which such costs are recovered in rates. Deferred energy costs relate to the following:

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

AES Warrior Run PURPA Generation

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

Market-based Maryland Generation Costs

Potomac Edison is authorized by the Maryland PSC to recover the 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.

Deferred energy costs, net were as follows:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(In millions)	2007		2006			2007			2006
Deferred energy costs, net	$	2.3	$	(0.2	)	$	(0.5	)	$	5.2

The $2.5 million change in deferred energy costs, net for the three months ended September 30, 2007 compared to the three months ended September 30, 2006 represents a net expense, primarily related to the AES Warrior Run PURPA generation facility.

The $5.7 million change in deferred energy costs, net for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006 represents a net credit to expense, primarily related to the AES Warrior Run PURPA generation facility and market-based generation costs.

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)	2007		2006		2007		2006
Operations and maintenance	$	85.7	$	84.3	$	256.6	$	264.2

Operations and maintenance expenses increased $1.4 million for the three months ended September 30, 2007 compared to the three months ended September 30, 2006, primarily due to:

	•		a $5.7 million increase in outside services expense, primarily due to a $4.6 million contingent fee relating to a consulting project and increased legal fees and

	•		a $1.0 million increase in labor and overhead expense due to a decrease in capitalized labor,

	•		partially offset by a $2.8 million decrease due to reduced claim reserves and a $2.3 million decrease in contractor services.

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

Operations and maintenance expenses decreased $7.6 million for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006, primarily due to:

	•		a $9.0 million decrease in contractor services and

	•		a $2.7 million decrease due to reduced claim reserves,

	•		partially offset by a $5.1 million increase in outside services expense, primarily due to a $4.6 million contingent fee relating to a consulting project and increased legal fees.

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2007		2006		2007		2006
Depreciation and amortization	$	40.4	$	37.7	$	121.7	$	113.3

Depreciation and amortization expenses increased $2.7 million and $8.4 million for the three and nine months ended September 30, 2007, respectively, compared to the three and nine months ended September 30, 2006, primarily due to increased depreciation resulting from net property, plant and equipment additions, amortization of regulatory assets and the West Virginia Rate Order, which shortened the depreciable lives of certain T&D assets.

Other Income and Expenses, Net

Other income and expenses, net were as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2007		2006		2007		2006
Other income and expenses, net	$	3.0	$	5.3	$	10.4	$	16.5

Other income and expenses, net, decreased $2.3 million and $6.1 million for the three and nine months ended September 30, 2007, respectively, compared to the three and nine months ended September 30, 2006, primarily as a result of decreased interest income on investments due to lower investment balances.

Interest Expense and Preferred Dividends:

Interest expense and preferred dividends were as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2007		2006		2007		2006
Interest expense and preferred dividends	$	18.2	$	20.2	$	55.4	$	62.4

Interest expense and preferred dividends decreased $2.0 million for the three months ended September 30, 2007 compared to the three months ended September 30, 2006, primarily due to lower average debt outstanding.

Interest expense and preferred dividends decreased $7.0 million for the nine months ended September 30, 2007 compared to nine months ended September 30, 2006, primarily due to lower average debt outstanding and the write-off of prior deferred financing costs during the nine months ended September 30, 2006 that did not recur during the nine months ended September 30, 2007.

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
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Income Tax Expense

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 three months ended September 30, 2006 was 33.3% and was lower than the federal statutory tax rate of 35%, primarily due to state income tax benefits related to West Virginia consolidated tax savings.

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 in relation to uncertain tax positions under FIN 48, which accounted for an increase of approximately 1.2%.

The effective tax rate for the nine months ended September 30, 2006 was 37.2% and was higher than the federal statutory tax rate of 35%, primarily due to state income taxes.

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
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Generation and Marketing

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


	Three Months Ended							Nine Months Ended
	September 30,							September 30,
	2007		2006		Change			2007		2006		Change
Generation (million kWhs)		12,640		12,798		(1.2	)%		37,491		37,050		1.2	%

Operating Revenues

Operating revenues were as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2007		2006		2007		2006
Revenue from affiliates	$	424.7	$	372.4	$	1,231.5	$	1,057.0
Wholesale and other revenue, net (a)		156.4		116.2		399.4		352.8

Total revenues	$	581.1	$	488.6	$	1,630.9	$	1,409.8


(a)		Amounts are net of energy trading gains and losses as described in Note 12, “Derivative Instruments and Hedging Activities.” Energy trading gains (losses) are presented in the wholesale and other revenues table below.

Revenue from affiliates:Revenue from affiliates results primarily from the sale of power to the Distribution Companies.

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. In addition, through December 31, 2006, AE Supply had a power sales agreement with Potomac Edison to provide the power necessary to meet Potomac Edison’s West Virginia load obligation at a fixed rate. In connection with the Asset Swap, Monongahela assumed the obligation to supply power to serve Potomac Edison’s West Virginia load. Thus, effective January 1, 2007, 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 under the 2007 West Virginia Rate Order of the ENEC for Allegheny’s West Virginia service territory, the amount charged to Potomac Edison reflects the adjustment for over and/or under recovery. See the “Regulatory Matters” section of MD&A below and Note 8, “Rates and Regulation,” for additional information.

Through December 31, 2006, to facilitate the economic dispatch of its generation, Monongahela sold the power that it generated from its West Virginia jurisdictional assets to AE Supply at PJM market prices and purchased from AE Supply, at PJM market prices, the power necessary to meet its West Virginia jurisdictional customer load. AE Supply recorded these transactions with Monongahela as either affiliated revenue or affiliated purchased power and transmission expense, depending on energy requirements as determined on an hourly basis. Effective January 1, 2007, 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. The net revenue from these PJM purchases and sales is reflected in wholesale and other revenues, net. See Note 4, “Asset Swap,” for additional information.

The average rate at which the Generation and Marketing segment sold power to the Distribution Companies was $39.69 and $35.17 per MWh for the three months ended September 30, 2007 and 2006, respectively, and $37.98 and $34.90 per MWh for the nine months ended September 30, 2007 and 2006, respectively.

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
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AND RESULTS OF OPERATIONS

Revenue from affiliates increased $52.3 million for the three months ended September 30, 2007 compared to the three months ended September 30, 2006, primarily due to:

	•		a $30.6 million increase as a result of higher prices during the third quarter 2007 due to a new power sales agreement with Potomac Edison effective July 1, 2007 that were partially offset by decreased sales volumes for certain of Potomac Edison’s customers in Virginia,

	•		a $23.9 million increase in Monongahela’s West Virginia affiliated revenues due to an increase in sales volume and price, including a $14.8 million increase reflecting the transfer of Monongahela’s PURPA contracts to the Generation and Marketing segment from the Delivery and Services segment, causing a corresponding increase in both revenues and purchased power, and a $5.3 million increase due to the West Virginia Rate Order, which increased generation rates charged to customers (such increases result in greater costs to the Delivery and Services segment and greater revenues to the Generation and Marketing segment),

	•		a $13.4 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,

	•		a $5.4 million increase in Potomac Edison’s affiliated revenues due to the assignment, in connection with the Asset Swap, of AE Supply’s below-market power supply agreement to serve Potomac Edison’s West Virginia load obligations, as a result of which, Potomac Edison now purchases the power necessary to service its West Virginia customers from Monongahela at rates that are greater than the rates under the AE Supply agreement at a prorated share of overall Monongahela generation costs,

	•		increased sales volumes as a result of increased CDD and increased customer load,

	•		partially offset by a $9.4 million decrease related to decreased sales volumes that was partially offset by higher contractual rates for certain of Potomac Edison’s customers in Maryland and

	•		a $6.0 million decrease in ancillary service revenues from the Delivery and Services segment due to a contract expiration.

Revenue from affiliates increased $174.5 million for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006, primarily due to:

	•		a $67.5 million increase in Monongahela’s West Virginia affiliated revenues due to an increase in sales volume and price, including a $48.8 million increase reflecting the transfer of Monongahela’s PURPA contracts to the Generation and Marketing segment from the Delivery and Services segment, causing a corresponding increase in both revenues and purchased power, and a $7.5 million increase due to the West Virginia Rate Order, which increased generation rates charged to customers (such increases result in greater costs to the Delivery and Services segment and greater revenues to the Generation and Marketing segment),

	•		a $39.0 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,

	•		a $30.6 million increase as a result of higher prices during the third quarter 2007 due to a new power sales agreement with Potomac Edison effective July 1, 2007 that were partially offset by decreased sales volumes for certain of Potomac Edison’s customers in Virginia,

	•		a $28.4 million increase in Potomac Edison’s affiliated revenues due to the assignment, in connection with the Asset Swap, of AE Supply’s below-market power supply agreement to serve Potomac Edison’s West Virginia load obligations, as a result of which, Potomac Edison now purchases from Monongahela the power necessary to service its West Virginia customers at rates that are greater than the rates under the AE Supply agreement at a prorated share of overall Monongahela generation costs,

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
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	•		a $12.5 million increase related to higher contractual rates with increased sales volumes for certain of Potomac Edison’s customers in Maryland and

	•		increased sales volumes as a result of increases in HDD and CDD and increased customer load,

	•		partially offset by a $13.5 million decrease in ancillary service revenues from the Delivery and Services segment due to a contract expiration.

Wholesale and other revenues, net:The table below describes the significant components of wholesale revenues.


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2007			2006			2007			2006
PJM Revenue:
Generation sold into PJM	$	623.4		$	550.5		$	1,862.0		$	1,601.2
Power purchased from PJM		(487.5	)		(429.2	)		(1,495.9	)		(1,261.2	)

Net		135.9			121.3			366.1			340.0
Cash flow hedges and trading activities:
Realized gains (losses)		5.4			(14.1	)		4.3			(18.7	)
Unrealized gains		2.8			8.5			4.4			26.8

Net		8.2			(5.6	)		8.7			8.1
Fort Martin Scrubber surcharge		6.1			—			11.6			—
Other revenues		6.2			0.5			13.0			4.7

Total wholesale and other revenues	$	156.4		$	116.2		$	399.4		$	352.8

Wholesale and other revenues increased $40.2 million for the three months ended September 30, 2007 compared to the three months ended September 30, 2006, primarily due to:

	•		an increase in net PJM revenues of $14.6 million,

	•		a $13.8 million increase related to cash flow hedges and trading activities due to decreasing PJM market prices subsequent to the transaction of certain cash flow hedges and the settlement of certain existing cash flow hedges in 2006,

	•		a $6.1 million increase relating to an environmental control surcharge that Monongahela and Potomac Edison impose on their West Virginia retail customers following the April 2007 Fort Martin Scrubber securitization financing (See Note 6, “Debt” for additional information regarding the securitization transaction) and

	•		a $5.7 million increase in other revenues as a result of increased sales related to load-following contracts.

The increase in net PJM revenues was 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, increased PJM capacity market revenues and an increase in the dispatch of gas-fired generation facilities as a result of higher market prices for electricity, offset by a decrease in MWhs generated due to a decrease in supercritical plant availability. Power purchased from PJM increased due to an increase in the market price of power, increased sales volume from the Distribution Companies due to increases in CDD, increased customer load, increased sales volumes for certain of Potomac Edison’s customers in Maryland and Virginia and the transfer of Monongahela’s PURPA contracts to the Generation and Marketing segment from the Delivery and Services segment, partially offset by the expiration of certain contracts to provide ancillary load services.

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

Wholesale and other revenues increased $46.6 million for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006, primarily due to:

	•		an increase in net PJM revenues of $26.1 million,

	•		an $11.6 million increase relating to an environmental control surcharge that Monongahela and Potomac Edison impose on their West Virginia retail customers following the April 2007 Fort Martin Scrubber securitization financing and

	•		an $8.3 million increase in other revenues as a result of increased sales related to load-following contracts.

See Note 6, “Debt” for additional information regarding the securitization transaction.

The increase in net PJM revenues was 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, increased net PJM capacity market revenues and an increase in the dispatch of gas-fired generation facilities as a result of higher market prices for electricity, which resulted in increased MWhs generated, partially offset by reduced revenues due to the March 2006 assignment of AE Supply’s rights to generation from OVEC in connection with the sale of a portion of AE’s equity interest in OVEC. Power purchased from PJM increased due to an increase in the market price of power, increased sales volume from the Distribution Companies due to increases in HDD and CDD, increased customer load, increased sales volumes for certain of Potomac Edison’s customers in Maryland and Virginia and the transfer of Monongahela’s PURPA contracts to the Generation and Marketing segment from the Delivery and Services segment, partially offset by the expiration of certain contracts to provide ancillary load services.

Fair Value of Contracts:Allegheny qualifies certain of its commodity contracts under the “normal purchase and normal sale” scope exception under SFAS No. 133. As a result, Allegheny accounts for these contracts under the accrual method, rather than marking these contracts to market value. Allegheny uses derivative accounting for energy contracts that do not qualify under the scope exception. These energy contracts are recorded at fair value, which represents the net unrealized gain and loss on open positions, in the Consolidated Balance Sheets, after applying the appropriate counterparty netting agreements. The realized and unrealized revenues from energy trading activities are recorded on a net basis in “Operating revenues” in the Consolidated Statements of Operations. The fair value of the remaining trading portfolio consists primarily of interest rate swap agreements and commodity cash flow hedges as of September 30, 2007. Changes in the fair value of the commodity cash flow hedges are reflected in other comprehensive income.

At September 30, 2007, the fair values of derivative contract assets and liabilities were $7.0 million and $24.2 million, respectively. At December 31, 2006, the fair values of derivative contract assets and liabilities were $1.5 million and $24.0 million, respectively.

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

The following table disaggregates the net fair values of derivative contract assets and liabilities, based on the underlying market price source and the contract settlement periods. The table excludes non-derivatives such as AE Supply’s generation assets, PLR requirements and SFAS No. 133 scope exceptions under the normal purchase and normal sale election:


	Fair value of contracts at September 30, 2007
	Settlement by:
Classification of contracts by source of fair value (In millions)	2007		2008			2009			2010			2011			Total
Prices actively quoted	$	3.6	$	(8.0	)	$	(5.7	)	$	(5.4	)	$	(1.7	)	$	(17.2	)
Prices provided by other external sources		—		—			—			—			—			—
Prices based on models		—		—			—			—			—			—

Total	$	3.6	$	(8.0	)	$	(5.7	)	$	(5.4	)	$	(1.7	)	$	(17.2	)

The fair value of AE Supply’s contracts that are scheduled to settle by December 31, 2007 was a net asset of $3.6 million, primarily related to gains associated with cash flow hedges. The fair value for 2009 and beyond solely relates to interest rate swaps.

See Note 12, “Derivative Instruments and Hedging Activities,” for additional information.

Changes in Fair Value:Net unrealized gains of $2.8 million and $4.4 million for the three and nine months ended September 30, 2007, respectively, were recorded on the Consolidated Statements of Operations in “Operating revenues” to reflect the change in fair value of the derivative contracts. The following table provides a summary of changes in the net fair value of AE Supply’s derivative contracts:


	Three Months Ended			Nine Months Ended
(In millions)	September 30, 2007			September 30, 2007
Net fair value of derivative contract liabilities at July 1 and January 1, respectively	$	(15.8	)	$	(22.5	)
Changes in fair value of cash flow hedges		(4.2	)		0.9
Unrealized gains on contracts, net		2.8			4.4

Net fair value of derivative contract liabilities at September 30	$	(17.2	)	$	(17.2	)

As shown in the table above, the net fair value of Allegheny’s derivative contracts decreased by $1.4 million during the three months ended September 30, 2007 and increased by $5.3 million during the nine months ended September 30, 2007. The change in the fair values was primarily due to changes in the fair values of commodity contracts and settlement of existing derivative contracts.

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)	2007		2006		2007		2006
Fuel	$	245.5	$	231.0	$	709.1	$	641.5

Total fuel expense increased by $14.5 million for the three months ended September 30, 2007 compared to the three months ended September 30, 2006, primarily due to a $6.6 million increase in natural gas expense, a $3.2 million increase in coal expense and a $3.9 million increase in emission allowance expense. The increase in natural gas expense was primarily due to a 1.2 million decatherm increase in the amount of natural gas burned. The increase in the amount of natural gas burned was primarily due to an increase in the dispatch of gas-fired generation facilities

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

as a result of higher market prices for power. The increase in coal expense was primarily due to an increase in the average price of coal of $3.18 per ton, partially offset by a decrease in total MWhs generated and a $6.7 million increase in the annual physical inventory adjustment.

Total fuel expense increased by $67.6 million for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006, primarily due to a $35.6 million increase in coal expense and a $25.8 million increase in natural gas expense. The increase in coal expense was primarily due to an increase in the average price of coal of $2.57 per ton, partially offset by a $6.7 million increase in the annual physical inventory adjustment. The increase in natural gas expense was primarily due to a 3.4 million decatherm increase in the amount of natural gas burned. The increase in the amount of natural gas burned was primarily due to an increase in the dispatch of gas-fired generation facilities as a result of higher market prices for power.

Purchased Power and Transmission:Purchased power and transmission expenses, including purchases from qualifying facilities under PURPA, were as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2007		2006		2007		2006
Other purchased power and transmission	$	10.8	$	8.2	$	28.4	$	26.6
From PURPA generation		14.8		—		48.8		—

Total purchased power and transmission	$	25.6	$	8.2	$	77.2	$	26.6

Purchased power and transmission expenses increased $17.4 million for the three months ended September 30, 2007 compared to the three months ended September 30, 2006, primarily due to a $14.8 million increase in purchased power from PURPA as a result of a January 1, 2007 transfer of Monongahela’s PURPA contracts from the Delivery and Services segment to the Generation and Marketing segment.

Purchased power and transmission expenses increased $50.6 million for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006, primarily due to a $48.8 million increase in purchased power from PURPA as a result of a January 1, 2007 transfer of Monongahela’s PURPA contracts from the Delivery and Services segment to the Generation and Marketing segment.

Gain on Sale of OVEC Power Agreement and Shares:On December 31, 2004, AE sold a 9% equity interest in the OVEC to Buckeye Power Generating, LLC. The gains on sale of OVEC power agreement and shares were $6.1 million for the nine months ended September 30, 2006, and represent the release of proceeds due to the fulfillment of certain post-closing commitments.

Expanded Net Energy Cost (“ENEC”)

The May 22, 2007 West Virginia Rate Order re-established an annual ENEC method of recovering net power supply costs, including fuel costs, purchased power costs and other related expenses, net of related revenue. Under the ENEC, actual costs and revenues will be tracked for under and/or over recoveries, and new ENEC rate filings will be made on an annual basis. Any under and/or over recovery of costs, net of related revenues, will be deferred, for subsequent recovery or refund via a customer surcharge, as a regulatory asset or regulatory liability with the corresponding impact on the Consolidated Statements of Operations reflected within “Deferred energy costs, net.” See the “Regulatory Matters” section of MD&A below and Note 8, “Rates and Regulation,” for additional information.

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Grant Town PURPA generation facility

Monongahela acquires energy from the Grant Town PURPA generation facility in West Virginia. The West Virginia PSC approved an amendment to the Electric Energy Purchase Agreement between Monongahela and American Bituminous Power Partners, L.P., the owners of the Grant Town PURPA generation facility, in April 2006. The amendment provided for an increase in the price of energy that Monongahela is acquiring until 2017. The West Virginia PSC authorized Monongahela to institute a temporary surcharge designed to recover the increase in costs from West Virginia customers, as well as a deferred accounting mechanism by which actual aggregate amounts of the incremental cost increase were tracked and reconciled by comparison to the aggregate amounts recovered from West Virginia customers through the temporary surcharge. As a result of the West Virginia Rate Order, the increase in costs discussed above are included in the ENEC. See the “Regulatory Matters” section of MD&A below and Note 8, “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)	2007		2006		2007			2006
Deferred energy costs, net	$	1.3	$	—	$	(5.6	)	$	—

The $1.3 million change in deferred energy costs, net for the three months ended September 30, 2007 compared to the three months ended September 30, 2006 and the $5.6 million change in deferred energy costs, net for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006 primarily related to the implementation of the ENEC.


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2007		2006		2007		2006
Operations and maintenance	$	71.3	$	68.2	$	256.8	$	248.6

Operations and maintenance expenses increased $3.1 million for the three months ended September 30, 2007 compared to the three months ended September 30, 2006, primarily due to:

	•		an $8.1 million reduction in estimated site remediation costs associated with a previously terminated generation project, which did not recur during 2007 and

	•		a $0.9 million increase in special maintenance expense due to the timing of maintenance outages,

	•		partially offset by a $6.5 million reduction in estimated site remediation costs associated with an ash disposal site.

Operations and maintenance expenses increased $8.2 million for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006, primarily due to:

	•		a $6.4 million reversal of a guarantee liability during the first quarter of 2006 associated with the Hunlock Creek Energy Ventures partnership, which did not recur during 2007 and

	•		an $8.1 million reduction in estimated site remediation costs associated with a previously terminated generation project during the third quarter of 2006, which did not recur during 2007,

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

•

partially offset by a $6.5 million reduction in estimated site remediation costs associated with an ash disposal site.

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2007		2006		2007		2006
Depreciation and amortization	$	26.3	$	30.6	$	87.7	$	91.0

Depreciation and amortization expenses decreased $4.3 million and $3.3 million for the three and nine months ended September 30, 2007, respectively, compared to the three and nine months ended September 30, 2006, primarily due to the West Virginia Rate Order, which extended the depreciable lives of regulated generating 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 West Virginia business and occupation taxes, 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)	2007		2006		2007		2006
Taxes other than income taxes	$	19.7	$	20.2	$	58.8	$	60.9

Taxes other than income taxes decreased $2.1 million for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006, primarily due to a $1.4 million decrease in capital stock and franchise taxes due to a favorable audit settlement during the second quarter of 2007.

Other Income and Expenses, Net

Other income and expenses, net were as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2007		2006		2007		2006
Other income and expenses, net	$	13.6	$	3.4	$	21.8	$	11.5

Other income and expenses, net, increased $10.2 million and $10.3 million for the three and nine months ended September 30, 2007, respectively, compared to the three and nine months ended September 30, 2006, primarily due to an $8.4 million gain relating to an exchange transaction involving La Paz, Arizona real estate during the third quarter of 2007.

Interest Expense and Preferred Dividends

Interest expense and preferred dividends were as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2007		2006		2007		2006
Interest expense and preferred dividends	$	43.3	$	47.0	$	131.6	$	150.6

Interest expense and preferred dividends decreased $3.7 million and $19.0 million for the three and nine months ended September 30, 2007, respectively, compared to the three and nine months ended September 30, 2006, primarily due to lower average debt outstanding, increased capitalization of interest and the discontinuance of interest expense related to the Merrill Lynch litigation as a result of a favorable appellate court ruling (See Note 19, “Commitments and Contingencies,” for additional information regarding this litigation). These increases were

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF 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, 2007 was 36.0% and was higher than the federal statutory tax rate of 35%, primarily due to state income taxes, which accounted for an increase of approximately 3.0%, partially offset by an additional benefit for Pennsylvania net operating losses recorded in the third quarter of 2007, which accounted for a reduction of approximately 2.0%.

The effective tax rate for the three months ended September 30, 2006 was 21.8% and was lower than the federal statutory tax rate of 35% primarily due to Pennsylvania net operating loss benefits recorded as a result of a change in a Pennsylvania tax law.

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 accounted for an increase of approximately 3.3%, partially offset by an additional benefit for Pennsylvania net operating losses recorded in the third quarter, which accounted for a reduction of approximately 1.3%.

The effective tax rate for the nine months ended September 30, 2006 was 30.0% and was lower than the federal statutory tax rate of 35%, primarily due to Pennsylvania net operating loss benefits recorded as a result of a change in a Pennsylvania tax law.

Minority Interest

Minority interest, which primarily represents equity interest in AE Supply, was $1.4 million and $1.0 million for the three months ended September 30, 2007 and 2006, respectively, and $2.4 million for the nine months ended September 30, 2007 and 2006.

Discontinued Operations

Losses from discontinued operations of $0.5 million and $2.2 million for the three and nine months ended September 30, 2006, respectively, relate to assets associated with AE Supply’s Gleason generation facility, which were sold during 2006.

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
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FINANCIAL CONDITION, REQUIREMENTS AND RESOURCES

Liquidity and Capital Requirements

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

Both Allegheny and AE Supply manage short-term obligations with cash on hand and amounts available under revolving credit facilities. AE and AE Supply manage excess cash through Allegheny’s internal money pool, and Monongahela, Potomac Edison and West Penn manage both excess cash and short-term obligations through the 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.

In September 2007, AE Supply amended its credit facility to increase the size of its revolving credit facility from $200 million to $400 million.

At September 30, 2007, Allegheny’s total borrowing capacity under AE and AE Supply’s revolving credit facilities and the use of this borrowing capacity were as follows:


	Total				LOC’s			Available
(In millions)	Capacity		Borrowed		Issued			Capacity
AE Revolving Credit Facility	$	400.0	$	—	$	6.7	(a)	$	393.3
AE Supply Revolving Facility		400.0		—		—			400.0

Total	$	800.0	$	—	$	6.7		$	793.3


(a)		This amount represents a letter of credit issued in connection with a contractual obligation of Allegheny Ventures that expires in July 2008. AE Supply also has a $2.5 million letter of credit outstanding that expires in February 2008 that was not issued under either AE’s revolving credit facility or AE Supply’s revolving credit facility.

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

Allegheny’s consolidated capital structure, excluding minority interest, as of September 30, 2007 and December 31, 2006, was as follows:


	September 30, 2007				December 31, 2006
(In millions)	Amount				Amount
Debt	$	3,957.7	62.0	%	$	3,585.2	63.0	%
Common equity		2,420.8	38.0	%		2,080.4	36.6	%
Preferred equity (a)		—	—	%		24.0	0.4	%

Total	$	6,378.5	100.0	%	$	5,689.6	100.0	%


(a)		On September 4, 2007, Monongahela redeemed all of the shares of its Cumulative Preferred Stock. See Note 7, “Preferred Stock Redemption” for additional information.

Long-Term Debt and Contractual Obligations

In April 2007, MP Environmental Funding LLC, an indirect subsidiary of Monongahela, and PE Environmental Funding LLC, an indirect subsidiary of Potomac Edison, issued $344 million and $115 million, respectively, of Senior Secured Sinking Fund Environmental Control Bonds, Series A. These bonds securitize the right to collect an environmental control surcharge that Monongahela and Potomac Edison impose on their retail customers in West Virginia. The bonds were issued in several tranches with interest rates ranging from 4.98% to 5.52% and maturities ranging from July 2014 to July 2027. Net proceeds from the sale of the bonds are non-current restricted funds and will be used to fund the majority of costs to construct and install Scrubbers at Fort Martin.

See Note 6, “Debt,” for additional information and details regarding Allegheny’s debt. See also Item 8, Note 4, “Capitalization,” in the 2006 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 2006 Annual Report on Form 10-K for additional information.

Off-Balance Sheet Arrangements

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

Other Matters Concerning Liquidity and Capital Requirements

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

244 miles of 765-kV transmission line from AEP’s substation near St. Albans, West Virginia to Allegheny’s Bedington substation near Martinsburg, West Virginia, and will also include approximately 46 miles of twin-circuit 500-kV lines from Bedington to a new substation to be built and owned by Allegheny near Kemptown, Maryland.

Total project costs of PATH are expected be approximately $1.8 billion. Allegheny’s share of the estimated costs is expected to be approximately $1.2 billion. Project siting land acquisition and approvals are expected to take place during the remainder of 2007 and throughout 2008 with construction of PATH expected to begin in 2009. PJM, the regional transmission organization, has specified June 2012 as the in-service date for the project.

On January 1, 2007, Allegheny adopted the provisions of FIN 48, which prescribes a comprehensive model for how companies should recognize, measure, present and disclose in their financial statements uncertain tax positions taken or expected to be taken on an income tax return. As a result of the implementation, Allegheny recognized additional liabilities related to its uncertain tax positions. See Note 5, Income Taxes, for additional information.

See Part I, Item 1, “Business,” and Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in the 2006 Annual Report on Form 10-K for information concerning expenditures other than those related to PATH.

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)	2007			2006
Net income	$	301.8		$	254.7
Loss from discontinued operations, net of tax		—			2.2
Non-cash items included in earnings		431.9			347.7
Pension and other postretirement employee benefit contributions		(46.5	)		(75.2	)
Changes in certain assets and liabilities		29.0			89.7
Net cash used in operating activities of discontinued operations		—			(3.4	)

Net cash provided by operating activities	$	716.2		$	615.7

Cash flows provided by operating activities for the nine months ended September 30, 2007 were $716.2 million, primarily as a result of net income of $301.8 million and non-cash charges of $431.9 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 $29.0 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 $29.0 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.

Cash flows provided by operating activities for the nine months ended September 30, 2006 were $615.7 million, primarily as a result of net income of $254.7 million, and non-cash charges of $347.7 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 $204.3 million and deferred income taxes of $109.5 million. In addition, cash flows of $89.7 million were provided as a result of changes in certain assets and liabilities, consisting primarily of a reduction in collateral deposits of $127.4 million due primarily to reduced collateral

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

requirements, and accrued interest of $20.7 million from the timing of cash payments. These amounts were partially offset by changes in receivables and payables of $72.5 million resulting from normal working capital activity. Cash flows provided by operating activities were also partially offset by contributions made to pension and other postretirement employee benefit plans of $75.2 million.

Investing Activities

Cash flows from investing activities are summarized as follows:


	Nine Months Ended
	September 30,
(In millions)	2007			2006
Capital expenditures	$	(590.3	)	$	(310.6	)
Proceeds from sale of assets		1.8			2.3
Purchase of minority interest in Hunlock Creek Energy Ventures		—			(13.9	)
Increase in restricted funds		(388.5	)		(140.2	)
Other investments		(4.0	)		(4.2	)
Net cash provided by investing activities of discontinued operations		—			27.8

Net cash used in investing activities	$	(981.0	)	$	(438.8	)

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.

Cash flows used in investing activities for the nine months ended September 30, 2006 were $438.8 million and primarily consisted of $310.6 million of capital expenditures, a $140.2 million increase in restricted funds due to net proceeds from Monongahela’s 5.70% First Mortgage Bond issuance and $13.9 million for the purchase of the minority interest in Hunlock Creek Energy Ventures, partially offset by the receipt of $27.8 million in proceeds from the sale of a receivable from the Tennessee Valley Authority.

Financing Activities

Cash flows from financing activities are summarized as follows:


	Nine Months Ended
	September 30,
(In millions)	2007			2006
Issuance of long-term debt	$	450.6		$	1,433.1
Repayment of long-term debt		(92.0	)		(1,644.3	)
Redemption of preferred stock of subsidiary		(25.1	)		—
Proceeds from the exercise of stock options		10.3			22.1
Cash dividends paid to minority shareholder in Hunlock Creek Energy Ventures		—			(0.4	)

Net cash provided by (used in) financing activities	$	343.8		$	(189.5	)

Cash flows provided by financing activities for the nine months ended September 30, 2007 were $343.8 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.

Cash flows used in financing activities for the nine months ended September 30, 2006 were $189.5 million and consisted primarily of $1,644.3 million related to payments on and retirement of long-term debt, partially offset by $1,433.1 million in

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

proceeds from the issuance of long-term debt and $22.1 million in cash proceeds received from employees for the exercise of stock options.

Credit Ratings

The following table lists Allegheny’s credit ratings, as of November 6, 2007:

Moody’s

S & P

Fitch

AE:

Outlook

Stable

Positive

Corporate Credit Rating

Not Rated

BBB-

Not Rated

Senior Unsecured Debt

Ba1

BB+

Short-term Rating

Not Rated

A-3

Not Rated

AE Supply:

Outlook

Stable

Positive

Senior Secured Debt

Baa2

BBB

BBB-

Senior Unsecured Debt

Ba1

BB+

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

Positive

Senior Unsecured Debt

Baa3

BBB-

BB+

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 2006 Annual Report on Form 10-K. See also Note 6 “Debt” in Allegheny’s Notes to Consolidated Financial Statements, included herein, regarding the accounting for the Fort Martin Scrubber project. Allegheny’s critical accounting policies have not changed materially from those reported in the 2006 Annual Report on Form 10-K.

Recent Accounting Pronouncements

See Note 3, “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 2007 that relate to Allegheny’s operations.

REGULATORY MATTERS

Federal Legislation, Regulation and Rate Matters

Transmission Rate Design.Actions by the Federal Energy Regulatory Commission (“FERC”) 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 $5.2 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 three 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 in Docket No. EL05-121-000 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. An initial decision was issued on July 13, 2006 by an administrative law judge, 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 Allegheny 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 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 the customer will pay the rates applicable in the transmission zone where the transaction sinks. The filing was required by the FERC November 2004 order rejecting long-term regional rate proposals discussed above. Several parties filed protests of the proposal. The proposal remains subject to FERC approval.

On September 17, 2007, American Electric Power Corporation (“AEP”) filed a complaint with FERC against MISO and PJM alleging the rate designs underlying their open access transmission tariffs are unjust, unreasonable and unduly discriminatory and therefore must be revised. AEP requested FERC to establish a refund-effective date of October 1, 2007 with respect to revisions alleged to be required. The Distribution Companies have intervened in this proceeding.

Wholesale Markets.In August 2005, PJM filed at FERC to replace its capacity market with a new Reliability Pricing Model (“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 participated 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 will be met either through purchases made in the proposed auctions or though commitments by load serving entities 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 this year, and additional auctions are expected to be conducted in January and May 2008. On June 25, 2007, FERC issued an order denying pending rehearing request of the December 22, 2006 order and affirming its acceptance of the RPM settlement agreement. On July 25, 2007, a coalition of PJM industrial customers and the office of the peoples’ counsel of Maryland and the District of Columbia filed a joint rehearing request challenging FERC’s finding that PJM’s new capacity markets are just and reasonable. This rehearing request is pending before FERC. In August 2007, FERC’s orders approving the RPM settlement were appealed to the federal appeals courts by several parties. These appeals are currently pending at the United States Court of Appeals for the District of Columbia Circuit and the United States Court of Appeals for the Third Circuit.

On July 3, 2006, PJM filed at FERC a proposal to implement a process for allocating long-term transmission rights (“LTTRs”). The PJM proposal would allocate a ten-year financial transmission right to PJM load serving entities (“LSEs”) based on the LSEs’ 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. Requests for rehearing of the May 17th order were denied by FERC in an order issued on October 22, 2007. FERC has 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. AE Supply and the Distribution Companies are participating in this stakeholder process.

Transmission Expansion.In June 2006, the PJM Board of Managers approved a Regional Transmission Expansion Plan (“RTEP”) that directed the Distribution Companies and Virginia Electric and Power Company to cause the construction of a 240-mile 500 kV transmission line project from southwestern Pennsylvania through northern West Virginia and into northern Virginia to address potential electric reliability issues caused by increased customer load in the mid-Atlantic area that could have adverse effects within the service territories of the Distribution Companies. Approximately 210 miles of the project is located in the Distribution Companies’ PJM zone. In October 2006, Allegheny formed TrAIL Company as the entity responsible for financing, constructing, owning, operating and maintaining this project, which has been named “Trans-Allegheny Interstate Line” and is referred to as “TrAIL.” The project includes the construction of approximately 51 miles of 500 kV and 138 kV lines in southwestern Pennsylvania to address electric reliability issues in that area.

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 includes the incentive rate treatments approved by FERC. On May 31, 2007, FERC issued an order permitting the formula tariff rate to become effective on June 1, 2007 subject to refund and hearing on specifically identified issues. One of the issues set for hearing is the level of the incentive return on equity for TrAIL. The hearing in this matter is scheduled to commence in April 2008.

On June 22, 2007, the PJM Board of Managers authorized the construction of a 290-mile, high-voltage transmission line, named the Potomac-Appalachian Transmission Highline or PATH. The project will include approximately 244 miles of 765-kV transmission line from AEP’s substation near St. Albans, West Virginia to Allegheny’s Bedington substation near Martinsburg, West Virginia, and will also include approximately 46 miles of twin-circuit 500-kV lines from Bedington to a new substation to be built and owned by Allegheny near Kemptown, Maryland. On September 1, 2007 Allegheny entered into an agreement with a subsidiary of AEP to build PATH. Total project costs are expected to be approximately $1.8 billion. Allegheny’s share of the estimated costs is expected to be approximately $1.2 billion.

On August 8, 2006, the United States Department of Energy (the “DOE”) published a congestion study in which the general area of the TrAIL Project was classified as a “critical congestion area” that merits further federal attention. On October 2, 2007, the DOE issued a National Interest Electric Transmission Corridor designation for the Mid-Atlantic corridor that includes the areas where TrAIL and PATH are proposed to be sited. Several requests for rehearing of the DOE’s October 2, 2007 designation have been filed and are pending before the DOE.

State Legislation, Regulation and Rate Matters

Pennsylvania

Transmission Expansion.On April 13, 2007, TrAIL Company filed an application with the Pennsylvania PUC for authorization to construct the TrAIL project in Pennsylvania. TrAIL Company is currently responding to discovery with regard to its application. An evidentiary hearing on this matter is scheduled to begin on January 23, 2008. Issuance of an order in this matter is expected by June 2008.

Default Service Regulations.On May 10, 2007, the Pennsylvania PUC entered a Final Rulemaking Order promulgating regulations defining the obligations of electric distribution companies (“EDCs”) to provide generation default service to retail electric customers at the conclusion of the EDCs’ restructuring transition periods. West Penn’s transition period will end December 31, 2010, when its generation rate caps expire and its stranded cost recovery concludes. The new regulations govern the EDCs’ obligation to provide default generation service to retail customers who do not or cannot choose service from a licensed electric generation supplier (“EGS”).

The regulations 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 must 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 shall 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.

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. TrAIL Company is currently responding to discovery with regard to its application. An evidentiary hearing on this matter is scheduled to begin on January 9, 2008. Issuance of an order in this matter is expected by May 2, 2008.

Rate Case.On July 26, 2006, Monongahela and Potomac Edison filed with the West Virginia PSC a request to raise their West Virginia retail rates by approximately $100 million annually, effective on August 25, 2006. The request included a $126 million increase in rates related to fuel and purchased power costs, including reinstatement of a fuel cost recovery clause, adjustable annually, to reflect upward or downward changes in the cost of fuel and purchased power, and a $26 million decrease in base rates. On May 22, 2007, the West Virginia PSC issued a final order directing Monongahela and Potomac Edison to reduce overall rates by approximately $6 million effective May 23, 2007, by increasing fuel and purchased power cost-related rates by $126 million and reducing base rates by approximately $132 million, which includes changes in authorized depreciation rates that will reduce 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 responding to the Petition for Reconsideration.

Maryland

Rate Stabilization and Standard Offer Service.In special session, the Maryland legislature passed emergency legislation on June 23, 2006, directing the Maryland Public Service Commission (the “Maryland PSC”), to among other things investigate options available to Allegheny to implement a rate mitigation or rate stabilization plan for Standard Offer Service (“SOS”) to protect its residential customers from rate shock when capped rates end on January 1, 2009.

On December 29, 2006, Allegheny filed with the Maryland PSC a proposed Rate Stabilization Ramp-Up Transition Plan designed to transition residential customers from capped generation rates to rates based on market prices. Under the plan as approved by the Maryland PSC on March 30, 2007, residential customers who did not elect to opt out of the program began paying a distribution surcharge in June 2007. The application of the surcharge will result in an overall rate increase of approximately 15% annually from 2007 through 2010. With the expiration of the residential generation rate caps and the move to generation rates based on market prices on January 1, 2009, the surcharge would convert to a credit on customers’ bills. Funds collected through the surcharge during 2007 and 2008, plus interest, would be returned to customers as a credit on their electric bills, thereby reducing the effect of the rate cap expiration. The credit would continue, with adjustments, to maintain rate stability until December 31, 2010 or until all monies collected from customers plus interest are returned. Of Allegheny’s more than 216,000 residential customers in Maryland, approximately 7,400, or 3.5%, elected to opt-out of Allegheny’s plan.

The Maryland PSC opened a new docket in August 2007 (Case No. 9117) to consider matters relating to possible “managed portfolio” approaches to SOS, the aggregation of low income SOS customers, and a retail supplier proposal for the utility “purchase” of all retailer receivables at no discount and with no recourse. Testimony was filed on September 14 and September 28, and hearings were held on October 3 through October 5 and October 9, 2007, and were continued into November. On September 25, 2007, the Maryland PSC opened a “Phase II” of Case 9117, and required the utilities to file testimony by October 12 on utility purchases or construction of generation, bidding for procurement of DSM resources and possible alternatives if the TrAIL and PATH projects are delayed or defeated. Hearings on Phase II are scheduled for November 5 and November 6, 2007.

Allegheny developed a plan for seeking bids to serve its Maryland residential load for the period after the rate cap expires on December 31, 2008. Allegheny filed the proposal with the Maryland PSC on August 3, 2007. On September 12, 2007, the Maryland PSC directed Allegheny to proceed with an initial partial procurement in October 2007, but to file a modified plan for the rest of the procurement after the resolution of Case No. 9117.

Advanced Metering and Demand Side Management Initiatives. On June 8, 2007, the Maryland PSC established Case No. 9111 to consider the following four items: 1) technical standards for, and operational capabilities of, advanced meters; 2) the extent to which demand side management programs are to be offered in Maryland on a competitively-neutral basis; 3) recovery of costs of demand side management programs; and 4) the appropriate measure(s) of cost effectiveness of demand side management programs to be employed in Maryland. The staff of the Maryland PSC filed its report on these matters on July 6, 2007. Allegheny filed on September 14, 2007 for approval of a fast track residential compact fluorescent light and education campaign, plus recovery of the $2.5 million cost over one year through a special surcharge on customers’ distribution bills. The Maryland PSC approved the program on September 26, 2007. On September 28, 2007, the Maryland PSC issued an order in Case No. 9111 that required the utilities to file detailed plans for how they will meet a proposal that electric demand in Maryland be reduced by 15% by 2015. On October 26, 2007, Allegheny filed its initial report on energy efficiency, conservation and demand reduction plans in connection with this order.

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. An evidentiary hearing in this matter is scheduled to commence on February 25, 2008. Issuance of an order in this matter is expected by July 2008.

Purchased Power Filing.During the 2007 session, the Virginia General Assembly amended the Virginia Electric Utility Restructuring Act of 1999 (the “Restructuring Act”), to re-regulate the provision of electric generation services in the Commonwealth beginning January 1, 2009. Until that time, Potomac Edison’s retail electric customers in Virginia have the right to choose their electricity generation supplier. Until December 31, 2008, Potomac Edison is the PLR for those customers who do not choose an alternate generation supplier or whose alternate generation supplier does not deliver. After January 1, 2009, Potomac Edison will provide generation services to all customers in Virginia at regulated rates. Potomac Edison had a power purchase agreement with AE Supply to provide it with the amount of electricity necessary to meet its PLR retail obligations through June 30, 2007 at capped generation rates. In April 2007, Potomac Edison conducted a competitive bidding process to purchase its PLR requirements from the wholesale market and AE Supply was the successful bidder with respect to a substantial portion of these requirements. On July 1, 2007 Potomac Edison began to purchase its PLR requirements at market prices. Market prices for purchased power resulting from that bidding process are higher than the rates Potomac Edison is currently allowed to recover from its retail customers.

Accordingly, on April 12, 2007, Potomac Edison filed an Application with the Virginia SCC to establish a fuel factor and increase retail rates on average by 49.1% on July 1, 2007 to recover Potomac Edison’s estimated costs for purchased power to serve the Virginia retail load. In the Application, Potomac Edison also proposed a transition plan that would limit the average increase on July 1, 2007 to 20% and defer, with interest, amounts above 20% for collection over the subsequent three years. Allegheny argued that, based on amendments to the Restructuring Act in 2001 and 2004, the generation rates that Potomac Edison will be able to charge its Virginia customers beginning on July 1, 2007, will be based on its cost of purchased power.

On June 28, 2007, the Virginia SCC issued an order Denying the Application and rejecting Potomac Edison’s request to recover its purchased power expenses effective July 1, 2007, denying Potomac Edison’s Motion for Interim Rates and dismissing 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. Potomac Edison filed an appeal with the Virginia Supreme Court on July 26, 2007 and also asked the Virginia Supreme Court for relief pending appeal. The Court denied Allegheny’s motions and set the matter for review in the ordinary course. Allegheny then filed at the Virginia SCC a new application for rate recovery of costs for load above 367 MW on September 11, 2007, and is continuing to pursue its appeal for full cost recovery. On October 10, 2007, the Virginia SCC issued an order setting Allegheny’s new application for hearing on December 4, 2007.

At this time, there can be no assurance that Potomac Edison will be able to recover any of the cost of power purchases in excess of the capped generation rates that it is currently permitted to charge its Virginia customers. The inability to recover such costs is expected to have a significantly negative effect on Potomac Edison’s income and cash flows from its Virginia operations, which in turn may have an adverse effect on its overall business, results of operations and financial condition. Potomac Edison’s management is currently reevaluating planned capital and other expenditures and may postpone or eliminate all or a portion of those expenditures or take other measures in response to the expected negative impact of these regulatory decisions.

Potomac Edison’s T&D rates in Virginia are presently capped through 2008, subject to certain exceptions. Prior to 2010, Potomac Edison has one opportunity to petition the Virginia SCC for changes to its T&D rate after July 1, 2007. Furthermore, the Restructuring Act requires the Virginia SCC to adjust Potomac Edison’s capped T&D rates not more than once annually for the timely recovery of costs prudently incurred after July 1, 2004 for T&D system reliability or to comply with state or federal environmental laws or regulations. During the first six months of 2009, the Commission will initiate a proceeding to review the rates, terms and conditions for Potomac Edison’s provision of generation, distribution and transmission services in the Commonwealth.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Allegheny’s primary market risk exposures are associated with interest rates and commodity prices. Allegheny has risk management policies to monitor and assist in controlling these market risks and uses derivative instruments to manage some of the exposures.

A summary of Allegheny’s market risks is included under Item 7A, Quantitative and Qualitative Disclosures About Market Risk, of the 2006 Annual Report on Form 10-K. Allegheny’s market risks have not changed materially from those reported in the 2006 Annual Report on Form 10-K.

As reported in the 2006 Annual Report on Form 10-K, Allegheny uses various methods to measure their exposure to market risk on a daily basis, including a value at risk model (“VaR”). Allegheny calculates VaR using the full term of all portfolio positions being marked-to-market. This calculation is based upon management’s best estimates and modeling assumptions, which could materially differ from actual results. As of September 28, 2007 and December 29, 2006, this calculation yielded a VaR of $1.15 million and $0.01 million, respectively. This VaR increase is due to forward settling emissions transactions entered into during the third quarter of 2007.

ITEM 4. CONTROLS AND PROCEDURES

See, Item 9a, “Controls and Procedures,” in the 2006 Annual Report on Form 10-K for additional information relating to Controls and Procedures.

Disclosure Controls and Procedures.AE carried out an evaluation, under the supervision and with the participation of its management, including its principal executive officer and principal financial officer, of the effectiveness of its disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, as of the end of the period covered by this report (the “Evaluation Date”). Based on that evaluation, the principal executive officer and principal financial officer of each registrant have concluded that the applicable registrant’s disclosure controls and procedures as of the Evaluation Date were effective to ensure that material information relating to each registrant (a) is accumulated and made known to the registrant’s management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure and (b) is recorded, processed, summarized and reported within the time periods specified in SEC’s rules and forms.

Changes in Internal Control Over Financial Reporting. Effective May 1, 2007, AE implemented new energy trading software, including new trade capture, validation and valuation, settlement, credit and accounting tools, to support its existing energy trading activities. The introduction of the new system resulted in changes to AE’s financial reporting controls and procedures, with such changes identified during the implementation of the new energy trading system. Therefore, as appropriate, AE is modifying the design and documentation of internal control process and procedures relating to the new system to supplement and complement existing internal controls over financial reporting. The system changes were undertaken to integrate systems and consolidate information, and were not undertaken in response to any actual or perceived deficiencies in AE’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time, Allegheny is involved in litigation and other legal disputes in the ordinary course of business. See Note 19, “Commitments and Contingencies” to the Consolidated Financial Statements of AE for information regarding legal proceedings.

ITEM 1A. RISK FACTORS

Except for the risk factors set forth below, there have been no material changes to the risk factors disclosed in Item 1A of Part 1 of the 2006 Annual Report on Form 10-K. The risk factors set forth below were disclosed in the 2006 Annual Report on Form 10-K and have been updated to provide additional information.

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

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

Virginia

Potomac Edison’s Virginia generation rates were originally capped until July 1, 2007, but this cap was extended by legislation until December 31, 2010. Potomac Edison had a power purchase agreement with AE Supply to provide Potomac Edison with the amount of electricity necessary to meet its Virginia PLR retail obligations until July 1, 2007 at capped generation rates. In April 2007, Potomac Edison conducted a competitive bidding process to purchase its PLR requirements from the wholesale market, and AE Supply was the successful bidder with respect to a substantial portion of those requirements. On July 1, 2007, Potomac Edison began to purchase those requirements at market prices. Market prices for purchased power are, and likely will continue to be, significantly higher than the rates Potomac Edison is currently allowed to recover from its retail customers.

On June 28, 2007, the Virginia SCC issued an Order Denying the Application and rejecting Potomac Edison’s request to recover its purchased power expenses effective July 1, 2007, denying Allegheny’s Motion for Interim Rates and dismissing 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. Potomac Edison filed an appeal with the Virginia Supreme Court on July 26, 2007 and also asked the Virginia Supreme Court for relief pending appeal. The Court denied Allegheny’s motions for expedited relief and set the matter for review in the ordinary course. Allegheny then filed at the Virginia SCC a new application for rate recovery of purchased power costs for load above 367 MW on September 11, 2007, and is continuing to pursue its appeal for full cost recovery. On October 10, 2007, the Virginia SCC issued an order setting Allegheny’s new application for hearing on December 4, 2007.

all or a portion of those expenditures or take other measures in response to the expected negative impact of these regulatory decisions.

West Virginia

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

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

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

The TrAIL Project and the PATH Project are subject to permitting and state regulatory approvals.

The construction of both the TrAIL Project and the PATH Project are subject to the prior approval of various state regulatory bodies. The inability to obtain any such state approval or other regulatory approval may have an adverse affect on Allegheny’s business, results of operations, cash flows and financial condition. See “Regulatory Matters” above.

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 and timely complete these projects 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 project, 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. Should this occur, Allegheny may be forced to find alternate arrangements, which may cause delay and/or increased costs. Furthermore, Allegheny can provide no assurance that it would be able to make such alternate arrangements on terms acceptable to it or at all.

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.

ITEM 6. EXHIBITS

EXHIBIT INDEX


		Documents
10.1*		Limited Liability Company Agreement of Potomac-Appalachian Transmission Highline, LLC, dated as of September 1, 2007

10.2		Amended and Restated Non-Employee Director Stock Plan

10.3		Amended and Restated Restricted Stock Plan for Outside Directors

10.4		Amended and Restated Revised Plan for Deferral of Compensation of Directors

10.5		Amended and Restated 1998 Long-term Incentive Plan

10.6		Amended and Restated Stock Unit Plan

10.7		Amended and Restated Annual Incentive Plan

10.8		Amended and Restated Supplemental Executive Retirement Plan

10.9		Amended and Restated Nonqualified Deferred Compensation Plan

10.10		Amendment to Employment Agreement of Senior Vice President and Chief Financial Officer

10.11		Amendment to Employment Agreement of Vice President

10.12		Amendment to Change in Control Agreement of Vice President and General Counsel

10.13		Amendment to Change in Control Agreement of Vice President

10.14		Amendment to Change in Control Agreement of Vice President and Controller

10.15		Amendment to Severance Agreement of Vice President and General Counsel

10.16		Amendment to Severance Agreement of Vice President

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


*		Confidential treatment has been requested from the Commission for portions of this document.

SIGNATURE

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


		ALLEGHENY ENERGY, INC.

Date: November 6, 2007	By:	/s/ Philip L. Goulding
		Philip L. Goulding
		Senior Vice President and
		Chief Financial Officer

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Allegheny Energy (AYE) Inactive 10-Q2007 Q3 Quarterly report

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