Allegheny Generating 10Q 2006 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 quarterly period ended September 30, 2006


	Name of Registrant
	State of Incorporation
	Address of Principal	IRS Employer
Commission	Executive	Identification
File Number	Offices and Telephone Number	Number

1-267	ALLEGHENY ENERGY, INC.	13-5531602
	(A Maryland Corporation)
	800 Cabin Hill Drive
	Greensburg, Pennsylvania 15601
	Telephone (724) 837-3000

1-5164	MONONGAHELA POWER COMPANY	13-5229392
	(An Ohio Corporation)
	1310 Fairmont Avenue
	Fairmont, West Virginia 26554
	Telephone (304) 366-3000

0-14688	ALLEGHENY	13-3079675
	GENERATING COMPANY
	(A Virginia Corporation)
	800 Cabin Hill Drive
	Greensburg, Pennsylvania 15601
	Telephone (724) 837-3000

This combined Form 10-Q is separately filed by Allegheny Energy, Inc., Monongahela Power Company and Allegheny Generating Company. Information contained in the Form 10-Q relating to Monongahela Power Company and Allegheny Generating Company is filed by each such registrant on its own behalf. Each of Monongahela Power Company and Allegheny Generating Company makes no representation as to information relating to registrants other than itself.

Indicate by check mark whether the registrants (1) have 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 registrants were required to file such reports) and (2) have been subject to such filing requirements for the past 90 days. Yesþ Noo

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.


Allegheny Energy, Inc.	Yesþ	Noo
Monongahela Power Company	Yeso	Noþ
Allegheny Generating Company	Yeso	Noþ

Indicate by check mark whether the registrants (1) have 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 and (2) have 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 (as defined in Rule 12b-2 of the Act).


	Large accelerated filer	Accelerated filer	Non-accelerated filer
Allegheny Energy, Inc.	þ	o	o
Monongahela Power Company	o	o	þ
Allegheny Generating Company	o	o	þ

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


Allegheny Energy, Inc.	Yeso	Noþ
Monongahela Power Company	Yeso	Noþ
Allegheny Generating Company	Yeso	Noþ

Number of shares outstanding of each class of common stock as of October 31, 2006:


Allegheny Energy, Inc.	165,262,790	($1.25 par value)
Monongahela Power Company	5,891,000	($50.00 par value)
Allegheny Generating Company	1,000	($1.00 par value)

TABLE OF CONTENTS


	Page No.
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)
Allegheny Energy, Inc. and Subsidiaries		4
Monongahela Power Company and Subsidiaries		37
Allegheny Generating Company		53

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”)		61
Item 3. Quantitative and Qualitative Disclosures About Market Risk		100
Item 4. Controls and Procedures		100

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		101
Item 1A. Risk Factors		101
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		102
Item 3. Defaults Upon Senior Securities		102
Item 4. Submission of Matters to a Vote of Security Holders		102
Item 5. Other Information		102
Item 6. Exhibits		103
Signatures		106
EX-31.1
EX-31.2
EX-32.1
EX-32.2

GLOSSARY

I. 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 Solutions		Allegheny Energy Solutions, Inc., a subsidiary of Allegheny Ventures.
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		Collectively, Monongahela, Potomac Edison and West Penn. The Distribution Companies do business as “Allegheny Power.”
Monongahela		Monongahela Power Company, a regulated subsidiary of AE.
Mountaineer		Mountaineer Gas Company, a former subsidiary of Monongahela that was sold on September 30, 2005.
Potomac Edison		The Potomac Edison Company, a regulated 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)	2006			2005			2006			2005
Operating revenues	$	816,645		$	845,064		$	2,384,526		$	2,313,744

Operating expenses:
Fuel consumed in electric generation		223,810			211,428			623,202			551,454
Purchased power and transmission		101,972			124,111			298,301			337,176
Gain on sale of OVEC power agreement and shares		—			—			(6,124	)		—
Impairment charge on Ohio T&D assets		—			30,500			—			30,500
Deferred energy costs, net		(181	)		(4,181	)		5,225			(4,800	)
Operations and maintenance		157,809			182,095			525,543			545,678
Depreciation and amortization		68,308			76,724			204,319			230,493
Taxes other than income taxes		53,762			53,300			159,630			160,096

Total operating expenses		605,480			673,977			1,810,096			1,850,597

Operating income		211,165			171,087			574,430			463,147

Other income and expenses, net		7,841			7,294			25,770			33,781

Interest expense and preferred dividends:
Interest expense		66,073			111,803			209,886			365,874
Preferred dividends of subsidiary		293			1,259			879			3,778

Total interest expense and preferred dividends		66,366			113,062			210,765			369,652

Income from continuing operations before income taxes and minority interest		152,640			65,319			389,435			127,276

Income tax expense		40,883			21,428			130,128			54,619

Minority interest in net income of subsidiaries		1,011			433			2,380			900

Income from continuing operations		110,746			43,458			256,927			71,757

Loss from discontinued operations, net of tax (Note 6)		(539	)		(7,758	)		(2,203	)		(11,822	)

Net income	$	110,207		$	35,700		$	254,724		$	59,935


Common share data:
Weighted-average common shares outstanding
Basic		164,813			162,711			163,813			152,379
Diluted		168,629			166,784			168,587			166,017
Basic income (loss) per common share:
Income from continuing operations	$	0.67		$	0.27		$	1.56		$	0.47
Loss from discontinued operations		—			(0.05	)		(0.01	)		(0.08	)

Net income per common share	$	0.67		$	0.22		$	1.55		$	0.39

Diluted income (loss) per common share:
Income from continuing operations	$	0.65		$	0.26		$	1.52		$	0.45
Loss from discontinued operations		—			(0.05	)		(0.01	)		(0.07	)

Net income per common share	$	0.65		$	0.21		$	1.51		$	0.38

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)	2006			2005
	(Revised-Note 1)
Cash Flows From Operating Activities:
Net income	$	254,724		$	59,935
Loss from discontinued operations, net of tax		2,203			11,822

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		204,319			230,493
Amortization of debt issuance costs		20,504			19,728
Amortization of power sale liability related to Ohio sale		(22,700	)		—
Impairment charge on Ohio T&D assets		—			30,500
Amortization of liability for adverse power purchase commitment		(12,866	)		(12,545	)
Amortization of Pennsylvania stranded cost recovery asset		11,457			12,086
Gain on asset sales and disposals		(1,205	)		(2,238	)
Minority interest in net income of subsidiaries		2,379			900
Deferred income taxes and investment tax credit, net		109,524			(21,436	)
Stock-based compensation expense		10,988			8,552
Unrealized gains on commodity contracts, net		(26,831	)		(18,176	)
Pension and other postretirement employee benefit plan expense		31,419			36,146
Pension and other postretirement employee benefit plan contributions		(75,255	)		(80,297	)
Other, net		17,978			1,995

Changes in certain assets and liabilities:
Accounts receivable, net		50,770			(83,996	)
Materials, supplies and fuel		2,446			3,281
Prepaid taxes		(9,623	)		(8,971	)
Collateral deposits		127,350			(55,274	)
Prepayments		(2,553	)		2,243
Other current assets		2,601			2,170
Accounts payable		(123,299	)		29,719
Accrued taxes		20,146			61,984
Accrued interest		20,707			46,826
Other current liabilities		1,435			2,709
Other assets		2,753			6,558
Other liabilities		(293	)		(7,432	)
Net cash provided by (used in) operating activities of discontinued operations		(3,406	)		55,552

Net cash provided by operating activities		615,672			332,834

Cash Flows From Investing Activities:
Capital expenditures		(310,590	)		(204,387	)
Proceeds from asset sales		2,308			247,404
Purchase of minority interest in Hunlock Creek Energy Ventures		(13,900	)		—
Decrease (increase) in restricted funds		(140,247	)		205,969
Other investments		(4,181	)		(2,947	)
Net cash provided by (used in) investing activities of discontinued operations		27,795			(6,524	)

Net cash provided by (used in) investing activities		(438,815	)		239,515

Cash Flows From Financing Activities:
Issuance of long-term debt		1,433,115			1,782,361
Repayment of long-term debt		(1,644,261	)		(2,202,021	)
Payments on capital lease obligations		(45	)		—
Proceeds from exercise of employee stock options		22,110			1,892
Cash dividends paid to minority shareholder in Hunlock Creek Energy Ventures		(400	)		—
Net cash used in financing activities of discontinued operations		—			(11	)

Net cash used in financing activities		(189,481	)		(417,779	)

Net increase (decrease) in cash and cash equivalents		(12,624	)		154,570
Cash and cash equivalents at beginning of period		262,212			189,482

Cash and cash equivalents at end of period	$	249,588		$	344,052

Supplemental Cash Flow Information:
Cash paid for interest (net of amount capitalized)	$	170,879		$	322,379

See accompanying Notes to Consolidated Financial Statements.

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


	September 30,			December 31,
(In thousands)	2006			2005
ASSETS
Current Assets:
Cash and cash equivalents	$	249,588		$	262,212
Accounts receivable:
Customer		175,412			179,634
Unbilled utility revenue		85,460			129,111
Wholesale and other		66,856			82,261
Allowance for uncollectible accounts		(15,538	)		(16,778	)
Materials and supplies		95,069			98,069
Fuel		65,466			67,273
Deferred income taxes		42,308			93,404
Prepaid taxes		55,381			45,758
Assets held for sale (Note 6)		911			1,521
Collateral deposits		44,965			147,775
Commodity contracts		2,617			9,325
Restricted funds		161,836			21,589
Regulatory assets		38,023			38,418
Other		13,880			14,246

Total current assets		1,082,234			1,173,818


Property, Plant and Equipment, Net:
Generation		5,765,260			5,751,077
Transmission		1,048,050			1,028,323
Distribution		3,556,970			3,448,350
Other		398,902			429,108
Accumulated depreciation		(4,600,105	)		(4,508,707	)

Subtotal		6,169,077			6,148,151
Construction work in progress		242,646			129,277

Total property, plant and equipment, net		6,411,723			6,277,428


Investments and Other Assets:
Non-current assets held for sale (Note 6)		21,182			48,559
Goodwill		367,287			367,287
Investments in unconsolidated affiliates		28,081			28,555
Intangible assets		27,396			27,396
Other		27,633			49,413

Total investments and other assets		471,579			521,210


Deferred Charges:
Regulatory assets		513,750			544,810
Other		31,039			41,546

Total deferred charges		544,789			586,356

Total Assets	$	8,510,325		$	8,558,812

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)	2006			2005
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Long-term debt due within one year (Note 5)	$	494,212		$	477,217
Accounts payable		202,211			316,713
Accrued taxes		167,849			154,587
Commodity contracts		14,589			92,934
Accrued interest		112,140			91,433
Other		142,443			153,570

Total current liabilities		1,133,444			1,286,454


Long-term Debt (Note 5)		3,408,148			3,624,483

Deferred Credits and Other Liabilities:
Commodity contracts		17,773			22,994
Investment tax credit		72,666			76,965
Deferred income taxes		781,817			692,241
Obligations under capital leases		17,407			16,427
Regulatory liabilities		460,435			454,275
Adverse power purchase commitment		171,259			184,224
Other		407,820			459,465

Total deferred credits and other liabilities		1,929,177			1,906,591

Commitments and Contingencies (Note 20)

Minority Interest		10,531			21,989

Preferred Stock of Subsidiary		24,000			24,000

Common Stockholders’ Equity:
Common stock, $1.25 par value, 260 million shares authorized; 165,287,497 and 163,002,295 shares issued at September 30, 2006 and December 31, 2005, respectively		206,609			203,753
Other paid-in capital		1,902,896			1,880,644
Retained earnings (accumulated deficit)		10,101			(244,625	)
Treasury stock at cost; 49,493 shares		(1,756	)		(1,756	)
Accumulated other comprehensive loss		(112,825	)		(142,721	)

Total common stockholders’ equity		2,005,025			1,695,295

Total Liabilities and Stockholders’ Equity	$	8,510,325		$	8,558,812

See accompanying Notes to Consolidated Financial Statements.

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(unaudited)


														Accumulated
					Other			Retained						other			Total
	Shares		Common		paid-in			earnings			Treasury			comprehensive			stockholders’
(In thousands, except shares)	outstanding		stock		capital			(deficit)			stock			income (loss)			equity
Balance at January 1, 2006		162,952,802	$	203,753	$	1,880,644		$	(244,625	)	$	(1,756	)	$	(142,721	)	$	1,695,295
Net income		—		—		—			254,724			—			—			254,724
Stock compensation expense:
Stock units		—		—		4,262			—			—			—			4,262
Non-employee stock awards		3,000		3		885			—			—			—			888
Stock options		—		—		5,837			—			—			—			5,837
Exercise of stock options		1,132,534		1,416		20,695			—			—			—			22,111
Conversion of stock units		1,149,668		1,437		(10,234	)		—			—			—			(8,797	)
Settlement of performance share plan		—		—		807			—			—			—			807
Other		—		—		—			2			—			—			2
Other comprehensive income		—		—		—			—			—			29,896			29,896

Balance at September 30, 2006		165,238,004	$	206,609	$	1,902,896		$	10,101		$	(1,756	)	$	(112,825	)	$	2,005,025

See accompanying Notes to Consolidated Financial Statements.

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


Note No.		Page No.
1	Basis of Presentation		10

2	Recent Accounting Pronouncements		11

3	Stock-Based Compensation		12

4	Review of Estimated Remaining Service Lives and Depreciation Practices		16

5	Debt		17

6	Discontinued Operations and Assets Held for Sale		19

7	Derivative Instruments and Hedging Activities		20

8	Asset Retirement Obligations (“AROs”)		20

9	Business Segments		21

10	Goodwill and Intangible Assets		22

11	Comprehensive Income		22

12	Pension Benefits and Postretirement Benefits Other Than Pensions		23

13	Income (Loss) Per Share		26

14	Adverse Power Purchase Commitment Liability		27

15	Regulatory Assets and Liabilities		27

16	Other Income and Expenses, Net		28

17	Guarantees and Letters of Credit		29

18	Variable Interest Entities (“VIE”)		29

19	HCEV Partnership Interest		30

20	Commitments and Contingencies		30

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

NOTE 1: BASIS OF PRESENTATION

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”).

The Generation and Marketing segment primarily consists of Allegheny’s electric generation subsidiaries. These subsidiaries include Allegheny Energy Supply Company, LLC (“AE Supply”), Allegheny Generating Company (“AGC”) and 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 77% and 23% of AGC, respectively. The Generation and Marketing segment is subject to federal regulation but is not 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 the people who are employed by Allegheny.

The accompanying unaudited interim financial statements should be read in conjunction with the Combined Annual Report on Form 10-K of AE, Monongahela, Potomac Edison and AGC for the year ended December 31, 2005 (the “2005 Annual Report on Form 10-K”).

These unaudited interim financial statements have been prepared by Allegheny, without audit, 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 balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.

Certain prior period amounts in the financial statements have been reclassified to conform with the financial statement presentation for the current period. In addition, the accompanying Consolidated Statements of Cash Flows present the cash flows from discontinued operations in each of the three major categories (operating, investing and financing activities). The Consolidated Statement of Cash Flows for the nine months ended September 30, 2005 was revised during 2006 to conform to this presentation. Accordingly, for the nine months ended September 30, 2005, approximately $6.5 million in cash outflows for capital expenditures of discontinued operations and less than $0.1 million in cash outflows for debt repayment of discontinued operations were moved from cash flows of operating activities to cash flows of investing and financing activities of discontinued operations, respectively.

Federal and State Income Taxes. Allegheny allocates income tax expense (benefit) to its subsidiaries pursuant to its consolidated tax sharing agreement. This corporate allocation may cause significant fluctuations in the effective quarterly and year-to-date tax rates from the statutory rates for certain of Allegheny’s subsidiaries, depending on the level of pre-tax income. Consolidated income tax expense differs from an amount calculated at the federal statutory income tax rate of 35%, principally due to state income taxes, tax credits and effects of utility rate making and certain non-deductible expenses, as well as additional tax adjustments recorded during the second quarter of 2005 and the third quarter of 2006, which are described below.

On July 2, 2006, the Pennsylvania State budget for fiscal year 2006-2007 was enacted. The budget included a provision that will raise 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 remains unchanged at 20 years. Allegheny

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

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, for the estimated portion of the loss carryforwards that will be realized during the carryforward period.

During the second quarter of 2005, Allegheny determined that it had not claimed certain income tax deductions in its 2003 income tax returns relating to commodity trading contracts. Allegheny filed a claim for these additional deductions, which increased Allegheny’s recorded tax net operating loss carryforwards in the amount of approximately $210 million and decreased other recorded deferred tax assets in a similar amount, except for certain state income tax effects. Allegheny recorded a charge of $3.8 million during the second quarter of 2005 to write-off state deferred tax assets that would not be realized due to state limitations on the use of net operating loss carryforwards resulting from the filing of this claim. The effect of this adjustment was not material to Allegheny’s results of operations for the year ended December 31, 2005.

On June 30, 2005, the state of Ohio enacted broad changes to its business tax system including a phase-out of the state’s income-based franchise tax over a five-year period beginning in 2006. The phase-out of the franchise tax will reduce the benefit of recorded tax assets by $1.9 million, and deferred tax assets were written down by this amount in the second quarter of 2005. The franchise tax has been replaced by a gross receipts tax that is being phased in over a five-year period beginning July 1, 2005.

NOTE 2: RECENT ACCOUNTING PRONOUNCEMENTS

The following is a summary of significant recent accounting pronouncements issued or implemented during 2006 that relate to Allegheny’s operations.

As discussed further in Note 3, “Stock-Based Compensation,” Allegheny adopted Statement of Financial Accounting Standards No. 123 (revised 2004),Share-Based Payment(“SFAS No. 123R”) effective January 1, 2006 using the modified prospective transition method.

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106, and 132(R)(“SFAS No. 158”). SFAS No. 158 requires the balance sheet recognition of the underfunded or overfunded status of pension and other postretirement benefit plans. The funded status recognition provisions of this Standard apply prospectively, beginning December 31, 2006. SFAS No. 158 also requires measurement of plan assets and benefit obligations at fiscal year end effective December 31, 2008, eliminating the use of earlier measurement dates currently permissible. Allegheny expects that its adoption of SFAS No. 158 will result in the recognition of an additional liability for its postretirement benefit plans of approximately $170 million at December 31, 2006. A regulatory asset will be established under SFAS No. 71Accounting for the Effects of Certain Types of Regulation(“SFAS No. 71”) for a portion of this liability. To the extent that a regulatory asset cannot be established in certain regulatory jurisdictions and to the extent that the liability relates to its unregulated operations, Allegheny will record a charge to accumulated comprehensive income, a component of stockholders’ equity, net of any deferred tax balances. Management is currently assessing the extent to which regulatory assets can be recorded and does not expect that SFAS No. 158 will have a material impact on Allegheny’s results of operations, cash flows or compliance with debt covenants.

In September 2006, the FASB issued 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 financial statements issued for fiscal years beginning after November 15, 2007. Management has not completed the process of determining the effect of this new pronouncement on Allegheny’s financial statements.

In September 2006, the SEC issued Staff Accounting Bulletin No. 108,Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (“SAB No. 108”), which expresses SEC staff views regarding the process by which misstatements in financial statements are evaluated for purposes of determining whether financial statement restatement is necessary. SAB No. 108 is effective for Allegheny for its December 31, 2006 annual financial statements. Management does not believe that the adoption of SAB No. 108 will have a material impact on Allegheny’s financial statements.

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

In June 2006, the FASB issued FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109(“FIN No. 48”).FIN No. 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold (whether a tax position is more likely than not to be sustained), below which the benefit of that position is not recognized in the financial statements. It requires a measurement determination for recognized tax positions based on the largest amount of benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement. FIN No. 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods and disclosure. The provisions of FIN No. 48 are effective beginning January 1, 2007, with the cumulative effect of adoption recorded as an adjustment to the 2007 opening retained earnings balance, subject to the effects of SFAS No. 71 relating to Allegheny’s regulated operations. Management is analyzing the impact of this interpretation on Allegheny’s open tax positions and expects to complete its analysis in the fourth quarter of 2006.

NOTE 3: STOCK-BASED COMPENSATION

In December 2004, the FASB issued SFAS No. 123R, which revises SFAS No. 123, “Accounting for Stock-Based Compensation,” and supersedes Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related guidance (“APB No. 25”). SFAS No. 123R requires that all share-based payments to employees, including grants of employee stock options, be measured at fair value on the date of grant and recognized as expense over the requisite service period.

Allegheny adopted SFAS No. 123R effective January 1, 2006 using the modified prospective transition method. Under this transition method, the fair value accounting and recognition provisions of SFAS No. 123R are applied to share-based awards granted or modified subsequent to the date of adoption and prior periods presented are not restated. In addition, compensation expense is recognized in future periods for all share-based payment awards that were outstanding, but not yet vested, as of January 1, 2006, based on the same estimated grant date fair values and service periods used to prepare Allegheny’s SFAS No. 123 pro-forma disclosures, net of estimated forfeitures. Prior to the adoption of SFAS No. 123R, Allegheny accounted for stock-based compensation using the intrinsic value method accompanied by pro forma disclosures of net income and earnings per share as if Allegheny had applied the fair value method to all such compensation.

The following table summarizes stock-based compensation expense recognized during the three and nine months ended September 30, 2006 and 2005:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Stock options	$	1.8	$	—	$	5.8	$	—
Stock units		1.0		2.0		4.3		8.1
Other		0.3		0.2		0.9		0.5


Stock-based compensation expense included in operations and maintenance expense		3.1		2.2		11.0		8.6
Income tax benefit		1.3		0.9		4.5		3.6

Total stock-based compensation expense, net of tax	$	1.8	$	1.3	$	6.5	$	5.0

No stock-based compensation cost was capitalized in 2006 or 2005.

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

As indicated in the preceding table, prior to January 1, 2006, no stock-based compensation expense was recognized for stock options. Allegheny’s net income and income per share for 2005 would have been reduced to the pro forma amounts shown below if compensation expense had been determined using the fair value provisions of SFAS No. 123:


	Three Months Ended		Nine Months Ended
	September 30,		September 30,
(In millions)	2005		2005
Consolidated net income, as reported	$	35.7	$	59.9
Add:
Stock-based employee compensation expense included in consolidated net income, net of related tax effects		1.2		4.8
Deduct:
Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		2.5		8.6

Consolidated net income, pro forma	$	34.4	$	56.1


Basic income per share:
As reported	$	0.22	$	0.39
Pro forma	$	0.21	$	0.37

Diluted income per share:
As reported	$	0.21	$	0.38
Pro forma	$	0.21	$	0.36

Stock Options

Allegheny’s Long-Term Incentive Plan (“LTIP”), which is shareholder approved, permits the award of stock options, restricted share awards and performance awards to employees for up to 10 million shares of stock. The exercise price, terms and other conditions applicable to stock option awards are generally determined by the Management Compensation and Development Committee of the Board of Directors. The exercise price of each award is equal to or greater than the fair market value per common share on the grant date. Stock options vest in annual tranches on a pro-rata basis over the vesting period, which is typically two to five years, and become fully vested and exercisable upon a change in control. Options typically expire after 10 years. Except as may be provided in a separate agreement with any individual employee, in the event of termination of employment, options not exercisable at the time of termination will expire as of the date of termination. Except as may be otherwise provided in a separate agreement with any individual employee, exercisable options will expire 90 days from the date of termination, except in the event of termination due to retirement or disability, in which case, exercisable options will expire three years after the date of termination. Allegheny may permit the exercise of options or the payment of withholding taxes through the tender of previously acquired shares of Allegheny common stock or through a reduction in the number of shares issuable upon option exercise. Stock option awards are expensed using the straight-line attribution method over the requisite service period of the last separately vesting tranche of the award.

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

Effective January 1, 2006, Allegheny records compensation expense for employee stock options based on the estimated fair value of the options on the date of grant using the Black-Scholes option-pricing model with the assumptions included in the table below. For stock options granted in 2006, the expected volatility was based on both historical stock volatility and the volatility levels implied on the grant date by actively traded option contracts on Allegheny’s common stock. The expected term of the 2006 stock option grants was calculated in accordance with SAB No. 107 using the “simplified” method. The risk-free interest rate was based on the United States Treasury yield curve at the time of the grant for a period equal to the expected term of the options granted. The following weighted-average assumptions were used to estimate the fair value of options granted during the three and nine months ended September 30, 2006 and 2005:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2006			2005		2006			2005
Annual risk-free interest rate		4.98	%		—		4.64	%		4.15	%
Expected term of the option (in years)		5.75			—		6.34			6.5
Expected annual dividend yield		—			—		—			—
Expected stock price volatility		28.6	%		—		29.31	%		35.0	%
Grant date fair value per stock option	$	14.35			—	$	14.22		$	8.77

Stock option activity for the three months ended September 30, 2006 was as follows:


	Number of			Weighted-Average
	Stock Options			Exercise Price
Outstanding at June 30, 2006		5,631,013		$	16.56
Granted		38,800		$	38.16
Exercised		(740,950	)	$	16.00
Forfeited		(11,700	)	$	22.22

Outstanding at September 30, 2006		4,917,163		$	16.80

Stock option activity for the nine months ended September 30, 2006 was as follows:


	Number of			Weighted-Average
	Stock Options			Exercise Price
Outstanding at December 31, 2005		6,141,357		$	17.04
Granted		176,800		$	36.08
Exercised		(1,131,934	)	$	19.53
Forfeited		(269,060	)	$	23.31

Outstanding at September 30, 2006		4,917,163		$	16.80

The grant-date fair value of options granted during the three and nine months ended September 30, 2006 was $0.6 million and $2.5 million, respectively. The total intrinsic value of options exercised during the three and nine months ended September 30, 2006 was $18.5 million and $22.1 million, respectively. Cash received by Allegheny from option exercises totaled $11.9 million and $22.1 million for the three and nine months ended September 30, 2006, respectively. Allegheny issued new shares to satisfy these stock option exercises. There was no cash tax benefit realized from tax deductions on options exercised during the three or nine months ended September 30, 2006 because of existing tax net operating loss carryforwards.

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

Stock options outstanding at September 30, 2006 were as follows:


			Weighted-Average
			Remaining				Aggregate
	Number of		Contractual Term				Intrinsic Value
Range of Exercise Prices	Stock Options		(in Years)		Exercise Price		(in millions)
$10.00 - $14.99		3,932,646		7.42	$	13.45	$	105.1
$15.00 - $19.99		154,000		8.31	$	18.91		3.3
$20.00 - $24.99		215,000		8.27	$	21.03		4.1
$25.00 - $29.99		75,000		9.17	$	28.49		0.9
$30.00 - $34.99		154,500		3.40	$	32.03		1.3
$35.00 - $39.99		197,600		9.02	$	36.41		0.7
$40.00 - $44.99		173,417		4.19	$	42.28		*
$45.00 - $49.99		15,000		4.50	$	46.26		*

Total		4,917,163		7.33	$	16.80	$	115.4


*		The aggregate intrinsic value of these stock options is zero, because the exercise prices of these stock options exceeded the market price of Allegheny’s stock at September 30, 2006.

Stock options exercisable at September 30, 2006 were as follows:


			Weighted-Average
			Remaining				Aggregate
	Number of		Contractual Term				Intrinsic Value
Range of Exercise Prices	Stock Options		(in Years)		Exercise Price		(in millions)
$10.00 - $14.99		1,796,302		7.41	$	13.42	$	48.1
$15.00 - $19.99		34,133		8.27	$	18.77		0.7
$20.00 - $24.99		59,000		7.63	$	20.92		1.1
$25.00 - $29.99		—		—	$	—		—
$30.00 - $34.99		154,500		3.40	$	32.03		1.3
$35.00 - $39.99		20,800		5.02	$	39.25		—
$40.00 - $44.99		173,417		4.19	$	42.28		*
$45.00 - $49.99		15,000		4.50	$	46.26		*

Total		2,253,152		6.86	$	17.66	$	51.2


*		The aggregate intrinsic value of these stock options is zero, because the exercise prices of these stock options exceeded the market price of Allegheny’s stock at September 30, 2006.

As of September 30, 2006, there was $16.3 million of total unrecognized compensation cost related to non-vested outstanding stock options, which is expected to be recognized over a weighted-average period of approximately 1.3 years.

Stock Units

Allegheny’s Stock Unit Plan (the “Plan”) permits the grant of stock units to its key executives for up to 4.5 million shares of stock. Upon vesting, an executive may convert each stock unit into one share of Allegheny common stock. These stock units vest in annual tranches on a pro-rata basis over the vesting period, which is typically three to five years, and become fully vested and exercisable upon a change in control. Stock unit awards granted prior to January 1, 2006 are expensed using the graded-vesting method of FASB Interpretation No. 28. The fair value of each stock unit is equivalent to the market price of Allegheny’s stock on the date of grant. No stock units were granted during the three or nine months ended September 30, 2006.

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

Stock unit activity for the three months ended September 30, 2006 was as follows:


				Weighted-Average		Aggregate
	Number of			Grant Date		Intrinsic Value
	Stock Units			Fair Value		(in millions)
Outstanding at June 30, 2006		1,639,625		$	15.43
Units converted into 321,484 common shares		(523,659	)	$	15.29

Outstanding at September 30, 2006		1,115,966		$	15.50	$	44.8

Units convertible at September 30, 2006		107,220		$	15.30	$	4.3

Stock unit activity for the nine months ended September 30, 2006 was as follows:


				Weighted-Average		Aggregate
	Number of			Grant Date		Intrinsic Value
	Stock Units			Fair Value		(in millions)
Outstanding at December 31, 2005		3,006,506		$	15.39
Units converted into 1,149,669 common shares		(1,870,540	)	$	15.33
Forfeited		(20,000	)	$	14.74

Outstanding at September 30, 2006		1,115,966		$	15.50	$	44.8

Units convertible at September 30, 2006		107,220		$	15.30	$	4.3

The total intrinsic value of stock units converted to common shares during the three and nine months ended September 30, 2006 was $19.9 million and $69.4 million, respectively. Allegheny issued new shares in connection with these 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, 2006, there was $4.2 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 one year.

NOTE 4: REVIEW OF ESTIMATED REMAINING SERVICE LIVES AND DEPRECIATION PRACTICES

With the assistance of an independent third party, Allegheny completed a review of the estimated remaining service lives and depreciation practices relating to its unregulated generation facilities during the first quarter of 2006. As a result of this review, effective January 1, 2006, Allegheny prospectively extended the depreciable lives of its unregulated coal-fired generation facilities for periods ranging from 5 to 15 years to match the estimated remaining economic lives of these generation facilities. The extension of estimated lives reflected a number of factors, including the physical condition of the facilities, current maintenance practices and planned investments in the facilities. Allegheny also updated its property unit catalog and retirement unit definitions. These changes were considered in estimating the revised depreciation rates. The effect of these changes in accounting estimates decreased depreciation expense related to Allegheny’s unregulated coal-fired generation facilities by $9.0 million and $26.7 million for the three and nine months ended September 30, 2006, respectively, compared to the amount that would have been reflected in such expenses had the estimates not been revised. Additionally, as certain activities previously expensed are now capitalized and depreciated, operations and maintenance expense decreased by $3.5 million and $13.7 million for the three and nine months ended September 30, 2006, respectively, compared to the amounts that would have been reflected in such expenses had the estimates not been revised.

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

NOTE 5: DEBT

At September 30, 2006, contractual maturities of long-term debt for the remainder of 2006 and for full years thereafter were as follows:


(In millions)	2006			2007			2008			2009			2010			Thereafter			Total
AE Supply:
Pollution Control Bonds	$	—		$	91.7		$	—		$	—		$	—		$	191.4		$	283.1
Medium-Term Notes		—			—			—			—			—			1,050.0			1,050.0
Debentures-AGC		—			—			—			—			—			100.0			100.0
AE Supply Credit Facility		—			—			—			—			—			747.0			747.0

Total AE Supply	$	—		$	91.7		$	—		$	—		$	—		$	2,088.4		$	2,180.1


Monongahela:
First Mortgage Bonds	$	300.0		$	—		$	—		$	—		$	—		$	340.0		$	640.0
Pollution Control Bonds		—			15.5			—			—			—			70.3			85.8
Medium-Term Notes		—			—			—			—			110.0			—			110.0

Total Monongahela	$	300.0		$	15.5		$	—		$	—		$	110.0		$	410.3		$	835.8


Potomac Edison:
First Mortgage Bonds	$	—		$	—		$	—		$	—		$	—		$	320.0		$	320.0
Medium-Term Notes		100.0			—			—			—			—			—			100.0

Total Potomac Edison	$	100.0		$	—		$	—		$	—		$	—		$	320.0		$	420.0


West Penn:
Transition Bonds	$	18.6		$	79.9		$	75.8		$	73.9		$	14.8		$	—		$	263.0
Medium-Term Notes		—			—			—			—			—			80.0			80.0
First Mortgage Bonds		—			—			—			—			—			145.0			145.0

Total West Penn	$	18.6		$	79.9		$	75.8		$	73.9		$	14.8		$	225.0		$	488.0


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

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


Unamortized debt discounts and premiums		(0.3	)		(1.3	)		(1.4	)		(1.4	)		(1.2	)		(3.1	)		(8.7	)
Eliminations (a)		—			(2.3	)		—			—			—			(110.5	)		(112.8	)

Total consolidated debt	$	418.3		$	183.5		$	74.4		$	72.5		$	123.6		$	3,030.1		$	3,902.4


(a)		Represents the elimination of AGC’s $100 million 6 7/8% Debentures due 2023, which are also included above under AE Supply, and $12.8 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 2005 Annual Report on Form 10-K.

On May 2, 2006, AE Supply entered into a new $967 million senior credit facility (the “AE Supply Credit Facility”) comprised of a $767 million term loan (the “AE Supply Term Loan”) and a $200 million revolving credit facility (the “AE Supply Revolving Facility”). The AE Supply Credit Facility matures in 2011 and has a current interest rate equal to the London Interbank Offered Rate (“LIBOR”) plus 0.75%, with decreases in the rate possible if AE Supply’s ratings improve from current levels. Proceeds from the AE Supply Credit Facility were used to refinance $967 million outstanding under AE Supply’s prior term loan. The AE Supply Revolving Facility can also be used, if availability exists, to issue letters of credit.

On May 22, 2006, AE entered into a new $579 million credit facility (the “AE Credit Facility”) comprised of a $400 million senior unsecured revolving credit facility (the “AE Revolving Credit Facility”) and a $179 million senior unsecured term loan (the “AE Term Loan”). The AE Credit Facility matures in 2011 and has an initial interest rate equal to LIBOR plus 1%, with decreases in the rate possible if AE’s ratings improve from current levels. Proceeds from the AE Credit Facility were used to refinance the $179 million outstanding under AE’s prior credit facility and to continue $135 million of letters of credit issued under AE’s prior revolving facility.

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

In August 2006, West Penn issued $145 million aggregate principal amount of 5.875% First Mortgage Bonds, which mature in 2016. Proceeds from the First Mortgage Bonds were used to repay a portion of a note payable, to pay a dividend to Allegheny and for other general corporate purposes.

In September 2006, Monongahela issued $150 million aggregate principal amount of 5.70% First Mortgage Bonds, which mature in 2017.

Issuances and repayments of indebtedness, by entity, during the three and nine months ended September 30, 2006 were as follows:


	Three Months Ended				Nine Months Ended
	September 30, 2006				September 30, 2006
(In millions)	Issuances		Repayments		Issuances		Repayments
AE:
AE Credit Facility	$	—	$	169.1	$	179.1	$	179.1
Prior Credit Facility		—		—		—		199.0

Total AE	$	—	$	169.1	$	179.1	$	378.1


Monongahela:
First Mortgage Bonds	$	150.0	$	—	$	150.0	$	—


AE Supply:
AE Supply Credit Facility	$	—	$	105.0	$	967.0	$	220.0
Prior AE Supply Loan		—		—		—		989.0

Total AE Supply	$	—	$	105.0	$	967.0	$	1,209.0


West Penn:
First Mortgage Bonds	$	145.0	$	—	$	145.0	$	—
Transition Bonds (a)		1.3		18.1		3.9		57.2

Total West Penn	$	146.3	$	18.1	$	148.9	$	57.2

Consolidated Total	$	296.3	$	292.2	$	1,445.0	$	1,644.3


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

Subsequent issuance and redemptions:

In October 2006, Monongahela used the net proceeds from the sale of the $150 million aggregate principal amount of 5.70% First Mortgage Bonds, plus available cash on hand, to fund the repayment at maturity of the $300 million aggregate principal amount of 5.0% First Mortgage Bonds.

In October 2006, Potomac Edison issued $100 million aggregate principal amount of 5.80% First Mortgage Bonds, which mature in 2016. In November 2006, Potomac Edison used the net proceeds from the sale of the bonds, plus available cash on hand, to fund the repayment at maturity of the $100 million aggregate principal amount of 5.0% Medium-Term Notes.

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

NOTE 6: DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE

The components of loss from discontinued operations were as follows:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2006			2005			2006			2005
AE Supply:
Operating revenues	$	—		$	—		$	—		$	0.4
Operating expenses		(0.4	)		8.5			(1.2	)		6.2
Other income		—			0.1			—			0.1
Interest expense		(0.4	)		(3.2	)		(2.2	)		(9.4	)

Income (loss) before income taxes		(0.8	)		5.4			(3.4	)		(2.7	)
Income tax benefit (expense)		0.3			(1.9	)		1.3			0.9
Impairment charge, net of tax		—			(4.4	)		(0.1	)		(7.6	)

Loss from discontinued operations, net of tax	$	(0.5	)	$	(0.9	)	$	(2.2	)	$	(9.4	)


Monongahela:
Operating revenues	$	—		$	21.3		$	—		$	218.1
Operating expenses		—			(25.3	)		—			(201.5	)
Other income and expenses, net		—			0.1			—			1.0
Interest expense		—			(2.0	)		—			(6.1	)


Income (loss) before income taxes		—			(5.9	)		—			11.5
Income tax benefit (expense)		—			2.2			—			(4.5	)
Impairment charge, net of tax		—			(3.1	)		—			(9.4	)

Loss from discontinued operations, net of tax	$	—		$	(6.8	)	$	—		$	(2.4	)


Allegheny:
Operating revenues	$	—		$	21.3		$	—		$	218.5
Operating expenses		(0.4	)		(16.8	)		(1.2	)		(195.3	)
Other income and expenses, net		—			0.2			—			1.1
Interest expense		(0.4	)		(5.2	)		(2.2	)		(15.5	)

Income (loss) before income taxes		(0.8	)		(0.5	)		(3.4	)		8.8
Income tax benefit (expense)		0.3			0.3			1.3			(3.6	)
Impairment charge, net of tax		—			(7.5	)		(0.1	)		(17.0	)

Loss from discontinued operations, net of tax	$	(0.5	)	$	(7.7	)	$	(2.2	)	$	(11.8	)

Impairment charges reflected in the table above represent adjustments of the carrying values of assets held for sale to current estimates of sales proceeds, less costs to sell.

Assets held for sale, all of which relate to AE Supply, were as follows:


	September 30,		December 31,
(In millions)	2006		2005
Current assets	$	0.9	$	1.5
Property, plant and equipment		21.2		23.1
Receivable from TVA		—		25.5

Total	$	22.1	$	50.1

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

NOTE 7: DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Allegheny utilizes derivative instruments to manage its exposure to various market risks, as described in the 2005 Annual Report on Form 10-K. The following information supplements, and should be read in conjunction with, Item 8, Note 5, “Derivative Instruments and Hedging Activities,” in the 2005 Annual Report on Form 10-K.

AE Supply has designated certain contracts as cash flow hedges. Changes in the fair value of these contracts upon such designation and thereafter are reflected in “Accumulated other comprehensive income” until contract settlement. See Note 11, “Comprehensive Income.” These contracts expire at various dates through September 2007. The pre-tax accumulated other comprehensive loss for the contracts was $1.7 million at September 30, 2006 and $50.5 million at December 31, 2005. The decrease 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 contract settlements and changes in market prices. The accumulated other comprehensive loss balance is expected to be completely reclassified as a reduction to earnings over the next twelve months. The ineffective portion of the cash flow hedges of $0.3 million and $1.2 million is reflected in earnings 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 $29.7 million and $106.6 million at September 30, 2006 and December 31, 2005, respectively. Operating revenues included net unrealized gains of $8.5 million and $4.9 million and net realized losses of $14.1 million and $11.1 million for the three months ended September 30, 2006 and 2005, respectively. Operating revenues included net unrealized gains of $26.8 million and $18.2 million and net realized losses of $18.7 million and $17.8 million for the nine months ended September 30, 2006 and 2005, respectively, relating to cash flow hedges and trading activities.

NOTE 8: ASSET RETIREMENT OBLIGATIONS (“AROs”)

Effective December 31, 2005, Allegheny adopted FASB Interpretation No. 47,Accounting for Conditional Asset Retirement Obligations (“Conditional AROs”)(“FIN No. 47”), which requires an entity to recognize a liability for the fair value of a Conditional ARO if the fair value of the liability can be reasonably estimated. The obligation to perform the asset retirement activity for a Conditional ARO is unconditional, even though uncertainty exists about the timing and (or) method of settlement.

Allegheny has AROs primarily related to ash landfills and underground and aboveground storage tanks and Conditional AROs related to asbestos contained in its generating facilities, wastewater treatment lagoons and transformers containing polychlorinated biphenyls (“PCBs”).

The following is an analysis of the changes in the ARO liability for the nine months ended September 30, 2006:


(In millions)	ARO Liability
Balance at December 31, 2005	$	48.8
Accretion of the liability		4.0
New ARO liability		1.8
Settlements of ARO liabilities		(1.0	)

Balance at September 30, 2006	$	53.6

Allegheny believes it is probable that, for regulated companies, any difference between expenses recorded for AROs and Conditional AROs and expenses recovered currently in rates with respect to these assets will be recoverable in future rates and therefore defers these regulatory costs as regulatory assets or a reduction against related regulatory liabilities.

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

NOTE 9: BUSINESS SEGMENTS

Allegheny manages and evaluates its operations in two business segments, the Delivery and Services segment and the Generation and Marketing segment. Monongahela operates in both segments. 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, 2006											Three Months Ended September 30, 2005
	Delivery		Generation									Delivery			Generation
	and		and									and			and
(In millions)	Services		Marketing			Eliminations			Total			Services			Marketing			Eliminations			Total
External operating revenues	$	700.4	$	116.2		$	—		$	816.6		$	728.2		$	116.8		$	—		$	845.0
Internal operating revenues		1.8		372.4			(374.2	)		—			2.8			379.6			(382.4	)		—

Total operating revenues	$	702.2	$	488.6		$	(374.2	)	$	816.6		$	731.0		$	496.4		$	(382.4	)	$	845.0
Depreciation and amortization	$	37.7	$	30.6		$	—		$	68.3		$	38.2		$	38.5		$	—		$	76.7
Operating income	$	80.7	$	130.4		$	—		$	211.1		$	36.3		$	134.7		$	—		$	171.0
Interest expense	$	20.1	$	46.8		$	(0.8	)	$	66.1		$	24.2		$	88.0		$	(0.4	)	$	111.8
Income from continuing operations	$	43.8	$	66.9		$	—		$	110.7		$	10.7		$	32.7		$	—		$	43.4
Loss from discontinued operations, net of tax	$	—	$	(0.5	)	$	—		$	(0.5	)	$	(6.8	)	$	(0.9	)	$	—		$	(7.7	)
Net income	$	43.8	$	66.4		$	—		$	110.2		$	3.9		$	31.8		$	—		$	35.7


	Nine Months ended September 30, 2006											Nine Months ended September 30, 2005
	Delivery		Generation									Delivery			Generation
	and		and									and			and
(In millions)	Services		Marketing			Eliminations			Total			Services			Marketing			Eliminations			Total
External operating revenues	$	2,031.8	$	352.7		$	—		$	2,384.5		$	2,126.5		$	187.2		$	—		$	2.313.7
Internal operating revenues		5.5		1,057.1			(1,062.6	)		—			7.1			1,130.6			(1,137.7	)		—

Total operating revenues	$	2,037.3	$	1,409.8		$	(1,062.6	)	$	2,384.5		$	2,133.6		$	1,317.8		$	(1,137.7	)	$	2,313.7
Depreciation and amortization	$	113.3	$	91.0		$	—		$	204.3		$	115.3		$	115.2		$	—		$	230.5
Operating income	$	227.1	$	347.3		$	—		$	574.4		$	191.1		$	272.0		$	—		$	463.1
Interest expense	$	61.9	$	150.2		$	(2.2	)	$	209.9		$	99.5		$	267.0		$	(0.6	)	$	365.9
Income (loss) from continuing operations	$	113.5	$	143.4		$	—		$	256.9		$	77.3		$	(5.5	)	$	(0.1	)	$	71.7
Loss from discontinued operations, net of tax	$	—	$	(2.2	)	$	—		$	(2.2	)	$	(2.5	)	$	(9.4	)	$	0.1		$	(11.8	)
Net income (loss)	$	113.5	$	141.2		$	—		$	254.7		$	74.8		$	(14.9	)	$	—		$	59.9

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

NOTE 10: GOODWILL AND INTANGIBLE ASSETS

There were no changes in goodwill during the nine months ended September 30, 2006.

The intangible assets included in “Investments and Other Assets” on the Consolidated Balance Sheets of $27.4 million at both September 30, 2006 and December 31, 2005, relate to an additional minimum pension liability.

The components of intangible assets included in “Property, Plant and Equipment, Net” on the Consolidated Balance Sheets were as follows:


	September 30, 2006				December 31, 2005
	Gross Carrying		Accumulated		Gross Carrying		Accumulated
(In millions)	Amount		Amortization		Amount		Amortization
Land easements, amortized	$	97.8	$	28.1	$	97.7	$	27.1
Land easements, unamortized		30.7		—		30.6		—
Software		45.9		28.4		72.3		50.9

Total	$	174.4	$	56.5	$	200.6	$	78.0

Amortization expense of intangible assets was $3.8 million and $3.7 million for the three months ended September 30, 2006 and 2005, respectively, and $11.5 million and $11.3 million for the nine months ended September 30, 2006 and 2005, respectively.

Amortization expense of intangible assets at September 30, 2006 is estimated to be as follows:


(In millions)	2006		2007		2008		2009		2010
Annual amortization expense	$	14.7	$	8.0	$	3.1	$	2.3	$	1.7

NOTE 11: COMPREHENSIVE INCOME

Comprehensive income consisted of the following:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(In millions)	2006		2005			2006		2005
Net income	$	110.2	$	35.7		$	254.7	$	59.9
Other comprehensive income (loss), net of tax:
Minimum pension liability adjustment		—		—			—		(0.2	)
Changes in value of available for sale securities		—		0.1			—		(0.2	)
Changes in fair value of cash flow hedges		6.0		(26.8	)		29.9		(36.2	)

Comprehensive income, net of income taxes	$	116.2	$	9.0		$	284.6	$	23.3

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

The components of accumulated other comprehensive loss, included in the shareholders’ equity section of the balance sheets, were as follows:


(In millions)	September 30, 2006			December 31, 2005
Accumulated other comprehensive loss on cash flow hedges, net of tax	$	(1.6	)	$	(31.5	)
Accumulated minimum pension liability		(111.2	)		(111.2	)

Total	$	(112.8	)	$	(142.7	)

NOTE 12: PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

Substantially all of Allegheny’s employees, including officers, are employed by AESC and are covered by noncontributory, defined benefit pension plans. Benefits are based on each employee’s years of service and compensation. Allegheny’s funding policy is to contribute annually to these plans at least the minimum amount required under the Employee Retirement Income Security Act of 1974 (“ERISA”) and not more than the amount that can be deducted for federal income tax purposes.

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 plans, are based upon an age and years-of-service vesting schedule and other plan provisions. Subsidized medical coverage is not provided in retirement to employees who were 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 postretirement health plans include a limit on Allegheny’s share of 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)	2006			2005			2006			2005
Components of net periodic cost:
Service cost	$	5.4		$	6.0		$	16.3		$	17.7
Interest cost		15.4			15.8			46.1			47.6
Expected return on plan assets		(17.4	)		(17.3	)		(52.2	)		(51.9	)
Amortization of unrecognized transition obligation		0.1			0.1			0.3			0.3
Amortization of prior service cost		0.8			0.9			2.6			2.7
Recognized actuarial loss		3.2			2.3			9.4			6.9

Subtotal		7.5			7.8			22.5			23.3
Curtailments and settlements		—			1.1			—			1.3

Net periodic cost	$	7.5		$	8.9		$	22.5		$	24.6


Allocation of net periodic cost:
AE Supply	$	2.3		$	2.4		$	6.8		$	6.8
Monongahela		1.9			3.0			5.8			8.0
West Penn		1.8			1.9			5.5			5.4
Potomac Edison		1.4			1.4			4.1			4.0
AE		0.1			0.2			0.3			0.4

Net periodic cost	$	7.5		$	8.9		$	22.5		$	24.6

Portion of net periodic cost above included in discontinued operations	$	—		$	1.0		$	—		$	1.7


	Postretirement Benefits Other Than Pensions
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2006			2005			2006			2005
Components of net periodic cost:
Service cost	$	1.2		$	1.0		$	3.8		$	3.0
Interest cost		4.2			4.2			12.6			12.6
Expected return on plan assets		(1.7	)		(1.6	)		(5.2	)		(4.6	)
Amortization of unrecognized transition obligation		1.4			1.5			4.3			4.4
Recognized actuarial loss		1.0			0.6			2.9			1.6

Subtotal		6.1			5.7			18.4			17.0
Curtailments and settlements		—			3.3			—			3.3

Net periodic cost	$	6.1		$	9.0		$	18.4		$	20.3


Allocation of net periodic cost:
Monongahela	$	1.7		$	4.3		$	5.1		$	7.5
West Penn		1.6			1.8			5.0			4.9
Potomac Edison		1.4			1.3			4.0			3.7
AE Supply		1.4			1.5			4.2			4.0
AE		—			0.1			0.1			0.2

Net periodic cost	$	6.1		$	9.0		$	18.4		$	20.3

Portion of net periodic cost above included in discontinued operations	$	—		$	1.9		$	—		$	2.6

For the three months ended September 30, 2006 and 2005, Allegheny allocated $3.4 million and $3.5 million, respectively, and for the nine months ended September 30, 2006 and 2005, Allegheny allocated $9.4 million and $8.8 million, respectively, of the above net periodic cost amounts to “Construction work in progress.”

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

Allegheny contributed $7.0 million and $65.2 million to its pension plans during the three and nine months ended September 30, 2006, respectively, including contributions of $0.1 million and $0.2 million, respectively, to the Supplemental Executive Retirement Plan (“SERP”). Allegheny also contributed $2.8 million and $10.0 million to fund its postretirement benefits plans other than pension plans during the three and nine months ended September 30, 2006, respectively. Allegheny does not anticipate making any significant additional contributions to its pension plans during the remainder of 2006. Allegheny currently anticipates contributing a total amount in 2006 ranging from $12.5 million to $14.5 million to fund its postretirement benefits plans other than pensions.

In the third quarter of 2006, the Pension Protection Act of 2006 (the “Act”) was signed into law. The Act will affect the manner in which many companies, including Allegheny, administer their pension plans. This legislation 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.

Allegheny made cash matching contributions to the 401(k) Employee Stock Ownership and Savings Plan (the “ESOSP”) in the amount of $2.0 million and $5.8 million for the three and nine months ended September 30, 2006, respectively.

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

NOTE 13: INCOME (LOSS) PER SHARE

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions, except share amounts)	2006			2005			2006			2005
Basic Income (Loss) per Share:
Numerator:
Income from continuing operations, net of tax	$	110.7		$	43.4		$	256.9		$	71.7
Loss from discontinued operations, net of tax		(0.5	)		(7.7	)		(2.2	)		(11.8	)

Net income	$	110.2		$	35.7		$	254.7		$	59.9


Denominator:
Weighted-average common shares outstanding		164,813,343			162,710,523			163,812,973			152,379,059

Basic Income (Loss) per Share:
Income from continuing operations, net of tax	$	0.67		$	0.27		$	1.56		$	0.47
Loss from discontinued operations, net of tax		—			(0.05	)		(0.01	)		(0.08	)

Net income	$	0.67		$	0.22		$	1.55		$	0.39


Diluted Income (Loss) per Share:
Numerator:
Income from continuing operations, net of tax	$	110.7		$	43.4		$	256.9		$	71.7
Add back: Interest expense on Trust Preferred Securities, net of tax		—			—			—			2.9

Income from continuing operations, net of tax after interest		110.7			43.4			256.9			74.6
Loss from discontinued operations, net of tax		(0.5	)		(7.7	)		(2.2	)		(11.8	)

Net income	$	110.2		$	35.7		$	254.7		$	62.8


Denominator:
Weighted-average common shares outstanding		164,813,343			162,710,523			163,812,973			152,379,059
Effect of dilutive securities:
Stock options		2,692,136			1,822,821			2,619,057			1,273,654
Performance shares		25,497			41,100			32,391			54,410
Non-employee stock awards		47,676			28,000			40,677			22,400
Stock units		1,050,672			2,181,176			2,081,523			2,106,382
Trust Preferred Securities		—			—			—			10,181,215

Total shares		168,629,324			166,783,620			168,586,621			166,017,120


Diluted Income (Loss) per Share:
Income from continuing operations, net of tax	$	0.65		$	0.26		$	1.52		$	0.45
Loss from discontinued operations, net of tax		—			(0.05	)		(0.01	)		(0.07	)

Net income	$	0.65		$	0.21		$	1.51		$	0.38

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

NOTE 14: ADVERSE POWER PURCHASE COMMITMENT LIABILITY

As of September 30, 2006, Allegheny’s liability for adverse power purchase commitments was $188.5 million, including a current liability of $17.3 million. Allegheny’s liability for adverse power purchase commitments decreased as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Amortization of liability for adverse power purchase commitments	$	4.3	$	4.2	$	12.9	$	12.6

The decreases in the reserve for adverse power purchase commitments are recorded as expense reductions in “Purchased power and transmission” on the Consolidated Statements of Operations.

NOTE 15: REGULATORY ASSETS AND LIABILITIES

Certain of Allegheny’s regulated utility operations are subject to the provisions of SFAS No. 71. Regulatory assets represent probable future revenues associated with deferred costs that are expected to be recovered from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. Regulatory assets and regulatory liabilities reflected in the Consolidated Balance Sheets at September 30, 2006 and December 31, 2005 relate to:


	September 30,		December 31,
(In millions)	2006		2005
Regulatory assets, including current portion:
Income taxes	$	312.0	$	312.2
Pennsylvania stranded cost recovery		63.6		88.1
Pennsylvania Competitive Transition Charge (“CTC”) reconciliation		105.0		97.7
Unamortized loss on reacquired debt		40.8		44.8
Other		30.3		40.4

Subtotal		551.7		583.2


Regulatory liabilities:
Net asset removal costs		420.6		413.0
Income taxes		38.6		41.3
Other		1.2		—

Subtotal		460.4		454.3

Net regulatory assets	$	91.3	$	128.9

See Note 8, “Asset Retirement Obligations (“AROs”),” for a discussion of a regulatory liability identified in conjunction with the application of a recent accounting pronouncement.

The Consolidated Balance Sheets include the amounts listed below for generating assets not subject to SFAS No. 71 “Accounting for the Effects of Certain Price Regulation” (“SFAS No. 71”).


	September 30,			December 31,
(In millions)	2006			2005
Property, plant and equipment	$	4,287.9		$	4,160.4
Amounts under construction included above	$	134.2		$	62.7
Accumulated depreciation	$	(2,048.0	)	$	(1,992.4	)

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

NOTE 16: OTHER INCOME AND EXPENSES, NET

Other income and expenses, net, represents non-operating income and expenses before income taxes and are comprised of the following:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Interest and dividend income	$	4.2	$	4.4	$	15.0	$	9.4
Coal brokering income		0.4		0.4		1.3		1.5
Gain on sale of land		0.2		—		1.0		1.6
Premium services		0.7		1.5		2.7		3.3
Gain on sale of investments		—		—		0.3		0.8
Cash received from a former trading executive’s forfeited assets		—		—		—		11.2
Proceeds from sale of America’s Fiber Network LLC		—		—		—		3.0
Other		2.4		1.0		5.5		3.0

Total	$	7.9	$	7.3	$	25.8	$	33.8

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. The AE Credit Facility includes a $400 million revolving facility, any unutilized portion of which is available for the issuance of letters of credit. In addition, the AE Supply Credit Facility includes a $200 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, 2006				December 31, 2005
	Amounts		Total
	Recorded on		Guarantees		Amounts Recorded		Total
	the Consolidated		and Letters		on the Consolidated		Guarantees and Letters
(In millions)	Balance Sheet		of Credit		Balance Sheet		of Credit
Guarantees:
Performance of a put option issued in connection with an asset sale (a)	$	—	$	—	$	6.4	$	6.4
Loans and other financing-related matters		—		8.4		—		8.7
Lease agreement		—		4.7		—		4.7
Purchase, sale, exchange or transportation of wholesale natural gas, electric power and related services		—		20.4		—		3.9
Other		0.2		0.2		0.2		0.2

Total Guarantees	$	0.2	$	33.7	$	6.6	$	23.9


Letters of Credit:
Under AE’s Revolving Facility (b)	$	—	$	135.5	$	—	$	136.5
Other (c)		—		2.1		—		1.6

Total Letters of Credit		—		137.6		—		138.1

Total Guarantees and Letters of Credit	$	0.2	$	171.3	$	6.6	$	162.0


(a)		The $6.4 million guarantee outstanding at December 31, 2005 was terminated during the first quarter of 2006 in connection with the purchase by Allegheny Energy Hunlock Creek LLC (“AE Hunlock”), a wholly owned subsidiary of AE, of a 50% interest owned by UGI Hunlock Creek Development Company (“UGI”) in Hunlock Creek Energy Ventures, LLC (“HCEV”). See Note 19, “HCEV Partnership Interest,” for additional information.

(b)		These amounts are comprised of a letter of credit for $125.0 million that expires in June 2007 and was issued on September 23, 2005 on behalf of Allegheny as collateral to stay enforcement of the judgment in Allegheny’s litigation against Merrill Lynch while an appeal is pending and a letter of credit for $9.5 million issued due to an AE Ventures contractual obligation that expires in July 2007. The September 30, 2006 amount also includes a $1.0 million letter of credit that is related to an interconnection agreement with TVA that was issued during May 2006 and expires in May 2007. The December 31, 2005 amount included a $2.0 million letter of credit related to AE Solutions.

(c)		These amounts are not issued under either the AE Revolving Credit Facility or the AE Supply Revolving Facility.

NOTE 18: VARIABLE INTEREST ENTITIES (“VIE”)

FASB Interpretation No. 46R (“FIN 46R”), “Consolidation of Variable Interest Entities,” requires an investor with the majority of the variable interests in a VIE to consolidate the entity and also requires majority and significant variable interest investors to provide certain disclosures. A VIE is an entity the equity investors of which do not have a controlling interest or in which the equity investment at risk is insufficient to finance the entity’s activities without receiving financial support from the other parties.

Potomac Edison and West Penn each have a long-term electricity purchase contract with an unrelated independent power producer (“IPP”) that represents a variable interest. Allegheny has been unable to obtain certain information from the IPPs necessary to determine if the related VIEs should be consolidated.

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

Potomac Edison and West Penn purchased power from these two IPPs in the amount of $27.0 million and $11.3 million, respectively, for the three months ended September 30, 2006, and $26.7 million and $11.5 million, respectively, for the three months ended September 30, 2005.

Potomac Edison and West Penn purchased power from these two IPPs in the amount of $71.8 million and $34.7 million, respectively, for the nine months ended September 30, 2006, and $79.3 million and $32.9 million, respectively, for the nine months ended September 30, 2005.

Potomac Edison recovers the full amount, and West Penn recovers a portion, of the cost of the applicable power contract in their respective rates charged to consumers or through customer surcharges. Neither Potomac Edison nor West Penn is subject to any risk of loss associated with the applicable VIE, because neither of them has any obligation to the applicable IPP other than to purchase the power that the IPP produces according to the terms of the applicable electricity purchase contract.

NOTE 19: HCEV PARTNERSHIP INTEREST

AE Hunlock previously owned a 50% interest in HCEV, which owned and operated a 48 MW coal-fired generating facility and a 44 MW gas-fired combustion turbine generation facility located on real property in Hunlock Township, Luzerne County, Pennsylvania. UGI also owned a 50% interest in HCEV. UGI held a put option under which it could require AE Supply to purchase UGI’s 50% interest in either the coal-fired facility, the gas-fired facility, or both for a 90-day period beginning on January 24, 2006.

AE, AE Hunlock, and AE Supply entered into an agreement dated March 1, 2006 with UGI, UGI Development Company (“UGI Development”), and HCEV under which (a) HCEV distributed the coal-fired facility to UGI together with the working capital, including coal inventory, used in the operation of that facility and any known and unknown liabilities associated with that facility; (b) UGI agreed to indemnify AE, AE Hunlock, and AE Supply from and against any known and unknown liabilities associated with the coal-fired facility; (c) after distribution of the coal-fired facility to UGI, AE Hunlock purchased UGI’s 50% interest in HCEV for a cash payment of approximately $13.9 million at closing and a post-closing adjustment of approximately $600,000 for aggregate cash consideration of approximately $14.5 million; (d) AE Hunlock thereby effectively obtained the gas-fired facility together with working capital, including inventory, used in the operation of that facility and any known and unknown liabilities associated with that facility, (e) HCEV was dissolved, and the assets and liabilities of HCEV, including the gas-fired facility, related working capital, including inventory, and any known and unknown liabilities associated with that facility, were contributed to AE Supply; (f) AE Supply agreed to indemnify UGI and its affiliates from and against any known and unknown liabilities associated with the gas-fired facility, (g) UGI Development granted AE Supply easement rights to the real property located in Hunlock Township, Luzerne County, Pennsylvania sufficient to allow for the operation of the gas-fired facility; and (h) AE and UGI agreed that they each will be responsible for 50% of any liabilities arising in connection with HCEV that are not directly attributable to either the coal unit or the gas unit.

NOTE 20: 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.

Clean Air Act Matters.Allegheny currently meets applicable standards for particulate matter emissions at its generation facilities through the use of high-efficiency electrostatic precipitators, cleaned coal, flue-gas conditioning, optimization software, fuel combustion modifications and, at times, through other means. From time to time, minor excursions of stack emission opacity that are normal to fossil fuel operations are experienced and are accommodated by the regulatory process. Allegheny meets current emission standards for sulfur dioxide (“SO₂”) by using emission controls, burning low-sulfur coal, purchasing cleaned coal (which has lower sulfur content), blending low-sulfur coal with higher sulfur coal and utilizing emission allowances.

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

Interstate Rule (“CAIR”) promulgated by the U.S. Environmental Protection Agency (the “EPA”) on March 10, 2005, may accelerate the need to install this equipment by phasing out a portion of currently available allowances.

The Clean Air Act mandates annual reductions of SO₂ and created a SO₂ emission allowance trading program. AE Supply and Monongahela comply with current SO₂ emission standards through a system-wide plan combining the use of emission controls, low sulfur fuel and emission allowances. Based on current forecasts, Allegheny estimates that it will have minimal exposure to the SO₂ allowance market in 2006, and may have exposure of about 40,000 tons in 2007 and between 40,000 and 80,000 tons in 2008. The exposure of Monongahela is expected to be approximately 75% of Allegheny’s exposure in 2007 and 2008. 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. Therefore, there can be no assurance that Allegheny’s need to purchase SO₂ allowances for these periods will not vary from current estimates. Allegheny continues to evaluate options for continuing compliance, and current plans include the installation of scrubbers at its Hatfield’s Ferry and Fort Martin generation facilities by year-end 2009 and the elimination of a scrubber bypass at its Pleasants generation facility by 2008. In July 2006, AE Supply entered into construction contracts with The Babcock & Wilcox Company and Washington Group International in connection with its plans to install scrubbers at its Hatfield’s Ferry generation facility.

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 are completing 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 estimates that its emission control activities, in concert with its inventory of banked allowances and any potential future transactions, will facilitate its compliance with NOx limits established by the SIP through 2008. Based on these estimates, Allegheny estimates that it will have minimal exposure to the NOx allowance market through 2008. 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. Therefore, there can be no assurance that Allegheny’s need to purchase NOx allowances or the cost to purchase such NO_X allowances for these periods will not vary from current estimates.

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 its strategy for compliance. The Pennsylvania Department of Environmental Protection (the “PA DEP”) proposed a more aggressive mercury control rule on June 24, 2006, which was approved by Pennsylvania Environmental Quality Board (“EQB”) on October 17, 2006. This is one of the two major reviews needed before the rule can go to EPA for approval, the second being that of the Pennsylvania Independent Regulatory Review Commission (“IRRC”). Subject to the IRRC’s review, it is anticipated that the PA DEP will submit this more aggressive mercury control rule to the EPA in November 2006. Allegheny is assessing the proposed rule to determine what, if any, effect it would have on Allegheny’s Pennsylvania operations that may be above and beyond the requirements of CAMR and filed comments to the proposed rule in August 2006.

Additionally, Maryland passed the Healthy Air Act in early 2006. This legislation imposes state-wide emission caps on SO₂ and NOx, requires that greater reductions in mercury emissions be made more quickly than would be required by CAMR and mandates that Maryland join the Regional Greenhouse Gas Initiative and participate in that coalition’s regional efforts to reduce carbon dioxide emissions. The 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. Allegheny requested PJM, by letter dated September 6, 2006, to conduct a reliability evaluation to determine if R. Paul Smith is considered vital to the regional reliability of power flow. On July 31, 2006, the Maryland Department of the Environment submitted emergency regulations to implement the Healthy Air Act. These emergency regulations are only effective for six months and then must be replaced by a permanent set of regulations developed under the normal public process. The Maryland Department of the Environment expects to have new permanent implementing regulations by June 2007.

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

Allegheny is assessing the new legislation and implementing regulations to determine the full extent of the impacts on Allegheny’s Maryland operations.

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 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. At this time, AE is engaged in discussions with the EPA with respect to environmental matters, including NSR issues. 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. There are four recent, significant federal court decisions that have addressed the application of NSR requirements to electric utility generation facilities: the Ohio Edison decision, the Duke Energy decision, the Alabama Power decision and the Cinergy decision. The Ohio Edison and Cinergy decisions are favorable to the EPA. The Duke Energy and Alabama Power decisions support the industry’s understanding of NSR requirements. The U.S. Court of Appeals for the Fourth Circuit affirmed the Duke Energy decision on June 15, 2005. On May 15, 2006, the U.S. Supreme Court agreed to hear an appeal of the Fourth Circuit’s decision in the Duke Energy case. Oral argument took place on November 1, 2006, and a decision is expected by the summer of 2007. The Supreme Court’s decision may provide clarity on whether the industry’s or the government’s interpretation of 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 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 U.S. 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 February 15, 2006, Allegheny filed a motion to dismiss the amended complaint. On May 30, 2006, the District Court judge denied Allegheny’s motion to dismiss. On June 30, 2006, Allegheny filed an answer to the plaintiffs’ first amended complaint. On July 26, 2006, at a status conference, the Court determined that discovery would proceed regarding liability issues, but not remedies, and the liability phase of discovery should be completed by June 30, 2007.

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

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

2003, the U.S. Court of Appeals for the District of Columbia Circuit issued an order to stay the implementation of that rule. On March 17, 2006, the Court issued a final decision declaring the rule unauthorized under the Clean Air Act. NSR requirements will continue to be interpreted under the pre-rule regulations and case law. Allegheny had established an NSR review process under the original regulatory program and does not expect the March 2006 appellate court decision in this matter to have any significant impact on its operations.

On February 16, 2005, two environmental groups, Citizens for Pennsylvania’s Future and the Environmental Integrity Project, sued AE Supply in the U.S. District Court for the Western District of Pennsylvania. The action alleged violations of opacity limits and particulate matter emission limits at the Hatfield’s Ferry generation facility. On July 13, 2006, the parties entered into a settlement agreement in which AE Supply agreed to certain operations and emission limit changes and to pay the plaintiffs’ attorneys fees. The agreement was filed and entered September 22, 2006, and the case was dismissed with prejudice, although the Court retains jurisdiction over the terms of the agreement.

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 $43.07 billion, assuming an exchange rate of 1.14 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 $3.6 billion and US $877 million, respectively, assuming an exchange rate of 1.14 Canadian dollars per US dollar) along with such other relief as the Court deems just. Allegheny has not been served with this lawsuit, and the time for service of the original action has expired. Allegheny intends to vigorously defend against this action but cannot predict its outcome.

Global Warming Class Action:On April 19, 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 defendants contributed to global warming, thereby causing Hurricane Katrina and plaintiffs’ damages. The plaintiffs seek unspecified damages. 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 either 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 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 an allocation of responsibility for historic and potential future asbestos liability.

Allegheny and numerous others are plaintiffs in a similar action filed against Zurich Insurance Company in California, Fuller-Austin Asbestos Settlement Trust, et al. v. Zurich-American Insurance Co., et al., Case No. CGC 04 431719 (Superior Court of California, County of San Francisco).

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 established adequate reserves, net of insurance receivables and recoveries, to cover existing and future asbestos claims. As of October 10, 2006, Allegheny had 815 open cases remaining in West Virginia and six open cases remaining in Pennsylvania.

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

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

Comprehensive Environmental Response Compensation and Liability Act of 1980 (“CERCLA”) Claim: On March 4, 1994, Monongahela and certain affiliated companies received notice that the EPA had identified them as potentially responsible parties (“PRPs”) with respect to the Jack’s Creek/Sitkin Smelting Superfund Site in Pennsylvania. Initially, approximately 175 PRPs were involved; however, the current number of active PRPs has been reduced as a result of settlements with de minimis contributors and other contributors to the site. The costs of remediation will be shared by all past and active responsible parties. In 1999, a PRP group that included Monongahela and certain affiliated companies entered into a consent order with the EPA to remediate the site. It is currently estimated that the total remediation costs to be borne by all of the responsible parties will not exceed $20.0 million. Allegheny has an accrued liability representing its estimated share of the remediation costs as of September 30, 2006.

Other Litigation

Nevada Power Contracts.On December 7, 2001, Nevada Power Company (“NPC”) filed a complaint with the Federal Energy Regulatory Commission (“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 and other parties filed petitions for review of FERC’s June 26, 2003 order with the U.S. Court of Appeals for the Ninth Circuit (the “NPC Petitions”). The NPC Petitions were consolidated in the Ninth Circuit. On December 17, 2003, AE Supply filed a motion to intervene in this proceeding in the Ninth Circuit. The Ninth Circuit heard oral argument in these cases on December 8, 2004.

Allegheny intends to vigorously defend against these actions but cannot predict their outcomes.

Sierra/Nevada.On April 2, 2003, NPC and Sierra Pacific Resources, Inc. (together, “Sierra/Nevada”) initiated a lawsuit in U.S. District Court in Nevada against AE and AE Supply, together with Merrill Lynch & Co. and Merrill Lynch Capital Services, Inc. (together, “Merrill”). The complaint 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 asserted claims against AE and AE Supply for: (a) tortious interference with Sierra/Nevada’s contractual and prospective economic advantages; (b) conspiracy and (c) violations of the Nevada state Racketeer Influenced and Corrupt Organization (“RICO”) Act. Sierra/Nevada filed an amended complaint on May 30, 2003, which asserted a fourth cause of action against AE and AE Supply for wrongful hiring and supervision. Sierra/Nevada seeks $180 million in compensatory damages plus attorneys’ fees and seeks in excess of $850 million under the RICO count. AE and AE Supply filed motions to dismiss the complaints on May 6, 2003 and June 23, 2003. Thereafter, plaintiffs filed a motion to stay the action, pending the outcome of certain state court proceedings in which they are seeking to reverse the Nevada PUC’s disallowance of expenses. On April 4, 2005, the District Court granted the stay motion, and the action is currently stayed. 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.

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 U.S. 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

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

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

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

On September 24, 2002, certain Merrill Lynch entities filed a complaint against AE in the U.S. 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 September 25, 2002, AE and AE Supply filed an action against Merrill Lynch in New York state court alleging fraudulent inducement and breaches of representations and warranties in the purchase agreement.

On May 29, 2003, the U.S. District Court for the Southern District of New York denied AE’s motion to stay Merrill Lynch’s action and 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 dismissed the New York state action and filed an answer and asserted affirmative defenses and counterclaims against Merrill Lynch in the U.S. District Court for the Southern District of New York. 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 12, 2005, the Court granted Merrill Lynch’s motion for summary judgment on its breach of contract claim, thereby requiring AE to purchase Merrill Lynch’s equity interest in AE Supply for $115 million plus interest from March 16, 2001, to be offset by any judgment in favor of AE and AE Supply on their counterclaims. The Court denied Merrill Lynch’s summary judgment motion with respect to AE and AE Supply’s counterclaims for fraudulent inducement and breach of contract and granted Merrill Lynch’s motion with respect to the counterclaims for breach of fiduciary duty and negligent misrepresentations.

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 contract. 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 Court entered its final judgment in accordance with its July 18, 2005 ruling. On September 22, 2005, AE and AE Supply filed a notice of appeal of the District Court’s judgment to the U.S. Court of Appeals for the Second Circuit, which heard oral argument on October 30, 2006. Although AE will not be required to pay Merrill Lynch the amount of the judgment while the appeal is pending, AE has posted a letter of credit to secure the judgment.

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, and continues to accrue interest expense thereafter.

Putative Shareholder, Benefit Plan Class Actions and Derivative Action.From October 2002 through December 2002, plaintiffs claiming to represent purchasers of AE’s securities filed 14 putative class action lawsuits against AE and several of its former senior managers in U.S. District Courts for the Southern District of New York and the District of Maryland. The complaints alleged that AE and senior management violated federal securities laws when AE purchased Merrill Lynch’s energy marketing and trading business with the knowledge that the business was built on illegal wash or round-trip trades with Enron, which the complaints alleged artificially inflated trading revenue, volume and growth. All of the securities cases were transferred to the District of Maryland and consolidated. The plaintiffs filed an amended complaint on May 3, 2004 that alleged that the defendants violated federal securities laws by failing to disclose weaknesses in Merrill Lynch’s energy marketing and trading business, as well as other internal control and accounting deficiencies.

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

In June 2003, a shareholder derivative action was filed against AE’s Board of Directors and several former senior managers in the Supreme Court of the State of New York for the County of New York. The suit alleges that the Board and former senior management breached fiduciary duties to AE and that such breaches exposed AE to the securities class action lawsuits. On April 8, 2005, a second shareholder derivative action was filed against AE’s Board of Directors and several former senior managers and former directors. The action was filed in the U.S. District Court for the District of Maryland and consolidated with the securities class actions pending in that Court. The Maryland derivative action contains allegations similar to the New York state court derivative action.

AE entered into agreements to settle the consolidated securities class action as well as the related shareholder derivative actions. The Court approved the settlement of the derivative actions on May 8, 2006 and the settlement of the consolidated securities class actions on July 17, 2006. Under the settlement in the consolidated securities class action, the action was dismissed with prejudice in exchange for a cash payment of $15.05 million, which was made by AE’s insurance carrier. Pursuant to the settlement of the shareholder derivative actions; the actions were dismissed with prejudice in exchange for a cash payment of $450,000, which was made by AE’s insurance carrier, and AE’s agreement to adopt certain corporate governance changes. In connection with the settlements, AE and the other settling defendants continue to deny allegations of wrongdoing, and they have received a full release of all claims asserted in the litigation. Pursuant to AE’s charter and bylaws and Section 2-418 of the Maryland General Corporation Law, AE has agreed to advance reasonable expenses to members of its Board of Directors in connection with the shareholder derivative actions.

In February and March 2003, two putative class action lawsuits were filed against AE in U.S. District Courts for the Southern District of New York and the District of Maryland. The suits alleged that AE and a senior manager violated ERISA by: (a) failing to provide complete and accurate information to plan beneficiaries regarding the energy trading business, among other things; (b) failing to diversify plan assets; (c) failing to monitor investment alternatives; (d) failing to avoid conflicts of interest and (e) violating fiduciary duties. The ERISA cases were consolidated in the District of Maryland. On April 26, 2004, the plaintiffs in the ERISA cases filed an amended complaint, adding a number of current and former directors of AE as defendants and clarifying the nature of their claims. On June 25, 2004, the defendants filed a motion to dismiss the amended complaint. Plaintiffs have opposed the motion and it remains outstanding. AE intends to vigorously defend against these actions but cannot predict their outcome.

Suits Related to the Gleason Generation Facility.Allegheny Energy Supply Gleason Generation Facility, LLC, a subsidiary of AE Supply, is the defendant in a suit brought in the Circuit Court for Weakley County, Tennessee, by residents living in the vicinity of the generation facility in Gleason, Tennessee. The original suit was filed on September 16, 2002. AE Supply purchased the generation facility in 2001. The plaintiffs are asserting claims based on trespass and/or nuisance, claiming personal injury and property damage as a result of noise from the generation facility. They seek a restraining order with respect to the operation of the plant and damages of $200 million. Mediation sessions were held on June 17, 2004 and February 22 and 23, 2006, but the parties did not reach settlement. On September 18, 2006, the Court heard oral argument on Allegheny’s summary judgment motions regarding the plaintiffs’ claims for, among other causes of action, property and punitive damages, and a decision from the Court on these motions is pending. The case has been set for trial on April 2, 2007. AE has undertaken property purchases and other mitigation measures. AE intends to vigorously defend against this action but cannot predict its outcome.

Harrison Fuel Litigation.On November 7, 2001, Harrison Fuel and its owner filed a lawsuit against Monongahela, “Allegheny Power” and AESC in the Circuit Court of Marion County, West Virginia. The lawsuit claims that Allegheny improperly and arbitrarily rejected bids from Harrison Fuel and other companies affiliated with its owner to supply coal to Allegheny. Plaintiffs seek damages of approximately $13 million. Allegheny intends to vigorously defend against this action but cannot predict its outcome.

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

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In thousands)	2006			2005			2006			2005
Operating revenues	$	213,910		$	220,534		$	588,526		$	585,232

Operating expenses:
Fuel consumed in electric generation		45,275			41,820			129,861			110,078
Purchased power and transmission		71,196			76,157			155,028			189,654
Impairment charge on Ohio T&D assets		—			30,500			—			30,500
Deferred energy costs, net		(578	)		—			(1,201	)		—
Operations and maintenance		41,236			45,314			131,935			141,430
Depreciation and amortization		16,410			16,563			49,130			50,067
Taxes other than income taxes		11,282			11,987			35,365			37,413

Total operating expenses		184,821			222,341			500,118			559,142

Operating income (loss)		29,089			(1,807	)		88,408			26,090

Other income and expenses, net		4,597			2,915			12,434			8,627

Interest expense		10,918			10,843			32,229			32,204

Income (loss) from continuing operations before income taxes		22,768			(9,735	)		68,613			2,513

Income tax expense (benefit)		9,064			(4,339	)		26,320			(12,502	)

Income (loss) from continuing operations		13,704			(5,396	)		42,293			15,015

Loss from discontinued operations, net of tax (Note 3)		—			(6,810	)		—			(2,440	)

Net income (loss)	$	13,704		$	(12,206	)	$	42,293		$	12,575

See accompanying Notes to Consolidated Financial Statements.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)


	Nine Months Ended
	September 30,
(In thousands)	2006				2005
				(Revised-Note 1)
Cash Flows From Operating Activities:
Net income	$	42,293			$	12,575
Income from discontinued operations, net of tax		—				2,440

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		49,130				50,067
Amortization of power sale liability related to Ohio sale		(22,700	)			—
Impairment charge on Ohio T&D assets		—				30,500
Gain on asset sales		(79	)			(65	)
Deferred income taxes and investment tax credit, net		21,765				(5,416	)
Other, net		4,265				2,648

Changes in certain assets and liabilities:
Accounts receivable, net		26,525				(14,830	)
Accounts receivable due from/payable to affiliates, net		(4,284	)			(43,623	)
Materials, supplies and fuel		212				2,712
Prepaid taxes		(3,346	)			(1,778	)
Collateral deposits		14,358				(11,123	)
Prepayments		(1,123	)			190
Other current assets		142				500
Accounts payable		(18,978	)			4,529
Accrued taxes		4,828				(4,459	)
Accrued interest		5,861				6,119
Other current liabilities		(5,783	)			3,246
Other assets		189				2,112
Other liabilities		1,184				565
Net cash provided by operating activities of discontinued operations		—				64,216

Net cash provided by operating activities		114,459				101,125


Cash Flows From Investing Activities:
Capital expenditures		(64,317	)			(47,851	)
Proceeds from asset sales		141				134,365
Note receivable from affiliate		(35,160	)			(44,987	)
Increase in restricted funds		(148,478	)			—
Net cash used in investing activities of discontinued operations		—				(6,524	)

Net cash provided by (used in) investing activities		(247,814	)			35,003


Cash Flows From Financing Activities:
Issuance of long-term debt		149,452				—
Deferred financing costs		(1,130	)			—
Cash dividends paid on capital stock:
Preferred stock		(879	)			(3,777	)
Common stock		(10,015	)			—
Net cash used in financing activities of discontinued operations		—				(67,061	)

Net cash provided by (used in) financing activities		137,428				(70,838	)

Net increase in cash and cash equivalents		4,073				65,290
Cash and cash equivalents at beginning of period		136,491				45,092

Cash and cash equivalents at end of period	$	140,564			$	110,382


Supplemental Cash Flow Information:
Cash paid for interest (net of amount capitalized)	$	23,560			$	31,131

See accompanying Notes to Consolidated Financial Statements.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(unaudited)


	September 30,			December 31,
(In thousands)	2006			2005
ASSETS
Current Assets:
Cash and cash equivalents	$	140,564		$	136,491
Accounts receivable:
Customer		39,693			45,061
Unbilled utility revenue		26,568			38,200
Wholesale and other		8,824			20,598
Allowance for uncollectible accounts		(2,469	)		(2,489	)
Note receivable from affiliate		60,633			25,473
Materials and supplies		15,020			15,916
Fuel		15,435			14,751
Prepaid taxes		23,421			20,075
Collateral deposits		—			9,533
Restricted funds		148,478			—
Regulatory assets		5,581			4,379
Other		4,542			3,827

Total current assets		486,290			331,815

Property, Plant and Equipment, Net:
Generation		957,739			951,636
Transmission		283,283			281,048
Distribution		958,272			930,817
Other		71,251			73,807
Accumulated depreciation		(924,373	)		(890,548	)

Subtotal		1,346,172			1,346,760
Construction work in progress		35,969			17,401

Total property, plant and equipment, net		1,382,141			1,364,161


Investments and Other Assets:
Investment in AGC		47,234			48,197
Other		2,093			6,904

Total investments and other assets		49,327			55,101


Deferred Charges:
Regulatory assets		94,140			101,117
Other		7,084			6,985

Total deferred charges		101,224			108,102

Total Assets	$	2,018,982		$	1,859,179

See accompanying Notes to Consolidated Financial Statements.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(unaudited)


	September 30,		December 31,
(In thousands, except share amounts)	2006		2005
LIABILITIES AND STOCKHOLDER’S EQUITY

Current Liabilities:
Long-term debt due within one year (Note 2)	$	301,000	$	299,959
Accounts payable		29,254		48,232
Accounts payable to affiliates, net		53,013		57,434
Deferred income taxes		1,873		—
Accrued taxes		46,594		41,766
Accrued interest		14,790		8,929
Ohio power commitment		13,700		25,900
Other		16,916		24,378

Total current liabilities		477,140		506,598


Long-term Debt (Note 2)		533,605		385,067

Deferred Credits and Other Liabilities:
Investment tax credit		—		442
Non-current income taxes payable		45,671		45,671
Deferred income taxes		215,172		194,248
Obligations under capital leases		5,034		5,554
Regulatory liabilities		239,804		242,416
Other		32,758		41,219

Total deferred credits and other liabilities		538,439		529,550

Commitments and Contingencies (Note 10)

Preferred Stock		24,000		24,000

Common Stockholder’s Equity:
Common stock, $50 par value, 8 million shares authorized and 5,891,000 shares outstanding		294,550		294,550
Other paid-in capital		41,153		40,719
Retained earnings		110,094		78,694
Accumulated other comprehensive income		1		1

Total common stockholder’s equity		445,798		413,964

Total Liabilities and Stockholder’s Equity	$	2,018,982	$	1,859,179

See accompanying Notes to Consolidated Financial Statements.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDER’S EQUITY
(unaudited)


										Accumulated		Total
					Other					other		common
	Shares		Common		paid-in		Retained			comprehensive		stockholder’s
(In thousands, except shares)	outstanding		stock		capital		earnings			income		equity
Balance at January 1, 2006		5,891,000	$	294,550	$	40,719	$	78,694		$	1	$	413,964
Net income		—		—		—		42,293			—		42,293
Pollution control bond interest paid by AE Supply		—		—		434		—			—		434
Dividends declared on preferred stock		—		—		—		(878	)		—		(878	)
Dividends declared on common stock		—		—		—		(10,015	)		—		(10,015	)

Balance at September 30, 2006		5,891,000	$	294,550	$	41,153	$	110,094		$	1	$	445,798

See accompanying Notes to Consolidated Financial Statements.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)


Note No.		Page No.
1	Basis of Presentation		43

2	Debt		44

3	Discontinued Operations		44

4	Asset Retirement Obligations (“AROs”)		45

5	Business Segments		46

6	Intangible Assets		47

7	Pension Benefits and Postretirement Benefits Other Than Pensions		47

8	Regulatory Assets and Liabilities		48

9	Other Income and Expenses, Net		48

10	Commitments and Contingencies		48

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

NOTE 1: BASIS OF PRESENTATION

Monongahela Power Company, together with its consolidated subsidiaries (“Monongahela”) is a wholly owned subsidiary of Allegheny Energy, Inc. (“AE,” and together with its consolidated subsidiaries, “Allegheny”). Monongahela, and its regulated utility affiliates, The Potomac Edison Company (“Potomac Edison”) and West Penn Power Company (“West Penn”), collectively doing business as Allegheny Power, operate electric transmission and distribution (“T&D”) systems. Monongahela operates an electric T&D system in West Virginia and also generates power for its West Virginia customers. Monongahela has two principal business segments. The Generation and Marketing segment includes Monongahela’s generation operations. The Delivery and Services segment includes Monongahela’s electric T&D operations.

Monongahela is subject to regulation by the Securities and Exchange Commission (“SEC”), the Public Service Commission of West Virginia and the Federal Energy Regulatory Commission.

Allegheny Energy Service Corporation (“AESC”) is a wholly owned subsidiary of AE that employs substantially all of the people who are employed by Allegheny.

Monongahela conducted electric T&D operations in Ohio until December 31, 2005 and a natural gas T&D business in West Virginia until September 30, 2005. Monongahela completed the sale of its Ohio electric T&D assets to Columbus Southern Power Company (“Columbus Southern”), a subsidiary of American Electric Power, Inc., on December 31, 2005. The results of operations related to the Ohio electric T&D assets were not reclassified as discontinued operations, because the terms of the sale include a power sales agreement under which Monongahela will sell power to Columbus Southern to serve Monongahela’s former Ohio retail customer base through May 31, 2007. On September 30, 2005, Monongahela sold its West Virginia natural gas operations. The results of operations relating to these assets have been classified as discontinued operations in the accompanying Consolidated Statements of Operations for all periods presented, until the date of sale.

The accompanying unaudited interim financial statements of Monongahela should be read in conjunction with the Combined Annual Report on Form 10-K of AE, Monongahela, Potomac Edison and Allegheny Generating Company (“AGC”) for the year ended December 31, 2005 (the “2005 Annual Report on Form 10-K”).

These unaudited interim financial statements have been prepared by Monongahela, without audit, pursuant to the rules and regulations of the SEC. Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States of America 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 balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.

Certain prior period amounts have been reclassified to conform to the financial statement presentation for the current period. In addition, the accompanying Consolidated Statements of Cash Flows present the cash flows from discontinued operations in each of the three major categories (operating, investing and financing activities). The consolidated statement of cash flows for the nine months ended September 30, 2005 was revised during 2006 to conform to this presentation. Accordingly, for the nine months ended September 30, 2005, approximately $6.5 million in cash outflows for capital expenditures of discontinued operations and approximately $67.1 million in cash outflows for debt activities of discontinued operations were moved from cash flows of operating activities to cash flows of investing and financing activities of discontinued operations, respectively.

Federal and State Income Taxes. Allegheny allocates income tax expense (benefit) to its subsidiaries pursuant to its consolidated tax sharing agreement. This corporate allocation may cause significant fluctuations in the effective quarterly and year-to-date tax rates from the statutory rates for certain of Allegheny’s subsidiaries, depending on the level of pre-tax income. Consolidated income tax expense (benefit) differs from an amount calculated at the federal statutory income tax rate of 35%, principally due to state income taxes, tax credits and the effects of utility rate making and certain non-deductible expenses, as well as an additional tax benefit recorded during the second quarter of 2005, which is described below.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

which increased Monongahela’s allocated share of consolidated tax savings. Accordingly, Monongahela recorded a tax benefit of $4.3 million during the second quarter of 2005 to recognize the additional tax savings. The effect of this adjustment was not material to Monongahela’s results of operations for the year ended December 31, 2005.

Recent Accounting Pronouncements. In September 2006, the SEC issued Staff Accounting Bulletin No. 108,Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements(“SAB No. 108”), which expresses SEC staff views regarding the process by which misstatements in financial statements are evaluated for purposes of determining whether financial statement restatement is necessary. SAB No. 108 is effective for Monongahela for its December 31, 2006 annual financial statements. Management does not believe that the adoption of SAB No. 108 will have a material impact on Monongahela’s financial statements.

NOTE 2: DEBT

At September 30, 2006, contractual maturities for long-term debt for the remainder of 2006 and for full years thereafter, excluding unamortized discounts of $1.2 million, were as follows:


(In millions)	2006		2007		2008		2009		2010		Thereafter		Total
First Mortgage Bonds	$	300.0	$	—	$	—	$	—	$	—	$	340.0	$	640.0
Pollution Control Bonds		—		15.5		—		—		—		70.3		85.8
Medium-Term Notes		—		—		—		—		110.0		—		110.0

Total	$	300.0	$	15.5	$	—	$	—	$	110.0	$	410.3	$	835.8

In September 2006, Monongahela issued $150 million aggregate principal amount of 5.70% First Mortgage Bonds, which mature in 2017. The net proceeds from the sale of the bonds are reported as restricted funds in the accompanying balance sheet at September 30, 2006. In October 2006, Monongahela used these net proceeds, plus available cash on hand, to fund the repayment at maturity of the $300 million aggregate principal amount of 5.0% First Mortgage Bonds.

Monongahela did not redeem any debt during the three and nine months ended September 30, 2006.

At September 30, 2006, substantially all of Monongahela’s properties were held subject to liens of various relative priorities securing debt obligations.

NOTE 3: DISCONTINUED OPERATIONS

The components of loss from discontinued operations were as follows:


	Three Months Ended			Nine Months Ended
(In millions)	September 30, 2005			September 30, 2005
Operating revenues	$	21.3		$	218.1
Operating expenses		(25.3	)		(201.5	)
Other income and expenses, net		0.1			1.0
Interest expense		(2.0	)		(6.1	)

Income (loss) before income taxes		(5.9	)		11.5
Income tax benefit (expense)		2.2			(4.5	)
Impairment charge, net of tax		(3.1	)		(9.4	)

Loss from discontinued operations, net of tax	$	(6.8	)	$	(2.4	)

Impairment charges, reflected in the table above, represent adjustments of the carrying values of assets held for sale to current estimates of sales proceeds, less costs to sell.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

NOTE 4: ASSET RETIREMENT OBLIGATIONS (“AROs”)

Effective December 31, 2005, Monongahela adopted Financial Accounting Standards Board Interpretation No. 47,Accounting for Conditional Asset Retirement Obligations (“Conditional AROs”) (“FIN No. 47”), which requires an entity to recognize a liability for the fair value of a Conditional ARO if the fair value of the liability can be reasonably estimated. The obligation to perform the asset retirement activity for a Conditional ARO is unconditional even though uncertainty exists about the timing and (or) method of settlement.

Monongahela has AROs primarily related to ash landfills and underground and aboveground storage tanks and Conditional AROs related to asbestos contained in its generating facilities, wastewater treatment lagoons and transformers containing polychlorinated biphenyls (“PCBs”).

For the nine months ended September 30, 2006, Monongahela’s total ARO balance, which includes AROs and Conditional AROs, increased $0.6 million, from $12.9 million at December 31, 2005 to $13.5 million at September 30, 2006. This increase was primarily due to accretion of the liability.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

NOTE 5: BUSINESS SEGMENTS

Monongahela manages and evaluates its operations in two business segments, the Delivery and Services segment and the Generation and Marketing segment. Monongahela accounts for intersegment sales based on cost or regulatory commission approved tariffs or contracts. Business segment information 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, 2006										Three Months Ended September 30, 2005
	Delivery		Generation								Delivery			Generation
	and		and								and			and
(In millions)	Services		Marketing			Eliminations			Total		Services			Marketing		Eliminations			Total
External operating revenues	$	173.7	$	40.2		$	—		$	213.9	$	176.6		$	43.9	$	—		$	220.5
Internal operating revenues		—		78.0			(78.0	)		—		—			79.6		(79.6	)		—

Total operating revenues	$	173.7	$	118.2		$	(78.0	)	$	213.9	$	176.6		$	123.5	$	(79.6	)	$	220.5
Depreciation and amortization	$	7.7	$	8.7		$	—		$	16.4	$	7.9		$	8.7	$	—		$	16.6
Operating income (loss)	$	27.4	$	1.7		$	—		$	29.1	$	(14.7	)	$	12.9	$	—		$	(1.8	)
Interest expense	$	6.4	$	4.5		$	—		$	10.9	$	6.2		$	4.6	$	—		$	10.8
Income (loss) from continuing operations	$	14.9	$	(1.2	)	$	—		$	13.7	$	(13.8	)	$	8.4	$	—		$	(5.4	)
Loss from discontinued operations, net of tax	$	—	$	—		$	—		$	—	$	(6.8	)	$	—	$	—		$	(6.8	)
Net income (loss)	$	14.9	$	(1.2	)	$	—		$	13.7	$	(20.6	)	$	8.4	$	—		$	(12.2	)


	Nine Months Ended September 30, 2006										Nine Months Ended September 30, 2005
	Delivery		Generation								Delivery			Generation
	and		and								and			and
(In millions)	Services		Marketing			Eliminations			Total		Services			Marketing		Eliminations			Total
External operating revenues	$	504.5	$	84.0		$	—		$	588.5	$	515.6		$	69.6	$	—		$	585.2
Internal operating revenues		—		225.6			(225.6	)		—		—			236.6		(236.6	)		—

Total operating revenues	$	504.5	$	309.6		$	(225.6	)	$	588.5	$	515.6		$	306.2	$	(236.6	)	$	585.2
Depreciation and amortization	$	22.8	$	26.3		$	—		$	49.1	$	24.0		$	26.1	$	—		$	50.1
Operating income	$	84.1	$	4.3		$	—		$	88.4	$	16.4		$	9.7	$	—		$	26.1
Interest expense	$	18.6	$	13.6		$	—		$	32.2	$	18.5		$	13.7	$	—		$	32.2
Income (loss) from continuing operations	$	43.3	$	(1.0	)	$	—		$	42.3	$	5.7		$	9.3	$	—		$	15.0
Loss from discontinued operations, net of tax	$	—	$	—		$	—		$	—	$	(2.4	)	$	—	$	—		$	(2.4	)
Net income (loss)	$	43.3	$	(1.0	)	$	—		$	42.3	$	3.3		$	9.3	$	—		$	12.6

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

NOTE 6: INTANGIBLE ASSETS

Intangible assets included in “Property, Plant and Equipment, Net” on the Consolidated Balance Sheets were as follows:


	September 30, 2006				December 31, 2005
	Gross Carrying		Accumulated		Gross Carrying		Accumulated
(In millions)	Amount		Amortization		Amount		Amortization
Land easements, amortized	$	0.5	$	0.2	$	0.5	$	0.2
Land easements, unamortized		30.7		—		30.6		—
Software		0.3		0.3		0.3		0.3

Total	$	31.5	$	0.5	$	31.4	$	0.5

Amortization expense for intangible assets was $0.3 million and $1.0 million for the three and nine months ended September 30, 2005, respectively. Annual amortization expense for intangible assets at September 30, 2006 is not expected to be material for 2006 through 2010.

NOTE 7: PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

Monongahela is responsible for its proportionate share of the net periodic cost for pension benefits and postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents provided by Allegheny, through AESC. Monongahela’s share of the costs was as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Pension benefits (a)	$	1.9	$	3.0	$	5.8	$	8.0
Postretirement benefits other than pensions (b)	$	1.7	$	4.3	$	5.1	$	7.5


(a)		Includes $1.0 million and $1.7 million of net periodic costs recorded in discontinued operations for the three and nine months ended September 30, 2005, respectively.

(b)		Includes $1.9 million and $2.6 million of net periodic costs recorded in discontinued operations for the three and nine months ended September 30, 2005, respectively.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

NOTE 8: REGULATORY ASSETS AND LIABILITIES

Monongahela’s electric generation and T&D operations are subject to the provisions of Statement of Financial Accounting Standard No. 71Accounting for the Effects of Certain Price Regulation(“SFAS No. 71”). Regulatory assets represent probable future revenues associated with deferred costs that are expected to be recovered from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. Regulatory assets and regulatory liabilities reflected in the Consolidated Balance Sheets at September 30, 2006 and December 31, 2005 relate to:


	September 30,			December 31,
(In millions)	2006			2005
Regulatory assets, including current portion:
Income taxes	$	77.1		$	77.4
Unamortized loss on reacquired debt		14.6			16.2
Other		8.0			11.9

Subtotal		99.7			105.5

Regulatory liabilities:
Net asset removal costs		240.6			242.1
Other		(0.8	)		0.3

Subtotal		239.8			242.4

Net regulatory liabilities	$	140.1		$	136.9

NOTE 9: OTHER INCOME AND EXPENSES, NET

Other income and expenses, net represents non-operating income and expenses before income taxes and are comprised of the following:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006			2005
Interest income	$	2.8	$	1.1	$	6.9		$	2.6
Equity in earnings of AGC		1.3		1.7		4.3			5.2
Premium services		0.1		—		0.5			0.2
Gain on sale of assets		—		—		0.1			—
Other		0.4		0.1		0.6			0.6

Total	$	4.6	$	2.9	$	12.4	��	$	8.6

NOTE 10: COMMITMENTS AND CONTINGENCIES

Environmental Matters and Litigation

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

Allegheny’s compliance with the Clean Air Act of 1970 (the “Clean Air Act”) has required, and may require in the future, that Allegheny install post-combustion control technologies on many of its generation facilities. The Clean Air Interstate Rule (“CAIR”) promulgated by the U.S. Environmental Protection Agency (the “EPA”) on March 10, 2005 may accelerate the need to install this equipment by phasing out a portion of currently available allowances.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

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. At this time, AE is engaged in discussions with the EPA with respect to environmental matters, including NSR issues. 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. There are four recent, significant federal court decisions that have addressed the application of NSR requirements to electric utility generation facilities: the Ohio Edison decision, the Duke Energy decision, the Alabama Power decision and the Cinergy decision. The Ohio Edison and Cinergy decisions are favorable to the EPA. The Duke Energy and Alabama Power decisions support the industry’s understanding of NSR requirements. The U.S. Court of Appeals for the Fourth Circuit affirmed the Duke Energy decision on June 15, 2005. On May 15, 2006, the U.S. Supreme Court agreed to hear an appeal of the Fourth Circuit’s decision in the Duke Energy case. Oral argument took place on November 1, 2006, and a decision is expected by the summer of 2007. The Supreme Court’s decision may provide clarity on whether the industry’s or the government’s interpretation of NSR regulations will prevail.

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

In 2003, the EPA issued the Equipment Replacement Rule, which sets forth a clearer set of rules for projects that may be undertaken without triggering NSR requirements. This rule would apply the Routine Maintenance, Repair and Replacement (“RMRR”) exception to the NSR requirement in a manner that is more consistent with the energy industry’s historical compliance approach. That rule was challenged by some states and environmental groups and, on December 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit issued an order to stay the implementation of that rule. On March 17, 2006, the Court issued a final decision declaring the rule unauthorized under the Clean Air Act. NSR requirements will continue to be interpreted under the pre-rule regulations and case law. Allegheny had established an NSR review process under the original regulatory program and does not expect the March 2006 appellate court decision in this matter to have any significant impact on its operations.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

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

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

of the responsible parties will not exceed $20.0 million. Allegheny has an accrued liability representing its estimated share of the remediation costs as of September 30, 2006.

ALLEGHENY GENERATING COMPANY

STATEMENTS OF OPERATIONS

(unaudited)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In thousands)	2006		2005		2006		2005
Operating revenues	$	16,858	$	17,358	$	48,097	$	50,941

Operating expenses:
Operations and maintenance		1,357		1,152		3,919		3,358
Depreciation		4,279		4,338		12,854		12,884
Taxes other than income taxes		798		737		2,395		2,211

Total operating expenses		6,434		6,227		19,168		18,453

Operating income		10,424		11,131		28,929		32,488

Other income and expenses, net		98		58		844		187

Interest expense		1,792		1,795		5,390		5,598

Income before income taxes		8,730		9,394		24,383		27,077

Income tax expense		2,800		1,985		5,572		4,547

Net income	$	5,930	$	7,409	$	18,811	$	22,530

See accompanying Notes to Financial Statements.

ALLEGHENY GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(unaudited)


	Nine Months Ended
	September 30,
(In thousands)	2006			2005
Cash Flows From Operating Activities:
Net income	$	18,811		$	22,530

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		12,854			12,884
Deferred income taxes and investment tax credit, net		(5,285	)		(5,329	)
Other, net		214			214

Changes in certain assets and liabilities:
Materials and supplies		(115	)		(157	)
Taxes receivable/accrued, net		2,871			1,015
Prepayments		210			249
Other current assets		11			(5	)
Accounts payable		(2,633	)		(21	)
Accounts payable to affiliates, net		206			473
Accrued interest		(1,719	)		(1,719	)
Other current liabilities		524			395
Other assets		—			(1	)
Other liabilities		2			2

Net cash provided by operating activities		25,951			30,530

Cash Flows From Investing Activities:
Capital expenditures		(3,382	)		(6,504	)

Cash Flows From Financing Activities:
Note payable to parent		—			(15,000	)
Cash dividends paid on common stock		(23,000	)		(16,200	)

Net cash used in financing activities		(23,000	)		(31,200	)

Net decrease in cash and cash equivalents		(431	)		(7,174	)
Cash and cash equivalents at beginning of period		1,858			7,500

Cash and cash equivalents at end of period	$	1,427		$	326

Supplemental Cash Flow Information:
Cash paid for interest	$	6,894		$	7,102

See accompanying Notes to Financial Statements.

ALLEGHENY GENERATING COMPANY
BALANCE SHEETS
(unaudited)


	September 30,			December 31,
(In thousands)	2006			2005
ASSETS

Current Assets:
Cash and cash equivalents	$	1,427		$	1,858
Materials and supplies		1,666			1,551
Taxes receivable		974			3,004
Other		4			225

Total current assets		4,071			6,638

Property, Plant and Equipment, Net:
Generation		782,195			788,952
Transmission		48,510			47,098
Other		2,949			2,960
Accumulated depreciation		(318,854	)		(316,250	)

Subtotal		514,800			522,760
Construction work in progress		10,859			12,372

Total property, plant and equipment, net		525,659			535,132

Deferred Charges:
Regulatory assets		8,109			8,295
Other		94			97

Total deferred charges		8,203			8,392

Total Assets	$	537,933		$	550,162

See accompanying Notes to Financial Statements.

ALLEGHENY GENERATING COMPANY
BALANCE SHEETS (continued)
(unaudited)


	September 30,		December 31,
(In thousands, except share amounts)	2006		2005
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Accounts payable	$	55	$	2,687
Accounts payable to affiliates, net		4,902		4,696
Accrued taxes		841		—
Accrued interest		573		2,292
Other		523		—

Total current liabilities		6,894		9,675


Long-term Debt (Note 2)		99,450		99,425

Deferred Credits and Other Liabilities:
Investment tax credit		36,283		37,273
Non-current income taxes payable		17,545		17,544
Deferred income taxes		149,926		153,630
Regulatory liabilities		22,214		22,806

Total deferred credits and other liabilities		225,968		231,253

Commitments and Contingencies (Note 4)

Stockholders’ Equity:

Common stock, $1.00 par value, 5,000 shares authorized and 1,000 shares outstanding		1		1
Other paid-in capital		172,669		172,669
Retained earnings		32,951		37,139

Total stockholders’ equity		205,621		209,809

Total Liabilities and Stockholders’ Equity	$	537,933	$	550,162

See accompanying Notes to Financial Statements.

ALLEGHENY GENERATING COMPANY
STATEMENT OF STOCKHOLDERS’ EQUITY
(unaudited)


					Other					Total
	Shares		Common		paid-in		Retained			stockholders’
(In thousands, except shares)	outstanding		stock		capital		earnings			equity
Balance at January 1, 2006		1,000	$	1	$	172,669	$	37,139		$	209,809
Net income		—		—		—		18,811			18,811
Dividends declared on common stock		—		—		—		(23,000	)		(23,000	)
Other		—		—		—		1			1

Balance at September 30, 2006		1,000	$	1	$	172,669	$	32,951		$	205,621

See accompanying Notes to Financial Statements.

ALLEGHENY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
(unaudited)


Note No.		Page No.
1	Basis of Presentation		59

2	Debt		59

3	Intangible Assets		60

4	Commitments and Contingencies		60

ALLEGHENY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
(unaudited)

NOTE 1: BASIS OF PRESENTATION

Allegheny Energy Supply Company, LLC (“AE Supply”) and Monongahela Power Company (“Monongahela” and together with AE Supply, the “Parents”), own 100% of Allegheny Generating Company (“AGC”). AE Supply owns approximately 77% and Monongahela owns approximately 23% of AGC. AGC owns an undivided 40% interest (1,035 megawatts (“MWs”)) in the 2,586 MW pumped storage, hydroelectric station in Bath County, Virginia, which is operated by the 60% owner, Virginia Electric and Power Company, a nonaffiliated utility. AGC sells its generation capacity to its Parents. AGC operates under a single business segment, Generation and Marketing.

AGC is subject to regulation by the Securities and Exchange Commission (“SEC”), the Virginia State Corporation Commission and the Federal Energy Regulatory Commission.

Allegheny Energy Service Corporation is a wholly owned subsidiary of AE that employs substantially all of the people who are employed by Allegheny.

The accompanying unaudited interim financial statements of AGC should be read in conjunction with the Combined Annual Report on the combined 2005 Form 10-K of AE, Monongahela, Potomac Edison and AGC for the year ended December 31, 2005.

These unaudited interim financial statements have been prepared by AGC, without audit, pursuant to the rules and regulations of the SEC. Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States of America have been condensed or omitted. These financial statements reflect all normal recurring adjustments that are necessary for a fair statement of the results of operations for the three and nine months ended September 30, 2006 and 2005, cash flows for the nine months ended September 30, 2006 and 2005, and financial position at September 30, 2006.

Federal and State Income Taxes. Allegheny allocates income tax expense (benefit) to its subsidiaries pursuant to its consolidated tax sharing agreement. This corporate allocation may cause significant fluctuations in the effective quarterly and year-to-date tax rates from the statutory rates for certain of Allegheny’s subsidiaries, depending on the level of pre-tax income. Consolidated income tax expense (benefit) differs from an amount calculated at the federal statutory income tax rate of 35%, principally due to state income taxes, tax credits and the effects of utility rate making and certain non-deductible expenses.

Recent Accounting Pronouncements. In September 2006, the SEC issued Staff Accounting Bulletin No. 108,Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements(“SAB No. 108”), which expresses SEC staff views regarding the process by which misstatements in financial statements are evaluated for purposes of determining whether financial statement restatement is necessary. SAB No. 108 is effective for AGC for its December 31, 2006 annual financial statements. Management does not believe that the adoption of SAB No. 108 will have a material impact on AGC’s financial statements.

NOTE 2: DEBT

As of September 30, 2006, AGC’s $100 million long-term debt balance, excluding unamortized debt discounts of $0.5 million, consisted of debentures that mature after 2010.

AGC did not issue or redeem any debt during the three or nine months ended September 30, 2006.

ALLEGHENY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
(unaudited)

NOTE 3: INTANGIBLE ASSETS

Intangible assets included in “Property, Plant and Equipment, Net” on the Consolidated Balance Sheets were as follows:


	September 30, 2006				December 31, 2005
	Gross Carrying		Accumulated		Gross Carrying		Accumulated
(In millions)	Amount		Amortization		Amount		Amortization
Land easements, amortized	$	1.4	$	0.8	$	1.5	$	0.8
Software		0.2		0.1		0.2		0.1

Total	$	1.6	$	0.9	$	1.7	$	0.9

Annual amortization expense for intangible assets at September 30, 2006 is not expected to be material for 2006 through 2010.

NOTE 4: COMMITMENTS AND CONTINGENCIES

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

The following discussion and analysis should be read in conjunction with the Financial Statements and Notes to Financial Statements included in this report, as well as the Financial Statements and Supplementary Data and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2005 Annual Report on Form 10-K of AE, Monongahela, Potomac Edison and AGC for the year ended December 31, 2005 (the “2005 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;

	•		regulatory matters; and

	•		asset sales and transfers.

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;

	•		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 the risk profile of the registrants is provided under the caption Item 1A, “Risk Factors,” in the 2005 Annual Report on Form 10-K.

ALLEGHENY 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 2005 Annual Report on Form 10-K.

Key Indicators and Performance Factors

The Delivery and Services Segment

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

Revenue per Megawatt-hour (“MWh”) sold. This measure is calculated by dividing total revenues from retail sales of electricity by total MWhs sold to retail customers.

Revenue per MWh sold during the three and nine months ended September 30, 2006 and 2005 was as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
Revenue per MWh sold	$	59.01	$	55.73	$	58.78	$	55.39

The following table provides retail electricity sales information:


	Three Months Ended							Nine Months Ended
	September 30,							September 30,
	2006		2005		Change			2006		2005		Change
Delivery and Services:
Retail electricity sales (million Kilowatt-hour (“kWhs”))		11,026		12,247		(10.0	)%		32,257		36,117		(10.7	)%

HDD (a)		113		23		391.3	%		3,069		3,337		(8.0	)%
CDD (a)		606		799		(24.2	)%		778		1,065		(26.9	)%


(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 but represent only one of several factors that impact the volume of electricity. 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. Normal (historical) HDDs are 97 and 3,594 for the three and nine months ended September 30, respectively, and normal (historical) CDDs are 561 and 767 for the three and nine months ended September 30, calculated on a load weighted-average basis across the geographic areas served by the Distribution Companies.

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:

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 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. This design characteristic enables these units to be larger and more efficient than other generation units. Allegheny’s Fort Martin, Harrison, Hatfield’s Ferry and Pleasants generation facilities contain supercritical units. These units generally operate at high capacity for extended periods of time.

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

The following table shows EAFs for supercritical units and EAFs and kWhs generated for all generating units, excluding kWhs associated with pumping at the Bath County, Virginia hydroelectric facility:


	Three Months Ended									Nine Months Ended
	September 30,									September 30,
	2006			2005			Change			2006			2005			Change
Supercritical Units:
EAF		89.6	%		89.4	%		0.2	%		86.2	%		85.3	%		0.9	%
All Generation Units:
EAF		91.9	%		90.0	%		1.9	%		88.8	%		88.3	%		0.5	%
kWhs generated (in millions)		12,798			13,188			(3.0	)%		37,048			36,574			1.3	%

ALLEGHENY ENERGY, INC.—CONSOLIDATED RESULTS OF OPERATIONS

Income (Loss) Summary


	Three Months Ended												Three Months Ended
	September 30, 2006												September 30, 2005
	Delivery			Generation									Delivery			Generation
	and			and									and			and
(In millions)	Services			Marketing			Eliminations			Total			Services			Marketing			Eliminations			Total
Operating revenues	$	702.2		$	488.6		$	(374.2	)	$	816.6		$	731.0		$	496.4		$	(382.4	)	$	845.0

Fuel consumed in electric generation		—			223.8			—			223.8			—			211.5			—			211.5
Purchased power and transmission		466.2			8.2			(372.4	)		102.0			485.2			18.5			(379.6	)		124.1
Impairment charge on Ohio T&D assets		—			—			—			—			30.5			—			—			30.5
Deferred energy costs, net		(0.2	)		—			—			(0.2	)		(4.2	)		—			—			(4.2	)
Operations and maintenance		84.3			75.4			(1.8	)		157.9			112.1			72.8			(2.8	)		182.1
Depreciation and amortization		37.7			30.6			—			68.3			38.2			38.5			—			76.7
Taxes other than income taxes		33.5			20.2			—			53.7			32.9			20.4			—			53.3

Total operating expenses		621.5			358.2			(374.2	)		605.5			694.7			361.7			(382.4	)		674.0

Operating income		80.7			130.4			—			211.1			36.3			134.7			—			171.0
Other income and expenses, net		5.3			3.4			(0.8	)		7.9			4.7			3.0			(0.4	)		7.3
Interest expense and preferred dividends		20.2			47.0			(0.8	)		66.4			25.0			88.5			(0.4	)		113.1

Income from continuing operations before income taxes and minority interest		65.8			86.8			—			152.6			16.0			49.2			—			65.2
Income tax expense		22.0			18.9			—			40.9			5.3			16.1			—			21.4
Minority interest		—			1.0			—			1.0			—			0.4			—			0.4

Income from continuing operations		43.8			66.9			—			110.7			10.7			32.7			—			43.4
Loss from discontinued operations, net of tax		—			(0.5	)		—			(0.5	)		(6.8	)		(0.9	)		—			(7.7	)

Net income	$	43.8		$	66.4		$	—		$	110.2		$	3.9		$	31.8		$	—		$	35.7


	Nine Months Ended											Nine Months Ended
	September 30, 2006											September 30, 2005
	Delivery		Generation									Delivery			Generation
	and		and									and			and
(In millions)	Services		Marketing			Eliminations			Total			Services			Marketing			Eliminations			Total
Operating revenues	$	2,037.3	$	1,409.8		$	(1,062.6	)	$	2,384.5		$	2,133.6		$	1,317.8		$	(1,137.7	)	$	2,313.7

Fuel consumed in electric generation		—		623.2			—			623.2			—			551.5			—			551.5
Purchased power and transmission		1,328.8		26.6			(1,057.1	)		298.3			1,406.3			61.5			(1,130.6	)		337.2
Gain on sale of OVEC power agreement and shares		—		(6.1	)		—			(6.1	)		—			—			—			—
Impairment charge on Ohio T&D assets		—		—			—			—			30.5			—			—			30.5
Deferred energy costs, net		5.2		—			—			5.2			(4.8	)		—			—			(4.8	)
Operations and maintenance		264.2		266.9			(5.5	)		525.6			296.3			256.4			(7.1	)		545.6
Depreciation and amortization		113.3		91.0			—			204.3			115.3			115.2			—			230.5
Taxes other than income taxes		98.7		60.9			—			159.6			98.9			61.2			—			160.1

Total operating expenses		1,810.2		1,062.5			(1,062.6	)		1,810.1			1,942.5			1,045.8			(1,137.7	)		1,850.6

Operating income		227.1		347.3			—			574.4			191.1			272.0			—			463.1
Other income and expenses, net		16.5		11.5			(2.2	)		25.8			16.9			17.6			(0.7	)		33.8
Interest expense and preferred dividends		62.4		150.6			(2.2	)		210.8			102.0			268.3			(0.6	)		369.7

Income from continuing operations before income taxes and minority interest		181.2		208.2			—			389.4			106.0			21.3			(0.1	)		127.2
Income tax expense		67.7		62.4			—			130.1			28.7			25.9			—			54.6
Minority interest		—		2.4			—			2.4			—			0.9			—			0.9

Income (loss) from continuing operations		113.5		143.4			—			256.9			77.3			(5.5	)		(0.1	)		71.7
Loss from discontinued operations, net of tax		—		(2.2	)		—			(2.2	)		(2.5	)		(9.4	)		0.1			(11.8	)

Net income (loss)	$	113.5	$	141.2		$	—		$	254.7		$	74.8		$	(14.9	)	$	—		$	59.9

ALLEGHENY ENERGY, INC.—CONSOLIDATED RESULTS

Operating Revenues

Operating revenues decreased $28.4 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, primarily due to:

	•		a decrease in average market prices,

	•		the March 2006 assignment of AE Supply’s rights to generation from the Ohio Valley Electric Corporation (“OVEC”) in connection with the December 31, 2004 sale of a portion of AE’s equity interest in OVEC,

	•		decreased revenues associated with the Harrison transformer failure,

	•		the expiration of a third-party transmission capacity contract and

	•		decreased revenues associated with a construction services project that was completed during the second quarter of 2006,

	•		partially offset by the expiration of a PLR contract with one large industrial customer in Maryland in December 2005, which resulted in greater net sales into PJM at market prices,

	•		higher generation rates charged to Pennsylvania customers effective January 1, 2006 as a result of a West Penn settlement with the Pennsylvania Public Utility Commission (the “Pennsylvania PUC”) and

	•		Monongahela’s agreement to provide power to Columbus Southern Power Company (“Columbus Southern”), a subsidiary of American Electric Power that serves Monongahela’s former Ohio service territory as of January 1, 2006, under a fixed price power supply agreement at a higher rate per kWh net of lost transmission and distribution (“T&D”) revenues.

Operating revenues increased $70.8 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to:

	•		the expiration of a PLR contract with one large industrial customer in Maryland in December 2005, which resulted in greater net sales into PJM at market prices,

	•		higher generation rates charged to Pennsylvania customers effective January 1, 2006 as a result of a West Penn settlement with the Pennsylvania PUC,

	•		Monongahela’s agreement to provide power to Columbus Southern as of January 1, 2006 under a fixed price power supply agreement at a higher rate per kWh net of lost T&D revenues and

	•		increased MWhs generated,

	•		partially offset by a decrease in average market prices,

	•		the March 2006 assignment of AE Supply’s rights to generation from OVEC in connection with the December 31, 2004 sale of a portion of AE’s equity interest in OVEC,

	•		decreased revenues associated with the Harrison transformer failure,

	•		the expiration of a third-party transmission capacity contract and

	•		decreased revenues associated with a construction services project that was completed during the second quarter of 2006.

Operating Income

Operating income increased $40.1 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, primarily due to:

	•		a $68.5 million decrease in operating expenses,

	•		partially offset by the $28.4 million decrease in operating revenues discussed above.

Operating expenses decreased as a result of a $22.1 million decrease in purchased power and transmission, a $24.2 million decrease in operations and maintenance expense and a $30.5 million impairment charge recorded during 2005 in connection with the sale of Monongahela’s Ohio T&D assets, partially offset by a $12.3 million increase in fuel consumed in

electric generation. Purchased power and transmission decreased due to the March 2006 assignment of AE Supply’s rights to generation from OVEC in connection with the December 31, 2004 sale of a portion of AE’s equity interest in OVEC, a reduction in contracts that were designated as normal purchase and normal sale and a reduction in power purchases due to the sale of Monongahela’s Ohio T&D assets during 2005. Operations and maintenance expense decreased due to reduced litigation settlement costs, a reduction in accrued site remediation reserves associated with a previously terminated generation project and decreased cost of goods sold and services expenses, primarily due to reductions in equipment procurement and subcontracting costs associated with a construction services project that was completed during the second quarter of 2006. These decreases were partially offset by increased contract work expense due to increased plant outages. Fuel consumed in electric generation increased due to an increase in coal expense resulting primarily from an increase in the average price of coal and increased coal consumed, partially offset by a decrease in natural gas expense due to a decrease in the average price of natural gas and a decrease in the volume of natural gas consumed.

Operating income increased $111.3 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to:

	•		the $70.8 million increase in operating revenues discussed above and

	•		a $40.5 million decrease in operating expenses.

Operating expenses decreased as a result of a $38.9 million decrease in purchased power and transmission expense, a $30.5 million impairment charge recorded during 2005 in connection with the sale of Monongahela’s Ohio T&D assets, a $20.0 million decrease in operations and maintenance expense and a $26.2 million decrease in depreciation and amortization expense, partially offset by a $71.7 million increase in fuel consumed in electric generation. Purchased power and transmission decreased due to the March 2006 assignment of AE Supply’s rights to generation from OVEC, a reduction in contracts that were designated as normal purchase and normal sale, a refund received on certain transmission charges and a reduction in purchases due to the sale of Monongahela’s Ohio T&D assets during 2005. Operations and maintenance expense decreased due to reduced litigation settlement costs, a reduction in accrued site remediation reserves associated with a previously terminated generation project, decreased cost of goods sold and services expenses, primarily due to reductions in equipment procurement and subcontracting costs associated with a construction services project that was completed during the second quarter of 2006, and decreased salaries and wages expense due to a decrease in the number of information technology employees as a result of the outsourcing of this function during 2005. These decreases were partially offset by increased contract work expense due to increased plant outages, Hatfield’s Ferry insurance proceeds received in 2005 and increased outside services expense due to costs associated with the implementation of Allegheny’s information technology initiatives. Depreciation and amortization expense decreased due to the extension of the depreciable lives of Allegheny’s unregulated coal-fired generation facilities, partially offset by increased depreciation resulting from net property plant and equipment additions. Fuel consumed in electric generation increased due to an increase in coal expense resulting from an increase in the average price of coal and increased coal consumed.

Income from Continuing Operations Before Income Taxes and Minority Interest

Income from continuing operations before income taxes and minority interest increased $87.4 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, primarily due to:

	•		the $40.1 million increase in operating income discussed above and

	•		a $46.7 million decrease in interest expense and preferred dividends, primarily due to lower average debt outstanding and the premium and associated costs recorded during 2005 to redeem AE Supply’s outstanding 10.25% and 13% Senior Notes.

Income from continuing operations before income taxes and minority interest increased $262.2 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to:

	•		the $111.3 million increase in operating income discussed above and

	•		a $158.9 million decrease in interest expense and preferred dividends, primarily due to the premium and associated costs recorded during 2005 to redeem AE Supply’s outstanding 10.25% and 13% Senior Notes, costs related to the April 2005 tender offer for AE’s outstanding Trust Preferred Securities, $38.5 million of interest recorded during the first quarter of 2005 related to a court decision in the litigation involving Merrill Lynch and lower average debt outstanding.

Income Tax Expense

The effective tax rates for Allegheny’s continuing operations were 26.7% and 32.2% for the three months ended September 30, 2006 and 2005, respectively, and were 33.3% and 41.7% for the nine months ended September 30, 2006 and 2005, respectively.

The effective tax rates for the three and nine months ended September 30, 2006 were lower than the federal statutory rate, primarily due to a state income tax benefit of $16.7 million as described in Note 1, “Basis of Presentation.”

The effective tax rate for the nine months ended September 30, 2005 was higher than the federal statutory tax rate, primarily due to:

	•		two charges to adjust state deferred and accrued income taxes taken during the three months ended September 30, 2005 in the amounts of $3.8 million and $1.9 million, respectively, as described in Note 1, “Basis of Presentation” and

	•		state income taxes, tax credits, the effects of utility rate making and certain non-deductible expenses.

Discontinued Operations

Allegheny recorded losses from discontinued operations of $0.5 million and $7.7 million for the three months ended September 30, 2006 and 2005, respectively, and $2.2 million and $11.8 million for the nine months ended September 30, 2006 and 2005, respectively.

The $7.2 million decrease in losses from discontinued operations for the three months ended September 30, 2006 compared to the three months ended September 30, 2005 was primarily due to losses associated with Monongahela’s natural gas operations, which were sold on September 30, 2005.

The $9.6 million decrease in losses from discontinued operations for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005 was primarily due to decreased losses associated with Monongahela’s former natural gas operations, which were sold on September 30, 2005, and AE Supply’s Gleason Generating Facility, partially offset by income in 2005 associated with AE Supply’s Wheatland Generating Facility, which was sold on August 12, 2005.

See Note 6, “Discontinued Operations and Assets Held for Sale,” for additional information.

ALLEGHENY ENERGY, INC.—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,
	2006		2005		Change			2006		2005		Change
Retail electricity sales (million kWhs)		11,026		12,247		(10.0	)%		32,257		36,117		(10.7	)%
HDD (a)		113		23		391.3	%		3,069		3,337		(8.0	)%
CDD (a)		606		799		(24.2	)%		778		1,065		(26.9	)%


(a)		Normal (historical) HDDs are 97 and 3,594 for the three and nine months ended September 30, respectively, and normal (historical) CDDs are 561 and 767 for the three and nine months ended September 30, respectively, calculated on a load weighted-average basis across the geographic areas served by the Distribution Companies.

Operating Revenues

Operating revenues were as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Retail electric:
Generation	$	435.5	$	455.8	$	1,266.8	$	1,337.5
Transmission		40.7		44.7		119.9		131.6
Distribution		174.4		182.0		509.3		531.3

Total retail electric		650.6		682.5		1,896.0		2,000.4

Transmission services and bulk power		41.8		29.3		115.7		86.8
Other affiliated and nonaffiliated energy services		9.8		19.2		25.6		46.4

Total operating revenues	$	702.2	$	731.0	$	2,037.3	$	2,133.6

Retail electric revenues decreased $31.9 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, primarily due to:

	•		a $55.9 million decrease in generation revenues as a result of decreased usage due to the expiration of a contract with one large industrial customer in Maryland in December 2005, the sale of Monongahela’s Ohio service territory on December 31, 2005 and milder weather and

	•		an $11.6 million decrease in T&D revenues as a result of decreased customer usage due to milder weather, the loss of one large industrial customer in Maryland and the sale of Monongahela’s Ohio service territory on December 31, 2005,

	•		partially offset by a $35.6 million increase in generation revenues due to higher generation rates charged to Pennsylvania customers, effective January 1, 2006, as a result of a West Penn settlement with the Pennsylvania PUC and an increase in the average generation rates for non-residential customers at Potomac Edison.

Retail electric revenues decreased $104.4 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to:

	•		a $147.8 million decrease in generation revenues as a result of decreased usage due to the expiration of a contract with one large industrial customer in Maryland in December 2005, the sale of Monongahela’s Ohio service territory on December 31, 2005 and milder weather and

	•		a $33.7 million decrease in T&D revenues as a result of decreased customer usage due to milder weather, the loss of one large industrial customer in Maryland and the sale of Monongahela’s Ohio service territory on December 31, 2005,

•

partially offset by a $79.1 million increase in generation revenues due to higher generation rates charged to Pennsylvania customers, effective January 1, 2006, as a result of a West Penn settlement with the Pennsylvania PUC and an increase in the average generation rates for non-residential customers at Potomac Edison.

Transmission services and bulk power revenues increased $12.5 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, primarily due to:

	•		a $20.8 million increase in bulk power revenues related to the fixed price power supply agreement with Columbus Southern to serve Monongahela’s former Ohio service territory as of January 1, 2006,

	•		partially offset by a $7.6 million decrease in transmission revenues related to the expiration of a third-party transmission capacity contract and

	•		a $1.2 million decrease in bulk power revenues resulting from decreased power sales from the AES Warrior Run generation facility due to a contractual reduction in the capacity rate.

Transmission services and bulk power revenues increased $28.9 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to:

	•		a $59.2 million increase in bulk power revenues related to the fixed price power supply agreement with Columbus Southern to serve Monongahela’s former Ohio service territory as of January 1, 2006,

	•		partially offset by a $22.7 million decrease in transmission revenues related to the expiration of a third-party transmission capacity contract and

	•		an $8.7 million decrease in bulk power revenues resulting from decreased power sales from the AES Warrior Run generation facility due to a scheduled outage at that facility during the first quarter of 2006 and a contractual reduction in the capacity rate.

Other affiliated and nonaffiliated energy services revenues decreased by $9.4 million and $20.8 million for the three and nine months ended September 30, 2006, respectively, compared to the three and nine months ended September 30, 2005, primarily due to decreased revenues associated with a construction services project that was completed during the second quarter of 2006.

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 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)	2006		2005		2006		2005
Other purchased power and transmission	$	412.5	$	432.0	$	1,175.9	$	1,250.4
From PURPA generation (a)		53.7		53.2		152.9		155.9

Total purchased power and transmission	$	466.2	$	485.2	$	1,328.8	$	1,406.3


(a) PURPA cost (cents per kWh sold)			5.6				5.5				5.4				5.4

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. The amount of power purchased under certain of these agreements that is subject to the market-based pricing component increases each year through the applicable transition period. In addition, Potomac Edison has a fixed rate power purchase agreement with AE Supply that was awarded on a competitive basis.

Other purchased power and transmission decreased $19.5 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, primarily due to:

	•		a $20.9 million decrease in other purchased power and transmission due to the expiration of a contract with one large industrial customer in Maryland in December 2005,

	•		a $9.7 million decrease in other purchased power and transmission due to the sale of Monongahela’s Ohio electric service territory and

	•		a reduction in other purchased power as a result of milder weather,

	•		partially offset by an $11.7 million increase in other purchased power and transmission, primarily due to a net increase in the price of purchased power from AE Supply for Pennsylvania customers effective January 1, 2006 as a result of a rate increase resulting from a West Penn settlement with the Pennsylvania PUC.

Other purchased power and transmission decreased $74.5 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to:

	•		a $50.9 million decrease in other purchased power and transmission related to the expiration of a contract with one large industrial customer in Maryland in December 2005,

	•		a $41.2 million decrease in other purchased power and transmission due to the sale of Monongahela’s Ohio electric service territory and

	•		a reduction in other purchased power as a result of milder weather,

	•		partially offset by a $35.8 million increase in other purchased power and transmission, primarily due to a net increase in the price of purchased power from AE Supply for Pennsylvania customers, effective January 1, 2006, as a result of a rate increase resulting from a West Penn settlement with the Pennsylvania PUC.

Purchased power and transmission from PURPA generation decreased $3.0 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to decreased power purchased from the AES Warrior Run PURPA generation facility due to a scheduled outage at that facility during the first quarter of 2006 and a decrease in the contractual capacity rate at that facility.

Impairment Charge on Ohio T&D Assets:During the three months ended September 30, 2005, the Delivery and Services segment recorded an impairment charge of $30.5 million in connection with the anticipated sale of Monongahela’s Ohio T&D assets. The impairment charge was recorded based on the estimated value, at September 30, 2005, of Monongahela’s power sales agreement with Columbus Southern to provide power at below-market prices from the time of closing through May 31, 2007, partially offset by approximately $8.0 million, representing the purchase price less the estimated net book value of the assets at the time of closing and approximately $2.0 million in expenses associated with the sale.

Deferred Energy Costs, Net:Deferred energy costs, net were as follows:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2006			2005			2006		2005
Deferred energy costs, net	$	(0.2	)	$	(4.2	)	$	5.2	$	(4.8	)

Deferred energy costs, net, are primarily related to the recovery of net costs associated with purchases from the AES Warrior Run PURPA generation facility and the deferral of market-based generation costs, as described in the following sections under the headings “AES Warrior Run PURPA Generation” and “Market-based Generation Costs.”

AES Warrior Run PURPA Generation

To satisfy certain of its obligations under PURPA, Allegheny, through its subsidiary, Potomac Edison, entered into a long-term contract 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 on Potomac Edison’s Consolidated Balance Sheets as deferred energy costs, pending subsequent recovery from, or return to, customers through adjustments to the AES Warrior Run Surcharge. Because the AES Warrior Run Surcharge represents a dollar-for-dollar recovery of net contract

costs, AES Warrior Run Surcharge revenues or revenues from sales of AES Warrior Run output do not impact Potomac Edison’s net income.

Market-based 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 power provider. An 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 relate 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 increased $4.0 million for the three months ended September 30, 2006 compared with the three months ended September 30, 2005, primarily as a result of $1.9 million in deferred costs related to PURPA and $2.5 million in deferred costs related to market-based generation.

Deferred energy costs, net increased $10.0 million for the nine months ended September 30, 2006 compared with the nine months ended September 30, 2005, primarily as a result of a $4.0 million increase in deferred costs related to PURPA and a $6.3 million increase in deferred costs related to market-based generation.

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Operations and maintenance	$	84.3	$	112.1	$	264.2	$	296.3

Operations and maintenance expenses decreased $27.8 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, primarily due to:

	•		approximately $15 million of reduced litigation settlement costs,

	•		a $9.6 million decrease in equipment procurement and subcontracting costs associated with a construction services project that was completed during the second quarter of 2006 and

	•		a $4.7 million decrease in salaries and wages expenses, primarily due to a decrease in the number of information technology employees as a result of the outsourcing of this function during 2005,

	•		partially offset by a $4.3 million increase due to costs associated with the implementation of Allegheny’s information technology initiatives.

Operations and maintenance expenses decreased $32.1 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to:

	•		approximately $15 million of reduced litigation settlement costs,

	•		an $18.1 million decrease in equipment procurement and subcontracting costs associated with a construction services project that was completed during the second quarter of 2006 and

	•		a $10.1 million decrease in salaries and wages expenses, primarily due to a decrease in the number of information technology employees as a result of the outsourcing of this function during 2005,

	•		partially offset by a $6.9 million increase in outside services expenses, primarily due to costs associated with the implementation of Allegheny’s information technology initiatives.

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Depreciation and amortization	$	37.7	$	38.2	$	113.3	$	115.3

Depreciation and amortization expenses decreased $2.0 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to an increase in the depreciable lives of certain West Penn assets as a result of an annual review of the estimated useful lives of these assets, the sale of Monongahela’s Ohio T&D assets and the retirement of certain software that became fully amortized during 2006.

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)	2006		2005		2006		2005
Interest expense and preferred dividends	$	20.2	$	25.0	$	62.4	$	102.0

Interest expense and preferred dividends decreased $4.8 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, primarily due to lower average debt outstanding.

Interest expense and preferred dividends decreased $39.6 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to:

	•		$21.0 million of costs related to the April 2005 tender offer for AE’s outstanding Trust Preferred Securities and

	•		a $17.0 million decrease in interest expense on long-term debt, primarily due to lower average debt outstanding.

For additional information regarding Allegheny’s short-term and long-term debt, see Note 5, “Debt.”

Discontinued Operations:Losses from discontinued operations were $6.8 million and $2.5 million for the three and nine months ended September 30, 2005, respectively. These amounts were related to Monongahela’s West Virginia natural gas operations, which were sold on September 30, 2005. See Note 6, “Discontinued Operations and Assets Held for Sale,” for additional information.

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,
	2006		2005		Change			2006		2005		Change
Generation (million kWhs)		12,798		13,188		(3.0	)%		37,048		36,574		1.3	%

Operating Revenues

Operating revenues were as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Revenue from affiliates	$	372.4	$	379.6	$	1,057.0	$	1,130.6
Wholesale and other revenues, net (a)		116.2		116.8		352.8		187.2

Total revenues	$	488.6	$	496.4	$	1,409.8	$	1,317.8


(a)		Amounts are net of energy trading gains and losses as described in Note 7, “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 has power sales agreements with Potomac Edison and West Penn under which AE Supply provides Potomac Edison and West Penn with a majority of the power necessary to meet their PLR obligations. These legacy agreements have both fixed-price and market-based pricing components. The amount of power sold under certain of these agreements that is subject to market-based pricing component increases each year through the applicable transition period. In addition, AE Supply has a fixed rate power sales agreement with Potomac Edison that was awarded on a competitive bid basis.

To facilitate the economic dispatch of its generation, Monongahela sells the power that it generates from its West Virginia jurisdictional assets to AE Supply at PJM market prices and purchases from AE Supply, at PJM market prices, the power necessary to meet its West Virginia jurisdictional customer load. AE Supply records energy purchases and capacity sales transactions with Monongahela as either affiliated revenue or affiliated purchased power and transmission expense, depending on energy requirements as determined on an hourly basis.

The average rate at which the Generation and Marketing segment sold power to the Distribution Companies was $35.17 and $32.32 per MWh for the three months ended September 30, 2006 and 2005, respectively, and $34.90 and $32.91 per MWh for the nine months ended September 30, 2006 and 2005, respectively.

Revenue from affiliates decreased $7.2 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, primarily due to:

	•		an $18.8 million decrease in revenue due to the expiration of a contract with one large industrial customer in Maryland in December 2005,

	•		a $4.3 million decrease in revenue related to decreased sales volumes as a result of a decrease in the number of Monongahela’s customers as the result of the sale of its Ohio service territory on December 31, 2005 and the concurrent expiration of a power supply contract between Monongahela and AE Supply and

	•		decreased sales volumes as a result of milder weather, which caused a decrease in electricity demand by the Delivery and Services segment,

	•		partially offset by an $18.1 million increase in affiliated revenues related to higher generation rates charged to Pennsylvania customers, effective January 1, 2006, as a result of a West Penn settlement with the Pennsylvania PUC and

	•		a $6.6 million increase in revenue related to increased contractual rates with decreased sales volumes from certain of Potomac Edison’s customers in Maryland.

Revenue from affiliates decreased $73.6 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to:

	•		a $55.2 million decrease in revenue related to the expiration of a contract with one large industrial customer in Maryland in December 2005,

	•		a $27.0 million decrease in revenue related to decreased sales volumes from certain of Potomac Edison’s customers in Maryland,

	•		an $11.3 million decrease in revenue related to decreased sales volumes as a result of Monongahela no longer serving customers in its former Ohio service territory, which was sold on December 31, 2005, and the concurrent expiration of a power supply contract between Monongahela and AE Supply and

	•		decreased sales volumes as a result of milder weather, which caused a decrease in electricity demand by the Delivery and Services segment,

	•		partially offset by a $51.0 million increase in affiliated revenues related to higher generation rates charged to Pennsylvania customers, effective January 1, 2006, as a result of a West Penn settlement with the Pennsylvania PUC.

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)	2006			2005 (a)			2006			2005 (a)
PJM Revenue:
Generation sold to PJM	$	550.5		$	792.4		$	1,601.2		$	1,807.2
Power purchased from PJM		(429.2	)		(672.3	)		(1,261.2	)		(1,626.4	)

Net		121.3			120.1			340.0			180.8

Release of escrow proceeds		—			2.7			—			2.7

Cash flow hedges and trading activities:
Realized losses		(14.1	)		(11.1	)		(18.7	)		(17.8	)
Unrealized gains		8.5			4.9			26.8			18.2

Net		(5.6	)		(6.2	)		8.1			0.4

Other revenues		0.5			0.2			4.7			3.3

Total wholesale and other revenues	$	116.2		$	116.8		$	352.8		$	187.2


(a)		Certain prior period amounts were reclassified from other revenues to power purchased from PJM to conform to the presentation for the current period.

Wholesale and other revenues decreased $0.6 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, primarily due to:

	•		a $2.7 million decrease related to the release of escrow proceeds during the third quarter of 2005 due to the resolution of a guarantee,

	•		partially offset by a $0.6 million decrease in net losses on cash flow hedges and trading revenues, primarily related to the settlement of cash flow hedges, losses on mark-to-market purchase contracts and a reduction in contracts that were designated as normal purchase and normal sale during 2006 and

	•		an increase in net PJM revenues of $1.2 million.

The increase in net PJM revenues was due to lower power purchased from PJM, partially offset by a decrease in revenues from generation sold to PJM. Revenues from generation sold to PJM were lower primarily due to a decrease in the market price of power, the March 2006 assignment of rights to generation from OVEC in connection with the December 31, 2004 sale of a portion of AE’s equity interest in OVEC and an unplanned outage at the Harrison power station, partially offset by an increase in MWhs generated by other power stations. Power purchased from PJM decreased due to a decrease in the market price of power and milder weather. In addition, power purchased from PJM decreased due to the expiration in December 2005 of a contract between Potomac Edison and one large industrial customer in Maryland that is no longer required to be served by AE Supply and reduced power needs because Monongahela is no longer serving customers in its former Ohio service territory, which was sold on December 31, 2005.

Wholesale and other revenues increased $165.6 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to:

	•		an increase in net PJM revenues of $159.2 million and

	•		a $7.7 million increase in net gains on cash flow hedges and trading revenues, primarily related to the settlement of cash flow hedges, partially offset by losses on mark-to-market purchase contracts and a reduction in contracts that were designated as normal purchase and normal sale during 2006,

	•		partially offset by a $2.7 million decrease related to the release of escrow proceeds during the third quarter of 2005 due to the resolution of a guarantee.

The increase in net PJM revenues is due to lower purchased power from PJM, partially offset by a decrease in revenues from generation sold to PJM. Revenues from generation sold to PJM were lower primarily due to a decrease in the market price of power and the March 2006 assignment of rights to generation from OVEC in connection with the December 31, 2004 sale of a portion of AE’s equity interest in OVEC, partially offset by an increase in MWhs generated. The increase in MWhs generated was due to increased availability of Allegheny’s supercritical plants. Power purchased from PJM decreased due to a decrease in the market price of power and milder weather. In addition, power purchased from PJM decreased due to the expiration in December 2005 of a contract between Potomac Edison and one large industrial customer in Maryland that is no longer required to be served by AE Supply, a decrease in sales volume related to certain Potomac Edison customers in Maryland and reduced power needs because Monongahela is no longer serving customers in its former Ohio service territory, which was sold on December 31, 2005.

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 on 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, 2006. Changes in the fair value of the commodity cash flow hedges are reflected in other comprehensive income.

At September 30, 2006, the fair values of derivative contract assets and liabilities were $2.6 million and $32.3 million, respectively. At December 31, 2005, the fair values of derivative contract assets and liabilities were $9.3 million and $115.9 million, respectively.

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, 2006
	Settlement by:
Classification of contracts																Settlement
by source of fair																In Excess of
value (In millions)	2006			2007			2008			2009			2010			Five Years			Total
Prices actively quoted	$	(7.7	)	$	(4.9	)	$	(5.7	)	$	(5.4	)	$	(5.1	)	$	(1.6	)	$	(30.4	)
Prices provided by other external sources		0.3			—			—			—			—			—			0.3
Prices based on models		0.4			—			—			—			—			—			0.4

Total	$	(7.0	)	$	(4.9	)	$	(5.7	)	$	(5.4	)	$	(5.1	)	$	(1.6	)	$	(29.7	)

The fair value of AE Supply’s contracts that are scheduled to settle by December 31, 2006 was a net liability of $7.0 million, primarily related to interest rate swaps and commodity cash flow hedges. The fair value of AE Supply’s contracts scheduled to settle during 2007 and future years are primarily related to interest rate swaps.

See Note 7, “Derivative Instruments and Hedging Activities,” for additional information.

Changes in Fair Value:Net unrealized gains of $8.5 million and $26.8 million for the three and nine months ended September 30, 2006, 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, 2006			September 30, 2006
Net fair value of contract liabilities at July 1 and January 1, respectively	$	(48.0	)	$	(106.6	)
Changes in fair value of cash flow hedges		9.8			48.7
Unrealized gains on contracts, net		8.5			26.8
Net options paid (a)		—			1.4

Net fair value of contract liabilities at September 30	$	(29.7	)	$	(29.7	)


(a)		Amount reflects $1.0 million of option premium expirations for the nine months ended September 30, 2006.

As shown in the table above, the net fair value of Allegheny’s derivative contracts increased by $18.3 million and $76.9 million during the three and nine months ended September 30, 2006, respectively. The increase in the fair values was primarily due to changes in the fair values of commodity contracts and settlements on interest rate and cash flow commodity contracts.

There has been, and may continue to be, significant volatility in the market prices for electricity at the wholesale level, which will affect Allegheny’s operating results and cash flows. Similarly, volatility in interest rates will affect Allegheny’s operating results and cash flows.

Operating Expenses

Fuel Consumed in Electric Generation:Fuel consumed in electric generation represents the cost of coal, natural gas, oil, lime and other materials consumed in the generation of power and emission allowances. Fuel consumed in electric generation was as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Fuel consumed in electric generation	$	223.8	$	211.5	$	623.2	$	551.5

Total fuel consumed in electric generation increased by $12.3 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, primarily due to a $16.7 million increase in coal expense and a $3.4 million increase in emission expense, partially offset by an $8.0 million decrease in natural gas expense. The increase in coal expense was due to an increase in the price of coal of $2.68 per ton and a 0.1 million-ton increase in the amount of coal burned. The increase in the amount of coal burned was primarily due to an increase in the use of lower British Thermal Unit (“BTU”) Powder River Basin coal partially offset by a decrease in total MWhs generated. The increase in emission expense was due to Allegheny purchasing NO_X emission allowances in excess of granted and banked allowances. The decrease in natural gas expense was due to a decrease in the price of natural gas of $1.82 per decatherm (“DT”) and a 0.4 million DT decrease in the amount of natural gas burned.

Total fuel consumed in electric generation increased by $71.7 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to a $77.9 million increase in coal expense. The increase in coal expense was due to an increase in the price of coal of $3.24 per ton and a 0.9 million-ton increase in the amount of coal burned. The increase in the amount of coal burned was primarily due to an increase in the use of lower BTU Powder River Basin coal and a 1.3% increase in total MWhs generated.

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


	Three Months Ended				Nine months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Purchased power and transmission expenses	$	8.2	$	18.5	$	26.6	$	61.5

Purchased power and transmission expenses decreased $10.3 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, primarily due to the March 2006 assignment of AE Supply’s rights to generation from OVEC in connection with the December 31, 2004 sale of a portion of AE’s equity interest in OVEC.

Purchased power and transmission expenses decreased $34.9 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to the March 2006 assignment of AE Supply’s rights to generation from OVEC in connection with the December 31, 2004 sale of a portion of AE’s equity interest in OVEC, a reduction in contracts that were designated as normal purchase and normal sale and a refund received on certain transmission charges.

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


	Three Months Ended				Nine months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Operations and maintenance	$	75.4	$	72.8	$	266.9	$	256.4

Operations and maintenance expenses increased $2.6 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, primarily due to:

	•		a $12.5 million increase in contract work expense, primarily due to insurance proceeds received during 2005 related to Hatfield’s Ferry Unit No. 2, which were recorded as an offset to contract work expense,

	•		partially offset by an $8.1 million reduction in accrued site remediation reserves associated with a previously terminated generation project and

	•		a $1.6 million decrease in materials and supplies expense, primarily due to decreased maintenance expenditures.

Operations and maintenance expenses increased $10.5 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to:

	•		a $25.8 million increase in contract work expense, primarily due to insurance proceeds received during 2005 related to Hatfield’s Ferry Unit No. 2, which were recorded as an offset to contract work expense and

	•		a $6.6 million increase in outside service expense, primarily due to costs associated with the implementation of Allegheny’s information technology initiatives,

	•		partially offset by a $17.2 million decrease in other operation and maintenance expense, primarily due to $6.4 million reversal of a guarantee liability associated with the Hunlock Creek Energy Ventures (“HCEV”) partnership and an $8.1 million reduction in accrued site remediation reserves associated with a previously terminated generation project and

	•		a $1.6 million decrease in salaries and wages expense due to a decrease in the number of information technology employees as a result of the outsourcing of this function during 2005.

See Note 17, “Guarantees and Letters of Credit” and Note 19, “HCEV Partnership Interest,” for additional information related to the HCEV partnership interest transaction.

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Depreciation and amortization	$	30.6	$	38.5	$	91.0	$	115.2

Depreciation and amortization expense decreased $7.9 million and $24.2 million for the three and nine months ended September 30, 2006, respectively, compared to the three and nine months ended September 30, 2005, primarily due to the extension of the depreciable lives of Allegheny’s unregulated coal-fired generation facilities, partially offset by increased depreciation resulting from net property, plant and equipment additions. The extension of the depreciable lives of Allegheny’s unregulated coal-fired generation facilities is discussed further at Note 4, “Review of Estimated Remaining Service Lives and Depreciation Practices,” to the Consolidated Financial Statements.

Other Income and Expenses, Net:Other income and expenses, net represent non-operating income and expenses before income taxes. Other income and expenses, net, were as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Other income and expenses, net	$	3.4	$	3.0	$	11.5	$	17.6

Other income and expenses, net decreased $6.1 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily as a result of $11.2 million in cash received from a former trading executive’s forfeited assets during 2005, partially offset by a $5.4 million increase in interest income on investments due to higher interest rates.

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)	2006		2005		2006		2005
Interest expense and preferred dividends	$	47.0	$	88.5	$	150.6	$	268.3

Interest expense and preferred dividends decreased $41.5 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, primarily due to lower average debt outstanding and $32.6 million recorded during 2005 to reflect the premium and associated costs to redeem AE Supply’s outstanding 10.25% and 13% Senior Notes.

Interest expense and preferred dividends decreased $117.7 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to:

	•		$32.6 million recorded during 2005 to reflect the premium and associated costs to redeem AE Supply’s outstanding 10.25% and 13% Senior Notes,

	•		$26.2 million in costs related to the April 2005 tender offer for AE’s outstanding Trust Preferred Securities,

	•		$38.5 million in interest expense recorded during the first quarter of 2005 related to a court decision in the litigation involving Merrill Lynch and

	•		a $16.1 million decrease in interest expense on long-term debt, primarily due to lower average debt outstanding.

For additional information regarding Allegheny’s long-term debt, see Note 5, “Debt.” For additional information regarding the litigation involving Merrill Lynch, see Note 20, “Commitments and Contingencies.”

Minority Interest:Minority interest, which primarily represents equity interest in AE Supply, was $1.0 million and $0.4 million for the three months ended September 30, 2006 and 2005, respectively, and $2.4 million and $0.9 million for the nine months ended September 30, 2006 and 2005, respectively.

Discontinued Operations:Losses from discontinued operations were as follows:


	Three Months Ended				Nine months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Loss from discontinued operations	$	0.5	$	0.9	$	2.2	$	9.4

Loss from discontinued operations decreased $7.2 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to decreased losses associated with AE Supply’s Gleason Generating Facility, partially offset by income in 2005 associated with AE Supply’s Wheatland Generating Facility, which was sold on August 12, 2005.

See Note 6, “Discontinued Operations and Assets Held for Sale,” for additional information.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES—CONSOLIDATED RESULTS OF OPERATIONS

Income (Loss) Summary


	Three Months Ended												Three Months Ended
	September 30, 2006												September 30, 2005
	Delivery			Generation									Delivery			Generation
	and			and									and			and
(In millions)	Services			Marketing			Eliminations			Total			Services			Marketing		Eliminations			Total
Operating revenues	$	173.7		$	118.2		$	(78.0	)	$	213.9		$	176.6		$	123.5	$	(79.6	)	$	220.5

Fuel consumed in electric generation		—			45.3			—			45.3			—			41.8		—			41.8
Purchased power and transmission		109.4			39.8			(78.0	)		71.2			119.3			36.4		(79.6	)		76.1
Impairment charge on Ohio T&D assets		—			—			—			—			30.5			—		—			30.5
Deferred energy costs, net		(0.6	)		—			—			(0.6	)		—			—		—			—
Operations and maintenance		23.7			17.5			—			41.2			27.5			17.8		—			45.3
Depreciation and amortization		7.7			8.7			—			16.4			7.9			8.7		—			16.6
Taxes other than income taxes		6.1			5.2			—			11.3			6.1			5.9		—			12.0

Total operating expenses		146.3			116.5			(78.0	)		184.8			191.3			110.6		(79.6	)		222.3

Operating income (loss)		27.4			1.7			—			29.1			(14.7	)		12.9		—			(1.8	)
Other income and expenses, net		2.0			2.6			—			4.6			0.9			2.0		—			2.9
Interest expense		6.4			4.5			—			10.9			6.2			4.6		—			10.8

Income (loss) from continuing operations before income taxes		23.0			(0.2	)		—			22.8			(20.0	)		10.3		—			(9.7	)
Income tax expense (benefit)		8.1			1.0			—			9.1			(6.2	)		1.9		—			(4.3	)

Income (loss) from continuing operations		14.9			(1.2	)		—			13.7			(13.8	)		8.4		—			(5.4	)
Loss from discontinued operations, net of tax		—			—			—			—			(6.8	)		—		—			(6.8	)

Net income (loss)	$	14.9		$	(1.2	)	$	—		$	13.7		$	(20.6	)	$	8.4	$	—		$	(12.2	)


	Nine Months Ended												Nine Months Ended
	September 30, 2006												September 30, 2005
	Delivery			Generation									Delivery			Generation
	and			and									and			and
(In millions)	Services			Marketing			Eliminations			Total			Services			Marketing			Eliminations			Total
Operating revenues	$	504.5		$	309.6		$	(225.6	)	$	588.5		$	515.6		$	306.2		$	(236.6	)	$	585.2
Fuel consumed in electric generation		—			129.9			—			129.9			—			110.1			—			110.1
Purchased power and transmission		306.5			74.1			(225.6	)		155.0			340.6			85.6			(236.6	)		189.6
Impairment charge on Ohio T&D assets		—			—			—			—			30.5			—			—			30.5
Deferred energy costs, net		(1.2	)		—			—			(1.2	)		—			—			—			—
Operations and maintenance		73.9			58.0			—			131.9			84.4			57.0			—			141.4
Depreciation and amortization		22.8			26.3			—			49.1			24.0			26.1			—			50.1
Taxes other than income taxes		18.4			17.0			—			35.4			19.7			17.7						37.4

Total operating expenses		420.4			305.3			(225.6	)		500.1			499.2			296.5			(236.6	)		559.1

Operating income		84.1			4.3			—			88.4			16.4			9.7			—			26.1
Other income and expenses, net		5.0			7.4			—			12.4			2.5			6.1			—			8.6
Interest expense		18.6			13.6			—			32.2			18.5			13.7			—			32.2

Income (loss) from continuing operations before income taxes		70.5			(1.9	)		—			68.6			0.4			2.1			—			2.5
Income tax expense (benefit)		27.2			(0.9	)		—			26.3			(5.3	)		(7.2	)		—			(12.5	)

Income (loss) from continuing operations		43.3			(1.0	)		—			42.3			5.7			9.3			—			15.0
Loss from discontinued operations, net of tax		—			—			—			—			(2.4	)		—			—			(2.4	)

Net income (loss)	$	43.3		$	(1.0	)	$	—		$	42.3		$	3.3		$	9.3		$	—		$	12.6

MONONGAHELA POWER COMPANY—CONSOLIDATED RESULTS

This section is an overview of Monongahela’s consolidated results of operations, which are discussed in greater detail by segment in “Monongahela Power Company—Discussion of Segment Results of Operations” below.

Operating Revenues

Operating revenues decreased $6.6 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, primarily due to:

	•		decreased revenues as a result of the Harrison transformer failure and

	•		decreased retail revenue resulting from milder weather,

	•		partially offset by increased revenues related to Monongahela’s agreement to provide power to Columbus Southern, a subsidiary of American Electric Power that serves Monongahela’s former Ohio service territory as of January 1, 2006, under a fixed price power supply agreement at a higher rate per kWh, net of lost T&D revenues.

Operating revenues increased $3.3 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to:

	•		increased generation revenue from sales as a result of additional MWhs generated and

	•		increased revenues related to Monongahela’s agreement to provide power to Columbus Southern under a fixed price power supply agreement at a higher rate per kWh, net of lost T&D revenues,

	•		partially offset by decreased retail revenue resulting from milder weather.

Operating Income

Operating income increased $30.9 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, due to:

	•		a $37.5 million decrease in operating expenses, primarily due to a $30.5 million impairment charge on Ohio T&D assets that was recorded in the third quarter of 2005,

	•		partially offset by a $6.6 million decrease in operating revenues discussed above.

Operating income increased $62.3 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, due to:

	•		a $59.0 million decrease in operating expenses and

	•		a $3.3 million increase in total operating revenues discussed above.

The decrease in total operating expenses was primarily due to a $34.6 million decrease in purchased power and transmission expenses, primarily as a result of reduced rates on purchased power related to a fixed price power supply agreement to provide power to Columbus Southern to serve Monongahela’s former Ohio service territory and a $30.5 million impairment charge on Ohio T&D assets that was recorded in the third quarter of 2005.

Income (Loss) from Continuing Operations Before Income Taxes

Income (loss) from continuing operations before income taxes increased $32.5 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, primarily due to a $30.9 million increase in operating income, as discussed above.

Income (loss) from continuing operations before income taxes increased $66.1 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to a $62.3 million increase in operating income, as discussed above.

Income Tax Expense

The effective tax rates for Monongahela’s continuing operations were 39.8% and 44.6% for the three months ended September 30, 2006 and 2005, respectively, and 38.4% and (497.6)% for the nine months ended September 30, 2006 and 2005, respectively.

The effective tax rate for the nine months ended September 30, 2005 was lower than the federal statutory tax rate, primarily due to the allocation of consolidated tax savings and a tax benefit relating to the amendment of 2003 income tax returns. See Note 1, “Basis of Presentation,” for additional information.

Discontinued Operations

Monongahela recorded losses from discontinued operations of $6.8 million and $2.4 million for the three and nine months ended September 30, 2005, respectively, relating to Monongahela’s West Virginia natural gas operations, which were sold on September 30, 2005.

See Note 3, “Discontinued Operations,” for additional information.

MONONGAHELA POWER COMPANY—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,
	2006		2005		Change			2006		2005		Change
Retail electricity sales (million kWhs)		2,663		3,125		(14.8	)%		7,717		9,196		(16.1	)%

HDD (a)		107		13		723.1	%		2,706		2,896		(6.6	)%
CDD (a)		598		904		(33.8	)%		776		1,203		(35.5	)%


(a)		Normal (historical) HDD are 81 and 3,509 for the three and nine months ended September 30, respectively, and normal (historical) CDD are 540 and 733 for the three and nine months ended September 30, respectively, calculated on a weighted-average basis across the geographic areas served by Monongahela.

Operating Revenues

Operating revenues were as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Retail electric:
Generation	$	90.8	$	103.9	$	264.6	$	307.7
Transmission		8.7		10.2		25.1		29.9
Distribution		48.2		54.3		138.8		154.9

Total retail electric		147.7		168.4		428.5		492.5

Transmission services and bulk power		23.7		6.1		68.1		17.7
Other affiliated and non-affiliated energy services		2.3		2.1		7.9		5.4

Total revenues	$	173.7	$	176.6	$	504.5	$	515.6

Retail electric revenues decreased $20.7 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, primarily due to a $13.1 million decrease in generation revenues and a $7.6 million decrease in T&D revenues. These decreases were primarily a result of milder weather and a reduction in customers due to the sale of Monongahela’s Ohio service territory on December 31, 2005.

Retail electric revenues decreased $64.0 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to a $43.1 million decrease in generation revenues and a $20.9 million decrease in T&D revenues. These decreases were primarily a result of milder weather and a reduction in customers due to the sale of Monongahela’s Ohio service territory on December 31, 2005.

Transmission services and bulk power increased $17.6 million and $50.4 million for the three and nine months ended September 30, 2006, respectively, compared to the three and nine months ended September 30, 2005, primarily due to bulk power sales related to a fixed price power supply agreement with Columbus Southern to serve Monongahela’s former Ohio service territory, partially offset by a reduction in transmission revenue related to the expiration of a third-party transmission capacity contract.

Operating Expenses

Purchased Power and Transmission:Purchased power and transmission represents power purchases from other companies and purchases from qualifying facilities under PURPA. Purchased power and transmission consists of the following items:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Other purchased power and transmission	$	94.3	$	104.7	$	261.0	$	297.9
From PURPA generation (a)		15.1		14.6		45.5		42.7

Total purchased power and transmission	$	109.4	$	119.3	$	306.5	$	340.6


(a) PURPA cost (cents per kWh sold)		4.7		4.8		4.5		4.5

Other purchased power and transmission primarily consists of Monongahela’s Delivery and Services segment’s purchases of energy from Monongahela’s Generation and Marketing segment to service its load requirements.

Other purchased power and transmission decreased $10.4 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, primarily due to reduced rates, including reduced rates on purchased power in relation to costs to provide power to Columbus Southern to serve Monongahela’s former Ohio service territory.

Other purchased power and transmission decreased $36.9 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to reduced rates on purchased power in relation to costs to provide power to Columbus Southern to serve Monongahela’s former Ohio service territory and reduced demand as a result of milder weather.

Purchased power from PURPA generation increased $2.8 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to an increase in rates at a certain PURPA facility.

Deferred Energy Costs, Net:Deferred energy costs, net were as follows:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(In millions)	2006			2005		2006			2005
Deferred energy costs, net	$	(0.6	)	$	—	$	(1.2	)	$	—

Grant Town PURPA Facility

Monongahela acquires energy from the Grant Town PURPA Facility in West Virginia. The West Virginia Public Service Commission (the “WV PSC”) approved an amendment to the Electric Energy Purchase Agreement between Monongahela and American Bituminous Power Partners, L.P. (“AmBit”), the owners of the Grant Town PURPA Facility. The amendment provides for an increase in the price of energy that Monongahela is acquiring until 2017. The WV 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 will be tracked and reconciled by comparison to the aggregate amounts recovered from West Virginia customers through the temporary surcharge.

Deferred energy costs, net decreased $1.2 million for the nine months ended September 30, 2006 compared with the nine months ended September 30, 2005, primarily as a result of decreased deferred costs related to the Grant Town PURPA Facility.


	Three Months Ended				Nine months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Operations and maintenance	$	23.7	$	27.5	$	73.9	$	84.4

Operations and maintenance expenses decreased $3.8 million and $10.5 million for the three and nine months ended September 30, 2006, respectively, compared to the three and nine months ended September 30, 2005, primarily due to decreased salaries and wages expense as a result of a decrease in the number of information technology employees due to the outsourcing of this function during 2005 and a reduction in right-of-way vegetation control, partially offset by increased outside services costs associated with the implementation of Allegheny’s information technology initiatives.

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Depreciation and amortization	$	7.7	$	7.9	$	22.8	$	24.0

Depreciation and amortization expenses decreased $1.2 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005 due to the sale of Ohio T&D assets at December 31, 2005, the retirement of certain software that became fully amortized during 2006.

Taxes Other Than Income Taxes:Taxes other than income taxes were as follows:


	Three Months Ended				Nine months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Taxes other than income taxes	$	6.1	$	6.1	$	18.4	$	19.7

Taxes other than income taxes decreased $1.3 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to a decrease in gross receipts taxes due to the sale of Monongahela’s Ohio service territory on December 31, 2005.

Other Income and Expenses, Net:Other income and expenses, net, represent non-operating income and expenses before income taxes. Other income and expenses, net were as follows:


	Three Months Ended				Nine months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Other income and expenses, net	$	2.0	$	0.9	$	5.0	$	2.5

Other income and expenses, net increased $1.1 million and $2.5 million for the three and nine months ended September 30, 2006, respectively, compared to the three and nine months ended September 30, 2005, primarily as a result of increased interest income on investments due to higher investment balances and higher interest rates.

Generation and Marketing

The following table provides electricity sales information:


	Three Months Ended							Nine Months Ended
	September 30,							September 30,
	2006		2005		Change			2006		2005		Change
Generation (million kWhs)		2,755		2,888		(4.6	)%		8,167		7,873		3.7	%

Operating Revenues

Operating revenues were as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Revenue from affiliates	$	64.4	$	64.6	$	213.1	$	224.0
Wholesale and other, net		53.8		58.9		96.5		82.2

Total revenues	$	118.2	$	123.5	$	309.6	$	306.2

Revenues from affiliates represent sales to Monongahela’s Delivery and Services segment to meet its customer obligations and affiliated sales to AE Supply, as discussed below.

To facilitate the economic dispatch of its generation, Monongahela sells the power that it generates from its West Virginia jurisdictional assets to AE Supply at PJM market prices and purchases from AE Supply, at PJM market prices, the power necessary to meet its West Virginia jurisdictional customer load. Monongahela records either affiliated revenues or purchased power and transmission expenses related to these transactions, depending on Monongahela’s net energy requirements, as determined on an hourly basis.

Total operating revenues decreased $5.3 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005 due to decreased generation volumes as a result of the Harrison transformer failure and milder weather, which caused a decrease in revenues from the Delivery and Services segment.

Total operating revenues increased $3.4 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005 due to increased generation volumes as a result of improved availability. These increases were partially offset by decreased sales volumes as a result of milder weather and reduced sales to Monongahela’s Delivery and Services segment, as well as a decrease in the number of Monongahela’s customers as a result of the sale of its Ohio service territory on December 31, 2005.

Operating Expenses

Fuel Consumed in Electric Generation:Fuel consumed in electric generation represents the cost of coal, lime and other materials consumed in the generation of power and emission allowances. Fuel consumed in electric generation was as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Fuel consumed in electric generation	$	45.3	$	41.8	$	129.9	$	110.1

Total fuel consumed in electric generation increased by $3.5 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, primarily due to a $1.7 million increase in coal expense and a $1.5 million increase in emission expense. The increase in coal expense was due to an increase in the price of coal of $1.90 per ton. The increase in emission expense was due to Monongahela purchasing NO_X emission allowances in excess of granted and banked allowances.

Total fuel consumed in electric generation increased by $19.8 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to a $17.3 million increase in coal expense and a $1.5 million increase in emission expense. The increase in coal expense was due to an increase in the price of coal of $2.86 per ton

and a 0.2 million-ton increase in the amount of coal burned. The increase in the amount of coal burned was primarily due to a 3.7% increase in total MWhs generated and an increase in the use of lower BTU Powder River Basin coal.

Purchased Power and Transmission:Purchased power and transmission represents power purchases from other companies. Purchased power and transmission was as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Purchased power and transmission	$	39.8	$	36.4	$	74.1	$	85.6

Purchased power and transmission increased $3.4 million for the three months ended September 30, 2006 compared to the three months ended September 30, 2005, primarily due to an increase in affiliated purchases to service load requirements.

Purchased power and transmission decreased $11.5 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to a decrease in affiliated purchases to service load requirements.


	Three Months Ended				Nine months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Operations and maintenance	$	17.5	$	17.8	$	58.0	$	57.0

Operations and maintenance expenses increased $1.0 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily due to costs associated with the implementation of Allegheny’s information technology initiatives, partially offset by decreased special maintenance.

Other Income and Expenses, Net:Other income and expenses, net represent non-operating income and expenses before income taxes. Other income and expenses, net, were as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Other income and expenses, net	$	2.6	$	2.0	$	7.4	$	6.1

Other income and expenses, net, increased $1.3 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily as a result of increased interest income on investments due to higher investment balances and higher interest rates, partially offset by a decrease in equity earnings from AGC.

ALLEGHENY GENERATING COMPANY—RESULTS OF OPERATIONS

Income Summary


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Operating revenues	$	16.9	$	17.4	$	48.1	$	50.9
Operating income	$	10.4	$	11.1	$	28.9	$	32.5
Income before income taxes	$	8.7	$	9.4	$	24.4	$	27.1
Net income	$	5.9	$	7.4	$	18.8	$	22.5

Operating Revenues and Expenses

AGC’s only operating asset is an undivided 40% interest in the Bath County, Virginia pumped-storage hydroelectric station and its connecting transmission facilities.

Pursuant to an agreement, AE Supply and Monongahela purchase all of AGC’s capacity at prices based on a “cost-of-service formula” wholesale rate schedule (the “revenue requirements”) approved by the Federal Energy Regulatory Commission (“FERC”). AE Supply and Monongahela purchase power capacity from AGC on a proportional basis, based on their respective equity ownership of AGC. Under this arrangement, AGC recovers in revenues all of its operations and maintenance expense, depreciation, taxes other than income taxes, income tax expense at the statutory rate and a component for debt and equity return on its investment.

Operating Revenues:Operating revenues were as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2006		2005		2006		2005
Operating revenues	$	16.9	$	17.4	$	48.1	$	50.9

Operating revenues decreased $2.8 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005, primarily as a result of decreased expenditure recoveries. Expenditure recovery is determined on the basis of the “cost-of-service” formula described above. The decrease in such recoveries resulted from a decrease in income tax expense.

Income Tax Expense

The effective tax rates were 32.1% and 22.9% for the three and nine months ended September 30, 2006, respectively. The effective tax rates were lower than the federal statutory tax rate, primarily due to the allocation of consolidated tax savings, the amortization of deferred investment tax credits and the receipt of a state tax refund.

The effective tax rates were 21.1% and 16.8% for the three and nine months ended September 30, 2005, respectively. The effective tax rates were lower than the federal statutory tax rate, primarily due to the allocation of consolidated tax savings and the amortization of deferred investment tax credits.

FINANCIAL CONDITION, REQUIREMENTS AND RESOURCES

Liquidity and Capital Requirements

To meet cash needs for operating expenses, the payment of interest, retirement of debt, acquisitions 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 an 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 AE 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 an internal money pool, and Monongahela, Potomac Edison and West Penn manage excess cash and short-term requirements through an internal money pool. The money pool provides funds to approved AE subsidiaries at the lower of the previous day’s Federal Funds Effective Interest Rate, as quoted by the Federal Reserve, or the previous day’s seven day commercial paper rate, as quoted by the same source, less four basis points. AE and AE Supply can only lend money into the money pool. Monongahela, West Penn and Potomac Edison can either lend money into, or borrow money from, the money pool.

Allegheny’s consolidated capital structure as of September 30, 2006 and December 31, 2005 was as follows:


	September 30, 2006				December 31, 2005
(In millions)	Amount		%		Amount		%
Debt	$	3,902.4		65.8	$	4,101.7		70.5
Common equity		2,005.0		33.8		1,695.3		29.1
Preferred equity		24.0		0.4		24.0		0.4

Total	$	5,931.4		100.0	$	5,821.0		100.0

In August 2006, West Penn Power Company issued $145 million aggregate principal amount of 5.875% First Mortgage Bonds, which mature in 2016. Proceeds from the First Mortgage Bonds were used to repay a portion of a note payable, to pay a dividend to Allegheny and for other general corporate purposes.

In September 2006, Monongahela issued $150 million aggregate principal amount of 5.70% First Mortgage Bonds, which mature in 2017. In October 2006, Monongahela used the net proceeds from the sale of the bonds, plus available cash on hand, to fund the repayment at maturity of the $300 million aggregate principal amount of 5.0% First Mortgage Bonds.

At September 30, 2006, $264.5 million was available under the AE Revolving Credit Facility and $200.0 million was available under the AE Supply Revolving Facility. Subject to certain limitations, AE Supply may borrow, or request letters of credit for, up to $50 million directly under the AE Revolving Credit Facility. AE is permitted to request letters of credit

under its revolving credit facility in an amount not in excess of $125 million on behalf of AE Supply and its subsidiaries. At September 30, 2006, Allegheny did not have access to any short-term revolving credit facilities or lines of credit with third-party financial institutions beyond those described above. There were $135.5 million of outstanding letters of credit issued under the AE Revolving Credit Facility at September 30, 2006. AE Supply also had a $2.1 million letter of credit outstanding, which is collateralized by cash that expires in February 2007 and was not issued under either the AE Revolving Credit Facility or the AE Supply Revolving Facility.

Allegheny made various other debt payments during the nine months ended September 30, 2006. See Note 5, “Debt” for additional information.

Off-Balance Sheet Arrangements

None of the registrants has any off-balance sheet arrangements that have, or are reasonably likely to have, a current or future material effect on their financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources.

Long-Term Debt and Contractual Obligations

See Note 5, “Debt,” for additional information and details regarding Allegheny’s debt. See also Item 8, Note 2, “Capitalization,” in the 2005 Annual Report on Form 10-K for additional details and discussion regarding debt covenants, refinancing and other debt issuances and repayments.

The registrants have various obligations and commitments to make future cash payments under debt instruments, lease arrangements, fuel and transportation agreements and other contracts. See Item 7, “Financial Condition, Requirements and Resources,” in the 2005 Annual Report on Form 10-K for additional information.

Allegheny has various obligations and commitments to make future cash payments under debt instruments, lease arrangements, fuel agreements and other contracts. The table below summarizes the payments due by period for these obligations and commitments, as of September 30, 2006. The table below does not include expected contributions for pension and postretirement benefits other than pensions, contingent liabilities, liabilities associated with assets held for sale and contractual commitments that were accounted for under fair value accounting. For more information regarding fair value accounting, see “Allegheny Energy, Inc.—Discussion of Segment Results of Operations—AE’s Generation and Marketing Segment Results.”


	Payments from
Contractual Obligations and	October 1, to		Payments from		Payments from		Payments from
Commitments	December 31,		January 1, 2007 to		January 1, 2009 to		January 1, 2011
(In millions)	2006		December 31, 2008		December 31, 2010		and beyond		Total
Long-term debt (a)	$	418.6	$	260.6	$	198.7	$	3,033.2	$	3,911.1
Interest on long-term debt (b)		57.2		440.7		426.7		541.6		1,466.2
Interest rate swap obligations		—		12.2		12.2		2.1		26.5
Capital lease obligations		2.5		14.5		9.3		4.5		30.8
Operating lease obligations		1.3		7.4		6.7		19.5		34.9
PURPA purchased power		57.2		458.9		467.8		4,179.5		5,163.4
Fuel purchase and transportation commitments		167.2		1,145.5		836.4		2,389.7		4,538.8
Other purchase obligation (c)		8.1		53.3		50.4		44.9		156.7

Total	$	712.1	$	2,393.1	$	2,008.2	$	10,215.0	$	15,328.4


(a)		Does not include debt associated with unamortized debt expense, discounts, premiums, payments made and debt issued subsequent to September 30, 2006.

(b)		Amounts are based on interest rates as of September 30, 2006 and do not reflect any payments made or interest rate changes subsequent to September 30, 2006. Total interest on long-term debt includes $11.0 million in interest that will accrue and be added to the principal amount of West Penn’s $115.0 million of 4.46% Transaction Bonds, Series 2005-A.

(c)		Amounts represent Allegheny’s expected cash payments for outsourcing of certain information technology functions and assistance with the installation of an enterprise resource planning system.

Monongahela has various obligations and commitments to make future cash payments under debt instruments, lease arrangements, fuel agreements and other contracts. The table below summarizes the payments due by period for these obligations and commitments, as of September 30, 2006. The table below does not include expected pension and postretirement benefits other than pension contributions, contingent liabilities and liabilities associated with assets held for sale.


Contractual Obligations and	Payments from		Payments from		Payments from		Payments from
Commitments	October 1, to		January 1, 2007 to		January 1, 2009 to		January 1, 2011
(In millions)	December 31, 2006		December 31, 2008		December 31, 2010		and beyond		Total
Long-term debt (a)	$	300.0	$	15.5	$	110.0	$	410.3	$	835.8
Interest on long-term debt (b)		8.2		64.7		56.4		129.5		258.8
Capital lease obligations		0.8		4.6		2.9		1.7		10.0
Operating lease obligations		0.1		0.5		—		—		0.6
PURPA purchased power		0.5		130.7		132.7		1,524.5		1,788.4
Fuel purchase and transportation commitments		34.4		244.6		178.5		510.0		967.5

Total	$	344.0	$	460.6	$	480.5	$	2,576.0	$	3,861.1


(a)		Does not include debt associated with unamortized debt expense, discounts, premiums and payments made subsequent to September 30, 2006.

(b)		Amounts are based on interest rates as of September 30, 2006 and do not reflect any payments made or interest rate changes subsequent to September 30, 2006 and any debt prepayments or interest rate changes.

The obligations for AGC did not change materially from the amounts reported in the 2005 Annual Report on Form 10-K.

Allegheny’s capital expenditures for the nine months ended September 30, 2006 were $310.6 million. Allegheny’s capital expenditures for full year 2006 and 2007 are estimated to be approximately $500 million and approximately $1 billion, respectively, and include estimated expenditures of approximately $170 million and approximately $600 million, respectively, for environmental control technology.

Financing

Debt:See Note 5, “Debt,” for a discussion of the issuances and repayments of debt by AE and its subsidiaries.

Asset Sales

In May 2006, AE Supply sold a receivable from the Tennessee Valley Authority (“TVA”) related to an Interconnection Agreement with TVA for net cash proceeds of approximately $27.8 million.

See Note 6, “Discontinued Operations and Assets Held for Sale,” for additional information relating to asset sales.

Cash Flows

Allegheny

Allegheny’s cash flows from operating activities primarily result from the sale of electricity. Future cash flows will be affected by, among other things, the impact that the economy, weather, customer choice and future regulatory proceedings have on revenues, future demand and market prices for energy, as well as Allegheny’s ability to produce and supply its customers with power at competitive prices.

Operating Activities:Changes in cash flows from operations are generally consistent with changes in results of operations and are further impacted by changes in working capital. Net income before depreciation and amortization expense is a significant component of cash flows from operating activities.

Cash provided by operating activities for the nine months ended September 30, 2006 was $615.7 million, consisting of net income of $254.7 million, discontinued operations and non-cash charges of $347.2 million and changes in certain assets and liabilities of $92.4 million, partially offset by pension and other postretirement employee benefit plan contributions of $75.3 million and net cash used in operating activities of discontinued operations of $3.4 million. Cash flows provided by operating activities for the nine months ended September 30, 2005 were $332.8 million, consisting of discontinued operations and non-cash charges of $297.8 million, net cash provided by operating activities of discontinued operations of $55.6 million and net income of $59.9 million, partially offset by pension and other postretirement employee benefit plan contributions of $80.3 million and changes in certain assets and liabilities of $0.2 million. Significant cash flows related to operating activities for the nine months ended September 30, 2005 included $47.2 million in payments to the holders of the 11 7/8% Trust Preferred Securities under the terms of the tender offer and consent solicitation and the cash receipt of $11.2 million from a former trading executive’s forfeited assets.

The changes in certain assets and liabilities for the nine months ended September 30, 2006 resulted in an increase in operating cash flows of $92.4 million. Operating cash flows were provided primarily by a $128.0 million decrease in collateral deposits, primarily resulting from reduced collateral requirements due to the expiration of power transactions with various counterparties, a $50.8 million decrease in accounts receivable, net, primarily due to the timing and volume of unbilled utility revenues, a $20.7 million increase in accrued interest and a $20.1 million increase in accrued taxes both primarily due to timing differences associated with the payment of certain obligations. These amounts were partially offset by cash flows used by operating activities, primarily as a result of a $123.3 million decrease in accounts payable, primarily due to timing differences associated with the payment of certain obligations.

Investing Activities:Cash flows used in investing activities for the nine months ended September 30, 2006 were $438.8 million. Cash flows provided by investing activities for the nine months ended September 30, 2005 were $239.5 million.

Significant cash flows used in investing activities for the nine months ended September 30, 2006 included $310.6 million in capital expenditures, $140.2 million increase in restricted funds due to net proceeds from the September 2006 5.70% First Mortgage Bond issuance and $13.9 million for the purchase of the minority interest in Hunlock Creek Energy Ventures. These amounts were partially offset by $27.8 million in proceeds received from the sale of TVA receivable related to assets held-for-sale.

Significant cash flows provided by investing activities for the nine months ended September 30, 2005 included a $206.0 million decrease in restricted funds, primarily due to the release of the proceeds related to the 2004 sales of OVEC and the Lincoln generation facility, and $247.4 million in proceeds from asset sales, primarily related to the sale of the West Virginia natural gas operations and the AE Supply Wheatland Generating Facility. These amounts were partially offset by $204.4 million in capital expenditures.

Financing Activities:Cash flows used in financing activities for the nine months ended September 30, 2006 and 2005 were $189.5 million and $417.8 million, respectively.

Significant cash flows used in financing activities for the nine months ended September 30, 2006 included $1,644.3 million related to payments on and retirement of long-term debt, primarily due to the May 2, 2006 refinancing of the Prior AE Supply Term Loan and the May 22, 2006 refinancing of the Prior AE Credit Facility. This amount was partially offset by $1,433.1 million (net of $6.8 million related to debt issuance costs) in proceeds from the issuance of long-term debt, primarily used to refinance the Prior AE Supply Term Loan and the Prior AE Credit Facility, and $22.1 million in cash proceeds received from employees for the exercise of stock options.

Significant cash flows used in financing activities for the nine months ended September 30, 2005 included $2,202.0 million in payments for the retirement of long-term debt, primarily due to the June 16, 2005 refinancing of AE’s Prior Credit Facility and Medium-Term Notes, the July 21, 2005 refinancing of the Prior AE Supply loan and Medium-Term Notes, and the August 15, 2005 refinancing of outstanding First Mortgage Bonds. This amount was partially offset by $1,782.4 million (net of $14.2 million related to debt issuance costs) in proceeds from the issuance of long-term debt, primarily related to refinancings and the issuance of $115.0 million in Transition Bonds.

Monongahela

Monongahela’s cash flows from operating activities primarily result from the sale, transmission and distribution of electricity. Future cash flows will be affected by, among other things, the impact that the economy, weather, customer choice and future regulatory proceedings have on revenues, future demand and market prices for energy.

Internal generation of cash, consisting of cash flows provided by operating activities reduced by common and preferred dividends, was $103.6 million for the nine months ended September 30, 2006 compared with $97.3 million for the same period in 2005.

Cash flows provided by operating activities for the nine months ended September 30, 2006 were $114.5 million, consisting of non-cash charges of $52.4 million, net income of $42.3 million and changes in certain assets and liabilities of $19.8 million. Cash flows provided by operating activities for the nine months ended September 30, 2005 were $101.1 million, consisting of net cash provided by operating activities of discontinued operations of $64.2 million, discontinued operations and non-cash charges of $80.2 million and net income of $12.6 million partially offset by changes in certain assets and liabilities of $55.9 million.

The changes in certain assets and liabilities for the nine months ended September 30, 2006 resulted in an increase in operating cash flows of $19.8 million. Operating cash flows were provided primarily by a $26.5 million decrease in accounts receivable, net, primarily due to the timing and volume of unbilled utility revenues and a $14.4 million decrease in collateral deposits, primarily due to reduced collateral requirements with various counterparties to Monongahela’s power contracts. These amounts were partially offset by cash flows used for operating activities primarily as a result of a $19.0 million decrease in accounts payable, primarily due to timing differences associated with the payment of certain obligations.

The changes in certain assets and liabilities for the nine months ended September 30, 2005 resulted in a decrease in operating cash flows of $55.9 million. Operating cash flows were used primarily for a $43.6 million change in accounts receivable due from/payable to affiliates, net, primarily due to timing differences associated with the payment of certain obligations, a $14.8 million increase in accounts receivable, net, primarily due to the timing and volume of unbilled utility revenues, and an $11.1 million increase in collateral deposits, primarily as a result of collateral requirements of PJM related to the Ohio customers. These amounts were partially offset by cash flows provided by operating activities, primarily due to a $6.1 million increase in accrued interest, primarily as a result of timing differences associated with the payment of certain obligations.

Investing Activities:Cash flows used in investing activities for the nine months ended September 30, 2006 was $247.8 million consisting primarily of an increase in restricted funds, capital expenditures and the issuance of a note receivable from an affiliate. Cash flows provided by investing activities for the nine months ended September 30, 2005 was $35.0 million consisting primarily of a source of $134.4 million resulting primarily from the proceeds received in connection with the sale of the West Virginia natural gas operations partially offset by capital expenditures and the issuance of a note receivable from an affiliate.

Financing Activities:Cash flows provided by financing activities for the nine months ended September 30, 2006 was $137.4 million and cash flows used in financing activities for the nine months ended September 30, 2005 was $70.8 million.

Cash flows used in financing activities for the nine months ended September 30, 2006 related to cash dividends paid on preferred and common stock. Cash flows used in financing activities for the nine months ended September 30, 2005 related to cash dividends paid on preferred stock. The nine months ended September 30, 2006 amount also includes proceeds from the issuance of long-term debt of $149.5 million, primarily used to partially refinance 5.0% First Mortgage Bonds. The nine months ended September 30, 2005 amount also included a use of $67.1 million for debt activities of discontinued operations consisting primarily of a decrease in a note payable to an affiliate.

AGC

AGC’s cash flows from operating activities primarily result from the sale of electricity. Future cash flows will be affected by, among other things, the impact that the economy and weather have on revenues, future demand and market prices for energy.

Internal generation of cash, consisting of cash flows provided by operating activities reduced by common dividends, was $3.0 million for the nine months ended September 30, 2006 compared with $14.3 million for the same period in 2005.

Cash flows provided by operating activities for the nine months ended September 30, 2006 were $26.0 million, consisting of net income of $18.8 million and non-cash charges of $7.8 million, partially offset by changes in certain assets and liabilities of $0.6 million. Cash flows provided by operating activities for the nine months ended September 30, 2005 were $30.5 million, consisting of net income of $22.5 million, non-cash charges of $7.8 million and changes in certain assets and liabilities of $0.2 million.

Investing Activities:Cash flows used in investing activities for the nine months ended September 30, 2006 and 2005 were $3.4 million and $6.5 million, respectively, consisting of capital expenditures.

Financing Activities:Cash flows used in financing activities for the nine months ended September 30, 2006 were $23.0 million consisting of cash dividends paid on common stock. Cash flows used in financing activities for the nine months ended September 30, 2005 were $31.2 million consisting of a $15.0 million payment on a note payable to parent and $16.2 million of cash dividends paid on common stock.

Credit Ratings

The following table lists Allegheny’s credit ratings, as of November 7, 2006:


	Moody’s	S & P	Fitch
Outlook	Stable (1)	Positive	Stable (2)
AE:
Corporate Credit Rating	Ba2 (3)	BB+	NR
Senior Unsecured Debt	Ba2	BB-	BB+
Short-term Rating	SGL-2 (4)	B2	NR
AE Supply:
Senior Secured Debt	Baa3	BBB-	BBB-
Senior Unsecured Debt	Ba3	BB-	BB+
Pollution Control Bonds	NR	NR	AAA
Monongahela:
First Mortgage Bonds	Baa2	BBB-	BBB+
Senior Unsecured Debt	Baa3	BB-	BBB-
Preferred Stock	Ba3	B+	BB+
Potomac Edison:
First Mortgage Bonds	Baa2	BBB-	BBB+
Senior Unsecured Debt	Baa3	BB-	BBB-
West Penn:
Transition Bonds	Aaa	AAA	AAA
First Mortgage Bonds	Baa2	BBB	BBB+
Senior Unsecured Debt	Baa3	BB+	BBB-
AGC:
Senior Unsecured Debt	Ba3	BB-	BB+


(1)		Moody’s outlook for Potomac Edison is negative
(2)		Fitch’s outlook for Monongahela is negative
(3)		Corporate family rating for AE only, which excludes all of its subsidiaries
(4)		Liquidity rating

OTHER MATTERS

Critical Accounting Policies

A summary of Allegheny’s critical accounting policies is included under Item 8, Note 1, Basis of Presentation, in the 2005 Annual Report on Form 10-K. Allegheny’s critical accounting policies have not changed materially from those reported in the 2005 Annual Report on Form 10-K.

Recent Accounting Pronouncements

See Note 2, “Recent Accounting Pronouncements” in Allegheny’s Notes to Consolidated Financial Statements included herein for a summary of significant recent accounting pronouncements issued or implemented during 2006 that relate to Allegheny’s operations.

REGULATORY MATTERS

See, Item 1, “Regulatory Framework Affecting Allegheny” in the 2005 Annual Report on Form 10-K for a summary of regulatory matters.

Federal Legislation, Regulation and Rate Matters

PJM and PJM Transmission Rate Design.Substantially all of Allegheny’s generation assets and power supply obligations are located within the PJM market, and PJM maintains functional control over the Distribution Companies’ transmission facilities. Changes in the PJM tariff, operating agreement, policies and/or market rules, including changes that are currently under consideration by FERC, could adversely affect Allegheny’s financial results. These matters include changes involving: the terms, conditions and pricing of transmission services; construction of transmission enhancements; auction of financial transmission rights (“FTRs”) and the allocation mechanism for the auction revenues; changes in transmission congestion patterns due to the implementation of PJM’s regional transmission expansion planning protocol or other required transmission system upgrades; new generation retirement rules and reliability pricing issues.

FERC actions with respect to the transmission rate design within PJM may impact the Distribution Companies. Beginning in July 2003, FERC issued a series of orders related to transmission rate design for PJM and Midwest Independent Transmission System Operator, Inc. (“MISO”), an adjoining RTO. Specifically, FERC ordered the elimination of multiple and additive (i.e., “pancaked”) rates between the PJM and MISO regions and called for the implementation of a long-term integrated 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. FERC required the implementation of a transition charge to replace the eliminated pancaked rate between MISO and PJM on an interim basis for a 16-month period ending March 31, 2006, and otherwise ordered the continuation of the existing rate design until replaced by a different rate design accepted by FERC. In February 2005, FERC accepted transition charge filings made by the MISO and PJM transmission owners, effective for the period from December 1, 2004 through March 31, 2006, subject to an evidentiary hearing. FERC’s February 2005 order remains subject to multiple rehearing requests and, potentially, appellate review. We cannot predict the outcome of these proceedings, or whether they will have a material impact on our business or financial position.

During the now-expired transition period, the Distribution Companies were both payers and payees of transition charges. These charges have resulted in the payment by the Distribution Companies of $13.7 million, and payments to the Distribution Companies of $4.8 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. We cannot predict the outcome of these proceedings. The Distribution Companies have entered into eight partial settlements with various parties with regard to the transition charges, and may enter into additional settlements in the future. Two of these partial settlements have been approved by FERC, 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 and another PJM transmission owner filed a proposed rate design with

FERC to replace the existing rate design within PJM, effective April 1, 2006. Two other PJM transmission owners and FERC staff also filed separate proposed rate designs. A hearing was held in April 2006 to determine whether the existing rate design is unjust and unreasonable and whether it should be replaced by any 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 the Distribution Companies was just and reasonable, but that the rate design proposed by FERC staff was also just and reasonable and 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 was unjust and unreasonable. The initial decision 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 FTRs (i.e., specialized rights that allow us and other holders of FTRs to deal with the financial effects of congestion on the PJM transmission system). The initial decision will not become effective until acted upon by FERC, which may accept, modify or reject the initial decision. FERC is expected to issue an order on this matter later this year.

In August 2005, PJM filed proposed tariff sheets at FERC to replace the current generation 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 current generation capacity market to be unjust and unreasonable and set a process to resolve features of the RPM that must be analyzed further before FERC can determine whether the RPM is a just and reasonable generation capacity market process. FERC ordered implementation of settlement procedures in this proceeding, and AE Supply and the Distribution Companies participated in a settlement agreement that was filed with FERC on September 29, 2006. The settlement agreement, if accepted by FERC, would create a locational capacity market in PJM in which PJM would procure needed capacity resources through auctions held three years in advance at prices and 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 through commitments by load serving entities to self-supply their capacity needs. The settlement agreement is not effective until approved by FERC. FERC is expected to issue an order on the settlement agreement by the end of 2006.

On July 3, 2006, PJM filed at FERC a proposal to implement a process for allocating long-term transmission rights (“LTTR”). 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 creates a link between PJM’s long-term transmission planning process and the LTTR allocation process to ensure that the transmission system is upgraded as necessary to maintain the availability of the LTTRs that PJM will allocate. The PJM proposal is pending before FERC. PJM has requested that FERC approve its LTTR proposal so that the first set of LTTRs can be allocated by March 2007 for the 2007/2008 PJM planning year.

Transmission Expansion.On February 28, 2006, the Distribution Companies requested PJM to include in the PJM Regional Transmission Expansion Plan (“RTEP”) a proposal by the Distribution Companies to construct the Trans-Allegheny Interstate Line (“TrAIL”). PJM’s RTEP identifies transmission system upgrades and enhancements, through a region-wide planning effort, to provide for the operational, economic and reliability requirements of PJM customers and to determine the best way to integrate transmission with generation and load response projects to meet load-serving obligations. TrAIL, which would be owned, operated and financed by one or more of Distribution Companies and/or an affiliate, is designed to increase the west-to-east energy transfer capability of the PJM Transmission System. As originally proposed, it would have consisted of a 330-mile 500 kV transmission line traversing the Distribution Companies’ PJM zone from west to east. In June 2006, the PJM Board of Managers approved an RTEP that includes some elements of the TrAIL proposal in a 240-mile transmission line project, 210 miles of which are to be constructed in the Distribution Companies’ PJM zone. The Distribution Companies were designated by PJM to construct the portion of the line that will be located in the Distribution Companies’ PJM zone. PJM has indicated that it will not give further consideration to the remaining elements of the TrAIL proposal as part of PJM’s 15-year RTEP.

Concurrent with the submission of the TrAIL proposal to PJM, Allegheny and the Distribution Companies submitted a petition for declaratory order to FERC requesting four incentive rate treatments. Incentive rate treatments are intended to promote the construction of transmission facilities, such as the TrAIL proposal. Upon the PJM Board of Managers’ approval of the RTEP in June 2006, Allegheny requested FERC to authorize the incentive rate treatments with regard to the transmission line to be constructed by the Distribution Companies or their affiliate in the Distribution Companies’ PJM zone. On July 20, 2006, FERC approved the incentive rate treatments for the transmission line. Approval of the incentive rates is subject to a subsequent filing with FERC pursuant to Section 205 of the Federal Power Act.

On March 6, 2006, the Distribution Companies filed a request with the Department of Energy seeking an early designation for the TrAIL route as a National Interest Electric Transmission Corridor pursuant to the Energy Policy Act. On August 8, 2006, the Department of Energy published a congestion study. In that study the Department of Energy requested comment by October 10, 2006 as to whether the designation of corridors in relation to the areas identified as congested in the study would be appropriate and in the public interest and, if so, how the geographic boundaries for those corridors should be established. The Distribution Companies submitted comments supporting the designation of a corridor for the Mid-Atlantic area. It cannot be determined at this time when a decision with respect to the designation of the TrAIL route as National Interest Electric Transmission Corridor will be forthcoming.

State Legislation, Regulation and Rate Matters

West Virginia:On May 4, 2005, the state of West Virginia adopted legislation permitting securitization financing for the construction of certain types of pollution control equipment at facilities owned by public utilities that are regulated by the West Virginia PSC, subject to the satisfaction of certain criteria. In April 2006, the West Virginia Public Service Commission (the “West Virginia PSC”) approved a settlement agreement among Monongahela, Potomac Edison and certain other interested parties relating to Allegheny’s plans to construct flue gas desulfurization equipment (“Scrubbers”) at the Fort Martin generation facility in West Virginia (“Fort Martin”). Concurrently, the West Virginia PSC granted Monongahela and Potomac Edison a certificate of public convenience and necessity authorizing the construction and operation of the Scrubbers, approved a proposed restructuring of the ownership of certain of Allegheny’s generation assets, and issued a related financing order (the “Financing Order”) approving a proposal by Monongahela and Potomac Edison to finance $338 million of project costs associated with the construction of Scrubbers, as well as certain additional related financing costs, using the securitization mechanism provided for by the legislation adopted in May 2005. Specifically, Monongahela and Potomac Edison received approval to issue environmental control bonds secured by the right to collect a surcharge from West Virginia retail customers that will be dedicated to the repayment of the bonds.

On September 8, 2006, Allegheny announced that the expected cost of installing the Scrubbers at Fort Martin would be higher than previously estimated. Allegheny currently estimates construction costs associated with the project to be up to $550 million, excluding certain related financing costs. The increased cost estimate is due to a number of factors, including construction challenges caused by site-specific characteristics, necessary changes in material-handling equipment and higher material costs. There can be no assurance that Allegheny will not encounter additional costs related to these or other items.

On October 3, 2006, Monongahela and Potomac Edison filed with the West Virginia PSC a Petition to Reopen Proceedings and to Amend Financing Order (“Petition”), informing the West Virginia PSC that the current estimate for constructing the Scrubbers at Fort Martin has increased from $338 million to an amount up to $550 million. The Petition requests that the West Virginia PSC reopen the Financing Order proceedings for the purposes of amending the Financing Order to increase the securitization financing authority for construction-related costs to an amount of up to $550 million and reduce the maximum amount of upfront financing costs (exclusive of costs for the West Virginia PSC’s financial advisor) that may be recovered from environmental control bond proceeds from $27 million to $23 million. In addition, Monongahela and Potomac Edison indicated in the Petition that a complete review and value engineering process was being performed on the Fort Martin Scrubbers project and that a supplement to the Petition updating and further refining the current project cost estimate would be submitted to the West Virginia PSC within 45 days. Monongahela and Potomac Edison have requested expedited treatment for the Petition; however, no procedural schedule has been set at this time.

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 $99.8 million annually. The request includes 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 $26.2 million decrease in base rates. The rate increase request is subject to approval by the West Virginia PSC. On August 22, 2006 the PSC issued an Order suspending Monongahela’s and Potomac Edison’s proposed new rates until May 23, 2007 and establishing a procedural schedule for the proceeding. Consistent with the procedural schedule, Monongahela and Potomac Edison filed direct testimony in support of the rate request on September 8, 2006. Evidentiary hearings in the proceeding are scheduled to begin on February 12, 2007.

Maryland:In special session, the Maryland legislature passed emergency legislation on June 23, 2006 reconstituting the Maryland Public Service Commission, directing a Commission investigation into the proposed merger of FPL Group, Inc. and Constellation Energy Group, Inc. and approving a transition plan for residential customers of Baltimore Gas & Electric Company to move from capped to market-based default service rates. For Allegheny, the legislation requires the Commission to investigate options available to implement a rate mitigation or rate stabilization plan, including the renegotiation of a settlement agreement to allow a portion of the residential electric supply in Allegheny’s Maryland service territory to be procured at market rates earlier than otherwise provided in its settlement agreement, so that residential electricity rates are not

exposed to volatile market conditions at one time while ensuring that customers obtain the full value of the savings provided under the existing rate cap.

Pennsylvania:On May 24, 2006, the PA PUC issued an Investigation Order (“Order”) for a generic investigation entitled “Policies to Mitigate Potential Electricity Price Increases.” The PUC’s purpose for this proceeding is to address the issues and develop policies to mitigate the effects of the higher electricity prices that may result with the expiration of the long-term generation price caps that are currently in place for many Pennsylvania utilities. Anen banc hearing to assist the PUC in developing policies to mitigate potential electricity price increases when rate caps ends was held on June 22, 2006.

The PA PUC is conducting an audit of the management efficiency of West Penn, as the PA PUC is required by state law to do every five to eight years for all major Pennsylvania utilities. The last such audit of West Penn by the PA PUC was completed in 2000. The audit is expected to take several months and concentrate on areas such as physical and information security, electric distribution system reliability, accounting controls and corporate governance.

In May 2004 the PA PUC modified its utility-specific benchmarks and performance standards for electric distribution system reliability. The benchmarks were set too low for West Penn, resulting in required reliability levels that were unattainable. West Penn appealed the benchmarks to the PA PUC. In 2005 the parties to the proceeding, including the Consumer Advocate, the Utility Workers Union of America Local 102, and the Rural Electric Association, entered an agreement settling the proceeding providing West Penn with attainable reliability benchmarks. The PA PUC approved the settlement in an Order issued July 27, 2006.

Virginia:Under the Virginia Electric Utility Restructuring Act of 1999 (the “Restructuring Act”), Potomac Edison’s retail electric customers in Virginia have the right to choose their electricity generation supplier. Potomac Edison is the PLR for those customers who do not choose an alternate generation supplier or whose alternate generation supplier does not deliver. The Restructuring Act capped Potomac Edison’s generation rates until July 1, 2007, but was amended in 2001 to provide that the rate for PLR retail service would be priced at market beginning July 1, 2007 (the “2001 Amendment”). The Restructuring Act was amended again in 2004 to extend the capped generation rate period until December 31, 2010, but provided for utilities, such as Potomac Edison, to recover purchased power costs (the “2004 Amendment”). Potomac Edison has a power purchase agreement with AE Supply to provide it with the amount of electricity necessary to meet its PLR retail obligations until July 1, 2007 at the capped generation rates. Beginning July 1, 2007, Potomac Edison will purchase its PLR requirements from the wholesale market at market prices. Market prices for purchased power at that time may be higher than the rates Potomac Edison will be allowed to recover from its retail customers.

Specifically, Allegheny believes that, based on the 2001 Amendment and the 2004 Amendment, that 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. However, based on a memorandum of understanding (“MOU”) between the Virginia State Corporation Commission (the “Virginia SCC”) and Potomac Edison entered into at the time of the transfer of Potomac Edison’s generation facilities to AE Supply in 2000, the Virginia SCC may find that the generation rates Potomac Edison is able to charge for a certain portion of the power it purchases, currently estimated to be approximately 2.2 million MWhs per year, would be limited to a price based upon a calculation of the cost to generate that power from the generation facilities that Potomac Edison previously owned. For the remainder of its power purchases, which Potomac Edison currently estimates to be approximately 1.1 million MWhs per year, Potomac Edison is permitted to petition the Virginia SCC to recover from its Virginia customers the market price of such MWhs beginning July 1, 2007. Thus, there can be no assurance that Potomac Edison will be able to recover any or all 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 may have a material adverse effect on Potomac Edison’s business, results of operations and financial condition.

Potomac Edison’s T&D rates in Virginia are capped through 2010, subject to certain exceptions. Prior to 2010, Potomac Edison has two opportunities to petition the Virginia SCC for changes to its T&D rates: the first prior to June 30, 2007, and the second 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.

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 2005 Annual Report on Form 10-K. Allegheny’s market risks have not changed materially from those reported in the 2005 Annual Report on Form 10-K.

As reported in the 2005 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 remaining 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 30, 2006 and December 31, 2005, this calculation yielded a VaR of $0.3 million and $0.4 million, respectively. This VaR decrease is primarily due to a decrease in forward positions of the portfolio and a decline of forward market prices.

ITEM 4. CONTROLS AND PROCEDURES

See, Item 9a, “Controls and Procedures,” in the 2005 Annual Report on Form 10-K for additional information relating to Controls and Procedures.

Disclosure Controls and Procedures.Each registrant 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 (a) material information relating to each registrant 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. There have been no changes in the registrants’ internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting during the three months ended September 30, 2006.

100

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Note 20, “Commitments and Contingencies,” for AE for information about legal proceedings. In addition, the registrants from time to time are involved in litigation and other legal disputes in the ordinary course of business.

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 2005 Annual Report on Form 10-K. The risk factors set forth below were disclosed in the 2005 Annual Report on Form 10-K, but have been updated to provide additional information.

Allegheny’s leverage could adversely affect its ability to operate successfully and meet contractual obligations.

Although Allegheny reduced debt by approximately $2.1 billion between December 1, 2003 and September 30, 2006 and plans to continue its debt reduction program, Allegheny still has substantial leverage. At September 30, 2006, Allegheny had $3.9 billion of debt on a consolidated basis. Approximately $2.2 billion represented debt of AE Supply and AGC and the remainder constituted debt of one or more of the Distribution Companies.

Allegheny’s leverage could have important consequences to it. For example, it could:

	•		make it more difficult for Allegheny to satisfy its obligations under the agreements governing its debt;

	•		require Allegheny to dedicate a substantial portion of its cash flow to payments on its debt, thereby reducing the availability of its cash flow for working capital, capital expenditures and other general corporate purposes;

	•		limit Allegheny’s flexibility in planning for, or reacting to, changes in its business, regulatory environment and the industry in which it operates;

	•		place Allegheny at a competitive disadvantage compared to its competitors that have less leverage;

	•		limit Allegheny’s ability to borrow additional funds; and

	•		increase Allegheny’s vulnerability to general adverse economic, regulatory and industry conditions.

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

Allegheny is dependent on coal for much of its electric generation capacity. Allegheny has coal supply contracts in place that partially mitigate its exposure to negative fluctuations in coal prices. Allegheny can provide no assurance, however, that the counterparties to these agreements will fulfill their obligations to supply coal. The suppliers under these agreements may experience financial or technical problems that inhibit their ability to fulfill their obligations. Various industry and operational factors, including increased costs, transportation constraints, safety issues and operational difficulties may have negative effects on coal supplier performance. In addition, the suppliers under these agreements may not be required to supply coal to Allegheny under certain circumstances, such as in the event of a natural disaster. If Allegheny is unable to obtain its coal requirements under these contracts, it may be required to purchase coal at higher prices, which could have a material adverse effect on its financial condition, cash flow and results of operations.

Based on current forecasts, Allegheny estimates that it will have minimal exposure to the SO₂ allowance market in 2006, and may have exposure of about 40,000 tons in 2007 and between 40,000 and 80,000 tons in 2008. The exposure of Monongahela is expected to be approximately 75% of Allegheny’s exposure in 2007 and 2008. 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. Therefore, there can be no assurance that Allegheny’s need to purchase SO₂ allowances for these periods will not vary from current estimates. Fluctuations in the availability or cost of emission allowances could have a material adverse effect on Allegheny’s financial condition, cash flows and results of operations.

101

Rate regulation in West Virginia may delay or deny Monongahela’s and Potomac Edison’s full recovery of costs.

The West Virginia PSC sets Monongahela’s and Potomac Edison’s rates in West Virginia through traditional, cost-based regulated utility ratemaking. As part of Monongahela’s and Potomac Edison’s efforts to spur deregulation in West Virginia, they agreed to terminate their respective fuel clauses, effective July 1, 2000. Thus, to recover increased, unexpected or necessary costs, including increased coal and other raw material costs, Monongahela and Potomac Edison filed, on July 26, 2006, for approval from the West Virginia PSC to recover such costs and to reinstate their respective fuel clauses. There can be no assurance that either Monongahela or Potomac Edison will be able to recover such costs or reinstate their respective fuel clauses under the ratemaking process. Even if Monongahela and Potomac Edison are able to recover these costs, there may be a significant delay between the time that they incur such costs and the time that they are allowed to recover such costs.

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.

102

ITEM 6. EXHIBITS

EXHIBIT INDEX

Allegheny Energy, Inc.


		Documents

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

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

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

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

103

EXHIBIT INDEX

Monongahela Power Company


		Documents

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

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

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

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

104

EXHIBIT INDEX

Allegheny Generating Company


		Documents

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

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

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

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

105

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 7, 2006	By:	/s/ Philip L. Goulding
		Philip L. Goulding
		Senior Vice President and
		Chief Financial Officer

		MONONGAHELA POWER COMPANY

Date: November 7, 2006	By:	/s/ Philip L. Goulding
		Philip L. Goulding
		Vice President and
		Principal Financial Officer

		ALLEGHENY GENERATING COMPANY.

Date: November 7, 2006	By:	/s/ Philip L. Goulding
		Philip L. Goulding
		Vice President and
		Principal Financial Officer

106

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

Allegheny Generating Inactive 10-Q2006 Q3 Quarterly report

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