Allegheny Energy 10Q 2006 Q2 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 June 30, 2006


	Name of Registrant
	State of Incorporation
Commission	Address of Principal Executive	IRS Employer
File Number	Offices and Telephone Number	Identification 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 July 31, 2006:


Allegheny Energy, Inc.	164,590,518	($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)		3

Allegheny Energy, Inc.:
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2006 and 2005		3
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2006 and 2005		4
Consolidated Balance Sheets as of June 30, 2006 and December 31, 2005		5
Notes to Consolidated Financial Statements		7

Monongahela Power Company:
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2006 and 2005		35
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2006 and 2005		36
Consolidated Balance Sheets as of June 30, 2006 and December 31, 2005		37
Notes to Consolidated Financial Statements		39

Allegheny Generating Company:
Statements of Operations for the Three and Six Months Ended June 30, 2006 and 2005		49
Statements of Cash Flows for the Six Months Ended June 30, 2006 and 2005		50
Balance Sheets as of June 30, 2006 and December 31, 2005		51
Notes to Financial Statements		53

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”)		56

Item 3. Quantitative and Qualitative Disclosures About Market Risk		92

Item 4. Controls and Procedures		92

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		93

Item 1A. Risk Factors		93

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		94

Item 3. Defaults Upon Senior Securities		94

Item 4. Submission of Matters to a Vote of Security Holders		94

Item 5. Other Information		95

Item 6. Exhibits		96

Signatures		99

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, which 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						Six Months Ended
	June 30,						June 30,
(In thousands)	2006			2005			2006			2005
Operating revenues	$	722,235		$	714,650		$	1,567,881		$	1,468,680

Operating expenses:
Fuel consumed in electric generation		186,185			166,139			399,392			340,026
Purchased power and transmission		95,097			108,243			196,329			213,065
Gain on sale of OVEC power agreement and shares		(1,124	)		—			(6,124	)		—
Deferred energy costs, net		413			(1,805	)		5,406			(619	)
Operations and maintenance		205,871			200,906			367,734			363,583
Depreciation and amortization		68,169			77,358			136,011			153,769
Taxes other than income taxes		52,201			51,738			105,868			106,796

Total operating expenses		606,812			602,579			1,204,616			1,176,620

Operating income		115,423			112,071			363,265			292,060

Other income and expenses, net (Note 14)		10,258			21,234			17,929			26,487

Interest expense and preferred dividends:
Interest expense		76,425			128,277			143,813			254,071
Preferred dividends of subsidiary		293			1,260			586			2,519

Total interest expense and preferred dividends		76,718			129,537			144,399			256,590

Income from continuing operations before income taxes and minority interest		48,963			3,768			236,795			61,957

Income tax expense from continuing operations		16,741			9,815			89,245			33,191

Minority interest in net income of subsidiaries		191			52			1,369			467

Income (loss) from continuing operations		32,031			(6,099	)		146,181			28,299

Loss from discontinued operations, net of tax (Note 5)		(898	)		(12,308	)		(1,664	)		(4,064	)

Net income (loss)	$	31,133		$	(18,407	)	$	144,517		$	24,235

Common share data:
Weighted average common shares outstanding
Basic		163,526			156,731			163,304			147,128
Diluted		168,608			156,731			168,557			150,276
Basic income (loss) per common share:
Income (loss) from continuing operations	$	0.20		$	(0.04	)	$	0.89		$	0.19
Loss from discontinued operations		(0.01	)		(0.08	)		(0.01	)		(0.03	)

Net income (loss) per common share	$	0.19		$	(0.12	)	$	0.88		$	0.16

Diluted income (loss) per common share:
Income (loss) from continuing operations	$	0.19		$	(0.04	)	$	0.87		$	0.19
Loss from discontinued operations		(0.01	)		(0.08	)		(0.01	)		(0.03	)

Net income (loss) per common share	$	0.18		$	(0.12	)	$	0.86		$	0.16

See accompanying Notes to Consolidated Financial Statements.

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


	Six Months Ended
	June 30,
(In thousands)	2006			2005
					(Revised-Note 1)
Cash Flows From Operating Activities:
Net income	$	144,517		$	24,235
Loss from discontinued operations, net of tax		1,664			4,064

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		136,011			153,769
Amortization of debt issuance costs		16,171			10,632
Amortization of power sale liability related to Ohio sale		(15,500	)		—
Amortization of reserve for adverse power purchase commitment		(8,577	)		(8,363	)
Gain on asset sales and disposals		(1,023	)		(1,614	)
Minority interest in net income of subsidiaries		1,369			467
Deferred income taxes and investment tax credit, net		89,628			27,650
Stock-based compensation expense		7,928			6,390
Unrealized gains on commodity contracts, net		(18,301	)		(13,278	)
Pension and other postretirement employee benefit plans expense		21,193			21,662
Pension and other postretirement employee benefit plans contributions		(65,381	)		(42,269	)
Other, net		17,514			9,089

Changes in certain assets and liabilities:
Accounts receivable, net		46,303			(35,795	)
Materials, supplies and fuel		(23,558	)		(22,701	)
Prepaid taxes		(7,596	)		(4,029	)
Collateral deposits		87,129			(17,111	)
Other current assets		164			7,093
Accounts payable		(111,169	)		(21,769	)
Accrued taxes		(23,056	)		(21,171	)
Accrued interest		5,429			41,082
Other current liabilities		937			6,546
Other assets		20,196			122
Other liabilities		(1,038	)		2,924
Net cash provided by (used in) operating activities of discontinued operations		(2,138	)		61,850

Net cash provided by operating activities		318,816			189,475


Cash Flows From Investing Activities:
Capital expenditures		(196,757	)		(126,641	)
Proceeds from asset sales		2,081			13,361
Purchase of minority interest in Hunlock Creek Energy Ventures		(13,900	)		—
Decrease in restricted funds		7,282			206,562
Other investments		(1,701	)		(767	)
Net cash provided by (used in) investing activities of discontinued operations		27,401			(3,766	)

Net cash provided by (used in) investing activities		(175,594	)		88,749

Cash Flows From Financing Activities:
Issuance of long-term debt		1,142,076			160,040
Repayment of long-term debt		(1,352,056	)		(443,145	)
Payments on capital lease obligations		(29	)		—
Proceeds from the exercise of employee stock options		10,244			1,196
Cash dividends paid to minority shareholder in Hunlock Creek Energy Ventures		(400	)		—
Net cash used in financing activities of discontinued operations		—			(7	)

Net cash used in financing activities		(200,165	)		(281,916	)

Net decrease in cash and cash equivalents		(56,943	)		(3,692	)
Cash and cash equivalents at beginning of period		262,212			189,482

Cash and cash equivalents at end of period	$	205,269		$	185,790

Supplemental Cash Flow Information:
Cash paid for interest (net of amount capitalized)	$	126,549		$	216,945

See accompanying Notes to Consolidated Financial Statements.

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


	June 30,			December 31,
(In thousands)	2006			2005
ASSETS
Current Assets:
Cash and cash equivalents	$	205,269		$	262,212
Accounts receivable:
Customer		170,807			179,634
Unbilled utility revenue		97,678			129,111
Wholesale and other		68,117			82,261
Allowance for uncollectible accounts		(16,085	)		(16,778	)
Materials and supplies		94,983			98,069
Fuel		91,556			67,273
Deferred income taxes		56,429			93,404
Prepaid taxes		53,354			45,758
Assets held for sale (Note 5)		921			1,521
Collateral deposits		60,646			147,775
Commodity contracts		4,651			9,325
Restricted funds		14,307			21,589
Regulatory assets		37,777			38,418
Other		12,365			14,246

Total current assets		952,775			1,173,818

Property, Plant and Equipment, Net:
Generation		5,759,004			5,751,077
Transmission		1,050,271			1,028,323
Distribution		3,521,355			3,448,350
Other		401,226			429,108
Accumulated depreciation		(4,563,742	)		(4,508,707	)

Subtotal		6,168,114			6,148,151
Construction work in progress		182,436			129,277

Total property, plant and equipment, net		6,350,550			6,277,428

Investments and Other Assets:
Non-current assets held for sale (Note 5)		21,179			48,559
Goodwill		367,287			367,287
Investments in unconsolidated affiliates		28,020			28,555
Intangible assets		27,396			27,396
Other		42,067			49,413

Total investments and other assets		485,949			521,210

Deferred Charges:
Commodity contracts		234			—
Regulatory assets		521,515			544,810
Other		30,918			41,546

Total deferred charges		552,667			586,356

Total Assets	$	8,341,941		$	8,558,812

See accompanying Notes to Consolidated Financial Statements.

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


	June 30,			December 31,
(In thousands, except share amounts)	2006			2005
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Long-term debt due within one year (Note 4)	$	494,889		$	477,217
Accounts payable		211,734			316,713
Accrued taxes		138,534			154,587
Commodity contracts		32,732			92,934
Accrued interest		94,253			91,433
Other		149,821			153,570

Total current liabilities		1,121,963			1,286,454


Long-term Debt (Note 4)		3,404,112			3,624,483

Deferred Credits and Other Liabilities:
Commodity contracts		20,169			22,994
Investment tax credit		74,423			76,965
Deferred income taxes		755,960			692,241
Obligations under capital leases		13,918			16,427
Regulatory liabilities		456,055			454,275
Adverse power purchase commitment		175,581			184,224
Other		409,734			459,465

Total deferred credits and other liabilities		1,905,840			1,906,591

Commitments and Contingencies (Note 18)

Minority Interest		9,520			21,989

Preferred Stock of Subsidiary		24,000			24,000

Common Stockholders’ Equity:
Common stock—$1.25 par value per share, 260 million shares authorized and 164,223,364 and 163,002,295 shares issued at June 30, 2006 and December 31, 2005		205,279			203,753
Other paid-in capital		1,891,907			1,880,644
Accumulated deficit		(100,107	)		(244,625	)
Treasury stock at cost; 49,493 shares		(1,756	)		(1,756	)
Accumulated other comprehensive loss		(118,817	)		(142,721	)

Total common stockholders’ equity		1,876,506			1,695,295

Total Liabilities and Stockholders’ Equity	$	8,341,941		$	8,558,812

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		8

2	Stock-Based Compensation		9

3	Review of Estimated Remaining Service Lives and Depreciation Practices		13

4	Debt		14

5	Discontinued Operations and Assets Held for Sale		15

6	Derivative Instruments and Hedging Activities		17

7	Asset Retirement Obligations (“AROs”)		17

8	Business Segments		19

9	Goodwill and Intangible Assets		20

10	Comprehensive Income (Loss)		20

11	Pension Benefits and Postretirement Benefits Other Than Pensions		21

12	Income (Loss) Per Share		24

13	Accounting for the Effects of Price Regulation		25

14	Other Income and Expenses, Net		25

15	Guarantees and Letters of Credit		26

16	Variable Interest Entities		26

17	HCEV Partnership Interest		27

18	Commitments and Contingencies		27

19	Subsequent Event		34

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 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 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 unaudited interim 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.

During the third quarter of 2004, AE and certain of its subsidiaries entered into agreements to sell, or made the decision to sell, certain non-core assets. The results of operations relating to these assets have been reclassified to discontinued operations in the accompanying Consolidated Statements of Operations for all periods presented, through the date of sale. The assets and liabilities associated with these discontinued operations have been reclassified as held for sale in the Consolidated Balance Sheets as of, and subsequent to, the date that held for sale criteria were met.

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 six months ended June 30, 2005 was revised during 2006 to conform to this presentation. Accordingly, for the six months ended June 30, 2005, approximately $3.8 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.

New Accounting Standards. As discussed further in Note 2, “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.

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

In July 2006, the Financial Accounting Standards Board issued FASB Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109.” FIN 48 prescribes a comprehensive model for how a company should recognize, measure, present, and disclose in its financial statements uncertain tax positions that it has taken or expects to take on a tax return. FIN 48 is effective in the first quarter of 2007. Allegheny is currently evaluating the impact of this statement on the company.

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, which are described below.

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: STOCK-BASED COMPENSATION

In December 2004, the FASB issued SFAS No. 123R. This Statement 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 the Company’s SFAS No. 123 pro-forma disclosures, net of estimated forfeitures. Prior to the adoption of SFAS No. 123R, Allegheny applied the provisions of SFAS No. 123 to its employee stock option and stock unit awards, which permitted the Company to account for stock-based compensation using the intrinsic value method prescribed by APB No. 25, 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.

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

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Stock options	$	1.9	$	—	$	4.0	$	—
Stock units		1.5		3.0		3.3		6.1
Other		0.3		0.2		0.6		0.3

Compensation expense included in operations and maintenance expense		3.7		3.2		7.9		6.4
Income tax benefit		1.5		1.4		3.2		2.7

Total, net of tax	$	2.2	$	1.8	$	4.7	$	3.7

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

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 (loss) and earnings (loss) 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			Six Months Ended
	June 30,			June 30,
(In millions)	2005			2005
Consolidated net income (loss), as reported	$	(18.4	)	$	24.2
Add:
Stock-based employee compensation expense included in consolidated net income, net of related tax effects		1.8			3.7
Deduct:
Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		3.0			6.2

Consolidated net income (loss), pro forma	$	(19.6	)	$	21.7


Basic income (loss) per share:
As reported	$	(0.12	)	$	0.16
Pro forma	$	(0.13	)	$	0.15

Diluted income (loss) per share:
As reported	$	(0.12	)	$	0.16
Pro forma	$	(0.13	)	$	0.14

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 each stock option award are generally determined by the Compensation Committee of the Board of Directors. The exercise price of each award has been equal to 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 three 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. The Company 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 a combination of our historical stock volatility and the volatility levels implied on the grant date by actively traded option contracts on our common stock. The expected term of the 2006 stock option grants was calculated in accordance with SEC Staff Accounting Bulletin (“SAB”) 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 six months ended June 30, 2006 and 2005:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
(Dollar amounts in millions)	2006			2005			2006			2005
Annual risk-free interest rate		4.96	%		4.28	%		4.55	%		4.15	%
Expected term of the option (in years)		6.5			6.5			6.5			6.5
Expected annual dividend yield		—			—			—			—
Expected stock price volatility		29.5	%		35.0	%		29.5	%		35.0	%
Grant date fair value per stock option	$	14.54		$	9.22		$	14.18		$	8.77

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


				Weighted-Average
	Number of			Exercise
	Stock Options			Price
Outstanding at March 31, 2006		5,961,523		$	16.90
Granted		3,000		$	35.39
Exercised		(89,550	)	$	19.97
Forfeited		(243,960	)	$	23.86

Outstanding at June 30, 2006		5,631,013		$	16.56

Stock option activity for the six months ended June 30, 2006 was as follows:


				Weighted-Average
	Number of			Exercise
	Stock Options			Price
Outstanding at December 31, 2005		6,141,357		$	17.04
Granted		138,000		$	35.49
Exercised		(390,984	)	$	26.20
Forfeited		(257,360	)	$	23.35

Outstanding at June 30, 2006		5,631,013		$	16.56

The grant-date fair value of options granted during the three and six months ended June 30, 2006 was $0.1 million and $2.0 million, respectively. The total intrinsic value of options exercised during the three and six months ended June 30, 2006 was $1.4 million and $3.6 million, respectively. Cash received by the Company from option exercises totaled $1.7 million and $10.2 million for the three and six months ended June 30, 2006, respectively. Allegheny issued new shares to satisfy these stock option exercises. There was no actual tax benefit realized from tax deductions on options exercised during the three or six months ended June 30, 2006 because of the Company’s tax operating loss carryforwards.

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

Stock options outstanding at June 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		4,569,996		7.67	$	13.45	$	108.0
$15.00 - $19.99		161,800		8.56	$	18.91		2.9
$20.00 - $24.99		215,000		8.52	$	21.03		3.5
$25.00 - $29.99		75,000		9.42	$	28.49		0.6
$30.00 - $34.99		257,500		3.54	$	31.77		1.4
$35.00 - $39.99		160,800		9.02	$	35.99		0.2
$40.00 - $44.99		175,917		4.44	$	42.28		*
$45.00 - $49.99		15,000		4.75	$	46.26		*

Total		5,631,013		7.49	$	16.56	$	116.6


*		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 June 30, 2006.

Stock options exercisable at June 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		2,139,522		7.65	$	13.41	$	50.6
$15.00 - $19.99		34,333		8.56	$	18.99		0.6
$20.00 - $24.99		59,000		7.88	$	20.92		1.0
$25.00 - $29.99		—		—	$	—		—
$30.00 - $34.99		257,500		3.54	$	31.77		1.4
$35.00 - $39.99		22,800		5.18	$	39.01		*
$40.00 - $44.99		175,917		4.44	$	42.29		*
$45.00 - $49.99		15,000		4.75	$	46.26		*

Total		2,704,072		7.04	$	17.67	$	53.6


*		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 June 30, 2006.

As of June 30, 2006, there was $17.6 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 1.4 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 six months ended June 30, 2006.

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

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


				Weighted-Average		Aggregate
	Number of			Grant Date		Intrinsic Value
	Stock Units			Fair Value		(in millions)
Outstanding at March 31, 2006		2,899,288		$	15.39
Converted		(1,239,663	)	$	15.35
Forfeited		(20,000	)	$	14.74

Outstanding at June 30, 2006		1,639,625		$	15.43	$	60.8

Convertible at June 30, 2006		365,628		$	15.30	$	13.5

Stock unit activity for the six months ended June 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
Converted		(1,346,881	)	$	15.34
Forfeited		(20,000	)	$	14.74

Outstanding at June 30, 2006		1,639,625		$	15.43	$	60.8

Convertible at June 30, 2006		365,628		$	15.30	$	13.5

The total intrinsic value of stock units converted to common shares during the three and six months ended June 30, 2006 was $45.8 million and $49.5 million, respectively. Allegheny issued new shares to satisfy these stock unit conversions.

As of June 30, 2006, there was $5.2 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 3: 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 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 approximately $8.8 million and $17.7 million for the three and six months ended June 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 approximately $6.5 million and $10.3 million for the three and six months ended June 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 4: DEBT

At June 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:
AE Credit Facility	$	0.9		$	1.8		$	1.8		$	1.8		$	1.8		$	161.0		$	169.1

Total AE	$	0.9		$	1.8		$	1.8		$	1.8		$	1.8		$	161.0		$	169.1

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		—			—			—			—			—			852.0			852.0

Total AE Supply	$	—		$	91.7		$	—		$	—		$	—		$	2,193.4		$	2,285.1

Monongahela:
First Mortgage Bonds	$	300.0		$	—		$	—		$	—		$	—		$	190.0		$	490.0
Pollution Control Bonds		—			15.5			—			—			—			70.3			85.8
Medium-Term Notes		—			—			—			—			110.0			—			110.0

Total Monongahela	$	300.0		$	15.5		$	—		$	—		$	110.0		$	260.3		$	685.8

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	$	36.7		$	79.9		$	75.4		$	73.1		$	14.7		$	—		$	279.8
Medium-Term Notes		—			—			—			—			—			80.0			80.0

Total West Penn	$	36.7		$	79.9		$	75.4		$	73.1		$	14.7		$	80.0		$	359.8
AGC:
Debentures	$	—		$	—		$	—		$	—		$	—		$	100.0		$	100.0

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

Unamortized debt discounts, premiums and terminated interest rate swaps		(0.6	)		(1.2	)		(1.2	)		(1.3	)		(1.2	)		(2.5	)		(8.0	)
Eliminations		—			(2.3	)		—			—			—			(110.5	)		(112.8	)

Total consolidated debt	$	437.0		$	185.4		$	76.0		$	73.6		$	125.3		$	3,001.7		$	3,899.0

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 an initial interest rate equal to the London Interbank Offered Rate (“LIBOR”) plus 0.875%, 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

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

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.

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


	Three Months Ended				Six Months Ended
	June 30, 2006				June 30, 2006
(In millions)	Issuances		Repayments		Issuances		Repayments
AE:
AE Credit Facility (a)	$	179.1	$	10.0	$	179.1	$	10.0
Prior Credit Facility (b)		—		189.0		—		199.0

Total AE	$	179.1	$	199.0	$	179.1	$	209.0

AE Supply:
AE Supply Credit Facility (c)	$	967.0	$	115.0	$	967.0	$	115.0
Prior AE Supply Loan (d)		—		967.0		—		989.0

Total AE Supply	$	967.0	$	1,082.0	$	967.0	$	1,104.0

West Penn:
Transition Bonds (e)	$	1.3	$	19.3	$	2.6	$	39.1

Consolidated Total	$	1,147.4	$	1,300.3	$	1,148.7	$	1,352.1


(a)		Reflects issuances and repayments under the AE Credit Facility, which was entered into on May 22, 2006.

(b)		Reflects repayments under AE’s prior credit facility, which was refinanced on May 22, 2006.

(c)		Reflects issuances and repayments under the AE Supply Credit Facility, which was entered into on May 2, 2006.

(d)		Reflects issuances and repayments under AE Supply’s prior term loan, which was refinanced on May 2, 2006.

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

NOTE 5: DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE

During the third quarter of 2004, Allegheny and certain of its subsidiaries decided to sell certain non-core assets. 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, through the date of sale. In addition, the assets and liabilities associated with these discontinued operations have been classified as held for sale in the consolidated balance sheets through the dates on which the sales concluded.

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

The components of income (loss) from discontinued operations were as follows:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2006			2005			2006			2005
AE Supply:
Operating revenues	$	—		$	0.2		$	—		$	0.4
Operating expenses		(0.4	)		(1.1	)		(0.8	)		(2.3	)
Interest expense		(0.9	)		(3.1	)		(1.8	)		(6.2	)

Loss before income taxes		(1.3	)		(4.0	)		(2.6	)		(8.1	)
Income tax benefit		0.5			1.4			1.0			2.8
Impairment charge, net of tax		(0.1	)		(3.2	)		(0.1	)		(3.2	)

Loss from discontinued operations, net of tax	$	(0.9	)	$	(5.8	)	$	(1.7	)	$	(8.5	)

Monongahela:
Operating revenues	$	—		$	46.6		$	—		$	196.8
Operating expenses		—			(46.0	)		—			(176.2	)
Other income and expenses, net		—			0.6			—			0.9
Interest expense		—			(2.0	)		—			(4.1	)

Income (loss) before income taxes		—			(0.8	)		—			17.4
Income tax expense		—			—			—			(6.7	)
Impairment charge, net of tax		—			(5.7	)		—			(6.3	)

Income (loss) from discontinued operations, net of tax	$	—		$	(6.5	)	$	—		$	4.4

Allegheny:
Operating revenues	$	—		$	46.8		$	—		$	197.2
Operating expenses		(0.4	)		(47.1	)		(0.8	)		(178.5	)
Other income and expenses, net		—			0.6			—			0.9
Interest expense		(0.9	)		(5.1	)		(1.8	)		(10.3	)
Income (loss) before income taxes		(1.3	)		(4.8	)		(2.6	)		9.3
Income tax benefit (expense)		0.5			1.4			1.0			(3.9	)
Impairment charge, net of tax		(0.1	)		(8.9	)		(0.1	)		(9.5	)

Loss from discontinued operations, net of tax.	$	(0.9	)	$	(12.3	)	$	(1.7	)	$	(4.1	)

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:


	June 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

On May 25, 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 $27.4 million.

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

NOTE 6: 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 (loss)” until contract settlement. See Note 10, “Comprehensive Income (Loss)” to the Consolidated Financial Statements. These contracts expire at various dates through September 2007. The accumulated other comprehensive loss for the contracts was $11.5 million at June 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 for these contracts at June 30, 2006 was $11.5 million and is expected to be completely reclassified as a reduction to earnings over the next fifteen months. The ineffective portion of the cash flow hedges of $0.3 million and $0.9 million is reflected in earnings for the three and six months ended June 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 $48.0 and $106.6 million at June 30, 2006 and December 31, 2005, respectively. Operating revenues included net unrealized gains of $5.3 million and $9.2 million and net realized losses of $8.2 million and $4.2 million for the three months ended June 30, 2006 and 2005, respectively. Operating revenues included net unrealized gains of $18.3 million and $13.3 million and net realized losses of $4.6 million and $6.8 million for the six months ended June 30, 2006 and 2005, respectively, relating to cash flow hedges and trading activities.

NOTE 7: ASSET RETIREMENT OBLIGATIONS (“AROs”)

Effective December 31, 2005, Allegheny adopted Financial Interpretation (“FIN”) 47, “Accounting for Conditional Asset Retirement Obligations (“Conditional AROs”),” 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 effect of adopting FIN 47 on Allegheny’s Consolidated Balance Sheets at December 31, 2005 was as follows:


	Effect of Adopting FIN 47 Increase
	Property,				Non-Current
	Plant and		Non-Current		Liabilities
	Equipment,		Regulatory		(Conditional
(In millions)	Net		Asset		AROs)
AE Supply	$	0.5	$	—	$	9.8
Monongahela		0.3		5.3		5.6
Potomac Edison		—		0.3		0.4
West Penn		—		0.4		0.4

Total Allegheny	$	0.8	$	6.0	$	16.2

For the six months ended June 30, 2006, Allegheny’s total ARO balance, which includes both AROs and Conditional AROs, increased $2.2 million, from $48.8 million at December 31, 2005 to $51.0 million at June 30, 2006. This increase was primarily due to accretion of the liability.

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

Allegheny believes it is probable that 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.

Under the rate making process, regulators generally permit recovery of costs associated with removing property, plant and equipment, which can relate to assets with, or without, an associated ARO. To the extent estimated removal costs are recovered in rates prior to being expended, or prior to being recognized as ARO deferred regulatory costs, such recoveries represent regulatory liabilities. To the extent estimated removal costs are expended prior to being recovered in rates, such recoveries represent regulatory assets. These estimated removal costs, which represent a regulatory liability (asset), were as follows:


	June 30,			December 31,
(In millions)	2006			2005
Monongahela	$	246.8		$	242.1
Potomac Edison		177.3			170.8
West Penn		(15.9	)		(17.4	)

Total	$	408.2		$	395.5

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

NOTE 8: BUSINESS SEGMENTS

Allegheny manages and evaluates its operations in two business segments, the Delivery and Services segment and the Generation and Marketing segment. 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 June 30, 2006											Three months ended June 30, 2005
	Delivery		Generation									Delivery			Generation
	and		and									and			and
(In millions)	Services		Marketing			Eliminations			Total			Services			Marketing			Eliminations			Total
External operating revenues	$	630.6	$	91.7		$	—		$	722.3		$	661.1		$	53.6		$	—		$	714.7
Internal operating revenues		1.9		322.4			(324.3	)		—			2.1			350.9			(353.0	)		—

Total operating revenues	$	632.5	$	414.1		$	(324.3	)	$	722.3		$	663.2		$	404.5		$	(353.0	)	$	714.7
Depreciation and amortization	$	37.9	$	30.3		$	—		$	68.2		$	39.0		$	38.4		$	—		$	77.4
Operating income	$	54.3	$	61.2		$	—		$	115.5		$	58.9		$	53.2		$	—		$	112.1
Interest expense	$	22.1	$	55.3		$	(1.0	)	$	76.4		$	46.5		$	82.0		$	(0.2	)	$	128.3
Income (loss) from continuing operations	$	23.3	$	8.7		$	—		$	32.0		$	16.9		$	(23.0	)	$	—		$	(6.1	)
Loss from discontinued operations, net of tax	$	—	$	(0.9	)	$	—		$	(0.9	)	$	(6.5	)	$	(5.8	)	$	—		$	(12.3	)
Net income (loss)	$	23.3	$	7.8		$	—		$	31.1		$	10.4		$	(28.8	)	$	—		$	(18.4	)


	Six months ended June 30, 2006											Six months ended June 30, 2005
	Delivery		Generation									Delivery		Generation
	and		and									and		and
(In millions)	Services		Marketing			Eliminations			Total			Services		Marketing			Eliminations			Total
External operating revenues	$	1,331.4	$	236.5		$	—		$	1,567.9		$	1,398.3	$	70.4		$	—		$	1,468.7
Internal operating revenues		3.7		684.7			(688.4	)		—			4.3		751.0			(755.3	)		—

Total operating revenues	$	1,335.1	$	921.2		$	(688.4	)	$	1,567.9		$	1,402.6	$	821.4		$	(755.3	)	$	1,468.7
Depreciation and amortization	$	75.6	$	60.4		$	—		$	136.0		$	77.1	$	76.7		$	—		$	153.8
Operating income	$	146.4	$	216.9		$	—		$	363.3		$	154.8	$	137.3		$	—		$	292.1
Interest expense	$	41.8	$	103.4		$	(1.4	)	$	143.8		$	75.4	$	178.9		$	(0.2	)	$	254.1
Income (loss) from continuing operations	$	69.7	$	76.5		$	—		$	146.2		$	66.6	$	(38.2	)	$	(0.1	)	$	28.3
Income (loss) from discontinued operations, net of tax	$	—	$	(1.7	)	$	—		$	(1.7	)	$	4.3	$	(8.5	)	$	0.1		$	(4.1	)
Net income (loss)	$	69.7	$	74.8		$	—		$	144.5		$	70.9	$	(46.7	)	$	—		$	24.2

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

NOTE 9: GOODWILL AND INTANGIBLE ASSETS

There were no changes in goodwill during the six months ended June 30, 2006.

The intangible assets included in “Investments and Other Assets” on the Consolidated Balance Sheets of $27.4 million at both June 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:


	June 30, 2006				December 31, 2005
	Gross Carrying		Accumulated		Gross Carrying		Accumulated
(In millions)	Amount		Amortization		Amount		Amortization
Land easements, amortized	$	97.8	$	27.8	$	97.7	$	27.1
Land easements, unamortized		30.7		—		30.6		—
Software		54.3		38.2		72.3		50.9

Total	$	182.8	$	66.0	$	200.6	$	78.0

Amortization expense for intangible assets was $4.1 million and $3.8 million for the three months ended June 30, 2006 and 2005, respectively, and $7.7 million and $7.6 million for the six months ended June 30, 2006 and 2005, respectively.

Amortization expense for intangible assets is estimated to be as follows:


(In millions)	2006		2007		2008		2009		2010
Annual amortization expense	$	13.1	$	12.7	$	10.5	$	9.8	$	8.8

NOTE 10: COMPREHENSIVE INCOME (LOSS)

Allegheny’s consolidated comprehensive income (loss) was as follows:


	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In millions)	2006		2005			2006		2005
Consolidated net income (loss)	$	31.1	$	(18.4	)	$	144.5	$	24.2
Other comprehensive income (loss), net of tax:
Minimum pension liability adjustment		—		(0.1	)		—		(0.2	)
Changes in value of available for sale securities		—		(0.2	)		—		(0.3	)
Changes in fair value of cash flow hedges		6.2		0.4			23.9		(9.4	)

Consolidated comprehensive income (loss), net of income taxes	$	37.3	$	(18.3	)	$	168.4	$	14.3

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

The components of, and changes in, accumulated other comprehensive loss were as follows:


	Unrealized			Minimum
	Gain (Loss) on			Pension			Accumulated Other
	Cash Flow			Liability			Comprehensive
(In millions)	Hedges			Adjustment			Income (Loss)
Balance at December 31, 2005	$	(31.5	)	$	(111.2	)	$	(142.7	)
Changes in accumulated other comprehensive loss, net of tax		17.7			—			17.7

Balance at March 31, 2006	$	(13.8	)	$	(111.2	)	$	(125.0	)
Changes in accumulated other comprehensive loss, net of tax		6.2			—			6.2

Balance at June 30, 2006	$	(7.6	)	$	(111.2	)	$	(118.8	)

NOTE 11: PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

Substantially all of Allegheny’s employees, including officers, are employed by AESC and are covered by 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						Six Months Ended
	June 30,						June 30,
(In millions)	2006			2005			2006			2005
Components of net periodic cost:
Service cost	$	5.5		$	5.8		$	10.9		$	11.7
Interest cost		15.3			16.0			30.7			31.8
Expected return on plan assets		(17.4	)		(17.3	)		(34.8	)		(34.6	)
Amortization of unrecognized transition obligation		0.1			0.1			0.2			0.2
Amortization of prior service cost		0.9			0.9			1.8			1.8
Recognized actuarial loss		3.1			2.3			6.2			4.6

Subtotal		7.5			7.8			15.0			15.5
Settlements		—			—			—			0.2

Net periodic cost	$	7.5		$	7.8		$	15.0		$	15.7

Allocation of net periodic cost:
Monongahela	$	1.9		$	2.5		$	3.9		$	5.0
AE Supply		2.3			2.1			4.5			4.4
West Penn		1.9			1.8			3.7			3.5
Potomac Edison		1.3			1.3			2.7			2.6
AE		0.1			0.1			0.2			0.2

Net periodic cost	$	7.5		$	7.8		$	15.0		$	15.7


	Postretirement Benefits Other Than Pensions
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2006			2005			2006			2005
Components of net periodic cost:
Service cost	$	1.3		$	1.0		$	2.6		$	2.0
Interest cost		4.2			4.2			8.4			8.4
Expected return on plan assets		(1.8	)		(1.5	)		(3.5	)		(3.0	)
Amortization of unrecognized transition obligation		1.5			1.4			2.9			2.9
Recognized actuarial loss		1.0			0.5			1.9			1.0

Net periodic cost	$	6.2		$	5.6		$	12.3		$	11.3

Allocation of net periodic cost:
Monongahela	$	1.7		$	1.6		$	3.4		$	3.2
West Penn		1.7			1.6			3.4			3.1
Potomac Edison		1.3			1.2			2.6			2.4
AE Supply		1.5			1.2			2.8			2.5
AE		—			—			0.1			0.1

Net periodic cost	$	6.2		$	5.6		$	12.3		$	11.3

For the three months ended June 30, 2006 and 2005, Allegheny allocated $2.8 million and $2.6 million, respectively, and for the six months ended June 30, 2006 and 2005, Allegheny allocated $6.0 million and $5.3 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)

Employer Contributions.Allegheny makes contributions to its pension plans in order to meet at least the minimum required funding amount under ERISA. These anticipated contributions may change in the future if Allegheny’s assumptions regarding prevailing interest rates change, if actual investments under-perform or out-perform expectations, if actuarial assumptions or asset valuation methods change or if pending reform legislation is passed.

Allegheny contributed $0.1 million and $58.2 million to its pension plans during the three and six months ended June 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 $7.2 million to its postretirement benefits other than pension plans during the three and six months ended June 30, 2006, respectively.

Allegheny made cash matching contributions to the 401(k) Employee Stock Ownership and Savings Plan (the “ESOSP”) in the amount of $1.7 million and $3.8 million for the three and six months ended June 30, 2006, respectively.

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

NOTE 12: 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						Six Months Ended
	June 30,						June 30,
(In millions, except share amounts)	2006			2005			2006			2005
Basic Income (Loss) per Share:
Numerator:
Income (loss) from continuing operations, net of tax	$	32.0		$	(6.1	)	$	146.2		$	28.3
Loss from discontinued operations, net of tax		(0.9	)		(12.3	)		(1.7	)		(4.1	)

Net income (loss)	$	31.1		$	(18.4	)	$	144.5		$	24.2

Denominator:
Weighted average common shares outstanding		163,526,221			156,730,744			163,304,498			147,127,707
Basic Income (Loss) per Share:
Income (loss) from continuing operations, net of tax	$	0.20		$	(0.04	)	$	0.89		$	0.19
Loss from discontinued operations, net of tax		(0.01	)		(0.08	)		(0.01	)		(0.03	)

Net income (loss)	$	0.19		$	(0.12	)	$	0.88		$	0.16

Diluted Income (Loss) per Share:
Numerator:
Income (loss) from continuing operations, net of tax	$	32.0		$	(6.1	)	$	146.2		$	28.3
Loss from discontinued operations, net of tax		(0.9	)		(12.3	)		(1.7	)		(4.1	)

Net income (loss)	$	31.1		$	(18.4	)	$	144.5		$	24.2

Denominator:
Weighted average common shares outstanding		163,526,221			156,730,744			163,304,498			147,127,707
Effect of dilutive securities:
Stock options		2,599,683			—			2,582,517			999,071
Performance shares		25,497			—			35,839			61,065
Non-employee stock awards		40,677			—			37,177			19,600
Stock units		2,415,780			—			2,596,948			2,068,986

Total shares		168,607,858			156,730,744			168,556,979			150,276,429

Shares potentially issuable under:
Stock options		—			1,041,027			—			—
Performance shares		—			62,765			—			—
Non-employee stock awards		—			22,400			—			—
Stock units		—			1,914,873			—			—
Convertible Securities		—			5,819,363			—			15,356,198

Total shares		—			8,860,428			—			15,356,198

Diluted Income (Loss) per Share:
Income (loss) from continuing operations, net of tax	$	0.19		$	(0.04	)	$	0.87		$	0.19
Loss from discontinued operations, net of tax		(0.01	)		(0.08	)		(0.01	)		(0.03	)

Net income (loss)	$	0.18		$	(0.12	)	$	0.86		$	0.16

The effects of shares potentially issuable are not included in the calculation of diluted earnings (loss) per share, as these amounts are antidilutive. The convertible securities were converted into shares of AE common stock in the second quarter of 2005.

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

NOTE 13: ACCOUNTING FOR THE EFFECTS OF PRICE REGULATION

As of June 30, 2006, Allegheny’s liability for adverse power purchase commitments was $192.8 million, including a current liability of $17.2 million. Allegheny’s liability for adverse power purchase commitments decreased as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Decrease in liability for adverse power purchase commitments	$	4.3	$	4.2	$	8.6	$	8.4

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


	June 30,			December 31,
(In millions)	2006			2005
Property, plant and equipment	$	4,245.5		$	4,160.4
Amounts under construction included above	$	95.2		$	62.7
Accumulated depreciation	$	(2,027.3	)	$	(1,992.4	)

NOTE 14: 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				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Interest and dividend income	$	5.3	$	3.2	$	10.8	$	5.0
Coal brokering income		0.9		1.1		0.9		1.1
Gain on sale of land		0.8		—		0.8		1.6
Premium services		0.6		0.8		2.0		1.8
Gain on sale of investments		0.3		0.8		0.3		0.8
Cash received from a former trading executive’s forfeited assets		—		11.2		—		11.2
Proceeds from sale of AFN		—		3.0		—		3.0
Other		2.3		1.1		3.1		2.0

Total	$	10.2	$	21.2	$	17.9	$	26.5

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

NOTE 15: 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:


	June 30, 2006				December 31, 2005
	Amounts						Amounts
	Recorded on		Total		Recorded on		Total
	the		Guarantees		the		Guarantees
	Consolidated		and Letters		Consolidated		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		—		8.5		—		8.7
Lease agreement		—		4.7		—		4.7
Purchase, sale, exchange or transportation of wholesale natural gas, electric power and related services		—		8.9		—		3.9
Other		0.2		0.2		0.2		0.2

Total Guarantees	$	0.2	$	22.3	$	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	$	159.9	$	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 17, “HCEV Partnership Interest,” to the Consolidated Financial Statements for additional information.

(b)		This amount is 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, a letter of credit for $9.5 million issued due to an AE Ventures contractual obligation that expires in July 2007 and a $1.0 million letter of credit that is related to an interconnection agreement with TVA.

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

NOTE 16: VARIABLE INTEREST ENTITIES

FASB Interpretation No. 46R (“FIN 46R”), “Consolidation of Variable Interest Entities,” requires an investor with the majority of the variable interests in a variable interest entity (“VIE”) to consolidate the entity and also requires majority and significant variable interest investors to provide certain disclosures. A VIE is an entity 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 $26.3 million and $10.9 million, respectively, for the three months ended June 30, 2006, and $26.9 million and $9.6 million, respectively, for the three months ended June 30, 2005.

Potomac Edison and West Penn purchased power from these two IPPs in the amount of $44.8 million and $23.4 million, respectively, for the six months ended June 30, 2006, and $52.5 million and $21.4 million, respectively, for the six months ended June 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 17: 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 18: 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 SO₂emission allowance trading program. AE Supply and Monongahela comply with current SO₂emission 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 little to no exposure to the SO₂ allowance market in 2006, and may have exposure of between zero and 40,000 tons in 2007 and between 40,000 and 80,000 tons in 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 facility 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 (“NO_X”) by using low NO_X 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 NO_x State Implementation Plan (“SIP”) call rule (known as the “NO_x 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 NO_x controls to meet the Pennsylvania, Maryland and West Virginia SIP calls. The NO_x compliance plan functions on a system-wide basis, similar to the SO₂compliance plan. AE Supply and Monongahela also have the option, in some cases, to purchase alternate fuels or NO_x 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 NO_x 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 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. 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 expects to file comments to the proposed rule by the end of August 2006.

Additionally, Maryland passed the Healthy Air Act in early 2006. This legislation imposes state-wide emission caps on SO₂ and NO_X, 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. On June 20, 2006, the Maryland Department of the Environment announced its intent to implement the requirements of the Healthy Air Act through new regulations that remain subject to review by the Joint Committee on Administrative, Executive and Legislative Review. Allegheny is assessing the new legislation to determine what, if any, effect it could have 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

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

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 three 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 and the Alabama Power decision. The Ohio Edison decision is 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 is scheduled for the fall of 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.

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.

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 is subject to EPA and public review.

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

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

Canadian Toxic-Tort Class Action:On June 30, 2005, AE Supply, Monongahela and AGC, along with 18 other companies with coal-fired generation facilities, were named as defendants in a toxic-tort, purported class action lawsuit filed in the Ontario Superior Court of Justice. On behalf of a purported class comprised of all persons residing in Ontario within the past six years (and/or their family members or heirs), the named plaintiffs allege that the defendants negligently failed to prevent their generation facilities from emitting air pollutants in such a manner as to cause death and multiple adverse health effects, as well as economic damages, to the plaintiff class. The plaintiffs seek damages in the approximate amount of Canadian $49.1 billion (approximately US $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 yet been served with this lawsuit. 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 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 has not yet been served with this lawsuit. 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).

In connection with a settlement, Allegheny received the final installment payment from one of its insurance companies in the amount of $625,000 on July 3, 2006. As part of the settlement, Allegheny released this insurance company from potential liabilities associated with claims against Allegheny alleging asbestos exposure.

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 July 18, 2006, Allegheny had 837 open cases remaining in West Virginia and five open cases remaining in Pennsylvania.

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

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

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 June 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.

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.

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

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 will hear oral argument no earlier than September 11, 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.

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, one of the actions has been, and the other action will be, 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

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

defendants continue to deny allegations of wrongdoing, and they will receive 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 June 30, 2006, Allegheny filed summary judgment motions regarding the plaintiffs’ claims for, among other causes of action, property and punitive damages. 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.

Litigation with Mobotec.On July 20, 2004, Mobotec USA, Inc. (“Mobotec USA”) filed a lawsuit in the Court of Common Pleas of Greene County, Pennsylvania, against AE, AE Supply and an Allegheny employee (the “Mobotec USA Action”). Allegheny had contracted with Mobotec USA for the installation of NO_x emissions reduction equipment at certain Allegheny facilities. Mobotec USA’s complaint alleged that AE and AE Supply had breached the contracts by failing to pay Mobotec USA approximately $3.3 million. The complaint also asserted claims for enforcement of mechanics’ liens and claims for (a) intentional interference with prospective business relations; (b) trade libel and defamation; (c) breach of the covenant of good faith and fair dealing; (d) unjust enrichment and quantum meruit; and (e) civil conspiracy. Mobotec USA alleges that Allegheny falsely told third parties that Mobotec USA was unsuccessful in installing equipment and claims that it lost approximately $50 million in prospective business as a result.

On September 9, 2004, AE and AE Supply filed an answer denying Mobotec USA’s claims and asserting a counterclaim for breach of contract based on Mobotec USA’s failure to achieve the emissions reduction levels guaranteed in the agreements. On September 23, 2005, Mobotec USA filed a Second Amended Complaint, which added AESC as a party and added claims for breaches of confidentiality agreements and misappropriation of trade secrets. The Allegheny defendants have filed an answer denying Mobotec USA’s claims. On October 19, 2005, AE Supply and Monongahela commenced in the Court of Common Pleas of Greene County, Pennsylvania, a separate but related action against Mobotec USA, Mobotec AB (Mobotec USA’s parent company) and certain individuals affiliated with Mobotec (the “Mobotec Parties”). This separate action was soon thereafter consolidated with the Mobotec Action for all purposes. In their amended complaint, AE Supply and Monongahela asserted claims for breach of contract, restitution, breach of warranty, negligence and negligent misrepresentation, based on Mobotec’s conduct. The Mobotec Parties filed a motion seeking dismissal of certain claims and certain parties with respect to the amended complaint filed by AE Supply and Monongahela. On April 6, 2006, the Court entered an order denying the Mobotec Parties’ motion to dismiss, except for an implied warranty claim that AE Supply and Monongahela did not contest.

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

On May 23, 2006, Allegheny reached an agreement with the Mobotec Parties to settle the litigation. Pursuant to the settlement agreement, Allegheny paid Mobotec USA $1.1 million, all claims between the parties were dismissed with prejudice, and the parties exchanged mutual releases. The settlement does not constitute an admission of fault.

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.

NOTE 19: SUBSEQUENT EVENT

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 is evaluating the effect of this change, and expects to record a benefit during the third quarter of 2006 in the amount of $10 million to $20 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.

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In thousands)	2006			2005			2006			2005
Operating revenues	$	177,421		$	178,117		$	374,616		$	364,698
Operating expenses:
Fuel consumed in electric generation		40,522			33,281			84,586			68,258
Purchased power and transmission		42,696			54,839			83,832			113,497
Deferred energy costs, net		(623	)		—			(623	)		—
Operations and maintenance		49,211			52,205			90,699			96,116
Depreciation and amortization		16,354			16,734			32,720			33,504
Taxes other than income taxes		11,813			12,693			24,083			25,426

Total operating expenses		159,973			169,752			315,297			336,801

Operating income		17,448			8,365			59,319			27,897

Other income and expenses, net (Note 8)		4,179			3,480			7,837			5,712

Interest expense		10,583			10,618			21,311			21,361

Income from continuing operations before income taxes		11,044			1,227			45,845			12,248

Income tax expense (benefit) from continuing operations		4,185			(7,862	)		17,256			(8,163	)

Income from continuing operations		6,859			9,089			28,589			20,411

Income (loss) from discontinued operations, net of tax (Note 3)		—			(6,501	)		—			4,370

Net income	$	6,859		$	2,588		$	28,589		$	24,781

See accompanying Notes to Consolidated Financial Statements.

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


	Six Months Ended
	June 30,
(In thousands)	2006			2005
				(Revised-Note 1)
Cash Flows From Operating Activities:
Net income	$	28,589		$	24,781
Income from discontinued operations, net of tax		—			(4,370	)

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		32,720			33,504
Amortization of power sale liability related to Ohio sale		(15,500	)		—
Gain on asset sales		(72	)		(64	)
Deferred income taxes and investment tax credit, net		15,965			1,761
Other, net		3,035			538

Changes in certain assets and liabilities:
Accounts receivable, net		18,935			(7,135	)
Materials, supplies and fuel		(4,015	)		(1,074	)
Prepaid taxes		6,592			7,464
Collateral deposits		9,538			(9,540	)
Other current assets		(249	)		882
Accounts payable		(8,812	)		(4,812	)
Accounts payable to affiliates, net		(2,038	)		32,963
Accrued taxes		(4,317	)		(14,192	)
Other current liabilities		(6,449	)		(632	)
Other assets		8,093			1,888
Other liabilities		(5,291	)		660
Net cash provided by operating activities of discontinued operations		—			97,279

Net cash provided by operating activities		76,724			159,901

Cash Flows From Investing Activities:
Capital expenditures		(40,963	)		(30,657	)
Proceeds from asset sales		129			129
Note receivable from affiliate		(60,756	)		(42,995	)
Net cash used in investing activities of discontinued operations		—			(3,766	)

Net cash used in investing activities		(101,590	)		(77,289	)

Cash Flows From Financing Activities:
Deferred financing costs		(135	)		—
Cash dividends paid on capital stock:
Preferred stock		(586	)		(2,519	)
Common stock		(10,015	)		—
Net cash used in financing activities of discontinued operations		—			(76,379	)

Net cash used in financing activities		(10,736	)		(78,898	)

Net increase (decrease) in cash and cash equivalents		(35,602	)		3,714
Cash and cash equivalents at beginning of period		136,491			45,092

Cash and cash equivalents at end of period	$	100,889		$	48,806

Supplemental Cash Flow Information:
Cash paid for interest (net of amount capitalized)	$	19,440		$	23,695

See accompanying Notes to Consolidated Financial Statements.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(unaudited)


	June 30,			December 31,
(In thousands)	2006			2005
ASSETS
Current Assets:
Cash and cash equivalents	$	100,889		$	136,491
Accounts receivable:
Customer		37,710			45,061
Unbilled utility revenue		28,520			38,200
Wholesale and other		17,362			20,598
Allowance for uncollectible accounts		(2,649	)		(2,489	)
Note receivable from affiliate		86,229			25,473
Materials and supplies		14,874			15,916
Fuel		19,808			14,751
Prepaid taxes		13,483			20,075
Collateral deposits		(5	)		9,533
Regulatory assets		5,003			4,379
Other		3,809			3,827

Total current assets		325,033			331,815

Property, Plant and Equipment, Net:
Generation		958,444			951,636
Transmission		281,976			281,048
Distribution		948,211			930,817
Other		69,360			73,807
Accumulated depreciation		(912,742	)		(890,548	)

Subtotal		1,345,249			1,346,760
Construction work in progress		26,058			17,401

Total property, plant and equipment, net		1,371,307			1,364,161

Investments and Other Assets:
Investment in AGC		48,169			48,197
Other		5,026			6,904

Total investments and other assets		53,195			55,101

Deferred Charges:
Regulatory assets		94,498			101,117
Other		5,939			6,985

Total deferred charges		100,437			108,102

Total Assets	$	1,849,972		$	1,859,179

See accompanying Notes to Consolidated Financial Statements.

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


	June 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)	$	300,986	$	299,959
Accounts payable		39,420		48,232
Accounts payable to affiliates, net		55,289		57,434
Deferred income taxes		2,025		—
Accrued taxes		37,449		41,766
Accrued interest		8,848		8,929
Ohio power commitment		20,900		25,900
Other		16,648		24,378

Total current liabilities		481,565		506,598


Long-term Debt (Note 2)		384,122		385,067

Deferred Credits and Other Liabilities:
Investment tax credit		—		442
Non-current income taxes payable		45,671		45,671
Deferred income taxes		208,458		194,248
Obligations under capital leases		3,628		5,554
Regulatory liabilities		238,696		242,416
Other		31,504		41,219

Total deferred credits and other liabilities		527,957		529,550

Commitments and Contingencies (Note 9)

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		41,094		40,719
Retained earnings		96,683		78,694
Accumulated other comprehensive income		1		1

Total common stockholder’s equity		432,328		413,964

Total Liabilities and Stockholder’s Equity	$	1,849,972	$	1,859,179

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		40

2	Debt		41

3	Discontinued Operations		41

4	Asset Retirement Obligations (“AROs”)		42

5	Business Segments		43

6	Intangible Assets		44

7	Pension Benefits and Postretirement Benefits Other Than Pensions		44

8	Other Income and Expenses, Net		44

9	Commitments and Contingencies		44

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, along with its regulated utility affiliates, The Potomac Edison Company (“Potomac Edison”) and West Penn Power Company (“West Penn”), collectively doing business as Allegheny Power, operates electric transmission and distribution (“T&D”) systems. Monongahela operates an electric T&D system in West Virginia. Monongahela 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 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.

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 six months ended June 30, 2005 was revised during 2006 to conform to this presentation. Accordingly, for the six months ended June 30, 2005, approximately $3.8 million in cash outflows for capital expenditures of discontinued operations and approximately $76.4 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.

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

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.

NOTE 2: DEBT

At June 30, 2006, contractual maturities for long-term debt for the remainder of 2006 and for full years thereafter, excluding unamortized discounts of $0.7 million, were as follows:


(In millions)	2006		2007		2008		2009		2010		Thereafter		Total
First Mortgage Bonds	$	300.0	$	—	$	—	$	—	$	—	$	190.0	$	490.0
Pollution Control Bonds		—		15.5		—		—		—		70.3		85.8
Medium-Term Notes		—		—		—		—		110.0		—		110.0

Total	$	300.0	$	15.5	$	—	$	—	$	110.0	$	260.3	$	685.8

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

Monongahela did not issue or redeem any debt during the three or six months ended June 30, 2006.

NOTE 3: DISCONTINUED OPERATIONS

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.


	Three Months			Six Months
	Ended June 30,			Ended June 30,
(In millions)	2005			2005
Operating revenues	$	46.6		$	196.8
Operating expenses		(46.0	)		(176.2	)
Other income and expenses, net		0.6			0.9
Interest expense		(2.0	)		(4.1	)

Income (loss) before income taxes		(0.8	)		17.4
Income tax expense		—			(6.7	)
Impairment charge, net of tax		(5.7	)		(6.3	)

Income (loss) from discontinued operations, net of tax	$	(6.5	)	$	4.4

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 FIN 47, “Accounting for Conditional Asset Retirement Obligations (“Conditional AROs”),” 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”). The effect of adopting FIN 47 on Monongahela’s Consolidated Balance Sheets at December 31, 2005 was a $0.3 million increase in property, plant and equipment, net, a $5.3 million increase in non-current regulatory assets, and the recognition of a $5.6 million non-current liability.

For the quarter ended June 30, 2006, Monongahela’s total ARO balance, which includes AROs and Conditional AROs, increased $0.5 million, from $12.9 million at December 31, 2005 to $13.4 million at June 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 June 30, 2006										Three months ended June 30, 2005
	Delivery		Generation								Delivery			Generation
	and		and								and			and
(In millions)	Services		Marketing			Eliminations			Total		Services			Marketing			Eliminations			Total
External operating revenues	$	156.7	$	20.7		$	—		$	177.4	$	161.7		$	16.4		$	—		$	178.1
Internal operating revenues		—		69.6			(69.6	)		—		—			75.3			(75.3	)		—

Total operating revenues	$	156.7	$	90.3		$	(69.6	)	$	177.4	$	161.7		$	91.7		$	(75.3	)	$	178.1
Depreciation and amortization	$	7.5	$	8.8		$	—		$	16.3	$	8.0		$	8.7		$	—		$	16.7
Operating income (loss)	$	19.5	$	(2.1	)	$	—		$	17.4	$	10.2		$	(1.8	)	$	—		$	8.4
Interest expense	$	6.0	$	4.5		$	—		$	10.5	$	6.1		$	4.6		$	—		$	10.7
Income (loss) from continuing operations	$	8.6	$	(1.7	)	$	—		$	6.9	$	7.9		$	1.2		$	—		$	9.1
Loss from discontinued operations, net of tax	$	—	$	—		$	—		$	—	$	(6.5	)	$	—		$	—		$	(6.5	)
Net income (loss)	$	8.6	$	(1.7	)	$	—		$	6.9	$	1.4		$	1.2		$	—		$	2.6


	Six months ended June 30, 2006									Six months ended June 30, 2005
	Delivery		Generation							Delivery		Generation
	and		and							and		and
(In millions)	Services		Marketing		Eliminations			Total		Services		Marketing			Eliminations			Total
External operating revenues	$	330.8	$	43.8	$	—		$	374.6	$	339.0	$	25.7		$	—		$	364.7
Internal operating revenues		—		147.6		(147.6	)		—		—		157.0			(157.0	)		—

Total operating revenues	$	330.8	$	191.4	$	(147.6	)	$	374.6	$	339.0	$	182.7		$	(157.0	)	$	364.7
Depreciation and amortization	$	15.1	$	17.6	$	—		$	32.7	$	16.1	$	17.4		$	—		$	33.5
Operating income (loss)	$	56.7	$	2.6	$	—		$	59.3	$	31.1	$	(3.2	)	$	—		$	27.9
Interest expense	$	12.2	$	9.1	$	—		$	21.3	$	12.3	$	9.1		$	—		$	21.4
Income from continuing operations	$	28.4	$	0.2	$	—		$	28.6	$	19.5	$	0.9		$	—		$	20.4
Income from discontinued operations, net of tax	$	—	$	—	$	—		$	—	$	4.4	$	—		$	—		$	4.4
Net income	$	28.4	$	0.2	$	—		$	28.6	$	23.9	$	0.9		$	—		$	24.8

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:


	June 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 not material for the three and six months ended June 30, 2006. Amortization expense for intangible assets was $0.4 million and $0.7 million for the three and six months ended June 30, 2005, respectively. Annual amortization expense for 2006 through 2010 is not expected to be material.

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				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Pension	$	1.9	$	2.5	$	3.9	$	5.0
Postretirement benefits other than pensions	$	1.7	$	1.6	$	3.4	$	3.2

NOTE 8: 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				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Interest income	$	2.1	$	1.4	$	4.1	$	1.5
Equity in earnings of AGC		1.6		1.8		3.0		3.5
Premium services		0.2		0.1		0.4		0.2
Other		0.2		0.2		0.3		0.5

Total	$	4.1	$	3.5	$	7.8	$	5.7

NOTE 9: 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.

The Clean Air Act mandates annual reductions of SO₂ and created a SO₂emission allowance trading program. AE Supply and Monongahela comply with current SO₂emission 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 little to no exposure to the SO₂ allowance market in 2006, and may have exposure of between zero and 40,000 tons in 2007 and between 40,000 and 80,000 tons in 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 the Hatfield’s Ferry generation facility.

AE Supply and Monongahela are completing installation of NO_x controls to meet the Pennsylvania, Maryland and West Virginia SIP calls. The NO_x compliance plan functions on a system-wide basis, similar to the SO₂compliance plan. AE Supply and Monongahela also have the option, in some cases, to purchase alternate fuels or NO_x 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 NO_x limits established by the SIP through 2008. Based on these estimates, Allegheny estimates that it will have minimal exposure to the NO_x 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 NO_X allowances for these periods will not vary from current estimates.

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

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 three 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 and the Alabama Power decision. The Ohio Edison decision is 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 is scheduled for the fall of 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 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 20, 2006, Allegheny filed an answer to the plaintiffs’ first amended complaint.

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

MONONGAHELA POWER COMPANY 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 June 30, 2006.

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

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

ALLEGHENY GENERATING COMPANY
STATEMENTS OF OPERATIONS
(unaudited)


	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In thousands)	2006			2005		2006		2005
Operating revenues	$	13,901		$	16,724	$	31,239	$	33,583

Operating expenses:
Operations and maintenance		1,055			1,069		2,562		2,206
Depreciation		4,290			4,309		8,575		8,546
Taxes other than income taxes		798			737		1,597		1,474

Total operating expenses		6,143			6,115		12,734		12,226

Operating income		7,758			10,609		18,505		21,357

Other income and expenses, net		701			76		746		129

Interest expense		1,790			1,848		3,598		3,803


Income before income taxes		6,669			8,837		15,653		17,683

Income tax expense (benefit)		(77	)		1,080		2,772		2,562

Net income	$	6,746		$	7,757	$	12,881	$	15,121

See accompanying Notes to Financial Statements.

ALLEGHENY GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(unaudited)


	Six Months Ended
	June 30,
(In thousands)	2006			2005
Cash Flows From Operating Activities:
Net income	$	12,881		$	15,121

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		8,575			8,546
Deferred income taxes and investment tax credit, net		(3,526	)		(3,553	)
Other, net		143			142

Changes in certain assets and liabilities:
Materials and supplies		(107	)		(113	)
Taxes receivable/accrued, net		(309	)		(216	)
Other current assets		(350	)		198
Accounts payable		(2,685	)		(26	)
Accounts payable to affiliates, net		471			470
Other current liabilities		234			242
Other liabilities		1			1

Net cash provided by operating activities		15,328			20,812

Cash Flows From Investing Activities:
Capital expenditures		(1,367	)		(4,394	)

Cash Flows From Financing Activities:
Note payable to parent		—			(15,000	)
Cash dividends paid on common stock		(13,000	)		(7,200	)

Net cash used in financing activities		(13,000	)		(22,200	)

Net increase (decrease) in cash and cash equivalents		961			(5,782	)
Cash and cash equivalents at beginning of period		1,858			7,500

Cash and cash equivalents at end of period	$	2,819		$	1,718

Supplemental Cash Flow Information:
Cash paid for interest	$	3,455		$	3,660

See accompanying Notes to Financial Statements.

ALLEGHENY GENERATING COMPANY
BALANCE SHEETS
(unaudited)


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

Current Assets:
Cash and cash equivalents	$	2,819		$	1,858
Materials and supplies		1,658			1,551
Taxes receivable		2,006			3,004
Other		574			225

Total current assets		7,057			6,638

Property, Plant and Equipment, Net:
Generation		781,829			788,952
Transmission		52,451			47,098
Other		2,948			2,960
Accumulated depreciation		(318,548	)		(316,250	)

Subtotal		518,680			522,760
Construction work in progress		9,244			12,372

Total property, plant and equipment, net		527,924			535,132

Deferred Charges:
Regulatory assets		8,171			8,295
Other		94			97

Total deferred charges		8,265			8,392

Total Assets	$	543,246		$	550,162

See accompanying Notes to Financial Statements.

ALLEGHENY GENERATING COMPANY
BALANCE SHEETS (continued)
(unaudited)


	June 30,		December 31,
(In thousands)	2006		2005
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Accounts payable	$	3	$	2,687
Accounts payable to affiliates, net		5,167		4,696
Accrued taxes		1,854		—
Accrued interest		2,292		2,292
Other		233		—

Total current liabilities		9,549		9,675


Long-term Debt (Note 2)		99,442		99,425

Deferred Credits and Other Liabilities:
Investment tax credit		36,613		37,273
Non-current income taxes payable		17,545		17,544
Deferred income taxes		147,996		153,630
Regulatory liabilities		22,411		22,806

Total deferred credits and other liabilities		224,565		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		37,020		37,139

Total stockholders’ equity		209,690		209,809

Total Liabilities and Stockholders’ Equity	$	543,246	$	550,162

See accompanying Notes to Financial Statements.

ALLEGHENY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
(unaudited)


Note No.		Page No.
1	Basis of Presentation		54

2	Debt		54

3	Intangible Assets		54

4	Commitments and Contingencies		55

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 77% and Monongahela owns 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 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 unaudited interim financial statements reflect all normal recurring adjustments that are necessary for a fair statement of the results of operations for the three and six months ended June 30, 2006 and 2005, cash flows for the six months ended June 30, 2006 and 2005 and financial position at June 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.

NOTE 2: DEBT

As of June 30, 2006, contractual maturities of long-term debt for the remainder of 2006 and for full years thereafter, excluding unamortized debt discounts of $0.6 million, were as follows:


(In millions)	2006		2007		2008		2009		2010		Thereafter		Total
Debentures	$	—	$	—	$	—	$	—	$	—	$	100.0	$	100.0

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

NOTE 3: INTANGIBLE ASSETS

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


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

Total	$	1.7	$	0.9	$	1.7	$	0.9

ALLEGHENY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
(unaudited)

Amortization expense for intangible assets was not material for the three and six months ended June 30, 2006 and 2005.

Annual amortization expense for 2006 through 2010 is not expected to be material.

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;

	•		changes in the price of power and fuel for electric generation;

	•		general economic and business conditions;

	•		changes in access to capital markets;

	•		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;

	•		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

	•		the continuing 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.

Harrison Unplanned Outage

Unit No. 1 at Allegheny’s Harrison generating facility experienced an unplanned outage due to a transformer failure on July 15, 2006. Allegheny returned Harrison Unit No. 1 to service on August 2, 2006 and estimates that the unplanned outage will adversely impact third quarter pre-tax financial results by $10 million to $15 million, consisting of lost revenues (net of fuel cost savings) and repair expenses.

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 MWs sold to retail customers.

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Revenue per MWh sold	$	58.06	$	54.49	$	58.66	$	55.21

The following table provides retail electricity sales information.


	Three Months Ended							Six Months Ended
	June 30,							June 30,
	2006		2005		Change			2006		2005		Change
Delivery and Services:
Retail electricity sales (million Kilowatt-hour (“kWhs”)		10,049		11,369		(11.6	)%		21,231		23,870		(11.1	)%

HDD (a)		530		598		(11.4	)%		2,956		3,314		(10.8	)%
CDD (a)		172		266		(35.3	)%		172		266		(35.3	)%


(a)		Heating degree-days (“HDD”) and cooling degree-days (“CDD”).The operations of the Distribution Companies are weather sensitive. Weather conditions directly influence the volume of electricity delivered by the Distribution Companies 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 656 and 3,497 for the three and six months ended June 30, respectively, and normal (historical) CDDs are 205 and 206 for the three and six months ended June 30, calculated on a 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									Six Months Ended
	June 30,									June 30,
	2006			2005			Change			2006			2005			Change
Supercritical Units:
EAF		77.8	%		79.2	%		(1.4	)%		84.5	%		83.2	%		1.3	%
All Generation Units:
EAF		83.3	%		85.3	%		(2.0	)%		87.3	%		87.4	%		(0.1	)%
kWhs generated (in millions)		11,234			11,089			1.3	%		24,251			23,386			3.7	%

ALLEGHENY ENERGY, INC.—CONSOLIDATED RESULTS OF OPERATIONS

Income (Loss) Summary


	Three Months Ended											Three Months Ended
	June 30, 2006											June 30, 2005
	Delivery		Generation									Delivery			Generation
	and		and									and			and
(In millions)	Services		Marketing			Eliminations			Total			Services			Marketing			Eliminations			Total
Operating revenues	$	632.5	$	414.1		$	(324.3	)	$	722.3		$	663.2		$	404.5		$	(353.0	)	$	714.7

Fuel consumed in electric generation		—		186.2			—			186.2			—			166.1			—			166.1
Purchased power and transmission		414.9		2.7			(322.5	)		95.1			436.0			23.2			(350.9	)		108.3
Gain on sale of OVEC power agreement and shares		—		(1.1	)		—			(1.1	)		—			—			—			—
Deferred energy costs, net		0.4		—			—			0.4			(1.8	)		—			—			(1.8	)
Operations and maintenance		93.1		114.5			(1.8	)		205.8			99.7			103.3			(2.1	)		200.9
Depreciation and amortization		37.9		30.3			—			68.2			39.0			38.4			—			77.4
Taxes other than income taxes		31.9		20.3			—			52.2			31.4			20.3			—			51.7

Total operating expenses		578.2		352.9			(324.3	)		606.8			604.3			351.3			(353.0	)		602.6

Operating income		54.3		61.2			—			115.5			58.9			53.2			—			112.1
Other income and expenses, net		6.9		4.3			(1.0	)		10.2			8.5			12.9			(0.2	)		21.2
Interest expense and preferred dividends		22.3		55.4			(1.0	)		76.7			47.3			82.4			(0.2	)		129.5

Income (loss) from continuing operations before income taxes and minority interest		38.9		10.1			—			49.0			20.1			(16.3	)		—			3.8
Income tax expense from continuing operations		15.6		1.2			—			16.8			3.2			6.6			—			9.8
Minority interest		—		0.2			—			0.2			—			0.1			—			0.1

Income (loss) from continuing operations		23.3		8.7			—			32.0			16.9			(23.0	)		—			(6.1	)
Loss from discontinued operations, net of tax		—		(0.9	)		—			(0.9	)		(6.5	)		(5.8	)		—			(12.3	)

Net income (loss)	$	23.3	$	7.8		$	—		$	31.1		$	10.4		$	(28.8	)	$	—		$	(18.4	)


	Six Months Ended											Six Months Ended
	June 30, 2006											June 30, 2005
	Delivery		Generation									Delivery			Generation
	and		and									and			and
(In millions)	Services		Marketing			Eliminations			Total			Services			Marketing			Eliminations			Total
Operating revenues	$	1,335.1	$	921.2		$	(688.4	)	$	1,567.9		$	1,402.6		$	821.4		$	(755.3	)	$	1,468.7

Fuel consumed in electric generation		—		399.4			—			399.4			—			340.0			—			340.0
Purchased power and transmission		862.6		18.4			(684.7	)		196.3			921.1			43.0			(751.0	)		213.1
Gain on sale of OVEC power agreement and shares		—		(6.1	)		—			(6.1	)		—			—			—			—
Deferred energy costs, net		5.4		—			—			5.4			(0.6	)		—			—			(0.6	)
Operations and maintenance		179.9		191.5			(3.7	)		367.7			184.2			183.6			(4.3	)		363.5
Depreciation and amortization		75.6		60.4			—			136.0			77.1			76.7			—			153.8
Taxes other than income taxes		65.2		40.7			—			105.9			66.0			40.8			—			106.8

Total operating expenses		1,188.7		704.3			(688.4	)		1,204.6			1,247.8			684.1			(755.3	)		1,176.6

Operating income		146.4		216.9			—			363.3			154.8			137.3			—			292.1
Other income and expenses, net		11.2		8.1			(1.4	)		17.9			12.2			14.6			(0.3	)		26.5
Interest expense and preferred dividends		42.2		103.6			(1.4	)		144.4			77.0			179.8			(0.2	)		256.6

Income (loss) from continuing operations before income taxes and minority interest		115.4		121.4			—			236.8			90.0			(27.9	)		(0.1	)		62.0
Income tax expense from continuing operations		45.7		43.5			—			89.2			23.4			9.8			—			33.2
Minority interest		—		1.4			—			1.4			—			0.5			—			0.5

Income (loss) from continuing operations		69.7		76.5			—			146.2			66.6			(38.2	)		(0.1	)		28.3
Income (loss) from discontinued operations, net of tax		—		(1.7	)		—			(1.7	)		4.3			(8.5	)		0.1			(4.1	)

Net income (loss)	$	69.7	$	74.8		$	—		$	144.5		$	70.9		$	(46.7	)	$	—		$	24.2

ALLEGHENY ENERGY, INC.—CONSOLIDATED RESULTS

Operating Revenues

Operating revenues increased $7.6 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005, primarily due to:

	•	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”),

	•	increased MWhs generated,

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

These increases were partially offset by:

	•	a decrease in average market prices,

	•	the expiration of a third-party transmission services contract,

	•	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 and

	•	milder weather.

Operating revenues increased $99.2 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, primarily 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,

	•	increased MWhs generated and increased average market prices,

	•	the expiration of a PLR contract with one large industrial customer in Maryland in December 2005 that resulted in sales into PJM at market prices and

	•	Monongahela’s agreement to provide power to Columbus Southern to serve Monongahela’s former Ohio service territory at a higher rate per kWh net of lost T&D revenues.

These increases were partially offset by:

	•	the expiration of a third-party transmission capacity sales contract,

	•	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 and

	•	milder weather.

Operating Income

Operating income increased $3.4 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005, primarily due to:

	•		the $7.6 million increase in operating revenues discussed above,

	•		partially offset by a $4.2 million increase in operating expenses.

Operating expenses increased as a result of a $20.1 million increase in fuel consumed in electric generation and a $4.9 million increase in operations and maintenance expense, partially offset by a $13.2 million decrease in purchased power and

transmission and a $9.2 million decrease in depreciation and amortization. Fuel consumed in electric generation increased due to increased coal prices and increased amounts of coal used as a result of increased MWhs generated by Allegheny’s coal-fired plants. Operations and maintenance expense increased due to Hatfield’s Ferry insurance proceeds received in 2005, stock option compensation cost associated with Allegheny’s adoption of SFAS No. 123R and increased outside services expense due to costs associated with the implementation of Allegheny’s information technology initiatives. These increases were partially offset by decreased salaries and wages expense due to a decrease in the number of information and technology employees as a result of the outsourcing of this function during 2005, decreased cost of goods sold and services expenses, primarily due to reductions in equipment procurement and subcontracting costs associated with a construction project that was completed during the second quarter of 2006, decreased legal costs related to a reduction in outside legal services and other decreases in operating expenses resulting from the changes in depreciation practices discussed in Note 3, “Review of Estimated Remaining Service Lives and Depreciation Practices,” to the Consolidated Financial Statements. 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 refund received on certain transmission charges. Depreciation and amortization decreased due to the extension of depreciable lives of Allegheny’s unregulated coal-fired generation facilities, which is discussed further in Note 3.

Operating income increased $71.2 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, primarily due to:

	•		the $99.2 million increase in operating revenues discussed above,

	•		partially offset by a $28.0 million increase in operating expenses.

Operating expenses increased as a result of a $59.4 million increase in fuel consumed in electric generation and a $4.2 million increase in operations and maintenance, partially offset by a $16.8 million decrease in purchased power and transmission and a $17.8 million decrease in depreciation and amortization. Fuel consumed in electric generation increased due to increased coal prices and increased amounts of coal used as a result of increased MWhs generated by Allegheny’s coal-fired plants. Operations and maintenance expense increased due to Hatfield’s Ferry insurance proceeds received in 2005, special maintenance performed at Allegheny’s generation facilities, stock option compensation cost associated with Allegheny’s adoption of SFAS No. 123R and increased outside services expense due to costs associated with the implementation of Allegheny’s information technology initiatives. These increases were partially offset by decreased salaries and wages expense due to a decrease in the number of information and technology employees as a result of the outsourcing of this function during 2005, decreased cost of goods sold and services expenses, primarily due to reductions in equipment procurement and subcontracting costs associated with a construction project that was completed during the second quarter of 2006 and other decreases in operating expenses resulting from the changes in depreciation practices discussed in Note 3, “Review of Estimated Remaining Service Lives and Depreciation Practices,” to the Consolidated Financial Statements. 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 refund received on certain transmission charges. Depreciation and amortization decreased due to the extension of depreciable lives of Allegheny’s unregulated coal-fired generation facilities, which is discussed further in Note 3.

Income from Continuing Operations

Income from continuing operations increased $38.1 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005, primarily due to:

	•	the $3.4 million increase in operating income discussed above and

	•	a $52.8 million decrease in interest expense and preferred dividends due to costs associated with the April 2005 tender offer for AE’s Trust Preferred Securities, lower average debt outstanding and lower borrowing rates, partially offset by the write-off of prior deferred financing costs as a result of the May 2006 refinancings.

These increases were partially offset by:

	•	an $11.0 million decrease in other income and expenses, net, primarily due to $11.2 million of cash received from a former trading executive’s forfeited assets during the three months ended June 30, 2005 and

	•	a $7.0 million increase in income tax expense resulting primarily from increased income from continuing operations, partially offset by state deferred income tax adjustments recorded in 2005.

Income from continuing operations increased $117.9 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, primarily due to:

	•	the $71.2 million increase in operating income discussed above and

	•	a $112.2 million decrease in interest expense and preferred dividends due to costs associated with the April 2005 tender offer for AE’s Trust Preferred Securities, $38.5 million of interest recorded during the three months ended June 30, 2005 related to a court decision in the litigation involving Merrill Lynch, lower average debt outstanding and lower borrowing rates, partially offset by the write-off of prior deferred financing costs as a result of the May 2006 refinancings,

These increases were partially offset by:

	•	an $8.6 million decrease in other income and expenses, net, primarily due to $11.2 million of cash received from a former trading executive’s forfeited assets during the three months ended June 30, 2005 and

	•	a $56.0 million increase in income tax expense resulting primarily from increased income from continuing operations.

See Note 14, “Other Income and Expenses, net” to the Consolidated Financial Statements for additional information.

Income Tax Expense

The effective tax rates for Allegheny’s continuing operations were 34.0% and 195.2% for the three months ended June 30, 2006 and 2005, respectively, and were 37.6% and 51.5% for the six months ended June 30, 2006 and 2005, respectively.

The effective tax rate for the three months ended June 30, 2006 was lower than the federal statutory rate, primarily due to a state income tax refund received.

The effective tax rate for the six months ended June 30, 2006 was higher than the federal statutory rate, primarily due to state income taxes, tax credits, the effects of utility rate making and certain non-deductible expenses.

The effective tax rates for the three and six months ended June 30, 2005 were 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 June 30, 2005 in the amounts of $3.8 million and $1.9 million, respectively, as described in Note 1, “Basis of Presentation,” to the Consolidated Financial Statements 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 $0.9 million and $12.3 million for the three months ended June 30, 2006 and 2005, respectively, and $1.7 million and $4.1 million for the six months ended June 30, 2006 and 2005, respectively.

The $11.4 million decrease in losses from discontinued operations for the three months ended June 30, 2006 compared to the three months ended June 30, 2005 was primarily due to decreased losses associated with AE Supply’s Gleason Generating Facility and losses associated with Monongahela’s natural gas operations, which were sold on September 30, 2005, partially offset by income in 2005 associated with AE Supply’s Wheatland Generating Facility, which was sold on August 12, 2005.

The $2.4 million decrease in losses from discontinued operations for the six months ended June 30, 2006 compared to the six months ended June 30, 2005 was primarily due to decreased losses associated with AE Supply’s Gleason Generating Facility, partially offset by income in 2005 associated with Monongahela’s natural gas operations, which were sold on September 30, 2005 and income in 2005 associated with AE Supply’s Wheatland Generating Facility, which was sold on August 12, 2005.

See Note 5, “Discontinued Operations and Assets Held for Sale,” to the Consolidated Financial Statements 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							Six Months Ended
	June 30,							June 30,
	2006		2005		Change			2006		2005		Change
Retail electricity sales (million kWhs)		10,049		11,369		(11.6	)%		21,231		23,870		(11.1	)%

HDD (a)		530		598		(11.4	)%		2,956		3,314		(10.8	)%
CDD (a)		172		266		(35.3	)%		172		266		(35.3	)%


(a)		Normal (historical) HDDs are 656 and 3,497 for the three and six months ended June 30, respectively, and normal (historical) CDDs are 205 and 206 for the three and six months ended June 30, respectively, calculated on a weighted-average basis across the geographic areas served by the Distribution Companies.

Operating Revenues

Operating revenues were as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Retail electric:
Generation	$	392.6	$	416.7	$	831.2	$	881.7
Transmission		37.0		40.9		79.2		86.9
Distribution		153.8		161.8		335.0		349.3

Total retail electric		583.4		619.4		1,245.4		1,317.9

Transmission services and bulk power		38.2		29.1		73.8		57.5
Other affiliated and nonaffiliated energy services		10.9		14.7		15.9		27.2

Total operating revenues	$	632.5	$	663.2	$	1,335.1	$	1,402.6

Retail electric revenues decreased $36.0 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005, primarily due to:

	•		a $44.4 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 $11.9 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 $24.5 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 rate at Potomac Edison due to a non-residential rate increase.

Retail electric revenues decreased $72.5 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, primarily due to:

	•		a $91.9 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

	•		a $22.0 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 $43.5 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 rate at Potomac Edison due to a non-residential rate increase.

Transmission services and bulk power revenues increased $9.1 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005, primarily due to:

	•		an $18.8 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 $7.7 million decrease in transmission revenues related to the expiration of a third-party transmission services contract.

Transmission services and bulk power revenues increased $16.3 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, primarily due to:

	•		a $38.4 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 $15.1 million decrease in transmission revenues related to the expiration of a third-party transmission services contract and

	•		a $7.5 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.

Other affiliated and nonaffiliated energy services revenues decreased by $3.8 million and $11.3 million for the three and six months ended June 30, 2006, respectively, compared to the three and six months ended June 30, 2005, primarily due to decreased revenues associated with a construction project that was completed during the second quarter of 2006 and the absence of revenues from businesses that were sold in 2005.

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				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Other purchased power and transmission	$	361.8	$	385.6	$	763.4	$	818.4
From PURPA generation (a)		53.1		50.4		99.2		102.7

Total purchased power and transmission	$	414.9	$	436.0	$	862.6	$	921.1


a) PURPA cost (cents per kWh sold)		5.6		5.3		5.4		5.2

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.

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.

Other purchased power and transmission decreased $23.8 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005, primarily due to:

	•		a $19.0 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 $12.1 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 $8.0 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 5% rate increase resulting from a West Penn settlement with the Pennsylvania PUC, partially offset by scheduled contractual price decreases under a contract with AE Supply.

Other purchased power and transmission decreased $55.0 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, primarily due to:

	•		a $30.0 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 $31.5 million decrease in other purchased power and transmission related 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 $24.1 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 5% rate increase resulting from a West Penn settlement with the Pennsylvania PUC, partially offset by scheduled contractual price decreases.

Purchased power and transmission from PURPA generation increased $2.7 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005, primarily due to increased power generated at the PURPA facilities and increased average rates.

Purchased power and transmission from PURPA generation decreased $3.5 million for the six months ended June 30, 2006 compared to the six months ended June 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, partially offset by increased power generated at the PURPA facilities during the second quarter of 2006 and increased average rates.

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


	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In millions)	2006		2005			2006		2005
Deferred energy costs, net	$	0.4	$	(1.8	)	$	5.4	$	(0.6	)

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 $2.2 million for the three months ended June 30, 2006 compared with the three months ended June 30, 2005, primarily as a result of a $1.7 million increase in deferred costs related to market-based generation, due to customer revenues exceeding generating costs.

Deferred energy costs, net increased $6.0 million for the six months ended June 30, 2006 compared with the six months ended June 30, 2005, primarily as a result of a $2.1 million increase in deferred costs related to PURPA and a $3.8 million increase in deferred costs related to market-based generation. Both of these increases were due to customer revenues exceeding generating costs.

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				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Operations and maintenance	$	93.1	$	99.7	$	179.9	$	184.2

Operations and maintenance expenses decreased $6.6 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005, primarily due to:

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

	•		a $5.4 million decrease in cost of goods sold and services expenses, primarily due to reductions in equipment procurement and subcontracting costs associated with a construction project that was completed during the second quarter of 2006,

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

Operations and maintenance expenses decreased $4.3 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, primarily due to:

	•		a $5.4 million decrease in salaries and wages expenses, primarily due to a decrease in the number of information and technology employees as a result of the outsourcing of this function during 2005 and

	•		an $8.3 million decrease in cost of goods sold and services expenses, primarily due to reductions in equipment procurement and subcontracting costs associated with a construction project that was completed during the second quarter of 2006,

	•		partially offset by a $6.6 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				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Depreciation and amortization	$	37.9	$	39.0	$	75.6	$	77.1

Depreciation and amortization expenses decreased $1.1 million and $1.5 million for the three and six months ended June 30, 2006, respectively, compared to the three and six months ended June 30, 2005, primarily due to the retirement of fully amortized software during 2006, and an increase in the depreciable lives of certain assets at West Penn as a result of an annual review of estimated useful asset lives.

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				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Other income and expenses, net	$	6.9	$	8.5	$	11.2	$	12.2

Other income and expenses, net, decreased $1.6 million and $1.0 million for the three and six months ended June 30, 2006 compared to the three and six months ended June 30, 2005, respectively, primarily due to the receipt during 2005 of proceeds on investments that were previously written-off.

Interest Expense and Preferred Dividends:Interest expense and preferred dividends were as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Interest expense and preferred dividends	$	22.3	$	47.3	$	42.2	$	77.0

Interest expense and preferred dividends decreased $25.0 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005, primarily due to:

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

	•		a $5.7 million decrease in interest expense on long-term debt as a result of lower average debt outstanding and lower borrowing rates, partially offset by the write-off of certain prior deferred financing costs as a result of the May 2006 AE refinancing.

Interest expense and preferred dividends decreased $34.8 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, primarily due to:

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

	•		a $14.8 million decrease in interest expense on long-term debt as a result of lower average debt outstanding and lower borrowing rates, partially offset by the write-off of certain prior deferred financing costs as a result of the May 2006 AE refinancing.

For additional information regarding Allegheny’s short-term and long-term debt, see Note 4, “Debt,” to the Consolidated Financial Statements.

Discontinued Operations:Income (loss) from discontinued operations was $(6.5) million and $4.3 million for the three and six months ended June 30, 2005, respectively. These amounts were related to Monongahela’s West Virginia natural gas operations, which were sold on September 30, 2005.

See Note 5, “Discontinued Operations and Assets Held for Sale,” to the Consolidated Financial Statements 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							Six Months Ended
	June 30,							June 30,
	2006		2005		Change			2006		2005		Change
Generation (million kWhs)		11,234		11,088		1.3	%		24,251		23,386		3.7	%

Operating Revenues

Operating revenues were as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Revenue from affiliates	$	322.4	$	350.9	$	684.7	$	751.0
Wholesale and other revenue, net (a)		91.7		53.6		236.5		70.4

Total revenues	$	414.1	$	404.5	$	921.2	$	821.4


(a)		Amounts are net of energy trading gains and losses as described in Note 6, “Derivative Instruments and Hedging Activities,” to the Consolidated Financial Statements. 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 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, AE Supply has a power sales agreement with Potomac Edison at a fixed rate that was awarded on a competitive bid basis.

The average rate at which the Generation and Marketing segment sold power to the Distribution Companies was $35.19 and $33.62 per MWh for the three months ended June 30, 2006 and 2005, respectively, and $34.76 and $33.21 per MWh for the six months ended June 30, 2006 and 2005, respectively.

Revenue from affiliates decreased $28.5 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005, primarily due to:

	•		an $8.7 million decrease in revenue related to decreased sales volumes from certain of Potomac Edison’s customers in Maryland that were previously provided power by the Generation and Marketing segment and are now served by nonaffiliated suppliers,

	•		an $18.4 million decrease in revenue related to decreased sales volumes due to the expiration of a contract with one large industrial customer in Maryland in December 2005,

	•		a $3.3 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 $13.5 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.

Revenue from affiliates decreased $66.3 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, primarily due to:

	•		a $33.6 million decrease in revenue related to decreased sales volumes from certain of Potomac Edison’s customers in Maryland that were previously provided power by the Generation and Marketing segment and are now served by nonaffiliated suppliers,

	•		a $36.4 million decrease in revenue related to decreased sales volumes due to the expiration of a contract with one large industrial customer in Maryland in December 2005,

	•		a $7.0 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 $32.9 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						Six Months Ended
	June 30,						June 30,
(In millions)	2006			2005			2006			2005
PJM Revenue:
Generation sold to PJM	$	468.8		$	486.6		$	1,050.8		$	1,014.8
Power purchased from PJM		(382.9	)		(446.4	)		(844.2	)		(966.8	)

Net		85.9			40.2			206.6			48.0

Cash flow hedges and trading activities:
Realized losses		(8.2	)		(4.2	)		(4.6	)		(6.8	)
Unrealized gains		5.3			9.2			18.3			13.3

Net		(2.9	)		5.0			13.7			6.5

Other revenues		8.7			8.4			16.2			15.9

Total wholesale and other revenues	$	91.7		$	53.6		$	236.5		$	70.4

Wholesale and other revenues increased $38.1 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005, primarily due to:

	•		an increase in net PJM revenues of $45.7 million,

	•		partially offset by a $7.9 million decrease in net gains 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.

The increase in net PJM revenues is 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 due to 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. Excluding OVEC, revenues from generation sold to PJM increased due to an increase in MWhs generated, partially offset by a decrease in the average market price of power. 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 that are now served by non-affiliated suppliers and a decrease in sales volume because Monongahela is no longer serving customers in its former Ohio service territory, which was sold on December 31, 2005. In addition, power purchased from PJM decreased due to milder weather and a decrease in the average market price of power.

Wholesale and other revenues increased $166.1 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, primarily due to:

	•		an increase in net PJM revenues of $158.6 million and

	•		a $7.2 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.

The increase in net PJM revenues is due to higher revenues from generation sold to PJM and lower power purchased from PJM. The increase in revenues from generation sold to PJM is primarily due to a 3.7% increase in total MWhs generated. This increase in total MWhs generated was due to increased availability of Allegheny’s supercritical plants and an increase in the average market price of power. These increases were partially offset by 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. 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 that are now served by non-affiliated suppliers and a decrease in sales volume because Monongahela is no longer serving customers in its former Ohio service territory, which was sold on December 31, 2005. In addition, power purchased from PJM decreased due to milder weather. These decreases were partially offset by the increase in the average market price of power.

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 June 30, 2006. Changes in the fair value of the commodity cash flow hedges are reflected in other comprehensive income.

At June 30, 2006, the fair values of derivative contract assets and liabilities were $4.9 million and $52.9 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 June 30, 2006
Classification of contracts																Settlement
by source of fair		Settlement by:														In Excess of
value (In millions)	2006			2007			2008			2009			2010			Five Years			Total
Prices actively quoted	$	(26.6	)	$	(5.7	)	$	(5.5	)	$	(5.2	)	$	(4.9	)	$	(1.6	)	$	(49.5	)
Prices provided by other external sources		1.0			0.2			—			—			—			—			1.2
Prices based on models		0.3			—			—			—			—			—			0.3

Total	$	(25.3	)	$	(5.5	)	$	(5.5	)	$	(5.2	)	$	(4.9	)	$	(1.6	)	$	(48.0	)

The fair value of AE Supply’s contracts that are scheduled to settle by December 31, 2006 was a net liability of $25.3 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 6, “Derivative Instruments and Hedging Activities,” to the Consolidated Financial Statements for additional information.

Changes in Fair Value:Net unrealized gains of $5.3 million and $18.3 million for the three and six months ended June 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			Six Months Ended
(In millions)	June 30, 2006			June 30, 2006
Net fair value of contract liabilities at April 1 and January 1, respectively	$	(62.3	)	$	(106.6	)
Changes in fair value of cash flow hedges		10.0			39.0
Unrealized gains on contracts, net		4.3			17.3
Net options paid		—			2.3

Net fair value of contract liabilities at June 30	$	(48.0	)	$	(48.0	)

As shown in the table above, the net fair value of Allegheny’s derivative contracts increased by $14.3 million and $58.6 million during the three and six months ended June 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				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Fuel consumed in electric generation	$	186.2	$	166.1	$	399.4	$	340.0

Total fuel consumed in electric generation increased by $20.1 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005, primarily due to a $24.1 million increase in coal expense. The increase in coal expense was due to an increase in the price of coal of $2.67 per ton, from $34.86 per ton to $37.53 per ton, and a 0.4 million-ton increase in the amount of coal burned. The increase in the amount of coal burned was primarily due to a 1.3% increase in total MWhs generated.

Total fuel consumed in electric generation increased by $59.4 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, primarily due to a $61.2 million increase in coal expense. The increase in coal expense was due to an increase in the price of coal of $3.56 per ton, from $34.04 per ton to $37.60 per ton, and a 0.8 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.

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Purchased power and transmission expenses	$	2.7	$	23.2	$	18.4	$	43.0

Purchased power and transmission expenses decreased $20.5 million and $24.6 million for the three and six months ended June 30, 2006, respectively, compared to the three and six months ended June 30, 2005, primarily due to the March 2006 assignment of AE Supply’s rights to generation from the 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 the OVEC to Buckeye Power Generating, LLC. The gains on sale of OVEC power agreement and shares were $1.1 million and $6.1 million for the three and six months ended June 30, 2006, respectively and represent the release of proceeds due to the fulfillment of certain post-closing commitments.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Operations and maintenance	$	114.5	$	103.3	$	191.5	$	183.6

Operations and maintenance expenses increased $11.2 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005, primarily as a result of a $13.4 million increase in contract work expense due to insurance proceeds received during 2005 related to Hatfield’s Ferry Unit No. 2 and increased planned maintenance costs.

Operations and maintenance expenses increased $7.9 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, primarily due to:

	•		a $13.3 million increase in contract work expense due to insurance proceeds received during 2005 related to Hatfield’s Ferry Unit No. 2 and increased planned maintenance costs and

	•		a $5.9 million increase in outside service expense, primarily due to costs associated with the implementation of Allegheny’s information technology initiatives,

	•		partially offset by a $10.8 million decrease in other operations and maintenance expense primarily due to the reversal of a guarantee liability associated with the Hunlock Creek Energy Ventures (“HCEV”) partnership.

See Note 15, “Guarantees and Letters of Credit,” to the Consolidated Financial Statements and Note 17, “HCEV Partnership Interest,” to the Consolidated Financial Statements for additional information related to the HCEV partnership interest transaction.”

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Depreciation and amortization	$	30.3	$	38.4	$	60.4	$	76.7

Depreciation and amortization expense decreased $8.1 million and $16.3 million for the three and six months ended June 30, 2006, respectively, compared to the three and six months ended June 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 in Note 3, “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				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Other income and expenses, net	$	4.3	$	12.9	$	8.1	$	14.6

Other income and expenses, net, decreased $8.6 million and $6.5 million for the three and six months ended June 30, 2006, respectively, compared to the three and six months ended June 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 increased 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				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Interest expense and preferred dividends	$	55.4	$	82.4	$	103.6	$	179.8

Interest expense and preferred dividends decreased $27.0 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005, primarily due to:

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

	•		a $4.7 million decrease in interest expense on long-term debt as a result of lower average debt outstanding and lower borrowing rates, partially offset by the write-off of certain prior deferred financing costs as a result of the May 2006 refinancings.

Interest expense and preferred dividends decreased $76.2 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, primarily due to:

	•		$26.2 million in costs related to the April 2005 tender offer for outstanding AE’s 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 $12.6 million decrease in interest expense on long-term debt as a result of lower average debt outstanding and lower borrowing rates, partially offset by the write-off of certain prior deferred financing costs as a result of the May 2006 refinancings.

For additional information regarding Allegheny’s long-term debt, see Note 4, “Debt” to the Consolidated Financial Statements. For additional information regarding the litigation involving Merrill Lynch, see Note 18, “Commitments and Contingencies” to the Consolidated Financial Statements.

Minority Interest

Minority interest, which primarily represents equity interest in AE Supply, was $0.2 million and $0.1 million for the three months ended June 30, 2006 and 2005, respectively, and $1.4 million and $0.5 million for the six months ended June 30, 2006 and 2005, respectively.

Discontinued Operations:Losses from discontinued operations were as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Loss from discontinued operations	$	0.9	$	5.8	$	1.7	$	8.5

Loss from discontinued operations decreased $4.9 million and $6.8 million for the three and six months ended June 30, 2006, respectively, compared to the three and six months ended June 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 5, “Discontinued Operations and Assets Held for Sale,” to the Consolidated Financial Statements for additional information.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES—CONSOLIDATED RESULTS OF OPERATIONS

Income (Loss) Summary


	Three Months Ended												Three Months Ended
	June 30, 2006												June 30, 2005
	Delivery			Generation									Delivery			Generation
	and			and									and			and
(In millions)	Services			Marketing			Eliminations			Total			Services			Marketing			Eliminations			Total
Operating revenues	$	156.7		$	90.3		$	(69.6	)	$	177.4		$	161.7		$	91.7		$	(75.3	)	$	178.1

Fuel consumed in electric generation		—			40.5			—			40.5			—			33.3			—			33.3
Purchased power and transmission		98.4			13.9			(69.6	)		42.7			106.8			23.3			(75.3	)		54.8
Deferred energy costs, net		(0.6	)		—			—			(0.6	)		—			—			—			—
Operations and maintenance		25.9			23.3			—			49.2			29.9			22.3			—			52.2
Depreciation and amortization		7.5			8.8			—			16.3			8.0			8.7			—			16.7
Taxes other than income taxes		6.0			5.9			—			11.9			6.8			5.9			—			12.7


Total operating expenses		137.2			92.4			(69.6	)		160.0			151.5			93.5			(75.3	)		169.7

Operating income (loss)		19.5			(2.1	)		—			17.4			10.2			(1.8	)		—			8.4
Other income and expenses, net		1.5			2.6			—			4.1			1.4			2.1			—			3.5
Interest expense		6.0			4.5			—			10.5			6.1			4.6			—			10.7


Income (loss) from continuing operations before income taxes		15.0			(4.0	)		—			11.0			5.5			(4.3	)		—			1.2
Income tax expense (benefit) from continuing operations		6.4			(2.3	)		—			4.1			(2.4	)		(5.5	)		—			(7.9	)


Income (loss) from continuing operations		8.6			(1.7	)		—			6.9			7.9			1.2			—			9.1
Loss from discontinued operations, net of tax		—			—			—			—			(6.5	)		—			—			(6.5	)


Net income (loss)	$	8.6		$	(1.7	)		—		$	6.9		$	1.4		$	1.2		$	—		$	2.6


	Six Months Ended												Six Months Ended
	June 30, 2006												June 30, 2005
	Delivery			Generation									Delivery		Generation
	and			and								��	and		and
(In millions)	Services			Marketing			Eliminations			Total			Services		Marketing			Eliminations			Total
Operating revenues	$	330.8		$	191.4		$	(147.6	)	$	374.6		$	339.0	$	182.7		$	(157.0	)	$	364.7
Fuel consumed in electric generation		—			84.6			—			84.6			—		68.3			—			68.3
Purchased power and transmission		197.1			34.3			(147.6	)		83.8			221.3		49.2			(157.0	)		113.5
Deferred energy costs, net		(0.6	)		—			—			(0.6	)		—		—			—			—
Operations and maintenance		50.2			40.5			—			90.7			56.9		39.2			—			96.1
Depreciation and amortization		15.1			17.6			—			32.7			16.1		17.4			—			33.5
Taxes other than income taxes		12.3			11.8			—			24.1			13.6		11.8						25.4


Total operating expenses		274.1			188.8			(147.6	)		315.3			307.9		185.9			(157.0	)		336.8

Operating income (loss)		56.7			2.6			—			59.3			31.1		(3.2	)		—			27.9
Other income and expenses, net		3.0			4.8			—			7.8			1.6		4.1			—			5.7
Interest expense		12.2			9.1			—			21.3			12.3		9.1			—			21.4


Income (loss) from continuing operations before income taxes		47.5			(1.7	)		—			45.8			20.4		(8.2	)		—			12.2
Income tax expense (benefit) from continuing operations		19.1			(1.9	)		—			17.2			0.9		(9.1	)		—			(8.2	)


Income from continuing operations		28.4			0.2			—			28.6			19.5		0.9			—			20.4
Income from discontinued operations, net of tax		—			—			—			—			4.4		—			—			4.4


Net income	$	28.4		$	0.2		$	—		$	28.6		$	23.9	$	0.9			—		$	24.8

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 increased $9.9 million for the six months ended June 30, 2006 compared to the six months ended June 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 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 T&D revenues,

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

Operating Income

Operating income increased $9.0 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005, due to a $9.7 million decrease in operating expenses. The decrease in total operating expenses was primarily due to a $12.1 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 $3.0 million decrease in operation and maintenance expense because of reduced salaries and wages expense. These decreases were partially offset by a $7.2 million increase in fuel consumed in electric generation due to an increase in coal expense.

Operating income increased $31.4 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, due to:

	•		a $21.5 million decrease in operating expenses and

	•		a $9.9 million increase in total operating revenues, as discussed above.

The decrease in total operating expenses was primarily due to a $29.7 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 $5.4 million decrease in operation and maintenance expense because of reduced salaries and wages expense. These decreases were partially offset by a $16.3 million increase in fuel consumed in electric generation due to an increase in coal expense.

Income from Continuing Operations

Income from continuing operations decreased $2.2 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005, primarily due to:

	•		a $12.0 million increase in income tax expense,

	•		partially offset by a $9.0 million increase in operating income, as discussed above.

Income from continuing operations increased $8.2 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, primarily due to:

	•		a $31.4 million increase in operating income, as discussed above,

	•		partially offset by a $25.4 million increase in income tax expense.

Income Tax Expense

The effective tax rates for Monongahela’s continuing operations were 37.9% and (640.7)% for the three months ended June 30, 2006 and 2005, respectively, and 37.6% and (66.6)% for the six months ended June 30, 2006 and 2005, respectively.

The effective tax rates for the three and six months ended June 30, 2005 were 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,” to Monongahela’s Consolidated Financial Statements for additional information.

Discontinued Operations

Monongahela recorded income (loss) from discontinued operations of $(6.5) million and $4.4 million for the three and six months ended June 30, 2005, respectively, relating to Monongahela’s West Virginia natural gas operations, which were sold on September 30, 2005.

See Note 3, “Discontinued Operations,” to Monongahela’s Consolidated Financial Statements 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							Six Months Ended
	June 30,							June 30,
	2006		2005		Change			2006		2005		Change
Retail electricity sales (million kWhs)		2,402		2,921		(17.8	)%		5,054		6,071		(16.8	)%

HDD (a)		452		484		(6.6	)%		2,599		2,883		(9.9	)%
CDD (a)		177		299		(40.8	)%		178		299		(40.5	)%


(a)		Normal (historical) HDD are 663 and 3,428 for the three and six months ended June 30, respectively, and normal (historical) CDD are 193 for both the three and six months ended June 30, calculated on a weighted-average basis across the geographic areas served by Monongahela.

Operating Revenues

Operating revenues were as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Retail electric:
Generation	$	83.3	$	98.2	$	173.8	$	203.8
Transmission		7.8		9.5		16.5		19.8
Distribution		41.1		46.5		90.5		100.6

Total retail electric		132.2		154.2		280.8		324.2

Transmission services and bulk power		21.5		5.8		44.4		11.5
Other affiliated and non-affiliated energy services		3.0		1.7		5.6		3.3

Total revenues	$	156.7	$	161.7	$	330.8	$	339.0

Retail electric revenues decreased $22.0 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005, primarily due to a $14.9 million decrease in generation revenues and a $7.1 million decrease in T&D revenues. These decreases were primarily a result of a reduction in customers and decreased usage due to the sale of Monongahela’s Ohio service territory on December 31, 2005, as well as milder weather.

Retail electric revenues decreased $43.4 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, primarily due to a $30.0 million decrease in generation revenues and a $13.4 million decrease in T&D revenues. These decreases were primarily a result of a reduction in customers and decreased usage due to the sale of Monongahela’s Ohio service territory on December 31, 2005, as well as milder weather.

Transmission services and bulk power increased $15.7 million and $32.9 million for the three and six months ended June 30, 2006, respectively, compared to the three and six months ended June 30, 2005, primarily due to bulk power sales related to a fixed price power supply agreement to provide power to 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 services 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				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Other purchased power and transmission	$	82.8	$	93.3	$	166.7	$	193.2
From PURPA generation (a)		15.6		13.5		30.4		28.1

Total purchased power and transmission	$	98.4	$	106.8	$	197.1	$	221.3


(a) PURPA cost (cents per kWh sold)			4.6				4.2				4.4				4.3

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 $10.5 million for the three months ended June 30, 2006 compared to the three months ended June 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, and reduced demand as a result of milder weather.

Other purchased power and transmission decreased $26.5 million for the six months ended June 30, 2006 compared to the six months ended June 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 $2.1 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005, primarily due to an increase in average rates.

Purchased power from PURPA generation increased $2.3 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, primarily due to increases in average rates and MWhs purchased. MWhs purchased increased as a result of higher output because of favorable river conditions at certain PURPA generation facilities.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Operations and maintenance	$	25.9	$	29.9	$	50.2	$	56.9

Operations and maintenance expenses decreased $4.0 million and $6.7 million for the three and six months ended June 30, 2006, respectively, compared to the three and six months ended June 30, 2005, primarily due to decreased salaries and wages expense as a result of a decrease in the number of information and technology employees due to the outsourcing of this function during 2005.

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Depreciation and amortization	$	7.5	$	8.0	$	15.1	$	16.1

Depreciation and amortization expenses decreased $1.0 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005 due to the retirement of fully amortized software during 2006.

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Taxes other than income taxes	$	6.0	$	6.8	$	12.3	$	13.6

Taxes other than income taxes decreased $1.3 million for the six months ended June 30, 2006 compared to the six months ended June 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				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Other income and expenses, net	$	1.5	$	1.4	$	3.0	$	1.6

Other income and expenses, net increased $1.4 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, primarily as a result of increased interest income on investments due to higher interest rates.

Generation and Marketing

The following table provides electricity sales information:


	Three Months Ended							Six Months Ended
	June 30,							June 30,
	2006		2005		Change			2006		2005		Change
Generation (million kWhs)		2,494		2,283		9.2	%		5,287		4,985		6.1	%

Operating Revenues

Operating revenues were as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Revenue from affiliates	$	71.6	$	74.5	$	148.7	$	159.4
Wholesale and other, net		18.7		17.2		42.7		23.3

Total revenues	$	90.3	$	91.7	$	191.4	$	182.7

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.

Monongahela’s Generation and Marketing segment purchases energy from, and sells power to, AE Supply at PJM market prices under a affiliated power sales agreement. Monongahela records either affiliated revenues or purchased power and transmission expenses related to these transaction, depending on Monongahela’s net energy requirements, as determined on an hourly basis.

Total operating revenues decreased $1.4 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005 due to decreased sales volumes as a result of milder weather, which caused a decrease in electricity demand, and reduced sales to Monongahela’s Delivery and Services segment because Monongahela is no longer serving customers in its former Ohio service territory, which was sold on December 31, 2005. These decreases were partially offset by increased generation volumes due to lower dispatch cost at certain plants.

Total operating revenues increased $8.7 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005 due to increased generation volumes as a result of increased market prices and availability, as well as lower dispatch costs at certain plants. These increases were partially offset by decreased sales volumes as a result of milder weather, which caused a decrease in electricity demand, and reduced sales to Monongahela’s Delivery and Services segment

because Monongahela is no longer serving customers in its former Ohio service territory, which was sold 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				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Fuel consumed in electric generation	$	40.5	$	33.3	$	84.6	$	68.3

Total fuel consumed in electric generation increased by $7.2 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005, primarily due to a $6.9 million increase in coal expense. The increase in coal expense was due to a 0.1 million-ton increase in the amount of coal burned and an increase in the price of coal of $2.42 per ton, from $35.54 per ton to $37.96 per ton. The increase in the amount of coal burned was primarily due to a 9.2% increase in total MWhs generated.

Total fuel consumed in electric generation increased by $16.3 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, primarily due to an $15.6 million increase in coal expense. The increase in coal expense was due to a 0.2 million-ton increase in the amount of coal burned and an increase in the price of coal of $3.40 per ton, from $34.66 per ton to $38.06 per ton. The increase in the amount of coal burned was primarily due to a 6.1% increase in total MWhs generated.

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Purchased power and transmission	$	13.9	$	23.3	$	34.3	$	49.2

Purchased power and transmission decreased $9.4 million and $14.9 million for the three and six months ended June 30, 2006, respectively, compared to the three and six months ended June 30, 2005, primarily due to a decrease in affiliated purchases to service load requirements. This decrease was a result of decreased demand due to Monongahela no longer serving customers in its former Ohio service territory, increased MWhs generated and reduced demand as a result of milder weather.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Operations and maintenance	$	23.3	$	22.3	$	40.5	$	39.2

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

Operations and maintenance expenses increased $1.3 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005, primarily due to costs associated with the implementation of Allegheny’s information technology initiatives, partially offset by decreased special maintenance.

ALLEGHENY GENERATING COMPANY—RESULTS OF OPERATIONS

Income Summary


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Operating revenues	$	13.9	$	16.7	$	31.2	$	33.6
Operating income	$	7.8	$	10.6	$	18.5	$	21.4
Income before income taxes	$	6.7	$	8.8	$	15.7	$	17.7
Net income	$	6.7	$	7.8	$	12.9	$	15.1

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				Six Months Ended
	June 30,				June 30,
(In millions)	2006		2005		2006		2005
Operating revenues	$	13.9	$	16.7	$	31.2	$	33.6

Operating revenues decreased $2.8 million and $2.4 million for the three and six months ended June 30, 2006 , respectively, compared to the three and six months ended June 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 (1.1)% and 17.7% for the three and six months ended June 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 12.2% and 14.5% for the three and six months ended June 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. The timing and amount of external financings depend primarily upon economic and financial market conditions and Allegheny’s cash needs and capital structure objectives. The availability and cost of external financings depend upon the financial condition of the companies seeking those funds and upon market conditions.

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


	June 30, 2006				December 31, 2005
(In millions)	Amount		%		Amount		%
Debt	$	3,899.0		67.2	$	4,101.7		70.5
Common equity		1,876.5		32.4		1,695.3		29.1
Preferred equity		24.0		0.4		24.0		0.4

Total	$	5,799.5		100.0	$	5,821.0		100.0

At June 30, 2006, $264.5 million was available under the AE Revolving Credit Facility and $115.0 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.

Allegheny made various other debt payments during the six months ended June 30, 2006. See Note 4, “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 operation, liquidity, capital expenditures or capital resources.

Long-Term Debt and Contractual Obligations

See Note 4, “Debt,” to the Consolidated Financial Statements 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 June 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	July 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)	$	437.6	$	263.9	$	201.3	$	3,004.2	$	3,907.0
Interest on long-term debt (b)		119.4		441.5		427.6		447.0		1,435.5
Interest rate swap obligations		3.1		12.2		12.2		2.1		29.6
Capital lease obligations		4.5		12.2		6.9		2.0		25.6
Operating lease obligations		2.5		7.2		6.7		19.5		35.9
PURPA purchased power		115.0		458.9		467.8		4,179.5		5,221.2
Fuel purchase and transportation commitments		312.3		1,030.7		666.6		2,221.9		4,231.5
Other purchase obligation (c)		34.7		53.3		50.4		44.9		183.3

Total	$	1,029.1	$	2,279.9	$	1,839.5	$	9,921.1	$	15,069.6


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

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


	Payments from
Contractual Obligations and	July 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)	$	300.0	$	15.5	$	110.0	$	260.3	$	685.8
Interest on long-term debt (b)		15.8		47.6		39.3		76.5		179.2
Capital lease obligations		1.4		3.7		2.0		0.5		7.6
Operating lease obligations		0.3		0.4		—		—		0.7
PURPA purchased power		32.3		130.7		132.7		1,524.5		1,820.2
Fuel purchase and transportation commitments		64.4		216.4		139.6		472.8		893.2

Total	$	414.2	$	414.3	$	423.6	$	2,334.6	$	3,586.7


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

(b)		Amounts are based on interest rates as of June 30, 2006 and do not reflect any payments made subsequent to June 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 last six months of 2006 and for the full year of 2007 are estimated at $327.6 million and $792.8 million, respectively, and include estimated expenditures of $146.8 million and $404.7 million, respectively, for environmental control technology. See Item 8, Note 23, Commitments and Contingencies, to the 2005 Annual Report on Form 10-K for additional information.

Financing

Debt:See Note 4, “Debt,” for a discussion of the issuances and repayments of debt by the registrants during the six months ended June 30, 2006.

Short-term Debt:Both AE and AE Supply manage short-term obligations with cash on hand and amounts available under revolving credit facilities. AE, Monongahela, Potomac Edison, West Penn and AE Supply 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.

At June 30, 2006, no registrant had access to any short-term revolving credit facilities or lines of credit with third-party financial institutions beyond those described above. AE had $264.5 million of revolving credit available under the $400 million AE Revolving Credit Facility and AE Supply had $115.0 million available under the $200 million AE Supply Revolving Facility. There were $135.5 million of outstanding letters of credit issued under the AE Revolving Credit Facility at June 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.

Asset Sales

On May 25, 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 $27.4 million.

See Note 5, “Discontinued Operations and Assets Held for Sale,” to the Consolidated Financial Statements 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 six months ended June 30, 2006 was $318.8 million, consisting of net income of $144.5 million and non-cash charges of $248.1 million, partially offset by pension and other postretirement employee benefit plan contributions of $65.4 million, changes in certain assets and liabilities of $6.3 million and net cash used in operating activities of discontinued operations of $2.1 million. Cash flows provided by operating activities for the six months ended June 30, 2005 were $189.5 million, consisting of discontinued operations and non-cash charges of $210.5 million, net cash provided by operating activities of discontinued operations of $61.9 and net income of $24.2 million, partially offset by pension and other postretirement employee benefit plan contributions of $42.3 million and changes in certain assets and liabilities of $64.8 million. Significant cash flows related to operating activities for the six months ended June 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 six months ended June 30, 2006 resulted in a decrease in operating cash flows of $6.3 million. Operating cash flows were used primarily for a $111.2 million decrease in accounts payable, primarily due to timing differences associated with the payment of certain obligations, a $23.6 million increase in materials, supplies and fuel inventory, primarily due to seasonal fuel usage, and a $23.1 million decrease in accrued taxes primarily due to timing differences associated with the payment of certain tax obligations. These amounts were partially offset by cash flows provided by operating activities primarily as a result of a $87.1 million decrease in collateral deposits, primarily due to reduced collateral requirements with various counterparties to Allegheny’s power contracts, and a $46.3 million decrease in accounts receivable, net, primarily due to the timing and volume of unbilled utility revenues.

The changes in certain assets and liabilities for the six months ended June 30, 2005 resulted in a decrease in operating cash flows of $64.8 million. Operating cash flows were used primarily for a $35.8 million increase in accounts receivable, net, primarily due to the timing and volume of unbilled utility revenues, a $22.7 million increase in materials, supplies and fuel inventory, primarily due to seasonal fuel usage, a $21.8 million decrease in accounts payable, primarily due to timing differences associated with the payment of certain obligations, a $21.2 million decrease in accrued taxes, primarily due to timing differences associated with the payment of certain tax obligations, and a $17.1 million increase in collateral deposits, primarily due to increased collateral requirements with various counterparties to Allegheny’s power contracts. These amounts were partially offset by cash flows provided by operating activities primarily as a result of a $41.1 million increase in accrued interest, primarily due to $41.3 million of interest expense accrued for the Merrill Lynch litigation judgment.

Investing Activities:Cash flows used in investing activities for the six months ended June 30, 2006 were $175.6 million. Cash flows provided by investing activities for the six months ended June 30, 2005 were $88.7 million.

Significant cash flows used in investing activities for the six months ended June 30, 2006 included $196.8 million in capital expenditures and $13.9 million for the purchase of the minority interest in Hunlock Creek Energy Ventures. These amounts were partially offset by $27.4 million in proceeds received from the sale of TVA receivable related to assets held-for-sale and a $7.3 million decrease in restricted funds, primarily due to the dissolution of Hunlock Creek Energy Ventures.

Significant cash flows provided by investing activities for the six months ended June 30, 2005 included a $206.6 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 $13.4 million in proceeds from asset sales, primarily related to the sale of the Hagerstown, Maryland property. These amounts were partially offset by $126.6 million in capital expenditures.

Financing Activities:Cash flows used in financing activities for the six months ended June 30, 2006 and 2005 were $200.2 million and $281.9 million, respectively.

Significant cash flows used in financing activities for the six months ended June 30, 2006 included $1,352.1 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 $1,142.1 million (net of $4.0 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 $10.2 million in cash proceeds received from employees for the exercise of stock options.

Significant cash flows used in financing activities for the six months ended June 30, 2005 included $443.1 million related to payments on and retirement of long-term debt, primarily due to the June 16, 2005 refinancing of the prior credit facility and repayments of the Prior AE Supply Term Loan due to the sale of OVEC and the Lincoln Generating Facility. This amount was partially offset by $160.0 million (net of $9.0 million related to debt issuance costs) in proceeds from the issuance of long-term debt, primarily used to refinance the outstanding borrowings under the prior credit facility.

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 $66.1 million for the six months ended June 30, 2006 compared with $157.4 million for the same period in 2005.

Cash flows provided by operating activities for the six months ended June 30, 2006 were $76.7 million, consisting of non-cash charges of $36.1 million, net income of $28.6 million and changes in certain assets and liabilities of $12.0 million. Cash flows provided by operating activities for the six months ended June 30, 2005 were $159.9 million, consisting of net cash provided by operating activities of discontinued operations of $97.3 million, discontinued operations and non-cash charges of $31.4 million, net income of $24.8 million and changes in certain assets and liabilities of $6.4 million.

The changes in certain assets and liabilities for the six months ended June 30, 2006 resulted in an increase in operating cash flows of $12.0 million. Operating cash flows were provided primarily by a $18.9 million decrease in accounts receivable, net, primarily due to the timing and volume of unbilled utility revenues, a $9.5 million decrease in collateral

deposits, primarily due to reduced collateral requirements with various counterparties to Monongahela’s power contracts, and a $6.6 million decrease in prepaid taxes, primarily due to timing differences associated with the prepayment of certain tax obligations. These amounts were partially offset by cash flows used for operating activities primarily as a result of an $8.8 million decrease in accounts payable, primarily due to timing differences associated with the payment of certain obligations, a $4.3 million decrease in accrued taxes, primarily due to timing differences associated with the payment of certain tax obligations, and a $4.0 million increase in materials, supplies and fuel inventory, primarily due to seasonal fuel usage.

The changes in certain assets and liabilities for the six months ended June 30, 2005 resulted in an increase in operating cash flows of $6.4 million. Operating cash flows were provided primarily by a $33.0 million increase in accounts payable to affiliates, net, primarily due to timing differences associated with the payment of certain obligations, and a $7.5 million decrease in prepaid taxes, primarily due to timing differences associated with the prepayment of certain tax obligations. These amounts were partially offset by cash flows used for operating activities primarily as a result of a $14.2 million decrease in accrued taxes, primarily due to timing differences associated with the payment of certain tax obligations, a $9.5 million increase in collateral deposits, primarily as a result of collateral requirements of PJM related to the Ohio customers, and a $7.1 million increase in accounts receivable, net, primarily due to the timing and volume of unbilled utility revenues.

Investing Activities:Cash flows used in investing activities for the six months ended June 30, 2006 and 2005 were $001.6 million and $77.3 million, respectively, consisting primarily of capital expenditures and the issuance of a note receivable from an affiliate.

Financing Activities:Cash flows used in financing activities for the six months ended June 30, 2006 and 2005 were $10.7 million and $78.9 million, respectively.

Significant cash flows used in financing activities for both periods related to cash dividends paid on preferred and common stock. The six months ended June 30, 2005 amount also included a use of $76.4 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 $2.3 million for the six months ended June 30, 2006 compared with $13.6 million for the same period in 2005.

Cash flows provided by operating activities for the six months ended June 30, 2006 were $15.3 million, consisting of net income of $12.9 million and non-cash charges of $5.2 million, partially offset by changes in certain assets and liabilities of $2.8 million. Cash flows provided by operating activities for the six months ended June 30, 2005 were $20.8 million, consisting of net income of $15.1 million, non-cash charges of $5.1 million and changes in certain assets and liabilities of $0.6 million.

The changes in certain assets and liabilities for the six months ended June 30, 2006 resulted in a decrease in operating cash flows of $2.8 million. Operating cash flows were used primarily for a $2.7 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 six months ended June 30, 2005 resulted in an increase in operating cash flows of $0.6 million. Operating cash flows were provided primarily by a $0.5 million increase in accounts payable to affiliates, net, primarily due to timing of the settlement of affiliate transactions.

Investing Activities:Cash flows used in investing activities for the six months ended June 30, 2006 and 2005 were $1.4 million and $4.4 million, respectively, consisting of capital expenditures.

Financing Activities:Cash flows used in financing activities for the six months ended June 30, 2006 were $13.0 million consisting of cash dividends paid on common stock. Cash flows used in financing activities for the six months ended June 30, 2005 were $22.2 million consisting of a $15.0 million payment on a note payable to parent and $7.2 million of cash dividends paid on common stock.

Change in Credit Ratings

The following table lists Allegheny’s credit ratings, as of August 8, 2006:


	Moody’s	S & P	Fitch
Outlook	Stable	Positive	Stable
AE:
Corporate Credit Rating	Ba1(a)	BB+	NR
Senior Unsecured Debt	Ba2	BB-	BB+
Short-term Rating	SGL-2(b)	B2	NR
AE Supply:
Senior Unsecured Debt	Ba3	BB-	BB+
Senior Secured Debt	Ba2	BBB-	BBB-
Pollution Control Bonds	NR	NR	AAA
Monongahela:
First Mortgage Bonds	Baa3	BBB-	BBB+
Senior Unsecured Debt	Ba1	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
Senior Unsecured Debt	Baa3	BB+	BBB-
AGC:
Senior Unsecured Debt	Ba3	BB-	BB+


(a)		Corporate Family rating

(b)		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.

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

Recent FERC actions with respect to the transmission rate design within PJM may impact the Distribution Companies. Beginning in July 2003, FERC issued a series of orders related to transmission rate design for the PJM and Midwest Independent Transmission System Operator regions. Specifically, FERC ordered the elimination of multiple and additive (i.e., “pancaked”) rates and called for the implementation of a long-term rate design for these regions. In November 2004, FERC rejected long-term regional rate proposals from the Distribution Companies and others. FERC concluded that neither the rate design proposals, nor the existing PJM rate design, had been shown to be just and reasonable. However, FERC ordered the continuation of the existing PJM rate design until replaced by a different rate design accepted by FERC and required the implementation of a transition charge for these regions through March 31, 2006, through filings made by transmission owners in these regions. In February 2005, FERC accepted the transition charge filings, effective December 1, 2004, subject to an evidentiary hearing.

These transition charges have resulted in net transmission charges to the Distribution Companies of approximately $8.9 million for the 16-month period ended March 31, 2006. The order following the evidentiary hearing on these transition charges 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 the Distribution Companies. The Distribution Companies have entered into partial settlements with regard to the transition charges. FERC has approved two of the settlements, and approval is pending on the others.

In a May 2005 order, FERC again determined that the existing PJM rate design may not be just and reasonable. On September 30, 2005, the Distribution Companies, together with another PJM transmission owner, filed a proposed rate design with FERC to replace the existing rate design within PJM, effective April 1, 2006. Two other PJM transmission owners and FERC staff also filed a 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 Allegheny is just and reasonable, but ruled that the rate design proposed by FERC staff is 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 is unjust and unreasonable but adopted the Distribution Companies’ position that the implementation of a new rate design does not necessitate a change in the allocation of auction revenue rights and financial transmission rights. 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.

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 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.

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 is expected to issue a final order on this matter by the end of 2006. In addition, FERC has ordered implementation of settlement procedures in this proceeding, and AE Supply and the Distribution Companies currently are participating in settlement process.

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 give further consideration to the remaining elements of the TrAIL proposal.

Concurrently 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 210-mile transmission line to be constructed by the Distribution Companies or their affiliate in the PJM zone. On July 20, 2006, FERC approved the incentive rate treatments for the 210-mile transmission line. Approval of the incentive rates is subject to AE and the Distribution Companies making 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. Allegheny cannot predict when a decision with respect to this matter will be forthcoming.

State Legislation, Regulation and Rate Matters

West Virginia:In 1998, the West Virginia legislature passed legislation directing the Public Service Commission of West Virginia (the “West Virginia PSC”) to determine whether retail electric competition was in the best interests of West Virginia and its citizens. In response, the West Virginia PSC submitted a plan to introduce full retail competition on January 1, 2001. The West Virginia legislature approved, but never implemented, this plan. In March 2003, the West Virginia legislature passed a bill that clarified the jurisdiction of the West Virginia PSC over electric generation facilities. Based on these actions, Allegheny has concluded that retail competition and the deregulation of generation is no longer likely in West Virginia. In 2000, Potomac Edison received approval to transfer its West Virginia generation assets to AE Supply. The West Virginia PSC never acted on a similar petition by Monongahela, and Monongahela agreed to withdraw its petition.

On March 24, 2005, Monongahela and Potomac Edison filed an application with the West Virginia PSC for a Certificate of Public Convenience and Necessity to construct the Scrubbers at Fort Martin. On May 24, 2005, Monongahela and Potomac Edison filed an application with the West Virginia PSC requesting approval to issue $382 million in environmental control bonds to raise capital for the installation of the Scrubbers at Fort Martin and related costs. Monongahela and Potomac Edison have proposed to secure these environmental control bonds with the rights to collect an environmental control charge from customers over the term of the bonds. Allegheny entered into a settlement agreement with a group of interested parties, which was filed with the West Virginia PSC on January 11, 2006. Pursuant to the settlement agreement, the parties requested that the West Virginia PSC approve construction of the Scrubbers and the related securitization transaction, as well as the related intercompany asset swap. Beginning on January 17, 2006, the West Virginia PSC held hearings on the applications filed by Monongahela and Potomac Edison related to the proposed asset swap and for a Certificate of Public Convenience and Necessity related to the proposed installation of the pollution control equipment at Fort Martin. On April 7, 2006 the West Virginia PSC approved the settlement agreement. On April 27, Monongahela and Potomac Edison filed a Petition for Correction and Reconsideration with the West Virginia PSC requesting that the PSC reconsider one issue in the April 7 Financing Order. On June 13, the West Virginia PSC issued an Order on the Petition modifying the April 7 Financing Order as Monongahela and Potomac Edison requested.

Allegheny may also be required to obtain certain lender approvals in order to consummate the Asset Swap. Currently, Allegheny plans to execute the Asset Swap and securitization only to the extent that it receives all of the regulatory and other approvals necessary for each aspect of the combined transaction.

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, effective on August 25, 2006. 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 million decrease in base rates. The rate increase request is subject to approval by the West Virginia PSC, which has not yet set a procedural schedule for the filing. The proposed rates may be suspended for up to 270 days by the West Virginia PSC.

Maryland:In special session, the Maryland legislature passed emergency legislation on June 14, 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, after the expiration of capped rates, 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.

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, 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 estimates and modeling assumptions, which could materially differ from actual results. As of June 30, 2006 and December 31, 2005, this calculation yielded a one-day VaR of $0.3 million.

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 June 30, 2006.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Note 18, “Commitments and Contingencies,” to the Consolidated Financial Statements 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 June 30, 2006 and plans to continue its debt reduction program, Allegheny still has substantial leverage. At June 30, 2006, Allegheny had $3.9 billion of debt on a consolidated basis. Approximately $169.1 million of that amount represented AE’s obligations, $2.3 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 little to no exposure to the SO₂ allowance market in 2006, and may have exposure of between zero and 40,000 tons in 2007 and between 40,000 and 80,000 tons in 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.

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

AE. AE’s annual meeting of stockholders was held on May 11, 2006. At the annual meeting, votes were taken for: (1) the election of directors; (2) ratification of the appointment of PricewaterhouseCoopers LLP as Allegheny’s independent registered public accounting firm; (3) a stockholder proposal requiring management to retain stock; (4) a stockholder proposal regarding an independent board chairman; (5) a stockholder proposal relating to director qualifications; (6) a stockholder proposal regarding performance-based options; (7) a stockholder proposal regarding a separate vote on golden pay; (8) a stockholder proposal to recoup unearned management bonuses in the event of a restatement of financial results; and (9) a stockholder proposal to redeem or vote on any poison pill.

AE’s stockholders elected H. Furlong Baldwin, Eleanor Baum, Paul J. Evanson, Cyrus F. Freidheim, Jr., Julia L. Johnson, Ted J. Kleisner, Steven H. Rice, Gunnar E. Sarsten and Michael H. Sutton to serve on the Board of Directors for one-year terms, which will expire in 2007. Stockholders ratified the appointment of PricewaterhouseCoopers LLP as Allegheny’s independent registered public accounting firm. The stockholders did not approve any of the stockholder proposals.

The following tables provide details regarding the number of votes cast by AE’s stockholders with respect to each of the matters indicated above.

Election of directors:


Nominees for Director	Votes For		Votes withheld
H. Furlong Baldwin		132,164,541		3,212,470
Eleanor Baum		131,753,227		3,623,784
Paul J. Evanson		131,820,699		3,556,312
Cyrus F. Freidheim, Jr.		132,360,862		3,016,149
Julia L. Johnson		132,355,654		3,021,357
Ted J. Kleisner		132,401,762		2,975,249
Steven H. Rice		131,876,564		3,500,447
Gunnar E. Sarsten		131,851,809		3,525,202
Michael H. Sutton		132,463,139		2,913,872

Other items as described above:


Item	Votes For	Votes Against	Abstentions	Broker Non-Votes
(2)	132,824,152	1,457,546	1,095,313	0
(3)	40,550,056	71,581,125	1,756,372	21,489,458
(4)	48,149,635	64,155,943	1,581,975	21,489,458
(5)	6,638,590	105,338,626	1,910,337	21,489,458
(6)	51,440,868	60,750,872	1,695,813	21,489,458
(7)	49,665,097	62,498,901	1,723,555	21,489,458
(8)	46,453,399	61,631,129	5,803,025	21,489,458
(9)	32,454,651	79,390,349	2,042,553	21,489,458

Monongahela. At the annual meeting of Monongahela shareholders held on April 27, 2006, votes were taken for the election of directors. The total number of votes cast was 5,891,000, with all votes being cast for the election of the following directors: Paul J. Evanson, Joseph H. Richardson, and Jeffrey D. Serkes.

AGC. At a special meeting of AGC’s shareholders held on May 18, 2006, votes were taken for the removal of a director. The total number of votes cast was 1,000, with all votes being cast for the removal of John P. Campbell.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

EXHIBIT INDEX

Allegheny Energy, Inc.


		Documents

10.1		EPC Agreement No. 1001 dated July 12, 2006, between Allegheny Energy Supply Company, LLC and The Babcock & Wilcox Company covering Flue Gas Desulfurization Project at Hatfield’s Ferry Units 1, 2 and 3

10.2		EPC Agreement No. 1002 dated July 13, 2006, between Allegheny Energy Supply Company, LLC and Washington Group International covering Balance of Plant for Flue Gas Desulfurization Project at Hatfield’s Ferry Units 1, 2 and 3

10.3		Letter Agreement, dated August 3, 2006, between Allegheny Energy Service Corporation and David E. Flitman

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

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

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

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: August 8, 2006	By:	/s/ Philip L. Goulding
		Philip L. Goulding
		Senior Vice President and Chief Financial Officer

	MONONGAHELA POWER COMPANY
Date: August 8, 2006	By:	/s/ Philip L. Goulding
		Philip L. Goulding
		Vice President and Principal Financial Officer

	ALLEGHENY GENERATING COMPANY.
Date: August 8, 2006	By:	/s/ Philip L. Goulding
		Philip L. Goulding
		Vice President and Principal Financial Officer

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

Allegheny Energy (AYE) Inactive 10-Q2006 Q2 Quarterly report

Content analysis