Allegheny Energy 10Q 2007 Q1 Quarterly report

Allegheny Energy (AYE) Inactive 10-Q2007 Q1 Quarterly report

Content analysis

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2007


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

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

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

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

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

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

Indicate by check mark 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. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (check one).


	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 April 30, 2007:


Allegheny Energy, Inc.	165,710,517	($1.25 par value)
Monongahela Power Company	5,891,000	($50.00 par value)
Allegheny Generating Company	1,000	($1.00 par value)

TABLE OF CONTENTS


	Page No.
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)
Allegheny Energy, Inc. and Subsidiaries		4
Monongahela Power Company and Subsidiaries		32
Allegheny Generating Company		49
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”)		57
Item 3. Quantitative and Qualitative Disclosures About Market Risk		96
Item 4. Controls and Procedures		96

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		97
Item 1A. Risk Factors		97
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		97
Item 3. Defaults Upon Senior Securities		97
Item 4. Submission of Matters to a Vote of Security Holders		97
Item 5. Other Information		97
Item 6. Exhibits		98
Signatures		101
EX-10.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2

GLOSSARY

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


AE		Allegheny Energy, Inc., a diversified utility holding company
Allegheny Ventures		Allegheny Ventures, Inc., an unregulated subsidiary of AE
AE Solutions		Allegheny Energy Solutions, Inc., a subsidiary of Allegheny Ventures
AE Supply		Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary of AE
AGC		Allegheny Generating Company, an unregulated generation subsidiary of AE Supply and Monongahela
Allegheny		AE together with its consolidated subsidiaries
Distribution Companies		Collectively, Monongahela, Potomac Edison and West Penn. The Distribution Companies do business as “Allegheny Power”
Monongahela		Monongahela Power Company, a regulated subsidiary of AE
Potomac Edison		The Potomac Edison Company, a regulated subsidiary of AE
TrAIL Company		Trans-Allegheny Interstate Line Company, an indirect subsidiary of AE
West Penn		West Penn Power Company, a regulated subsidiary of AE

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


	Three Months Ended March 31,
(In thousands)	2007			2006
Operating revenues	$	847,625		$	845,646

Operating expenses:
Fuel		232,225			218,689
Purchased power and transmission		93,266			101,232
Gain on sale of OVEC power agreement and shares		—			(5,000	)
Deferred energy costs, net		(1,455	)		4,993
Operations and maintenance		160,544			156,381
Depreciation and amortization		71,981			67,842
Taxes other than income taxes		55,890			53,667

Total operating expenses		612,451			597,804


Operating income		235,174			247,842

Other income and expenses, net		5,862			7,671

Interest expense and preferred dividends:
Interest expense		59,236			67,388
Preferred dividend of subsidiary		293			293

Total interest expense and preferred dividends		59,529			67,681

Income from continuing operations before income taxes and minority interest		181,507			187,832

Income tax expense		71,378			72,504

Minority interest in net income of subsidiaries		387			1,178

Income from continuing operations		109,742			114,150

Loss from discontinued operations, net of tax (Note 8)		—			(766	)

Net income	$	109,742		$	113,384

Common share data:
Weighted average common shares outstanding
Basic		165,494			163,080
Diluted		169,181			168,504

Basic income per common share:
Income from continuing operations	$	0.66		$	0.70
Loss from discontinued operations, net of tax		—			—

Net income per common share	$	0.66		$	0.70

Diluted income (loss) per common share:
Income from continuing operations	$	0.65		$	0.68
Loss from discontinued operations, net of tax		—			(0.01	)

Net income per common share	$	0.65		$	0.67

See accompanying Notes to Consolidated Financial Statements.

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


	Three Months Ended
	March 31,
(In thousands)	2007			2006
Cash Flows From Operating Activities:
Net income	$	109,742		$	113,384
Loss from discontinued operations, net of tax		—			766
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		71,981			67,842
Amortization of debt issuance costs		2,695			3,541
Amortization of power sale liability related to Ohio sale		(9,100	)		(10,700	)
Amortization of liability for adverse power purchase commitment		(4,322	)		(4,289	)
Amortization of Pennsylvania stranded cost recovery asset		4,664			3,980
Minority interest in net income of subsidiaries		387			1,178
Deferred income taxes and investment tax credit, net		74,955			71,870
Stock-based compensation expense		2,823			4,152
Unrealized gains on commodity contracts, net		(2,450	)		(13,005	)
Pension and other postretirement employee benefit plan expense		9,414			10,435
Pension and other postretirement employee benefit plan contributions		(39,322	)		(62,482	)
Other, net		(508	)		5,898

Changes in certain assets and liabilities:
Accounts receivable, net		(44,519	)		14,741
Materials, supplies and fuel		851			(3,227	)
Prepaid taxes		(34,542	)		(32,703	)
Collateral deposits		(8,333	)		53,601
Prepayments		(1,304	)		(245	)
Other current assets		10,668			647
Accounts payable		24,958			(106,668	)
Accrued taxes		(11,433	)		(52,568	)
Accrued interest		8,189			15,271
Other current liabilities		92			(7,255	)
Other assets		(2,076	)		1,252
Deferred income taxes		(12,262	)		35,942
Other liabilities		2,599			80
Net cash used in operating activities of discontinued operations		—			(1,250	)

Net cash provided by operating activities		153,847			110,188

Cash Flows From Investing Activities:
Capital expenditures		(168,439	)		(94,760	)
Proceeds from sale of assets		260			34
Purchase of minority interest in Hunlock Creek Energy Ventures		—			(13,900	)
Decrease in restricted funds		1,322			5,271
Other investments		(992	)		(1,725	)

Net cash used in investing activities		(167,849	)		(105,080	)

Cash Flows From Financing Activities:
Deferred financing costs		—			(206	)
Repayment of long-term debt		(36,073	)		(51,757	)
Payments on capital lease obligations		(1	)		(11	)
Exercise of stock options		4,580			8,465
Cash dividends paid to minority shareholder in Hunlock Creek Energy Ventures		—			(400	)

Net cash used in financing activities		(31,494	)		(43,909	)

Net decrease in cash and cash equivalents		(45,496	)		(38,801	)
Cash and cash equivalents at beginning of period		114,138			262,212

Cash and cash equivalents at end of period	$	68,642		$	223,411

Supplemental Cash Flow Information:
Cash paid for interest (net of amount capitalized)	$	48,493		$	50,709

See accompanying Notes to Consolidated Financial Statements.

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


	March 31,			December 31,
(In thousands)	2007			2006
ASSETS
Current Assets:
Cash and cash equivalents	$	68,642		$	114,138
Accounts receivable:
Customer		220,788			167,792
Unbilled utility revenue		97,553			117,977
Wholesale and other		72,948			63,894
Allowance for uncollectible accounts		(13,758	)		(14,591	)
Materials and supplies		98,661			96,117
Fuel		71,556			74,951
Deferred income taxes		129,636			127,531
Prepaid taxes		79,145			44,603
Collateral deposits		47,264			39,399
Commodity contracts		34			1,430
Restricted funds		11,601			12,923
Regulatory assets		40,784			39,128
Other		14,766			24,130

Total current assets		939,620			909,422

Property, Plant and Equipment, Net:
Generation		5,831,687			5,820,278
Transmission		1,061,692			1,056,759
Distribution		3,632,429			3,597,405
Other		448,625			412,894
Accumulated depreciation		(4,706,362	)		(4,636,972	)

Subtotal		6,268,071			6,250,364
Construction work in progress		308,708			262,529

Total property, plant and equipment, net		6,576,779			6,512,893

Investments and Other Assets:
Goodwill		367,287			367,287
Investments in unconsolidated affiliates		28,114			28,259
Other		28,714			27,932

Total investments and other assets		424,115			423,478

Deferred Charges:
Regulatory assets		657,746			674,095
Other		36,020			32,558

Total deferred charges		693,766			706,653

Total Assets	$	8,634,280		$	8,552,446

See accompanying Notes to Consolidated Financial Statements.

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


	March 31,			December 31,
(In thousands, except share data)	2007			2006
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Long-term debt due within one year (Note 5)	$	187,136		$	201,189
Accounts payable		243,002			236,706
Accrued taxes		100,590			136,216
Commodity contracts		10,272			5,984
Accrued interest		108,043			99,854
Other		130,019			140,830

Total current liabilities		779,062			820,779


Long-term Debt (Note 5)		3,363,668			3,383,986

Deferred Credits and Other Liabilities:
Commodity contracts		15,324			17,982
Taxes payable		64,065			—
Investment tax credit		72,042			72,938
Deferred income taxes		978,935			936,911
Obligations under capital leases		26,962			26,007
Regulatory liabilities		443,211			464,092
Adverse power purchase commitment		162,653			166,937
Other		516,229			547,706

Total deferred credits and other liabilities		2,279,421			2,232,573

Commitments and Contingencies (Note 20)

Minority Interest		11,120			10,713

Preferred Stock of Subsidiary		24,000			24,000

Common Stockholders’ Equity:
Common stock, $1.25 par value, 260 million shares authorized and 165,654,590 and 165,409,908 shares issued at March 31, 2007 and December 31, 2006, respectively		207,068			206,762
Other paid-in capital		1,913,920			1,907,879
Retained earnings		166,717			74,698
Treasury stock at cost; 49,493 shares		(1,756	)		(1,756	)
Accumulated other comprehensive loss		(108,940	)		(107,188	)

Total common stockholders’ equity		2,177,009			2,080,395

Total Liabilities and Stockholders’ Equity	$	8,634,280		$	8,552,446

See accompanying Notes to Consolidated Financial Statements.

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


														Accumulated
					Other									other			Total
	Shares		Common		paid-in			Retained			Treasury			comprehensive			stockholders’
(In thousands, except shares)	outstanding		stock		capital			earnings			stock			loss			equity
Balance at December 31, 2006		165,360,415	$	206,762	$	1,907,879		$	74,698		$	(1,756	)	$	(107,188	)	$	2,080,395
Net income		—		—		—			109,742			—			—			109,742
Adoption of FIN 48		—		—		—			(17,722	)		—			—			(17,722	)
Pension and other postretirement employee benefit amortization, net of tax of $1,069		—		—		—			—			—			1,569			1,569
Unrealized income on available-for-sale securities, net of tax		—		—		—			—			—			3			3
Unrealized losses on cash flow hedges for the period, net of tax of $2,110		—		—		—			—			—			(3,324	)		(3,324	)
Stock-based compensation expense:
Stock units		—		—		798			—			—			—			798
Non-employee stock awards		12,400		15		378			—			—			—			393
Stock options		—		—		1,631			—			—			—			1,631
Exercise of stock options		163,805		205		4,376			—			—			—			4,581
Conversion of stock units		68,477		86		(1,142	)		—			—			—			(1,056	)
Other		—		—		—			(1	)		—			—			(1	)

Balance at March 31, 2007		165,605,097	$	207,068	$	1,913,920		$	166,717		$	(1,756	)	$	(108,940	)	$	2,177,009

See accompanying Notes to Consolidated Financial Statements.

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


Note No.		Page No.
1	Basis of Presentation		10

2	Recent Accounting Pronouncements		11

3	Asset Swap		12

4	Income Taxes		12

5	Debt		14

6	Stock-Based Compensation		15

7	Derivative Instruments and Hedging Activities		17

8	Discontinued Operations		17

9	Business Segments		18

10	Goodwill and Intangible Assets		18

11	Comprehensive Income		19

12	Pension Benefits and Postretirement Benefits Other Than Pensions		19

13	Income (Loss) Per Share		21

14	Adverse Power Purchase Commitment Liability		22

15	Regulatory Assets and Liabilities		22

16	Asset Retirement Obligations (“AROs”)		23

17	Other Income and Expenses, Net		23

18	Guarantees and Letters of Credit		24

19	Variable Interest Entities (“VIE”)		24

20	Commitments and Contingencies		25

21	Subsequent Event		31

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”) and Trans-Allegheny Interstate Line Company (“TrAIL Company”). TrAIL Company was formed in 2006 in connection with the construction, management and financing of transmission expansion projects, including Allegheny’s proposed 210-mile 500 kv transmission line (the Trans-Allegheny Interstate Line).

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

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

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

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

During the fourth quarter of 2006, Allegheny changed its classification of fuel handling and residual disposal costs within its Consolidated Statements of Operations from “Operations and maintenance” expenses to “Fuel” expenses to improve comparability with other energy and utility companies and facilitate a better understanding of operating costs. Accordingly, Allegheny reclassified such costs previously reported in the amount of $5.5 million, for the three months ended March 31, 2006 to conform to the financial statement presentation for the current period.

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

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

NOTE 2: RECENT ACCOUNTING PRONOUNCEMENTS

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

In June 2006, the Emerging Issues Tax Force (“EITF”) reached a consensus on 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (“EITF 06-3”). EITF 06-3 provides guidance on disclosing the accounting policy for the income statement presentation of any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer on either a gross (included in revenues and costs) or a net (excluded from revenues and costs) basis. In addition, EITF 06-3 requires disclosure of any such taxes that are reported on a gross basis as well, as the amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented. EITF 06-3 became effective for Allegheny January 1, 2007. It is Allegheny’s policy to record taxes collected from customers that are assessed on those customers on a net basis. That is, in instances in which Allegheny acts as a collection agent for a taxing authority by collecting taxes which are the responsibility of the customer, Allegheny records the amount collected as a liability and relieves such liability upon remittance to the taxing authority without impacting revenues or expenses. Therefore, the January 1, 2007 implementation of EITF 06-3 did not have a material impact on Allegheny’s financial statements.

In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109 (“FIN 48”). On May 2, 2007, the FASB issued FASB Interpretation No. 48-1, Definition of Settlement in FASB Interpretation No. 48 (“FIN 48-1”), which provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. Allegheny adopted the provisions of FIN 48 and FIN 48-1 as of January 1, 2007. See Note 4, “Income Taxes,” for additional information related to FIN 48 and its impact on Allegheny’s consolidated financial position.

In September 2006, the FASB issued Statement of Financial Accounting Standard (“SFAS”) No. 157, Fair Value Measurements (“SFAS No. 157”). SFAS No. 157 defines fair value and establishes a framework for measuring fair value when fair value is required for recognition or disclosure purposes under GAAP. The standard also expands disclosure about fair value measurement but does not require any new fair value measurements. SFAS No. 157 is effective for Allegheny January 1, 2008. Management has not completed the process of determining the effect of SFAS No. 157 on Allegheny’s financial statements, however, at this time the adoption of SFAS 157 is not expected to have a material impact on Allegheny’s consolidated results of operations or financial position.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure certain financial instruments and other items at fair value that are not currently required to be measured at fair value. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for Allegheny January 1, 2008. Management has not completed the process of determining the effect of SFAS No. 159 on Allegheny’s financial statements, however, at this time the adoption of SFAS No. 159 is not expected to have a material impact on Allegheny’s consolidated results of operations or financial position.

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

NOTE 3: ASSET SWAP

On January 1, 2007, AE Supply and Monongahela completed an intercompany exchange of assets (the “Asset Swap”) that realigned generation ownership and contractual arrangements within the Allegheny system. The Asset Swap was substantially a non-cash transaction and was recorded at the net book value of the assets, liabilities and interest transferred, with certain adjustments. There was no change in Allegheny’s consolidated stockholders’ equity as a result of the Asset Swap. After the Asset Swap, Monongahela owns 100% of the Fort Martin generation facility in West Virginia (“Fort Martin”), allowing Allegheny to finance the construction of flue-gas desulfurization equipment (“Scrubbers”) at Fort Martin through the securitization of an environmental control charge that Monongahela and Potomac Edison impose on their retail customers in West Virginia.

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

In connection with the Asset Swap, AE Supply assumed approximately $6 million in debt associated with outstanding pollution control bonds. Monongahela also will remain obligated to the note holders for the repayment of this debt. Additionally, AE Supply is required to pay in advance of their scheduled maturities approximately $16 million in the aggregate in connection with the redemption of certain pollution control bonds that, by their terms, must be redeemed as a result of the change in ownership of Fort Martin.

NOTE 4: INCOME TAXES

Allegheny allocates federal income tax expense (benefit) among its subsidiaries pursuant to its consolidated tax sharing agreement. 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, effects of utility rate making and certain non-deductible expenses.

In June 2006, the FASB issued FIN 48, which prescribes a comprehensive model for how companies should recognize, measure, present and disclose in their financial statements uncertain tax positions taken or expected to be taken on an income tax return. Under FIN 48, tax benefits should be recognized in the financial statements when it is more likely than not that the position will be sustained upon examination by the tax authorities. Such tax positions should be measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with the tax authority assuming full knowledge of the position and all relevant facts.

The Company adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation, the Company recognized a $17.7 million reduction to its January 1, 2007 balance of retained earnings.

Unrecognized tax benefits were approximately $107.6 million and $110.9 million at January 1, 2007 and March 31, 2007, respectively. If recognized, the portion of these amounts that would reduce the Company’s effective tax rate were $38.7 million and $40.5 million ($58.9 million and $62.2 million before the federal effects on state income tax positions), at January 1, 2007 and March 31, 2007, respectively.

The unrecognized tax benefit balance also included approximately $48.7 million of tax positions at January 1, 2007 and March 31, 2007 for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would impact the timing of cash payments to the taxing authorities.

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

Allegheny records interest and penalties associated with uncertain tax positions as a component of income tax expense. Allegheny had accrued interest, net of tax, related to uncertain tax positions of $11.8 million and $12.0 million at January 1, 2007 and March 31, 2007, respectively.

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

As stated above, the IRS is currently auditing Allegheny’s income tax returns for the tax years 1998 through 2003. These audits are anticipated to be completed by December 31, 2007. During the audit period, Allegheny changed its method of applying the inventory capitalization rules from its traditional method to the simplified service cost method. The IRS has proposed adjustments related to the change in method that are strictly timing in nature. Interest accrued on this position was $10.1 million, net of tax, at March 31, 2007. It is reasonably possible that a portion of this interest accrual will reverse in the next 12 months. However, should the IRS’s position prevail, the adjustments would not result in a material charge to Allegheny’s results of operations. Also, Allegheny has filed various refund claims with the IRS primarily related to property type items. These items will be settled along with the 1998 through 2003 audits and are not expected to result in a material adjustment to Allegheny’s financial position. Additionally, Allegheny has liabilities for uncertain positions taken on various state income tax returns that it files. The statute of limitations for some of these returns will expire during 2007 and could result in a benefit of approximately $2.6 million.

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

NOTE 5: DEBT

At March 31, 2007, contractual maturities of long-term debt for the remainder of 2007 and for full years thereafter were as follows:


(In millions)	2007			2008			2009			2010			2011			Thereafter			Total
AE Supply:
Medium-Term Notes	$	—		$	—		$	—		$	—		$	400.0		$	650.0		$	1,050.0
AE Supply Credit Facility		—			—			—			—			747.0			—			747.0
Pollution Control Bonds		95.4			—			—			—			—			179.0			274.4
Debentures-AGC		—			—			—			—			—			100.0			100.0

Total AE Supply	$	95.4		$	—		$	—		$	—		$	1,147.0		$	929.0		$	2,171.4


Monongahela:
First Mortgage Bonds	$	—		$	—		$	—		$	—		$	—		$	340.0		$	340.0
Medium-Term Notes		—			—			—			110.0			—			—			110.0
Pollution Control Bonds		14.5			—			—			—			—			70.2			84.7

Total Monongahela	$	14.5		$	—		$	—		$	110.0		$	—		$	410.2		$	534.7


Potomac Edison:
First Mortgage Bonds	$	—		$	—		$	—		$	—		$	—		$	420.0		$	420.0

Total Potomac Edison	$	—		$	—		$	—		$	—		$	—		$	420.0		$	420.0


West Penn:
Transition Bonds	$	59.3		$	76.5		$	75.5		$	15.2		$	—		$	—		$	226.5
First Mortgage Bonds		—			—			—			—			—			145.0			145.0
Medium-Term Notes		—			—			—			—			—			80.0			80.0

Total West Penn	$	59.3		$	76.5		$	75.5		$	15.2		$	—		$	225.0		$	451.5


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

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


Unamortized debt discounts and premiums		(1.0	)		(1.4	)		(1.4	)		(1.3	)		(1.0	)		(2.2	)		(8.3	)
Eliminations (a)		(4.1	)		—			—			—			—			(114.4	)		(118.5	)

Total consolidated debt	$	164.1		$	75.1		$	74.1		$	123.9		$	1,146.0		$	1,967.6		$	3,550.8


(a)		Represents the elimination of AGC’s $100 million 6 7/8% Debentures due 2023, which are also included above under AE Supply, and $18.5 million in the aggregate of pollution control bonds, for which Monongahela and AE Supply were co-obligors.

Certain of Allegheny’s properties are subject to liens of various relative priorities securing debt. For additional information regarding property liens, see Item 2, “Properties” in the 2006 Annual Report on Form 10-K.

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

Issuances and repayments of indebtedness, by entity, for the three months ended March 31, 2007 were as follows:


(In millions)	Issuances			Repayments
Monongahela:
Pollution Control Bonds	$	—		$	1.0
AE Supply:
Pollution Control Bonds		7.0			15.6
West Penn:
Transition Bonds (a)		1.4			20.6

Eliminations (b)		(7.0	)		(1.2	)


Consolidated Total	$	1.4		$	36.0


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

(b)		Represents the elimination of changes in the balances for certain pollution control bonds for which Monongahela and AE Supply were co-obligors, as a result of the January 1, 2007 Asset Swap.

Subsequent debt activity

On April 11, 2007, MP Environmental Funding LLC and PE Environmental Funding LLC, both indirect subsidiaries of AE, issued $344 million and $115 million, respectively, of Senior Secured Sinking Fund Environmental Control Bonds, Series A. These bonds securitize the right to collect an environmental control surcharge from the West Virginia customers of Monongahela and Potomac Edison. The bonds were issued in several tranches with interest rates ranging from 4.98% to 5.52% and scheduled maturities ranging from July 2014 to July 2027. Net proceeds from the sale of the bonds represent restricted funds and will be used to fund the majority of costs to construct and install Scrubbers at Fort Martin.

NOTE 6: STOCK-BASED COMPENSATION

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

The following table summarizes stock-based compensation expense:


	Three Months Ended
	March 31,
(In millions)	2007		2006
Stock options	$	1.6	$	2.1
Stock units		0.8		1.8
Other		0.4		0.3

Stock-based compensation expense included in operations and maintenance expense		2.8		4.2
Income tax benefit		1.1		1.7

Total stock-based compensation expense, net of tax	$	1.7	$	2.5

No stock-based compensation cost was capitalized for the three months ended March 31, 2007 or 2006.

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

Stock Options

Stock option activity was as follows:


				Weighted-Average		Aggregate
	Number of			Exercise		Intrinsic Value (a)
	Stock Options			Price		(in millions)
Outstanding at December 31, 2006		4,670,338		$	16.504
Granted		11,000		$	48.282
Exercised		(163,805	)	$	27.963
Forfeited		(51,927	)	$	13.389

Outstanding at March 31, 2007		4,465,606		$	16.198	$	147.1

Exercisable at March 31, 2007		2,467,171		$	16.362	$	80.9


(a)		Intrinsic value represents the difference between the current market value of Allegheny’s stock and the exercise price of the option.

Cash received by Allegheny from option exercises totaled $4.6 million in the first quarter of 2007. Allegheny issued new shares to satisfy these stock option exercises.

As of March 31, 2007, there was approximately $15.0 million of unrecognized compensation cost related to non-vested outstanding stock options, which is expected to be recognized over a weighted-average period of approximately 1.8 years.

Stock Units

Stock unit activity was as follows:


				Weighted-Average		Aggregate
	Number of			Grant Date		Intrinsic Value
	Stock Units			Fair Value		(in millions)
Outstanding at December 31, 2006		1,045,966		$	15.29
Units converted into 68,477 common shares		(107,220	)	$	15.30

Outstanding at March 31, 2007		938,746		$	15.29	$	46.1

There were no stock units convertible at March 31, 2007.

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

As of March 31, 2007, there was $2.2 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 seven months.

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

Non-employee director stock plan share activity was as follows:


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

Shares earned but not issued at March 31, 2007		60,493

NOTE 7: DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Allegheny has designated certain contracts as cash flow hedges of forecasted sales of electricity. Changes in the fair value of these contracts upon such designation and thereafter are reflected in “Accumulated other comprehensive loss” until the hedged item is realized. These contracts expire at various dates through December 2007. The pre-tax accumulated other comprehensive income (loss) for the contracts was $(4.3) million at March 31, 2007 and $1.3 million at December 31, 2006. 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 changes in market prices. The accumulated other comprehensive loss balance is expected to be completely reclassified as a reduction to earnings over the next nine months. The ineffective portion of the cash flow hedges of $0.2 million and $(0.6) million is reflected in earnings for the three months ended March 31, 2007 and 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 $25.6 million and $22.5 million at March 31, 2007 and December 31, 2006, respectively. Operating revenues included net unrealized gains related to trading activities of $2.4 million and $13.0 million for the three months ended March 31, 2007 and 2006 and net realized gains (losses) related to cash flow hedges and trading activities of $(3.9) million and $3.6 million for the three months ended March 31, 2007 and 2006, respectively.

NOTE 8: DISCONTINUED OPERATIONS

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


	Three Months
	Ended
(In millions)	March 31, 2006
Operating revenues	$	—
Operating expenses		(0.4	)
Interest expense		(0.9	)

Loss before income taxes		(1.3	)
Income tax benefit		0.5

Loss from discontinued operations, net of tax	$	(0.8	)

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

NOTE 9: BUSINESS SEGMENTS

Allegheny manages and evaluates its operations in two business segments, the Delivery and Services segment and the Generation and Marketing segment. Monongahela operates in both segments. All other Allegheny subsidiaries operate in only one segment. The Delivery and Services segment includes the operations of Potomac Edison, West Penn, Allegheny Ventures, TrAIL Company and Monongahela’s electric T&D business. The Generation and Marketing segment includes the operations of AE Supply, AGC and Monongahela’s West Virginia generating assets.

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.


	Three months ended March 31, 2007									Three months ended March 31, 2006
	Delivery		Generation							Delivery		Generation
	and		and							and		and
(In millions)	Services		Marketing		Eliminations			Total		Services		Marketing			Eliminations			Total
External operating revenues	$	754.8	$	92.8	$	—		$	847.6	$	700.8	$	144.8		$	—		$	845.6
Internal operating revenues		3.1		431.7		(434.8	)		—		1.8		362.3			(364.1	)		—

Total operating revenues	$	757.9	$	524.5	$	(434.8	)	$	847.6	$	702.6	$	507.1		$	(364.1	)	$	845.6

Depreciation and amortization	$	40.2	$	31.8	$	—		$	72.0	$	37.7	$	30.1		$	—		$	67.8

Operating income	$	96.6	$	138.6	$	—		$	235.2	$	92.1	$	155.7		$	—		$	247.8

Interest expense	$	18.4	$	42.0	$	(1.2	)	$	59.2	$	19.7	$	48.1		$	(0.4	)	$	67.4

Income tax expense from continuing operations	$	35.5	$	35.9	$	—		$	71.4	$	30.1	$	42.3		$	—		$	72.4

Income from continuing operations	$	45.4	$	64.3	$	—		$	109.7	$	46.4	$	67.8		$	—		$	114.2

Loss from discontinued operations, net of tax	$	—	$	—	$	—		$	—	$	—	$	(0.8	)	$	—		$	(0.8	)

Net income	$	45.4	$	64.3	$	—		$	109.7	$	46.4	$	67.0		$	—		$	113.4

NOTE 10: GOODWILL AND INTANGIBLE ASSETS

There were no additions to, or disposals of, goodwill during the three months ended March 31, 2007.

Additional intangible assets included in “Property, plant and equipment, net” on the Consolidated Balance Sheets were as follows:


	March 31, 2007				December 31, 2006
	Gross				Gross
	Carrying		Accumulated		Carrying		Accumulated
(In millions)	Amount		Amortization		Amount		Amortization
Land easements, amortized	$	98.5	$	28.7	$	97.9	$	28.4
Land easements, unamortized		30.7		—		30.7		—
Software		85.3		33.6		47.0		31.1

Total	$	214.5	$	62.3	$	175.6	$	59.5

Amortization expense for intangible assets was $4.1 million and $3.6 million for the three months ended March 31, 2007 and 2006, respectively.

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

Amortization expense for intangible assets at March 31, 2007 is estimated to be as follows:


(In millions)	2007		2008		2009		2010		2011
Annual amortization expense	$	12.9	$	9.8	$	9.2	$	8.2	$	7.3

NOTE 11: COMPREHENSIVE INCOME

Comprehensive income consisted of the following:


	Three Months Ended
	March 31,
(In millions)	2007			2006
Net income	$	109.7		$	113.4
Other comprehensive income (loss), net of tax:
Unrealized gains (losses) on cash flow hedges for the period, net of tax of $2.1 and $11.2		(3.3	)		17.7
Pension and other postretirement employee benefit amortization, net of tax of $1.1 and $0		1.6			—

Comprehensive income, net of income taxes	$	108.0		$	131.1

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


	March 31,			December 31,
(In millions)	2007			2006
Accumulated other comprehensive income (loss) on cash flow hedges, net of tax	$	(3.1	)	$	0.2
Net unrecognized pension and other postretirement benefit costs, net of tax		(105.8	)		(107.4	)

Total	$	(108.9	)	$	(107.2	)

NOTE 12: PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

Substantially all of Allegheny’s employees, including officers, are employed by AESC and are covered by a noncontributory, defined benefit pension plan. Allegheny also maintains a Supplemental Executive Retirement Plan (“SERP”) for executive officers and other senior executives. Allegheny also provides subsidies for medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the plans, are based upon an age and years-of-service vesting schedule, other plan provisions and certain collective bargaining arrangements. Subsidized medical coverage is not provided in retirement to employees hired on or after January 1, 1993, with the exception of certain union employees who were hired or became members before May 1, 2006. The provisions of the postretirement health care plans and certain collective bargaining arrangements limit Allegheny’s costs for eligible retirees and dependents.

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

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


							Postretirement Benefits Other
	Pension Benefits						Than Pensions
	Three Months Ended						Three Months Ended
	March 31,						March 31,
(In millions)	2007			2006			2007			2006
Components of net periodic cost:
Service cost	$	5.3		$	5.4		$	1.1		$	1.3
Interest cost		16.2			15.4			4.3			4.2
Expected return on plan assets		(18.3	)		(17.4	)		(1.7	)		(1.7	)
Amortization of unrecognized transition obligation		0.1			0.1			1.4			1.4
Amortization of prior service cost		0.8			0.9			—			—
Recognized actuarial loss		2.7			3.1			0.6			0.9

Net periodic cost	$	6.8		$	7.5		$	5.7		$	6.1

Allocation of net periodic cost:
Monongahela	$	2.0		$	2.0		$	1.7		$	1.7
AE Supply		1.8			2.2			1.1			1.3
West Penn		1.7			1.8			1.6			1.7
Potomac Edison		1.3			1.4			1.3			1.3
AE		—			0.1			—			0.1

Net periodic cost	$	6.8		$	7.5		$	5.7		$	6.1

For the three months ended March 31, 2007 and 2006, Allegheny allocated $3.1 million and $3.2 million, respectively, of the above net periodic cost amounts to “Construction work in progress,” a component of “Property, plant and equipment, net.”

Allegheny contributed $35.6 million to its pension plans during the three months ended March 31, 2007, including a contribution of $0.1 million to the SERP. Allegheny also contributed $3.8 million to fund its postretirement benefits plans other than pension plans during the three months ended March 31, 2007. Allegheny estimates that its total contributions to the pension plans during 2007 will approximate $50 million. Allegheny currently anticipates contributing a total amount in 2007 ranging from $15.0 million to $18.0 million to fund its postretirement benefits plans other than pension plans.

Allegheny made matching cash contributions to the Employee Stock Ownership and Savings Plan (the “ESOSP”) in the amount of $2.3 million for the three months ended March 31, 2007.

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

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

NOTE 13: INCOME (LOSS) PER SHARE

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


	Three Months Ended
	March 31,
(In millions, except share amounts)	2007		2006
Basic Income (Loss) per Share:
Numerator:
Income from continuing operations, net of tax	$	109.7	$	114.2
Loss from discontinued operations, net of tax		—		(0.8	)

Net income	$	109.7	$	113.4

Denominator:
Weighted average common shares outstanding		165,494,332		163,080,312

Basic Income per Share:
Income from continuing operations, net of tax	$	0.66	$	0.70
Loss from discontinued operations, net of tax		—		—

Net income	$	0.66	$	0.70

Diluted Income (Loss) per Share:
Numerator:
Income from continuing operations, net of tax	$	109.7	$	114.2
Loss from discontinued operations, net of tax		—		(0.8	)

Net income	$	109.7	$	113.4

Denominator:
Weighted average common shares outstanding		165,494,332		163,080,312
Effect of dilutive securities:
Stock options		2,721,411		2,565,351
Stock units		885,176		2,778,116
Non-employee stock awards		54,559		33,678
Performance shares		25,497		46,180

Total shares		169,180,975		168,503,637

Diluted Income (Loss) per Share:
Income from continuing operations, net of tax	$	0.65	$	0.68
Loss from discontinued operations, net of tax		—		(0.01	)

Net income	$	0.65	$	0.67

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

NOTE 14: ADVERSE POWER PURCHASE COMMITMENT LIABILITY

As of March 31, 2007, Allegheny’s reserve for adverse power purchase commitments was $179.9 million, including a current liability of $17.2 million. Allegheny’s liability for adverse power purchase commitments decreased as follows:


	Three Months Ended
	March 31,
(In millions)	2007		2006
Amortization of liability for adverse power purchase commitments	$	4.3	$	4.3

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

NOTE 15: REGULATORY ASSETS AND LIABILITIES

Certain of Allegheny’s regulated utility operations are subject to the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation (“SFAS No. 71”). Regulatory assets represent probable future revenues associated with costs that are expected to be recovered in the future from customers through the rate-making process. Regulatory liabilities generally represent probable future reductions in revenues associated with amounts that are to be credited or refunded to customers through the rate-making process. Regulatory assets and regulatory liabilities reflected in the Consolidated Balance Sheets at March 31, 2007 and December 31, 2006 relate to:


	March 31,		December 31,
(In millions)	2007		2006
Regulatory assets, including current portion:
Income taxes	$	298.3	$	300.4
Pension and other postretirement benefits		175.2		178.2
Pennsylvania stranded cost recovery		45.6		55.6
Pennsylvania Competitive Transition Charge (“CTC”) reconciliation		110.0		107.4
Unamortized loss on reacquired debt		38.5		39.6
Other		30.9		32.0

Subtotal		698.5		713.2

Regulatory liabilities, including current portion:
Net asset removal costs		399.5		421.4
Income taxes		38.9		38.9
Other		5.9		4.5

Subtotal		444.3		464.8

Net regulatory assets	$	254.2	$	248.4

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


	March 31,			December 31,
(In millions)	2007			2006
Property, plant and equipment	$	4,256.0		$	4,338.7
Amounts under construction included above	$	194.7		$	136.6
Accumulated depreciation	$	(1,973.4	)	$	(2,054.6	)

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

NOTE 16: ASSET RETIREMENT OBLIGATIONS (“AROs”)

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

The following is an analysis of the changes in the ARO liability for the three months ended March 31, 2007:


(In millions)	ARO Liability
Balance at December 31, 2006	$	54.8
Accretion of the liability		1.5

Balance at March 31, 2007	$	56.3

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

NOTE 17: 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
	March 31,
(In millions)	2007		2006
Interest and dividend income	$	3.5	$	5.5
Tax reimbursement on contributions in aid of construction		1.1		1.5
Premium services		0.4		1.4
Other		0.9		(0.7	)

Total	$	5.9	$	7.7

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

NOTE 18: GUARANTEES AND LETTERS OF CREDIT

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


	March 31, 2007				December 31, 2006
	Amounts		Total		Amounts		Total
	Recorded on		Guarantees		Recorded on		Guarantees
	the Consolidated		and Letters		the Consolidated		and Letters
(In millions)	Balance Sheet		of Credit		Balance Sheet		of Credit
Guarantees:
Loans and other financing-related matters	$	—	$	8.2	$	—	$	8.4
Lease agreement		—		4.8		—		4.7
Purchase, sale, exchange or transportation of wholesale natural gas, electric power and related services		—		20.0		—		20.4
Other		0.2		0.2		0.2		0.2

Total Guarantees	$	0.2	$	33.2	$	0.2	$	33.7

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

Total Letters of Credit		—		134.3		—		133.9

Total Guarantees and Letters of Credit	$	0.2	$	167.5	$	0.2	$	167.6


(a)		The March 31, 2007 and December 31, 2006 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 and a letter of credit for $6.8 million issued due to a contractual obligation of Allegheny Ventures that expires in July 2007.

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

NOTE 19: VARIABLE INTEREST ENTITIES (“VIE”)

FASB Interpretation No. 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.

Potomac Edison and West Penn had power purchases from these two IPPs in the amount of $26.2 million and $12.7 million, respectively, for the three months ended March 31, 2007 and $18.5 million and $12.5 million, respectively, for the three months ended March 31, 2006.

Potomac Edison recovers the full amount, and West Penn recovers a portion, of the cost of the applicable power

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

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 20: COMMITMENTS AND CONTINGENCIES

Environmental Matters and Litigation

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

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

	•		developing an accurate CO₂ emissions inventory;

	•		improving the efficiency of its coal-burning fleet;

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

	•		following developing technologies for carbon sequestration;

	•		participating in carbon dioxide sequestration efforts (e.g. reforestation projects) both domestically and abroad; and analyzing options for future energy investment (e.g. renewables, clean-coal, etc.).

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

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

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

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

The Clean Air Act mandates annual reductions of SO₂ and created a SO₂ emission allowance trading program. AE Supply and Monongahela comply with current SO₂ emission standards through a system-wide plan combining the use of emission controls, low sulfur fuel and emission allowances. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities, as well as the implementation of environmental controls. Allegheny continues to evaluate options for compliance, and current plans include the installation of Scrubbers at its Hatfield’s Ferry and Fort Martin generating facilities by 2009 and the elimination of a scrubber bypass at its Pleasants generation facility by 2008. In July 2006, AE Supply entered into construction contracts with The Babcock & Wilcox Company (“B&W”) and Washington Group International (“WGI”) in connection with its plans to install Scrubbers at its Hatfield’s Ferry generation facility. Monongahela has also entered into construction contracts with B&W and WGI in connection with its plans to install Scrubbers at Fort Martin.

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

AE Supply and Monongahela have completed installation of NOx controls to meet the Pennsylvania, Maryland and West Virginia SIP calls. The NOx compliance plan functions on a system-wide basis, similar to the SO₂ compliance plan. AE Supply and Monongahela also have the option, in some cases, to purchase alternate fuels or NOx allowances, if needed, to supplement their compliance strategies. Allegheny estimates that its emission control activities, in concert with its inventory of banked allowances and future transactions, will facilitate its compliance with NOx limits established by the SIP 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.

On March 15, 2005, the United States Environmental Protection Agency (the “EPA”) issued the Clean Air Mercury Rule (“CAMR”) establishing a cap and trade system designed to reduce mercury emissions from coal-fired power plants in two phases during 2010 and 2018. This rule will be implemented through state implementation plans currently under development. The rule has been challenged by several parties. Allegheny is currently assessing CAMR and developing its strategy for compliance, but it will include the emission reduction projects discussed above for the Hatfield’s Ferry, Fort Martin and Pleasants generating facilities, as they will have a co-benefit effect and also remove mercury from plant emissions. The Pennsylvania Department of Environmental Protection (the “PA DEP”) proposed a more aggressive mercury control rule on June 24, 2006, which was finalized on February 17, 2007. Allegheny is assessing the proposed rule to determine what, if any, effect it would have on Allegheny’s Pennsylvania operations. Pennsylvania’s proposed shortened compliance schedule and more aggressive emissions limits might result in the installation of additional emission controls at any of Allegheny’s three Pennsylvania coal-fired facilities or in a change in fuel specifications. Controls might include additional Scrubbers, activated carbon injection, selective catalytic reduction or other, currently emerging technologies.

Additionally, Maryland passed the Healthy Air Act in early 2006. This legislation imposes state-wide emission caps on SO₂ and NOx, requires 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 emission. 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. In response to Allegheny’s request and after conducting a reliability evaluation, PJM, by letter dated November 8, 2006, determined that R. Paul Smith is vital to the regional reliability of power flow. Pursuant to the legislation, the Maryland Department of the Environment (the “MDE”) will now create specific regulations for R. Paul Smith in 2007 to comply with both the Healthy Air Act and the federal CAIR. Allegheny is assessing the new legislation and upcoming implementing regulations to determine the full extent of the impacts on Allegheny’s Maryland operations and is working with the MDE on the R. Paul Smith-specific regulations.

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

requested information under Section 114 of the Clean Air Act to determine compliance with the Clean Air Act and related requirements, including potential application of the NSR standards of the Clean Air Act, which can require the installation of additional air pollution control equipment when the major modification of an existing facility results in an increase in emissions. AE has provided responsive information to this and a subsequent request.

If NSR requirements are imposed on Allegheny’s generation facilities, in addition to the possible imposition of fines, compliance would entail significant capital investments in pollution control technology.

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

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

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

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

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

Canadian Toxic-Tort Class Action:On June 30, 2005, AE Supply, Monongahela and AGC, along with 18 other companies with coal-fired generation facilities, were named as defendants in a toxic-tort, purported class action lawsuit filed in the Ontario Superior Court of Justice. On behalf of a purported class comprised of all persons residing in Ontario within the past six years (and/or their family members or heirs), the named plaintiffs allege that the defendants negligently failed to prevent their generation facilities from emitting air pollutants in such a manner as to cause death and multiple adverse health effects, as well as economic damages, to the plaintiff class. The plaintiffs seek damages in the approximate amount of Canadian $49.1 billion (approximately US $41.6 billion, assuming an exchange rate of 1.18 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 $3.5 billion and US $850 million, respectively, assuming an exchange rate of 1.18 Canadian

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

dollars per US dollar) along with such other relief as the court deems just. Allegheny has not yet been served with this lawsuit, and the time for service of the original lawsuit has expired. Allegheny intends to vigorously defend against this action but cannot predict its outcome.

Global Warming Class Action:On April 9, 2006, AE, along with numerous other companies with coal-fired generation facilities and companies in other industries, was named as a defendant in a class action lawsuit in the United States District Court for the Southern District of Mississippi. On behalf of a purported class of residents and property owners in Mississippi who were harmed by hurricane Katrina, the named plaintiffs allege that the emission of greenhouse gases by the defendants contributed to global warming, thereby causing Hurricane Katrina and plaintiffs’ damages. The plaintiffs seek unspecified damages. On December 6, 2006, AE filed a motion to dismiss plaintiffs’ complaint on jurisdictional grounds and joined a motion filed by other defendants to dismiss the complaint for failure to state a claim. These motions remain pending. AE intends to vigorously defend against this action but cannot predict its outcome.

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

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

Allegheny does not believe that the existence or pendency of either the asbestos suits or the actions involving its insurance will have a material impact on its consolidated financial position, results of operations or cash flows. Allegheny believes that it has established adequate reserves, net of insurance receivables and recoveries, to cover existing and future asbestos claims. As of March 31, 2007, Allegheny had 828 open cases remaining in West Virginia and four open cases remaining in Pennsylvania.

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

Other Litigation

Nevada Power Contracts.On December 7, 2001, Nevada Power Company (“NPC”) filed a complaint with the 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

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

December 17, 2003, AE Supply filed a motion to intervene in this proceeding in the Ninth Circuit. On December 19, 2006, the Ninth Circuit issued an opinion remanding the case to the FERC to determine, in accordance with the guidance set forth in the Ninth Circuit’s opinion, whether FERC utilized the appropriate standard of review in deciding various claims, including NPC’s complaint.

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. On July 20, 2006, the Nevada Supreme Court reversed the Nevada PUC’s disallowance of the $180 million in deferred energy expenses, which formed the basis of the plaintiffs’ claims. An announcement was made on March 23, 2007 that the Nevada PUC has approved two settlements relating to the requested disallowance.

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

Claim by California Parties.On October 5, 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the California Department of Water Resources (“CDWR”) during 2001. The settlement demand to AE Supply in the amount of approximately $190 million was made in the context of mediation efforts by FERC and the U.S. Court of Appeals for the Ninth Circuit to resolve all outstanding claims of alleged price manipulation in the California energy markets during 2000 and 2001. No complaint has been filed against Allegheny. Allegheny believes that all issues in connection with AE Supply sales to CDWR were resolved by a settlement in 2003 and otherwise believes that the California parties’ demand is without merit. Allegheny intends to vigorously defend against this claim but cannot predict its outcome.

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

On September 24, 2002, certain Merrill Lynch entities filed a complaint against AE in the U.S. District Court for the Southern District of New York, alleging that AE breached the asset purchase agreement by failing to repurchase the equity interest in AE Supply from Merrill Lynch and seeking damages in excess of $125 million. On September 25, 2002, AE and AE Supply filed an action against Merrill Lynch in New York state court alleging fraudulent inducement and breaches of representations and warranties in the purchase agreement.

On May 29, 2003, the U.S. District Court for the Southern District of New York 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,

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

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.

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, for which it had granted Merrill Lynch summary judgment, and with respect to AE and AE Supply’s counterclaims for fraudulent inducement and breach of contract. Following the trial, on July 18, 2005, the District Court entered an order: (a) ruling against AE and AE Supply on their fraudulent inducement and breach of contract claims; (b) requiring AE to pay $115 million plus interest to Merrill Lynch; and (c) requiring Merrill Lynch to return its equity interest in AE Supply to AE. On August 26, 2005, the Court entered its final judgment in accordance with its July 18, 2005 ruling. On September 22, 2005, AE and AE Supply filed a notice of appeal of the District Court’s judgment to the U.S. Court of Appeals for the Second Circuit, which heard oral argument on October 30, 2006.Although AE will not be required to pay Merrill Lynch the amount of the judgment while the appeal is pending, AE has posted a letter of credit to secure the judgment.

As a result of the District Court’s ruling, AE recorded a charge during the first quarter of 2005 in the amount of $38.5 million, representing interest from March 16, 2001 through March 31, 2005. AE is continuing to accrue interest expense thereafter.

Putative Benefit Plan Class 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. Allegheny has entered into an agreement to settle the consolidated ERISA class actions and on February 13, 2007, the District Court entered an order preliminarily approving the settlement. The proposed settlement remains subject to court approval, following notice to class members. Under the proposed settlement, the consolidated ERISA class actions will be dismissed with prejudice in exchange for a cash payment of $4 million, of which approximately $3.9 million will be made by Allegheny Energy’s insurance carrier.

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 and sold it to the Tennessee Valley Authority on December 15, 2006. 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. In April 2007, Allegheny Energy Supply Generation Facility, LLC reached a global settlement with all of the plaintiffs, and the case was dismissed with prejudice.

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 third parties to supply coal to Allegheny from a mine owned by Harrison Fuel. Plaintiffs seek damages of approximately $13 million. On January 5, 2007, the Court entered an order setting this case for trial on May 14, 2007. A motion to have the matter dismissed before trial is scheduled for argument on May 7, 2007. Allegheny intends to vigorously defend against this action but cannot predict its outcome.

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

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

NOTE 21: SUBSEQUENT EVENT

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


	Three Months Ended March 31,
(In thousands)	2007			2006
Operating revenues	$	200,886		$	197,195
Operating expenses:
Fuel		60,447			45,138
Purchased power and transmission		38,734			41,136
Deferred energy costs, net		(333	)		—
Operations and maintenance		54,809			40,414
Depreciation and amortization		17,811			16,366
Taxes other than income taxes		12,451			12,270

Total operating expenses		183,919			155,324

Operating income		16,967			41,871

Other income and expenses, net (Note 10)		3,901			3,658

Interest expense		8,529			10,728

Income before income taxes		12,339			34,801

Income tax expense		5,377			13,071

Net income	$	6,962		$	21,730

See accompanying Notes to Consolidated Financial Statements.

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


	Three Months Ended March 31,
(In thousands)	2007			2006
Cash Flows From Operating Activities:
Net income	$	6,962		$	21,730

Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		17,811			16,366
Amortization of power sale liability related to Ohio sale		(9,100	)		(10,700	)
Amortization of liability for adverse power purchase commitment		1,699			—
Deferred income taxes and investment tax credit, net		1,237			15,814
Other, net		(132	)		1,119

Changes in certain assets and liabilities:
Accounts receivable, net		(1,050	)		15,628
Materials, supplies and fuel		(6,585	)		967
Prepaid taxes		480			3,298
Collateral deposits		(24,400	)		8,045
Prepayments		112			245
Other current assets		(261	)		122
Accounts payable		26,968			(15,254	)
Accounts payable to affiliates, net		(19,509	)		(16,573	)
Accrued taxes		(28,306	)		(7,144	)
Accrued interest		(457	)		5,364
Other current liabilities		(1,376	)		(5,517	)
Other assets		230			234
Other liabilities		(190	)		55

Net cash provided by (used in) operating activities		(35,867	)		33,799

Cash Flows From Investing Activities:
Capital expenditures		(39,014	)		(18,736	)
Notes receivable from affiliates		27,337			(45,381	)

Net cash used in investing activities		(11,677	)		(64,117	)

Cash Flows From Financing Activities:
Notes payable to affiliates		24,352			—
Deferred financing costs		—			(118	)
Repayment of long-term debt		(851	)		—
Asset Swap		1,052			—
Intercompany tax sharing agreement benefit		3,394			—
Cash dividends paid on capital stock:
Preferred stock		(293	)		(293	)
Common stock		—			(10,015	)

Net cash provided by (used in) financing activities		27,654			(10,426	)

Net decrease in cash and cash equivalents		(19,890	)		(40,744	)
Cash and cash equivalents at beginning of period		22,283			136,491

Cash and cash equivalents at end of period	$	2,393		$	95,747

Supplemental Cash Flow Information:
Cash paid for interest (net of amount capitalized)	$	7,937		$	4,517

See accompanying Notes to Consolidated Financial Statements.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(unaudited)


	March 31,			December 31,
(In thousands)	2007			2006
ASSETS
Current Assets:
Cash and cash equivalents	$	2,393		$	22,283
Accounts receivable:
Customer		47,868			38,007
Unbilled utility revenue		29,174			33,952
Wholesale and other		8,077			12,341
Allowance for uncollectible accounts		(1,814	)		(2,095	)
Note receivable from affiliate		—			27,337
Materials and supplies		19,334			15,695
Fuel		24,453			17,557
Prepaid taxes		19,634			20,114
Deferred income taxes		5,325			—
Collateral deposits		24,128			—
Regulatory assets		6,750			6,417
Other		16,822			8,638

Total current assets		202,144			200,246

Property, Plant and Equipment, Net:
Generation		1,101,522			967,486
Transmission		294,014			283,497
Distribution		976,693			968,377
Other		74,114			74,762
Accumulated depreciation		(1,070,633	)		(936,098	)

Subtotal		1,375,710			1,358,024
Construction work in progress		54,126			38,114

Total property, plant and equipment, net		1,429,836			1,396,138

Investments and Other Assets:
Investment in AGC		70,797			46,765
Other		2,715			2,437

Total investments and other assets		73,512			49,202

Deferred Charges:
Regulatory assets		86,381			88,940
Other		9,566			9,791

Total deferred charges		95,947			98,731

Total Assets	$	1,801,439		$	1,744,317

See accompanying Notes to Consolidated Financial Statements.

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


	March 31,		December 31,
(In thousands, except share data)	2007		2006
LIABILITIES AND STOCKHOLDER’S EQUITY

Current Liabilities:
Long-term debt due within one year (Note 5)	$	14,500	$	15,500
Accounts payable		61,925		35,844
Accounts payable to affiliates, net		43,344		62,853
Accrued taxes		22,883		37,836
Accrued interest		7,236		7,693
Ohio power commitment		1,400		10,500
Note payable to affiliate		24,352		—
Other		20,619		19,558

Total current liabilities		196,259		189,784

Long-term Debt (Note 5)		519,186		519,145

Deferred Credits and Other Liabilities:
Non-current affiliated income taxes payable		46,046		45,671
Deferred income taxes		221,237		213,987
Obligations under capital leases		7,968		7,353
Regulatory liabilities		214,299		239,120
Other		35,206		32,598

Total deferred credits and other liabilities		524,756		538,729

Commitments and Contingencies (Note 11)

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 at March 31, 2007 and December 31, 2006		294,550		294,550
Other paid-in capital		99,132		41,468
Retained earnings		143,553		136,639
Accumulated other comprehensive income		3		2

Total common stockholder’s equity		537,238		472,659

Total Liabilities and Stockholder’s Equity	$	1,801,439	$	1,744,317

See accompanying Notes to Consolidated Financial Statements.

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


										Accumulated		Total
					Other					other		common
	Shares		Common		paid-in		Retained			comprehensive		stockholder’s
(In thousands, except shares)	outstanding		stock		capital		earnings			income (loss)		equity
Balance at December 31, 2006		5,891,000	$	294,550	$	41,468	$	136,639		$	2	$	472,659
Net income		—		—		—		6,962			—		6,962
Adoption of FIN 48		—		—		—		245			—		245
Asset Swap		—		—		53,504		—			—		53,504
Intercompany tax sharing agreement benefit		—		—		3,950		—			—		3,950
Pollution control bond interest paid by AE Supply		—		—		60		—			—		60
Pollution control bond retirement		—		—		150		—			—		150
Dividends declared on preferred stock		—		—		—		(293	)		—		(293	)
Other comprehensive income		—		—		—		—			1		1

Balance at March 31, 2007		5,891,000	$	294,550	$	99,132	$	143,553		$	3	$	537,238

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		38

2	Recent Accounting Pronouncements		39

3	Asset Swap		40

4	Income Taxes		41

5	Debt		42

6	Business Segments		43

7	Pension Benefits and Postretirement Benefits Other Than Pensions		43

8	Asset Retirement Obligations (“AROs”)		43

9	Regulatory Assets and Liabilities		44

10	Other Income and Expenses, Net		44

11	Commitments and Contingencies		44

12	Subsequent Event		48

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

NOTE 1: BASIS OF PRESENTATION

Monongahela Power Company, together with its consolidated subsidiaries (“Monongahela”), is a wholly-owned subsidiary of Allegheny Energy, Inc. (“AE,” and together with its consolidated subsidiaries, “Allegheny”). Monongahela has two principal business segments. The Generation and Marketing segment includes Monongahela’s power generation operations. The Delivery and Services segment includes Monongahela’s electric T&D operations.

Monongahela owned approximately 41% and 23% of Allegheny Generating Company (“AGC”) at March 31, 2007 and December 31, 2006, respectively, and accounts for its investment in AGC using the equity method of accounting.

Monongahela records its proportional share of operating costs, assets and liabilities of other jointly owned generating facilities in the corresponding line items in these Consolidated Financial Statements.

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 and who provide services to Monongahela.

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 and AGC for the year ended December 31, 2006 (the “2006 Annual Report on Form 10-K”).

These unaudited interim financial statements have been prepared by Monongahela 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 (“GAAP”) have been condensed or omitted. These financial statements include all adjustments, consisting of normal recurring adjustments, considered necessary by management to fairly state the results of operations, financial position and cash flows. The results reported in these consolidated interim financial statements are not necessarily indicative of the results that may be expected for the entire year. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.

During 2006, Monongahela changed its classification of fuel handling and residual disposal costs within its Consolidated Statements of Operations from “Operations and maintenance” expenses to “Fuel” expenses to improve comparability with other energy and utility companies and facilitate a better understanding of operating costs. Accordingly, Monongahela reclassified such costs previously reported in the amount of $1.1 million for the three months ended March 31, 2006 to conform to the financial statement presentation for the current period.

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

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

Federal and State Income Taxes

AE and its subsidiaries, including Monongahela, file a consolidated federal income tax return. The consolidated income tax liability is allocated among AE and its subsidiaries generally in proportion to the taxable income of each participant, except that no subsidiary pays tax in excess of its separate return income tax liability. This corporate allocation may cause fluctuations and variances in the effective quarterly and year-to-date tax rates compared to statutory rates, depending on the level of pre-tax income. Monongahela’s consolidated income tax expense differs from an amount calculated at the federal statutory income tax rate of 35%, principally due to consolidated tax benefits, state income taxes, tax credits and certain non-deductible expenses.

NOTE 2: RECENT ACCOUNTING PRONOUNCEMENTS

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

In June 2006, the Emerging Issues Task Force (“EITF”) reached a consensus on 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (“EITF 06-3”). EITF 06-3 provides guidance on disclosing the accounting policy for the income statement presentation of any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer on either a gross (included in revenues and costs) or a net (excluded from revenues and costs) basis. In addition, EITF 06-3 requires disclosure of any such taxes that are reported on a gross basis, as well as the amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented. EITF 06-3 became effective January 1, 2007. It is Monongahela’s policy to record taxes collected from customers that are assessed on those customers, on a net basis. That is, in instances in which Monongahela acts as a collection agent for a taxing authority by collecting taxes which are the responsibility of the customer, Monongahela records the amount collected as a liability and relieves such liability upon remittance to the taxing authority without impacting revenues or expenses. Therefore, the January 1, 2007 implementation of EITF 06-3 did not have a material impact on Monongahela’s financial statements.

In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109 (“FIN 48”). On May 2, 2007, the FASB issued FASB Interpretation No. 48-1, Definition of Settlement in FASB Interpretation No. 48 (“FIN 48-1”), which provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. Monongahela adopted the provisions of FIN 48 and FIN 48-1 as of January 1, 2007. See Note 4, “Income Taxes,” for additional information related to FIN 48 and its impact on Monongahela’s consolidated financial position.

In September 2006, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 157, Fair Value Measurements (“SFAS No. 157”). SFAS No. 157 defines fair value and establishes a framework for measuring fair value when fair value is required for recognition or disclosure purposes under GAAP. The standard also expands disclosure about fair value measurement but does not require any new fair value measurements. SFAS No. 157 is effective for Monongahela January 1, 2008. Management has not completed the process of determining the effect of SFAS No. 157 on Monongahela’s financial statements, however, at this time the adoption of SFAS 157 is not expected to have a material impact on Monongahela’s consolidated results of operations or financial position.

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

items at fair value that are not currently required to be measured at fair value. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for Monongahela January 1, 2008. Management has not completed the process of determining the effect of SFAS No. 159 on Monongahela’s financial statements, however, at this time the adoption of SFAS No. 159 is not expected to have a material impact on Monongahela’s consolidated results of operations or financial position.

NOTE 3: ASSET SWAP

On January 1, 2007, AE Supply and Monongahela completed an intercompany exchange of assets (the “Asset Swap”) that realigned generation ownership and contractual arrangements within the Allegheny system. After the Asset Swap, Monongahela owns 100% of the Fort Martin generation facility in West Virginia (“Fort Martin”), allowing Allegheny to finance the construction of flue-gas desulfurization equipment (“Scrubbers”) at Fort Martin through the securitization of an environmental control charge that Monongahela and Potomac Edison impose on their retail customers in West Virginia.

The Asset Swap was recorded on January 1, 2007 at the net book value of the assets, liabilities and interests transferred, with certain adjustments, and resulted in an increase in stockholder’s equity by Monongahela of approximately $54 million. The Asset Swap was substantially a non-cash transaction and, as such, affected the recognized property, plant and equipment and other related assets and liabilities as well as Other Paid-In Capital. The Asset Swap resulted in certain minor cash transactions that are reflected in the Statements of Cash Flows. The impact of the Asset Swap’s non-cash transactions are not reflected in the Statements of Cash Flows.

The following table shows Monongahela’s utility plant investment and accumulated depreciation for generating facilities jointly owned with AE Supply:


	March 31, 2007						December 31, 2006
Generation facility	Ownership		Plant		Accumulated		Ownership		Plant		Accumulated
(Dollars in millions)	%		Investment		Depreciation		%		Investment		Depreciation
Albright		100.0	$	119.2	$	90.7		57.5	$	68.7	$	46.5
Fort Martin		100.0	$	460.9	$	269.1		19.1	$	71.0	$	49.1
Harrison		20.5	$	286.8	$	165.2		21.3	$	297.0	$	168.1
Hatfield’s Ferry		—	$	—	$	—		23.4	$	154.5	$	60.3
Pleasants		7.7	$	90.2	$	51.3		21.3	$	249.4	$	140.0
Rivesville		100.0	$	57.5	$	44.1		85.1	$	48.9	$	36.9
Willow Island		100.0	$	106.4	$	71.7		85.1	$	90.6	$	59.6

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

Through its equity interest in AGC, Monongahela owns an interest in AGC’s jointly owned electric utility plant. Monongahela’s ownership interest in AGC’s jointly owned electric utility plant was approximately 41% and approximately 23% at March 31, 2007 and December 31, 2006, respectively. The following table shows AGC’s utility plant investment and accumulated depreciation in the Bath County generation facility:


	March 31, 2007						December 31, 2006
Generation facility	Ownership		Plant		Accumulated		Ownership		Plant		Accumulated
(Dollars in millions)	%		Investment		Depreciation		%		Investment		Depreciation
Bath County		40	$	840.4	$	322.1		40	$	835.6	$	318.1

NOTE 4: INCOME TAXES

Allegheny allocates federal income tax expense (benefit) among its subsidiaries pursuant to its consolidated tax sharing agreement. This corporate allocation may cause 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, effects of utility rate making and certain non-deductible expenses.

The Company adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation, the Company recognized a $0.2 million addition to its January 1, 2007 balance of retained earnings.

Unrecognized tax benefits were approximately $17.6 million and $17.7 million at January 1, 2007 and March 31, 2007, respectively. If recognized, the portion of these amounts that would reduce the Company’s effective tax rate were $0.3 million and $0.4 million at January 1, 2007 and March 31, 2007, respectively.

The unrecognized tax benefit balance also included approximately $17.3 million of tax positions at January 1, 2007 and March 31, 2007 for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would impact the timing of cash payments to the taxing authorities.

Monongahela records interest and penalties associated with uncertain tax positions as a component of income tax expense. Monongahela had accrued interest, net of tax, related to uncertain tax positions of $2.2 million at January 1, 2007 and March 31, 2007.

The major jurisdictions in which Monongahela is subject to income tax are U.S. Federal, Pennsylvania, West Virginia and Virginia. Monongahela is part of the consolidated federal income tax returns of its parent company Allegheny Energy, Inc. Those returns are currently under audit by the Internal Revenue Service (“IRS”) for the tax years 1998 through 2003. The 2004 and 2005 federal returns have been filed and are still subject to review. Monongahela is also subject to tax in Pennsylvania. Returns filed with the Pennsylvania Department of Revenue for the tax years 2002 through 2005 are subject to review. Monongahela is also a part of the consolidated West Virginia return of its parent company Allegheny. The consolidated West Virginia returns have been audited through 2004. The 2005 return remains subject to review. Additionally, Monongahela is subject to tax in Virginia. The Virginia returns for tax years 2003 through 2005 remain subject to review.

As stated above, the IRS is currently auditing Allegheny’s tax returns for the tax years 1998 through 2003. These

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

audits are anticipated to be completed by December 31, 2007. During the audit period, Monongahela changed its method of applying the inventory capitalization rules from its traditional method to the simplified service cost method. The IRS has proposed adjustments related to the change in method that are strictly timing in nature. Interest accrued on this position was $2.6 million, net of tax, at March 31, 2007. It is reasonably possible that a portion of the interest accrual will reverse within the next 12 months. However, should the IRS’s position prevail, the adjustments would not result in a material charge to Monongahela’s results of operations. Also, Monongahela has filed various refund claims with the IRS primarily related to property type items. These items will be settled along with the 1998 through 2003 audits and are not expected to result in a material adjustment to Monongahela’s financial position.

NOTE 5: DEBT

At March 31, 2007 contractual maturities for long-term debt, excluding unamortized discounts of $1.0 million, were as follows:


(In millions)	2007		2008		2009		2010		2011		Thereafter		Total
First Mortgage Bonds	$	—	$	—	$	—	$	—	$	—	$	340.0	$	340.0
Medium-Term Notes		—		—		—		110.0		—		—		110.0
Pollution Control Bonds		14.5		—		—		—		—		70.2		84.7

Total	$	14.5	$	—	$	—	$	110.0	$	—	$	410.2	$	534.7

At March 31, 2007, substantially all of Monongahela’s properties were held subject to liens of various relative priorities securing debt obligations.

Subsequent debt activity

On April 11, 2007, MP Environmental Funding LLC, a subsidiary of Monongahela, and PE Environmental Funding LLC, a subsidiary of Potomac Edison, issued $344 million and $115 million, respectively, of Senior Secured Sinking Fund Environmental Control Bonds, Series A. These bonds securitize the right to collect an environmental control surcharge from the West Virginia customers of Monongahela and Potomac Edison. The bonds were issued in several tranches with interest rates ranging from 4.98% to 5.52% and scheduled maturities ranging from July 2014 to July 2027. Net proceeds from the sale of the bonds represent restricted funds and will be used to fund the majority of costs to construct and install Scrubbers at Fort Martin.

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

NOTE 6: BUSINESS SEGMENTS

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. Business segment information is summarized below.


	Three months ended March 31, 2007										Three months ended March 31, 2006
	Delivery		Generation								Delivery		Generation
	and		and								and		and
(In millions)	Services		Marketing			Eliminations			Total		Services		Marketing		Eliminations			Total
External operating revenues	$	181.1	$	19.8		$	—		$	200.9	$	174.1	$	23.1	$	—		$	197.2
Internal operating revenues		—		97.5			(97.5	)		—		—		78.0		(78.0	)		—

Total operating revenues	$	181.1	$	117.3		$	(97.5	)	$	200.9	$	174.1	$	101.1	$	(78.0	)	$	197.2
Depreciation and amortization	$	7.8	$	10.0		$	—		$	17.8	$	7.6	$	8.8	$	—		$	16.4
Operating income (loss)	$	36.4	$	(19.4	)	$	—		$	17.0	$	37.2	$	4.7	$	—		$	41.9
Interest expense	$	4.7	$	3.9		$	—		$	8.6	$	6.2	$	4.6	$	—		$	10.8
Income tax expense (benefit)	$	14.2	$	(8.9	)	$	—		$	5.3	$	12.7	$	0.4	$	—		$	13.1
Net income (loss)	$	17.7	$	(10.7	)	$	—		$	7.0	$	19.8	$	1.9	$	—		$	21.7

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 March 31,
(In millions)	2007		2006
Pension benefits	$	2.0	$	2.0
Postretirement benefits other than pension benefits	$	1.7	$	1.7

NOTE 8: ASSET RETIREMENT OBLIGATIONS (“AROs”)

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 following is an analysis of the changes in the ARO liability for the three months ended March 31, 2007:


(In millions)	ARO Liability
Balance at December 31, 2006	$	13.7
Net transfer of ARO liabilities from AE Supply due to Asset Swap		2.5
New ARO liability		0.3

Balance at March 31, 2007	$	16.5

Monongahela 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 a reduction against related regulatory liabilities.

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

NOTE 9: REGULATORY ASSETS AND LIABILITIES

Monongahela’s electric generation and T&D operations are subject to the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues associated with costs that are expected to be recovered in the future from customers through the rate-making process. Regulatory liabilities generally represent probable future reductions in revenues associated with amounts that are to be credited or refunded to customers through the rate-making process. Regulatory assets and regulatory liabilities reflected in the Consolidated Balance Sheets relate to:


	March 31,		December 31,
(In millions)	2007		2006
Regulatory assets, including current portion:
Income taxes	$	70.3	$	72.0
Unamortized loss on reacquired debt		13.8		14.2
Other		9.0		9.1

Subtotal		93.1		95.3

Regulatory liabilities:
Non-legal asset removal costs		214.3		239.1

Subtotal		214.3		239.1

Net regulatory liabilities	$	121.2	$	143.8

NOTE 10: OTHER INCOME AND EXPENSES, NET

Other income and expenses, net represents non-operating income and expenses before income taxes. The following table summarizes Monongahela’s other income and expenses, net:


	Three Months Ended March 31,
(In millions)	2007		2006
Interest income	$	0.7	$	2.0
Equity in earnings of AGC		3.0		1.4
Other		0.2		0.3

Total	$	3.9	$	3.7

NOTE 11: COMMITMENTS AND CONTINGENCIES

Environmental Matters and Litigation

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

requirements of a national regulation are known, and the capabilities of control or reduction technologies are more fully understood. Allegheny recognizes the possibility that federal legislation and implementation regulations addressing climate change will be adopted some time in the future. Allegheny’s current strategy focuses on:

	•		developing an accurate CO₂ emissions inventory;

	•		improving the efficiency of its coal-burning fleet;

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

	•		following developing technologies for carbon sequestration;

	•		participating in carbon dioxide sequestration efforts (e.g. reforestation projects) both domestically and abroad; and analyzing options for future energy investment (e.g. renewables, clean-coal, etc.).

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

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.

Clean Air Act Litigation. In August 2000, AE received a letter from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten electric generation facilities, which collectively include 22 generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island. AE Supply and Monongahela own these generation facilities. The letter requested information under Section 114 of the Clean Air Act to determine compliance with the Clean Air Act and related requirements, including potential application of the 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.

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

Pennsylvania Air Pollution Control Act at the Hatfield’s Ferry, Armstrong and Mitchell facilities in Pennsylvania. The PA Enforcement Action appears to raise the same issues regarding Allegheny’s Pennsylvania generation facilities that are before the federal District Court in the West Virginia DJ Action, except that the PA Enforcement Action also includes the PA DEP and the Maryland Attorney General. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. On May 30, 2006, the District Court denied Allegheny’s motion to dismiss the amended complaint. On July 26, 2006, at a status conference, the Court determined that discovery would proceed regarding liability issues, but not remedies, and the liability phase of discovery should be completed by July 31, 2007.

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

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

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

Other Litigation

NOTE 12: SUBSEQUENT EVENT

ALLEGHENY GENERATING COMPANY
STATEMENTS OF OPERATIONS
(unaudited)


	Three Months Ended
	March 31,
(In thousands)	2007		2006
Operating revenues	$	16,911	$	17,338

Operating expenses:
Operations and maintenance		1,364		1,507
Depreciation		4,295		4,285
Taxes other than income taxes		794		799

Total operating expenses		6,453		6,591

Operating income		10,458		10,747

Other income, net		70		45

Interest expense		1,771		1,808

Income before income taxes		8,757		8,984

Income tax expense		2,764		2,849

Net income	$	5,993	$	6,135

See accompanying Notes to Financial Statements.

ALLEGHENY GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(unaudited)


	Three Months Ended
	March 31,
(In thousands)	2007			2006
Cash Flows From Operating Activities:
Net income	$	5,993		$	6,135

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		4,295			4,285
Deferred income taxes and investment tax credit, net		(2,022	)		(1,761	)
Other, net		72			71

Changes in certain assets and liabilities:
Accounts receivable from/payable to affiliates, net		(8,603	)		(3,532	)
Materials and supplies		(29	)		(42	)
Taxes receivable/accrued, net		7,907			6,887
Prepayments		126			79
Other current assets		3			4
Accounts payable		(1,489	)		(2,685	)
Accrued interest		(1,738	)		(1,719	)
Other current liabilities		166			119
Other assets		—			104
Other liabilities		—			1

Net cash provided by operating activities		4,681			7,946

Cash Flows From Investing Activities:
Capital expenditures		(1,122	)		(763	)

Cash Flows From Financing Activities:
Intercompany tax sharing agreement benefit		1,348			—
Cash dividends paid on common stock		(5,000	)		(5,000	)

Net cash used in financing activities		(3,652	)		(5,000	)

Net increase (decrease) in cash and cash equivalents		(93	)		2,183
Cash and cash equivalents at beginning of period		2,846			1,858

Cash and cash equivalents at end of period	$	2,753		$	4,041

Supplemental Cash Flow Information:
Cash paid for interest	$	3,438		$	3,455

See accompanying Notes to Financial Statements.

ALLEGHENY GENERATING COMPANY
BALANCE SHEETS
(unaudited)


	March 31,			December 31,
(In thousands)	2007			2006
ASSETS

Current Assets:
Cash and cash equivalents	$	2,753		$	2,846
Accounts receivable from affiliate		2,971			—
Materials and supplies		1,748			1,720
Taxes receivable		—			762
Other		231			360

Total current assets		7,703			5,688

Property, Plant and Equipment, Net:
Generation		782,187			777,507
Transmission		55,247			55,169
Other		2,943			2,949
Accumulated depreciation		(322,079	)		(318,164	)

Subtotal		518,298			517,461
Construction work in progress		2,953			6,963

Total property, plant and equipment, net		521,251			524,424

Deferred Charges:
Regulatory assets		7,732			7,842
Other		90			92

Total deferred charges		7,822			7,934

Total Assets	$	536,776		$	538,046

See accompanying Notes to Financial Statements.

ALLEGHENY GENERATING COMPANY
BALANCE SHEETS (continued)
(unaudited)


	March 31,		December 31,
(In thousands, except share data)	2007		2006
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	1,257	$	2,746
Accounts payable to affiliates, net		—		5,632
Accrued interest		554		2,292
Accrued taxes		7,145		—
Other current liabilities		165		—

Total current liabilities		9,121		10,670

Long-term Debt (Note 2)		99,466		99,458

Deferred Credits and Other Liabilities:
Investment tax credit		35,623		35,953
Non-current affiliated income taxes payable		17,544		17,544
Deferred income taxes		147,084		148,824
Regulatory liabilities		22,018		22,018

Total deferred credits and other liabilities		222,269		224,339

Commitments and Contingencies (Note 3)

Stockholders’ Equity:
Common stock, $1.00 par value, 5,000 shares authorized and 1,000 shares outstanding at March 31, 2007 and December 31, 2006		1		1
Other paid-in capital		174,017		172,669
Retained earnings		31,902		30,909

Total stockholders’ equity		205,920		203,579

Total Liabilities and Stockholders’ Equity	$	536,776	$	538,046

See accompanying Notes to Financial Statements.

ALLEGHENY GENERATING COMPANY
STATEMENT OF STOCKHOLDERS’ EQUITY
(unaudited)


					Other					Total
	Shares		Common		paid-in		Retained			stockholders’
(In thousands, except shares)	outstanding		stock		capital		earnings			equity
Balance at December 31, 2006		1,000	$	1	$	172,669	$	30,909		$	203,579
Net income		—		—		—		5,993			5,993
Intercompany tax sharing agreement benefit		—		—		1,348		—			1,348
Dividends declared on common stock		—		—		—		(5,000	)		(5,000	)

Balance at March 31, 2007		1,000	$	1	$	174,017	$	31,902		$	205,920

See accompanying Notes to Financial Statements.

ALLEGHENY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
(unaudited)

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”). At March 31, 2007 and December 31, 2006, AE Supply owned approximately 59% and 77%, respectively, and Monongahela owned approximately 41% and 23%, respectively, of AGC. AGC owns an undivided 40% interest (1,059 megawatts (“MWs”)) in the 2,648 MW pumped storage, hydroelectric station in Bath County, Virginia, 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, 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 and who provide services to AGC.

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

These unaudited interim financial statements have been prepared by AGC 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 (“GAAP”) have been condensed or omitted. These financial statements include all adjustments, consisting of normal recurring adjustments, considered necessary by management to fairly state the results of operations, financial position and cash flows. The results reported in these consolidated interim financial statements are not necessarily indicative of the results that may be expected for the entire year. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.

Certain amounts in previously issued financial statements have been reclassified to conform to the current presentation.

Federal and State IncomeTaxes.

AE and its subsidiaries, including AGC, file a consolidated federal income tax return. The consolidated income tax liability is allocated among AE and its subsidiaries generally in proportion to the taxable income of each participant, except that no subsidiary pays tax in excess of its separate return income tax liability. This corporate allocation may cause fluctuations and variances in the effective quarterly and year-to-date tax rates compared to statutory rates, depending on the level of pre-tax income. AGC’s consolidated income tax expense differs from an amount calculated at the federal statutory income tax rate of 35%, principally due to consolidated tax benefits, state income taxes, tax credits and certain non-deductible expenses.

In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109 (“FIN 48”). On May 2, 2007, the FASB issued FASB Interpretation No. 48-1, Definition of Settlement in FASB Interpretation No. 48 (“FIN 48-1”), which provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. AGC adopted the provisions of FIN 48 and FIN 48-1 as of January 1, 2007. The January 1, 2007 adoption of FIN 48 and FIN 48-1 did not have a material impact on AGC’s financial statements.

ALLEGHENY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
(unaudited)

NOTE 2: DEBT

As of March 31, 2007, contractual maturities of long-term debt, excluding unamortized debt discounts of $0.5 million, are as follows:


(In millions)	2007		2008		2009		2010		2011		Thereafter		Total
Debentures	$	—	$	—	$	—	$	—	$	—	$	100.0	$	100.0

NOTE 3: COMMITMENTS AND CONTINGENCIES

Environmental Matters and Litigation

Other Litigation

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

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

Forward-Looking Statements

In addition to historical information, this report contains a number of forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Words such as anticipate, expect, project, intend, plan, believe and words and terms of similar substance used in connection with any discussion of future plans, actions or events identify forward-looking statements. These include statements with respect to:

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

	•		financing plans;

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

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

	•		results of litigation;

	•		results of operations;

	•		internal controls and procedures;

	•		capital expenditures;

	•		status and condition of plants and equipment;

	•		capacity purchase commitments and

	•		regulatory matters.

Forward-looking statements involve estimates, expectations and projections and, as a result, are subject to risks and uncertainties. There can be no assurance that actual results will not differ materially from expectations. Actual results have varied materially and unpredictably from past expectations.

Factors that could cause actual results to differ materially include, among others, the following:

	•		plant performance and unplanned outages;

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

	•		general economic and business conditions;

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

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

	•		environmental regulations;

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

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

	•		changes in the weather and other natural phenomena;

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

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

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

	•		the loss of any significant customers or suppliers;

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

	•		inflationary and interest rate trends;

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

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

	•		other risks, including the effects of global instability, terrorism and war.

A detailed discussion of certain factors affecting the risk profile of the registrants is provided under the caption Item 1A, “Risk Factors,” in the 2006 Annual Report on Form 10-K.

ALLEGHENY RESULTS OF OPERATIONS

Overview

Allegheny is an integrated energy business that owns and operates electric generation facilities and delivers electric services to customers in Pennsylvania, West Virginia, Maryland, and Virginia. AE, Allegheny’s parent holding company, was incorporated in Maryland in 1925. Allegheny operates its business primarily through AE’s various directly and indirectly owned subsidiaries. These operations are aligned in two operating segments, the Delivery and Services segment and the Generation and Marketing segment. Additional information regarding the composition and activities of these segments is included in the 2006 Annual Report on Form 10-K.

Key Indicators and Performance Factors

The Delivery and Services Segment

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

Revenue per MWh sold. This measure is calculated by dividing total revenues from retail sales of electricity by total MWhs sold to retail customers. Revenue per MWh sold during the three months ended March 31, 2007 and 2006 was as follows:


	Three Months Ended
	March 31,
	2007		2006
Revenue per MWh sold	$	60.50	$	59.20

Operations and maintenance costs (“O&M”).Management closely monitors and manages O&M in absolute terms, as well as in relation to total MWhs sold.

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

The Generation and Marketing Segment

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

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

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

Station operations and maintenance costs (“Station O&M”).Station O&M includes base operations and special maintenance costs. Base and operations maintenance costs consist of normal recurring expenses related to the day-to-day on-going operation of the generation facility. Special maintenance includes outage related maintenance and projects that relate to all of the generating facilities.

The following table shows kWhs generated, EAFs and Station O&M related to the Generation and Marketing segment:


	Three Months Ended March 31,
	2007			2006			% Change
Supercritical Units:
EAF		89.5	%		91.0	%		(1.5	)
Station O&M (in millions):
Base operations (a)	$	25.0		$	23.1			8.2
Special		10.4			8.4			23.8

Total Station O&M	$	35.4		$	31.5			12.4


All Generation Units:
kWhs generated (in millions)		13,092			13,017			0.6
EAF		89.2	%		91.2	%		(2.0	)
Station O&M (in millions):
Base operations (a)	$	38.0		$	38.0			—
Special		11.4			9.2			23.9

Total Station O&M	$	49.4		$	47.2			4.7


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

Operating Statistics

The following table provides retail electricity sales information.


	Three Months Ended
	March 31,
	2007		2006		% Change
Retail electricity sales (million kWhs)		11,712		11,182		4.7
HDD (a)		2,776		2,426		14.4


(a)		Heating degree-days (“HDD”).The operations of the Distribution Companies are weather sensitive. Weather conditions directly influence the volume of electricity delivered by the Distribution Companies representing one of several factors that impact the volume of electricity. Accordingly, deviations in weather from normal levels can affect Allegheny’s financial performance. HDD is most likely to impact the usage of Allegheny’s residential and commercial customers. Industrial customers are less weather sensitive. Degree-day data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. Each degree of temperature below 65° Fahrenheit is counted as one heating degree-day. Normal (historical) HDD are 2,841, calculated on a weighted-average basis across the geographic areas served by the Distribution Companies.

ALLEGHENY ENERGY, INC.—CONSOLIDATED RESULTS OF OPERATIONS

Income Summary


	Three months ended March 31, 2007
	Delivery			Generation
	and			and
(In millions)	Services			Marketing		Eliminations			Total
Operating revenues	$	757.9		$	524.5	$	(434.8	)	$	847.6
Fuel		—			232.2		—			232.2
Purchased power and transmission		500.8			24.2		(431.7	)		93.3
Deferred energy costs, net		(1.5	)		—		—			(1.5	)
Operations and maintenance		86.3			77.3		(3.1	)		160.5
Depreciation and amortization		40.2			31.8		—			72.0
Taxes other than income taxes		35.5			20.4		—			55.9

Total operating expenses		661.3			385.9		(434.8	)		612.4
Operating income		96.6			138.6		—			235.2
Other income and expenses, net		3.0			4.1		(1.2	)		5.9
Interest expense and preferred dividends		18.7			42.1		(1.2	)		59.6

Income from continuing operations before income taxes and minority interest		80.9			100.6		—			181.5
Income tax expense		35.5			35.9		—			71.4
Minority interest in net income of subsidiaries		—			0.4		—			0.4

Net income	$	45.4		$	64.3	$	—		$	109.7


	Three months ended March 31, 2006
	Delivery		Generation
	and		and
(In millions)	Services		Marketing			Eliminations			Total
Operating revenues	$	702.6	$	507.1		$	(364.1	)	$	845.6
Fuel		—		218.7			—			218.7
Purchased power and transmission		447.7		15.7			(362.2	)		101.2
Gain on sale of OVEC power agreement and shares		—		(5.0	)		—			(5.0	)
Deferred energy costs, net		5.0		—			—			5.0
Operations and maintenance		86.8		71.5			(1.9	)		156.4
Depreciation and amortization		37.7		30.1			—			67.8
Taxes other than income taxes		33.3		20.4			—			53.7

Total operating expenses		610.5		351.4			(364.1	)		597.8
Operating income		92.1		155.7			—			247.8
Other income and expenses, net		4.3		3.8			(0.4	)		7.7
Interest expense and preferred dividends		19.9		48.2			(0.4	)		67.7

Income from continuing operations before income taxes and minority interest		76.5		111.3			—			187.8
Income tax expense		30.1		42.3			—			72.4
Minority interest in net income of subsidiaries		—		1.2			—			1.2

Income from continuing operations		46.4		67.8			—			114.2
Loss from discontinued operations, net of tax		—		(0.8	)		—			(0.8	)

Net income	$	46.4	$	67.0		$	—		$	113.4

ALLEGHENY ENERGY, INC.—CONSOLIDATED RESULTS

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

Operating Revenues

Operating revenues increased $2.0 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to higher generation rates in Pennsylvania as a result of a rate settlement approved by the Pennsylvania PUC, increased transmission and distribution revenues due to colder weather, the addition of new customers, greater customer usage and increased MWhs generated. These increases were partially offset by decreased revenues due to the net impact of lower realized market prices, including gains on hedging activities during the three months ended March 31, 2006 that did not recur in the three months ended March 31, 2007 and reduced revenues due to the March 2006 assignment of AE Supply’s rights to generation from OVEC in connection with the sale of a portion of AE’s equity interest in OVEC.

Operating Income

Operating income decreased $12.6 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to a $14.6 million increase in operating expenses, partially offset by the $2.0 million increase in operating revenues discussed above.

Operating expenses increased primarily due to:

	•		a $13.5 million increase in fuel expense, primarily due to an increase in the average price of coal and an increase in the amount of coal consumed,

	•		a $5.0 million gain from the release of escrowed proceeds relating to the sale of the OVEC power agreement and shares, which was recorded during the three months ended March 31, 2006,

	•		a $4.1 million increase in operations and maintenance expense, primarily due to the reversal of a guarantee liability in 2006 associated with the Hunlock Creek Energy Ventures partnership and

	•		a $4.2 million increase in depreciation and amortization expense, primarily due to net property, plant and equipment additions.

The above increases were partially offset by a $7.9 million decrease in purchased power and transmission expense, primarily due to reduced purchases from OVEC and reduced purchased power and transmission related to a contract to supply power for Monongahela’s former Ohio electric service territory through May 2007, as well as a $6.5 million decrease in deferred energy costs, net related to PURPA and market-based generation.

Income from Continuing Operations Before Income Taxes and Minority Interest

Income from continuing operations before income taxes and minority interest decreased $6.3 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to:

	•		the $12.6 million decrease in operating income discussed above,

	•		partially offset by an $8.1 million decrease in interest expense and preferred dividends, primarily due to lower average debt outstanding.

Income Tax Expense

The effective tax rate for the three months ended March 31, 2007 was 39.3% and was higher than income tax expense calculated at the federal statutory tax rate, primarily due to state income taxes and other adjustments related to tax reserves. See Note 4, “Income Taxes,” for additional information on the adoption of FIN 48.

The effective tax rate for the three months ended March 31, 2006 was 38.5% and was higher than income tax expense calculated at the federal statutory tax rate, primarily due to state income taxes.

ALLEGHENY ENERGY, INC.—DISCUSSION OF SEGMENT RESULTS OF OPERATIONS:

Delivery and Services

The following table provides retail electricity sales information.


	Three Months Ended
	March 31,
	2007		2006		% Change
Retail electricity sales (million kWhs)		11,712		11,182		4.7
HDD (a)		2,776		2,426		14.4

(a)

Normal (historical) HDD are 2,841, 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
	March 31,
(In millions)	2007		2006
Retail electric:
Generation	$	471.6	$	438.7
Transmission		43.8		42.1
Distribution		193.2		181.2

Total retail electric		708.6		662.0

Transmission services and bulk power		38.5		35.7
Other affiliated and nonaffiliated energy services		10.8		4.9

Total Delivery and Services operating revenues	$	757.9	$	702.6

Retail electric revenues increased $46.6 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to:

	•		a $32.9 million increase in generation revenues due to greater customer usage due to colder weather and from the addition of new customers, as well as the effect of a January 1, 2007 rate increase arising from a settlement approved by the Pennsylvania PUC and

	•		a $13.7 million increase in T&D revenues as a result of increased customer usage due to colder weather and the addition of new customers.

Transmission services and bulk power revenues increased $2.8 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to:

	•		a $3.8 million increase in bulk power revenues, primarily due to a scheduled maintenance outage at the AES Warrior Run generation facility during the three months ended March 31, 2006 that did not recur during the three months ended March 31, 2007,

	•		partially offset by a $1.2 million decrease in bulk power revenues related to a fixed price power supply agreement to serve Monongahela’s former Ohio service territory.

Other affiliated and nonaffiliated energy services revenues increased $5.9 million for the three months ended March 31,

2007 compared to the three months ended March 31, 2006, primarily due to the deferral of revenue on certain fiber optic agreements in 2006 and the impact of regulatory activities related to certain transmission contracts.

Operating Expenses

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


	Three Months Ended
	March 31,
(In millions)	2007		2006
Other purchased power and transmission	$	461.6	$	401.5
From PURPA generation (a)		39.2		46.2

Total purchased power and transmission	$	500.8	$	447.7


a) PURPA cost (cents per kWh)			5.5				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. In addition, through December 31, 2006, Potomac Edison had a power purchase agreement with AE Supply under which AE Supply provided Potomac Edison with the power necessary to meet its West Virginia load obligation at a fixed rate. Subsequent to the Asset Swap, effective January 1, 2007, Potomac Edison purchases the power necessary to service its West Virginia customers from Monongahela’s Generation and Marketing segment at a prorated share of overall Monongahela generation costs and associated revenue.

Through December 31, 2006, to facilitate the economic dispatch of its generation, Monongahela sold the power that it generated from its West Virginia jurisdictional assets to AE Supply at PJM market prices and purchased from AE Supply, at PJM market prices, the power necessary to meet its West Virginia jurisdictional customer load. Subsequent to the Asset Swap, effective January 1, 2007, Monongahela sells the power that it generates from its West Virginia jurisdictional assets into the PJM market and purchases from the PJM market the power necessary to meet its West Virginia jurisdictional customer load and its contractual obligations. The net revenue from these PJM purchases and sales is reflected in wholesale and other revenues, net within the Generation and Marketing segment.

Other purchased power and transmission increased $60.1 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to:

	•		an increase in other purchased power as a result of colder weather, the addition of new customers and increased prices,

	•		an approximate $11 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 as a result of a January 1, 2007 rate increase due to a settlement approved by the Pennsylvania PUC and

	•		a $4.2 million increase in other purchased power and transmission related to a contract to supply power for Monongahela’s former Ohio electric service territory through May 2007.

Purchased power and transmission from PURPA generation decreased $7.0 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to a $14.8 million decrease in purchased power from PURPA as a result of a January 1, 2007 transfer of Monongahela’s PURPA contracts from the Delivery and Services segment to the Generation and Marketing segment, partially offset by an increase in purchased power due to a scheduled maintenance outage at the AES Warrior Run generation facility during the three months ended March 31, 2006 that did not recur during the three months ended March 31, 2007.

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


	Three Months Ended
	March 31,
(In millions)	2007			2006
Deferred energy costs, net	$	(1.5	)	$	5.0

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,” “Grant Town PURPA Generation facility” and “Market-based Generation Costs.”

AES Warrior Run PURPA Generation

To satisfy certain of its obligations under PURPA, Allegheny, through Potomac Edison, entered into a long-term contract beginning July 1, 2000 to purchase capacity and energy from the AES Warrior Run PURPA generation facility through the beginning of 2030. Potomac Edison is authorized by the Maryland 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.

Grant Town PURPA Generation facility

Monongahela acquires energy from the Grant Town PURPA generation facility in West Virginia. The West Virginia PSC approved an amendment to the Electric Energy Purchase Agreement between Monongahela and American Bituminous Power Partners, L.P., the owners of the Grant Town PURPA generation facility, in April 2006. The amendment provides for an increase in the price of energy that Monongahela is acquiring until 2017. The West Virginia Public Service Commission authorized Monongahela and Potomac Edison to institute a temporary surcharge designed to recover the increase in costs from West Virginia customers as well as a deferred accounting mechanism by which actual aggregate amounts of the incremental cost increase will be tracked and reconciled by comparison to the aggregate amounts recovered from West Virginia customers through the temporary surcharge.

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 generation provider. A regulatory asset or liability is recorded on Potomac Edison’s balance sheet relative to any under-recovery or over-recovery for the generation component of costs charged to Maryland commercial and industrial customers. Deferred energy costs, net relate, in part, to the recovery from or payment to customers related to these generation costs to the extent amounts paid for generation costs differ from prices currently charged to customers.

Deferred energy costs, net decreased $6.5 million for the three months ended March 31, 2007 compared with the three months ended March 31, 2006, primarily as a result of a $3.3 million decrease related to PURPA and a $3.2 million decrease related to market-based generation.

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


	Three Months Ended
	March 31,
(In millions)	2007		2006
Depreciation and amortization	$	40.2	$	37.7

Depreciation and amortization expenses increased $2.5 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to net property, plant and equipment additions.

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


	Three Months Ended
	March 31,
(In millions)	2007		2006
Taxes other than income taxes	$	35.5	$	33.3

Taxes other than income taxes increased $2.2 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to increased gross receipts taxes as a result of increased taxable revenues in Pennsylvania.

Other Income and Expenses, Net

Other income and expenses, net represents non-operating income and expenses before income taxes. Other income and expenses, net were as follows:


	Three Months Ended
	March 31,
(In millions)	2007		2006
Other income and expenses, net	$	3.0	$	4.3

Other income and expenses, net decreased $1.3 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily as a result of decreased interest income on investments.

See Note 17, “Other Income and Expenses, Net,” for additional details.

Interest Expense and Preferred Dividends:

Interest expense and preferred dividends were as follows:


	Three Months Ended
	March 31,
(In millions)	2007		2006
Interest expense and preferred dividends	$	18.7	$	19.9

Interest expense and preferred dividends decreased $1.2 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to lower average debt outstanding.

Income Tax Expense

The effective tax rate for the three months ended March 31, 2007 was 43.9% and was higher than income tax expense calculated at the federal statutory tax rate, primarily due to state income taxes, the accounting for deferred taxes related to utility property and other adjustments related to tax reserves.

The effective tax rate for the three months ended March 31, 2006 was 39.3% and was higher than income tax expense calculated at the federal statutory tax rate, primarily due to state income taxes, partially offset by the allocation of consolidated tax savings.

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
	March 31,
	2007		2006		Change
Generation (million kWhs)		13,092		13,017		0.6	%

Operating Revenues

Operating revenues were as follows:


	Three Months Ended
	March 31,
(In millions)	2007		2006
Revenue from affiliates	$	431.7	$	362.3
Wholesale and other, net (a)		92.8		144.8

Total revenues	$	524.5	$	507.1


(a)		Amounts are net of energy trading gains and losses as described in Note 7, “Derivative Instruments and Hedging Activities.” Energy trading gains (losses) are presented in the wholesale and other revenues table below.

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

AE Supply provides Potomac Edison and West Penn with a majority of the power necessary to meet their PLR obligations under power sales agreements that have both fixed-price and market-based pricing components. In addition, through December 31, 2006, AE Supply had a power sales agreement with Potomac Edison to provide the power necessary to meet Potomac Edison’s West Virginia load obligation at a fixed rate. Subsequent to the Asset Swap, effective January 1, 2007, Potomac Edison purchases the power necessary to service its West Virginia customers from Monongahela at a prorated share of overall Monongahela generation costs and associated revenue.

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

See Note 3, “Asset Swap,” for additional information.

The average rate at which the Generation and Marketing segment sold power to the Distribution Companies was $37.00 and $34.37 per MWh for the three months ended March 31, 2007 and 2006, respectively.

Revenue from affiliates increased $69.4 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to:

	•		a $19.2 million increase due to an increase in sales volume and price reflecting the transfer of Monongahela’s PURPA contracts to the Generation and Marketing segment from the Delivery and Services segment, causing a corresponding increase in both revenues and purchased power,

	•		a $15.1 million increase related to the assignment, in connection with the Asset Swap, of AE Supply’s below-market power supply agreement to serve Potomac Edison’s West Virginia load obligations, as a result of which, Potomac Edison now purchases the power necessary to service its West Virginia customers from Monongahela at a prorated share of overall Monongahela generation costs and associated revenue,

	•		increased sales volumes as a result of colder weather,

	•		a $14.0 million increase, primarily related to higher generation rates charged to Pennsylvania customers, effective January 1, 2007, as a result of a West Penn settlement approved by the Pennsylvania PUC, which are passed on to AE Supply under the terms of a power supply agreement between West Penn and AE Supply and

	•		a $16.5 million increase related to higher contractual rates with increased sales volumes for certain of Potomac Edison’s customers in Maryland,

	•		partially offset by a $3.0 million decrease in ancillary service revenues from the Delivery and Services segment due to a contract expiration.

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


	Three Months Ended
	March 31,
(In millions)	2007			2006
PJM Revenue:
Generation sold into PJM	$	629.5		$	581.9
Power purchased from PJM		(539.4	)		(453.8	)

Net		90.1			128.1


Cash flow hedges and trading activities:
Realized gains (losses)		(3.9	)		3.6
Unrealized gains (losses)		2.4			13.0

Net		(1.5	)		16.6

Other revenues		4.2			0.1

Total wholesale and other revenues	$	92.8		$	144.8

Wholesale and other revenues decreased $52.0 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to:

	•		a decrease in net PJM revenues of $38.0 million and

	•		an $18.1 million decrease in cash flow hedges and trading revenues, primarily related to the settlement of cash flow hedges that were transacted during a period of high prices during the first quarter of 2006,

•

partially offset by a $4.1 million increase in other revenues, primarily due to sales of certain other power supply contracts within the Allegheny Power service territory and proceeds from the annual U.S. Environmental Protection Agency’s (“EPA”) emissions allowance auction.

The decrease in net PJM revenues was due to higher power purchased from PJM, partially offset by an increase in revenues from generation sold to PJM. Revenues from generation sold to PJM were higher primarily due to an increase in the market price of power and an increase in the MWhs generated by all power stations, partially offset by reduced revenues due to the March 2006 assignment of AE Supply’s rights to generation from OVEC in connection with the sale of a portion of AE’s equity interest in OVEC. Power purchased from PJM increased due to an increase in the market price of power, and increased sales volume from the Distribution Companies due to colder weather and increased sales volumes for certain of Potomac Edison’s customers in Maryland.

Fair Value of Contracts:Allegheny qualifies certain of its commodity contracts under the “normal purchase and normal sale” scope exception under SFAS No. 133. As a result, Allegheny accounts for these contracts under the accrual method, rather than marking these contracts to market value. Allegheny uses derivative accounting for energy contracts that do not qualify under the scope exception. These energy contracts are recorded at fair value, which represents the net unrealized gain and loss on open positions, in the Consolidated Balance Sheets, after applying the appropriate counterparty netting agreements. The realized and unrealized revenues from energy trading activities are recorded on a net basis in “Operating revenues” in the Consolidated Statements of Operations. The fair value of the remaining trading portfolio consists primarily of interest rate swap agreements and contracts designated as cash flow hedges as of March 31, 2007. Changes in the fair value of the commodity cash flow hedges are reflected in other comprehensive income.

At March 31, 2007, there were no derivative contract assets, and the fair value of derivative contract liabilities was $25.6 million. At December 31, 2006, the fair values of derivative contract assets and liabilities were $1.5 million and $24.0 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 March 31, 2007
Classification of contracts
by source of fair value
(In millions)	Settlement by:
	2007			2008			2009			2010			2011			Total
Prices actively quoted	$	(7.3	)	$	(5.8	)	$	(5.5	)	$	(5.3	)	$	(1.7	)	$	(25.6	)
Prices provided by other external sources		—			—			—			—			—			—
Prices based on models		—			—			—			—			—			—

Total	$	(7.3	)	$	(5.8	)	$	(5.5	)	$	(5.3	)	$	(1.7	)	$	(25.6	)

The fair value of AE Supply’s contracts that are scheduled to settle by December 31, 2007 was a net liability of $7.3 million, primarily related to interest rate swaps.

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

Changes in Fair Value:Net unrealized gains of $2.4 million for the three months ended March 31, 2007 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
	March 31,
(In millions)	2007
Net fair value of derivative contract liabilities at January 1	$	(22.5	)
Changes in fair value of cash flow hedges		(5.5	)
Unrealized gains on contracts, net		2.4

Net fair value of derivative contract liabilities at March 31	$	(25.6	)

As shown in the table above, the net fair value of Allegheny’s derivative contracts decreased by $3.1 million during the three months ended March 31, 2007. The decrease in the fair value was primarily due to changes in the fair value of commodity contracts and settlements on interest rate contracts.

Operating Expenses

Fuel:Fuel expense represents the cost of coal, natural gas, oil, lime and other materials consumed in the generation of power, emission allowances, fuel handling and residual disposal costs. Fuel expense was as follows:


	Three Months Ended
	March 31,
(In millions)	2007		2006
Fuel	$	232.2	$	218.7

Total fuel increased by $13.5 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to a $13.7 million increase in coal expense. The increase in coal expense was due to an increase in the average price of coal of $1.81 per ton and a 0.1 million-ton increase in the amount of coal burned. The increase in the amount of coal burned was primarily due to an increase in total MWhs generated.

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


	Three Months Ended
	March 31,
(In millions)	2007		2006
Purchased power and transmission expenses	$	24.2	$	15.7

Purchased power and transmission expenses increased $8.5 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to a $16.3 million increase in purchased power from PURPA as a result of a January 1, 2007 transfer of Monongahela’s PURPA contracts from the Delivery and Services segment to the Generation and Marketing segment, partially offset by a $10.0 million decrease 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.

Gain on Sale of OVEC Power Agreement and Shares:On December 31, 2004, AE sold a 9% equity interest in OVEC to Buckeye Power Generating, LLC. The gain on the sale of the OVEC power agreement and shares of $5.0 million for the three months ended March 31, 2006 represents the release of proceeds due to the fulfillment of certain post-closing commitments.

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


	Three Months Ended
	March 31,
(In millions)	2007		2006
Operations and maintenance	$	77.3	$	71.5

Operations and maintenance expenses increased $5.8 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to:

	•		a $6.4 million reversal of a guarantee liability associated with the Hunlock Creek Energy Ventures partnership during the three months ended March 31, 2006 that did not recur during the three months ended March 31, 2007 and

	•		a $4.1 million increase in contract work expense, primarily due to maintenance performed during a scheduled outage at Fort Martin Unit No. 1 which occurred during the three months ended March 31, 2007, partially offset by a maintenance outage at the Harrison generation facility during the three months ended March 31, 2006 that did not recur during the three months ended March 31, 2007,

	•		partially offset by a $1.9 million decrease in materials and supplies expense due to decreased base maintenance expenditures at several Allegheny generation facilities and a $1.3 million decrease in insurance expense, primarily due to decreased claims.

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


	Three Months Ended
	March 31,
(In millions)	2007		2006
Depreciation and amortization	$	31.8	$	30.1

Depreciation and amortization expense increased $1.7 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to net property, plant and equipment additions.

Interest Expense and Preferred Dividends

Interest expense and preferred dividends were as follows:


	Three Months Ended
	March 31,
(In millions)	2007		2006
Interest expense and preferred dividends	$	42.1	$	48.2

Interest expense and preferred dividends decreased $6.1 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to lower average debt outstanding.

Income Tax Expense

The effective tax rate for the three months ended March 31, 2007 was 35.6% and was higher than income tax expense calculated at the federal statutory tax rate, primarily due to state income taxes, partially offset by an adjustment to deferred taxes for a West Virginia corporate net income tax rate change.

The effective tax rate for the three months ended March 31, 2006 was 38.0% and was higher than income tax expense calculated at the federal statutory tax rate, primarily due to state income taxes, partially offset by the allocation of consolidated tax savings.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES—CONSOLIDATED RESULTS OF OPERATIONS

Income (Loss) Summary


	Three months ended March 31, 2007
	Delivery			Generation
	and			and
(In millions)	Services			Marketing			Eliminations			Total
Operating revenues	$	181.1		$	117.3		$	(97.5	)	$	200.9
Fuel		—			60.4			—			60.4
Purchased power and transmission		107.6			28.6			(97.5	)		38.7
Deferred energy costs, net		(0.3	)		—			—			(0.3	)
Operations and maintenance		24.1			30.7			—			54.8
Depreciation and amortization		7.8			10.0			—			17.8
Taxes other than income taxes		5.5			7.0			—			12.5

Total operating expenses		144.7			136.7			(97.5	)		183.9
Operating income (loss)		36.4			(19.4	)		—			17.0
Other income and expenses, net		0.2			3.7			—			3.9
Interest expense		4.7			3.9			—			8.6

Income (loss) before income taxes		31.9			(19.6	)		—			12.3
Income tax expense (benefit)		14.2			(8.9	)		—			5.3

Net income (loss)	$	17.7		$	(10.7	)	$	—		$	7.0


	Three months ended March 31, 2006
	Delivery		Generation
	and		and
(In millions)	Services		Marketing		Eliminations			Total
Operating revenues	$	174.1	$	101.1	$	(78.0	)	$	197.2
Fuel		—		45.1		—			45.1
Purchased power and transmission		98.7		20.4		(78.0	)		41.1
Operations and maintenance		24.3		16.2		—			40.5
Depreciation and amortization		7.6		8.8		—			16.4
Taxes other than income taxes		6.3		5.9		—			12.2

Total operating expenses		136.9		96.4		(78.0	)		155.3
Operating income		37.2		4.7		—			41.9
Other income and expenses, net		1.5		2.2		—			3.7
Interest expense		6.2		4.6		—			10.8

Income before income taxes		32.5		2.3		—			34.8
Income tax expense		12.7		0.4		—			13.1

Net income	$	19.8	$	1.9	$	—		$	21.7

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 $3.7 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to colder weather and higher customer demand due to new customers.

Operating Income

Operating income decreased $24.9 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to a $28.6 million increase in operating expenses, partially offset by the $3.7 million increase in operating revenues discussed above.

Operating expenses increased primarily due to:

	•		a $15.3 million increase in fuel expense, primarily due to an increase in the average price of coal and an increase in the amount of coal consumed and

	•		a $14.3 million increase in operations and maintenance expenses, primarily due to an increase in contract work due to a planned maintenance outage in the first quarter of 2007 and an increase in salaries and wages due to the January 1, 2007 Asset Swap.

See Note 3, “Asset Swap,” for additional information.

Income Before Income Taxes

Income before income taxes decreased $22.5 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to the $24.9 million decrease in operating income discussed above.

Income Tax Expense

The effective tax rate for the three months ended March 31, 2007 was 43.6% and was higher than income tax expense calculated at the federal statutory tax rate, primarily due to state income taxes, the accounting for deferred taxes related to utility property and other adjustments related to tax reserves.

The effective tax rate for the three months ended March 31, 2006 was 37.6% and was higher than income tax expense calculated at the federal statutory tax rate, primarily due to state income taxes.

MONONGAHELA POWER COMPANY-DISCUSSION OF SEGMENT RESULTS OF OPERATIONS:

Delivery and Services

The following table provides retail electricity sales information:


	Three Months Ended
	March 31,
	2007		2006		% Change
Retail electricity sales (million kWhs)		2,783		2,653		4.9
HDD (a)		2,617		2,147		21.9


(a)		Normal (historical) Heating Degree Days (“HDD”) are 2,765, calculated on a weighted-average basis across the geographic areas served by Monongahela.

Operating Revenues

Operating revenues were as follows:


	Three Months Ended
	March 31,
(In millions)	2007		2006
Retail electric:
Generation	$	95.3	$	90.6
Transmission		9.1		8.6
Distribution		52.5		49.5

Total retail electric		156.9		148.7

Transmission services and bulk power		21.7		22.8
Other affiliated and non-affiliated energy services		2.5		2.6

Total Delivery and Services revenues	$	181.1	$	174.1

Retail electric revenues increased $8.2 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to:

	•		a $4.7 million increase in generation revenues due to load growth from increased customer usage due to colder weather and the addition of new customers and

	•		a $3.5 million increase in T&D revenues as a result of increased customer usage due to colder weather and the addition of new customers.

Transmission services and bulk power decreased $1.1 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to reduced bulk power sales related to a fixed price power supply agreement to serve Monongahela’s former Ohio service territory.

Operating Expenses

Purchased Power and Transmission:Purchased power and transmission consists of the following items:


	Three Months Ended
	March 31,
(In millions)	2007		2006
Other purchased power and transmission	$	107.6	$	83.9
From PURPA generation (a)		—		14.8

Total purchased power and transmission	$	107.6	$	98.7


(a) PURPA cost (cents per kWh)	—	4.3

Other purchased power and transmission primarily consists of Monongahela’s Delivery and Services segment’s purchases of power from Monongahela’s Generation and Marketing segment to service its load requirements. For further information, see the discussion under the heading “Generation and Marketing” below.

Other purchased power and transmission increased $23.7 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to increased power purchases in order to replace PURPA power lost as a result of a January 1, 2007 transfer of Monongahela’s PURPA contracts from the Delivery and Services segment to the Generation and Marketing segment. In addition, other purchased power increased due to colder weather.

Purchased power from PURPA generation decreased $14.8 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily as a result of a January 1, 2007 transfer of Monongahela’s PURPA contracts from the Delivery and Services segment to the Generation and Marketing segment.

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
	March 31,
(In millions)	2007		2006
Other income and expenses, net	$	0.2	$	1.5

Other income and expenses, net decreased $1.3 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily as a result of a decrease in interest income on investments.

Interest Expense:

Interest expense was as follows:


	Three Months Ended
	March 31,
(In millions)	2007		2006
Interest expense	$	4.7	$	6.2

Interest expense decreased $1.5 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to lower average debt outstanding.

Income Tax Expense

The effective tax rate for the three months ended March 31, 2007 was 44.5% and was higher than income tax expense calculated at the federal statutory tax rate, primarily due to state income taxes and the accounting for deferred taxes related to utility property.

The effective tax rate for the three months ended March 31, 2006 was 39.1% and was higher than income tax expense calculated at the federal statutory tax rate, primarily due to state income taxes.

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

March 31,

2007

2006

% Change

Generation (million kWhs)

3,234

2,816

14.8

Operating Revenues

Operating revenues were as follows:


	Three Months Ended
	March 31,
(In millions)	2007			2006
Revenue from affiliates	$	144.8		$	77.2
Wholesale and other, net		(27.5	)		23.9

Total operating revenues	$	117.3		$	101.1

Revenue from affiliates for the three months ended March 31, 2007 includes sales to Monongahela’s Delivery and Services segment to meet its customer obligations and sales to Potomac Edison to meet its West Virginia customer obligations.

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

Total operating revenues increased $16.2 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006 primarily due to:

	•		an increase in affiliated sales volume and price reflecting the transfer of Monongahela’s PURPA contracts to the Generation and Marketing segment from the Delivery and Services segment, causing a corresponding increase in both revenues and purchased power and

	•		an increase in affiliated revenues related to the assignment to Monongahela, in connection with the Asset Swap, of AE Supply’s below-market power supply agreement to serve Potomac Edison’s West Virginia load obligations, as a result

	•		of which, Potomac Edison now purchases the power necessary to service its West Virginia customers from Monongahela at a prorated share of overall Monongahela generation costs and associated revenue,

	•		partially offset by a decrease in wholesale and other revenue as a result of changes to the contractual obligations discussed above.

See Note 3, “Asset Swap,” for additional information.

Operating Expenses

Fuel:Fuel expense represents the cost of coal, natural gas, oil, lime and other materials consumed in the generation of power, emission allowances and fuel handling and residual disposal costs. Fuel expense was as follows:


	Three Months Ended
	March 31,

(In millions)	2007		2006
Fuel	$	60.4	$	45.1

Total fuel increased by $15.3 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to a $15.0 million increase in coal expense resulting from an increase in the average price of coal of $3.35 per ton and a 0.3 million-ton increase in the amount of coal burned.

Purchased Power and Transmission:Purchased power and transmission was as follows:


	Three Months Ended
	March 31,
(In millions)	2007		2006
Purchased power and transmission	$	28.6	$	20.4

Purchased power and transmission increased $8.2 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to:

	•		a $16.3 million increase from the transfer of Monongahela’s PURPA contracts to the Generation and Marketing segment from the Delivery and Services segment and

	•		a $3.0 million increase in capacity purchased from AGC due to Monongahela’s increased ownership interest in AGC as a result of the January 1, 2007 Asset Swap,

	•		partially offset by an $11.6 million decrease in affiliated purchased power due to the termination of an AE Supply contract as part of the January 1, 2007 Asset Swap as described above in “Operating Revenues.”

See Note 3, “Asset Swap,” for additional information


	Three Months Ended
	March 31,
(In millions)	2007		2006
Operations and maintenance	$	30.7	$	16.2

Operations and maintenance expenses increased $14.5 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to:

	•		a $7.6 million increase in contract work expense, primarily due to maintenance performed during a scheduled outage at Fort Martin Unit No. 1 in the three months ended March 31, 2007, partially offset by maintenance outages at the Harrison generation facility during the three months ended March 31, 2006 that did not recur during the three months ended March 31, 2007,

	•		a $3.0 million increase in salaries and wages expense, primarily due to the January 1, 2007 Asset Swap and a scheduled outage at Fort Martin Unit No. 1 and

	•		a $1.3 million increase in materials and supplies expense, primarily due to the change in Monongahela’s ownership of certain generation facilities as a result of the January 1, 2007 Asset Swap.

See Note 3, “Asset Swap,” for additional information.

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


	Three Months Ended
	March 31,
(In millions)	2007		2006
Depreciation and amortization	$	10.0	$	8.8

Depreciation and amortization increased $1.2 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily as a result of the change in Monongahela’s depreciable asset base due to the January 1, 2007 Asset Swap.

See Note 3, “Asset Swap,” for additional information.

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


	Three Months Ended
	March 31,
(In millions)	2007		2006
Taxes other than income taxes	$	7.0	$	5.9

Taxes other than income taxes increased $1.1 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to changes in property taxes and business and occupation tax as the result of the January 1, 2007 Asset Swap.

See Note 3, “Asset Swap,” for additional information.

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
	March 31,
(In millions)	2007		2006
Other income and expenses, net	$	3.7	$	2.2

Other income and expenses, net, increased $1.5 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006, primarily due to an increase in equity earnings from AGC as a result of the January 1, 2007 Asset Swap.

See Note 3, “Asset Swap,” for additional information.

Income Tax Expense

The effective tax rate for the three months ended March 31, 2007 was 45.4% and was higher than income tax expense calculated at the federal statutory tax rate, primarily due to state income taxes and the allocation of consolidated tax savings.

The effective tax rate for the three months ended March 31, 2006 was 17.4% and was lower than income tax expense calculated at the federal statutory tax rate, primarily due to the allocation of consolidated tax savings.

ALLEGHENY GENERATING COMPANY—RESULTS OF OPERATIONS

Income Summary


	Three Months Ended
	March 31,
(In millions)	2007		2006
Operating revenues	$	16.9	$	17.3
Operating income	$	10.5	$	10.7
Income before income taxes	$	8.8	$	9.0
Net income	$	6.0	$	6.1

Allegheny Generating Company’s results of operations did not change significantly for the three months ended March 31, 2007 as compared to the three months ended March 31, 2006.

Income Tax Expense

The effective tax rates for the three months ended March 31, 2007 and March 31, 2006 were 31.6% and 31.7%, respectively. Income tax expense for the three months ended March 31, 2007 and the three months ended March 31, 2006 were lower than income tax expense calculated at 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—Allegheny

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

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

At March 31, 2007, Allegheny’s total borrowing capacity under AE and AE Supply’s revolving credit facilities and the use of this borrowing capacity were as follows:


	Total				LOC’s			Available
(In millions)	Capacity		Borrowed		Issued			Capacity
AE Revolving Credit Facility (a)	$	400.0	$	—	$	131.8	(b)	$	268.2
AE Supply Revolving Facility		200.0		—		—			200.0

Total	$	600.0	$	—	$	131.8		$	468.2


(a)		Allegheny has agreed to maintain $35 million of availability under AE’s revolving credit facility to stay enforcement of the judgment in its litigation against Merrill Lynch while an appeal is pending.

(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 and a letter of credit for $6.8 million issued due to an Allegheny Ventures contractual obligation that expires in July 2007. AE Supply also has a $2.5 million letter of credit outstanding that expires in February 2008, is collateralized by cash and was not issued under either AE’s revolving credit facility or AE Supply’s revolving credit facility.

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


	March 31, 2007				December 31, 2006
(In millions)	Amount		%		Amount		%
Debt	$	3,550.8		61.8	$	3,585.2		63.0
Common equity		2,177.0		37.8		2,080.4		36.6
Preferred equity		24.0		0.4		24.0		0.4

Total	$	5,751.8		100.0	$	5,689.6		100.0

Subsequent debt activity

5.52% and scheduled maturities ranging from July 2014 to July 2027. Net proceeds from the sale of the bonds represent restricted funds and will be used to fund the majority of costs to construct and install Scrubbers at Fort Martin.

Long-Term Debt and Contractual Obligations

See Note 5, “Debt,” for additional information and details regarding Allegheny’s debt. See also Item 8, Note 4, “Capitalization,” in the 2006 Annual Report on Form 10-K for additional details and discussion regarding debt covenants, refinancings and other debt issuances and repayments.

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, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in the 2006 Annual Report on Form 10-K for additional information.

Off-Balance Sheet Arrangements

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

Allegheny Cash Flows

Operating Activities

Allegheny’s cash flows from operating activities result primarily from the generation, sale and delivery of electricity. Future cash flows will be affected by the economy, weather, customer choice, future regulatory proceedings and future demand and market prices for energy, as well as Allegheny’s ability to produce and supply its customers with power at competitive prices. Cash flows from operating activities for the three months ended March 31, 2007 and 2006 are summarized as follows:


	Three Months Ended
	March 31,
(In millions)	2007			2006
Net income	$	109.7		$	113.4
Loss from discontinued operations, net of tax		—			0.8
Non-cash items included in earnings		150.5			140.9
Pension and other postretirement employee benefit contributions		(39.3	)		(62.5	)
Changes in certain assets and liabilities		(67.1	)		(81.1	)
Net cash used in operating activities of discontinued operations		—			(1.3	)

Net cash provided by operating activities	$	153.8		$	110.2

Significant cash outflows for the three months ended March 31, 2007 included $39.3 million in payments to Allegheny’s pension and other postretirement benefit plans, which decreased $23.2 million for the three months ended March 31, 2007 as compared to the three months ended March 31, 2006. Changes in certain assets and liabilities primarily consisted of a $44.5 million increase in accounts receivable, net, primarily due to the timing and volume of unbilled utility revenues and a $34.5 million increase in prepaid taxes, primarily as a result of timing differences associated with the payment of certain tax obligations.

Cash flows provided by operating activities for the three months ended March 31, 2006 consisted of net income of $113.4 million and discontinued operations and non-cash charges of $141.7 million, partially offset by $62.5 million in payments to Allegheny’s pension and other postretirement benefit plans, changes in certain assets and liabilities of $81.1 million and net cash used in operating activities of discontinued operations of $1.3 million. The changes in certain assets and liabilities for the three months ended March 31, 2006 resulted in a decrease in operating cash flows of $81.1 million, resulting from a $106.7 million decrease in accounts payable, primarily due to timing differences associated with the payment of certain obligations, partially

offset by a $55.4 million decrease in collateral deposits, primarily due to reduced collateral requirements with various counterparties to Allegheny’s power contracts.

Investing Activities

Cash flows from investing activities for the three months ended March 31, 2007 and 2006 are summarized as follows:


	Three Months Ended
	March 31,
(In millions)	2007			2006
Capital expenditures	$	(168.4	)	$	(94.8	)
Proceeds from sale of assets		0.3			—
Purchase of minority interest in Hunlock Creek Energy Ventures		—			(13.9	)
Decrease in restricted funds		1.3			5.3
Other investments		(1.0	)		(1.7	)

Net cash used in investing activities	$	(167.8	)	$	(105.1	)

Significant cash flows used in investing activities for the three months ended March 31, 2007 related to capital expenditures.

Significant cash flows used in investing activities for the three months ended March 31, 2006 included capital expenditures and the purchase of the minority interest in HCEV.

Financing Activities

Cash flows from financing activities for the three months ended March 31, 2007 and 2006 are summarized as follows:


	Three Months Ended
	March 31,
(In millions)	2007			2006
Repayment of long-term debt	$	(36.1	)	$	(51.8	)
Proceeds from the exercise of stock options		4.6			8.5
Deferred financing costs		—			(0.2	)
Cash dividends paid to minority shareholder in Hunlock Creek Energy Ventures		—			(0.4	)

Net cash used in financing activities	$	(31.5	)	$	(43.9	)

Significant cash flows used in financing activities for the three months ended March 31, 2007 included repayments of long-term debt, primarily related to repayments of a portion of the amounts outstanding under West Penn’s 2005 Transition Bonds and AE Supply’s Pollution Control Bonds, partially offset by proceeds from the exercise of stock options.

Significant cash flows used in financing activities for the three months ended March 31, 2006 included repayments of long-term debt, partially offset by proceeds from the exercise of stock options.

Monongahela Cash Flows

Operating Activities

Monongahela’s cash flows from operating activities result primarily from the generation, sale and delivery of electricity. Future cash flows will be affected by the economy, weather, customer choice, future regulatory proceedings, future demand and market prices for power. Cash flows from operating activities for the three months ending March 31, 2007 and 2006 are summarized as follows:


	Three Months Ended
	March 31,
(In millions)	2007			2006
Net income	$	7.0		$	21.7
Non-cash items included in earnings		11.5			22.6
Changes in certain assets and liabilities		(54.4	)		(10.5	)

Net cash provided by (used in) operating activities	$	(35.9	)	$	33.8

Operating cash flows for the three months ended March 31, 2007 included changes in certain assets and liabilities primarily consisting of a $28.3 million change in accrued taxes, primarily as a result of timing differences associated with the payment of certain tax obligations, a $24.4 million increase in collateral deposits, primarily due to the collateral requirements of various contracts and a $19.5 million decrease in accounts payable to affiliates, net, primarily due to timing differences associated with the payment of certain obligations. These amounts were partially offset by cash flows from operating activities primarily as a result of a $27.0 million increase in accounts payable due to the timing differences associated with the payment of certain obligations.

Operating cash flows for the three months ended March 31, 2006 included changes in certain assets and liabilities primarily consisting of a $16.6 million decrease in accounts payable to affiliates, net, a $15.3 million decrease in accounts payable, both due to the timing differences associated with the payment of certain obligations, and a $7.1 million change in accrued taxes, primarily as a result of timing differences associated with the payment of certain tax obligations. These amounts were partially offset by cash flows from operating activities primarily as a result of a $15.6 million decrease in accounts receivable, net, primarily due to the timing and volume of unbilled utility revenues, an $8.0 million decrease in collateral deposits, primarily due to the collateral requirements of various contracts and a $5.4 million change in accrued interest, primarily due to timing differences associated with the payment of certain interest obligations.

Investing Activities

Cash flows from investing activities for the three months ended March 31, 2007 and 2006 are summarized as follows:


	Three Months Ended
	March 31,
(In millions)	2007			2006
Capital expenditures	$	(39.0	)	$	(18.7	)
Notes receivable from affiliates		27.3			(45.4	)

Net cash used in investing activities	$	(11.7	)	$	(64.1	)

Significant cash flows used in investing activities for the three months ended March 31, 2007 were for capital expenditures, partially offset by cash provided by a decrease in a note receivable from affiliate.

Significant cash flows used in investing activities for the three months ended March 31, 2006 were for capital expenditures and an increase in a note receivable from affiliate.

Financing Activities

Cash flows from financing activities for the three months ended March 31, 2007 and 2006 are summarized as follows:


	Three Months Ended
	March 31,
(In millions)	2007			2006
Notes payable to affiliates	$	24.4		$	—
Repayment of long-term debt		(0.9	)		—
Intercompany tax sharing agreement benefit		3.4			—
Cash payment from AE Supply related to Asset Swap		1.1			—
Deferred financing costs		—			(0.1	)
Cash dividends paid on preferred stock		(0.3	)		(0.3	)
Cash dividends paid on common stock		—			(10.0	)

Net cash provided by (used in) financing activities	$	27.7		$	(10.4	)

Significant cash flows from financing activities for the three months ended March 31, 2007 related to an increase in notes payable to affiliates.

Significant cash flows used in financing activities for the three months ended March 31, 2006 related to cash dividends paid on preferred and common stock.

AGC Cash Flows

Operating Activities

AGC’s cash flows from operating activities primarily result from the sale of electricity. Future cash flows will be affected by the economy, weather, future demand and market prices for power. Cash flows from operating activities for the three months ended March 31, 2007 and 2006 are summarized as follows:


	Three Months Ended
	March 31,
(In millions)	2007			2006
Net income	$	6.0		$	6.1
Non-cash items included in earnings		2.3			2.6
Changes in certain assets and liabilities		(3.6	)		(0.8	)

Net cash provided by operating activities	$	4.7		$	7.9

Operating cash flows for the three months ended March 31, 2007 included changes in certain assets and liabilities primarily consisting of an $8.6 million change in accounts receivable from/payable to affiliates, net, a $1.5 million change in accounts payable and a $1.7 million change in interest accrued, each primarily as a result of timing differences associated with the payment of certain interest and other obligations. These amounts were partially offset by a $7.9 million change in taxes receivable/accrued, net as a result of timing differences associated with the payment of certain tax obligations.

Operating cash flows for the three months ended March 31, 2006 included changes in certain assets and liabilities primarily consisting of a $3.5 million change in accounts receivable from/payable to affiliates, net, a $2.7 million change in accounts payable, each primarily as a result of timing differences associated with the payment of certain obligations and a $1.7 million change in accrued interest primarily as a result of timing differences associated with the payment of certain interest obligations. These amounts were partially offset by a $6.9 million change in taxes receivable/accrued, net, primarily as a result of timing differences associated with the payment of certain tax obligations.

Investing Activities

Cash flows used in investing activities for the three months ended March 31, 2007 and 2006 were $1.1 million and $0.8 million, respectively, consisting of capital expenditures.

Financing Activities

Cash flows from financing activities for the three months ended March 31, 2007 and 2006 are summarized as follows:


	Three Months Ended
	March 31,
(In millions)	2007			2006
Intercompany tax sharing agreement benefit	$	1.3		$	—
Cash dividends paid on common stock		(5.0	)		(5.0	)

Net cash used in financing activities	$	(3.7	)	$	(5.0	)

Cash flows used in financing activities for the three months ended March 31, 2007 included $5.0 million of cash dividends paid on common stock partially offset by a $1.3 million intercompany tax sharing agreement benefit. Cash flows used in financing activities for the three months ended March 31, 2006 consisted of $5.0 million of cash dividends paid on common stock.

Credit Ratings

The following table lists Allegheny’s credit ratings, as of May 8, 2007:


	Moody’s	S & P	Fitch
Outlook	Stable (1)	Stable	Stable (2)
AE:
Corporate Credit Rating	Ba2⁽³⁾	BBB-	NR⁽⁵⁾
Senior Unsecured Debt	Ba2	BB+	BB+
Short-term Rating	SGL-2⁽⁴⁾	A-3	NR⁽⁵⁾
AE Supply:
Senior Secured Debt	Baa3	BBB	BBB-
Senior Unsecured Debt	Ba3	BB+	BB+
Pollution Control Bonds	NR⁽⁵⁾	NR⁽⁵⁾	AAA
Monongahela:
First Mortgage Bonds	Baa2	BBB	BBB+
Senior Unsecured Debt	Baa3	BB+	BBB-
Preferred Stock	Ba3	BB	BB+
Environmental Control Bonds	Aaa	AAA	AAA
Potomac Edison:
First Mortgage Bonds	Baa2	BBB	BBB+
Senior Unsecured Debt	Baa3	BB+	BBB-
Environmental Control Bonds	Aaa	AAA	AAA
West Penn:
Transition Bonds	Aaa	AAA	AAA
First Mortgage Bonds	Baa2	BBB	BBB+
Senior Unsecured Debt	Baa3	BBB-	BBB-
AGC:
Senior Unsecured Debt	Ba3	BBB-	BB+


(1)		Moody’s outlook for Potomac Edison is negative

(2)		Fitch’s outlook for Monongahela is negative

(3)		Corporate family rating for AE only, which excludes all of its subsidiaries

(4)		Liquidity rating

(5)		Not rated

OTHER MATTERS

Critical Accounting Policies

A summary of critical accounting policies is included under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for all of the registrants in the 2006 Annual Report on Form 10-K. The registrants’ critical accounting policies have not changed materially from those reported in the 2006 Annual Report on Form 10-K.

Recent Accounting Pronouncements

See Note 2, “Recent Accounting Pronouncements” in Allegheny’s and Monongahela’s Notes to Consolidated Financial Statements, included herein for a summary of significant recent accounting pronouncements issued or implemented during 2007 that relate to the registrants’ operations.

REGULATORY MATTERS

See, Item 1, “Regulatory Framework Affecting Allegheny” in the 2006 Annual Report on Form 10-K for a summary of regulatory matters.

Federal Legislation, Regulation and Rate Matters

Transmission Rate Design.Actions by the Federal Energy Regulatory Commission (“FERC”) with respect to the transmission rate design within PJM may impact the Distribution Companies. Beginning in July 2003, FERC issued a series of orders related to transmission rate design for the PJM and Midwest Independent Transmission System Operator regions. Specifically, FERC ordered the elimination of multiple and additive (i.e., “pancaked”) rates and called for the implementation of a long-term rate design for these regions. In November 2004, FERC rejected long-term regional rate proposals from the Distribution Companies and others. FERC concluded that neither the rate design proposals, nor the existing PJM rate design, had been shown to be just and reasonable. However, FERC ordered the continuation of the existing PJM rate design and the implementation of a transition charge for these regions through March 31, 2006 through filings made by transmission owners in both regions. In February 2005, FERC accepted these transition charges, effective December 1, 2004, subject to an evidentiary hearing. FERC’s February 2005 order remains subject to multiple rehearing requests and, potentially, appellate review. Allegheny cannot predict the outcome of these proceedings or whether they will have a material impact on its business or financial position.

During the now-expired transition period, the Distribution Companies were both payers and payees of transition charges. These charges resulted in the payment by the Distribution Companies of $13.7 million, and payments to the Distribution Companies of $4.8 million, for the 16-month period ended March 31, 2006. Following the evidentiary hearing, on August 10, 2006, an administrative law judge issued an initial decision that generally found fault with the methodologies used to develop the transition charges. That decision is now subject to review by FERC. The order that will be issued by FERC on review of the initial decision may require the Distribution Companies to refund some portion of the amounts received from these transition charges or entitle the Distribution Companies to receive additional revenue from these charges. In addition, the Distribution Companies may be required to pay additional amounts as a result of increases in the transition charges previously billed to them, or they may receive refunds of transition charges previously billed. Allegheny cannot predict the outcome of these proceedings. The Distribution Companies have entered into nine partial settlements with regard to the transition charges, and may enter into additional settlements in the future. FERC has approved two of these settlements, and approval is pending for the remaining partial settlements.

In a May 2005 order, FERC again determined that the existing PJM rate design may not be just and reasonable. On September 30, 2005, the Distribution Companies, together with another PJM transmission owner, filed a proposed rate design with FERC in Docket No. EL05-121-000 to replace the existing rate design within PJM, effective April 1, 2006. Two other PJM transmission owners also filed a separate proposed rate design. A hearing was held in April 2006 to determine whether the rate design is unjust and unreasonable and whether it should be replaced by either of the proposed rate designs. An initial decision was issued on July 13, 2006 by an administrative law judge, finding that the existing PJM rate design for existing transmission facilities is not just and reasonable. The administrative law judge found that the rate design for existing

transmission facilities proposed by Allegheny is just and reasonable, but ruled that the rate design proposed by FERC staff is also just and reasonable, is superior and should be made effective as of April 1, 2006. The initial decision also found that the Distribution Companies’ proposal for rate recovery for new transmission facilities had not demonstrated that the existing rate recovery mechanism for such facilities is unjust and unreasonable but adopted the Distribution Companies’ position that the implementation of a new rate design does not necessitate a change in the allocation of auction revenue rights and financial transmission rights. On April 19, 2007, FERC issued an Order on the initial decision that (a) retained the current license plate rate design for existing facilities, (b) requires that the parties develop a detailed “beneficiary pays” methodology for new facilities below 500 kV that would be set forth in the PJM tariff, and (c) allocates on a region-wide basis the costs of new, centrally-planned facilities that operate at or above 500 kV.

In August 2005, PJM filed at FERC to replace the current 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 capacity market to be unjust and unreasonable and set a process to resolve features of the RPM that must be analyzed further before it can determine whether the RPM is a just and reasonable capacity market process. FERC ordered the implementation of settlement procedures in this proceeding, and AE Supply and the Distribution Companies participated in a settlement agreement that was filed with the FERC on September 29, 2006. The settlement agreement would create a locational capacity market in PJM, in which PJM would procure needed capacity resources through auctions held three years in advance at prices and in quantities determined by an administratively established demand curve. Under the settlement agreement, capacity needs in PJM will be met either through purchases made in the proposed auctions or though commitments by load serving entities to self-supply their capacity needs. On December 22, 2006, FERC conditionally approved the settlement agreement, the implementation of which will begin with the 2007-2008 PJM planning year.

On July 3, 2006, PJM filed at FERC a proposal to implement a process for allocating long-term transmission rights (“LTTRs”). The PJM proposal would allocate a ten-year financial transmission right to PJM load serving entities (“LSEs”) based on the LSEs’ zonal base load. The PJM proposal created a link between PJM’s long-term transmission planning process and the LTTR allocation process to ensure that the transmission system is being upgraded as necessary to maintain the availability of the LTTRs that PJM will allocate. On November 22, 2006, FERC issued an Order accepting PJM’s proposal, subject to modifications. On January 22, 2007, PJM filed a related settlement agreement, as well as a proposal to allocate any costs to fund LTTRs fully to holders of financial transmission rights on a pro-rata basis. PJM recommended the creation of a new stakeholder process to determine whether this full funding mechanism should be changed subsequent to the 2007-2008 PJM planning year.

Transmission Expansion.On February 28, 2006, the Distribution Companies requested PJM to include in the PJM Regional Transmission Expansion Plan (“RTEP”) a proposal by the Distribution Companies to construct the Trans-Allegheny Interstate Line (“TrAIL”). PJM’s RTEP identifies transmission system upgrades and enhancements, through a region-wide planning effort, to provide for the operational, economic and reliability requirements of PJM customers and to determine the best way to integrate transmission with generation and load response projects to meet load-serving obligations. TrAIL, as originally proposed, was designed to increase the west-to-east energy transfer capability of the PJM Transmission System and 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 continues to consider as part of its 15-year RTEP process several transmission alternatives that may be constructed within the Distribution Companies’ PJM zone.

Concurrent with the submission of the TrAIL proposal to PJM, Allegheny and the Distribution Companies submitted a petition for declaratory order to FERC requesting four incentive rate treatments. Incentive rate treatments are intended to promote the construction of transmission facilities, such as the TrAIL proposal. Upon the PJM Board of Managers’ approval of the RTEP in June 2006, Allegheny requested FERC to authorize the incentive rate treatments with regard to the 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 transmission line. In October 2006, Allegheny designated TrAIL Company as the entity responsible for financing, constructing, owning, operating and maintaining TrAIL.

On February 21, 2007, TrAIL Company submitted to FERC a filing under Section 205 of the FPA to implement a formula tariff rate with a proposed effective date of June 1, 2007 that includes the incentive rate treatments approved by FERC. On February 22, 2007, TrAIL Company submitted to FERC an application under Section 204 of the FPA requesting authorizations to issue equity and debt securities to finance the TrAIL project. TrAIL Company requested FERC to act on this application by April 23, 2007. FERC action on both of these filings is pending. On February 27, 2007, TrAIL Company submitted an application to PJM for membership as a transmission owner and its membership was approved effective as of March 28, 2007.

On March 6, 2006, the Distribution Companies filed a request with the DOE requesting an early designation for the route of TrAIL as a National Interest Electric Transmission Corridor pursuant to the Energy Policy Act. On August 8, 2006, the DOE published a congestion study in which the general area of the TrAIL Project was classified as a “critical congestion area” that merits further federal attention. In that study, the DOE requested comment by October 10, 2006 as to whether the designation of corridors in relation to the areas identified as congested in the study would be appropriate and in the public interest and, if so, how the geographic boundaries for those corridors should be established. The Distribution Companies submitted comments supporting the designation of a corridor for the Mid-Atlantic area necessary for the construction of the TrAIL project. On April 26, 2007, the DOE issued a draft designation for the Mid-Atlantic corridor that includes the area where TrAIL is proposed to be sited. The DOE will not issue an official designation until after a 60-day comment period.

During 2006, PJM submitted to FERC three filings providing for the cost allocation of RTEP projects among PJM transmission zones. The filings include allocations for several projects to be constructed by the Distribution Companies or by TrAIL Company. The allocations for the TrAIL Project have been protested by several intervenors. The April 19, 2007 order issued by FERC discussed above with regard to transmission rate design will effect the final resolution for these cost allocations by requiring (a) the parties to develop a detailed “beneficiary pays” methodology for new facilities below 500 kV that would be set forth in the PJM tariff, and (b) PJM to allocate on a region-wide basis the costs of new, centrally-planned facilities that operate at or above 500 kV.

On April 18, 2007, PJM released a study indicating that new 765 kV transmission lines and related facilities linking the existing Amos substation owned by American Electric Power (AEP) near St. Albans, WV, to a new substation near Kemptown, Maryland, previously proposed by Allegheny, is the preferred solution for ensuring long-term reliability of the PJM region’s transmission system. Concurrently with the release of the PJM study, Allegheny and AEP signed a memorandum of understanding to form a joint venture company to build and own the new 765 kV transmission lines and related facilities. The joint venture will build and own approximately 250 miles of the lines from the Amos station to the Maryland border. An additional estimated 40 miles of 765 kV lines from the Maryland border to the Kemptown substation will be developed and owned by an Allegheny affiliate. The proposed project is estimated to cost approximately $1.8 billion, some of which will be owned by the joint venture, with other portions owned by the respective companies. Allegheny estimates its total investment in the project will exceed $1 billion. Once the project has been included in the next PJM RTEP, the joint venture will seek regulatory recovery consistent with FERC’s declaratory orders issued on July 20, 2006 for TrAIL and AEP’s Interstate 765 Project.

State Legislation, Regulation and Rate Matters

Pennsylvania

Transmission Expansion.On April 13, 2007, TrAIL Company filed an application with the Pennsylvania PUC for authorization to construct the TrAIL project in Pennsylvania. The application requests issuance of an order by April 13, 2008.

West Virginia

Transmission Expansion.On March 30, 2007, TrAIL Company filed an application with the West Virginia PSC for authorization to construct the TrAIL project in West Virginia. The application requests issuance of an order by December 31, 2007.

Rate Case.On July 26, 2006, Monongahela and Potomac Edison filed with the West Virginia PSC a request to raise their West Virginia retail rates by approximately $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 $26.2 million decrease in base rates. The rate increase request is subject to approval by the West Virginia PSC. On August 22, 2006, the West Virginia PSC issued an Order suspending Monongahela’s and Potomac Edison’s proposed new rates until May 23, 2007 and establishing a procedural schedule for the proceeding. Consistent with the procedural schedule, Monongahela and Potomac Edison filed direct testimony in support of the rate request on September 8, 2006. On January 22, 2007, intervenors in the proceeding filed testimony. On February 5, 2007, Monongahela and Potomac Edison filed rebuttal testimony and intervenors filed cross-rebuttal testimony. Evidentiary hearings in the proceeding took place between February 12 and 16, 2007. Following the evidentiary hearings, the parties, including Monongahela and Potomac Edison, filed initial briefs on March 22, 2007 and reply briefs on April 5, 2007. A West Virginia PSC order is expected prior to the May 23, 2007 end of the suspension period. The new rates resulting from this proceeding will be effective on May 23, 2007.

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

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

On October 3, 2006, Monongahela and Potomac Edison filed with the West Virginia PSC a Petition to Reopen Proceedings and to Amend Financing Order (“Petition”), informing the West Virginia PSC that the current estimate for constructing the Scrubbers at Fort Martin had increased from $338 million to an amount up to $550 million. The Petition requested that the West Virginia PSC reopen the Financing Order proceedings for the purposes of amending the Financing Order to increase the securitization financing authority for construction related costs to an amount up to $550 million and reduce the maximum amount of upfront financing costs (exclusive of costs for the West Virginia PSC’s financial advisor) that may be recovered from environmental control bond proceeds from $27 million to $23 million. In addition, Monongahela and Potomac Edison indicated in the Petition that a complete review and value engineering process was being performed on the Fort Martin Scrubbers project and that a supplement to the Petition updating and further refining the current project cost estimate would be submitted to the West Virginia PSC within 45 days. On November 13, 2006, Allegheny filed a Supplement to the Petition with the West Virginia PSC that detailed the construction cost estimate of $550 million.

On December 18, 2006, Allegheny reached a settlement agreement with all parties in the reopened cases and filed the agreement with the West Virginia PSC. The settlement agreement requested that the West Virginia PSC authorize Allegheny to securitize up to $450 million of the estimated construction costs, plus $16.5 million of upfront financing costs and certain other costs. The agreement also requested that Allegheny be permitted to recover a return on actual construction costs exceeding the $450 million during the period prior to placing the project into commercial service and permits Allegheny to file for recovery of any costs exceeding the $450 million once the Scrubber is in commercial service. On January 17, 2007, the West Virginia PSC approved the settlement agreement.

On April 11, 2007, Allegheny completed the sale of $459.3 million in environmental control bonds.

Maryland

Rate Stabilization.In special session, the Maryland legislature passed emergency legislation on June 23, 2006, reconstituting the Maryland Public Service Commission (the “Maryland PSC”), 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 and Electric Company to move from capped rates to market-based default service rates. For Allegheny, the legislation requires the Commission to investigate options available to implement a rate mitigation or rate stabilization plan, including the renegotiation of a settlement agreement to allow a portion of the residential electric supply in Allegheny’s Maryland service territory to be procured at market rates earlier than otherwise provided in its settlement agreement, so that residential electricity rates are not exposed to volatile market conditions at one time, while ensuring that customers obtain the full value of the savings provided under the existing generation rate cap.

On December 29, 2006, Allegheny filed its proposed Rate Stabilization Ramp-Up Transition Plan with the Maryland PSC, which is designed to transition residential customers from capped generation rates to rates based on market prices. Under the plan as originally proposed, residential customers would pay a distribution surcharge beginning in early 2007. The application of the surcharge would result in an overall rate increase of approximately 15% annually from 2007 through 2010. With the expiration of the residential generation rate caps and the move to generation rates based on market prices on January 1, 2009, the surcharge would convert to a credit on customers’ bills. Funds collected through the surcharge during 2007 and 2008, plus interest, would be returned to customers as a credit on their electric bills, thereby reducing the effect of the rate cap expiration. The credit would continue, with adjustments, to maintain rate stability until December 31, 2010 or until all monies collected from customers plus interest are returned. On January 31, 2007, after a series of public hearings on the Ramp-Up Transition Plan, Allegheny filed supplemental testimony setting forth an alternative to its original proposal. The alternative proposal would allow customers the ability to opt out of participating in the plan and contains other adjustments to address points raised in the public hearings. On February 2, 2007, all 21 members of the western Maryland delegation to the Maryland legislature sent a letter to the Maryland PSC publicly endorsing Allegheny’s alternative plan and urging its prompt approval by the Maryland PSC. The Maryland PSC held an evidentiary hearing on the proposed plan on March 15, 2007 and on March 30 issued an order approving the plan with the opt-out and refund procedures largely as agreed to by the Company. The plan will become operational in June 2007.

Virginia

Transmission Expansion.On April 19, 2007, TrAIL Company filed an application with the Virginia SCC for authorization to construct the TrAIL project in Virginia. The application requests issuance of an order by April 18, 2008.

During the 2007 session, the Virginia General Assembly amended the Virginia Electric Utility Restructuring Act of 1999 (the “Restructuring Act”), to re-regulate the provision of electric generation services in the Commonwealth beginning January 1, 2009. Until that time Potomac Edison’s retail electric customers in Virginia have the right to choose their electricity generation supplier. Until December 31, 2008, Potomac Edison is the PLR for those customers who do not choose an alternate generation supplier or whose alternate generation supplier does not deliver. After January 1, 2009 Potomac Edison will provide generation services to all customers in Virginia at regulated rates Potomac Edison has a power purchase agreement with AE Supply to provide it with the amount of electricity necessary to meet its PLR retail obligations through June 30, 2007 at capped generation rates. Beginning July 1, 2007, Potomac Edison will purchase its PLR requirements from the wholesale market at market prices. Market prices for purchased power at that time may be higher than the rates Potomac Edison will be allowed to recover from its retail customers.

Specifically, Allegheny believes that, based on amendments to the Restructuring Act in 2001 and 2004, the generation rates that Potomac Edison will be able to charge its Virginia customers beginning on July 1, 2007 will be based on its cost of purchased power. However, based on a memorandum of understanding (“MOU”) between the Virginia State Corporation Commission (the “Virginia SCC”) and Potomac Edison entered into at the time of the transfer of Potomac Edison’s generation facilities to AE Supply in 2000, the Virginia SCC may find that the generation rates Potomac Edison is able to charge for a certain portion of the power it purchases, currently estimated to be approximately 2.2 million MWhs per year,

would be limited to a price based upon a calculation of the cost to generate that power from the generation facilities that Potomac Edison previously owned. For the remainder of its power purchases, which Potomac Edison currently estimates to be approximately 1.1 million MWhs per year, Potomac Edison is permitted to petition the Virginia SCC to recover from its Virginia customers the market price of such MWhs beginning July 1, 2007. Thus, there can be no assurance that Potomac Edison will be able to recover any or all of the cost of power purchases in excess of the capped generation rates that it is currently permitted to charge its Virginia customers. The inability to recover such costs may have a material adverse effect on Potomac Edison’s business, results of operations and financial condition.

On April 12, 2007, Potomac Edison filed an Application with the Virginia SCC to establish a fuel factor and increase retail rates on average by 49.1% on July 1, 2007 to recover Potomac Edison’s estimated costs for purchased power to serve the Virginia retail load. In the Application, Potomac Edison also proposed a transition plan that would limit the average increase on July 1, 2007 to 20% and defer, with interest, amounts above 20% for collection over the subsequent three years.

Potomac Edison’s T&D rates in Virginia are presently capped through 2008, subject to certain exceptions. Prior to 2010, Potomac Edison has two opportunities to petition the Virginia SCC for changes to its T&D rates: the first prior to June 30, 2007, and the second after July 1, 2007. Furthermore, the Restructuring Act requires the Virginia SCC to adjust Potomac Edison’s capped T&D rates not more than once annually for the timely recovery of costs prudently incurred after July 1, 2004 for T&D system reliability or to comply with state or federal environmental laws or regulations. During the first six months of 2009, the Commission will initiate a proceeding to review the rates, terms and conditions for Potomac Edison’s provision of generation, distribution and transmission services in the Commonwealth.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

As reported in the 2006 Annual Report on Form 10-K, Allegheny uses various methods to measure their exposure to market risk on a daily basis, including a value at risk model (“VaR”). Allegheny calculates VaR using the full term of all remaining positions being marked-to-market. This calculation is based upon management’s best estimates and modeling assumptions, which could materially differ from actual results. As of March 30, 2007 and December 29, 2006, this calculation yielded a VaR of $3,000 and $8,000, respectively. This VaR decrease is primarily due to a decrease in forward positions of the portfolio.

ITEM 4. CONTROLS AND PROCEDURES

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

Disclosure Controls and Procedures.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 material information relating to each registrant (a) is accumulated and made known to the registrant’s management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure and (b) is recorded, processed, summarized and reported within the time periods specified in SEC’s rules and forms.

Changes in Internal Control Over Financial Reporting. Effective January 1, 2007, AE implemented a series of SAP enterprise resource planning (“ERP”) modules, including a new general ledger and chart of accounts and new consolidation, reporting, payroll, accounts payable/receivable, work management, and purchasing and materials management tools. The introduction of these ERP modules and the related workflow capabilities resulted in changes to AE’s financial reporting controls and procedures, with such changes identified during the implementation of the ERP modules. Therefore, as appropriate, AE is modifying the design and documentation of internal control process and procedures relating to the new system to supplement and complement existing internal controls over financial reporting. The system changes were undertaken to integrate systems and consolidate information, and were not undertaken in response to any actual or perceived deficiencies in AE’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Note 20, “Commitments and Contingencies,” for AE for information about legal proceedings. In addition, the registrants from time to time are involved in litigation and other legal disputes in the ordinary course of business.

ITEM 1A. RISK FACTORS

There have been no material changes to the risk factors disclosed in Item 1A of Part 1 of the 2006 Annual Report on Form 10-K.

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

No matters were submitted to a vote of security holders of AE or Monongahela during the first quarter of 2007.

At the annual meeting of AGC’s shareholders held on February 21, 2007, votes were taken for the election of directors. The total number of votes cast was 1,000, with all votes being cast for the election of Paul J. Evanson, David M. Feinberg and Philip L. Goulding.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

EXHIBIT INDEX

Allegheny Energy, Inc.


		Documents
10.1*		Alliance Agreement for Engineering, Construction and Project Management for the Trans-Allegheny Interstate Line Project, dated February 28, 2007, by and between Trans-Allegheny Interstate Line Company and Kenny Construction Company

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

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

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

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


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

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

100

SIGNATURE

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


		ALLEGHENY ENERGY, INC.

Date: May 8, 2007	By:	/s/ Philip L. Goulding

		Philip L. Goulding
		Senior Vice President and
		Chief Financial Officer

		MONONGAHELA POWER COMPANY

Date: May 8, 2007	By:	/s/ Philip L. Goulding

		Philip L. Goulding
		Vice President and
		Principal Financial Officer

		ALLEGHENY GENERATING COMPANY.

Date: May 8, 2007	By:	/s/ Philip L. Goulding

		Philip L. Goulding
		Vice President and
		Principal Financial Officer

101

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Avg

Note No.

Page No.

Basis of Presentation

Commitments and Contingencies