Allegheny Energy 10Q 2007 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2007


	Name of Registrant
	State of Incorporation
	Address of Principal
Commission	Executive	IRS Employer
File Number	Offices and Telephone Number	Identification Number
1-267	ALLEGHENY ENERGY, INC.	13-5531602
	(A Maryland Corporation)
	800 Cabin Hill Drive
	Greensburg, Pennsylvania 15601
	Telephone (724) 837-3000

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Act).


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

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


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

Number of shares outstanding of each class of common stock as of July 31, 2007:


Allegheny Energy, Inc.	166,072,015	($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		31
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		103
Item 4. Controls and Procedures		104

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		105
Item 1A. Risk Factors		105
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		106
Item 3. Defaults Upon Senior Securities		106
Item 4. Submission of Matters to a Vote of Security Holders		107
Item 5. Other Information		108
Item 6. Exhibits		109
Signatures		112
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 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		Monongahela, Potomac Edison and West Penn, which collectively 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						Six Months Ended
	June 30,						June 30,
(In thousands, except per share data)	2007			2006			2007			2006
Operating revenues	$	826,482		$	722,235		$	1,674,107		$	1,567,881

Operating expenses:
Fuel		231,330			191,765			463,555			410,452
Purchased power and transmission		106,407			95,097			199,673			196,329
Gain on sale of OVEC power agreement and shares		—			(1,124	)		—			(6,124	)
Deferred energy costs, net		(8,245	)		413			(9,700	)		5,406
Operations and maintenance		190,514			200,291			351,058			356,674
Depreciation and amortization		70,726			68,169			142,707			136,011
Taxes other than income taxes		48,868			52,201			104,758			105,868

Total operating expenses		639,600			606,812			1,252,051			1,204,616


Operating income		186,882			115,423			422,056			363,265

Other income and expenses, net		6,905			10,258			12,767			17,929

Interest expense and preferred dividends:
Interest expense		62,919			76,425			122,155			143,813
Preferred dividends of subsidiary		293			293			586			586

Total interest expense and preferred dividends		63,212			76,718			122,741			144,399

Income from continuing operations before income taxes and minority interest		130,575			48,963			312,082			236,795

Income tax expense		52,878			16,741			124,256			89,245

Minority interest in net income of subsidiaries		653			191			1,040			1,369

Income from continuing operations		77,044			32,031			186,786			146,181

Loss from discontinued operations, net of tax (Note 11)		—			(898	)		—			(1,664	)

Net income	$	77,044		$	31,133		$	186,786		$	144,517


Common share data:
Weighted average common shares outstanding:
Basic		165,794			163,526			165,645			163,304
Diluted		169,469			168,608			169,326			168,557

Basic income (loss) per common share:
Income from continuing operations	$	0.46		$	0.20		$	1.13		$	0.89
Loss from discontinued operations, net of tax		—			(0.01	)		—			(0.01	)

Net income per common share	$	0.46		$	0.19		$	1.13		$	0.88

Diluted income (loss) per common share:
Income from continuing operations	$	0.45		$	0.19		$	1.10		$	0.87
Loss from discontinued operations, net of tax		—			(0.01	)		—			(0.01	)

Net income per common share	$	0.45		$	0.18		$	1.10		$	0.86

See accompanying Notes to Consolidated Financial Statements.

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


	Six Months Ended
	June 30,
(In thousands)	2007			2006
Cash Flows From Operating Activities:
Net income	$	186,786		$	144,517
Loss from discontinued operations, net of tax		—			1,664
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		142,707			136,011
Amortization of debt issuance costs		5,051			16,171
Amortization of power sale liability related to Ohio sale		(10,500	)		(15,500	)
Amortization of liability for adverse power purchase commitment		(8,644	)		(8,577	)
Amortization of Pennsylvania stranded cost recovery asset		8,833			7,468
Loss (gain) on asset sales and disposals		15			(1,023	)
Minority interest in net income of subsidiaries		1,040			1,369
Deferred income taxes and investment tax credit, net		123,319			89,628
Deferred energy costs, net		(9,700	)		5,405
Stock-based compensation expense		5,559			7,928
Unrealized gains on commodity contracts, net		(1,607	)		(18,301	)
Pension and other postretirement employee benefit plan expense		18,115			21,193
Pension and other postretirement employee benefit plan contributions		(42,174	)		(65,381	)
Deferred revenue – Fort Martin scrubber project		8,005			—
Other, net		2,421			10,161

Changes in certain assets and liabilities:
Accounts receivable, net		(54,017	)		46,303
Materials, supplies and fuel		(7,983	)		(23,558	)
Prepaid taxes		(7,361	)		(7,596	)
Collateral deposits		(203	)		94,895
Prepayments		(1,161	)		272
Other current assets		8,137			(108	)
Accounts payable		40,430			(111,169	)
Accrued taxes		(12,324	)		(16,054	)
Accrued interest		8,142			5,429
Other current liabilities		(2,521	)		1,841
Other assets		1,366			8,615
Deferred income taxes		(12,190	)		(7,002	)
Other liabilities		5,368			(3,647	)
Net cash used in operating activities of discontinued operations		—			(2,138	)

Net cash provided by operating activities		394,909			318,816


Cash Flows From Investing Activities:
Capital expenditures		(351,259	)		(196,757	)
Proceeds from sale of assets		268			2,081
Purchase of minority interest in Hunlock Creek Energy Ventures		—			(13,900	)
Decrease (increase) in restricted funds		(417,871	)		7,282
Other investments		(1,259	)		(1,701	)
Net cash provided by investing activities of discontinued operations		—			27,401

Net cash used in investing activities		(770,121	)		(175,594	)


Cash Flows From Financing Activities:
Issuance of long-term debt		451,189			1,142,076
Repayment of long-term debt		(56,404	)		(1,352,056	)
Payments on capital lease obligations		(2	)		(29	)
Exercise of stock options		9,044			10,244
Cash dividends paid to minority shareholder in Hunlock Creek Energy Ventures		—			(400	)

Net cash provided by (used in) financing activities		403,827			(200,165	)


Net increase (decrease) in cash and cash equivalents		28,615			(56,943	)
Cash and cash equivalents at beginning of period		114,138			262,212

Cash and cash equivalents at end of period	$	142,753		$	205,269

Supplemental Cash Flow Information:
Cash paid for interest (net of amount capitalized)	$	108,850		$	126,549

See accompanying Notes to Consolidated Financial Statements.

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


	June 30,			December 31,
(In thousands)	2007			2006
ASSETS
Current Assets:
Cash and cash equivalents	$	142,753		$	114,138
Accounts receivable:
Customer		194,414			167,792
Unbilled utility revenue		101,632			117,977
Wholesale and other		99,267			63,894
Allowance for uncollectible accounts		(14,139	)		(14,591	)
Materials and supplies		101,478			96,117
Fuel		77,573			74,951
Deferred income taxes		125,432			127,531
Prepaid taxes		51,964			44,603
Collateral deposits		52,465			39,399
Commodity contracts		6,054			1,430
Restricted funds		19,527			12,923
Regulatory assets		49,442			39,128
Other		19,341			24,130

Total current assets		1,027,203			909,422

Property, Plant and Equipment, Net:
Generation		5,858,768			5,820,278
Transmission		1,060,809			1,056,759
Distribution		3,674,609			3,597,405
Other		457,944			412,894
Accumulated depreciation		(4,759,201	)		(4,636,972	)

Subtotal		6,292,929			6,250,364
Construction work in progress		420,540			262,529

Total property, plant and equipment, net		6,713,469			6,512,893

Investments and Other Assets:
Restricted funds – Fort Martin scrubber project		411,267			—
Goodwill		367,287			367,287
Investments in unconsolidated affiliates		27,868			28,259
Other		13,464			27,932

Total investments and other assets		819,886			423,478

Deferred Charges:
Regulatory assets		732,135			674,095
Other		40,650			32,558

Total deferred charges		772,785			706,653

Total Assets	$	9,333,343		$	8,552,446

See accompanying Notes to Consolidated Financial Statements.

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


	June 30,			December 31,
(In thousands, except share amounts)	2007			2006
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Long-term debt due within one year (Note 5)	$	201,410		$	201,189
Accounts payable		288,143			236,706
Accrued taxes		103,139			136,216
Commodity contracts		5,936			5,984
Accrued interest		107,996			99,854
Other		127,752			140,830

Total current liabilities		834,376			820,779


Long-term Debt (Note 5)		3,790,080			3,383,986

Deferred Credits and Other Liabilities:
Commodity contracts		15,924			17,982
Income taxes payable		59,903			—
Investment tax credit		71,146			72,938
Deferred income taxes		1,058,246			936,911
Obligations under capital leases		29,536			26,007
Regulatory liabilities		449,194			464,092
Adverse power purchase commitment		158,368			166,937
Other		525,619			547,706

Total deferred credits and other liabilities		2,367,936			2,232,573


Commitments and Contingencies (Note 16)

Minority Interest		11,753			10,713

Preferred Stock of Subsidiary		24,000			24,000

Common Stockholders’ Equity:
Common stock—$1.25 par value per share, 260 million shares authorized and 166,117,768 and 165,409,908 shares issued at June 30, 2007 and December 31, 2006, respectively		207,647			206,762
Other paid-in capital		1,905,441			1,907,879
Retained earnings		243,762			74,698
Treasury stock at cost; 49,493 shares		(1,756	)		(1,756	)
Accumulated other comprehensive loss		(49,896	)		(107,188	)

Total common stockholders’ equity		2,305,198			2,080,395

Total Liabilities and Stockholders’ Equity	$	9,333,343		$	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		—		—		—			186,786			—			—			186,786
Adoption of FIN 48		—		—		—			(17,722	)		—			—			(17,722	)
Pension and other postretirement employee benefit amortization, net of tax of $1,140		—		—		—			—			—			1,801			1,801
Unrealized losses on available-for-sale securities, net of tax of $1		—		—		—			—			—			(1	)		(1	)
Unrealized gains on cash flow hedges for the period, net of tax of $2,022		—		—		—			—			—			3,186			3,186
Stock-based compensation expense:
Stock units		—		—		1,510			—			—			—			1,510
Non-employee stock awards		13,800		17		666			—			—			—			683
Stock options		—		—		3,365			—			—			—			3,365
Exercise of stock options		378,053		473		8,572			—			—			—			9,045
Conversion of stock units		316,007		395		(8,245	)		—			—			—			(7,850	)
Effects of West Virginia Rate Order:
Establishment of regulatory asset related to pension obligation, net of tax of $35,663		—		—		—			—			—			52,306			52,306
Adjustment related to 2005 SO₂ allowance sale, net of tax of $5,777		—		—		(8,306	)		—			—			—			(8,306	)

Balance at June 30, 2007		166,068,275	$	207,647	$	1,905,441		$	243,762		$	(1,756	)	$	(49,896	)	$	2,305,198

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	Rates and Regulation	16

7	Regulatory Assets and Liabilities	18

8	Stock-Based Compensation	18

9	Pension Benefits and Postretirement Benefits Other Than Pensions	20

10	Derivative Instruments and Hedging Activities	22

11	Discontinued Operations	22

12	Business Segments	23

13	Comprehensive Income	23

14	Income (Loss) Per Share	24

15	Other Income and Expenses, Net	25

16	Commitments and Contingencies	25

17	Subsequent Event	30

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

NOTE 1: BASIS OF PRESENTATION

Business Description

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

The Delivery and Services segment primarily consists of Allegheny’s regulated utility subsidiaries. These subsidiaries include Monongahela Power Company (“Monongahela”), excluding its generation operations, The Potomac Edison Company (“Potomac Edison”) and West Penn Power Company (“West Penn”) (collectively, the “Distribution Companies”). The Distribution Companies primarily operate electric transmission and distribution (“T&D”) systems in Pennsylvania, West Virginia, Maryland and Virginia. The Distribution Companies are subject to federal and state regulation. The Delivery and Services segment also includes Allegheny Ventures, Inc. (“Allegheny Ventures”) 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” or “TrAIL”).

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

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

Financial Statement Presentation

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

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

During the fourth quarter of 2006, Allegheny changed its classification of fuel handling and residual disposal costs within its Consolidated Statements of Operations from “Operations and maintenance” expenses to “Fuel” 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 $5.6 million and $11.1 million for the three and six months ended June 30, 2006, respectively, to conform to the financial statement presentation for the current period.

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

Deferred Energy Costs, Net.See Item 8, Note 1, “Basis of Presentation,” in the 2006 Annual Report on Form 10-K for a description of Allegheny’s deferred energy accounting. See also Note 6, “Rates and Regulation,” for the accounting resulting from a May 22, 2007 rate order that established an annual Expanded Net Energy Cost (“ENEC”) method of recovering net power and related costs in West Virginia.

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

Restricted Funds.As described in Note 5, “Debt,” in April 2007, MP Environmental Funding LLC and PE Environmental Funding LLC issued an aggregate $459 million of Senior Secured Sinking Fund Environmental Control Bonds, Series A. Net proceeds from the sale of the bonds represent non-current restricted funds and will be used to fund the majority of costs to construct and install flue-gas desulfurization equipment (“Scrubbers”) at the Fort Martin generation facility in West Virginia (“Fort Martin”).

NOTE 2: RECENT ACCOUNTING PRONOUNCEMENTS

In April 2007, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 39-1, Amendment of FASB Interpretation No. 39 (“FIN 39-1”). FIN 39-1 permits entities that are party to master netting arrangements to offset cash collateral receivables or payables that approximate fair values with net derivatives positions. FIN 39-1 is effective for Allegheny beginning on January 1, 2008. Management has not completed the process of determining the effect of FIN 39-1 on Allegheny’s financial statements. However, at this time, the adoption of FIN 39-1 is not expected to have a material impact on Allegheny’s consolidated results of operations or financial position.

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

In June 2006, the FASB issued 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 and May 2, 2007, respectively. See Note 4, “Income Taxes,” for additional information related to FIN 48 and its impact on Allegheny’s consolidated financial position.

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

In September 2006, the FASB issued Statement of Financial Accounting Standard (“SFAS”) No. 157, Fair Value Measurements (“SFAS No. 157”). SFAS No. 157 defines fair value and establishes a framework for measuring fair value when fair value is required for recognition or disclosure purposes under GAAP. The standard also expands disclosure about fair value measurement but does not require any new fair value measurements. SFAS No. 157 is effective for Allegheny beginning on January 1, 2008. Management has not completed the process of determining the effect of SFAS No. 157 on Allegheny’s financial statements. However, at this time, the adoption of SFAS 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 at fair value certain financial instruments and other items that are not currently required to be measured at fair value. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for Allegheny beginning on January 1, 2008. Management has not completed the process of determining the

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

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.

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 Fort Martin, which allowed Allegheny to finance the construction of Scrubbers at Fort Martin through the securitization of an environmental control charge that Monongahela and Potomac Edison impose on their retail customers in West Virginia. See Note 5, “Debt,” for additional information.

Supply and Monongahela, and has a greater ownership interest in the Harrison and Pleasants generation facilities in West Virginia. AE Supply also received contractual rights to generation from OVEC. The Asset Swap resulted in a net transfer of 660 MWs of generation capacity from AE Supply to Monongahela. Additionally, Monongahela assumed from AE Supply the contractual obligation to provide power to 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, on July 2, 2007, AE Supply paid approximately $16 million in the aggregate in connection with the redemption of certain pollution control bonds that, by their terms, had to be redeemed in advance of their scheduled maturities as a result of the change in ownership of Fort Martin.

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 generally 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 based on the technical merits of the position. Such tax positions should be measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts.

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

Unrecognized tax benefits were approximately $113.6 million and $107.6 million at June 30, 2007 and January 1, 2007, respectively. If recognized, the portion of these amounts that would reduce Allegheny’s effective tax rate was $41.7 million and $38.7 million ($64.9 million and $58.9 million before the federal effects on state income tax positions), at June 30, 2007 and January 1, 2007, respectively.

The unrecognized tax benefit balance also included approximately $48.7 million of tax positions at June 30, 2007 and January 1, 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. Accrued interest, net of tax, related to uncertain tax positions was $12.9 million and $11.8 million at June 30, 2007 and January 1, 2007, respectively.

The total gross FIN 48 reserve at June 30, 2007 was $76.7 million (net of state tax benefits of $54.6 million). Approximately $59.9 million of this reserve will not be resolved in the next 12 months and has been classified as long term income taxes payable on the accompanying Consolidated Balance Sheet at June 30, 2007.

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 $10.9 million, net of tax, at June 30, 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 $0.9 million. Additionally, some of the state tax returns containing these positions are currently under audits that are likely to be resolved within the next 12 months. Should these audits be resolved in a favorable manner, they could result in benefits of up to $4.2 million.

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

NOTE 5: DEBT

In April 2007, MP Environmental Funding LLC, an indirect subsidiary of Monongahela, and PE Environmental Funding LLC, an indirect subsidiary of Potomac Edison, issued $344 million and $115 million, respectively, of Senior Secured Sinking Fund Environmental Control Bonds, Series A. These bonds securitize the right to collect an environmental control surcharge (“ECC”) 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 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.

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

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

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

	•		ECC revenues will be recorded as billed;

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

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

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

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


	Six Months Ended
	June 30, 2007
(In millions)	Issuances			Repayments
Monongahela:
Environmental Control Bonds	$	344.5		$	—
Pollution Control Bonds		—			1.0
Potomac Edison:
Environmental Control Bonds		114.8			—
West Penn:
Transition Bonds (a)		2.8			41.0
AE Supply:
Pollution Control Bonds		7.0			15.6

Eliminations (b)		(7.0	)		(1.2	)

Consolidated Total	$	462.1		$	56.4


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

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

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

Long-Term Debt

At June 30, 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
Environmental Control Bonds		—			15.0			10.5			11.1			11.6			296.3			344.5
Pollution Control Bonds		14.5			—			—			—			—			70.2			84.7

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


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

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


West Penn:
Transition Bonds	$	38.9		$	76.9		$	76.4		$	15.3		$	—		$	—		$	207.5
First Mortgage Bonds		—			—			—			—			—			145.0			145.0
Medium—Term Notes		—			—			—			—			—			80.0			80.0

Total West Penn	$	38.9		$	76.9		$	76.4		$	15.3		$	—		$	225.0		$	432.5


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

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


Unamortized debt discounts, premiums and terminated interest rate swaps		(0.6	)		(1.4	)		(1.4	)		(1.3	)		(1.0	)		(2.2	)		(7.9	)
Eliminations (a)		(4.1	)		—			—			—			—			(114.4	)		(118.5	)

Total consolidated debt	$	144.1		$	95.4		$	89.0		$	138.8		$	1,161.4		$	2,362.8		$	3,991.5


(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 are co-obligors.

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

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

NOTE 6: RATES AND REGULATION

West Virginia

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

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

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

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

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

Virginia

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

Potomac Edison had a power purchase agreement with AE Supply to provide it with the amount of electricity necessary to meet its PLR retail obligations through June 30, 2007 at capped generation rates. In April 2007, Potomac Edison conducted a competitive bidding process to purchase its PLR requirements from the wholesale market for service beginning July 1, 2007, and AE Supply was the successful bidder with respect to a substantial portion of those requirements. Market prices for purchased power resulting from

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

that bidding process, at which Potomac Edison began to purchase its PLR requirements on July 1, 2007, currently are higher, and likely will continue to be higher, than the rates Potomac Edison is currently allowed to recover from its retail customers.

Accordingly, in an April 2007 filing with the State Corporation Commission of Virginia (“Virginia SCC”), Potomac Edison requested to adjust its fuel factor and to implement a rate stabilization plan, including an increase in retail rates beginning July 1, 2007, to moderate the impact of increased purchased power costs. Additionally, Potomac Edison filed a Motion for Interim Rates with the Virginia SCC on May 10, 2007. In June 2007, the Virginia SCC issued an order that denied Potomac Edison’s application and motion to establish interim rates, cancelled evidentiary hearings and dismissed the case. On July 6, 2007, Potomac Edison filed with the Virginia SCC a Motion for Suspension of Order and Motion for Interim Rates, which the Virginia SCC failed to act upon within the time prescribed. On July 2, 2007, Potomac Edison filed an appeal of this decision to the Virginia Supreme Court and also asked the Virginia Supreme Court for relief pending appeal.

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

Maryland

In December 2006, Potomac Edison proposed a rate stabilization and market transition plan (the “Plan”) for its Maryland residential customers, in accordance with a bill passed by the Maryland legislature in 2006. The Maryland Public Service Commission approved the Plan effective June 7, 2007. The Plan provides for a gradual transition of Potomac Edison’s residential customers from capped generation rates to market-based generation rates, while at the same time preserving for customers the benefit of rate caps.

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

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

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

See Note 5, “Debt,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Regulatory Matters,” and “Risk Factors,” below and Item 8, Note 14, “Rates and Regulation” in the 2006 Annual Report on Form 10-K for additional information regarding certain rate and regulatory matters.

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

NOTE 7: 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 June 30, 2007 and December 31, 2006 relate to:


	June 30,		December 31,
(In millions)	2007		2006
Regulatory assets, including current portion:
Income taxes	$	298.3	$	300.4
Pension benefits and postretirement benefits other than pension		257.9		178.2
Pennsylvania stranded cost recovery		37.1		55.6
Pennsylvania Competitive Transition Charge (“CTC”) reconciliation		112.1		107.4
Unamortized loss on reacquired debt		37.4		39.6
Deferred ENEC charges		8.2		—
Other		30.6		32.0

Subtotal		781.6		713.2

Regulatory liabilities, including current portion:
Net asset removal costs		388.5		421.4
Income taxes		37.9		38.9
S0₂ allowances		14.0		—
Fort Martin scrubber project		8.0		—
Other		1.3		4.5

Subtotal		449.7		464.8

Net regulatory assets	$	331.9	$	248.4

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


	June 30,			December 31,
(In millions)	2007			2006
Property, plant and equipment	$	4,347.6		$	4,338.7
Amounts under construction included above	$	278.2		$	136.6
Accumulated depreciation	$	(1,981.5	)	$	(2,054.6	)

NOTE 8: 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, “Stock-Based Compensation,” in the 2006 Annual Report on Form 10-K. Allegheny records compensation expense for share-based payments to employees, including grants of employee stock options and stock units, over the requisite service period based on their estimated fair value on the date of grant.

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

The following table summarizes stock-based compensation expense:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Stock options	$	1.7	$	1.9	$	3.4	$	4.0
Stock units		0.7		1.5		1.5		3.3
Other		0.3		0.3		0.7		0.6

Stock-based compensation expense included in operations and maintenance expense		2.7		3.7		5.6		7.9
Income tax benefit		1.1		1.5		2.3		3.2

Total stock-based compensation expense, net of tax	$	1.6	$	2.2	$	3.3	$	4.7

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

Stock Options

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


						Aggregate
				Weighted-		Intrinsic
	Number of			Average		Value
	Stock Options			Exercise Price		(in millions)
Outstanding at March 31, 2007		4,465,606		$	16.198
Granted		14,000		$	54.544
Exercised		(214,248	)	$	20.835
Forfeited		(2,400	)	$	13.350

Outstanding at June 30, 2007		4,262,958		$	16.092	$	152.0

Exercisable at June 30, 2007		2,583,723		$	15.646	$	93.3

Stock option activity for the six months ended June 30, 2007 was as follows:


						Aggregate
				Weighted-		Intrinsic
	Number of			Average		Value
	Stock Options			Exercise Price		(in millions)
Outstanding at December 31, 2006		4,670,338		$	16.504
Granted		25,000		$	51.789
Exercised		(378,053	)	$	23.923
Forfeited		(54,327	)	$	13.388

Outstanding at June 30, 2007		4,262,958		$	16.092	$	152.0

Exercisable at June 30, 2007		2,583,723		$	15.646	$	93.3

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

Allegheny received cash from option exercises totaling $4.5 million and $9.0 million for the three and six months ended June 30, 2007, respectively. Allegheny issued new shares of its common stock to satisfy these stock option exercises.

As of June 30, 2007, there was approximately $13.2 million of unrecognized compensation cost related to non-vested outstanding stock options, which is expected to be recognized over a weighted-average period of approximately 1.6 years.

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

Stock Units

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


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

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

Outstanding at June 30, 2007		528,858

There were no stock units convertible at June 30, 2007.

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

As of June 30, 2007, there was $1.5 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 six months.

Non-Employee Director Stock Plan

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


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

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

Shares earned but not issued at June 30, 2007		64,693

NOTE 9: PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

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

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

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


	Pension Benefits
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2007			2006			2007			2006
Components of net periodic cost:
Service cost	$	5.3		$	5.5		$	10.7		$	10.9
Interest cost		16.2			15.3			32.3			30.7
Expected return on plan assets		(18.3	)		(17.4	)		(36.5	)		(34.8	)
Amortization of unrecognized transition obligation		0.1			0.1			0.2			0.2
Amortization of prior service cost		0.8			0.9			1.6			1.8
Recognized actuarial loss		2.7			3.1			5.3			6.2

Net periodic cost	$	6.8		$	7.5		$	13.6		$	15.0

Allocation of net periodic cost:
Monongahela	$	2.3		$	1.9		$	4.3		$	3.9
AE Supply		1.4			2.3			3.3			4.5
West Penn		1.7			1.9			3.4			3.7
Potomac Edison		1.3			1.3			2.5			2.7
AE		0.1			0.1			0.1			0.2

Net periodic cost	$	6.8		$	7.5		$	13.6		$	15.0


	Postretirement Benefits Other Than Pensions
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2007			2006			2007			2006
Components of net periodic cost:
Service cost	$	1.1		$	1.3		$	2.3		$	2.6
Interest cost		4.3			4.2			8.5			8.4
Expected return on plan assets		(1.7	)		(1.8	)		(3.4	)		(3.5	)
Amortization of unrecognized transition obligation		1.4			1.5			2.8			2.9
Recognized actuarial loss		0.6			1.0			1.2			1.9

Net periodic cost	$	5.7		$	6.2		$	11.4		$	12.3

Allocation of net periodic cost:
Monongahela	$	1.7		$	1.7		$	3.5		$	3.4
West Penn		1.6			1.7			3.1			3.4
Potomac Edison		1.3			1.3			2.6			2.6
AE Supply		1.1			1.5			2.2			2.8
AE		—			—			—			0.1

Net periodic cost	$	5.7		$	6.2		$	11.4		$	12.3

For the three months ended June 30, 2007 and 2006, Allegheny allocated net periodic cost of $3.8 million and $2.8 million, respectively, and, for the six months ended June 30, 2007 and 2006, Allegheny allocated net periodic cost of $7.0 million and $6.0 million, respectively, to “Construction work in progress,” a component of “Property, plant and equipment, net.”

Allegheny contributed $0.1 million and $35.6 million to its pension plans during the three and six months ended June 30, 2007, respectively, including contributions of $0.1 million and $0.1 million during the three and six months ended June 30, 2007, respectively, to the SERP. Allegheny also contributed $2.8 million and $6.5 million to fund its postretirement benefits plans other than pension plans during the three and six months ended June 30, 2007, respectively. 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 $12.0 million to $15.0 million to fund its postretirement benefits plans other than pension plans.

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

Allegheny made matching cash contributions to the Employee Stock Ownership and Savings Plan of $1.8 million and $4.2 million for the three and six months ended June 30, 2007, respectively.

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

NOTE 10: DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Allegheny has designated certain contracts as cash flow hedges of forecasted sales of electricity. Changes in the fair value of these contracts upon such designation and thereafter are reflected in “Accumulated other comprehensive loss” until the hedged item is realized. These contracts expire at various dates through December 2008. The pre-tax accumulated other comprehensive income for the contracts was $6.5 million at June 30, 2007 and $1.3 million at December 31, 2006. The increase in accumulated other comprehensive income related to cash flow hedges is a result of the change in the fair value of these contracts due to changes in market prices and settlements and additional cash flow hedge contracts. The entire accumulated other comprehensive income balance is expected to be completely recorded as an increase to earnings over the next eighteen months, with $6.5 million recorded as an increase to earnings over the next twelve months. Certain contracts have been de-designated as hedges during the second quarter as a result of entering into physical marketing contracts. The related other comprehensive income amount of $1.5 million will be recorded to income over the next quarter. The ineffective portion of cash flow hedges reflected in earnings was $0.3 million and $0.1 million for the three and six months ended June 30, 2007, respectively, and $0.3 million and $0.9 million for the three and six months ended June 30, 2006, respectively.

Derivative contracts that are not designated as cash flow hedges or normal purchase and normal sale contracts are accounted for on a mark-to-market basis with changes in fair value reflected in earnings. The recorded net fair value of mark-to-market and cash flow hedge derivative commodity contracts was a net liability of $15.8 million and $22.5 million at June 30, 2007 and December 31, 2006, respectively.

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2007			2006			2007			2006
Amounts included in operating revenues:
Net unrealized gains	$	(0.8	)	$	5.3		$	1.6		$	18.3
Net realized gains (losses)	$	2.8		$	(8.2	)	$	(1.1	)	$	(4.6	)

NOTE 11: DISCONTINUED OPERATIONS

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


	Three Months			Six Months
	Ended			Ended
(In millions)	June 30, 2006			June 30, 2006
Operating revenues	$	—		$	—
Operating expenses		(0.4	)		(0.8	)
Interest expense		(0.9	)		(1.8	)

Loss before income taxes		(1.3	)		(2.6	)
Income tax benefit		0.5			1.0
Impairment charge, net of tax		(0.1	)		(0.1	)

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

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

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

NOTE 12: BUSINESS SEGMENTS

Allegheny manages and evaluates its operations in two business segments, the Delivery and Services segment and the Generation and Marketing segment. Business segment information for Allegheny is summarized below. Significant transactions between reportable segments are shown as eliminations to reconcile the segment information to consolidated amounts. The majority of the eliminations relate to power sold by the Generation and Marketing segment to the Delivery and Services segment.


	Three Months Ended June 30, 2007									Three Months Ended June 30, 2006
	Delivery		Generation							Delivery		Generation
	and		and							and		and
(In millions)	Services		Marketing		Eliminations			Total		Services		Marketing			Eliminations			Total
External operating revenues	$	676.3	$	150.2	$	—		$	826.5	$	630.6	$	91.7		$	—		$	722.3
Internal operating revenues		2.2		375.1		(377.3	)		—		1.9		322.4			(324.3	)		—

Total operating revenues	$	678.5	$	525.3	$	(377.3	)	$	826.5	$	632.5	$	414.1		$	(324.3	)	$	722.3
Depreciation and amortization	$	41.1	$	29.6	$	—		$	70.7	$	37.9	$	30.3		$	—		$	68.2
Operating income	$	69.9	$	116.9	$	—		$	186.8	$	54.3	$	61.2		$	—		$	115.5
Interest expense	$	18.5	$	46.1	$	(1.6	)	$	63.0	$	22.1	$	55.3		$	(1.0	)	$	76.4
Income from continuing operations	$	33.4	$	43.6	$	—		$	77.0	$	23.3	$	8.7		$	—		$	32.0
Loss from discontinued operations, net of tax	$	—	$	—	$	—		$	—	$	—	$	(0.9	)	$	—		$	(0.9	)
Net income	$	33.4	$	43.6	$	—		$	77.0	$	23.3	$	7.8		$	—		$	31.1


	Six Months Ended June 30, 2007									Six Months Ended June 30, 2006
	Delivery		Generation							Delivery		Generation
	and		and							and		and
(In millions)	Services		Marketing		Eliminations			Total		Services		Marketing			Eliminations			Total
External operating revenues	$	1,431.1	$	243.0	$	—		$	1,674.1	$	1,331.4	$	236.5		$	—		$	1,567.9
Internal operating revenues		5.3		806.8		(812.1	)		—		3.7		684.7			(688.4	)		—

Total operating revenues	$	1,436.4	$	1,049.8	$	(812.1	)	$	1,674.1	$	1,335.1	$	921.2		$	(688.4	)	$	1,567.9
Depreciation and amortization	$	81.3	$	61.4	$	—		$	142.7	$	75.6	$	60.4		$	—		$	136.0
Operating income	$	166.5	$	255.5	$	—		$	422.0	$	146.4	$	216.9		$	—		$	363.3
Interest expense	$	36.9	$	88.1	$	(2.8	)	$	122.2	$	41.8	$	103.4		$	(1.4	)	$	143.8
Income from continuing operations	$	78.9	$	107.9	$	—		$	186.8	$	69.7	$	76.5		$	—		$	146.2
Loss from discontinued operations, net of tax	$	—	$	—	$	—		$	—	$	—	$	(1.7	)	$	—		$	(1.7	)
Net income	$	78.9	$	107.9	$	—		$	186.8	$	69.7	$	74.8		$	—		$	144.5

NOTE 13: COMPREHENSIVE INCOME

Comprehensive income consisted of the following:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Net income	$	77.0	$	31.1	$	186.8	$	144.5
Other comprehensive income:
Unrealized gains on cash flow hedges, net of tax		6.5		6.2		3.2		23.9
West Virginia Rate Order – establishment of regulatory asset related to pension obligation, net of tax		52.3		—		52.3		—
Pension and other postretirement employee benefit amortization, net of tax		0.2		—		1.8		—

Comprehensive income	$	136.0	$	37.3	$	244.1	$	168.4

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

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


	June 30,			December 31,
(In millions)	2007			2006
Cash flow hedges, net of tax	$	3.4		$	0.2
Net unrecognized pension and other postretirement benefit costs, net of tax		(53.3	)		(107.4	)

Total	$	(49.9	)	$	(107.2	)

NOTE 14: INCOME (LOSS) PER SHARE

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


	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In millions, except share amounts)	2007		2006			2007		2006
Basic Income (Loss) per Share:
Numerator:
Income from continuing operations, net of tax	$	77.0	$	32.0		$	186.8	$	146.2
Loss from discontinued operations, net of tax		—		(0.9	)		—		(1.7	)

Net income	$	77.0	$	31.1		$	186.8	$	144.5


Denominator:
Weighted average common shares outstanding		165,794,012		163,526,221			165,645,000		163,304,498


Basic Income (Loss) per Share:
Income from continuing operations, net of tax	$	0.46	$	0.20		$	1.13	$	0.89
Loss from discontinued operations, net of tax		—		(0.01	)		—		(0.01	)

Net income	$	0.46	$	0.19		$	1.13	$	0.88


Diluted Income (Loss) per Share:
Numerator:
Income from continuing operations, net of tax	$	77.0	$	32.0		$	186.8	$	146.2
Loss from discontinued operations, net of tax		—		(0.9	)		—		(1.7	)

Net income	$	77.0	$	31.1		$	186.8	$	144.5


Denominator:
Weighted average common shares outstanding		165,794,012		163,526,221			165,645,000		163,304,498
Effect of dilutive securities:
Stock options		2,784,081		2,599,683			2,752,745		2,582,517
Stock units		805,342		2,415,780			845,259		2,596,948
Non-employee stock awards		60,539		40,677			57,550		37,177
Performance shares		25,497		25,497			25,497		35,839

Total shares		169,469,471		168,607,858			169,326,051		168,556,979


Diluted Income (Loss) per Share:
Income from continuing operations, net of tax	$	0.45	$	0.19		$	1.10	$	0.87
Loss from discontinued operations, net of tax		—		(0.01	)		—		(0.01	)

Net income	$	0.45	$	0.18		$	1.10	$	0.86

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

NOTE 15: OTHER INCOME AND EXPENSES, NET

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Interest and dividend income	$	3.9	$	5.3	$	7.4	$	10.8
Tax reimbursement on contributions in aid of construction		1.7		1.6		2.8		3.1
Premium services		0.7		0.6		1.1		2.0
Coal brokering income		—		0.9		—		0.9
Gain on sale of land		—		0.8		—		0.8
Gain on sale of investments		—		0.3		—		0.3
Other		0.6		0.7		1.5		—

Total	$	6.9	$	10.2	$	12.8	$	17.9

NOTE 16: COMMITMENTS AND CONTINGENCIES

Environmental Matters and Litigation

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

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

	•		developing an accurate CO₂ emissions inventory;

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

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

	•		following developing technologies for carbon sequestration;

	•		participating in carbon dioxide sequestration efforts (e.g. reforestation projects) both domestically and abroad;

	•		analyzing options for future energy investment (e.g. renewables, clean-coal, etc.); and

	•		improving demand-side efficiency programs.

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

its customers. Allegheny’s management is following this issue closely and will take further appropriate action as the economics and legislation unfold.

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

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

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 in 2008. AE Supply has entered into construction contracts with The Babcock & Wilcox Company (“B&W”) and Washington Group International (“WGI”) in connection with its plans to install Scrubbers at its Hatfield’s Ferry generation facility. Monongahela has entered into construction contracts with B&W and WGI in connection with its plans to install Scrubbers at Fort Martin.

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

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

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

Additionally, Maryland passed the Healthy Air Act in early 2006. This legislation imposes state-wide emission caps on SO₂ and NOx, requires greater reductions in mercury emissions more quickly than required by CAMR and mandates that Maryland join the Regional Greenhouse Gas Initiative (“RGGI”) and participate in that coalition’s regional efforts to reduce CO₂ emission. On April 20, 2007, Maryland’s governor signed the RGGI, as a result of which, Maryland became the 10^th state to join the Northeast regional climate change and energy efficiency program. The Healthy Air Act does provide a conditional exemption for the R. Paul Smith power station, provided that PJM declares the station vital to reliability in the Baltimore/Washington DC metropolitan area. In

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

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.

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 New Source Review (“NSR”) standards of the Clean Air Act, which can require the installation of additional air pollution control equipment when the major modification of an existing facility results in an increase in emissions. AE has provided responsive information to this and a subsequent request.

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

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

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

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

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

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

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

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 $47.05 billion, assuming an exchange rate of 1.0435 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 $3.9 billion and US $958 million, respectively, assuming an exchange rate of 1.0435 Canadian dollars per US dollar) along with such other relief as the court deems just. Allegheny has not yet been served with this lawsuit, and the time for service of the original lawsuit has expired. Allegheny intends to vigorously defend against this action but cannot predict its outcome.

Global Warming Class Action:On April 9, 2006, AE, along with numerous other companies with coal-fired generation facilities and companies in other industries, was named as a defendant in a class action lawsuit in the United States District Court for the Southern District of Mississippi. On behalf of a purported class of residents and property owners in Mississippi who were harmed by hurricane Katrina, the named plaintiffs allege that the emission of greenhouse gases by the defendants contributed to global warming, thereby causing Hurricane Katrina and plaintiffs’ damages. The plaintiffs seek unspecified damages. On December 6, 2006, AE filed a motion to dismiss plaintiffs’ complaint on jurisdictional grounds and joined a motion filed by other defendants to dismiss the complaint for failure to state a claim. A hearing has been scheduled for August 30, 2007 on the motion to dismiss that AE joined. No hearing has been set on the other motion. AE intends to vigorously defend against this action but cannot predict its outcome.

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

Allegheny does not believe that the existence or pendency of either the asbestos suits or the actions involving its insurance will have a material impact on its consolidated financial position, results of operations or cash flows. Allegheny believes that it has recorded appropriate liabilities to cover existing and future asbestos claims. As of June 30, 2007, Allegheny had 829 open cases remaining in West Virginia, three open cases remaining in Pennsylvania and one open case in Illinois.

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, Nevada and other parties filed petitions for review of FERC’s June 26, 2003 order with the United States Court of Appeals for the Ninth Circuit (the “NPC Petitions”). The NPC Petitions

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

were consolidated in the Ninth Circuit. On 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. On May 3, 2007, AE Supply and others filed a petition to appeal the Ninth Circuit’s ruling to the United States Supreme Court, and the parties are awaiting a decision from the Supreme Court on whether the appeal will be heard.

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 United States 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 were 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 approved two settlements relating to the requested disallowance, and those proceedings have been closed. On May 9, 2007, AE, AE Supply and Merrill filed a motion to dismiss the previously settled lawsuit based on Sierra/Nevada’s failure to file an amended complaint by the court established deadline. Sierra/Nevada contested that motion and has filed a motion to file an amended complaint. At a July 30, 2007 hearing, the judge denied the motion to dismiss for failure to timely file an amended complaint, granted Sierra/Nevada leave to file an amended complaint, set a trial date for May 20, 2008 and stated that the court would address the motions to dismiss previously filed by AE and AE Supply that seek to have the case dismissed on its merits.

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

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

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

On September 24, 2002, certain Merrill Lynch entities filed a complaint against AE in the United States District Court for the Southern District of New York, alleging that AE breached the asset purchase agreement by failing to repurchase the equity interest in AE Supply from Merrill Lynch and seeking damages in excess of $125 million. On 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 District Court ordered that AE and AE Supply assert their claims against Merrill Lynch, which were initially brought in New York state court, as counterclaims in Merrill Lynch’s federal court action. As a result, AE and AE Supply

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

dismissed the New York state action and filed an answer and asserted affirmative defenses and counterclaims against Merrill Lynch in the District Court. The counterclaims, as amended, alleged that Merrill Lynch fraudulently induced AE and AE Supply to enter into the purchase agreement, that Merrill Lynch breached certain representations and warranties contained in the purchase agreement, that Merrill Lynch negligently misrepresented certain facts relating to the purchase agreement and that Merrill Lynch breached fiduciary duties owed to AE and AE Supply. The counterclaims sought damages in excess of $605 million, among other relief.

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 District 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 United States 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 the United States 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. AE entered into an agreement to settle the consolidated ERISA class actions, and the District Court approved the settlement on June 25, 2007. Under the settlement, the consolidated ERISA class actions were dismissed with prejudice against all defendants in exchange for a cash payment of $4 million, of which approximately $3.9 million was made by AE’s insurance carrier.

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 claimed that Allegheny improperly and arbitrarily rejected bids from third parties to supply coal to Allegheny from a mine owned by Harrison Fuel. Plaintiffs sought damages of approximately $13 million. The parties agreed to a global settlement on May 7, 2007, and the case has been dismissed with prejudice.

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

NOTE 17: SUBSEQUENT EVENT

On August 3, 2007, Monongahela issued a redemption notice to holders of all 90,000 shares of its 4.40% Cumulative Preferred Stock, $100 par value, all 40,000 shares of its 4.80% Cumulative Preferred Stock, Series B, $100 par value, all 60,000 shares of its 4.50% Cumulative Preferred Stock, Series C, $100 par value and all 50,000 shares of its $6.28 Cumulative Preferred Stock, Series D, $100 par value. Monongahela plans to redeem the outstanding cumulative preferred stock as of September 4, 2007. In connection with the redemption, Monongahela will pay accrued and unpaid dividends at the redemption date plus a redemption premium of approximately $1.1 million.

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In thousands)	2007			2006			2007			2006
Operating revenues	$	206,687		$	177,421		$	407,573		$	374,616
Operating expenses:
Fuel		62,597			41,753			123,044			86,890
Purchased power and transmission		44,120			42,696			82,854			83,832
Deferred energy costs, net		(6,460	)		(623	)		(6,793	)		(623	)
Operations and maintenance		55,457			47,980			110,266			88,395
Depreciation and amortization		15,742			16,354			33,553			32,720
Taxes other than income taxes		11,920			11,813			24,371			24,083

Total operating expenses		183,376			159,973			367,295			315,297

Operating income		23,311			17,448			40,278			59,319
Other income and expenses, net		3,955			4,179			7,856			7,837
Interest expense		12,922			10,583			21,451			21,311

Income before income taxes		14,344			11,044			26,683			45,845
Income tax expense		6,805			4,185			12,182			17,256

Net income	$	7,539		$	6,859		$	14,501		$	28,589

See accompanying Notes to Consolidated Financial Statements.

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


	Six Months Ended
	June 30,
(In thousands)	2007			2006
Cash Flows From Operating Activities:
Net income	$	14,501		$	28,589
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		33,553			32,720
Amortization of power sale liability related to Ohio sale		(10,500	)		(15,500	)
Amortization of liability for adverse power purchase commitment		1,133			—
Loss (gain) on asset sales		2			(72	)
Deferred income taxes and investment tax credit, net		11,813			15,965
Deferred energy costs, net		(6,793	)		(623	)
Deferred revenue – Fort Martin scrubber project		7,248			—
Other, net		792			3,658

Changes in certain assets and liabilities:
Accounts receivable, net		3,601			18,935
Materials, supplies and fuel		(1,685	)		(4,015	)
Taxes receivable/accrued, net		(37,202	)		(4,317	)
Prepaid taxes		4,353			6,592
Collateral deposits		(22,293	)		11,417
Prepayments		(851	)		245
Other current assets		(1,862	)		(494	)
Accounts payable		7,282			(8,812	)
Accounts payable to affiliates, net		(18,835	)		(2,038	)
Accrued interest		4,046			(81	)
Other current liabilities		(1,338	)		(6,368	)
Other assets		705			6,214
Unearned revenue – Potomac Edison purchased power		112,336			—
Other liabilities		(513	)		(5,291	)

Net cash provided by operating activities		99,493			76,724

Cash Flows From Investing Activities:
Capital expenditures		(86,121	)		(40,963	)
Proceeds from asset sales		—			129
Notes receivable from affiliates		27,337			(60,756	)
Increase in restricted funds		(417,199	)		—

Net cash used in investing activities		(475,983	)		(101,590	)

Cash Flows From Financing Activities:
Notes payable to affiliates		17,504			—
Issuance of long-term debt		338,753			(135	)
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		(586	)		(586	)
Common stock		(2,999	)		(10,015	)

Net cash provided by (used in) financing activities		356,267			(10,736	)

Net decrease in cash and cash equivalents		(20,223	)		(35,602	)
Cash and cash equivalents at beginning of period		22,283			136,491

Cash and cash equivalents at end of period	$	2,060		$	100,889

Supplemental Cash Flow Information:
Cash paid for interest (net of amount capitalized)	$	15,726		$	19,440

See accompanying Notes to Consolidated Financial Statements.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(unaudited)


	June 30,			December 31,
(In thousands)	2007			2006
ASSETS
Current Assets:
Cash and cash equivalents	$	2,060		$	22,283
Accounts receivable:
Customer		43,486			38,007
Unbilled utility revenue		28,229			33,952
Wholesale and other		9,255			12,341
Allowance for uncollectible accounts		(1,651	)		(2,095	)
Note receivable from affiliate		—			27,337
Materials and supplies		19,009			15,695
Fuel		19,878			17,557
Prepaid taxes		15,761			20,114
Collateral deposits		24,447			—
Restricted funds		5,932			—
Regulatory assets		12,610			6,417
Other		33,842			8,638

Total current assets		212,858			200,246

Property, Plant and Equipment, Net:
Generation		1,119,004			967,486
Transmission		294,750			283,497
Distribution		986,616			968,377
Other		77,391			74,762
Accumulated depreciation		(1,087,061	)		(936,098	)

Subtotal		1,390,700			1,358,024
Construction work in progress		68,879			38,114

Total property, plant and equipment, net		1,459,579			1,396,138

Investments and Other Assets:
Restricted funds – Fort Martin scrubber project		411,267			—
Investment in AGC		70,626			46,765
Other		6			2,437

Total investments and other assets		481,899			49,202

Deferred Charges:
Regulatory assets		86,132			88,940
Other		14,526			9,791

Total deferred charges		100,658			98,731

Total Assets	$	2,254,994		$	1,744,317

See accompanying Notes to Consolidated Financial Statements.

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


	June 30,		December 31,
(In thousands, except share data)	2007		2006
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Long-term debt due within one year (Note 5)	$	23,937	$	15,500
Accounts payable		46,822		35,844
Accounts payable to affiliates, net		43,418		62,853
Accrued taxes		23,269		37,836
Accrued interest		11,739		7,693
Ohio power commitment		—		10,500
Note payable to affiliate		17,504		—
Other		20,399		19,558

Total current liabilities		187,088		189,784


Long-term Debt (Note 5)		854,264		519,145

Deferred Credits and Other Liabilities:
Non-current affiliated income taxes payable		46,048		45,671
Deferred income taxes		226,036		213,987
Obligations under capital leases		9,305		7,353
Regulatory liabilities		225,725		239,120
Unearned revenue – Potomac Edison purchased power		112,336		—
Other		36,593		32,598

Total deferred credits and other liabilities		656,043		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 June 30, 2007 and December 31, 2006		294,550		294,550
Other paid-in capital		91,248		41,468
Retained earnings		147,800		136,639
Accumulated other comprehensive income		1		2

Total common stockholder’s equity		533,599		472,659

Total Liabilities and Stockholder’s Equity	$	2,254,994	$	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		—		—		—			14,501			—			14,501
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		—		—		482			—			—			482
Pollution control bond retirement		—		—		150			—			—			150
Dividends declared on preferred stock		—		—		—			(586	)		—			(586	)
Dividends declared on common stock		—		—		—			(2,999	)		—			(2,999	)
Other comprehensive income		—		—		—			—			(1	)		(1	)
Adjustment related to 2005 SO₂ allowance sale, net of tax of $5,777 in accordance with the West Virginia Rate Order		—		—		(8,306	)		—			—			(8,306	)

Balance at June 30, 2007		5,891,000	$	294,550	$	91,248		$	147,800		$	1		$	533,599

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		37

	2	Recent Accounting Pronouncements		38

	3	Asset Swap		39

	4	Income Taxes		40

	5	Debt		41

	6	Rates and Regulation		42

	7	Regulatory Assets and Liabilities		43

	8	Pension Benefits and Postretirement Benefits Other Than Pensions		43

	9	Business Segments		44

	10	Other Income and Expenses, Net		44

	11	Commitments and Contingencies		45

	12	Subsequent Event		48

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

NOTE 1: BASIS OF PRESENTATION

Business Description

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 transmission and distribution (“T&D”) operations.

Monongahela owned approximately 41% and 23% of Allegheny Generating Company (“AGC”) at June 30, 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 (the “West Virginia PSC”) 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.

Financial Statement Presentation

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 the fourth quarter of 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 $1.2 million and $2.3 million for the three and six months ended June 30, 2006, respectively, to conform to the financial statement presentation for the current period.

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

Deferred Energy Costs, Net.See Item 8, Note 1, “Basis of Presentation,” in the 2006 Annual Report on Form 10-K for a description of Monongahela’s deferred energy accounting. See also Note 6, “Rates and Regulation,” for the accounting resulting from a May 22, 2007 rate order that established an annual Expanded Net Energy Cost (“ENEC”) method of recovering net power and related costs in West Virginia.

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

NOTE 2: RECENT ACCOUNTING PRONOUNCEMENTS

In June 2006, the Emerging Issues Task Force (“EITF”) reached a consensus on Issue No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (“EITF 06-3”). EITF 06-3 provides guidance on disclosing the accounting policy for the income statement presentation of any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer on either a gross (included in revenues and costs) or a net (excluded from revenues and costs) basis. 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. Monongahela records 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 that 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 Financial Accounting Standards Board (“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 and May 2, 2007, respectively. See Note 4, “Income Taxes,” for additional information related to FIN 48 and its impact on Monongahela’s consolidated financial position.

On September 8, 2006, the FASB issued FSP AUG AIR-1, Accounting for Planned Major Maintenance Activities (the “FSP”). The FSP permits the following methods for accounting for planned major maintenance activities: direct expense, built-in overhaul and deferral. The FSP requires entities to disclose the method of accounting for planned major maintenance activities, as well as the impact of any change in method required as a result of the adoption of the FSP. The FSP prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities. Monongahela 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 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 beginning on 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.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure at fair value certain financial instruments and other items that are not currently required to be measured at fair value. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for Monongahela beginning on 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.

MONONGAHELA POWER COMPANY 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. After the Asset Swap, Monongahela owns 100% of Fort Martin, which allowed Allegheny to finance the construction of 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 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. See Note 5, “Debt,” for additional information.

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:


	June 30, 2007							December 31, 2006
Generation facility				Plant		Accumulated					Plant		Accumulated
(Dollars in millions)	Ownership			Investment		Depreciation		Ownership			Investment		Depreciation
Albright		100.0	%	$	119.1	$	91.4		57.5	%	$	68.7	$	46.5
Fort Martin		100.0	%	$	477.2	$	266.6		19.1	%	$	71.0	$	49.1
Harrison		20.5	%	$	289.0	$	166.3		21.3	%	$	297.0	$	168.1
Hatfield’s Ferry		—	%	$	—	$	—		23.4	%	$	154.5	$	60.3
Pleasants		7.7	%	$	90.2	$	51.8		21.3	%	$	249.4	$	140.0
Rivesville		100.0	%	$	57.5	$	44.5		85.1	%	$	48.9	$	36.9
Willow Island		100.0	%	$	106.4	$	72.5		85.1	%	$	90.6	$	59.6

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 June 30, 2007 and December 31, 2006, respectively. The following table shows AGC’s utility plant investment and accumulated depreciation in the Bath County generation facility:


	June 30, 2007							December 31, 2006
Generation facility				Plant		Accumulated					Plant		Accumulated
(Dollars in millions)	Ownership			Investment		Depreciation		Ownership			Investment		Depreciation
Bath County		40	%	$	836.7	$	322.4		40	%	$	835.6	$	318.1

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

NOTE 4: 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 generally 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.

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

Unrecognized tax benefits were approximately $17.8 million and $17.6 million at June 30, 2007 and January 1, 2007, respectively. If recognized, the portion of these amounts that would reduce Monongahela’s effective tax rate was $0.5 million and $0.3 million at June 30, 2007 and January 1, 2007, respectively.

The unrecognized tax benefit balance also included approximately $17.3 million of tax positions at June 30, 2007 and January 1, 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. Accrued interest, net of tax, related to uncertain tax positions was $2.3 million and $2.2 million at June 30, 2007 and January 1, 2007, respectively.

The major jurisdictions in which Monongahela is subject to income tax are U.S. Federal, Pennsylvania, West Virginia and Virginia. Monongahela is part of Allegheny’s consolidated federal income tax returns. 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 Allegheny’s consolidated West Virginia return. 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 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 $2.8 million, net of tax, at June 30, 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.

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

NOTE 5: DEBT

Potomac Edison utilized its net cash proceeds from the Senior Secured Sinking Fund Environmental Control Bonds to purchase prepaid power to be obtained from Monongahela. Monongahela recognized a liability in the form of unearned revenue representing its obligation to provide power to Potomac Edison. Monongahela will use its net proceeds from the bonds together with the cash from Potomac Edison to construct Scrubbers at Fort Martin.

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

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

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

	•		ECC revenues will be recorded as billed;

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

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

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

Long-Term Debt

At June 30, 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
Environmental Control Bonds		—		15.0		10.5		11.1		11.6		296.3		344.5
Pollution Control Bonds		14.5		—		—		—		—		70.2		84.7

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

At June 30, 2007, substantially all of Monongahela’s properties were held subject to liens of various relative priorities securing debt obligations.

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

NOTE 6: RATES AND REGULATION

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

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

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

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

	•		The West Virginia Rate Order provides for the recovery of pension expense on an accrual basis. Monongahela and Potomac Edison previously recovered pension costs on a cash basis in West Virginia, and, therefore, Allegheny did not record a regulatory asset related to the portion of pension obligations allocable to the West Virginia jurisdiction when it adopted SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106 and 132R (“SFAS No. 158”) on December 31, 2006. As a result of the West Virginia Rate Order, in the second quarter of 2007, Allegheny’s service subsidiary, AESC, established a regulatory asset related to Monongahela’s pension obligations recorded upon adoption of SFAS No. 158, in the amount of approximately $75 million, with a corresponding credit to “Other comprehensive income,” net of income tax effect.

See Note 5, “Debt,” Management’s Discussion and Analysis of Financial Condition and Results of Operations – “Regulatory Matters,” below and Item 8, Note 11, “Rates and Regulation,” in the 2006 Annual Report on Form 10-K for additional information regarding certain rate and regulatory matters.

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

NOTE 7: 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:


	June 30,		December 31,
(In millions)	2007		2006
Regulatory assets, including current portion:
Income taxes	$	70.3	$	72.0
Unamortized loss on reacquired debt		13.4		14.2
Deferred ENEC charges		8.2		—
Other		6.8		9.1

Subtotal		98.7		95.3


Regulatory liabilities, including current portion:
Non-legal asset removal costs		205.0		239.1
SO₂ Allowances		14.0		—
Fort Martin scrubber project		7.2		—

Subtotal		226.2		239.1

Net regulatory liabilities	$	127.5	$	143.8

NOTE 8: PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Pension benefits	$	2.3	$	1.9	$	4.3	$	3.9
Postretirement benefits other than pension benefits	$	1.7	$	1.7	$	3.5	$	3.4

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

NOTE 9: 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 June 30, 2007									Three months ended June 30, 2006
	Delivery		Generation							Delivery		Generation
	and		and							and		and
(In millions)	Services		Marketing		Eliminations			Total		Services		Marketing			Eliminations			Total
External operating revenues	$	160.8	$	45.9	$	—		$	206.7	$	156.7	$	20.7		$	—		$	177.4
Internal operating revenues		—		94.0		(94.0	)		—		—		69.6			(69.6	)		—

Total operating revenues	$	160.8	$	139.9	$	(94.0	)	$	206.7	$	156.7	$	90.3		$	(69.6	)	$	177.4
Depreciation and amortization	$	8.1	$	7.6	$	—		$	15.7	$	7.5	$	8.8		$	—		$	16.3
Operating income (loss)	$	18.0	$	5.3	$	—		$	23.3	$	19.5	$	(2.1	)	$	—		$	17.4
Interest expense	$	4.8	$	8.1	$	—		$	12.9	$	6.0	$	4.5		$	—		$	10.5
Net income (loss)	$	7.4	$	0.1	$	—		$	7.5	$	8.6	$	(1.7	)	$	—		$	6.9


	Six months ended June 30, 2007										Six months ended June 30, 2006
	Delivery		Generation								Delivery		Generation
	and		and								and		and
(In millions)	Services		Marketing			Eliminations			Total		Services		Marketing		Eliminations			Total
External operating revenues	$	341.9	$	65.7		$	—		$	407.6	$	330.8	$	43.8	$	—		$	374.6
Internal operating revenues		—		191.5			(191.5	)		—		—		147.6		(147.6	)		—

Total operating revenues	$	341.9	$	257.2		$	(191.5	)	$	407.6	$	330.8	$	191.4	$	(147.6	)	$	374.6
Depreciation and amortization	$	15.9	$	17.6		$	—		$	33.5	$	15.1	$	17.6	$	—		$	32.7
Operating income (loss)	$	54.4	$	(14.1	)	$	—		$	40.3	$	56.7	$	2.6	$	—		$	59.3
Interest expense	$	9.5	$	12.0		$	—		$	21.5	$	12.2	$	9.1	$	—		$	21.3
Net income (loss)	$	25.1	$	(10.6	)	$	—		$	14.5	$	28.4	$	0.2	$	—		$	28.6

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					Six Months Ended
	June 30,					June 30,
(In millions)	2007			2006		2007			2006
Equity in earnings of AGC	$	3.2		$	1.6	$	6.2		$	3.0
Interest income		0.4			2.1		1.1			4.1
Premium services		(0.1	)		0.2		(0.4	)		0.4
Other		0.5			0.2		1.0			0.3

Total	$	4.0		$	4.1	$	7.9		$	7.8

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

NOTE 11: COMMITMENTS AND CONTINGENCIES

Environmental Matters and Litigation

	•		developing an accurate CO₂ emissions inventory;

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

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

	•		following developing technologies for carbon sequestration;

	•		participating in carbon dioxide sequestration efforts (e.g. reforestation projects) both domestically and abroad;

	•		analyzing options for future energy investment (e.g. renewables, clean-coal, etc.); and

	•		improving demand-side efficiency programs.

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

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

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 in 2008. AE Supply has entered into construction contracts with The Babcock & Wilcox Company (“B&W”) and Washington Group International (“WGI”) in connection with its plans to install Scrubbers at its Hatfield’s Ferry generation facility. Monongahela has entered into construction contracts with B&W and WGI in connection with its plans to install Scrubbers at Fort Martin.

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

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

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					Six Months Ended
	June 30,					June 30,
(In thousands)	2007		2006			2007		2006
Operating revenues	$	17,082	$	13,901		$	33,993	$	31,239
Operating expenses:
Operations and maintenance		1,236		1,055			2,600		2,562
Depreciation		4,322		4,290			8,617		8,575
Taxes other than income taxes		794		798			1,588		1,597

Total operating expenses		6,352		6,143			12,805		12,734

Operating income		10,730		7,758			21,188		18,505
Other income and expenses, net		106		701			176		746
Interest expense		1,791		1,790			3,562		3,598


Income before income taxes		9,045		6,669			17,802		15,653
Income tax expense (benefit)		2,833		(77	)		5,597		2,772

Net income	$	6,212	$	6,746		$	12,205	$	12,881

See accompanying Notes to Financial Statements.

ALLEGHENY GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(unaudited)


	Six Months Ended
	June 30,
(In thousands)	2007			2006
Cash Flows From Operating Activities:
Net income	$	12,205		$	12,881
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		8,617			8,575
Deferred income taxes and investment tax credit, net		(3,461	)		(3,526	)
Other, net		144			143

Changes in certain assets and liabilities:
Materials and supplies		(26	)		(107	)
Taxes receivable/accrued, net		2,078			2,853
Prepayments		253			157
Other current assets		(29	)		(507	)
Accounts payable		(890	)		(2,685	)
Accrued interest		(19	)		—
Accounts payable to affiliates, net		(1,520	)		471
Other current liabilities		332			234
Deferred income taxes		—			(3,162	)
Other liabilities		—			1

Net cash provided by operating activities		17,684			15,328


Cash Flows From Investing Activities:
Capital expenditures		(2,662	)		(1,367	)


Cash Flows From Financing Activities:
Intercompany tax sharing agreement benefit		1,348			—
Cash dividends paid on common stock		(13,000	)		(13,000	)

Net cash used in financing activities		(11,652	)		(13,000	)

Net increase in cash and cash equivalents		3,370			961
Cash and cash equivalents at beginning of period		2,846			1,858

Cash and cash equivalents at end of period	$	6,216		$	2,819

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

See accompanying Notes to Financial Statements.

ALLEGHENY GENERATING COMPANY
BALANCE SHEETS
(unaudited)


	June 30,			December 31,
(In thousands)	2007			2006
ASSETS
Current Assets:
Cash and cash equivalents	$	6,216		$	2,846
Materials and supplies		1,746			1,720
Taxes receivable		—			762
Other		136			360

Total current assets		8,098			5,688

Property, Plant and Equipment, Net:
Generation		782,280			777,507
Transmission		51,443			55,169
Other		2,943			2,949
Accumulated depreciation		(322,422	)		(318,164	)

Subtotal		514,244			517,461
Construction work in progress		3,665			6,963

Total property, plant and equipment, net		517,909			524,424

Deferred Charges:
Regulatory assets		7,669			7,842
Other		89			92

Total deferred charges		7,758			7,934

Total Assets	$	533,765		$	538,046

See accompanying Notes to Financial Statements.

ALLEGHENY GENERATING COMPANY
BALANCE SHEETS (continued)
(unaudited)


	June 30,		December 31,
(In thousands, except share data)	2007		2006
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	1,296	$	2,746
Accounts payable to affiliates, net		4,112		5,632
Accrued interest		2,273		2,292
Accrued taxes		1,316		—
Other current liabilities		332		—

Total current liabilities		9,329		10,670


Long-term Debt		99,474		99,458

Deferred Credits and Other Liabilities:
Investment tax credit		35,293		35,953
Non-current affiliated income taxes payable		17,544		17,544
Deferred income taxes		146,358		148,824
Regulatory liabilities		21,634		22,018

Total deferred credits and other liabilities		220,829		224,339


Commitments and Contingencies (Note 2)

Stockholders’ Equity:
Common stock, $1.00 par value, 5,000 shares authorized and 1,000 shares outstanding at June 30, 2007 and December 31, 2006		1		1
Other paid-in capital		174,017		172,669
Retained earnings		30,115		30,909

Total stockholders’ equity		204,133		203,579

Total Liabilities and Stockholders’ Equity	$	533,765	$	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 share data)	outstanding		stock		capital		earnings			equity
Balance at December 31, 2006		1,000	$	1	$	172,669	$	30,909		$	203,579
Net income		—		—		—		12,205			12,205
Intercompany tax sharing agreement benefit		—		—		1,348		—			1,348
Dividends declared on common stock		—		—		—		(13,000	)		(13,000	)
Other		—		—		—		1			1

Balance at June 30, 2007		1,000	$	1	$	174,017	$	30,115		$	204,133

See accompanying Notes to Financial Statements.

ALLEGHENY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
(unaudited)


Note No.		Page No.
1	Basis of Presentation	55

2	Commitments and Contingencies	56

ALLEGHENY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
(unaudited)

NOTE 1: BASIS OF PRESENTATION

Business Description

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 June 30, 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.

Financial Statement Presentation

The accompanying unaudited interim financial statements of AGC 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.

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 Income Taxes

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 generally 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 Financial Accounting Standards Board “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 and May 2, 2007, respectively. The 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: COMMITMENTS AND CONTINGENCIES

Environmental Matters and Litigation

Other Litigation

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

ITEM 2.

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

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

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

Overview

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

Key Indicators and Performance Factors

The Delivery and Services Segment

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

Revenue per MWh sold. This measure is calculated by dividing total revenues from retail sales of electricity by total MWhs sold to retail customers. Revenue per MWh sold during the three and six months ended June 30, 2007 and 2006 was as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2007		2006		2007		2006
Revenue per MWh sold	$	59.29	$	58.06	$	59.93	$	58.66

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 following table provides retail electricity sales information.


	Three Months Ended							Six Months Ended
	June 30,							June 30,
	2007		2006		Change			2007		2006		Change
Delivery and Services:
Retail electricity sales (million kWhs)		10,666		10,049		6.1	%		22,377		21,231		5.4	%
HDD (a)		599		530		13.0	%		3,375		2,956		14.2	%
CDD (a)		276		172		60.5	%		278		172		61.6	%


(a)		Heating degree-days (“HDD” ) and cooling degree-days (“CDD”).The operations of the Distribution Companies are weather sensitive. Weather conditions directly influence the volume of electricity delivered by the Distribution Companies representing one of several factors that impact the volume of electricity delivered. Accordingly, deviations in weather from normal levels can affect Allegheny’s financial performance. HDD and CDD are most likely to impact the usage of Allegheny’s residential and commercial customers. Industrial customers are less weather sensitive. Degree-day data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit, and CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one cooling degree-day, and each degree of temperature below 65° Fahrenheit is counted as one heating degree-day. Normal (historical) HDDs are 656 and 3,497 for the three and six months ended June 30, respectively and normal (historical) CDDs are 205 and 206 for the three and six months ended June 30, respectively, calculated on a weighted-average basis across the geographic areas served by the Distribution Companies.

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

The Generation and Marketing Segment

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

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

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

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

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

The following table shows kWhs generated, excluding kWhs consumed by pumping at the Bath County, Virginia hydroelectric station, EAFs and Station O&M related to the Generation and Marketing segment:


	Three Months Ended									Six Months Ended
	June 30,									June 30,
	2007			2006			Change			2007			2006			Change
Supercritical Units:
kWhs generated (in millions)		9,311			9,185			1.4	%		20,060			19,734			1.7	%
EAF		79.4	%		77.8	%		1.6	%		84.5	%		84.5	%		—	%
Station O&M (in millions):
Base operations (a)	$	31.4		$	23.4			34.2	%	$	56.5		$	46.0			22.8	%
Special		29.9			34.4			(13.1	)%		40.3			42.5			(5.2	)%

Total Station O&M	$	61.3		$	57.8			6.1	%	$	96.8		$	88.5			9.4	%

All Generation Units:
kWhs generated (in millions)		11,759			11,234			4.7	%		24,851			24,251			2.5	%
EAF		82.0	%		83.4	%		(1.4	)%		85.5	%		87.3	%		(1.8	)%
Station O&M (in millions):
Base operations (a)	$	47.1		$	40.6			16.0	%	$	85.2		$	78.5			8.5	%
Special		36.1			42.5			(15.1	)%		47.5			51.7			(8.1	)%

Total Station O&M	$	83.2		$	83.1			0.1	%	$	132.7		$	130.2			1.9	%


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

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

CONSOLIDATED RESULTS OF OPERATIONS

Income (Loss) Summary

																		��
	Three Months Ended												Three Months Ended
	June 30, 2007												June 30, 2006
	Delivery			Generation									Delivery		Generation
	and			and									and		and
(In millions)	Services			Marketing			Eliminations			Total			Services		Marketing			Eliminations			Total
Operating revenues	$	678.5		$	525.3		$	(377.3	)	$	826.5		$	632.5	$	414.1		$	(324.3	)	$	722.3
Fuel		—			231.4			—			231.4			—		191.8			—			191.8
Purchased power and transmission		454.1			27.4			(375.1	)		106.4			414.9		2.7			(322.5	)		95.1
Gain on sale of OVEC power agreement and shares		—			—			—			—			—		(1.1	)		—			(1.1	)
Deferred energy costs, net		(1.3	)		(6.9	)		—			(8.2	)		0.4		—			—			0.4
Operations and maintenance		84.6			108.2			(2.2	)		190.6			93.1		108.9			(1.8	)		200.2
Depreciation and amortization		41.1			29.6			—			70.7			37.9		30.3			—			68.2
Taxes other than income taxes		30.1			18.7			—			48.8			31.9		20.3			—			52.2

Total operating expenses		608.6			408.4			(377.3	)		639.7			578.2		352.9			(324.3	)		606.8

Operating income		69.9			116.9			—			186.8			54.3		61.2			—			115.5
Other income and expenses, net		4.4			4.1			(1.6	)		6.9			6.9		4.3			(1.0	)		10.2
Interest expense and preferred dividends		18.6			46.2			(1.6	)		63.2			22.3		55.4			(1.0	)		76.7

Income from continuing operations before income taxes and minority interest		55.7			74.8			—			130.5			38.9		10.1			—			49.0
Income tax expense from continuing operations		22.3			30.6			—			52.9			15.6		1.2			—			16.8
Minority interest		—			0.6			—			0.6			—		0.2			—			0.2

Income from continuing operations		33.4			43.6			—			77.0			23.3		8.7			—			32.0
Loss from discontinued operations, net of tax		—			—			—			—			—		(0.9	)		—			(0.9	)

Net income	$	33.4		$	43.6		$	—		$	77.0		$	23.3	$	7.8		$	—		$	31.1


	Six Months Ended												Six Months Ended
	June 30, 2007												June 30, 2006
	Delivery			Generation									Delivery		Generation
	and			and									and		and
(In millions)	Services			Marketing			Eliminations			Total			Services		Marketing			Eliminations			Total
Operating revenues	$	1,436.4		$	1,049.8		$	(812.1	)	$	1,674.1		$	1,335.1	$	921.2		$	(688.4	)	$	1,567.9
Fuel		—			463.6			—			463.6			—		410.5			—			410.5
Purchased power and transmission		954.9			51.6			(806.8	)		199.7			862.6		18.4			(684.7	)		196.3
Gain on sale of OVEC power agreement and shares		—			—			—			—			—		(6.1	)		—			(6.1	)
Deferred energy costs, net		(2.8	)		(6.9	)		—			(9.7	)		5.4		—			—			5.4
Operations and maintenance		170.9			185.5			(5.3	)		351.1			179.9		180.4			(3.7	)		356.6
Depreciation and amortization		81.3			61.4			—			142.7			75.6		60.4			—			136.0
Taxes other than income taxes		65.6			39.1			—			104.7			65.2		40.7			—			105.9

Total operating expenses		1,269.9			794.3			(812.1	)		1,252.1			1,188.7		704.3			(688.4	)		1,204.6

Operating income		166.5			255.5			—			422.0			146.4		216.9			—			363.3
Other income and expenses, net		7.4			8.2			(2.8	)		12.8			11.2		8.1			(1.4	)		17.9
Interest expense and preferred dividends		37.2			88.3			(2.8	)		122.7			42.2		103.6			(1.4	)		144.4

Income from continuing operations before income taxes and minority interest		136.7			175.4			—			312.1			115.4		121.4			—			236.8
Income tax expense from continuing operations		57.8			66.5			—			124.3			45.7		43.5			—			89.2
Minority interest		—			1.0			—			1.0			—		1.4			—			1.4

Income from continuing operations		78.9			107.9			—			186.8			69.7		76.5			—			146.2
Loss from discontinued operations, net of tax		—			—			—			—			—		(1.7	)		—			(1.7	)

Net income	$	78.9		$	107.9		$	—		$	186.8		$	69.7	$	74.8		$	—		$	144.5

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

CONSOLIDATED RESULTS

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

Operating Revenues

Operating revenues increased $104.2 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, primarily due to:

	•		an increase in average market prices in Allegheny’s region of the PJM market from $45.37 per MWh for the three months ended June 30, 2006 to $54.79 per MWh for the three months ended June 30, 2007,

	•		increased MWhs generated,

	•		higher generation rates charged to Pennsylvania customers as a result of a rate settlement approved by the Pennsylvania Public Utility Commission (the “Pennsylvania PUC”) and

	•		increased transmission and distribution revenues due to increases in HDD and CDD and increased customer load.

Operating revenues increased $106.2 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006, primarily due to:

	•		an increase in average market prices in Allegheny’s region of the PJM market from $47.83 per MWh for the six months ended June 30, 2006 to $54.33 per MWh for the six months ended June 30, 2007,

	•		increased MWhs generated,

	•		higher generation rates charged to Pennsylvania customers as a result of a rate settlement approved by the Pennsylvania PUC and

	•		increased transmission and distribution revenues due to increases in HDD and CDD and increased customer load,

	•		partially offset by gains on hedging activities during the first quarter of 2006 that did not recur during the six months ended June 30, 2007 and reduced revenues due to the March 2006 assignment of AE Supply’s rights to generation from the Ohio Valley Electric Corporation (“OVEC”) in connection with the December 31, 2004 sale of a portion of AE’s equity interest in OVEC.

Operating Income

Operating income increased $71.3 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, primarily due to:

	•		the $104.2 million increase in operating revenues discussed above,

	•		a $9.6 million decrease in operations and maintenance expenses due to decreases in certain outside contractor costs and decreased claim reserves and

	•		an $8.6 million change in deferred energy costs, net, representing a greater net credit to expense for energy costs incurred but not yet recovered in rates, related primarily to the West Virginia regulatory order (the “West Virginia Rate Order”) that, effective May 23, 2007, allows certain costs to be deferred and recovered in future customer rates,

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

	•		partially offset by a $39.6 million increase in fuel expense, primarily due to higher natural gas costs relating to an increase in the amount of natural gas burned as a result of an increase in the dispatch of gas-fired generation facilities resulting from higher market prices for power, as well as higher coal cost, primarily due to an increase in the average price of coal and

	•		an $11.3 million increase in purchased power and transmission expense due to purchased power from PURPA as a result of outages during the three months ended June 30, 2006 that did not recur during the three months ended June 30, 2007 and a refund received on certain transmission charges during the three months ended June 30, 2006 that did not recur during the three months ended June 30, 2007.

For additional information regarding the West Virginia Rate Order, see the “Regulatory Matters” section of Managements Discussion and Analysis (“MD&A”) below and Note 6, “Rates and Regulation.”

Operating income increased $58.7 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006, primarily due to:

	•		the $106.2 million increase in operating revenues discussed above and

	•		a $15.1 million change in deferred energy costs representing a greater net credit to expense for energy costs incurred but not yet recovered in rates, related primarily to the West Virginia Rate Order that, effective May 23, 2007, allows certain costs to be deferred and recovered in future customer rates, and a greater net credit to expense for deferred energy costs related to the AES Warrior Run generation facility,

	•		partially offset by a $53.1 million increase in fuel expense, primarily relating to higher natural gas costs due to an increase in the amount of natural gas burned as a result of an increase in the dispatch of gas-fired generation facilities resulting from higher market prices for power as well as higher coal cost, primarily due to an increase in the average price of coal.

For additional information regarding the West Virginia Rate Order, see the “Regulatory Matters” section of MD&A below and Note 6, “Rates and Regulation.” For additional information regarding deferred costs related to the AES Warrior Run generation facility see “Deferred Energy Costs, Net,” below.

Income from Continuing Operations Before Income Taxes and Minority Interest

Income from continuing operations before income taxes and minority interest increased $81.5 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006. This increase was primarily due to the $71.3 million increase in operating income discussed above and a $13.5 million decrease in interest expense and preferred dividends due to lower average debt outstanding and the write-off of prior deferred financing costs during the three months ended June 30, 2006 that did not recur during the three months ended June 30, 2007.

Income from continuing operations before income taxes and minority interest increased $75.3 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006. This increase was primarily due to the $58.7 million increase in operating income discussed above and a $21.7 million decrease in interest expense and preferred dividends due to lower average debt outstanding and the write-off of prior deferred financing costs during the three months ended June 30, 2006 that did not recur during the three months ended June 30, 2007.

Income Tax Expense

The effective tax rate for the three months ended June 30, 2007 was 40.4% and was higher than income tax expense calculated at the federal statutory tax rate, primarily due to state income taxes and 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 June 30, 2006 was 34.0% and was lower than income tax expense calculated at the federal statutory tax rate, primarily due to a state income tax refund that decreased the tax rate for the quarter by 4.3%.

The effective tax rate for the six months ended June 30, 2007 was 39.7% 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.

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

The effective tax rate for the six months ended June 30, 2006 was 37.6% and was higher than income tax expense calculated at the federal statutory tax rate, primarily due to state income taxes, the effects of utility rate making and certain non-deductible expenses.

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

DISCUSSION OF SEGMENT RESULTS OF OPERATIONS:

Delivery and Services

The following table provides retail electricity sales information:


	Three Months Ended							Six Months Ended
	June 30,							June 30,
	2007		2006		Change			2007		2006		Change
Retail electricity sales (million kWhs)		10,666		10,049		6.1	%		22,377		21,231		5.4	%
HDD (a)		599		530		13.0	%		3,375		2,956		14.2	%
CDD (a)		276		172		60.5	%		278		172		61.6	%


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

Operating Revenues

Operating revenues were as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Retail electric:
Generation	$	428.9	$	392.6	$	900.4	$	831.2
Transmission		39.0		37.0		82.9		79.2
Distribution		164.5		153.8		357.7		335.0

Total retail electric		632.4		583.4		1,341.0		1,245.4

Transmission services and bulk power		35.8		38.2		74.3		73.8
Other affiliated and nonaffiliated energy services		10.3		10.9		21.1		15.9

Total operating revenues	$	678.5	$	632.5	$	1,436.4	$	1,335.1

Retail electric revenues increased $49.0 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, primarily due to:

	•		a $36.3 million increase in generation revenues due to greater customer usage resulting from increases in HDD and CDD, increased customer load, the effect of a January 1, 2007 rate increase arising from a settlement approved by the Pennsylvania PUC and the May 22, 2007 West Virginia Rate Order and

	•		a $12.7 million increase in T&D revenues due to greater customer usage resulting from increases in HDD and CDD and increased customer load, partially offset by decreased T&D rates as a result of the May 22, 2007 West Virginia Rate Order.

Retail electric revenues increased $95.6 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006, primarily due to:

	•		a $69.2 million increase in generation revenues due to greater customer usage resulting from increases in HDD and CDD, increased customer load, the effect of a January 1, 2007 rate increase arising from a settlement approved by the Pennsylvania PUC and the May 22, 2007 West Virginia Rate Order and

	•		a $26.4 million increase in T&D revenues due to increased customer usage resulting from increases in HDD and CDD and increased customer load, partially offset by decreased T&D rates as a result of the May 22, 2007 West Virginia Rate Order.

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

Transmission services and bulk power revenues decreased $2.4 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, primarily due to:

	•		a $5.7 million decrease in bulk power revenues related to the May 2007 expiration of a fixed price power supply agreement to serve Monongahela’s former Ohio service territory,

	•		partially offset by a $2.3 million increase due to a PJM refund received during the second quarter of 2007 in connection with excess congestion related to the 2006-2007 planning year.

Other affiliated and nonaffiliated energy services revenues increased $5.2 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006, primarily due to the deferral of revenue on certain fiber optic agreements during the first quarter of 2006 and the impact of regulatory activities related to certain transmission contracts.

Operating Expenses

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Other purchased power and transmission	$	411.0	$	361.8	$	872.6	$	763.4
From PURPA generation (a)		43.1		53.1		82.3		99.2

Total purchased power and transmission	$	454.1	$	414.9	$	954.9	$	862.6



a) PURPA cost (cents per kWh sold)		6.1		5.6		5.8		5.4

West Penn and Potomac Edison have power purchase agreements with AE Supply, under which AE Supply provides West Penn and Potomac Edison with the majority of the power necessary to meet their PLR obligations. These agreements have both fixed-price and market-based pricing components. 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 $49.2 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, primarily due to:

	•		a $24.2 million increase, primarily due to increased power sales volume as a result of increases in HDD and CDD and increased customer load,

	•		a $14.0 million increase, 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 due to the January 1, 2007 power supply agreement between Potomac Edison and Monongahela discussed above.

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

Other purchased power and transmission increased $109.2 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006, primarily due to:

	•		a $56.0 million increase, primarily due to increased power sales volume as a result of increases in HDD and CDD and increased customer load,

	•		a $25.6 million increase, 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,

	•		a $16.6 million increase due to the January 1, 2007 power supply agreement between Potomac Edison and Monongahela discussed above and

	•		a $4.8 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 $10.0 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, primarily due to a $15.6 million decrease in purchased power from PURPA as a result of a January 1, 2007 transfer of Monongahela’s PURPA contracts from the Delivery and Services segment to the Generation and Marketing segment, partially offset by an increase in purchased power due to outages at the AES Warrior Run generation facility during the three months ended June 30, 2006 that did not recur during the three months ended June 30, 2007.

Purchased power and transmission from PURPA generation decreased $16.9 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006, primarily due to a $30.4 million decrease in purchased power from PURPA as a result of a January 1, 2007 transfer of Monongahela’s PURPA contracts from the Delivery and Services segment to the Generation and Marketing segment, partially offset by an increase in purchased power due to outages at the AES Warrior Run generation facility during the six months ended June 30, 2006 that did not recur during the six months ended June 30, 2007.

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

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 Public Service Commission (the “Maryland PSC”) to recover all contract costs from the AES Warrior Run PURPA generation facility, net of any revenues received from the sale of AES Warrior Run output into the wholesale energy market, by means of a retail revenue surcharge (the “AES Warrior Run Surcharge”). Any under-recovery or over-recovery of net costs is being deferred pending subsequent recovery from, or return to, customers through adjustments to the AES Warrior Run Surcharge.

Market-based Generation Costs

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

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

Deferred energy costs, net were as follows:


	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In millions)	2007			2006		2007			2006
Deferred energy costs, net	$	(1.3	)	$	0.4	$	(2.8	)	$	5.4

The $1.7 million change in deferred energy costs, net for the three months ended June 30, 2007 compared to the three months ended June 30, 2006 represented a greater net credit to expense, primarily related to the AES Warrior Run PURPA generation facility.

The $8.2 million change in deferred energy costs, net for the six months ended June 30, 2007 compared to the six months ended June 30, 2006 represented a greater net credit to expense, primarily related to the AES Warrior Run PURPA generation facility and market-based generation costs.

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Operations and maintenance	$	84.6	$	93.1	$	170.9	$	179.9

Operations and maintenance expenses decreased $8.5 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, primarily due to:

	•		a $2.4 million decrease due to reduced claim reserves,

	•		a $2.2 million decrease in contractor services,

	•		a $1.8 million decrease in outside services expense due to lower legal and consulting fees and

	•		a $1.6 million decrease in benefits expense due to an increase in capitalized labor expense.

Operations and maintenance expenses decreased $9.0 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006, primarily due to:

	•		a $4.2 million decrease in contractor services,

	•		a $2.4 million decrease in contract work expense due to reserves established for an environmental matter during the six months ended June 30, 2006 that did not recur during the six months ended June 30, 2007 and a reduction in pole inspection expenses and

	•		a $2.0 million decrease in benefits expense due to an increase in capitalized labor expense.

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Depreciation and amortization	$	41.1	$	37.9	$	81.3	$	75.6

Depreciation and amortization expenses increased $3.2 million and $5.7 million for the three and six months ended June 30, 2007, respectively, compared to the three and six months ended June 30, 2006, primarily due to net property, plant and equipment additions.

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

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Taxes other than income taxes	$	30.1	$	31.9	$	65.6	$	65.2

Taxes other than income taxes decreased $1.8 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, primarily due to a decrease in property tax due to a favorable audit settlement during the three months ended June 30, 2007, partially offset by an increase in gross receipts tax due to an increase in taxable regulated utility revenues.

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				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Other income and expenses, net	$	4.4	$	6.9	$	7.4	$	11.2

Other income and expenses, net, decreased $2.5 million and $3.8 million for the three and six months ended June 30, 2007, respectively, compared to the three and six months ended June 30, 2006, primarily as a result of decreased interest income on investments due to lower investment balances and gains on non-operating land sales during the three months ended June 30, 2006 that did not recur during the three months ended June 30, 2007.

See Note 15, “Other Income and Expenses, Net,” for additional details.

Interest Expense and Preferred Dividends:

Interest expense and preferred dividends were as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Interest expense and preferred dividends	$	18.6	$	22.3	$	37.2	$	42.2

Interest expense and preferred dividends decreased $3.7 million and $5.0 million for the three and six months ended June 30, 2007, respectively, compared to the three and six months ended June 30, 2006, primarily due to lower average debt outstanding and the write-off of prior deferred financing costs during the three months ended June 30, 2006 that did not recur during the three months ended June 30, 2007.

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

Income Tax Expense

The effective tax rate for the three months ended June 30, 2007 was 39.9% 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, other adjustments related to tax reserves and a nondeductible expense that increased the tax rate for the quarter by 0.7%.

The effective tax rate for the three months ended June 30, 2006 was 39.8% 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.

The effective tax rate for the six months ended June 30, 2007 was 42.2% 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, other adjustments related to tax reserves and a nondeductible expense that increased the tax rate for the quarter.

The effective tax rate for the six months ended June 30, 2006 was 39.5% 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							Six Months Ended
	June 30,							June 30,
	2007		2006		Change			2007		2006		Change
Generation (million kWhs)		11,759		11,234		4.7	%		24,851		24,251		2.5	%

Operating Revenues

Operating revenues were as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Revenue from affiliates	$	375.1	$	322.4	$	806.8	$	684.7
Wholesale and other revenue, net (a)		150.2		91.7		243.0		236.5

Total revenues	$	525.3	$	414.1	$	1,049.8	$	921.2


(a)		Amounts are net of energy trading gains and losses as described in Note 10, “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. Effective with the institution of the ENEC, the amount charged to Potomac Edison reflects the adjustment for over and/or under recovery. See the “Regulatory Matters” section of MD&A below and Note 6, “Rates and Regulations,” for additional information.

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

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 $37.29 and $35.19 per MWh for the three months ended June 30, 2007 and 2006, respectively, and $37.13 and $34.76 per MWh for the six months ended June 30, 2007 and 2006, respectively.

Revenue from affiliates increased $52.7 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, primarily due to:

	•		a $24.4 million increase in Monongahela Power’s West Virginia affiliated revenues due to an increase in sales volume and price, including a $17.7 million increase reflecting the transfer of Monongahela’s PURPA contracts to the Generation and Marketing segment from the Delivery and Services segment, causing a corresponding increase in both revenues and purchased power,

	•		a $7.3 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 increases in HDD and CDD and increased customer load,

	•		an approximate $14.0 million increase due 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 $5.3 million increase related to higher contractual rates with increased sales volumes for certain of Potomac Edison’s customers in Maryland,

	•		partially offset by a $4.5 million decrease in ancillary service revenues from the Delivery and Services segment due to a contract expiration.

Revenue from affiliates increased $122.1 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006, primarily due to:

	•		a $43.6 million increase in Monongahela Power’s West Virginia affiliated revenues due to an increase in sales volume and price, including a $34.0 million increase reflecting the transfer of Monongahela’s PURPA contracts to the Generation and Marketing segment from the Delivery and Services segment, causing a corresponding increase in both revenues and purchased power,

	•		a $22.4 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 increases in HDD and CDD and increased customer load,

	•		an approximate $25.6 million increase due 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

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

	•		a $21.9 million increase related to higher contractual rates with increased sales volumes for certain of Potomac Edison’s customers in Maryland,

	•		partially offset by a $7.5 million decrease in ancillary service revenues from the Delivery and Services segment due to a contract expiration.

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2007			2006			2007			2006
PJM Revenue:
Generation sold into PJM	$	609.1		$	468.8		$	1,238.6		$	1,050.8
Power purchased from PJM		(469.0	)		(378.2	)		(1,008.4	)		(832.1	)

Net		140.1			90.6			230.2			218.7
Cash flow hedges and trading activities:
Realized gains (losses)		2.8			(8.2	)		(1.1	)		(4.6	)
Unrealized gains (losses)		(0.8	)		5.3			1.6			18.3

Net		2.0			(2.9	)		0.5			13.7

Fort Martin Scrubber Securitization		5.5			—			5.5			—
Other revenues		2.6			4.0			6.8			4.1

Total wholesale and other revenues	$	150.2		$	91.7		$	243.0		$	236.5

Wholesale and other revenues increased $58.5 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, primarily due to:

	•		an increase in net PJM revenues of $49.5 million and

	•		$5.5 million of Fort Martin Scrubber Securitization revenues collected during the second quarter of 2007 relating to an environmental control surcharge collected from the West Virginia customers of Monongahela and Potomac Edison following the April 2007 Fort Martin Scrubber financing. See Note 5, “Debt” for additional information regarding the debt issuance.

The increase in net PJM revenues was due to higher revenues from generation sold to PJM, partially offset by an increase in power purchased from PJM. Revenues from generation sold to PJM were higher, primarily due to an increase in the market price of power, an increase in supercritical plant availability and the dispatch of gas-fired generation facilities as a result of higher prices for electricity, both of which resulted in increased MWhs generated. 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 increases in HDD and CDD, increased customer load, increased sales volumes for certain of Potomac Edison’s customers in Maryland and the transfer of Monongahela’s PURPA contracts to the Generation and Marketing segment from the Delivery and Services segment.

Wholesale and other revenues increased $6.5 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006, primarily due to:

	•		an increase in net PJM revenues of $11.5 million and

	•		$5.5 million of Fort Martin Scrubber Securitization revenues collected during the second quarter of 2007 relating to an environmental control surcharge collected from the West Virginia customers of Monongahela and Potomac Edison following the April 2007 Fort Martin Scrubber financing. See Note 5, “Debt” for additional information regarding the debt issuance,

	•		partially offset by a $13.2 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.

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

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

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

At June 30, 2007, the fair values of derivative contract assets and liabilities were $6.1 million and $21.9 million, respectively. 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 June 30, 2007
	Settlement by:
Classification of contracts by source of fair value (In millions)	2007		2008			2009			2010			2011			Total
Prices actively quoted	$	3.1	$	(5.9	)	$	(5.6	)	$	(5.6	)	$	(1.8	)	$	(15.8	)
Prices provided by other external sources		—		—			—			—			—			—
Prices based on models		—		—			—			—			—			—

Total	$	3.1	$	(5.9	)	$	(5.6	)	$	(5.6	)	$	(1.8	)	$	(15.8	)

The fair value of AE Supply’s contracts that are scheduled to settle by December 31, 2007 was a net asset of $3.1 million, primarily related to gains associated with cash flow hedges, partially offset by interest rate swaps.

See Note 10, “Derivative Instruments and Hedging Activities,” for additional information.

Changes in Fair Value:Net unrealized gains (losses) of $(0.8) million and $1.6 million for the three and six months ended June 30, 2007, respectively, were recorded on the Consolidated Statements of Operations in “Operating revenues” to reflect the change in fair value of the derivative contracts. The following table provides a summary of changes in the net fair value of AE Supply’s derivative contracts:


	Three Months Ended			Six Months Ended
(In millions)	June 30, 2007			June 30, 2007
Net fair value of derivative contract liabilities at April 1 and January 1, respectively	$	(25.6	)	$	(22.5	)
Changes in fair value of cash flow hedges		10.6			5.1
Unrealized gains on contracts, net		(0.8	)		1.6

Net fair value of derivative contract liabilities at June 30	$	(15.8	)	$	(15.8	)

As shown in the table above, the net fair value of Allegheny’s derivative contracts increased by $9.8 million and $6.7 million during the three and six months ended June 30, 2007, respectively. The increase in the fair values was primarily due to changes in the fair values of commodity contracts.

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

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				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Fuel	$	231.4	$	191.8	$	463.6	$	410.5

Total fuel increased by $39.6 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, primarily due to an $18.7 million increase in coal expense and a $19.6 million increase in natural gas expense. The increase in coal expense was primarily due to an increase in the average price of coal of $2.78 per ton. The increase in natural gas expense was primarily due to a 2.1 million decatherm increase in the amount of natural gas burned. The increase in the amount of natural gas burned was primarily due to an increase in the dispatch of gas-fired generation facilities as a result of higher market prices for power.

Total fuel increased by $53.1 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006, primarily due to a $32.5 million increase in coal expense and a $19.3 million increase in natural gas expense. The increase in coal expense was primarily due to an increase in the average price of coal of $2.27 per ton. The increase in natural gas expense was primarily due to a 2.1 million decatherm increase in the amount of natural gas burned during the second quarter of 2007. The increase in the amount of natural gas burned was primarily due to an increase in the dispatch of gas-fired generation facilities as a result of higher market prices for power.

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Purchased power and transmission expenses	$	27.4	$	2.7	$	51.6	$	18.4

Purchased power and transmission expenses increased $24.7 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, primarily due to a $17.7 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, an increase in expense related to the sale of excess natural gas purchased for gas generation and a refund received on certain transmission charges during the three months ended June 30, 2006 that did not recur during the three months ended June 30, 2007.

Purchased power and transmission expenses increased $33.2 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006, primarily due to a $34.0 million increase in purchased power from PURPA as a result of a January 1, 2007 transfer of Monongahela’s PURPA contracts from the Delivery and Services segment to the Generation and Marketing segment.

Gain on Sale of OVEC Power Agreement and Shares:On December 31, 2004, AE sold a 9% equity interest in the OVEC to Buckeye Power Generating, LLC. The gains on sale of OVEC power agreement and shares were $1.1 million and $6.1 million for the three and six months ended June 30, 2006, respectively, and represent the release of proceeds due to the fulfillment of certain post-closing commitments.

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

Expanded Net Energy Cost (“ENEC”)

The May 22, 2007 West Virginia Rate Order re-established an annual ENEC method of recovering net power supply costs, including fuel costs, purchased power costs and other related expenses, net of related revenue. Under the ENEC, actual costs and revenues will be tracked for under and/or over recoveries, and new ENEC rate filings will be made on an annual basis. Any under and/or over recovery of costs, net of related revenues, will be deferred, for subsequent recovery or refund via a customer surcharge, as a regulatory asset or regulatory liability with the corresponding impact on the Consolidated Statements of Operations reflected within “Deferred energy costs, net.” See the “Regulatory Matters” section of MD&A below and Note 6, “Rates and Regulation,” for additional information.

Grant Town PURPA generation facility

Monongahela acquires energy from the Grant Town PURPA generation facility in West Virginia. The West Virginia PSC approved an amendment to the Electric Energy Purchase Agreement between Monongahela and American Bituminous Power Partners, L.P., the owners of the Grant Town PURPA generation facility, in April 2006. The amendment provided for an increase in the price of energy that Monongahela is acquiring until 2017. The West Virginia PSC authorized Monongahela to institute a temporary surcharge designed to recover the increase in costs from West Virginia customers as well as a deferred accounting mechanism by which actual aggregate amounts of the incremental cost increase were tracked and reconciled by comparison to the aggregate amounts recovered from West Virginia customers through the temporary surcharge. As a result of the May 22, 2007 West Virginia Rate Order, the increase in costs discussed above are included in the ENEC. See the “Regulatory Matters” section of MD&A below and Note 6, “Rates and Regulation,” for additional information.

Deferred energy costs, net were as follows:


	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In millions)	2007			2006		2007			2006
Deferred energy costs, net	$	(6.9	)	$	—	$	(6.9	)	$	—

The $6.9 million change in deferred energy costs, net for the three and six months ended June 30, 2007 compared to the three and six months ended June 30, 2006 represented a net credit to expense, primarily related to the implementation of the ENEC.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Operations and maintenance	$	108.2	$	108.9	$	185.5	$	180.4

Operations and maintenance expenses increased $5.1 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006, primarily due to a $6.4 million reversal of a guarantee liability associated with the Hunlock Creek Energy Ventures partnership that was recorded during the three months ended March 31, 2006, partially offset by a decrease in outside services expense, primarily due to certain outside contractor costs during the six months ended June 30, 2006 that did not recur during the six months ended June 30, 2007.

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

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Taxes other than income taxes	$	18.7	$	20.3	$	39.1	$	40.7

Taxes other than income taxes decreased $1.6 million for the three and six months ended June 30, 2007 compared to the three and six months ended June 30, 2006, primarily due to a $1.3 million decrease in capital stock and franchise taxes due to a favorable audit settlement during the three months ended June 30, 2007.

Interest Expense and Preferred Dividends

Interest expense and preferred dividends were as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Interest expense and preferred dividends	$	46.2	$	55.4	$	88.3	$	103.6

Interest expense and preferred dividends decreased $9.2 million and $15.3 million for the three and six months ended June 30, 2007, respectively, compared to the three and six months ended June 30, 2006, primarily due to lower average debt outstanding and the write-off of prior deferred financing costs during the three months ended June 30, 2006 that did not recur during the three months ended June 30, 2007. These decreases were partially offset by increased interest expense associated with the April 2007 issuance of environmental control bonds. See Note 5, “Debt,” for additional information.

Income Tax Expense

The effective tax rate for the three months ended June 30, 2007 was 40.8% and was higher than income tax expense calculated at the federal statutory tax rate, primarily due to state income taxes, other adjustments related to tax reserves and a nondeductible expense that increased the tax rate for the quarter by 0.7%.

The effective tax rate for the three months ended June 30, 2006 was 12.0% and was lower than income tax expense calculated at the federal statutory tax rate primarily due to a state income tax refund that decreased the tax rate for the quarter by 20.7% and the allocation of consolidated tax savings.

The effective tax rate for the six months ended June 30, 2007 was 37.8% and was higher than income tax expense calculated at the federal statutory tax rate, primarily due to state income taxes and a nondeductible expense that increased the tax rate for the period by 0.3%, partially offset by an adjustment to deferred taxes for a West Virginia corporate net income tax rate change.

The effective tax rate for the six months ended June 30, 2006 was 35.8% and was higher than income tax expense calculated at the federal statutory tax rate, primarily due to adjustments related to tax reserves, partially offset by a state tax refund that decreased the tax rate for the period by 1.7% and the allocation of consolidated tax savings.

Minority Interest

Minority interest, which primarily represents equity interest in AE Supply, was $0.6 million and $0.2 million for the three months ended June 30, 2007 and 2006, respectively, and $1.0 million and $1.4 million for the six months ended June 30, 2007 and 2006, respectively.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CONSOLIDATED RESULTS OF OPERATIONS

Income (Loss) Summary


	Three Months Ended											Three Months Ended
	June 30, 2007											June 30, 2006
	Delivery		Generation									Delivery			Generation
	and		and									and			and
(In millions)	Services		Marketing			Eliminations			Total			Services			Marketing			Eliminations			Total
Operating revenues	$	160.8	$	139.9		$	(94.0	)	$	206.7		$	156.7		$	90.3		$	(69.6	)	$	177.4
Fuel		—		62.6			—			62.6			—			41.8			—			41.8
Purchased power and transmission		107.3		30.9			(94.0	)		44.2			98.4			13.9			(69.6	)		42.7
Deferred energy costs, net		0.4		(6.9	)		—			(6.5	)		(0.6	)		—			—			(0.6	)
Operations and maintenance		22.1		33.4			—			55.5			25.9			22.0			—			47.9
Depreciation and amortization		8.1		7.6			—			15.7			7.5			8.8			—			16.3
Taxes other than income taxes		4.9		7.0			—			11.9			6.0			5.9			—			11.9

Total operating expenses		142.8		134.6			(94.0	)		183.4			137.2			92.4			(69.6	)		160.0

Operating income (loss)		18.0		5.3			—			23.3			19.5			(2.1	)		—			17.4
Other income and expenses, net		0.2		3.8			—			4.0			1.5			2.6			—			4.1
Interest expense		4.8		8.1			—			12.9			6.0			4.5			—			10.5

Income (loss) before income taxes		13.4		1.0			—			14.4			15.0			(4.0	)		—			11.0
Income tax expense (benefit)		6.0		0.9			—			6.9			6.4			(2.3	)		—			4.1

Net income (loss)	$	7.4	$	0.1			—		$	7.5		$	8.6		$	(1.7	)		—		$	6.9


	Six Months Ended											Six Months Ended
	June 30, 2007											June 30, 2006
	Delivery		Generation									Delivery			Generation
	and		and									and			and
(In millions)	Services		Marketing			Eliminations			Total			Services			Marketing			Eliminations			Total
Operating revenues	$	341.9	$	257.2		$	(191.5	)	$	407.6		$	330.8		$	191.4		$	(147.6	)	$	374.6
Fuel		—		123.0			—			123.0			—			86.9			—			86.9
Purchased power and transmission		214.9		59.5			(191.5	)		82.9			197.1			34.3			(147.6	)		83.8
Deferred energy costs, net		0.1		(6.9	)		—			(6.8	)		(0.6	)		—			—			(0.6	)
Operations and maintenance		46.2		64.1			—			110.3			50.2			38.2			—			88.4
Depreciation and amortization		15.9		17.6			—			33.5			15.1			17.6			—			32.7
Taxes other than income taxes		10.4		14.0			—			24.4			12.3			11.8			—			24.1

Total operating expenses		287.5		271.3			(191.5	)		367.3			274.1			188.8			(147.6	)		315.3

Operating income (loss)		54.4		(14.1	)		—			40.3			56.7			2.6			—			59.3
Other income and expenses, net		0.4		7.5			—			7.9			3.0			4.8			—			7.8
Interest expense		9.5		12.0			—			21.5			12.2			9.1			—			21.3

Income (loss) before income taxes		45.3		(18.6	)		—			26.7			47.5			(1.7	)		—			45.8
Income tax expense (benefit)		20.2		(8.0	)		—			12.2			19.1			(1.9	)		—			17.2

Net income (loss)	$	25.1	$	(10.6	)	$	—		$	14.5		$	28.4		$	0.2		$	—		$	28.6

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 $29.3 million and $33.0 million for the three and six months ended June 30, 2007, respectively, compared to the three and six months ended June 30, 2006, primarily due to:

	•		increased generation revenue as a result of additional MWhs generated,

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

	•		increased retail revenue resulting from increases in HDD and CDD and higher rates.

Operating Income

Operating income increased $5.9 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, primarily due to:

	•		the $29.3 million increase in operating revenues discussed above and

	•		a $5.9 million change in deferred energy costs, net, representing a greater net credit to expense for energy costs incurred but not yet recovered in rates, related primarily to the West Virginia Rate Order that, effective May 23, 2007, allows certain costs to be deferred and recovered in future customer rates,

	•		partially offset by a $23.4 million increase in operating expenses, primarily due to a $20.8 million increase in fuel expense resulting from an increase in the average price of coal and an increase in the amount of coal consumed as a result of the Asset Swap and

	•		a $7.6 million increase in operations and maintenance expenses, primarily due to an increase in contract work as a result of a planned maintenance outage in the first quarter of 2007 as well as an increase in salaries and wages due to the Asset Swap.

For additional information regarding the West Virginia Rate Order, see the “Regulatory Matters” section of MD&A below and Note 6, “Rates and Regulation.”

Operating income decreased $19.0 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006, primarily due to a $52.0 million increase in operating expenses, partially offset by the $33.0 million increase in operating revenues discussed above.

Operating expenses increased primarily due to:

	•		a $36.1 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 as a result of the Asset Swap and

	•		a $21.9 million increase in operations and maintenance expenses, primarily due to an increase in contract work as a result of a planned maintenance outage in the first quarter of 2007 as well as an increase in salaries and wages due to the Asset Swap,

	•		partially offset by a $6.2 million change in deferred energy costs, net, representing a greater net credit to expense for energy costs incurred but not yet recovered in rates, related primarily to the West Virginia Rate Order that, effective May 23, 2007, allows certain costs to be deferred and recovered in future customer rates.

For additional information regarding the Asset Swap, see Note 3, “Asset Swap.” For additional information regarding the West Virginia Rate Order, see the “Regulatory Matters” section of MD&A below and Note 6, “Rates and Regulation.”

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Income Before Income Taxes

Income before income taxes increased $3.4 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, primarily due to a $5.9 million increase in operating income, as discussed above, partially offset by a $2.4 million increase in interest expense primarily due to interest on $344 million of Senior Secured Sinking Fund Environmental Control Bonds, Series A, issued in April 2007.

Income before income taxes decreased $19.1 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006, primarily due to the $19.0 million decrease in operating income discussed above.

Income Tax Expense

The effective tax rate for the three months ended June 30, 2007 was 47.9% and was higher than income tax expense calculated at the federal statutory tax rate, primarily due to state income taxes, a reduction in the share of consolidated tax savings that increased the tax rate for the quarter by 3.0%, and a nondeductible expense that increased the tax rate for the quarter by 1.3%.

The effective tax rate for the three months ended June 30, 2006 was 37.3% and was higher than income tax expense calculated at the federal statutory tax rate, primarily due to state income taxes partially offset by the amortization of deferred investment tax credits that lowered the rate for the quarter by 4.9%.

The effective tax rate for the six months ended June 30, 2007 was 45.7% and was higher than income tax expense calculated at the federal statutory tax rate, primarily due to state income taxes, a reduction in the share of consolidated tax savings that increased the tax rate for the period by 3.2%, the accounting for deferred taxes related to utility property which increased the rate for the period by 2.8% and a nondeductible expense that increased the tax rate for the period by 0.7%.

The effective tax rate for the six months ended June 30, 2006 was 37.6% and was higher than income tax expense calculated at the federal statutory tax rate, primarily due to state income taxes partially offset by the amortization of deferred investment tax credits that lowered the tax rate for the period by 2.3%.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

DISCUSSION OF SEGMENT RESULTS OF OPERATIONS:

Delivery and Services

The following table provides retail electricity sales information:


	Three Months Ended							Six Months Ended
	June 30,							June 30,
	2007		2006		Change			2007		2006		Change
Retail electricity sales (million kWhs)		2,600		2,402		8.2	%		5,383		5,054		6.5	%
HDD (a)		535		452		18.4	%		3,152		2,599		21.3	%
CDD (a)		265		177		49.7	%		269		178		51.1	%


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

Operating Revenues

Operating revenues were as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Retail electric:
Generation	$	92.5	$	83.3	$	187.8	$	173.8
Transmission		8.4		7.8		17.6		16.5
Distribution		39.9		41.1		92.3		90.5

Total retail electric		140.8		132.2		297.7		280.8
Transmission services and bulk power		17.0		21.5		38.7		44.4
Other affiliated and non-affiliated energy services		3.0		3.0		5.5		5.6

Total Delivery and Services revenues	$	160.8	$	156.7	$	341.9	$	330.8

Retail electric revenues increased $8.6 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, primarily due to a $9.2 million increase in generation revenues. This increase was due to greater customer usage primarily as a result of increases in HDD and CDD as well as higher rates.

Retail electric revenues increased $16.9 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006, primarily due to a $14.0 million increase in generation revenues due to greater customer usage, primarily as a result of increases in HDD and CDD as well as higher rates and a $2.9 million increase in T&D revenues due to greater customer usage, primarily as a result of increases in HDD and CDD.

Transmission services and bulk power decreased $4.5 million and $5.7 million for the three and six months ended June 30, 2007, respectively, compared to the three and six months ended June 30, 2006, primarily due to the expiration in May 2007 of a fixed price power supply agreement to serve Monongahela’s former Ohio service territory.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Operating Expenses

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Other purchased power and transmission	$	107.3	$	82.8	$	214.9	$	166.7
From PURPA generation (a)		—		15.6		—		30.4

Total purchased power and transmission	$	107.3	$	98.4	$	214.9	$	197.1


(a) PURPA cost (cents per kWh sold)		—		4.6		—		4.4

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 $24.5 million and $48.2 million for the three and six months ended June 30, 2007, respectively, compared to the three and six months ended June 30, 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 increases in HDD and CDD.

Purchased power from PURPA generation decreased $15.6 million and $30.4 million for the three and six months ended June 30, 2007, respectively, compared to the three and six months ended June 30, 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.


	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In millions)	2007		2006			2007		2006
Deferred energy costs, net	$	0.4	$	(0.6	)	$	0.1	$	(0.6	)

The $1.0 million change in Deferred energy costs, net for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, represents a greater net charge to expense, primarily relating to costs associated with the Grant Town PURPA generation facility which were previously recorded by the Delivery and Services segment but now are recorded by the Generation and Marketing segment as a result of the Asset Swap. See Note 3, “Asset Swap,” for additional information.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Operations and maintenance	$	22.1	$	25.9	$	46.2	$	50.2

Operations and maintenance expenses decreased $3.8 million for the three months ended June 30, 2007, compared to the three months ended June 30, 2006, primarily due to a decrease in contractor services, a decrease in outside services expense due to lower legal and consulting fees, a decrease in claim reserves, a decrease in employee benefit expenses due to an increase in capitalized labor expenses and a decrease in rental expenses as a result of decreases in information technology leases in connection with the outsourcing of Allegheny’s information technology function.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Operations and maintenance expenses decreased $4.0 million for the six months ended June 30, 2007, compared to the six months ended June 30, 2006, primarily due to:

	•		a $1.9 million decrease in contractor services and

	•		decreases in uncollectible expenses due to improved collections and recoveries, contract work as a result of the timing of pole inspections and employee benefit expenses due to an increase in capitalized labor expenses.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Taxes other than income taxes	$	4.9	$	6.0	$	10.4	$	12.3

Taxes other than income taxes decreased $1.1 million and $1.9 million for the three and six months ended June 30, 2007, respectively, compared to the three and six months ended June 30, 2006, primarily due to a change in business and occupation tax as the result of the Asset Swap and a decrease in property taxes due to a favorable audit settlement during the six months ended June 30, 2007.

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				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Other income and expenses, net	$	0.2	$	1.5	$	0.4	$	3.0

Other income and expenses, net decreased $1.3 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, primarily as a result of decreased interest income on investments due to lower investment balances.

Other income and expenses, net decreased $2.6 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006, primarily as a result of decreased interest income on investments due to lower investment balances.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Interest Expense:

Interest expense was as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Interest expense	$	4.8	$	6.0	$	9.5	$	12.2

Interest expense decreased $1.2 million and $2.7 million for the three and six months ended June 30, 2007, respectively, compared to the three and six months ended June 30, 2006, primarily due to lower average debt outstanding.

Income Tax Expense

The effective tax rate for the three months ended June 30, 2007 was 44.8% 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 June 30, 2006 was 42.7% 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 six months ended June 30, 2007 was 44.6% 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 six months ended June 30, 2006 was 40.2% 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.

Generation and Marketing

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


	Three Months Ended							Six Months Ended
	June 30,							June 30,
	2007		2006		Change			2007		2006		Change
Generation (million kWhs)		3,210		2,646		21.3	%		6,445		5,412		19.1	%

Operating Revenues

Operating revenues were as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007			2006
Revenue from affiliates	$	128.2	$	71.6	$	273.0		$	148.7
Wholesale and other, net		11.7		18.7		(15.8	)		42.7

Total revenues	$	139.9	$	90.3	$	257.2		$	191.4

Revenue from affiliates for the six months ended June 30, 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

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 $49.6 million for the three months ended June 30, 2007 compared to the three months ended June 30, 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,

	•		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 and

	•		Fort Martin Scrubber Securitization revenues collected during the second quarter of 2007 relating to an environmental control surcharge collected from the West Virginia customers of Monongahela following the April 2007 Fort Martin Scrubber financing. See Note 5, “Debt” for additional information regarding the debt issuance,

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

Total operating revenues increased $65.8 million for the six months ended June 30, 2007 compared to the six months ended June 30, 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 and

	•		Fort Martin Scrubber Securitization revenues collected during the second quarter of 2007 relating to an environmental control surcharge collected from the West Virginia customers of Monongahela following the April 2007 Fort Martin Scrubber financing. See Note 5, “Debt” for additional information regarding the debt issuance,

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

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				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Fuel	$	62.6	$	41.8	$	123.0	$	86.9

Total fuel increased by $20.8 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, primarily due to a $19.2 million increase in coal expense. The increase in coal expense was due to a 0.4 million-ton increase in the amount of coal burned and an increase in the price of coal of $3.72 per ton. The increase in the amount of coal burned was primarily due to an increase in total MWhs generated as a result of the Asset Swap.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Total fuel increased by $36.1 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006, primarily due to a $34.1 million increase in coal expense. The increase in coal expense was due to a 0.6 million-ton increase in the amount of coal burned and an increase in the price of coal of $3.53 per ton. The increase in the amount of coal burned was primarily due to an increase in total MWhs generated as a result of the Asset Swap.

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Purchased power and transmission	$	30.9	$	13.9	$	59.5	$	34.3

Purchased power and transmission increased $17.0 million for the three months ended June 30, 2007, compared to the three months ended June 30, 2006, primarily due to:

	•		a $17.7 million increase from the transfer of Monongahela’s PURPA contracts to the Generation and Marketing segment from the Delivery and Services segment and

	•		a $3.8 million increase in capacity purchased from AGC, primarily due to Monongahela’s increased ownership interest in AGC as a result of the Asset Swap,

	•		partially offset by a $6.2 million decrease in affiliated purchased power due to the termination of an AE Supply contract as part of the Asset Swap as described above in “Operating Revenues.”

Purchased power and transmission increased $25.2 million for the six months ended June 30, 2007, compared to the six months ended June 30, 2006, primarily due to:

	•		a $34.0 million increase from the transfer of Monongahela’s PURPA contracts to the Generation and Marketing segment from the Delivery and Services segment and

	•		a $6.8 million increase in capacity purchased from AGC, primarily due to Monongahela’s increased ownership interest in AGC as a result of the Asset Swap,

	•		partially offset by a $17.8 million decrease in affiliated purchased power due to the termination of an AE Supply contract as part of the Asset Swap as described above in “Operating Revenues.”

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

Expanded Net Energy Cost (“ENEC”)

The May 22, 2007 West Virginia Rate Order re-established an annual ENEC method of recovering net power supply costs, including fuel costs, purchased power costs and other related expenses, net of related revenue. Under the ENEC, actual costs and revenues will be tracked for under and/or over recoveries and new ENEC rate filings will be made on an annual basis. Any under and/or over recovery of costs, net of related revenues, will be deferred, for subsequent recovery or refund via a customer surcharge, as a regulatory asset or regulatory liability with the corresponding impact on the Consolidated Statements of Operations reflected within Deferred Energy Costs, Net. See Note 6, “Rates and Regulation,” for additional information.

Grant Town PURPA generation facility

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

temporary surcharge designed to recover the increase in costs from West Virginia customers, as well as a deferred accounting mechanism by which actual aggregate amounts of the incremental cost increase were tracked and reconciled by comparison to the aggregate amounts recovered from West Virginia customers through the temporary surcharge. As a result of the May 22, 2007 West Virginia Rate Order, the increase in costs discussed above are included in the ENEC. See the “Regulatory Matters” section of MD&A below and Note 6, “Rates and Regulation,” for additional information.

Deferred energy costs, net were as follows:


	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In millions)	2007			2006		2007			2006
Deferred energy costs, net	$	(6.9	)	$	—	$	(6.9	)	$	—


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Operations and maintenance	$	33.4	$	22.0	$	64.1	$	38.2

Operations and maintenance expenses increased $11.4 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, primarily due to:

	•		a $6.5 million increase in contract work expense, primarily due to maintenance performed during a scheduled outage at Fort Martin Unit No. 1 in 2007, partially offset by maintenance outages at the Hatfield generation facility during the three months ended June 30, 2006 that did not recur during the three months ended June 30, 2007 and

	•		a $2.9 million increase in salaries and wages expense, primarily due to the Asset Swap and a scheduled outage at Fort Martin Unit No. 1.

See Note 3, “Asset Swap,” for information regarding the Asset Swap and the related changes in plant ownership percentages, including the Hatfield generation facility.

Operations and maintenance expenses increased $25.9 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006, primarily due to:

	•		a $14.1 million increase in contract work expense, primarily due to maintenance performed during a scheduled outage at Fort Martin Unit No. 1 in 2007, partially offset by maintenance outages at the Hatfield generation facility during the six months ended June 30, 2006 that did not recur during the six months ended June 30, 2007,

	•		a $5.9 million increase in salaries and wages expense, primarily due to the Asset Swap and a scheduled outage at Fort Martin Unit No. 1 and

	•		a $1.7 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 Asset Swap.

See Note 3, “Asset Swap,” for information regarding the Asset Swap and the related changes in plant ownership percentages, including the Hatfield generation facility.

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Depreciation and Amortization	$	7.6	$	8.8	$	17.6	$	17.6

Depreciation and amortization decreased $1.2 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, primarily as a result of the extension of depreciable lives of Monongahela’s depreciable assets as required under the West Virginia Rate Order, partially offset by a change in Monongahela’s depreciable asset base due to the 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				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Taxes other than income taxes	$	7.0	$	5.9	$	14.0	$	11.8

Taxes other than income taxes increased $1.1 million and $2.2 million for the three and six months ended June 30, 2007, respectively, compared to the three and six months ended June 30, 2006, primarily due to changes in property taxes and business and occupation tax as the result of the 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				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Other income and expenses, net	$	3.8	$	2.6	$	7.5	$	4.8

Other income and expenses, net, increased $1.2 million for the three months ended June 30, 2007 compared to the three months ended June 30, 2006, primarily due to a $1.6 million increase in equity earnings from AGC as a result of the Asset Swap, partially offset by a $0.4 million decrease in interest and dividend income as a result of decreased interest income on investments due to lower investment balances.

Other income and expenses, net, increased $2.7 million for the six months ended June 30, 2007 compared to the six months ended June 30, 2006, primarily due to a $3.2 million increase in equity earnings from AGC as a result of the Asset Swap, partially offset by a $0.8 decrease in interest and dividend income as a result of decreased interest income on investments due to lower investment balances.

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

MONONGAHELA POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Interest Expense

Interest expense was as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Interest expense	$	8.1	$	4.5	$	12.0	$	9.1

Interest expense increased $3.6 million and $2.9 million for the three and six months ended June 30, 2007, respectively, compared to the three and six months ended June 30, 2006, primarily due to interest on $344 million of Senior Secured Sinking Fund Environmental Control Bonds, Series A, issued in April 2007. See Note 5, “Debt,” for additional information.

Income Tax Expense

The effective tax rate for the three months ended June 30, 2007 was 90.0% 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 nondeductible expenses that increased the rate for the quarter by 19.2%, applied to a small amount of pre-tax income.

The effective tax rate for the three months ended June 30, 2006 was 57.5% and was higher than income tax benefit calculated at the federal statutory tax rate, primarily due to state income taxes, and the accounting for deferred taxes related to utility property applied to a small amount of pre-tax loss.

The effective tax rate for the six months ended June 30, 2007 was 43.0% and was higher than income tax benefit calculated at the federal statutory tax rate, primarily due to state income taxes, the accounting for deferred taxes related to utility property and a nondeductible expense that increased the tax rate for the period by 1.0%.

The effective tax rate for the six months ended June 30, 2006 was a tax benefit of 111.8% and was higher than the income tax benefit calculated at the federal statutory tax rate, primarily due to state income taxes, and the accounting for deferred taxes related to utility property applied to a small amount of pretax loss.

ALLEGHENY GENERATING COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

Income Summary


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Operating revenues	$	17.1	$	13.9	$	34.0	$	31.2
Operating income	$	10.7	$	7.8	$	21.2	$	18.5
Income before income taxes	$	9.0	$	6.7	$	17.8	$	15.7
Net income	$	6.2	$	6.7	$	12.2	$	12.9

Operating Revenues and Expenses

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

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

Operating Revenues:Operating revenues were as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2007		2006		2007		2006
Operating revenues	$	17.1	$	13.9	$	34.0	$	31.2

Operating revenues increased $3.2 million and $2.8 million for the three and six months ended June 30, 2007, respectively, compared to the three and six months ended June 30, 2006, primarily as a result of increased expenditure recoveries. Expenditure recovery is determined on the basis of the “cost-of-service” formula described above. The increase in such recoveries resulted from an increase in recoveries from income tax expense, as 2006 income tax expense recoveries were reduced because of income tax refunds recorded in 2006.

Income Tax Expense

The effective tax rate for the three months ended June 30, 2007 was 31.3% and was 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.

The effective tax rate for the three months ended June 30, 2006 was (1.2)% and was lower than income tax benefit calculated at the federal statutory tax rate, primarily due to the allocation of consolidated tax savings, the amortization of deferred investment tax credits and the receipt of a state tax refund that decreased the tax rate for the quarter by 31.5%.

The effective tax rate for the six months ended June 30, 2007 was 31.4% and was 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.

The effective tax rate for the six months ended June 30, 2006 was 17.7% and was lower than income tax expense calculated at the federal statutory tax rate, primarily due to the allocation of consolidated tax savings, the amortization of deferred investment tax credits and the receipt of a state tax refund that decreased the tax rate for the period by 13.4%.

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


	Total				LOC’s			Available
(In millions)	Capacity		Borrowed		Issued			Capacity
AE Revolving Credit Facility (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 2008, which was issued 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 in connection with an Allegheny Ventures contractual obligation that expires in July 2008. 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 June 30, 2007 and December 31, 2006, was as follows:


	June 30, 2007				December 31, 2006
(In millions)	Amount		%		Amount		%
Debt	$	3,991.5		63.1	$	3,585.2		63.0
Common equity		2,305.2		36.5		2,080.4		36.6
Preferred equity		24.0		0.4		24.0		0.4

Total	$	6,320.7		100.0		5,689.6		100.0

Long-Term Debt and Contractual Obligations

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.

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.

Allegheny adopted the provisions of FIN 48 on January 1, 2007, which prescribes a comprehensive model for how companies should recognize, measure, present and disclose in their financial statements uncertain tax positions taken or expected to be taken on an income tax return. As a result of the implementation, Allegheny recognized additional liabilities related to its uncertain tax positions. See Note 4, Income Taxes, for additional information.

AE, Monongahela and AGC 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 are summarized as follows:


	Six Months Ended
	June 30,
(In millions)	2007			2006
Net income	$	186.8		$	144.5
Loss from discontinued operations, net of tax		—			1.7
Non-cash items included in earnings		284.6			251.9
Pension and other postretirement employee benefit contributions		(42.2	)		(65.4	)
Changes in certain assets and liabilities		(34.3	)		(11.8	)
Net cash used in operating activities of discontinued operations		—			(2.1	)

Net cash provided by operating activities	$	394.9		$	318.8

Cash flows provided by operating activities for the six months ended June 30, 2007 were $394.9 million, primarily as a result of net income of $186.8 million and non-cash charges of $284.6 million, primarily consisting of depreciation and amortization of $142.7 million and deferred income taxes of $123.3 million. These amounts were partially offset by contributions made to pension and other postretirement employee benefit plans of $42.2 million as well as changes in certain assets and liabilities of $34.3 million, primarily resulting from a $13.6 million change in receivables and payables as a result of normal working capital activity, an $8.5 million amortization of prepayments and a $12.2 million change in deferred income tax liabilities as a result of the implementation of FIN 48, partially offset by a change in accrued interest of $8.1 million from the timing of cash payments.

Cash flows provided by operating activities for the six months ended June 30, 2006 were $318.8 million, primarily as a result of net income of $144.5 million and non-cash charges of $251.9 million, primarily consisting of depreciation and amortization of $136.0 million and deferred income taxes of $89.6 million. These amounts were partially offset by

contributions made to pension and other postretirement employee benefit plans of $65.4 million as well as changes in certain assets and liabilities of $11.8 million, primarily resulting from normal working capital activity.

Investing Activities

Cash flows from investing activities are summarized as follows:


	Six Months Ended
	June 30,
(In millions)	2007			2006
Capital expenditures	$	(351.3	)	$	(196.8	)
Proceeds from sale of assets		0.3			2.1
Purchase of minority interest in Hunlock Creek Energy Ventures		—			(13.9	)
Decrease (increase) in restricted funds		(417.9	)		7.3
Other investments		(1.2	)		(1.7	)
Net cash provided by investing activities of discontinued operations		—			27.4

Net cash used in investing activities	$	(770.1	)	$	(175.6	)

Cash flows used in investing activities for the six months ended June 30, 2007 were $770.1 million and primarily consisted of $351.3 million of capital expenditures and a $417.9 million increase in restricted funds primarily as a result of the receipt and investment of the funds for the bonds relating to the Fort Martin Scrubber construction.

Cash flows used in investing activities for the six months ended June 30, 2006 were $175.6 million and primarily consisted of $196.8 million of capital expenditures and $13.9 million for the purchase of the minority interest in Hunlock Creek Energy Ventures, partially offset by the receipt of $27.4 million in proceeds from the sale of a receivable from the Tennessee Valley Authority.

Financing Activities

Cash flows from financing activities are summarized as follows:


	Six Months Ended
	June 30,
(In millions)	2007			2006
Issuance of long-term debt	$	451.2		$	1,142.1
Repayment of long-term debt		(56.4	)		(1,352.1	)
Proceeds from the exercise of stock options		9.0			10.2
Cash dividends paid to minority shareholder in Hunlock Creek Energy Ventures		—			(0.4	)

Net cash provided by (used in) financing activities	$	403.8		$	(200.2	)

Cash flows provided by financing activities for the six months ended June 30, 2007 were $403.8 million and consisted primarily of the issuance of long-term debt for the construction of the Scrubbers at Fort Martin of $451.2 million, partially offset by the repayment of certain long term debt of $56.4 million.

Cash flows used in financing activities for the six months ended June 30, 2006 were $200.2 million and consisted primarily of $1,352.1 million related to payments on and retirement of long-term debt, partially offset by $1,142.1 million in proceeds from the issuance of long-term debt.

Monongahela Cash Flows

Operating Activities

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


	Six Months Ended
	June 30,
(In millions)	2007		2006
Net income	$	14.5	$	28.6
Non-cash items included in earnings		37.3		36.1
Changes in certain assets and liabilities		47.7		12.0

Net cash provided by operating activities	$	99.5	$	76.7

Cash flows provided by operating activities for the six months ended June 30, 2007 were $99.5 million, primarily as a result of net income of $14.5 million and related net non-cash charges of $37.3 million, which consist primarily of depreciation of $33.5 million, deferred taxes of $11.8 million and a charge related to the Fort Martin Scrubber recovery of $7.2 million, respectively. These amounts were partially offset by a $10.5 million amortization of a purchase power liability and the recognition of a credit to expense related to the implementation of the ENEC. In addition, cash flows of $47.7 million were provided as a result of changes in certain assets and liabilities, consisting primarily of the receipt of $112.3 million as a prepayment of power from Potomac Edison related to the Fort Martin Scrubber securitization, partially offset by changes in receivables and payables of $45.1 million resulting from normal working capital activity and a $22.3 million increase in collateral deposits due primarily to increased collateral requirements.

Cash flows provided by operating activities for the six months ended June 30, 2006 were $76.7 million, primarily as a result of net income of $28.6 million and related net non-cash charges of $36.1 million, which consist primarily of depreciation of $32.7 million and deferred taxes of $16.0 million. These amounts were partially offset by a $15.5 million amortization of a purchase power liability. In addition, cash flows of $12.0 million were provided as a result of changes in certain assets and liabilities, consisting primarily of changes in receivables and payables of $3.8 million resulting from normal working capital activity as well as reductions in prepaid taxes of $6.6 million as a result of their amortization and collateral deposits of $11.4 million due primarily to reduced collateral requirements.

Investing Activities

Cash flows from investing activities are summarized as follows:


	Six Months Ended
	June 30,
(In millions)	2007			2006
Capital expenditures	$	(86.1	)	$	(41.0	)
Proceeds from asset sales		—			0.1
Notes receivable from affiliates		27.3			(60.7	)
Increase in restricted funds		(417.2	)		—

Net cash used in investing activities	$	(476.0	)	$	(101.6	)

Cash flows used in investing activities for the six months ended June 30, 2007 were $476.0 million and consisted of capital expenditures of $86.1 million and an increase in restricted funds of $417.2 million primarily as a result of amounts borrowed and received from Potomac Edison as a prepayment of power, but not yet used, for the construction of the Fort Martin Scrubbers. These items were partially offset by a reduction in a note receivable from an affiliate of $27.3 million.

Cash flows used in investing activities for the six months ended June 30, 2006 were $101.6 million and consisted of capital expenditures of $41.0 million and a note receivable from an affiliate of $60.7 million.

Financing Activities

Cash flows from financing activities are summarized as follows:


	Six Months Ended
	June 30,
(In millions)	2007			2006
Notes payable to affiliates	$	17.5		$	—
Issuance of long-term debt		338.8			(0.1	)
Repayment of long-term debt		(0.8	)		—
Asset Swap		1.0			—
Intercompany tax sharing agreement benefit		3.4			—
Cash dividends paid on preferred stock		(0.6	)		(0.6	)
Cash dividends paid on common stock		(3.0	)		(10.0	)

Net cash provided by (used in) financing activities	$	356.3		$	(10.7	)

Cash flows provided by financing activities for the six months ended June 2007 were $356.3 million and consisted primarily of $338.8 million from the issuance of long term debt associated with the Fort Martin Scrubber securitization and a note payable to an affiliate of $17.5 million, partially offset by $3.6 million in dividend payments.

Cash flows used in financing activities for the six months ended June 30, 2006 of $10.7 million consisted primarily of dividend payments.

AGC Cash Flows

Operating Activities

AGC’s cash flows from operating activities primarily result from the sale of electricity. Cash flows from operating activities are summarized as follows:


	Six Months Ended
	June 30,
(In millions)	2007		2006
Net income	$	12.2	$	12.9
Non-cash items included in earnings		5.3		5.2
Changes in certain assets and liabilities		0.2		(2.8	)

Net cash provided by operating activities	$	17.7	$	15.3

AGC’s cash flows provided by operating activities for the six months ended June 30, 2007 were $17.7 million and consisted primarily of net income of $12.2 million and related net non-cash charges of $5.3 million, which consist primarily of depreciation and deferred tax expenses.

AGC’s cash flows provided by operating activities for the six months ended June 30, 2006 were $15.3 million and consisted of net income of $12.9 million and related net non-cash charges of $5.2 million, consisting primarily of depreciation and deferred tax expense. These items were partially offset by changes in certain assets and liabilities of $2.8 million, primarily associated with normal working capital activity.

Investing Activities

For the six months ended June 30, 2007 and 2006 cash flows of $2.7 million and $1.4 million respectively, were used in investing activities as a result of capital expenditures.

Financing Activities


	Six Months Ended
	June 30,
(In millions)	2007			2006
Intercompany tax sharing agreement benefit	$	1.3		$	—
Cash dividends paid on common stock		(13.0	)		(13.0	)

Net cash used in financing activities	$	(11.7	)	$	(13.0	)

Cash flows used in financing activities for the six months ended June 30, 2007 and 2006 of $11.7 million and $13.0 million, respectively, consisted primarily of dividend payments.

Credit Ratings

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


	Moody’s	S & P	Fitch
AE:
Outlook	Under Review (1)	Stable	Stable
Corporate Credit Rating	Ba2(2)	BBB-	Not Rated
Senior Unsecured Debt	Ba2	BB+	BB+
Short-term Rating	SGL-2(3)	A-3	Not Rated
AE Supply:
Outlook	Under Review (1)	Stable	Stable
Senior Secured Debt	Baa3	BBB	BBB-
Senior Unsecured Debt	Ba3	BB+	BB+
Pollution Control Bonds	Not Rated	Not Rated	AAA
Monongahela:
Outlook	Stable	Stable	Negative
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:
Outlook	Negative	Stable	Negative
First Mortgage Bonds	Baa2	BBB	BBB
Environmental Control Bonds	Aaa	AAA	AAA
West Penn:
Outlook	Stable	Stable	Stable
Transition Bonds	Aaa	AAA	AAA
First Mortgage Bonds	Baa2	BBB	BBB+
Senior Unsecured Debt	Baa3	BBB-	BBB-
AGC:
Outlook	Under Review (1)	Stable	Stable
Senior Unsecured Debt	Ba3	BBB-	BB+


(1)		Under review for possible upgrade from stable

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

(3)		Liquidity rating

OTHER MATTERS

Critical Accounting Policies

A summary of critical accounting policies is included under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for all of the registrants in the 2006 Annual Report on Form 10-K. See also Note 5 “Debt” in Allegheny’s and Monongahela’s Notes to Consolidated Financial Statements, included herein, regarding the accounting for the Fort Martin scrubber project. 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

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 $5.2 million, for the 16-month period ended March 31, 2006. Following the evidentiary hearing, on August 10, 2006, an administrative law judge issued an initial decision that generally found fault with the methodologies used to develop the transition charges. That decision is now subject to review by FERC. The order that will be issued by FERC on review of the initial decision may require the Distribution Companies to refund some portion of the amounts received from these transition charges or entitle the Distribution Companies to receive additional revenue from these charges. In addition, the Distribution Companies may be required to pay additional amounts as a result of increases in the transition charges previously billed to them, or they may receive refunds of transition charges previously billed. Allegheny cannot predict the outcome of these proceedings. The Distribution Companies have entered into nine partial settlements with regard to the transition charges, and may enter into additional settlements in the future. FERC has approved three of these settlements, and approval is pending for the remaining partial settlements.

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

recovery mechanism for such facilities is unjust and unreasonable but adopted the Distribution Companies’ position that the implementation of a new rate design does not necessitate a change in the allocation of auction revenue rights and financial transmission rights. On April 19, 2007, FERC issued an Order on the initial decision that (a) retained the current license plate rate design for existing facilities, (b) requires that the parties develop a detailed “beneficiary pays” methodology for new facilities below 500 kV that would be set forth in the PJM tariff, and (c) allocates on a region-wide basis the costs of new, centrally-planned facilities that operate at or above 500 kV. The Distribution Companies are participating in settlement discussions regarding the “beneficiary pays” methodology.

In August 2005, PJM filed at FERC to replace its capacity market with a new Reliability Pricing Model (“RPM”) to address reliability concerns. On April 20, 2006, FERC issued an initial order that found PJM’s capacity market to be unjust and unreasonable and set a process to resolve features of the RPM that needed to be analyzed further before it could determine whether the RPM is a just and reasonable capacity market process. FERC ordered the implementation of settlement procedures in this proceeding, and AE Supply and the Distribution Companies participated in a settlement agreement that was filed with the FERC on September 29, 2006. The settlement agreement created a locational capacity market in PJM, in which PJM procures needed capacity resources through auctions held three years in advance at prices and in quantities determined by an administratively established demand curve. Under the settlement agreement, capacity needs in PJM will be met either through purchases made in the proposed auctions or though commitments by load serving entities to self-supply their capacity needs. On December 22, 2006, FERC conditionally approved the settlement agreement, the implementation of which began with the 2007-2008 PJM planning year. Capacity auctions were held in April and June of this year, and additional auctions are expected to be conducted in October and January. On June 25, 2007, FERC issued an order denying pending rehearing request of the December 22, 2006 order and affirming its acceptance of the RPM settlement agreement. On July 25, 2007, a coalition of PJM industrial customers and the office of the peoples’ counsel of Maryland and the District of Columbia filed a joint rehearing request challenging FERC’s finding that PJM’s new capacity markets are just and reasonable. This rehearing request is pending before FERC.

On July 3, 2006, PJM filed at FERC a proposal to implement a process for allocating long-term transmission rights (“LTTRs”). The PJM proposal would allocate a ten-year financial transmission right to PJM load serving entities (“LSEs”) based on the LSEs’ zonal base load. The PJM proposal created a link between PJM’s long-term transmission planning process and the LTTR allocation process to ensure that the transmission system is being upgraded as necessary to maintain the availability of the LTTRs that PJM will allocate. On November 22, 2006, FERC issued an Order accepting PJM’s proposal, subject to modifications. On January 22, 2007, PJM filed a related settlement agreement, as well as a proposal to allocate any costs to fund LTTRs fully to holders of financial transmission rights on a pro-rata basis. FERC accepted this settlement agreement and related cost allocation proposal in an order issued on May 17, 2007. Requests for rehearing of the May 17^th order are pending at FERC. FERC has also ordered the creation of a stakeholder process to determine whether the PJM proposed full funding mechanism that was accepted by FERC should be changed subsequent to the 2007-2008 PJM planning year. AE Supply and the Distribution Companies are participating in this stakeholder process.

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

On July 20, 2006, FERC approved incentive rate treatments for TrAIL. On February 21, 2007, TrAIL Company submitted to FERC a filing under Section 205 of the Federal Power Act (the “FPA”) to implement a formula tariff rate, with a proposed effective date of June 1, 2007, that includes the incentive rate treatments approved by FERC. On May 31, 2007, FERC issued an order permitting the formula tariff rate to become effective on June 1, 2007 subject to refund and hearing on specifically identified issues. One of the issues set for hearing is the level of the incentive return on equity for TrAIL. TrAIL Company is currently engaged in settlement discussions regarding the issues set for hearing.

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, which FERC approved on April 18, 2007. On

February 27, 2007, TrAIL Company submitted an application to PJM for membership as a transmission owner, which PJM approved effective as of March 28, 2007.

On August 8, 2006, the United States Department of Energy (the “DOE”) published a congestion study in which the general area of the TrAIL Project was classified as a “critical congestion area” that merits further federal attention. 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. 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. On July 6, 2007, Allegheny, the Distribution Companies and TrAIL Company filed comments supporting the designation of the Mid-Atlantic corridor.

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. Several intervenors have protested the allocations for the TrAIL Project. 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. The Distribution Companies are participating in settlement discussions regarding the “beneficiary pays” methodology.

On June 22, 2007, the PJM Board of Managers authorized the construction of 250 miles of 765-kV extra-high voltage transmission from the Amos substation, which is located near St. Albans, West Virginia and is owned by American Electric Power (“AEP”), to Allegheny’s Bedington substation, which is located northeast of Martinsburg, West Virginia. Another 40 miles of transmission, consisting of twin-circuit 500-kV transmission, will be constructed from the Bedington substation to a new substation at Kemptown, Maryland, which is located southeast of Frederick, Maryland. In April 2007, Allegheny and AEP announced plans to form a joint venture to build the project (the “PATH Project”). Based on current plans, the total project is estimated to cost approximately $1.8 billion. Allegheny currently estimates that its total investment in the project will be approximately $1.2 billion.

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. TrAIL Company is currently responding to discovery with regard to its application. An evidentiary hearing on this matter is scheduled to begin on January 21, 2008.

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

The regulations provide that the incumbent EDC will be the default service provider (“DSP”) in its service territory, although the Pennsylvania PUC may reassign the default service obligation to one or more alternative DSPs when necessary for the accommodation, safety and convenience of the public. The DSP must file a default service plan not later than 12 months prior to the end of the applicable generation rate cap. The default service plan must identify the DSP’s generation supply acquisition strategy and include a rate design plan to recover all reasonable costs of default service. The default service plan must be designed to acquire generation supply at prevailing market prices to meet the DSP’s anticipated default service obligation at reasonable costs. A DSP’s affiliate generation supplier may participate in the DSP’s competitive bid solicitations for generation service. DSPs will use an automatic energy adjustment clause to recover all reasonable costs of obtaining alternative energy pursuant to the Alternative Energy Portfolio Standards Act, and the DSP may use an automatic adjustment clause to recover non-alternative energy default service costs. Automatic adjustment clauses will be subject to annual review and audit by the Pennsylvania PUC. Default service rates shall be adjusted on a quarterly basis, or more frequently, for

100

customer classes with a peak load up to 500 KW, and on a monthly basis, or more frequently, for customer classes with peak loads greater than 500 KW.

West Virginia

Transmission Expansion.On March 30, 2007, TrAIL Company filed an application with the West Virginia PSC for authorization to construct the TrAIL project in West Virginia. The application requests issuance of an order by December 31, 2007. A procedural schedule has not been issued in this proceeding. TrAIL Company is currently responding to discovery with regard to its application.

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 included a $126 million increase in rates related to fuel and purchased power costs, including reinstatement of a fuel cost recovery clause, adjustable annually, to reflect upward or downward changes in the cost of fuel and purchased power, and a $26.2 million decrease in base rates. On May 22, 2007, the West Virginia PSC issued a final Order directing Monongahela and Potomac Edison to reduce overall rates by approximately $6.2 million effective May 23, 2007, by increasing fuel and purchased power cost-related rates by $126 million and reducing base rates by approximately $132 million, which includes changes in authorized depreciation rates that will reduce depreciation expense by approximately $16 million. The Order approved the request by Monongahela and Potomac Edison to reinstate a fuel cost recovery clause. On June 15, 2007, Monongahela and Potomac Edison filed a Petition for Reconsideration and Clarification (“Petition for Reconsideration”) of certain findings in the Order. Other parties in the proceeding were expected to submit responses to the Petition for Reconsideration on July 9, 2007. The West Virginia PSC has no procedural deadline for responding to these petitions.

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.

101

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, directing the Maryland Public Service Commission (the “Maryland PSC”), to among other things investigate options available to Allegheny to implement a rate mitigation or rate stabilization plan to protect its customers from rate shock when capped rates end on January 1, 2009.

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, 2007, issued an order approving the plan with the opt-out and refund procedures largely as agreed to by Allegheny. The plan became operational in June 2007. Of Allegheny’s more than 216,000 residential customers in Maryland, approximately 7,400, or 3.5%, elected to opt-out of Allegheny’s plan.

Advanced Metering and Demand Side Management Initiatives. On June 8, 2007, the Maryland PSC established a collaborative process to consider the following four items: 1) technical standards for, and operational capabilities of, advanced meters; 2) the extent to which demand side management programs are to be offered in Maryland on a competitively-neutral basis; 3) recovery of costs of demand side management programs; and 4) the appropriate measure(s) of cost effectiveness of demand side management programs to be employed in Maryland. The staff of the Maryland PSC filed its report on these matters on July 6, 2007.

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. An evidentiary hearing in this matter is scheduled to commence on January 14, 2008.

Purchased Power Filing.During the 2007 session, the Virginia General Assembly amended the Virginia Electric Utility Restructuring Act of 1999 (the “Restructuring Act”), to re-regulate the provision of electric generation services in the Commonwealth beginning January 1, 2009. Until that time, Potomac Edison’s retail electric customers in Virginia have the right to choose their electricity generation supplier. Until December 31, 2008, Potomac Edison is the PLR for those customers who do not choose an alternate generation supplier or whose alternate generation supplier does not deliver. After January 1, 2009, Potomac Edison will provide generation services to all customers in Virginia at regulated rates. Potomac Edison had a power purchase agreement with AE Supply to provide it with the amount of electricity necessary to meet its PLR retail obligations through June 30, 2007 at capped generation rates. In April 2007, Potomac Edison conducted a competitive bidding

102

process to purchase its PLR requirements from the wholesale market and AE Supply was the successful bidder with respect to a substantial portion of these requirements. On July 1, 2007 Potomac Edison began to purchase its PLR requirements at market prices. Market prices for purchased power resulting from that bidding process are higher than the rates Potomac Edison is currently allowed to recover from its retail customers.

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

On April 20, 2007 the Virginia SCC issued a scheduling order requiring Potomac Edison to file a legal memorandum addressing the applicability of a Memorandum of Understanding (the “MOU”) signed by Potomac Edison in 2000 (in connection with the transfer of its generating assets to an affiliate) on Potomac Edison’s request to recover its purchased power expenses effective July 1, 2007. Potomac Edison filed a Motion for Interim Rates on May 10, 2007. Potomac Edison and other parties filed their legal arguments on the effect of the MOU. On June 28, 2007, the Virginia SCC issued an Order Denying the Application and rejecting Potomac Edison’s request to recover its purchased power expenses effective July 1, 2007, denying Potomac Edison’s Motion for Interim Rates and dismissing the case. On July 6, 2007, Potomac Edison filed with the Virginia SCC a Motion for Suspension of Order and Motion for Interim Rates, which the Virginia SCC failed to act upon within the time prescribed. Potomac Edison then filed an appeal with the Virginia Supreme Court on July 26, 2007 and also asked the Virginia Supreme Court for relief pending appeal.

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

See Part II, Item 1A, “Risk Factors” below.

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 June 30, 2007 and December 29, 2006, this calculation yielded a VaR of $0 and $8,000, respectively. This VaR decrease is due to the roll-off of all forward positions of the portfolio.

103

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

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.

104

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Note 16, “Commitments and Contingencies” to the consolidated financial statements of AE for information regarding legal proceedings. In addition, the registrants from time to time are involved in litigation and other legal disputes in the ordinary course of business.

ITEM 1A. RISK FACTORS

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

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

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

Virginia

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

On April 20, 2007, the Virginia SCC issued a scheduling order requiring Potomac Edison to file a legal memorandum addressing the applicability of the MOU signed by Potomac Edison in 2000 (in connection with the transfer of its generating assets to an affiliate) on Potomac Edison’s request to recover its purchased power expenses effective July 1, 2007. Potomac Edison filed a Motion for Interim Rates on May 10, 2007. Potomac Edison and other parties filed their legal arguments on the effect of the MOU. On June 28, 2007, the Virginia SCC issued an Order Denying the Application and rejecting Potomac Edison’s request to recover its purchased power expenses effective July 1, 2007, denying Allegheny’s Motion for Interim Rates and dismissing the case. On July 6, 2007, Potomac Edison filed with the Virginia SCC a Motion for Suspension of Order and Motion for Interim Rates, which the Virginia SCC failed to act upon within the time prescribed. Potomac Edison then filed an appeal with the Virginia Supreme Court on July 26, 2007 and also asked the Virginia Supreme Court for relief pending appeal.

105

West Virginia

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

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

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

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

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

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

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

Additionally, Allegheny has contracted with specialized vendors to acquire some of the necessary materials and construction related services in order to accomplish the installation of Scrubbers at the Fort Martin and Hatfield’s Ferry generation facilities and in connection with the TrAIL project, and may in the future enter into additional such contracts with respect to these and other capital projects, including the PATH Project. As such, Allegheny is exposed to the risk that these contractors may not perform as required under their contracts. Should this occur, Allegheny may be forced to find alternate arrangements, which may cause delay and/or increased costs. Furthermore, Allegheny can provide no assurance that it would be able to make such alternate arrangements on terms acceptable to it or at all.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

106

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

AE. AE’s annual meeting of stockholders was held on May 17, 2007. At the annual meeting, votes were taken for: (1) the election of directors; (2) ratification of the appointment of PricewaterhouseCoopers LLP as Allegheny’s independent registered public accounting firm; (3) a stockholder proposal to recoup unearned management bonuses under certain conditions; (4) a stockholder proposal to separate the roles of the Chief Executive Officer and the Chairman of Board; (5) a stockholder proposal requesting a director election majority vote standard; (6) a stockholder proposal regarding special shareholder meetings; (7) a stockholder proposal regarding performance-based stock options; (8) a stockholder proposal requesting a report on utilizing the National Interest Electric Transmission Corridor (“NIETC”) designation; and (9) a stockholder proposal requesting a report on climate change.

AE’s stockholders elected H. Furlong Baldwin, Eleanor Baum, Paul J. Evanson, Cyrus F. Freidheim, Jr., Julia L. Johnson, Ted J. Kleisner, Steven H. Rice, Gunnar E. Sarsten and Michael H. Sutton to serve on the Board of Directors for one-year terms, which will expire in 2008. Stockholders ratified the appointment of PricewaterhouseCoopers LLP as Allegheny’s independent registered public accounting firm.

The stockholders did not approve four stockholder proposals, including one regarding separating the roles of the Chief Executive Officer and the Chairman of Board. Based on a majority of the votes cast, the stockholders approved stockholder proposals to amend corporate governance documents to implement majority voting for the election of directors, to give holders of at least 10% to 25% of outstanding common shares the ability to call a special stockholder meeting, and to adopt a policy regarding performance-based stock options.

107

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

Election of directors:


Nominees for Director	Votes For		Votes withheld
H. Furlong Baldwin		139,295,097		1,945,877
Eleanor Baum		137,431,147		3,809,827
Paul J. Evanson		138,118,834		3,122,140
Cyrus F. Freidheim, Jr.		138,906,539		2,334,435
Julia L. Johnson		139,463,641		1,777,333
Ted J. Kleisner		139,451,571		1,789,403
Steven H. Rice		137,502,090		3,738,884
Gunnar E. Sarsten		137,454,891		3,786,083
Michael H. Sutton		139,442,670		1,798,304

Other items as described above:


Item	Votes For		Votes Against		Abstentions		Broker Non-Votes
(2)		137,581,883		2,616,980		1,042,111		0
(3)		13,625,587		106,396,564		2,678,385		42,834,921
(4)		18,819,301		102,443,460		1,437,778		42,834,919
(5)		60,854,748		60,358,994		1,486,793		42,834,922
(6)		68,791,040		51,567,108		2,342,388		42,834,922
(7)		60,699,596		56,633,223		5,367,712		42,834,926
(8)		8,843,999		99,152,056		14,704,478		42,834,924
(9)		42,633,794		65,308,490		14,758,250		42,834,923

Monongahela. At the annual meeting of Monongahela shareholders held on April 19, 2007, votes were taken for the election of directors. The total number of votes cast was 5,891,000, with all votes being cast for the election of the following directors: Paul J. Evanson, David E. Flitman and Philip L. Goulding.

AGC. No matters were submitted to a vote of security holders of AGC during the second quarter of 2007.

ITEM 5. OTHER INFORMATION

None.

108

ITEM 6. EXHIBITS

EXHIBIT INDEX

Allegheny Energy, Inc.


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

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

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

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

109

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

110

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

111

SIGNATURE

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


	ALLEGHENY ENERGY, INC.
Date: August 8, 2007	By:	/s/ Philip L. Goulding
		Philip L. Goulding
		Senior Vice President and Chief Financial Officer

	MONONGAHELA POWER COMPANY
Date: August 8, 2007	By:	/s/ Philip L. Goulding
		Philip L. Goulding
		Vice President and Principal Financial Officer

	ALLEGHENY GENERATING COMPANY.
Date: August 8, 2007	By:	/s/ Philip L. Goulding
		Philip L. Goulding
		Vice President and Principal Financial Officer

112

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

Allegheny Energy (AYE) Inactive 10-Q2007 Q2 Quarterly report

Content analysis