Edgar Filing: RANGE RESOURCES CORP

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K/A

CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934

Date of report (Date of earliest event reported):
January 25, 2005 (December 10, 2004)

RANGE RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)


Delaware	0-9592	34-1312571

(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)


777 Main Street, Suite 800
Ft. Worth, Texas		76102

(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (817) 870-2601

(Former name or former address, if changed since last report): Not applicable

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligations of the registrant under any of the following provisions (see General Instruction A.2. below):


o		Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o		Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o		Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o		Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

TABLE OF CONTENTS


Item 2.01 — Completion of Acquisition or Disposition of Assets
Item 9.01 — Financial Statements and Exhibits
SIGNATURES
Stock Purchase Agreement
Consent of KPMG LLP

Table of Contents

Item 2.01 – Completion of Acquisition or Disposition of Assets

On December 10, 2004 Range Resources Corporation (the “Company”) consummated the acquisition of the PMOG Holdings, Inc. pursuant to a Stock Purchase Agreement by and between the Company and First Reserve Fund IX, L.P., a Delaware limited liability company, Donald E. Vandenberg, Richard M. Brillhart, Jeremy H. Grantham, Charles Ian Landon. A Current Report on Form 8-K was filed on December 15, 2004 to report this transaction.

Item 9.01 - Financial Statements and Exhibits

(a)	Financial Statements of Businesses Acquired

	Audited consolidated balance sheet of PMOG Holdings, Inc. and subsidiaries as of December 31, 2003 and the related statements of operations, shareholder’s equity, comprehensive income and cash flows for the year ended December 31, 2003 is included herein. Unaudited consolidated balance sheet of PMOG Holdings, Inc. and subsidiaries as of September 30, 2004 and the related statements of operations, shareholders equity, comprehensive income, and cash flows for the nine months ended September 30, 2004 is included herein.

(b)	Pro Forma Financial Information

	Unaudited pro forma condensed statements of operations of Range Resources Corporation for the year ended December 31, 2003 and the nine months ended September 30, 2004 are included herein. Unaudited pro forma balance sheet of Range Resources Corporation as of September 30, 2004 is included herein.

(c)	Exhibits


Exhibit
Number		Description
*2.1		Stock Purchase Agreement by and between Range Resources Corporation and First Reserve Fund IX, L.P., Donald E. Vandenberg, Richard M. Brillhart, Jeremy H. Grantham and Charles Ian Landon dated November 22, 2004

		*All schedules to this Exhibit 2.1 filed herewith have been omitted in accordance with Item 601 (b)(2) of Regulations S-K. The Company will furnish supplemetally a copy of any omitted schedule to the Commission upon request

*23.1		Consent of KPMG LLP

**99.1		Press Release dated December 14, 2004 (incorporated by reference to Exhibit 99.1 to the Company’s Form 8-K as filed with the SEC on December 15, 2004)

*		Filed herewith

**		Previously filed

Table of Contents

Certain information included in this report contains certain statements (other than statements of historical fact) that constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. When used herein, the words “budget,” “budgeted,” “assumes,” “should,” “goal,” “anticipates,” “expects,” “believes,” “seeks,” “plans,” “estimates,” “intends,” “projects” or “targets” and similar expressions that convey the uncertainty of future events or outcomes are intended to identify forward-looking statements. Where any forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that while we believe these assumptions or bases to be reasonable and to be made in good faith, assumed facts or bases almost always vary from actual results and the difference between assumed facts or bases and the actual results could be material, depending on the circumstances. It is important to note that our actual results could differ materially from those projected by such forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable and such forward-looking statements are based upon the best data available at the date this report is filed with the SEC, we cannot assure you that such expectations will prove correct. Factors that could cause our results to differ materially from the results discussed in such forward-looking statements include, but are not limited to, the following: production variance from expectations, volatility of oil and gas prices, hedging results, the need to develop and replace reserves, the substantial capital expenditures required to fund operations, exploration risks, environmental risks, uncertainties about estimates of reserves, competition, litigation, government regulation, political risks, our ability to implement our business strategy, costs and results of drilling new projects, mechanical and other inherent risks associated with oil and gas production, weather, availability of drilling equipment and changes in interest rates. All such forward-looking statements in this document are expressly qualified in their entirety by the cautionary statements in this paragraph, and the Company undertakes no obligation to publicly update or revise any forward-looking statements.

SIGNATURES

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 hereunto duly authorized.


	RANGE RESOURCES CORPORATION
	By:	/s/ ROGER S. MANNY
		Roger S. Manny
		Chief Financial Officer

Date: January 26, 2005

Table of Contents

Index to Financial Statements


	Page
Description	number
Consolidated Financial Statements of PMOG Holdings, Inc. and Subsidiaries		F-1
Unaudited Pro Forma Combined Financial Information of Range Resources Corporation		F-39

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Consolidated Financial Statements

December 31, 2003

(With Independent Auditors’ Report Thereon)

F-1

Independent Auditors’ Report

The Board of Directors and Shareholder
PMOG Holdings, Inc. and Subsidiaries:

We have audited the accompanying consolidated balance sheet of PMOG Holdings, Inc. and subsidiaries (Successor) as of December 31, 2003 and the related consolidated statements of operations, shareholder’s equity and comprehensive income, and cash flows for the period from January 1, 2003 to August 12, 2003 (Predecessor period), and from August 13, 2003 to December 31, 2003, (Successor period). These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the aforementioned Successor financial statements present fairly, in all material respects, the financial position of PMOG Holdings, Inc. and subsidiaries as of December 31, 2003, and the results of their operations and their cash flows for the Successor period, in conformity with accounting principles generally accepted in the United States of America. Further, in our opinion, the aforementioned Predecessor financial statements present fairly, in all material respects, the results of operations and cash flows for the Predecessor period, in conformity with accounting principles generally accepted in the United States of America.

As discussed in note 1 to the consolidated financial statements, effective August 13, 2003, a wholly owned subsidiary of PMOG Holdings, Inc. acquired all of the outstanding stock of the Predecessor in a business combination accounted for as a purchase. As a result of the acquisition, the financial information for the period after the acquisition is presented on a different cost basis than that for the period before the acquisition and, therefore, is not comparable.

As discussed in note 1 to the consolidated financial statements, the Company adopted, in the predecessor period, the provisions of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, in 2003.

September 30, 2004 except for footnote 12
which is as of November 22, 2004

F-2

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Consolidated Balance Sheet

December 31, 2003


Assets
Current assets:
Cash and cash equivalents	$	1,150,212
Trade receivables less allowance for doubtful accounts of $0 (note 7)		3,760,096
Prepaid expenses and other current assets		23,530
Deferred tax asset (note 3)		549,361

Total current assets		5,483,199

Properties and equipment:
Natural gas properties		85,878,454
Transportation and other equipment		984,345
Less accumulated depreciation, depletion, and amortization		(1,362,578	)

Net properties and equipment		85,500,221

Other assets:
Deferred financing fees, net of amortization of $125,335		877,345

Total assets	$	91,860,765

F-3

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Consolidated Balance Sheet

December 31, 2003


Liabilities and Shareholder’s Equity
Current liabilities:
Accounts payable and accrued expenses	$	2,331,793
Income taxes payable		943,652
Fair value of gas hedges (note 8)		1,408,620
Current portion of capital lease obligation (note 11)		9,783

Total current liabilities		4,693,848

Long-term debt:
Credit facility (note 4)		60,000,000
Long-term portion of capital lease obligation (note 11)		17,957

		60,017,957

Other long-term liabilities:
Fair value of gas hedges – noncurrent (note 8)		470,372
Asset retirement obligation		435,664
Deferred income tax liability – noncurrent		846,907

		1,752,943

Total liabilities		66,464,748

Shareholder’s equity:
Common stock, $0.01 par value. 10,000 shares authorized, 1,000 shares issued and outstanding		10
Preferred stock, $0.01 par value. 10,000 shares authorized, none issued and outstanding		—
Additional paid-in capital		23,196,825
Restricted shares issuable (0.75 common shares)		58,450
Retained earnings		2,924,758
Accumulated other comprehensive (loss), net		(784,026	)

Total shareholder’s equity		25,396,017

Total liabilities and shareholder’s equity	$	91,860,765

See accompanying notes to consolidated financial statements.

(Continued)

F-4

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Consolidated Statement of Operations

Period from August 13, 2003 to December 31, 2003 (Successor) and period from
January 1, 2003 to August 12, 2003 (Predecessor)


	Successor		Predecessor
	Period from		Period from
	August 13, 2003		January 1, 2003
	to		to
	December 31, 2003		August 12, 2003
Revenues, net (note 8)	$	9,140,114		14,527,311

Expenses:

Operating expenses (exclusive of depreciation, depletion, and amortization shown separately below)		1,218,456		1,774,033
Depreciation, depletion, and amortization		1,362,578		959,548
Selling, general, and administrative expenses		603,302		642,243

Total expenses		3,184,336		3,375,824

Operating profit		5,955,778		11,151,487

Other expenses (income):
Interest expense (income)		1,057,016		(3,000	)

Income before income taxes and cumulative effect of change in accounting principle		4,898,762		11,154,487
Income tax expense (note 3)		1,974,004		3,958,290


Net income before cumulative effect of change in accounting principle		2,924,758		7,196,197
Cumulative effect of change in accounting principle (net of tax of $113,188) (note 1(m))		—		(169,781	)

Net income	$	2,924,758		7,026,416

See accompanying notes to consolidated financial statements.

(Continued)

F-5

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Consolidated Statement of Shareholder’s Equity and Comprehensive Income

Period from August 13, 2003 to December 31, 2003 (Successor) and period from
January 1, 2003 to August 12, 2003 (Predecessor)


										Accumulated
										other
			Additional			Restricted				comprehensive			Total
	Common		paid-in			shares		Retained		income (loss),			shareholder’s
	stock		capital			issuable		earnings		net			equity
Balance as of January 1, 2003	$	10		500,000			—		31,380,209		(466,935	)		31,413,284
Net income		—		—			—		7,026,416		—			7,026,416
Change in fair value of cash flow hedges, net of tax benefit of $399,824		—		—			—		—		(625,365	)		(625,365	)

Reclassification adjustment for cash flow hedge expense realized in net income, net of tax benefit of $698,356		—		—			—		—		1,092,300			1,092,300


Comprehensive income														7,493,351


Balance as of August 12, 2003	$	10		500,000			—		38,406,625		—			38,906,635




Balance as of August 13, 2003	$	—		—			—		—		—			—
Issuance of common stock (1,000 shares)		10		—			—		—		—			10
Capital contributions		—		23,558,985			—		—		—			23,558,985
Return of capital		—		(362,160	)		—		—		—			(362,160	)
Restricted shares award		—		—			58,450		—		—			58,450
Net income		—		—			—		2,924,758		—			2,924,758

Change in fair value of open cash flow hedges, net of tax benefit of $364,031		—		—			—		—		(584,861	)		(584,861	)

Reclassification adjustment for cash flow hedge benefit realized in net income, net of tax expense of $127,335		—		—			—		—		(199,165	)		(199,165	)

Comprehensive income														2,140,732


Balance as of December 31, 2003	$	10		23,196,825			58,450		2,924,758		(784,026	)		25,396,017

See accompanying notes to consolidated financial statements.

(Continued)

F-6

PMOG HOLDINGS, INC. AND SUBSIDIARIES
Consolidated Statement of Cash Flows

Period from August 13, 2003 to December 31, 2003 (Successor) and period from
January 1, 2003 to August 12, 2003 (Predecessor)


	Successor			Predecessor
	Period from August			Period from
	13, 2003 to			January 1, 2003 to
	December 31, 2003			August 12, 2003
Cash flows from operating activities:
Net income	$	2,924,758			7,026,416
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization		1,362,578			959,548
Deferred income taxes		1,707,245			(840,375	)
Amortization of deferred financing costs		125,335			—
Accretion of asset retirement obligations		9,886			17,809
Cumulative effect of change in accounting principle		—			169,781
Loss on disposal of property and equipment		8,424			2,477
Change in operating assets and liabilities:
Accounts receivable		(3,760,096	)		45,692
Prepaid expenses and other current assets		(23,530	)		—
Accounts payable and accrued expenses		2,331,793			1,052,018
Income taxes payable		266,759			4,798,665

Net cash provided by operating activities		4,953,152			13,232,031

Cash flows from investing activities:
Capital expenditures		(86,505,949	)		(5,276,008	)
Proceeds from sale of natural gas property		92,136			—

Net cash used in investing activities		(86,413,813	)		(5,276,008	)

Cash flows from financing activities:
Intercompany financing		—			(7,956,023	)
Proceeds from issuance of 100 shares of common stock and receipt of additional capital contributions		23,558,995			—
Restricted shares award		58,450			—
Borrowings under long-term credit facility		60,450,000			—
Payments under long-term credit facility		(450,000	)		—
Deferred financing fees		(1,002,680	)		—
Payments on capital lease obligations		(3,892	)		—

Net cash provided by (used in) financing activities		82,610,873			(7,956,023	)

Net change in cash and cash equivalents		1,150,212			—
Cash and cash equivalents at beginning of period		—			—

Cash and cash equivalents at end of period	$	1,150,212			—

Supplemental disclosures of cash flow information:
Cash paid for interest	$	526,881			—
Cash paid for taxes		—			—
Noncash transactions:
Net unrealized gain (loss) on investment in derivative, net of deferred income taxes	$	(1,146,186	)		—
Equipment acquired through capital lease obligation		31,632			—
Derivatives with a negative value of $603,600 were assumed by the Company from its parent on August 27, 2003. The after tax effect of this transaction resulted in a $362,160 return of capital.

See accompanying notes to consolidated financial statements.

(Continued)

F-7

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2003

(1)

Summary of Significant Accounting Policies

	*(a)*	*Description of Business*

		Pine Mountain Oil and Gas, Inc. (PMOGI), which was established in Virginia in 1984, was formerly wholly owned by Pittston Coal Company, an indirectly wholly owned subsidiary of The Brink’s Company (formerly, The Pittston Company). On August 13, 2003, PMOGI’s stock was sold to Pine Mountain Acquisition, Inc (PMAI) for a total consideration of approximately $83.6 million ($23.2 million cash, $60.0 million debt plus transaction costs of $0.4 million). PMAI is a wholly owned subsidiary of PMOG Holdings, Inc. (ultimately owned by First Reserve Fund IX, L.P.) and Pine Mountain Oil and Gas, Inc. represents their only asset and represents all of their operations. PMOG Holdings, Inc., PMAI and PMOGI are collectively referred to herein as the Company.

		Subsequent to the acquisition, the accounts of the Company have been adjusted using the push down basis of accounting to recognize the allocation of the consideration paid for the common stock to the respective net assets acquired. The acquisition was accounted for as a purchase and the total purchase price was allocated to the properties and equipment.

		The Company is in the business of producing and selling natural gas from company-owned natural gas wells and receiving royalty income from natural gas production and sales of natural gas reserves by third parties. The Company’s natural gas reserves are located in West Virginia, Virginia, and Wyoming. The Company controls approximately 414,000 acres of oil and gas interests through direct ownership, leases, or joint ventures.

		The majority of the Company’s production comes from coalbed methane (CBM) production in Virginia, while the remainder comes from conventional reservoirs in Virginia and West Virginia and from CBM reserves in Wyoming. Approximately 50% of the Company’s revenue comes from working interests and 50% from royalty interests. The Company has an overriding royalty interest on certain reserves located in Wyoming.

	*(b)*	*Basis of Presentation*

		The accompanying consolidated financial statements include the accounts of PMOG Holdings, Inc. and its wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

		As a result of the acquisition discussed above, the financial statements for the period subsequent to August 12, 2004 have been presented on the Company’s new basis of accounting (Successor Company or Successor Period), while the results of its operations for the period from January 1, 2003 to August 12, 2003 reflect the historical results of the predecessor company (Predecessor Company or Predecessor Period).

	*(c)*	*Cash Equivalents*

		For purposes of the statement of cash flows, the Company considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents.

	*(d)*	*Trade Accounts Receivable*

		Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. The Company determines the allowance based

(Continued)

F-8

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2003

		on historical write-off experience. The Company reviews its allowance for doubtful accounts monthly. Past due balances over 90 days and a specified amount are reviewed individually for collectibility. All other balances are reviewed on a pooled basis. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. The Company does not have any off-balance-sheet credit exposure related to its customers.

	*(e)*	*Natural Gas Properties*

		Of the 414,000 acres controlled by the Company, approximately 250,000 are located in Virginia, 120,000 are located in West Virginia, and 44,000 are located in Wyoming.

		Approximately 250,000 acres of the 414,000 acres controlled by the Company are located in Southwest Virginia. Development of both CBM and conventional resources is ongoing in this area. Equitable Production Company (Equitable) operates natural gas production facilities on 220,000 acres under agreements providing the Company both a 12.5% royalty interest and rights to participate in a working interest on a well-by-well basis. The remaining 30,000 acres in Virginia are held under a lease by Columbia Natural Resources (Columbia), which provides a royalty interest to the Company. In addition to these properties, the Company participated in a CBM project in Pulaski and Montgomery counties in Virginia. Following the initial well test in the spring of 2003, the Company decided to sell its interests in this project in October 2003 with a resulting loss of $8,400.

		In West Virginia, the Company’s properties total approximately 120,000 acres. The largest area consists of 85,000 acres, with 75,000 acres owned and 10,000 acres leased. The Company currently operates 88 wells on this property. The remaining 35,000 acres provide a royalty interest through provisions of a Columbia lease.

		The Wyoming properties amount to approximately 44,000 acres, on which an overriding royalty interest of 1 to 2% is generated on an extensive, ongoing development program.

		Exploration and development costs are accounted for by the successful efforts method.

		The Company assesses impairment of capitalized costs of proved natural gas properties by comparing net capitalized costs to undiscounted future net cash flows using expected prices. Prices utilized in each year’s calculation for measurement purposes and expected costs are held constant throughout the estimated life of the properties. If net capitalized costs exceed undiscounted future net cash flow, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows.

		Property acquisition costs are capitalized when incurred. Geological and geophysical costs and delay rentals are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether the wells have discovered economically producible reserves. If reserves are not discovered, such costs are expensed as dry holes. Development costs, including equipment and intangible drilling costs related to both producing wells and developmental dry holes, are capitalized.

		Unproved properties are assessed on a property-by-property basis and properties considered to be impaired are charged to expense when such impairment is deemed to have occurred.

		Costs of certain proved properties, exploration and development costs and equipment, are depreciated or depleted by the units-of-production method based as estimated proved developed gas reserves.

(Continued)

F-9

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2003

		Upon sale or retirement of complete fields of depreciable or depletable property, the net cost thereof, less proceeds or salvage value, is credited or charged to income. Upon retirement of a partial unit of property, the cost thereof is charged to accumulated depreciation and depletion.

	*(f)*	*Transportation and Other Equipment*

		Transportation and other equipment are carried at cost. Depreciation is provided principally on the straight-line method over useful lives of 3 to 15 years.

		Long-lived assets, such as transportation and other equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset.

		Maintenance and repairs are charged to expense as incurred. Major renewals and betterments are capitalized. Upon the sale or other disposition of assets, the cost and related accumulated depreciation, depletion and amortization are removed from the accounts, the proceeds applied thereto and any resulting gain or loss is reflected in income.

	*(g)*	*Income Taxes*

		Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. See also footnote 2.

	*(h)*	*Derivative Financial Instruments*

		The Company sells natural gas in the normal course of its business and utilizes derivative instruments to minimize the variability in forecasted cash flows due to price movements in natural gas. The Company enters into derivative instruments such as swap contracts and collars to hedge a portion of its forecasted natural gas sales.

		All such derivative instruments are recorded in the balance sheet at fair value. All derivatives have been designated as cash flow hedges and, accordingly, effective changes in the fair value of derivatives are recognized in accumulated other comprehensive income (loss) until the hedged transaction is recognized in earnings.

	*(i)*	*Use of Estimates*

		Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities and revenues and expenses and the disclosure of contingent assets

(Continued)

F-10

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2003

		and liabilities to prepare these financial statements in conformity with generally accepted accounting principles. Actual results could differ from those estimates. Estimates which are particularly significant to the financial statements include estimates of natural gas reserves, future cash flows from natural gas properties, and accumulated depletion.

	*(j)*	*Revenue Recognition*

		Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold by the Company under contracts with terms ranging from one month to three years. Virtually all of the Company’s contracts pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, the Company’s revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. The Company believes that the pricing provisions of its natural gas contracts are customary in the industry.

	*(k)*	*Fair Value of Financial Instruments*

		The carrying values of the Company’s receivables and payables are estimated to be substantially the same as their fair values as of December 31, 2003. See footnote 8 for discussion related to derivative financial instruments.

	*(l)*	*Deferred Financing Fees*

		The Successor Company incurred legal and bank fees related to the issuance of debt (note 4). These debt issuance costs are amortized over the life of the loan, which is 36 months. Related amortization expense of $125,335 is included in interest expense.

	*(m)*	*New Accounting Standards*

		In June 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires the Company to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. Once calculated, the liability is then discounted to fair value using present value techniques and a credit adjusted risk free rate commensurate with the estimated years to settlement. The Company also records a corresponding asset, which is depreciated over the life of the asset. The liability is accreted through changes to operating expenses. Subsequent to the initial measurement of the asset retirement obligation, the obligation will be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. This statement is effective for fiscal years beginning after June 15, 2002. The Company adopted SFAS No. 143 on January 1, 2003 and recorded a net asset of $96,964 and a related liability of $379,933 (using a 7.5% discount rate) and a cumulative effect on change in accounting principle on prior years of $169,781 (net of taxes of $113,188).

(Continued)

F-11

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2003

		Additionally, SFAS No. 143 results in ongoing costs related to the depreciation of the assets and accretion of the liability. For the period ended December 31 2003, the Company recognized depreciation and operating expense related to SFAS No. 143 of $9,090 and $9,886, respectively. For the period ended August 13, 2003, the Company recognized depreciation and operating expenses related to SFAS No. 143 of $6,978 and $17,809, respectively. These costs are reported in depreciation, depletion and amortization, and operating expenses, respectively.

		The following shows the changes in the asset retirement obligation for the year ended December 31, 2003:


Balance at January 1, 2003	$	379,933
Accretion expense		27,695
Liabilities incurred for new wells drilled		28,036
Liabilities settled		—

Balance at December 31, 2003	$	435,664

(2)	Related Party Transactions (Prior to August 13, 2003)

	Prior to the sales transaction on August 13, 2003, the Predecessor Company had receivables and payables and was a party to certain transactions with the Brink’s Company and Pittston Coal Company (affiliated companies) in the normal course of business.

	Pittston Coal Management Company (PCMC) provided executive, legal, engineering, geological, accounting and administrative services to affiliated companies owned by Pittston Coal Company, including the Predecessor Company. PCMC allocated its costs to the Company based primarily on production, head count and asset base. The Company incurred expenses of approximately $224,000 to PCMC for such services for the period January 1, 2003 through August 12, 2003. The Company paid $5,000 to PCMC for the rent of an office after August 13, 2003.

	Cash generated or used by the Predecessor Company was ultimately received or provided by The Brink’s Company.

	The Predecessor Company was included in the consolidated U.S. Federal income tax return filed by The Brink’s Company. The Brink’s Company’s consolidated provision and actual cash payments for U.S. Federal income taxes are allocated between the Company and other affiliates of The Brink’s Company in accordance with The Brink’s Company’s tax allocation policy. In general, the consolidated current tax provision of The Brink’s Company is allocated among the affiliates based principally upon the financial income, taxable income, credits and other amounts directly related to the respective affiliate. The Brink’s Company gives credit to its subsidiaries’ intercompany accounts for the tax effect of U.S. Federal income tax losses and other attributes to the extent the attributes are utilized on a consolidated basis. As a result, the allocated affiliate amounts of taxes payable or refundable are not necessarily comparable to those that would have resulted if the affiliate had filed separate tax returns.

(Continued)

F-12

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2003

(3)	Income Taxes

	The Company is subject to U.S. federal and state income taxes. The income tax provision consisted of the following:


	Successor		Predecessor
	Period from		Period from
	August 13,		January 1,
	2003 to		2003 to
	December 31,		August 12,
	2003		2003
Current:
Federal	$	779,554		4,058,511
State		164,098		740,154

Total current income taxes		943,652		4,798,665

Deferred:
Federal		955,470		(713,900	)
State		74,882		(126,475	)

Total deferred income taxes		1,030,352		(840,375	)

Total income taxes	$	1,974,004		3,958,290

The following table accounts for the difference between the actual tax provision and the amounts obtained by applying the U.S. statutory income tax rate of 34 percent in each period during 2003 to income before income taxes:


	Successor		Predecessor
	Period from		Period from
	August 13,		January 1,
	2003 to		2003 to
	December 31,		August 12,
	2003		2003
Tax provision computed at statutory rate	$	1,665,579		3,792,526
State income taxes, net of federal benefit		293,926		546,800
Percentage depletion		—		(381,036	)
Other		14,499		—

	$	1,974,004		3,958,290

Accumulated other comprehensive loss is net of tax of $491,366 as of December 31, 2003.

(Continued)

F-13

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2003

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2003 are presented below:


	December 31,
	2003
Deferred tax assets:
Hedges	$	732,806
Asset retirement obligations		163,777

Total deferred tax assets		896,583

Deferred tax liabilities:
Properties and equipment, principally due to differences in depreciation and amortization		1,194,129

Total gross deferred tax liabilities		1,194,129

Net deferred tax liabilities	$	(297,546	)

	Based on historical and expected future taxable earnings of the Company, management believes it is more likely than not that the Company’s existing deferred tax asset at December 31, 2003 will be realized.

	In connection with the acquisition of the Company, both the Company and seller made an Internal Revenue Code Section 338(h)(10) election for tax purposes.

(4)	Long-Term Debt

	On August 13, 2003, the Company entered into an $85,000,000 credit facility. As of December 31, 2003, the available borrowing base under the credit facility was $60,700,000. The outstanding balance of $60,000,000 as of December 31, 2003, accrues interest based on the type of advance obtained by the Company and the interest rate ranges from 3.25% to 6.125%. As of December 31, 2003, the interest rate on the outstanding balance was 3.79%. Accrued interest of $404,800 as of December 31, 2003 is recorded within accounts payable and accrued expenses. The credit facility matures on August 13, 2006, and is collateralized by the Company’s interest in oil and gas properties. In accordance with the terms of the credit facility, the Company must maintain certain financial covenants, including a current ratio, interest coverage ratio, and minimum tangible net worth. Additionally, the Company may not assume any additional debt. The Company was in compliance with all financial debt covenants at December 31, 2003.

(5)	401(k) Plan (Successor)

	The Company sponsors a 401(k) plan to assist eligible employees in providing for retirement. Employee contributions are matched at rates of between 50% and 100% for up to 5% of compensation. This 401(k) plan was not effective until December 1, 2003. For the period from August 13, 2003 to December 31, 2003, the Company contributed $587.

	*Employee Benefit Plans (Predecessor Basis)*

	The Company, along with other employees of The Brink’s Company (the Parent), participated in a noncontributory defined benefit pension plan sponsored by its Parent. This plan covered employees who met certain minimum requirements. Benefits under the plan were based on salary and years of service. It was the plan sponsor’s policy to fund at least the minimum actuarially determined amounts necessary in

(Continued)

F-14

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2003

	accordance with applicable regulations. The Company, along with other employees of The Brink’s Company, also participated in a benefit plan sponsored by its parent that provided certain postretirement health care and life insurance benefits for eligible active and retired employees. The Company, along with other employees of The Brink’s Company, participated in a 401(k) Plan and, within limits, matched employee contributions at rates of between 50% to 100% for up to 5% of compensation (subject to certain limitations). The Company was allocated its portion of the costs for the above plans, which are recorded in selling, general, and administrative expenses. Costs totaled approximately $6,000 for the period January 1, 2003 through August 12, 2003.

	The following disclosures relate to The Brink’s Company pension plan, and postretirement benefit plan other than pension, only:


	2003
Discount rate expense		6.75	%
Expected long-term rate of return on assets		8.75	%
Average rate of salary increase		5.00	%

(6)	Commitments and Contingencies

	The Company would be exposed to natural gas price fluctuations on underlying sale contracts should the counterparties to the Company’s hedging instruments or the counterparties to the Company’s gas marketing contracts not perform. Such nonperformance is not anticipated. There were no counterparty default losses during the periods from January 1, 2003 to August 12, 2003 and August 13, 2003 to December 31, 2003.

	The Company is not party to any legal action that would materially affect the Company’s results of operations or financial condition.

(7)	Business and Credit Concentrations

	Cash (Successor)

	The Company maintains its cash in bank deposit accounts, which, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts. The Company believes it is not exposed to any significant risk on its cash.

	Revenue and Trade Receivables (Predecessor and Successor)

	The Company has a concentration of customers who are engaged in oil and gas production. This concentration of customers may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. The Company performs ongoing credit evaluations of its customers and generally does not require collateral.

	Earned gross revenues from gas sales and royalty income from one customer for the period from January 1, 2003 through August 12, 2003 accounted for more than 10% of the Company’s earned gross revenues from gas sales and royalty income. Gross gas sales and royalty income with one customer for the period of January 1, 2003 through August 12, 2003 accounted for approximately $13.4 million or 92% of the Company’s gross earned revenues and royalty income.

(Continued)

F-15

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2003

	Earned gross revenues from gas sales and royalty income from one customer for the period from August 13, 2003 through December 31, 2003 accounted for more than 10% of the Company’s earned gross revenues from gas sales and royalty income. Gross gas sales and royalty income with one customer for the period of August 13, 2003 through December 31, 2003 accounted for approximately $7.5 million or 82% of the Company’s net revenues of $9.1 million. Trade accounts receivable from gas sales and royalty interests from the same customer accounted for more than 10% of the Company’s trade accounts receivable as of December 31, 2003. Trade accounts receivable from this customer accounted for approximately $3.1 million or 83% as of December 31, 2003.

(8)	Derivative Financial Instruments

	The Company sells natural gas in the normal course of its business and utilizes derivative instruments to minimize the variability in forecasted cash flows due to price movements in natural gas. The Company enters into derivative instruments such as swap contracts and collars to hedge a portion of its forecasted natural gas sales.

	The Company has designated its natural gas derivatives as cash flow hedges for accounting purposes. Effectiveness is assessed based on the total changes in the estimated present value of cash flows. No amounts were excluded from the measurement of ineffectiveness and no ineffective amounts were recorded in earnings for the periods presented. As a result, for natural gas derivatives, the changes in fair value were recorded in accumulated other comprehensive income (loss) and subsequently reclassified to earnings in the same period as the natural gas is sold or royalty income is earned.


	December 31,
	2003
Net gain (loss) in other comprehensive income (loss) at balance sheet date expected to be reclassified to earnings within next 12 months (net of tax of $373,273)	$	(595,126	)
Net gain (loss) in other comprehensive income (loss) at balance sheet date expected to be reclassified to earnings beyond next 12 months (net of tax of $118,093)		(188,900	)
Outstanding notional amounts of hedges in MMbtu’s (in ’000s)		11,953
Maximum number of months hedges outstanding		54

By using derivative instruments to hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates repayment risk. The Company minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties.

(Continued)

F-16

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2003

The settling of cash flow hedges included in earnings and respective gross revenues from gas sales and royalty income are as follows:


	Successor		Predecessor
	Period from		Period from
	August 13,		January 1,
	2003 to		2003 to
	December 31,		August 12,
	2003		2003
Gross working interest natural gas revenues	$	4,933,492		8,881,320
Gross royalty income		3,792,873		7,294,793
Settlement of cash flow hedges		326,500		(1,790,656	)
Gas operating and other income		87,249		141,854

Total net revenues	$	9,140,114		14,527,311

(9)	Supplemental Disclosure of Cash Flows

	Because the Predecessor Company was included in The Brink’s Company’s consolidated tax return, the Predecessor Company did not pay taxes to (or receive refunds from) the U.S. Government during the period from January 1, 2003 to August 12, 2003. See note 2 for a description of The Brink’s Company’s tax allocation policy.

(10)	Operating Lease for Office Space

	The Company has two leases for office space in Virginia and West Virginia. The terms of the lease are on a month-by-month basis. For the period from August 13, 2003 through December 31, 2003, rent expense related to the operating leases totaled approximately $17,200. For the period from January 1, 2003 through August 12, 2003, rent expenses related to the operating leases totaled approximately $8,000.

(11)	Obligation Under Capital Lease

	The Company has entered into a capital lease for a vehicle during the period from August 13, 2003 to December 31, 2003. The obligations under the capital lease have been recorded in the accompanying financial statements at the present value of future minimum lease payments, discounted at an interest rate of 9.4%. The capitalized cost and accumulated depreciation of the vehicle at December 31, 2003, was $31,632 and $3,515, respectively. The capitalized cost is included in the transportation and other equipment amount in the accompanying balance sheet.

(Continued)

F-17

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2003

Future minimum lease payments under the capital lease are as follows:


	Capital
	Leases
Year ending December 31:
2004	$	12,107
2005		12,107
2006		9,080

Total minimum lease payments		33,294
Less amount representing interest		5,554

Present value of minimum capital lease payments		27,740
Less current installments of obligations under capital lease payments		9,783

Obligations under capital leases, excluding current installments	$	17,957

(12)	Subsequent Events

	On April 13, 2004, PMOG Holdings, Inc. had a 232 for one common stock split.

	On May 21, 2004, PMOG Holdings, Inc. entered into a Consulting Agreement (CA), effective as of August 13, 2003 (Effective Date), with Donald E. Vandenberg (Consultant). Consultant is a shareholder of PMOG Holdings, Inc. Under the CA, the Consultant agreed to perform services for PMOG Holdings, Inc. beginning as of the Effective Date and continuing for a one-year period (Consulting Period), subject to the terms and conditions of the CA. On May 21, 2004, PMOG Holdings, Inc. also entered into a Restricted Stock Agreement (RSA) with Consultant. Under the RSA, PMOG Holdings, Inc. agreed to issue 35 restricted shares (0.15 shares on a pre-split basis) of common stock of PMOG Holdings, Inc. for each month during the Consulting Period to Consultant in consideration for the performance of the consulting services pursuant to the CA. The restricted shares will be issued to the Consultant at the end of the one-year period. Expense of $58,450 was recognized for the period from August 13, 2003 through December 31, 2003 related to the CA.

	During 2004, PMOG Holdings, Inc. entered into Stock Purchase Agreements (SPAs) with Robertson Investment Trust, LLC, Consultant, Richard Brillhart, Jerry Grantham, and Ian Landon (collectively referred to as Other Stockholders). Mr. Brillhart, Mr. Grantham, and Mr. Landon are employees of PMOG Holdings, Inc. while Consultant is an independent contractor. Under the SPAs, PMOG Holdings, Inc. issued 6,094.7 post-split shares of common stock of PMOG Holdings, Inc. to the Other Stockholders at $100 per share.

	On November 22, 2004, the shareholders of PMOG Holdings, Inc. entered into a stock purchase agreement to sell of all of its issued and outstanding shares to Range Resources Corporation. The stock purchase agreement is subject to certain closing adjustments and conditions.

(Continued)

F-18

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2003

(13)	Cost Incurred in Gas Property Acquisition, Exploration, and Development Activities

	Costs incurred by the Company in gas property acquisition, explorations, and development are presented below:


	Successor		Predecessor
	Period from		Period from
	August 13,		January 1,
	2003 to		2003 to
	December 31,		August 12,
	2003		2003
Property acquisition cost:
Property acquisition costs, proved	$	80,391,192		—
Property acquisition costs, unproved		2,423,131		—
Development costs		3,691,626		5,170,932

	$	86,505,949		5,170,932

	The proved reserves attributable to the development costs in the above table were 9,254,068 Mcf for period from January 1, 2003 to December 31, 2003 (amounts unaudited). Of the above development costs incurred for the periods presented the amounts of $3,691,626 and $5,170,932 were incurred to develop proved undeveloped properties from the prior period-end.

	Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells and to provide facilities to extract, treat, and gather gas.

(14)	Oil and Gas Capitalized Costs

	Aggregate capitalized costs for the Company related to oil and gas exploration and production activities with applicable accumulated depreciation, depletion, and amortization are presented below:


	Successor
	December 31,
	2003
Proved properties:
Leasehold – acquired properties	$	76,383,095
Equipment – acquired properties		5,379,602
Intangible drilling costs		2,907,010
Tangible well equipment		784,616
Capitalized asset retirement cost		424,131
Undeveloped properties		—

		85,878,454

Less accumulated depreciation, depletion, and amortization		1,331,561

	$	84,546,893

(Continued)

F-19

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2003

(15)	Results of Gas Producing Activities

	The results of operations for gas producing activities (excluding corporate overhead and interest costs) are presented below:


	Successor		Predecessor
	Period from		Period from
	August 13,		January 1,
	2003 through		2003 to
	December 31,		August 12,
	2003		2003
Revenue:
Gas sales	$	9,140,114		14,527,311
Expenses:
Production and related costs		1,218,456		1,774,033
Depreciation, depletion, and amortization		1,331,561		959,548

Results of operations for oil and gas producing activities before provision for income taxes		6,590,097		11,793,730

Provision for income taxes		2,636,038		4,185,132

Results of operations for oil and gas producing activities (excluding corporate overhead and interest costs)	$	3,954,059		7,608,598

	Production costs include those costs incurred to operate and maintain productive wells and related equipment, including such costs as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, and other production taxes. In addition, production costs include administrative expenses and depreciation applicable to support equipment associated with these activities.

	Depreciation, depletion, and amortization expense includes those costs associated with capitalized acquisition, exploration, and development costs, but does not include the depreciation applicable to support equipment.

	The provision for income taxes is computed using the Company’s effective tax rate.

(Continued)

F-20

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2003

(16)	Net Proved Gas Reserves (Unaudited)

	The proved reserves of gas of the Company have been estimated by an independent petroleum engineer, Wright & Company, Inc. at December 31, 2003. These reserves have been prepared in compliance with the Securities and Exchange Commission rules based on year end prices. An analysis of the change in estimated quantities of oil and gas reserves, all of which are located within the United States, is shown below:


	Gas (Mcf)
	December 31,
	2003
Proved developed and undeveloped reserves:
Beginning of year (1)		49,327,785
Revisions of previous estimates		6,229,111

Beginning of year as revised		55,556,896

New discoveries and extensions:
Appalachian Basin		9,254,068
Additional reporting of proved undeveloped reserves (1)		73,327,290

Production		(5,097,719	)


End of year		133,040,535

Proved developed and undeveloped reserves:
Beginning of year (1)		49,327,785


End of year		133,040,535

(1) Beginning of year reserve amounts did not include proved undeveloped gas reserves.

The above amounts include the Company’s royalty and working interest net proved gas reserves.

(Continued)

F-21

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2003

(17)	Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Gas Reserves (Unaudited)

	Summarized in the following table is information for the Company with respect to the standardized measure of discounted future net cash flows relating to proved gas reserves. Future cash inflows are computed by applying year-end prices of gas relating to the Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration, and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the statutory rate in effect at the end of each year to the future pretax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties.


	2003
Future estimated revenues	$	841,453,307
Future estimated production costs		(144,653,601	)
Future estimated development costs		(43,218,340	)

Future net cash flows before income taxes		653,581,366

10% annual discount for estimated timing of cash flows		(400,584,379	)

Discounted future net cash flows before income taxes		252,996,987

Future estimated income tax expense, discounted 10% annually		(89,653,998	)


Standardized measure of discounted future estimated net cash flows	$	163,342,989

The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows:


	Year ended
	December 31 ,
	2003
Sales of oil and gas production, net of production costs	$	(23,165,878	)
Changes in estimated future development costs		(52,049,798	)
Net changes in prices and production costs		3,546,036
Extensions, discoveries, and improved recovery, less related cost		21,211,373
Development costs incurred during the period		8,862,558
Revisions of previous quantity estimates		10,870,499
Additional reporting of proved undeveloped reserves (1)		168,074,467
Net change in estimated income taxes		(52,856,993	)
Accretion of discount		10,513,430

	$	95,005,694

(1)	Beginning of year reserve amounts did not include proved undeveloped gas reserves.

	It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large

(Continued)

F-22

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2003

number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

(Continued)

F-23

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Consolidated Financial Statements

September 30, 2004

(Unaudited)

(Continued)

F-24

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Consolidated Balance Sheet

September 30, 2004

(Unaudited)


Assets
Current assets:
Cash and cash equivalents	$	1,667,282
Trade receivables less allowance for doubtful accounts of $0 (note 6)		4,667,777
Prepaid expenses and other current assets		9,875
Deferred tax asset (note 2)		2,387,568


Total current assets		8,732,502


Properties and equipment:
Natural gas properties		94,006,571
Transportation and other equipment		1,013,219
Less accumulated depreciation, depletion, and amortization		(4,146,828	)


Net properties and equipment		90,872,962


Other assets:
Deferred tax asset		3,086,154
Deferred financing fees, net of amortization of $376,005		626,675

Total other assets		3,712,829


Total assets	$	103,318,293

(Continued)

F-25

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Consolidated Balance Sheet

September 30, 2004

(Unaudited)


Current liabilities:
Accounts payable and accrued expenses	$	2,022,956
Income taxes payable		656,252
Fair value of gas hedges (note 7)		6,121,968
Current portion of capital lease obligation (note 9)		4,978


Total current liabilities		8,806,154


Long-term debt:
Credit facility (note 3)		57,000,000
Long-term portion of capital lease obligation (note 9)		14,114


		57,014,114


Other long-term liabilities:
Fair value of gas hedges – noncurrent (note 7)		7,459,389
Asset retirement obligation		483,073
Deferred income tax liability – noncurrent (note 2)		3,251,067


		11,193,529


Total liabilities		77,013,797


Shareholder’s equity:
Common stock, $0.01 par value. 2,320,000 shares authorized, 238,094.7 shares issued and outstanding		2,381
Preferred stock, $0.01 par value. 10,000 shares authorized, none issued and outstanding		—
Additional paid-in capital		23,803,873
Restricted shares issuable (420 common shares)		369,079
Retained earnings		10,051,630
Accumulated other comprehensive (loss), net		(7,922,467	)


Total shareholder’s equity		26,304,496


Total liabilities and shareholder’s equity	$	103,318,293

See accompanying notes to consolidated financial statements.

(Continued)

F-26

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Consolidated Statement of Operations

Nine Months Ended September 30, 2004
(Unaudited)


Revenues, net (note 7)	$	21,534,625

Expenses:
Operating expenses (exclusive of depreciation, depletion, and amortization shown separately below)		3,172,623
Depreciation, depletion, and amortization		2,813,727
Selling, general, and administrative expenses		1,909,028


Total expenses		7,895,378


Operating profit		13,639,247

Other expenses (income):
Interest expense (income)		1,955,848


Income before income taxes		11,683,399

Income tax expense (note 2)		4,556,527


Net income	$	7,126,872

See accompanying notes to consolidated financial statements.

(Continued)

F-27

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Consolidated Statement of Shareholder’s Equity and Comprehensive Income

Nine Months Period Ended September 30, 2004


										Accumulated
										other
			Additional			Restricted				comprehensive			Total
	Common		paid-in			shares		Retained		income (loss),			shareholder’s
	stock		capital			issuable		earnings		net			equity
Balance as of January 1, 2004	$	10		23,196,825			58,450		2,924,758		(784,026	)		25,396,017
Stock split (232 share for each 1 share)		2,310		(2,310	)		—		—		—			—
Issuance of common stock (6,094.7 shares)		61		609,358			—		—		—			609,419
Restricted shares award		—		—			310,629		—		—			310,629
Net income		—		—			—		7,126,872		—			7,126,872
Change in fair value of open cash flow hedges, net of tax benefit of $5,139,623		—		—			—		—		(8,406,149	)		(8,406,149	)
Reclassification adjustment for cash flow hedge benefit realized in net income, net of tax expense of $764,450		—		—			—		—		1,267,708			1,267,708


Comprehensive income														(11,569	)


Balance as of September 30, 2004	$	2,381		23,803,873			369,079		10,051,630		(7,922,467	)		26,304,496

See accompanying notes to consolidated financial statements.

(Continued)

F-28

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Consolidated Statement of Cash Flows

Nine Months Period Ended September 30, 2004
(Unaudited)


Cash flows from operating activities:
Net income	$	7,126,872
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization		2,784,250
Deferred income taxes		2,043,723
Amortization of deferred financing costs		250,670
Accretion of asset retirement obligations		29,477
Change in operating assets and liabilities:
Accounts receivable		(907,681	)
Prepaid expenses and other current assets		13,655
Accounts payable and accrued expenses		(308,837	)
Income taxes payable		(287,400	)


Net cash provided by operating activities		10,744,729


Cash flows from investing activities:
Capital expenditures		(8,139,059	)


Net cash used in investing activities		(8,139,059	)


Cash flows from financing activities:
Common stock issuance		609,419
Restricted shares award		310,629
Net repayments under long-term credit facility		(3,000,000	)
Payments on capital lease obligations		(8,648	)


Net cash provided by (used in) financing activities		(2,088,600	)


Net change in cash and cash equivalents		517,070

Cash and cash equivalents at beginning of period		1,150,212


Cash and cash equivalents at end of period	$	1,667,282


Supplemental disclosures of cash flow information:
Cash paid for interest	$	2,081,330
Cash paid for taxes		2,650,204

See accompanying notes to consolidated financial statements.

(Continued)

F-29

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

September 30, 2004

(1)

Summary of Significant Accounting Policies

	*(a)*	*Description of Business*

		Pine Mountain Oil and Gas, Inc. (PMOGI), which was established in Virginia in 1984, was formerly wholly owned by Pittston Coal Company, an indirectly wholly owned subsidiary of The Brink’s Company (formerly, The Pittston Company). On August 13, 2003, PMOGI’s stock was sold to Pine Mountain Acquisition, Inc (PMAI) for a total consideration of approximately $83.6 million ($23.2 million cash, $60.0 million debt plus transaction costs of $0.4 million). PMAI is a wholly owned subsidiary of PMOG Holdings, Inc. (97% owned by First Reserve Fund IX, L.P.) and Pine Mountain Oil and Gas, Inc. represents their only asset and represents all of their operations. PMOG Holdings, Inc., PMAI and PMOGI are collectively referred to herein as the Company.

		Subsequent to the acquisition, the accounts of the Company have been adjusted using the push down basis of accounting to recognize the allocation of the consideration paid for the common stock to the respective net assets acquired. The total purchase price was allocated to the properties and equipment.

		The Company is in the business of producing and selling natural gas from company-owned natural gas wells and receiving royalty income from natural gas production and sales of natural gas reserves by third parties. The Company’s natural gas reserves are located in West Virginia, Virginia, and Wyoming. The Company controls approximately 414,000 acres of oil and gas interests through direct ownership, leases, or joint ventures.

		The majority of the Company’s production comes from coalbed methane (CBM) production in Virginia, while the remainder comes from conventional reservoirs in Virginia and West Virginia and from CBM reserves in Wyoming. Approximately 50% of the Company’s revenue comes from working interests and 50% from royalty interests. The Company has an overriding royalty interest on certain reserves located in Wyoming.

	*(d)*	*Basis of Presentation*

		The accompanying consolidated financial statements include the accounts of PMOG Holdings, Inc. and its wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

		Comparative results for the period from August 13, 2003 (inception) through September 30, 2003 have not been presented because management believes the limited operating period which makes comparability not meaningful.

	*(e)*	*Cash Equivalents*

		For purposes of the statement of cash flows, the Company considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents.

	*(d)*	*Trade Accounts Receivable*

		Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. The Company determines the allowance based on historical write-off experience. The Company reviews its allowance for doubtful accounts monthly. Past due balances over 90 days and a specified amount are reviewed individually for

(Continued)

F-30

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

September 30, 2004

		collectibility. All other balances are reviewed on a pooled basis. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. The Company does not have any off-balance-sheet credit exposure related to its customers.

	*(e)*	*Natural Gas Properties*

		Of the 414,000 acres controlled by the Company, approximately 250,000 are located in Virginia, 120,000 are located in West Virginia, and 44,000 are located in Wyoming.

		Approximately 250,000 acres of the 414,000 acres controlled by the Company are located in Southwest Virginia. Development of both CBM and conventional resources is ongoing in this area. Equitable Production Company (Equitable) operates natural gas production facilities on 220,000 acres under agreements providing the Company both a 12.5% royalty interest and rights to participate in a working interest on a well-by-well basis. The remaining 30,000 acres in Virginia are held under a lease by Columbia Natural Resources (Columbia), which provides a royalty interest to the Company. In addition to these properties, the Company participated in a CBM project in Pulaski and Montgomery counties in Virginia. Following the initial well test in the spring of 2003, the Company decided to sell its interests in this project in October 2003 with a resulting loss of $8,400.

		In West Virginia, the Company’s properties total approximately 120,000 acres. The largest area consists of 85,000 acres, with 75,000 acres owned and 10,000 acres leased. The remaining 35,000 acres provide a royalty interest through provisions of a Columbia lease.

		The Wyoming properties amount to approximately 44,000 acres, on which an overriding royalty interest of 1 to 2% is generated on an extensive, ongoing development program.

		Exploration and development costs are accounted for by the successful efforts method.

		The Company assesses impairment of capitalized costs of proved natural gas properties by comparing net capitalized costs to undiscounted future net cash flows using expected prices. Prices utilized in each year’s calculation for measurement purposes and expected costs are held constant throughout the estimated life of the properties. If net capitalized costs exceed undiscounted future net cash flow, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows.

		Property acquisition costs are capitalized when incurred. Geological and geophysical costs and delay rentals are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether the wells have discovered economically producible reserves. If reserves are not discovered, such costs are expensed as dry holes. Development costs, including equipment and intangible drilling costs related to both producing wells and developmental dry holes, are capitalized.

		Unproved properties are assessed on a property-by-property basis and properties considered to be impaired are charged to expense when such impairment is deemed to have occurred.

		Costs of certain proved properties, exploration and development costs and equipment, are depreciated or depleted by the units-of-production method based as estimated proved developed gas reserves.

(Continued)

F-31

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

September 30, 2004

		Upon sale or retirement of complete fields of depreciable or depletable property, the net cost thereof, less proceeds or salvage value, is credited or charged to income. Upon retirement of a partial unit of property, the cost thereof is charged to accumulated depreciation and depletion.

	*(f)*	*Transportation and Other Equipment*

		Transportation and other equipment are carried at cost. Depreciation is provided principally on the straight-line method over useful lives of 3 to 15 years.

		Long-lived assets, such as transportation and other equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset.

		Maintenance and repairs are charged to expense as incurred. Major renewals and betterments are capitalized. Upon the sale or other disposition of assets, the cost and related accumulated depreciation, depletion and amortization are removed from the accounts, the proceeds applied thereto and any resulting gain or loss is reflected in income.

	*(g)*	*Income Taxes*

		Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

	*(h)*	*Derivative Financial Instruments*

		The Company sells natural gas in the normal course of its business and utilizes derivative instruments to minimize the variability in forecasted cash flows due to price movements in natural gas. The Company enters into derivative instruments such as swap contracts and collars to hedge a portion of its forecasted natural gas sales.

		All such derivative instruments are recorded in the balance sheet at fair value. All derivatives have been designated as cash flow hedges and, accordingly, effective changes in the fair value of derivatives are recognized in accumulated other comprehensive income (loss) until the hedged transaction is recognized in earnings.

	*(i)*	*Use of Estimates*

		Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities and revenues and expenses and the disclosure of contingent assets and liabilities to prepare these financial statements in conformity with generally accepted accounting principles. Actual results could differ from those estimates. Estimates which are particularly significant to the financial statements include estimates of natural gas reserves, future cash flows from natural gas properties, and accumulated depletion.

(Continued)

F-32

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

September 30, 2004

	*(j)*	*Revenue Recognition*

		Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold by the Company under contracts with terms ranging from one month to three years. Virtually all of the Company’s contracts pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, the Company’s revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. The Company believes that the pricing provisions of its natural gas contracts are customary in the industry.

	*(k)*	*Fair Value of Financial Instruments*

		The carrying values of the Company’s receivables and payables are estimated to be substantially the same as their fair values as of September 30, 2004. See footnote 7 for discussion related to derivative financial instruments.

	*(l)*	*Deferred Financing Fees*

		The Company incurred legal and bank fees related to the issuance of debt (note 3). These debt issuance costs are amortized over the life of the loan, which is 36 months. Related amortization expense is included in interest expense.

	*(m)*	*Asset Retirement Obligation*

		In June 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires the Company to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. Once calculated, the liability is then discounted to fair value using present value techniques and a credit adjusted risk free rate commensurate with the estimated years to settlement. The Company also records a corresponding asset, which is depreciated over the life of the asset. The liability is accreted through changes to operating expenses. Subsequent to the initial measurement of the asset retirement obligation, the obligation will be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. This statement is effective for fiscal years beginning after June 15, 2002. The Company adopted SFAS No. 143 on January 1, 2003.

		Additionally, SFAS No. 143 results in ongoing costs related to the depreciation of the assets and accretion of the liability. For the nine months ended September 30 2004, the Company recognized depreciation and operating expense related to SFAS No. 143 of $14,125 and $29,477, respectively. These costs are reported in depreciation, depletion and amortization, and operating expenses, respectively.

(Continued)

F-33

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

September 30, 2004

The following shows the changes in the asset retirement obligation for the nine months ended September 30, 2004:


Balance at January 1, 2004	$	435,664
Accretion expense		29,477
Liabilities incurred for new wells drilled		17,932
Liabilities settled		—


Balance at September 30, 2004	$	483,073

(2)	Income Taxes

	The Company is subject to U.S. federal and state income taxes. The income tax provision for the nine months ended September 30, 2004 consisted of the following:


Current	$	2,512,804
Deferred		2,043,723

Total income tax expense	$	4,556,527

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at September 30, 2004 are presented below:


	September 30,
	2004
Deferred tax assets:
Hedges	$	5,298,449
Asset retirement obligations		175,273


Total deferred tax assets		5,473,722

Deferred tax liabilities:
Properties and equipment, principally due to differences in depreciation and amortization		3,251,067


Total gross deferred tax liabilities		3,251,067


Net deferred tax liabilities	$	2,222,655

Based on historical and expected future taxable earnings of the Company, management believes it is more likely than not that the Company’s existing deferred tax asset at September 30, 2004 will be realized.

In connection with the acquisition of the Company, both the Company and seller made an Internal Revenue Code Section 338(h)(10) election for tax purposes.

(Continued)

F-34

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

September 30, 2004

(3)	Long-Term Debt

	On August 13, 2003, the Company entered into an $85,000,000 credit facility. As of September 30, 2004, the available borrowing base under the credit facility was $65,000,000. The outstanding balance of $57,000,000 as of September 30, 2004, accrues interest based on the type of advance obtained by the Company and the interest rate ranges from 3.25% to 6.125%. As of September 30, 2004, the interest rate on the outstanding balance was 4.34%. Accrued interest of $41,230 as of September 30, 2004 is recorded within accounts payable and accrued expenses. The credit facility matures on August 13, 2006, and is collateralized by the Company’s interest in oil and gas properties. In accordance with the terms of the credit facility, the Company must maintain certain financial covenants, including a current ratio, interest coverage ratio, and minimum tangible net worth. Additionally, the Company may not assume any additional debt. The Company was in compliance with all financial debt covenants at September 30, 2004.

(4)	401(k) Plan

	The Company sponsors a 401(k) plan to assist eligible employees in providing for retirement. Employee contributions are matched at rates of between 50% and 100% for up to 5% of compensation. For the nine months ended September 30, 2004, the Company contributed $12,124.

(5)	Commitments and Contingencies

	The Company would be exposed to natural gas price fluctuations on underlying sale contracts should the counterparties to the Company’s hedging instruments or the counterparties to the Company’s gas marketing contracts not perform. Such nonperformance is not anticipated. There were no counterparty default losses during the nine months ended September 30, 2004.

	The Company is not party to any legal action that would materially affect the Company’s results of operations or financial condition.

(6)	Business and Credit Concentrations

	Cash

	The Company maintains its cash in bank deposit accounts, which, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts. The Company believes it is not exposed to any significant risk on its cash.

	Revenue and Trade Receivables

	The Company has a concentration of customers who are engaged in oil and gas production. This concentration of customers may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. The Company performs ongoing credit evaluations of its customers and generally does not require collateral.

	Earned gross revenues from gas sales and royalty income from one customer for the nine months ended September 30, 2004 accounted for more than 10% of the Company’s earned gross revenues from gas sales and royalty income. Gross gas sales and royalty income with one customer for the nine months ended September 30, 2004 accounted for approximately $18.6 million or 86% of the Company’s gross earned revenues and royalty income.

(Continued)

F-35

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

September 30, 2004

	Trade accounts receivable from gas sales and royalty interests from the same customer accounted for more than 10% of the Company’s trade accounts receivable as of September 30, 2004. Trade accounts receivable from this customer accounted for approximately $4.1 million as of September 30, 2004.

(7)	Derivative Financial Instruments

	The Company sells natural gas in the normal course of its business and utilizes derivative instruments to minimize the variability in forecasted cash flows due to price movements in natural gas. The Company enters into derivative instruments such as swap contracts and collars to hedge a portion of its forecasted natural gas sales.

	The Company has designated its natural gas derivatives as cash flow hedges for accounting purposes. Effectiveness is assessed based on the total changes in the estimated present value of cash flows. No amounts were excluded from the measurement of ineffectiveness and no ineffective amounts were recorded in earnings for the periods presented. As a result, for natural gas derivatives, the changes in fair value were recorded in accumulated other comprehensive income (loss) and subsequently reclassified to earnings in the same period as the natural gas is sold or royalty income is earned.


	September 30,
	2004
Net gain (loss) in other comprehensive income (loss) at balance sheet date expected to be reclassified to earnings within next 12 months, net of tax	$	(3,569,107	)
Net gain (loss) in other comprehensive income (loss) at balance sheet date expected to be reclassified to earnings beyond next 12 months, net of tax		(4,353,360	)
Outstanding notional amounts of hedges in MMbtu’s (in ’000s)		17,379
Maximum number of months hedges outstanding	45 months

The settling of cash flow hedges included in earnings and respective gross revenues from gas sales and royalty income for the nine months ended September 30, 2004 are as follows:


Gross working interest natural gas revenues	$	13,798,654
Gross royalty income		9,565,494
Settlement of cash flow hedges		(2,044,690	)
Gas operating and other income		215,167


Total net revenues	$	21,534,625

(Continued)

F-36

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

September 30, 2004

(8)	Operating Lease for Office Space

	The Company has two leases for office space in Virginia and West Virginia. The terms of the lease are on a month-by-month basis. For the nine months ended September 30, 2004, rent expense related to the operating leases totaled approximately $17,800.

(9)	Obligation Under Capital Lease

	The Company has entered into a capital lease for a vehicle during 2003. The obligations under the capital lease have been recorded in the accompanying financial statements at the present value of future minimum lease payments, discounted at an interest rate of 9.4%. The capitalized cost is included in the transportation and other equipment amount in the accompanying balance sheet.

(10)	Common Stock

	On April 2004, the Company had a 232 for one common stock split. In April 2004, the Company sold 4,737.7 shares of common stock to an unaffiliated company for $100/share. In May 2004, the Company sold 1,357 shares of common stock to certain officers and directors for $100/share.

(11)	Cost Incurred in Gas Property Acquisition, Exploration, and Development Activities

	Costs incurred by the Company in gas property acquisition, explorations, and development during the nine months ended September 30, 2004 are presented below:


Property acquisition cost:
Property acquisition costs, proved	$	725,787
Development costs		7,413,272


	$	8,139,059

Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells and to provide facilities to extract, treat, and gather gas.

(Continued)

F-37

PMOG HOLDINGS, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

September 30, 2004

(12)	Oil and Gas Capitalized Costs

	Aggregate capitalized costs for the Company related to oil and gas exploration and production activities with applicable accumulated depreciation, depletion, and amortization for the nine months ended September 30, 2004 are presented below:


Book value
Properties subject to depletion	$	91,583,440
Unproved properties		2,423,131


Total		94,006,571

Less accumulated depreciation, depletion, and amortization		(4,034,757	)


Net	$	89,971,814

(Continued)

F-38

Range Resources Corporation

Unaudited pro forma combined financial information

On June 23, 2004, Range Resources Corporation (the “Company”) closed on the acquisition of the 50% of Great Lakes Energy Partners, L.L.C. (“Great Lakes”) that it did not previously own. On December 10, 2004, the Company closed on the acquisition of PMOG Holdings, Inc. (“Pine Mountain”). The following unaudited pro forma combined financial information shows the pro form effects of the Great Lakes and Pine Mountain acquisitions. The unaudited pro forma combined financial information includes a statement of operations for the year ended December 31, 2003 and the nine months ended September 30, 2004 which assumes the mergers occurred on January 1, 2003 and an unaudited balance sheet for September 30, 2004 which assumes the Pine Mountain acquisition occurred on that date (the Great Lakes acquisition had already occurred).

The unaudited pro forma combined financial information has been prepared to assist in your analysis of the financial effects of the acquisitions. The pro forma amounts for the Great Lakes acquisition are based on the historical financial statements of Range and Great Lakes and should be read in conjunction with those historical financial statements and related notes, which were previously filed on Form 8-K/A dated August 17, 2004. The historical Great Lakes amounts presented represent the 50% not previously owned by the Company prior to the acquisition. The pro forma amounts for the Pine Mountain acquisition are also based on historical financial statements of Range and Pine Mountain and should be read in conjunction with those historical financial statements and related notes. The Pine Mountain financial statements are included herein.

The pro forma information is based on the estimates and assumptions set forth in the notes to such information. It is preliminary and is being furnished solely for information purposes. The pro forma information does not purport to represent what the financial position and the results of operations of the combined company would have actually been had the merger in fact occurred on the date indicated, nor is it necessarily indicative of the results of operations or financial position that may occur in the future.

F-39

Range Resources Corporation
Unaudited pro forma balance sheet
As of September 30, 2004


	Range			Pine			Pro forma
(in thousands, except share data)	Resources			Mountain			adjustments ⁽²⁾			Pro forma

Assets
Current assets
Cash and equivalents	$	501		$	1,667		$			$	2,168
Accounts receivables, net		46,019			4,668						50,687
IPF receivables		2,900			—						2,900
Unrealized derivative gain		379			—						379
Deferred tax asset		37,084			2,388			(2,388	)(c)		37,084
Inventory and other		13,522			9						13,531

		100,405			8,732			(2,388	)		106,749


IPF receivables		3,046			—						3,046
Unrealized derivative gain		218			—						218
Oil and gas properties, successful efforts method		1,770,148			89,972			202,143	(a)		2,062,263
Accumulated depletion and depreciation		(681,500	)		—						(681,500	)

		1,088,648			89,972			202,143			1,380,763


Transportation and field assets		57,163			901						58,064
Accumulated depletion and amortization		(21,094	)		—						(21,094	)

		36,069			901						36,970

Other		15,205			3,713			(2,784	)(a),(b),(d)		16,134

	$	1,243,591		$	103,318		$	196,971		$	1,543,880


Liabilities and stockholders’ equity
Current liabilities
Accounts payable	$	49,205		$	2,679		$			$	51,884
Asset retirement obligation		14,712			—						14,712
Accrued liabilities		26,091			5			(4,355	)(a),(c)		21,741
Unrealized derivative loss		103,420			6,122			(6,122	)(c)		103,420

		193,428			8,806			(10,477	)		191,757


Senior debt		306,900			57,000			62,892	(d)		426,792
Capital lease obligation		—			14			—			14
Subordinated notes		196,587			—						196,587
Deferred taxes, net		19,425			3,251			75,675	(a)		98,351
Unrealized derivative loss		29,477			7,459			(7,459	)(c)		29,477
Deferred compensation liability		32,839			—						32,839
Asset retirement obligation		56,213			483						56,696
Commitments and contingencies
Stockholders’ equity
Preferred stock, $1 par, 10,000,000 shares authorized, 5.9% cumulative convertible preferred stock, 1,000,000 shares issued and outstanding at September 30, 2004 entitled in liquidation to $50.0 million		50,000			—						50,000
Common stock, $.01 par, 100,000,000 shares authorized, 69,466,877 issued and outstanding		695			2			55	(d)		752
Capital in excess of par value		549,453			23,804			78,784	(d)		652,041
Restricted shares		—			369			(369	)(a)		—
Retained earnings (deficit)		(99,799	)		10,052			(10,052	)(a)		(99,799	)
Stock held by employee benefit trust, 1,627,424 shares at cost		(9,009	)		—						(9,009	)
Deferred compensation		(1,403	)		—						(1,403	)
Accumulated other comprehensive income (loss)		(81,215	)		(7,922	)		7,922	(a)		(81,215	)

		408,722			26,305			76,340			511,367

	$	1,243,591		$	103,318		$	196,971		$	1,543,880

See notes to unaudited pro forma combined financial statements.

F-40

Range Resources Corporation
Unaudited pro forma statement of operations
Year ended December 31, 2003



				50%
	Range			Great		Pro forma						Pine		Pro forma
(in thousands, except per share data)	Resources			Lakes		adjustments ⁽³⁾			Pro forma			Mountain		adjustments ⁽²⁾			Pro forma

Revenues
Oil and gas sales	$	226,402		$	54,278	$			$	280,680		$	23,438				$	304,118
Transportation and gathering		3,509			1,886					5,395			—					5,395
Gain on retirement of securities		18,526			—					18,526			—					18,526
Other		(2,670	)		379					(2,291	)		229					(2,062	)

		245,767			56,543					302,310			23,667					325,977


Expenses
Direct operating		36,423			9,710					46,133			2,264		(10	)(f)		48,387
Production and ad valorem taxes		12,894			511					13,405			728					14,133
Exploration		13,946			1,931					15,877			—					15,877
General and administrative		24,377			1,876					26,253			1,246					27,499
Interest expense		22,165			3,884		(22	)(i)		33,703			1,054		2,999	(e)		37,756
							(130	)(j)
							7,806	(k)
Depletion, depreciation and amortization		86,549			14,569		2,238	(l)		103,356			2,322		6,000	(f)		111,678


		196,354			32,481		9,892			238,727			7,614		8,989			255,330

Income before income taxes		49,413			24,062		(9,892	)		63,583			16,053		(8,989	)		70,647
Income taxes		18,489			—		5,243	(m)		23,732			5,932		(3,325	)(g)		26,339

Net income		30,924			24,062		(15,135	)		39,851			10,121		(5,664	)		44,308
Preferred dividends		(803	)		—		—			(803	)		—		—			(803	)


Net income available to common shareholders	$	30,121		$	24,062	$	(15,135	)	$	39,048		$	10,121	$	(5,664	)	$	43,505


Earnings per common share:
Net income per common share -basic	$	0.56							$	0.59							$	0.60


Net income per common share-diluted	$	0.53				$			$	0.57							$	0.58


Shares outstanding:
Basic		54,272					12,190			66,462					5,750			72,212
Diluted		57,850					12,190			70,040					5,750			75,790

See notes to unaudited pro forma combined financial statements.

F-41

Range Resources Corporation
Unaudited pro forma statement of operations
Nine months ended September 30, 2004



				50%
	Range			Great		Pro forma						Pine		Pro forma
(in thousands, except per share data)	Resources			Lakes		adjustments⁽³⁾			Pro forma			Mountain		adjustments ⁽²⁾			Pro forma

Revenues
Oil and gas sales	$	218,495		$	27,708	$			$	246,203		$	21,366				$	267,569
Transportation and gathering		1,107			770					1,877			—					1,877
Gain on retirement of securities		(39	)		—					(39	)		—					(39	)
Other		(1,120	)		56					(1,064	)		169					(895	)

		218,443			28,534					246,977			21,535					268,512


Expenses
Direct operating		33,119			4,836					37,955			2,438		(29	)(f)		40,364
Production and ad valorem taxes		14,382			246					14,628			735					15,363
Exploration		12,382			1,152					13,534			—					13,534
General and administrative		28,306			1,078					29,384			1,909					31,293
Interest expense		15,480			877		(11	)(i)		20,182			1,956		1,083	(e)		23,221
							(70	)(j)
							3,906	(k)
Depletion, depreciation and amortization		70,998			6,552		1,464	(l)		79,014			2,814		3,667	(f)		85,495


		174,667			14,741		5,289			194,697			9,852		4,721			209,270

Income before income taxes		43,776			13,793		(5,289	)		52,280			11,683		(4,721	)		59,242
Income taxes		16,088			—		3,145	(m)		19,233			4,557		(1,981	)(a)		21,809


Net income		27,688			13,793		(8,434	)		33,047			7,126		(2,740	)		37,433
Preferred dividends		(2,212	)		—		—			(2,212	)		—		—			(2,212	)


Net income available to common shareholders	$	25,476		$	13,793	$	(8,434	)	$	30,835		$	7,126	$	(2,740	)	$	35,221


Earnings per common share:
Net income per common share -basic	$	0.42							$	0.46							$	0.48


Net income per common share-diluted	$	0.40							$	0.43							$	0.46


Shares outstanding:
Basic		59,999					7,430			67,429					5,750			73,179
Diluted		68,760					7,430			76,190					5,750			81,940

See notes to unaudited pro forma combined financial statements.

F-42

Range Resources Corporation
Notes to unaudited pro forma combined
financial information

(1) Basis of presentation

The accompanying unaudited pro forma statements of operations present the pro forma effects of the Great Lakes and Pine Mountain acquisitions. The unaudited pro forma statements of operations are presented as though the acquisitions occurred on January 1, 2003. The unaudited pro forma balance sheet for September 30, 2004 is presented as though the Pine Mountain acquisition occurred on that date.

(2) Pro forma adjustments related to the Pine Mountain acquisition

The unaudited pro forma balance sheet includes the following adjustments:

(a)

This entry adjusts the historical book values of Pine Mountain assets and liabilities to their estimated fair values as of September 30, 2004. The calculation of the total purchase price and the preliminary allocation of this price to assets and liabilities are shown below:

Calculation and preliminary allocation of purchase price (in thousands):



Cash paid to sellers	$	150,706
Cash paid for Pine Mountain debt		57,000
Cash paid for hedges		13,581
Cash paid for transaction costs		500

	$	221,787

Plus fair value of liabilities assumed (in thousands):



Current liabilities	$	(1,671	)
Deferred taxes		78,926
Asset retirement obligation		483
Capital lease obligation		14

	$	299,539

Fair value of Pine Mountain assets (in thousands):



Current assets	$	6,344
Oil and natural gas properties		292,115
Gas transportation assets		901
Other non-current assets		179

	$	299,539

The total purchase price includes $500,000 of estimated merger costs. These costs include legal and accounting fees. The purchase also results in the reversal of the Pine Mountain deferred taxes retained earnings and other comprehensive income and an accrual of $670,000 of incentive costs to be paid to Pine Mountain employees.

F-43

The purchase price is preliminary and is subject to change due to several factors, including (1) changes in the fair values of Pine Mountain’s assets and liabilities as of the effective time of the acquisition, (2) actual acquisition costs incurred, (3) changes in Range’s valuation estimates that may be made between now and the effective time of the acquisition. These changes will not be known until after the effective time of the acquisition. However, Range does not believe that the final purchase price allocation will differ materially from the estimated allocation present herein.

	(b)	This adjustment reflects the write-off in purchase accounting of $627,000 of deferred financing costs related to the Pine Mountain Credit Facility.

	(c)	This adjustment reflects the settlement of $13.6 million of the Pine Mountain commodity hedges and the recognition of a $5.1 million tax benefit related to the loss.

	(d)	This adjustment reflects the issuance of 5,750,000 shares of Range common stock at a price of $18.74 with the remainder of the purchase price being financed through the Company’s senior credit facility. The stock transaction includes estimated transaction costs of $5.1 million. Fees for an amended and restated senior credit facility are estimated to be $750,000.

The unaudited pro forma statement of operations includes the following adjustments:

	(e)	This adjustment increases interest expense for the effect of additional borrowings under the Senior Credit Facility and amortization of fees associated with an amended and restated senior credit facility. This adjustment also reflects the write-off of Pine Mountains’ deferred financing costs and related amortization attributed to their prior credit facility.

	(f)	This adjustment revised Pine Mountain historical depreciation, depletion and amortization expense to reflect the adjustment of Pine Mountains’ assets from historical book value to fair value. For the oil and gas producing properties, pro forma depletion was calculated using the equivalent units-of-production method. This adjustment also includes a reclass of accretion expense from direct operating expense.

	(g)	This adjustment recognizes income tax effects of the adjustments to depreciation, depletion and amortization and interest expense at an effective tax rate of approximately 37%.

(3) Method of accounting for the Great Lakes acquisition

Range accounted for the acquisition using the purchase method of accounting for business combinations. The purchase method of accounting requires that Great Lakes’ assets and liabilities assumed by Range be revalued and recorded at their estimated “fair values.”

The Company previously owned a 50% interest in Great Lakes, and as an investment in an LLC, accounted for its 50% ownership using the proportional consolidation method. Thus, 50% of Great Lakes assets and liabilities and operating results are included in the Company’s historic financial statements.

On June 2, 2004, we agreed to purchase FirstEnergy’s interest in Great Lakes for a cash purchase price of $200.0 million plus an optional cash payment equal to 50% of Great Lakes’ commodity hedge liability (“Optional Hedging Payment”) which was $27.7 million at closing on June 23, 2004. The transaction also includes the assumption of debt and other liabilities, which totaled $96.1 million and $1.3 in transaction expenses, for an aggregate anticipated purchase price of $325.1 million. In consideration for the Optional Hedging Payment, FirstEnergy reimbursed Great Lakes, as a capital contribution, for 50% of each commodity derivative position, and the Company did not assume any commodity derivative liabilities associated with the 50% purchased interest.

F-44

The calculation of the total purchase price and the allocation of this price to assets and liabilities are shown below:

Calculation and preliminary allocation of purchase price (in thousands):



Cash paid to FirstEnergy	$	200,000
Optional Hedging Payment		27,720
Cash paid for transaction costs		1,266

Total purchase price	$	228,986

Plus fair value of liabilities assumed (in thousands):



Current liabilities	$	8,375
Long-term debt		70,000
Asset retirement obligation		17,035
Other non-current liabilities		658

Total purchase price liabilities assumed	$	325,054

Fair value of Great Lakes assets (in thousands):



Current assets	$	13,437
Oil and natural gas properties		296,322
Gas gathering and processing assets		14,429
Other non-current assets		866

Total fair value of Great Lakes assets	$	325,054

The total purchase price included $1.3 million of estimated merger costs. These costs include investment banking expenses, legal and accounting fees, printing expenses and other acquisition related costs.

In order to finance the acquisition, the acquisition required the consolidation of the Great Lakes Credit Facility into an amended and restated senior credit facility, the issuance of 12,190,000 shares of Range common stock at a price of $12.25 and the issuance of $100.0 million of additional 7.375% senior subordinated notes. The stock transaction included transaction costs of $7.5 million and the issuance of 7.375% senior subordinated notes included transaction expense of $3.0 million and a discount of $1.9 million. Fees for amended and restated senior credit facility were $1.0 million.

The unaudited pro forma statements of operations include the following adjustments:

	(i)	This adjustment increases interest expense for the effect of additional borrowings under the Senior Credit Facility and amortization of fees associated with an amended and restated senior credit facility.

	(j)	This adjustment reflects the decrease in amortization due to the write-off of 50% of Great Lakes’ deferred financing costs attributed to FirstEnergy’s share of the Great Lakes Credit Facility.

	(k)	This adjustment increases interest expense for the effect of issuance of an additional $100 million of 7.375% senior subordinated notes and the amortization of the associated discount and estimated issuance costs.

	(l)	This adjustment revises Great Lakes historical depreciation, depletion and amortization expense to reflect the adjustment of Great Lakes assets from historical book value in the purchase price allocation. For the oil and gas producing properties, pro forma depletion was calculated using the equivalent units-of-production method.

F-45

(m)

This adjustment recognizes income tax effects of the adjustments to depreciation, depletion and amortization and interest expense at an effective tax rate of approximately 37%. This adjustment also recognizes tax expense for Great Lakes’ 50% income prior to the acquisition. Great Lakes did not recognize income taxes as a limited liability corporation.

(4) Net earnings per common share

Net earnings per common share outstanding for the nine months ended September 30, 2004 and the year ended December 31, 2003.



	Nine months
	ended			Year ended
	September 30,			December 31,
(in thousands)	2004			2003

Numerator:
Net income	$	37,433		$	44,308
Preferred stock dividends		(2,212	)		(803	)


Numerator for basic earnings per share	$	35,221		$	43,505


Net income	$	37,433		$	44,308
Effect of dilutive securities		—			—


Numerator for diluted earnings per share after assumed Conversions	$	37,433		$	44,308


Denominator:
Range weighted average shares outstanding		61,686			55,796
Pro forma increase		13,180			17,940
Stock held in deferred compensation plan		(1,687	)		(1,524	)


Pro forma shares outstanding – basic		73,179			72,212


Range weighted average shares outstanding		61,686			55,796
Pro forma increase – Great Lakes		7,430			12,190
Pro forma increase – Pine Mountain		5,750			5,750
Employee stock options		1,192			442
Common shares assumed issued for convertible preferred		5,882			1,612


Pro forma shares outstanding - diluted		81,940			75,790

F-46

(5) Supplemental pro forma information on oil and gas operations

Pro forma costs incurred

The following tables reflect the costs incurred in oil and natural gas producing property acquisitions, exploration and development activities of Range, Great Lakes, Pine Mountain and the combined company on a pro forma basis for the year ended December 31, 2003:



	Year Ended December 31, 2003
	Range		Great				Pine		Combined
(in thousands)	Resources		Lakes		Total		Mountain		Pro Forma

Acquisitions:
Unproved leasehold	$	5,580	$	1,824	$	7,404	$	—	$	7,404
Proved oil and gas properties		90,723		2,557		93,280		—		93,280
Gas gathering facilities		4,622		—		4,622		—		4,622
Development		83,433		21,648		105,081		3,692		108,773
Exploration		22,564		4,382		26,946		—		26,946


Subtotal		206,922		30,411		237,333		3,692		241,025


Asset retirement obligations		4,597		1,731		6,328		424		6,752


Total	$	211,519	$	32,142	$	243,661	$	4,116	$	247,777

F-47

Pro forma quantities of oil and natural gas reserves

Quantities of Proved Reserves



	Crude Oil and NGLs (Mbbls)
	Range			50% Great						Pine		Combined
	Resources			Lakes			Total			Mountain		Pro forma

Balance, December 31, 2002		22,952			5,689			28,641			—		28,641
Revisions		445			(136	)		309			—		309
Extensions, discoveries and additions		3,331			116			3,447			—		3,447
Purchases		8,758			177			8,935			—		8,935
Sales		(39	)		(7	)		(46	)		—		(46	)
Production		(2,424	)		(311	)		(2,735	)		—		(2,735	)

Balance, December 31, 2003		33,023			5,528			38,551			—		38,551



	Natural Gas (Mmcf)
	Range			50% Great						Pine			Combined
	Resources			Lakes			Total			Mountain			Pro forma

Balance, December 31, 2002		440,267			218,346			658,613			49,328			707,941
Revisions		4,625			6,437			11,062			6,229			17,291
Extensions, discoveries and additions		48,364			14,480			62,844			9,254			72,098
Purchases		37,734			975			38,709			—			38,709
Additional reporting of proved undeveloped reserves		—			—			—			73,327			73,327
Sales		(1,076	)		(657	)		(1,733	)		—			(1,733	)
Production		(43,510	)		(11,153	)		(54,663	)		(5,098	)		(59,761	)

Balance, December 31, 2003		486,404			228,428			714,832			133,040			847,872



	Natural Gas Equivalents (Mmcfe)
	Range			50% Great						Pine			Combined
	Resources			Lakes			Total			Mountain			Pro forma

Balance, December 31, 2002		577,977			252,478			830,455			49,328			879,783
Revisions		7,294			5,621			12,915			6,229			19,144
Extensions, discoveries and additions		68,351			15,176			83,527			9,254			92,781
Purchases		90,284			2,035			92,319			—			92,319
Additional reporting of proved undeveloped reserves		—			—			—			73,327			73,327
Sales		(1,312	)		(700	)		(2,012	)		—			(2,012	)
Production		(58,053	)		(13,019	)		(71,072	)		(5,098	)		(76,170	)

Balance, December 31, 2003		684,541			261,591			946,132			133,040			1,079,172



	Range		50% Great				Pine		Combined
	Resources		Lakes		Total		Mountain		Pro forma

Proved developed reserves (Mmcfe)
December 31, 2002		423,280		147,919		571,199		49,328		620,527
December 31, 2003		493,659		151,310		644,969		59,713		704,682

F-48

Pro forma standardized measure of discounted future cash flows

The following table sets forth the standardized measures of discounted future net cash flows relating to proved oil, natural gas and NGL reserves for Range, Great Lakes, Pine Mountain and the combined company on a pro forma basis as of December 31, 2003:



	Range			50% Great						Pine			Pro forma
(in thousands)	Resources			Lakes			Total			Mountain			Combined

Future cash inflows	$	3,803,479		$	1,640,172		$	5,443,651		$	841,453		$	6,285,104
Future costs:
Production		(842,052	)		(308,104	)		(1,150,156	)		(144,654	)		(1,294,810	)
Development		(274,029	)		(155,035	)		(429,064	)		(43,218	)		(472,282	)

Future net cash flows		2,687,398			1,177,033			3,864,431			653,581			4,518,012
Income taxes		(740,965	)		(328,769	)		(1,069,734	)		(89,654	)		(1,159,388	)


Total undiscounted future net cash flows		1,946,433			848,264			2,794,697			563,927			3,358,624
10% discount factor		(943,452	)		(520,991	)		(1,464,443	)		(400,584	)		(1,865,027	)

Standardized measure	$	1,002,981		$	327,273		$	1,330,254		$	163,343		$	1,493,597

The “Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves” (“Standardized Measure”) is a disclosure requirement of SFAS 69. The Standardized Measure does not purport to present the fair value of oil and gas reserves. This would require consideration of expected future economic and operating conditions, which are not taken into account in calculating the Standardized Measure.

Future cash inflows were estimated by applying year-end prices to the estimated future production less estimated future production costs based on year-end costs. Future net cash inflows were discounted using a 10% annual discount rate to arrive at the Standardized Measure.

Pro forma changes relating to standardized measure of discounted future net cash flows



	Range			50% Great						Pine			Combined
(in thousands)	Resources			Lakes			Total			Mountain			Pro Forma

Standardized measure, beginning of year	$	499,633		$	124,167		$	623,800		$	68,337		$	692,137
Revisions:
Prices		160,932			129,059			289,991			3,546			293,537
Quantities		267,906			20,542			288,448			10,870			299,318
Estimated future development cost		(253,788	)		(155,035	)		(408,823	)		(52,050	)		(460,873	)
Accretion of discount		96,361			35,415			131,776			10,513			142,289
Income taxes		(103,375	)		(41,118	)		(144,493	)		(52,857	)		(197,350	)


Net revisions		168,036			(11,137	)		156,899			(79,978	)		76,921
Purchases		145,772			4,314			150,086			—			150,086
Extensions, discoveries and additions		110,358			32,166			142,524			21,211			163,735
Production		(177,085	)		(44,057	)		(221,142	)		(23,166	)		(244,308	)
Development costs incurred		204,137			138,591			342,728			8,863			351,591
Sales		(2,117	)		(1,485	)		(3,602	)		—			(3,602	)
Additional reporting of proved undeveloped reserves		—			—			—			168,074			168,074
Changes in timing and other		54,247			84,714			138,961			—			138,961

Standardized measure, end-of-year	$	1,002,981		$	327,273		$	1,330,254		$	163,341		$	1,493,595

F-49