Edgar Filing: RANGE RESOURCES CORP

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

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

Date of report (Date of earliest event reported):
August 7, 2009

RANGE RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)


Delaware	001-12209	34-1312571

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


100 Throckmorton, Suite 1200
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 8.01 OTHER EVENTS
ITEM 8. Financial Statements and Supplementary Data
SIGNATURES
EX-23.1

ITEM 8.01 OTHER EVENTS

This current report on Form 8-K was prepared to provide revised financial information for the years ended December 31, 2006, 2007 and 2008 for immaterial errors identified in the second quarter of 2009. As noted in Footnote 2 to our consolidated financial statements included in our quarterly report on Form 10-Q for the period ended June 30, 2009, we have identified certain leases amounting to $8.2 million that expired in 2006, 2007, and 2008, which were not expensed as required. Based on guidance set forth in Staff Accounting Bulletin No. 99, “Materiality” and in Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” (“SAB 108”), we have determined that these amounts are immaterial to each of the periods affected and, therefore, we are not required to amend our previously filed reports. However, if these adjustments were recorded in 2009, we believe the impact could be material to this year. We have adjusted our previously reported results for the years ended December 31, 2006, 2007, and 2008 for these immaterial amounts as required by SAB 108. In addition to recording additional lease expirations, we have made four other adjustments to prior year numbers to correct other immaterial items, which included the following adjustments: (1) tax expense of $3.5 million for discrete tax items recorded in 2008 related to the year ended December 31, 2007 (2) revenue reduction for volumetric ineffectiveness related to our derivative positions of $1.7 million recorded in 2008 related to the year ended December 31, 2007 (3) dry hole expense of $2.4 million not recorded in the year ended December 31, 2007 and (4) deferred compensation income of $7.1 million recorded in 2007 related to the year ended December 31, 2006 and prior years. The balance sheets as of December 31, 2008 and December 31, 2007 have been adjusted to reflect the cumulative impact of these errors.

Please note, we have not otherwise updated our financial information for activities or events occurring after the date this information was presented in our annual report on Form 10-K for the year ended December 31, 2008, filed on February 27, 2009 (“2008 Form 10-K”). You should read our quarterly reports on Form 10-Q for the periods ended March 31, 2009 and June 30, 2009 and our current reports on Form 8-K for updated information.

This filing includes updated information for the following items included in our 2008 Form 10-K:

ITEM 8. Financial Statements and Supplementary Data

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: August 7, 2009

RANGE RESOURCES CORPORATION
INDEX TO FINANCIAL STATEMENTS


	Page
	Number
Report of Independent Registered Public Accounting Firm — Consolidated Financial Statements		F- 2

Consolidated Balance Sheets at December 31, 2008 and 2007		F- 3

Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007 and 2006		F- 4

Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006		F- 5

Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2008, 2007 and 2006		F- 6

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2008, 2007 and 2006		F- 7

Notes to Consolidated Financial Statements		F-8

Selected Quarterly Financial Data (Unaudited)		F-35

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)		F-37

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Range Resources Corporation:

We have audited the accompanying consolidated balance sheets of Range Resources Corporation (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity, comprehensive income and cash flows for each of the three years in the period ended December 31, 2008. 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated 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 consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Range Resources Corporation at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 3 to the consolidated financial statements, in 2008, the Company adopted Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities Including an amendment of FASB Statement No. 115.”

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Range Resources Corporation’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2009 expressed an unqualified opinion thereon.

Ernst & Young LLP

Fort Worth, Texas
February 23, 2009, except for Note 2, as to which the date is August 5, 2009

F-2

RANGE RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)


	December 31,
	2008			2007
Assets
Current assets:
Cash and equivalents	$	753		$	4,018
Accounts receivable, less allowance for doubtful accounts of $954 and $583		162,201			166,484
Unrealized derivative gain		221,430			53,018
Deferred tax asset		—			26,907
Inventory and other		19,927			11,387

Total current assets		404,311			261,814


Unrealized derivative gain		5,231			1,082
Equity method investments		147,126			113,722
Oil and gas properties, successful efforts method		6,028,980			4,432,362
Accumulated depletion and depreciation		(1,186,934	)		(939,769	)

		4,842,046			3,492,593

Transportation and field assets		142,662			104,802
Accumulated depreciation and amortization		(56,434	)		(43,676	)

		86,228			61,126
Other assets		66,937			74,956

Total assets	$	5,551,879		$	4,005,293


Liabilities
Current liabilities:
Accounts payable	$	250,640		$	212,514
Asset retirement obligations		2,055			1,903
Accrued liabilities		47,309			42,964
Deferred tax liability		32,984			—
Accrued interest		20,516			17,595
Unrealized derivative loss		10			30,457

Total current liabilities		353,514			305,433

Bank debt		693,000			303,500
Subordinated notes and other long term debt		1,097,668			847,158
Deferred tax liability		779,218			589,857
Unrealized derivative loss		—			45,819
Deferred compensation liability		93,247			120,223
Asset retirement obligations and other liabilities		83,890			75,567
Commitments and contingencies

Stockholders’ Equity
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding		—			—
Common stock, $0.01 par, 475,000,000 shares authorized, 155,609,387 issued at December 31, 2008 and 149,667,497 issued at December 31, 2007		1,556			1,497
Common stock held in treasury, 233,900 shares at December 31, 2008 and 155,500 shares at December 31, 2007		(8,557	)		(5,334	)
Additional paid-in capital		1,695,268			1,386,884
Retained earnings		685,568			360,427
Accumulated other comprehensive income (loss)		77,507			(25,738	)

Total stockholders’ equity		2,451,342			1,717,736

Total liabilities and stockholders’ equity	$	5,551,879		$	4,005,293

See accompanying notes.

F-3

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)


	Year Ended December 31,
	2008			2007			2006
Revenues
Oil and gas sales	$	1,226,560		$	862,537		$	599,139
Transportation and gathering		4,577			2,290			2,422
Derivative fair value income (loss)		71,861			(9,493	)		142,395
Other		21,675			5,031			856

Total revenue		1,324,673			860,365			744,812


Costs and expenses
Direct operating		142,387			107,499			81,261
Production and ad valorem taxes		55,172			42,443			36,415
Exploration		67,690			45,782			44,088
Abandonment and impairment of unproved properties		47,355			11,236			4,549
General and administrative		92,308			69,670			49,886
Deferred compensation plan		(24,689	)		35,438			(233	)
Interest expense		99,748			77,737			55,849
Depletion, depreciation and amortization		299,831			220,578			154,482

Total costs and expenses		779,802			610,383			426,297


Income from continuing operations before income taxes		544,871			249,982			318,515

Income tax expense
Current		4,268			320			1,912
Deferred		189,563			95,987			120,726

Total income tax expense		193,831			96,307			122,638


Income from continuing operations		351,040			153,675			195,877

Discontinued operations, net of taxes		—			63,593			(35,247	)


Net income	$	351,040		$	217,268		$	160,630


Earnings per common share:
Basic-income from continuing operations	$	2.32		$	1.07		$	1.46
-discontinued operations		—			0.44			(0.26	)

-net income	$	2.32		$	1.51		$	1.20


Diluted-income from continuing operations	$	2.25		$	1.02		$	1.41
-discontinued operations		—			0.43			(0.25	)

-net income	$	2.25		$	1.45		$	1.16


Weighted average common shares outstanding:
Basic		151,116			143,791			133,751
Diluted		155,943			149,911			138,711

See accompanying notes.

F-4

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Year Ended December 31,
	2008			2007			2006
Operating activities:
Net income	$	351,040		$	217,268		$	160,630
Adjustments to reconcile net cash provided from operating activities:
(Income) loss from discontinued operations		—			(63,593	)		35,247
Loss (income) from equity method investments		218			(974	)		(548	)
Deferred income tax expense		189,563			95,987			120,726
Depletion, depreciation and amortization		299,831			220,578			154,482
Exploration dry hole costs		13,371			17,586			15,089
Mark-to-market on oil and gas derivatives not designated as hedges		(85,594	)		80,495			(86,491	)
Abandonment and impairment of unproved properties		47,355			11,236			4,549
Unrealized derivative (gains) loss		(1,695	)		820			(5,654	)
Allowance for bad debts		450			—			80
Amortization of deferred financing costs and other		2,900			2,277			1,827
Deferred and stock-based compensation		6,621			61,258			20,349
(Gain) losses on sale of assets and other		(19,507	)		2,212			940
Changes in working capital, net of amounts from business acquisitions:
Accounts receivable		6,701			(50,570	)		30,185
Inventory and other		(9,246	)		(1,040	)		(1,157	)
Accounts payable		10,663			28,640			(5,049	)
Accrued liabilities and other		12,096			9,922			(3,696	)

Net cash provided from continuing operations		824,767			632,102			441,509
Net cash provided from discontinued operations		—			10,189			38,366

Net cash provided from operating activities		824,767			642,291			479,875


Investing activities:
Additions to oil and gas properties		(881,950	)		(782,398	)		(487,245	)
Additions to field service assets		(36,076	)		(26,044	)		(14,449	)
Acquisitions, net of cash acquired		(834,758	)		(336,453	)		(360,149	)
Investing activities of discontinued operations		—			(7,375	)		(29,195	)
Investment in equity method investment and other assets		(44,162	)		(94,630	)		(21,009	)
Proceeds from disposal of assets and discontinued operations		68,231			234,332			388
Purchase of marketable securities held by the deferred compensation plan		(11,208	)		(48,018	)		—
Proceeds from the sales of marketable securities held by the deferred compensation plan		8,146			40,014			—

Net cash used in investing activities		(1,731,777	)		(1,020,572	)		(911,659	)


Financing activities:
Borrowing on credit facilities		1,476,000			864,500			802,500
Repayment on credit facilities		(1,086,500	)		(1,013,000	)		(619,700	)
Issuance of subordinated notes		250,000			250,000			249,500
Dividends paid		(24,625	)		(19,082	)		(12,189	)
Debt issuance costs		(8,710	)		(3,686	)		(6,960	)
Issuance of common stock		291,183			296,229			16,265
Cash overdrafts		4,420			3,877			—
Proceeds from the sales of common stock held by the deferred compensation plan		5,303			6,505			—
Purchases of common stock held by the deferred compensation plan and other treasury stock purchases		(3,326	)		(5,426	)		—

Net cash provided from financing activities		903,745			379,917			429,416


(Decrease) increase in cash and equivalents		(3,265	)		1,636			(2,368	)
Cash and equivalents at beginning of year		4,018			2,382			4,750

Cash and equivalents at end of year	$	753		$	4,018		$	2,382

See accompanying notes.

F-5

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)


																Accumulated
					Treasury			Additional								other
	Common stock				common			paid-in		Retained			Deferred			comprehensive
	Shares		Par value		stock			capital		earnings			compensation			(loss) income			Total
Balance
December 31, 2005		129,913	$	1,299	$	(81	)	$	833,667	$	13,800		$	(4,635	)	$	(147,127	)	$	696,923

Issuance of common stock		9,018		90		—			203,280		—			4,635			—			208,005

Stock-based compensation expense		—		—		—			20,991		—			—			—			20,991

Common dividends declared ($0.09 per share)		—		—		—			—		(12,189	)		—			—			(12,189	)

Treasury stock issuance		—		—		81			—		—			—			—			81

Other comprehensive income		—		—		—			—		—			—			183,648			183,648

Net income		—		—		—			—		160,630			—			—			160,630


Balance
December 31, 2006		138,931		1,389		—			1,057,938		162,241			—			36,521			1,258,089

Issuance of common stock		10,736		108		—			312,427		—			—			—			312,535

Stock-based compensation expense		—		—		—			16,519		—			—			—			16,519

Common dividends declared ($0.13 per share)		—		—		—			—		(19,082	)		—			—			(19,082	)

Treasury stock purchase		—		—		(5,334	)		—		—			—			—			(5,334	)

Other comprehensive loss		—		—		—			—		—			—			(62,259	)		(62,259	)

Net income		—		—		—			—		217,268			—			—			217,268


Balance
December 31, 2007		149,667		1,497		(5,334	)		1,386,884		360,427			—			(25,738	)		1,717,736

Issuance of common stock		5,942		59		—			291,822		—			—			—			291,881

Stock-based compensation expense		—		—		—			16,562		—			—			—			16,562

Common dividends declared ($0.16 per share)		—		—		—			—		(24,625	)		—			—			(24,625	)

Treasury stock purchase		—		—		(3,223	)		—		—			—			—			(3,223	)

Other comprehensive income		—		—		—			—		—			—			101,971			101,971

Net income		—		—		—			—		351,040			—			—			351,040

Adoption of SFAS No. 159, net of tax		—		—		—			—		(1,274	)		—			1,274			—

Balance

December 31, 2008		155,609	$	1,556	$	(8,557	)	$	1,695,268	$	685,568		$	—		$	77,507		$	2,451,342

See accompanying notes.

F-6

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)


	December 31,
	2008		2007			2006
Net income	$	351,040	$	217,268		$	160,630
Other comprehensive (loss) income:
Realized loss (gain) on hedge derivative contract settlements reclassified into earnings from other comprehensive (loss) income		39,416		(2,621	)		60,764
Change in unrealized deferred hedging gains (losses)		62,555		(54,477	)		120,832
Change in unrealized (losses) gains on securities held by deferred compensation plan, net of taxes		—		(5,161	)		2,052

Total comprehensive income	$	453,011	$	155,009		$	344,278

See accompanying notes.

F-7

RANGE RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) SUMMARY OF ORGANIZATION AND NATURE OF BUSINESS

Range Resources Corporation (“Range,” “we,” “us,” or “our”) is engaged in the exploration, development and acquisition of oil and gas properties primarily in the Southwestern, Appalachian and Gulf Coast regions of the United States. We seek to increase our reserves and production primarily through drilling and complementary acquisitions. Range is a Delaware corporation with its common stock trading on the New York Stock Exchange.

(2) RESTATEMENT OF PRIOR PERIODS

In second quarter 2009, we identified certain leases amounting to $8.2 million that expired in 2006, 2007, and 2008, which were not expensed as required. Based on guidance set forth in Staff Accounting Bulletin No. 99, “Materiality” and in Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” (“SAB 108”), we have determined that these amounts are immaterial to each of the periods affected and, therefore, we are not required to amend our previously filed reports. However, if these adjustments were recorded in 2009, we believe the impact could be material to this year. We have adjusted, in the tables below, our previously reported results for the years ended December 31, 2006, 2007, and 2008 for these immaterial amounts as required by SAB 108. In addition to recording additional lease expirations, we have made four other adjustments to prior year numbers to correct other immaterial items, which included the following adjustments: (1) tax expense of $3.5 million for discrete tax items recorded in 2008 related to the year ended December 31, 2007 (2) revenue reduction for volumetric ineffectiveness related to our derivative positions of $1.7 million recorded in 2008 related to the year ended December 31, 2007 (3) dry hole expense of $2.4 million not recorded in the year ended December 31, 2007 and (4) deferred compensation income of $7.1 million recorded in 2007 related to the year ended December 31, 2006 and prior years to correct errors associated with accounting for the Company’s deferred compensation plan, or Rabbi Trust.


	Year Ended									Year Ended									Year Ended
	December 31, 2008									December 31, 2007									December 31, 2006
	Previously									Previously									Previously						As
	Reported			Adjustments			As Adjusted			Reported			Adjustments			As Adjusted			Reported			Adjustments			Adjusted
Oil and gas sales	$	1,226,560		$	—		$	1,226,560		$	862,537		$	—		$	862,537		$	599,139		$	—		$	599,139
Transportation and gathering		4,577			—			4,577			2,290			—			2,290			2,422			—			2,422
Derivative fair value income		70,135			1,726			71,861			(7,767	)		(1,726	)		(9,493	)		142,395			—			142,395
Other		21,675			—			21,675			5,031			—			5,031			856			—			856

Total revenues		1,322,947			1,726			1,324,673			862,091			(1,726	)		860,365			744,812			—			744,812

Direct operating costs		142,387			—			142,387			107,499			—			107,499			81,261			—			81,261
Production and ad valorem taxes		55,172			—			55,172			42,443			—			42,443			36,415			—			36,415
Exploration		67,690			—			67,690			43,345			2,437			45,782			44,088			—			44,088
Abandonment & impairment of unproved properties		47,906			(551	)		47,355			6,750			4,486			11,236			257			4,292			4,549
General and administrative expense		92,308			—			92,308			69,670			—			69,670			49,886			—			49,886
Deferred compensation plan		(24,689	)		—			(24,689	)		28,332			7,106			35,438			6,873			(7,106	)		(233	)
Interest expense		99,748			—			99,748			77,737			—			77,737			55,849			—			55,849
Depletion, depreciation and amortization		299,831			—			299,831			220,578			—			220,578			154,482			—			154,482

Total costs and expenses		780,353			(551	)		779,802			596,354			14,029			610,383			429,111			(2,814	)		426,297

Income from continuing operations before income taxes		542,594			2,277			544,871			265,737			(15,755	)		249,982			315,701			2,814			318,515

Income tax expense
Current		4,268			—			4,268			320			—			320			1,912			—			1,912
Deferred		192,168			(2,605	)		189,563			98,441			(2,454	)		95,987			119,840			886			120,726

Total		196,436			(2,605	)		193,831			98,761			(2,454	)		96,307			121,752			886			122,638

Net income from continuing operations		346,158			4,882			351,040			166,976			(13,301	)		153,675			193,949			1,928			195,877

Discontinued operations		—			—			—			63,593			—			63,593			(35,247	)		—			(35,247	)


Net income	$	346,158		$	4,882		$	351,040		$	230,569		$	(13,301	)	$	217,268		$	158,702		$	1,928		$	160,630


Earnings per common share:
Basic — income from continuing operations	$	2.29		$	0.03		$	2.32		$	1.16		$	(0.09	)	$	1.07		$	1.45		$	0.01		$	1.46
— discontinued operations		—			—			—			0.44			—			0.44			(0.26	)		—			(0.26	)

— net income	$	2.29		$	0.03		$	2.32		$	1.60		$	(0.09	)	$	1.51		$	1.19		$	0.01		$	1.20


Earnings per common share:
Diluted — income from continuing operations	$	2.22		$	0.03		$	2.25		$	1.11		$	(0.09	)	$	1.02		$	1.39		$	0.02		$	1.41
— discontinued operations		—			—			—			0.43			—			0.43			(0.25	)		—			(0.25	)

— net income	$	2.22		$	0.03		$	2.25		$	1.54		$	(0.09	)	$	1.45		$	1.14		$	0.02		$	1.16

F-8


	December 31, 2008									December 31, 2007
							As									As
	2008			Adjustments			Adjusted			2007			Adjustments			Adjusted
Assets
Current assets:
Cash and equivalents	$	753		$	—		$	753		$	4,018		$	—		$	4,018
Accounts receivable, less allowance for doubtful accounts of $954 and $583		162,201			—			162,201			166,484			—			166,484
Unrealized derivative gain		221,430			—			221,430			53,018			—			53,018
Deferred tax asset		—			—			—			26,907			—			26,907
Inventory and other		19,927			—			19,927			11,387			—			11,387

Total current assets		404,311			—			404,311			261,814			—			261,814

Unrealized derivative gain		5,231			—			5,231			1,082			—			1,082
Equity method investments		147,126			—			147,126			113,722			—			113,722
Oil and gas properties, successful efforts method		6,039,644			(10,664	)		6,028,980			4,443,577			(11,215	)		4,432,362
Accumulated depletion and depreciation		(1,186,934	)		—			(1,186,934	)		(939,769	)		—			(939,769	)

		4,852,710			(10,664	)		4,842,046			3,503,808			(11,215	)		3,492,593

Transportation and field assets		142,662			—			142,662			104,802			—			104,802
Accumulated depreciation and amortization		(56,434	)		—			(56,434	)		(43,676	)		—			(43,676	)

		86,228			—			86,228			61,126			—			61,126
Other assets		66,937			—			66,937			74,956			—			74,956

Total assets	$	5,562,543		$	(10,664	)	$	5,551,879		$	4,016,508		$	(11,215	)	$	4,005,293


Liabilities
Current liabilities:
Accounts payable	$	250,640		$	—		$	250,640		$	212,514		$	—		$	212,514
Asset retirement obligations		2,055			—			2,055			1,903			—			1,903
Accrued liabilities		47,309			—			47,309			42,964			—			42,964
Deferred tax liability		32,984			—			32,984			—			—
Accrued interest		20,516			—			20,516			17,595			—			17,595
Unrealized derivative loss		10			—			10			30,457			—			30,457

Total current liabilities		353,514			—			353,514			305,433			—			305,433

Bank debt		693,000			—			693,000			303,500			—			303,500
Subordinated notes and other long-term debt		1,097,668			—			1,097,668			847,158			—			847,158
Deferred tax liability		783,391			(4,173	)		779,218			590,786			(929	)		589,857
Unrealized derivative loss		—			—			—			45,819			—			45,819
Deferred compensation liability		93,247			—			93,247			120,223			—			120,223
Asset retirement obligations and other liabilities		83,890			—			83,890			75,567			—			75,567
Commitments and contingencies		—			—			—			—			—			—

Stockholder’s Equity
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding		—			—						—			—			—
Common stock, $0.01 par, 475,000,000 shares authorized, 155,609,387 issued at December 31, 2008 and 149,667,497 issued at December 31, 2007		1,556			—			1,556			1,497			—			1,497
Common stock held in treasury, 233,900 shares at December 31, 2008 and 155,500 shares at December 31, 2007		(8,557	)		—			(8,557	)		(5,334	)		—			(5,334	)
Additional paid-in capital		1,695,268			—			1,695,268			1,386,884			—			1,386,884
Retained earnings		692,059			(6,491	)		685,568			371,800			(11,373	)		360,427
Accumulated other comprehensive income (loss)		77,507			—			77,507			(26,825	)		1,087			(25,738	)

Total stockholders’ equity		2,457,833			(6,491	)		2,451,342			1,728,022			(10,286	)		1,717,736

Total liabilities and stockholders’ equity	$	5,562,543		$	(10,664	)	$	5,551,879		$	4,016,508		$	(11,215	)	$	4,005,293

F-9

In addition to the changes detailed above, the following individual line items within net cash provided from operating activities were impacted. However, these adjustments had no impact on total cash provided from operating activities for any of the respective years. There were no adjustments to previously reported amounts included in net cash used in investing activities or net cash provided from financing activities (in thousands):


	2008						2007				2006
				As					As					As
	Reported			Adjusted			Reported		Adjusted		Reported			Adjusted
Net income	$	346,158		$	351,040		$	230,569	$	217,268	$	158,702		$	160,630

Deferred income taxes		192,168			189,563			98,441		95,987		119,840			120,726

Mark-to-market on oil and gas derivative not designated as hedges		(83,868	)		(85,594	)		78,769		80,495		(86,491	)		(86,491	)

Exploration dry hole costs		13,371			13,371			15,149		17,586		15,089			15,089

Abandonment and impairment of unproved properties		47,906			47,355			6,750		11,236		257			4,549

Deferred and stock-based compensation		6,621			6,621			54,152		61,258		27,455			20,349

(3) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements include the accounts of all of our subsidiaries. Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting and are carried at our share of net assets plus loans and advances. Income from equity method investments represents our proportionate share of income generated by equity method investees and is included in “Other revenues” on our consolidated statement of operations. All material intercompany balances and transactions have been eliminated.

During first quarter 2007, we sold our interests in our Austin Chalk properties that we purchased as part of the Stroud acquisition (see also Note 4). We also sold our Gulf of Mexico properties at the end of first quarter 2007. In accordance with Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment of Disposal of Long-Lived Assets,” we have reflected the results of operations of the above divestitures as discontinued operations, rather than a component of continuing operations. All periods presented reflect our Gulf of Mexico operations as discontinued operations. See also Note 5 for additional information regarding discontinued operations.

Use of Estimates

The preparation of financial statements in accordance with generally accepted accounting principles in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year-end, the reported amounts of revenues and expenses during the year and the reported amount of proved oil and gas reserves. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments that are not readily apparent from other sources. Actual results could differ from the estimates and assumptions used.

Income per Common Share

Basic net income per share is calculated based on the weighted average number of common shares outstanding. Diluted net income per share assumes issuance of stock compensation awards, provided the effect is not antidilutive.

F-10

Business Segment Information

SFAS No. 131, “Disclosure about Segments of an Enterprise and Related Information,” establishes standards for reporting information about operating segments. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and this information is regularly evaluated by the chief decision maker for the purpose of allocating resources and assessing performance.

Segment reporting is not applicable to us as we have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis. Throughout the year, we allocate capital resources on a project-by-project basis, across our entire asset base to maximize profitability without regard to individual areas or segments.

Revenue Recognition and Gas Imbalances

Oil, gas and natural gas liquids revenues are recognized when the products are sold and delivery to the purchaser has occurred. We recognize the cost of revenues, such a transportation and compression expense, as a reduction to revenue. Although receivables are concentrated in the oil and gas industry, we do not view this as unusual credit risk. We provide for an allowance for doubtful accounts for specific receivables judged unlikely to be collected based on the age of the receivable, our experience with the debtor, potential offsets to the amount owed and economic conditions. In certain instances, we require purchasers to post stand-by letters of credit. Many of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We have allowances for doubtful accounts relating to exploration and production receivables of $954,000 at December 31, 2008 compared to $583,000 at December 31, 2007.

We use the sales method to account for gas imbalances, recognizing revenue based on gas delivered rather than our working interest share of the gas produced. A liability is recognized when the imbalance exceeds the estimate of remaining reserves. Gas imbalances at December 31, 2008 and December 31, 2007 were not significant. At December 31, 2008, we had recorded a net liability of $480,000 for those wells where it was determined that there were insufficient reserves to recover the imbalance situation.

Cash and Equivalents

Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with maturities of three months or less.

Marketable Securities

Holdings of equity securities held in our deferred compensation plans qualify as trading and are recorded at fair value. Investments in the deferred compensation plans are in mutual funds.

Inventories

Inventories consist primarily of tubular goods used in our operations and are stated at the lower of specific cost of each inventory item or market value.

Oil and Gas Properties

We follow the successful efforts method of accounting for oil and gas producing activities. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, delay rentals and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. The status of suspended well costs is monitored continuously and reviewed not less than quarterly. We capitalize successful exploratory wells and all developmental wells, whether successful or not. Oil and NGLs are converted to gas equivalent basis or mcfe at the rate of one barrel of oil equating to 6 mcf of gas. Depreciation, depletion and amortization of proved producing properties is provided on the units of production method.

Our long-lived assets are reviewed for impairment periodically as events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization is less than the estimated expected undiscounted future net cash flows. The expected future net cash flows are estimated based on our plans to produce and develop proved reserves. Expected future net cash inflow from the sale of production of reserves is calculated based on estimated future prices and estimated operating and development costs. We estimate prices based upon

F-11

market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. When the carrying value exceeds the sum of future net cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future net cash flows) and the carrying value of the asset. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future oil and gas prices, an estimate of the ultimate amount of recoverable oil and gas reserves that will be produced from a field, the timing of future production, future production costs, future abandonment costs and future inflation. We cannot predict whether impairment charges may be required in the future.

Proceeds from the disposal of miscellaneous properties are credited to the net book value of their amortization group with no immediate effect on income. However, gain or loss is recognized from the sale of less than an entire amortization group if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.

We adhere to the SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” for recognizing any impairment of capitalized costs related to unproved properties. The majority of these costs generally relate to the acquisition of leasehold costs. The costs are capitalized and periodically evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. We consider a combination of time, geologic and engineering factors to evaluate the need for impairment of these costs. Unproved properties had a net book value of $758.0 million in 2008 compared to $262.6 million in 2007 and $222.0 million in 2006. The increase from 2007 represents additional acreage purchases primarily in the Marcellus and Barnett Shale. We have recorded abandonment and impairment expense related to unproved properties of $47.4 million in 2008 compared to $11.2 million in 2007 and $4.5 million in 2006.

Transportation and Field Assets

Our gas transportation and gathering systems are generally located in proximity to certain of our principal fields. Depreciation on these systems is provided on the straight-line method based on estimated useful lives of 10 to 15 years. We receive third-party income for providing field service and certain transportation services, which are recognized as earned. Depreciation on the associated assets is calculated on the straight-line method based on estimated useful lives ranging from five to seven years. Buildings are depreciated over 10 to 15 years. Depreciation expense was $13.7 million in 2008 compared to $10.9 million in 2007 and $7.5 million in 2006.

Other Assets

The expenses of issuing debt are capitalized and included in other assets on our consolidated balance sheet. These costs are amortized over the expected life of the related instruments. When a security is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed. Other assets at December 31, 2008 include $21.7 million of unamortized debt issuance costs, $33.5 million of marketable securities held in our deferred compensation plans and $11.7 million of other investments.

Stock-based Compensation

The 2005 Equity Based Compensation Plan (the “2005 Plan”) authorizes the Compensation Committee of the Board of Directors to grant, among other things, stock options, stock appreciation rights and restricted stock awards to employees. The 2004 Non-Employee Director Stock Plan (the “Director Plan”) allows grants to our non-employee directors of our Board of Directors. The 2005 Plan was approved by stockholders in May 2005 and replaced our 1999 stock option plan. No new grants will be made from the 1999 stock option plan. The number of shares that may be issued under the 2005 Plan is equal to (i) 5.6 million shares (15.0 million less the 2.2 million shares issued under the 1999 Stock Options Plan before May 18, 2005, the effective date of the 2005 Plan and less the 7.2 million shares issuable pursuant to awards under the 1999 Stock Option Plan outstanding as of the effective date of the 2005 Plan) plus (ii) the number of shares subject to 1999 Stock Option Plan awards outstanding at May 18, 2005, that subsequently lapse or terminate without the underlying shares being issued. The Director Plan was approved by stockholders in May 2004 and no more than 450,000 shares of common stock may be issued under the Plan.

Stock options represent the right to purchase shares of stock in the future at the fair market value of the stock on the date of grant. Most stock options granted under our stock option plans vest over a three year period and expire five years from the date they are granted. Beginning in 2005, we began granting stock-settled stock appreciation rights (“SARs”) to reduce the dilutive impact of our equity plans. Similar to stock options, SARs represent the right to receive a payment equal to the excess

F-12

of the fair market value of shares of common stock on the date the right is exercised over the value of the stock on the date of grant. All SARs granted under the 2005 Plan will be settled in shares of stock, vest over a three-year period and have a maximum term of five years from the date they are granted.

The Compensation Committee grants restricted stock to certain employees and to non-employee directors of the Board of Directors as part of their compensation. Compensation expense is recognized over the balance of the vesting period, which is typically three years for employee grants and immediate vesting for non-employee directors. All restricted shares that are granted are placed in the deferred compensation plan. All vested restricted stock held in our deferred compensation plan is marked-to-market each reporting period based on the market value of our stock. This mark-to-market is presented in the caption “Deferred compensation plan” in our statement of operations. See additional information in Note 13.

The fair value of stock options and stock-settled SARs is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. The model employs various assumptions, based on management’s best estimates at the time of the grant, which impact the fair value calculated and ultimately, the expense that is recognized over the life of the award. The fair value of restricted stock awards is determined based on the fair market value of our common stock on the date of grant.

Stock-based compensation represents amortization of restricted stock grants and stock option/SARs expense recognized under SFAS No. 123(R). In 2006, stock-based compensation was allocated to direct operating expense ($1.4 million), exploration expense ($2.5 million) and general and administrative expense ($10.7 million) to align SFAS No. 123(R) expense with the employees’ cash compensation. In 2007, stock-based compensation was allocated to direct operating expense ($1.8 million), exploration expense ($2.3 million) and general and administrative expense ($10.8 million). In 2008, stock-based compensation was allocated to direct operating expense ($2.8 million), exploration expense ($4.1 million) and general and administrative expense ($23.8 million) for a total of $31.2 million. We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. Unlike the other forms of stock-based compensation mentioned above, the deferred compensation plan cost is directly tied to the change in our stock price and not directly related to the functional expenses and therefore, is not allocated to the functional categories.

Derivative Financial Instruments and Hedging

We account for our derivative activities under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. The statement, as amended, establishes accounting and reporting standards requiring that every derivative instrument be recorded on the balance sheet as either an asset or a liability measured at its fair value. The statement requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. All of the derivative instruments that we use are to manage the price risk attributable to our expected oil and gas production. Cash flows from oil and gas derivative contract settlements are reflected in operating activities in our statement of cash flows.

Historically, we applied hedge accounting to qualifying derivatives used to manage price risk associated with our oil and gas production. Accordingly, we recorded changes in the fair value of our swap and collar contracts, including changes associated with time value, under the caption “Accumulated other comprehensive income (loss)” on our consolidated balance sheet. Gains or losses on these swap and collar contracts are reclassified out of “Accumulated other comprehensive income (loss)” and into “Oil and gas sales” when the forecasted sale of production occurred. Any hedge ineffectiveness associated with contracts qualifying for and designated as a cash flow hedge (which represents the amount by which the change in the fair value of the derivative differs from the change in the cash flows of the forecasted sale of production) is reported currently each period under the caption “Derivative fair value income (loss)” in our consolidated statement of operations.

To designate a derivative as a cash flow hedge, we document at the hedge’s inception our assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. The ineffective portion of the hedge is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. If, during the derivative’s term, we determine the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings as oil or gas revenue when the underlying transaction occurs. If it is determined that the designated hedge transaction is not probable to occur, any unrealized gains or losses are recognized immediately in the statement of operations as a “Derivative fair value income or loss.” During 2008 and 2007, there were losses of $580,000 and $16.2 million reclassified into earnings as a result of the discontinuance of hedge accounting treatment for our derivatives.

F-13

Some of our derivatives do not qualify for hedge accounting but are, to a degree, an economic offset to our commodity price exposure. These contracts are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in our consolidated statement of operations under the caption “Derivative fair value income (loss).”

We also enter into basis swap agreements which do not qualify as hedges for hedge accounting and are also marked to market. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreement that effectively fix our basis adjustments.

Asset Retirement Obligations

The fair values of asset retirement obligations are recognized in the period they are incurred, if a reasonable estimate of fair value can be made. Asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities and include costs to dismantle and relocate or dispose of production platforms, gathering systems, wells and related structures. Estimates are based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. The depreciation will generally be determined on a units-of-production basis while accretion to be recognized will escalate over the life of the producing assets. We do not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined.

Deferred Taxes

Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. The realization of deferred tax assets is assessed periodically based on several interrelated factors. These factors include our expectation to generate sufficient taxable income including tax credits and operating loss carryforwards.

Accumulated Other Comprehensive Income (Loss)

We follow the provisions of SFAS No. 130, “Reporting Comprehensive Income” which establishes standards for reporting comprehensive income. Comprehensive income includes net income as well as all changes in equity during the period, except those resulting from investments and distributions to owners. At December 31, 2008, we had a $122.3 million pre-tax gain in accumulated other comprehensive income, or OCI, relating to unrealized commodity hedges. At December 31, 2007, we had a $39.3 million pre-tax loss in OCI relating to unrealized commodity hedges.

The components of accumulated other comprehensive income (loss) and related tax effects for three years ended December 31, 2008, were as follows (in thousands):


	Gross			Tax Effect			Net of Tax
Accumulated other comprehensive loss at December 31, 2005	$	(234,363	)	$	87,236		$	(147,127	)
Contract settlements reclassified to income		96,450			(35,686	)		60,764
Change in unrealized deferred hedging gains		192,183			(71,351	)		120,832
Change in unrealized gains (losses) on securities held by deferred compensation plan		3,203			(1,151	)		2,052


Accumulated other comprehensive income at December 31, 2006		57,473			(20,952	)		36,521
Contract settlements reclassified to income		(4,161	)		1,540			(2,621	)
Change in unrealized deferred hedging gains		(86,470	)		31,993			(54,477	)
Change in unrealized gains (losses) on securities held by deferred compensation plan		(8,194	)		3,033			(5,161	)


Accumulated other comprehensive loss at December 31, 2007		(41,352	)		15,614			(25,738	)
Contract settlements reclassified to income		63,574			(24,158	)		39,416
Change in unrealized deferred hedging gains		98,008			(35,453	)		62,555
Adoption of SFAS No. 159		2,022			(748	)		1,274


Accumulated other comprehensive income at December 31, 2008	$	122,252		$	(44,745	)	$	77,507

F-14

Reclassifications

Certain reclassifications of prior years’ data have been made to conform to our current year classification. This includes the reclassification of abandonment and impairment expense for unproved properties from the line on statement of operations called “Depletion, depreciation and amortization.” These reclassifications did not impact our net income, stockholders’ equity or cash flows.

Accounting Pronouncements Implemented

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurement.” This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements but provides guidance on how to measure fair value by providing a fair value hierarchy used to classify the source of the information. We adopted SFAS No. 157 effective January 1, 2008 for our financial instruments and the adoption did not have a significant effect on our consolidated results of operations, financial position or cash flows. See Note 12 for other disclosures required by SFAS No. 157. In February 2008, the FASB issued FSP SFAS No. 157-2 which delays the effective date of SFAS No. 157 for all non-financial assets and non-financial liabilities except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). This deferral of SFAS No. 157 primarily impacts our asset retirement obligation (ARO), which uses fair value measures at the date incurred to determine our liability. We do not expect the pending adoption in 2009 of SFAS No. 157 non-recurring fair value measures to have a significant impact on our financial statements.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. It requires that unrealized gains and losses on items for which the fair value option has been elected be recorded in net income or loss. The statement also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities. We adopted SFAS No. 159 effective January 1, 2008 and the impact of the adoption resulted in a reclassification of a $2.0 million pre-tax loss ($1.3 million after tax) related to our investment securities held in our deferred compensation plan from accumulated other comprehensive loss to retained earnings. We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. All investment securities held in our deferred compensation plans are reported in the balance sheet category called “Other assets” and total $33.5 million at December 31, 2008 compared to $51.5 million at December 31, 2007. As of January 1, 2008, all of these investment securities are accounted for using the mark-to-market accounting method, are classified as trading securities and all subsequent changes to fair value will be included in our statement of operations. For these securities, interest and dividends and mark-to-market gains or losses are included in our statement of operations category called “Deferred compensation plan expense.” For 2008, interest and dividends were $1.5 million and the mark-to-market was a loss of $19.4 million. See Note 12 for other disclosures required by SFAS No. 159.

Accounting Pronouncements Not Yet Adopted

In June 2008, the FASB issued Staff Position No. EITF 03-6-1 “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities,” (“FSP EITF 03-6-1”) which provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings allocation in computing earnings per share under the two class method. We adopted FSP EITF 03-6-1 on January 1, 2009 with no impact on our reported earnings per share.

In March 2008, the FASB issued SFAS No. 161, “Disclosure about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133.” SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133 with the intent to provide users of financial statements with an enhanced understanding of: (i) how and why any entity uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations; and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for us on January 1, 2009 and will only impact future disclosures about our derivative instruments and hedging activities.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” SFAS No. 141(R) replaces SFAS No. 141. The statement retains the purchase method of accounting for acquisitions, but requires a number of changes, including changes in the way assets and liabilities are recognized in the purchase method of accounting. It changes the recognition of assets acquired and liabilities assumed arising from contingencies, requires the capitalization of in-process research and development at fair value, and requires the expensing of acquisition-related costs as incurred. The statement will apply prospectively to business combinations occurring in our fiscal year beginning January 1, 2009. The effect of adopting SFAS No. 141(R) is not expected to have an effect on our reported financial position or earnings.

F-15

(4) ACQUISITIONS AND DISPOSITIONS

Acquisitions

Acquisitions are accounted for as purchases, and accordingly, the results of operations are included in our statement of operations from the closing date of the acquisition. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. In the past, acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities.

In 2008, we completed several acquisitions of Barnett Shale producing and unproved properties for $331.2 million. After recording asset retirement obligations and transactions costs of $827,000, the purchase price allocated to proved properties was $232.9 million and unproved properties was $99.4 million. Also during 2008, we purchased unproved leaseholds for $494.3 million, which includes a single transaction to acquire Marcellus Shale unproved properties for $223.9 million.

In May 2007, we acquired additional interests in the Nora field of Virginia and entered into a joint development plan with Equitable Resources, Inc. (“Equitable”). As a result of this transaction, Equitable and Range equalized their working interests in the Nora field, including producing wells, undrilled acreage and gathering systems. Range retained its separately owned royalty interest in the Nora field. Equitable will operate the producing wells and manage the drilling operations of all future coal bed methane wells and the gathering system. Range will oversee the drilling of formations below the coal bed methane formations, including tight gas, shale and deeper formations. A newly formed limited liability corporation will hold the investment in the gathering system which is owned 50% by Equitable and 50% by Range. All business decisions require the unanimous consent of both parties. The gathering system investment is accounted for as an equity method investment. Including estimated transaction costs, we paid $281.8 million which includes $190.2 million allocated to oil and gas properties, $94.7 million allocated to our equity method investment and a $3.1 million asset retirement obligation. In December 2007, we paid an additional $7.1 million for additional interests in the same field. No pro forma information has been provided as the acquisition was not considered significant.

Our purchases in 2006 included the acquisition in June of Stroud Energy, Inc. (“Stroud”), a private oil and gas company with operations in the Barnett Shale in North Texas, the Cotton Valley in East Texas and the Austin Chalk in Central Texas. To acquire Stroud, we paid $171.5 million of cash (including transaction costs) and issued 6.5 million shares of our common stock. The cash portion of the acquisition was funded with borrowings under our bank facility. We also assumed $106.7 million of Stroud’s debt which was retired with borrowings under our bank facility. The fair value of consideration issued was based on the average of our stock price for the five day period before and after May 11, 2006, the date the acquisition was announced. See also Note 5 for discussion of discontinued operations.

The following table summarizes the final purchase price allocation of fair value of assets acquired and liabilities assumed at closing (in thousands):


Purchase price:
Cash paid (including transaction costs)	$	171,529
6.5 million shares of common stock (at fair value of $27.26 per share)		177,641
Stock options assumed (652,000 options)		9,478
Debt retired		106,700

Total	$	465,348


Allocation of purchase price:
Working capital deficit	$	(13,557	)
Other long-term assets		55
Oil and gas properties		487,345
Assets held for sale		140,000
Deferred income taxes		(147,062	)
Asset retirement obligations		(1,433	)

Total	$	465,348

F-16

Pro forma

The following unaudited pro forma data include the results of operations as if the Stroud acquisition had been consummated at the beginning of 2006. The pro forma data is based on historical information and does not necessarily reflect the actual results that would have occurred nor are they necessarily indicative of future results of operations (in thousands, except per share data).


	Year Ended
	December 31,
	2006
Revenues	$	779,487
Income from continuing operations	$	318,034
Net income	$	163,926

Per share data:
Income from continuing operations — basic	$	1.43
Income from continuing operations — diluted	$	1.38

Net income — basic	$	1.20
Net income — diluted	$	1.16

Dispositions

In first quarter 2008, we sold East Texas properties for proceeds of $64.0 million and recorded a gain of $20.2 million. In February 2007, we sold the Stroud Austin Chalk properties for proceeds of $80.4 million and recorded a loss on the sale of $2.3 million. These properties were acquired in 2006 as part of our Stroud acquisition and were classified as assets held for sale on the acquisition date. In March 2007, we sold our Gulf of Mexico properties for proceeds of $155.0 million and recorded a gain on the sale of $95.1 million. We have reflected the results of operations of the Austin Chalk and Gulf of Mexico divestitures as discontinued operations rather than a component of continuing operations for 2007 and all prior years. See Note 5 for additional information.

(5) DISCONTINUED OPERATIONS

As part of the Stroud acquisition (see also discussion in Note 4), we purchased Austin Chalk properties in Central Texas, which were sold in February 2007 for proceeds of $80.4 million. We originally allocated $140.0 million to these properties as part of the purchase price allocation. However, after the acquisition, natural gas prices started to decline. As a result, during 2006 we recognized impairment expense of $74.9 million. In March 2007, we also sold our Gulf of Mexico properties for proceeds of $155.0 million. All prior year periods reflect our Gulf of Mexico operations and the Austin Chalk properties as discontinued operations. Discontinued operations for the years ended December 31, 2007 and 2006 are summarized as follows (in thousands):

F-17


	2007		2006
Revenues
Oil and gas sales ^(a)	$	15,187	$	54,192
Transportation and gathering		10		85
Other		310		(19	)
Gain on disposition of assets		92,757		—

Total revenues		108,264		54,258

Costs and expenses
Direct operating		2,559		12,201
Production and ad valorem taxes		141		1,065
Exploration and other		215		2,400
Interest expense ^(b)		845		3,232
Depletion, depreciation and amortization		6,672		14,953
Impairment ^(c)		—		74,910

Total costs and expenses		10,432		108,761

Income (loss) from discontinued operations before income taxes		97,832		(54,503	)

Income tax expense (benefit)		34,239		(19,256	)


Income (loss) from discontinued operations, net of taxes	$	63,593	$	(35,247	)


Production
Crude oil (bbls)		40,634		139,189
Natural gas (mcf)		1,990,277		7,927,557
Total (mcfe) ^(d)		2,234,081		8,762,691


^a)		Realized hedging gains and losses for the Gulf of Mexico properties have been allocated to discontinued operations based on the designated hedge values for those assets.

^b)		Interest expense is allocated to discontinued operations for our Austin Chalk properties based on the debt incurred at the time of the acquisition and for the Gulf of Mexico properties, interest expense was allocated based upon the ratio of the Gulf of Mexico properties to our total oil and gas properties at December 31, 2006.

^c)		Impairment expenses for the Austin Chalk properties includes losses in fair value resulting from lower oil and gas prices and amortization of the carrying value for volumes produced since the acquisition date.

^d)		Oil is converted to mcfe at the rate of one barrel equals six mcf.

(6) INCOME TAXES

Our income tax expense from continuing operations was $193.8 million for the year ended December 31, 2008 compared to $96.3 million in 2007 and $122.6 million in 2006. A reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows:


	Year Ended December 31,
	2008			2007			2006
Federal statutory tax rate		35.0	%		35.0	%		35.0	%
State		1.8			2.8			3.5
Valuation allowance		(0.2	)		0.8			—
Other		(1.0	)		(0.1	)		—

Consolidated effective tax rate		35.6	%		38.5	%		38.5	%


Income taxes paid (refunded) (in thousands)	$	4,298		$	(572	)	$	1,973

F-18

Income tax provision (benefit) attributable to income from continuing operations consists of the following:


	Year Ended December 31,
	2008		2007			2006
	(in thousands)
Current:
U.S. federal	$	1,000	$	(129	)	$	150
U.S. state and local		3,268		449			1,762

	$	4,268	$	320		$	1,912


Deferred:
U.S. federal	$	186,436	$	90,687		$	111,330
U.S. state and local		3,127		5,300			9,396

	$	189,563	$	95,987		$	120,726


Total tax provision	$	193,831	$	96,307		$	122,638

Significant components of deferred tax assets and liabilities are as follows:


	December 31,
	2008			2007
	(in thousands)
Deferred tax assets:
Current
Current net unrealized loss in OCI	$	—		$	5,195
Deferred compensation		1,289			3,981
Current portion of asset retirement obligation		767			704
Other		4,411			2,967
Current portion of net operating loss carryforward		4,258			14,060

Subtotal		10,725			26,907


Non-current
Net operating loss carryforward		21,673			35,156
Net unrealized loss in OCI		—			10,421
Deferred compensation		41,083			41,224
AMT credits and other credits		7,106			3,011
Non-current portion of asset retirement obligation		30,168			27,302
Other		12,602			9,046
Valuation allowance		(4,147	)		(5,101	)

Subtotal		108,485			121,059


Deferred tax liabilities:
Current
Net unrealized gain in OCI		(43,709	)		—

Subtotal		(43,709	)		—

Non-current
Depreciation, depletion and investments		(848,356	)		(703,503	)
Net unrealized gain in OCI		(1,036	)		—
Cumulative unrealized mark-to-market gain		(38,029	)		(6,155	)
Other		(282	)		(1,258	)

Subtotal		(887,703	)		(710,916	)


Net deferred tax liability	$	(812,202	)	$	(562,950	)

F-19

At December 31, 2008, deferred tax liabilities exceeded deferred tax assets by $812.2 million, with $44.7 million of deferred tax liability related to net deferred hedging gains included in OCI. We have a capital loss carryforward of $8.3 million and a full valuation allowance recorded of $2.9 million.

At December 31, 2008, we had regular net operating loss (“NOL”) carryforwards of $160.4 million and alternative minimum tax (“AMT”) NOL carryforwards of $92.5 million that expire between 2012 and 2027. Our deferred tax asset related to regular NOL carryforwards at December 31, 2008 was $10.7 million, which is net of the SFAS No. 123(R) reduction for unrealized benefits. Regular NOLs generally offset taxable income and to such extent, no income tax payments are required. At December 31, 2008, we have AMT credit carryforwards of $1.8 million that are not subject to limitation or expiration.

We file consolidated tax returns in the United States federal jurisdiction and separate income tax returns in many state jurisdictions. We are subject to U.S. Federal income tax examinations for the years after 2002 and we are subject to various state tax examinations for years after 2001. Our continuing policy is to recognize interest related to income tax expense in interest expense and penalties in general and administrative expense. We do not have any accrued interest or penalties related to tax amounts as of December 31, 2008. Throughout 2008, our unrecognized tax benefits were not material.

(7) EARNINGS PER COMMON SHARE

The following table sets forth the computation of basic and diluted earnings per common share (in thousands, except per share amounts):


	Year Ended December 31,
	2008			2007			2006
Numerator:
Income from continuing operations	$	351,040		$	153,675		$	195,877
Income (loss) from discontinued operations		—			63,593			(35,247	)

Net income	$	351,040		$	217,268		$	160,630


Denominator:
Weighted average shares, basic		151,116			143,791			133,751
Effect of dilutive securities:
Employee stock options, SARs and stock held in deferred compensation plan		4,876			6,178			4,961
Treasury shares		(49	)		(58	)		(1	)

Weighted average common shares — diluted		155,943			149,911			138,711


Basic — income from continuing operations	$	2.32		$	1.07		$	1.46
— discontinued operations		—			0.44			(0.26	)

— net income	$	2.32		$	$1.51		$	1.20


Diluted — income from continuing operations	$	2.25		$	1.02		$	1.41
— discontinued operations		—			0.43			(0.25	)

— net income	$	2.25		$	1.45		$	1.16

F-20

For the year ended December 31, 2008, stock appreciation rights for 880,000 shares were outstanding but not included in the computations of diluted earnings per share, because the grant price of the SARs was greater than the average price of the common stock and would be anti-dilutive to the computations (345,000 shares for the year ended December 31, 2007 and 88,500 shares for the year ended December 31, 2006).

(8) SUSPENDED EXPLORATORY WELL COSTS

The following table reflects the changes in capitalized exploratory well costs for the year ended December 31, 2008, 2007 and 2006 (in thousands):


	2008			2007			2006
Balance at beginning of period	$	15,053		$	9,984		$	25,340
Additions to capitalized exploratory well costs pending the determination of proved reserves		43,968			14,428			4,695
Divested wells		—			(1,325	)		—
Reclassifications to wells, facilities and equipment based on determination of proved reserves		(3,847	)		—			(16,710	)
Capitalized exploratory well costs charged to expense		(7,551	)		(8,034	)		(3,341	)

Balance at end of period		47,623			15,053			9,984
Less exploratory well costs that have been capitalized for a period of one year or less		(41,681	)		(12,067	)		(4,792	)

Capitalized exploratory well costs that have been capitalized for a period greater than one year	$	5,942		$	2,986		$	5,192


Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		3			2			3

As of December 31, 2008, the $5.9 million of capitalized exploratory well costs that have been capitalized for more than one year relates to wells waiting on pipelines. Of the $47.6 million of capitalized exploratory well costs at December 31, 2008, $41.7 million was incurred in 2008 and $5.9 million in 2007.

(9) INDEBTEDNESS

We had the following debt outstanding as of the dates shown below (bank debt interest rate at December 31, 2008 is shown parenthetically). No interest was capitalized during 2008, 2007, and 2006 (in thousands):


	December 31,
	2008		2007
Bank debt (2.9%)	$	693,000	$	303,500

Senior subordinated notes:
7.375% senior subordinated notes due 2013, net of $2.0 million and $2.4 million discount, respectively		197,968		197,602
6.375% senior subordinated notes due 2015		150,000		150,000
7.5% senior subordinated notes due 2016, net of $405,000 and $444,000 discount, respectively		249,595		249,556
7.5% senior subordinated notes due 2017		250,000		250,000
7.25% senior subordinated notes due 2018		250,000		—
Other		105		—

Total debt	$	1,790,668	$	1,150,658

F-21

Bank Debt

In October 2006, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our bank credit facility, which is secured by substantially all of our assets. The bank credit facility provides for an initial commitment equal to the lesser of the facility amount or the borrowing base. On December 31, 2008, the facility amount was $1.25 billion and the borrowing base was $1.5 billion. The bank credit facility provides for a borrowing base subject to redeterminations semi-annually each April and October and for event-driven unscheduled redeterminations. Our current bank group is comprised of twentysix commercial banks each holding between 2.3% and 5.0% of the total facility. Of those twentysix banks, fourteen are domestic banks and twelve are foreign banks or wholly-owned subsidiaries of foreign banks. The facility amount may be increased to the borrowing base amount with twenty days notice, subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the facility increase. In December 2008, we elected to utilize the expansion option under our bank credit facility and increased our credit facility commitment by $250.0 million, which made the current bank commitment $1.25 billion. As of December 31, 2008, the outstanding balance under the bank credit facility was $693.0 million and there was $557.0 million of borrowing capacity available under the facility amount. The loan matures on October 25, 2012. Borrowings under the bank facility can either be at the Alternate Base Rate (as defined) plus a spread ranging from 0.875% to 1.625% or LIBOR borrowings at the Adjusted LIBO Rate (as defined) plus a spread ranging from 1.75% to 2.5%. The applicable spread is dependent upon borrowings relative to the borrowing base. We may elect, from time to time, to convert all or any part of our LIBOR loans to base rate loans or to convert all or any of the base rate loans to LIBOR loans. The weighted average interest rate was 4.4% for the year ended December 31, 2008 compared to 6.4% for the year ended December 31, 2007. A commitment fee is paid on the undrawn balance based on an annual rate of 0.375% to 0.50%. At December 31, 2008, the commitment fee was 0.375% and the interest rate margin was 1.75%.

Senior Subordinated Notes

In 2003, we issued $100.0 million aggregate principal amount of 7.375% senior subordinated notes due 2013 (“7.375% Notes”). In 2004, we issued an additional $100.0 million of 7.375% Notes; therefore, $200.0 million of the 7.375% Notes is currently outstanding. The 7.375% Notes were issued at a discount which will be amortized over the life of the 7.375% Notes into interest expense. In 2005, we issued $150.0 million aggregate principal amount of 6.375% senior subordinated notes due 2015 (“6.375% Notes”). In May 2006, we issued $150.0 million aggregate principal amount of the 7.5% senior subordinated notes due 2016 (the “7.5% Notes due 2016”). In August 2006, we issued an additional $100.0 million of the 7.5% Notes due 2016; therefore, $250.0 million of the 7.5% Notes due 2016 is currently outstanding. The 7.5% Notes due 2016 were also issued at a discount, which is being amortized over the life of the 7.5% Notes due 2016. In September 2007, we issued $250.0 million principal amount of 7.5% senior subordinated notes due 2017 (“7.5% Notes due 2017”). In May 2008, we issued $250.0 million aggregate principal amount of 7.25% senior subordinated notes due 2018 (“7.25% Notes”). Interest on our senior subordinated notes is payable semi-annually, at varying times, and each of the notes is guaranteed by certain of our subsidiaries.

We may redeem the 7.375% Notes, in whole or in part, at any time on or after July 15, 2008, at redemption prices of 103.7% of the principal amount as of July 15, 2008, and declining to 100.0% on July 15, 2011 and thereafter. We may redeem the 6.375% Notes, in whole or in part, at any time on or after March 15, 2010, at redemption prices from 103.2% of the principal amount as of March 15, 2010 and declining to 100% on March 15, 2013 and thereafter. We may redeem the 7.5% Notes due 2016, in whole or in part, at any time on or after May 15, 2011 at redemption prices from 103.75% of the principal amount as of May 15, 2011 and declining to 100% on May 15, 2014 and thereafter. Before May 15, 2009, we may redeem up to 35% of the original aggregate principal amount of the 7.5% Notes due 2016 at a redemption price of 107.5% of principal amount thereof plus accrued and unpaid interest if any, with the proceeds of certain equity offerings; provided that at least 65% of the original aggregate principal amount of our 7.5% Notes 2016 remains outstanding immediately after the occurrence of such redemption and provided that such redemption occurs within 60 days of the date of closing the equity sale. We may redeem the 7.5% Notes due 2017, in whole or in part, at any time on or after October 1, 2012 at redemption prices ranging from 103.75% of the principal amount as of October 1, 2012 and declining to 100% on October 1, 2015 and thereafter. Before October 1, 2010, we may redeem up to 35% of the original aggregate principal amount of the 7.5% Notes due 2017 at a redemption price of 107.5% of principal amount thereof plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings provided that at least 65% of the original aggregate principal amount of our 7.5% Notes due 2017 remains outstanding immediately after the occurrence of such redemption and provided that such redemption occurs 60 days of the date of closing the equity sale. We may redeem the 7.25% Notes, in whole or in part, at any time on or after May 1, 2016 at redemption prices of 103.625% of the principal amount as of May 1, 2013 and declining to 100.0% on May 1, 2016 and thereafter. Before May 1, 2011, we may redeem up to 35% of the original aggregate principal amount of the 7.25% Notes at a redemption price equal to 107.25% of the principal amount thereof, plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings provided that at least 65% of the original principal amount of the 7.25% Notes remain outstanding

F-22

immediately after the occurrence of such redemption and also provided such redemption shall occur within 60 days of the date of the closing of the equity offering.

If we experience a change of control, there will be a requirement to repurchase all or a portion of the senior subordinated notes at 101% of the principal amount plus accrued and unpaid interest, if any. All of the senior subordinated notes and the guarantees by our subsidiary guarantors are general, unsecured obligations and are subordinated to our bank debt and will be subordinated to future senior debt that we or our subsidiary guarantors are permitted to incur under the bank credit facility and the indentures governing the subordinated notes.

Guarantees

Range Resources Corporation is a holding company which owns no operating assets and has no significant operations independent of its subsidiaries. The guarantees by our subsidiaries of the 7.375% Notes, the 6.375% Notes, the 7.5% Notes due 2016, the 7.5% Notes due 2017 and the 7.25% Notes are full and unconditional and joint and several; any subsidiaries other than the subsidiary guarantors are minor subsidiaries.

Debt Covenants and Maturity

Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate, or make investments. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined in the credit agreement) of no greater than 4.0 to 1.0 and a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0. We were in compliance with our covenants under the bank credit facility at December 31, 2008.

Following is the principal maturity schedule for the long-term debt outstanding as of December 31, 2008 (in thousands):


	Year Ended
	December 31,
2009	$	—
2010		—
2011		—
2012		693,022
2013		198,050
2014		—
Thereafter		899,596

	$	1,790,668

The indentures governing our senior subordinated notes contain various restrictive covenants that are substantially identical and may limit our ability to, among other things, pay cash dividends, incur additional indebtedness, sell assets, enter into transactions with affiliates, or change the nature of our business. At December 31, 2008, we were in compliance with these covenants.

F-23

(10) ASSET RETIREMENT OBLIGATION

Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. A reconciliation of our liability for plugging and abandonment costs for the years ended December 31, 2008 and 2007 is as follows (in thousands):


	2008			2007
Beginning of period	$	75,308		$	95,588
Liabilities incurred		2,347			3,118
Acquisitions — continuing operations		250			3,301
Liabilities settled		(1,399	)		(2,782	)
Disposition of wells		(898	)		(20,066	)
Accretion expense — continuing operations		5,471			5,960
Accretion expense — discontinued operations		—			382
Change in estimate		2,378			(10,193	)

End of period		83,457			75,308


Less current portion		(2,055	)		(1,903	)


Long-term asset retirement obligation	$	81,402		$	73,405

Accretion expense is recognized as a component of depreciation, depletion and amortization on our statement of operations.

(11) CAPITAL STOCK

In May 2008, at our annual meeting, our shareholders approved an increase to our number of authorized shares of common stock. We now have authorized capital stock of 485.0 million shares which includes 475.0 million shares of common stock and 10.0 million shares of preferred stock. The following is a schedule of changes in the number of common shares outstanding since the beginning of 2007:


	Year Ended December 31,
	2008			2007
Beginning balance		149,511,997			138,931,565
Public offerings		4,435,300			8,050,000
Shares issued in lieu of bonuses		—			29,483
Stock options/SARs exercised		1,339,536			2,220,627
Restricted stock grants		167,054			408,067
Shares contributed to 401(k) plan		—			27,755
Treasury shares		(78,400	)		(155,500	)

Ending balance		155,375,487			149,511,997

In May 2008, we completed a public offering of 4.4 million shares of common stock at $66.38 per share. After underwriting discount and other offering costs of $12.3 million, net proceeds of $282.2 million were used to repay indebtedness on our bank credit facility. In April 2007, we completed a public offering of 8.1 million shares of common stock at $36.28 per share. Total proceeds from the offering of $280.4 million funded our acquisition of properties and a gathering system in Virginia.

F-24

Treasury Stock

In 2008, the Board of Directors approved up to $10.0 million of repurchases of common stock based on market conditions and opportunities. During 2008, we repurchased 78,400 shares of common stock an average price of $41.11 for a total of $3.2 million. As of December 31, 2008, we have $6.8 million remaining authorization to repurchase shares.

(12) FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

Financial instruments include cash and equivalents, receivables, payables, marketable securities, debt and commodity derivatives. The carrying value of cash and equivalents, receivables, payables is considered to be representative of fair value because of their short maturity.

The following table sets forth our other financial instruments fair values at each of these dates (in thousands):


	December 31, 2008						December 31, 2007
	Book			Fair			Book			Fair
	Value			Value			Value			Value
Derivative assets:
Commodity swaps and collars ^(a)	$	226,661		$	226,661		$	54,100		$	54,100

Derivative liabilities:
Commodity swaps and collars^(a)		(10	)		(10	)		(76,276	)		(76,276	)


Net derivative asset (liability)	$	226,651		$	226,651		$	(22,176	)	$	(22,176	)

Marketable securities ^(b)	$	33,473		$	33,473		$	51,482		$	51,482

Long-term debt ^(c)	$	1,790,668		$	1,621,793		$	1,150,658		$	1,158,033


^(a)		All derivatives are marked to market and therefore their book value is equal to fair value.

^(b)		Marketable securities held in our deferred compensation plans which are marked to market and therefore their book value is equal to fair value.

^(c)		The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior subordinated notes is based on year-end market quotes.

Commodity Derivative Instruments

We use commodity-based derivative contracts to manage exposures to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. These contracts consist of collars and fixed price swaps. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. At December 31, 2008, we had open swap contracts covering 25.6 Bcf of gas at prices averaging $8.38 per mcf. We also had collars covering 54.8 Bcf of gas at weighted average floor and cap prices of $8.28 to $9.27 per mcf and 2.9 million barrels of oil at weighted average floor and cap prices of $64.01 to $76.00 per barrel. Their fair value, represented by the estimated amount that would be realized upon termination, based on a comparison of the contract price and a reference price, generally NYMEX, approximated a net unrealized pre-tax gain of $214.2 million at December 31, 2008. These contracts expire monthly through December 2009. The following table sets forth the derivative volumes by year as of December 31, 2008:


			Weighted
Period	Contract Type	Volume Hedged	Average Hedge Price
Natural Gas
2009	Swaps	70,000 Mmbtu/day	$8.38
2009	Collars	150,000 Mmbtu/day	$8.28 – $9.27

Crude Oil
2009	Collars	8,000 bbl/day	$64.01 – $76.00

F-25

Under SFAS No. 133, every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date. Changes in the fair value of effective cash flow hedges are recorded as a component of “Accumulated other comprehensive income (loss),” which is later transferred to earnings when the hedged transaction occurs. If the derivative does not qualify as a hedge or is not designated as a hedge, the change in fair value of the derivative is recognized in earnings. As of December 31, 2008, an unrealized pre-tax derivative gain of $122.2 million was recorded in “Accumulated other comprehensive income (loss).” This gain will be reclassified into earnings in 2009 as the contracts settle. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date.

For those derivative instruments that qualify for hedge accounting, settled transaction gains and losses are determined monthly, and are included as increases or decreases to “Oil and gas sales” in the period the hedged production is sold. Oil and gas sales include $63.6 million of losses in 2008 compared to gains of $4.2 million in 2007 and losses of $93.2 million in 2006. Any ineffectiveness associated with these hedges is reflected in the caption called “Derivative fair value income (loss)” in our statement of operations. The year ended December 31, 2008 includes ineffective unrealized gains of $1.7 million compared to losses of $820,000 in 2007 and gains of $6.0 million in 2006.

Some of our derivatives do not qualify for hedge accounting but are, to a degree, an economic offset to our commodity price exposure. These contracts are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in the income statement caption called “Derivative fair value income (loss)” (see table below).

In addition to the swaps and collars above, we have entered into basis swap agreements which do not qualify for hedge accounting and are marked to market. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location, relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix our basis adjustments. The fair value of the basis swaps was a net unrealized pre-tax gain of $12.4 million at December 31, 2008.

Derivative fair value income (loss)

The following table presents information about the components of derivative fair value income (loss) in the three-year period ended December 31, 2008 (in thousands):


	2008			2007			2006
Change in fair value of derivatives that do not qualify for hedge accounting	$	85,594		$	(80,495	)	$	86,491
Realized (loss) gain on settlement-gas ^(a)		(1,383	)		71,098			49,939
Realized loss on settlement-oil ^(a)		(15,431	)		(244	)		—
Hedge ineffectiveness — realized		1,386			968			—
— unrealized		1,695			(820	)		5,965

Derivative fair value income (loss)	$	71,861		$	(9,493	)	$	142,395


^(a)		These amounts represent the realized gains and losses on settled derivatives that do not qualify for hedge accounting, which before settlement are included in the category above called the change in fair value of derivatives that do not qualify for hedge accounting.

F-26

The combined fair value of derivatives included in our consolidated balance sheets as of December 31, 2008 and December 31, 2007 is summarized below (in thousands). We conduct derivative activities with twelve financial institutions, ten of which are secured lenders in our bank credit facility. We believe all of these institutions are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. The credit worthiness of our counterparties is subject to periodic review. The assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty.


	December 31,
	2008			2007
Derivative assets:
Natural gas — swaps	$	57,280		$	54,577
— collars		121,781			4,916
— basis swaps		12,434			1,082
Crude oil — collars		35,166			(6,475	)

	$	226,661		$	54,100


Derivative liabilities:
Natural gas — swaps	$	—		$	6,594
— collars		—			11,302
— basis swap		(10	)		(937	)
Crude oil — collars		—			(93,235	)

	$	(10	)	$	(76,276	)

Fair Value Measurements

Effective January 1, 2008, we adopted SFAS No. 157, as discussed in Note 3, which among other things, requires enhanced disclosures about assets and liabilities carried at fair value. As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. SFAS No. 157 describes three approaches to measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which include multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset.

SFAS No. 157 does not prescribe which valuation technique should be used when measuring fair value and does not prioritize among techniques. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and lowest priority to unobservable inputs (level 3 measurements). The three levels of fair value hierarchy defined by SFAS No. 157 are as follows:

Level 1 — Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities as of the reporting date.

Level 2 — Pricing inputs are other than quoted prices in active markets included in either Level 1, which are directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars, are valued using commodity market data, which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

F-27

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At December 31, 2008, we have no Level 3 measurements.

We use a market approach for our fair value measurements and endeavor to use the best information available. Accordingly, valuation techniques that maximize the use of observable impacts are favored. The following table presents the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis, as set forth in SFAS No. 157 (in thousands):


			Fair Value Measurements at December 31, 2008 Using
			Quoted Prices in				Significant
	Total Carrying		Active Markets for		Significant		Unobservable
	Value as of		Identical Assets		Observable Inputs		Inputs
	December 31, 2008		(Level 1)		(Level 2)		(Level 3)
Trading securities held in the deferred compensation plans	$	33,473	$	33,473	$	—	$	—

Derivatives — swaps		57,280		—		57,280		—
— collars		156,947		—		156,947		—
— basis swaps		12,424		—		12,424		—

These items are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using December 31, 2008 market values. Derivatives in Level 2 are measured at fair value with a market approach using third-party pricing services which have been corroborated with data from active markets or broker quotes.

Concentration of Credit Risk

Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions and end-users in various industries. Letters of credit or other appropriate security are obtained as necessary to limit risk of loss. Our allowance for uncollectible receivables was $954,000 at December 31, 2008 and $583,000 at December 31, 2007. Commodity-based contracts expose us to the credit risk of nonperformance by the counterparty to the contracts. These contracts consist of collars and fixed price swaps. This exposure is diversified among major investment grade financial institutions the majority of which we have master netting agreements with that provide for offsetting payables against receivables from separate derivative contracts. Our derivative counterparties include twelve financial institutions, ten of which are secured lenders in our bank credit facility. Mitsui & Co. and J. Aron & Company are the two counterparties not in our bank group. At December 31, 2008, our net derivative receivable includes a receivable from J. Aron & Company of $987,000 and a receivable from Mitsui & Co. for $18.0 million.

F-28

(13) EMPLOYEE BENEFIT AND EQUITY PLANS

Stock and Option Plans

We have six equity-based stock plans, of which two are active. Under the active plans, incentive and non-qualified stock options, stock appreciation rights and annual cash incentive awards may be issued to directors and employees pursuant to decisions of the Compensation Committee, which is made up of outside independent directors from the Board of Directors. All stock options and SARs granted under these plans have been issued at the prevailing market price at the time of the grant. Since the middle of 2005, only SARs have been granted under the plans to limit the dilutive impact of our equity plans. Information with respect to stock option and SARs activities is summarized below:


				Weighted
				Average
				Exercise
	Shares			Price
Outstanding at December 31, 2005		8,742,305		$	9.31
Granted		1,658,160			24.36
Stock options assumed in Stroud acquisition		652,062			19.67
Exercised		(2,051,237	)		9.22
Expired/forfeited		(149,164	)		18.32


Outstanding at December 31, 2006		8,852,126			12.76
Granted		1,680,643			33.78
Exercised		(2,461,689	)		9.45
Expired/forfeited		(298,755	)		23.42


Outstanding at December 31, 2007		7,772,325			17.95
Granted		1,159,649			63.18
Exercised		(1,590,390	)		12.24
Expired/forfeited		(92,918	)		40.82


Outstanding at December 31, 2008		7,248,666		$	26.15

The following table shows information with respect to outstanding stock options and SARs at December 31, 2008:


	Outstanding						Exercisable
			Weighted-
			Average		Weighted-				Weighted
			Remaining		Average				Average
			Contractual		Exercise				Exercise
Range of Exercise Prices	Shares		Life		Price		Shares		Price
$1.29 – $9.99		1,495,340		2.01	$	4.47		1,495,340	$	4.47
10.00 – 19.99		1,878,048		1.33		16.25		1,878,048		16.25
20.00 – 29.99		1,295,286		2.25		24.37		750,081		24.34
30.00 – 39.99		1,455,132		3.26		33.98		410,482		34.61
40.00 – 49.99		29,130		4.17		42.37		5,010		42.67
50.00 – 59.99		720,565		4.12		58.57		180		58.60
60.00 – 69.99		28,427		4.37		65.33		—		—
70.00 – 75.00		346,738		4.38		75.00		26,484		75.00

Total		7,248,666		2.47	$	26.15		4,565,625	$	15.74

F-29

During 2008, 2007 and 2006, we granted SARs to officers, non-officer employees and directors. The weighted average grant date fair value of these SARs, based on our Black-Scholes-Merton assumptions, is shown below:


	2008			2007			2006
Weighted average exercise price per share	$	63.18		$	33.78		$	24.36
Expected annual dividends per share		0.26	%		0.36	%		0.30	%
Expected life in years		3.5			3.5			3.5
Expected volatility		41	%		36	%		41	%
Risk-free interest rate		2.4	%		4.7	%		4.8	%

Weighted average grant date fair value	$	20.58		$	10.67		$	8.51

The volatility factors are based on a combination of both the historical volatilities of the stock and implied volatility of traded options on our common stock. The dividend yield is based on the current annual dividend at the time of grant. For SARs granted in 2007 and 2006, we used the “simplified” method prescribed by SEC Staff Accounting Bulletin No. 107 to estimate the expected term of the options, which is calculated based on the midpoint between the vesting date and the life of the SAR. For SARs granted in 2008, the expected term was based on the historical exercise activity. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant for periods commensurate with the expected terms of the options. Of the 7.2 million grants outstanding at December 31, 2008, 2.5 million grants relate to stock options with the remainder of 4.7 million grants relating to SARs.

The total intrinsic value (the difference in value between exercise and market price) of stock options and SARs exercised during the years ended December 31, 2008 was $67.9 million compared to $67.2 million in 2007 and $37.1 million in 2006. As of December 31, 2008, the aggregate intrinsic value of the awards outstanding was $94.4 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option/SARs awards currently exercisable was $87.0 million and 1.9 years. As of December 31, 2008, the number of fully vested awards and awards expected to vest was 7.2 million. The weighted average exercise price and weighted average remaining contractual life of these awards were $25.81 and 2.45 years and the aggregate intrinsic value was $94.3 million. As of December 31, 2008, unrecognized compensation cost related to the awards was $23.2 million, which is expected to be recognized over a weighted average period of 0.9 years.

For the year ended December 31, 2008, total stock-based compensation expense for stock options and SARs under SFAS No. 123(R) was $16.6 million compared to $15.2 million in 2007. For 2008, the total related tax benefits were $4.1 million. For the year ended December 31, 2008, cash received upon exercise of stock option awards was $9.0 million. Due to the net operating loss carryforward for tax purposes, tax benefits realized for deductions that were in excess of the stock-based compensation expense were not recognized.

Restricted Stock Grants

In 2008, we issued 362,000 shares of restricted stock grants as compensation to directors and employees at an average price of $63.00. The restricted stock grants included 14,400 issued to directors, which vest immediately and 347,600 to employees with vesting generally over a three-year period. In 2007, we issued 435,000 shares of restricted stock grants as compensation to directors and employees, at an average price of $34.85. The restricted grants included 15,900 issued to directors, which vest immediately, and 419,100 to employees with vesting over a three-year period. In 2006, we issued 499,200 shares of restricted stock grants as compensation to directors and employees, at an average price of $24.43. The restricted grants included 15,000 issued to directors, which vest immediately, and 484,200 to employees with vesting over a three-to-four year period. We recorded compensation expense for restricted stock grants of $14.7 million in the year ended December 31, 2008 compared to $8.7 million in 2007 and $4.3 million in 2006. As of December 31, 2008, there was $23.1 million of unrecognized compensation related to restricted stock awards expected to be recognized over the next three years, prior to mark-to-market adjustments. The vesting of these shares is dependent only upon the employees’ continued service with us. For restricted stock grants, the fair value is equal to the closing price of our common stock on the grant date. All of our restricted stock grants are held in our deferred compensation plan and the liability is marked-to-market each reporting period based on the value of our stock. This mark-to-market is presented in the statement of operations caption “Deferred compensation plan” (see discussion below). The proceeds received from the sale of stock held in our deferred compensation plan were $5.3 million in 2008.

F-30

A summary of the status of our non-vested restricted stock outstanding at December 31, 2008 and changes during the twelve months then ended, is presented below:


				Weighted
				Average Grant
	Shares			Date Fair Value
Non-vested shares outstanding at December 31, 2007		563,660		$	30.42
Granted		362,313			63.00
Vested		(438,058	)		37.54
Forfeited		(14,368	)		38.87

Non-vested shares outstanding at December 31, 2008		473,547		$	48.50

401(k) Plan

We maintain a 401(k) Plan for our employees. The 401(k) Plan permits employees to contribute up to 50% of their salary (subject to Internal Revenue Service limitations) on a pretax basis. Historically, we have made discretionary contributions of our common stock to the 401(k) Plan annually. Beginning in 2008, we began matching up to 6% of salary in cash. All our contributions become fully vested after the individual employee has two years of service with us. In 2008, we contributed $2.7 million to the 401(k) Plan compared to $2.3 million in 2007 and $1.9 million in 2006. We do not require that employees hold any contributed Range stock in their account. Employees have a variety of investment options in the 401(k) Plan. Employees may, at any time, diversify out of our stock, based on their personal investment strategy.

Deferred Compensation Plan

In 1996, the Board of Directors adopted a deferred compensation plan (“the Plan”). The Plan gave directors, officers and key employees the ability to defer all or a portion of their salaries and bonuses and invest in Range common stock or make other investments at the individual’s discretion. Great Lakes Energy Partners (which we purchased in 2004) also had a deferred compensation plan that allowed certain employees to defer all or a portion of their salaries and bonuses and invest such amounts in certain investments at the employee’s discretion. In December 2004, we adopted the Range Resources Corporation Deferred Compensation Plan (“2005 Deferred Compensation Plan”). The 2005 Deferred Compensation Plan is intended to operate in a manner substantially similar to the old plans, subject to new requirements and changes mandated under Section 409A of the Internal Revenue Code. The old plans will not receive additional contributions. The assets of all of the plans are held in a rabbi trust, which we refer to as the Rabbi Trust, and are therefore available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Our stock held in the Rabbi Trust is treated as a liability award (as defined by SFAS No. 123(R)) as employees are allowed to take withdrawals from the Rabbi Trust either in cash or in Range stock. The liability for the vested portion of the stock held in the Rabbi Trust is reflected in the deferred compensation liability on our balance sheet and is adjusted to fair value each reporting period by a charge or credit to “Deferred compensation plan expense” on our consolidated statement of operations. The assets of the Rabbi Trust, other than our common stock, are invested in marketable securities and reported at their market value in the balance sheet category “Other assets.” The deferred compensation liability on our consolidated balance sheet reflects the vested market value of the marketable securities and the Range stock held in the Rabbi Trust. Changes in the market value of the marketable securities and changes in the fair value of the liability are charged or credited to “Deferred compensation plan expense” each quarter. We recorded mark-to-market income of $24.7 million in 2008 compared to mark-to-market expense of $35.4 million in 2007 and mark-to-market income of $233,000 in 2006. The Rabbi Trust held 2.3 million shares (1.9 million of vested shares) of Range stock at December 31, 2008 compared to 2.1 million shares (1.5 million of vested shares) at December 31, 2007.

F-31

(14) SUPPLEMENTAL CASH FLOW INFORMATION


	Year Ended December 31,
	2008		2007			2006
	(in thousands)
Net cash provided from continuing operations included:
Income taxes paid to (refunded from) taxing authorities	$	4,298	$	(572	)	$	1,973
Interest paid		93,954		71,708			55,925
Non-cash investing and financing activities:
6.5 million shares issued for Stroud acquisition	$	—	$	—		$	177,641
Stock options (652,000) issued in Stroud acquisition		—		—			9,478
Asset retirement costs capitalized, excluding acquisitions ^(a)		4,647		(7,075	)		25,821


^(a)		For information regarding purchase price allocations of businesses acquired see Note 10.

(15) COMMITMENTS AND CONTINGENCIES

Litigation

We are involved in various legal actions and claims arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, cash flows or results of operations.

Lease Commitments

We lease certain office space, compressors and equipment under cancelable and non-cancelable leases. Rent expense under such arrangements totaled $9.2 million in 2008 compared to $5.4 million in 2007 and $5.0 million in 2006. Commitments related to these lease payments are not recorded in the accompanying consolidated balance sheets. Future minimum rental commitments under non-cancelable leases having remaining lease terms in excess of one year are as follows (in thousands):


	Operating
	Lease
	Obligations
2009	$	10,423
2010		10,536
2011		8,943
2012		6,057
2013		3,528
Thereafter		9,257
Sublease rentals		(139	)

	$	48,605

Other Commitments

We also have agreements in place to purchase seismic data. These agreements total $900,000 in both 2009 and 2010. We have lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period, generally not exceeding two years. We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, we have allowed acreage to expire and will allow additional acreage to expire in the future.

F-32

Transportation Contracts

We have entered firm transportation contracts with various pipelines. Under these contracts, we are obligated to transport minimum daily gas volumes, or pay for any deficiencies at a specified reservation fee rate. In most cases, our production committed to these pipelines is expected to exceed the minimum daily volumes provided in the contracts. As of December 31, 2008, future minimum transportation fees under our gas transportation commitments are as follows (in thousands):


	Transportation
	Commitments
2009	$	17,369
2010		16,725
2011		16,270
2012		13,332
2013		12,529
Thereafter		69,145

	$	145,370

In addition to the amounts included in the above table, we have contracted with a pipeline company through 2017 to deliver natural gas production volumes in Appalachia from certain Marcellus Shale wells. The agreement calls for incremental increases over the initial 40,000 Mmbtu per day. These increases, which are contingent on certain pipeline modifications, are 30,000 Mmbtu per day in March 2009, 30,000 Mmbtu per day in October 2009, 30,000 Mmbtu per day in March 2010 and an additional 20,000 Mmbtu per day for July 2010 for a total of an additional 110,000 Mmbtu per day.

Drilling Contracts

As of December 31, 2008, we have contracts with drilling contractors to use six drilling rigs with terms of up to three years and minimum future commitments of $26.9 million in 2009, $58.4 million in both 2010 and 2011 and $31.7 million in 2012. Early termination of these contracts at December 31, 2008 would have required us to pay maximum penalties of $129.3 million. We do not expect to pay any early termination penalties related to these contracts.

Delivery Commitments

Under a sales agreement with Enterprise Products Operating, LLC, we have an obligation to deliver 30,000 Mmbtu per day of volume at various delivery points within the Barnett Shale basin. The contract, which began in 2008, extends for five years ending March 2013. As of December 31, 2008, remaining volumes to be delivered under this commitment are approximately 46.5 bcf.

(16) MAJOR CUSTOMERS

We market our production on a competitive basis. Gas is sold under various types of contracts including month-to-month, and one-to-five-year contracts. Pricing on the month-to-month and short-term contracts is based largely on NYMEX, with fixed or floating basis. For one to five-year contracts, we sell our gas on NYMEX pricing, published regional index pricing or percentage of proceeds sales based on local indices. We sell our oil under contracts ranging in terms from month-to-month, up to as long as one year. The price for oil is generally equal to a posted price set by major purchasers in the area or is based on NYMEX pricing or fixed pricing, adjusted for quality and transportation differentials. We sell to oil and gas purchasers on the basis of price, credit quality and service reliability. For the year ended December 31, 2008, one customer accounted for 10% or more of total oil and gas revenues. For the year ended December 31, 2007, we had no customers that accounted for 10% or more of total oil and gas revenues. For the year ended December 31, 2006, two customers each accounted for 10% or more of total oil and gas revenues and the combined sales to those customers accounted for 25% of total oil and gas revenues. We believe that the loss of any one customer would not have a material adverse effect on our results.

F-33

(17) EQUITY METHOD INVESTMENTS

We account for our investments in entities over which we have significant influence, but not control, using the equity method of accounting. Under the equity method of accounting, we record our proportionate share of the net earnings, declared dividends and partnership distributions based on the most recently available financial statements of the investee. We also evaluate our equity method investments for potential impairment whenever events or changes in circumstances indicate that there is an other-than-temporary decline in value of the investment. Such events may include sustained operating losses by the investee or long-term negative changes in the investee’s industry. These indicators were not present, and as a result, we did not recognize any impairment charges related to our equity method investments for the years ended December 31, 2008, 2007 or 2006.

Investment in Whipstock Natural Gas Services, LLC

In 2006, we acquired a 50% interest in Whipstock Natural Gas Services, LLC (Whipstock), an unconsolidated investee in the business of providing oil and gas drilling equipment, well servicing rigs and equipment, and other well services in Appalachia. On the acquisition date, we contributed cash of $11.7 million representing the fair value of 50% of the membership interest in Whipstock.

Whipstock follows a calendar year basis of financial reporting consistent with us and our equity in Whipstock’s earnings from the acquisition date is included in other revenue in our results of operations for 2008, 2007 and 2006. During the year ended December 31, 2008, we received cash distributions from Whipstock of $1.8 million. There were no dividends or partnership distributions received from Whipstock during the years ended December 31, 2007 or 2006. In determining our proportionate share of the net earnings of Whipstock, certain adjustments are required to be made to Whipstock’s reported results to eliminate the profits recognized by Whipstock for services provided to us. For the year ended December 31, 2008, our equity in the earnings of Whipstock totaled $479,000, compared to $132,000 in 2007 and $548,000 in 2006. In 2008, equity in the earnings of Whipstock was reduced by $1.8 million to eliminate the profit on services provided to us compared to $2.7 million in 2007 and $1.1 million in 2006. Range and Whipstock have entered into an agreement whereby Whipstock will provide us with the right of first refusal such that we will have the opportunity to secure services from Whipstock in preference to and in advance of Whipstock entering into additional commitments for services with other customers. All services provided to us are based on Whipstock’s usual and customary terms.

Investment in Nora Gathering, LLC

In May 2007, we completed the initial closing of a joint development arrangement with Equitable Production Company. Pursuant to the terms of the arrangement, Range and Equitable (the parties) agreed to among other things, form a new pipeline and natural gas gathering operations entity, Nora Gathering, LLC (NGLLC). NGLLC is an unconsolidated investee created by the parties for the purpose of conducting pipeline, natural gas gathering, and transportation operations associated with the parties’ collective interests in properties in the Nora Field. In connection with the acquisition, we contributed cash of $94.7 million for a 50% membership interest in NGLLC. During 2008, Range and Equitable each contributed $29.0 million in additional capital to NGLLC in order to fund the expansion of the Nora Field gathering system infrastructure.

NGLLC follows a calendar year basis of financial reporting consistent with Range and our equity in NGLLC earnings from the acquisition date is included in other revenue in our results of operations for 2008 and 2007. There were no dividends or partnership distributions received from NGLLC during the years ended December 31, 2008 or December 31, 2007. In determining our proportionate share of the net earnings of NGLLC, certain adjustments are required to be made to NGLLC’s reported results to eliminate the profits recognized by NGLLC included in the gathering and transportation fees charged to us on production in the Nora field. For the year ended December 31, 2008 our equity in the earnings of NGLLC of $261,000 was reduced by $4.8 million to eliminate the profit on gathering fees charged to us. For the year ended December 31, 2007, our equity in the earnings of NGLLC of $841,000 was reduced by $1.8 million to eliminate the profit on gathering and transportation fees charged to us. The gathering and transportation rate charged by NGLLC to us on our production in the Nora field is considered to be at market.

F-34

(18) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

The following tables set forth unaudited financial information on a quarterly basis for each of the last two years (in thousands). As discussed in Note 3, certain reclassifications have been made to conform to our current year classifications. This includes the reclassification of abandonment and impairment expense for unproved properties from depletion, depreciation and amortization. These reclassifications did not impact net income.


	2008 ^(a)
	March			June			September			December			Total
Revenues
Oil and gas sales	$	307,384		$	347,622		$	347,720		$	223,834		$	1,226,560
Transportation and gathering		1,129			1,224			1,537			687			4,577
Derivative fair value (loss) income		(123,767	)		(196,684	)		272,869			119,443			71,861
Other		20,592			(359	)		544			898			21,675

Total revenues		205,338			151,803			622,670			344,862			1,324,673


Costs and expenses
Direct operating		32,950			37,228			36,532			35,677			142,387
Production and ad valorem taxes		13,840			16,056			15,210			10,066			55,172
Exploration		16,593			19,462			19,149			12,486			67,690
Abandonment and impairment of unproved properties		2,124			3,474			5,055			36,702			47,355
General and administrative		17,412			23,938			24,650			26,308			92,308
Deferred compensation plan		20,611			7,539			(37,515	)		(15,324	)		(24,689	)
Interest expense		23,146			23,842			25,373			27,387			99,748
Depletion, depreciation and amortization		70,133			72,115			76,690			80,893			299,831

Total costs and expenses		196,809			203,654			165,144			214,195			779,802


Income (loss) from continuing operations before income taxes		8,529			(51,851	)		457,526			130,667			544,871

Income tax expense (benefit)
Current		886			949			2,374			59			4,268
Deferred		2,794			(20,445	)		170,202			37,012			189,563

		3,680			(19,496	)		172,576			37,071			193,831


Net income (loss)	$	4,849		$	(32,355	)	$	284,950		$	93,596		$	351,040


Income (loss) per common share:
Basic	$	0.03		$	(0.22	)	$	1.87		$	0.61		$	2.32


Diluted	$	0.03		$	(0.22	)	$	1.81		$	0.60		$	2.25


^(a)		The quarterly impact of the adjustments described in Note 2 for the twelve months ended December 31, 2008 is an increase (decrease) to income from continuing operations before income taxes in the amounts of ($687,000), $3.6 million, ($572,000) and ($64,000) for the first, second, third and fourth quarters, respectively. Additionally, net income increased (decreased) by $3.1 million, $2.2 million, ($374,000) and ($80,000) for the first, second, third and fourth quarters, respectively. Diluted earnings per share increased $0.02 per share in the first quarter and increased $0.01 per share in the second quarter, with no effect on earnings per share for the third or fourth quarter.

F-35


	2007 ^(b)
	March			June			September			December			Total
Revenues
Oil and gas sales	$	193,316		$	213,896		$	214,424		$	240,901		$	862,537
Transportation and gathering		184			511			508			1,087			2,290
Derivative fair value (loss) income		(42,620	)		28,766			24,974			(20,613	)		(9,493	)
Other		1,961			341			2,447			282			5,031

Total revenues		152,841			243,514			242,353			221,657			860,365


Costs and expenses
Direct operating		25,414			24,816			28,003			29,266			107,499
Production and ad valorem taxes		10,412			11,230			11,316			9,485			42,443
Exploration		11,710			11,725			8,670			13,677			45,782
Abandonment and impairment of unproved properties		1,867			493			1,815			7,061			11,236
General and administrative		14,678			17,838			18,058			19,096			69,670
Deferred compensation plan		8,833			7,893			6,317			12,395			35,438
Interest expense		18,848			17,573			19,935			21,381			77,737
Depletion, depreciation and amortization		47,176			51,465			55,294			66,643			220,578

Total costs and expenses		138,938			143,033			149,408			179,004			610,383


Income from continuing operations before income taxes		13,903			100,481			92,945			42,653			249,982

Income tax expense (benefit)
Current		384			(101	)		133			(96	)		320
Deferred		4,796			34,323			34,763			22,105			95,987

		5,180			34,222			34,896			22,009			96,307


Income from continuing operations		8,723			66,259			58,049			20,644			153,675
Discontinued operations, net of taxes		64,768			(979	)		(196	)		—			63,593


Net income	$	73,491		$	65,280		$	57,853		$	20,644		$	217,268


Earnings per common share:
Basic — income from continuing operations	$	0.06		$	0.45		$	0.39		$	0.14		$	1.07
— discontinued operations		0.47			(0.01	)		—			—			0.44

— net income	$	0.53		$	0.44		$	0.39		$	0.14		$	1.51


Diluted — income from continuing operations	$	0.06		$	0.44		$	0.38		$	0.13		$	1.02
— discontinued operations		0.45			—			—			—			0.43

— net income	$	0.51		$	0.44		$	0.38		$	0.13		$	1.45


^(b)		The quarterly impact of the adjustments described in Note 2 for the twelve months ended December 31, 2007 is an increase (decrease) to income from continuing operations before income taxes in the amounts of $703,000, $948,000, ($1.1 million) and ($16.3 million) for the first, second, third and fourth quarters, respectively. Additionally, net income increased (decreased) by $354,000, $1.1 million, ($1.1 million) and ($13.7 million) in the first, second, third and fourth quarters, respectively. The fourth quarter adjustment to decrease income from continuing operations before income taxes is primarily comprised of a $12.4 million correction related to the Company’s deferred compensation plan, or the Rabbi trust. Diluted earnings per share increased $0.01 per share in the second quarter, decreased $0.01 per share in the third quarter and decreased $0.07 per share in the fourth quarter, with no effect on earnings per share in the second quarter.

Principal Unconsolidated Investees (unaudited)


Company	December 31, 2008 Ownership	Activity
Whipstock Natural Gas Services, LLC	50%	Drilling services
Nora Gathering, LLC	50%	Gas gathering and transportation

F-36

(19)

SUPPLEMENTAL INFORMATION ON NATURAL GAS AND OIL EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES

The following information concerning our gas and oil operations has been provided pursuant to SFAS No. 69, “Disclosures about Oil and Gas Producing Activities.” Our gas and oil producing activities are conducted onshore within the continental United States and offshore in the Gulf of Mexico. Our Gulf of Mexico assets were sold in first quarter 2007. In December 2008, the SEC announced revisions to modernize oil and gas reporting requirements which are effective for our December 31, 2009 reporting period. We are in the process of evaluating the impact of these new requirements.

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization ^(a)


	December 31,
	2008			2007			2006
	(in thousands)
Oil and gas properties:
Properties subject to depletion	$	5,271,021		$	4,169,714		$	3,132,927
Unproved properties		757,959			262,648			221,874

Total		6,028,980			4,432,362			3,354,801
Accumulated depreciation, depletion and amortization		(1,186,934	)		(939,769	)		(751,005	)

Net capitalized costs	$	4,842,046		$	3,492,593		$	2,603,796


^(a)		Includes capitalized asset retirement costs and the associated accumulated amortization.

Costs Incurred for Property Acquisition, Exploration and Development ^(a)


	Year Ended December 31,
	2008		2007			2006
	(in thousands)
Acquisitions:
Unproved leasehold	$	99,446	$	4,552		$	132,821
Proved oil and gas properties		251,471		253,064			209,262
Purchase price adjustment ^(b)		—		—			147,062
Asset retirement obligations		251		3,301			896
Acreage purchases ^(c)		494,341		78,095			79,762
Development		729,268		732,550			464,586
Exploration:
Drilling		133,116		40,567			25,618
Expense		63,560		42,309			42,173
Stock-based compensation expense		4,130		3,473			3,079
Gas gathering facilities:
Exploratory		—		—			3,418
Development		47,056		18,655			16,272

Subtotal		1,822,639		1,176,566			1,124,949

Asset retirement obligations		4,647		(7,075	)		25,821


Total costs incurred ^(d)	$	1,827,286	$	1,169,491		$	1,150,770


Assets held for sale:
Acquisitions	$	—	$	—		$	140,110
Development	$	—	$	1,114		$	15,012


^(a)		Includes cost incurred whether capitalized or expensed.

^(b)		Represents the offset to our deferred tax liability resulting from differences in book and tax basis at date of acquisition.

^(c)		Includes a single transaction to acquire Marcellus Shale acreage for $223.9 million.

^(d)		2006 includes $21.5 million related to our divested Gulf of Mexico properties.

F-37

Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)

Reserves of crude oil, condensate, natural gas liquids and natural gas are estimated by our engineers and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year. Many assumptions and judgmental decisions are required to estimate reserves. Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors.

The SEC defines proved reserves as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those proved reserves, which can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered as a result of additional investments for drilling new wells to offset productive units, recompleting existing wells, and/or installing facilities to collect and transport production.

Production quantities shown are net volumes withdrawn from reservoirs. These may differ from sales quantities due to inventory changes, and, especially in the case of natural gas, volumes consumed for fuel and/or shrinkage from extraction of natural gas liquids.

The reported value of proved reserves is not necessarily indicative of either fair market value or present value of future net cash flows because prices, costs and governmental policies do not remain static, appropriate discount rates may vary, and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in significantly different amounts.

The average realized prices used at December 31, 2008 to estimate reserve information were $42.76 per barrel of oil, $25.00 per barrel for natural gas liquids and $5.23 per mcf for gas, using benchmark prices (NYMEX) of $44.60 per barrel and $5.71 per Mmbtu. The average realized prices used at December 31, 2007 to estimate reserve information were $91.88 per barrel for oil, $52.64 per barrel for natural gas liquids and $6.44 per mcf for gas, using benchmark prices (NYMEX) of $95.98 per barrel and $6.80 per Mmbtu. The average realized prices used at December 31, 2006 to estimate reserve information were $57.66 per barrel for oil, $25.98 per barrel for natural gas liquids and $5.24 per mcf for gas, using benchmark prices (NYMEX) of $61.05 per barrel and $5.64 per Mmbtu. All of our proved reserves are located within the United States.

F-38


	Crude Oil						Natural Gas
	and NGLs			Natural Gas			Equivalents ^(b)
	(Mbbls)			(Mmcf)			(Mmcfe)
Proved developed and undeveloped reserves:
Balance, December 31, 2005		46,892			1,125,410			1,406,762
Revisions		(42	)		(48,609	)		(48,863	)
Extensions, discoveries and additions		10,871			314,261			379,491
Purchases		242			121,683			123,133
Property sales		(4	)		(1,500	)		(1,522	)
Production		(4,252	)		(75,267	)		(100,775	)


Balance, December 31, 2006 ^(a)		53,707			1,435,978			1,758,226
Revisions		2,432			(386	)		14,207
Extensions, discoveries and additions		13,741			401,805			484,250
Purchases		1,934			121,382			132,984
Property sales		(649	)		(35,362	)		(39,254	)
Production		(4,505	)		(90,620	)		(117,651	)


Balance, December 31, 2007		66,660			1,832,797			2,232,762
Revisions		(3,155	)		(23,397	)		(42,333	)
Extensions, discoveries and additions		15,841			423,354			518,404
Purchases		53			95,262			95,578
Property sales		(1,592	)		(147	)		(9,701	)
Production		(4,471	)		(114,323	)		(141,145	)


Balance, December 31, 2008		73,336			2,213,546			2,653,565


Proved developed reserves:
December 31, 2006		37,750			875,395			1,101,895

December 31, 2007		47,015			1,144,709			1,426,802

December 31, 2008		49,009			1,337,978			1,632,032


^(a)		The December 31, 2006 balance excludes reserves associated with the Austin Chalk properties. The total proved developed and undeveloped reserves for these assets at December 31, 2006 were 42.3 Bcfe, which is comprised of 39.3 Bcfe of gas. These assets were sold in the first quarter of 2007.

^(b)		Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf.

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

The following summarizes the policies we used in the preparation of the accompanying gas and oil reserve disclosures, standardized measures of discounted future net cash flows from proved gas and oil reserves and the reconciliations of standardized measures from year to year. The information disclosed, as prescribed by SFAS No. 69, is an attempt to present the information in a manner comparable with industry peers.

The information is based on estimates of proved reserves attributable to our interest in gas and oil properties as of December 31 of the years presented. These estimates were prepared by our petroleum engineering staff. Proved reserves are estimated quantities of natural gas and crude oil, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

F-39

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:

1.		Estimates are made of quantities of proved reserves and future amounts expected to be produced based on current year-end economic conditions.

2.		Estimated future cash inflows are calculated by applying current year-end prices of gas and oil relating to our proved reserves to the quantities of those reserves produced in each future year.

3.		Future cash flows are reduced by estimated production costs, administrative costs, costs to develop and produce the proved reserves and abandonment costs, all based on current year-end economic conditions. Future income tax expenses are based on current year-end statutory tax rates giving effect to the remaining tax basis in the gas and oil properties, other deductions, credits and allowances relating to our proved gas and oil reserves.

4.		The resulting future net cash flows are discounted to present value by applying a discount rate of 10%.

The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of our gas and oil reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

The standardized measure of discounted future net cash flows relating to proved gas and oil reserves is as follows and excludes cash flows associated with hedges outstanding at each of the respective reporting dates.


	As of December 31,
	2008			2007
	(in thousands)
Future cash inflows	$	14,293,651		$	17,231,826
Future costs:
Production		(4,034,065	)		(3,859,591	)
Development		(1,818,509	)		(1,464,229	)


Future net cash flows before income taxes		8,441,077			11,908,006

Future income tax expense		(2,381,826	)		(3,854,952	)


Total future net cash flows before 10% discount		6,059,251			8,053,054

10% annual discount		(3,477,871	)		(4,386,691	)


Standardized measure of discounted future net cash flows	$	2,581,380		$	3,666,363

F-40

The following table summarizes changes in the standardized measure of discounted future net cash flows.


	As of December 31,
	2008			2007			2006
	(in thousands)
Beginning of period	$	3,666,363		$	2,002,224		$	3,384,310
Revisions of previous estimates:
Changes in prices		(1,675,703	)		1,310,378			(2,390,159	)
Revisions in quantities		(65,931	)		37,188			(91,793	)
Changes in future development costs		(688,259	)		(542,684	)		(623,607	)
Accretion of discount		520,482			277,144			488,737
Net change in income taxes		719,595			(769,242	)		733,846
Purchases of reserves in place		148,857			348,119			231,314
Additions to proved reserves from extensions, discoveries and improved recovery		807,386			1,267,649			712,902
Production		(1,029,001	)		(711,354	)		(554,788	)
Development costs incurred during the period		333,979			304,165			223,158
Sales of gas and oil		(15,109	)		(102,757	)		(2,859	)
Timing and other		(141,279	)		245,533			(108,837	)

End of period	$	2,581,380		$	3,666,363		$	2,002,224

F-41

RANGE RESOURCES CORPORATION
INDEX TO EXHIBITS


Exhibit No.		Description
23.1*		Consent of Independent Registered Public Accounting Firm


*		Filed herewith.