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Document and Company Information - USD ($)	12 Months Ended
Document and Company Information - USD ($)	Dec. 31, 2009	Feb. 19, 2010	Jun. 30, 2009
Document and Company Information [Abstract]
Entity Registrant Name	RANGE RESOURCES CORP
Entity Central Index Key	0000315852
Document Type	10-K
Document Period End Date	Dec. 31, 2009
Amendment Flag	false
Company Fiscal Year End Date	--12-31
Entity Well Known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 6,361,198,000
Entity Common Stock Shares Outstanding		159,142,506

Consolidated Balance Sheets - USD ($) $ in Thousands	12 Months Ended
Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2009	Dec. 31, 2008
Current assets:
Cash and cash equivalents	$ 767	$ 753
Accounts receivable, less allowance for doubtful accounts of $2,176 and $954	123,622	162,201
Deferred tax asset	8,054	0
Unrealized derivative gain	21,545	221,430
Inventory and other	21,292	19,927
Total current assets	175,280	404,311
Unrealized derivative gain	4,107	5,231
Equity method investments	146,809	147,126
Oil and gas properties, successful efforts method	6,308,707	6,028,980
Accumulated depletion and depreciation	(1,409,888)	(1,186,934)
Oil and gas properties, successful efforts method	4,898,819	4,842,046
Transportation and field assets	161,034	142,662
Accumulated depreciation and amortization	(69,199)	(56,434)
Transportation and field assets, net	91,835	86,228
Other assets	79,031	66,937
Total assets	5,395,881	5,551,879
Current liabilities:
Accounts payable	214,548	250,640
Asset retirement obligations	2,446	2,055
Accrued liabilities	58,585	47,309
Deferred tax liability	0	32,984
Accrued interest	24,037	20,516
Unrealized derivative loss	14,488	10
Total current liabilities	314,104	353,514
Bank debt	324,000	693,000
Subordinated notes and other long term debt	1,383,833	1,097,668
Deferred tax liability	776,965	779,218
Unrealized derivative loss	271	0
Deferred compensation liability	135,541	93,247
Asset retirement obligations and other liabilities	$ 82,578	$ 83,890
Commitments and contingencies
Stockholders' Equity
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding	$ 0	$ 0
Common stock, $0.01 par, 475,000,000 shares authorized, 158,336,264 issued at December 31, 2009 and 155,609,387 issued at December 31, 2008	1,583	1,556
Common stock held in treasury, 217,327 shares at December 31, 2009 and 233,900 shares at December 31, 2008	(7,964)	(8,557)
Additional paid-in capital	1,772,020	1,695,268
Retained earnings	606,529	685,568
Accumulated other comprehensive income	6,421	77,507
Total stockholders' equity	2,378,589	2,451,342
Total liabilities and stockholders' equity	$ 5,395,881	$ 5,551,879

Consolidated Balance Sheets (Parenthetical) - USD ($)	Dec. 31, 2009	Dec. 31, 2008
Current assets:
Allowance for doubtful accounts on accounts recievable	$ 2,176,000	$ 954,000
Stockholders' Equity
Preferred stock, par value	$ 1	$ 1
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	475,000,000	475,000,000
Common stock, shares issued	158,336,264	155,609,387
Common stock held in treasury, shares	217,327	233,900

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2009	Dec. 31, 2008	Dec. 31, 2007
Revenues
Oil and gas sales	$ 839,921	$ 1,226,560	$ 862,537
Transportation and gathering	486	4,577	2,290
Derivative fair value income (loss)	66,446	71,861	(9,493)
Other	488	21,675	5,031
Total revenue	907,341	1,324,673	860,365
Costs and expenses
Direct operating	133,846	142,387	107,499
Production and ad valorem taxes	32,169	55,172	42,443
Exploration	46,899	67,690	45,782
Abandonment and impairment of unproved properties	113,538	47,355	11,236
General and administrative	116,749	92,308	69,670
Deferred compensation plan	31,073	(24,689)	35,438
Interest expense	117,367	99,748	77,737
Depletion, depreciation and amortization	374,432	299,831	220,578
Total costs and expenses	966,073	779,802	610,383
(Loss) income from continuing operations before income taxes	(58,732)	544,871	249,982
Income tax (benefit) expense
Current	(636)	4,268	320
Deferred	(4,226)	189,563	95,987
Total income tax (benefit) expense	(4,862)	193,831	96,307
(Loss) income from continuing operations	(53,870)	351,040	153,675
Discontinued operations, net of taxes	0	0	63,593
Net (loss) income	$ (53,870)	$ 351,040	$ 217,268
(Loss) income per common share:
Basic-(loss) income from continuing operations	$ (0.35)	$ 2.32	$ 1.07
- discontinued operations	0	0	0.44
- net (loss) income	(0.35)	2.32	1.51
Diluted-(loss) income from continuing operations	(0.35)	2.25	1.02
- discontinued operations	0	0	0.43
- net (loss) income	$ (0.35)	$ 2.25	$ 1.45
Weighted average common shares outstanding:
Basic	154,514	151,116	143,791
Diluted	154,514	155,943	149,911

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2009	Dec. 31, 2008	Dec. 31, 2007
Operating activities:
Net (loss) income	$ (53,870)	$ 351,040	$ 217,268
Adjustments to reconcile net cash provided from operating activities:
Income from discontinued operations	0	0	(63,593)
Loss (income) from equity method investments	13,699	218	(974)
Deferred income tax (benefit) expense	(4,226)	189,563	95,987
Depletion, depreciation and amortization	374,432	299,831	220,578
Exploration dry hole costs	2,159	13,371	17,586
Mark-to-market on oil and gas derivatives not designated as hedges	115,909	(85,594)	80,495
Abandonment and impairment of unproved properties	113,538	47,355	11,236
Unrealized derivative loss (gain)	1,696	(1,695)	820
Allowance for bad debts	1,351	450	0
Amortization of deferred financing costs and other	8,755	2,900	2,277
Deferred and stock-based compensation	73,402	6,621	61,258
(Gains) losses on sale of assets and other	(10,413)	(19,507)	2,212
Changes in working capital, net of amounts from business acquisitions:
Accounts receivable	1,007	6,701	(50,570)
Inventory and other	(1,463)	(9,246)	(1,040)
Accounts payable	(44,765)	10,663	28,640
Accrued liabilities and other	464	12,096	9,922
Net cash provided from continuing operations	591,675	824,767	632,102
Net cash provided from discontinued operations	0	0	10,189
Net cash provided from operating activities	591,675	824,767	642,291
Investing activities:
Additions to oil and gas properties	(541,182)	(881,950)	(782,398)
Additions to field service assets	(33,098)	(36,076)	(26,044)
Acquisitions, net of cash acquired	(139,288)	(834,758)	(336,453)
Investing activities of discontinued operations	0	0	(7,375)
Investment In equity method investment and other assets	7,076	(44,162)	(94,630)
Proceeds from disposal of assets and discontinued operations	234,076	68,231	234,332
Purchase of marketable securities held by the deferred compensation plan	(7,470)	(11,208)	(48,018)
Proceeds from the sales of marketable securities held by the deferred compensation plan	6,079	8,146	40,014
Net cash used in investing activities	(473,807)	(1,731,777)	(1,020,572)
Financing activities:
Borrowing on credit facilities	707,000	1,476,000	864,500
Repayment on credit facilities	(1,076,000)	(1,086,500)	(1,013,000)
Issuance of subordinated notes	285,201	250,000	250,000
Dividends paid	(25,169)	(24,625)	(19,082)
Debt issuance costs	(6,399)	(8,710)	(3,686)
Issuance of common stock	12,737	291,183	296,229
Change in cash overdrafts	(22,370)	4,420	3,877
Proceeds from the sales of common stock held by the deferred compensation plan	7,201	5,303	6,505
Purchases of common stock held by the deferred compensation plan and other treasury stock purchases	(55)	(3,326)	(5,426)
Net cash (used in) provided from financing activities	(117,854)	903,745	379,917
Increase (decrease) in cash and cash equivalents	14	(3,265)	1,636
Cash and cash equivalents at beginning of year	753	4,018	2,382
Cash and cash equivalents at end of year	$ 767	$ 753	$ 4,018

Consolidated Statements of Stockholders Equity - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2009	Dec. 31, 2008	Dec. 31, 2007
Statement [Line Items]
Balance	$ 2,451,342	$ 1,717,736	$ 1,258,089
Issuance of common stock	57,601	291,881	312,535
Stock-based compensation expense	19,771	16,562	16,519
Common dividends declared ($0.16, $0.16 and $0.13 per share in 2009, 2008 and 2007 respectively)	(25,169)	(24,625)	(19,082)
Treasury stock purchase	0	(3,223)	(5,334)
Other comprehensive income (loss)	(71,086)	101,971	(62,259)
Net income (loss)	(53,870)	351,040	217,268
Adoption of SFAS No. 159, net of tax		0
Balance	2,378,589	2,451,342	1,717,736
Common stock
Statement [Line Items]
Balance	$ 1,556	$ 1,497	$ 1,389
Balance, Shares	155,609	149,667	138,931
Issuance of common stock	$ 27	$ 59	$ 108
Issuance of common stock,Shares	2,727	5,942	10,736
Balance	$ 1,583	$ 1,556	$ 1,497
Balance, Shares	158,336	155,609	149,667
Treasury common stock
Statement [Line Items]
Balance	$ (8,557)	$ (5,334)
Treasury stock purchase	593	(3,223)	$ (5,334)
Balance	(7,964)	(8,557)	(5,334)
Additional paid-in capital
Statement [Line Items]
Balance	1,695,268	1,386,884	1,057,938
Issuance of common stock	57,574	291,822	312,427
Stock-based compensation expense	19,771	16,562	16,519
Treasury stock purchase	(593)
Balance	1,772,020	1,695,268	1,386,884
Retained earnings (deficit)
Statement [Line Items]
Balance	685,568	360,427	162,241
Common dividends declared ($0.16, $0.16 and $0.13 per share in 2009, 2008 and 2007 respectively)	(25,169)	(24,625)	(19,082)
Net income (loss)	(53,870)	351,040	217,268
Adoption of SFAS No. 159, net of tax		(1,274)
Balance	606,529	685,568	360,427
Accumulated other comprehensive (loss) income
Statement [Line Items]
Balance	77,507	(25,738)	36,521
Other comprehensive income (loss)	(71,086)	101,971	(62,259)
Adoption of SFAS No. 159, net of tax		1,274
Balance	$ 6,421	$ 77,507	$ (25,738)

Consolidated Statements of Stockholders Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2009	Dec. 31, 2008	Dec. 31, 2007
Statement [Line Items]
Common dividends per share	$ 0.16	$ 0.16	$ 0.13

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2009	Dec. 31, 2008	Dec. 31, 2007
Statements of Comprehensive Income [Abstract]
Net (loss) income	$ (53,870)	$ 351,040	$ 217,268
Other comprehensive (loss) income:
Realized loss (gain) on hedge derivative contract settlements reclassified into earnings from other comprehensive (loss) income	(127,965)	39,416	(2,621)
Change in unrealized deferred hedging gains (losses)	56,879	62,555	(54,477)
Change in unrealized (losses) gains on securities held by deferred compensation plan, net of taxes	0	0	(5,161)
Total comprehensive (loss) income	$ (124,956)	$ 453,011	$ 155,009

Summary of Organization and Nature of Business	12 Months Ended
Summary of Organization and Nature of Business	Dec. 31, 2009
Summary of Organization and Nature of Business [Abstract]
Summary of Organization and Nature of Business	(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 natural gas properties primarily in the Southwestern and Appalachian 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 our common stock listed and traded on the New York Stock Exchange under the symbol “RRC.”

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2009

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

(2) 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. We have evaluated events or transactions that occurred subsequent to December 31, 2009 through the date and time this annual report on Form 10-K was filed.

During first quarter 2007, we sold our interests in our Austin Chalk properties that we purchased as part of the 2006 Stroud Energy acquisition. We also sold our Gulf of Mexico properties in first quarter 2007. We have reflected the results of operations of these divestitures as discontinued operations, rather than a component of continuing operations. See also Note 4 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 these estimates and changes in these estimates are recorded when known.

Income per Common Share

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

Business Segment Information

We have evaluated how Range is organized and managed and have identified only one operating segment, which is the exploration and production of oil, natural gas and natural gas liquids. We consider our gathering, processing and marketing functions as ancillary to our oil and gas producing activities. 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.

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 as 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 an 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 $2.2 million at December 31, 2009 compared to $954,000 at December 31, 2008. During the year ended 2009, we recorded $1.4 million of bad debt expense compared to $450,000 in the same period of the prior year.

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, 2009 and December 31, 2008 were not significant. At December 31, 2009, we had recorded a net liability of $326,000 for those wells where it was determined that there were insufficient reserves to recover the imbalance situation.

Cash and Cash 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 and consist of various publicly-traded mutual funds that include investments from equities to money market instruments.

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, on a first-in, first-out basis. Our inventory is primarily acquired for use in future drilling operations.

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. Historically, we have adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report. We adopted the new SEC accounting and disclosure regulations for oil and gas companies effective December 31, 2009. Accounting Standards Codification (ASC) 2010-3 clarified that the effect of the change in price encompassed in the new SEC rules is a change in accounting principle inseparable from a change in estimate for 2009 and will be accounted for prospectively. We estimate the effect of this change in estimate increased depletion, depreciation and amortization expense by approximately $3.4 million ($2.2 million after tax) primarily due to lower prices reflected in our estimated reserves.

Our oil and gas producing properties are reviewed for impairment periodically as events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. These 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 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 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 using a discount rate similar to market participants) 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 oil and gas producing 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 evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leasehold costs. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors. We continue to experience an increase in lease expirations caused by (1) current economic conditions, which have impacted our future drilling plans thereby increasing the amount of lease expirations and (2) our expansion in shale plays which involve acquisitions of significant acreage positions prior to development. Unproved properties had a net book value of $774.5 million in 2009 compared to $758.0 million in 2008 and $262.6 million in 2007. The increase from 2007 represents additional acreage purchases primarily in the Marcellus Shale and Barnett Shale. We have recorded abandonment and impairment expense related to unproved properties of $113.5 million in 2009 compared to $47.4 million in 2008 and $11.2 million in 2007.

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 $31.7 million in 2009 compared to $13.7 million in 2008 and $10.9 million in 2007. The fourth quarter 2009 includes accelerated depreciation expense of $10.3 million related to an interim processing plant in our Appalachian region that will be dismantled in first quarter 2010.

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, 2009 include $24.2 million of unamortized debt issuance costs, $43.6 million of marketable securities held in our deferred compensation plans and $11.1 million of other investments.

Stock-based Compensation Arrangements

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. We have utilized historical data and analyzed current information to reasonably support these assumptions. The fair value of restricted stock awards is determined based on the fair market value of our common stock on the date of grant.

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. Restricted stock awards are classified as a liability and are remeasured at fair value each reporting period.

Derivative Financial Instruments and Hedging

All of our derivative instruments are issued to manage the price risk attributable to our expected oil and gas production. While there is risk that the financial benefit of rising oil and gas prices may not be captured, we believe the benefits of stable and predictable cash flow are more important. Among these benefits are more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our ongoing development drilling and production enhancement programs, more consistent returns on invested capital and better access to bank and other capital markets. Every unsettled derivative instrument is recorded on our consolidated balance sheet as either an asset or a liability measured at its fair value. Changes in a derivative’s fair value should be recognized in earnings unless specific hedge accounting criteria are met. Cash flows from oil and gas derivative contract settlements are reflected in operating activities in our consolidated statements of cash flows.

Through December 2009, we have elected to designate our commodity derivative instruments that qualify for hedge accounting as cash flow hedges. 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 hedged transaction is not probable to occur, any unrealized gains or losses are recognized immediately in the statement of operations as derivative fair value income (loss). During 2009, we recognized a gain of $5.4 million compared to a loss of $583,000 in 2008 and a loss of $16.3 million in 2007 as a result of the discontinuance of hedge accounting treatment for certain of our derivatives.

We apply hedge accounting to qualifying derivatives (or “hedge derivatives”) used to manage price risk associated with our oil and gas production. Accordingly, we record changes in the fair value of our swap and collar contracts, including changes associated with time value, in accumulated other comprehensive income (loss) (“AOCI”) on our consolidated balance sheet. Gains or losses on these swap and collar contracts are reclassified out of AOCI and into oil and gas sales when the underlying physical transaction occurs. Any hedge ineffectiveness associated with a contract qualifying 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 in derivative fair value income (loss) on our consolidated statement of operations. Ineffectiveness can be associated with open positions (unrealized) or can be associated with closed contracts (realized).

Realized and unrealized gains and losses on derivatives that are not designated as hedges (or a “non-hedge derivative”) 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 each period in derivative fair value income (loss). We also enter 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 (“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.

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. Deferred tax assets are recorded when it is more likely than not that they will be realized. 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)

The following details the components of AOCI and related tax effects for the three years ended December 31, 2009. Amounts included in AOCI as of December 31, 2009 and 2008, relates to our derivative activity.


	Gross			Tax Effect			Net of Tax
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 fair value accounting for trading securities		2,022			(748	)		1,274


Accumulated other comprehensive income at December 31, 2008		122,252			(44,745	)		77,507
Contract settlements reclassified to income		(203,119	)		75,154			(127,965	)
Change in unrealized deferred hedging gains		91,059			(34,180	)		56,879


Accumulated other comprehensive income at December 31, 2009	$	10,192		$	(3,771	)	$	6,421

Accounting Pronouncements Implemented

In February 2008, the FASB issued Accounting Standards Codification (“ASC”) 820-10 (formerly FASB Staff Position FAS No. 157-2), which delayed the effective date of ASC 820-10 (formerly 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 primarily applied to our asset retirement obligation, which uses fair value measures at the date incurred to determine our liability and any property impairment that may occur. We adopted the provisions of this standard effective January 1, 2009 and the adoption did not have a material effect on our consolidated results of operations or financial position.

In June 2008, the FASB issued ASC 260-10 (formerly Staff Position No. EITF 03-6-1), “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities,” which provides that unvested share-based payment awards that contain nonforteitable 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 the provisions of this standard on January 1, 2009 with no impact on our reported earnings per share.

In March 2008, the FASB issued ASC 815-10 (formerly SFAS No. 161), which amends and expands disclosure requirements 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; and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The provisions of this standard were adopted on January 1, 2009. See Note 11 for additional disclosures about our derivative instruments and hedging activities.

In December 2007, the FASB issued ASC 805-10 (formerly SFAS No. 141(R)), “Business Combinations,” which 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 provisions of this standard will apply prospectively to business combinations occurring in our fiscal year beginning January 1, 2009 and the adoption did not have an impact on our financial position or results of operations.

In April 2009, the FASB issued additional application guidance and enhancements to disclosures regarding fair value measurements. ASC 825-10 (formerly FASB Staff Position No. FAS 107-1 and APB 28-1), “Interim Disclosures about Fair Value of Financial Instruments,” enhances consistency in financial reporting by increasing the frequency of fair value disclosures. ASC 820-10 (formerly “FASB Staff Position No. FAS 157-4”), “Determining Fair Value when the Volume and Level of Activity for the Asset or Liability have Significantly Decreased and Identifying Transactions that are Not Orderly,” provides guidelines for making fair value measurements more consistent. We adopted the provisions of these standards for the period ended June 30, 2009, which did not have an impact on our financial position or results of operations.

In May 2009, the FASB issued ASC 855-10 (formerly SFAS No. 165), “Subsequent Events,” which establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. We adopted this standard upon issuance with no impact on our financial position or results of operations.

In June 2009, the FASB issued ASC 105-10 (formerly SFAS No. 168), “Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles.” The FASB Accounting Standards Codification (“Codification”) has become the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in accordance with GAAP. All existing accounting standard documents are superseded by the Codification and any accounting literature not included in the Codification will not be authoritative. However, rules and interpretive releases of the SEC issued under the authority of federal securities laws will continue to be the source of authoritative generally accepted accounting principles for SEC registrants. Effective September 30, 2009, all references made to GAAP in our consolidated financial statements will include the new Codification numbering system along with original references. The Codification does not change or alter existing GAAP and, therefore, will not have an impact on our financial position, results of operations or cash flows.

In December 2008, the SEC announced that it had approved revisions to its oil and gas reporting disclosures. The new disclosure requirements include provisions that:

•

Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.

•

Require companies to report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end prices. The FASB aligned the current accounting standards with these rules.

•

Permit companies to disclose their probable and possible reserves on a voluntary basis. In the past, proved reserves were the only reserves allowed in the disclosures.

•

Require companies to provide additional disclosure regarding the aging of proved undeveloped reserves.

•

Permit the use of reliable technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

•

Replace the existing “certainty” test for areas beyond one offsetting drilling unit from a productive well with a “reasonable certainty” test.

•

Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures regarding internal controls over reserve estimation, as well as a report addressing the independence and qualifications of its reserves preparer or auditor will be mandatory.

We began complying with the disclosure requirements in this annual report on Form 10-K.

In January 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-03, “Oil and Gas Reserve Estimation and Disclosures.” This ASU amends the FASB’s Accounting Standards Codification Topic 932, “Extractive Activities — Oil and Gas” to align the accounting requirements of Topic 932 with the SEC’s final rule, “Modernization of the Oil and Gas Reporting Requirements” issued on December 31, 2008. In summary, the revisions in ASU 2010-3 modernize the disclosure rules to better align with current industry practices and expand the disclosure requirements for equity method investments so that more useful information is provided. More specifically, the main provisions include the following:

•

An expanded definition of oil and gas producing activities to include nontraditional resources such as bitumen extracted from oil sands.

•

The use of an average of the first day of the month price for the 12-month period, rather than a year-end price for determining whether reserves can be produced economically.

•

Amended definitions of key terms such as “reliable technology” and “reasonable certainty” which are used in estimating proved oil and gas reserve quantities.

•

A requirement for disclosing separate information about reserve quantities and financial statement amounts for geographical areas representing 15 percent or more of proved reserves.

This ASU is effective for annual reporting periods ended on or after December 31, 2009, and it requires (1) the effect of the adoption to be included within each of the dollar amounts and quantities disclosed, (2) qualitative and quantitative disclosure of the estimated effect of adoption on each of the dollar amounts and quantities disclosed, if significant and practical to estimate and (3) the effect of adoption on the financial statements, if significant and practical to estimate. Adoption of these requirements did not significantly impact our reported reserves or our consolidated financial statements.

In February 2007, the FASB issued ASC 825-10 (formerly SFAS 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 ASC 825-10 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. 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.

Accounting Pronouncements Not Yet Adopted

In June 2009, the FASB ASC 810-10-65 (formerly SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)”) which amends the consolidation guidance applicable to a variable interest entity (“VIE”). This standard also amends the guidance governing the determination of whether an enterprise is the primary beneficiary of a VIE, and is therefore required to consolidate an entity, by requiring a qualitative analysis rather than a quantitative analysis. Previously, the standard required reconsideration of whether an enterprise was the beneficiary of a VIE only when specific events had occurred. This standard is effective for calendar year companies beginning in January 1, 2010. Early adoption is prohibited. We are currently evaluating the potential impact of the adoption of this standard on its financial statements, but do not expect it to have a material effect.

Acquisitions and Dispositions	12 Months Ended
Acquisitions and Dispositions	Dec. 31, 2009
Acquisitions and Dispositions [Abstract]
Acquisitions and Dispositions	(3) 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 2009, we completed no material acquisitions. 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. In May 2007, we acquired additional interests in the Nora field of Virginia and entered into a joint development plan with EQT Corporation (“EQT”). As a result of this transaction, EQT 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. EQT 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 EQT 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. Dispositions In second quarter 2009, we sold certain oil properties located in West Texas for proceeds of $181.8 million. In fourth quarter 2009, we sold natural gas properties in New York for proceeds of $36.3 million. The proceeds from the sale of these properties were credited to oil and gas properties, with no gain or loss recognized, as the dispositions did not materially impact the depletion rate of the remaining properties in the amortization base. Additionally, in 2009 we sold Marcellus Shale acreage for $11.2 million and we recognized a gain of $10.4 million. 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 Austin Chalk 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 4 for additional information. In December 2009, we announced our plan to offer for sale our tight gas sand properties in Ohio. The properties include approximately 3,500 producing wells, 418,000 net acres of leasehold and 1,600 miles of pipeline and gathering system infrastructure. The data room opened in January 2010 and on February 8, 2010, we announced that we signed a definitive agreement to sell these assets for a price of $330.0 million, subject to normal post-closing adjustments. However, the completion of the sale is dependent upon customary prospective buyer due diligence procedures and there can be no assurance the sale will be completed. The approximate net book value of these assets at December 31, 2009 was $240.0 million.

Discontinued Operations

12 Months Ended

Dec. 31, 2009

Discontinued Operations [Abstract]

Discontinued Operations

(4) DISCONTINUED OPERATIONS

As part of an acquisition completed in 2006, we purchased Austin Chalk properties in Central Texas, which were sold in 2007 for proceeds of $80.4 million. Also in 2007, we 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 year ended December 31, 2007 is summarized as follows (in thousands):


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

Total revenues		108,264

Costs and expenses
Direct operating		2,559
Production and ad valorem taxes		141
Exploration and other		215
Interest expense ^(b)		845
Depletion, depreciation and amortization		6,672

Total costs and expenses		10,432

Income from discontinued operations before income taxes		97,832

Income tax expense		34,239


Income from discontinued operations, net of taxes	$	63,593


Production
Crude oil (bbls)		40,634
Natural gas (mcf)		1,990,277
Total (mcfe) ^(c)		2,234,081


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

Income Taxes

12 Months Ended

Dec. 31, 2009

Income Taxes [Abstract]

Income Taxes

(5) INCOME TAXES

Our income tax benefit from continuing operations was $4.9 million for the year ended December 31, 2009 compared to income tax expense of $193.8 million in 2008 and $96.3 million in 2007. A reconciliation between the statutory federal income tax rate and our effective income tax rate (benefit) is as follows:


	Year Ended December 31,
	2009			2008			2007
Federal statutory tax rate		(35.0	%)		35.0	%		35.0	%
State		29.3			1.8			2.8
Valuation allowance		(2.8	)		(0.2	)		0.8
Other		0.2			(1.0	)		(0.1	)

Consolidated effective tax rate (benefit)		(8.3	%)		35.6	%		38.5	%


Income taxes paid (refunded) (in thousands)	$	170		$	4,298		$	(572	)

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


	Year Ended December 31,
	2009			2008		2007
				(in thousands)
Current:
U.S. federal	$	(1,000	)	$	1,000	$	(129	)
U.S. state and local		364			3,268		449

	$	(636	)	$	4,268	$	320


Deferred:
U.S. federal	$	(20,913	)	$	186,436	$	90,687
U.S. state and local		16,687			3,127		5,300

	$	(4,226	)	$	189,563	$	95,987


Total tax (benefit) provision	$	(4,862	)	$	193,831	$	96,307

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


	December 31,
	2009			2008
	(in thousands)
Deferred tax assets:
Current
Deferred compensation	$	3,337		$	1,289
Current portion of asset retirement obligation		952			767
Other		6,207			4,411
Current portion of net operating loss carryforward		—			4,258

Subtotal		10,496			10,725


Non-current
Net operating loss carryforward		72,131			21,673
Deferred compensation		53,869			41,083
AMT credits and other credits		3,815			7,106
Non-current portion of asset retirement obligation		29,642			30,168
Cumulative unrealized mark-to-market loss		8,625			—
Other		20,311			12,602
Valuation allowance		(2,555	)		(4,147	)

Subtotal		185,838			108,485


Deferred tax liabilities:
Current
Net unrealized gain in OCI		(2,443	)		(43,709	)

Subtotal		(2,443	)		(43,709	)


Non-current
Depreciation, depletion and investments		(959,931	)		(848,356	)
Net unrealized gain in OCI		(1,328	)		(1,036	)
Cumulative unrealized mark-to-market gain		—			(38,029	)
Other		(1,543	)		(282	)

Subtotal		(962,802	)		(887,703	)


Net deferred tax liability	$	(768,911	)	$	(812,202	)

At December 31, 2009, deferred tax liabilities exceeded deferred tax assets by $768.9 million, with $3.8 million of deferred tax liability related to net deferred hedging gains included in OCI. We have a full valuation allowance of $601,000 recorded against our capital loss carryover and a $2.0 million valuation allowance on the deferred tax asset related to our deferred compensation plan for planned future distributions to top level executives to the extent that their estimated future compensation plus distribution amounts would exceed the $1.0 million deductible limit provided under I.R.C. Section 162(m).

At December 31, 2009, we had regular net operating loss (“NOL”) carryforwards of $321.5 million and alternative minimum tax (“AMT”) NOL carryforwards of $259.0 million that expire between 2012 and 2027. Our deferred tax asset related to regular NOL carryforwards at December 31, 2009 was $159.4 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, 2009, we have AMT credit carryforwards of $777,000 that are not subject to limitation or expiration.

We file consolidated tax returns in the United States federal jurisdiction. We file separate company state income tax returns in Louisiana, Mississippi, Ohio, Pennsylvania and Virginia and file consolidated or unitary state income tax returns in New Mexico, Oklahoma, Texas and West Virginia. We are subject to U.S. Federal income tax examinations for the years after 2005 and we are subject to various state tax examinations for years after 2004. We have not extended the statute of limitation period in any tax jurisdiction. 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, 2009. Throughout 2009, our unrecognized tax benefits were not material.

Earnings (Loss) Per Common Share

12 Months Ended

Dec. 31, 2009

Earnings (Loss) Per Common Share [Abstract]

Earnings (Loss) Per Common Share

(6) EARNINGS (LOSS) PER COMMON SHARE

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


	Year Ended December 31,
	2009			2008			2007
Numerator:
(Loss) income from continuing operations	$	(53,870	)	$	351,040		$	153,675
Income from discontinued operations		—			—			63,593

Net (loss) income	$	(53,870	)	$	351,040		$	217,268


Denominator:
Weighted average shares—basic		154,514			151,116			143,791

Effect of dilutive securities:
Employee stock options, SARs and stock held in deferred compensation plan		—			4,876			6,178
Treasury shares		—			(49	)		(58	)

Weighted average common shares—diluted		154,514			155,943			149,911


Basic—(loss) income from continuing operations	$	(0.35	)	$	2.32		$	1.07
–discontinued operations		—			—			0.44

–net (loss) income	$	(0.35	)	$	2.32		$	$1.51


Diluted—(loss) income from continuing operations	$	(0.35	)	$	2.25		$	1.02
–discontinued operations		—			—			0.43

–net (loss) income	$	(0.35	)	$	2.25		$	1.45

Weighted average shares-basic excludes 2.6 million shares at December 31, 2009, 2.3 million shares at December 31, 2008 and 2.0 million shares at December 31, 2007 of restricted stock that is held in our deferred compensation plans (although all restricted stock is issued and outstanding upon grant). Due to our net loss for the year ended December 31, 2009, we excluded 7.2 million of outstanding stock options/SARs and 2.6 million of restricted stock held in our deferred compensation plans from the computations of diluted net loss per share because the effect would have been anti-dilutive. For 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).

Suspended Exploratory Well Costs

12 Months Ended

Dec. 31, 2009

Suspended Exploratory Well Costs [Abstract]

Suspended Exploratory Well Costs

(7) SUSPENDED EXPLORATORY WELL COSTS

We capitalize exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. Capitalized exploratory well costs are presented in oil and gas properties in our consolidated balance sheets. If an exploratory well is determined to be impaired, the well costs are charged to expense. The following table reflects the changes in capitalized exploratory well costs for the year ended December 31, 2009, 2008 and 2007 (in thousands):


	2009			2008			2007
Balance at beginning of period	$	47,623		$	15,053		$	9,984
Additions to capitalized exploratory well costs pending the determination of proved reserves		26,216			43,968			14,428
Divested wells		—			—			(1,325	)
Reclassifications to wells, facilities and equipment based on determination of proved reserves		(52,849	)		(3,847	)		—
Capitalized exploratory well costs charged to expense		(1,938	)		(7,551	)		(8,034	)

Balance at end of period		19,052			47,623			15,053
Less exploratory well costs that have been capitalized for a period of one year or less		(10,778	)		(41,681	)		(12,067	)

Capitalized exploratory well costs that have been capitalized for a period greater than one year	$	8,274		$	5,942		$	2,986


Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		6			3			2

As of December 31, 2009, the $8.3 million of capitalized exploratory well costs that have been capitalized for more than one year relates to wells waiting on pipelines. Of the $19.1 million of capitalized exploratory well costs at December 31, 2009, $10.7 million was incurred in 2009 and $8.3 million in 2008.

Indebtedness

12 Months Ended

Dec. 31, 2009

Indebtedness [Abstract]

Indebtedness

(8) INDEBTEDNESS

We had the following debt outstanding as of the dates shown below (bank debt interest rate at December 31, 2009 is shown parenthetically). No interest was capitalized during 2009, 2008, and 2007 (in thousands):


	December 31,
	2009		2008
Bank debt (2.1%)	$	324,000	$	693,000

Senior subordinated notes:
7.375% senior subordinated notes due 2013, net of $1.6 million and $2.0 million discount, respectively		198,362		197,968
6.375% senior subordinated notes due 2015		150,000		150,000
7.5% senior subordinated notes due 2016, net of $363 and $405 discount, respectively		249,637		249,595
7.5% senior subordinated notes due 2017		250,000		250,000
7.25% senior subordinated notes due 2018		250,000		250,000
8.0% senior subordinated notes due 2019, net of $14.2 million discount		285,834		—
Other		—		105

Total debt	$	1,707,833	$	1,790,668

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, 2009, 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 twenty-six commercial banks each holding between 2.4% and 5.0% of the total facility. 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. As of December 31, 2009, the outstanding balance under the bank credit facility was $324.0 million and $100,000 of undrawn letters of credit leaving $925.9 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 2.4% for the year ended December 31, 2009 compared to 4.4% for the year ended December 31, 2008. A commitment fee is paid on the undrawn balance based on an annual rate of 0.375% to 0.50%. At December 31, 2009, the commitment fee was 0.375% and the interest rate margin was 1.75% on our LIBOR loans and 0.875% on our base rate loans.

Senior Subordinated Notes

In May 2008, we issued $250.0 million aggregate principal amount of 7.25% senior subordinated notes due 2018 (“7.25% Notes”). In May 2009, we issued $300.0 million aggregate principal amount of our 8.0% senior subordinated notes due 2019 (“8.0% Notes”). The 8.0% Notes were issued at a discount, which is being amortized over the life of the 8.0% 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 7.25% Notes, in whole or in part, at any time on or after May 1, 2013 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 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. We may redeem the 8.0% Notes, in whole or in part, at any time on or after May 15, 2014, at redemption prices of 104.0% of the principal amount as of May 15, 2014 declining to 100.0% on May 15, 2017 and thereafter. Before May 15, 2012, we may redeem up to 35% of the original aggregate principal amount of the 8.0% Notes at a redemption price equal to 108.0% 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 aggregate principal amount of the 8.0% Notes remain outstanding 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 our senior subordinated 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, 2009.

Following is the principal maturity schedule for the long-term debt outstanding as of December 31, 2009 (in thousands):


	Year Ended
	December 31,
2010	$	—
2011		—
2012		324,000
2013		198,362
2014		—
2015		150,000
Thereafter		1,035,471

	$	1,707,833

The indentures governing our senior subordinated notes contain various restrictive covenants that are substantially identical to each other 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, 2009, we were in compliance with these covenants.

Asset Retirement Obligation

12 Months Ended

Dec. 31, 2009

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation

(9) 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. Significant assumptions used in determining such obligations include estimates of plugging and abandonment costs, estimated future inflation rates and well life. The inputs are calculated based on historical data as well as current estimated costs. A reconciliation of our liability for plugging and abandonment costs for the years ended December 31, 2009 and 2008 is as follows (in thousands):


	2009			2008
Beginning of period	$	83,457		$	75,308

Liabilities incurred		1,622			2,347
Acquisitions		—			250
Liabilities settled		(724	)		(1,399	)
Disposition of wells		(15,946	)		(898	)
Accretion expense		5,893			5,471
Change in estimate		4,510			2,378

End of period		78,812			83,457


Less current portion		(2,446	)		(2,055	)


Long-term asset retirement obligation	$	76,366		$	81,402

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

Capital Stock

12 Months Ended

Dec. 31, 2009

Capital Stock [Abstract]

Capital Stock

(10) CAPITAL STOCK

We 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 2008:


	Year Ended December 31,
	2009		2008
Beginning balance		155,375,487		149,511,997
Public offerings		—		4,435,300
Shares issued in lieu of cash bonuses		184,926		—
Stock options/SARs exercised		1,384,861		1,339,536
Restricted stock grants		413,353		167,054
Issued for acreage purchases		743,737		—
Treasury shares		16,573		(78,400	)

Ending balance		158,118,937		155,375,487

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 January 2010, we issued 380,229 additional shares of common stock for acreage purchases.

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, 2009, we have $6.8 million remaining authorization to repurchase shares.

Shelf Registration Statement

In June 2009, we filed a shelf registration statement with the Securities and Exchange Commission to potentially offer securities which include debt securities or common stock. The securities will be offered at prices and on terms to be determined at the time of sale. Net proceeds from the sale of such securities will be used for general corporate purposes, including a reduction of bank debt. Also in June 2009, we issued a $200.0 million registration statement where we may, from time to time, sell shares of our common stock in connection with an acquisition or business combination. As of December 31, 2009, we have $176.5 million remaining under this registration statement.

Common Stock Dividends

The Board of Directors declared quarterly dividends of $0.04 per common share for each of the four quarters of 2009, $0.04 per common share for each of the four quarters of 2008, and $0.03 per common share for the first three quarters of 2007 and $0.04 per common share for fourth quarter 2007. The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of the Board of Directors and will depend on our financial condition, earnings and cash flow from operations, level of capital expenditures, our future business prospects and other matters the Board of Directors deems relevant.

Derivative Activities

12 Months Ended

Dec. 31, 2009

Derivative Activities [Abstract]

Derivative Activities

(11) DERIVATIVE ACTIVITIES

We use commodity-based derivative contracts to manage exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. We typically utilize commodity swap and collar contracts to (1) reduce the effect of price volatility of the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. At December 31, 2009, we had collars covering 108.5 Bcf of gas at weighted average floor and cap prices of $5.62 to $7.40 per mcf and 0.4 million barrels of oil at weighted average floor and cap prices of $75.00 to $93.75 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 $28.7 million at December 31, 2009. These contracts expire monthly through December 2011. The following table sets forth the derivative volumes by year as of December 31, 2009:


			Weighted
Period	Contract Type	Volume Hedged	Average Hedge Price
Natural Gas
2010	Collars	242,356 Mmbtu/day	$5.53–$7.37
2011	Collars	55,000 Mmbtu/day	$6.00–$7.50

Crude Oil
2010	Collars	1,000 bbl/day	$75.00–$93.75

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 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 our hedge derivatives are recorded as a component of AOCI, which is later transferred to oil and gas sales when the hedged transaction occurs and the hedging contract is settled. As of December 31, 2009, an unrealized pre-tax derivative gain of $10.2 million was recorded in AOCI. This gain will be reclassified into earnings as a gain of $7.0 million in 2010 and a gain of $3.2 million in 2011 as the contracts settle. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date. If the derivative does not qualify as a hedge or is not designated as a hedge, changes in fair value of these non-hedge derivatives are recognized in earnings in derivative fair value income (loss).

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 $203.1 million of gains in 2009 compared to losses of $63.6 million in 2008 and gains of $4.2 million in 2007, related to settled hedging transactions. Any ineffectiveness associated with these hedge derivatives are reflected in derivative fair value income (loss) in our statement of operations. The ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in future cash flows from the item hedged. Derivative fair value income (loss) for the year ended December 31, 2009 includes ineffective gains (unrealized and realized) of $3.1 million compared to gains of $3.1 million in 2008 and gains of $148,000 in 2007.

In addition to the 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 loss of $17.8 million at December 31, 2009.

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, 2009 (in thousands):


	2009			2008			2007
Change in fair value of derivatives that do not qualify for hedge accounting	$	(115,909	)	$	85,594		$	(80,495	)
Realized gain (loss) on settlement—gas ^(a)		171,998			(1,383	)		71,098
Realized gain (loss) on settlement—oil ^(a)		7,304			(15,431	)		(244	)
Hedge ineffectiveness—realized		4,749			1,386			968
—unrealized		(1,696	)		1,695			(820	)

Derivative fair value income (loss)	$	66,446		$	71,861		$	(9,493	)


^(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.

Derivative assets and liabilities

The combined fair value of derivatives included in our consolidated balance sheets as of December 31, 2009 and 2008 is summarized below (in thousands). We conduct derivative activities with twelve financial institutions, eleven 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. For example, we have two counterparties with a total derivative position equal to a net receivable of $8.0 million. This receivable includes a basis swap payable of $1.1 million which is netted and reported in our derivative receivable.


	December 31,
	2009			2008
Derivative assets:
Natural gas—swaps	$	—		$	57,280
—collars		26,649			121,781
—basis swaps		(1,063	)		12,434
Crude oil—collars		66			35,166

	$	25,652		$	226,661


Derivative liabilities:
Natural gas—collars	$	2,020		$	—
—basis swaps		(16,779	)		(10	)

	$	(14,759	)	$	(10	)

The table below provides data about the fair value of our derivative contracts. Derivative assets and liabilities shown below are presented as gross assets and liabilities, without regard to master netting arrangements, which are considered in the presentation of derivative assets and liabilities in our consolidated balance sheets (in thousands):


	December 31, 2009								December 31, 2008
	Assets		(Liabilities)						Assets		(Liabilities)
	Carrying Value		Carrying Value			Net Carrying Value			Carrying Value		Carrying Value			Net Carrying Value
Derivatives that qualify for cash flow hedge accounting :
Collars ⁽¹⁾	$	22,062	$	—		$	22,062		$	124,193	$	—		$	124,193

	$	22,062	$	—		$	22,062		$	124,193	$	—		$	124,193


Derivatives that do not qualify for hedge accounting :
Swaps ⁽¹⁾	$	—	$	—		$	—		$	57,280	$	—		$	57,280
Collars ⁽¹⁾		6,673		—			6,673			32,754		—			32,754
Basis swaps ⁽¹⁾		65		(17,907	)		(17,842	)		12,481		(57	)		12,424

	$	6,738	$	(17,907	)	$	(11,169	)	$	102,515	$	(57	)	$	102,458


⁽¹⁾		Include in unrealized derivative gain (loss) on our balance sheet.

The effects of our hedge derivatives on accumulated other comprehensive income (loss) on the consolidated balance sheets are summarized below:


	Year Ended December 31,
							Realized Gain (Loss)
	Change in Hedge						Reclassified from OCI
	Derivative Fair Value						into Revenue ^(a)
	2009			2008			2009			2008
Swaps	$	—		$	(21,572	)	$	—		$	6,404
Collars		91,059			119,579			203,119			(69,979	)
Income taxes		(34,180	)		(35,452	)		(75,154	)		24,159

	$	56,879		$	62,555		$	127,965		$	(39,416	)


^(a)		For realized gains upon contract settlement, the reduction in other comprehensive income is offset by an increase in oil and gas sales. For realized losses upon contract settlement, the increase in other comprehensive income is offset by a decrease in oil and gas sales.

The effects of our non-hedge derivatives and the ineffective portion of our hedge derivative on our consolidated statement of operations is summarized below:


	Year Ended December 31,
	Gain (Loss) Recognized in								Gain (Loss) Recognized in								Derivative Fair Value
	Income (Non-hedge Derivatives)								Income (Ineffective Portion)								Income (Loss)
	2009			2008		2007			2009		2008			2007			2009			2008		2007
Swaps	$	63,755		$	14,395	$	8,255		$	—	$	(438	)	$	1,856		$	63,755		$	13,957	$	10,111
Collars		33,859			33,118		(17,163	)		3,053		3,520			(1,708	)		36,912			36,638		(18,871	)
Basis swaps		(34,221	)		21,266		(733	)		—		—			—			(34,221	)		21,266		(733	)

Total	$	63,393		$	68,779	$	(9,641	)	$	3,053	$	3,082		$	148		$	66,446		$	71,861	$	(9,493	)

Fair Value Measurements

12 Months Ended

Dec. 31, 2009

Fair Value Measurements [Abstract]

Fair Value Measurements

(12) FAIR VALUE 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 presents the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis (in thousands):


	Fair Value Measurements at December 31, 2009 Using:
	Quoted Prices in		Significant			Significant		Total Carrying
	Active Markets for		Other			Unobservable		Value as of
	Identical Assets		Observable Inputs			Inputs		December 31,
	(Level 1)		(Level 2)			(Level 3)		2009
Trading securities held in the deferred compensation plans	$	43,554	$	—		$	—	$	43,554

Derivatives—collars		—		28,735			—		28,735
—basis swaps		—		(17,842	)		—		(17,842	)

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, 2009 market value. 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.

Our trading securities held in the deferred compensation plan are accounted for using the mark-to-market accounting method and are included in the balance sheet category called “other assets.” We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. Interest, dividends, and mark-to-market gains/losses are included in the statement of operations category called deferred compensation plan expense. For the year ended December 31, 2009, interest and dividends were $487,000 and mark-to-market was a gain of $10.4 million. For the year ended December 31, 2008, interest and dividends were $1.5 million and the mark-to-market was a loss of $19.4 million.

The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2009 and 2008 (in thousands):


	December 31, 2009						December 31, 2008
	Carrying			Fair			Carrying			Fair
	Value			Value			Value			Value
Assets:
Commodity swaps and collars	$	25,652		$	25,652		$	226,661		$	226,661
Marketable securities ^(a)		43,554			43,554			33,473			33,473

Liabilities:
Commodity swaps and collars		(14,759	)		(14,759	)		(10	)		(10	)
Long-term debt ^(b)		(1,707,833	)		(1,826,458	)		(1,790,668	)		(1,621,793	)


^(a)		Marketable securities are held in our deferred compensation plans.

^(b)		The book value of our bank debt approximate fair value because of its floating rate structure. The fair value of our senior subordinated notes is based on end of period market quotes.

Our current assets and liabilities contain financial instruments, the most significant of which are trade accounts receivables and payables. We believe the carrying values of our trade accounts receivables and payables approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments and (2) our historical incurrence of and expected future insignificance of bad debt expense.

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 $2.2 million at December 31, 2009 and $954,000 at December 31, 2008. Commodity-based contracts expose us to the credit risk of nonperformance by the counterparty to the contracts. As of December 31, 2009, these derivative contracts consist of collars. This exposure is diversified primarily 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, eleven of which are secured lenders in our bank credit facility. J. Aron & Company is the only counterparty not in our bank group. At December 31, 2009, our net derivative receivable includes a payable to J. Aron & Company of $1.6 million.

Stock Based Compensation Plans

12 Months Ended

Dec. 31, 2009

Stock Based Compensation Plans [Abstract]

Stock Based Compensation Plans

(13) STOCK-BASED COMPENSATION PLANS

Description of the Plans

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 and directors. The 2004 Non-Employee Director Stock Option Plan (the “Director Plan”) allows such 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 Option 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 plus (iii) subsequent shares approved by the shareholders. 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-based awards under the Plans

Stock options represent the right to purchase shares of stock in the future at the fair 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 appreciation rights (“SARs”) to reduce the dilutive impact of our equity plans. Similar to stock options, SARs represents the right to receive a payment equal to the excess 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 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 stock awards are issued at prevailing market prices at the time of the grant and the vesting is based upon an employee’s continued employment with us. Prior to vesting, all restricted stock awards have the right to vote such stock and receive dividends thereon. All restricted shares that are granted are placed in our deferred compensation plan. Restricted stock awards are classified as a liability and are remeasured at fair value each reporting period. This mark-to-market is reported in our statement of operations in deferred compensation plan expense.

As part of the closure of our Houston office, there were eighteen employees whose unvested SARs and restricted stock grants were modified and fully vested effective with the closing of the office on November 1, 2009. The incremental compensation cost of this modification was $2.5 million.

Total Stock-Based Compensation Expense

Stock-based compensation represents amortization of restricted stock grants and stock option/SARs expense. In 2009, stock-based compensation was allocated to operating expense ($2.6 million), exploration expense ($4.8 million), and general administrative expense ($33.5 million) for a total of $41.8 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. In 2007, stock-based compensation was allocated to direct operating expense ($1.8 million), exploration expense ($3.5 million) and general and administrative expense ($18.2 million) for a total of $23.9 million. Unlike the other forms of stock-based compensation mentioned above, the mark-to-market of the vested restricted stock held in our deferred compensation plans 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. For the year ended December 31, 2009, cash received upon exercise of stock option awards was $12.7 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.

Stock and Option Plans

We have two active equity-based stock plans. Under these 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 non-employee, independent directors from the Board of Directors. All awards granted under these plans have been issued at prevailing market prices 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. Of the 7.2 million grants outstanding at December 31, 2009, 1.3 million of the grants relate to stock options with the remainder of 5.9 million grants relating to SARs. Information with respect to stock option and SARs activities is summarized below:


				Weighted
				Average
	Shares			Exercise Price
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
Granted		1,714,165			36.90
Exercised		(1,717,584	)		14.31
Expired/forfeited		(90,535	)		40.73

Outstanding at December 31, 2009		7,154,712		$	31.38

The following table shows information with respect to outstanding stock options and SARs at December 31, 2009:


	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		909,036		1.97	$	3.43		909,036	$	3.43
10.00–19.99		1,058,329		0.46		17.11		1,058,329		17.11
20.00–29.99		1,099,533		1.23		24.31		1,099,533		24.31
30.00–39.99		2,384,613		3.08		34.16		856,974		34.31
40.00–49.99		622,324		4.34		41.74		58,185		41.77
50.00–59.99		708,212		3.14		58.49		255,349		58.58
60.00–69.99		25,927		3.25		65.43		8,829		65.30
70.00–75.00		346,738		3.38		75.00		123,613		75.00

Total		7,154,712		2.40	$	31.38		4,369,848	$	23.93

Stock Appreciation Right Awards

During 2009, 2008 and 2007, 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:


	2009			2008			2007
Weighted average exercise price per share	$	36.90		$	63.18		$	33.78
Expected annual dividends per share		0.44	%		0.26	%		0.36	%
Expected life in years		3.5			3.5			3.5
Expected volatility		58	%		41	%		36	%
Risk-free interest rate		1.5	%		2.4	%		4.7	%

Weighted average grant date fair value of SARs granted	$	15.42		$	20.58		$	10.67

The dividend yield is based on the current annual dividend at the time of grant. For SARs granted in 2007, we used the “simplified” method 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 and 2009, the expected term was based on the historical exercise activity. 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 risk-free interest 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.

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, 2009 was $50.9 million compared to $67.9 million in 2008 and $67.2 million in 2007. As of December 31, 2009, the aggregate intrinsic value of the awards outstanding was $147.4 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option/SARs awards currently exercisable was $118.7 million and 1.6 years. As of December 31, 2009, the number of fully vested awards and awards expected to vest was 7.1 million. The weighted average exercise price and weighted average remaining contractual life of these awards were $31.23 and 2.4 years and the aggregate intrinsic value was $146.4 million. As of December 31, 2009, unrecognized compensation cost related to the awards was $26.4 million, which is expected to be recognized over a weighted average period of 1.6 years.

Restricted Stock Awards

In 2009, we granted 686,000 shares of restricted stock grants as compensation to directors and employees at an average price of $39.99. The restricted stock grants included 22,700 issued to directors, which vest immediately and 663,300 to employees with vesting generally over a three-year period. 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. We recorded compensation expense for restricted stock grants of $19.7 million in the year ended December 31, 2009 compared to $14.7 million in 2008 and $8.7 million in 2007. As of December 31, 2009, there was $25.8 million of unrecognized compensation related to restricted stock awards expected to be recognized over the next three years. All of our restricted stock grants are held in our deferred compensation plan. All restricted stock awards are classified as liability award and are remeasured at fair value each reporting period. This mark-to-market is reported in the deferred compensation expense in our consolidated statement of operations (see additional discussion below). The proceeds received from the sale of stock held in our deferred compensation plan was $7.2 million in 2009.

A summary of the status of our non-vested restricted stock outstanding at December 31, 2009 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, 2008		473,547		$	48.50
Granted		685,578			39.99
Vested		(521,536	)		40.91
Forfeited		(10,400	)		40.83

Non-vested shares outstanding at December 31, 2009		627,189		$	45.64

401(k) Plan

We maintain a 401(k) benefit plan that allows employees to contribute up to 50% of their salary (subject to Internal Revenue Service limitations) on a pretax basis. Prior to 2008, we 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 2009, we contributed $3.2 million to the plan compared to $2.7 million in 2008 and $2.3 million in 2007. We do not require that employees hold any contributed Range stock in their account. Employees have a variety of investment options in the plan. Employees may, at any time, diversify out of our stock, based on their personal investment strategy.

Deferred Compensation Plan

In December 2004, the Board of Directors approved a deferred compensation plan. The deferred compensation plan gives 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. Range provides a matching contribution which vests over three years. The assets of all of the plans are held in a grantor 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 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 other assets. The deferred compensation liability on our consolidated balance sheet reflects the vested market value of the marketable securities and the vested 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 a mark-to-market loss of $31.1 million in 2009 compared to mark-to-market income of $24.7 million in 2008 and a mark-to-market loss of $35.4 million in 2007. The Rabbi Trust held 2.7 million shares (2.1 million of vested shares) of Range stock at December 31, 2009 compared to 2.3 million shares (1.9 million of vested shares) at December 31, 2008.

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2009

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

(14) SUPPLEMENTAL CASH FLOW INFORMATION


	Year Ended December 31,
	2009		2008		2007
	(in thousands)
Net cash provided from continuing operations included:
Income taxes paid to (refunded from) taxing authorities	$	170	$	4,298	$	(572	)
Interest paid		108,685		93,954		71,708

Non-cash investing and finance activities:
Asset retirement costs (removed) capitalized, net		6,131		4,647		(7,075	)
Unproved property purchased with stock		33,726		—		—
Shares issued in lieu of bonuses		6,312		—		926

Commitments and Contingencies

12 Months Ended

Dec. 31, 2009

Commitments and Contingencies [Abstract]

Commitments and Contingencies

(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, office equipment, production facilities, compressors and transportation equipment under cancelable and non-cancelable leases. Rent expense under operating leases (including renewable monthly leases) totaled $11.8 million in 2009 compared to $9.2 million in 2008 and $5.4 million in 2007. Commitments related to these lease payments are not recorded in our 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
2010	$	11,751
2011		9,989
2012		6,113
2013		3,429
2014		2,851
Thereafter		6,652
Sublease rentals		(852	)

	$	39,933

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, 2009, future minimum transportation fees under our gas transportation commitments are as follows (in thousands):


	Transportation
	Commitments
2010	$	36,062
2011		35,836
2012		32,913
2013		31,881
2014		28,590
Thereafter		207,583

	$	372,865

In addition to the amounts included in the above table, we have contracted with several pipeline companies through 2017 to deliver natural gas production volumes in Appalachia from certain Marcellus Shale wells. The agreements call for total incremental increases of 402,000 Mmbtu per day over the initial 100,000 Mmbtu per day at December 31, 2009. These increases, which are contingent on certain pipeline modifications, are 30,000 Mmbtu per day in March 2010, 72,000 Mmbtu per day in July 2010, 150,000 Mmbtu per day in November 2011 and an additional 150,000 Mmbtu per day in November 2012.

Drilling Contracts

As of December 31, 2009, we have contracts with drilling contractors to use six drilling rigs with terms of up to three years and minimum future commitments of $57.9 million in 2010, $58.4 million in 2011, $39.2 million in 2012 and $484,000 in 2013. These six rigs were custom built for our Marcellus Shale program. Early termination of these contracts at December 31, 2009 would have required us to pay maximum penalties of $115.3 million. We do not expect to pay any early termination penalties related to these contracts.

Delivery Commitments

Under a sales agreement, we have an obligation to deliver 30,000 Mmbtu per day of volume at various delivery points within the Barnett Shale in the Fort Worth Basin. The contract, which began in 2008, extends for five years ending March 2013. As of December 31, 2009, remaining volumes to be delivered under this commitment are approximately 35.6 Bcf.

Other

We have lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period, generally not exceeding three 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. To date, our expenditures to comply with environmental or safety regulations have not been significant and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

Major Customers	12 Months Ended
Major Customers	Dec. 31, 2009
Major Customers [Abstract]
Major Customers	(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, 2009, we had no customers that accounted for 10% or more of total oil and gas revenues. 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. We believe that the loss of any one customer would not have a material adverse effect on our results.

Equity Method Investments	12 Months Ended
Equity Method Investments	Dec. 31, 2009
Equity Method Investments [Abstract]
Equity Method Investments	(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. For our investment in Whipstock, these indicators were present during the year ended December 31, 2009, and as a result, we did recognize impairment charges of $9.0 million related to our equity method investment in 2009. *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 2009, 2008 and 2007. During the year ended December 31, 2009, we received $301,000 in cash distributions from Whipstock. 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 year ended December 31, 2007. 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, 2009, our equity in the losses of Whipstock totaled $13.1 million, compared to losses of $479,000 in 2008 and earnings of $132,000 in 2007. In 2009, equity in the losses of Whipstock was reduced by $422,000 to eliminate the profit on services provided to us compared to $1.8 million in 2008 and $2.7 million in 2007. In addition, equity in 2009 losses of Whipstock reflected a $9.0 million impairment charge due to an other than temporary decline in the fair value of our investment. Our fair value determination was based on a discounted cash flow analysis which qualifies as a level 3 fair value measurement in the fair value hierarchy table. Our net book value in this equity investment was $2.8 million at December 31, 2009. 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 EQT Corporation. Pursuant to the terms of the arrangement, Range and EQT (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 2009 and 2008, Range and EQT each contributed $6.4 million and $29.0 million, respectively, 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 2009, 2008 and 2007. There were no dividends or partnership distributions received from NGLLC during the years ended December 31, 2009 or December 31, 2008. 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, 2009 our equity in the losses of NGLLC of $629,600 was reduced by $7.0 million to eliminate the profit on gathering and transportation fees charged to us. 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 and transportation fees charged to us. For the year ended December 31, 2007, our equity in earnings of NGLLC of $841,000 was reduced by $1.8 million to eliminate the profit on gathering and transportation fees charged to us. Our net book value in this equity investment was $144.0 million at December 31, 2009. The gathering and transportation rate charged by NGLLC to us on our production in the Nora field is considered to be at market.

Office Closing and Exit Activities

12 Months Ended

Dec. 31, 2009

Office Closing and Exit Activities [Abstract]

Office Closing and Exit Activities

(18) OFFICE CLOSING AND EXIT ACTIVITIES

In the third quarter 2009, we announced the closing of our Gulf Coast Area administrative and operations office in Houston, Texas. The properties are now operated out of our Southwest Area office in Fort Worth. As of December 31, 2009, we have accrued $1.3 million of severance costs. Expenses related to lease termination and severance costs are included in general and administrative expenses in our consolidated statement of operations.

In addition, in December 2009 we sold our natural gas properties in New York. We have accrued $635,000 of severance costs related to this divestiture and the cost is included in direct operating expense in our consolidated statement of operations. The following table details our exit activities (in thousands):


Balance at December 31, 2008	$	—
Accrued one-time termination costs		1,895
Office lease		252
Payments		(579	)

Balance at December 31, 2009	$	1,568

Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2009

Selected Quarterly Financial Data (Unaudited) [Abstract]

Selected Quarterly Financial Data (Unaudited)

(19) 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).


	2009
	March			June			September			December			Total
Revenues
Oil and gas sales	$	203,189		$	192,523		$	202,122		$	242,087		$	839,921
Transportation and gathering		(505	)		2,152			2,444			(3,605	)		486
Derivative fair value income (loss)		75,547			(9,856	)		(482	)		1,237			66,446
Other		(1,794	)		(4,387	)		(443	)		7,112			488

Total revenue		276,437			180,432			203,641			246,831			907,341


Costs and expenses
Direct operating		35,541			34,828			31,111			32,366			133,846
Production and ad valorem taxes		8,257			7,564			7,600			8,748			32,169
Exploration		13,339			11,368			11,102			11,090			46,899
Abandonment and impairment of unproved properties		19,572			40,954			24,053			28,959			113,538
General and administrative		24,910			29,103			30,568			32,168			116,749
Deferred compensation plan		12,434			756			16,445			1,438			31,073
Interest expense		26,629			29,555			30,633			30,550			117,367
Depletion, depreciation and amortization		84,320			88,713			97,208			104,191			374,432

Total costs and expenses		225,002			242,841			248,720			249,510			966,073


Income (loss) from continuing operations before income taxes		51,435			(62,409	)		(45,079	)		(2,679	)		(58,732	)

Income tax expense (benefit)
Current		—			619			(695	)		(560	)		(636	)
Deferred		18,827			(23,145	)		(14,566	)		14,658			(4,226	)

		18,827			(22,526	)		(15,261	)		14,098			(4,862	)


Net income (loss)	$	32,608		$	(39,883	)	$	(29,818	)	$	(16,777	)	$	(53,870	)


Income (loss) per common share:
Basic	$	0.21		$	(0.26	)	$	(0.19	)	$	(0.11	)	$	(0.35	)


Diluted	$	0.21		$	(0.26	)	$	(0.19	)	$	(0.11	)	$	(0.35	)


	2008
	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 revenue		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

Principal Unconsolidated Investees (unaudited)


Company	December 31, 2009 Ownership			Activity
Whipstock Natural Gas Services, LLC		50	%	Drilling services
Nora Gathering, LLC		50	%	Gas gathering and transportation

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities

12 Months Ended

Dec. 31, 2009

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities [Abstract]

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities

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

Our gas and oil producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States.

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


	December 31,
	2009			2008			2007
	(in thousands)
Oil and gas properties:
Properties subject to depletion	$	5,534,204		$	5,271,020		$	4,169,714
Unproved properties		774,503			757,960			262,648

Total		6,308,707			6,028,980			4,432,362
Accumulated depreciation, depletion and amortization		(1,409,888	)		(1,186,934	)		(939,769	)

Net capitalized costs	$	4,898,819		$	4,842,046		$	3,492,593


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

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


	Year Ended December 31,
	2009		2008		2007
	(in thousands)
Acquisitions:
Unproved leasehold	$	—	$	99,446	$	4,552
Proved oil and gas properties		—		251,471		253,064
Asset retirement obligations		—		251		3,301
Acreage purchases ^(b)		176,867		494,341		78,095
Development		497,702		729,268		732,550
Exploration:
Drilling		57,121		133,116		40,567
Expense		42,082		63,560		42,309
Stock-based compensation expense		4,817		4,130		3,473
Gas gathering facilities:
Development		29,524		47,056		18,655

Subtotal		808,113		1,822,639		1,176,566

Asset retirement obligations		6,131		4,647		(7,075	)


Total costs incurred	$	814,244	$	1,827,286	$	1,169,491


Assets held for sale:
Development	$	—	$	—	$	1,114


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

^(b)		2008 includes a single transaction to acquire Marcellus Shale acreage for $223.9 million.

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.

Recent SEC and FASB Rule-Making Activity

In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. See Note 2. Summary of Significant Accounting Policies – Accounting Pronouncements Implemented. We adopted the rules effective December 31, 2009 and the rule changes, including those related to pricing and technology, are included in our reserves estimates. In addition, in January 2010 the FASB issued Accounting Standards Update 2010-03, “Oil and Gas Reserve Estimation and Disclosures,” to provide consistency with the SEC rules. See Note 2. Summary of Significant Accounting Policies – Accounting Pronouncements Implemented.

Application of the new rules resulted in the use of lower prices at December 31, 2009 for both oil and gas than would have resulted under the previous rules. Use of 12-month average pricing at December 31, 2009 as required by the new rules resulted in a decrease in proved reserves of approximately 86.0 Bcfe. Use of year-end prices as required by the old rules would have resulted in an increase in proved reserves of approximately 3.0 Bcfe at December 31, 2009. Therefore, the total impact of the new price methodology was negative reserves revisions of 89.0 Bcfe. We also estimate that we added 230 Bcfe of additional proved developed reserves, primarily in our Marcellus Shale play, where we have experienced good drilling results, as allowed by the new SEC definitions.

Because we use year-end reserves and add back current quarter production to calculate fourth quarter depletion expense, adoption of these new standards had an impact on fourth quarter 2009 DD&A expense. We estimate the impact of using 12-month average commodity prices, as required by the new standards, instead of year-end commodity prices, to be an increase in fourth quarter 2009 DD&A expense of approximately $3.4 million before income taxes.

Reserve Estimation

At year-end 2009, the following independent petroleum consultants conducted a process review of our reserves: DeGolyer and MacNaughton (Southwest), H.J. Gruy and Associates, Inc. (Southwest) and Wright and Company, Inc. (Appalachia). These engineers were selected for their geographic expertise and their historical experience in engineering certain properties. At December 31, 2009, these consultants collectively reviewed approximately 88% of our proved reserves. A copy of the summary reserve report of each of these independent petroleum consultants is included as an exhibit to this Annual Report on Form 10-K. The technical person at each independent petroleum consulting firm responsible for reviewing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent petroleum consultants to ensure the integrity, accuracy and timeliness of data furnished to independent petroleum consultants for their reserves review process. Throughout the year, our technical team meets regularly with representatives of each of our independent petroleum consultants to review properties and discuss methods and assumptions. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, our senior management reviews and approves any internally estimated significant changes to our proved reserves. We provide historical information to our consultants for our largest producing properties such as ownership interest; oil and gas production; well test data; commodity prices and operating and development costs. The consultants perform an independent analysis and differences are reviewed with our Senior Vice President of Reservoir Engineering. In some cases, additional meetings are held to review additional reserve work performed by the technical teams related to any identified reserve differences.

Historical variances between our reserve estimates and the aggregate estimates of our consultants have been less than 5%. The reserves included in this report on Form 10-K are those reserves estimated by our employees. All of our reserve estimates are reviewed and approved by our Senior Vice President of Reservoir Engineering, who reports directly to our President. Mr. Alan Farquharson, our Senior Vice President of Reservoir Engineering, holds a Bachelor of Science degree in Electrical Engineering from the Pennsylvania State University. Before joining Range, he held various technical and managerial positions with Amoco, Hunt Oil and Union Pacific Resources. During the year, our reserves group may also perform separate, detailed technical reviews of reserve estimates for significant acquisitions or for properties with problematic indicators such as excessively long lives, sudden changes in performance or changes in economic or operating conditions.

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 in future years 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 from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Proved undeveloped reserves can only be assigned to acreage for which improved recovery technology is contemplated unless such techniques have been proven effective by actual tests in the area and in the same reservoir. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating they are scheduled to be drilled within five years, unless specific circumstances, justify a longer time.

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, 2009 to estimate reserve information were $54.65 per barrel of oil, $34.05 per barrel for natural gas liquids and $3.19 per mcf for gas, using benchmark prices (NYMEX) of $60.85 per barrel and $3.87 per Mmbtu. 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.



	Crude Oil			Natural			Natural Gas
	and NGLs			Gas			Equivalents ^(b)
	(Mbbls)			(Mmcf)			(Mmcfe)
Proved developed and undeveloped reserves:
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
Revisions		6,898			(37,497	)		3,890
Extensions, discoveries and additions		24,971			620,114			769,939
Purchases		—			—			—
Property sales		(14,791	)		(50,797	)		(139,543	)
Production		(4,744	)		(130,649	)		(159,112	)


Balance, December 31, 2009		85,670			2,614,717			3,128,739


Proved developed reserves:
December 31, 2007		47,015			1,144,709			1,426,802

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

December 31, 2009		46,831			1,445,705			1,726,696


Proved undeveloped reserves:
December 31, 2007		19,645			688,088			805,961

December 31, 2008		24,327			875,567			1,021,531

December 31, 2009		38,839			1,169,012			1,402,043


^(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 includes 39.3 Bcf of gas. These assets were sold in first quarter 2007.

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

The following details the changes in proved undeveloped reserves for 2009 (Mmcfe):


Beginning proved undeveloped reserves	1,021,531
Undeveloped reserves transferred to developed	(117,353	)
Revisions	(29,847	)
Extension and discoveries	527,712

Ending proved undeveloped reserves	1,402,043

During 2009, various exploration and development drilling evaluations were completed. Approximately $140.0 million was spent during 2009 related to undeveloped reserves that were transferred to developed reserves. Estimated future development costs relating to the development of proved undeveloped reserves are projected to be approximately $292 million in 2010, $472 million in 2011 and $428 million in 2012. Included in proved undeveloped reserves at December 31, 2009 are approximately 116,000 Mmcfe of reserves that have been reported for five or more years, 45% of which will be sold with our Ohio properties. The remaining reserves are in fields in which we are currently active. All proved undeveloped drilling locations are scheduled to be drilled prior to the end of 2014.

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 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.

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.		Prior to 2009, estimated future cash inflows were 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. For 2009, estimated future cash inflows are calculated by applying a twelve-month average price 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,
	2009			2008
	(in thousands)
Future cash inflows	$	11,969,906		$	14,293,651
Future costs:
Production		(3,371,762	)		(4,034,065	)
Development		(1,877,330	)		(1,818,509	)


Future net cash flows before income taxes		6,720,814			8,441,077

Future income tax expense		(1,767,965	)		(2,381,826	)


Total future net cash flows before 10% discount		4,952,849			6,059,251

10% annual discount		(2,861,760	)		(3,477,871	)


Standardized measure of discounted future net cash flows	$	2,091,089		$	2,581,380

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


	As of December 31,
	2009			2008			2007
	(in thousands)
Beginning of period	$	2,581,380		$	3,666,363		$	2,002,224
Revisions of previous estimates:
Changes in prices		(992,809	)		(1,675,703	)		1,310,378
Revisions in quantities		4,124			(65,931	)		37,188
Changes in future development costs		(375,344	)		(688,259	)		(542,684	)
Accretion of discount		340,025			520,482			277,144
Net change in income taxes		317,158			719,595			(769,242	)
Purchases of reserves in place		—			148,857			348,119
Additions to proved reserves from extensions, discoveries and improved recovery		816,278			807,386			1,267,649
Production		(673,907	)		(1,029,001	)		(711,354	)
Development costs incurred during the period		316,523			333,979			304,165
Sales of gas and oil		(147,942	)		(15,109	)		(102,757	)
Timing and other		(94,397	)		(141,279	)		245,533

End of period	$	2,091,089		$	2,581,380		$	3,666,363