Exhibit 99.1

NEWS RELEASE

RANGE ANNOUNCES 2010 RESULTS

FORT WORTH, TEXAS, FEBRUARY 28, 2011...RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its 2010 results. Range continued to execute its strategy of double-digit production and reserve growth at a top-quartile or better cost structure, while maintaining a strong financial position. Production increased 14% while sequential production growth reached 32 consecutive quarters. Proved reserves increased 42%, with all-in reserve replacement of 931%. All-in finding and development cost averaged $0.71 per mcfe, while drill bit only finding cost averaged $0.59 per mcfe.

Financial results for 2010 were negatively impacted by the decline in natural gas prices and a non-cash property impairment related to the recently announced sale of the Barnett Shale properties. Year-over-year, average realized prices declined 19% to $5.23 per mcfe. Natural gas, NGL and oil sales (including all cash-settled derivatives) declined 6% to $960.9 million. Reported GAAP net income including property impairments of $470 million ($463 million due to the Barnett Shale property sale) resulted in a net loss of $239 million. Reported diluted earnings per share for 2010 were a loss of $1.53. Net cash provided from operating activities including changes in working capital totaled $513 million for 2010. Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $89 million or $0.56 per diluted share. Due to lower realized prices, cash flow from operations before changes in working capital, a non-GAAP measure, declined 14% year-over-year to $577 million. On the same basis as analysts’ First Call estimates, earnings per share and cash flow from operations per share for the fourth quarter were $0.19 and $0.99, respectively. For the fourth quarter and the year, earnings per share and cash flow from operations per share on the same basis as analysts’ First Call estimates, each exceeded the average of the analysts’ estimates. See “Non-GAAP Financial Measures” for a definition of each of these non-GAAP financial measures and tables that reconcile each of these non-GAAP measures to their most directly comparable GAAP financial measure.

Commenting, John H. Pinkerton, the Company’s Chairman and CEO, said, “2010 was a value creating year, as we again achieved double-digit production and reserve growth per share, debt adjusted. This growth was delivered at an all-in finding and development cost of $0.71 per mcfe. Our attention to costs served us well, as we saw per unit lease operating costs and DD&A expense decrease materially. Turning to the balance sheet, we ended the year in the strongest financial position in our history with nearly $1 billion of liquidity. Given our extremely large inventory of high-return, low-cost drilling projects, we are well-positioned to continue to drive up production and reserves per share at low cost for years to come.”

Financial Discussion

(Except for reported GAAP amounts, specific expense categories exclude non-cash property impairments, mark-to-market on unrealized derivatives, non-cash stock based compensation, and other items shown separately on the attached tables.)

Fourth Quarter

Reported GAAP revenues for the fourth quarter were $239 million, production increased by 18% to 541 Mmcfe per day, net cash provided from operating activities including changes in working capital was $114 million and earnings were a net loss of $318 million. The amounts corresponding to analysts’ estimates for the same measures, which are non-GAAP measures for the fourth quarter of 2010, are as follows (see the accompanying tables for the reconciliation of these non-GAAP measures to their most directly comparable GAAP financial measure): Natural gas, NGL and oil sales, including all cash-settled derivatives, declined 4% to $265 million, realized prices declined 19% to $5.33 per mcfe, cash flow from operations before changes in working capital decreased 15% to $159 million and adjusted net income decreased 41% to $30 million. Production for the fourth quarter 2010 totaled 49.8 Bcfe, comprised of 37.7 Bcf of natural gas (76%), 1.5 million barrels of NGLs (18%) and 0.5 million barrels of oil (6%). Production in the fourth quarter 2009 totaled 42.0 Bcfe and was 82% natural gas, 10% NGLs and 8% crude oil. While natural gas production rose 9% versus the prior year quarter, NGLs and crude oil production increased by 59%.

During the quarter, Range continued to lower its cost structure. On a unit of production basis, the Company’s five largest operating cost categories fell 13% in aggregate as compared to the prior year quarter. Direct operating expenses for the quarter were $0.72 per mcfe, a 4% decrease compared to the prior-year quarter.

Depreciation, depletion and amortization expense decreased 25% to $1.85 per mcfe. General and administrative expenses increased 16% to $0.57 per mcfe. Production taxes decreased 19%, while interest expense was flat versus the prior year quarter.

With the execution of a definitive agreement regarding the expected sale of the Company’s Barnett Shale properties, Range recorded a $463 million non-cash impairment in the fourth quarter in consideration of the proposed sale. Range will recognize a gain for tax purposes on the sale, however, no cash taxes are expected to be paid upon the closing of the transaction, as the gain will be fully absorbed by utilizing a portion of the Company’s tax net operating loss carryforward.

Full Year 2010

Production for 2010 totaled 181 Bcfe, comprised of 142 Bcf of natural gas (79%), 4.5 million barrels of NGLs (15%) and 2.0 million barrels of oil (6%). Production for 2009 totaled 159 Bcfe and was 82% natural gas, 8% NGLs and 10% crude oil. Range has increased its natural gas production by 9% but has increased its NGLs and crude oil production by 36% when compared year-over-year. Production rose in each quarter of the year and averaged 495 Mmcfe per day for the year. Wellhead prices, after adjustment for all cash-settled hedges and derivatives, decreased 19% to $5.23 per mcfe. The average gas price declined 27% to $4.46 per mcf, as the average oil price increased 11% to $69.31 per barrel and the average natural gas liquids price increased 35% to $39.03 per barrel. The cash margin per mcfe for 2010 averaged $3.11 per mcfe, down from the $4.17 per mcfe realized in 2009.

Comparing the year-over-year changes in Range’s cost structure are consistent with the favorable quarterly comparison. On a unit of production basis, the Company’s five largest operating cost categories fell 9% in aggregate as compared to the prior year. Direct operating expenses for the year were $0.72 per mcfe, a 12% decrease compared to the prior year. Depreciation, depletion and amortization expense decreased 14% to $2.01 per mcfe. General and administrative expenses increased 8% to $0.55 per mcfe. Interest expense declined 1% to $0.73 per mcfe while production taxes decreased 5% to $0.19 per mcfe.

Reserves

Proved reserves at December 31, 2010 totaled 4.4 Tcfe, including 3,567 Bcf of natural gas and 146 million barrels of crude oil and liquids. Reserves increased 1,313 Bcfe or 42% compared to the prior year. Range replaced 931% of production in 2010. Drilling alone replaced 840% of production. At year-end, reserves were 80% natural gas by volume and 20% crude oil and liquids. The percentage of proved undeveloped reserves increased to 51% versus 45% in 2009. Independent petroleum consultants reviewed approximately 90% of the reserves by volume. Current Securities and Exchange Commission (“SEC”) rules require that the reserve calculations be based on the average prices throughout the year, versus the previous method which required year-end prices. The benchmark cash prices under the current method were $4.38 per Mmbtu for natural gas and $79.81 per barrel for crude oil (Cushing), representing the simple average of the prices for the first day of each month of 2010. Based on these prices adjusted for energy content, quality and basis differentials ($3.70 per Mmbtu, $39.14 per barrel for natural gas liquids and $72.51 per barrel for crude oil), the pre-tax discounted (10%) present value of the year-end 2010 reserves was $4.6 billion ($3.5 billion after tax). As of year-end 2010, for each of its proved developed wells in the Marcellus Shale play, Range recorded a modest 1.9 offset drilling locations as proved undeveloped reserves. Range’s finding and development cost from all sources, including leasehold additions and all price and performance revisions averaged $0.71 per mcfe.

SUMMARY OF CHANGES IN PROVED RESERVES

(in Bcfe)

Balance at December 31, 2009			3,129
Extensions, discoveries and additions			1,410
Purchases			125
Performance revisions			108
Price revisions			40
Sales			(189	)
Production			(181	)
Balance at December 31, 2010			4,442

Range previously announced that it had revised its estimate of its unproved resource potential. Range estimates that its unproved resource potential at year-end 2010 was 35 — 52 Tcfe, up from 24 — 32 Tcfe at year-end 2009. The unproved resource potential as compared to our year-end 2010 proved reserve base of 4.4 Tcfe reflects the opportunity to grow our proved reserves by roughly 8 — 12 times. In addition, Range announced that its initial Utica Shale well in Pennsylvania averaged 4.4 Mmcf per day on a seven-day production test. While encouraged by the initial results of our first Utica Shale well, we did not include any resource potential for the Utica Shale in our year-end 2010 estimate. As Range and other operators drill additional Utica Shale wells in 2011, we expect to gain additional information to assist us in determining the unproved resource potential from the Utica Shale.

Operational Highlights

During the fourth quarter, Range’s Marcellus division brought online 11 horizontal wells in southwestern Pennsylvania, nine of which were located in the liquids-rich wet area of the play. With the Lycoming County gathering system now online, five wells were recently turned to sales in this area with an average production rate of 9.0 (7.9 net) Mmcf per day per well. Twenty additional horizontal wells are expected to be brought online in the northeastern portion of the play by third quarter 2011. Earlier this month, Range completed a significant Marcellus step-out well in the southwest portion of the play, which tested at 18.6 Mmcfe per day on a five-day test. Current production in the Marcellus is approximately 260 Mmcfe per day net, from both the southwest and northeast areas. At the end of the year, the Marcellus division had drilled 52 horizontal wells that were waiting on completion and 15 wells waiting on pipeline connection. Range is well on schedule to achieve its Marcellus Shale year-end 2011 production exit rate target of 400 Mmcfe per day net.

Range’s Appalachian division drilled a total of 51 (26 net) wells in the fourth quarter, continuing its successful development of tight gas sand, coal bed methane and horizontal drilling projects in Virginia. The division averaged four rigs running during the quarter. On the recently acquired Nora extension property a Huron Shale horizontal was drilled and completed approximately 25 miles from the prior Nora field horizontal wells. The step-out well in this virgin pressured area tested at 2.6 Mmcf per day, which is materially higher than the typical Nora horizontal well.

The Midcontinent division continued development of liquids-rich plays in the fourth quarter of 2010. Two additional horizontal Mississippian Lime wells were completed at depths of 5,000 feet for a combined daily average rate of 1,314 (1,035 net) Boe per day. Range is also in the process of completing three Ardmore Basin horizontal Woodford shale wells. One operated rig will remain active throughout the year, while

non-operated activity is expected to add 1 to 2 additional rigs to the area. Range participated with Devon Energy (10% working interest) in a horizontal Cana Shale well in Blaine County Oklahoma, where we control approximately 80,000 (42,000 net) legacy acres that are all held by production. Finally, in the Texas Panhandle, Range completed the industry’s first successful horizontal St. Louis Lime well in an oil and liquids-rich area, which tested at 19.2 (5.8 net) Mmcfe per day net.

Conference Call Information

A conference call to review the fourth quarter financial results is scheduled on Tuesday, March 1 at 1:00 p.m. ET. To participate in the call, please dial 877-407-0778 and ask for the Range Resources year-end 2010 financial results conference call. A replay of the call will be available through March 16. To access the phone replay dial 877-660-6853. The account number is 286 and the conference ID is 367761.

A simultaneous webcast of the call may be accessed over the Internet at www.rangeresources.com or www.vcall.com. To listen, please go to either website in time to register and install any necessary software. The webcast will be archived for replay on the Company’s website for 15 days.

Non-GAAP Financial Measures and Supplemental Tables

Adjusted net income comparable to analysts’ estimates as set forth in this release represents income from operations before income taxes adjusted for certain non-cash items (detailed below and in the accompanying table) less income taxes. We believe adjusted net income comparable to analysts’ estimates is calculated on the same basis as analysts’ estimates and that many investors use this published research in making investment decisions useful in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Diluted earnings per share (adjusted) as set forth in this release represents adjusted net income comparable to analysts’ estimates on a diluted per share basis. A table is included which reconciles loss from operations to adjusted net income comparable to analysts’ estimates and diluted earnings per share (adjusted). On its website, the Company provides additional comparative information on prior periods.

Earnings for 2010 included $2.1 million in mark-to-market losses on certain derivative transactions, derivative ineffective hedging gain of $2.4 million, gain on sale of properties of $77.6 million, non-cash stock compensation expense of $31.7 million, impairment expenses related to unproved properties of $70.0 million, $469.7 million in proved property impairments and $17.2 million in debt extinguishment, lawsuit settlements and termination costs. Excluding such items, income before income taxes would have been $144.7 million, a 44% decrease over the prior year. Adjusting for the after-tax effect of these items, the Company’s earnings would have been $89.3 million in 2010 or $0.57 per share ($0.56 per diluted share). If similar items were excluded, 2009 earnings would have been $164.9 million or $1.07 per share ($1.04 per diluted share). Earnings for 2009 included a mark-to-market derivative loss of $115.9 million, ineffective hedging losses of $1.7 million, $72.5 million of non-cash stock compensation, an abandonment and impairment expense related to unproved properties of $113.5 million and $10.4 million in gains on sales of properties. (See reconciliation of non-GAAP earnings in the accompanying table.)

Cash flow from operations before changes in working capital as defined in this release represents net cash provided by operations before changes in working capital and exploration expense adjusted for certain non-cash compensation items. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company’s ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operations, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity. A table is included which reconciles Net cash provided by operations to cash flow from operations before changes in working capital as used in this release. On its website, the Company provides additional comparative information on prior periods for cash flow, cash margins and non-GAAP earnings as used in this release.

The cash prices realized for natural gas, NGL and oil production including the amounts realized on cash-settled derivatives is a critical component in the Company’s performance tracked by investors and professional research analysts in valuing, comparing, rating and providing investment recommendations and forecasts of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Due to the GAAP disclosures of various hedging and derivative transactions, such information is now reported in various lines of the income statement. The Company believes that it is important to furnish a table reflecting the details of the various components of each income statement line to better inform the reader the details of each amount and provide a summary of the realized cash-settled amounts which historically were reported as natural gas, NGL and oil sales. This information will serve to bridge the gap between

various readers’ understanding and fully disclose the information needed.

Range has disclosed two primary metrics in this release to measure our ability to establish a long-term trend of adding reserves at a reasonable cost — a reserve replacement ratio and finding and development cost per unit. The reserve replacement ratio is an indicator of our ability to replace annual production volumes and grow our reserves. It is important to economically find and develop new reserves that will offset produced volumes and provide for future production given the inherent decline of hydrocarbon reserves as they are produced. We believe the ability to develop a competitive advantage over other natural gas and oil companies is dependent on adding reserves in our core areas at lower costs than our competition. The reserve replacement ratio is calculated by dividing production for the year into the total of proved extensions, discoveries and additions, proved reserves added by performance and the addition of reserves due to changes in prices as shown in the summary of changes in the proved reserves table.

Finding and development cost per unit is a non-GAAP metric used in the exploration and production industry by companies, investors and analysts. The calculations presented by the Company are based on costs incurred excluding asset retirement obligations and divided by proved reserve additions (extensions, discoveries and additions shown in the summary of changes in proved reserves table) adjusted for the changes in proved reserves for performance revisions and/or price revisions as stated in each instance in the release. This calculation does not include the future development costs required for the development of proved undeveloped reserves. The SEC method of computing finding costs contains additional cost components and results in a higher number. A reconciliation of the two methods is shown on our website at www.rangeresources.com.

The reserve replacement ratio and finding and development cost per unit are statistical indicators that have limitations, including their predictive and comparative value. As an annual measure, the reserve replacement ratio can be limited because it may vary widely based on the extent and timing of new discoveries and the varying effects of changes in prices and well performance. In addition, since the reserve replacement ratio and finding and development cost per unit do not consider the cost or timing of future production of new reserves, such measures may not be an adequate measure of value creation. These reserves metrics may not be comparable to similarly titled measurements used by other companies.

Year-end pre-tax discounted present value may be considered a non-GAAP financial measure as defined by the SEC. We believe that the presentation of pre-tax discounted present value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We further believe investors and creditors use pre-tax discounted present value as a basis for comparison of the relative size and value of our reserves as compared with other companies. Range’s pre-tax discounted present value as of December 31, 2010 may be reconciled to its standardized measure of discounted future net cash flows as of December 31, 2010 by reducing Range’s pre-tax discounted present value by the discounted future income taxes associated with such reserves.

Reconciliation of PV-10
($ in millions)
(unaudited)

		December 31,
		2010
Standardized measure of discounted future net of cash flows		$	3,479
Discounted future cash flows for income taxes			1,168
Discounted future net cash flows before income taxes (PV-10)		$	4,647

Range has disclosed a debt-adjusted per share metric in this release to measure per-share growth of production and reserves. This debt-adjusted metric keeps the debt-to-capitalization ratio unchanged during the calculation period. To achieve a constant debt-to-capitalization ratio, the share count is adjusted to increase/decrease equity from the actual end-of-year to the beginning of period level debt-to-cap. This adjustment is made by

dividing the necessary increase/decrease in equity by the average common share price during the year for production (year-end price for reserves) to arrive at shares issued/repurchased. The production or reserves are then divided by this adjusted share count to reach the debt-adjusted per share results.

Hedging and Derivatives

In this news release, Range has reclassified within total revenues its financial reporting of the cash settlement of its commodity derivatives. Under this presentation those hedges considered “effective” under ASC 815 are included in “Natural gas, NGL and oil sales” when settled. For those hedges designated to regions where the historical correlation between NYMEX and regional prices is “non-highly effective” or is “volumetric ineffective” due to sale of the underlying reserves, they are deemed to be “derivatives” and the cash settlements are included in a separate line item shown as “Derivative fair value income (loss)” in the consolidated statements of operations included in the Company’s Form 10-K along with the change in mark-to-market valuations of such unrealized derivatives. The Company has provided additional information regarding natural gas, NGL and oil sales in a supplemental table included with this release, which would correspond to amounts shown by analysts for natural gas, NGL and oil sales realized, including cash-settled derivatives.

RANGE RESOURCES CORPORATION (NYSE: RRC) is an independent natural gas company operating in the Appalachian and Southwestern regions of the United States.

Except for historical information, statements made in this release such as expected drill-bit finding and development costs, high-quality and high-return projects, attractive returns on capital, expected operating costs, expected production growth, expected capital funding sources, reduction of future unit costs, attractive hedge positions, solid financial position, estimated ultimate recovery and unproved resource potential are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management’s assumptions and Range’s future performance are subject to a wide range of business risks and uncertainties and there is no assurance that these goals and projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward-looking statements, including, but not limited to, the volatility of oil and gas prices, the results of our hedging transactions, the costs and results of drilling and operations, the timing of production, mechanical and other inherent risks associated with oil and gas production, weather, the availability of drilling equipment, changes in interest rates, litigation, uncertainties about reserve estimates and environmental risks. Range undertakes no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in Range’s filings with the Securities and Exchange Commission (“SEC”), which are incorporated by reference.

The SEC permits oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, as well as the option to disclose probable and possible reserves. Range has elected not to disclose the Company’s probable and possible reserves in its filings with the SEC. Range uses certain broader terms such as “resource potential,” or “unproved resource potential” or “upside” or other descriptions of volumes of resources potentially recoverable through additional drilling or recovery techniques that may include probable and possible reserves as defined by the SEC’s guidelines. Range has not attempted to distinguish probable and possible reserves from these broader classifications. The SEC’s rules prohibit us from including in filings with the SEC these broader classifications of reserves. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. Unproved resource potential refers to Range’s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques and have not been reviewed by independent engineers. Unproved resource potential does not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System and does not include proved reserves. Area wide unproven, unrisked resource potential has not been fully risked by Range’s management. Actual quantities that may be ultimately recovered from Range’s interests will differ substantially. Factors affecting ultimate recovery include the scope of Range’s drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling services

and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, field spacing rules, recoveries of gas in place, length of horizontal laterals, actual drilling results, including geological and mechanical factors affecting recovery rates and other factors. Estimates of resource potential may change significantly as development of our resource plays provides additional data. Investors are urged to consider closely the disclosure in our most recent Annual Report on Form 10-K, available from our website at www.rangeresources.com or by written request to 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. You can also obtain this Form 10-K by calling the SEC at 1-800-SEC-0330.

2011-8

Contact:		Rodney Waller, Senior Vice President
		David Amend, Investor Relations Manager
		Laith Sando, Senior Financial Analyst
		(817) 870-2601
		www.rangeresources.com

RANGE RESOURCES CORPORATION

STATEMENTS OF INCOME
Based on GAAP reported earnings with additional
details of items included in each line in Form 10-K

		Three Months Ended December 31,												Twelve Months Ended December 31,
(Unaudited, in thousands, except per share data)		2010				2009								2010				2009
Revenues
Natural gas, NGL and oil sales (a)		$	246,503			$	242,087							$	909,607			$	839,921
Cash-settled derivative gain (loss) (a)(c)			18,758				34,966								35,636				184,051
Early cash-settled derivative gain (c)			—				—								15,697				—
Transportation and gathering			212				(3,418	)							2,271				1,351
Transportation and gathering — non-cash stock compensation (b)			(277	)			(187	)							(1,203	)			(865	)
Change in mark-to-market on unrealized derivatives (c)			(25,971	)			(32,516	)							(2,086	)			(115,909	)
Ineffective hedging gain (loss) (c)			(13	)			(1,213	)							2,387				(1,696	)
Equity method investment (d)			348				(7,151	)							(1,482	)			(13,699	)
Gain (loss) on sale of properties			(1,514	)			10,374								77,597				10,413
Interest and other (d)			672				3,889								551				3,774
			238,718				246,831				-3	%			1,038,975				907,341				15	%
Expenses
Direct operating			35,899				31,487								129,277				130,610
Direct operating — non-cash stock compensation (b)			601				244								2,325				2,601
Production and ad valorem taxes			8,619				8,748								33,652				32,169
Exploration			15,765				9,106								56,878				41,782
Exploration — non-cash stock compensation (b)			978				1,770								4,209				4,703
Abandonment and impairment of unproven properties			23,533				28,959								69,971				113,538
General and administrative			28,330				20,630								99,423				80,714
General and administrative — non-cash stock compensation (b)			7,773				10,548								34,174				33,254
General and administrative — lawsuit settlements			331				—								3,366				—
General and administrative — bad debt expense			3,608				200								3,608				1,351
Termination costs			514				1,307								5,652				2,147
Termination costs — non-cash stock compensation (b)			—				332								2,800				332
Deferred compensation plan (e)			14,978				1,438								(10,216	)			31,073
Interest expense			36,320				30,550								131,192				117,367
Loss on early extinguishment of debt			—				—								5,351				—
Depletion, depreciation and amortization			92,116				103,261								363,507				373,502
Impairment of proved properties			463,244				930								469,749				930
			732,609				249,510				194	%			1,404,918				966,073				45	%
Income (loss) from operations before income taxes			(493,891	)			(2,679	)		NM					(365,943	)			(58,732	)			-523	%
Income tax (benefit) expense
Current			(826	)			(560	)							(836	)			(636	)
Deferred			(175,346	)			14,658								(125,851	)			(4,226	)
			(176,172	)			14,098								(126,687	)			(4,862	)
Net income (loss)		$	(317,719	)		$	(16,777	)		NM				$	(239,256	)		$	(53,870	)			-344	%
(Loss) income per common share
Basic		$	(2.02	)		$	(0.11	)		NM				$	(1.53	)		$	(0.35	)			-337	%
Diluted		$	(2.02	)		$	(0.11	)		NM				$	(1.53	)		$	(0.35	)			-337	%
Weighted average common shares outstanding, as reported
Basic			157,162				155,275				1	%			156,874				154,514				2	%
Diluted			157,162				155,275				1	%			156,874				154,514				2	%

RANGE RESOURCES CORPORATION

BALANCE SHEETS

		December 31,				December 31,
		2010				2009
(in thousands)		(Audited)				(Audited)
Assets
Current assets		$	130,264			$	153,735
Current unrealized derivative gain			131,450				21,545
Natural gas and oil properties			4,922,057				4,898,819
Transportation and field assets			74,733				91,835
Unrealized derivative gain			—				4,107
Other			240,082				225,840
		$	5,498,586			$	5,395,881
Liabilities and Stockholders’ Equity
Current liabilities		$	426,190			$	297,170
Current asset retirement obligation			4,020				2,446
Current unrealized derivative loss			352				14,488
Bank debt			274,000				324,000
Subordinated notes			1,686,536				1,383,833
Total long-term debt			1,960,536				1,707,833
Deferred tax liability			672,041				776,965
Unrealized derivative loss			13,412				271
Deferred compensation liability			134,488				135,541
Long-term asset retirement obligation and other			63,786				82,578
Common stock and retained earnings			2,163,803				2,380,132
Common stock in treasury			(7,512	)			(7,964	)
Accumulated other comprehensive income			67,470				6,421
Total stockholders’ equity			2,223,761				2,378,589
		$	5,498,586			$	5,395,881

RANGE RESOURCES CORPORATION

CASH FLOWS FROM OPERATING ACTIVITIES

		Three Months Ended								Twelve Months Ended
		December 31,								December 31,
(Unaudited, in thousands)		2010				2009				2010				2009
Net income (loss)		$	(317,719	)		$	(16,777	)		$	(239,256	)		$	(53,870	)
Adjustments to reconcile net income to net cash provided from operating activities:
Loss (gain) from equity investment			(348	)			7,151				1,482				13,699
Deferred income tax (benefit) expense			(175,346	)			14,658				(125,851	)			(4,226	)
Depletion, depreciation, amortization and proved property impairment			555,360				104,191				833,256				374,432
Exploration dry hole costs			2,039				1,817				3,700				2,159
Abandonment and impairment of unproved properties			23,533				31,330				69,971				113,538
Mark-to-market (gain) loss on oil and gas derivatives not designated as hedges			25,971				30,145				2,086				115,909
Unrealized derivative (gain) loss			13				1,213				(2,387	)			1,696
Allowance for bad debts			3,608				200				3,608				1,351
Amortization of deferred financing costs and other			1,181				3,465				10,072				8,755
Deferred and stock-based compensation			24,651				14,558				34,964				73,402
(Gain) loss on sale of assets and other			1,514				(10,374	)			(77,597	)			(10,413	)
Changes in working capital:
Accounts receivable			(12,216	)			(37,366	)			(1,937	)			1,007
Inventory and other			2,074				(656	)			(333	)			(1,463	)
Accounts payable			(9,498	)			22,311				2,867				(44,765	)
Accrued liabilities			(10,363	)			(17,959	)			(1,323	)			464
Net changes in working capital			(30,003	)			(33,670	)			(726	)			(44,757	)
Net cash provided from operating activities		$	114,454			$	147,907			$	513,322			$	591,675

RECONCILIATION OF NET CASH PROVIDED FROM OPERATING
ACTIVITIES, AS REPORTED, TO CASH FLOW FROM OPERATIONS
BEFORE CHANGES IN WORKING CAPITAL, a non-GAAP measure

		Three Months Ended								Twelve Months Ended
		December 31,								December 31,
(Unaudited, in thousands)		2010				2009				2010				2009
Net cash provided from operating activities, as reported		$	114,454			$	147,907			$	513,322			$	591,675
Net change in working capital			30,003				33,670				726				44,757
Exploration expense			13,726				7,289				53,178				39,623
Office closing severance/exit accrual			514				1,307				5,652				2,147
Lawsuit settlements			331				—				3,366				—
Non-cash compensation and other			226				(1,984	)			610				(3,867	)
Cash flow from operations before changes in working capital, a non-GAAP measure		$	159,254			$	188,189			$	576,854			$	674,335

ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING

		Three Months Ended								Twelve Months Ended
		December 31,								December 31,
(Unaudited, in thousands)		2010				2009				2010				2009
Basic:
Weighted average shares outstanding			160,083				157,963				159,708				157,108
Stock held by deferred compensation plan			(2,921	)			(2,688	)			(2,834	)			(2,594	)
			157,162				155,275				156,874				154,514
Dilutive:
Weighted average shares outstanding			160,083				157,963				159,708				157,108
Dilutive stock options under treasury method unless anti-dilutive			(2,921	)			(2,688	)			(2,834	)			(2,594	)
			157,162				155,275				156,874				154,514

RANGE RESOURCES CORPORATION

RECONCILIATION OF NATURAL GAS, NGL AND OIL SALES AND
DERIVATIVE FAIR VALUE INCOME (LOSS) TO CALCULATED
CASH REALIZED NATURAL GAS, NGL AND OIL SALES,
PRODUCTION PRICES AND DIRECT OPERATING CASH COSTS,
non-GAAP measures

		Three Months Ended												Twelve Months Ended
		December 31,												December 31,
		2010				2009								2010				2009
(Unaudited, in thousands, except per unit data)
Natural gas, NGL and oil sales components:
Natural gas sales		$	116,907			$	132,175							$	533,157			$	432,821
NGL sales			63,175				26,950								175,236				63,405
Oil sales			36,820				38,685								136,442				140,577
Cash-settled hedges (effective):
Natural gas			29,601				44,340								64,749				190,934
Crude oil			—				(63	)							23				12,184				—
Total natural gas, NGL and oil sales, as reported		$	246,503			$	242,087				2	%		$	909,607			$	839,921				8	%
Derivative fair value income (loss) components:
Cash-settled derivatives (ineffective):
Natural Gas		$	18,758			$	35,289							$	35,632			$	176,799
Crude oil			—				(323	)							15,701				7,252
Change in mark-to-market on unrealized derivatives			(25,971	)			(32,516	)							(2,086	)			(115,909	)
Unrealized ineffectiveness			(13	)			(1,213	)							2,387				(1,696	)
Total derivative fair value income (loss), as reported		$	(7,226	)		$	1,237							$	51,634			$	66,446
Natural gas, NGL and oil sales, including cash-settled derivatives:
Natural gas sales		$	165,266			$	211,804							$	633,538			$	800,554
NGL sales			63,175				26,950								175,236				63,405
Oil sales			36,820				38,299								152,166				160,013
Total		$	265,261			$	277,053				-4	%		$	960,940			$	1,023,972				-6	%
Production during the period (a):
Natural gas (mcf)			37,713,341				34,442,796				9	%			142,033,758				130,648,694				9	%
NGL (bbl)			1,501,093				694,740				116	%			` 4,490,199				2,186,999				105	%
Oil (bbl)			508,485				569,276				-11	%			1,969,050				2,556,879				-23	%
Gas equivalent (mcfe) (b)			49,770,809				42,026,892				18	%			180,789,252				159,111,962				14	%
Production — average per day (a):
Natural gas (mcf)			409,928				374,378				9	%			389,134				357,942				9	%
NGL (bbl)			16,316				7,552				116	%			12,302				5,992				105	%
Oil (bbl)			5,527				6,188				-11	%			5,395				7,005				-23	%
Gas equivalent (mcfe) (b)			540,987				456,814				18	%			495,313				435,923				14	%
Average prices realized, including cash-settled hedges and derivatives:
Natural gas (mcf)		$	4.38			$	6.15				-29	%		$	4.46			$	6.13				-27	%
NGL (bbl)		$	42.09			$	38.79				9	%		$	39.03			$	28.99				35	%
Oil (bbl) (c)		$	72.41			$	67.28				8	%		$	69.31			$	62.58				11	%
Gas equivalent (mcfe) (b)		$	5.33			$	6.59				-19	%		$	5.23			$	6.44				-19	%
Direct operating cash costs per mcfe (d):
Field expenses		$	0.70			$	0.72				-3	%		$	0.69			$	0.78				-12	%
Workovers			0.02				0.03				-33	%			0.03				0.04				-25	%
Total direct operating cash costs		$	0.72			$	0.75				-4	%		$	0.72			$	0.82				-12	%

RANGE RESOURCES CORPORATION

RECONCILIATION OF INCOME (LOSS) FROM OPERATIONS BEFORE INCOME TAXES
AS REPORTED TO INCOME FROM OPERATIONS BEFORE INCOME TAXES
EXCLUDING CERTAIN ITEMS, a non-GAAP measure

		Three Months Ended												Twelve Months Ended
		December 31,												December 31,
		2010				2009								2010				2009
(Unaudited, in thousands, except per share data)
Income (loss) from operations before income taxes, as reported		$	(493,891	)		$	(2,679	)		NM				$	(365,943	)		$	(58,732	)			523	%
Adjustment for certain non-cash items
(Gain) loss on sale of properties			1,514				(10,374	)							(77,597	)			(10,413	)
Equity method impairment			—				6,000								—				8,950
Change in mark-to-market on unrealized derivatives (gain) loss			25,971				32,516								2,086				115,909
Unrealized derivative (gain) loss			13				1,213								(2,387	)			1,696
Abandonment and impairment of unproven properties			23,533				28,959								69,971				113,538
Loss on early extinguishment of debt			—				—								5,351				—
Proved property impairment and accelerated depreciation on interim plant			463,244				11,269								469,749				11,269
Termination costs			514				1,639								8,452				2,479
Lawsuit settlements			331				—								3,366				—
Transportation and gathering — non-cash stock compensation			277				187								1,203				865
Direct operating — non-cash stock compensation			601				244								2,325				2,601
Exploration expenses — non-cash stock compensation			978				1,770								4,209				4,703
General & administrative — non-cash stock compensation			7,773				10,548								34,174				33,254
Deferred compensation plan — non-cash stock compensation			14,978				1,438								(10,216	)			31,073
Income from operations before income taxes, as adjusted			45,836				82,730				-45	%			144,743				257,192				-44	%
Income tax expense, adjusted
Current			(826	)			(560	)							(836	)			(636	)
Deferred			16,257				31,495								56,264				92,951
Net income excluding certain items, a non-GAAP measure		$	30,405			$	51,795				-41	%		$	89,315			$	164,877				-46	%
Non-GAAP income per common share
Basic		$	0.19			$	0.33				-42	%		$	0.57			$	1.07				-47	%
Diluted		$	0.19			$	0.32				-41	%		$	0.56			$	1.04				-46	%
Non-GAAP diluted shares outstanding, if dilutive			160,707				159,513								158,428				158,778

HEDGING POSITION
As of February 28, 2011

				Gas				Oil
				Volume		Average		Volume		Average
				Hedged		Hedge		Hedged		Hedge
				(Mmbtu/d)		Prices		(Bbl/d)		Prices
(Unaudited)
1Q2011		Collars		408,200		$5.56 - $6.48		—		—
1Q2011		Calls		—		—		5,500		$80.00
2Q2011		Collars		408,200		$5.56 - $6.48		—		—
2Q2011		Calls		—		—		5,500		$80.00
3Q2011		Collars		408,200		$5.56 - $6.48		—		—
3Q2011		Calls		—		—		5,500		$80.00
4Q2011		Collars		438,200		$5.47 - $6.38		—		—
4Q2011		Calls		—		—		5,500		$80.00
2012		Collars		119,641		$5.50 - $6.25		2,000		$70.00 - $80.00
2012		Calls		—		—		4,700		$85.00

Note:		Details as to the Company’s hedges are posted on its website and are updated periodically. See website for Supplemental Tables 6 and 7 detailing any premiums paid or received in connection with the hedges above.

SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS