Exhibit 99.1

NEWS RELEASE

RANGE ANNOUNCES THIRD QUARTER 2011 RESULTS

FORT WORTH, TEXAS, OCTOBER 25, 2011...RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its third quarter 2011 financial results. The favorable third quarter results were driven by higher production volumes, higher realized prices and lower unit costs. Reported GAAP net income for third quarter 2011 totaled $34.8 million ($0.21 per diluted share), up from a loss of $8.2 million ($0.05 per diluted share) for the prior year quarter. Net cash provided from operating activities including changes in working capital totaled $100.2 million for the third quarter versus $140.1 million for the prior year quarter. Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $44.7 million ($0.28 per diluted share), versus $18.9 million ($0.12 per diluted share) for the prior year quarter. Cash flow from operations before changes in working capital, a non-GAAP measure, increased 35% year-over-year to $190.0 million. Comparing these amounts to analysts’ average First Call consensus estimates, the Company’s earnings per share ($0.28 per diluted share) was greater than the consensus of analysts’ estimates of $0.23 per diluted share and cash flow per share ($1.19 per diluted share) for the quarter was greater than the consensus analysts’ estimates of $1.07 per diluted share. 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.

The third quarter results reflect a 7% increase in production, a 15% increase in realized prices and a 9% decrease in the unit costs of the Company’s five largest cost categories compared to the prior year quarter. As previously announced, production averaged 537.2 Mmcfe net per day. Production was 76% natural gas, 17% natural gas liquids (NGLs) and 7% crude oil. Targeted drilling to Range’s liquids-rich plays increased the Company’s liquid production by almost 12% between years. Realized prices, including all cash-settled derivatives, averaged $5.73 per mcfe, a 15% increase over the prior year quarter. The increase in the average per mcfe prices was primarily due to strong NGL and oil prices as well as liquids making up a larger percentage of the production mix. During the third quarter, the Company continued to drive down its unit costs. In aggregate, the Company’s five largest cost categories, direct operating, production taxes, general and administrative, interest and depreciation, depletion and amortization, decreased 9% on a unit of production basis as compared to the prior year quarter. The most significant cost declines related to direct operating costs, production taxes and general and administrative expenses.

Range also announced that it has increased its year-over-year 2011 production growth target by ten percent from 10% to 11% for the year. Fourth quarter 2011 production guidance has been set at 608 Mmcfe per day. The fourth quarter production guidance represents a 12% increase over actual production in the prior year quarter. Adjusted for the Barnett sale, the fourth quarter production guidance represents a 43% increase over the prior year. Range also fine tuned its capital spending estimate for 2011 from $1.38 billion to $1.47 billion, a 6.5% increase. The additional capital spending is attributable to non-operated drilling activities in the Marcellus, Ardmore Woodford and Cana Woodford shale plays as well as leasehold acquisition costs related to the Mississippian horizontal play in Oklahoma.

Commenting on the announcement, John Pinkerton, Range’s Chairman and CEO, said, “Third quarter results reflect terrific operating performance driving excellent financial performance. Higher production and higher realized prices combined with significantly lower unit costs drove a 35% increase in cash flow and more than doubled the analysts’ earnings compared to the third quarter of last year. Due to our outstanding drilling results and the progress of the infrastructure build-out, we have increased our full year 2011 production growth target by 10%. Looking to the fourth quarter, we anticipate total production to jump 70 Mmcfe per day over the third quarter and for our Marcellus production to reach our exit rate goal of 400 Mmcfe per day net. Given the momentum of the higher production coupled with the cost reductions, we anticipate fourth quarter results to exceed those of the third quarter. In turn, these results should give our shareholders a good indication of how accelerating production growth and continued reduction in unit costs will positively impact our ongoing results. We believe these are the key elements that will drive our results for 2012 and beyond.”

Financial Discussion —

(Except for reported GAAP amounts, specific expense categories exclude non-cash property impairments, mark-to-market on unrealized derivatives, non-cash stock compensation and other items shown separately on attached tables but include the results associated with Barnett Shale properties combined with the reported continuing operations amounts.)

As previously announced, Range closed substantially all of the Barnett Shale property sale at the end of April and the remainder of the sale during the third quarter. Under generally accepted accounting principles (GAAP), the Barnett Shale properties have been reclassified as “Discontinued operations” for the quarter and for the prior-year comparable period. As a result, production, revenue and expenses associated with the properties have been removed from continuing operations and reclassified to discontinued operations. In this release, Range has included Statements of Operations that reconcile and reclassify Barnett Shale discontinued operations into continuing operations for comparative purposes. These supplemental non-GAAP tables present the reported GAAP amounts as compared to the amounts that would have been reported if the Barnett Shale operations were included in continuing operations. All variances discussed in this release include the Barnett Shale operations as continuing operations in the current year and the prior year periods.

For the quarter, production averaged 537.2 Mmcfe per day, comprised of 410.5 Mmcf per day of gas (76%), 15,429 barrels per day of natural gas liquids (17%) and 5,680 barrels per day of oil (7%). Due to continued drilling success in the Marcellus Shale and Midcontinent areas, the Company’s liquids production increased 12% over the prior year period, while natural gas production grew 5%. Realized prices, including all cash-settled derivatives, averaged $5.73 per mcfe, a 15% increase over the prior-year quarter of $4.97. The increase in the average per mcfe price was due to a greater proportion of liquids in the total production mix and stronger NGL and crude oil prices. The average realized natural gas liquids price increased 45% to $49.52 a barrel versus the prior-year quarter, while the average oil price rose 22% to $81.70 a barrel. The average realized natural gas price was $4.51 per mcf, 4% higher than the prior-year quarter. Reported GAAP natural gas, NGL and oil sale revenues for the quarter were $271.8 million, an increase of 45% as compared to the prior year excluding sales from the Barnett Shale properties shown as discontinued operations. Total natural gas, NGL and oil sales (including all cash settled derivatives and the Barnett Shale properties) increased 23% compared to the prior-year quarter to $283.3 million resulting from higher volumes and prices. Total revenues include $9.4 million of cash proceeds for natural gas hedges that were included in the Barnett Shale property sale. Under GAAP, the proceeds of these hedges are recognized as the hedges are settled. The final $9.4 million of cash proceeds associated with these natural gas hedges will be recognized in the fourth quarter. Natural gas liquids realized prices include $3.1 million of cash-settled hedging gains for the quarter. These cash proceeds represent the first NGL hedges to be settled during 2011.

During the third quarter of 2011, Range continued to lower its cost structure. On a unit of production basis the Company’s five largest cost categories fell by 9% in aggregate compared to the prior-year period with each of the five components showing meaningful improvements. Direct operating expenses dropped 20% to $0.58 per mcfe, production tax expense decreased 23% to $0.15 per mcfe, general and administrative expense fell 12% to $0.53 per mcfe, interest expense declined 5% to $0.69 per mcfe and depreciation, depletion and amortization expense decreased 4% to $1.89 per mcfe.

In addition to the final closing of the Barnett Shale property sale in the third quarter for $12 million in proceeds, the Company also sold producing properties located in East Texas for $11.0 million and some shallow coal bed methane properties in Pennsylvania for $6.0 million. An impairment charge of $31.2 million was recognized on the properties. An additional $7.5 million impairment was recognized on certain minor Gulf Coast dry gas properties due to low commodity prices at quarter end.

Capital Expenditures —

Third quarter drilling expenditures of $352.4 million funded the drilling of 77 (64 net) wells and the completion of previously drilled wells. A 100% drilling success rate was achieved. During the third quarter, total capital expenditures were $473.5 million which included $77.5 million on acreage acquisition and $25.5 million on infrastructure build-out primarily on non-operated properties. For the first nine months of 2011, Range has drilled 223 (197 net) wells and spent $900.8 million on drilling and recompletions. In addition, during the first

nine months of 2011, $145.1 million was expended on acreage, $37.3 million on gas gathering systems and $53.3 million for exploration expense (includes $26.2 million for seismic, $14.2 million for delay rentals and $2.5 million for dry hole costs). During the third quarter, approximately $100 million was expended on our non-operated properties and leasehold acquisitions.

Credit Facility —

Last week, lenders under Range’s revolving credit facility completed their regular semi-annual redetermination of the borrowing base, voting unanimously to reaffirm the $2.0 billion borrowing base and aggregate commitment of $1.5 billion. The facility is comprised of commitments from a diverse group of 26 financial institutions with no institution holding more than 7% of total commitments. The next borrowing base redetermination is scheduled for April 1, 2012. At the end of the third quarter, Range has $52 million of invested cash on hand and no amount outstanding on the credit facility.

Operational Discussion —

Marcellus Shale Division

Significant progress was made on multiple fronts in the Marcellus Shale and the division is solidly on track to reach the 2011 year-end production target of 400 Mmcfe per day net to Range. Currently, total production from the Marcellus Shale is running approximately 350 Mmcfe per day net to Range. In southwest Pennsylvania, Range drilled 42 wells during the third quarter. During the quarter, a total of 28 wells were turned to sales bringing the total horizontal Marcellus wells producing in the southwest to 214 wells. At the end of the third quarter, there were 12 wells waiting on pipeline and 74 wells waiting on completion in the southwest. In northeast Pennsylvania, Range drilled 14 wells during the third quarter. A total of 10 wells were turned to sales during the third quarter. At quarter-end, there were 15 wells on production in the northeast with 11 wells waiting on pipeline and 22 wells waiting on completion.

In addition to the operational progress in the Marcellus, Range made substantial progress during the quarter regarding infrastructure build-out and marketing arrangements. Below are the key accomplishments achieved during the third quarter.

	•		During the third quarter, an additional 40 Mmcf per day of fully dedicated cryogenic gas processing capacity was brought on line increasing Range’s total dedicated processing capacity to 390 Mmcf per day. In addition to the committed capacity, Range currently has access to approximately 100 Mmcf per day of interruptible processing capacity.
	•		Phase I of the Lycoming trunkline system in northeast Pennsylvania was completed and Phase II is expected to be completed by the end of 2011. Additional phases are planned to complete Range’s expected development in Lycoming County. The trunkline will give 350 Mmcf per day of capacity flowing into the Transco system moving gas into and out of the Leidy storage complex.
	•		Range accomplished a key element in the development of its liquid-rich Marcellus play by signing its first ethane sales contract. The contract with NOVA Chemicals Corporation was signed at the conclusion of the binding open season of the Mariner West Project. The project was the culmination of years of planning and will ensure that Range can continue accelerating its Marcellus Shale development plans. The first sales under the contract are targeted to occur in late 2013. Anticipating Range’s ethane production growth, numerous petrochemical companies, both domestic and international, have approached the Company as potential customers.

•

Late in the third quarter, Range began receiving an incremental NGL pricing uplift when the C3+ fractionation facility was completed at the gas processing facility located in Houston, Pennsylvania. This complex allows for the production of 60,000 barrels per day of purity propane, butane, and natural gasoline for sale into the premium Northeast markets. As a result, Range’s realizations should improve since the liquids will no longer be required to be trucked or railed offsite to be

fractionated. Range expects that the railroad siding at the Houston, Pennsylvania plant will be fully operational in the near future allowing for the direct rail shipment of purity NGL products to customers. Until then, trucks will transload to rail cars at a nearby facility that will significantly reduce the freight costs. With the start-up of the rail facilities, Range believes it will be able to fully realize the expected uplift in incremental NGL pricing of $12 to $15 million annually by the elimination of all intermediate transportation charges before freight cost to the customers.

•

Basis during the third quarter in the southwest area of the Marcellus continued to be in the flat to positive $0.08 per mcf range above the NYMEX Henry Hub index price depending on bid week quotes and daily swing gas spot markets. In the northeast along the Transco-Leidy transmission system, basis during the third quarter continued in the positive $0.10 to $0.15 per mcf above the NYMEX Henry Hub index price depending on bid week quotes and daily swing gas spot markets. Currently, Range has commitments in the southwest portion of the Marcellus for over 420 Mmcf per day to transport natural gas to markets either with Range-owned firm transportation or firm sales arrangements with customers who hold firm transportation. Transportation commitments in the southwest are planned to increase to 550 Mmcf per day during 2012 to accommodate the expected increased production from that region. In the northeast Marcellus along the Transco-Leidy transmission line, Range currently has commitments of 80 Mmcf per day increasing to 100 Mmcf per day during 2012 in the form of firm sales arrangements with customers owning existing firm transportation on Transco and storage at Leidy. Range believes that our existing firm sales arrangements both in the southwest and the northeast can be further increased as it demonstrates that additional production volumes are available.

Midcontinent Division

Third quarter activity in the Midcontinent Division focused on the Texas Panhandle St. Louis play, as well as increased leasing in the Mississippian horizontal play of northern Oklahoma. Two offset St. Louis horizontal wells were added in the Texas Panhandle at combined rates of 20.4 Mmcf of natural gas and 1,394 barrels of liquids per day or 28.8 (13.1 net) Mmcfe per day based on 24-hour test rates. The original discovery well, which was placed on production in January of this year, continues producing at rates of 11.2 Mmcf of natural gas and 694 barrels of liquids per day or 15.4 (4.7 net) Mmcfe per day. The cumulative production for the discovery well is 4.6 Bcfe. Drilling activity continues in the play with two additional St. Louis offsets scheduled to be drilled during the fourth quarter. In the Woodford play of the Ardmore Basin, three wells were connected to sales during the quarter at combined rates of 2,738 gross (1,307 net) boe per day. Activity by other companies in the Cana Woodford is further de-risking our held by production leasehold position of 42,000 net acres in the play. Range has participated in three non-operated wells in the Cana during the year.

Leasing activity expanded during the quarter in the Mississippian horizontal play of northern Oklahoma. Having started the year with 15,000 net acres, Range’s position has increased to 105,000 net acres. Reserve projections are estimated in the range of 400-500 Mboe per well for approximately 2,000 foot laterals at depths of 5,000 feet. These potential reserves generate attractive finding and development costs, along with strong rates of return in this liquids-rich play. Range’s production from the Mississippi horizontal area continues to hold at 3,400 gross (2,709 net) boe per day. With its larger acreage position, Range is targeting a two rig drilling program in 2012 and is currently focused on adding the necessary infrastructure to facilitate future development.

Appalachia Division

The Appalachian Division continued development of its 350,000 (235,000 net) acre position in Virginia during the third quarter of 2011. Range owns the gas rights on 216,000 royalty acres of this position and receives the added economic benefit of the royalty for wells drilled on this acreage. The division averaged three drilling rigs running in the quarter with activity focused on tight gas sand and horizontal drilling projects in Nora. The division drilled 10 (10 net) vertical and 10 (10 net) horizontal wells in the quarter. The horizontal wells targeted the Huron Shale and Berea Sandstone in the Nora field. Over the past three years, Range has continued to optimize horizontal drilling operations in these formations by reducing the number of drilling days and corresponding well cost while at the same time increasing lateral length by 30%. With increased lateral length, Range has also increased the number of frac stages per well to effectively stimulate the formation. The initial 30- day average production from these longer laterals is 40% higher than the average of earlier drilled horizontals. Through longer laterals and more frac stages, we have improved our estimated ultimate recoveries from

about 1 Bcf per well up to 1.3 Bcf per well while keeping our cost at $1.2 million. Also in the quarter, Range performed seven recompletions of behind-pipe pays in its continued efforts to maximize production on existing wells.

Hedging Position as of October 25, 2011

										Premium (Paid)
		Daily Volume				Hedge Price				/ Received
Gas (Mmbtu)
3Q 2011 Collars			318,200			$	5.43 - $6.29				($0.40	)
4Q 2011 Collars			348,200			$	5.33 - $6.18				($0.37	)
2012 Swaps			70,000			$	5.00				($0.04	)
2012 Collars			189,641			$	5.32 - $5.91				($0.28	)
2013 Collars			160,000			$	5.09 - $5.65				—
Oil (Bbls)
3Q 2011 Calls			5,500			$	80.00			$	10.37
4Q 2011 Calls			5,500			$	80.00			$	10.37
2012 Collars			2,000			$	70.00 - $80.00			$	7.50
2012 Calls			4,700			$	85.00			$	13.71
NGL (Bbls)
3Q 2011 Swaps			7,000			$	104.17				—
4Q 2011 Swaps			7,000			$	104.17				—
2012 Swaps			5,000			$	102.59				—

Conference Call Information —

The Company will host a conference call on Wednesday, October 26 at 1:00 p.m. ET to review the third quarter results. To participate in the call, please dial 877-407-0778 and ask for the Range Resources’ third quarter earnings conference call. A replay of the call will be available through December 11. To access the phone replay dial 877-660-6853. The account number is 286 and the conference ID is 381259. Additional financial and statistical information about the period not included in this release but discussed on the conference call will be available on our home page at www.rangeresources.com.

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 until January 26.

Non-GAAP Financial Measures and Supplemental Tables —

Adjusted net income comparable to analysts’ estimates as used in this release represents income from continuing operations before income taxes adjusted for certain 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 income or loss from continuing 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.

Third quarter 2011 earnings included income of $55.0 million for the non-cash unrealized mark-to-market increase in value of the Company’s derivatives, loss of $8.7 million recorded for the mark-to-market in

the deferred compensation plan for the increase in the Company’s common stock during the period and $10.2 million of non-cash stock compensation expense, $38.7 million of proved property impairment reflecting lower gas prices related to Gulf Coast properties and the sold East Texas properties, and an unproved property impairment expense of $16.6 million. Excluding these items, net income would have been $44.7 million or $0.28 per share ($0.28 fully diluted). Excluding similar non-cash items from the prior-year quarter, net income would have been $18.9 million or $0.12 per share ($0.12 fully diluted). By excluding these non-cash items from our reported earnings, we believe we present our earnings in a manner consistent with the presentation used by analysts in their projection of the Company’s earnings. (See the reconciliation of non-GAAP earnings in the accompanying table.)

“Cash flow from operations before changes in working capital” as used 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 operating, 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 from operating activities” 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 Statements of Operations. The Company believes that it is important to furnish a table reflecting the details of the various components of each line in the statements of operations 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 reader’s understanding and fully disclose the information needed.

The Company discloses in this release the detail components of many of the single line items shown in the GAAP financial statements included in the Company’s Quarterly Report on Form 10-Q. The Company believes that it is important to furnish this detail of the various components comprising each line of the Statements of Operations to better inform the reader the details of each amount, the changes between periods and the effect on its financial results.

Hedging and Derivatives —

In this release, Range has reclassified within total revenues its 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 there is “volumetric ineffectiveness” due to the 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” in the Form 10-Q 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 all cash-settled derivatives.

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

Except for historical information, statements made in this release such as attractive returns on capital, expected operating costs, expected production growth, expected capital funding sources, expectation of exceptional results in subsequent periods, expected reduction of future unit costs, attractive hedge positions and expansion of plays 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, environmental risks and regulatory changes. 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.

SOURCE:		Range Resources Corporation Main number: 817-870-2601

Investor Contacts:

Rodney Waller, Senior Vice President
817-869-4258

David Amend, Investor Relations Manager
817-869-4266

Laith Sando, Senior Financial Analyst
817-869-4267

or

Media Contact:

Matt Pitzarella, Director of Corporate Communications
724-873-3224

www.rangeresources.com

RANGE RESOURCES CORPORATION

STATEMENTS OF OPERATIONS
Based on GAAP reported earnings with additional
details of items included in each line in Form 10-Q
(Unaudited, in thousands, except per share data)

		Three Months Ended September 30,												Nine Months Ended September 30,
		2011				2010								2011				2010
Revenues and other income:
Natural gas, NGL and oil sales (a)		$	271,799			$	187,757							$	755,367			$	548,583
Derivative cash settlements gain (loss) (a) (c)			10,742				10,179								8,342				16,878
Gain on early settlement of oil collars (c)			—				15,697								—				15,697
Transportation and gathering			1,191				(1,357	)							1,195				2,030
Transportation and gathering — non-cash stock compensation (b)			(375	)			(283	)							(1,107	)			(926	)
Change in mark-to-market on unrealized derivatives gain (loss) (c)			58,990				(18,284	)							67,093				23,885
Ineffective hedging gain (loss) (c)			(3,971	)			2,389								2,531				2,400
Gain (loss) on sale of properties			203				67								(1,280	)			78,156
Equity method investment (d)			(640	)			(845	)							(1,399	)			(1,830	)
Other (d)			266				(165	)							1,668				(118	)
Total revenues and other income			338,205				195,155				73	%			832,410				684,755				22	%
Costs and expenses:
Direct operating			29,365				24,991								85,638				67,073
Direct operating — non-cash stock compensation (b)			463				544								1,416				1,469
Production and ad valorem taxes			7,317				6,903								21,746				19,108
Exploration			16,704				14,202								53,217				40,553
Exploration — non-cash stock compensation (b)			902				1,023								3,168				3,231
Abandonment and impairment of unproved properties			16,627				14,435								52,064				30,713
General and administrative			26,398				28,233								80,814				71,093
General and administrative — non-cash stock compensation (b)			8,491				7,821								27,488				26,401
General and administrative — lawsuit settlements			168				469								238				3,035
General and administrative — bad debt expense			850				—								446				—
Termination costs			—				—								—				5,138
Termination costs — non-cash stock compensation (b)			—				—								—				2,800
Deferred compensation plan (e)			8,717				(5,347	)							33,569				(25,194	)
Interest expense			34,181				23,363								90,343				65,565
Loss on early extinguishment of debt			(4	)			5,351								18,576				5,351
Depletion, depreciation and amortization			93,619				69,730								244,129			$	202,350
Impairment of proved property			38,681				—								38,681				6,505
Total costs and expenses			282,479				191,718				47	%			751,533				525,191				43	%
Income from continuing operations before income taxes			55,726				3,437				1,521	%			80,877				159,564				-49	%
Income tax expense:
Current			(7	)			(10	)							1				(10	)
Deferred			22,547				794								35,345				61,569
			22,540				784								35,346				61,559
Income from continuing operations			33,186				2,653				1,151	%			45,531				98,005				-54	%
Discontinued operations, net of tax			1,569				(10,821	)							15,484				(19,542	)
Net income (loss)		$	34,755			$	(8,168	)			526	%		$	61,015			$	78,463				-22	%
Income (Loss) Per Common Share:
Basic-Income (loss) from continuing operations		$	0.21			$	0.02							$	0.28			$	0.61
Discontinued operations			0.01				(0.07	)							0.10				(0.12	)
Net income (loss)		$	0.22			$	(0.05	)			540	%		$	0.38			$	0.49				-22	%
Diluted-Income (loss) from continuing operations		$	0.20			$	0.02							$	0.28			$	0.61
Discontinued operations			0.01				(0.07	)							0.10				(0.12	)
Net income (loss)		$	0.21			$	(0.05	)			520	%		$	0.38			$	0.49				-22	%
Weighted average common shares outstanding, as reported:
Basic			158,154				157,109				1	%			157,901				156,777				1	%
Diluted			159,322				158,184				1	%			158,939				158,493				0	%

(a)		See separate natural gas, NGL and oil sales information table.
(b)		Costs associated with stock compensation and restricted stock amortization, which have been reflected in the categories associated with the direct personnel costs, which are combined with the cash costs in the 10-Q.
(c)		Included in Derivative fair value income in the 10-Q.
(d)		Included in Other revenues in the 10-Q.
(e)		Reflects the change in market value of the vested Company stock held in the deferred compensation plan.

RANGE RESOURCES CORPORATION

STATEMENTS OF OPERATIONS
Restated for Barnett discontinued operations,
a non-GAAP presentation
(Unaudited, in thousands, except per share data)

		Three Months Ended September 30, 2011												Three Months Ended September 30, 2010
						Barnett												Barnett
						Discontinued				Including								Discontinued				Including
		As reported				Operations				Barnett Ops				As reported				Operations				Barnett Ops
Revenues:
Natural gas, NGL and oil sales		$	271,799			$	723			$	272,522			$	187,757			$	31,803			$	219,560
Derivative cash settlements gain (loss)			10,742				—				10,742				10,179				—				10,179
Gas on early settlement of oil collars			—				—				—				15,697				—				15,697
Transportation and gathering			1,191				—				1,191				(1,357	)			6				(1,351	)
Transportation and gathering — non-cash stock compensation			(375	)			—				(375	)			(283	)			—				(283	)
Change in mark-to-market on unrealized derivatives gain (loss)			58,990				—				58,990				(18,284	)			—				(18,284	)
Ineffective hedging gain (loss)			(3,971	)			—				(3,971	)			2,389				—				2,389
Gain (loss) on sale of properties			203				1,032				1,235				67				—				67
Equity method investment			(640	)			—				(640	)			(845	)			—				(845	)
Interest and other			266				—				266				(165	)			(3	)			(168	)
			338,205				1,755				339,960				195,155				31,806				226,961
Expenses:
Direct operating			29,365				(611	)			28,754				24,991				8,690				33,681
Direct operating — non-cash stock compensation			463				—				463				544				62				606
Production and ad valorem taxes			7,317				(44	)			7,273				6,903				1,970				8,873
Exploration			16,704				—				16,704				14,202				11				14,213
Exploration — non-cash stock compensation			902				—				902				1,023				—				1,023
Abandonment and impairment of unproved properties			16,627				—				16,627				14,435				6,099				20,534
General and administrative			26,398				—				26,398				28,233				—				28,233
General and administrative — non-cash stock compensation			8,491				—				8,491				7,821				—				7,821
General and administrative — lawsuit settlements			168				—				168				469				—				469
General and administrative — bad debt expense			850				—				850				—				—				—
Termination costs			—				—				—				—				—				—
Termination costs — non-cash stock compensation			—				—				—				—				—				—
Deferred compensation plan			8,717				—				8,717				(5,347	)			—				(5,347	)
Interest expense			34,181				—				34,181				23,363				10,443				33,806
Loss on early extinguishment of debt			(4	)			—				(4	)			5,351				—				5,351
Depletion, depreciation and amortization			93,619				—				93,619				69,730				22,038				91,768
Impairment of proved properties			38,681				—				38,681				—				—				—
			282,479				(655	)			281,824				191,718				49,313				241,031
Income (loss) from continuing operations before income taxes			55,726				2,410				58,136				3,437				(17,507	)			(14,070	)
Income tax expense (benefit):
Current			(7	)			—				(7	)			(10	)			—				(10	)
Deferred			22,547				841				23,388				794				(6,686	)			(5,892	)
			22,540				841				23,381				784				(6,686	)			(5,902	)
Income (loss) from continuing operations			33,186				1,569				34,755				2,653				(10,821	)			(8,168	)
Discontinued operations-Barnett Shale, net of tax			1,569				(1,569	)			—				(10,821	)			10,821				—
Net income (loss)		$	34,755			$	—			$	34,755			$	(8,168	)		$	—			$	(8,168	)
OPERATING HIGHLIGHTS
Average daily production:
Natural gas (mcf)			406,977				3,525				410,501				297,286				92,042				389,328
NGL (bbl)			15,550				(120	)			15,429				11,516				2,395				13,911
Oil (bbl)			5,686				(6	)			5,680				4,926				87				5,012
Gas equivalent (mcfe)			534,388				2,769				537,157				395,936				106,929				502,865
Average prices realized:
Natural gas (mcf)		$	4.52			$	3.12			$	4.51			$	4.80			$	2.85			$	4.34
NGL (bbl)		$	49.31			$	21.71			$	49.52			$	34.40			$	32.29			$	34.04
Oil (bbl)		$	81.72			$	98.13			$	81.70			$	66.74			$	72.66			$	66.84
Gas equivalent (mcfe)		$	5.75			$	2.84			$	5.73			$	5.43			$	3.23			$	4.97
Direct operating cash costs per mcfe:
Field expenses		$	0.57			$	—			$	0.55			$	0.67			$	0.84			$	0.71
Workovers			0.03			$	—				0.03				0.02				0.04				0.02
Total operating costs		$	0.60			$	—			$	0.58			$	0.69			$	0.88			$	0.73

RANGE RESOURCES CORPORATION

STATEMENTS OF OPERATIONS
Restated for Barnett discontinued operations,
a non-GAAP presentation
(Unaudited, in thousands, except per share data)

		Nine Months Ended September 30, 2011												Nine Months Ended September 30, 2010
						Barnett												Barnett
						Discontinued				Including								Discontinued				Including
		As reported				Operations				Barnett Ops				As reported				Operations				Barnett Ops
Revenues:
Natural gas, NGL and oil sales		$	755,367			$	53,757			$	809,124			$	548,583			$	114,521			$	663,104
Derivative cash settlements gain (loss)			8,342				—				8,342				16,878				—				16,878
Gain on early settlement of oil collars			—				—				—				15,697				—				15,697
Transportation and gathering			1,195				6				1,201				2,030				29				2,059
Transportation and gathering — non-cash stock compensation			(1,107	)			—				(1,107	)			(926	)			—				(926	)
Change in mark-to-market on unrealized derivatives gain (loss)			67,093				—				67,093				23,885				—				23,885
Ineffective hedging gain (loss)			2,531				—				2,531				2,400				—				2,400
Gain (loss) on sale of properties			(1,280	)			4,852				3,572				78,156				955				79,111
Equity method investment			(1,399	)			—				(1,399	)			(1,830	)			—				(1,830	)
Interest and other			1,668				4				1,672				(118	)			(3	)			(121	)
			832,410				58,619				891,029				684,755				115,502				800,257
Expenses:
Direct operating			85,638				9,790				95,428				67,073				26,305				93,378
Direct operating — non-cash stock compensation			1,416				45				1,461				1,469				255				1,724
Production and ad valorem taxes			21,746				1,206				22,952				19,108				5,925				25,033
Exploration			53,217				37				53,254				40,553				560				41,113
Exploration — non-cash stock compensation			3,168				—				3,168				3,231				—				3,231
Abandonment and impairment of unproved properties			52,064				—				52,064				30,713				15,725				46,438
General and administrative			80,814				—				80,814				71,093				—				71,093
General and administrative — non-cash stock compensation			27,488				—				27,488				26,401				—				26,401
General and administrative — lawsuit settlements			238				—				238				3,035				—				3,035
General and administrative — bad debt expense			446				—				446				—				—				—
Termination costs			—				—				—				5,138				—				5,138
Termination costs — non-cash stock compensation.			—				—				—				2,800				—				2,800
Deferred compensation plan			33,569				—				33,569				(25,194	)			—				(25,194	)
Interest expense			90,343				14,791				105,134				65,565				29,307				94,872
Loss on early extinguishment of debt			18,576				—				18,576				5,351				—				5,351
Depletion, depreciation and amortization			244,129				8,894				253,023				202,350				69,041				271,391
Impairment of proved properties			38,681				—				38,681				6,505				—				6,505
			751,533				34,763				786,296				525,191				147,118				672,309
Income (loss) from continuing operations before income taxes			80,877				23,856				104,733				159,564				(31,616	)			127,948
Income tax expense (benefit):
Current			1				—				1				(10	)			—				(10	)
Deferred			35,345				8,372				43,717				61,569				(12,074	)			49,495
			35,346				8,372				43,718				61,559				(12,074	)			49,485
Income (loss) from continuing operations			45,531				15,484				61,015				98,005				(19,542	)			78,463
Discontinued operations-Barnett Shale, net of tax.			15,484				(15,484	)			—				(19,542	)			19,542				—
Net income		$	61,015			$	—			$	61,015			$	78,463			$	—			$	78,463
OPERATING HIGHLIGHTS
Average daily production:
Natural gas (mcf)			366,516				43,109				409,625				282,596				99,530				382,126
NGL (bbl)			13,914				793				14,708				8,786				2,163				10,949
Oil (bbl)			5,356				30				5,386				5,248				102				5,350
Gas equivalent (mcfe)			482,138				48,046				530,184				366,804				113,117				479,921
Average prices realized:
Natural gas (mcf)		$	4.58			$	2.93			$	4.48			$	4.87			$	3.40			$	4.49
NGL (bbl)		$	49.39			$	45.86			$	49.20			$	38.30			$	34.19			$	37.49
Oil (bbl)		$	80.53			$	92.00			$	80.59			$	68.11			$	74.19			$	68.23
Gas equivalent (mcfe)		$	5.80			$	3.44			$	5.65			$	5.65			$	3.71			$	5.19
Direct operating cash costs per mcfe:
Field expenses		$	0.63			$	0.73			$	0.64			$	0.64			$	0.81			$	0.68
Workovers			0.02				0.02				0.02				0.03				0.04				0.03
Total operating costs		$	0.65			$	0.75			$	0.66			$	0.67			$	0.85			$	0.71

RANGE RESOURCES CORPORATION

BALANCE SHEETS
(In thousands)

		September 30,				December 31,
		2011				2010
		(Unaudited)				(Audited)
Assets
Current assets		$	151,656			$	100,883
Current assets of discontinued operations			2,626				876,304
Current unrealized derivative gain			136,488				123,255
Natural gas and oil properties			4,846,835				4,084,013
Transportation and field assets			54,264				74,049
Other			284,609				240,082
		$	5,476,478			$	5,498,586
Liabilities and Stockholders’ Equity
Current liabilities		$	401,843			$	393,228
Current asset retirement obligation			4,020				4,020
Current unrealized derivative loss			—				352
Current liabilities of discontinued operations			1,064				32,962
Bank debt			—				274,000
Subordinated notes			1,787,678				1,686,536
Total long-term debt			1,787,678				1,960,536
Deferred tax liability			714,677				672,041
Unrealized derivative loss			—				13,412
Deferred compensation liability			165,810				134,488
Long-term asset retirement obligation and other.			77,633				59,885
Long-term liabilities of discontinued operations			—				3,901
Common stock and retained earnings			2,244,000				2,163,803
Stock in deferred compensation plan and treasury			(6,456	)			(7,512	)
Accumulated other comprehensive income			86,209				67,470
Total stockholders’ equity			2,323,753				2,223,761
		$	5,476,478			$	5,498,586

RANGE RESOURCES CORPORATION

CASH FLOWS FROM OPERATING ACTIVITIES
(Unaudited, in thousands)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
Net income		$	34,755			$	(8,168	)		$	61,015			$	78,463
Adjustments to reconcile net income to net cash provided from operating activities:
(Income) loss discontinued operations			(1,569	)			10,821				(15,484	)			19,542
(Gain) loss from equity investment, net of distributions			5,640				845				24,899				1,830
Deferred income tax expense (benefit)			22,547				795				35,345				61,570
Depletion, depreciation, amortization and proved property impairment			132,300				71,390				282,810				210,516
Exploration dry hole costs			2,509				1,661				2,515				1,661
Abandonment and impairment of unproved properties			16,627				14,435				52,064				30,713
Mark-to-market (gain) loss on oil and gas derivatives not designated as hedges			(58,990	)			18,284				(67,093	)			(23,885	)
Unrealized derivative (gain) loss			3,971				(2,389	)			(2,531	)			(2,400	)
Allowance for bad debts			850				—				446				—
Amortization of deferred financing costs, loss on extinguishment of debt, and other			3,862				6,524				23,753				8,891
Deferred and stock-based compensation			18,598				4,447				66,759				10,313
(Gain) loss on sale of assets and other			(203	)			(67	)			1,280				(78,156	)
Changes in working capital:
Accounts receivable			(25,420	)			(9,796	)			(29,579	)			(1,735	)
Inventory and other			(1,872	)			(2,745	)			875				(2,407	)
Accounts payable			(13,483	)			(1,494	)			(19,705	)			12,365
Accrued liabilities and other			(23,849	)			18,181				(24,285	)			4,143
Net changes in working capital			(64,624	)			4,146				(72,694	)			12,366
Net cash provided from continuing operations			116,273				122,724				393,084				331,424
Net cash provided from discontinued operations			(16,092	)			17,369				20,710				69,106
Net cash provided from operating activities		$	100,181			$	140,093			$	413,794			$	400,530

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
Net cash provided from operating activities, as reported		$	100,181			$	140,093			$	413,794			$	400,530
Net changes in working capital from continuing operations			64,624				(4,146	)			72,694				(12,366	)
Exploration expense			14,195				12,541				50,702				38,892
Office closing severance/exit accrual			—				—				—				5,138
Lawsuit settlements			168				469				238				3,035
Equity method investment distribution			(5,000	)			—				(23,500	)			—
Non-cash compensation adjustment			(1,664	)			(1,515	)			185				(1,533	)
Net changes in working capital from discontinued operations and other			17,470				(6,666	)			7,270				(16,096	)
Cash flow from operations before changes in working capital, a non-GAAP measure		$	189,974			$	140,776			$	521,383			$	417,600

ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING
(Unaudited, in thousands)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
Basic:
Weighted average shares outstanding			161,085				160,038				160,789				159,582
Stock held by deferred compensation plan			(2,931	)			(2,929	)			(2,888	)			(2,805	)
Adjusted basic			158,154				157,109				157,901				156,777
Dilutive:
Weighted average shares outstanding			161,085				160,038				160,789				159,582
Anti-dilutive or dilutive stock options under treasury method			(1,763	)			(1,854	)			(1,850	)			(1,089	)
Adjusted dilutive			159,322				158,184				158,939				158,493

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
(Unaudited, in thousands, except per unit data)

		As Reported, GAAP												Non-GAAP
		Excludes Barnett Operations												Includes Barnett Operations
		Three Months Ended												Three Months Ended
		September 30,												September 30,
		2011				2010				%				2011				2010				%
Natural gas, NGL and oil sales components:
Natural gas sales		$	135,133			$	105,448							$	136,146			$	129,557
NGL sales			67,447				36,450								67,206				43,562
Oil sales			42,461				30,243								42,412				30,825
Cash-settled hedges (effective):
Natural gas			17,346				15,616								17,346				15,616
Crude oil			—				—								—				—
Early cash-settled natural gas hedges sold with Barnett sale			9,412				—								9,412				—
Total natural gas, NGL and oil sales, as reported		$	271,799			$	187,757				45	%		$	272,522			$	219,560				24	%
Derivative fair value income (loss) components:
Cash-settled derivatives (ineffective):
Natural gas		$	7,370			$	10,179							$	7,370			$	10,179
Crude oil			285				15,697								285				15,697
NGLs			3,088				—								3,088				—
Change in mark-to-market on unrealized derivatives			58,990				(18,284	)							58,990				(18,284	)
Unrealized ineffectiveness			(3,971	)			2,389								(3,971	)			2,389
Total derivative fair value income (loss), as reported		$	65,762			$	9,981							$	65,762			$	9,981
Natural gas, NGL and oil sales, including all cash-settled derivatives:
Natural gas sales		$	169,261			$	131,243							$	170,274			$	155,352
NGL sales			70,535				36,450								70,294				43,562
Oil sales			42,746				45,940								42,697				46,522
Total		$	282,542			$	213,633				32	%		$	283,265			$	245,436				15	%
Production during the period (a):
Natural gas (mcf)			37,441,857				27,350,286				37	%			37,766,121				35,818,171				5	%
NGL (bbl)			1,430,568				1,059,485				35	%			1,419,485				1,279,781				11	%
Oil (bbl)			523,074				453,147				15	%			522,572				461,145				13	%
Gas equivalent (mcfe) (b)			49,163,709				36,426,083				35	%			49,418,463				46,263,547				7	%
Production — average per day (a):
Natural gas (mcf)			406,977				297,286				37	%			410,501				389,328				5	%
NGL (bbl)			15,550				11,516				35	%			15,429				13,911				11	%
Oil (bbl)			5,686				4,926				15	%			5,680				5,012				13	%
Gas equivalent (mcfe) (b)			534,388				395,936				35	%			537,157				502,865				7	%
Average prices realized, including cash-settled derivatives and early cash-settled hedges for Barnett:
Natural gas (mcf)		$	4.52			$	4.80				-6	%		$	4.51			$	4.34				4	%
NGL (bbl)		$	49.31			$	34.40				43	%		$	49.52			$	34.04				45	%
Oil (bbl)		$	81.72			$	66.74				22	%		$	81.70			$	66.84				22	%
Gas equivalent (mcfe) (b)		$	5.75			$	5.43				6	%		$	5.73			$	4.97				15	%
Direct operating cash costs per mcfe (c):
Field expenses		$	0.57			$	0.67				-15	%		$	0.55			$	0.71				-23	%
Workovers			0.03				0.02				50	%			0.03				0.02				50	%
Total direct operating cash costs (c)		$	0.60			$	0.69				-13	%		$	0.58			$	0.73				-21	%