EXHIBIT 99.1

NEWS RELEASE

RANGE ANNOUNCES FIRST QUARTER 2012 RESULTS

FORT WORTH, TEXAS, APRIL 25, 2012….RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its first quarter 2012 results. Revenues for the first quarter 2012 totaled $247 million, a 16% increase over the prior year quarter. Net cash provided from operating activities including changes in working capital totaled $156 million, an 11% increase over the prior year first quarter. The net loss for the first quarter 2012 was $42 million ($0.26 loss per diluted share) versus a net loss of $25 million for the first quarter 2011. Revenue and cash flow results were driven by higher production volumes and lower unit costs offset by lower realized prices. Earnings also included the impact of a derivative mark-to-market loss and a onetime retroactive charge for the recently adopted Pennsylvania impact fee.

Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $24 million ($0.15 per diluted share) for first quarter 2012 versus the prior year quarter amount of $35 million ($0.22 per diluted share). Cash flow from operations before changes in working capital, a non-GAAP measure, was $163 million essentially equal to the prior year quarter. Comparing these amounts to analysts’ average First Call consensus estimates, the Company’s earnings per share of $0.15 per diluted share exceeded the consensus of analysts’ estimates of $0.13 per diluted share. Cash flow per share of $1.02 per diluted share also exceeded the consensus analysts’ estimates of $0.97 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.

Commenting on the announcement, Jeff Ventura, Range’s President and CEO, said, “The operational results from the first quarter 2012 demonstrate the progress that Range is making in expanding our liquid-rich development areas. 71% of our total production for the quarter was produced from our liquid-rich and oil projects. We are on track to significantly drive up our liquids production in 2012 while hitting our overall 30% to 35% production growth target. Financially, we held our own as first quarter 2012 cash flow was equal to the prior year quarter. Higher production volumes and lower unit costs offset the impact of lower natural gas prices. We strengthened our balance sheet during the quarter by issuing 5% ten and a half year subordinated notes. This allowed us to end the quarter with $123 million of invested cash and no outstanding amount under our bank credit facility. The combination of the invested cash and the unused credit facility increased our committed liquidity position to nearly $1.6 billion at quarter-end. Subsequent to quarter-end, we also increased our credit facility commitment from $1.5 billion to $1.75 billion and reaffirmed our $2 billion borrowing base. Operationally, we made important progress in all five of our liquids-rich and oil projects: super-rich Marcellus, super-rich Upper Devonian, wet Utica, horizontal Mississippian and Cline Shale. We have worked diligently over the past several years to develop a deep inventory of projects that generate attractive returns even in this period of low natural gas prices. Our financial strength coupled with our high return inventory puts us in an excellent position to continue to deliver per share value for our shareholders.”

During the quarter, 71% of Range’s production came from our liquid-rich and oil areas with only 29% of our production coming from dry gas areas. Production for the first quarter 2012 averaged 655.5 Mmcfe net per day, a record high for the Company, and a 20% increase over the prior-year quarter. Adjusting for the Barnett Shale production sold in April 2011, the increase would have been 50%. This record production was driven by the continued success of the Company’s drilling program. On a year-over-year basis, crude oil production increased 36%, while natural gas liquid (NGL) production rose 20% and natural gas production increased 19%. For the quarter, production was comprised of 512.5 Mmcf per day of gas (78%), 17,152 barrels per day of NGLs (16%) and 6,682 barrels per day of oil (6%).

---

Realized prices, including all cash-settled derivatives averaged $5.19 per mcfe before transportation, gathering and compression costs, a 14% decrease versus the prior-year quarter. The average realized prices by product were $4.01 per mcf for natural gas, $46.20 per barrel for NGLs and $83.54 per barrel for oil. (The realized price, including all cash-settled derivatives, but net of transportation, gathering and compression costs, averaged $4.51 per mcfe for the quarter.)

Financial Discussion –

(Range sold its Barnett Shale properties in April of 2011. Under generally accepted accounting principles, activity in 2011 for the Barnett Shale properties was reclassified as “Discontinued operations.” As a result, production, revenue and expenses associated with the properties were removed from continuing operations and reclassified as discontinued operations. In this release, the Statements of Income are broken out to reconcile and show the changes to the current period and the prior-year period for the reclassification of the discontinued operations. 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 all prior year periods. 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 amounts associated with Barnett Shale properties combined with the reported continuing operations amounts. Effective with 2011 year-end reporting, the Company reclassified only third party transportation, gathering and compression costs as a separate component of operating expenses which previously was included as a reduction of natural gas, natural gas liquids and oil sales. Prior reported results have been similarly reclassified to conform to the current year presentation.)

First quarter financial results were driven by the 20% increase in production and a 6% reduction in unit costs partially offset by a 14% decline in realized prices. Natural gas, NGL and oil revenue (including all cash settled derivatives) was $309.8 million, 24% higher than the prior year quarter of $250.6 million (excluding the Barnett Shale properties sold in April 2011 shown as discontinued operations). Adjusting for the Barnett Shale properties, the year-over-year revenue increase would have been 5%.

During the first quarter of 2012, Range continued to lower its cost structure. On a unit of production basis, the Company’s five largest cost categories fell by 6% in aggregate compared to the prior-year period. Lease operating expense decreased 36% to $0.48 per mcfe, interest expense decreased 15% to $0.62 per mcfe while general and administrative expense decreased 9% to $0.50 per mcfe. Transportation, gathering and compression expense of $0.68 per mcfe increased 23% due to continued expansion of Marcellus infrastructure. Depreciation, depletion and amortization expense rose 2% to $1.68 per mcfe as there was no depletion in March 2011 for discontinued operations related to the Barnett Shale properties.

Several non-cash or non-recurring items impacted first quarter results. A $53.0 million mark-to-market loss was recorded to reflect the reduction in the value of the Company’s commodity hedges due to increased oil and natural gasoline (C5) commodity prices during the quarter. A $24.0 million onetime expense was recorded in the first quarter due to the retroactive payment required under the recently adopted Pennsylvania impact fee for wells drilled in 2011 and prior years. A $10.4 million loss was incurred from the sale of certain East Texas properties. A $7.8 million reduction in expense relating to the Company’s deferred compensation plan was recorded due to the decrease in our common stock price during the quarter.

 

2

---

Capital Expenditures –

First quarter drilling expenditures of $334 million funded the drilling of 74 (58 net) wells and the completion of previously drilled wells. A 100% drilling success rate was achieved. During the quarter, total capital expenditures were $436 million which included $75 million for leasehold, $21 million for exploration and $6 million for infrastructure build-out. The capital expenditure budget for the year of $1.6 billion remains unchanged.

Credit Facility –

On April 9^th, lenders under Range’s bank credit facility completed their regular semi-annual redetermination of the borrowing base, unanimously reaffirming the requested $2.0 billion borrowing base. The lenders also agreed to increase the aggregate commitment under the borrowing base from $1.5 billion to $1.75 billion. The facility is comprised of commitments from a diverse group of 29 financial institutions with no institution holding more than 6% of the total commitment. The next borrowing base redetermination is scheduled for October 1, 2012. At the end of the first quarter 2012, Range had $123 million of invested cash on hand and no amount outstanding under the credit facility.

Operational Discussion –

Marcellus Shale Division

Current Marcellus Shale production is approximately 460 Mmcfe per day net with roughly 80% of the production coming from the liquid-rich area of the play. We are on track to meet our 600 Mmcfe per day net production target by year-end 2012. During the first quarter, 28 horizontal wells were brought online in southwest Pennsylvania, all of which are located in the wet area of the play. The initial 24-hour production rates of the new wells averaged 6.6 Mmcf per day of natural gas and 252 barrels of NGLs and condensate per day or 8.2 (7.0 net) Mmcfe per day. Two wells in the wet area utilized the new reduced cluster spacing (“RCS”) completion technique and produced at approximately twice the initial rate of non-RCS wells on the same pad. Due to the capacity limitations of the production facilities, many of the 28 newly connected wells are producing at constrained rates. Of significance at quarter-end there were three wells producing into sales at a combined rate of 45 (37.1 net) Mmcfe per day. Subsequent to the end of the quarter, three additional wells on the same pad were turned to sales with total production now at approximately 75 (61.8 net) Mmcfe per day. At quarter-end, in southwest Pennsylvania there were 57 Marcellus Shale wells waiting on completion and 43 additional wells waiting on pipeline. A few days ago, we commenced flowback operations on one well at the edge of the super-rich area. The peak one-day production was 108 barrels per day condensate, 501 barrels per day NGLs, and 7.1 Mmcf per day gas. If ethane was extracted, we estimate that the well would have made 6 Mmcf per day and over 1,300 barrels per day of liquids. (Range’s net revenue interest in this well is 83.75%.) The well’s lateral length is 2,752 feet and was completed with 14 stages using the RCS method. Based on its initial results, the new targeting methods combined with the RCS completion have significantly improved the well’s performance and we believe that this could be impactful in both the wet and super-rich areas.

During the quarter, our first Upper Devonian test in the super-rich area of southwest Pennsylvania was drilled and is currently being completed. A second Upper Devonian test in the super-rich area is currently drilling. Rotary sidewall cores have been taken on both Upper Devonian wells. The preliminary core analysis is very encouraging from both wells.

 

3

---

During the first quarter, 10 horizontal wells were drilled in northeast Pennsylvania and five horizontal wells were turned to sales in the Lycoming County area. First quarter results include four wells that had outstanding 24-hour initial test rates. The average test rate for the four wells was 22 (18.9 net) Mmcf per day and the wells had an average lateral length of 3,000 feet with 10 stages. At the end of the first quarter, there were 8 wells waiting on pipeline and 21 wells waiting on completion in northeast Lycoming area. In Bradford County on our non-operated position, 10 (2.5 net) horizontal wells were drilled and 7 (1.8 net) wells were turned to sales. At the end of the quarter 15 (3.8 net) wells were waiting on pipeline and 22 (5.5 net) wells were waiting on completion. Range has no non-operated rigs running in Bradford County.

Range continues to make progress with its midstream partners in expanding the infrastructure to accommodate the significant growth in volumes anticipated over the next several years. In the super-rich and wet areas of southwest Pennsylvania, an additional 50 miles of twenty-inch trunkline is currently being constructed that will interconnect with gas processing facilities. Also in southwest Pennsylvania, in Allegheny and Butler Counties, where Range owns a sizeable leasehold position, 40 miles of twenty-inch trunkline was recently completed to flow natural gas into the Dominion Transmission system. In northeast Pennsylvania, phase two of the trunkline system, encompassing 18 miles of thirty-inch pipeline was also recently completed.

Southwest Division

Range’s Midcontinent team continues to focus its efforts in the horizontal Mississippian play which yielded strong initial results for the quarter. Range’s acreage position in the play has increased to 145,000 net acres at quarter-end, up from 105,000 net acres at year-end 2011. Range is currently running two rigs in the play. Initial results on the first two wells of the 2012 program compare favorably with prior results. Initial 24-hour rates for the two wells averaged 525 (428 net) boe per day per well (320 barrels per day oil, 117 barrels per NGLs and 530 mcf per day gas), with an average lateral length of 2,700 feet and 15 stages. Estimates of ultimate reserves per well continue to be consistent with our 400-500 Mboe per well projection for the play. As the program gains momentum, longer lateral lengths and varying stimulation methods will be attempted to determine the most efficient and cost effective means to add value. A third processing facility and associated infrastructure is currently under construction in the play and is expected to become operational late in the second quarter. Two other processing facilities are currently being used.

In the Texas Panhandle, one rig is currently running in the development of the horizontal St. Louis Lime play. The first well of the 2012 program has been completed and is expected to be turned to sales in the second quarter. Additional drilling will continue with 7 (4.6 net) St. Louis Lime horizontals and 1 (0.8 net) Granite Wash horizontal well planned for the year. Range has secured capacity in several third party projects being developed in the Texas Panhandle to increase pipeline and processing capacity to support its planned development in this area.

Range’s Permian team is focusing on 100,000 net acres in our Conger field area in Glasscock and Sterling Counties, Texas that is over 90% held by production. Range announced the results of its first Cline Shale well in February of this year and performance is continuing to outperform the projected ultimate recovery of 340 Mboe. A second well has been drilled and completed at 484 (378 net) boe per day (282 barrels per day oil, 123 barrels per day NGLs and 476 mcf per day gas). For the remainder of 2012, Range plans to drill three more horizontal Cline Shale wells. The three wells will be spread across the Conger field properties to further de-risk the acreage block.

The Permian team’s first vertical Wolfberry well in the Conger field had an initial production rate of 495 (371.3 net) boe per day (195 barrels per day oil, 141 barrels per day NGLs and 954 mcf per day gas). The 90-day average production rate for the well was 204 (153.0 net) boe per day (59 barrels per

 

4

---

day oil, 83 barrels per day NGLs, and 372 mcf per day gas). The team has also completed its second vertical Wolfberry well at an initial production rate of 517 (403.3 net) boe per day (212 barrels per day oil, 144 barrels per day NGLs and 969 mcf per day gas). Range has the potential for 100–150 additional Wolfberry locations on 40 acre spacing at Conger. Range plans to drill two more vertical Wolfberry wells in 2012.

Southern Appalachia Division

The Southern Appalachia Division continued development of multi-pay horizons on its 350,000 (235,000 net) acre position in Virginia during the first quarter of 2012. The division had one drilling rig and two completion rigs running in the quarter. The division placed on line 16 wells including four tight-gas sand, eight coalbed methane and four horizontal Huron Shale wells. The division also performed cleanouts on five horizontal wells in the field resulting in doubling the wells’ production.

Conference Call Information –

The Company will host a conference call on Thursday April 26 at 1:00pm ET to review the first quarter results. To participate in the call, please dial 877-407-0778 and ask for the Range Resources’ first quarter financial results conference call. A replay of the call will be available through May 31 at 877-660-6853. The account number is 286 and the conference ID for the replay is 392701. Additional financial and statistical information about the period not included in this release but discussed on the conference call is 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 May 31.

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. Adjusted diluted earnings per share 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 adjusted diluted earnings per share. On its website, the Company provides additional comparative information on prior periods.

First quarter 2012 earnings included a loss of $53.0 million for the non-cash unrealized mark-to-market reduction in value of the Company’s derivatives, unproved property impairment expense of $20.3 million, a $7.8 million gain recorded for the mark-to-market in the deferred compensation plan, a $24 million onetime charge reflecting the retroactive payment required by the Pennsylvania impact fee for wells drilled in 2011 and prior years and $9.9 million of non-cash stock compensation expense. Excluding these items, net income would have been $24.4 million or $0.15 per diluted share. Excluding similar non-cash items from the prior-year quarter, net income would have been $35.2 million or $0.22 per diluted share. 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.)

 

5

---

“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, NGLs 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 and transportation, gathering and compression costs, 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 of the details of each amount and provide a summary of the realized cash-settled amounts which historically were reported as natural gas, NGLs and oil sales. This information will serve to bridge the gap between various readers’ understanding and fully disclose the information needed.

The Company discloses in this release the detailed 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 of 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, NGLs 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 (loss)” 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, NGLs and oil sales in a supplemental table included with this release which would correspond to amounts shown by analysts for natural gas, NGLs and oil sales realized, including all cash-settled derivatives.

 

6

---

RANGE RESOURCES CORPORATION (NYSE: RRC) is a leading independent oil and natural gas producer with operations focused in Appalachia and the southwest region of the United States. The Company pursues an organic growth strategy targeting high return, low-cost projects within its large inventory of low risk, development drilling opportunities. The Company is headquartered in Fort Worth, Texas. More information about Range can be found at http://www.rangeresources.com/ and

http://www.myrangeresources.com/.

Except for historical information, statements made in this release such as consistent growth at low cost, deliver per share value, excellent hedge position, high return projects, financial strength, future liquidity, future expansion of infrastructure to accommodate expected future growth, number of wells expected to be completed and turned to sales, expected impact from RCS completions and generates attractive returns 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 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.

Estimated ultimate recovery, or “EUR,” refers to our management’s internal estimates of per well hydrocarbon quantities that may be potentially recovered from a hypothetical future well completed as a producer in the area. These quantities do not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules. Our management estimated these ultimate recoveries based on our previous operating experience in the given area and publicly available information relating to the operations of producers who are conducting operating in these areas. Actual quantities that may be ultimately recovered from Range’s interests may 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 ultimate recoveries may change significantly as development of our resource plays provides additional data. In addition, our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.

Further information on risks and uncertainties is available in Range’s filings with the Securities and Exchange Commission (“SEC”), which are incorporated by reference. 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.

 

7

---

2012-13

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

 

8

---

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 March 31,
		2012				2011
Revenues and other income:
Natural gas, NGLs and oil sales (a)		$	317,617			$	251,963
Derivative cash settlements gain (loss) (a) (b)			(7,829	)			(1,366	)
Change in mark-to-market on unrealized derivatives gain (loss) (b)			(52,056	)			(40,036	)
Ineffective hedging (loss) gain (b)			(948	)			568
(Loss) gain on sale of properties			(10,426	)			139
Equity method investment (c)			316				262
Transportation and gathering (c)			(334	)			703
Transportation and gathering – non-cash stock compensation (c) (d)			(453	)			(390	)
Other (c)			1,006				815
Total revenues and other income			246,893				212,658				16	%
Costs and expenses:
Direct operating			28,665				28,407
Direct operating – non-cash stock compensation (d)			357				310
Transportation, gathering and compression			40,820				25,082
Production and ad valorem taxes			12,634				6,879
Pennsylvania impact fee - prior year			24,000				—
Exploration			20,588				25,858
Exploration – non-cash stock compensation (d)			928				1,329
Abandonment and impairment of unproved properties			20,289				16,537
General and administrative			30,055				27,117
General and administrative – non-cash stock compensation (d)			8,158				7,530
General and administrative – lawsuit settlements			516				—
General and administrative – bad debt expense			—				(688	)
Deferred compensation plan (e)			(7,830	)			30,630
Interest expense			37,205				24,779
Depletion, depreciation and amortization			100,151				72,216
Total costs and expenses			316,536				265,986				19	%
Loss from continuing operations before income taxes			(69,643	)			(53,328	)			-31	%
Income tax benefit:
Current			—				—
Deferred			(27,843	)			(19,897	)
			(27,843	)			(19,897	)
Loss from continuing operations			(41,800	)			(33,431	)			-25	%
Discontinued operations, net of tax			—				8,398
Net loss		$	(41,800	)		$	(25,033	)			-67	%
Loss Per Common Share:
Basic-Loss from continuing operations		$	(0.26	)		$	(0.21	)
Discontinued operations			—				0.05	)
Net loss		$	(0.26	)		$	(0.16	)			-63	%
Diluted-Loss from continuing operations		$	(0.26	)		$	(0.21	)
Discontinued operations			—				0.05	)
Net loss		$	(0.26	)		$	(0.16	)			-63	%
Weighted average common shares outstanding, as reported:
Basic			158,913				157,545				1	%
Diluted			158,913				157,545				1	%

 

(a)	See separate natural gas, NGLs and oil sales information table.

(b)	Included in Derivative fair value loss in the 10-Q.

(c)	Included in Other revenues in the 10-Q.

(d)	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.

(e)	Reflects the change in market value of the vested Company stock held in the deferred compensation plan.

 

9

---

RANGE RESOURCES CORPORATION

STATEMENTS OF OPERATIONS

Restated for Barnett discontinued operations,

a non-GAAP presentation

 

		Three Months Ended March 31, 2012												Three Months Ended March 31, 2011
(Unaudited, in thousands, except per share data)		As reported				Barnett Discontinued Operations				Including Barnett Ops				As reported				Barnett Discontinued Operations				Including Barnett Ops
Revenues and other income:
Natural gas, NGLs and oil sales		$	317,617				—			$	317,617			$	251,963			$	44,573			$	296,536
Derivative cash settlements gain (loss)			(7,829	)			—				(7,829	)			(1,366	)			—				(1,366	)
Change in mark-to-market on unrealized derivatives gain (loss)			(52,056	)			—				(52,056	)			(40,036	)			—				(40,036	)
Ineffective hedging gain (loss)			(948	)			—				(948	)			568				—				568
Gain (loss) on sale of properties			(10,426	)			—				(10,426	)			139				—				139
Equity method investment			316				—				316				262				—				262
Transportation and gathering			(334	)			—				(334	)			703				5				708
Transportation and gathering – non-cash stock compensation			(453	)			—				(453	)			(390	)			—				(390	)
Interest and other			1,006				—				1,006				815				4				819
			246,893				—				246,893				212,658				44,582				257,240
Costs and expenses:
Direct operating			28,665				—				28,665				28,407				8,232				36,639
Direct operating – non-cash stock compensation			357				—				357				310				45				355
Transportation, gathering and compression			40,820				—				40,820				25,082				2,316				27,398
Production and ad valorem taxes			12,634				—				12,634				6,879				1,066				7,945
Pennsylvania impact fee – prior year			24,000								24,000				—				—				—
Exploration			20,588				—				20,588				25,858				32				25,890
Exploration – non-cash stock compensation			928				—				928				1,329				—				1,329
Abandonment and impairment of unproved properties			20,289				—				20,289				16,537				—				16,537
General and administrative			30,055				—				30,055				27,117				—				27,117
General and administrative – non-cash stock compensation			8,158				—				8,158				7,530				—				7,530
General and administrative – lawsuit settlements			516				—				516				—				—				—
General and administrative – bad debt expense			—				—				—				(688	)			—				(688	)
Deferred compensation plan			(7,830	)			—				(7,830	)			30,630				—				30,630
Interest expense			37,205				—				37,205				24,779				11,076				35,855
Depletion, depreciation and amortization			100,151				—				100,151				72,216				8,880				81,096
			316,536				—				316,536				265,986				31,647				297,633
(Loss) income from continuing operations before income taxes			(69,643	)			—				(69,643	)			(53,328	)			12,935				(40,393	)
Income tax expense (benefit):
Current			—				—				—				—				—				—
Deferred			(27,843	)			—				(27,843	)			(19,897	)			4,537				(15,360	)
			(27,843	)			—				(27,843	)			(19,897	)			4,537				(15,360	)
(Loss) income from continuing operations			(41,800	)			—				(41,800	)			(33,431	)			8,398				(25,033	)
Discontinued operations-Barnett Shale, net of tax			—				—				—				8,398				(8,398	)			—
Net loss		$	(41,800	)			—			$	(41,800	)		$	(25,033	)			—			$	(25,033	)
OPERATING HIGHLIGHTS
Average daily production:
Natural gas (mcf)			512,453				—				512,453				331,172				98,728				429,900
NGLs (bbl)			17,152				—				17,152				12,573				1,765				14,338
Oil (bbl)			6,682				—				6,682				4,846				78				4,924
Gas equivalent (mcfe)			655,457				—				655,457				435,686				109,783				545,469
Average prices realized before transportation, gathering and compression:
Natural gas (mcf)		$	4.01				—			$	4.01			$	5.40			$	4.11			$	5.10
NGLs (bbl)		$	46.20				—			$	46.20			$	48.65			$	46.65			$	48.40
Oil (bbl)		$	83.54				—			$	83.54			$	79.31			$	89.89			$	79.48
Gas equivalent (mcfe)		$	5.19				—			$	5.19			$	6.39			$	4.51			$	6.01
Direct operating cash costs per mcfe:
Field expenses		$	0.45				—			$	0.45			$	0.71			$	0.81			$	0.74
Workovers			0.03				—				0.03				0.01				0.02				0.01
Total operating costs		$	0.48				—			$	0.48			$	0.72			$	0.83			$	0.75
Transportation, gathering and compression cost per mcfe:		$	0.68				—			$	0.68			$	0.63			$	0.23			$	0.55

 

10

---

RANGE RESOURCES CORPORATION

BALANCE SHEETS

(In thousands)

 

		March 31, 2012				December 31, 2011
		(Unaudited)
Assets
Current assets		$	246,371			$	141,342
Current unrealized derivative gain			216,508				173,921
Natural gas and oil properties			5,439,429				5,157,566
Transportation and field assets			50,156				52,678
Other			325,481				319,963
		$	6,277,945			$	5,845,470
Liabilities and Stockholders’ Equity
Current liabilities		$	544,763			$	506,274
Current asset retirement obligation			5,005				5,005
Current unrealized derivative loss			4,767				—
Current liabilities of discontinued operations			—				653
Bank debt			—				187,000
Subordinated notes			2,388,260				1,787,967
Total long-term debt			2,388,260				1,974,967
Deferred tax liability			685,078				710,490
Unrealized derivative loss			3,792				173
Deferred compensation liability			165,958				169,188
Long-term asset retirement obligation and other			87,233				86,300
Common stock and retained earnings			2,199,208				2,242,136
Treasury stock			(6,278	)			(6,343	)
Accumulated other comprehensive income			200,159				156,627
Total stockholders’ equity			2,393,089				2,392,420
		$	6,277,945			$	5,845,470

 

11

---

RANGE RESOURCES CORPORATION

CASH FLOWS FROM OPERATING ACTIVITIES

(Unaudited, in thousands)

		Three Months Ended March 31,
		2012				2011
Net loss		$	(41,800	)		$	(25,033	)
Adjustments to reconcile net income to net cash provided from operating activities:
(Income) loss discontinued operations			—				(8,398	)
(Gain) loss from equity investment, net of distributions			251				12,705
Deferred income tax expense (benefit)			(27,843	)			(19,897	)
Depletion, depreciation, amortization and proved property impairment			100,151				72,216
Exploration dry hole costs			709				10
Abandonment and impairment of unproved properties			20,289				16,537
Mark-to-market (gain) loss on oil and gas derivatives not designated as hedges			52,056				40,036
Unrealized derivative (gain) loss			948				(568	)
Allowance for bad debts			—				(688	)
Amortization of deferred financing costs, loss on extinguishment of debt, and other			1,848				(78	)
Deferred and stock-based compensation			2,508				40,650
(Loss) gain on sale of assets and other			10,426				(139	)
Changes in working capital:
Accounts receivable			11,947				(10,528	)
Inventory and other			(897	)			3,574
Accounts payable			8,962				2,302
Accrued liabilities and other			16,422				(1,491	)
Net changes in working capital			36,434				(6,143	)
Net cash provided from continuing operations			155,977				121,210
Net cash provided from discontinued operations			—				19,412
Net cash provided from operating activities		$	155,977			$	140,622

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 March 31,
		2012				2011
Net cash provided from operating activities, as reported		$	155,977			$	140,622
Net changes in working capital from continuing operations			(36,434	)			6,143
Exploration expense			19,879				25,848
Lawsuit settlements			516				—
Equity method investment distribution / intercompany elimination			(566	)			(12,966	)
Prior year Pennsylvania impact fee			24,000				—
Non-cash compensation adjustment			(388	)			1,320
Net changes in working capital from discontinued operations and other			—				2,480
Cash flow from operations before changes in working capital, a non-GAAP measure		$	162,984			$	163,447

ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING

(Unaudited, in thousands)

 

		Three Months Ended March 31,
		2012				2011
Basic:
Weighted average shares outstanding			161,739				160,438
Stock held by deferred compensation plan			(2,826	)			(2,893	)
Adjusted basic			158,913				157,545
Dilutive:
Weighted average shares outstanding			161,739				160,438
Anti-dilutive or dilutive stock options under treasury method			(2,826	)			(2,893	)
Adjusted dilutive			158,913				157,545

 

12

---

RANGE RESOURCES CORPORATION

RECONCILIATION OF NATURAL GAS, NGLs AND OIL SALES

AND DERIVATIVE FAIR VALUE INCOME (LOSS) TO

CALCULATED CASH REALIZED NATURAL GAS, NGLs AND

OIL PRICES WITH AND WITHOUT THIRD PARTY

TRANSPORTATION, GATHERING AND COMPRESSION FEES

non-GAAP measures

(Unaudited, in thousands, except per unit data)		As Reported, GAAP Excludes Barnett Operations Three Months Ended March 31,												Non-GAAP Includes Barnett Operations Three Months Ended March 31,
		2012				2011				%				2012				2011				%
Natural gas, NGLs and oil sales components:
Natural gas sales		$	128,068			$	130,795							$	128,068			$	158,723
NGLs sales			76,498				55,045								76,498				62,454
Oil sales			55,422				36,507								55,422				37,136
Cash-settled hedges (effective):
Natural gas			57,629				29,616								57,629				38,223
Crude oil			—				—								—				—
Total natural gas, NGLs and oil sales, as reported		$	317,617			$	251,963				26	%		$	317,617			$	296,536				7	%
Derivative fair value income (loss) components:
Cash-settled derivatives (ineffective):
Natural gas		$	1,185			$	552							$	1,185			$	552
NGLs			(4,392	)			—								(4,392	)			—
Crude Oil			(4,622	)			(1,918	)							(4,622	)			(1,918	)
Change in mark-to-market on unrealized derivatives			(52,056	)			(40,036	)							(52,056	)			(40,036	)
Unrealized ineffectiveness			(948	)			568								(948	)			568
Total derivative fair value income (loss), as reported		$	(60,833	)		$	(40,834	)						$	(60,833	)		$	(40,834	)
Natural gas, NGLs and oil sales, including all cash-settled derivatives:
Natural gas sales		$	186,882			$	160,963							$	186,882			$	197,498
NGLs sales			72,106				55,045								72,106				62,454
Oil sales			50,800				34,589								50,800				35,218
Total		$	309,788			$	250,597				24	%		$	309,788			$	295,170				5	%
Third party transportation, gathering and compression fee components:
Natural gas		$	38,506			$	24,512							$	38,506			$	26,828
NGLs			2,314				570								2,314				570
Total transportation, gathering and compression, as reported		$	40,820			$	25,082							$	40,820			$	27,398
Production during the period (a):
Natural gas (mcf)			46,633,207				29,805,523				56	%			46,633,207				38,691,021				21	%
NGLs (bbl)			1,560,826				1,131,565				38	%`			1,560,826				1,290,408				21	%
Oil (bbl)			608,077				436,132				39	%			608,077				443,120				37	%
Gas equivalent (mcfe) (b)			59,646,625				39,211,706				52	%			59,646,625				49,092,189				21	%
Production – average per day (a):
Natural gas (mcf)			512,453				331,172				55	%			512,453				429,900				19	%
NGLs (bbl)			17,152				12,573				36	%			17,152				14,338				20	%
Oil (bbl)			6,682				4,846				38	%			6,682				4,924				36	%
Gas equivalent (mcfe) (b)			655,457				435,686				50	%			655,457				545,469				20	%
Average prices realized, including all derivative settlements but excluding transportation, gathering and compression costs:
Natural gas (mcf)		$	4.01			$	5.40				-26	%		$	4.01			$	5.10				-21	%
NGLs (bbl)		$	46.20			$	48.65				-5	%		$	46.20			$	48.40				-5	%
Oil (bbl)		$	83.54			$	79.31				5	%		$	83.54			$	79.48				5	%
Gas equivalent (mcfe) (b)		$	5.19			$	6.39				-19	%		$	5.19			$	6.01				-14	%
Average prices realized, including all derivative settlements, net of transportation, gathering and compression costs:
Natural gas (mcf)		$	3.18			$	4.58				-30	%		$	3.18			$	4.41				-28	%
NGLs (bbl)		$	44.71			$	48.14				-7	%		$	44.71			$	47.96				-7	%
Oil (bbl)		$	83.54			$	79.31				5	%		$	83.54			$	79.48				5	%
Gas equivalent (mcfe) (b)		$	4.51			$	5.75				-22	%		$	4.51			$	5.45				-17	%

 

(a)	Represents volumes sold regardless of when produced.

(b)	Oil and NGLs are converted to mcfe at a rate of one barrel equals six mcf based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.

 

13

---

RANGE RESOURCES CORPORATION

RECONCILIATION OF INCOME (LOSS) FROM CONTINUING

OPERATIONS BEFORE INCOME TAXES AS REPORTED TO

INCOME FROM OPERATIONS BEFORE INCOME TAXES

EXCLUDING CERTAIN ITEMS, a non-GAAP measure

(Unaudited, in thousands, except per share data)

 

		Three Months Ended March 31,
		2012				2011				%
(Loss) income from continuing operations before income taxes, as reported		$	(69,643	)		$	(53,328	)			-31	%
Adjustment for certain items:
(Loss) gain on sale of properties			10,426				(139	)
Barnett discontinued operations less gain on sale			—				12,980
Change in mark-to-market on unrealized derivatives (gain) loss			52,056				40,036
Unrealized derivative (gain) loss			948				(568	)
Abandonment and impairment of unproved properties			20,289				16,537
Prior year Pennsylvania impact fee			24,000				—
Lawsuit settlements			516				—
Transportation and gathering – non-cash stock compensation			453				390
Direct operating – non-cash stock compensation			357				310
Exploration expenses – non-cash stock compensation			928				1,329
General & administrative – non-cash stock compensation			8,158				7,530
Deferred compensation plan – non-cash stock compensation			(7,830	)			30,630
Income from operations before income taxes, as adjusted			40,658				55,707				-27	%
Income tax expense, as adjusted
Current			—				—
Deferred			16,244				20,485
Net income excluding certain items, a non-GAAP measure		$	24,414			$	35,222				-31	%
Non-GAAP income per common share
Basic .		$	0.15			$	0.22				-32	%
Diluted		$	0.15			$	0.22				-32	%
Non-GAAP diluted shares outstanding, if dilutive			159,858				158,515

HEDGING POSITION AS OF APRIL 25, 2012

(Unaudited)

 

		Daily Volume				Hedge Price				Premium (Paid) / Received
Gas (Mmbtu)
1Q 2012 Swaps			160,000			$	4.10			$	(0.02	)
1Q 2012 Collars			189,641			$	5.32 - $5.91			$	(0.28	)
2Q 2012 Swaps			210,000			$	3.94			$	(0.01	)
2Q 2012 Collars			189,641			$	5.32 - $5.91			$	(0.28	)
3Q 2012 Swaps			160,000			$	4.18			$	(0.02	)
3Q 2012 Collars			279,641			$	4.76 - $5.22			$	(0.19	)
4Q 2012 Swaps			200,000			$	4.07			$	(0.02	)
4Q 2012 Collars			279,641			$	4.76 - $5.22			$	(0.19	)
2013 Swaps			102,521			$	3.66				—
2013 Collars			240,000			$	4.73 - $5.20				—
2014 Collars			90,000			$	4.25 - $4.85				—
Oil (Bbls)
1Q 2012 Calls			4,700			$	85.00			$	13.71
1Q 2012 Collars			2,000			$	70.00 - $80.00			$	7.50
2Q 2012 Calls			2,200			$	85.00			$	13.71
2Q 2012 Collars			4,500			$	75.56 - $82.78			$	10.18
3Q 2012 Calls			2,200			$	85.00			$	13.71
3Q 2012 Collars			4,500			$	75.56 - $82.78			$	9.30
4Q 2012 Calls			2,200			$	85.00			$	13.71
4Q 2012 Collars			4,500			$	75.56 - $82.78			$	8.56
2013 Swaps			4,756			$	96.49				—
2013 Collars			3,000			$	90.60 - $100.00				—
2014 Swaps			3,000			$	93.33				—
2014 Collars			2,000			$	85.55 - $100.00				—
NGLs (using C5) (Bbls)
1Q 2012 Swaps			12,000			$	96.28				—
2Q 2012 Swaps			12,000			$	96.28				—
3Q 2012 Swaps			12,000			$	96.28				—
4Q 2012 Swaps			12,000			$	96.28				—
2013 Swaps			8,000			$	89.64				—

 

 

14

---

NOTE: SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS

 

15