EXHIBIT 99.1

NEWS RELEASE

RANGE ANNOUNCES SECOND QUARTER 2012 RESULTS

FORT WORTH, TEXAS, JULY 24, 2012…RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its second quarter 2012 results. Revenues for the second quarter 2012 totaled $442 million, a 32% increase over the prior year quarter. Net cash provided from operating activities including changes in working capital totaled $127 million, declining 25% from the prior year quarter. Reported net income for the second quarter 2012 totaled $55.7 million ($0.34 per diluted share), a 6% increase over the second quarter 2011. Revenue and cash flow results were driven by higher production volumes and lower unit costs offset by lower realized prices. Revenue and earnings also included the impact of a derivative mark-to-market gain of $136 million.

Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $18.1 million ($0.11 per diluted share) compared to $43.2 million ($0.27 per diluted share) in the prior year quarter. Cash flow from operations before changes in working capital, a non-GAAP measure, decreased 7% year-over-year to $156 million. Comparing these amounts to analysts’ average First Call consensus estimates, the Company’s earnings per share ($0.11 per diluted share) were six cents higher than the consensus of analysts’ estimates of $0.05 per diluted share. Cash flow per share ($0.97 per diluted share) for the quarter was two cents higher than the consensus analysts’ estimates of $0.95 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, “Our second quarter results reflect excellent performance. The benefits of our Barnett sale last year have positively impacted our second quarter operating and financial results. The sale allowed us to fast-forward the development of our core plays, improve our capital efficiency, lower our cost structure, and strengthen our financial position. The 42% increase in production coupled with a 16% decrease in aggregate cash unit costs are a vivid reflection of our performance combined with the sale benefits. While low natural gas prices impacted our financial results, our strong hedge position provided substantial protection. Looking ahead, we have approximately 80% of expected production hedged for the remainder of the year.

We now expect our 2012 production growth to be 35%, or the high end of our previous full-year guidance. We also expect liquids growth in the fourth quarter to reach 40% compared to the fourth quarter of 2011. With the excellent drilling results in the first half of the year and our strong hedge position, we are well positioned to add material per share value in the second half of 2012.”

 

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Financial Discussion –

(Range sold substantially all of its Barnett Shale properties in April of 2011. Under generally accepted accounting principles (“GAAP”), 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.)

For the quarter, production averaged 719.3 Mmcfe per day, comprised of 574.7 Mmcf per day of gas (80%), 17,259 barrels per day of natural gas liquids (14%) and 6,846 barrels per day of oil (6%). Natural gas production grew 48%, NGL production increased 20% and crude oil production increased 23% over the prior-year quarter due to outstanding drilling results. Realized prices, including all cash-settled derivatives, averaged $4.74 per mcfe, a 26% decrease over the prior-year quarter of $6.43 and a 9% decrease as compared to the first quarter 2012 of $5.19 per mcfe. The average realized natural gas price was $3.66 per mcf, 32% lower than the prior-year quarter. NGL prices decreased 18% to $42.30 per barrel versus the prior-year quarter, while the average oil price rose 5% to $84.31 per barrel.

Reported natural gas, NGL and oil sale revenues for the quarter were $298 million, an increase of 5% as compared to the prior year excluding sales from the Barnett properties. Total natural gas, NGL and oil sales (including all cash settled derivatives and the Barnett properties) increased 5% compared to the prior-year quarter to $311 million due to higher volumes offset by lower prices. Cash settled hedging gains of approximately $90 million were realized during the quarter. As of June 30, 2012, Range had future hedging gains of approximately $340 million with roughly half to be recognized in the second half of 2012, roughly 45% in 2013 and 5% in 2014, if prices remain the same.

During the second quarter of 2012, Range continued to lower its cost structure. On a unit of production basis, the Company’s five largest cash cost categories decreased an average 16% versus the prior year quarter, even with the Pennsylvania impact fee affecting only the current year quarter. Per unit cash costs including DD&A being the six main operating expense categories were down 11% for the quarter compared to the prior year quarter. The most significant per unit cash cost declines in the second quarter compared to the prior year quarter were lease operating unit expenses down 38%, general and administrative costs down 21%, and interest expense down 14%.

Several non-cash or non-recurring items impacted second quarter results. A $136 million mark-to-market gain was recorded to reflect the increase in the value of the Company’s commodity hedges due to lower oil and NGL commodity prices during the quarter. A $3.2 million loss was incurred on the sale of certain non-core properties.

 

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Capital Expenditures –

Second quarter drilling expenditures of $390 million funded the drilling of 79 (68 net) wells and the completion of previously drilled wells. A 100% drilling success rate was achieved. Year to date drilling expenditures for 2012 totaled $724 million. For the first six months of 2012, Range has drilled 153 (126 net) wells. At June 30, 55 (49 net) wells drilled during the year had been placed on production. The remaining 98 (77 net) wells are in various stages of completion or waiting on pipeline connection. In the first six months of 2012, $152 million was expended on acreage, $24 million on gas gathering systems and $35 million for exploration expense (including $20 million for seismic and $7 million for delay rentals).

The capital expenditure budget for 2012 of $1.6 billion remains unchanged. In the plan, capital spending was heavily weighted to the first half of the year. Plans include the drilling of longer laterals with a greater number of frac stages for Marcellus wells. Under this plan, coupled with increased drilling efficiencies, the number of rigs required will be reduced throughout the second half of the year. This will allow us to complete our Marcellus program with reduced drilling costs while adding more frac stages with our Reduced Cluster Spacing (“RCS”) techniques and is expected to increase recoveries and improve our rates of return.

To optimize its portfolio and maintain a strong balance sheet, Range has engaged RBC Richardson Barr to market its Ardmore Basin Woodford properties. These properties include 9,300 net acres in the heart of the play, currently producing 1,100 barrels of liquids per day and 5.7 Mmcf per day, with multiple infill drilling opportunities at very good rates of return. However, with higher returns in the Marcellus and horizontal Mississippian projects, Range has determined to market the Woodford properties and focus its efforts on these two projects which also have greater scale and potential upside.

Hedging Status

Range hedges portions of its expected future production volumes to increase the predictability of its cash flow and to help maintain a strong financial position. At June 30, 2012, Range had more than 80% of its expected 2012 natural gas production hedged at a weighted average floor of $4.18 per mcf. Similarly, Range has hedged or committed approximately 80% of its projected crude oil production at a floor of $91.19 and approximately 60% of its composite NGL production for 2012 at above current market prices. During the second quarter, Range realized approximately $90 million in hedging gains. As of June 30, 2012, Range had future hedging gains of approximately $340 million with roughly half to be recognized in the second half of 2012, roughly 45% in 2013 and 5% in 2014 if commodity prices remain the same. In order to more effectively hedge its NGL production, Range is currently using natural gasoline (C5) and propane (C3) as proxy hedges for the heavy and light portions of the NGL composite barrel to better correlate the market relationship between our hedges and our production. We believe this approach has allowed us to support our NGL prices without the additional cost of hedging each NGL barrel component. Please see Range’s detailed hedging schedule posted on its website.

 

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Operational Discussion –

Marcellus Shale-

Marcellus Shale production reached 500 Mmcfe per day net at the end of the second quarter. Range is on track to meet or exceed its 600 Mmcfe per day net production target by year-end 2012.

Southern Marcellus Shale Division-

The Southern Marcellus Shale division ended the second quarter at approximately 378 Mmcfe per day net from the Marcellus Shale with four horizontal and two air rigs in operation. Due to improvements in drilling and completion efficiencies, we are expecting to utilize fewer rigs in the second half of the year while still meeting our production targets.

During the second quarter, the division brought online 33 wells in southwest Pennsylvania, with 15 wells in the super-rich area, 13 wells in the wet area and 5 wells in the dry area. The initial 24-hour production rates of the 33 new wells averaged 6.9 (5.3 net) Mmcfe per day (4.8 Mmcf gas, 160 barrels of condensate and 183 barrels of NGLs. As of June 30, 2012 the division had 50 wells waiting on completion and an additional 56 wells waiting on pipeline for sales.

In the super-rich area, we recently tested a well that flowed at an initial 24-hour rate of 11.7 Mmcfe per day (5.7 Mmcf of gas, 546 barrels of condensate and 454 barrels of NGLs). In addition, we have recently drilled and brought online two pads that are along the wet/dry line of 1,050 BTU gas. One is just on the dry side and has 1,040 BTU gas. This pad has five wells that averaged 14.0 Mmcf per day per well for an initial 24-hour rate to sales. After two months of production, the wells have averaged 7.4 Mmcf per day and we expect reserves for these wells to average 7 to 8 Bcf each. The wells average lateral length is 2,630 feet with 11 stages. The other pad is just over the wet/dry line and has a BTU content of 1,065. This 10 well pad had an average IP of 13.7 Mmcf per day per well for its initial 24-hour rate to sales. After three months of production, these wells have averaged 5.6 Mmcf per day while being facility constrained and appear to have average reserves in the range of 7 to 8 Bcf each. They have an average lateral length of 2,700 feet with 10 stages per well. The two pads are about 35 miles apart, and we believe the quality of these wells is excellent.

Northern Marcellus Shale Division-

In the Northern Marcellus Shale Division, Range drilled 16 horizontal wells during the second quarter in Lycoming County. Also, a total of 16 horizontal wells were turned to sales during the second quarter. Significant well results include three wells brought online with an average lateral length of 3,850 feet with 14 frac stages per well. The first well had a 24-hour initial production rate of 10.2 (8.7 net) Mmcf per day, the second well 12.3 (10.6 net) Mmcf per day and the third 12.1 (10.4 net) Mmcf per day. At the end of the second quarter there were 53 horizontal wells producing 132 net Mmcf per day with 12 wells waiting on pipeline and 23 wells waiting on completion.

Range expects to reduce the number of rigs to two rigs by the end of the third quarter and one rig by the end of the fourth quarter. In addition to Marcellus drilling, the Northern Division is planning to drill two horizontal test wells in the Utica Shale in northwest Pennsylvania by year-end 2012. The first Utica test was spud earlier this month and is currently drilling.

In the Bradford County joint venture area with Talisman operating, one (0.25 net) horizontal well was turned to sales. In total there are 15 wells producing 53.5 (9.4 net) Mmcf per day. There were 24 (6.2 net) wells waiting on pipeline and 12 (2.9 net) wells waiting on completion.

 

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Midcontinent Division-

Range’s Midcontinent team is focused on the liquids-rich horizontal Mississippian play in northern Oklahoma. Results continue to improve with recent wells considerably better than our first 8 horizontal wells drilled. With the new processing facility commencing operation at the end of the quarter, four wells were turned to production with two of the wells not yet reaching their peak rates. The four wells have achieved combined peak rates to date of 2,848 (2,001 net) boe per day (1,277 barrels oil, 918 barrels NGLs and 3,917 mcf gas). Of these, the Balder #1-30N was our first well to test in excess of 1,000 barrels of oil equivalent per day. It produced at a peak 24-hour production rate of 1,363 (941 net) barrels of oil equivalent per day (782 barrels oil, 340 barrels NGLs and 1,448 mcf gas). Its peak 30-day average daily production rate was 1,258 (871 net) barrels of oil equivalent per day (665 barrels oil, 346 barrels NGLs and 1,478 mcf gas). The lateral length on this well reached a total of 3,911 feet with a 19 stage frac. This well is one of several recent tests to extend Range’s previous lateral lengths from 2,000 feet plus to a 4,000 foot target. Range has an 86.3% working interest in this well.

Range now has 152,000 net acres in the horizontal Mississippian play. Early performance on wells in the 2012 drilling program with a longer lateral length indicates that the EUR’s will exceed the reserves assigned to wells drilled in 2009 to 2011, and expects reserves to be in the 600 Mboe range. We are continuing to prepare field infrastructure in anticipation of ramping up activity in the second half of 2012 and into 2013.

Drilling also continues in the Texas Panhandle with one active rig. Two St. Louis wells were turned to sales in the quarter at combined gross rates of 27.8 (11.9 net) Mmcfe per day (18.9 Mmcf gas, 643 barrels of oil and 835 barrels of NGLs per day).

Permian Division-

In the Cline shale and Wolfberry plays, Range has 100,000 net acres, with approximately 91% held by production from our Conger field. Range has drilled an additional Wolfberry well which is currently being completed. We are also drilling our third Cline shale horizontal. The average estimated ultimate recovery for the first two Cline Shale wells is projected to be 340 Mboe per well and for the first Wolfberry well is projected to be 216 Mboe. Plans for the remainder of the year are to drill four Wolfberry wells and one additional Cline well.

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 second quarter of 2012. The division had two drilling rigs running in the quarter and drilled 22 gross (19.5 net) wells including 13 (13 net) tight-gas sand, 4 (1.5 net) CBM and 5 (5 net) horizontal Huron shale wells. The five Huron wells on average were drilled in the fewest number of days and achieved the longest completed lateral length to date at over 3,600 ft. Three of the Huron wells have been brought online with early production results above expectations.

 

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Guidance – Third Quarter 2012

Production per day Guidance

 

Natural gas production:		618 - 620 Mmcf per day
NGL production:		18,300 - 18,600 bbls per day
Oil production:		7,600 - 7,800 bbls per day
Equivalent production:		773 - 778 Mmcfe per day

Total production growth for 2012 is now targeted at 35% year over year, or the high end of our previous full-year guidance. However, in the Marcellus where significant production is scheduled to be placed on line, placing five to eight wells per drilling pad could bring 25 Mmcfe per day to 80 Mmcfe per day on at one time assuming no infrastructure constraints. Therefore, third quarter production could vary by the timing of when each pad of wells are actually placed on production. Any variation in production from guidance is expected to be made up by the production in the fourth quarter to achieve the total year over year production guidance target.

Expense per mcfe Guidance

 

Direct operating expense:		$0.42-$0.44 per mcfe
Transportation, gathering and compression expense (a):		$0.63-$0.65 per mcfe
Production tax expense (b):		$0.19 per mcfe
Exploration expense:		$20 million
Unproved property impairment expense:		$20-$22 million
G&A expense:		$0.46-$0.47 per mcfe
Interest expense:		$0.60 per mcfe
DD&A expense:		$1.66-$1.68 per mcfe

 

(a)	Prior to year-end 2011 this expense was netted against revenue. Please refer to Table 6 of the 2Q 2012 Supplement Tables for historical detail of this expense by product.

(b)	Production tax expense in third quarter should equal approximately $0.10/mcfe plus an estimated $6 million for the Pennsylvania impact fee. Total production tax expense including the impact fee is expected to be $0.19/mcfe.

Differential Pricing History (c)

 

		2Q 2011				3Q 2011				4Q 2011				1Q 2012				2Q 2012
Natural Gas		$	0.16			$	0.26			$	0.07			($	0.02	)		($	0.13	)
NGL (% of WTI NYMEX)			50	%			54	%			54	%			48	%			39	%
Oil (% of WTI NYMEX)			90	%			91	%			92	%			88	%			91	%

 

(c)	Differentials based on pre-hedge pricing, excluding transportation, gathering and compression expense.

 

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Conference Call Information –

The Company will host a conference call on Wednesday, July 25, 2012 at 1:00 pm ET to review the second quarter results. To participate in the call, please dial 877-407-0778 and ask for the Range Resources’ second quarter earnings conference call. A replay of the call will be available through August 31, 2012. To access the phone replay dial 877-660-6853. The account number is 286 and the conference ID for the replay is 397444. 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 August 31, 2012.

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.

Second quarter 2012 earnings included a gain of $136 million for the non-cash unrealized mark-to-market increase in value of the Company’s derivatives and expenses associated with the mark-to-market in the deferred compensation plan for the increase in the Company’s common stock during the period of $9.3 million, non-cash stock compensation expense of $14.6 million, an unproved property impairment expense of $44 million and $3.2 million of loss on sale of properties. Excluding these items, net income would have been $18.1 million or $0.11 per diluted share. Excluding similar non-cash items from the prior-year quarter, net income would have been $43.2 million or $0.27 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.)

“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

 

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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” 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.

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 excellent drilling results, strong hedge position, add material per share value, increased drilling efficiencies, reduced drilling costs, increase recoveries and improve out rates of return, high return projects, financial strength, future liquidity, expected number of rigs, 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

 

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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.

2012-17

 

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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

 

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RANGE RESOURCES CORPORATION

STATEMENTS OF OPERATIONS

Based on GAAP reported earnings with additional

details of items included in each line in Form 10-Q

 

		Three Months Ended June 30,												Six Months Ended June 30,
(Unaudited, in thousands, except per share data)		2012				2011								2012				2011
Revenues and other income:
Natural gas, NGLs and oil sales (a)		$	298,349			$	285,353							$	615,966			$	537,316
Derivative cash settlements gain (loss) (a) (b)			12,198				(1,034	)							4,369				(2,400	)
Change in mark-to-market on unrealized derivatives gain (loss) (b)			135,777				48,139								83,721				8,103
Ineffective hedging (loss) gain (b)			594				5,934								(354	)			6,502
(Loss) gain on sale of properties			(3,227	)			(1,622	)							(13,653	)			(1,483	)
Equity method investment (c)			501				(1,021	)							817				(759	)
Transportation and gathering (c)			(677	)			(699	)							(1,011	)			4
Transportation and gathering –non-cash stock -based compensation (c) (d)			(408	)			(342	)							(861	)			(732	)
Other (c)			(667	)			587								339				1,402
Total revenues and other income			442,440				335,295				32	%			689,333				547,953				26	%
Costs and expenses:
Direct operating			26,349				27,866								55,014				56,273
Direct operating – non-cash stock compensation (d)			692				643								1,049				953
Transportation, gathering and compression			44,744				28,666								85,564				53,748
Production and ad valorem taxes			11,079				7,550								23,713				14,429
Pennsylvania impact fee - prior year			707				—								24,707				—
Exploration			14,523				10,655								35,111				36,513
Exploration – non-cash stock compensation (d)			994				937								1,922				2,266
Abandonment and impairment of unproved properties			43,641				18,900								63,930				35,437
General and administrative			30,565				27,299								60,620				54,416
General and administrative – non-cash stock compensation (d)			12,540				11,467								20,698				18,997
General and administrative – lawsuit settlements			900				70								1,416				70
General and administrative – bad debt expense			—				284								—				(404	)
Deferred compensation plan (e)			9,333				(5,778	)							1,503				24,852
Interest expense			42,888				31,383								80,093				56,162
Loss on early extinguishment of debt			—				18,580								—				18,580
Depletion, depreciation and amortization			108,802				78,294								208,953				150,510
Total costs and expenses			347,757				256,816				35	%			664,293				522,802				27	%
Income from continuing operations before income taxes			94,683				78,479				21	%			25,040				25,151				0	%
Income tax expense:
Current			—				8								—				8
Deferred			39,007				32,695								11,164				12,798
			39,007				32,703								11,164				12,806
Income from continuing operations			55,676				45,776				22	%			13,876				12,345				12	%
Discontinued operations, net of tax			—				5,517								—				13,915
Net income		$	55,676			$	51,293				9	%		$	13,876			$	26,260				-47	%
Income Per Common Share:
Basic-Income from continuing operations		$	0.34			$	0.28							$	0.09			$	0.08
Discontinued operations			—				0.04								—				0.08
Net income		$	0.34			$	0.32				6	%		$	0.09			$	0.16				-44	%
Diluted-Income from continuing operations		$	0.34			$	0.28							$	0.09			$	0.08
Discontinued operations			—				0.04								—				0.08
Net income		$	0.34			$	0.32				6	%		$	0.09			$	0.16				-44	%
Weighted average common shares outstanding, as reported:
Basic			159,412				157,997				1	%			159,162				157,772				1	%
Diluted			160,030				158,833				1	%			159,949				158,729				1	%

 

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

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

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

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

 

11

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RANGE RESOURCES CORPORATION

STATEMENTS OF OPERATIONS

Restated for Barnett discontinued operations,

a non-GAAP presentation

 

		Three Months Ended June 30, 2012												Three Months Ended June 30, 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		$	298,349				—			$	298,349			$	285,353			$	12,751			$	298,104
Derivative cash settlements gain (loss)			12,198				—				12,198				(1,034	)			—				(1,034	)
Change in mark-to-market on unrealized derivatives gain (loss)			135,777				—				135,777				48,139				—				48,139
Ineffective hedging gain (loss)			594				—				594				5,934				—				5,934
(Loss) gain on sale of properties			(3,227	)			—				(3,227	)			(1,622	)			3,820				2,198
Equity method investment			501				—				501				(1,021	)			—				(1,021	)
Transportation and gathering			(677	)			—				(677	)			(699	)			1				(698	)
Transportation and gathering – non-cash stock-based compensation			(408	)			—				(408	)			(342	)			—				(342	)
Other			(667	)			—				(667	)			587				—				587
			442,440				—				442,440				335,295				16,572				351,867
Costs and expenses:
Direct operating			26,349				—				26,349				27,866				2,169				30,035
Direct operating – non-cash stock-based compensation			692				—				692				643				—				643
Transportation, gathering and compression			44,744				—				44,744				28,666				1,974				30,640
Production and ad valorem taxes			11,079				—				11,079				7,550				184				7,734
Pennsylvania impact fee – prior year			707				—				707				—				—				—
Exploration			14,523				—				14,523				10,655				5				10,660
Exploration – non-cash stock-based compensation			994				—				994				937				—				937
Abandonment and impairment of unproved properties			43,641				—				43,641				18,900				—				18,900
General and administrative			30,565				—				30,565				27,299				—				27,299
General and administrative – non-cash stock-based compensation			12,540				—				12,540				11,467				—				11,467
General and administrative – lawsuit settlements			900				—				900				70				—				70
General and administrative – bad debt expense			—				—				—				284				—				284
Deferred compensation plan			9,333				—				9,333				(5,778	)			—				(5,778	)
Interest expense			42,888				—				42,888				31,383				3,715				35,098
Loss on early extinguishment of debt			—				—				—				18,580				—				18,580
Depletion, depreciation and amortization			108,802				—				108,802				78,294				14				78,308
			347,757				—				347,757				256,816				8,061				264,877
Income from continuing operations before income taxes			94,683				—				94,683				78,479				8,511				86,990
Income tax expense:
Current			—				—				—				8				—				8
Deferred			39,007				—				39,007				32,695				2,994				35,689
			39,007				—				39,007				32,703				2,994				35,697
Income from continuing operations			55,676				—				55,676				45,776				5,517				51,293
Discontinued operations-Barnett Shale, net of tax			—				—				—				5,517				(5,517	)			—
Net income		$	55,676				—			$	55,676			$	51,293				—			$	51,293
OPERATING HIGHLIGHTS
Average daily production:
Natural gas (mcf)			574,651				—				574,651				360,566				28,120				388,686
NGLs (bbl)			17,259				—				17,259				13,588				756				14,344
Oil (bbl)			6,846				—				6,846				5,527				18				5,545
Gas equivalents (mcfe)			719,285				—				719,285				475,256				32,762				508,018
Average prices realized before transportation, gathering and compression:
Natural gas (mcf)		$	3.66				—			$	3.66			$	5.47			$	3.84			$	5.35
NGLs (bbl)		$	42.30				—			$	42.30			$	52.06			$	40.15			$	51.44
Oil (bbl)		$	84.31				—			$	84.31			$	80.34			$	102.88			$	80.42
Gas equivalents (mcfe)		$	4.74				—			$	4.74			$	6.57			$	4.28			$	6.43
Direct operating cash costs per mcfe:
Field expenses		$	0.39				—			$	0.39			$	0.63			$	0.71			$	0.64
Workovers			0.01				—				0.01				0.01				0.02				0.01
Total operating costs		$	0.40				—			$	0.40			$	0.64			$	0.73			$	0.65
Transportation, gathering and compression cost per mcfe:		$	0.68				—			$	0.68			$	0.66			$	0.66			$	0.66

 

12

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RANGE RESOURCES CORPORATION

STATEMENTS OF OPERATIONS

Restated for Barnett discontinued operations,

a non-GAAP presentation

		Six Months Ended June 30, 2012												Six Months Ended June 30, 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		$	615,966				—			$	615,966			$	537,316			$	57,324			$	594,640
Derivative cash settlements gain (loss)			4,369				—				4,369				(2,400	)			—				(2,400	)
Change in mark-to-market on unrealized derivatives gain (loss)			83,721				—				83,721				8,103				—				8,103
Ineffective hedging gain (loss)			(354	)			—				(354	)			6,502				—				6,502
(Loss) gain on sale of properties			(13,653	)			—				(13,653	)			(1,483	)			3,820				2,337
Equity method investment			817				—				817				(759	)			—				(759	)
Transportation and gathering			(1,011	)			—				(1,011	)			4				6				10
Transportation and gathering – non-cash stock-based compensation			(861	)			—				(861	)			(732	)			—				(732	)
Other			339				—				339				1,402				4				1,406
			689,333				—				689,333				547,953				61,154				609,107
Costs and expenses:
Direct operating			55,014				—				55,014				56,273				10,401				66,674
Direct operating – non-cash stock-based compensation			1,049				—				1,049				953				45				998
Transportation, gathering and compression			85,564				—				85,564				53,748				4,290				58,038
Production and ad valorem taxes			23,713				—				23,713				14,429				1,250				15,679
Pennsylvania impact fee – prior year			24,707				—				24,707				—				—				—
Exploration			35,111				—				35,111				36,513				37				36,550
Exploration – non-cash stock-based compensation			1,922				—				1,922				2,266				—				2,266
Abandonment and impairment of unproved properties			63,930				—				63,930				35,437				—				35,437
General and administrative			60,620				—				60,620				54,416				—				54,416
General and administrative – non-cash stock-based compensation			20,698				—				20,698				18,997				—				18,997
General and administrative – lawsuit settlements			1,416				—				1,416				70				—				70
General and administrative – bad debt expense			—				—				—				(404	)			—				(404	)
Deferred compensation plan			1,503				—				1,503				24,852				—				24,852
Interest expense			80,093				—				80,093				56,162				14,791				70,953
Loss on early extinguishment of debt			—				—				—				18,580				—				18,580
Depletion, depreciation and amortization			208,953				—				208,953				150,510				8,894				159,404
			664,293				—				664,293				522,802				39,708				562,510
Income from continuing operations before income taxes			25,040				—				25,040				25,151				21,446				46,597
Income tax expense:
Current			—				—				—				8				—				8
Deferred			11,164				—				11,164				12,798				7,531				20,329
			11,164				—				11,164				12,806				7,531				20,337
Income from continuing operations			13,876				—				13,876				12,345				13,915				26,260
Discontinued operations-Barnett Shale, net of tax			—				—				—				13,915				(13,915	)			—
Net income		$	13,876				—			$	13,876			$	26,260				—			$	26,260
OPERATING HIGHLIGHTS
Average daily production:
Natural gas (mcf)			543,552				—				543,552				345,950				63,229				409,179
NGLs (bbl)			17,206				—				17,206				13,083				1,257				14,341
Oil (bbl)			6,764				—				6,764				5,188				48				5,236
Gas equivalents (mcfe)			687,371				—				687,371				455,580				71,060				526,640
Average prices realized before transportation, gathering and compression:
Natural gas (mcf)		$	3.83				—			$	3.83			$	5.44			$	4.05			$	5.22
NGLs (bbl)		$	44.24				—			$	44.24			$	50.43			$	44.69			$	49.93
Oil (bbl)		$	83.93				—			$	83.93			$	79.86			$	92.36			$	79.98
Gas equivalents (mcfe)		$	4.96				—			$	4.96			$	6.49			$	4.46			$	6.21
Direct operating cash costs per mcfe:
Field expenses		$	0.42				—			$	0.42			$	0.67			$	0.79			$	0.69
Workovers			0.02				—				0.02				0.01				0.02				0.01
Total operating costs		$	0.44				—			$	0.44			$	0.68			$	0.81			$	0.70
Transportation, gathering and compression cost per mcfe:		$	0.68				—			$	0.68			$	0.65			$	0.33			$	0.61

 

13

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RANGE RESOURCES CORPORATION

BALANCE SHEETS

 

		June 30, 2012				December 31, 2011
(In thousands)		(Unaudited)				(Audited)
Assets
Current assets		$	121,107			$	141,342
Current unrealized derivative gain			251,236				173,921
Natural gas and oil properties			5,771,040				5,157,566
Transportation and field assets			46,618				52,678
Other			353,893				319,963
		$	6,543,894			$	5,845,470
Liabilities and Stockholders’ Equity
Current liabilities		$	532,212			$	506,274
Current asset retirement obligation			5,005				5,005
Current unrealized derivative loss			3,283				—
Current liabilities of discontinued operations			—				653
Bank debt			235,000				187,000
Subordinated notes			2,388,562				1,787,967
Total long-term debt			2,623,562				1,974,967
Deferred tax liability			698,429				710,490
Unrealized derivative loss			2,405				173
Deferred compensation liability			170,763				169,188
Long-term asset retirement obligation and other			91,514				86,300
Common stock and retained earnings			2,265,338				2,242,136
Treasury stock			(5,655	)			(6,343	)
Accumulated other comprehensive income			157,038				156,627
Total stockholders’ equity			2,416,721				2,392,420
		$	6,543,894			$	5,845,470

 

14

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RANGE RESOURCES CORPORATION

CASH FLOWS FROM OPERATING ACTIVITIES

 

		Three Months Ended June 30,								Six Months Ended June 30,
(Unaudited, in thousands)		2012				2011				2012				2011
Net income		$	55,676			$	51,293			$	13,876			$	26,260
Adjustments to reconcile net income to net cash provided from operating activities:
(Income) loss discontinued operations			—				(5,517	)			—				(13,915	)
(Gain) loss from equity investment, net of distributions			2,042				2,397				2,293				15,102
Deferred income tax expense			39,007				32,695				11,164				12,798
Depletion, depreciation, amortization and proved property impairment			108,802				78,294				208,953				150,510
Exploration dry hole costs			108				(4	)			817				6
Abandonment and impairment of unproved properties			43,641				18,900				63,930				35,437
Mark-to-market (gain) loss on oil and gas derivatives not designated as hedges			(135,777	)			(48,139	)			(83,721	)			(8,103	)
Unrealized derivatives (gain) loss			(594	)			(5,934	)			354				(6,502	)
Allowance for bad debts			—				284				—				(404	)
Amortization of deferred financing costs, loss on extinguishment of debt, and other			2,045				21,756				3,893				21,678
Deferred and stock-based compensation			23,833				7,511				26,341				48,161
(Gain) loss on sale of assets and other			3,227				1,622				13,653				1,483
Changes in working capital:
Accounts receivable			(336	)			529				11,611				(9,999	)
Inventory and other			(1,927	)			(805	)			(2,824	)			2,769
Accounts payable			(30,884	)			2,713				(21,922	)			5,015
Accrued liabilities and other			18,106				9,146				34,528				7,655
Net changes in working capital			(15,041	)			11,583				21,393				5,440
Net cash provided from continuing operations			126,969				166,741				282,946				287,951
Net cash provided from discontinued operations			—				2,142				—				21,554
Net cash provided from operating activities		$	126,969			$	168,883			$	282,946			$	309,505

RECONCILIATION OF NET CASH PROVIDED FROM OPERATING ACTIVITIES, AS

REPORTED, TO CASH FLOW FROM OPERATIONS BEFORE CHANGES IN

WORKING CAPITAL, a non-GAAP measure

 

		Three Months Ended June 30,								Six Months Ended June 30,
(Unaudited, in thousands)		2012				2011				2012				2011
Net cash provided from operating activities, as reported		$	126,969			$	168,883			$	282,946			$	309,505
Net changes in working capital from continuing operations			15,041				(11,583	)			(21,393	)			(5,440	)
Exploration expense			14,415				10,659				34,294				36,507
Lawsuit settlements			900				70				1,416				70
Equity method investment distribution / intercompany elimination			(2,544	)			(1,377	)			(3,110	)			(14,344	)
Prior year Pennsylvania impact fee			707				—				24,707				—
Non-cash compensation adjustment			245				(1,258	)			(143	)			63
Net changes in working capital from discontinued operations and other			—				2,568				—				5,048
Cash flow from operations before changes in working capital, a non-GAAP measure		$	155,733			$	167,962			$	318,717			$	331,409
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING
		Three Months Ended June 30,								Six Months Ended June 30,
(Unaudited, in thousands)		2012				2011				2012				2011
Basic:
Weighted average shares outstanding			162,325				160,836				162,031				160,638
Stock held by deferred compensation plan			(2,913	)			(2,839	)			(2,869	)			(2,866	)
Adjusted basic			159,412				157,997				159,162				157,772
Dilutive:
Weighted average shares outstanding			162,325				160,836				162,031				160,638
Anti-dilutive or dilutive stock options under treasury method			(2,295	)			(2,003	)			(2,082	)			(1,909	)
Adjusted dilutive			160,030				158,833				159,949				158,729

 

15

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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

 

		As Reported, GAAP												Non-GAAP
		Excludes Barnett Operations												Includes Barnett Operations
		Three Months Ended June 30,												Three Months Ended June 30,
(Unaudited, in thousands, except per unit data)		2012				2011				%				2012				2011				%
Natural gas, NGLs and oil sales components:
Natural gas sales		$	111,413			$	150,188							$	111,413			$	160,010
NGLs sales			56,280				64,376								56,280				67,137
Oil sales			52,075				46,504								52,075				46,672
Cash-settled hedges (effective):
Natural gas			78,896				24,285								78,896				24,285
Crude oil			(315	)			—								(315	)			—
Total natural gas, NGLs and oil sales, as reported		$	298,349			$	285,353				5	%		$	298,349			$	298,104				0	%
Derivative fair value income (loss) components:
Cash-settled derivatives (ineffective):
Natural gas		$	1,278			$	5,060							$	1,278			$	5,060
NGLs			10,152				—								10,152				—
Crude Oil			768				(6,094	)							768				(6,094	)
Change in mark-to-market on unrealized derivatives			135,777				48,139								135,777				48,139
Unrealized ineffectiveness			594				5,934								594				5,934
Total derivative fair value income (loss), as reported		$	148,569			$	53,039							$	148,569			$	53,039
Natural gas, NGLs and oil sales, including all cash-settled derivatives (c):
Natural gas sales		$	191,587			$	179,533							$	191,587			$	189,355
NGLs sales			66,432				64,376								66,432				67,137
Oil sales			52,528				40,410								52,528				40,578
Total		$	310,547			$	284,319				9	%		$	310,547			$	297,070				5	%
Third party transportation, gathering and compression fee components:
Natural gas		$	42,168			$	26,888							$	42,168			$	28,862
NGLs			2,576				1,778								2,576				1,778
Total transportation, gathering and compression, as reported		$	44,744			$	28,666							$	44,744			$	30,640
Production during the period (a):
Natural gas (mcf)			52,293,227				32,811,471				59	%			52,293,227				35,370,403				48	%
NGLs (bbl)			1,570,593				1,236,502				27	%			1,570,593				1,305,263				20	%
Oil (bbl)			623,026				502,962				24	%			623,026				504,604				23	%
Gas equivalent (mcfe) (b)			65,454,941				43,248,255				51	%			65,454,941				46,229,606				42	%
Production – average per day (a):
Natural gas (mcf)			574,651				360,566				59	%			574,651				388,686				48	%
NGLs (bbl)			17,259				13,588				27	%			17,259				14,344				20	%
Oil (bbl)			6,846				5,527				24	%			6,846				5,545				23	%
Gas equivalent (mcfe) (b)			719,285				475,256				51	%			719,285				508,018				42	%
Average prices, including cash-settled hedges and derivatives before third party transportation costs (c):
Natural gas (mcf)		$	3.66			$	5.47				-33	%		$	3.66			$	5.35				-32	%
NGLs (bbl)		$	42.30			$	52.06				-19	%		$	42.30			$	51.44				-18	%
Oil (bbl)		$	84.31			$	80.34				5	%		$	84.31			$	80.42				5	%
Gas equivalent (mcfe) (b)		$	4.74			$	6.57				-28	%		$	4.74			$	6.43				-26	%
Average prices, including cash-settled hedges and derivatives (d):
Natural gas (mcf)		$	2.86			$	4.65				-39	%		$	2.86			$	4.54				-37	%
NGLs (bbl)		$	40.66			$	50.62				-20	%		$	40.66			$	50.07				-19	%
Oil (bbl)		$	84.31			$	80.34				5	%		$	84.31			$	80.42				5	%
Gas equivalent (mcfe) (b)		$	4.06			$	5.91				-31	%		$	4.06			$	5.76				-30	%

 

(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.

(c)	Excluding third party transportation, gathering and compression costs.

(d)	Net of transportation, gathering and compression costs.

 

16

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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

 

		As Reported, GAAP												Non-GAAP
		Excludes Barnett Operations												Includes Barnett Operations
		Six Months Ended June 30,												Six Months Ended June 30,
(Unaudited, in thousands, except per unit data)		2012				2011				%				2012				2011				%
Natural gas, NGLs and oil sales components:
Natural gas sales		$	239,481			$	280,983							$	239,481			$	318,733
NGLs sales			132,778				119,421								132,778				129,591
Oil sales			107,497				83,011								107,497				83,808
Cash-settled hedges (effective):
Natural gas			136,525				53,901								136,525				62,508
Crude oil			(315	)			—								(315	)			—
Total natural gas, NGLs and oil sales, as reported		$	615,966			$	537,316				15	%		$	615,966			$	594,640				4	%
Derivative fair value income (loss) components:
Cash-settled derivatives (ineffective):
Natural gas		$	2,463			$	5,612							$	2,463			$	5,612
NGLs			5,760				—								5,760				—
Crude Oil			(3,854	)			(8,012	)							(3,854	)			(8,012	)
Change in mark-to-market on unrealized derivatives			83,721				8,103								83,721				8,103
Unrealized ineffectiveness			(354	)			6,502								(354	)			6,502
Total derivative fair value income (loss), as reported		$	87,736			$	12,205							$	87,736			$	12,205
Natural gas, NGLs and oil sales, including all cash-settled derivatives (c):
Natural gas sales		$	378,469			$	340,496							$	378,469			$	386,853
NGLs sales			138,538				119,421								138,538				129,591
Oil sales			103,328				74,999								103,328				75,796
Total		$	620,335			$	534,916				16	%		$	620,335			$	592,240				5	%
Third party transportation, gathering and compression fee components:
Natural gas		$	80,674			$	51,400							$	80,674			$	55,690
NGLs			4,890				2,348								4,890				2,348
Total transportation, gathering and compression, as reported		$	85,564			$	53,748							$	85,564			$	58,038
Production during the period (a):
Natural gas (mcf)			98,926,434				62,616,994				58	%			98,926,434				74,061,424				34	%
NGLs (bbl)			3,131,419				2,368,068				32	%			3,131,419				2,595,671				21	%
Oil (bbl)			1,231,103				939,094				31	%			1,231,103				947,724				30	%
Gas equivalent (mcfe) (b)			125,101,566				82,459,960				52	%			125,101,566				95,321,795				31	%
Production – average per day (a):
Natural gas (mcf)			543,552				345,950				57	%			543,552				409,179				33	%
NGLs (bbl)			17,206				13,083				32	%			17,206				14,341				20	%
Oil (bbl)			6,764				5,188				30	%			6,764				5,236				29	%
Gas equivalent (mcfe) (b)			687,371				455,580				51	%			687,371				526,640				31	%
Average prices, including cash-settled hedges and derivatives before third party transportation costs (c):
Natural gas (mcf)		$	3.83			$	5.44				-30	%		$	3.83			$	5.22				-27	%
NGLs (bbl)		$	44.24			$	50.43				-12	%		$	44.24			$	49.93				-11	%
Oil (bbl)		$	83.93			$	79.86				5	%		$	83.93			$	79.98				5	%
Gas equivalent (mcfe) (b)		$	4.96			$	6.49				-24	%		$	4.96			$	6.21				-20	%
Average prices, including cash-settled hedges and derivatives (d):
Natural gas (mcf)		$	3.01			$	4.62				-35	%		$	3.01			$	4.47				-33	%
NGLs (bbl)		$	42.68			$	49.44				-14	%		$	42.68			$	49.02				-13	%
Oil (bbl)		$	83.93			$	79.86				5	%		$	83.93			$	79.98				5	%
Gas equivalent (mcfe) (b)		$	4.27			$	5.84				-27	%		$	4.27			$	5.60				-24	%

 

(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.

(c)	Excluding third party transportation, gathering and compression costs.

(d)	Net of transportation, gathering and compression costs.

 

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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

 

		Three Months Ended June 30,												Six Months Ended June 30,
(Unaudited, in thousands, except per share data)		2012				2011				%				2012				2011				%
Income from continuing operations before income taxes, as reported		$	94,683			$	78,479				21	%		$	25,040			$	25,151				0	%
Adjustment for certain items:
(Gain) loss on sale of properties			3,227				1,622								13,653				1,483
Barnett discontinued operations less gain on sale			—				4,691								—				17,626
Change in mark-to-market on unrealized derivatives (gain) loss			(135,777	)			(48,139	)							(83,721	)			(8,103	)
Unrealized derivative (gain) loss			(594	)			(5,934	)							354				(6,502	)
Abandonment and impairment of unproved properties			43,641				18,900								63,930				35,437
Prior year Pennsylvania impact fee			707				—								24,707				—
Lawsuit settlements			900				—								1,416				70
Transportation and gathering – non-cash stock-based compensation			408				342								861				732
Direct operating – non-cash stock-based compensation			692				643								1,049				953
Exploration expenses – non-cash stock-based compensation			994				937								1,922				2,266
General & administrative – non-cash stock-based compensation			12,540				11,467								20,698				18,997
Deferred compensation plan – non-cash adjustment			9,333				(5,778	)							1,503				24,852
Income from operations before income taxes, as adjusted			30,754				57,230				-46	%			71,412				112,962				-37	%
Income tax expense, as adjusted
Current			—				8								—				8
Deferred			12,668				13,985								28,912				34,495
Net income excluding certain items, a non-GAAP measure		$	18,086			$	43,237				-58	%		$	42,500			$	78,459				-46	%
Non-GAAP income per common share
Basic		$	0.11			$	0.27				-59	%		$	0.27			$	0.50				-46	%
Diluted		$	0.11			$	0.27				-59	%		$	0.27			$	0.49				-45	%
Non-GAAP diluted shares outstanding, if dilutive			160,030				158,833								159,949				158,729

HEDGING POSITION AS OF JULY 18, 2012

(Unaudited)

 

		Daily Volume				Hedge Price		Premium (Paid) / Received
Gas (Mmbtu)
2Q 2012 Swaps			213,297			$3.92		($0.01)
2Q 2012 Collars			189,641			$5.32 – $5.91		($0.28)
3Q 2012 Swaps			220,000			$3.73		($0.02)
3Q 2012 Collars			279,641			$4.76 - $5.22		($0.19)
4Q 2012 Swaps			270,000			$3.77		($0.02)
4Q 2012 Collars			279,641			$4.76 - $5.22		($0.19)
2013 Swaps			177,521			$3.57		—
2013 Collars			240,000			$4.73 - $5.20		—
2014 Collars			285,000			$3.74 - $4.47		—
Oil (Bbls)
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			4,000			$94.56		—
2014 Collars			2,000			$85.55 - $100.00		—
C5 Natural Gasoline (Bbls)
2Q 2012 Swaps			10,681			$2.2923		—
3Q 2012 Swaps			6,500			$2.2923		—
4Q 2012 Swaps			6,500			$2.2923		—
2013 Swaps			6,500			$2.1343		—
C3 Propane (Bbls)
2Q 2012 Swaps			1,648			$1.1372		—
3Q 2012 Swaps			6,000			$1.2241		—
4Q 2012 Swaps			6,000			$1.2241		—
2013 Swaps			5,000			$0.9418		—

NOTE: SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS

 

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