EXHIBIT 99.1

RANGE ANNOUNCES SECOND QUARTER 2013 RESULTS

FORT WORTH, TEXAS, July 24, 2013…RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its second quarter 2013 financial results.

Second Quarter Highlights –

 

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Record daily production of 910 Mmcfe per day, an increase of 27% over the prior-year quarter; 30% adjusted for the New Mexico asset sale

 

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Adjusted cash flow was $227 million, an increase of 46% as compared to the prior year quarter

 

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Unit costs decline 7% as compared to the prior-year quarter

 

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New Mexico asset sale for $275 million closed April 1st generating $83 million pre-tax gain

 

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Class leading liquids-rich wells drilled in Pennsylvania continue to provide impressive results

 

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Initial ethane deliveries to Mariner West commenced July 21st

Changes in Guidance –

 

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Type curve and EUR increased 38% over the 2012 type curve in the super-rich SW PA area to 1.82 Mmboe (10.9 Bcfe)

 

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Type curve and EUR increased 41% in wet SW PA area to 12.3 Bcfe

 

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Type curve and EUR increased 63% in dry SW PA area to 12.2 Bcf

 

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Tighter spacing positive test results with 500 feet between laterals in Marcellus adds 12 to 15 Tcfe of unproved resource potential attributable to the super-rich and wet areas in the southwest

Commenting on the announcement, Jeff Ventura, Range’s President and CEO, said, “Range had an impressive first half of 2013, continuing to set record production results while decreasing our unit costs. Our balance sheet and liquidity are set for continued growth as outlined in our business plan of growing production 20% to 25% for many years. Importantly, cash flow growth is expected to outpace our production growth percentage. With the progress made during the first half of 2013, we are focused on the higher end of our production growth range for 2013. The first deliveries of ethane into Mariner West to Sarnia, Canada commenced start up operations on July 21^st. Range has access to the only operating de-ethanizer in Appalachia while others are still under construction. This will allow us to continue our planned growth without concern for pipeline quality requirements. Additional ethane and propane transportation projects are scheduled to become operational next year conforming to our growth plans. Our growth is led by our approximate one million acre leasehold position in Pennsylvania which essentially doubles when stacked pay reservoirs across most of our acreage in the Basin are considered. This acreage position is anchored by the Marcellus, one of the most prolific reservoirs in the U.S. We believe that our 20% to 25% production growth that we expect to deliver for many years, coupled with the high returns, low cost and low reinvestment risk will drive substantial per share value for our shareholders for years to come.”

Financial Discussion

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

GAAP revenues for the second quarter of 2013 totaled $673 million (a 50% increase as compared to second quarter 2012), GAAP net cash provided from operating activities including changes in working capital was $79 million (a 38% decrease as compared to second quarter 2012 primarily due to the payment of a previously announced legal settlement) and GAAP earnings increased by 159% to $144 million ($0.88 per diluted share) versus $56 million ($0.34 per diluted share) in the second quarter 2012.

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Non-GAAP revenues for second quarter 2013 totaled $431 million (a 36% increase as compared to second quarter 2012), cash flow from operations before changes in working capital, a non-GAAP measure, reached $227 million ($1.40 per diluted share, and a 46% increase as compared to second quarter 2012). Adjusted net income, a non-GAAP measure, was $55 million ($0.34 per diluted share, and a 204% increase as compared to second quarter 2012).

Several non-cash or non-recurring items impacted second quarter results. A $159.5 million mark-to-market commodity hedge gain was recorded. An $83.3 million gain on sale of properties was recognized primarily on the sale of New Mexico properties, effective April 1, 2013. A $52.9 million charge for lawsuit settlements was recorded, and $15.4 million of non-cash stock compensation expenses were recorded while a reduction in deferred compensation expense of $6.9 million was recognized with the decrease in the common stock price between quarters in the second quarter.

Reviewing the Company’s six major expense categories of direct operating expense, transportation, gathering and compression expense, production and ad valorem tax expense, general and administrative expense, interest expense and depletion, depreciation and amortization expense, total unit costs decreased by $0.30 per mcfe or 7% compared to the prior-year quarter led by decreases in production and ad valorem tax expense (-24%), interest expense (-18%), depreciation, depletion and amortization expense (-13%), general and administrative expense (-9%) and direct operating expense (-3%). These reductions more than offset a $0.12 per mcfe increase in transportation cost related to Range’s increased Marcellus activity and moving natural gas to more favorable markets.

As previously reported, second quarter production volumes reached a record high, averaging 910 Mmcfe per day, a 27% increase over the prior-year quarter. Year-over-year oil and condensate production increased 39%, NGL production rose 35%, while natural gas production increased 24%. Adjusting for the sale of the New Mexico properties which closed on April 1, 2013 comprising production of approximately 18 Mmcfe per day with 30% being liquids, second quarter production would have increased 30% over the prior year quarter with oil and condensate production increasing 57%, NGL production increasing 35% and natural gas production increasing 27%. The record production was driven by the continued success of the Company’s drilling program primarily in the Marcellus Shale. Realized prices, after adjustment for all cash-settled hedges, averaged $5.02 per mcfe, a 6% increase from the prior-year period. Production and realized prices by each commodity for the second quarter were: natural gas – 713 Mmcf per day ($4.20 per mcf), NGLs – 23,247 barrels per day ($32.91 per barrel) and crude oil and condensate – 9,500 barrels per day ($85.09 per barrel).

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 which are posted here and on our website.

Capital Expenditures

Second quarter drilling expenditures of $262 million funded the drilling of 79 (73 net) wells and the completion of previously drilled wells. A 100% drilling success rate was achieved. In addition, during the second quarter, $22 million was expended on acreage purchases, $14 million on gas gathering systems and $12 million on exploration expense. The Company remains on track with its 2013 capital expenditure budget of $1.3 billion.

Balance Sheet

During the second quarter, Range closed the $275 million sale of its New Mexico properties. The net proceeds were used to reduce the outstanding balance on the Company’s bank credit facility. In addition, in May, Range completed the redemption for all $250 million in outstanding principal of its 7.25% Senior Subordinated Notes due 2018. The principal along with the $9.1 million redemption premium was funded using borrowings under the bank credit facility. As a result, Range currently has no senior subordinated note maturities until 2019. At the end of the second quarter, the Company had approximately $1.4 billion of committed liquidity available under its $1.75 billion bank commitment amount and $2.0 billion bank credit facility borrowing base.

 

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Operational Discussion

Range has updated its investor presentation with updated pricing in its economic sensitivity analysis, revised EURs and type curves in southwest Pennsylvania and other financial and operational information. Please see www.rangeresources.com under the Investor Relations tab, “Presentations and Webcasts” area, for the presentation entitled, “Company Presentation – July 2013.”

EURs, Economics and Well Designs Updated –

The Southern Marcellus division recently updated its EURs, economics and well designs for each of the three Marcellus areas in southwest Pennsylvania. These updated well designs incorporate reduced cluster spacing, longer laterals, improved lateral targeting in the reservoir and increased frac stages. All of these improvements are currently being implemented.

The following are highlights from the resulting changes in the updated development program. More details are provided in the most current Company Presentation found on Range’s website.

In the super-rich area of southwest Pennsylvania, Range is expecting:

 

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to drill average lateral lengths of 4,500 feet with 22 frac stages

 

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the EUR to be 1.82 Mmboe per well (or 10.9 Bcfe per well) or 400 mboe per 1,000 feet of lateral (or 2.41 Bcfe on an equivalent basis for comparative purposes)

In the wet area of southwest Pennsylvania Range is expecting:

 

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to drill average lateral lengths of 4,200 feet with 21 frac stages

 

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the EUR to be 12.3 Bcfe or 2.93 Bcfe per 1,000 feet of lateral

In the dry area of southwest Pennsylvania Range is expecting:

 

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to drill average lateral lengths of 5,000 feet with 25 frac stages

 

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the EUR to be 12.2 Bcfe or 2.44 Bcfe per 1,000 feet of lateral

Tighter Spacing Test Results Released –

Range announced the results of its three-year tighter spacing tests with 500 feet between laterals as compared to the historical 1,000 foot spacing between laterals currently used. These tests covered two different pads drilled in the super-rich and wet areas where both 1,000 foot spaced wells and 500 foot spaced wells were drilled on each pad in opposite directions or utilizing existing offsetting 1,000 foot spaced wells. After three years of production history, the production results indicate that wells drilled with 500 feet between horizontal laterals average approximately 80% of the estimated ultimate recoveries of horizontal wells drilled with 1,000 foot spacing between wells. The Company has released the comparative zero time plot production curves for the test wells in the Company’s updated presentation. The Company has increased its estimated unproved resource potential by an incremental 12 to 15 Tcfe in the wet and super-rich areas in the Marcellus as a result of the tighter spacing of 500 foot laterals. This additional resource potential brings Range’s total future unproved resource potential estimate to 60 to 83 Tcfe excluding any unproved resource potential for its Utica Shale acreage or tighter spacing in the dry gas areas in the Marcellus which Range also believes are prospective for 500 foot spacing.

Southern Marcellus Shale Division –

During the second quarter, the division brought online 45 Marcellus wells in southwest Pennsylvania, with 19 wells in the super-rich area, 15 wells in the wet area and 11 dry gas wells. Infrastructure build out remained on track during the quarter and Range started delivering ethane on July 21^st for the initial commissioning of the Mariner West ethane pipeline to Sarnia, Canada. Range expects to deliver intermittently an average of 5,000 (4,175 net) barrels per day of ethane to the Mariner West pipeline during the second half of 2013 prior to full contract deliveries of 15,000 (12,525 net) barrels per day starting in early 2014. These initial ethane deliveries will also allow Range to meet pipeline quality specifications in southwest Pennsylvania.

 

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In the super-rich area of southwest Pennsylvania the division brought online 19 wells in the second quarter. The initial production rates of these super-rich wells averaged 1,863 (1,548 net) boe per day with 65% liquids (344 barrels condensate, 866 barrels NGLs and 3.9 Mmcf gas). All of the wells in the quarter were completed with reduced cluster spacing. The average lateral length for the wells was 3,686 feet and they averaged 18.8 frac stages per lateral. A six-well pad brought online early in the quarter had a 30-day average production rate per well of 1,037 (879 net) boe per day that was 69% liquids (160 barrels condensate, 556 barrels NGLs and 1.9 Mmcf gas). The higher initial production rates and higher expected recoveries are a result of improved lateral targeting and completion techniques that are now being applied across the super-rich and wet areas of the play. Future wells are expected to have an average lateral length of 4,500 feet and 22 frac stages.

Range also announced two super-rich wells with extraordinary 24-hour initial production rates that were turned to sales during July. The first well was drilled with a 4,115 foot lateral with 21 frac stages. The well tested at a peak 24-hour production rate into sales of 3,670 (3,046 net) boe per day with 72% liquids assuming 80% ethane extraction. The initial production rate includes 1,094 barrels of condensate per day, 1,540 barrels of NGLs per day and 6.2 Mmcf of gas per day. The second well had a peak 24-hour production rate into sales of 5,721 (4,748 net) boe per day with 63% liquids assuming 80% ethane extraction. The second well’s initial production rate was composed of 866 barrels per day of condensate, 2,727 barrels of NGLs per day and 12.8 Mmcf of gas per day. The second well was drilled with a 5,082 foot lateral and 26 frac stages. The pads are approximately ten miles apart.

In the wet area of southwest Pennsylvania the division brought online 15 wells in the second quarter. The initial production rates of these wet gas wells averaged 13.7 (11.5 net) Mmcfe per day with 38% liquids (8.5 Mmcf gas, 854 barrels NGLs and 16 barrels condensate). The average lateral length for these 15 wells was 2,627 feet and they averaged 13.5 frac stages per lateral, with 14 of the wells utilizing reduced cluster spacing. Twelve of the wet gas wells brought online in the second quarter have produced long enough to have a 30-day average of 7.5 (6.3 net) Mmcfe per day with 34% liquids (5.0 Mmcf gas, 425 barrels NGLs and 2 barrels condensate) despite being curtailed due to pipeline and plant constraints. Future wells are expected to have an average lateral length of 4,200 feet and 21 frac stages.

In the dry gas area of southwest Pennsylvania the division brought online 11 (9.6 net) wells during the second quarter. The initial production rates of these wells averaged 8.5 Mmcf per day with an average lateral length of 2,974 feet and an average of 14.4 frac stages per lateral. Future dry gas Marcellus wells in southwest Pennsylvania are expected to utilize longer laterals and additional frac stages with an average lateral length of 5,000 feet and 25 frac stages.

At quarter-end the division’s backlog of wells waiting on completion or pipeline connection decreased to 41 wells. Range expects to turn to sales a total of 103 wells in the southern Marcellus during 2013.

Northern Marcellus Shale Division –

In northeast Pennsylvania, Range brought online two wells in the second quarter, both in Lycoming County. These two wells produced at an average 24-hour production rate per well of 12.6 (10.7 net) Mmcf per day from an average lateral length of 3,342 feet with 10.5 frac stages. The division’s backlog of uncompleted wells and wells waiting on pipeline connection increased to 29 at quarter-end. Range anticipates drilling another eight wells and completing some of its backlog in northeast Pennsylvania during the remainder of 2013. The eight wells are expected to be drilled with laterals of 4,000 feet to 6,600 feet. Several wells expected to be drilled in early 2014 are designed with 6,500 foot to 7,000 foot laterals.

At the end of the second quarter, in the Bradford County area operated by Talisman, there were a total of 27 (7.9 net) wells producing and 36 (10.7 net) wells waiting on completion or pipeline connection.

In northwest Pennsylvania, Range continues to monitor offset Utica shale activity where the Company has approximately 181,000 net acres of leasehold prospective for liquids-rich Utica shale.

Midcontinent Division –

During the second quarter, the Midcontinent division continued to focus on Range’s horizontal Mississippian acreage along the Nemaha Ridge. The division tested smaller volume stimulation designs during late 2012 through part of the second quarter. Results were below expectations, so the division moved back to a larger volume. A total of 11 (10.1 net) wells were turned to sales during the quarter with average lateral lengths of 3,776 feet with 20 frac stages. The division has brought online 28 wells so far this year and the 30-day average IP rate per well is 346 (270 net) boe per day with 76% liquids.

 

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Notably, the division recently completed three wells with larger stimulations. One well was turned to production with a 24-hour initial production rate of 1,306 (788 net) boe per day that was 66% liquids (230 barrels oil, 629 barrels NGLs and 2,682 mcf gas) from a lateral of 4,288 feet with 20 frac stages. The second well was turned to sales with an initial 24-hour peak rate of 957 (788 net) boe per day that was 55% liquids (268 barrels oil, 258 barrels NGLs and 2,585 mcf gas) from a lateral of 3,615 feet with 20 stages. In the last few days, the third well’s 24-hour initial production rate was 1,116 (826 net) boe per day with 80% liquids (625 barrels oil, 287 barrels NGLs and 1,225 mcf gas) from a lateral of 4,265 feet with 23 frac stages. Results from the wells with the larger stimulations indicate that EURs are expected to be in the range of 485 – 600 Mboe per well. Range anticipates bringing online an additional 10 to 12 net Horizontal Mississippian wells by year-end using the larger stimulation design.

Range completed one operated St. Louis well during the quarter with a 24-hour initial production rate to sales of 8.3 (5.8 net) Mmcfe per day with 30% liquids. Earlier in the year, two additional operated wells with lower working interest were turned to sales with 24-hour initial production rates of 11.2 (1.9 net) Mmcfe per day and 5.3 (0.9 net) Mmcfe per day. In addition, Range expects to drill two to four more wells in that area by the end of 2013.

Permian Division –

Range’s Permian division drilled eight additional vertical Wolfberry test wells in the second quarter of 2013. Initial production rates based on 24-hour tests averaged 342 (270 net) boe per day with 80% liquids (193 barrels oil, 79 barrels NGLs and 423 mcf gas). In the Cline Shale, Range continues to monitor industry activity in an area where the Company has approximately 100,000 net acre position that is over 90% held by production.

Southern Appalachia Division –

The Southern Appalachia division continued development of multi-pay horizons on its 350,000 (250,000 net) acre position in Virginia during the second quarter of 2013. Range owns the fee minerals on 216,000 acres of this position and receives the added economic benefit of the royalty for wells drilled on this acreage. The division had two drilling rigs running in the quarter and drilled 12 wells including seven horizontal Huron Shale wells and five coalbed methane wells. The horizontal Huron wells set new records in Virginia for lateral length with two laterals over 4,500 feet. Four of these horizontals have been brought online with early average production rates being the best to date. The division turned online a total of 9 wells during the quarter.

Guidance –

Production Guidance:

Production growth for 2013 is targeted to the higher end of our 20% to 25% year-over-year guidance. Production for the third quarter of 2013 is expected to range between 945 to 950 Mmcfe per day. Liquids are expected to be approximately 22% of third quarter production. The Company has included in this guidance for the third quarter an average of 1,630 (1,360 net) barrels per day of ethane deliveries for the Mariner West pipeline commissioning process. These projected initial volumes may be subject to start up delays while commissioning the pipeline, ethane storage facilities and the cracker in Canada. The Company continues to expect to deliver on average 5,000 (4,175 net) barrels per day of ethane over the last six months of the year. Under the current contract arrangements, Range is scheduled to increase ethane deliveries under this first ethane arrangement to 15,000 barrels per day at the beginning of 2014. Because ethane deliveries are FOB the Houston processing plant, the Company is not expected to incur any additional costs associated with the contract and will record ethane sales as deliveries are made.

 

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Guidance for 2013 Activity:

Under the current plan, Range expects to turn to sales approximately 173 net wells in the Marcellus and Horizontal Mississippian during 2013, as shown below:

 

		Wells in First Half 2013				Remaining 2013 Wells				Planned Total Wells to Sales in 2013
Super-Rich area			39				20				59
Wet area			15				11				26
Dry area (NE & SW)			28				21				49
Total Marcellus			82				52				134
Hz. Mississippian			28				11				39
Total			110				63				173

Expense per mcfe 3Q 2013 Guidance:

 

Direct operating expense:		$	0.38—$0.40 per mcfe
Transportation, gathering and compression expense:		$	0.80—$0.82 per mcfe
Production tax expense:		$	0.14—$0.15 per mcfe
Exploration expense:		$	19—$21 million
Unproved property impairment expense:		$	15—$17 million
G&A expense:		$	0.40—$0.42 per mcfe
Interest expense:		$	0.51—$0.52 per mcfe
DD&A expense:		$	1.46—$1.48 per mcfe

Differential Pricing History (a)

 

		1Q 2012				2Q 2012				3Q 2012				4Q 2012				1Q 2013				2Q 2013
Natural Gas		($	0.02	)		($	0.13	)		($	0.03	)		$	0.18			$	0.15			$	0.04
NGL (% of WTI NYMEX)			48	%			39	%			33	%			43	%			38	%			33	%
Oil (% of WTI NYMEX)			88	%			91	%			90	%			89	%			90	%			89	%

 

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

Hedging Status

Range hedges portions of its expected future production volumes to increase the predictability of cash flow and to help maintain a strong, flexible financial position. Range currently has over 75% of its expected remaining 2013 (third and fourth quarter) natural gas production hedged at a weighted average floor price of $4.18 per mcf. Similarly, Range has hedged more than 80% of its projected remaining crude oil production at a floor price of $94.80 and more than 50% of its composite NGL production near current market prices. Please see Range’s detailed hedging schedule posted at the end of the financial tables below and on its website at www.rangeresources.com.

Effective March 1, 2013, Range elected to discontinue hedge accounting for derivative contracts and moved to mark-to-market accounting for its derivative contracts. The mark-to-market accounting treatment may create fluctuations in earnings as commodity prices change both positively and negatively, however, such mark-to-market adjustments have no cash flow impact. The impact to cash flow will occur as the underlying contracts are settled. As of July 1, 2013, the Company expects to reclassify into earnings $49.5 million of unrealized net gains frozen in the first quarter with discontinuance of hedge accounting in the remaining six months of 2013 and $10.9 million of unrealized net gains in 2014.

Conference Call Information

A conference call to review the financial results is scheduled on Thursday, July 25 at 11:00 a.m. ET. To participate in the call, please dial 877-407-0778 and ask for the Range Resources second quarter 2013 financial results conference call. A replay of the call will be available through August 25. To access the phone replay dial 877-660-6853. The conference ID is 417201.

 

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A simultaneous webcast of the call may be accessed over the Internet at http://www.rangeresources.com. The webcast will be archived for replay on the Company’s website until August 25.

Non-GAAP Financial Measures:

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

Second quarter 2013 earnings included a gain of $159.5 million for the non-cash unrealized mark-to-market increase in value of the Company’s derivatives, a gain of $83.3 million primarily for sale of the New Mexico properties closed on April 1, unproved property impairment expense of $19.2 million, a $6.9 million gain recorded for the mark-to-market in the deferred compensation plan, a $52.9 million expense primarily for settlement of a class action lawsuit concerning alleged deductions from prices used to calculate royalties paid to royalty owners in certain Oklahoma wells in prior years, and $15.4 million of non-cash stock compensation expenses. Excluding these and other items, net income would have been $55.0 million or $0.34 per diluted share. Excluding similar non-cash items from the prior-year quarter, net income would have been $18.1 million or $0.11 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 defined in this release represents net cash provided by operations before changes in working capital and exploration expense adjusted for certain non-cash compensation items. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company’s ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operations, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity. A table is included which reconciles “Net cash provided by operations” to “Cash flow from operations before changes in working capital” as used in this release. On its website, the Company provides additional comparative information on prior periods for cash flow, cash margins and non-GAAP earnings as used in this release.

The cash prices realized for oil and natural gas production including the amounts realized on cash-settled derivatives and net of transportation, gathering and compression expense 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 derivative transactions and third party transportation, gathering and compression expense, such information is now reported in various lines of the income statement. The Company believes that it is important to furnish a table reflecting the details of the various components of each income statement line to better inform the reader of the details of each amount and provide a summary of the realized cash-settled amounts and third party transportation, gathering and compression expense 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 unaudited 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.

 

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Hedging and Derivatives

As discussed in this news release, Range has reclassified within total revenues its financial reporting of the cash settlement of its commodity derivatives. Under this presentation, those hedges considered “effective” under ASC 815 are included in “Natural gas, NGLs and oil sales” when settled. For undesignated hedges and those hedges designated to regions where the historical correlation between NYMEX and regional prices is “non-highly effective” or is “volumetric ineffective” due to sale of the underlying reserves, they are deemed to be “derivatives” and the cash settlements are included in a separate line item shown as “Derivative fair value income (loss)” in the consolidated statements of operations included in the Company’s Form 10-Q along with the change in mark-to-market valuations of such unrealized derivatives. Effective March 1, 2013 the Company de-designated all commodity contracts and elected to discontinue hedge accounting prospectively. 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 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/.

All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future growth in production, low-reinvestment risk, earnings and per-share value, improved well performance, expected greater capital efficiency, future rates of return, continued drilling improvements, capital spending plans, disproportionate growth in liquids production, cost structure improvements, reduction in operating costs, sole access to facilities, reserves in stacked reservoirs, resolution of pipeline quality requirements, planned exports, expected drilling and development plans, future guidance information, technical progress, estimated ethane volumes, progress in liquid-rich areas, unproved resource potential, continued improvements, growth objectives, future low cost structure, EURs, estimated capital to drill and complete wells and superior economics are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management’s assumptions and Range’s future performance are subject to a wide range of business risks and uncertainties and there is no assurance that these goals and projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward-looking statements, including, but not limited to, the volatility of oil and gas prices, the results of our hedging transactions, the costs and results of actual drilling and operations, the timing of production, mechanical and other inherent risks associated with oil and gas production, weather, the availability of drilling equipment, changes in interest rates, litigation, uncertainties about reserve estimates, environmental risks and regulatory changes. Range undertakes no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in Range’s filings with the Securities and Exchange Commission (“SEC”), which are incorporated by reference.

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

 

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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. Actual quantities that may be recovered from Range’s interests could differ substantially. Factors affecting ultimate recovery include the scope of Range’s drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, field spacing rules, recoveries of gas in place, length of horizontal laterals, actual drilling results, including geological and mechanical factors affecting recovery rates and other factors. Estimates of resource potential may change significantly as development of our resource plays provides additional data. Investors are urged to consider closely the disclosure in our most recent Annual Report on Form 10-K, available from our website at www.rangeresources.com or by written request to 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. You can also obtain this Form 10-K by calling the SEC at 1-800-SEC-0330.

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. 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.

2013-18

SOURCE: Range Resources Corporation

Investor Contacts:

Rodney Waller, Senior Vice President

817-869-4258

David Amend, Investor Relations Manager

817-869-4266

Laith Sando, Research Manager

817-869-4267

Michael Freeman, Financial Analyst

817-869-4264

or

Media Contact:

Matt Pitzarella, Director of Corporate Communications

724-873-3224

www.rangeresources.com

 

9

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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

(Unaudited, in thousands, except per share data)

 

		Three Months Ended June 30,												Six Months Ended June 30,
		2013				2012				%				2013				2012				%
Revenues and other income:
Natural gas, NGLs and oil sales (a)		$	437,678			$	298,349							$	835,917			$	615,966
Derivative cash settlements gain (loss) (a) (b)			(21,767	)			12,198								(21,385	)			4,369
Change in mark-to-market on unrealized derivatives gain (loss) (b)			159,371				135,777								62,569				83,721
Ineffective hedging (loss) gain (b)			155				594								(3,300	)			(354	)
Gain (loss) on sale of properties			83,287				(3,227	)							83,121				(13,653	)
Brokered natural gas and marketing			14,404				5,406								35,462				8,681
Equity method investment (c)			353				501								273				817
Other (c)			(125	)			(667	)							(62	)			339
Total revenues and other income			673,356				448,931				50	%			992,595				699,886				42	%
Costs and expenses:
Direct operating			31,940				26,349								61,467				55,014
Direct operating – non-cash stock compensation (d)			696				692								1,357				1,049
Transportation, gathering and compression			66,048				44,744								128,464				85,564
Production and ad valorem taxes			11,113				11,079								22,496				23,713
Pennsylvania impact fee —prior year			—				707								—				24,707
Brokered natural gas and marketing			16,132				6,083								38,198				9,692
Brokered natural gas and marketing – non-cash stock-based compensation (d)			530				408								779				861
Exploration			12,108				14,523								27,818				35,111
Exploration – non-cash stock compensation (d)			960				994								2,030				1,922
Abandonment and impairment of unproved properties			19,156				43,641								34,374				63,930
General and administrative			35,607				30,565								70,961				60,620
General and administrative – non-cash stock compensation (d)			13,263				12,540								23,569				20,698
General and administrative – lawsuit settlements			52,867				900								91,265				1,416
General and administrative – bad debt expense			250				—								250				—
Deferred compensation plan (e)			(6,878	)			9,333								35,482				1,503
Interest expense			45,071				42,888								87,281				80,093
Loss on early extinguishment of debt			12,280				—								12,280				—
Depletion, depreciation and amortization			119,995				108,802								235,096				208,953
Impairment of proved properties and other assets			741				—								741				—
Total costs and expenses			431,879				354,248				22	%			873,908				674,846				29	%
Income from continuing operations before income taxes			241,477				94,683				155	%			118,687				25,040				374	%
Income tax expense (benefit):
Current			(25	)			—								—				—
Deferred			97,519				39,007								50,314				11,164
			97,494				39,007								50,314				11,164
Net income		$	143,983			$	55,676				159	%		$	68,373			$	13,876				393	%
Income Per Common Share:
Basic		$	0.88			$	0.34							$	0.42			$	0.09
Diluted		$	0.88			$	0.34							$	0.42			$	0.09
Weighted average common shares outstanding, as reported:
Basic			160,565				159,412				1	%			160,346				159,162				1	%
Diluted			161,414				160,030				1	%			161,223				159,949				1	%

 

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

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

(c)	Included in Brokered natural gas, marketing and 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.

 

10

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RANGE RESOURCES CORPORATION

BALANCE SHEETS

 

		June 30, 2013				December 31, 2012
(In thousands)		(Unaudited)				(Audited)
Assets
Current assets		$	176,396			$	190,062
Current unrealized derivatives			97,052				137,552
Natural gas and oil properties			6,333,791				6,096,184
Transportation and field assets			36,207				41,567
Other			286,736				263,370
		$	6,930,182			$	6,728,735
Liabilities and Stockholders’ Equity
Current liabilities		$	502,010			$	448,202
Current asset retirement obligation			2,366				2,470
Current unrealized derivatives			—				4,471
Bank debt			309,000				739,000
Subordinated notes			2,639,835				2,139,185
			2,948,835				2,878,185
Deferred tax liability			735,166				698,302
Unrealized derivatives			—				3,463
Deferred compensation liability			207,906				187,604
Long-term asset retirement obligation and other			148,116				148,646
			1,091,188				1,038,015
Common stock and retained earnings			2,352,646				2,278,243
Treasury stock			(3,751	)			(4,760	)
Accumulated other comprehensive income			36,888				83,909
Total stockholders’ equity			2,385,783				2,357,392
		$	6,930,182			$	6,728,735

 

11

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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)		2013				2012				2013				2012
Net income (loss)		$	143,983			$	55,676			$	68,373			$	13,876
Adjustments to reconcile net cash provided from continuing operations:
(Gain) loss from equity investment, net of distributions			(2,162	)			2,042				(1,552	)			2,293
Deferred income tax expense (benefit)			97,519				39,007				50,314				11,164
Depletion, depreciation, amortization and proved property impairment			120,736				108,802				235,837				208,953
Exploration dry hole costs			—				108				(159	)			817
Abandonment and impairment of unproved properties			19,156				43,641				34,374				63,930
Mark-to-market (gain) loss on oil and gas derivatives not designated as hedges			(159,371	)			(135,777	)			(62,569	)			(83,721	)
Unrealized derivatives (gain) loss			(155	)			(594	)			3,300				354
Allowance for bad debts			250				—				250				—
Amortization of deferred issuance costs, loss on extinguishment of debt, and other			14,582				2,045				16,662				3,893
Deferred and stock-based compensation			8,334				23,833				63,325				26,341
Gain (loss) on sale of assets and other			(83,287	)			3,227				(83,121	)			13,653
Changes in working capital:
Accounts receivable			(15,289	)			(336	)			(13,997	)			11,611
Inventory and other			1,379				(1,927	)			1,545				(2,824	)
Accounts payable			(16,156	)			(30,884	)			(10,381	)			(21,922	)
Accrued liabilities and other			(50,879	)			18,106				(22,312	)			34,528
Net changes in working capital			(80,945	)			(15,041	)			(45,145	)			21,393
Net cash provided from operating activities		$	78,640			$	126,969			$	279,889			$	282,946

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)		2013				2012				2013				2012
Net cash provided from operating activities, as reported		$	78,640			$	126,969			$	279,889			$	282,946
Net changes in working capital from continuing operations			80,945				15,041				45,145				(21,393	)
Exploration expense			12,108				14,415				27,977				34,294
Lawsuit settlements			52,867				900				91,265				1,416
Equity method investment distribution / intercompany elimination			1,809				(2,544	)			1,278				(3,110	)
Prior year Pennsylvania impact fee			—				707				—				24,707
Non-cash compensation adjustment			247				245				41				(143	)
Cash flow from operations before changes in working capital, a non-GAAP measure		$	226,616			$	155,733			$	445,595			$	318,717
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING
		Three Months Ended June 30,								Six Months Ended June 30,
(Unaudited, in thousands)		2013				2012				2013				2012
Basic:
Weighted average shares outstanding			163,211				162,325				163,027				162,031
Stock held by deferred compensation plan			(2,646	)			(2,913	)			(2,681	)			(2,869	)
Adjusted basic			160,565				159,412				160,346				159,162
Dilutive:
Weighted average shares outstanding			163,211				162,325				163,027				162,031
Dilutive stock options under treasury method			(1,797	)			(2,295	)			(1,804	)			(2,082	)
Adjusted dilutive			161,414				160,030				161,223				159,949

 

RECONCILIATION OF TOTAL REVENUES AND OTHER

INCOME TO TOTAL REVENUE EXCLUDING CERTAIN

ITEMS, a non-GAAP measure

 

		Three Months Ended June 30,												Six Months Ended June 30,
(Unaudited, in thousands)		2013				2012				%				2013				2012				%
Total revenues and other income, as reported		$	673,356			$	448,931				50	%		$	992,595			$	699,886				42	%
Adjustment for certain special items:
Change in mark-to-market on unrealized derivative (gain) loss			(159,371	)			(135,777	)							(62,569	)			(83,721	)
Ineffective hedging (gain) loss			(155	)			(594	)							3,300				354
(Gain) loss on sale of properties			(83,287	)			3,227								(83,121	)			13,653
Total revenues, as adjusted, non-GAAP		$	430,543			$	315,787				36	%		$	850,205			$	630,172				35	%

 

12

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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

 

		Three Months Ended June 30,												Six Months Ended June 30,
(Unaudited, in thousands, except per unit data)		2013				2012				%				2013				2012				%
Natural gas, NGLs and oil sales components:
Natural gas sales		$	272,720			$	111,413							$	526,665			$	239,481
NGLs sales			66,587				56,280								134,158				132,778
Oil sales			73,562				52,075								151,562				107,497
Cash-settled hedges (effective):
Natural gas			24,694				78,896								23,315				136,525
Crude oil			115				(315	)							217				(315	)
Total natural gas, NGLs and oil sales, as reported		$	437,678			$	298,349				47	%		$	835,917			$	615,966				36	%
Derivative fair value income (loss) components:
Cash-settled derivatives (ineffective):
Natural gas		$	(24,698	)		$	1,278							$	(23,319	)		$	2,463
NGLs			3,043				10,152								2,148				5,760
Crude Oil			(111	)			768								(213	)			(3,854	)
Change in mark-to-market on unrealized derivatives			159,371				135,777								62,569				83,721
Unrealized ineffectiveness			155				594								(3,300	)			(354	)
Total derivative fair value income (loss), as reported		$	137,760			$	148,569							$	37,885			$	87,736
Natural gas, NGLs and oil sales, including all cash-settled derivatives (c):
Natural gas sales		$	272,716			$	191,587							$	526,661			$	378,469
NGL sales			69,630				66,432								136,306				138,538
Oil sales			73,566				52,528								151,566				103,328
Total		$	415,912			$	310,547				34	%		$	814,533			$	620,335				31	%
Third party transportation, gathering and compression fee components:
Natural gas		$	62,754			$	42,168							$	121,995			$	80,674
NGLs			3,294				2,576								6,469				4,890
Total transportation, gathering and compression, as reported		$	66,048			$	44,744							$	128,464			$	85,564
Production during the period (a):
Natural gas (mcf)			64,926,278				52,293,227				24	%			126,950,234				98,926,434				28	%
NGLs (bbl)			2,115,489				1,570,593				35	%			4,004,913				3,131,419				28	%
Oil (bbl)			864,517				623,026				39	%			1,777,179				1,231,103				44	%
Gas equivalent (mcfe) (b)			82,806,314				65,454,941				27	%			161,642,786				125,101,566				29	%
Production – average per day (a):
Natural gas (mcf)			713,476				574,651				24	%			701,383				543,552				29	%
NGLs (bbl)			23,247				17,259				35	%			22,127				17,206				29	%
Oil (bbl)			9,500				6,846				39	%			9,819				6,764				45	%
Gas equivalent (mcfe) (b)			909,959				719,285				27	%			893,054				687,371				30	%
Average prices, including cash-settled hedges and derivatives before third party transportation costs:
Natural gas (mcf)		$	4.20			$	3.66				15	%		$	4.15			$	3.83				8	%
NGLs (bbl)		$	32.91			$	42.30				-22	%		$	34.03			$	44.24				-23	%
Oil (bbl)		$	85.09			$	84.31				1	%		$	85.28			$	83.93				2	%
Gas equivalent (mcfe) (b)		$	5.02			$	4.74				6	%		$	5.04			$	4.96				2	%
Average prices, including cash-settled hedges and derivatives (d):
Natural gas (mcf)		$	3.23			$	2.86				13	%		$	3.19			$	3.01				6	%
NGLs (bbl)		$	31.36			$	40.66				-23	%		$	32.42			$	42.68				-24	%
Oil (bbl)		$	85.09			$	84.31				1	%		$	85.28			$	83.93				2	%
Gas equivalent (mcfe) (b)		$	4.23			$	4.06				4	%		$	4.24			$	4.27				-1	%
Transportation, gathering and compression expense per mcfe		$	0.80			$	0.68				17	%		$	0.79			$	0.68				16	%

 

(a)	Represents volumes sold regardless of when produced.

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

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

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

 

13

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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)		2013				2012				%				2013				2012				%
Income from continuing operations before income taxes, as reported		$	241,477			$	94,683				155	%		$	118,687			$	25,040				374	%
Adjustment for certain special items:
Gain (loss) on sale of properties			(83,287	)			3,227								(83,121	)			13,653
Change in mark-to-market on unrealized derivatives (gain) loss			(159,371	)			(135,777	)							(62,569	)			(83,721	)
Unrealized derivative (gain) loss			(155	)			(594	)							3,300				354
Abandonment and impairment of unproved properties			19,156				43,641								34,374				63,930
Loss on early extinguishment of debt			12,280				—								12,280				—
Prior year Pennsylvania impact fee			—				707								—				24,707
Proved property and other asset impairment			741				—								741				—
Lawsuit settlements			52,867				900								91,265				1,416
Brokered natural gas and marketing – non cash stock-based compensation			530				408								779				861
Direct operating – non-cash stock-based compensation			696				692								1,357				1,049
Exploration expenses – non-cash stock-based compensation			960				994								2,030				1,922
General & administrative – non-cash stock-based compensation			13,263				12,540								23,569				20,698
Deferred compensation plan – non-cash adjustment			(6,878	)			9,333								35,482				1,503
Income from operations before income taxes, as adjusted			92,279				30,754				200	%			178,174				71,412				150	%
Income tax expense, as adjusted
Current			(25	)			—								—				—
Deferred			37,273				12,668								70,266				28,912
Net income excluding certain items, a non-GAAP measure		$	55,031			$	18,086				204	%		$	107,908			$	42,500				154	%
Non-GAAP income per common share
Basic		$	0.34			$	0.11				209	%		$	0.67			$	0.27				148	%
Diluted		$	0.34			$	0.11				209	%		$	0.67			$	0.27				148	%
Non-GAAP diluted shares outstanding, if dilutive			161,414				160,030								161,223				159,949

HEDGING POSITION AS OF JULY 24, 2013 –

(Unaudited)

 

		Daily Volume				Hedge Price
Gas (Mmbtu)
3Q 2013 Swaps			300,000			$	3.75
3Q 2013 Collars			280,000			$	4.59—$5.05
4Q 2013 Swaps			293,370			$	3.82
4Q 2013 Collars			280,000			$	4.59—$5.05
2014 Swaps			30,000			$	4.17
2014 Collars			447,500			$	3.84—$4.48
2015 Collars			145,000			$	4.07—$4.56
Oil (Bbls)
3Q 2013 Swaps			5,825			$	96.74
3Q 2013 Collars			3,000			$	90.60—$100.00
4Q 2013 Swaps			6,825			$	96.79
4Q 2013 Collars			3,000			$	90.60—$100.00
2014 Swaps			7,000			$	94.14
2014 Collars			2,000			$	85.55—$100.00
2015 Swaps			2,000			$	90.20
C5 Natural Gasoline (Bbls)
3Q 2013 Swaps			6,500			$	2.134
4Q 2013 Swaps			6,500			$	2.134
C3 Propane (Bbls)
3Q 2013 Swaps			9,326			$	0.940
4Q 2013 Swaps			10,000			$	0.941
2014 Swaps			1,000			$	0.960

 

14

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NOTE: SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS

 

15