Range Announces Second Quarter Results

RANGE RESOURCES CORPORATION (NYSE: RRC) today announced second quarter results. Production averaged 434 Mmcfe per day, representing another record high for the Company and a 14% increase over the prior-year quarter. This represents the 26^th consecutive quarter of sequential production growth. Currently, the Company is running 14 rigs versus 30 rigs at this time last year. While production increased 14%, realized prices fell 32%. Oil and gas prices, after adjustment for hedging, averaged $6.18 per mcfe, versus $9.03 per mcfe in the prior-year quarter. This compares to price realizations of $6.62 per mcfe for the first quarter of 2009. As a result, oil and gas sales (including cash-settled derivatives) declined 22% to $244 million. Cash flow from operations before changes in working capital, a non-GAAP measure, declined 29% to $156 million. Range reported a loss for the quarter of $40 million, down 23% from the prior year. Diluted earnings per share declined 18% to ($0.26) per share compared to ($0.22) per share in the prior year. Adjusting for certain non-cash items, net income comparable to analysts’ estimates would have been $34 million compared to $78 million in the second quarter of 2008. The diluted earnings per share using these analyst adjusted numbers would have been $0.21 in the second quarter of 2009. Adjusted earnings and cash flow both exceeded the average analysts’ estimates. (See the accompanying tables reconciling these non-GAAP measures.)

Commenting on the announcement, John Pinkerton, Range’s Chairman and CEO, said, "While our financial results reflect the decline in oil and gas prices, our operating results were outstanding, reflecting excellent second quarter drilling results. On the cost side of our business, unit operating costs continued to decline, and we are experiencing significant decreases in service costs. For the balance of the year, approximately 80% of our natural gas production is hedged at an average floor price of $7.49 per mcf, providing significant cash flow protection. In addition, we have recently added to our hedge position for 2010. Given our excellent portfolio of drilling opportunities driven by the Marcellus, Nora and the Barnett, coupled with our low cost structure and shallow decline property base, we are well positioned to continue our strategy of consistently growing production and reserves at low costs. Our core drilling projects are driving capital efficiency, allowing us to do more with less. In particular, given the progress we have made so far in 2009, we anticipate exiting 2009 at the higher end of the Marcellus production target rate of 80 – 100 Mmcfe per day net and doubling the production exit rate in 2010. As the Marcellus ramps up, we look for our capital efficiency to continue to strengthen.”

Financial Discussion –

(Excludes non-cash mark-to-market and non-cash stock-based compensation items shown separately on attached tables.)

For the quarter, production averaged 434 Mmcfe per day, comprised of 351 Mmcf per day of gas and 13,816 barrels per day of oil and natural gas liquids. Wellhead prices, including cash-settled derivatives, averaged $6.18 per mcfe, a 32% decrease over the prior-year period. The average gas price was $5.85 per mcf, a 31% decrease, and the average oil price decreased 16% to $60.88 a barrel.

Direct operating expenses for the quarter were $0.86 per mcfe, an 18% decrease versus the prior-year quarter of $1.05 and an 8% decrease compared to $0.93 in the first quarter of 2009. Production taxes were $0.19 per mcfe, a 59% decline versus the prior-year quarter of $0.46 per mcfe due to lower commodity prices and a 14% decrease compared to $0.22 per mcfe in the first quarter 2009. Exploration expense in the second quarter totaled $10 million, down 43% from $18 million in the prior year due primarily to lower seismic and dry hole costs. General and administrative expenses were $0.51 per mcfe, an increase of $0.02 per mcfe from the prior-year quarter primarily due to higher personnel costs associated with the Marcellus Shale play, and $0.01 per mcfe higher than first quarter 2009. Interest expense rose to $30 million compared to $24 million in the prior-year quarter, due to higher debt balances and the terming out of an additional $300 million of 10-year high yield notes at 8% during the quarter. Interest expense was $0.75 per mcfe as compared to $0.69 per mcfe for the prior-year quarter and $0.71 per mcfe for the first quarter 2009. Depreciation, depletion and amortization rose to $2.25 per mcfe, versus $2.08 per mcfe in the prior-year quarter, but remained level with first quarter 2009. As previously announced, Range has elected not to renew certain leases, primarily those outside the core of our North Texas Barnett Shale play, given current low commodity prices. The second quarter abandonment and impairment expense was $41 million compared to $3 million in the comparable period of the prior year.

Second quarter development expenditures totaled $110 million, funding the drilling of 145 (95.8 net) wells and 6 (5.9 net) recompletions. A 100% success rate was achieved. For the first six months of 2009, 161 (102.9 net) wells have been successfully drilled and are now on production, while 84 (55.9 net) wells are currently in various stages of completion or waiting on pipeline connection. Total capital expenditures for the second quarter, including all drilling, acreage, seismic and infrastructure costs aggregated $165 million. Excluding $16 million of Marcellus Shale acreage that was acquired in exchange for Range common stock, cash capital expenditures totaled $149 million. Second quarter cash flow of $156 million was more than sufficient to fund all of the cash capital expenditures for the quarter. For the year, cash flow and the proceeds from already completed asset sales are expected to fully fund capital expenditures. Range has hedged additional natural gas volumes for 2010. The current hedge position is 47% of the expected gas production for the first half of 2010 at a weighted average collar of a $5.50 floor and a $7.44 cap and 24% of expected production for the second half of 2010 at a weighted average collar of a $5.50 floor and a $7.50 cap.

Operational Discussion –

During the second quarter, the Marcellus Shale division continued to make excellent progress. Marcellus Shale production is on plan and now exceeds 50 Mmcfe per day net and is expected to approach the higher end of the previously announced target of 80 - 100 Mmcfe per day net by year end. From inception, Range has drilled and completed 46 horizontal Marcellus Shale wells, of which 41 are on production. Range currently estimates that of these, 24 wells (those with at least 120 days of production history) have an average gross ultimate recovery of 4.4 Bcfe. Range has posted on its website a zero-time-plot production curve based on the production to date from these 24 wells. (Such information is not a projection across all of our acreage nor is it a forecast of future well results.) Our current average cost to drill and complete in southwest Pennsylvania from a multi-well pad site is approximately $3.5 million per well, resulting in estimated finding and development costs of less than $1.00 per mcfe net. Range plans to drill approximately 70 horizontal wells in the Marcellus Shale play in 2009 with approximately 50 expected to be completed prior to year end. The Marcellus division currently has three horizontal rigs operating, which is scheduled to increase to six rigs by year end. The build out of the Marcellus midstream infrastructure in southwest Pennsylvania is progressing as scheduled. By December 2009 or January 2010, gross processing capacity should be expanded to 200 Mmcf per day. An additional 120 Mmcf per day of processing capacity has been ordered for start-up in early 2011, which is expected to increase gross processing capacity to more than 300 Mmcf per day.

The Southwest division also delivered strong drilling results in the second quarter. For the quarter, Barnett production averaged 120 Mmcfe per day net. The division recently tested seven wells in Denton County for a combined rate of 17 Mmcfe per day. These wells are expected to be online by the end of the month. We also completed two wells in northeast Parker County, one of which recently came online at 7.6 Mmcfe per day and may be the best well to date in that county. Plans are to complete the 2009 drilling program in the Barnett with a two-rig program. Activity will continue to focus in the core of our acreage where we have achieved excellent results and expect finding and development costs to approximate $1.25 per mcfe for the second half of the year.

During the second quarter 2009, Range’s Appalachian division continued to focus on its key coal bed methane, shale and tight gas sand drilling projects in the Nora area of Virginia. During the quarter, Range drilled three horizontal Huron Shale wells and one horizontal Big Lime well. Year-to-date, 11 horizontal wells have been completed in the Huron Shale, and two horizontal wells have been completed in the Berea. We also completed the first horizontal well in Virginia in the Big Lime formation at 3,500 feet. For the horizontal wells that are currently on production, the initial production rates have averaged 1.0 Mmcf per day. In addition, during the second quarter of 2009, 61 coal bed methane and 19 vertical tight gas sand wells were drilled in the Nora field.

The Midcontinent Division expanded several key areas during the first half of 2009 to reach a new record net production rate of 57 Mmcfe per day. In the second quarter, a total of 10 (7.0 net) wells were drilled at a 100% success rate. For the St. Louis Lime play in the Texas Panhandle, 2 (0.8 net) wells were completed during the quarter with combined production rates of 3.6 (1.3 net) Mmcfe per day. A third well has been logged and is waiting on completion. A six-mile pipeline, expected to be completed in August, will allow further development of the field and expansion of the St. Louis play.

Conference Call Information

The Company will host a conference call on Thursday, July 23 at 1:00 p.m. ET to review these results. To participate in the call, please dial 877-407-0778 and ask for the Range Resources second quarter financial results conference call. A replay of the call will be available through June 30 at 877-660-6853. The account number is 286 and the conference ID for the replay is 328371. Additional financial and statistical information about the period not included in this release but to be presented in 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 for 15 days.

Non-GAAP Financial Measures and Supplemental Tables:

Second quarter 2009 results included several non-cash items: a $61 million non-cash mark-to-market gain on unrealized derivatives, a $41 million impairment of unproved properties, a $3 million impairment of equity ventures, a $1 million expense recorded for the mark-to-market in the deferred compensation plan and $11 million of non-cash stock compensation expense. Excluding these items, net income would have been $34 million or $0.22 per share ($0.21 fully diluted). This compares favorably to analysts’ estimates of $0.18 per share. Excluding similar non-cash items from the prior-year quarter, net income would have been $78 million or $0.52 per share ($0.50 fully diluted). By excluding these non-cash items from our 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 accompanying table for calculation of these non-GAAP measures.)

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 SFAS No. 133 (Appalachia oil and gas hedges and Southwest oil hedges) are included in "Oil and gas sales” when settled. For those hedges designated to regions where the historical correlation between NYMEX and regional prices is "non-highly effective” (Southwest gas) or is "volumetric ineffective” due to sale of the underlying reserves (Southwest oil), 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 Form 10-Q along with the change in mark-to-market valuations of such unrealized derivatives. The Company has provided additional information regarding oil and gas sales in a supplemental table included with this release, which would correspond to amounts shown by analysts for oil and gas sales realized, including cash-settled derivatives.

"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.

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

Except for historical information, statements made in this release, including those relating to estimated reserves, significant potential, future or expected earnings, rates of return, expected debt reduction, asset sales, cash flow, capital expenditures, production growth, processing capacity or planned number of wells 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 the Company’s future performance are subject to a wide range of business risks and uncertainties and there is no assurance that these goals and projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward-looking statements, including, but not limited to, the volatility of oil and gas prices, the results of our hedging transactions, the costs and results of drilling and operations, the timing of production, mechanical and other inherent risks associated with oil and gas production, weather, the availability of drilling equipment, changes in interest rates, litigation, uncertainties about reserve estimates and environmental risks. The Company undertakes no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in the Company’s filings with the Securities and Exchange Commission, which are incorporated by reference.

(a) Certain minor amounts were restated in 2008 and prior. See Footnote (18) in June 2009 Form 10Q.

(b) See separate oil and gas sales information table.

(c) Costs associated with FASB 123R 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.

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

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

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

(a) Certain minor amounts were restated in 2008 and prior. See Footnote (18) in June 2009 Form 10Q.

(a) Certain minor amounts were restated in 2008 and prior. See Footnote (18) in June 2009 Form 10Q.

(a) Oil and natural gas liquids are converted to gas equivalents on a basis of six mcf per barrel.

(a) Certain minor amounts were restated in 2008 and prior. See Footnote (18) in June 2009 Form 10Q.

Note: Details as to the Company’s hedges are posted on its website and are updated periodically.