Range Announces Record 2008 Results

RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its 2008 results. Production, reserves, revenues, oil and gas sales, cash flow and earnings all reached record high levels for the year. Reported revenues were $1.32 billion up 53%, oil and gas sales were $1.23 billion up 42%, net cash provided from operating activities was $825 million up 30% and reported GAAP net income was $346 million or $2.22 diluted earnings per share, up 50% over the prior year. The following measures are non-GAAP financial measures that we believe are most comparable to analysts’ estimates for the same amounts for the year. Please see the accompanying definitions and tables for the reconciliation of each of these non-GAAP measures. Oil and gas sales including cash-settled derivatives totaled $1.21 billion, a 28% increase over the prior year. Cash flow from operations before changes in working capital increased 27% to $853 million. Adjusted net income comparable to analysts’ estimates was $309 million, increasing 22% from the prior comparable year. Diluted earnings per share (adjusted) were $1.98, a 16% increase. On the same basis as analysts’ estimates, earnings per share and cash flow from operations per share for the fourth quarter and for the full-year 2008 exceeded the average First Call estimates. A 20% increase in production coupled with a 7% rise in realized prices drove the record results. Proved reserves increased 19% to 2.7 Tcfe at year-end 2008. Range replaced 405% of production during the year at an all-in cost of $3.10 per mcfe. During 2008, Range invested approximately $600 million to acquire roughly 400,000 net acres of leasehold. Drill bit only finding cost was $1.70 per mcfe.

Commenting, John H. Pinkerton, the Company’s Chairman and CEO, said, "Record highs were achieved in 2008 for all key metrics both on an absolute and per share basis. Operationally, production rose 20% and proved reserves increased 19%. Additionally, we added 400,000 net acres to our leasehold inventory at an attractive cost averaging $1,500 per acre. The majority of this acreage was added in our Marcellus Shale play. Looking ahead, we are well-positioned to continue to add value in the current lower commodity price environment. Our drilling plans for 2009 have been scaled back to focus on the Barnett Shale, the Nora Field and the Marcellus Shale. Each of these areas provides attractive rates of return at current price levels. Our balance sheet is strong, and we have substantial liquidity under our bank facility. We have 81% of our 2009 natural gas production hedged at an average floor price of $7.62 per mcf. Importantly, we continue to make solid progress with regard to delineating and expanding our emerging plays. The unrisked resource potential of the drilling inventory and emerging plays is 8 to 10 times larger than our current proven reserves and will serve as the catalyst for our future growth for many years to come. We look at 2009 as being a year where we may be able to capture unique opportunities in our core operating areas.”

Production for the year totaled 141 Bcfe, comprised of 114 Bcf of gas and 4.5 million barrels of oil and liquids. Production rose in each quarter of the year and averaged 386 Mmcfe per day. Range has now achieved sequential production growth for 24 consecutive quarters. Wellhead prices, after adjustment for all cash-settled hedges and derivatives, rose 7% to $8.58 per mcfe. The average gas price rose 6% to $8.15 per mcf, as the average oil price rose 13% to $68.20 per barrel. The cash margin per mcfe for 2008 rose to a record $6.04 per mcfe, 7% higher than 2007.

Reported revenues for the fourth quarter were $345 million up 54%, net cash provided from operating activities was $224 million up 20% and net income was $94 million or $0.60 per diluted share, up 173% over the prior year. The amounts corresponding to analysts’ estimates for the same measures, which are non-GAAP measures for the fourth quarter of 2008, are as follows (see the accompanying tables for the reconciliation of these non-GAAP measures to their most directly comparable GAAP financial measure): Oil and gas revenues, including all cash-settled derivatives, declined 3% to $255 million, production increased by 17% to 403 Mmcfe per day, realized prices decreased 17% to $6.86 per mcfe, and cash flow from operations before changes in working capital decreased 13% to $165 million and diluted earnings per share (adjusted) decreased 21% to $0.33.

As previously noted, Range replaced 405% of production in 2008. Drilling alone replaced 367% of production. Proved reserves at December 31, 2008 totaled 2.7 Tcfe, including 2.2 Tcf of natural gas and 73 million barrels of crude oil and liquids. Reserves increased 421 Bcfe or 19% compared to the prior year. At year-end, reserves were 83% natural gas by volume, and the reserve life index stood at 18 years based on fourth quarter production rates. The percentage of proved undeveloped reserves increased to 38% versus 36% in 2007. Independent petroleum consultants reviewed 87% of the reserves by volume. At year-end, the pretax present value of proved reserves, based on constant prices and costs, discounted at 10% totaled $3.4 billion, and the after tax standardized measure was $2.6 billion. The reserve value was based on year-end benchmark prices of $5.71 per Mmbtu and $44.60 per barrel NYMEX. The Company’s all-in finding and development cost averaged $3.10 per mcfe. Drill bit only finding cost was $1.70 per mcfe.

2009 Capital Spending –

Range’s 2009 capital spending budget is currently $700 million which is expected to approximate cash flow based upon current commodity prices. We will monitor commodity prices and oil field service costs throughout the year and remain flexible to adjust our capital spending. Range is targeting 10% year-over-year production growth for 2009 with the current capital budget. The production growth target is entirely attributable to the Company’s drilling program. We currently anticipate spending $540 million to drill 500 wells (315 net) wells, $100 million for leasehold, $20 million for seismic and $40 million for pipelines and facilities. Nearly 90% of the drilling capital is attributable to Barnett Shale, Nora Field and Marcellus Shale, where well economics are attractive even at current service costs and natural gas prices. Range is considering the sale of a few properties in 2009. Proceeds from any asset sales will be used to seize opportunities that add per share value, such as drilling more wells at lower service costs, adding leasehold in key areas, making opportunistic acquisitions in our existing core operating areas or paying down debt.

Operational Highlights –

During the fourth quarter, the Marcellus Shale division continued to make outstanding progress in completion design and efficiencies and has brought to sales another significant producer. Our most recent horizontal well brought online had a maximum 24-hour rate to sales of 10.3 Mmcfe per day. This rate was achieved after being produced under compressor-constrained conditions for 14 days. Of the last eleven Marcellus wells announced, four had initial rates of 9.9 Mmcfe per day or more. The best well had an initial rate of 24.5 Mmcfe per day. We are also announcing results from two vertical delineation wells in the northeast part of the Marcellus play. These two vertical wells achieved 24-hour initial production rates of 6.3 Mmcfe per day and 2.3 Mmcfe per day. The 6.3 Mmcfe per day is the highest reported 24-hour initial rate from a vertical well in the Marcellus play to date. These initial vertical well results are very encouraging, and Range intends to analyze further opportunities including horizontal development in the northeast portion of the play. Since late October 2008, 13 new Marcellus horizontal wells have been brought online to the new gas processing facility. The 24-hour maximum production rate for those 13 wells averaged 6.9 Mmcfe per day. Again, several of those wells have been produced under constrained conditions. Currently there are 14 wells, including seven horizontals that have been fraced and are waiting on processing capacity expansion before they are turned to sales. In early April 2009, processing capacity is expected to expand from 30 to 60 Mmcf per day. Additional expansions are planned that would bring processing capacity to 180 Mmcf per day by late 2009 or early 2010. Plans are to drill more than 60 wells in the Marcellus Shale play in 2009. The targeted production exit rate for 2009 is 80 – 100 Mmcfe per day net. On the regulatory front, progress has been made in the permitting process for Marcellus Shale wells, and Range has a majority of its 2009 drilling permits already in hand. Range has also secured water withdrawal and disposal capacity for several years of activity in the Marcellus Shale.

During the quarter, four horizontal Huron Shale wells were drilled at the Nora Field in Virginia. To date, nine horizontals have been completed to the Huron Shale and one horizontal Berea well has been completed. Of the seven horizontal Huron Shale wells that are currently on production, the initial production rates have averaged 1.1 Mmcf per day. The initial production rate on the Berea horizontal well was 1.5 Mmcf per day. For 2009, Range plans 220 coal bed, 60 tight gas sand and 20 horizontal Huron Shale wells in the Nora field where Range has a 50% working interest. In West Virginia, Range completed a horizontal Big Lime well on its 77,000 acre Widen property in late 2008 with encouraging results and plans two additional horizontal wells in 2009 to continue testing this horizon.

In the Fort Worth Basin's Barnett Shale play, Range completed what it believes to be the best well in Hill County to date, for both the Company and the industry. The initial production rate from the Ellig #1-H was 9.0 Mmcfe per day, and it has averaged 4.8 Mmcfe per day over the first 30 days of production. Additional activity in the Fort Worth Basin included the completion of a pilot project to test 250-foot well spacing in southern Tarrant County. The first two pilot wells had a combined initial production rate of 14.0 Mmcfe per day. Range has more than 1,000 additional locations to drill in the core of the Barnett Shale play. The division plans 64 (61 net) new wells for 2009 in the North Texas Barnett Shale play.

Activity for the Midcontinent division in the fourth quarter included the drilling of 16 (6.2 net) wells with an 88% success rate. In the Texas Panhandle, Range's initial offset to its St. Louis discovery yielded production from the St. Louis Lime at a rate of 2.3 (0.9 net) Mmcfe per day. A second offset completed for 3.0 (1.1 net) Mmcfe per day, with a third well currently being completed. Two additional wells in the Watonga-Chickasha Trend commenced production during the quarter at rates of 2.0 (1.5 net) Mmcfe per day and 1.5 (1.2 net) Mmcfe per day. A deep Anadarko Basin well encountered significant Springer production, commencing sales at a rate of 10.9 (3.5 net) Mmcfe per day. Drilling has also continued in the Ardmore Basin Woodford Play, where three wells are currently being completed. The division plans 44 (25 net) new wells for 2009.

The Company will host a conference call on Wednesday, February 25 at 1:00 p.m. ET to review these results. To participate in the call, please dial 877-407-8035 and ask for the Range Resources 2008 financial results conference call. A replay of the call will be available through March 4 at 877-660-6853. The conference ID for the replay is 312118 and the Account number is 286.

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:

Earnings for 2008 included $83.9 million in mark-to-market gains on certain derivative transactions, derivative ineffective hedging gains of $1.7 million, $20.2 million gain on sale of properties, non-cash stock compensation expense of $6.5 million and an abandonment and impairment expense related to unproved properties of $47.9 million. Excluding such items, income before income taxes would have been $491 million, a 20% increase over the prior year. Adjusting for the after-tax effect of these items, the Company’s earnings would have been $309 million in 2008 or $2.05 per share ($1.98 per diluted share). If similar items were excluded, 2007 earnings would have been $254 million or $1.77 per share ($1.70 per diluted share). Earnings for 2007 included a mark-to-market derivative loss of $78.8 million, ineffective hedging losses of $0.8 million, $52.3 million of non-cash stock compensation and an abandonment and impairment expense related to unproved properties of $6.8 million. (See reconciliation of non-GAAP earnings in the accompanying table.) The Company believes results excluding these items are more comparable to estimates provided by security analysts and, therefore, are useful in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies.

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 is a critical component in the Company’s performance tracked by investors and professional research analysts in valuing, comparing, rating and providing investment recommendations and forecasts of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Due to the GAAP disclosures of various hedging and derivative transactions, such information is now reported in various lines of the 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 the details of each amount and provide a summary of the realized cash-settled amounts which historically were reported as oil and gas sales revenues. This information will serve to bridge the gap between various readers’ understanding and fully disclose the information needed.

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 expected reserves quantities, targeted capital expenditures, number of wells to be drilled, assessments of financial condition and liquidity, drilling inventory, unrisked resource potential and emerging plays resource potential 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. 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.

Finding costs from all sources is calculated by taking all cash expenditures for drilling, development, acreage and acquisitions divided by the sum of extensions, discoveries, additions, purchases and all pricing and performance revisions to reserve volumes. Drill bit finding costs is calculated by taking all cash expenditures for drilling and development costs divided by the sum of extensions, discoveries, additions and performance revisions to reserves volumes.

The Securities and Exchange Commission permits oil and gas companies, in filings made with the SEC, to disclose only 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. Range uses the terms "probable" and "possible" reserves, "unproven" or "unrisked resource potential” or "upside” or other descriptions of volumes of reserves or resources potentially recoverable through additional drilling or recovery techniques that the SEC's guidelines strictly prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by Range. 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. Resource potential does not constitute reserves within the meaning of the Society of Petroleum Engineer's Petroleum Resource Management System and does not include any proved reserves. Area wide unproven, unrisked resource potential has not been risked by Range's management. Actual quantities that may be ultimately recovered from Range's interests will differ substantially. Factors affecting ultimate recovery include the scope of Range's drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. 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 by calling the SEC at 1-800-SEC-0330.

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

(b) 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-K.

(c) Included in Derivative fair value income in 10-K.

(d) Included in Other revenues in the 10-K.

(e) Reflects the change in the market value of the vested Company stock and, in the prior year, other investments during the period held in the deferred compensation plan.

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

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

(c) Average prices, including all cash-settled derivatives.

(d) Excludes non-cash stock compensation.

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