EXHIBIT 99.1
NEWS RELEASE
RANGE ANNOUNCES 2009 RESULTS
FORT WORTH, TEXAS, FEBRUARY 23, 2010...RANGE RESOURCES CORPORATION (NYSE: RRC)today announced its 2009 results. For 2009, Range again achieved its goal of double-digit production and reserve growth at a top-quartile or better cost structure, while maintaining a strong financial position. Specifically in 2009, production increased 13%, while sequential production growth reached 28 consecutive quarters. Proved reserves increased 18%, with all-in reserve replacement of 486%. All-in finding and development cost averaged $1.00 per mcfe, while drill bit only finding cost averaged $0.69 per mcfe. Production and reserve growth on a debt-adjusted, per share basis exceeded 10%, representing the fifth consecutive year of double-digit per-share growth for both production and reserves. This growth was achieved despite roughly a 50% decrease in capital spending and the sale of $219 million of properties. Financial discipline was maintained as total debt declined by $83 million, while fully diluted shares outstanding increased by only 1.8%.
Financial results for 2009 were negatively impacted by the decline in oil and gas prices. Year-over-year, oil and gas prices fell 56%, however Range’s hedging program softened the decline as our average realized prices, after hedging declined by only 25%. The decline in prices more than offset the increase in production resulting in oil and gas sales revenue (including cash-settled derivatives) decreasing 15% to $1.02 billion. Reported GAAP earnings resulted in a loss of $53.9 million or a diluted loss per share of $0.35, while net cash provided from operating activities including changes in working capital totaled $591.7 million. Adjusted net income comparable to analysts’ estimates was $164.7 million with diluted earnings per share of $1.04. On the same basis as analysts’ estimates, earnings per share and cash flow from operations per share for the fourth quarter and the full-year 2009 exceeded the consensus of the analysts’ estimates. Please see “Non-GAAP Financial Measures” for a definition of each of these non-GAAP financial measures and tables that reconcile each of these non-GAAP measures to their most directly comparable GAAP financial measure.
Commenting, John H. Pinkerton, the Company’s Chairman and CEO, said, “Due to the recession, many companies in many industries spent 2009 restructuring their operations and balance sheets. In most cases, these companies downsized their operations and issued significant amounts of equity to reduce debt, resulting in a substantial loss in shareholder value. Fortunately, at Range, we weren’t forced to undertake any of these measures. Despite the impact of the recession and lower commodity prices, we accomplished much during 2009. The benchmark for creating shareholder value in the exploration and production business is increasing production and reserves on a per share basis. In 2009, we grew both production and reserves per share by over 10%, marking the fifth consecutive year of double-digit per share growth in both production and reserves. This growth was achieved at a cost of $1.00 per mcfe — the lowest all-in finding and development cost in our history. We also maintained our strong financial position as total debt declined $83 million during the year and the average diluted shares outstanding increased by only 1.8%.
While the accomplishments noted above drive value on a year-over-year basis, I believe our most significant achievements in 2009 and over the past several years, have been refocusing our capital and technical teams away from the more traditional higher cost, lower growth plays to the unconventional plays that are lower cost, higher growth and have superior economics. In particular, our discovery of the Marcellus Shale play and the aggregation of 900,000 net acres in the high-quality portions of the play was an extraordinary achievement. As a result, Range is extremely well-positioned to achieve per share growth in production and reserves at low cost for many years to come. Even in the current commodity price environment, we believe we can generate very attractive returns on capital and continue to build substantial shareholder value. While our year-end proved reserves were 3.1 Tcfe, we believe that our current leasehold position of 2.5 million net acres contains 22 to 30 Tcfe of resource potential. Our goal is to exploit this resource potential for the benefit of Range’s shareholders by continuing to drive up production and reserves on a per share basis at low cost.”
Reported GAAP revenues for the fourth quarter were $247 million, net cash provided from operating activities including changes in working capital was $148 million and earnings were a net loss of $16.8 million. All these amounts were lower than the previous year. The amounts corresponding to analysts’ estimates for the same measures, which are non-GAAP measures for the fourth quarter of 2009, are as follows (see the accompanying tables for the reconciliation of these non-GAAP measures to their most directly comparable GAAP financial
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measure): Oil and gas sales, including all cash-settled derivatives, rose 9% to $277 million, production increased by 13% to 457 Mmcfe per day, realized prices declined 4% to $6.59 per mcfe, cash flow from operations before changes in working capital increased 14% to $188 million and adjusted net income decreased 1% to $51.6 million.
Production for the year totaled 159 Bcfe, comprised of 131 Bcf of gas and 4.7 million barrels of oil and liquids. Production rose in each quarter of the year and averaged 436 Mmcfe per day for the year. As noted above, Range has achieved sequential production growth for 28 consecutive quarters. Wellhead prices, after adjustment for all cash-settled hedges and derivatives, decreased 25% to $6.44 per mcfe. The average gas price declined 25% to $6.13 per mcf, as the average oil price decreased 8% to $62.58 per barrel. The cash margin per mcfe for 2009 averaged $4.17 per mcfe.
SUMMARY OF CHANGES IN PROVED RESERVES
(in Mmcfe)
| | | | | |
Balance at December 31, 2008 | | | 2,654 | |
| | | | | |
| Extensions, discoveries and additions | | | 770 | |
| Purchases | | | — | |
| Performance revisions | | | 90 | |
| Price revisions | | | (86 | ) |
| Sales | | | (140 | ) |
| Production | | | (159 | ) |
| | | | | |
| | | | | |
Balance at December 31, 2009 | | | 3,129 | |
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Proved reserves at December 31, 2009 totaled 3.1 Tcfe, including 2,615 Bcf of natural gas and 85.7 million barrels of crude oil and liquids. Reserves increased 475 Bcfe or 18% compared to the prior year. Range replaced 486% of production in 2009. Drilling alone replaced 540% of production. At year-end, reserves were 84% natural gas by volume, and the reserve life index stood at 19 years based on fourth quarter production rates. The percentage of proved undeveloped reserves increased to 45% versus 38% in 2008. Independent petroleum consultants reviewed 88% of the reserves by volume. For year-end 2009, new Securities and Exchange Commission (“SEC”) rules were implemented requiring that the reserve calculations be based on the average prices throughout the year, versus the previous method which required year-end prices. The benchmark cash prices under the new method were $3.87 per Mmbtu for natural gas and $60.85 per barrel for crude oil (Cushing), representing the simple average of the prices for the first day of each month of 2009. Based on these prices adjusted for energy content, quality and basis differentials ($3.19 per Mmbtu and $54.65 per barrel, respectively), the pre-tax discounted (10%) present value of the year-end 2009 reserves was $2.6 billion. Using the previous SEC pricing method (year-end benchmark prices of $5.79 per Mmbtu and $79.36 per barrel with similar adjustments) proved reserves would have been 3.2 Tcfe and the pre-tax discounted (10%) present value would have been $5.1 billion. Using the 10-year futures strip prices at December 31, 2009 (averaging $6.91 per Mmbtu and $92.36 per barrel with similar adjustments), reserves would have been 3.3 Tcfe with a pre-tax discounted (10%) present value of $6.6 billion. As of year-end 2009, for each of its proved developed wells in the Marcellus Shale play, Range recorded on average 1.2 offset drilling locations as proved undeveloped reserves. In addition to the new SEC rules regarding oil and gas prices, the SEC also implemented new rules regarding proved undeveloped reserves. The rule change allows for additional drilling locations to be classified as proved undeveloped reserves assuming such locations are supported by reliable technologies. As noted above for year-end 2009 using the new SEC rules for both oil and gas prices and proved undeveloped reserves, Range’s finding and development cost from all sources, including leasehold additions and all price and performance revisions averaged $1.00 per mcfe. Based on the previous SEC rules for determining reserves and pricing, Range’s finding and development cost for 2009, including leasehold additions and all price and performance revisions, would have been $1.22 per mcfe. The $1.22 per mcfe average for 2009 based on the previous SEC rules compares to Range’s historical average of $1.97 per mcfe for the five-year period 2004 through 2008. The “apples-to-apples” decrease of approximately 40% in finding and development cost for 2009 versus the prior five-year period is a reflection of
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Range’s high-graded property portfolio and, in particular, the impact of the Marcellus Shale play. Range’s drill-bit only finding and development cost with performance revisions and excluding acreage for 2009 would have been $0.95 per mcfe using the previous SEC rules.
2010 Capital Budget —
Range’s 2010 capital budget has been set at $950 million excluding acquisitions. The budget is expected to be funded internally from operating cash flow and asset sales. In December 2009, Range sold its New York properties for $36 million. Recently, Range announced that it had entered into a definitive agreement to sell its tight sand properties in Ohio for $330 million. The Ohio property sale is expected to close prior to the end of March. The 2010 capital program includes $700 million for the drilling of 464 (338 net) wells and 38 (29 net) recompletions, $190 million for leasehold, $20 million for seismic and $40 million for pipelines, facilities and field operations. Approximately 90% of the budget is allocated to the Marcellus, Barnett and Nora areas. A significant portion of the leasehold budget is associated with the Marcellus Shale and relates to blocking up our acreage position in key areas of the play.
Based on the capital budget, Range estimates that 2010 production volumes will increase by 12% over the prior year after deducting the asset sales. Pro forma for the New York and Ohio property sales, the 2010 projected production increase would have been 19%. Range estimates that companywide production growth in 2011 will be in the area of 25%. With regard to the Marcellus Shale play, Range exited 2009 with net production of slightly more than 100 Mmcfe per day. The Marcellus net production target for 2010 is 180 — 200 Mmcfe per day doubling to 360-400 Mmcfe per day in 2011.
Operational Highlights —
During the fourth quarter, the Marcellus Shale division continued to make outstanding progress. Most notably, we drilled and completed our first two horizontal wells in the northeastern portion of the play in Lycoming County, Pennsylvania. The average seven-day test rate for the first well was 13.3 Mmcfe per day, while the average seven-day test rate for the second well was 13.6 Mmcfe per day. These two wells are now shut-in awaiting pipeline hook-up. The pipeline to the first well is expected to be completed late in the fourth quarter of 2010 with the pipeline to the second well expected to be completed in 2011. We also drilled our first horizontal Upper Devonian Shale well and our first horizontal Utica Shale well. The Upper Devonian well has been completed and is testing, and the Utica well has been drilled and cased and is awaiting completion. Currently, Range’s net production in the Marcellus is approximately 115 Mmcfe per day. We have 31 horizontal wells that have been drilled, of which 26 are awaiting completion and five are awaiting pipeline hook up. In the southwest portion of the play, where we have drilled the majority of our wells and have been accumulating data for the past 2.5 years, the average estimated ultimate recovery (“EUR”) for a Marcellus horizontal is 4.4 Bcfe gross. Prior to August 2009, typical Range Marcellus wells had horizontal laterals that averaged 2,200 to 2,800 feet and were typically fraced with eight stages. Since then, we have been experimenting with longer laterals and more frac stages. The longer laterals range from 2,900 up to 5,000 feet and the higher frac stages range from nine stages up to 17 stages. As has been demonstrated in other shale plays, it appears that the longer laterals result in higher initial production rates, higher EURs and improved economics. Currently we are running 13 drilling rigs in the play. Plans are to add more rigs in the fourth quarter and exit at 16 rigs. During 2010, we expect to drill and case 150 horizontal Marcellus Shale wells. For 2011, we plan to increase our rig count and exit the year with 24 rigs running. Finally, the build out of the Marcellus midstream infrastructure is progressing as scheduled. In the high Btu portion of the play, gross cryogenic processing capacity increased to 155 Mmcf per day in the fourth quarter of 2009, and an additional 30 Mmcf per day is expected to be added in mid-2010. Another 150 Mmcf per day has been requested for first quarter 2011, which will bring gross cryogenic processing capacity to 335 Mmcf per day. In the dry gas portion of the play, we have 160 Mmcf per day of pipeline tap capacity with 20 Mmcf per day of compression capacity in place currently. Plans are in place to steadily increase dry gas pipeline compression capacity to meet our needs.
The Southwest Division maintained its strong performance despite a reduction in rig count from six rigs in mid-2008 to one currently. The Barnett group grew production by 25% year-over-year and exited 2009 at an average of 125 Mmcfe per day. Range continued its success in its core properties in Hood County with the completion of three new wells at a combined rate of 8 (6.0 net) Mmcfe per day. Range will run one to two rigs in 2010 and drill approximately 30 wells. We expect to grow production 8% year-over-year to average about 132 Mmcfe per day in 2010.
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During the fourth 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 four horizontal Huron Shale wells and one horizontal Big Lime well. Year-to-date, 19 horizontal wells have been completed in these target zones and are producing as expected. In addition, during the fourth quarter of 2009, 43 coal bed methane and 10 vertical tight gas sand wells were successfully drilled in the Nora field.
Fourth quarter activity for the Midcontinent Division included the drilling of 3 (2.5 net) wells with a 100% success rate. Twenty-nine wells are planned for the Texas Panhandle area in 2010. In the northern Oklahoma shallow oil play, Range drilled its first horizontal well which yielded initial production rates of 517 (417 net) Boe per day. This rate was 13 times the initial vertical well rate at just three times the vertical well cost. Range has now completed six horizontal wells in the Woodford Shale play of the Ardmore Basin with reserves above 3.4 Bcfe and well costs of approximately $3.5 million. In total, the Midcontinent Division plans 39 (32 net) new wells for 2010.
The Company will host a conference call on Wednesday, February 24 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 2009 financial results conference call. A replay of the call will be available through March 3 at 877-660-6853. The conference ID for the replay is 345409 and the Account number is 286. 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 atwww.rangeresources.com orwww.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:
Adjusted net income comparable to analysts’ estimates as set forth in this release represents income 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 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.
Earnings for 2009 included $115.9 million in mark-to-market losses on certain derivative transactions, derivative ineffective hedging loss of $1.7 million, non-cash stock compensation expense of $72.8 million, impairment expenses related primarily to unproved properties of $124.8 million, $10.8 million in equity impairments and severance accruals and $10.4 million in gains on sales of properties. Excluding such items, income before income taxes would have been $256.9 million, a 48% decrease over the prior year. Adjusting for the after-tax effect of these items, the Company’s earnings would have been $164.7 million in 2009 or $1.07 per share ($1.04 per diluted share). If similar items were excluded, 2008 earnings would have been $309.2 million or $2.05 per share ($1.98 per diluted share). Earnings for 2008 included a mark-to-market derivative gain of $85.6 million, ineffective hedging gains of $1.7 million, $6.5 million of non-cash stock compensation, an abandonment and impairment expense related to unproved properties of $47.4 million and $20.2 million in gains on sales of properties. (See 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
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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 has disclosed two primary metrics in this release to measure our ability to establish a long-term trend of adding reserves at a reasonable cost — a reserve replacement ratio and finding and development cost per unit. The reserve replacement ratio is an indicator of our ability to replace annual production volumes and grow our reserves. It is important to economically find and develop new reserves that will offset produced volumes and provide for future production given the inherent decline of hydrocarbon reserves as they are produced. We believe the ability to develop a competitive advantage over other natural gas and oil companies is dependent on adding reserves in our core areas at lower costs than our competition. The reserve replacement ratio is calculated by dividing production for the year into the total of proved extensions, discoveries and additions, proved reserves added by performance and the reduction of reserves due to changes in prices as shown in the summary of changes in proved reserves table.
Finding and development cost per unit is a non-GAAP metric used in the exploration and production industry by companies, investors and analysts. The calculations presented by the Company are based on costs incurred excluding asset retirement obligations and divided by proved reserve additions (extensions, discoveries and additions shown in the summary of changes in proved reserves table) adjusted for the changes in proved reserves for performance revisions and/or price revisions as stated in each instance in the release. This calculation does not include the future development costs required for the development of proved undeveloped reserves. The SEC method of computing finding costs contains additional cost components and results in a higher number. A reconciliation of the two methods is shown on our website at www.rangeresources.com.
The reserve replacement ratio and finding and development cost per unit are statistical indicators that have limitations, including their predictive and comparative value. As an annual measure, the reserve replacement ratio can be limited because it may vary widely based on the extent and timing of new discoveries and the varying effects of changes in prices and well performance. In addition, since the reserve replacement ratio and finding and development cost per unit do not consider the cost or timing of future production of new reserves, such measures may not be an adequate measure of value creation. These reserves metrics may not be comparable to similarly titled measurements used by other companies.
Year-end pre-tax discounted present value may be considered a non-GAAP financial measure as defined by the SEC. We believe that the presentation of pre-tax discounted present value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We further believe investors and creditors use pre-tax discounted present value as a basis for comparison of the relative size and value of our reserves as compared with other companies. Range’s pre-tax discounted present value as of December 31, 2009 may be reconciled to its standardized measure of discounted future net cash flows as of December 31, 2009 by reducing Range’s pre-tax discounted present value by the discounted future income taxes associated with such reserves.
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Reconciliation of PV-10
($ in millions)
(unaudited)
| | | | | |
| | | December 31, | |
| | | 2009 | |
| Standardized measure of discounted future net of cash flows | | $ | 2,593 | |
| Discounted future cash flows for income taxes | | | 502 | |
| | | | |
| Discounted future net cash flows before income taxes (PV-10) | | $ | 2,091 | |
| | | | |
Except for historical information, statements made in this release such as per share exposure, unproved resource potential, expected production rates, expected operating costs and expected leasehold impairment, possible reserve write downs, and finding and development costs in 2009 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 drilling and operations, the timing of production, mechanical and other inherent risks associated with oil and gas production, weather, the availability of drilling equipment, changes in interest rates, litigation, uncertainties about reserve estimates and environmental risks. Range undertakes no obligation to publicly update or revise any forward-looking statements. 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. Beginning with year-end reserves for 2009, the SEC permits the optional disclosure of 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, unrisked resource potential has not been fully 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, 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.
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RANGE RESOURCES CORPORATION (NYSE: RRC)is an independent oil and gas company operating in the Southwestern and Appalachian regions of the United States. | | 2010-6 |
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| Contacts: | | Rodney Waller, Senior Vice President |
| | | David Amend, Investor Relations Manager |
| | | Karen Giles, Manager of Corporate Communications |
| | | (817) 870-2601 |
| | | www.rangeresources.com |
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RANGE RESOURCES CORPORATION
STATEMENTS OF INCOME
Based on GAAP reported earnings with additional
details of items included in each line in Form 10-K
(Unaudited, in thousands, except per share data)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended December 31, | | | Twelve Months Ended December 31, | |
| | | 2009 | | | 2008 (a) | | | | | | | 2009 | | | 2008 (a) | | | | | |
| Revenues | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil and gas sales (b) | | $ | 242,087 | | | $ | 223,834 | | | | | | | $ | 839,921 | | | $ | 1,226,560 | | | | | |
| Cash-settled derivative gain (loss) (b)(d) | | | 34,966 | | | | 30,832 | | | | | | | | 184,051 | | | | (15,428 | ) | | | | |
| Transportation and gathering | | | (3,418 | ) | | | 826 | | | | | | | | 1,351 | | | | 5,060 | | | | | |
| Transportation and gathering — non-cash stock compensation (c) | | | (187 | ) | | | (139 | ) | | | | | | | (865 | ) | | | (483 | ) | | | | |
| Change in mark-to-market on unrealized derivatives (d) | | | (32,516 | ) | | | 88,778 | | | | | | | | (115,909 | ) | | | 85,594 | | | | | |
| Ineffective hedging gain (loss) (d) | | | (1,213 | ) | | | (167 | ) | | | | | | | (1,696 | ) | | | 1,695 | | | | | |
| Gain (loss) on sale of properties (e) | | | 10,374 | | | | 116 | | | | | | | | 10,413 | | | | 20,166 | | | | | |
| Other (e) | | | (3,262 | ) | | | 782 | | | | | | | | (9,925 | ) | | | 1,509 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 246,831 | | | | 344,862 | | | | -28 | % | | | 907,341 | | | | 1,324,673 | | | | -32 | % |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Expenses | | | | | | | | | | | | | | | | | | | | | | | | |
| Direct operating | | | 32,122 | | | | 34,959 | | | | | | | | 131,245 | | | | 139,618 | | | | | |
| Direct operating — non-cash stock compensation (c) | | | 244 | | | | 718 | | | | | | | | 2,601 | | | | 2,769 | | | | | |
| Production and ad valorem taxes | | | 8,748 | | | | 10,066 | | | | | | | | 32,169 | | | | 55,172 | | | | | |
| Exploration | | | 9,206 | | | | 11,484 | | | | | | | | 42,082 | | | | 63,560 | | | | | |
| Exploration — non-cash stock compensation (c) | | | 1,884 | | | | 1,002 | | | | | | | | 4,817 | | | | 4,130 | | | | | |
| Abandonment and impairment of unproven properties | | | 28,959 | | | | 36,702 | | | | | | | | 113,538 | | | | 47,355 | | | | | |
| General and administrative | | | 21,402 | | | | 19,580 | | | | | | | | 83,277 | | | | 68,464 | | | | | |
| General and administrative — non-cash stock compensation (c) | | | 10,766 | | | | 6,728 | | | | | | | | 33,472 | | | | 23,844 | | | | | |
| Deferred compensation plan (f) | | | 1,438 | | | | (15,324 | ) | | | | | | | 31,073 | | | | (24,689 | ) | | | | |
| Interest | | | 30,550 | | | | 27,387 | | | | | | | | 117,367 | | | | 99,748 | | | | | |
| Depletion, depreciation and amortization | | | 92,922 | | | | 80,893 | | | | | | | | 363,163 | | | | 299,831 | | | | | |
| Write-off of interim plant and other | | | 11,269 | | | | — | | | | | | | | 11,269 | | | | — | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 249,510 | | | | 214,195 | | | | 16 | % | | | 966,073 | | | | 779,802 | | | | 24 | % |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| (Loss) Income from operations before income taxes | | | (2,679 | ) | | | 130,667 | | | | -102 | % | | | (58,732 | ) | | | 544,871 | | | | -111 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Income taxes | | | | | | | | | | | | | | | | | | | | | | | | |
| Current | | | (560 | ) | | | 59 | | | | | | | | (636 | ) | | | 4,268 | | | | | |
| Deferred | | | 14,658 | | | | 37,012 | | | | | | | | (4,226 | ) | | | 189,563 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 14,098 | | | | 37,071 | | | | | | | | (4,862 | ) | | | 193,831 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
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| Net (loss) income | | $ | (16,777 | ) | | $ | 93,596 | | | | -118 | % | | $ | (53,870 | ) | | $ | 351,040 | | | | -115 | % |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Earnings per share | | | | | | | | | | | | | | | | | | | | | | | | |
| Basic operations | | $ | (0.11 | ) | | $ | 0.61 | | | | -118 | % | | $ | (0.35 | ) | | $ | 2.32 | | | | -115 | % |
| | | | | | | | | | | | | | | | | | | | | |
| Diluted | | $ | (0.11 | ) | | $ | 0.60 | | | | -118 | % | | $ | (0.35 | ) | | $ | 2.25 | | | | -116 | % |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Weighted average shares outstanding, as reported | | | | | | | | | | | | | | | | | | | | | | | | |
| Basic | | | 155,275 | | | | 152,989 | | | | 1 | % | | | 154,514 | | | | 151,116 | | | | 2 | % |
| Diluted | | | 155,275 | | | | 157,118 | | | | -1 | % | | | 154,514 | | | | 155,943 | | | | -1 | % |
| | |
| (a) | | Certain minor amounts were restated in 2008 and prior. See 8-K filed on August 10, 2009. |
| |
| (b) | | See separate oil and gas sales information table. |
| |
| (c) | | 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-K. |
| |
| (d) | | Included in Derivative fair value income in the 10-K. |
| |
| (e) | | Included in Other revenues in the 10-K. |
| |
| (f) | | Reflects the change in the market value of the vested Company stock held in the deferred compensation plan. |
11
RANGE RESOURCES CORPORATION
BALANCE SHEETS
(Audited, in thousands)
| | | | | | | | | |
| | | December 31, | | | December 31, | |
| | | 2009 | | | 2008 (a) | |
| | | | | | | | | |
| Assets | | | | | | | | |
| Current assets | | $ | 153,735 | | | $ | 182,881 | |
| Current unrealized derivative gain | | | 21,545 | | | | 221,430 | |
| Oil and gas properties | | | 4,898,819 | | | | 4,842,046 | |
| Transportation and field assets | | | 91,835 | | | | 86,228 | |
| Unrealized derivative gain | | | 4,107 | | | | 5,231 | |
| Other | | | 225,840 | | | | 214,063 | |
| | | | | | | |
| | | $ | 5,395,881 | | | $ | 5,551,879 | |
| | | | | | | |
| | | | | | | | | |
| Liabilities and Stockholders’ Equity | | | | | | | | |
| Current liabilities | | $ | 297,170 | | | $ | 351,449 | |
| Current asset retirement obligation | | | 2,446 | | | | 2,055 | |
| Current unrealized derivative loss | | | 14,488 | | | | 10 | |
| | | | | | | | | |
| Bank debt | | | 324,000 | | | | 693,000 | |
| Subordinated notes | | | 1,383,833 | | | | 1,097,668 | |
| | | | | | | |
| Total long-term debt | | | 1,707,833 | | | | 1,790,668 | |
| | | | | | | |
| | | | | | | | | |
| Deferred taxes | | | 776,965 | | | | 779,218 | |
| Unrealized derivative loss | | | 271 | | | | — | |
| Deferred compensation liability | | | 135,541 | | | | 93,247 | |
| Long-term asset retirement obligation and other | | | 82,578 | | | | 83,890 | |
| | | | | | | | | |
| Common stock and retained earnings | | | 2,380,132 | | | | 2,382,392 | |
| Treasury stock | | | (7,964 | ) | | | (8,557 | ) |
| Other comprehensive income | | | 6,421 | | | | 77,507 | |
| | | | | | | |
| Total stockholders’ equity | | | 2,378,589 | | | | 2,451,342 | |
| | | | | | | |
| | | $ | 5,395,881 | | | $ | 5,551,879 | |
| | | | | | | |
| | |
| (a) | | Certain minor amounts were restated in 2008 and prior. See 8-K filed on August 10, 2009. |
12
RANGE RESOURCES CORPORATION
CASH FLOWS FROM OPERATIONS
(Unaudited, in thousands)
| | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Twelve Months Ended | |
| | | December 31, | | | December 31, | |
| | | 2009 | | | 2008 (a) | | | 2009 | | | 2008 (a) | |
| | | | | | | | | | | | | | | | | |
| Net income (loss) | | $ | (16,777 | ) | | $ | 93,596 | | | $ | (53,870 | ) | | $ | 351,040 | |
| Adjustments to reconcile net income to net cash provided by operations: | | | | | | | | | | | | | | | | |
| Loss (gain) from equity investment | | | 7,151 | | | | 388 | | | | 13,699 | | | | 218 | |
| Deferred income tax expense (benefit) | | | 14,658 | | | | 37,012 | | | | (4,226 | ) | | | 189,563 | |
| Depletion, depreciation and amortization | | | 104,191 | | | | 80,893 | | | | 374,432 | | | | 299,831 | |
| Exploration dry hole costs | | | 1,817 | | | | 4,034 | | | | 2,159 | | | | 13,371 | |
| Abandonment and impairment of unproved properties | | | 28,959 | | | | 36,702 | | | | 113,538 | | | | 47,355 | |
| Mark-to-market losses on oil and gas derivatives not designated as hedges | | | 32,516 | | | | (88,778 | ) | | | 115,909 | | | | (85,594 | ) |
| Ineffective hedging (gain) loss | | | 1,213 | | | | 167 | | | | 1,696 | | | | (1,695 | ) |
| Allowance for bad debts | | | 200 | | | | — | | | | 1,351 | | | | 450 | |
| Amortization of deferred financing costs and other | | | 5,013 | | | | 763 | | | | 8,755 | | | | 2,900 | |
| Deferred and stock-based compensation | | | 14,558 | | | | (6,792 | ) | | | 73,402 | | | | 6,621 | |
| (Gain) loss on sale of assets and other | | | (11,922 | ) | | | 358 | | | | (10,413 | ) | | | (19,507 | ) |
| | | | | | | | | | | | | | | | | |
| Changes in working capital: | | | | | | | | | | | | | | | | |
| Accounts receivable | | | (37,366 | ) | | | 71,169 | | | | 1,007 | | | | 6,701 | |
| Inventory and other | | | (656 | ) | | | (3,983 | ) | | | (1,463 | ) | | | (9,246 | ) |
| Accounts payable | | | 22,311 | | | | 7,736 | | | | (44,765 | ) | | | 10,663 | |
| Accrued liabilities | | | (17,959 | ) | | | (8,886 | ) | | | 464 | | | | 12,096 | |
| | | | | | | | | | | | | |
| Net changes in working capital | | | (33,670 | ) | | | 66,036 | | | | (44,757 | ) | | | 20,214 | |
| | | | | | | | | | | | | |
| Net cash provided from operations | | $ | 147,907 | | | $ | 224,379 | | | $ | 591,675 | | | $ | 824,767 | |
| | | | | | | | | | | | | |
RECONCILIATION OF NET CASH PROVIDED FROM CONTINUING
OPERATIONS, AS REPORTED TO CASH FLOW FROM OPERATIONS
BEFORE CHANGES IN WORKING CAPITAL, a non-GAAP measure
(Unaudited, in thousands)
| | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Twelve Months Ended | |
| | | December 31, | | | December 31, | |
| | | 2009 | | | 2008 (a) | | | 2009 | | | 2008 (a) | |
| | | | | | | | | | | | | | | | | |
| Net cash provided from continuing operations, as reported | | $ | 147,907 | | | $ | 224,379 | | | $ | 591,675 | | | $ | 824,767 | |
| Net change in working capital | | | 33,670 | | | | (66,036 | ) | | | 44,757 | | | | (20,214 | ) |
| Exploration expense | | | 7,389 | | | | 7,450 | | | | 39,923 | | | | 50,189 | |
| Other | | | (1,027 | ) | | | (807 | ) | | | (2,270 | ) | | | (1,411 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Cash flow from operations before changes in working capital, non-GAAP measure | | $ | 187,939 | | | $ | 164,986 | | | $ | 674,085 | | | $ | 853,331 | |
| | | | | | | | | | | | | |
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING
(Unaudited, in thousands)
| | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Twelve Months Ended | |
| | | December 31, | | | December 31, | |
| | | 2009 (b) | | | 2008 (a) | | | 2009 (b) | | | 2008 (a) | |
| | | | | | | | | | | | | | | | | |
| Basic: | | | | | | | | | | | | | | | | |
| Weighted average shares outstanding | | | 157,963 | | | | 155,398 | | | | 157,108 | | | | 153,435 | |
| Stock held by deferred compensation plan | | | (2,688 | ) | | | (2,409 | ) | | | (2,594 | ) | | | (2,319 | ) |
| | | | | | | | | | | | | |
| | | | 155,275 | | | | 152,989 | | | | 154,514 | | | | 151,116 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Dilutive: | | | | | | | | | | | | | | | | |
| Weighted average shares outstanding | | | 157,963 | | | | 155,398 | | | | 157,108 | | | | 153,435 | |
| Dilutive stock options under treasury method unless anti-dilutive | | | (2,688 | ) | | | 1,720 | | | | (2,594 | ) | | | 2,508 | |
| | | | | | | | | | | | | |
| | | | 155,275 | | | | 157,118 | | | | 154,514 | | | | 155,943 | |
| | | | | | | | | | | | | |
| | |
| (a) | | Certain minor amounts were restated in 2008 and prior. See 8-K filed on August 10, 2009. |
| |
| (b) | | Due to loss in 2009 only basic outstanding shares used for GAAP. |
13
RANGE RESOURCES CORPORATION
OIL AND GAS SALES INFORMATION
A Non-GAAP Measure
(Unaudited, in thousands, except per unit data)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Twelve Months Ended | |
| | | December 31, | | | December 31, | |
| | | 2009 | | | 2008 | | | | | | | 2009 | | | 2008 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil and gas sales components: | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil sales | | $ | 38,685 | | | $ | 40,842 | | | | | | | $ | 140,577 | | | $ | 298,482 | | | | | |
| NGL sales | | | 26,950 | | | | 13,250 | | | | | | | | 63,405 | | | | 68,491 | | | | | |
| Gas sales | | | 132,175 | | | | 147,348 | | | | | | | | 432,821 | | | | 923,161 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash-settled hedges (effective): | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude oil | | | (63 | ) | | | 4,292 | | | | | | | | 12,184 | | | | (71,135 | ) | | | | |
| Natural gas | | | 44,340 | | | | 18,102 | | | | | | | | 190,934 | | | | 8,561 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Total oil and gas sales, as reported | | $ | 242,087 | | | $ | 223,834 | | | | 8 | % | | $ | 839,921 | | | $ | 1,226,560 | | | | -32 | % |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Derivative fair value income (loss) components: | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash-settled derivatives (ineffective): | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude oil | | $ | (323 | ) | | $ | 1,052 | | | | | | | $ | 7,252 | | | $ | (15,991 | ) | | | | |
| Natural gas | | | 35,289 | | | | 29,780 | | | | | | | | 176,799 | | | | 563 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Change in mark-to-market on unrealized derivatives | | | (32,516 | ) | | | 88,778 | | | | | | | | (115,909 | ) | | | 85,594 | | | | | |
| Unrealized ineffectiveness | | | (1,213 | ) | | | (167 | ) | | | | | | | (1,696 | ) | | | 1,695 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Total derivative fair value income (loss), as reported | | $ | 1,237 | | | $ | 119,443 | | | | | | | $ | 66,446 | | | $ | 71,861 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil and gas sales, including cash-settled derivatives: | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil sales | | $ | 38,299 | | | $ | 46,186 | | | | | | | $ | 160,013 | | | $ | 210,356 | | | | | |
| Natural gas liquid sales | | | 26,950 | | | | 13,250 | | | | | | | | 63,405 | | | | 68,491 | | | | | |
| Gas sales | | | 211,804 | | | | 195,230 | | | | | | | | 800,554 | | | | 932,285 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 277,053 | | | $ | 254,666 | | | | 9 | % | | $ | 1,023,972 | | | $ | 1,211,132 | | | | -15 | % |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Production during the period: | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil (bbl) | | | 569,276 | | | | 741,391 | | | | -23 | % | | | 2,556,879 | | | | 3,084,529 | | | | -17 | % |
| Natural gas liquid (bbl) | | | 694,740 | | | | 392,335 | | | | 77 | % | | | 2,186,999 | | | | 1,385,701 | | | | 58 | % |
| Gas (mcf) | | | 34,442,796 | | | | 30,293,825 | | | | 14 | % | | | 130,648,694 | | | | 114,323,436 | | | | 14 | % |
| Equivalent (mcfe) (a) | | | 42,026,892 | | | | 37,096,181 | | | | 13 | % | | | 159,111,962 | | | | 141,144,816 | | | | 13 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Production — average per day: | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil (bbl) | | | 6,188 | | | | 8,059 | | | | -23 | % | | | 7,005 | | | | 8,428 | | | | -17 | % |
| Natural gas liquid (bbl) | | | 7,552 | | | | 4,265 | | | | 77 | % | | | 5,992 | | | | 3,786 | | | | 58 | % |
| Gas (mcf) | | | 374,378 | | | | 329,281 | | | | 14 | % | | | 357,942 | | | | 312,359 | | | | 15 | % |
| Equivalent (mcfe) (a) | | | 456,814 | | | | 403,219 | | | | 13 | % | | | 435,923 | | | | 385,642 | | | | 13 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Average prices realized, including cash-settled hedges and derivatives: | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude oil (per bbl) | | $ | 67.28 | | | $ | 62.30 | | | | 8 | % | | $ | 62.58 | | | $ | 68.20 | | | | -8 | % |
| Natural gas liquid (per bbl) | | $ | 38.79 | | | $ | 33.77 | | | | 15 | % | | $ | 28.99 | | | $ | 49.43 | | | | -41 | % |
| Gas (per mcf) | | $ | 6.15 | | | $ | 6.44 | | | | -5 | % | | $ | 6.13 | | | $ | 8.15 | | | | -25 | % |
| Equivalent (per mcfe) (a) | | $ | 6.59 | | | $ | 6.86 | | | | -4 | % | | $ | 6.44 | | | $ | 8.58 | | | | -25 | % |
| | |
| (a) | | Oil and natural gas liquids are converted to gas equivalents on a basis of six mcf per barrel. |
14
RANGE RESOURCES CORPORATION
RECONCILIATION OF INCOME (LOSS) FROM OPERATIONS BEFORE INCOME TAXES
AS REPORTED TO INCOME FROM OPERATIONS BEFORE INCOME TAXES
EXCLUDING CERTAIN NON-CASH ITEMS, a non-GAAP measure
(Unaudited, in thousands, except per share data)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Twelve Months Ended | |
| | | December 31, | | | December 31, | |
| | | 2009 | | | 2008 (a) | | | | | | | 2009 | | | 2008 (a) | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| As reported | | $ | (2,679 | ) | | $ | 130,667 | | | | -102 | % | | $ | (58,732 | ) | | $ | 544,871 | | | | -111 | % |
| Adjustment for certain non-cash items | | | | | | | | | | | | | | | | | | | | | | | | |
| (Gain) loss on sale of properties | | | (10,374 | ) | | | (116 | ) | | | | | | | (10,413 | ) | | | (20,166 | ) | | | | |
| Change in mark-to-market on unrealized derivatives | | | 32,516 | | | | (88,778 | ) | | | | | | | 115,909 | | | | (85,594 | ) | | | | |
| Ineffective hedging (gain) loss | | | 1,213 | | | | 167 | | | | | | | | 1,696 | | | | (1,695 | ) | | | | |
| Abandonment and impairment of unproven properties | | | 28,959 | | | | 36,702 | | | | | | | | 113,538 | | | | 47,355 | | | | | |
| Write-off of interim plant and other | | | 11,269 | | | | — | | | | | | | | 11,269 | | | | — | | | | | |
| Equity method impairment | | | 6,000 | | | | — | | | | | | | | 8,950 | | | | — | | | | | |
| Net severance accrual | | | 1,055 | | | | — | | | | | | | | 1,895 | | | | — | | | | | |
| Transportation and gathering — non-cash stock compensation | | | 187 | | | | 139 | | | | | | | | 865 | | | | 483 | | | | | |
| Direct operating — non-cash stock compensation | | | 244 | | | | 718 | | | | | | | | 2,601 | | | | 2,769 | | | | | |
| Exploration expenses — non-cash stock compensation | | | 1,884 | | | | 1,002 | | | | | | | | 4,817 | | | | 4,130 | | | | | |
| General & administrative — non-cash stock compensation | | | 10,766 | | | | 6,728 | | | | | | | | 33,472 | | | | 23,844 | | | | | |
| Deferred compensation plan — non-cash stock compensation | | | 1,438 | | | | (15,324 | ) | | | | | | | 31,073 | | | | (24,689 | ) | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| As adjusted | | | 82,478 | | | | 71,905 | | | | 15 | % | | | 256,940 | | | | 491,308 | | | | -48 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Income taxes, adjusted | | | | | | | | | | | | | | | | | | | | | | | | |
| Current | | | (560 | ) | | | 59 | | | | | | | | (636 | ) | | | 4,268 | | | | | |
| Deferred | | | 31,400 | | | | 19,933 | | | | | | | | 92,856 | | | | 177,807 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Net income excluding certain items, a non-GAAP measure | | | 51,638 | | | $ | 51,913 | | | | -1 | % | | | 164,720 | | | $ | 309,233 | | | | -47 | % |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Non-GAAP earnings per share | | | | | | | | | | | | | | | | | | | | | | | | |
| Basic . | | $ | 0.34 | | | $ | 0.34 | | | | | | | $ | 1.07 | | | $ | 2.05 | | | | -48 | % |
| | | | | | | | | | | | | | | | | | | | | |
| Diluted | | $ | 0.32 | | | $ | 0.33 | | | | -3 | % | | $ | 1.04 | | | $ | 1.98 | | | | -47 | % |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| GAAP diluted shares outstanding (b) | | | 159,513 | | | | 157,118 | | | | 2 | % | | | 158,778 | | | | 155,943 | | | | 2 | % |
| | | | | | | | | | | | | | | | | | | | | |
| | |
| (a) | | Certain minor amounts were restated in 2008 and prior. See 8-K filed on August 10, 2009. |
| |
| (b) | | GAAP diluted shares outstanding for 2009 have been adjusted for dilutive stock options due to adjustments which changes the non-GAAP amount to income. |
HEDGING POSITION
As of February 23, 2010
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Gas | | | Oil | |
| | | | | | | Volume | | | Average | | | Volume | | | Average | |
| | | | | | | Hedged | | | Hedge | | | Hedged | | | Hedge | |
| | | | | | | (Mmbtu/d) | | | Prices | | | (Bbl/d) | | | Prices | |
| | | | | | | | | | | | | | | | | | | | | |
| 1Q 2010 | | Collars | | | 273,444 | | | $ | 5.50 - $7.32 | | | | 1,000 | | | $ | 75.00- $93.75 | |
| 2Q 2010 | | Collars | | | 300,000 | | | $ | 5.50 - $7.22 | | | | 1,000 | | | $ | 75.00- $93.75 | |
| 3Q 2010 | | Collars | | | 315,000 | | | $ | 5.55 - $7.19 | | | | 1,000 | | | $ | 75.00- $93.75 | |
| 4Q 2010 | | Collars | | | 335,000 | | | $ | 5.56 - $7.20 | | | | 1,000 | | | $ | 75.00- $93.75 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Total 2010 | | | | | | | 306,055 | | | $ | 5.53- $7.23 | | | | 1,000 | | | $ | 75.00- $93.75 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Total 2011 | | Collars | | | 115,000 | | | $ | 6.00- $7.24 | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | |
15
