Exhibit 99.1
NEWS RELEASE
RANGE ANNOUNCES SECOND QUARTER 2010 RESULTS
FORT WORTH, TEXAS, JULY 26, 2010...RANGE RESOURCES CORPORATION (NYSE: RRC)today announced its second quarter 2010 results. Production averaged 472 Mmcfe per day, a record high for the Company and a 9% increase over the prior-year quarter. This represents the 30th consecutive quarter of sequential production growth. The record level of production was achieved despite the impact of selling non-core properties at the end of the first quarter 2010. The driver for the production growth was solid results from all of the Company’s divisions. The Marcellus Shale Division saw the largest production increase due to continued outstanding drilling results.
Reported GAAP net income increased to $9.1 million versus a loss of $39.9 million for the prior-year quarter. Diluted earnings per share rose to $0.06 compared to a loss of $0.26 for the prior-year quarter. Net cash provided from operating activities totaled $108 million for the second quarter. Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $14.1 million or $0.09 per diluted share compared to $33.7 million or $0.21 per diluted share for the prior-year quarter. Due to lower realized prices, cash flow from operations before changes in working capital, a non-GAAP measure, declined 17% from the prior-year quarter to $129 million. 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 on the announcement, John Pinkerton, Range’s Chairman and CEO, said, “Significant progress was made in the second quarter. We fully replaced the production we sold with our Ohio sale and were able to record the highest quarterly production in our Company’s history. We accomplished this while continuing to drive down our cost structure. The catalyst for our performance was outstanding drilling results. We believe we are on track to deliver all-in finding cost of below $1.00 per mcfe for 2010. As a result, we are generating attractive returns on our capital despite low natural gas prices. With 75% of our 2010 gas production hedged and 60% of our 2011 gas production hedged, coupled with our low cost structure, solid financial position, and high return projects, we are confident that we can continue to drive up our per share value.”
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 472 Mmcfe per day, comprised of 382 Mmcf per day of gas (81%), 9,651 barrels per day of natural gas liquids (12%) and 5,327 barrels per day of oil (7%). Natural gas production grew 9% over the prior-year quarter, despite the sale of the Ohio properties at the end of the first quarter. Adjusting for asset sales, second quarter natural gas production would have grown by 13%. Natural gas liquids production rose 67% as a result of outstanding drilling results in the liquids rich area of the Marcellus Shale play in southwest Pennsylvania. Compared to the prior-year quarter, oil production declined 34% primarily due to the sale of our West Texas oil properties last year. Wellhead prices, including cash-settled derivatives, averaged $5.07 per mcfe, an 18% decrease versus the prior-year quarter. The average realized gas price was $4.37 per mcf, a 25% decrease from the prior-year quarter. The natural gas liquids price increased 54% to $37.13 a barrel versus the prior-year quarter. The average oil price rose 12% to $67.96 a barrel over the prior-year quarter. Total natural gas, NGL and oil sales (including cash settled derivatives) declined 11% compared to the prior-year quarter to $217 million as lower prices more than offset higher volumes.
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During the second quarter 2010, Range continued to lower its cost structure. On a unit of production basis, the Company’s four largest cost categories fell by 8% in aggregate compared to the prior-year period. Direct operating expenses for the quarter were $0.68 per mcfe, a 21% decrease compared to the prior-year quarter of $0.86. Depreciation, depletion and amortization expense decreased 6% to $2.12 per mcfe. Interest expense declined 4% to $0.72 per mcfe. General and administrative expenses excluding the lawsuit settlements were $0.52 per mcfe, a $0.01 increase over the prior-year quarter due primarily to continued increases in the Marcellus Shale division.
Property Transactions
In June, Range completed the second and final closing of its Ohio property sale, generating approximately $23 million of additional proceeds. Total proceeds from the sale were $323 million. The sale resulted in the recording of a pre-tax gain of $67 million in the first quarter and $10 million in the second quarter.
Also in June, Range acquired natural gas properties located in Virginia from a subsidiary of Chesapeake Energy Corporation for $135 million. The properties are contiguous to and partially overlap the Company’s existing Nora/Haysi properties. The acquired properties are currently producing 10 Mmcfe per day and include 115,000 net acres of leasehold and 30 miles of gas transmission lines. Range estimates the proved reserves associated with the acquisition total 125 Bcfe. The acquired properties contributed approximately 2 Mmcfe per day toward the Company’s total average second quarter production of 472 Mmcfe per day. The Company owns the mineral interests in both the Nora and Haysi Fields. The acquisition blocks up over 350,000 acres for future development in stacked pay reservoirs of the shallow coal bed methane horizons, tight gas horizons and the deeper Huron Shale. These same reservoirs are currently being developed in the adjoining Nora Field. Based on the results of the infill drilling program at Nora over the last several years, Range believes that the acquired acreage has significant infill drilling and behind pipe opportunities with attractive economics even at low gas prices.
Capital Expenditures —
Second quarter drilling expenditures totaled $237 million, funding the drilling of 87 (65.6 net) wells. A 97% success rate was achieved. For the first six months of the year, 159 (123.5 net) wells were drilled. At June 30, 53 (38.6 net) wells were in various stages of completion or waiting on pipeline connection. As of June 30, Range had drilled 146 horizontal Marcellus wells to date of which 29 are awaiting completion and four are awaiting pipeline hook up. In addition in the second quarter, $32 million was expended on acreage, $8 million on expanding gas gathering systems and $13 million for exploration expense.
The Company’s Board of Directors recently approved an additional $215 million in capital spending for 2010. This increases the 2010 capital budget from $950 million to $1.2 billion. The capital spending increase is related to seizing opportunities in the Marcellus Shale play ($210 million) and for development of the recently acquired properties in Virginia ($5 million). Of the additional Marcellus capital, approximately $65 million is for the planned drilling of 18 additional Marcellus wells in the southwest portion of the play and to complete 15 of them prior to year end. Because we are becoming more efficient, we are drilling more wells with the same number of rigs. Another $73 million is for the construction of drilling locations, roads and other infrastructure requirements for wells expected to be drilled in 2011. Given the size and scale of Range’s acreage position, it is prudent and cost effective to undertake these construction activities prior to the winter season, in order to achieve a more cost efficient, continuous operation. Range is combining 14,000 net acres in Bradford County with Talisman in an industry joint venture. Range will own approximately a 33% working interest in the combined acreage position. Talisman has drilled some excellent wells in the area and will be the operator of the
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joint venture wells. Range’s share of the joint venture’s cost for the remainder of 2010 is estimated to be $25 million. An additional $40 million is for leasehold in the Marcellus Shale, allowing us to continue to block up acreage in our core areas. The remaining $7 million is for additional seismic expenditures.
With the increase in capital spending, Range is increasing its production growth guidance for 2010 from 12% to 14%. Specifically with regard to the Marcellus, Range is increasing its 2010 exit rate target from 180 to 200 Mmcfe net per day to 200 to 210 Mmcfe net per day. For 2011, Range currently anticipates that its production will increase by no less than 25% and the 2011 Marcellus exit rate target has been increased from 360 to 400 Mmcfe per day net to 400 to 420 Mmcfe per day net.
The Company had at quarter end a debt-to-capitalization ratio, net of cash, of 40% with almost $900 million of undrawn capacity under its bank credit facility. The increase in the 2010 capital budget will be funded by draws under the credit facility. Range is also considering additional asset sales to fund a portion of the capital increase.
Operational Discussion —
Range’s Marcellus Shale Division continues to exceed expectations. Current net production is approximately 160 Mmcfe per day, ahead of its mid-year target. Drilling rigs are becoming more efficient as are completions and production operations. These increased efficiencies and cost improvements are resulting in improved economics and rates of return. These efficiencies, coupled with being ahead of schedule on production volumes, are allowing us to add an additional $210 million of capital to the Marcellus project in 2010. The additional capital, in turn, will help us to accelerate the Company’s net asset value of the Marcellus Shale play.
Pipeline, compression and plant processing infrastructure capacity in the Marcellus is on schedule. In the southwest portion of the play, an additional 30 Mmcfe per day of capacity is scheduled to be complete in the fourth quarter of this year and an additional 150 Mmcfe per day is scheduled for first quarter 2011. This processing capacity coupled with additional dry gas taps will position Range well in 2011 and beyond for increased production in the southwest portion of the play. With regard to the northeast portion of the play, solid progress is being made on the first phase of the Lycoming County pipeline project which is scheduled to begin flowing gas on or before year end 2010. Firm take away capacity has been contracted for both the southwest and northeast areas to allow our Marcellus Shale production to flow on time and within our forecasts.
As we ramp up development in the Marcellus, our technical team continues to make significant progress. Our production curves as updated and presented with zero time plots on our website illustrate continued improvements in well performance and demonstrate the progress that our technical team is making. Range previously announced an encouraging test of its first Upper Devonian Shale horizontal well. Given the Upper Devonian’s prevalence across our acreage position, we are very encouraged regarding the increased unproved resource potential this well implies on our existing acreage in southwestern Pennsylvania. The Marcellus Shale team plans two additional Upper Devonian test wells in 2010. Range plans to spud another Utica Shale well early in the first quarter of 2011.
In the second quarter, the Southwest Division continued its success while running two rigs. In the Barnett Shale formation, the Company completed four wells with excellent results. In Johnson County, two wells were completed with a combined rate of 6.0 (3.6 net) Mmcfe per day, while in Tarrant County, another two wells were completed with combined rates of 10 (7.0 net) Mmcfe per day. In the Permian Basin, the division drilled and completed one new oil well and deepened another. One of the
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wells came online at 509 (381 net) Boe per day, while the other had initial production of 640 (480 net) Boe per day.
During the second quarter 2010, Range’s Appalachian Division continued to focus its key tight gas sand, coal bed methane and horizontal drilling projects in the Nora field in Virginia, drilling a total of 35 (17.5 net) wells. During the quarter, Range drilled 12 vertical tight gas sand wells and one horizontal Huron Shale well. In addition, Range drilled 15 new coalbed methane wells and 7 infill coalbed methane wells in the Nora field for the quarter.
During the second quarter, the Midcontinent Division focused on the Texas Panhandle Granite Wash and the northern Oklahoma shallow oil plays. Two vertical Granite Wash wells commenced sales during the quarter at combined rates of 4.4 (3.5 net) Mmcfe per day. One additional well is completing with three more scheduled in the play for 2010. In the northern Oklahoma shallow oil play, one horizontal well was placed on production at a rate of 295 (236 net) BOE per day. This well reached only one-half of its projected lateral length, yet has responded with more than 50% of the production volumes associated with the first horizontal test. A second well is currently completing, with three additional wells planned for the remainder of the year. In the Ardmore Basin Woodford play, drilling operations also commenced in the quarter. One well is currently completing, and one rig will remain active for the remainder of 2010. All three of these main play areas of the Midcontinent contain oil components which greatly add to their well economics and rates of return.
Conference Call Information
The Company will host a conference call on Tuesday, July 27 at 9:00 a.m. ET to review these results. To participate in the call, please dial 877-407-8031 and ask for the Range Resources’ second quarter financial results conference call. A replay of the call will be available through August 2 at 877-660-6853. The account number is 286 and the conference ID for the replay is 353994. 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 and Supplemental Tables:
Second quarter 2010 results included several non-cash items. The $10 million gain on the secondary closing of the Ohio property sale, a $4 million non-cash mark-to-market loss on unrealized derivatives, property impairments of $13 million, a $14 million gain recorded for the mark-to-market in the deferred compensation plan, $13 million of non-cash stock compensation expense and $3 million for lawsuit settlements were recorded. Excluding these items, net income would have been $14.1 million or $0.09 per share ($0.09 fully diluted). Excluding similar non-cash items from the prior-year quarter, net income would have been $33.7 million or $0.22 per share ($0.21 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.)
“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
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accepted by the investment community as a financial indicator of an oil and gas company’s ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered as an alternative to “Cash flows from operating, investing, or financing activities” as an indicator of cash flows, or as a measure of liquidity. A table is included which reconciles “Net cash provided from operating activities” to “Cash flow from operations before changes in working capital” as used in this release. On its website, the Company provides additional comparative information on prior periods.
Hedging and Derivatives
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 (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.
RANGE RESOURCES CORPORATION (NYSE: RRC)is an independent natural gas company operating in the Southwestern and Appalachian regions of the United States.
Except for historical information, statements made in this release such as expected drill bit finding and development costs, attractive returns on capital, expected operating costs, expected production growth and exit rates, expected capital funding sources, reduction of future unit costs, attractive hedge positions, solid financial position, estimated ultimate recovery and unproved 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 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, 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. 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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| Contacts: | | Rodney Waller, Sr. Vice President | | | 817-869-4258 | | | |
| | | David Amend, Investor Relations Manager | | | 817-869-4266 | | | |
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| Karen Giles, Corporate Communications Manager 817-869-4238 | | | | | | |
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| | | Main number: | | | 817-870-2601 | | | |
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| | | 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-Q (Unaudited, in thousands, except per share data)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30, | | | Six Months Ended June 30, | |
| | | 2010 | | | 2009 | | | | | | | 2010 | | | 2009 | | | | | |
| Revenues | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil and gas sales (a) | | $ | 206,784 | | | $ | 192,523 | | | | | | | $ | 443,544 | | | $ | 395,712 | | | | | |
| Cash-settled derivative gain (loss) (a)(c) | | | 10,695 | | | | 51,383 | | | | | | | | 6,699 | | | | 95,858 | | | | | |
| Transportation and gathering | | | 983 | | | | 2,339 | | | | | | | | 3,410 | | | | 2,110 | | | | | |
| Transportation and gathering — non-cash stock compensation (b) | | | (309 | ) | | | (187 | ) | | | | | | | (643 | ) | | | (463 | ) | | | | |
| Change in mark-to-market on unrealized derivatives (c) | | | (4,409 | ) | | | (61,595 | ) | | | | | | | 42,169 | | | | (30,070 | ) | | | | |
| Ineffective hedging gain (loss) (c) | | | 260 | | | | 356 | | | | | | | | 11 | | | | (97 | ) | | | | |
| Equity method investment (d) | | | 636 | | | | (4,608 | ) | | | | | | | (985 | ) | | | (5,526 | ) | | | | |
| Gain (loss) on sale of properties (d) | | | 10,176 | | | | (29 | ) | | | | | | | 79,044 | | | | 7 | | | | | |
| Interest and other (d) | | | 1 | | | | 250 | | | | | | | | 47 | | | | (662 | ) | | | | |
| | | | 224,817 | | | | 180,432 | | | | 25 | % | | | 573,296 | | | | 456,869 | | | | 25 | % |
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| Expenses | | | | | | | | | | | | | | | | | | | | | | | | |
| Direct operating | | | 29,150 | | | | 33,998 | | | | | | | | 59,697 | | | | 68,810 | | | | | |
| Direct operating — non-cash stock compensation (b) | | | 625 | | | | 830 | | | | | | | | 1,118 | | | | 1,559 | | | | | |
| Production and ad valorem taxes | | | 8,090 | | | | 7,564 | | | | | | | | 16,160 | | | | 15,821 | | | | | |
| Exploration | | | 13,401 | | | | 10,475 | | | | | | | | 26,900 | | | | 22,753 | | | | | |
| Exploration — non-cash stock compensation (b) | | | 1,072 | | | | 893 | | | | | | | | 2,208 | | | | 1,954 | | | | | |
| Abandonment and impairment of unproven properties | | | 13,497 | | | | 40,954 | | | | | | | | 25,904 | | | | 60,526 | | | | | |
| General and administrative | | | 22,532 | | | | 20,168 | | | | | | | | 42,860 | | | | 38,853 | | | | | |
| General and administrative — non-cash stock compensation (b) | | | 10,738 | | | | 8,935 | | | | | | | | 18,580 | | | | 15,160 | | | | | |
| General and administrative — lawsuit settlements | | | 2,566 | | | | — | | | | | | | | 2,566 | | | | — | | | | | |
| Termination costs | | | — | | | | — | | | | | | | | 5,138 | | | | — | | | | | |
| Termination costs — non-cash stock compensation (b) | | | — | | | | — | | | | | | | | 2,800 | | | | — | | | | | |
| Deferred compensation plan (e) | | | (14,135 | ) | | | 756 | | | | | | | | (19,847 | ) | | | 13,190 | | | | | |
| Interest | | | 30,779 | | | | 29,555 | | | | | | | | 61,066 | | | | 56,184 | | | | | |
| Depletion, depreciation and amortization | | | 90,997 | | | | 88,713 | | | | | | | | 179,623 | | | | 173,033 | | | | | |
| Proved property impairment | | | — | | | | — | | | | | | | | 6,505 | | | | — | | | | | |
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| | | | 209,312 | | | | 242,841 | | | | -14 | % | | | 431,278 | | | | 467,843 | | | | -8 | % |
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| Income (loss) from operations before income taxes | | | 15,505 | | | | (62,409 | ) | | | 125 | % | | | 142,018 | | | | (10,974 | ) | | | 1,394 | % |
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| Income taxes | | | | | | | | | | | | | | | | | | | | | | | | |
| Current | | | — | | | | 619 | | | | | | | | — | | | | 619 | | | | | |
| Deferred | | | 6,453 | | | | (23,145 | ) | | | | | | | 55,387 | | | | (4,318 | ) | | | | |
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| | | | 6,453 | | | | (22,526 | ) | | | | | | | 55,387 | | | | (3,699 | ) | | | | |
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| Net income (loss) | | $ | 9,052 | | | $ | (39,883 | ) | | | 123 | % | | $ | 86,631 | | | $ | (7,275 | ) | | | 1,291 | % |
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| Earnings per share | | | | | | | | | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.06 | | | $ | (0.26 | ) | | | 123 | % | | $ | 0.54 | | | $ | (0.05 | ) | | | 1,180 | % |
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| Diluted | | $ | 0.06 | | | $ | (0.26 | ) | | | 123 | % | | $ | 0.54 | | | $ | (0.05 | ) | | | 1,180 | % |
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| Weighted average shares outstanding, as reported | | | | | | | | | | | | | | | | | | | | | | | | |
| Basic | | | 156,820 | | | | 154,389 | | | | 2 | % | | | 156,608 | | | | 154,056 | | | | 2 | % |
| Diluted | | | 158,472 | | | | 154,389 | | | | 3 | % | | | 158,601 | | | | 154,056 | | | | 3 | % |
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| (a) | | See separate oil and gas sales information table. |
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| (b) | | 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. |
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| (c) | | Included in Derivative fair value income (loss) in the 10-Q. |
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| (d) | | Included in Other revenues in the 10-Q. |
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| (e) | | Reflects the change in the market value of the vested Company stock held in the deferred compensation plan. |
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RANGE RESOURCES CORPORATION
BALANCE SHEETS
(in thousands)
| | | | | | | | | |
| | | June 30, | | | December 31, | |
| | | 2010 | | | 2009 | |
| | | (Unaudited) | | | (Audited) | |
| Assets | | | | | | | | |
| Current assets | | $ | 289,548 | | | $ | 153,735 | |
| Current unrealized derivative gain | | | 83,864 | | | | 21,545 | |
| Oil and gas properties | | | 5,055,513 | | | | 4,898,819 | |
| Transportation and field assets | | | 80,807 | | | | 91,835 | |
| Unrealized derivative gain | | | 26,032 | | | | 4,107 | |
| Other | | | 227,081 | | | | 225,840 | |
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| | | $ | 5,762,845 | | | $ | 5,395,881 | |
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| Liabilities and Stockholders’ Equity | | | | | | | | |
| Current liabilities | | $ | 346,394 | | | $ | 297,170 | |
| Current asset retirement obligation | | | 2,446 | | | | 2,446 | |
| Current unrealized derivative loss | | | 2,781 | | | | 14,488 | |
| Bank debt | | | 475,000 | | | | 324,000 | |
| Subordinated notes | | | 1,384,562 | | | | 1,383,833 | |
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| Total long-term debt | | | 1,859,562 | | | | 1,707,833 | |
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| Deferred taxes | | | 839,245 | | | | 776,965 | |
| Unrealized derivative loss | | | — | | | | 271 | |
| Deferred compensation liability | | | 113,247 | | | | 135,541 | |
| Long-term asset retirement obligation and other | | | 72,331 | | | | 82,578 | |
| Common stock and retained earnings | | | 2,491,958 | | | | 2,380,132 | |
| Treasury stock | | | (7,741 | ) | | | (7,964 | ) |
| Other comprehensive income | | | 42,622 | | | | 6,421 | |
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| Total stockholders’ equity | | | 2,526,839 | | | | 2,378,589 | |
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| | | $ | 5,762,845 | | | $ | 5,395,881 | |
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RANGE RESOURCES CORPORATION
CASH FLOWS FROM OPERATING ACTIVITIES
(Unaudited, in thousands)
| | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30, | | | June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| Net income (loss) | | $ | 9,052 | | | $ | (39,883 | ) | | $ | 86,631 | | | $ | (7,275 | ) |
| Adjustments to reconcile net income to net cash provided from operating activities: | | | | | | | | | | | | | | | | |
| Loss (gain) from equity investment | | | (636 | ) | | | 4,607 | | | | 985 | | | | 5,526 | |
| Deferred income tax expense (benefit) | | | 6,453 | | | | (23,145 | ) | | | 55,387 | | | | (4,318 | ) |
| Depletion, depreciation and amortization and impairment of proved properties | | | 90,998 | | | | 88,713 | | | | 186,129 | | | | 173,033 | |
| Exploration dry hole costs | | | — | | | | 8 | | | | — | | | | 131 | |
| Abandonment and impairment of unproved properties | | | 13,497 | | | | 40,954 | | | | 25,904 | | | | 60,526 | |
| Mark-to-market (gains) losses on oil and gas derivatives not designated as hedges | | | 4,409 | | | | 61,595 | | | | (42,169 | ) | | | 30,070 | |
| Unrealized derivative (gain) loss | | | (260 | ) | | | (356 | ) | | | (11 | ) | | | 97 | |
| Amortization of deferred financing costs and other | | | 1,200 | | | | 1,283 | | | | 2,367 | | | | 2,333 | |
| Deferred and stock-based compensation | | | (1,411 | ) | | | 11,630 | | | | 5,866 | | | | 32,794 | |
| (Gain) loss on sale of assets and other | | | (10,176 | ) | | | 1,947 | | | | (79,044 | ) | | | 1,943 | |
| | | | | | | | | | | | | | | | | |
| Changes in working capital: | | | | | | | | | | | | | | | | |
| Accounts receivable | | | 8,547 | | | | 1,057 | | | | 15,392 | | | | 46,453 | |
| Inventory and other | | | 1,038 | | | | (432 | ) | | | 338 | | | | (2,154 | ) |
| Accounts payable | | | (3,593 | ) | | | (33,909 | ) | | | 13,859 | | | | (72,008 | ) |
| Accrued liabilities | | | (11,555 | ) | | | 5,204 | | | | (11,197 | ) | | | 1,283 | |
| | | | | | | | | | | | | |
| Net changes in working capital | | | (5,563 | ) | | | (28,080 | ) | | | 18,392 | | | | (26,426 | ) |
| | | | | | | | | | | | | |
| Net cash provided from operating activities | | $ | 107,563 | | | $ | 119,273 | | | $ | 260,437 | | | $ | 268,434 | |
| | | | | | | | | | | | | |
RECONCILIATION OF NET CASH PROVIDED FROM OPERATING
ACTIVITIES, AS REPORTED, TO CASH FLOW FROM OPERATIONS
BEFORE CHANGES IN WORKING CAPITAL, a non-GAAP measure
(Unaudited, in thousands)
| | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30, | | | June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| Net cash provided from operating activities, as reported | | $ | 107,563 | | | $ | 119,273 | | | $ | 260,437 | | | $ | 268,434 | |
| | | | | | | | | | | | | | | | | |
| Net change in working capital | | | 5,563 | | | | 28,080 | | | | (18,392 | ) | | | 26,426 | |
| | | | | | | | | | | | | | | | | |
| Exploration expense | | | 13,527 | | | | 10,467 | | | | 27,026 | | | | 22,622 | |
| | | | | | | | | | | | | | | | | |
| Office closing severance/exit accrual | | | — | | | | — | | | | 5,138 | | | | — | |
| | | | | | | | | | | | | | | | | |
| Lawsuit settlements | | | 2,566 | | | | — | | | | 2,566 | | | | — | |
| | | | | | | | | | | | | | | | | |
| Non-cash compensation and other | | | 156 | | | | (1,946 | ) | | | 49 | | | | (2,418 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Cash flow from operations before changes in working capital, a non-GAAP measure | | $ | 129,375 | | | $ | 155,874 | | | $ | 276,824 | | | $ | 315,064 | |
| | | | | | | | | | | | | |
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING
(Unaudited, in thousands)
| | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30, | | | June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| Basic: | | | | | | | | | | | | | | | | |
| Weighted average shares outstanding | | | 159,625 | | | | 156,948 | | | | 159,350 | | | | 156,522 | |
| Stock held by deferred compensation plan | | | (2,805 | ) | | | (2,559 | ) | | | (2,742 | ) | | | (2,466 | ) |
| | | | | | | | | | | | | |
| | | | 156,820 | | | | 154,389 | | | | 156,608 | | | | 154,056 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Dilutive: | | | | | | | | | | | | | | | | |
| Weighted average shares outstanding | | | 159,625 | | | | 156,948 | | | | 159,350 | | | | 156,522 | |
| Dilutive stock options under treasury method unless anti-dilutive | | | (1,153 | ) | | | (2,559 | ) | | | (749 | ) | | | (2,466 | ) |
| | | | | | | | | | | | | |
| | | | 158,472 | | | | 154,389 | | | | 158,601 | | | | 154,056 | |
| | | | | | | | | | | | | |
13
RANGE RESOURCES CORPORATION
RECONCILIATION OF OIL AND GAS SALES AND DERIVATIVE FAIR VALUE
INCOME (LOSS) TO CALCULATED CASH REALIZED OIL AND GAS SALES,
PRODUCTION PRICES AND DIRECT
OPERATING CASH COSTS,a non-GAAP measure
(Unaudited, in thousands, except per unit data)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30, | | | | | | | June 30, | | | | | |
| | | 2010 | | | 2009 | | | | | | | 2010 | | | 2009 | | | | | |
| Oil and gas sales components: | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil sales | | $ | 32,913 | | | $ | 39,943 | | | | | | | $ | 68,797 | | | $ | 68,022 | | | | | |
| NGL sales | | | 32,608 | | | | 12,702 | | | | | | | | 68,499 | | | | 19,569 | | | | | |
| Gas sales | | | 122,923 | | | | 86,723 | | | | | | | | 286,693 | | | | 203,642 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash-settled hedges (effective): | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude oil | | | 23 | | | | 2,642 | | | | | | | | 23 | | | | 12,007 | | | | | |
| Natural gas | | | 18,317 | | | | 50,513 | | | | | | | | 19,532 | | | | 92,472 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total oil and gas sales, as reported | | $ | 206,784 | | | $ | 192,523 | | | | 7 | % | | $ | 443,544 | | | $ | 395,712 | | | | 12 | % |
| | | | | | | | | | | | | | | | | | | | | |
| Derivative fair value income (loss) components: | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash-settled derivatives (ineffective): | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude oil | | $ | — | | | $ | 1,934 | | | | | | | $ | — | | | $ | 7,548 | | | | | |
| Natural gas | | | 10,695 | | | | 49,449 | | | | | | | | 6,699 | | | | 88,310 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Change in mark-to-market on unrealized derivatives | | | (4,409 | ) | | | (61,595 | ) | | | | | | | 42,169 | | | | (30,070 | ) | | | | |
| Unrealized ineffectiveness | | | 260 | | | | 356 | | | | | | | | 11 | | | | (97 | ) | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Total derivative fair value income (loss), as reported | | $ | 6,546 | | | $ | (9,856 | ) | | | | | | $ | 48,879 | | | $ | 65,691 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil and gas sales, including cash-settled derivatives: | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil sales | | $ | 32,936 | | | $ | 44,519 | | | | | | | $ | 68,820 | | | $ | 87,577 | | | | | |
| Natural gas liquid sales | | | 32,608 | | | | 12,702 | | | | | | | | 68,499 | | | | 19,569 | | | | | |
| Gas sales | | | 151,935 | | | | 186,685 | | | | | | | | 312,924 | | | | 384,424 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 217,479 | | | $ | 243,906 | | | | -11 | % | | $ | 450,243 | | | $ | 491,570 | | | | -8 | % |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Production during the period (a): | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil (bbl) | | | 484,742 | | | | 731,244 | | | | -34 | % | | | 999,420 | | | | 1,453,204 | | | | -31 | % |
| Natural gas liquid (bbl) | | | 878,219 | | | | 525,993 | | | | 67 | % | | | 1,709,355 | | | | 949,254 | | | | 80 | % |
| Gas (mcf) | | | 34,751,687 | | | | 31,905,593 | | | | 9 | % | | | 68,502,246 | | | | 62,457,926 | | | | 10 | % |
| Equivalent (mcfe) (b) | | | 42,929,453 | | | | 39,449,015 | | | | 9 | % | | | 84,754,896 | | | | 76,872,674 | | | | 10 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Production — average per day (a): | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil (bbl) | | | 5,327 | | | | 8,036 | | | | -34 | % | | | 5,522 | | | | 8,029 | | | | -31 | % |
| Natural gas liquid (bbl) | | | 9,651 | | | | 5,780 | | | | 67 | % | | | 9,444 | | | | 5,244 | | | | 80 | % |
| Gas (mcf) | | | 381,887 | | | | 350,611 | | | | 9 | % | | | 378,465 | | | | 345,071 | | | | 10 | % |
| Equivalent (mcfe) (b) | | | 471,752 | | | | 433,506 | | | | 9 | % | | | 468,259 | | | | 424,711 | | | | 10 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Average prices realized, including cash-settled hedges and derivatives: | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude oil (per bbl) | | $ | 67.96 | | | $ | 60.88 | | | | 12 | % | | $ | 68.86 | | | $ | 60.26 | | | | 14 | % |
| Natural gas liquid (per bbl) | | $ | 37.13 | | | $ | 24.15 | | | | 54 | % | | $ | 40.07 | | | $ | 20.61 | | | | 94 | % |
| Gas (per mcf) | | $ | 4.37 | | | $ | 5.85 | | | | -25 | % | | $ | 4.57 | | | $ | 6.15 | | | | -26 | % |
| Equivalent (per mcfe) (b) | | $ | 5.07 | | | $ | 6.18 | | | | -18 | % | | $ | 5.31 | | | $ | 6.39 | | | | -17 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Direct operating cash costs per mcfe (c): | | | | | | | | | | | | | | | | | | | | | | | | |
| Field expenses | | $ | 0.65 | | | $ | 0.84 | | | | -23 | % | | $ | 0.67 | | | $ | 0.87 | | | | -23 | % |
| Workovers | | | 0.03 | | | | 0.02 | | | | 50 | % | | | 0.03 | | | | 0.03 | | | | 0 | % |
| | | | | | | | | | | | | | | | | | | | | |
| Total direct operating cash costs | | $ | 0.68 | | | $ | 0.86 | | | | -21 | % | | $ | 0.70 | | | $ | 0.90 | | | | -22 | % |
| | | | | | | | | | | | | | | | | | | | | |
| | |
| (a) | | Represents volumes sold regardless of when produced. |
| |
| (b) | | Oil and natural gas liquids are converted to gas equivalents on a basis of six mcf per barrel. |
| |
| (c) | | Excludes non-cash stock compensation. |
14
RANGE RESOURCES CORPORATION
RECONCILIATION OF INCOME (LOSS) FROM OPERATIONS BEFORE INCOME TAXES
AS REPORTED TO INCOME FROM OPERATIONS BEFORE INCOME TAXES
EXCLUDING CERTAIN ITEMS, a non-GAAP measure
(Unaudited, in thousands, except per share data)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30, | | | | | | | June 30, | | | | | |
| | | 2010 | | | 2009 | | | | | | | 2010 | | | 2009 | | | | | |
| Income (loss) from operations before income taxes, as reported | | $ | 15,505 | | | $ | (62,409 | ) | | | 125 | % | | $ | 142,018 | | | $ | (10,974 | ) | | | 1,394 | % |
| Adjustment for certain non-cash items | | | | | | | | | | | | | | | | | | | | | | | | |
| (Gain) loss on sale of properties | | | (10,176 | ) | | | 29 | | | | | | | | (79,044 | ) | | | (7 | ) | | | | |
| Change in mark-to-market on unrealized derivatives (gain) loss | | | 4,409 | | | | 61,595 | | | | | | | | (42,169 | ) | | | 30,070 | | | | | |
| Ineffective hedging (gain) loss | | | (260 | ) | | | (356 | ) | | | | | | | (11 | ) | | | 97 | | | | | |
| Abandonment and impairment of unproven properties | | | 13,497 | | | | 40,954 | | | | | | | | 25,904 | | | | 60,526 | | | | | |
| Proved property impairment | | | — | | | | — | | | | | | | | 6,505 | | | | — | | | | | |
| Termination costs | | | — | | | | — | | | | | | | | 7,938 | | | | — | | | | | |
| Lawsuit settlements | | | 2,566 | | | | — | | | | | | | | 2,566 | | | | — | | | | | |
| Equity method impairment | | | — | | | | 2,950 | | | | | | | | — | | | | 2,950 | | | | | |
| Transportation and gathering — non-cash stock compensation | | | 309 | | | | 187 | | | | | | | | 643 | | | | 463 | | | | | |
| Direct operating — non-cash stock compensation | | | 625 | | | | 830 | | | | | | | | 1,118 | | | | 1,559 | | | | | |
| Exploration expenses — non-cash stock compensation | | | 1,072 | | | | 893 | | | | | | | | 2,208 | | | | 1,954 | | | | | |
| General & administrative — non-cash stock compensation | | | 10,738 | | | | 8,935 | | | | | | | | 18,580 | | | | 15,160 | | | | | |
| Deferred compensation plan — non-cash stock compensation | | | (14,135 | ) | | | 756 | | | | | | | | (19,847 | ) | | | 13,190 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Income from operations before income taxes, as adjusted | | | 24,150 | | | | 54,364 | | | | -56 | % | | | 66,409 | | | | 114,988 | | | | -42 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Income taxes, adjusted | | | | | | | | | | | | | | | | | | | | | | | | |
| Current | | | — | | | | 619 | | | | | | | | — | | | | 619 | | | | | |
| Deferred | | | 10,051 | | | | 20,061 | | | | | | | | 26,387 | | | | 42,251 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Net income excluding certain items, a non-GAAP measure | | $ | 14,099 | | | $ | 33,684 | | | | -58 | % | | $ | 40,022 | | | $ | 72,118 | | | | -45 | % |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Non-GAAP earnings per share | | | | | | | | | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.09 | | | $ | 0.22 | | | | -59 | % | | $ | 0.26 | | | $ | 0.47 | | | | -45 | % |
| | | | | | | | | | | | | | | | | | | | | |
| Diluted | | $ | 0.09 | | | $ | 0.21 | | | | -57 | % | | $ | 0.25 | | | $ | 0.46 | | | | -46 | % |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Non-GAAP diluted shares outstanding, if dilutive | | | 158,472 | | | | 158,350 | | | | | | | | 158,601 | | | | 158,150 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
HEDGING POSITION
As of July 26, 2010
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Gas | | | Oil | |
| | | | | | | Volume | | | Average | | | Volume | | | Average | |
| | | | | | | Hedged | | | Hedge | | | Hedged | | | Hedge | |
| | | | | | | (Mmbtu/d) | | | Prices | | | (Bbl/d) | | | Prices | |
| 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 | | | | | | | 325,000 | | | $ | 5.56 - $7.20 | | | | 1,000 | | | $ | 75.00- $93.75 | |
| | | | | | | | | | | | | | | | | |
| Total 2011 | | Collars | | | 325,000 | | | $ | 5.57 - $6.54 | | | | 5,244 | | | $ | 70.00 - $90.00 | |
| | | | | | | | | | | | | | | | | |
| Total 2012 | | Collars | | | 60,300 | | | $ | 5.50 - $6.25 | | | | 2,000 | | | $ | 70.00 - $80.00 | |
| | | | | | | | | | | | | | | | | |
| | |
| Note: | | Details as to the Company’s hedges are posted on its website and are updated periodically. See website for Supplemental Tables 6 and 7 detailing any premiums paid or received in connection with the hedges above. |
15
SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS
16
