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Range Announces Second Quarter 2012 Results

FORT WORTH, Texas--(BUSINESS WIRE)--Jul. 24, 2012-- RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its second quarter 2012 results. Revenues for the second quarter 2012 totaled $442 million, a 32% increase over the prior year quarter. Net cash provided from operating activities including changes in working capital totaled $127 million, declining 25% from the prior year quarter. Reported net income for the second quarter 2012 totaled $55.7 million ($0.34 per diluted share), a 6% increase over the second quarter 2011. Revenue and cash flow results were driven by higher production volumes and lower unit costs offset by lower realized prices. Revenue and earnings also included the impact of a derivative mark-to-market gain of $136 million.

Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $18.1 million ($0.11 per diluted share) compared to $43.2 million ($0.27 per diluted share) in the prior year quarter. Cash flow from operations before changes in working capital, a non-GAAP measure, decreased 7% year-over-year to $156 million. Comparing these amounts to analysts’ average First Call consensus estimates, the Company’s earnings per share ($0.11 per diluted share) were six cents higher than the consensus of analysts’ estimates of $0.05 per diluted share. Cash flow per share ($0.97 per diluted share) for the quarter was two cents higher than the consensus analysts’ estimates of $0.95 per diluted share. 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, Jeff Ventura, Range’s President and CEO, said, “Our second quarter results reflect excellent performance. The benefits of our Barnett sale last year have positively impacted our second quarter operating and financial results. The sale allowed us to fast-forward the development of our core plays, improve our capital efficiency, lower our cost structure, and strengthen our financial position. The 42% increase in production coupled with a 16% decrease in aggregate cash unit costs are a vivid reflection of our performance combined with the sale benefits. While low natural gas prices impacted our financial results, our strong hedge position provided substantial protection. Looking ahead, we have approximately 80% of expected production hedged for the remainder of the year.

“We now expect our 2012 production growth to be 35%, or the high end of our previous full-year guidance. We also expect liquids growth in the fourth quarter to reach 40% compared to the fourth quarter of 2011. With the excellent drilling results in the first half of the year and our strong hedge position, we are well positioned to add material per share value in the second half of 2012.”

Financial Discussion

(Range sold substantially all of its Barnett Shale properties in April of 2011. Under generally accepted accounting principles (“GAAP”), activity in 2011 for the Barnett Shale properties was reclassified as “Discontinued operations.” As a result, production, revenue and expenses associated with the properties were removed from continuing operations and reclassified as discontinued operations. In this release, the Statements of Income are broken out to reconcile and show the changes to the current period and the prior-year period for the reclassification of the discontinued operations. These supplemental non-GAAP tables present the reported GAAP amounts as compared to the amounts that would have been reported if the Barnett Shale operations were included in continuing operations. All variances discussed in this release include the Barnett Shale operations as continuing operations in all prior year periods. Except for reported GAAP amounts, specific expense categories exclude non-cash property impairments, mark-to-market on unrealized derivatives, non-cash stock compensation and other items shown separately on attached tables but include the amounts associated with Barnett Shale properties combined with the reported continuing operations amounts. Effective with 2011 year-end reporting, the Company reclassified only third party transportation, gathering and compression costs as a separate component of operating expenses which previously was included as a reduction of natural gas, natural gas liquids and oil sales. Prior reported results have been similarly reclassified to conform to the current year presentation.)

For the quarter, production averaged 719.3 Mmcfe per day, comprised of 574.7 Mmcf per day of gas (80%), 17,259 barrels per day of natural gas liquids (14%) and 6,846 barrels per day of oil (6%). Natural gas production grew 48%, NGL production increased 20% and crude oil production increased 23% over the prior-year quarter due to outstanding drilling results. Realized prices, including all cash-settled derivatives, averaged $4.74 per mcfe, a 26% decrease over the prior-year quarter of $6.43 and a 9% decrease as compared to the first quarter 2012 of $5.19 per mcfe. The average realized natural gas price was $3.66 per mcf, 32% lower than the prior-year quarter. NGL prices decreased 18% to $42.30 per barrel versus the prior-year quarter, while the average oil price rose 5% to $84.31 per barrel.

Reported natural gas, NGL and oil sale revenues for the quarter were $298 million, an increase of 5% as compared to the prior year excluding sales from the Barnett properties. Total natural gas, NGL and oil sales (including all cash settled derivatives and the Barnett properties) increased 5% compared to the prior-year quarter to $311 million due to higher volumes offset by lower prices. Cash settled hedging gains of approximately $90 million were realized during the quarter. As of June 30, 2012, Range had future hedging gains of approximately $340 million with roughly half to be recognized in the second half of 2012, roughly 45% in 2013 and 5% in 2014, if prices remain the same.

During the second quarter of 2012, Range continued to lower its cost structure. On a unit of production basis, the Company’s five largest cash cost categories decreased an average 16% versus the prior year quarter, even with the Pennsylvania impact fee affecting only the current year quarter. Per unit cash costs including DD&A being the six main operating expense categories were down 11% for the quarter compared to the prior year quarter. The most significant per unit cash cost declines in the second quarter compared to the prior year quarter were lease operating unit expenses down 38%, general and administrative costs down 21%, and interest expense down 14%.

Several non-cash or non-recurring items impacted second quarter results. A $136 million mark-to-market gain was recorded to reflect the increase in the value of the Company’s commodity hedges due to lower oil and NGL commodity prices during the quarter. A $3.2 million loss was incurred on the sale of certain non-core properties.

Capital Expenditures

Second quarter drilling expenditures of $390 million funded the drilling of 79 (68 net) wells and the completion of previously drilled wells. A 100% drilling success rate was achieved. Year to date drilling expenditures for 2012 totaled $724 million. For the first six months of 2012, Range has drilled 153 (126 net) wells. At June 30, 55 (49 net) wells drilled during the year had been placed on production. The remaining 98 (77 net) wells are in various stages of completion or waiting on pipeline connection. In the first six months of 2012, $152 million was expended on acreage, $24 million on gas gathering systems and $35 million for exploration expense (including $20 million for seismic and $7 million for delay rentals).

The capital expenditure budget for 2012 of $1.6 billion remains unchanged. In the plan, capital spending was heavily weighted to the first half of the year. Plans include the drilling of longer laterals with a greater number of frac stages for Marcellus wells. Under this plan, coupled with increased drilling efficiencies, the number of rigs required will be reduced throughout the second half of the year. This will allow us to complete our Marcellus program with reduced drilling costs while adding more frac stages with our Reduced Cluster Spacing (“RCS”) techniques and is expected to increase recoveries and improve our rates of return.

To optimize its portfolio and maintain a strong balance sheet, Range has engaged RBC Richardson Barr to market its Ardmore Basin Woodford properties. These properties include 9,300 net acres in the heart of the play, currently producing 1,100 barrels of liquids per day and 5.7 Mmcf per day, with multiple infill drilling opportunities at very good rates of return. However, with higher returns in the Marcellus and horizontal Mississippian projects, Range has determined to market the Woodford properties and focus its efforts on these two projects which also have greater scale and potential upside.

Hedging Status

Range hedges portions of its expected future production volumes to increase the predictability of its cash flow and to help maintain a strong financial position. At June 30, 2012, Range had more than 80% of its expected 2012 natural gas production hedged at a weighted average floor of $4.18 per mcf. Similarly, Range has hedged or committed approximately 80% of its projected crude oil production at a floor of $91.19 and approximately 60% of its composite NGL production for 2012 at above current market prices. During the second quarter, Range realized approximately $90 million in hedging gains. As of June 30, 2012, Range had future hedging gains of approximately $340 million with roughly half to be recognized in the second half of 2012, roughly 45% in 2013 and 5% in 2014 if commodity prices remain the same. In order to more effectively hedge its NGL production, Range is currently using natural gasoline (C5) and propane (C3) as proxy hedges for the heavy and light portions of the NGL composite barrel to better correlate the market relationship between our hedges and our production. We believe this approach has allowed us to support our NGL prices without the additional cost of hedging each NGL barrel component. Please see Range’s detailed hedging schedule posted on its website.

Operational Discussion

Marcellus Shale-

Marcellus Shale production reached 500 Mmcfe per day net at the end of the second quarter. Range is on track to meet or exceed its 600 Mmcfe per day net production target by year-end 2012.

Southern Marcellus Shale Division-

The Southern Marcellus Shale division ended the second quarter at approximately 378 Mmcfe per day net from the Marcellus Shale with four horizontal and two air rigs in operation. Due to improvements in drilling and completion efficiencies, we are expecting to utilize fewer rigs in the second half of the year while still meeting our production targets.

During the second quarter, the division brought online 33 wells in southwest Pennsylvania, with 15 wells in the super-rich area, 13 wells in the wet area and 5 wells in the dry area. The initial 24-hour production rates of the 33 new wells averaged 6.9 (5.3 net) Mmcfe per day (4.8 Mmcf gas, 160 barrels of condensate and 183 barrels of NGLs. As of June 30, 2012 the division had 50 wells waiting on completion and an additional 56 wells waiting on pipeline for sales.

In the super-rich area, we recently tested a well that flowed at an initial 24-hour rate of 11.7 Mmcfe per day (5.7 Mmcf of gas, 546 barrels of condensate and 454 barrels of NGLs). In addition, we have recently drilled and brought online two pads that are along the wet/dry line of 1,050 BTU gas. One is just on the dry side and has 1,040 BTU gas. This pad has five wells that averaged 14.0 Mmcf per day per well for an initial 24-hour rate to sales. After two months of production, the wells have averaged 7.4 Mmcf per day and we expect reserves for these wells to average 7 to 8 Bcf each. The wells average lateral length is 2,630 feet with 11 stages. The other pad is just over the wet/dry line and has a BTU content of 1,065. This 10 well pad had an average IP of 13.7 Mmcf per day per well for its initial 24-hour rate to sales. After three months of production, these wells have averaged 5.6 Mmcf per day while being facility constrained and appear to have average reserves in the range of 7 to 8 Bcf each. They have an average lateral length of 2,700 feet with 10 stages per well. The two pads are about 35 miles apart, and we believe the quality of these wells is excellent.

Northern Marcellus Shale Division-

In the Northern Marcellus Shale Division, Range drilled 16 horizontal wells during the second quarter in Lycoming County. Also, a total of 16 horizontal wells were turned to sales during the second quarter. Significant well results include three wells brought online with an average lateral length of 3,850 feet with 14 frac stages per well. The first well had a 24-hour initial production rate of 10.2 (8.7 net) Mmcf per day, the second well 12.3 (10.6 net) Mmcf per day and the third 12.1 (10.4 net) Mmcf per day. At the end of the second quarter there were 53 horizontal wells producing 132 net Mmcf per day with 12 wells waiting on pipeline and 23 wells waiting on completion.

Range expects to reduce the number of rigs to two rigs by the end of the third quarter and one rig by the end of the fourth quarter. In addition to Marcellus drilling, the Northern Division is planning to drill two horizontal test wells in the Utica Shale in northwest Pennsylvania by year-end 2012. The first Utica test was spud earlier this month and is currently drilling.

In the Bradford County joint venture area with Talisman operating, one (0.25 net) horizontal well was turned to sales. In total there are 15 wells producing 53.5 (9.4 net) Mmcf per day. There were 24 (6.2 net) wells waiting on pipeline and 12 (2.9 net) wells waiting on completion.

Midcontinent Division-

Range’s Midcontinent team is focused on the liquids-rich horizontal Mississippian play in northern Oklahoma. Results continue to improve with recent wells considerably better than our first 8 horizontal wells drilled. With the new processing facility commencing operation at the end of the quarter, four wells were turned to production with two of the wells not yet reaching their peak rates. The four wells have achieved combined peak rates to date of 2,848 (2,001 net) boe per day (1,277 barrels oil, 918 barrels NGLs and 3,917 mcf gas). Of these, the Balder #1-30N was our first well to test in excess of 1,000 barrels of oil equivalent per day. It produced at a peak 24-hour production rate of 1,363 (941 net) barrels of oil equivalent per day (782 barrels oil, 340 barrels NGLs and 1,448 mcf gas). Its peak 30-day average daily production rate was 1,258 (871 net) barrels of oil equivalent per day (665 barrels oil, 346 barrels NGLs and 1,478 mcf gas). The lateral length on this well reached a total of 3,911 feet with a 19 stage frac. This well is one of several recent tests to extend Range’s previous lateral lengths from 2,000 feet plus to a 4,000 foot target. Range has an 86.3% working interest in this well.

Range now has 152,000 net acres in the horizontal Mississippian play. Early performance on wells in the 2012 drilling program with a longer lateral length indicates that the EUR’s will exceed the reserves assigned to wells drilled in 2009 to 2011, and expects reserves to be in the 600 Mboe range. We are continuing to prepare field infrastructure in anticipation of ramping up activity in the second half of 2012 and into 2013.

Drilling also continues in the Texas Panhandle with one active rig. Two St. Louis wells were turned to sales in the quarter at combined gross rates of 27.8 (11.9 net) Mmcfe per day (18.9 Mmcf gas, 643 barrels of oil and 835 barrels of NGLs per day).

Permian Division-

In the Cline shale and Wolfberry plays, Range has 100,000 net acres, with approximately 91% held by production from our Conger field. Range has drilled an additional Wolfberry well which is currently being completed. We are also drilling our third Cline shale horizontal. The average estimated ultimate recovery for the first two Cline Shale wells is projected to be 340 Mboe per well and for the first Wolfberry well is projected to be 216 Mboe. Plans for the remainder of the year are to drill four Wolfberry wells and one additional Cline well.

Southern Appalachia Division-

The Southern Appalachia Division continued development of multi-pay horizons on its 350,000 (235,000 net) acre position in Virginia during the second quarter of 2012. The division had two drilling rigs running in the quarter and drilled 22 gross (19.5 net) wells including 13 (13 net) tight-gas sand, 4 (1.5 net) CBM and 5 (5 net) horizontal Huron shale wells. The five Huron wells on average were drilled in the fewest number of days and achieved the longest completed lateral length to date at over 3,600 ft. Three of the Huron wells have been brought online with early production results above expectations.

Guidance – Third Quarter 2012

Production per day Guidance

  Natural gas production:   618 - 620 Mmcf per day
NGL production: 18,300 - 18,600 bbls per day
Oil production: 7,600 - 7,800 bbls per day
Equivalent production: 773 - 778 Mmcfe per day

Total production growth for 2012 is now targeted at 35% year over year, or the high end of our previous full-year guidance. However, in the Marcellus where significant production is scheduled to be placed on line, placing five to eight wells per drilling pad could bring 25 Mmcfe per day to 80 Mmcfe per day on at one time assuming no infrastructure constraints. Therefore, third quarter production could vary by the timing of when each pad of wells are actually placed on production. Any variation in production from guidance is expected to be made up by the production in the fourth quarter to achieve the total year over year production guidance target.

Expense per mcfe Guidance

  Direct operating expense:   $0.42-$0.44 per mcfe
Transportation, gathering and compression expense (a): $0.63-$0.65 per mcfe
Production tax expense (b): $0.19 per mcfe
Exploration expense: $20 million
Unproved property impairment expense: $20-$22 million
G&A expense: $0.46-$0.47 per mcfe
Interest expense: $0.60 per mcfe
DD&A expense: $1.66-$1.68 per mcfe
(a)   Prior to year-end 2011 this expense was netted against revenue. Please refer to Table 6 of the 2Q 2012 Supplement Tables for historical detail of this expense by product.
(b) Production tax expense in third quarter should equal approximately $0.10/mcfe plus an estimated $6 million for the Pennsylvania impact fee. Total production tax expense including the impact fee is expected to be $0.19/mcfe.

Differential Pricing History (c)

    2Q 2011   3Q 2011   4Q 2011   1Q 2012   2Q 2012
Natural Gas $0.16 $0.26 $0.07 ($0.02) ($0.13)
NGL (% of WTI NYMEX) 50% 54% 54% 48% 39%
Oil (% of WTI NYMEX) 90% 91% 92% 88% 91%
(c)   Differentials based on pre-hedge pricing, excluding transportation, gathering and compression expense.

Conference Call Information

The Company will host a conference call on Wednesday, July 25, 2012 at 1:00 pm ET to review the second quarter results. To participate in the call, please dial 877-407-0778 and ask for the Range Resources’ second quarter earnings conference call. A replay of the call will be available through August 31, 2012. To access the phone replay dial 877-660-6853. The account number is 286 and the conference ID for the replay is 397444. Additional financial and statistical information about the period not included in this release but discussed on the conference call will be available on our home page at www.rangeresources.com.

A simultaneous webcast of the call may be accessed over the Internet at www.rangeresources.com or www.vcall.com. To listen, please go to either website in time to register and install any necessary software. The webcast will be archived for replay on the Company’s website until August 31, 2012.

Non-GAAP Financial Measures and Supplemental Tables

Adjusted net income comparable to analysts’ estimates as used in this release represents income from continuing operations before income taxes adjusted for certain 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. Adjusted diluted earnings per share as set forth in this release represents adjusted net income comparable to analysts’ estimates on a diluted per share basis. A table is included which reconciles income or loss from continuing operations to adjusted net income comparable to analysts’ estimates and adjusted diluted earnings per share. On its website, the Company provides additional comparative information on prior periods.

Second quarter 2012 earnings included a gain of $136 million for the non-cash unrealized mark-to-market increase in value of the Company’s derivatives and expenses associated with the mark-to-market in the deferred compensation plan for the increase in the Company’s common stock during the period of $9.3 million, non-cash stock compensation expense of $14.6 million, an unproved property impairment expense of $44 million and $3.2 million of loss on sale of properties. Excluding these items, net income would have been $18.1 million or $0.11 per diluted share. Excluding similar non-cash items from the prior-year quarter, net income would have been $43.2 million or $0.27 per diluted share. By excluding these non-cash items from our reported earnings, we believe we present our earnings in a manner consistent with the presentation used by analysts in their projection of the Company’s earnings. (See the reconciliation of non-GAAP earnings in the accompanying table.)

“Cash flow from operations before changes in working capital” as used in this release represents net cash provided by operations before changes in working capital and exploration expense adjusted for certain non-cash compensation items. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company’s ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered as an alternative to “Cash flows from 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 for cash flow, cash margins and non-GAAP earnings as used in this release.

The cash prices realized for natural gas, NGLs and oil 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 and transportation, gathering and compression costs, such information is now reported in various lines of the Statements of Operations. The Company believes that it is important to furnish a table reflecting the details of the various components of each line in the Statements of Operations to better inform the reader of the details of each amount and provide a summary of the realized cash-settled amounts which historically were reported as natural gas, NGLs and oil sales. This information will serve to bridge the gap between various readers’ understanding and fully disclose the information needed.

The Company discloses in this release the detailed components of many of the single line items shown in the GAAP financial statements included in the Company’s Quarterly Report on Form 10-Q. The Company believes that it is important to furnish this detail of the various components comprising each line of the Statements of Operations to better inform the reader of the details of each amount, the changes between periods and the effect on its financial results.

Hedging and Derivatives

In this release, Range has reclassified within total revenues its reporting of the cash settlement of its commodity derivatives. Under this presentation those hedges considered “effective” under ASC 815 are included in “Natural gas, NGLs and oil sales” when settled. For those hedges designated to regions where the historical correlation between NYMEX and regional prices is “non-highly effective” or there is “volumetric ineffectiveness” due to the sale of the underlying reserves, they are deemed to be “derivatives” and the cash settlements are included in a separate line item shown as “Derivative fair value income” in the Form 10-Q along with the change in mark-to-market valuations of such unrealized derivatives. The Company has provided additional information regarding natural gas, NGLs and oil sales in a supplemental table included with this release which would correspond to amounts shown by analysts for natural gas, NGLs and oil sales realized, including all cash-settled derivatives.

RANGE RESOURCES CORPORATION (NYSE: RRC) is a leading independent oil and natural gas producer with operations focused in Appalachia and the southwest region of the United States. The Company pursues an organic growth strategy targeting high return, low-cost projects within its large inventory of low risk, development drilling opportunities. The Company is headquartered in Fort Worth, Texas. More information about Range can be found at http://www.rangeresources.com/ and http://www.myrangeresources.com/.

Except for historical information, statements made in this release such as excellent drilling results, strong hedge position, add material per share value, increased drilling efficiencies, reduced drilling costs, increase recoveries and improve out rates of return, high return projects, financial strength, future liquidity, expected number of rigs, and generates attractive returns 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 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.

Estimated ultimate recovery, or “EUR,” refers to our management’s internal estimates of per well hydrocarbon quantities that may be potentially recovered from a hypothetical future well completed as a producer in the area. These quantities do not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules. Our management estimated these ultimate recoveries based on our previous operating experience in the given area and publicly available information relating to the operations of producers who are conducting operating in these areas. Actual quantities that may be ultimately recovered from Range's interests may 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 ultimate recoveries may change significantly as development of our resource plays provides additional data. In addition, our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.

Further information on risks and uncertainties is available in Range’s filings with the Securities and Exchange Commission (“SEC”), which are incorporated by reference. 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.

 
 

RANGE RESOURCES CORPORATION

 
STATEMENTS OF OPERATIONS                
Based on GAAP reported earnings with additional
details of items included in each line in Form 10-Q
(Unaudited, in thousands, except per share data) Three Months Ended June 30, Six Months Ended June 30,
  2012     2011     2012     2011  
Revenues and other income:
Natural gas, NGLs and oil sales (a) $ 298,349 $ 285,353 $ 615,966 $ 537,316
Derivative cash settlements gain (loss) (a) (b) 12,198 (1,034 ) 4,369 (2,400 )
Change in mark-to-market on unrealized derivatives gain (loss) (b) 135,777 48,139 83,721 8,103
Ineffective hedging (loss) gain (b) 594 5,934 (354 ) 6,502
(Loss) gain on sale of properties (3,227 ) (1,622 ) (13,653 ) (1,483 )
Equity method investment (c) 501 (1,021 ) 817 (759 )
Transportation and gathering (c) (677 ) (699 ) (1,011 ) 4
Transportation and gathering – non-cash stock -based compensation (c) (d) (408 ) (342 ) (861 ) (732 )
Other (c)   (667 )   587     339     1,402  
Total revenues and other income   442,440     335,295   32 %   689,333     547,953   26 %
Costs and expenses:
Direct operating 26,349 27,866 55,014 56,273
Direct operating – non-cash stock compensation (d) 692 643 1,049 953
Transportation, gathering and compression 44,744 28,666 85,564 53,748
Production and ad valorem taxes 11,079 7,550 23,713 14,429
Pennsylvania impact fee - prior year 707 - 24,707 -
Exploration 14,523 10,655 35,111 36,513
Exploration – non-cash stock compensation (d) 994 937 1,922 2,266
Abandonment and impairment of unproved properties 43,641 18,900 63,930 35,437
General and administrative 30,565 27,299 60,620 54,416
General and administrative – non-cash stock compensation (d) 12,540 11,467 20,698 18,997
General and administrative – lawsuit settlements 900 70 1,416 70
General and administrative – bad debt expense - 284 - (404 )
Deferred compensation plan (e) 9,333 (5,778 ) 1,503 24,852
Interest expense 42,888 31,383 80,093 56,162
Loss on early extinguishment of debt - 18,580 - 18,580
Depletion, depreciation and amortization   108,802     78,294     208,953     150,510  
Total costs and expenses   347,757     256,816   35 %   664,293     522,802   27 %
 
Income from continuing operations before income taxes 94,683 78,479 21 % 25,040 25,151

0

%
 
Income tax expense:
Current - 8 - 8
Deferred   39,007     32,695     11,164     12,798  
  39,007     32,703     11,164     12,806  
 
Income from continuing operations 55,676 45,776 22 % 13,876 12,345 12 %
 
Discontinued operations, net of tax   -     5,517     -     13,915  
 
Net income $ 55,676   $ 51,293   9 % $ 13,876   $ 26,260   -47 %
 
Income Per Common Share:
 
Basic-Income from continuing operations $ 0.34 $ 0.28 $ 0.09 $ 0.08
Discontinued operations   -     0.04     -     0.08  
Net income $ 0.34   $ 0.32   6 % $ 0.09   $ 0.16   -44 %
 
Diluted-Income from continuing operations $ 0.34 $ 0.28 $ 0.09 $ 0.08
Discontinued operations   -     0.04     -     0.08  
Net income $ 0.34   $ 0.32   6 % $ 0.09   $ 0.16   -44 %
 
Weighted average common shares outstanding, as reported:
Basic 159,412 157,997 1 % 159,162 157,772 1 %
Diluted 160,030 158,833 1 % 159,949 158,729 1 %
(a)   See separate natural gas, NGLs and oil sales information table.
(b) Included in Derivative fair value loss in the Form 10-Q.
(c) Included in Other revenues in the Form 10-Q.
(d)

Costs associated with stock compensation and restricted stock amortization, which have been reflected in the categories associated with the direct personnel costs, which are combined with the cash costs in the Form 10-Q.

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

RANGE RESOURCES CORPORATION

 
STATEMENTS OF OPERATIONS                
Restated for Barnett discontinued operations,
a non-GAAP presentation Three Months Ended June 30, 2012 Three Months Ended June 30, 2011
(Unaudited, in thousands, except per share data)

As
reported

 

Barnett
Discontinued
Operations

 

Including
Barnett
Ops

As
reported

 

Barnett
Discontinued
Operations

 

Including
Barnett
Ops

Revenues and other income:
Natural gas, NGLs and oil sales $ 298,349 - $ 298,349 $ 285,353 $ 12,751 $ 298,104
Derivative cash settlements gain (loss) 12,198 - 12,198 (1,034 ) - (1,034 )

Change in mark-to-market on unrealized derivatives gain (loss)

135,777 - 135,777 48,139 - 48,139
Ineffective hedging gain (loss) 594 - 594 5,934 - 5,934
(Loss) gain on sale of properties (3,227 ) - (3,227 ) (1,622 ) 3,820 2,198
Equity method investment 501 - 501 (1,021 ) - (1,021 )
Transportation and gathering (677 ) - (677 ) (699 ) 1 (698 )

Transportation and gathering – non-cash stock-based compensation

(408 ) - (408 ) (342 ) - (342 )
Other   (667 )   -     (667 )   587       -       587  
  442,440     -     442,440     335,295       16,572       351,867  
Costs and expenses:
Direct operating 26,349 - 26,349 27,866 2,169 30,035
Direct operating – non-cash stock-based compensation 692 - 692 643 - 643
Transportation, gathering and compression 44,744 - 44,744 28,666 1,974 30,640
Production and ad valorem taxes 11,079 - 11,079 7,550 184 7,734
Pennsylvania impact fee – prior year 707 - 707 - - -
Exploration 14,523 - 14,523 10,655 5 10,660
Exploration – non-cash stock-based compensation 994 - 994 937 - 937
Abandonment and impairment of unproved properties 43,641 - 43,641 18,900 - 18,900
General and administrative 30,565 - 30,565 27,299 - 27,299

General and administrative – non-cash stock-based compensation

12,540 - 12,540 11,467 - 11,467
General and administrative – lawsuit settlements 900 - 900 70 - 70
General and administrative – bad debt expense - - - 284 - 284
Deferred compensation plan 9,333 - 9,333 (5,778 ) - (5,778 )
Interest expense 42,888 - 42,888 31,383 3,715 35,098
Loss on early extinguishment of debt - - - 18,580 - 18,580
Depletion, depreciation and amortization   108,802     -     108,802     78,294       14       78,308  
  347,757     -     347,757     256,816       8,061       264,877  
 
Income from continuing operations before income taxes 94,683 - 94,683 78,479 8,511 86,990
 
Income tax expense:
Current - - - 8 - 8
Deferred   39,007     -     39,007     32,695       2,994       35,689  
  39,007     -     39,007     32,703       2,994       35,697  
 
Income from continuing operations 55,676 - 55,676 45,776 5,517 51,293
Discontinued operations-Barnett Shale, net of tax   -     -     -     5,517       (5,517 )     -  
Net income $ 55,676     -   $ 55,676   $ 51,293       -     $ 51,293  
 
OPERATING HIGHLIGHTS
 
Average daily production:
Natural gas (mcf) 574,651 - 574,651 360,566 28,120 388,686
NGLs (bbl) 17,259 - 17,259 13,588 756 14,344
Oil (bbl) 6,846 - 6,846 5,527 18 5,545
Gas equivalents (mcfe) 719,285 - 719,285 475,256 32,762 508,018
 
Average prices realized before transportation, gathering and compression:
Natural gas (mcf) $ 3.66 - $ 3.66 $ 5.47 $ 3.84 $ 5.35
NGLs (bbl) $ 42.30 - $ 42.30 $ 52.06 $ 40.15 $ 51.44
Oil (bbl) $ 84.31 - $ 84.31 $ 80.34 $ 102.88 $ 80.42
Gas equivalents (mcfe) $ 4.74 - $ 4.74 $ 6.57 $ 4.28 $ 6.43
 
Direct operating cash costs per mcfe:
Field expenses $ 0.39 - $ 0.39 $ 0.63 $ 0.71 $ 0.64
Workovers   0.01     -     0.01     0.01       0.02       0.01  
Total operating costs $ 0.40     -   $ 0.40   $ 0.64     $ 0.73     $ 0.65  
 
Transportation, gathering and compression cost per mcfe: $ 0.68     -   $ 0.68   $ 0.66     $ 0.66     $ 0.66  
 
 

RANGE RESOURCES CORPORATION

 
STATEMENTS OF OPERATIONS                
Restated for Barnett discontinued operations,
a non-GAAP presentation Six Months Ended June 30, 2012 Six Months Ended June 30, 2011
(Unaudited, in thousands, except per share data)

As
reported

 

Barnett
Discontinued
Operations

 

Including
Barnett
Ops

As
reported

 

Barnett
Discontinued
Operations

 

Including
Barnett
Ops

Revenues and other income:
Natural gas, NGLs and oil sales $ 615,966 - $ 615,966 $ 537,316 $ 57,324 $ 594,640
Derivative cash settlements gain (loss) 4,369 - 4,369 (2,400 ) - (2,400 )

Change in mark-to-market on unrealized derivatives gain (loss)

83,721 - 83,721 8,103 - 8,103
Ineffective hedging gain (loss) (354 ) - (354 ) 6,502 - 6,502
(Loss) gain on sale of properties (13,653 ) - (13,653 ) (1,483 ) 3,820 2,337
Equity method investment 817 - 817 (759 ) - (759 )
Transportation and gathering (1,011 ) - (1,011 ) 4 6 10

Transportation and gathering – non-cash stock-based compensation

(861 ) - (861 ) (732 ) - (732 )
Other   339     -     339     1,402       4       1,406  
  689,333     -     689,333     547,953       61,154       609,107  
Costs and expenses:
Direct operating 55,014 - 55,014 56,273 10,401 66,674
Direct operating – non-cash stock-based compensation 1,049 - 1,049 953 45 998
Transportation, gathering and compression 85,564 - 85,564 53,748 4,290 58,038
Production and ad valorem taxes 23,713 - 23,713 14,429 1,250 15,679
Pennsylvania impact fee – prior year 24,707 - 24,707 - - -
Exploration 35,111 - 35,111 36,513 37 36,550
Exploration – non-cash stock-based compensation 1,922 - 1,922 2,266 - 2,266
Abandonment and impairment of unproved properties 63,930 - 63,930 35,437 - 35,437
General and administrative 60,620 - 60,620 54,416 - 54,416

General and administrative – non-cash stock-based compensation

20,698 - 20,698 18,997 - 18,997
General and administrative – lawsuit settlements 1,416 - 1,416 70 - 70
General and administrative – bad debt expense - - - (404 ) - (404 )
Deferred compensation plan 1,503 - 1,503 24,852 - 24,852
Interest expense 80,093 - 80,093 56,162 14,791 70,953
Loss on early extinguishment of debt - - - 18,580 - 18,580
Depletion, depreciation and amortization   208,953     -     208,953     150,510       8,894       159,404  
  664,293     -     664,293     522,802       39,708       562,510  
 
Income from continuing operations before income taxes 25,040 - 25,040 25,151 21,446 46,597
 
Income tax expense:
Current - - - 8 - 8
Deferred   11,164     -     11,164     12,798       7,531       20,329  
  11,164     -     11,164     12,806       7,531       20,337  
 
Income from continuing operations 13,876 - 13,876 12,345 13,915 26,260
Discontinued operations-Barnett Shale, net of tax   -     -     -     13,915       (13,915 )     -  
Net income $ 13,876     -   $ 13,876   $ 26,260       -     $ 26,260  
 
OPERATING HIGHLIGHTS
 
Average daily production:
Natural gas (mcf) 543,552 - 543,552 345,950 63,229 409,179
NGLs (bbl) 17,206 - 17,206 13,083 1,257 14,341
Oil (bbl) 6,764 - 6,764 5,188 48 5,236
Gas equivalents (mcfe) 687,371 - 687,371 455,580 71,060 526,640
 
Average prices realized before transportation, gathering and compression:
Natural gas (mcf) $ 3.83 - $ 3.83 $ 5.44 $ 4.05 $ 5.22
NGLs (bbl) $ 44.24 - $ 44.24 $ 50.43 $ 44.69 $ 49.93
Oil (bbl) $ 83.93 - $ 83.93 $ 79.86 $ 92.36 $ 79.98
Gas equivalents (mcfe) $ 4.96 - $ 4.96 $ 6.49 $ 4.46 $ 6.21
 
Direct operating cash costs per mcfe:
Field expenses $ 0.42 - $ 0.42 $ 0.67 $ 0.79 $ 0.69
Workovers   0.02     -     0.02     0.01       0.02       0.01  
Total operating costs $ 0.44     -   $ 0.44   $ 0.68     $ 0.81     $ 0.70  
 
Transportation, gathering and compression cost per mcfe: $ 0.68     -   $ 0.68   $ 0.65     $ 0.33     $ 0.61  
 
 

RANGE RESOURCES CORPORATION

 
BALANCE SHEETS      

(In thousands)

June 30, December 31,
  2012     2011  
(Unaudited) (Audited)
Assets
Current assets $ 121,107 $ 141,342
Current unrealized derivative gain 251,236 173,921
Natural gas and oil properties 5,771,040 5,157,566
Transportation and field assets 46,618 52,678
Other   353,893     319,963  
$ 6,543,894   $ 5,845,470  
 
Liabilities and Stockholders’ Equity
Current liabilities $ 532,212 $ 506,274
Current asset retirement obligation 5,005 5,005
Current unrealized derivative loss 3,283 -
Current liabilities of discontinued operations - 653
 
Bank debt 235,000 187,000
Subordinated notes   2,388,562     1,787,967  
Total long-term debt   2,623,562     1,974,967  
 
Deferred tax liability 698,429 710,490
Unrealized derivative loss 2,405 173
Deferred compensation liability 170,763 169,188
Long-term asset retirement obligation and other 91,514 86,300
 
Common stock and retained earnings 2,265,338 2,242,136
Treasury stock (5,655 ) (6,343 )
Accumulated other comprehensive income   157,038     156,627  
Total stockholders’ equity   2,416,721     2,392,420  
$ 6,543,894   $ 5,845,470  
 
 

RANGE RESOURCES CORPORATION

 
CASH FLOWS FROM OPERATING ACTIVITIES          
(Unaudited, in thousands) Three Months Ended Six Months Ended
June 30, June 30,
  2012       2011     2012     2011  
 
Net income $ 55,676 $ 51,293 $ 13,876 $ 26,260
Adjustments to reconcile net income to net cash provided from operating activities:
(Income) loss discontinued operations - (5,517 ) - (13,915 )
(Gain) loss from equity investment, net of distributions 2,042 2,397 2,293 15,102
Deferred income tax expense 39,007 32,695 11,164 12,798
Depletion, depreciation, amortization and proved property impairment 108,802 78,294 208,953 150,510
Exploration dry hole costs 108 (4 ) 817 6
Abandonment and impairment of unproved properties 43,641 18,900 63,930 35,437
Mark-to-market (gain) loss on oil and gas derivatives not designated as hedges (135,777 ) (48,139 ) (83,721 ) (8,103 )
Unrealized derivatives (gain) loss (594 ) (5,934 ) 354 (6,502 )
Allowance for bad debts - 284 - (404 )
Amortization of deferred financing costs, loss on extinguishment of debt, and other 2,045 21,756 3,893 21,678
Deferred and stock-based compensation 23,833 7,511 26,341 48,161
(Gain) loss on sale of assets and other 3,227 1,622 13,653 1,483
 
Changes in working capital:
Accounts receivable (336 ) 529 11,611 (9,999 )
Inventory and other (1,927 ) (805 ) (2,824 ) 2,769
Accounts payable (30,884 ) 2,713 (21,922 ) 5,015
Accrued liabilities and other   18,106     9,146     34,528     7,655  
Net changes in working capital   (15,041 )   11,583     21,393     5,440  
Net cash provided from continuing operations 126,969 166,741 282,946 287,951
Net cash provided from discontinued operations   -     2,142     -     21,554  
Net cash provided from operating activities $ 126,969   $ 168,883   $ 282,946   $ 309,505  
 
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,
  2012     2011     2012     2011  
 
Net cash provided from operating activities, as reported $ 126,969 $ 168,883 $ 282,946 $ 309,505
Net changes in working capital from continuing operations 15,041 (11,583 ) (21,393 ) (5,440 )
Exploration expense 14,415 10,659 34,294 36,507
Lawsuit settlements 900 70 1,416 70
Equity method investment distribution / intercompany elimination (2,544 ) (1,377 ) (3,110 ) (14,344 )
Prior year Pennsylvania impact fee 707 - 24,707 -
Non-cash compensation adjustment 245 (1,258 ) (143 ) 63
Net changes in working capital from discontinued operations and other   -     2,568     -     5,048  
Cash flow from operations before changes in working capital, a non-GAAP measure $ 155,733   $ 167,962   $ 318,717   $ 331,409  
 
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING
(Unaudited, in thousands) Three Months Ended Six Months Ended
June 30, June 30,
  2012     2011     2012     2011  
Basic:
Weighted average shares outstanding 162,325 160,836 162,031 160,638
Stock held by deferred compensation plan   (2,913 )   (2,839 )   (2,869 )   (2,866 )
Adjusted basic   159,412     157,997     159,162     157,772  
 
Dilutive:
Weighted average shares outstanding 162,325 160,836 162,031 160,638
Anti-dilutive or dilutive stock options under treasury method   (2,295 )   (2,003 )   (2,082 )   (1,909 )
Adjusted dilutive   160,030     158,833     159,949     158,729  
 
 

RANGE RESOURCES CORPORATION

 
RECONCILIATION OF NATURAL GAS, NGLs AND OIL SALES AND DERIVATIVE FAIR VALUE INCOME (LOSS) TO CALCULATED CASH REALIZED NATURAL GAS, NGLs AND OIL PRICES WITH AND WITHOUT THIRD PARTY TRANSPORTATION, GATHERING AND COMPRESSION FEES        
non-GAAP measures
As Reported, GAAP Non-GAAP
Excludes Barnett Operations Includes Barnett Operations
(Unaudited, in thousands, except per unit data) Three Months Ended June 30, Three Months Ended June 30,
  2012       2011     %   2012       2011     %
Natural gas, NGLs and oil sales components:    
Natural gas sales $ 111,413 $ 150,188 $ 111,413 $ 160,010
NGLs sales 56,280 64,376 56,280 67,137
Oil sales 52,075 46,504 52,075 46,672
 
Cash-settled hedges (effective):
Natural gas 78,896 24,285 78,896 24,285
Crude oil   (315 )   -     (315 )   -  
Total natural gas, NGLs and oil sales, as reported $ 298,349   $ 285,353   5 % $ 298,349   $ 298,104   0 %
 
Derivative fair value income (loss) components:
Cash-settled derivatives (ineffective):
Natural gas $ 1,278 $ 5,060 $ 1,278 $ 5,060
NGLs 10,152 - 10,152 -
Crude Oil 768 (6,094 ) 768 (6,094 )
Change in mark-to-market on unrealized derivatives 135,777 48,139 135,777 48,139
Unrealized ineffectiveness   594     5,934     594     5,934  
Total derivative fair value income (loss), as reported $ 148,569   $ 53,039   $ 148,569   $ 53,039  
 
Natural gas, NGLs and oil sales, including all cash-settled derivatives (c):
Natural gas sales $ 191,587 $ 179,533 $ 191,587 $ 189,355
NGLs sales 66,432 64,376 66,432 67,137
Oil sales   52,528     40,410     52,528     40,578  
Total $ 310,547   $ 284,319   9 % $ 310,547   $ 297,070   5 %
 
Third party transportation, gathering and compression fee components:
Natural gas $ 42,168 $ 26,888 $ 42,168 $ 28,862
NGLs   2,576     1,778     2,576     1,778  
Total transportation, gathering and compression, as reported $ 44,744   $ 28,666   $ 44,744   $ 30,640  
 
Production during the period (a):
Natural gas (mcf) 52,293,227 32,811,471 59 % 52,293,227 35,370,403 48 %
NGLs (bbl) 1,570,593 1,236,502 27 % 1,570,593 1,305,263 20 %
Oil (bbl) 623,026 502,962 24 % 623,026 504,604 23 %
Gas equivalent (mcfe) (b) 65,454,941 43,248,255 51 % 65,454,941 46,229,606 42 %
 
Production – average per day (a):
Natural gas (mcf) 574,651 360,566 59 % 574,651 388,686 48 %
NGLs (bbl) 17,259 13,588 27 % 17,259 14,344 20 %
Oil (bbl) 6,846 5,527 24 % 6,846 5,545 23 %
Gas equivalent (mcfe) (b) 719,285 475,256 51 % 719,285 508,018 42 %
 
Average prices, including cash-settled hedges and derivatives before third party transportation costs (c):
Natural gas (mcf) $ 3.66 $ 5.47 -33 % $ 3.66 $ 5.35 -32 %
NGLs (bbl) $ 42.30 $ 52.06 -19 % $ 42.30 $ 51.44 -18 %
Oil (bbl) $ 84.31 $ 80.34 5 % $ 84.31 $ 80.42 5 %
Gas equivalent (mcfe) (b) $ 4.74 $ 6.57 -28 % $ 4.74 $ 6.43 -26 %
 
Average prices, including cash-settled hedges and derivatives (d):
Natural gas (mcf) $ 2.86 $ 4.65 -39 % $ 2.86 $ 4.54 -37 %
NGLs (bbl) $ 40.66 $ 50.62 -20 % $ 40.66 $ 50.07 -19 %
Oil (bbl) $ 84.31 $ 80.34 5 % $ 84.31 $ 80.42 5 %
Gas equivalent (mcfe) (b) $ 4.06 $ 5.91 -31 % $ 4.06 $ 5.76 -30 %
(a)   Represents volumes sold regardless of when produced.
(b) Oil and NGLs are converted to mcfe at a rate of one barrel equals six mcf based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.
(c) Excluding third party transportation, gathering and compression costs.
(d) Net of transportation, gathering and compression costs.
 
 

RANGE RESOURCES CORPORATION

 
RECONCILIATION OF NATURAL GAS, NGLs AND OIL SALES AND DERIVATIVE FAIR VALUE INCOME (LOSS) TO CALCULATED CASH REALIZED NATURAL GAS, NGLs AND OIL PRICES WITH AND WITHOUT THIRD PARTY TRANSPORTATION, GATHERING AND COMPRESSION FEES        
non-GAAP measures
As Reported, GAAP Non-GAAP
Excludes Barnett Operations Includes Barnett Operations
(Unaudited, in thousands, except per unit data) Six Months Ended June 30, Six Months Ended June 30,
  2012       2011     %   2012       2011     %
Natural gas, NGLs and oil sales components:    
Natural gas sales $ 239,481 $ 280,983 $ 239,481 $ 318,733
NGLs sales 132,778 119,421 132,778 129,591
Oil sales 107,497 83,011 107,497 83,808
 
Cash-settled hedges (effective):
Natural gas 136,525 53,901 136,525 62,508
Crude oil   (315 )   -     (315 )   -  
Total natural gas, NGLs and oil sales, as reported $ 615,966   $ 537,316   15 % $ 615,966   $ 594,640   4 %
 
Derivative fair value income (loss) components:
Cash-settled derivatives (ineffective):
Natural gas $ 2,463 $ 5,612 $ 2,463 $ 5,612
NGLs 5,760 - 5,760 -
Crude Oil (3,854 ) (8,012 ) (3,854 ) (8,012 )
Change in mark-to-market on unrealized derivatives 83,721 8,103 83,721 8,103
Unrealized ineffectiveness   (354 )   6,502     (354 )   6,502  
Total derivative fair value income (loss), as reported $ 87,736   $ 12,205   $ 87,736   $ 12,205  
 
Natural gas, NGLs and oil sales, including all cash-settled derivatives (c):
Natural gas sales $ 378,469 $ 340,496 $ 378,469 $ 386,853
NGLs sales 138,538 119,421 138,538 129,591
Oil sales   103,328     74,999     103,328     75,796  
Total $ 620,335   $ 534,916   16 % $ 620,335   $ 592,240   5 %
 
Third party transportation, gathering and compression fee components:
Natural gas $ 80,674 $ 51,400 $ 80,674 $ 55,690
NGLs   4,890     2,348     4,890     2,348  
Total transportation, gathering and compression, as reported $ 85,564   $ 53,748   $ 85,564   $ 58,038  
 
Production during the period (a):
Natural gas (mcf) 98,926,434 62,616,994 58 % 98,926,434 74,061,424 34 %
NGLs (bbl) 3,131,419 2,368,068 32 % 3,131,419 2,595,671 21 %
Oil (bbl) 1,231,103 939,094 31 % 1,231,103 947,724 30 %
Gas equivalent (mcfe) (b) 125,101,566 82,459,960 52 % 125,101,566 95,321,795 31 %
 
Production – average per day (a):
Natural gas (mcf) 543,552 345,950 57 % 543,552 409,179 33 %
NGLs (bbl) 17,206 13,083 32 % 17,206 14,341 20 %
Oil (bbl) 6,764 5,188 30 % 6,764 5,236 29 %
Gas equivalent (mcfe) (b) 687,371 455,580 51 % 687,371 526,640 31 %
 
Average prices, including cash-settled hedges and derivatives before third party transportation costs (c):
Natural gas (mcf) $ 3.83 $ 5.44 -30 % $ 3.83 $ 5.22 -27 %
NGLs (bbl) $ 44.24 $ 50.43 -12 % $ 44.24 $ 49.93 -11 %
Oil (bbl) $ 83.93 $ 79.86 5 % $ 83.93 $ 79.98 5 %
Gas equivalent (mcfe) (b) $ 4.96 $ 6.49 -24 % $ 4.96 $ 6.21 -20 %
 
Average prices, including cash-settled hedges and derivatives (d):
Natural gas (mcf) $ 3.01 $ 4.62 -35 % $ 3.01 $ 4.47 -33 %
NGLs (bbl) $ 42.68 $ 49.44 -14 % $ 42.68 $ 49.02 -13 %
Oil (bbl) $ 83.93 $ 79.86 5 % $ 83.93 $ 79.98 5 %
Gas equivalent (mcfe) (b) $ 4.27 $ 5.84 -27 % $ 4.27 $ 5.60 -24 %
(a)   Represents volumes sold regardless of when produced.
(b) Oil and NGLs are converted to mcfe at a rate of one barrel equals six mcf based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.
(c) Excluding third party transportation, gathering and compression costs.
(d) Net of transportation, gathering and compression costs.
 
 

RANGE RESOURCES CORPORATION

 

RECONCILIATION OF INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AS REPORTED TO INCOME FROM OPERATIONS BEFORE INCOME TAXES

EXCLUDING CERTAIN ITEMS, a non-GAAP measure

           

(Unaudited, in thousands, except per share data)

Three Months Ended June 30, Six Months Ended June 30,
  2012       2011     %   2012     2011     %
 

Income from continuing operations before income taxes, as reported

$ 94,683 $ 78,479 21 % $ 25,040 $ 25,151

0

%
Adjustment for certain items:
(Gain) loss on sale of properties 3,227 1,622 13,653 1,483
Barnett discontinued operations less gain on sale - 4,691 - 17,626
Change in mark-to-market on unrealized derivatives (gain) loss (135,777 ) (48,139 ) (83,721 ) (8,103 )
Unrealized derivative (gain) loss (594 ) (5,934 ) 354 (6,502 )
Abandonment and impairment of unproved properties 43,641 18,900 63,930 35,437
Prior year Pennsylvania impact fee 707 - 24,707 -
Lawsuit settlements 900 - 1,416 70
Transportation and gathering – non-cash stock-based compensation 408 342 861 732
Direct operating – non-cash stock-based compensation 692 643 1,049 953
Exploration expenses – non-cash stock-based compensation 994 937 1,922 2,266
General & administrative – non-cash stock-based compensation 12,540 11,467 20,698 18,997
Deferred compensation plan – non-cash adjustment   9,333     (5,778 )   1,503     24,852  
 
Income from operations before income taxes, as adjusted 30,754 57,230 -46 % 71,412 112,962 -37 %
 
Income tax expense, as adjusted
Current - 8 - 8
Deferred   12,668     13,985     28,912     34,495  
Net income excluding certain items, a non-GAAP measure $ 18,086   $ 43,237   -58 % $ 42,500   $ 78,459   -46 %
 
Non-GAAP income per common share

Basic

$ 0.11   $ 0.27   -59 % $ 0.27   $ 0.50   -46 %

Diluted

$ 0.11   $ 0.27   -59 % $ 0.27   $ 0.49   -45 %
 
Non-GAAP diluted shares outstanding, if dilutive   160,030     158,833     159,949     158,729  
 
 
HEDGING POSITION AS OF JULY 18, 2012
(Unaudited)
 
    Daily Volume     Hedge Price    

Premium (Paid) /
Received

Gas (Mmbtu)
2Q 2012 Swaps 213,297 $3.92 ($0.01)
2Q 2012 Collars 189,641 $5.32 – $5.91 ($0.28)
3Q 2012 Swaps 220,000 $3.73 ($0.02)
3Q 2012 Collars 279,641 $4.76 - $5.22 ($0.19)
4Q 2012 Swaps 270,000 $3.77 ($0.02)
4Q 2012 Collars 279,641 $4.76 - $5.22 ($0.19)
 
2013 Swaps 177,521 $3.57 --
2013 Collars 240,000 $4.73 - $5.20 --
 
2014 Collars 285,000 $3.74 - $4.47 --
 
Oil (Bbls)
2Q 2012 Calls 2,200 $85.00 $13.71
2Q 2012 Collars 4,500 $75.56 - $82.78 $10.18
3Q 2012 Calls 2,200 $85.00 $13.71
3Q 2012 Collars 4,500 $75.56 - $82.78 $9.30
4Q 2012 Calls 2,200 $85.00 $13.71
4Q 2012 Collars 4,500 $75.56 - $82.78 $8.56
 
2013 Swaps 4,756 $96.49 --
2013 Collars 3,000 $90.60 - $100.00 --
 
2014 Swaps 4,000 $94.56 --
2014 Collars 2,000 $85.55 - $100.00 --
 
C5 Natural Gasoline (Bbls)
2Q 2012 Swaps 10,681 $2.2923 --
3Q 2012 Swaps 6,500 $2.2923 --
4Q 2012 Swaps 6,500 $2.2923 --
 
2013 Swaps 6,500 $2.1343 --
 
C3 Propane (Bbls)
2Q 2012 Swaps 1,648 $1.1372 --
3Q 2012 Swaps 6,000 $1.2241 --
4Q 2012 Swaps 6,000 $1.2241 --
 
2013 Swaps 5,000 $0.9418 --

NOTE: SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS

Source: Range Resources Corporation

Range Resources Corporation
Main number: 817-870-2601
or
Investor Contacts:
Rodney Waller, 817-869-4258
Senior Vice President
or
David Amend, 817-869-4266
Investor Relations Manager
or
Laith Sando, 817-869-4267
Senior Financial Analyst
or
Media Contact:
Matt Pitzarella, 724-873-3224
Director of Corporate Communications
www.rangeresources.com


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