UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of report (Date of earliest event reported): October 25, 2012 (October 24, 2012)
RANGE RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)
| Delaware | 001-12209 | 34-1312571 | ||
| (State or other jurisdiction of incorporation) |
(Commission File Number) |
(IRS Employer Identification No.) | ||
| 100 Throckmorton, Suite 1200 Ft. Worth, Texas |
76102 | |||
| (Address of principal executive offices) | (Zip Code) | |||
Registrant’s telephone number, including area code: (817) 870-2601
(Former name or former address, if changed since last report): Not applicable
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligations of the registrant under any of the following provisions (see General Instruction A.2. below):
| ¨ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
| ¨ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
| ¨ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
| ¨ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
ITEM 2.02 Results of Operations and Financial Condition
On October 24, 2012 Range Resources Corporation issued a press release announcing its third quarter results. A copy of this press release is being furnished as an exhibit to this report on Form 8-K.
ITEM 9.01 Financial Statements and Exhibits
(d) Exhibits:
| 99.1 | Press Release dated October 24, 2012 |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| RANGE RESOURCES CORPORATION | ||
| By: | /s/ Roger S. Manny | |
| Roger S. Manny | ||
| Chief Financial Officer | ||
Date: October 25, 2012
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EXHIBIT INDEX
| Exhibit Number |
Description | |
| 99.1 | Press Release dated October 24, 2012 | |
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EXHIBIT 99.1
NEWS RELEASE
RANGE ANNOUNCES THIRD QUARTER 2012 RESULTS
FORT WORTH, TEXAS, OCTOBER 24, 2012…RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its third quarter 2012 results. Third quarter results were driven by record high production, which was 47% higher than the prior-year quarter, a 12% decrease in unit costs, offset by a 24% decline in commodity prices. Reported natural gas, NGL and oil revenues totaled $337 million, an 11% increase versus the prior year quarter. Net cash provided from operating activities including changes in working capital was $178 million, a 28% increase over the prior-year quarter. Reported net loss for the third quarter was $53.8 million ($0.34 loss per diluted share), versus net income of $34.8 million ($0.21 per diluted share) for the third quarter of 2011. Earnings in the current quarter included a $58.4 million non-cash derivative mark-to-market reduction in value as compared to a $55.0 million non-cash derivative mark-to-market increase in value in the prior-year quarter.
Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $32.0 million ($0.20 per diluted share) versus $44.7 million ($0.28 per diluted share) in the prior-year quarter. Cash flow from operations before changes in working capital, a non-GAAP measure, decreased less than 1% from the prior-year quarter to $189.2 million. Comparing these amounts to analysts’ average First Call consensus estimates, the Company’s earnings per share ($0.20 per diluted share) were three cents higher than the consensus of analysts’ estimates of $0.17 per diluted share. Cash flow per share ($1.18 per diluted share) for the quarter was also three cents higher than the consensus analysts’ estimates of $1.15 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, “We accomplished much in the third quarter. Our record 47% production increase coupled with the 12% reduction in unit costs reflects the high quality of our asset base and exceptional operational performance by the entire Range team. We continue to fine-tune our drilling and completion process in our core plays seeing improved well performance and greater capital efficiency. Of particular importance were two wells, each producing in excess of 1,000 barrels of liquids per day – one in the super-rich Marcellus and one in the Horizontal Mississippian oil play. Substantial progress was also made on the infrastructure and marketing front, as we executed a historical agreement to become the anchor shipper on the Mariner East project which will allow us to store and sell propane and ethane along the east coast and to the international markets. Our $190 million of non-core asset sales so far this year reflects our long-standing strategy of high grading our assets and protecting our financial position. With three quarters of the year behind us, 2012 is shaping up to being the “inflection point” year we had anticipated.”
Financial Discussion –
(Except for generally accepted accounting principles (“GAAP”) reported amounts, specific expense categories exclude non-cash impairments, unrealized mark-to-market on derivatives, non-cash stock compensation and other items shown separately on the attached tables. Effective with 2011 year-end reporting, the Company reclassified 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. We sold substantially all of our Barnett Shale properties in
April 2011. Under GAAP, activity in 2011 for our Barnett Shale properties was reclassified as “Discontinued operations.” As a result, production, revenue and expenses associated with these properties were removed from continuing operations and reclassified as discontinued operations. In this release, supplemental Statements of Operations are presented to reconcile the changes to the prior-year periods for the reclassification of our Barnett Shale properties to discontinued operations. These supplemental non-GAAP tables present the reported GAAP amounts and 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. )
For the third quarter, production averaged 790 Mmcfe per day, comprised of 623.3 Mmcf per day of natural gas (79%), 20,040 barrels per day of natural gas liquids (15%) and 7,748 barrels per day of oil (6%). Natural gas production grew 52%, NGL production increased 30% and crude oil production rose 36% over the prior-year quarter due to outstanding drilling results. Realized prices, including all cash-settled derivatives, averaged $4.88 per mcfe, a 24% decrease over the prior-year quarter of $6.41 and a 3% increase as compared to the second quarter 2012 of $4.74 per mcfe. The average realized natural gas price was $3.88 per mcf, 27% lower than the prior-year quarter. NGL prices decreased 24% to $38.79 per barrel versus the prior-year quarter, while the average oil price rose 4% to $84.86 per barrel.
Reported natural gas, NGL and oil sale revenues for the quarter were $337 million, an increase of 11% as compared to the prior-year quarter. Total natural gas, NGL and oil sales of $355 million (including all cash settled derivatives) increased 12% compared to the prior-year quarter due to higher volumes partially offsetting lower prices. Cash settled hedging gains of $79 million were realized during the quarter. As of September 30, 2012, Range had future hedging position value gains of approximately $145 million with approximately 40% expected to be recognized in the fourth quarter of 2012, 56% in 2013 and 4% in 2014, assuming prices remained the same.
During the third 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 of 13% versus the prior-year quarter, even with the Pennsylvania impact fee affecting only the current year quarter. Per unit cash costs including non-cash DD&A declined 12% for the quarter compared to the prior-year quarter. The unit cash cost declines in the third quarter were lease operating unit expenses down 31%, production and ad valorem taxes down 18%, interest expense down 12% and general and administrative costs down 14% while transportation, gathering and compression costs increased 5%. Gathering and compression costs rose due to additional upfront facility construction costs necessary for the planned increases in volumes in the Marcellus Shale.
Capital Expenditures –
Third quarter drilling expenditures of $400 million funded the drilling of 81 (74 net) wells and the completion of previously drilled wells. A 100% drilling success rate was achieved. Year-to-date drilling expenditures for 2012 totaled $1.1 billion. For the first nine months of 2012, Range has drilled 234 (200 net) wells. At September 30, 172 (155 net) wells drilled during the year had been placed on production. The remaining 62 (45 net) wells are in various stages of completion or waiting on pipeline connection. In addition, during the first nine months of 2012, $174 million was expended on acreage, $33 million on gas gathering systems and $49 million for exploration expense (including $27 million for seismic and $11 million for delay rentals). The Company is on plan with its capital expenditure budget for 2012 of $1.6 billion. In the plan, capital spending was heavily weighted to the first half of the year.
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Asset Sales –
Recently, Range has signed agreements to sell assets with estimated total sales proceeds of approximately $170 million. In the first half of the year, Range sold an additional $20 million of assets or $190 million to date. These assets consist primarily of our Ardmore Basin Woodford properties, scattered miscellaneous Marcellus acreage and other non-core assets. These recent transactions are expected to close during the fourth quarter and are subject to customary closing conditions and purchase price adjustments. The Ardmore Woodford properties are comprised of 9,341 net acres located in southern Oklahoma. Net production from the properties is approximately 12 Mmcfe per day which includes approximately 1,000 barrels per day of liquids.
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, flexible financial position. At September 30, 2012, Range had approximately 85% of its expected fourth quarter 2012 natural gas production hedged at a weighted average floor price of $4.17 per mcf. Similarly, Range has hedged or committed for the fourth quarter 2012 approximately 80% of its projected crude oil production at a floor price of $90.82 and approximately 60% of its composite NGL production at above current market prices. Please see Range’s detailed hedging schedule posted at the end of the financial tables below and on its website at http://www.rangeresources.com.
Operational Discussion –
Southern Marcellus Shale Division-
During the third quarter, the division brought online 68 horizontal wells in southwest Pennsylvania, with 24 wells in the super-rich area, 40 wells in the wet area and four wells in the dry area utilizing generally five rigs. The initial 24-hour production rates of the new 68 wells averaged 5.3 Mmcf per day of gas and 412 barrels per day of liquids (160 barrels of condensate and 252 barrels of NGLs), or 7.8 (6.4 net) Mmcfe per day. The majority of these wells are producing under constrained conditions since the facilities are designed for cost efficiencies and are intentionally designed not to cover the initial peak production rates of the wells. The initial 24-hour production rates by area are:
| (A) (B) Area |
(C) (D) # of Wells |
(E) Gas (F) Mmcf/d |
(G) Condensate (H) bbl/d |
(I) NGL (J) bbl/d |
(K) Total Liquids (L) bbl/d | |||||
| (M) Super-Rich |
(N) 24 | (O) 3.1 | (P) 289 | (Q) 263 | (R) 552 | |||||
| (S) Wet |
(T) 40 | (U) 6.0 | (V) 99 | (W) 270 | (X) 369 | |||||
| (Y) Dry |
(Z) 4 | (AA) 11.0 | (BB) | (CC) | (DD) |
In the southwest Marcellus, the Company drilled and cased 25 wells in the third quarter as compared to 39 wells drilled and cased in the second quarter. Sixty-eight wells were turned to sales in the third quarter which was more than double the 33 wells turned to sales in the second quarter. The Company’s backlog of 106 uncompleted wells and wells waiting on pipeline connection at the end of the second quarter in southwest Marcellus declined to 63 wells at the end of the third quarter. At September 30, 2012, there were 36 wells waiting on completion and 27 wells waiting on pipeline tie-ins to sales. The division expects to utilize six rigs in the fourth quarter 2012.
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In the super-rich area, we had a significant step-out well from our core area that tested at 1,044 barrels per day of liquids (267 barrels of condensate and 777 barrels of NGLs) and 10.3 Mmcf per day of gas, or 16.5 (14.0 net) Mmcfe per day. With ethane recovery, the well would have tested at 2,053 barrels per day of liquids (267 barrels of condensate and 1,786 barrels of NGLs) and 8.7 Mmcf per day of gas, or 21.1 (17.9 net) Mmcfe per day. The lateral length on this test was 3,797 feet and was completed using a 20-stage reduced cluster spacing (“RCS”) completion. We expect to bring this well online in late 2013 or early 2014 and drill additional wells in the area starting in 2013. Range’s second Upper Devonian super-rich well continued to clean-up following our August announcement and ultimately had a peak 24-hour rate of 552 barrels per day of liquids (172 barrels of condensate and 380 barrels of NGLs) and 4.7 Mmcf per day of gas, or 8.0 (6.8 net) Mmcfe per day. With ethane recovery, the well would have tested at 998 barrels per day of liquids (172 barrels of condensate and 826 barrels of NGLs) and 4.0 Mmcf per day of gas, or 10.0 (8.5 net) Mmcfe per day.
Northern Marcellus Shale Division-
In the northeast Marcellus, Range drilled and cased 13 wells in the third quarter as compared to 22 wells in second quarter while running five rigs. We expect to exit the year at one rig and plan to have one rig running most of next year to maintain the continuous drilling commitments under the leases. Sixteen wells were turned to sales in the third quarter which was the same as the second quarter. The Company’s backlog of 35 uncompleted and wells waiting on pipeline connection at the end of the second quarter in the northeast Marcellus declined to 31 wells at the end of the third quarter. At September 30, 2012 there were 12 wells waiting on pipeline and 19 wells waiting on completion.
Significant production results included three wells with initial 24-hour rates of 17.9 (15.3 net) Mmcf per day, 11.3 (9.7 net) Mmcf per day and 9.9 (8.5 net) Mmcf per day. The average lateral length for these three wells was 4,100 feet with an average of 14 frac stages per well.
The third phase of the Lycoming 30-inch trunkline and associated gathering system began late in the second quarter and is scheduled to be ready for sales in fourth quarter 2012. The trunkline will provide 350 Mmcf per day of capacity, net to Range, flowing into the Transco system moving gas into and out of the Leidy storage complex. Range expects to tie-in an additional 18 wells by year-end 2012 in Lycoming County.
In addition to Marcellus drilling, the division drilled and successfully completed the industry’s first wet Utica test in northwestern Pennsylvania where the Company has 190,000 net acres of leasehold. The well is currently shut in waiting testing. A second wet Utica test is scheduled to spud in the fourth quarter.
In the Bradford County participating area with Talisman, there were a total of 15 (2.8 net) wells producing, 12 (2.3 net) wells waiting on completion and 24 (4.5 net) wells waiting on pipeline.
Marcellus Shale Infrastructure-
Mariner East
As the anchor shipper under the 15-year Mariner East Project, Range has firm transportation of 40,000 barrels per day (20,000 barrels of ethane and 20,000 barrels of propane) of liquids transport from the MarkWest Houston processing plant to the Sunoco Marcus Hook terminal and dock facilities. Under the agreements, Range has access to a very significant pro rata share of the 1 million barrels of propane storage at the facility and could utilize its full capacity commitment for propane deliveries until the ethane facilities are in place. The Mariner East Project is expected to commence pipeline deliveries of propane in the second half of 2014. Ethane deliveries are forecasted to start in the first half of 2015 after additional ethane facilities are constructed at Marcus Hook. In the interim, MarkWest is transporting on behalf of Range a portion of its propane sourced from the Houston plant to the Marcus Hook facilities by rail for sales to domestic and international customers.
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Ethane Contracts
Range also executed a 15-year ethane sales agreement with INEOS Europe AG for delivery at Sunoco’s Marcus Hook dock facilities. The agreement is effective upon FERC formal approval of the Mariner East Project. INEOS is a global manufacturer of petrochemicals, specialty chemicals and oil products and currently plans to utilize its own ship fleet to take delivery of the ethane at the Marcus Hook dock facilities. Contracted sales volumes will start at 10,000 barrels per day in the first half of 2015 and increase over time to 20,000 barrels per day.
Range’s three liquids transportation (Mariner East, Mariner West and ATEX) and sales agreements are expected to provide the Company substantial operational and marketing flexibility. If the full contractual volumes under these three contracts were currently being delivered using current prices with a portion of its propane being exported, Range estimates these projects would add $0.35 to $0.45 per mcf of incremental value in the liquids-rich area.
Range expects these agreements will provide long-term assurance of meeting pipeline gas quality standards by removing ethane from the gas stream and allowing for potential increased development in the liquids-rich, stacked pay area of southwest Pennsylvania. With minimum ethane extraction to meet pipeline quality specifications, Range estimates that it has the potential to grow its Marcellus natural gas production, solely from the liquids-rich area in southwest Pennsylvania, to approximately 1.8 Bcf per day. With typical ethane extraction, the Company estimates that these contracts would require approximately 800 Mmcf per day inlet gross production by 2016. Currently, Range estimates the Company would be capable of producing approximately 24,000 barrels per day of ethane and 10,000 barrels per day of propane under normal recovery. Having multiple transportation and marketing outlets, including international export, combined with the ethane and propane storage is expected to increase Range’s flexibility and reduce future development risk.
Midcontinent Division-
Midcontinent operations for the third quarter focused on infrastructure buildout and commencement of pad drilling operations in the Horizontal Mississippian oil play. Six wells were completed and turned to sales with the majority of the activity during the quarter focused on drilling and completion of salt water disposal facilities. Current plans are to begin 2013 with a five rig drilling program.
Of the six Horizontal Mississippian wells placed on production late in the third quarter, the 24-hour peak rate to sales averaged 445 (312 net) boe per day (254 barrels oil, 111 barrels NGLs and 475 mcf gas). The wells came on production late in the quarter and many have not yet reached 30-days of production with volumes continuing to show improvement with time. Of the six wells, the lateral lengths averaged 3,700 feet with 17 to 20 frac stages. Range has increased its acreage position in the play to approximately 156,000 net acres.
During the third quarter, Range brought on the Nancy Ann #1-1S at a peak 24-hour rate to sales of 1,227 (742 net) barrels of oil equivalent per day (834 barrels of oil, 230 barrels NGLs, and 980 mcf gas). This represents the second Range Horizontal Mississippian well to exceed 1,000 barrels of oil equivalent per day. The lateral length on the well totaled 3,985 feet with a 20 stage frac. Range owns a 74.9% working interest. Range’s Balder #1-30N which was turned to sales in the second quarter of 2012 has achieved a 90-day average of 1,049 (724 net) barrels of oil equivalent per day (479 barrels of oil, 333 barrels of NGLs, and 1,421 mcf of gas). The Nancy Ann and Balder wells are approximately eight miles apart, being on the western and eastern sides of the Nehama Ridge, helping to de-risk the Nehama Ridge in this area.
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One additional St. Louis well commenced production late in the third quarter at 11.2 (6.7 net) Mmcfe per day (8.0 mcf gas, 213 barrels oil, and 323 barrels NGLs). Range has an 85% working interest and 60% net revenue interest in the well. Two to three additional St. Louis wells are scheduled to be drilled in the fourth quarter.
Permian Division-
Range completed its third Wolfberry well with an initial 24-hour production rate to sales of 505 boe per day (243 barrels of oil, 126 barrels NGLs, and 814 mcf gas) or 397 boe per day net. This is substantially better than Range’s first two Wolfberry wells which are projected to recover 216 Mboe (EUR) each. The cost to drill and complete the third well was $2.5 million, a substantial reduction versus the first two wells. Range also drilled, completed and is testing its third Cline Shale horizontal well. The well is located on the far eastern side of Range’s acre block at Conger. This well is approximately 12 miles east of Range’s first Cline Shale horizontal well, which is projected to recover 360 Mboe. Range plans to drill and complete three additional Wolfberry wells at Conger in the fourth quarter in addition to recompleting an existing Strawn producer.
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 third quarter. The division had one drilling rig and two completion rigs running in the quarter and drilled 12 (12 net) tight gas sand wells. The division turned online 21 (21 net) wells including 17 (17 net) tight gas sand, and 4 (4 net) horizontal Huron wells. Initial production results of the horizontal Huron wells indicate that the 2012 wells are the best to date while at the same time continuing to achieve significant cost reductions. Despite spending only $27 million in capital to date, (down approximately 50% versus last year), the division’s production rate for the first nine months of 2012 is up 4% compared to the production rate for 2011.
Guidance – Fourth Quarter 2012
Production per day Guidance:
Production growth for 2012 is targeted at 35% year-over-year, the high-end of our previous full-year guidance. Our original guidance included the Ardmore Woodford properties for the entire year. Due to sale of these properties, coupled with curtailed production in portions of the wet and super-rich Marcellus due to bottlenecks and equipment limitations in the gathering systems which we expect to continue during the fourth quarter, we are revising our fourth quarter liquids growth as compared to the fourth quarter of 2011 to 33% to 36% versus our previous guidance of 40%.
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Expense per mcfe Guidance:
| Direct operating expense: |
$0.43 —$0.45 per mcfe | |
| Transportation, gathering and compression expense (a): |
$0.75—$0.79 per mcfe | |
| Production tax expense (b): $0.15 per mcfe |
$0.75—$0.79 per mcfe | |
| Exploration expense: |
$19 million | |
| Unproved property impairment expense: |
$19—$21 million | |
| G&A expense: |
$0.44—$0.46 per mcfe | |
| Interest expense: |
$0.59—$0.60 per mcfe | |
| DD&A expense: |
$1.65—$1.68 per mcfe |
| (a) | Prior to year-end 2011 this expense was netted against revenue. Please refer to Table 6 of the 3Q 2012 Supplement Tables for historical detail of this expense by product. |
| (b) | Production tax expense in fourth quarter should equal approximately $0.08 per mcfe plus an estimated $5 million for the Pennsylvania impact fee. Total production tax expense including the impact fee is expected to be $0.15 per mcfe. |
Differential Pricing History (c)
| 3Q 2011 | 4Q 2011 | 1Q 2012 | 2Q 2012 | 3Q 2012 | ||||||||||||||||
| Natural Gas |
$ | 0.26 | $ | 0.07 | ($ | 0.02 | ) | ($ | 0.13 | ) | ($ | 0.03 | ) | |||||||
| NGL (% of WTI NYMEX) |
54 | % | 54 | % | 48 | % | 39 | % | 33 | % | ||||||||||
| Oil (% of WTI NYMEX) |
91 | % | 92 | % | 88 | % | 91 | % | 90 | % | ||||||||||
| (c) | Differentials based on pre-hedge pricing, excluding transportation, gathering and compression expense. |
Conference Call Information –
The Company will host a conference call on Thursday, October 25 at 12:00 p.m. ET. To participate in the call, please dial 877-407-0778 and ask for the Range Resources third quarter 2012 earnings conference call. A replay of the call will be available through November 30, 2012. To access the phone replay dial 877-660-6853. The conference ID is 401263. 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 http://www.rangeresources.com.
A simultaneous webcast of the call may be accessed over the internet at http://www.rangeresources.com or http://www.vcall.com. The webcast will be archived for replay on the Company’s website until November 30, 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.
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Third quarter 2012 earnings included a reduction in value of $58 million for the non-cash unrealized mark-to-market decrease in value of the Company’s commodity derivatives, a $20 million expense associated with the deferred compensation plan for the increase in the Company’s common stock during the period, a non-cash stock compensation expense of $12 million, a non-cash unproved property impairment expense of $40 million, a $1 million expense in connection with certain litigation, a $1 million impairment on surface acreage and $1 million gain on sale of certain properties. Excluding these items, net income would have been $32 million or $0.20 per diluted share. Excluding similar non-cash items from the prior-year quarter, net income would have been $45 million or $0.28 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 to 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
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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 (loss) income” in the Company’s 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 expected improvement in well performance, expected greater capital efficiency, protecting our financial position, the expected continued reduction in units costs, expected timing and amounts of proceeds from asset sales, expected addition of future value for shareholders, expected amount of future capital spending, expected timing, methods utilized and number of rigs related to drilling operations, expected timing of infrastructure improvements and future production and unit cost guidance information 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.
9
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.
2012-22
| SOURCE: | Range Resources Corporation | |
| Main number: 817-870-2601 | ||
| Investor Contacts: | ||
| Rodney Waller, Senior Vice President | ||
| 817-869-4258 | ||
| David Amend, Investor Relations Manager | ||
| 817-869-4266 | ||
| Laith Sando, Senior Financial Analyst | ||
| 817-869-4267 | ||
| Michael Freeman, Financial Analyst | ||
| 817-869-4264 | ||
| or | ||
| Media Contact: | ||
| Matt Pitzarella, Director of Corporate Communications | ||
| 724-873-3224 | ||
| http://www.rangeresources.com | ||
10
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 September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||||||||||
| Revenues and other income: |
||||||||||||||||||||||||
| Natural gas, NGLs and oil sales (a) |
$ | 337,040 | $ | 304,230 | $ | 953,006 | $ | 841,546 | ||||||||||||||||
| Derivative cash settlements gain (loss) (a) (b) |
17,625 | 10,742 | 21,994 | 8,342 | ||||||||||||||||||||
| Change in mark-to-market on unrealized derivatives gain (loss) (b) |
(53,646 | ) | 58,990 | 30,075 | 67,093 | |||||||||||||||||||
| Ineffective hedging (loss) gain (b) |
(4,707 | ) | (3,971 | ) | (5,061 | ) | 2,531 | |||||||||||||||||
| Gain (loss) on sale of properties |
949 | 203 | (12,704 | ) | (1,280 | ) | ||||||||||||||||||
| Equity method investment (c) |
(1,012 | ) | (640 | ) | (195 | ) | (1,399 | ) | ||||||||||||||||
| Transportation and gathering (c) |
(986 | ) | 1,191 | (1,997 | ) | 1,195 | ||||||||||||||||||
| Transportation and gathering – non-cash stock -based compensation (c) (d) |
(452 | ) | (375 | ) | (1,313 | ) | (1,107 | ) | ||||||||||||||||
| Other (c) |
82 | 266 | 421 | 1,668 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total revenues and other income |
294,893 | 370,636 | -20 | % | 984,226 | 918,589 | 7 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Costs and expenses: |
||||||||||||||||||||||||
| Direct operating |
29,030 | 29,365 | 84,044 | 85,638 | ||||||||||||||||||||
| Direct operating – non-cash stock compensation (d) |
598 | 463 | 1,647 | 1,416 | ||||||||||||||||||||
| Transportation, gathering and compression |
51,600 | 32,431 | 137,164 | 86,179 | ||||||||||||||||||||
| Production and ad valorem taxes |
8,819 | 7,317 | 32,532 | 21,746 | ||||||||||||||||||||
| Pennsylvania impact fee - prior year |
— | — | 24,707 | — | ||||||||||||||||||||
| Exploration |
13,626 | 16,704 | 48,737 | 53,217 | ||||||||||||||||||||
| Exploration – non-cash stock compensation (d) |
1,126 | 902 | 3,048 | 3,168 | ||||||||||||||||||||
| Abandonment and impairment of unproved properties |
40,118 | 16,627 | 104,048 | 52,064 | ||||||||||||||||||||
| General and administrative |
33,333 | 26,398 | 93,953 | 80,814 | ||||||||||||||||||||
| General and administrative – non-cash stock compensation (d) |
10,057 | 8,491 | 30,755 | 27,488 | ||||||||||||||||||||
| General and administrative – lawsuit settlements |
1,107 | 168 | 2,523 | 238 | ||||||||||||||||||||
| General and administrative – bad debt expense |
— | 850 | — | 446 | ||||||||||||||||||||
| Deferred compensation plan (e) |
20,052 | 8,717 | 21,555 | 33,569 | ||||||||||||||||||||
| Interest expense |
43,997 | 34,181 | 124,090 | 90,343 | ||||||||||||||||||||
| Loss on early extinguishment of debt |
— | (4 | ) | — | 18,576 | |||||||||||||||||||
| Depletion, depreciation and amortization |
123,059 | 93,619 | 332,012 | 244,129 | ||||||||||||||||||||
| Impairment of proved properties |
1,281 | 38,681 | 1,281 | 38,681 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total costs and expenses |
377,803 | 314,910 | 20 | % | 1,042,096 | 837,712 | 24 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Income (loss) from continuing operations before income taxes |
(82,910 | ) | 55,726 | -249 | % | (57,870 | ) | 80,877 | -172 | % | ||||||||||||||
| Income tax expense: |
||||||||||||||||||||||||
| Current |
— | (7 | ) | — | 1 | |||||||||||||||||||
| Deferred |
(29,074 | ) | 22,547 | (17,910 | ) | 35,345 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| (29,074 | ) | 22,540 | (17,910 | ) | 35,346 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Income from continuing operations |
(53,836 | ) | 33,186 | -262 | % | (39,960 | ) | 45,531 | -188 | % | ||||||||||||||
| Discontinued operations, net of tax |
— | 1,569 | — | 15,484 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Net income (loss) |
$ | (53,836 | ) | $ | 34,755 | -255 | % | $ | (39,960 | ) | $ | 61,015 | -165 | % | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Income Per Common Share: |
||||||||||||||||||||||||
| Basic-Income (loss) from continuing operations |
$ | (0.34 | ) | $ | 0.21 | $ | (0.25 | ) | $ | 0.28 | ||||||||||||||
| Discontinued operations |
— | 0.01 | — | 0.10 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Net income (loss) |
$ | (0.34 | ) | $ | 0.22 | -255 | % | $ | (0.25 | ) | $ | 0.38 | -166 | % | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Diluted-Income (loss) from continuing operations |
$ | (0.34 | ) | $ | 0.20 | $ | (0.25 | ) | $ | 0.28 | ||||||||||||||
| Discontinued operations |
— | 0.01 | — | 0.10 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Net income (loss) |
$ | (0.34 | ) | $ | 0.21 | -262 | % | $ | (0.25 | ) | $ | 0.38 | -166 | % | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Weighted average common shares outstanding, as reported: |
||||||||||||||||||||||||
| Basic |
159,563 | 158,154 | 1 | % | 159,297 | 157,901 | 1 | % | ||||||||||||||||
| Diluted |
159,563 | 159,322 | 0 | % | 159,297 | 158,939 | 0 | % | ||||||||||||||||
| (a) | See separate natural gas, NGLs and oil sales information table. |
| (b) | Included in Derivative fair value (loss) income in the 10-Q. |
| (c) | Included in Other revenues in the 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 10-Q. |
| (e) | Reflects the change in market value of the vested Company stock held in the deferred compensation plan. |
11
RANGE RESOURCES CORPORATION
STATEMENTS OF OPERATIONS
Restated for Barnett discontinued operations,
a non-GAAP presentation
(Unaudited, in thousands, except per share data)
| Three Months Ended September 30, 2012 | Three Months Ended September 30, 2011 | |||||||||||||||||||||||
| 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 |
$ | 337,040 | — | $ | 337,040 | $ | 304,230 | $ | 1,673 | $ | 305,903 | |||||||||||||
| Derivative cash settlements gain (loss) |
17,625 | — | 17,625 | 10,742 | — | 10,742 | ||||||||||||||||||
| Change in mark-to-market on unrealized derivatives gain (loss) |
(53,646 | ) | — | (53,646 | ) | 58,990 | — | 58,990 | ||||||||||||||||
| Ineffective hedging gain (loss) |
(4,707 | ) | — | (4,707 | ) | (3,971 | ) | — | (3,971 | ) | ||||||||||||||
| Gain (loss) on sale of properties |
949 | — | 949 | 203 | 1,032 | 1,235 | ||||||||||||||||||
| Equity method investment |
(1,012 | ) | — | (1,012 | ) | (640 | ) | — | (640 | ) | ||||||||||||||
| Transportation and gathering |
(986 | ) | — | (986 | ) | 1,191 | — | 1,191 | ||||||||||||||||
| Transportation and gathering – non-cash stock-based compensation |
(452 | ) | — | (452 | ) | (375 | ) | — | (375 | ) | ||||||||||||||
| Interest and other |
82 | — | 82 | 266 | — | 266 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| 294,893 | — | 294,893 | 370,636 | 2,705 | 373,341 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Costs and expenses: |
||||||||||||||||||||||||
| Direct operating |
29,030 | — | 29,030 | 29,365 | (611 | ) | 28,754 | |||||||||||||||||
| Direct operating – non-cash stock-based compensation |
598 | — | 598 | 463 | — | 463 | ||||||||||||||||||
| Transportation, gathering and compression |
51,600 | — | 51,600 | 32,431 | 950 | 33,381 | ||||||||||||||||||
| Production and ad valorem taxes |
8,819 | — | 8,819 | 7,317 | (44 | ) | 7,273 | |||||||||||||||||
| Pennsylvania impact fee – prior year |
— | — | — | — | — | — | ||||||||||||||||||
| Exploration |
13,626 | — | 13,626 | 16,704 | — | 16,704 | ||||||||||||||||||
| Exploration – non-cash stock-based compensation |
1,126 | — | 1,126 | 902 | — | 902 | ||||||||||||||||||
| Abandonment and impairment of unproved properties |
40,118 | — | 40,118 | 16,627 | — | 16,627 | ||||||||||||||||||
| General and administrative |
33,333 | — | 33,333 | 26,398 | — | 26,398 | ||||||||||||||||||
| General and administrative – non-cash stock-based compensation |
10,057 | — | 10,057 | 8,491 | — | 8,491 | ||||||||||||||||||
| General and administrative – lawsuit settlements |
1,107 | — | 1,107 | 168 | — | 168 | ||||||||||||||||||
| General and administrative – bad debt expense |
— | — | — | 850 | — | 850 | ||||||||||||||||||
| Deferred compensation plan |
20,052 | — | 20,052 | 8,717 | — | 8,717 | ||||||||||||||||||
| Interest expense |
43,997 | — | 43,997 | 34,181 | — | 34,181 | ||||||||||||||||||
| Loss on early extinguishment of debt |
— | — | — | (4 | ) | — | (4 | ) | ||||||||||||||||
| Depletion, depreciation and amortization |
123,059 | — | 123,059 | 93,619 | — | 93,619 | ||||||||||||||||||
| Impairment of proved properties |
1,281 | — | 1,281 | 38,681 | — | 38,681 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| 377,803 | — | 377,803 | 314,910 | 295 | 315,205 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Income (loss) from continuing operations before income taxes |
(82,910 | ) | — | (82,910 | ) | 55,726 | 2,410 | 58,136 | ||||||||||||||||
| Income tax expense: |
||||||||||||||||||||||||
| Current |
— | — | — | (7 | ) | — | (7 | ) | ||||||||||||||||
| Deferred |
(29,074 | ) | — | (29,074 | ) | 22,547 | 841 | 23,388 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| (29,074 | ) | — | (29,074 | ) | 22,540 | 841 | 23,381 | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Income (loss) from continuing operations |
(53,836 | ) | — | (53,836 | ) | 33,186 | 1,569 | 34,755 | ||||||||||||||||
| Discontinued operations-Barnett Shale, net of tax |
— | — | — | 1,569 | (1,569 | ) | — | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Net income (loss) |
$ | (53,836 | ) | — | $ | (53,836 | ) | $ | 34,755 | — | $ | 34,755 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| OPERATING HIGHLIGHTS |
||||||||||||||||||||||||
| Average daily production: |
||||||||||||||||||||||||
| Natural gas (mcf) |
623,344 | — | 623,344 | 406,977 | 3,525 | 410,502 | ||||||||||||||||||
| NGLs (bbl) |
20,040 | — | 20,040 | 15,550 | (120 | ) | 15,430 | |||||||||||||||||
| Oil (bbl) |
7,748 | — | 7,748 | 5,686 | (6 | ) | 5,680 | |||||||||||||||||
| Gas equivalents (mcfe) |
790,074 | — | 790,074 | 534,388 | 2,769 | 537,157 | ||||||||||||||||||
| Average prices realized before transportation, gathering and compression: |
||||||||||||||||||||||||
| Natural gas (mcf) |
$ | 3.88 | — | $ | 3.88 | $ | 5.33 | — | $ | 5.34 | ||||||||||||||
| NGLs (bbl) |
$ | 38.79 | — | $ | 38.79 | $ | 50.69 | — | $ | 50.92 | ||||||||||||||
| Oil (bbl) |
$ | 84.86 | — | $ | 84.86 | $ | 81.72 | — | $ | 81.71 | ||||||||||||||
| Gas equivalents (mcfe) |
$ | 4.88 | — | $ | 4.88 | $ | 6.41 | — | $ | 6.41 | ||||||||||||||
| Direct operating cash costs per mcfe: |
||||||||||||||||||||||||
| Field expenses |
$ | 0.38 | — | $ | 0.38 | $ | 0.57 | — | $ | 0.55 | ||||||||||||||
| Workovers |
0.02 | — | 0.02 | 0.03 | — | 0.03 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total operating costs |
$ | 0.40 | — | $ | 0.40 | $ | 0.60 | — | $ | 0.58 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Transportation, gathering and compression cost per mcf: |
$ | 0.71 | — | $ | 0.71 | $ | 0.66 | — | $ | 0.68 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
12
RANGE RESOURCES CORPORATION
STATEMENTS OF OPERATIONS
Restated for Barnett discontinued operations,
a non-GAAP presentation
(Unaudited, in thousands, except per share data)
| Nine Months Ended September 30, 2012 | Nine Months Ended September 30, 2011 | |||||||||||||||||||||||
| 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 |
$ | 953,006 | — | $ | 953,006 | $ | 841,546 | $ | 58,997 | $ | 900,543 | |||||||||||||
| Derivative cash settlements gain (loss) |
21,994 | — | 21,994 | 8,342 | — | 8,342 | ||||||||||||||||||
| Change in mark-to-market on unrealized derivatives gain (loss) |
30,075 | — | 30,075 | 67,093 | — | 67,093 | ||||||||||||||||||
| Ineffective hedging gain (loss) |
(5,061 | ) | — | (5,061 | ) | 2,531 | — | 2,531 | ||||||||||||||||
| Gain (loss) on sale of properties |
(12,704 | ) | — | (12,704 | ) | (1,280 | ) | 4,852 | 3,572 | |||||||||||||||
| Equity method investment |
(195 | ) | — | (195 | ) | (1,399 | ) | — | (1,399 | ) | ||||||||||||||
| Transportation and gathering |
(1,997 | ) | — | (1,997 | ) | 1,195 | 6 | 1,201 | ||||||||||||||||
| Transportation and gathering – non-cash stock-based compensation |
(1,313 | ) | — | (1,313 | ) | (1,107 | ) | — | (1,107 | ) | ||||||||||||||
| Interest and other |
421 | — | 421 | 1,668 | 4 | 1,672 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| 984,226 | — | 984,226 | 918,589 | 63,859 | 982,448 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Costs and expenses: |
||||||||||||||||||||||||
| Direct operating |
84,044 | — | 84,044 | 85,638 | 9,790 | 95,428 | ||||||||||||||||||
| Direct operating – non-cash stock-based compensation |
1,647 | — | 1,647 | 1,416 | 45 | 1,461 | ||||||||||||||||||
| Transportation, gathering and compression |
137,164 | — | 137,164 | 86,179 | 5,240 | 91,419 | ||||||||||||||||||
| Production and ad valorem taxes |
32,532 | — | 32,532 | 21,746 | 1,206 | 22,952 | ||||||||||||||||||
| Pennsylvania impact fee – prior year |
24,707 | — | 24,707 | — | — | — | ||||||||||||||||||
| Exploration |
48,737 | — | 48,737 | 53,217 | 37 | 53,254 | ||||||||||||||||||
| Exploration – non-cash stock-based compensation |
3,048 | — | 3,048 | 3,168 | — | 3,168 | ||||||||||||||||||
| Abandonment and impairment of unproved properties |
104,048 | — | 104,048 | 52,064 | — | 52,064 | ||||||||||||||||||
| General and administrative |
93,953 | — | 93,953 | 80,814 | — | 80,814 | ||||||||||||||||||
| General and administrative – non-cash stock-based compensation |
30,755 | — | 30,755 | 27,488 | — | 27,488 | ||||||||||||||||||
| General and administrative – lawsuit settlements |
2,523 | — | 2,523 | 238 | — | 238 | ||||||||||||||||||
| General and administrative – bad debt expense |
— | — | — | 446 | — | 446 | ||||||||||||||||||
| Deferred compensation plan |
21,555 | — | 21,555 | 33,569 | — | 33,569 | ||||||||||||||||||
| Interest expense |
124,090 | — | 124,090 | 90,343 | 14,791 | 105,134 | ||||||||||||||||||
| Loss on early extinguishment of debt |
— | — | — | 18,576 | — | 18,576 | ||||||||||||||||||
| Depletion, depreciation and amortization |
332,012 | — | 332,012 | 244,129 | 8,894 | 253,023 | ||||||||||||||||||
| Impairment of proved properties |
1,281 | — | 1,281 | 38,681 | — | 38,681 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| 1,042,096 | — | 1,042,096 | 837,712 | 40,003 | 877,715 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Income (loss) from continuing operations before income taxes |
(57,870 | ) | — | (57,870 | ) | 80,877 | 23,856 | 104,733 | ||||||||||||||||
| Income tax expense: |
||||||||||||||||||||||||
| Current |
— | — | — | 1 | — | 1 | ||||||||||||||||||
| Deferred |
(17,910 | ) | — | (17,910 | ) | 35,345 | 8,372 | 43,717 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| (17,910 | ) | — | (17,910 | ) | 35,346 | 8,372 | 43,718 | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Income (loss) from continuing operations |
(39,960 | ) | — | (39,960 | ) | 45,531 | 15,484 | 61,015 | ||||||||||||||||
| Discontinued operations-Barnett Shale, net of tax |
— | — | — | 15,484 | (15,484 | ) | — | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Net income (loss) |
$ | (39,960 | ) | — | $ | (39,960 | ) | $ | 61,015 | — | $ | 61,015 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| OPERATING HIGHLIGHTS |
||||||||||||||||||||||||
| Average daily production: |
||||||||||||||||||||||||
| Natural gas (mcf) |
570,343 | — | 570,343 | 366,516 | 43,109 | 409,625 | ||||||||||||||||||
| NGLs (bbl) |
18,157 | — | 18,157 | 13,914 | 793 | 14,707 | ||||||||||||||||||
| Oil (bbl) |
7,095 | — | 7,095 | 5,356 | 30 | 5,386 | ||||||||||||||||||
| Gas equivalents (mcfe) |
721,855 | — | 721,855 | 482,138 | 48,046 | 530,184 | ||||||||||||||||||
| Average prices realized before transportation, gathering and compression: |
||||||||||||||||||||||||
| Natural gas (mcf) |
$ | 3.85 | — | $ | 3.85 | $ | 5.40 | — | $ | 5.26 | ||||||||||||||
| NGLs (bbl) |
$ | 42.22 | — | $ | 42.22 | $ | 50.53 | $ | 45.86 | $ | 50.28 | |||||||||||||
| Oil (bbl) |
$ | 84.27 | — | $ | 84.27 | $ | 80.53 | $ | 92.00 | $ | 80.59 | |||||||||||||
| Gas equivalents (mcfe) |
$ | 4.93 | — | $ | 4.93 | $ | 6.46 | — | $ | 6.28 | ||||||||||||||
| Direct operating cash costs per mcfe: |
||||||||||||||||||||||||
| Field expenses |
$ | 0.40 | — | $ | 0.40 | $ | 0.63 | $ | 0.73 | $ | 0.64 | |||||||||||||
| Workovers |
0.02 | — | 0.02 | 0.02 | 0.02 | 0.02 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total operating costs |
$ | 0.42 | — | $ | 0.42 | $ | 0.65 | $ | 0.75 | $ | 0.66 | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Transportation, gathering and compression cost per mcf: |
$ | 0.69 | — | $ | 0.69 | $ | 0.65 | $ | 0.40 | $ | 0.63 | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
13
RANGE RESOURCES CORPORATION
BALANCE SHEETS
(In thousands)
| September 30 2012 |
December 31 2011 |
|||||||
| (Unaudited) | (Audited) | |||||||
| Assets |
||||||||
| Current assets |
$ | 138,694 | $ | 141,342 | ||||
| Current unrealized derivative gain |
131,841 | 173,921 | ||||||
| Natural gas and oil properties |
6,058,147 | 5,157,566 | ||||||
| Transportation and field assets |
44,222 | 52,678 | ||||||
| Other |
284,816 | 319,963 | ||||||
|
|
|
|
|
|||||
| $ | 6,657,720 | $ | 5,845,470 | |||||
|
|
|
|
|
|||||
| Liabilities and Stockholders’ Equity |
||||||||
| Current liabilities |
$ | 536,445 | $ | 506,274 | ||||
| Current asset retirement obligation |
5,005 | 5,005 | ||||||
| Current unrealized derivative loss |
4,294 | — | ||||||
| Current liabilities of discontinued operations |
— | 653 | ||||||
| Bank debt |
461,000 | 187,000 | ||||||
| Subordinated notes |
2,388,869 | 1,787,967 | ||||||
|
|
|
|
|
|||||
| Total long-term debt |
2,849,869 | 1,974,967 | ||||||
|
|
|
|
|
|||||
| Deferred tax liability |
656,849 | 710,490 | ||||||
| Unrealized derivative loss |
8,939 | 173 | ||||||
| Deferred compensation liability |
198,082 | 169,188 | ||||||
| Long-term asset retirement obligation and other |
116,410 | 86,300 | ||||||
| Common stock and retained earnings |
2,219,409 | 2,242,136 | ||||||
| Treasury stock |
(4,879 | ) | (6,343 | ) | ||||
| Accumulated other comprehensive income |
67,297 | 156,627 | ||||||
|
|
|
|
|
|||||
| Total stockholders’ equity |
2,281,827 | 2,392,420 | ||||||
|
|
|
|
|
|||||
| $ | 6,657,720 | $ | 5,845,470 | |||||
|
|
|
|
|
|||||
14
RANGE RESOURCES CORPORATION
CASH FLOWS FROM OPERATING ACTIVITIES
(Unaudited, in thousands)
| Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| Net income (loss) |
$ | (53,836 | ) | $ | 34,755 | $ | (39,960 | ) | $ | 61,015 | ||||||
| Adjustments to reconcile net income to net cash provided from operating activities: |
||||||||||||||||
| (Income) loss discontinued operations |
— | (1,569 | ) | — | (15,484 | ) | ||||||||||
| (Gain) loss from equity investment, net of distributions |
(41 | ) | 3,675 | 2,252 | 18,777 | |||||||||||
| Deferred income tax expense |
(29,074 | ) | 22,547 | (17,910 | ) | 35,345 | ||||||||||
| Depletion, depreciation, amortization and proved property impairment |
124,340 | 132,300 | 333,293 | 282,810 | ||||||||||||
| Exploration dry hole costs |
15 | 2,510 | 832 | 2,516 | ||||||||||||
| Abandonment and impairment of unproved properties |
40,118 | 16,627 | 104,048 | 52,064 | ||||||||||||
| Mark-to-market (gain) loss on oil and gas derivatives not designated as hedges |
53,645 | (58,990 | ) | (30,076 | ) | (67,093 | ) | |||||||||
| Unrealized derivatives (gain) loss |
4,707 | 3,971 | 5,061 | (2,531 | ) | |||||||||||
| Allowance for bad debts |
— | 850 | — | 446 | ||||||||||||
| Amortization of deferred financing costs, loss on extinguishment of debt, and other |
2,077 | 2,075 | 5,970 | 23,753 | ||||||||||||
| Deferred and stock-based compensation |
32,232 | 18,598 | 58,573 | 66,759 | ||||||||||||
| Gain (loss) on sale of assets and other |
(949 | ) | (203 | ) | 12,704 | 1,280 | ||||||||||
| Changes in working capital: |
||||||||||||||||
| Accounts receivable |
(21,090 | ) | (24,357 | ) | (9,479 | ) | (34,356 | ) | ||||||||
| Inventory and other |
(2,570 | ) | (1,894 | ) | (5,394 | ) | 875 | |||||||||
| Accounts payable |
32,996 | (12,277 | ) | 11,074 | (7,262 | ) | ||||||||||
| Accrued liabilities and other |
(4,393 | ) | 2,298 | 30,135 | 9,953 | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net changes in working capital |
4,943 | (36,230 | ) | 26,336 | (30,790 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net cash provided from continuing operations |
178,177 | 140,916 | 461,123 | 428,867 | ||||||||||||
| Net cash (used in) provided from discontinued operations |
— | (2,076 | ) | — | 19,478 | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net cash provided from operating activities |
$ | 178,177 | $ | 138,840 | $ | 461,123 | $ | 448,345 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
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 September 30, |
Nine Months Ended September 30, |
|||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| Net cash provided from operating activities, as reported |
$ | 178,177 | $ | 138,840 | $ | 461,123 | $ | 448,345 | ||||||||
| Net changes in working capital from continuing operations |
(4,943 | ) | 36,230 | (26,336 | ) | 30,790 | ||||||||||
| Exploration expense |
13,611 | 14,194 | 47,905 | 50,701 | ||||||||||||
| Lawsuit settlements |
1,107 | 168 | 2,523 | 238 | ||||||||||||
| Equity method investment distribution / intercompany elimination |
1,053 | (3,034 | ) | (2,057 | ) | (17,378 | ) | |||||||||
| Prior year Pennsylvania impact fee |
— | — | 24,707 | — | ||||||||||||
| Non-cash compensation adjustment |
146 | 122 | 3 | 185 | ||||||||||||
| Net changes in working capital from discontinued operations and other |
— | 3,454 | — | 8,502 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Cash flow from operations before changes in working capital, a non-GAAP measure |
$ | 189,151 | $ | 189,974 | $ | 507,868 | $ | 521,383 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING
(Unaudited, in thousands)
| Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| Basic: |
||||||||||||||||
| Weighted average shares outstanding |
162,527 | 161,085 | 162,198 | 160,789 | ||||||||||||
| Stock held by deferred compensation plan |
(2,964 | ) | (2,931 | ) | (2,901 | ) | (2,888 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Adjusted basic |
159,563 | 158,154 | 159,297 | 157,901 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Dilutive: |
||||||||||||||||
| Weighted average shares outstanding |
162,527 | 161,085 | 162,198 | 160,789 | ||||||||||||
| Anti-dilutive or dilutive stock options under treasury method |
(2,964 | ) | (1,763 | ) | (2,901 | ) | (1,850 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Adjusted dilutive |
159,563 | 159,322 | 159,297 | 158,939 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
15
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
(Unaudited, in thousands, except per unit data)
| As Reported, GAAP | Non-GAAP | |||||||||||||||||||||||
| Excludes Barnett Operations | Includes Barnett Operations | |||||||||||||||||||||||
| Three Months Ended September 30, | Three Months Ended September 30, | |||||||||||||||||||||||
| 2012 | 2011 | % | 2012 | 2011 | % | |||||||||||||||||||
| Natural gas, NGLs and oil sales components: |
||||||||||||||||||||||||
| Natural gas sales |
$ | 159,525 | $ | 165,581 | $ | 159,525 | $ | 167,544 | ||||||||||||||||
| NGLs sales |
56,826 | 69,430 | 56,826 | 69,189 | ||||||||||||||||||||
| Oil sales |
59,221 | 42,461 | 59,221 | 42,412 | ||||||||||||||||||||
| Cash-settled hedges (effective): |
||||||||||||||||||||||||
| Natural gas |
62,150 | 26,758 | 62,150 | 26,758 | ||||||||||||||||||||
| Crude oil |
(682 | ) | — | (682 | ) | — | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total natural gas, NGLs and oil sales, as reported |
$ | 337,040 | $ | 304,230 | 11 | % | $ | 337,040 | $ | 305,903 | 10 | % | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Derivative fair value income (loss) components: |
||||||||||||||||||||||||
| Cash-settled derivatives (ineffective): |
||||||||||||||||||||||||
| Natural gas |
$ | 988 | $ | 7,370 | $ | 988 | $ | 7,370 | ||||||||||||||||
| NGLs |
14,682 | 3,087 | 14,682 | 3,087 | ||||||||||||||||||||
| Crude Oil |
1,955 | 285 | 1,955 | 285 | ||||||||||||||||||||
| Change in mark-to-market on unrealized derivatives |
(53,646 | ) | 58,990 | (53,646 | ) | 58,990 | ||||||||||||||||||
| Unrealized ineffectiveness |
(4,707 | ) | (3,971 | ) | (4,707 | ) | (3,971 | ) | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total derivative fair value income (loss), as reported |
$ | (40,728 | ) | $ | 65,761 | $ | (40,728 | ) | $ | 65,761 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Natural gas, NGLs and oil sales, including all cash-settled derivatives (c): |
||||||||||||||||||||||||
| Natural gas sales |
$ | 222,663 | $ | 199,709 | $ | 222,663 | $ | 201,672 | ||||||||||||||||
| NGL sales |
71,508 | 72,517 | 71,508 | 72,276 | ||||||||||||||||||||
| Oil sales |
60,494 | 42,746 | 60,494 | 42,697 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total |
$ | 354,665 | $ | 314,972 | 13 | % | $ | 354,665 | $ | 316,645 | 12 | % | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Third party transportation, gathering and compression fee components: |
||||||||||||||||||||||||
| Natural gas |
$ | 48,737 | $ | 30,448 | $ | 48,737 | $ | 31,398 | ||||||||||||||||
| NGLs |
2,863 | 1,983 | 2,863 | 1,983 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total transportation, gathering and compression, as reported |
$ | 51,600 | $ | 32,431 | $ | 51,600 | $ | 33,381 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Production during the period (a): |
||||||||||||||||||||||||
| Natural gas (mcf) |
57,347,638 | 37,441,857 | 53 | % | 57,347,638 | 37,766,122 | 52 | % | ||||||||||||||||
| NGLs (bbl) |
1,843,667 | 1,430,568 | 29 | % | 1,843,667 | 1,419,485 | 30 | % | ||||||||||||||||
| Oil (bbl) |
712,858 | 523,074 | 36 | % | 712,858 | 522,572 | 36 | % | ||||||||||||||||
| Gas equivalent (mcfe) (b) |
72,686,788 | 49,163,709 | 48 | % | 72,686,788 | 49,418,463 | 47 | % | ||||||||||||||||
| Production – average per day (a): |
||||||||||||||||||||||||
| Natural gas (mcf) |
623,344 | 406,977 | 53 | % | 623,344 | 410,501 | 52 | % | ||||||||||||||||
| NGLs (bbl) |
20,040 | 15,550 | 29 | % | 20,040 | 15,429 | 30 | % | ||||||||||||||||
| Oil (bbl) |
7,748 | 5,686 | 36 | % | 7,748 | 5,680 | 36 | % | ||||||||||||||||
| Gas equivalent (mcfe) (b) |
790,074 | 534,388 | 48 | % | 790,074 | 537,157 | 47 | % | ||||||||||||||||
| Average prices, including cash-settled hedges and derivatives before third party transportation costs: |
||||||||||||||||||||||||
| Natural gas (mcf) |
$ | 3.88 | $ | 5.33 | -27 | % | $ | 3.88 | $ | 5.34 | -27 | % | ||||||||||||
| NGLs (bbl) |
$ | 38.79 | $ | 50.69 | -23 | % | $ | 38.79 | $ | 50.92 | -24 | % | ||||||||||||
| Oil (bbl) |
$ | 84.86 | $ | 81.72 | 4 | % | $ | 84.86 | $ | 81.71 | 4 | % | ||||||||||||
| Gas equivalent (mcfe) (b) |
$ | 4.88 | $ | 6.41 | -24 | % | $ | 4.88 | $ | 6.41 | -24 | % | ||||||||||||
| Average prices, including cash-settled hedges and derivatives (d): |
||||||||||||||||||||||||
| Natural gas (mcf) |
$ | 3.03 | $ | 4.52 | -33 | % | $ | 3.03 | $ | 4.51 | -33 | % | ||||||||||||
| NGLs (bbl) |
$ | 37.23 | $ | 49.30 | -24 | % | $ | 37.23 | $ | 49.52 | -25 | % | ||||||||||||
| Oil (bbl) |
$ | 84.86 | $ | 81.72 | 4 | % | $ | 84.86 | $ | 81.71 | 4 | % | ||||||||||||
| Gas equivalent (mcfe) (b) |
$ | 4.17 | $ | 5.75 | -27 | % | $ | 4.17 | $ | 5.73 | -27 | % | ||||||||||||
| (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. |
16
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
(Unaudited, in thousands, except per unit data)
| As Reported, GAAP | Non-GAAP | |||||||||||||||||||||||
| Excludes Barnett Operations | Includes Barnett Operations | |||||||||||||||||||||||
| Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||
| 2012 | 2011 | % | 2012 | 2011 | % | |||||||||||||||||||
| Natural gas, NGLs and oil sales components: |
||||||||||||||||||||||||
| Natural gas sales |
$ | 399,006 | $ | 446,564 | $ | 399,006 | $ | 486,277 | ||||||||||||||||
| NGLs sales |
189,604 | 188,851 | 189,604 | 198,780 | ||||||||||||||||||||
| Oil sales |
166,718 | 125,472 | 166,718 | 126,220 | ||||||||||||||||||||
| Cash-settled hedges (effective): |
||||||||||||||||||||||||
| Natural gas |
198,675 | 80,659 | 198,675 | 89,266 | ||||||||||||||||||||
| Crude oil |
(997 | ) | — | (997 | ) | — | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total natural gas, NGLs and oil sales, as reported |
$ | 953,006 | $ | 841,546 | 13 | % | $ | 953,006 | $ | 900,543 | 6 | % | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Derivative fair value income (loss) components: |
||||||||||||||||||||||||
| Cash-settled derivatives (ineffective): |
||||||||||||||||||||||||
| Natural gas |
$ | 3,451 | $ | 12,982 | $ | 3,451 | $ | 12,982 | ||||||||||||||||
| NGLs |
20,442 | 3,087 | 20,442 | 3,087 | ||||||||||||||||||||
| Crude Oil |
(1,899 | ) | (7,727 | ) | (1,899 | ) | (7,727 | ) | ||||||||||||||||
| Change in mark-to-market on unrealized derivatives |
30,075 | 67,093 | 30,075 | 67,093 | ||||||||||||||||||||
| Unrealized ineffectiveness |
(5,061 | ) | 2,531 | (5,061 | ) | 2,531 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total derivative fair value income (loss), as reported |
$ | 47,008 | $ | 77,966 | $ | 47,008 | $ | 77,966 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Natural gas, NGLs and oil sales, including all cash-settled derivatives (c): |
||||||||||||||||||||||||
| Natural gas sales |
$ | 601,132 | $ | 540,205 | $ | 601,132 | $ | 588,525 | ||||||||||||||||
| NGLs sales |
210,046 | 191,938 | 210,046 | 201,867 | ||||||||||||||||||||
| Oil sales |
163,822 | 117,745 | 163,822 | 118,493 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total |
$ | 975,000 | $ | 849,888 | 15 | % | $ | 975,000 | $ | 908,885 | 7 | % | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Third party transportation, gathering and compression fee components: |
||||||||||||||||||||||||
| Natural gas |
$ | 129,411 | $ | 81,848 | $ | 129,411 | $ | 87,088 | ||||||||||||||||
| NGLs |
7,753 | 4,331 | 7,753 | 4,331 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Total transportation, gathering and compression, as reported |
$ | 137,164 | $ | 86,179 | $ | 137,164 | $ | 91,419 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Production during the period (a): |
||||||||||||||||||||||||
| Natural gas (mcf) |
156,274,072 | 100,058,851 | 56 | % | 156,274,072 | 111,827,546 | 40 | % | ||||||||||||||||
| NGLs (bbl) |
4,975,086 | 3,798,635 | 31 | % | 4,975,086 | 4,015,156 | 24 | % | ||||||||||||||||
| Oil (bbl) |
1,943,961 | 1,462,168 | 33 | % | 1,943,961 | 1,470,296 | 32 | % | ||||||||||||||||
| Gas equivalent (mcfe) (b) |
197,788,354 | 131,623,670 | 50 | % | 197,788,354 | 144,740,258 | 37 | % | ||||||||||||||||
| Production – average per day (a): |
||||||||||||||||||||||||
| Natural gas (mcf) |
570,343 | 366,516 | 56 | % | 570,343 | 409,625 | 39 | % | ||||||||||||||||
| NGLs (bbl) |
18,157 | 13,914 | 30 | % | 18,157 | 14,708 | 23 | % | ||||||||||||||||
| Oil (bbl) |
7,095 | 5,356 | 32 | % | 7,095 | 5,386 | 32 | % | ||||||||||||||||
| Gas equivalent (mcfe) (b) |
721,855 | 482,138 | 50 | % | 721,855 | 530,184 | 36 | % | ||||||||||||||||
| Average prices, including cash-settled hedges and derivatives before third party transportation costs: |
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| Natural gas (mcf) |
$ | 3.85 | $ | 5.40 | -29 | % | $ | 3.85 | $ | 5.26 | -27 | % | ||||||||||||
| NGLs (bbl) |
$ | 42.22 | $ | 50.53 | -16 | % | $ | 42.22 | $ | 50.28 | -16 | % | ||||||||||||
| Oil (bbl) |
$ | 84.27 | $ | 80.53 | 5 | % | $ | 84.27 | $ | 80.59 | 5 | % | ||||||||||||
| Gas equivalent (mcfe) (b) |
$ | 4.93 | $ | 6.46 | -24 | % | $ | 4.93 | $ | 6.28 | -21 | % | ||||||||||||
| Average prices, including cash-settled hedges and derivatives (d): |
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| Natural gas (mcf) |
$ | 3.02 | $ | 4.58 | -34 | % | $ | 3.02 | $ | 4.48 | -33 | % | ||||||||||||
| NGLs (bbl) |
$ | 40.66 | $ | 49.39 | -18 | % | $ | 40.66 | $ | 49.20 | -17 | % | ||||||||||||
| Oil (bbl) |
$ | 84.27 | $ | 80.53 | 5 | % | $ | 84.27 | $ | 80.59 | 5 | % | ||||||||||||
| Gas equivalent (mcfe) (b) |
$ | 4.24 | $ | 5.80 | -27 | % | $ | 4.24 | $ | 5.65 | -25 | % | ||||||||||||
| (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. |
17
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 September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||
| 2012 | 2011 | % | 2012 | 2011 | % | |||||||||||||||||||
| (Loss) income from continuing operations before income taxes, as reported |
$ | (82,910 | ) | $ | 55,726 | -249 | % | $ | (57,870 | ) | $ | 80,877 | -172 | % | ||||||||||
| Adjustment for certain items: |
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| Gain (loss) on sale of properties |
(949 | ) | (203 | ) | 12,704 | 1,280 | ||||||||||||||||||
| Barnett discontinued operations less gain on sale |
— | 1,378 | — | 19,004 | ||||||||||||||||||||
| Change in mark-to-market on unrealized derivatives (gain) loss |
53,646 | (58,990 | ) | (30,075 | ) | (67,093 | ) | |||||||||||||||||
| Unrealized derivative (gain) loss |
4,707 | 3,971 | 5,061 | (2,531 | ) | |||||||||||||||||||
| Abandonment and impairment of unproved properties |
40,118 | 16,627 | 104,048 | 52,064 | ||||||||||||||||||||
| Loss on early extinguishment of debt |
— | (4 | ) | — | 18,576 | |||||||||||||||||||
| Prior year Pennsylvania impact fee |
— | — | 24,707 | — | ||||||||||||||||||||
| Proved property and other asset impairment |
1,281 | 38,681 | 1,281 | 38,681 | ||||||||||||||||||||
| Lawsuit settlements |
1,107 | 168 | 2,523 | 238 | ||||||||||||||||||||
| Transportation and gathering – non-cash stock-based compensation |
452 | 375 | 1,313 | 1,107 | ||||||||||||||||||||
| Direct operating – non-cash stock-based compensation |
598 | 463 | 1,647 | 1,416 | ||||||||||||||||||||
| Exploration expenses – non-cash stock-based compensation |
1,126 | 902 | 3,048 | 3,168 | ||||||||||||||||||||
| General & administrative – non-cash stock-based compensation |
10,057 | 8,491 | 30,755 | 27,488 | ||||||||||||||||||||
| Deferred compensation plan – non-cash adjustment |
20,052 | 8,717 | 21,555 | 33,569 | ||||||||||||||||||||
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| Income from operations before income taxes, as adjusted |
49,285 | 76,302 | -35 | % | 120,697 | 207,844 | -42 | % | ||||||||||||||||
| Income tax expense, as adjusted |
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| Current |
— | (7 | ) | — | 1 | |||||||||||||||||||
| Deferred |
17,287 | 31,650 | 45,749 | 84,725 | ||||||||||||||||||||
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| Net income excluding certain items, a non-GAAP measure |
$ | 31,998 | $ | 44,659 | -28 | % | $ | 74,948 | $ | 123,118 | -39 | % | ||||||||||||
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| Non-GAAP income per common share |
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| Basic. |
$ | 0.20 | $ | 0.28 | -29 | % | $ | 0.47 | $ | 0.78 | -40 | % | ||||||||||||
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| Diluted |
$ | 0.20 | $ | 0.28 | -29 | % | $ | 0.47 | $ | 0.77 | -39 | % | ||||||||||||
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| Non-GAAP diluted shares outstanding, if dilutive |
160,222 | 159,322 | 160,130 | 158,939 | ||||||||||||||||||||
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HEDGING POSITION AS OF OCTOBER 24, 2012
(Unaudited)
| Daily Volume | Hedge Price | Premium (Paid) / Received |
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| Gas (Mmbtu) |
||||||||||
| 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 |
213,384 | $3.65 | — | |||||||
| 2013 Collars |
280,000 | $4.59 - $5.05 | — | |||||||
| 2014 Collars |
385,000 | $3.80 - $4.48 | — | |||||||
| Oil (Bbls) |
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| 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 |
5,081 | $96.59 | — | |||||||
| 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) |
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| 3Q 2012 Swaps |
6,500 | $2.2923 | — | |||||||
| 4Q 2012 Swaps |
6,500 | $2.2923 | — | |||||||
| 2013 Swaps |
6,500 | $2.1343 | — | |||||||
| C3 Propane (Bbls) |
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| 3Q 2012 Swaps |
6,000 | $1.2241 | — | |||||||
| 4Q 2012 Swaps |
6,000 | $1.2241 | — | |||||||
| 2013 Swaps |
5,000 | $0.9418 | — | |||||||
18
NOTE: SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS
19