- Reports record annual production of 753 Mmcfe per day, an increase of 36% over 2011, with fourth quarter oil and NGL volumes increasing 41%.
- Drill bit reserve replacement of 773% at $0.86 per mcfe all-in finding and development cost.
- Fourth quarter adjusted non-GAAP earnings of $0.46 per share exceeds average First Call consensus estimates by 17 cents.
- Asset sale agreement recently executed for $275 million.
Range Resources Corporation (NYSE: RRC) today announced its 2012 financial results.
2012 Highlights –
- Reports record annual production of 753 Mmcfe per day, an increase of 36% over 2011, with fourth quarter oil and NGL volumes increasing 41%
- Reports 29% increase in total proved reserves to 6.5 Tcfe, with oil and NGL reserves increasing 64%
- Drill bit reserve replacement of 773% at $0.86 per mcfe all-in finding and development cost
- Fourth quarter adjusted non-GAAP cash flow of $1.54 per share exceeds average First Call consensus estimates by 18 cents
- Fourth quarter adjusted non-GAAP earnings of $0.46 per share exceeds average First Call consensus estimates by 17 cents
- Unit costs continue to decline, highlighted by 32% reduction in lease operating costs compared to 2011
- Innovative marketing arrangements increased price realizations from propane exports
- Unrisked resource potential increases to 48 - 68 Tcfe, including 2.3 – 3.5 billion barrels of oil and NGLs
- Asset sale agreement recently executed for $275 million
As previously reported, production for 2012 averaged 753 Mmcfe per day, a 36% increase over 2011. Fourth quarter 2012 production volumes averaged 844 Mmcfe per day, another record high for Range. Fourth quarter 2012 production increased 35% over the prior-year period and was 7% higher than third quarter 2012. Oil and NGL production increased 41% during the fourth quarter reflecting the Company’s focus on its high return, liquids-rich plays during 2012.
Proved reserves increased 29% year-over-year to 6.5 Tcfe, driven by a 64% increase in liquids reserves. All-in finding and development cost averaged $0.86 per mcfe, while replacing 773% of production from drilling. Drill bit finding cost averaged $0.67 per mcfe. Production and reserves per share on a debt-adjusted basis increased 29% and 22%, respectively. This represents the seventh consecutive year of double-digit per-share growth for both production and reserves. Range’s unrisked unproved resource potential at year-end 2012 increased to 48 - 68 Tcfe; including 2.3 - 3.5 billion barrels of NGLs and crude oil.Commenting, Jeff Ventura, the Company’s President and CEO, said, “Range had outstanding operational results for 2012. The Marcellus Shale play that Range discovered in 2004 became the largest producing field in the U.S. in 2012. Our million acre position in Pennsylvania provides for future growth with low reinvestment risk and strong rates of return. The Marcellus fueled our 29% increase in proved reserves while increasing our liquids reserves by 64%. Year-over-year production was up 36% while our liquids growth in the fourth quarter was 41% compared to the prior year quarter. Our cost structure per mcfe improved in each quarter of 2012. All-in finding and development costs continue to be under a dollar per mcfe with our three year average being $0.82 per mcfe and our three year reserve replacement averaging 815%. Consistent low finding costs are now visibly translating into lower DD&A rates in our financial statements, with $1.46 per mcfe in the fourth quarter. The lower rate will help drive future earnings. Our reserves per well in the Marcellus continue to improve as we gain additional production history and continue to optimize drilling and completion designs.
“Looking ahead, 2013 should be even better than 2012. We expect to grow production in the 20% to 25% range utilizing our existing low-cost, high rate of return inventory. Range’s liquids production is expected to grow disproportionately greater than overall production in 2013 as we continue to focus the majority of our capital in our liquids-rich areas. With the continued ramp up in production volumes, we expect our cost structure to improve further as volumes grow faster than our absolute costs. Importantly, with our access to the growing global markets for NGLs through our innovative Mariner West and East projects we are increasing our price realizations and improving our profit margins. In addition to the Marcellus, our Horizontal Mississippian oil play is gaining substantial momentum and should add to our liquids production and reserves, while the Cline Shale, Wolfberry and Utica plays have exciting liquids potential. We are looking for 2013 to be a year of increasing production, reserves, cash flow and earnings which should translate into higher per share value for all Range shareholders.”
(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. We sold substantially all of our Barnett Shale properties in April 2011. Under GAAP, activity 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.)
Full Year 2012
GAAP revenues for 2012 totaled $1.5 billion (18% increase as compared to 2011), GAAP net cash provided from operating activities including changes in working capital reached $647 million ($4.04 per diluted share) and GAAP earnings were $13 million ($0.08 per diluted share) versus $58 million ($0.36 per diluted share) in 2011. 2012 results were driven by record high production and a decrease in unit costs, offset by a 23% decline in realized prices.
Non-GAAP revenues for 2012 totaled $1.4 billion (11% increase compared to 2011), cash flow from operations before changes in working capital, a non-GAAP measure, reached $756 million ($4.71 per diluted share versus consensus of $4.33 per share). Adjusted net income, a non-GAAP measure, was $148 million ($0.92 per diluted share for 2012 versus average First Call consensus estimates of $0.74 per share). Wellhead prices, after adjustment for all cash-settled hedges and derivatives, averaged $5.05 per mcfe. The Company’s cost structure continued to improve as total unit costs decreased by $0.40 per mcfe or 9% as compared to the prior year. Direct operating expenses for the year averaged $0.41 per mcfe, a 32% decrease compared to the prior year. Depreciation, depletion and amortization expense decreased 7% to $1.62 per mcfe.
GAAP revenues for the fourth quarter of 2012 totaled $458 million (51% increase as compared to fourth quarter 2011), GAAP net cash provided from operating activities including changes in working capital reached $186 million ($1.16 per diluted share) and GAAP earnings were $53 million ($0.32 per diluted share) versus a net loss of $3 million ($0.02 loss per diluted share) in 2011. Fourth quarter results were driven by a 35% increase in production and lower unit costs.
Non-GAAP revenues for fourth quarter 2012 totaled $418 million (19% increase compared to fourth quarter 2011), cash flow from operations before changes in working capital, a non-GAAP measure, reached $248 million ($1.54 per diluted share versus average First Call consensus estimates of $1.36 per share). Adjusted net income, a non-GAAP measure, was $73 million ($0.46 per diluted share for the fourth quarter 2012 versus average First Call consensus estimates of $0.29 per share). Wellhead prices, after adjustment for all cash-settled hedges and derivatives, averaged $5.35 per mcfe. The Company’s total unit costs decreased by $0.36 per mcfe or 9% compared to the prior-year quarter. Direct operating expenses for the quarter were $0.38 per mcfe, a 16% decrease compared to the prior-year quarter. Depreciation, depletion and amortization expense decreased 14% to $1.46 per mcfe.
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.
During 2012, Range strengthened its balance sheet with the sale of its Ardmore Woodford and other miscellaneous properties for approximately $170 million. The sale proceeds were used to pay down the outstanding balance on its bank credit facility. At year-end 2012, following the redemption of $250 million in high-coupon 7.5% bonds, the Company had over $900 million of liquidity on its credit facility. Increasing quarterly cash flow and the proceeds from additional asset sales are expected to strengthen the balance sheet in 2013.
Recent Asset Sale Agreement
Range recently entered into an agreement to sell certain of its Permian Basin properties in southeast New Mexico and West Texas for a purchase price of $275 million. The sale is expected to close in April and is subject to customary closing conditions and purchase price adjustments. The properties being sold consist of approximately 7,000 net acres that are currently producing approximately 18 Mmcfe per day with approximately 70% being natural gas and 30% oil and NGLs. With this sale, the Company will have sold $2.3 billion in assets since 2004 while focusing its resources and personnel on the highest rate of return projects in the portfolio.
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. Range currently has over 70% of its expected 2013 natural gas production hedged at a weighted average floor price of $4.18 per mcf. Similarly, Range has hedged more than 80% of its projected crude oil production at a floor price of $94.55 and more than 50% of its composite NGL production near 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.
Range has updated its investor presentation with acreage maps, updated economic sensitivity analysis and other financial and operational information. Please see www.rangeresources.com under the Investor Relations tab, “Presentations and Webcasts” area, for the presentation entitled, “Company Presentation - February 26, 2013.”
Fourth quarter drilling expenditures of $234 million funded the drilling of 64 (54 net) wells. A 100% success rate was achieved. Drilling expenditures for 2012 totaled $1.36 billion, and Range drilled 298 (257 net) wells and 4 (4 net) recompletions during the year. Total capital spending for 2012 was $1.62 billion, including $189 million for leasehold. All-in finding and development cost for 2012 averaged $0.86 per mcfe, with drill bit reserve replacement of 773%. Drill bit only finding cost averaged $0.67 per mcfe.
Marcellus Shale -
Range continued to make significant progress in the Marcellus Shale during 2012 as we continued to grow production and reserves and delineate our sizable acreage position while expanding our current and future marketing and transportation capabilities for natural gas and NGLs. Range was able to reach its year-end production target of 600 Mmcfe per day net with approximately 75% of that production coming from the liquids-rich area of the play. Another milestone for Range in 2012 was the signing of two additional ethane transportation agreements, ATEX and Mariner East; the culmination of several years of planning. Mariner East will also transport propane to the northeast United States for both domestic consumption and export to international markets. Ethane exports to Canada under the first ethane sales agreement are expected to commence on time in mid-2013. These ethane sales are expected to allow Range to meet natural gas pipeline quality requirements for the foreseeable future and are expected to eliminate shut-in production risk in the liquids-rich area. Prior to the Mariner East pipeline being completed in 2014, Range is shipping propane by rail for export through the Marcus Hook port facility near Philadelphia to the international market. This innovative arrangement increased our NGL realizations in the fourth quarter of 2012. Additional exports of propane are planned for 2013.
Southern Marcellus Shale Division -
In early February, Range revised its estimated ultimate recovery (“EUR”) for wells drilled in both the wet and super-rich areas of the Southern Marcellus Shale division. In the super-rich area, Range estimates wells will cost $5.1 million in development mode to drill and complete with a lateral length of 3,800 feet and 18 frac stages. This is expected to develop an EUR of 1.44 million barrels of oil equivalent that is 57% liquids (109 thousand barrels condensate, 715 thousand barrels NGLs and 3.7 Bcf gas). These projected well-level economics generate a 93% rate of return based on NYMEX “strip pricing” as of December 31, 2012. In the wet area, Range estimates wells will cost $4.9 million in development mode to drill and complete with a lateral length of 3,200 feet and 13 frac stages. This is expected to develop an EUR of 8.7 Bcf equivalent that is 49% liquids (27 thousand barrels condensate, 685 thousand barrels NGLs and 4.4 Bcf gas). These projected well-level economics generate a 78% rate of return based on NYMEX “strip pricing” as of December 31, 2012.
During the fourth quarter, the division brought online 30 horizontal wells in southwest Pennsylvania, 26 of which were located in the liquids-rich area of the play. The initial production rates of the new wells averaged 6.5 (5.1 net) Mmcfe per day consisting of 3.9 (3.0 net) Mmcf per day of natural gas and 432 (355 net) barrels of NGLs and condensate per day. Twenty-two of the wells brought online in the fourth quarter were in the super-rich area of the play, eight of which utilized reduced cluster spacing completions. In January, the division completed a three-well pad in the super-rich area at the combined 24-hour rate of 6,123 (5,220 net) boe per day that was 68% liquids (1,209 barrels condensate, 2,956 barrels NGLs and 11.7 Mmcf gas). In February, the division completed two wells on another super-rich area pad at the combined 24-hour rate of 6,866 (5,685 net) boe per day that was 59% liquids (793 barrels condensate, 3,260 barrels NGLs and 16.9 Mmcf gas).
In the southwest Marcellus, the Company drilled and cased 25 wells in the fourth quarter and the Company turned to sales 30 wells. As a result, the Company’s backlog of uncompleted wells and wells waiting on pipeline connection declined to 58. The division is currently utilizing six rigs and plans to maintain similar activity levels throughout 2013.
Northern Marcellus Shale Division -
In the northeast Marcellus, Range drilled and cased eight wells in the fourth quarter. A significant well was drilled in Lycoming County that produced at a 24-hour rate of 14.2 (12.2 net) Mmcf per day from a lateral of 2,475 feet and nine frac stages. In total, 11 wells were turned to sales in the fourth quarter. As a result, the Company’s backlog of uncompleted wells and wells waiting on pipeline connection declined to 28 wells at year-end. We are currently running two rigs in northeast Pennsylvania and anticipate running one or two rigs for 2013 to maintain continuous drilling commitments under the leases.
In the Bradford County participating area with Talisman, there were a total of 17 (4.5 net) wells producing, 13 (3.5 net) wells waiting on completion and 24 (6.5 net) wells waiting on pipeline.
In northwest Pennsylvania, Range drilled its first Utica well (50% WI) on its 181,000 net acres. The well encountered 285 feet of Utica/Point Pleasant pay at a depth of approximately 7,000 feet. The well confirmed that we are in the wet gas window and have good pressure. Diagnostics indicate that the well was not effectively stimulated and to date has tested at just over 1.4 Mmcfe per day. However, we are encouraged by the well data and we are monitoring offset activity as we choose the timing of our next test.
Midcontinent Division -
Midcontinent operations in the fourth quarter focused on the Horizontal Mississippian play in Oklahoma and Kansas along the Nemaha Ridge. Recently, the division drilled a well with a 24-hour initial production rate of 812 (710 net) boe per day that was 82% liquids (458 barrels oil, 207 barrels NGLs and 0.9 Mmcf gas) from a lateral that was limited to 2,342 feet due to unit size. With five rigs currently running, completion activity is expected to build late in the first quarter of 2013.
During the fourth quarter, 9 (8.2 net) wells were turned to sales with average lateral lengths of 3,800 feet and 20 frac stages. Average 7-day rates for the completions were 482 (363 net) boe per day with 76% liquids. Additionally, we now have 30-day rates on two of our previously announced 1,000+ boe per day wells that were drilled in the fourth quarter. The Dakota #9-5S achieved a 30-day average rate 802 (654 net) boe per day (348 barrels oil, 265 barrels NGLs and 1.1 Mmcf gas). The Troche #1-4N had a 30-day average of 615 (372 net) boe per day (361 barrels oil, 148 barrels NGLs and 0.6 Mmcf gas). The current leasehold position of approximately 160,000 net acres is expected to be held by production with the drilling schedule we have planned through 2015. A total of 51 Horizontal Mississippian and 17 saltwater disposal wells are expected to be drilled in 2013.
In addition, a one rig program is anticipated in the Texas Panhandle for most of 2013 where Range has had some early success drilling Horizontal St. Louis wells. Another St. Louis well was completed in the fourth quarter for 10.9 (4.3 net) Mmcfe per day (7.8 Mmcf gas, 203 barrels oil and 314 barrels NGLs). Six to eight additional test wells are planned for drilling in 2013.
Permian Division -
Range’s Permian team is targeting the Wolfberry and Cline Shale oil plays in West Texas. In the Wolfberry, Range completed three additional wells in the fourth quarter. The average 24-hour initial production rate for these wells was 521 (406 net) boe per day with 78% liquids (301 barrels oil, 104 barrels NGLs and 0.7 Mmcf gas). In addition to higher initial rates in the Wolfberry, drill and completion costs were reduced to $2.4 million for the most recent three wells. The six Wolfberry wells drilled to date are producing above our initial forecasts. In the Cline Shale, Range completed its third well in the fourth quarter. The initial 24-hour rate on this well was 620 (511 net) boe per day with 77% liquids (231 barrels oil, 249 barrels NGLs and 0.8 Mmcf gas). Range will continue to test these plays throughout 2013, while monitoring industry activity in an area where Range has approximately 100,000 net acres that are over 90% held by production.
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 fourth quarter. The division had one drilling rig and one completion rig running in the quarter and drilled 2 (2 net) tight gas sand wells and turned online 4 (4 net) wells. Despite spending only $29 million in capital in 2012, (down approximately 50% versus prior year), the division’s 2012 production rate was up 2% compared to 2011.
Guidance – First Quarter 2013
Production per day Guidance:
Production growth for 2013 is targeted at 20%-25% year-over-year. Production for the first quarter of 2013 is expected to range between 845 to 850 Mmcfe per day. Liquids are expected to be approximately 20% of first quarter production. Daily liquids production is expected to be slightly lower in the first quarter of 2013 compared to fourth quarter of 2012. This is the result of completion timing and the mix of wells being turned on. In the winter the Company typically completes fewer wells due to weather, as is typical in Appalachia. As a result of fewer completions and fewer wells being turned on, first quarter production will be relatively flat, while liquids will decline slightly. The relatively small set of wells being turned to sales in first quarter has some high-return dry gas wells which keeps that portion of the production growing in first quarter 2013. Range expects completions and wells being turned to sales to accelerate throughout the rest of the year and that activity is expected to be weighted toward the liquids-rich areas. As a result, Range is expecting liquids production growth during 2013 to be greater than the 20%-25% year-over-year overall production growth target.
Expense per mcfe Guidance:
| Direct operating expense: || || $0.38 - $0.40 per mcfe |
| Transportation, gathering and compression expense (a): || || $0.75 - $0.77 per mcfe |
| Production tax expense (b): || || $0.14 - $0.15 per mcfe |
| Exploration expense: || || $18 - $20 million |
| Unproved property impairment expense: || || $15 - $17 million |
| G&A expense: || || $0.40 - $0.42 per mcfe |
| Interest expense: || || $0.55 - $0.57 per mcfe |
| DD&A expense: || || $1.46 - $1.48 per mcfe |
(a) Prior to year-end 2011 this expense was netted against revenue. Please refer to Table 6 of the 4Q 2012 Supplement Tables for historical detail of this expense by product.
(b) Production tax expense in first quarter should equal approximately $0.07 per mcfe plus an estimated $6.2 million for the Pennsylvania impact fee. Total production tax expense including the impact fee is expected to be $0.14 - $0.15 per mcfe.
Differential Pricing History (c)
| || || 3Q 2011 || || 4Q 2011 || || 1Q 2012 || || 2Q 2012 || || 3Q 2012 || || 4Q 2012 |
| Natural Gas || || $ || 0.26 || || || $ || 0.07 || || || ($0.02 || ) || || ($0.13 || ) || || ($0.03 || ) || || $ || 0.18 || |
| NGL (% of WTI NYMEX) || || || 54 || % || || || 54 || % || || 48 || % || || 39 || % || || 33 || % || || || 43 || % |
| Oil (% of WTI NYMEX) || || || 91 || % || || || 92 || % || || 88 || % || || 91 || % || || 90 || % || || || 89 || % |
(c) Differentials based on pre-hedge pricing, excluding transportation, gathering and compression expense.
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