FORT WORTH, Texas--(BUSINESS WIRE)--RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its third quarter 2013 financial results.
Third Quarter Highlights –
- Record production of 960 Mmcfe per day, an increase of 21% over the prior-year quarter.
- Adjusted cash flow was $244 million, an increase of 29% as compared to the prior-year quarter.
- Unit costs were reduced 12% versus the prior-year quarter.
- Basin leading liquids-rich wells drilled in Pennsylvania continue to provide impressive results.
- Approximately 540,000 net acres of Range’s leasehold is in southwest Pennsylvania where the largest estimated gas in place (GIP) occurs when combining all three shale horizons.
- Range’s southwest and northeast Marcellus natural gas price realizations were $0.41 and $0.56 higher, respectively, than local pricing indices.
- Mariner West Project, exporting ethane to Sarnia, Canada, is expected to be fully operational in November.
- When all three ethane solutions are fully operational, based on today’s prices, Range’s average price for ethane would equate to a natural gas price of $4.13, net of transportation cost without considering the expected benefit of up to 8% additional propane recovery which could add a net $0.40 to $0.50 to an equivalent natural gas price.
Commenting on the announcement, Jeff Ventura, Range’s President and CEO, said, “Range continued to make significant progress during the third quarter, with record production results, lower unit costs, and materially higher cash flow. Our balance sheet, liquidity and cash flow growth positions us well to continue growing production 20% to 25% for many years. With the progress made during the first three quarters of 2013, we are focused on achieving the higher end of our production growth range for 2013 even with the sale of our New Mexico properties. The first delivery of ethane into the Mariner West pipeline to Sarnia, Canada commenced in July with intermittent deliveries and the project is expected to be fully operational in November. Once fully operational, Mariner West will allow us to continue our planned growth without concern for pipeline quality requirements for our residue gas. Our growth is led by our approximate one million acre leasehold position in Pennsylvania which essentially doubles when stacked pay reservoirs across most of our acreage in the Basin are considered. This acreage position is anchored by the Marcellus, the most prolific gas reservoir in North America. Based on the estimated gas in place (GIP) maps released by Range today, our southwest Pennsylvania acreage is strategically located at the nexus where the largest estimated gas in place exists when considering all three shale horizons. Range believes that this area also encompasses the core of the super-rich and wet areas of both the Marcellus and the Upper Devonian shales. We believe that our expected 20% to 25% production growth for many years, coupled with the high returns, low cost and low reinvestment risk will drive substantial per share value for our shareholders for years to come.”
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.)
GAAP revenues for the third quarter of 2013 totaled $442 million (a 47% increase as compared to third quarter 2012), GAAP net cash provided from operating activities including changes in working capital was $223 million (a 25% increase as compared to third quarter 2012) and GAAP earnings increased by 136% to $19 million ($0.12 per diluted share) versus a loss of $54 million ($0.34 per diluted share loss) in the third quarter 2012.
Non-GAAP revenues for third quarter 2013 totaled $433 million (a 21% increase as compared to third quarter 2012), cash flow from operations before changes in working capital, a non-GAAP measure, reached $244 million ($1.51 per diluted share, a 28% increase as compared to third quarter 2012). Adjusted net income, a non-GAAP measure, was $57 million ($0.35 per diluted share, a 75% increase as compared to third quarter 2012).
Several non-cash or non-recurring items impacted third quarter results. A $33.4 million mark-to-market commodity hedge loss was recognized for GAAP reporting along with a $6 million gain on sale of assets. An unproved property impairment expense of $11.7 million was recorded along with a $7 million proved property impairment on minor Gulf coast properties. A net expense of $3.7 million was incurred for blending the Company’s rich residue gas to meet pipeline quality requirements. A $13.2 million non-cash stock compensation expense was recorded while a reduction in deferred compensation expense of $2.2 million was recognized with the decrease in the common stock price between quarters.
Reviewing the Company’s six major expense categories, total unit costs decreased by $0.47 per mcfe or 12% compared to the prior-year quarter led by decreases in interest expense (-18%), general and administrative expense (-17%), direct operating expense (-15%), depreciation, depletion and amortization expense (-12%), and transportation, gathering and compression (-3%). Production and ad valorem tax expense rose 8% due to higher commodity prices.
As previously reported, third quarter production volumes reached a record high, averaging 960 Mmcfe per day, a 21% increase over the prior-year quarter. Year-over-year oil and condensate production increased 43%, natural gas liquids (“NGL”) production rose 28%, while natural gas production increased 19%. Adjusting for the sale of the New Mexico properties which closed on April 1, 2013 comprising production of approximately 18 Mmcfe per day at the time of sale, third quarter production would have increased 24% over the prior-year quarter with oil and condensate production increasing 58%, NGL production increasing 29% and natural gas production increasing 21%. The record production was driven by the continued success of the Company’s drilling program primarily in the Marcellus Shale. Realized prices, after adjustment for all cash-settled hedges, averaged $4.80 per mcfe, a 2% decrease from the prior-year period. Production and realized prices by each commodity for the third quarter were: natural gas – 739 Mmcf per day ($3.88 per mcf), NGLs – 25,678 barrels per day ($31.08 per barrel) and crude oil and condensate – 11,065 barrels per day ($85.46 per barrel).
See “Non-GAAP Financial Measures” for a definition of each of the non-GAAP financial measures discussed above and tables that reconcile each non-GAAP measure to its most directly comparable GAAP financial measure which are included in this release and on our website.
Capital Expenditures
Third quarter drilling expenditures of $258 million funded the drilling of 46 (45 net) wells and the completion of previously drilled wells. A 100% drilling success rate was achieved. In addition, during the third quarter, $39 million was expended on acreage purchases, $20 million on gas gathering systems and $20 million on exploration expense. The Company remains on track with its 2013 capital expenditure budget of approximately $1.3 billion.
Operational Discussion
Marcellus Shale Marketing and Transportation Update –
Currently, Range has contracts in place for approximately 1.0 Bcf per day of firm capacity increasing to 1.5 Bcf per day by 2015 at an average cost of $0.23 per Mmbtu. The term of these contracts is generally for 10 years, the majority of which are renewable at the expiration date at the option of Range. Importantly, the majority of Range’s Marcellus activity is located in southwest Pennsylvania where six of the largest pipelines in Appalachia are located and pass through. This significant amount of existing infrastructure has allowed Range to secure firm transportation at rates of approximately $0.20 to $0.25 per Mmbtu. Range expects that future transportation capacity will be added at similar rates utilizing existing infrastructure. Range’s objective is to layer in additional firm commitments that match the Company’s increasing production volumes. To this end, Range has already contracted for an additional 200 Mmcf per day of capacity for 2017. The Company is also in discussions for additional firm capacity on several large takeaway systems. These future capacity expansions, to multiple markets outside the Appalachian region, will support our growth while maximizing net realized natural gas prices.
In addition to the Company’s own firm capacity, Range utilizes firm sales arrangements with buyers who have their own firm transportation. For 2013, Range expects its firm sales contracts covering Marcellus gas production will average approximately 300 Mmcf per day. These contracts generally have terms of 12 to 24 months. As with firm transportation contracts, Range expects to extend and add to these firm sales contracts as production grows. Range plans to continue using a strategy whereby approximately 60% of its Marcellus natural gas volumes are sold under the Company’s own firm transportation and the remainder will be sold under firm sales arrangements where the purchaser owns firm transportation. This strategy, combined with the Company’s access to multiple markets outside of Appalachia, allows Range the flexibility of flowing gas to multiple markets at reasonable costs and maximizing its price realizations rather than being limited solely to the local markets.
Third quarter 2013 Marcellus realizations were a reflection of this strategy as the Company received prices greater than the local markets. Range’s realized average natural gas price for all its Marcellus natural gas production was $0.06 below the NYMEX Henry Hub benchmark price for the quarter. By region, Range’s realized prices were $0.41 better than the average of the TCO, DTI and TETCO M2 index prices in southwest Pennsylvania and were $0.56 better than the average of the Leidy/Transco index price for the third quarter in northeast Pennsylvania.
Mariner West Project-
Mariner West is expected to be fully operational in November. Pipeline testing and line fill has been ongoing since July. The project has several benefits to Range, including:
1. Removal of ethane from the gas stream, allowing Range to meet pipeline specifications and continue to grow southwest Pennsylvania wet gas volumes.
2. Current base pricing FOB at the Houston, Pennsylvania plant, is attractive.
3. Ethane extraction results in up to an additional 8% increase in propane volumes which carry a more attractive net back price.
Range’s Marketing Plan-
Range is the largest producer of wet gas in the Appalachian Basin, with the most comprehensive and diversified plan to move our growing volumes of gas, NGLs and condensate. Our existing contracts and commitments are intended to ensure we can move our products to new and growing markets at prices greater than the local markets. Our innovative portfolio of ethane marketing arrangements, the result of many years of negotiation and planning, demonstrate this. The three contracts include two long-term sales contracts providing export of ethane to two international destinations, Canada and Europe, plus a transportation agreement to the Gulf Coast. We believe that if these three marketing arrangements were fully operational today, based on today’s prices, our average price for ethane would equate to a natural gas price of $4.13, net of transportation cost without considering the expected benefit of up to 8% additional propane recovery, which at today’s prices could add a net $0.40 to $0.50 to an equivalent natural gas price. In addition, propane exports from the Marcus Hook facility in Philadelphia have started, with additional sales expected both locally and internationally, when the Mariner East project becomes operational in 2014.
Marcellus Shale–
Marcellus production for the third quarter averaged approximately 900 (756 net) Mmcfe net per day. Marcellus production for the first nine months of 2013 averaged approximately 855 (718 net) Mmcfe net per day, which represents a 40% increase on a year to date comparison to 2012.
Range has updated its investor presentation with gas in place (GIP) maps for the Appalachian Basin reflecting the individual and combined Marcellus, Upper Devonian and Utica/Point Pleasant Shales. Please see www.rangeresources.com under the Investor Relations tab, “Presentations and Webcasts” area, for the presentation entitled, “Company Presentation – October 29, 2013.” The maps reflect our view that the estimated greatest GIP accumulation in these respective shales is located in the southwestern portion of Pennsylvania. This mapping of GIP has been a key driver for Range concentrating its acreage position in this area to take advantage of the multiple stacked horizons, complemented by the core liquid rich areas of the Marcellus and Upper Devonian shales.
Southern Marcellus Shale Division –
Range estimates that its acreage in southwest Pennsylvania is amongst the core of the Appalachian Basin based on well results and gas in place estimates. During the third quarter, the division brought online 26 Marcellus wells in this area, with 24 wells in the super-rich area, and two wells in the dry gas area.
In the super-rich area of southwest Pennsylvania the division brought online 24 (23 net) wells in the third quarter. The initial 24-hour production rates of these super-rich wells averaged 2,657 (2,122 net) boe per day with 66% liquids assuming 80% ethane extraction. All of the wells in the quarter were completed with reduced cluster spacing. The average lateral length for the wells was 4,030 feet and they averaged 21 frac stages per lateral. The higher initial production rates and higher expected recoveries are a result of improved targeting and completion techniques that are now being applied by Range across all areas of the play. The performance of the 17 super-rich wells, that were announced earlier this year, continues to impress. Now having been on line 240 days, these wells are 43% above the 1.32 Mmboe type curve. (The Company has included in its current corporate presentation an updated zero time plot covering these super-rich wells.)
Range’s best well in the super-rich area, announced last quarter, had an initial 24-hour production rate of 5,720 boe per day with 63% liquids assuming 80% ethane extraction. The well produced an average 30-day rate of 2,700 boe per day with 61% liquids, and an average 60-day rate of 2,121 boe per day with 60% liquids assuming 80% ethane extraction. Among liquids rich wells, with initial production of 60% liquids or greater, Range believes that it has drilled five of the top ten producing wells in the Appalachian Basin. Normalizing results, on a per 1,000 lateral foot basis, Range has drilled eight of the top ten liquids rich producing wells.
At quarter-end the division’s backlog of wells waiting on pipeline connection decreased to 11 wells. Range expects to turn to sales a total of 125 wells in the southern Marcellus during 2013. Range continues to minimize the number of wells drilled but waiting on pipeline connection allowing for better utilization of capital spent.
Northern Marcellus Shale Division –
In northeast Pennsylvania, Range brought online 10 wells in the third quarter including a step-out well in Lycoming County that had a 24-hour initial production rate of 22.9 (19.7 net) Mmcf per day. The 30-day average rate for the same well was 15 (12.9) Mmcf per day. In 60 days the well has produced over 750 Mmcf. Two more wells on the same pad were recently turned to sales under constrained conditions at a combined rate of 42 (36.1 net) Mmcf per day. The three wells on the pad have an average lateral length of about 5,000 feet and 23 frac stages. The division’s backlog of wells waiting on pipeline connection declined to 13 at quarter-end. Range anticipates drilling another four wells during the remainder of 2013 and turning an additional 9 wells to sales.
At the end of the third quarter, in the Bradford County area operated by Talisman, there were a total of 38 (11.2 net) wells producing and 31 (9.1 net) wells waiting on completion or pipeline connection.
Midcontinent Division –
During the third quarter, the Midcontinent division continued to focus on Range’s horizontal Mississippian acreage along the Nemaha Ridge. Initially, activity has been concentrated across the southern portion of the Company’s acreage position. In October, Range completed a 12 mile northern step-out well that had an initial 7-day production of over 300 barrels of oil per day and an average 30-day rate of 330 boe per day with 94% liquids (85% oil and 9% NGLs). The division tested completions with larger frac stimulations on four wells that averaged production rates 45% above the 600 Mboe type curve for the first 65 days. Results from wells completed with the larger fracs continue to significantly exceed results seen from wells drilled in the early part of 2013 that were completed with smaller fracs. A total of 7 (6.8 net) wells were turned to sales during the quarter with average lateral lengths of 3,742 feet with 21 frac stages. The initial production on these wells averaged 622 (493 net) boe per day with 75% liquids and is the highest average for any quarter to date. Despite the larger fracs, Range has been able to drill and complete the wells at the same cost of $3.2 million. Range anticipates bringing online four additional horizontal Mississippian wells with larger frac stimulations during the fourth quarter.
Range also turned to sales two St. Louis wells during the quarter with a 24-hour initial combined production rate of 20.5 (13.4 net) Mmcfe per day with 28% liquids. The Company expects to drill another two wells in that area during the fourth quarter.
Permian Division –
Range’s Permian division turned to sales six additional vertical Wolfberry wells in the third quarter of 2013. Average 24-hour initial production rates were 324 (243 net) boe per day with 77% liquids. During the remainder of the year, Range has drilled and is currently completing both a Cline and a Wolfcamp horizontal well with 7,000 foot laterals.
Southern Appalachia Division –
The Southern Appalachia division continued development of multi-pay horizons on its 350,000 (250,000 net) acre position in Virginia. Range owns the fee minerals on 216,000 acres of this position and receives the added economic benefit of the royalty for wells drilled on this acreage. Range drilled two horizontal Huron Shale wells, and turned to sales five wells during the third quarter. The Company expects to turn to sales another three wells during the remainder of 2013.
Guidance
Production Guidance:
Production growth for 2013 is now targeted to the higher end of our original 20% to 25% year-over-year guidance. Production for the fourth quarter of 2013 is expected to average approximately 1.0 Bcfe per day with 25% liquids.
Guidance for 2013 Activity:
Under the current plan, Range expects to turn to sales approximately 196 net wells in the Marcellus and Horizontal Mississippian during 2013, as shown below. A number of the wells expected to be turned to sales in the fourth quarter are expected to occur just before year-end, and therefore will not have a material impact on production for the quarter.
|
Year to Date |
Expected |
Total Planned |
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| Super-Rich area | 63 | 18 | 81 | |||
| Wet area | 15 | 10 | 25 | |||
| Dry area (NE & SW) | 40 | 11 | 51 | |||
| Total Marcellus | 118 | 39 | 157 | |||
| Hz. Mississippian | 35 | 4 | 39 | |||
| Total | 153 | 43 | 196 |
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Expense per mcfe 4Q 2013 Guidance: |
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|
Direct operating expense: |
$0.34 - $0.36 per mcfe |
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|
Transportation, gathering and compression expense: |
$0.77 - $0.79 per mcfe |
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Production tax expense: |
$0.14 - $0.15 per mcfe |
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|
Exploration expense: |
$16 - $17 million |
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Unproved property impairment expense: |
$14 - $16 million |
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G&A expense: |
$0.39 - $0.41 per mcfe |
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|
Interest expense: |
$0.49 - $0.50 per mcfe |
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|
DD&A expense: |
$1.46 - $1.48 per mcfe |
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Total Corporate Differential Pricing History (a) |
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| 2Q 2012 | 3Q 2012 | 4Q 2012 | 1Q 2013 | 2Q 2013 | 3Q 2013 | |||||||||||||||||
| Natural Gas | ($0.13 | ) | ($0.03 | ) | $ | 0.18 | $ | 0.15 | $ | 0.04 | ($0.17 | ) | ||||||||||
| NGL (% of WTI NYMEX) | 39 | % | 33 | % | 43 | % | 38 | % | 33 | % | 31 | % | ||||||||||
| Oil (% of WTI NYMEX) | 91 | % | 90 | % | 89 | % | 90 | % | 89 | % | 87 | % | ||||||||||
(a) Differentials based on pre-hedge pricing, excluding transportation, gathering and compression expense.
Hedging Status
Range hedges portions of its expected future production volumes to increase the predictability of cash flow and to help maintain a strong, flexible financial position. Range currently has over 75% of its expected remaining 2013 natural gas production hedged at a weighted average floor price of $4.20 per mcf. Similarly, Range has hedged more than 80% of its projected remaining crude oil production at a floor price of $94.90 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 www.rangeresources.com.
Effective March 1, 2013, Range elected to discontinue hedge accounting for derivative contracts and moved to mark-to-market accounting for its derivative contracts. The mark-to-market accounting treatment may create fluctuations in earnings as commodity prices change both positively and negatively, however, such mark-to-market adjustments have no cash flow impact. The impact to cash flow will occur as the underlying contracts are settled. As of October 1, 2013, the Company expects to reclassify into earnings $22.1 million of unrealized net gains frozen in the first quarter with discontinuance of hedge accounting in the remaining three months of 2013 and $10.2 million of unrealized net gains in 2014.
Conference Call Information
A conference call to review the financial results is scheduled on Wednesday, October 30 at 09:00 a.m. ET. To participate in the call, please dial 877-407-0778 and ask for the Range Resources third quarter 2013 financial results conference call. A replay of the call will be available through November 30, 2013. To access the phone replay dial 877-660-6853. The conference ID is 100298.
A simultaneous webcast of the call may be accessed over the Internet at http://www.rangeresources.com. The webcast will be archived for replay on the Company's website until November 30, 2013.
Non-GAAP Financial Measures:
Adjusted net income comparable to analysts’ estimates as set forth in this release represents income or loss from operations before income taxes adjusted for certain non-cash items (detailed below and in the accompanying table) less income taxes. We believe adjusted net income comparable to analysts’ estimates is calculated on the same basis as analysts’ estimates and that many investors use this published research in making investment decisions useful in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Diluted earnings per share (adjusted) as set forth in this release represents adjusted net income comparable to analysts’ estimates on a diluted per share basis. A table is included which reconciles income or loss from operations to adjusted net income comparable to analysts’ estimates and diluted earnings per share (adjusted). On its website, the Company provides additional comparative information on prior periods along with non-GAAP revenue disclosures.
Third quarter 2013 earnings included a loss of $33.4 million for the non-cash unrealized mark-to-market decrease in value of the Company’s derivatives, unproved property impairment expense of $11.7 million, a $2.2 million gain recorded for the mark-to-market valuation in the deferred compensation plan, $13.2 million of non-cash stock compensation expenses, and a $7 million proved property impairment on some minor properties on the Gulf coast. A net expense of $3.7 million was also incurred for blending the Company’s rich residue gas to meet pipeline quality requirements. Excluding these and other items, net income would have been $57.0 million or $0.35 per diluted share. Excluding similar non-cash items from the prior-year quarter, net income would have been $32.0 million or $0.20 per diluted share. By excluding these non-cash items from our reported earnings, we believe we present our earnings in a manner consistent with the presentation used by analysts in their projection of the Company’s earnings. (See the reconciliation of non-GAAP earnings in the accompanying table.)
Cash flow from operations before changes in working capital as defined in this release represents net cash provided by operations before changes in working capital and exploration expense adjusted for certain non-cash compensation items. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company’s ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operations, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity. A table is included which reconciles “Net cash provided by operations” to “Cash flow from operations before changes in working capital” as used in this release. On its website, the Company provides additional comparative information on prior periods for cash flow, cash margins and non-GAAP earnings as used in this release.
The cash prices realized for oil and natural gas production including the amounts realized on cash-settled derivatives and net of transportation, gathering and compression expense 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 derivative transactions and third party transportation, gathering and compression expense, such information is now reported in various lines of the income statement. The Company believes that it is important to furnish a table reflecting the details of the various components of each income statement line to better inform the reader of the details of each amount and provide a summary of the realized cash-settled amounts and third party transportation, gathering and compression expense 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 unaudited 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
As discussed in this news release, Range has reclassified within total revenues its financial reporting of the cash settlement of its commodity derivatives. Under this presentation, those hedges considered “effective” under ASC 815 are included in “Natural gas, NGLs and oil sales” when settled. For undesignated hedges and those hedges designated to regions where the historical correlation between NYMEX and regional prices is “non-highly effective” or is “volumetric ineffective” due to sale of the underlying reserves, they are deemed to be “derivatives” and the cash settlements are included in a separate line item shown as “Derivative fair value income (loss)” in the consolidated statements of operations included in the Company’s Form 10-Q along with the change in mark-to-market valuations of such unrealized derivatives. Effective March 1, 2013 the Company de-designated all commodity contracts and elected to discontinue hedge accounting prospectively. 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 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/.
All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future liquidity, production growth, completion of ethane projects, resolution of pipeline quality requirements, estimated gas in place, future rates of return, future low costs, low reinvestment risk, earnings and per-share value, capital spending plans, firm capacity contract renewals, future transportation capacity rates, continued utilization of existing infrastructure, gas marketability, firm sales contract renewals, maximized realized natural gas prices, acreage quality, access to multiple gas markets, expected drilling and development plans, improved capital efficiency, future financial position and future 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 our hedging transactions, the costs and results of actual drilling and operations, the timing of production, mechanical and other inherent risks associated with oil and gas production, weather, the availability of drilling equipment, changes in interest rates, litigation, uncertainties about reserve estimates, environmental risks and regulatory changes. Range undertakes no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in Range's filings with the Securities and Exchange Commission ("SEC"), which are incorporated by reference.
The SEC permits oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions as well as the option to disclose probable and possible reserves. Range has elected not to disclose the Company’s probable and possible reserves in its filings with the SEC. Range uses certain broader terms such as “resource potential,” or “unproved resource potential” or “upside” or other descriptions of volumes of resources potentially recoverable through additional drilling or recovery techniques that may include probable and possible reserves as defined by the SEC's guidelines. Range has not attempted to distinguish probable and possible reserves from these broader classifications. The SEC’s rules prohibit us from including in filings with the SEC these broader classifications of reserves. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. Unproved resource potential refers to Range's internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques and have not been reviewed by independent engineers. Unproved resource potential and gas in place do not constitute reserves within the meaning of the Society of Petroleum Engineer's Petroleum Resource Management System and does not include proved reserves. Area wide unproven resource potential and gas in place has not been fully risked by Range's management. “Gas in place” is merely an indication of the size of a hydrocarbon reservoir and is not an indication of reserves or the quantity of natural gas that is likely to be produced. You should not assume that estimates of gas in place are comparable to proved reserves or representative of estimates of future production from our properties. It is not possible to measure gas in place in an exact way, and estimating gas in place is inherently uncertain. Gas in place has been estimated based on subjective analysis of geological and other relevant data applicable to our properties, including assumptions regarding area, thickness, porosity and saturation. Changes in these factors or inaccuracies in our assumptions could materially alter the estimates of gas in place. “EUR,” or estimated ultimate recovery, refers to our management’s estimates of hydrocarbon quantities that may be recovered from a well completed as a producer in the area. These quantities may 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. Actual quantities that may be recovered from Range's interests could 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. Actual quantities that may be recovered from Range’s interests could differ substantially from estimates disclosed. Estimates of resource potential may change significantly as development of our resource plays provides additional data. Investors are urged to consider closely the disclosure in our most recent Annual Report on Form 10-K, available from our website at www.rangeresources.com or by written request to 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. You can also obtain this Form 10-K by calling the SEC at 1-800-SEC-0330.
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. Investors are urged to consider closely the disclosure in our most recent Annual Report on Form 10-K, available from our website at www.rangeresources.com or by written request to 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. You can also obtain this Form 10-K by calling the SEC at 1-800-SEC-0330.
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RANGE RESOURCES CORPORATION |
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| 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, | ||||||||||||||||||||||
| 2013 | 2012 | % | 2013 | 2012 | % | ||||||||||||||||||
| Revenues and other income: | |||||||||||||||||||||||
| Natural gas, NGLs and oil sales (a) | $ | 431,214 | $ | 337,040 | $ | 1,267,131 | $ | 953,006 | |||||||||||||||
| Realized (loss) gain on settlement (a) (c) | (6,951 | ) | 17,625 | (28,335 | ) | 21,994 | |||||||||||||||||
| Change in fair value of derivatives that did not qualify or | (34,219 | ) | (53,646 | ) | |||||||||||||||||||
| were not designated for hedge accounting (c) | 28,350 | 30,075 | |||||||||||||||||||||
| Hedge ineffectiveness (loss) gain (c) | 815 | (4,707 | ) | (2,485 | ) | (5,061 | ) | ||||||||||||||||
| Gain (loss) on sale of assets | 6,008 | 949 | 89,129 | (12,704 | ) | ||||||||||||||||||
| Brokered natural gas, marketing and other | 9,213 | 3,449 | 40,737 | 12,130 | |||||||||||||||||||
| Brokered natural gas - blending (d) | 36,278 | - | 40,216 | - | |||||||||||||||||||
| Equity method investment (d) | 268 | (1,012 | ) | 541 | (195 | ) | |||||||||||||||||
| Other (d) | (588 | ) | 82 | (651 | ) | 421 | |||||||||||||||||
| Total revenues and other income | 442,038 | 299,780 | 47 | % | 1,434,633 | 999,666 | 44 | % | |||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||
| Direct operating | 30,208 | 29,030 | 91,675 | 84,044 | |||||||||||||||||||
| Direct operating – non-cash stock compensation (b) | 699 | 598 | 2,056 | 1,647 | |||||||||||||||||||
| Transportation, gathering and compression | 60,958 | 51,600 | 189,422 | 137,164 | |||||||||||||||||||
| Production and ad valorem taxes | 11,454 | 8,819 | 33,950 | 32,532 | |||||||||||||||||||
| Pennsylvania impact fee - prior year | - | - | - | 24,707 | |||||||||||||||||||
| Brokered natural gas and marketing | 10,588 | 4,435 | 44,769 | 14,127 | |||||||||||||||||||
| Brokered natural gas and marketing – non-cash stock- | |||||||||||||||||||||||
| based compensation (b) | 531 | 452 | 1,310 | 1,313 | |||||||||||||||||||
| Brokered natural gas and marketing – blending | 39,998 | - | 44,015 | - | |||||||||||||||||||
| Exploration | 19,513 | 13,626 | 47,331 | 48,737 | |||||||||||||||||||
| Exploration – non-cash stock compensation (b) | 983 | 1,126 | 3,013 | 3,048 | |||||||||||||||||||
| Abandonment and impairment of unproved properties | 11,692 | 40,118 | 46,066 | 104,048 | |||||||||||||||||||
| General and administrative | 33,564 | 33,333 | 104,525 | 93,953 | |||||||||||||||||||
| General and administrative – non-cash stock | 11,031 | 10,057 | |||||||||||||||||||||
| compensation (b) | 34,600 | 30,755 | |||||||||||||||||||||
| General and administrative – lawsuit settlements | 324 | 1,107 | 91,589 | 2,523 | |||||||||||||||||||
| General and administrative – bad debt expense | - | - | 250 | - | |||||||||||||||||||
| Deferred compensation plan (e) | (2,225 | ) | 20,052 | 33,257 | 21,555 | ||||||||||||||||||
| Interest expense | 44,321 | 43,997 | 131,602 | 124,090 | |||||||||||||||||||
| Loss on early extinguishment of debt | - | - | 12,280 | - | |||||||||||||||||||
| Depletion, depreciation and amortization | 130,343 | 123,059 | 365,439 | 332,012 | |||||||||||||||||||
| Impairment of proved properties and other assets | 7,012 | 1,281 | 7,753 | 1,281 | |||||||||||||||||||
| Total costs and expenses | 410,994 | 382,690 | 7 | % | 1,284,902 | 1,057,536 | 21 | % | |||||||||||||||
| Income (loss) from operations before income taxes | 31,044 | (82,910 | ) | 137 | % | 149,731 | (57,870 | ) | 359 | % | |||||||||||||
| Income tax expense (benefit): | |||||||||||||||||||||||
| Current | - | - | - | - | |||||||||||||||||||
| Deferred | 11,866 | (29,074 | ) | 62,180 | (17,910 | ) | |||||||||||||||||
| 11,866 | (29,074 | ) | 62,180 | (17,910 | ) | ||||||||||||||||||
| Net income (loss) | $ | 19,178 | $ | (53,836 | ) | 136 | % | $ | 87,551 | $ | (39,960 | ) | 319 | % | |||||||||
| Net Income (Loss) Per Common Share: | |||||||||||||||||||||||
| Basic | $ | 0.12 | $ | (0.34 | ) | $ | 0.54 | $ | (0.25 | ) | |||||||||||||
| Diluted | $ | 0.12 | $ | (0.34 | ) | $ | 0.53 | $ | (0.25 | ) | |||||||||||||
| Weighted average common shares outstanding, as reported: | |||||||||||||||||||||||
| Basic | 160,500 | 159,563 | 1 | % | 160,398 | 159,297 | 1 | % | |||||||||||||||
| Diluted | 161,374 | 159,563 | 1 | % | 161,321 | 159,297 | 1 | % | |||||||||||||||
(a) See separate natural gas, NGLs and oil sales information table.
(b) Costs associated with stock compensation and restricted stock amortization, which have been reflected in the categories associated with the direct personnel costs, which are combined with the cash costs in the 10-Q.
(c) Included in Derivative fair value income in the 10-Q.
(d) Included in Brokered natural gas, marketing and other revenues in the 10-Q.
(e) Reflects the change in market value of the vested Company stock held in the deferred compensation plan.
|
RANGE RESOURCES CORPORATION |
||||||||
| BALANCE SHEETS | ||||||||
| (In thousands) | September 30, | December 31, | ||||||
| 2013 | 2012 | |||||||
| (Unaudited) | (Audited) | |||||||
| Assets | ||||||||
| Current assets | $ | 164,560 | $ | 190,062 | ||||
| Unrealized derivatives | 55,993 | 137,552 | ||||||
| Deferred tax asset | 2,179 | - | ||||||
| Natural gas and oil properties, successful efforts method | 6,507,304 | 6,096,184 | ||||||
| Transportation and field assets | 34,914 | 41,567 | ||||||
| Other assets | 265,680 | 263,370 | ||||||
| $ | 7,030,630 | $ | 6,728,735 | |||||
| Liabilities and Stockholders’ Equity | ||||||||
| Current liabilities | $ | 443,246 | $ | 448,202 | ||||
| Asset retirement obligations | 2,366 | 2,470 | ||||||
| Unrealized derivatives | 7,971 | 4,471 | ||||||
| Bank debt | 427,000 | 739,000 | ||||||
| Subordinated notes | 2,640,170 | 2,139,185 | ||||||
| 3,067,170 | 2,878,185 | |||||||
| Deferred tax liability | 759,556 | 698,302 | ||||||
| Unrealized derivatives | 103 | 3,463 | ||||||
| Deferred compensation liability | 207,404 | 187,604 | ||||||
| Asset retirement obligation & other liabilities | 151,813 | 148,646 | ||||||
| 1,118,876 | 1,038,015 | |||||||
| Common stock and retained earnings | 2,375,019 | 2,278,243 | ||||||
| Common stock held in treasury | (3,751 | ) | (4,760 | ) | ||||
| Accumulated other comprehensive income | 19,733 | 83,909 | ||||||
| Total stockholders’ equity | 2,391,001 | 2,357,392 | ||||||
| $ | 7,030,630 | $ | 6,728,735 | |||||
| RECONCILIATION OF TOTAL REVENUES AND | ||||||||||||||||||||||
|
OTHER INCOME TO TOTAL REVENUE EXCLUDING |
||||||||||||||||||||||
|
CERTAIN ITEMS, a non-GAAP measure |
||||||||||||||||||||||
| (Unaudited, in thousands) | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| 2013 | 2012 | % | 2013 | 2012 | % | |||||||||||||||||
| Total revenues and other income, as reported | $ | 442,038 | $ | 299,780 | 47 | % | $ | 1,434,633 | $ | 999,666 | 44 | % | ||||||||||
| Adjustment for certain special items: | ||||||||||||||||||||||
|
Change in fair value of derivatives that did not qualify or were
not designated for hedge accounting |
34,219 | 53,646 | (28,350 | ) | (30,075 | ) | ||||||||||||||||
| Hedge ineffectiveness (gain) loss | (815 | ) | 4,707 | 2,485 | 5,061 | |||||||||||||||||
| (Gain) loss on sale of assets | (6,008 | ) | (949 | ) | (89,129 | ) | 12,704 | |||||||||||||||
| Brokered natural gas - blending | (36,278 | ) | - | (40,216 | ) | - | ||||||||||||||||
| Total revenue, as adjusted, non-GAAP | $ | 433,156 | $ | 357,184 | 21 | % | $ | 1,279,423 | $ | 987,356 | 30 | % | ||||||||||
|
RANGE RESOURCES CORPORATION |
||||||||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||||||
| (Unaudited, in thousands) | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||
| Net income (loss) | $ | 19,178 | $ | (53,836 | ) | $ | 87,551 | $ | (39,960 | ) | ||||||
| Adjustments to reconcile net income (loss) to net cash provided from operating activities: | ||||||||||||||||
| (Gain) Loss from equity method investment, net of distributions | 378 | (41 | ) | (1,174 | ) | 2,252 | ||||||||||
| Deferred income tax expense (benefit) | 11,866 | (29,074 | ) | 62,180 | (17,910 | ) | ||||||||||
| Depletion, depreciation, amortization and impairment | 137,355 | 124,340 | 373,192 | 333,293 | ||||||||||||
| Exploration dry hole costs | 4,063 | 15 | 3,904 | 832 | ||||||||||||
| Abandonment and impairment of unproved properties | 11,692 | 40,118 | 46,066 | 104,048 | ||||||||||||
| Mark-to-market on natural gas, NGLs and oil derivatives not designated as hedges | 34,219 | 53,645 | (28,350 | ) | (30,076 | ) | ||||||||||
| Unrealized derivatives (gain) loss | (815 | ) | 4,707 | 2,485 | 5,061 | |||||||||||
| Allowance for bad debts | - | - | 250 | - | ||||||||||||
| Amortization of deferred issuance costs, loss on extinguishment of debt and other | 3,073 | 2,077 | 19,735 | 5,970 | ||||||||||||
| Deferred and stock-based compensation | 10,862 | 32,232 | 74,187 | 58,573 | ||||||||||||
| Gain (loss) on sale of assets | (6,008 | ) | (949 | ) | (89,129 | ) | 12,704 | |||||||||
| Changes in working capital: | ||||||||||||||||
| Accounts receivable | 7,491 | (21,090 | ) | (6,506 | ) | (9,479 | ) | |||||||||
| Inventory and other | 1,714 | (2,570 | ) | 3,259 | (5,394 | ) | ||||||||||
| Accounts payable | (18,853 | ) | 32,996 | (29,234 | ) | 11,074 | ||||||||||
| Accrued liabilities and other | 6,762 | (4,393 | ) | (15,550 | ) | 30,135 | ||||||||||
| Net changes in working capital | (2,886 | ) | 4,943 | (48,031 | ) | 26,336 | ||||||||||
| Net cash provided from operating activities | $ | 222,977 | $ | 178,177 | $ | 502,866 | $ | 461,123 | ||||||||
| 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, | ||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||
| Net cash provided from operating activities, as reported | $ | 222,977 | $ | 178,177 | $ | 502,866 | $ | 461,123 | ||||||||
| Net changes in working capital | 2,886 | (4,943 | ) | 48,031 | (26,336 | ) | ||||||||||
| Exploration | 15,450 | 13,611 | 43,427 | 47,905 | ||||||||||||
| Lawsuit settlements | 324 | 1,107 | 91,589 | 2,523 | ||||||||||||
| Equity method investment distribution / intercompany elimination | (646 | ) | 1,053 | 632 | (2,057 | ) | ||||||||||
| Loss on gas blending | 3,720 | - | 3,799 | - | ||||||||||||
| Prior year Pennsylvania impact fee | - | - | - | 24,707 | ||||||||||||
| Non-cash compensation adjustment | (619 | ) | 146 | (578 | ) | 3 | ||||||||||
| Cash flow from operation before changes in working capital, a non-GAAP measure | $ | 244,092 | $ | 189,151 | $ | 689,766 | $ | 507,868 | ||||||||
| ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING | ||||||||||||||||
| (Unaudited, in thousands) | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||||||||
| Basic: | ||||||||||||||||
| Weighted average shares outstanding | 163,407 | 162,527 | 163,155 | 162,198 | ||||||||||||
| Stock held by deferred compensation plan | (2,907 | ) | (2,964 | ) | (2,757 | ) | (2,901 | ) | ||||||||
| Total reported | 160,500 | 159,563 | 160,398 | 159,297 | ||||||||||||
| Dilutive: | ||||||||||||||||
| Weighted average shares outstanding | 163,407 | 162,527 | 163,155 | 162,198 | ||||||||||||
| Dilutive stock options under treasury method | (2,033 | ) | (2,964 | ) | (1,834 | ) | (2,901 | ) | ||||||||
| Total reported | 161,374 | 159,563 | 161,321 | 159,297 | ||||||||||||
|
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) | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| 2013 | 2012 | % | 2013 | 2012 | % | |||||||||||||||||
| Natural gas, NGLs and Oil Sales components: | ||||||||||||||||||||||
| Natural gas sales | $ | 233,019 | $ | 159,525 | $ | 718,176 | $ | 399,006 | ||||||||||||||
| NGLs sales | 77,317 | 56,826 | 211,475 | 189,604 | ||||||||||||||||||
| Oil sales | 93,473 | 59,221 | 243,057 | 166,718 | ||||||||||||||||||
| Cash-settled hedges (effective): | ||||||||||||||||||||||
| Natural Gas | 25,870 | 62,150 | 90,693 | 198,675 | ||||||||||||||||||
| Crude Oil | 1,535 | (682 | ) | 3,730 | (997 | ) | ||||||||||||||||
| Total Oil and Gas Sales, as reported | $ | 431,214 | $ | 337,040 | 28 | % | $ | 1,267,131 | $ | 953,006 | 33 | % | ||||||||||
| Derivative Fair Value Income (Loss) components: | ||||||||||||||||||||||
| Realized gain (loss) on settlement: | ||||||||||||||||||||||
| Natural Gas | $ | 4,961 | $ | 988 | $ | (18,358 | ) | $ | 3,451 | |||||||||||||
| NGLs | (3,907 | ) | 14,682 | (1,759 | ) | 20,442 | ||||||||||||||||
| Crude Oil | (8,005 | ) | 1,955 | (8,218 | ) | (1,899 | ) | |||||||||||||||
|
Change in fair value of derivatives that did not qualify or were not designated for hedge accounting
|
(34,219 | ) | (53,646 | ) | 28,350 | 30,075 | ||||||||||||||||
| Unrealized hedge ineffectiveness | 815 | (4,707 | ) | (2,485 | ) | (5,061 | ) | |||||||||||||||
| Total Derivative Fair Value Income (Loss), as reported | $ | (40,355 | ) | $ | (40,728 | ) | $ | (2,470 | ) | $ | 47,008 | |||||||||||
| Transportation, Gathering and Compression components: | ||||||||||||||||||||||
| Natural Gas | $ | 57,576 | $ | 48,737 | $ | 179,571 | $ | 129,411 | ||||||||||||||
| NGLs | 3,382 | 2,863 | 9,851 | 7,753 | ||||||||||||||||||
| Total transportation, gathering and compression, as reported | $ | 60,958 | $ | 51,600 | $ | 189,422 | $ | 137,164 | ||||||||||||||
| Natural gas, NGL and Oil sales, including cash-settled derivatives (c): | ||||||||||||||||||||||
| Natural Gas Sales | $ | 263,850 | $ | 222,663 | $ | 790,511 | $ | 601,132 | ||||||||||||||
| NGL Sales | 73,410 | 71,508 | 209,716 | 210,046 | ||||||||||||||||||
| Oil Sales | 87,003 | 60,494 | 238,569 | 163,822 | ||||||||||||||||||
| Total | $ | 424,263 | $ | 354,665 | 20 | % | $ | 1,238,796 | $ | 975,000 | 27 | % | ||||||||||
| Production of Oil and Gas during the periods (a): | ||||||||||||||||||||||
| Natural Gas (mcf) | 68,024,813 | 57,347,638 | 19 | % | 194,975,047 | 156,274,072 | 25 | % | ||||||||||||||
| NGL (bbl) | 2,362,340 | 1,843,667 | 28 | % | 6,367,253 | 4,975,086 | 28 | % | ||||||||||||||
| Oil (bbl) | 1,018,013 | 712,858 | 43 | % | 2,795,192 | 1,943,961 | 44 | % | ||||||||||||||
| Gas equivalent (mcfe) (b) | 88,306,931 | 72,686,788 | 21 | % | 249,979,717 | 197,788,354 | 26 | % | ||||||||||||||
| Production of Oil and Gas – average per day (a): | ||||||||||||||||||||||
| Natural Gas (mcf) | 739,400 | 623,344 | 19 | % | 714,194 | 570,343 | 25 | % | ||||||||||||||
| NGL (bbl) | 25,678 | 20,040 | 28 | % | 23,323 | 18,157 | 28 | % | ||||||||||||||
| Oil (bbl) | 11,065 | 7,748 | 43 | % | 10,239 | 7,095 | 44 | % | ||||||||||||||
| Gas equivalent (mcfe) (b) | 959,858 | 790,074 | 21 | % | 915,567 | 721,855 | 27 | % | ||||||||||||||
| Average prices, including cash settled hedges that qualify for hedge accounting before third party transportation costs: (c) | ||||||||||||||||||||||
| Natural Gas (mcf) | $ | 3.81 | $ | 3.87 | -2 | % | $ | 4.15 | $ | 3.82 | 8 | % | ||||||||||
| NGL (bbl) | $ | 32.73 | $ | 30.82 | 6 | % | $ | 33.21 | $ | 38.11 | -13 | % | ||||||||||
| Oil (bbl) | $ | 93.33 | $ | 82.12 | 14 | % | $ | 88.29 | $ | 85.25 | 4 | % | ||||||||||
| Gas equivalent (mcfe) (b) | $ | 4.88 | $ | 4.64 | 5 | % | $ | 5.07 | $ | 4.82 | 5 | % | ||||||||||
| Average prices, including cash-settled hedges and derivatives before third party transportation costs: (c) | ||||||||||||||||||||||
| Natural Gas (mcf) | $ | 3.88 | $ | 3.88 | 0 | % | $ | 4.05 | $ | 3.85 | 5 | % | ||||||||||
| NGL (bbl) | $ | 31.08 | $ | 38.79 | -20 | % | $ | 32.94 | $ | 42.22 | -22 | % | ||||||||||
| Oil (bbl) | $ | 85.46 | $ | 84.86 | 1 | % | $ | 85.35 | $ | 84.27 | 1 | % | ||||||||||
| Gas equivalent (mcfe) (b) | $ | 4.80 | $ | 4.88 | -2 | % | $ | 4.96 | $ | 4.93 | 1 | % | ||||||||||
| Average prices, including cash-settled hedges and derivatives (d): | ||||||||||||||||||||||
| Natural Gas (mcf) | $ | 3.03 | $ | 3.03 | 0 | % | $ | 3.13 | $ | 3.02 | 4 | % | ||||||||||
| NGL (bbl) | $ | 29.64 | $ | 37.23 | -20 | % | $ | 31.39 | $ | 40.66 | -23 | % | ||||||||||
| Oil (bbl) | $ | 85.46 | $ | 84.86 | 1 | % | $ | 85.35 | $ | 84.27 | 1 | % | ||||||||||
| Gas equivalent (mcfe) (b) | $ | 4.11 | $ | 4.17 | -1 | % | $ | 4.20 | $ | 4.24 | -1 | % | ||||||||||
| Transportation, gathering and compression expense per mcfe | $ | 0.69 | $ | 0.71 | -3 | % | $ | 0.76 | $ | 0.69 | 9 | % | ||||||||||
(a) Represents volumes sold regardless of when produced.
(b) Oil and NGLs are converted at the rate of one barrel equals six mcfe based upon the approximate relative energy content of oil to natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.
(c) Excluding third party transportation, gathering and compression costs.
(d) Net of transportation, gathering and compression costs.
|
RANGE RESOURCES CORPORATION |
||||||||||||||||||||||
|
RECONCILIATION OF INCOME (LOSS) FROM CONTINUING |
||||||||||||||||||||||
|
OPERATIONS BEFORE INCOME TAXES AS REPORTED TO |
||||||||||||||||||||||
|
INCOME FROM OPERATIONS BEFORE INCOME TAXES |
||||||||||||||||||||||
| EXCLUDING CERTAIN ITEMS, a non-GAAP measure | ||||||||||||||||||||||
| (Unaudited, in thousands, except per share data) | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| 2013 | 2012 | % | 2013 | 2012 | % | |||||||||||||||||
|
Income (loss) from operations before income taxes, as reported |
$ | 31,044 | $ | (82,910 | ) | 137 | % | $ | 149,731 | $ | (57,870 | ) | 359 | % | ||||||||
| Adjustment for certain special items: | ||||||||||||||||||||||
| Gain (loss) on sale of assets | (6,008 | ) | (949 | ) | (89,129 | ) | 12,704 | |||||||||||||||
|
Change in fair value of derivatives that did not qualify or were not designated for hedge accounting (gain) loss |
34,219 | 53,646 | (28,350 | ) | (30,075 | ) | ||||||||||||||||
| Unrealized hedge ineffectiveness (gain) loss | (815 | ) | 4,707 | 2,485 | 5,061 | |||||||||||||||||
| Abandonment and impairment of unproved properties | 11,692 | 40,118 | 46,066 | 104,048 | ||||||||||||||||||
| Loss on gas blending – brokered natural gas and marketing | 3,720 | - | 3,799 | - | ||||||||||||||||||
| Loss on early extinguishment of debt | - | - | 12,280 | - | ||||||||||||||||||
| Prior year Pennsylvania impact fee | - | - | - | 24,707 | ||||||||||||||||||
| Impairment of proved property and other assets | 7,012 | 1,281 | 7,753 | 1,281 | ||||||||||||||||||
| Lawsuit settlements | 324 | 1,107 | 91,589 | 2,523 | ||||||||||||||||||
|
Brokered natural gas and marketing – non cash stock-based compensation |
531 |
452 |
1,310 |
1,313 |
||||||||||||||||||
| Direct operating – non-cash stock-based compensation | 699 | 598 | 2,056 | 1,647 | ||||||||||||||||||
| Exploration – non-cash stock-based compensation | 983 | 1,126 | 3,013 | 3,048 | ||||||||||||||||||
| General & administrative – non-cash stock-based compensation | 11,031 | 10,057 | 34,600 | 30,755 | ||||||||||||||||||
| Deferred compensation plan – non-cash adjustment | (2,225 | ) | 20,052 | 33,257 | 21,555 | |||||||||||||||||
| Income from operations before income taxes, as adjusted | 92,207 | 49,285 | 87 | % | 270,460 | 120,697 | 124 | % | ||||||||||||||
| Income tax expense, as adjusted | ||||||||||||||||||||||
| Current | - | - | - | - | ||||||||||||||||||
| Deferred | 35,244 | 17,287 | 105,542 | 46,199 | ||||||||||||||||||
| Net income excluding certain items, a non-GAAP measure | $ | 56,963 | $ | 31,998 | 78 | % | $ | 164,918 | $ | 74,498 | 121 | % | ||||||||||
| Non-GAAP income per common share | ||||||||||||||||||||||
| Basic | $ | 0.35 | $ | 0.20 | 75 | % | $ | 1.03 | $ | 0.47 | 119 | % | ||||||||||
| Diluted | $ | 0.35 | $ | 0.20 | 75 | % | $ | 1.02 | $ | 0.47 | 117 | % | ||||||||||
| Non-GAAP diluted shares outstanding, if dilutive | 161,374 | 160,222 | 161,321 | 160,130 | ||||||||||||||||||
| HEDGING POSITION AS OF OCTOBER 29, 2013 – | ||||||
| (Unaudited) | ||||||
| Daily Volume | Hedge Price | |||||
| Gas (Mmbtu) | ||||||
| 4Q 2013 Swaps | 293,370 | $3.82 | ||||
| 4Q 2013 Collars | 280,000 | $4.59 - $5.05 | ||||
| 2014 Swaps | 50,000 | $4.12 | ||||
| 2014 Collars | 447,500 | $3.84 - $4.48 | ||||
| 2015 Swaps | 67,500 | $4.16 | ||||
| 2015 Collars | 145,000 | $4.07 - $4.56 | ||||
| Oil (Bbls) | ||||||
| 4Q 2013 Swaps | 6,825 | $96.79 | ||||
| 4Q 2013 Collars | 3,000 | $90.60 - $100.00 | ||||
| 2014 Swaps | 7,500 | $94.33 | ||||
| 2014 Collars | 2,000 | $85.55 - $100.00 | ||||
| 2015 Swaps | 3,000 | $90.13 | ||||
| C5 Natural Gasoline (Bbls) | ||||||
| 4Q 2013 Swaps | 6,500 | $2.134 | ||||
| C4 Normal Butane (Bbls) | ||||||
| 4Q 2013 Swaps | 2,000 | $1.320 | ||||
| 2014 Swaps | 3,000 | $1.328 | ||||
| C3 Propane (Bbls) | ||||||
| 4Q 2013 Swaps | 11,000 | $0.945 | ||||
| 2014 Swaps | 10,000 | $0.989 | ||||
NOTE: SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS
