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 October 28, 2015 - 4:30 PM EDT
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Range Announces Third Quarter 2015 Results

FORT WORTH, TX--(Marketwired - Oct 28, 2015) - RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its third quarter financial results. 

Highlights - 

  • Unit costs declined by $0.36 per mcfe, or 12% compared to the prior-year quarter.
  • Production volumes averaged 1,445 Mmcfe per day, a 20% increase over the prior-year quarter.
  • Marcellus production averaged 1,277 Mmcfe per day, a 27% increase over the prior-year quarter.
  • First Utica well in Washington County, Pennsylvania estimated to have 15 Bcf EUR, or 2.8 Bcf per 1,000 feet of lateral.
  • Second Utica well brought online with choke management at 13 Mmcf per day rate and projected to have higher EUR than the first well.
  • Full-year 2015 capital budget of $870 million is on track to deliver 20% annual year-over-year growth.
  • Mariner East I with full operations for propane and ethane expected by the end of the year. 

Commenting, Jeff Ventura, Range's Chairman, President and CEO, said, "Our operational results in the third quarter continued to improve during this challenging commodity period. Range is expecting to deliver our 20% production growth target in 2015 from a significantly lower capital budget of only $870 million, compared to $1.5 billion in 2014. We believe Range has one of the most capital efficient operations in the industry and we expect to continue improvements in 2016 and beyond. The keys to increasing capital efficiency are our large, concentrated, stacked pay acreage position that can deliver high quality returns at low-cost and right-sized takeaway capacity to move products to better or improving markets. This gives Range a sustainable competitive advantage in the current market and becomes more important as the natural gas markets improve.

"We are continuing to work on potential non-core asset sales for areas in our portfolio that cannot compete against the Marcellus for capital. Range expects to close one or more non-core asset sales prior to year-end. Any sales proceeds will be used to reduce debt and strengthen our balance sheet. Importantly, we are continuing to drive down costs and implement innovative marketing solutions that are expected to deliver improved margins. We also see signs of improved pricing ahead, especially in Appalachia, as the Mariner East I project becomes fully operational by year-end and completion of other infrastructure projects to move natural gas and NGLs out of the basin. Each of these projects is expected to improve the basis differentials in the southwest area of the Marcellus in the near-term. These projects, combined with the industry slowdown and reduction in capital spending, should help to bring supply and demand in balance both nationally and regionally, thus improving our prices and margins going forward." 

Capital Expenditures

Third quarter drilling expenditures of $188 million funded the drilling of 25 (20 net) wells with a 100% drilling success rate. During the third quarter, 31 wells were turned to sales. In addition, during the third quarter, $9 million was expended on acreage, $6 million on gas gathering systems and $4 million for exploration expense. Range is on target with its $870 million capital budget for 2015. Similar to recent years, the 2015 capital budget is front-end loaded and has been redirected to more dry gas drilling to maximize expected rates of return. The Company started the year running 15 rigs, is currently running five rigs and plans to finish the year with five rigs. Range expects to have 50 to 60 wells waiting on completion at the end of the year, consistent with prior-year averages.

Operational Discussion

Range has updated its investor presentation with third quarter financial and operational results. Please see www.rangeresources.com under the "Investors" tab, "Company Presentations" area, for the presentation entitled, "Company Presentation - October 28, 2015."

Range has made significant improvements in capital efficiencies over the last four years as lateral lengths increased and completion techniques have been optimized. These improvements, combined with the added benefit of lower service costs, have lowered well cost per lateral foot about 60% in the Marcellus over that time frame. In addition to these industry leading well costs, Range also has some of the highest estimated ultimate recoveries ("EUR") on a normalized basis (per 1,000 feet of lateral). The table below shows the expected averages for the wells turned to sales in 2015.

 
Marcellus Area   Average
EUR (Bcfe)
  Average
Well Cost
    per 1,000 ft.   per 1,000 ft.
SW Dry   2.52   $883,000
SW Wet   2.95   $991,000
SW Super rich   2.40   $1,100,000
NE Dry   2.67   $865,000
 

Southern Marcellus Shale Division -

Production for the third quarter averaged 999 net Mmcfe per day for the division, a 28% increase over the prior-year quarter. The division's third quarter net production included 635 Mmcf per day of gas, 51,967 barrels per day of NGLs and 8,676 barrels per day of condensate. During the third quarter, 23 wells were turned in line in southwest Pennsylvania. The division averaged completing 7.5 frac stages per day in the third quarter of 2015, compared to 5.2 stages in the third quarter of 2014, a 44% increase. 

During the third quarter, Range brought online a second Washington County Utica well, the Claysville Sportsman's Unit 9H. The well was completed with a lateral length of 5,228 feet, utilizing 32 stages. Both dry Utica wells are now producing under restricted rates into the newly constructed dry gas pipeline infrastructure. Based on our extensive reservoir modeling combined with production history for the first well, the Claysville Sportsman's Unit 11H, we estimate the EUR to be approximately 15 Bcf, or considering the 5,362 foot lateral, 2.8 Bcf per 1,000 feet of lateral. The second well is being produced utilizing choke management at 13 Mmcf per day designed to manage the near-wellbore pressure drawdown and was completed with a higher sand concentration. To date, the second well appears to have greater estimated reserves than the first well. In addition, a third Utica well is currently drilling from a nearby pad, and is expected to be completed in early 2016. Range holds approximately 400,000 net acres in southwest Pennsylvania, considered prospective for Utica dry gas.

During the third quarter, Range brought online 22 Marcellus wells, four in the super-rich area, 10 in the wet gas area and eight in the dry gas area. The 14 wells brought online in the wet and super-rich areas had a 24-hour IP average of 16.1 Mmcfe per day (6.6 Mmcf of gas, 1,179 barrels of NGLs and 404 barrels of condensate), from an average lateral length of 5,360 feet, utilizing 27 stages. In the dry gas area, the 24-hour IP averaged 15.7 Mmcf per day, from an average lateral length of 5,293 feet, utilizing 28 stages. Most of the facilities that Range is currently constructing are designed to limit initial flow, resulting in flatter initial production while achieving lower facility cost. 

Northern Marcellus Shale Division - 

In northeast Pennsylvania, production for the third quarter averaged 278 net Mmcf per day for the division, a 22% increase over the prior-year quarter. In the third quarter, four wells were brought online. The four wells averaged a 24-hour IP of 11.3 Mmcfe per day, and a 30-day IP of 9.2 Mmcf per day, from an average lateral length of 6,504 feet utilizing 28 stages. As stated previously, most of the facilities that Range is currently constructing are designed to limit initial flow, resulting in flatter initial production for a longer period and achieving a lower facility cost. The division has no rigs operating currently and does not anticipate bringing online any wells in the fourth quarter of 2015. 

Southern Appalachia Division -

Production for the third quarter averaged 109 net Mmcf per day for the division, a 2% decrease compared to the prior-year, and flat with the second quarter. With the division's continued focus on maintaining production for the year, production for the division remained flat compared to the second quarter while only turning in line three wells. The division drilled one coalbed methane ("CBM") well and completed two additional wells in the third quarter 2015. The division continued using a new completion technique on CBM wells which resulted in the best group of CBM wells in the Nora field in over 25 years. In addition to these more efficient completions which have resulted in improved economics, Range also has the added economic benefit of owning the majority of the royalty and receiving a premium gas price due to the assets being in close proximity to the growing southeast markets.

Marcellus Shale Marketing and Transportation Update -

Commodity prices continued to be challenging in the third quarter, but Range expects improvement in the fourth quarter and 2016. Specifically, Range's marketing team has put in place numerous strategies that are now showing results. As anchor shipper on Spectra's Uniontown to Gas City project, which moves gas from Appalachia to Gas City, Indiana, Range realized a price uplift of $1.13 per mcf, after transportation costs, in September revenue on approximately 167,000 Mmcf per day of net production, or approximately $5.7 million. Also, during the third quarter, Range initiated a new marketing arrangement for condensate sales. Under the new agreement, Range is upgrading its transportation logistics which will allow multiple options in marketing condensate production going forward. During the third quarter, Range became the first Appalachian producer to provide condensate barrels for export to overseas markets, further demonstrating Range's position as an innovative first-mover. 

The Mariner East I project is scheduled to commence full operations by the end of the year. Our latest communications with Sunoco Logistics indicate that ethane startup should occur within the next month and full ethane and propane operations by the end of the year. While the benefits of this project have been discussed before, the project's significance to Range bears repeating. First, when fully operational, Range will ship 20,000 barrels of ethane via pipeline to the Marcus Hook facilities in Philadelphia. The 20,000 barrels of ethane will be sold to INEOS, FOB at Marcus Hook, under a 15-year sales agreement. Second, 20,000 barrels of propane will be shipped via pipeline to Marcus Hook, where it can be sold in either the international market, or the local market, depending on which option yields the best price. The supply of large ships available to transport propane to international markets is expected to increase by roughly 50% in 2016, thus lowering shipping costs, and improving the expected net price received. Range has begun locking in the premium spread between the Mont Belvieu index and the respective European and Asian propane market indexes for 2016 on a limited amount of our propane volumes. Third, Range has access to 800,000 barrels of propane storage (80% of the total capacity) at Marcus Hook, which is especially valuable as it allows faster loading of ocean-going vessels and potential seasonal price opportunities. Fourth, having access to the harbor facilities at Marcus Hook is an important advantage for Range, as it could permit future export of other NGL products and growing volumes of ethane and propane.

A key component of Range's marketing strategy for many years has focused on securing firm transportation capacity, at a reasonable cost, to access markets outside of the Appalachian basin. This strategy was implemented many years ago, when Range realized that Marcellus volumes would quickly exceed the historical pipeline infrastructure and local demand. As a result, Range was able to assemble a diversified portfolio of firm transportation projects at low-cost that corresponds to its expected Appalachian volumes. Range believes that pipeline infrastructure construction will likely exceed the gas volumes expected to be moved out of Appalachia. This added capacity will be available in the secondary market as producers are not expected to satisfy all of their volume commitments, providing excess capacity in the takeaway pipelines. With the slowdown in capital spending expected for 2016, the availability and amount of excess capacity may occur earlier and greater than expected. As producers are able to flow more gas out of the basin, basis differentials in Appalachia are expected to improve.

In the Appalachian Basin, Marcellus and Utica production has grown rapidly over the past four years, with annual growth ranging between three to four Bcf per day. The rate of growth has already slowed and may further decline with the significant reduction in capital spending and rig count over the past year which is expected to continue in 2016. This slowdown in growth should cause a faster rebalancing of Appalachian markets, resulting in improved basis differentials. Regardless of when the rebalancing occurs, Range's portfolio is expected to provide for maximizing gas price realizations after cost of transportation. As an example, Range owns firm transportation to East Coast markets which are trading at a significant premium to NYMEX for the upcoming winter. In addition, as a part of its overall corporate strategy, Range has consistently hedged a significant portion of its production as a means of protecting cash flow. For 2016, Range has hedged 630,000 Mmbtu per day of its expected gas production at a floor price of $3.42.

Financial Discussion

(Except for generally accepted accounting principles ("GAAP") reported amounts, specific expense categories exclude non-cash impairments, derivative fair value income/(loss), non-cash stock compensation and other items shown separately on the attached tables. "Total unit costs" as used in this release are composed of direct operating, transportation, gathering and compression, production and ad valorem tax, general and administrative, interest and depletion, depreciation and amortization costs divided by production as shown on the attached tables. "Total unit cash costs" are the same as "Total unit costs" except depletion, depreciation and amortization cost is excluded. See "Non-GAAP Financial Measures" for a definition of each of the non-GAAP financial measures and the tables that reconcile each of the non-GAAP measures to their most directly comparable GAAP financial measure.)

GAAP revenues for the third quarter of 2015 totaled $479 million (a 22% decrease as compared to third quarter 2014), GAAP net cash provided from operating activities including changes in working capital reached $145 million and GAAP net income was a loss of $301 million ($1.81 loss per diluted share) versus earnings of $146 million ($0.86 per diluted share) in the prior-year quarter. Third quarter 2015 results included a pre-tax proved property impairment of $502 million related to certain oil and gas properties located in northern Oklahoma and legacy producing assets in northwest Pennsylvania, a $22 million loss from early extinguishment of debt, $202 million in derivative gains due to decreases in future commodity prices compared to a $142 million gain in the third quarter of 2014, and a $44 million gain in the deferred compensation plan due to decreases in the Company's stock price compared to a gain of $46 million in third quarter 2014.

Non-GAAP revenues for third quarter 2015 totaled $416 million (a 15% decrease compared to third quarter 2014) and cash flow from operations before changes in working capital, a non-GAAP measure, was $169 million. Adjusted net income comparable to analysts' estimates, a non-GAAP measure, was $5.5 million ($0.03 per diluted share) for the third quarter 2015, compared to $62 million ($0.37 per diluted share) in the prior-year quarter. The Company's total unit cash costs of $1.64 per mcfe in third quarter 2015 decreased by $0.23 per mcfe or 12% compared to the prior-year quarter. The Company's total unit costs in third quarter 2015 decreased by $0.36 per mcfe or 12% compared to the prior-year quarter and were $0.17 per mcfe lower or 6% compared to the second quarter of 2015.

                 
Expenses   2Q 2015 (per mcfe)   3Q 2015 (per mcfe)   3Q 2014 (per mcfe)   YOY Increase (Decrease)
                       
Direct operating   $ 0.27   $ 0.26   $ 0.33   -21%
Transportation, gathering and compression     0.76     0.75     0.76   -1%
Production and ad valorem taxes     0.07     0.06     0.09   -33%
General and administrative     0.30     0.25     0.34   -26%
Interest     0.35     0.32     0.35   -9%
    $ 1.75   $ 1.64   $ 1.87   -12%
Depletion, depreciation and amortization     1.21     1.16     1.28   -9%
    $ 2.97 (a)   $ 2.79 (a)   $ 3.16 (a)   -12%
                       
(a) Amounts may not add due to rounding.    
     

Third quarter 2015 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts' estimates) averaged $2.93 per mcfe, a 30% decrease from the prior-year quarter. Additional detail on commodity price realizations can be found in the Supplemental Tables provided on the Company's website.

  • Production and realized prices for each commodity for the third quarter of 2015 without the effect of hedging were: natural gas - 1,057 Mmcf per day ($1.94 per mcf); NGLs - 54,186 barrels per day ($6.23 per barrel) and crude oil and condensate - 10,420 barrels per day ($33.26 per barrel). 

  • The third quarter average natural gas price decreased to $2.77 per mcf (including the impact of cash-settled hedges), as compared to the prior-year quarter of $3.63 per mcf. Financial hedges based upon NYMEX increased realizations $0.79 per mcf while financial basis hedges increased realizations $0.04 per mcf during the third quarter. The average Company natural gas differential including the settled financial basis hedges but before NYMEX hedging for the third quarter was ($0.78) per mcf, compared to ($0.49) per mcf in the prior-year quarter.

  • Total NGL pricing per barrel including ethane and processing expenses after realized cash-settled hedging was $9.45 for the third quarter compared to $22.53 per barrel in the prior-year quarter. Hedging increased NGL prices by $3.22 per barrel in the third quarter compared to $0.27 in the prior-year quarter. Our gross Marcellus C3+ NGL barrel (without ethane) including realized hedges for the third quarter was approximately $17.15 per barrel. 

  • Crude oil and condensate price realizations, before realized hedges, for the third quarter averaged $13.35 below West Texas Intermediate ("WTI"), or $33.26 per barrel; compared to $16.17 per barrel below WTI in the second quarter of 2015, a 17% improvement and $15.65 per barrel below WTI in the prior-year quarter, a 15% improvement. Hedging for the third quarter added $42.99 per barrel compared to a loss of $2.68 in the prior-year.

Financial Position and Liquidity

On August 3, 2015, Range called for redemption of all $500 million in outstanding principal of its 6.75% Senior Subordinated Notes due in 2020 at a price of 103.375% of the outstanding principal, plus accrued interest. Combined with the issuance in May 2015 of $750 million of its 4.875% Senior Notes due 2025, Range has significantly reduced its borrowing costs and extended the average maturity of its debt.

As of September 30, 2015, Range has bank commitments of $2 billion under the maximum bank credit facility of $4 billion. With outstanding bank debt of $987 million and undrawn letters of credit of $136.8 million, Range has immediately available committed liquidity at September 30, 2015 of $876.2 million. 

Guidance - Fourth Quarter 2015

Production Guidance:

Production growth for 2015 is targeted at 20% year-over-year. Average daily production for the fourth quarter of 2015 is expected to be approximately 1.42 Bcfe per day with approximately 26% liquids, without any incremental volumes associated with the Mariner East I start-up.

Expense per mcfe Guidance:

Direct operating expense:   $0.27  -  $0.29 per mcfe
Transportation, gathering and compression expense:   $0.79  -  $0.81 per mcfe
Production tax expense:   $0.07  -  $0.08 per mcfe
Exploration expense:   $6  -  $8 million
Unproved property impairment expense:   $11  -  $13 million
G&A expense:   $0.26  -  $0.28 per mcfe
Interest expense:   $0.32  -  $0.33 per mcfe
DD&A expense:   $1.15  -  $1.17 per mcfe

Based on historical trends, base net expense for brokered natural gas and marketing activity is expected to be $5 million net expense per quarter.

Guidance for Remaining 2015 Activity:

Unchanged from the previous quarter, Range expects to turn in line 169 wells during 2015, as shown below. The number of wells expected to be turned in line has slowed in the fourth quarter of the year, reflecting capital spent and rig counts being weighted to the first half of the current year.

    Wells turned in line -
First 9 Months 2015
  Expected remaining wells to turn in line-
4
th Quarter 2015
  Total planned wells to turn in line for 2015
Super-Rich area   25   0   25
Wet area   49   8   57
Dry- SW   25   9   34
Dry- NE   17   0   17
  Total Marcellus/Utica   116   17   133
Nora area   24   1   25
Midcontinent   11   0   11
    Total   151   18   169
             
             

NYMEX 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 approximately 85% of its remaining 2015 natural gas production hedged at a weighted average floor price of $3.70 per Mmbtu. Similarly, Range has hedged approximately 90% of its remaining 2015 projected crude oil and condensate production at a floor price of $98.92 per barrel and over half of its remaining composite NGL production. 

For calendar year 2016, Range has hedged 630,000 Mmbtu per day of its expected natural gas production at a weighted average price of $3.42 per Mmbtu and has started hedging 2017 gas volumes. Similarly, Range has hedged 4,247 barrels per day of its 2016 projected crude oil production at an average price of $65.27 per barrel and 27,000 barrels per day of its expected NGL production. Please see Range's detailed hedging schedule posted at the end of the financial tables below and on its website at www.rangeresources.com

Basis Hedging Status

In addition to the collars and swaps above, at September 30, 2015, Range had natural gas basis swap contracts which lock in the differential between NYMEX and certain physical pricing indices, primarily in Appalachia. These contracts settle monthly through March 2017, and the fair value of these contracts was a loss of $2.0 million at September 30, 2015.

Conference Call Information

A conference call to review the financial results is scheduled on Thursday, October 29 at 9:00 a.m., Eastern Time. To participate in the call, please dial 877-407-0778 and ask for the Range Resources third quarter 2015 financial results conference call. A replay of the call will be available through November 29. To access the phone replay dial 877-660-6853. The conference ID is 13622392.

A simultaneous webcast of the call may be accessed over the Internet at www.rangeresources.com. The webcast will be archived for replay on the Company's website until November 29.

Non-GAAP Financial Measures:

Adjusted net income comparable to analysts' estimates as set forth in this release (sometimes referred to as "Adjusted net income") represents income or loss from operations before income taxes adjusted for certain non-cash items (detailed in the accompanying table) less income taxes. We believe Adjusted net income is comparable to analysts' estimates and is calculated on the same basis as analysts' estimates. We believe that many investors use this published research in making investment decisions and 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. 

Cash flow from operations before changes in working capital (sometimes referred to as "Adjusted cash flow") 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.

RANGE RESOURCES CORPORATION (NYSE: RRC) is a leading U.S. independent oil and natural gas producer with operations focused in Appalachia. 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 www.rangeresources.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, future production growth, future completion of ethane projects, estimated gas in place, future rates of return, future low costs, low reinvestment risk, future earnings and per-share value, future capital spending plans, increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, maximized realized natural gas prices, acreage quality, access to multiple gas markets, expected drilling and development plans, improved capital efficiency, future financial position, future technical improvements, future marketing opportunities, future market improvements, maximizing future rates of return, strong inventory of uncompleted wells, expectation to create future value, expected lower well costs, acreage prospective for other horizons, expected future asset sales 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," "unrisked resource potential," "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 actually being realized. Unproved resource potential refers to Range's internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques and have not been reviewed by independent engineers. Unproved resource potential does not constitute reserves within the meaning of the Society of Petroleum Engineer's Petroleum Resource Management System and does not include proved reserves. Area wide unproven resource potential has not been fully risked by Range's management. "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 and completion services and equipment, lease expirations, transportation constraints, regulatory approvals, field spacing rules, recoveries of gas in place, length of horizontal laterals, actual drilling and completion results, including geological and mechanical factors affecting recovery rates and other factors. Estimates of resource potential may change significantly as development of our resource plays provides additional data. 

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 on the SEC's website at www.sec.gov or by calling the SEC at 1-800-SEC-0330.

 
RANGE RESOURCES CORPORATION
 
STATEMENTS OF OPERATIONS
Based on GAAP reported earnings with additional details of items included in each line in Form 10-Q
(Unaudited, in thousands, except per share data)
                                     
    Three Months Ended September 30,     Nine Months Ended September 30,  
    2015     2014     %     2015     2014     %  
Revenues and other income:                                            
  Natural gas, NGLs and oil sales (a)   $ 252,065     $ 446,067           $ 835,601     $ 1,495,601        
  Derivative fair value income/(loss)     202,004       142,057             290,052       (28,902 )      
  (Loss) gain on sale of assets     (681 )     167             2,053       281,878        
  Brokered natural gas, marketing and other (b)     25,141       28,118             60,822       91,641        
  Equity method investment (b)     -       -             -       (277 )      
  ARO settlement (loss) gain (b)     (5 )     135             23       (651 )      
  Other (b)     728       71             843       191        
    Total revenues and other income     479,252       616,615     -22 %     1,189,394       1,839,481     -35 %
                                             
Costs and expenses:                                            
  Direct operating     34,449       37,072             104,826       109,013        
  Direct operating - non-cash stock-based compensation (c)     609       720             2,149       3,509        
  Transportation, gathering and compression     99,634       84,777             284,258       235,747        
  Production and ad valorem taxes     7,336       10,110             26,506       32,632        
  Brokered natural gas and marketing     31,713       28,050             79,181       95,296        
  Brokered natural gas and marketing - non-cash stock-     618       656             1,743       2,314        
  based compensation (c)                                            
  Exploration     3,547       10,410             14,975       36,502        
  Exploration - non-cash stock-based compensation (c)     688       1,033             2,171       3,408        
  Abandonment and impairment of unproved properties     12,366       13,444             36,187       32,771        
  General and administrative     33,038       37,255             106,814       109,854        
  General and administrative - non-cash stock-based     11,512       11,556             38,545       43,856        
  compensation (c)                                            
  General and administrative - lawsuit settlements     1,278       1,252             2,012       2,203        
  General and administrative - bad debt expense     350       -             600       250        
  General and administrative - legal contingency     -       4,900             2,500       4,900        
  (DEP penalty in prior year)                                            
  Termination costs     (76 )     -             4,570       -        
  Termination costs - non-cash stock-based compensation (c)     (1 )     -             1,720       -        
  Deferred compensation plan (d)     (43,705 )     (46,198 )           (56,611 )     (37,714 )      
  Interest expense     42,904       39,188             125,590       130,077        
  Loss on early extinguishment of debt     22,495       -             22,495       24,596        
  Depletion, depreciation and amortization     153,993       142,450             453,178       404,493        
  Impairment of proved properties and other assets     502,233       -             502,233       24,991        
    Total costs and expenses     914,981       376,675     143 %     1,755,642       1,258,698     39 %
                                             
(Loss) income before income taxes     (435,729 )     239,940     -282 %     (566,248 )     580,783     -197 %
                                             
Income tax (benefit) expense:                                            
  Current     -       -             -       5        
  Deferred     (134,781 )     93,522             (174,390 )     230,450        
      (134,781 )     93,522             (174,390 )     230,455        
                                             
Net (loss) income   $ (300,948 )   $ 146,418     -306 %   $ (391,858 )   $ 350,328     -212 %
                                             
Net (Loss) Income Per Common Share:                                            
                                             
  Basic   $ (1.81 )   $ 0.87           $ (2.36 )   $ 2.11        
  Diluted   $ (1.81 )   $ 0.86           $ (2.36 )   $ 2.10        
                                             
Weighted average common shares outstanding, as reported:                                            
  Basic     166,517       165,841     0 %     166,327       162,866     2 %
  Diluted     166,517       166,460     0 %     166,327       163,685     2 %
                                               
(a)   See separate natural gas, NGLs and oil sales information table.
(b)   Included in Brokered natural gas, marketing and other revenues in the 10-Q.
(c)   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.
(d)   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,  
    2015     2014  
    (Unaudited)     (Audited)  
Assets                
  Current assets   $ 134,320     $ 207,243  
  Derivative assets - current     289,108       363,049  
  Natural gas and oil properties, successful efforts method     7,784,794       7,977,573  
  Transportation and field assets     29,835       37,581  
  Other     159,847       161,334  
    $ 8,397,904     $ 8,746,780  
                 
Liabilities and Stockholders' Equity                
  Current liabilities   $ 447,830     $ 740,197  
  Asset retirement obligations     17,689       15,067  
  Derivative liabilities     293       -  
                 
  Bank debt     987,000       723,000  
  Senior notes     750,000       -  
  Senior subordinated notes     1,850,000       2,350,000  
      3,587,000       3,073,000  
                 
  Deferred tax liability     843,189       997,494  
  Derivative liabilities     111       -  
  Deferred compensation liability     117,137       178,599  
  Asset retirement obligations and other liabilities     299,973       284,994  
      1,260,410       1,461,087  
                 
  Common stock and retained earnings     3,086,957       3,460,517  
  Common stock held in treasury stock     (2,275 )     (3,088 )
    Total stockholders' equity     3,084,682       3,457,429  
    $ 8,397,904     $ 8,746,780  
                 
                 
                 
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,
    2015     2014     %   2015     2014     %
                                         
Total revenues and other income, as reported   $ 479,252     $ 616,615     -22%   $ 1,189,394     $ 1,839,481     -35%
Adjustment for certain special items:                                        
  Total change in fair value related to derivatives prior to     (64,075 )     (125,154 )         70,593       (84,957 )    
settlement                                        
  ARO settlement loss (gain)     5       (135 )         (23 )     651      
  Loss (gain) on sale of assets     681       (167 )         (2,053 )     (281,878 )    
Total revenues, as adjusted, non-GAAP   $ 415,863     $ 491,159     -15%   $ 1,257,911     $ 1,473,297     -15%
                                         
   
RANGE RESOURCES CORPORATION  
   
CASH FLOWS FROM OPERATING ACTIVITIES                
(Unaudited, in thousands) Three Months Ended September 30,     Nine Months Ended September 30,  
  2015     2014     2015     2014  
                               
Net (loss) income $ (300,948 )   $ 146,418     $ (391,858 )   $ 350,328  
Adjustments to reconcile net cash provided from continuing operations:                              
  Equity method investment, net of distributions   -       -       -       3,096  
  Deferred income tax (benefit) expense   (134,781 )     93,522       (174,390 )     230,450  
  Depletion, depreciation, amortization and impairment   656,226       142,450       955,411       429,484  
  Exploration dry hole costs   (19 )     -       87       1  
  Abandonment and impairment of unproved properties   12,366       13,444       36,187       32,771  
  Derivative fair value (income)/loss   (202,004 )     (142,057 )     (290,052 )     28,902  
  Cash settlements on derivative financial instruments that do not qualify for hedge accounting   137,929       16,903       360,645       (113,859 )
  Allowance for bad debts   350       -       600       250  
  Amortization of deferred issuance costs, loss on extinguishment of debt, and other   24,482       1,618       27,572       31,430  
  Deferred and stock-based compensation   (30,471 )     (32,426 )     (10,679 )     15,486  
  Loss (gain) on sale of assets and other   681       (167 )     (2,053 )     (281,878 )
                               
Changes in working capital:                              
    Accounts receivable   5,753       11,823       79,448       13,098  
    Inventory and other   (3,324 )     1,537       (7,073 )     (5,335 )
    Accounts payable   (16,650 )     (33,470 )     (13,158 )     (13,355 )
    Accrued liabilities and other   (4,172 )     (6,180 )     (55,127 )     (65,931 )
    Net changes in working capital   (18,393 )     (26,290 )     4,090       (71,523 )
      Net cash provided from operating activities $ 145,418     $ 213,415     $ 515,560     $ 654,938  
                       
                       
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,  
  2015     2014     2015     2014  
                               
Net cash provided from operating activities, as reported $ 145,418     $ 213,415     $ 515,560     $ 654,938  
  Net changes in working capital   18,393       26,290       (4,090 )     71,523  
  Exploration expense   3,566       10,410       14,888       36,501  
  Lawsuit settlements   1,278       1,252       2,012       2,203  
  Legal contingency / DEP penalty   -       4,900       2,500       4,900  
  Equity method investment distribution / intercompany elimination   -       -       -       (2,819 )
  Termination costs   (76 )     -       4,570       -  
  Non-cash compensation adjustment   47       304       637       246  
Cash flow from operations before changes in working capital - a non-GAAP measure $ 168,626     $ 256,571     $ 536,077     $ 767,492  
                               
                               
                               
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING                              
  (Unaudited, in thousands) Three Months Ended September 30,     Nine Months Ended September 30,  
  2015     2014     2015     2014  
Basic:                              
Weighted average shares outstanding   169,362       168,697       169,142       165,675  
Stock held by deferred compensation plan   (2,845 )     (2,856 )     (2,815 )     (2,809 )
  Adjusted basic   166,517       165,841       166,327       162,866  
                               
Dilutive:                              
Weighted average shares outstanding   169,362       168,697       169,142       165,675  
Dilutive stock options under treasury method   (2,845 )     (2,237 )     (2,815 )     (1,990 )
  Adjusted dilutive   166,517       166,460       166,327       163,685  
                                 
                                 
                                 
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, a non-GAAP measure                    
                       
(Unaudited, in thousands, except per unit data) Three Months Ended September 30,   Nine Months Ended September 30,
  2015   2014   %   2015   2014   %
Natural gas, NGL and oil sales components:                              
  Natural gas sales $ 189,113   $ 252,562       $ 589,517   $ 874,514    
  NGL sales   31,066     109,858         131,822     355,360    
  Oil sales   31,886     80,144         114,262     255,146    
                               
Cash-settled hedges (effective):                              
  Natural gas   -     1,966         -     6,760    
  Crude oil   -     1,537         -     3,821    
Total oil and gas sales, as reported $ 252,065   $ 446,067   -43%   $ 835,601   $ 1,495,601   -44%
                               
Derivative fair value income (loss), as reported: $ 202,004   $ 142,057       $ 290,052   $ (28,902)    
Cash settlements on derivative financial instruments - (gain) loss:                              
  Natural gas   (80,675)     (19,762)         (223,603)     83,983    
  NGLs   (16,047)     (1,323)         (31,608)     13,114    
  Crude Oil   (41,207)     4,182         (105,434)     16,762    
Total change in fair value related to derivatives prior to settlement, a non GAAP measure $ 64,075   $ 125,154       $ (70,593)   $ 84,957    
                               
Transportation, gathering and compression components:                              
  Natural gas $ 87,886   $ 72,186       $ 247,744   $ 205,765    
  NGLs   11,748     12,591         36,514     29,982    
Total transportation, gathering and compression, as reported $ 99,634   $ 84,777       $ 284,258   $ 235,747    
                               
Natural gas, NGL and oil sales, including cash-settled derivatives: (c)                              
  Natural gas sales $ 269,788   $ 274,290       $ 813,120   $ 797,291    
  NGL sales   47,113     111,181         163,430     342,246    
  Oil sales   73,093     77,499         219,696     242,205    
Total $ 389,994   $ 462,970   -16%   $ 1,196,246   $ 1,381,742   -13%
                               
Production of oil and gas during the periods (a):                              
  Natural gas (mcf)   97,273,739     75,665,182   29%     265,511,105     205,444,379   29%
  NGL (bbl)   4,985,092     4,934,882   1%     15,449,495     13,877,217   11%
  Oil (bbl)   958,628     985,300   -3%     3,187,005     3,010,054   6%
Gas equivalent (mcfe) (b)   132,936,059     111,186,274   20%     377,330,105     306,768,005   23%
                               
Production of oil and gas - average per day (a):                              
  Natural gas (mcf)   1,057,323     822,448   29%     972,568     752,544   29%
  NGL (bbl)   54,186     53,640   1%     56,592     50,832   11%
  Oil (bbl)   10,420     10,710   -3%     11,674     11,026   6%
Gas equivalent (mcfe) (b)   1,444,957     1,208,546   20%     1,382,162     1,123,692   23%
                               
Average prices, including cash-settled hedges that qualify for hedge accounting before third party transportation costs:                              
  Natural gas (mcf) $ 1.94   $ 3.36   -42%   $ 2.22   $ 4.29   -48%
  NGL (bbl) $ 6.23   $ 22.26   -72%   $ 8.53   $ 25.61   -67%
  Oil (bbl) $ 33.26   $ 82.90   -60%   $ 35.85   $ 86.03   -58%
Gas equivalent (mcfe) (b) $ 1.90   $ 4.01   -53%   $ 2.21   $ 4.88   -55%
                               
Average prices, including cash-settled hedges and derivatives before third party transportation costs: (c)                              
  Natural gas (mcf) $ 2.77   $ 3.63   -23%   $ 3.06   $ 3.88   -21%
  NGL (bbl) $ 9.45   $ 22.53   -58%   $ 10.58   $ 24.66   -57%
  Oil (bbl) $ 76.25   $ 78.66   -3%   $ 68.93   $ 80.47   -14%
Gas equivalent (mcfe) (b) $ 2.93   $ 4.16   -30%   $ 3.17   $ 4.50   -30%
                               
Average prices, including cash-settled hedges and derivatives: (d)                              
  Natural gas (mcf) $ 1.87   $ 2.67   -30%   $ 2.13   $ 2.88   -26%
  NGL (bbl) $ 7.09   $ 19.98   -64%   $ 8.21   $ 22.50   -63%
  Oil (bbl) $ 76.25   $ 78.66   -3%   $ 68.93   $ 80.47   -14%
Gas equivalent (mcfe) (b) $ 2.18   $ 3.40   -36%   $ 2.42   $ 3.74   -35%
                               
Transportation, gathering and compression expense per mcfe $ 0.75   $ 0.76   -2%   $ 0.75   $ 0.77   -2%
                               

(a) Represents volumes sold regardless of when produced.
(b) Oil and NGLs are converted at the rate of one barrel equals six mcfe.
(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,  
    2015     2014     %     2015     2014     %  
                                             
(Loss) income from operations before income taxes, as reported   $ (435,729 )   $ 239,940     -282 %   $ (566,248 )   $ 580,783     -197 %
Adjustment for certain special items:                                            
  Loss (gain) on sale of assets     681       (167 )           (2,053 )     (281,878 )      
  Loss (gain) on ARO settlements     5       (135 )           (23 )     651        
  Change in fair value related to derivatives prior to settlement     (64,075 )     (125,154 )           70,593       (84,957 )      
  Abandonment and impairment of unproved properties     12,366       13,444             36,187       32,771        
  Loss on early extinguishment of debt     22,495       -             22,495       24,596        
  Impairment of proved property and other assets     502,233       -             502,233       24,991        
  Lawsuit settlements     1,278       1,252             2,012       2,203        
  DEP penalty     -       4,900             -       4,900        
  Legal contingency     -       -             2,500       -        
  Termination costs     (76 )     -             4,570       -        
  Termination costs - non-cash stock-based compensation     (1 )     -             1,720       -        
  Brokered natural gas and marketing - non-cash stock-based compensation     618       656             1,743       2,314        
  Direct operating - non-cash stock-based compensation     609       720             2,149       3,509        
  Exploration expenses - non-cash stock-based compensation     688       1,033             2,171       3,408        
  General & administrative - non-cash stock-based compensation     11,512       11,556             38,545       43,856        
  Deferred compensation plan - non-cash adjustment     (43,705 )     (46,198 )           (56,611 )     (37,714 )      
                                             
Income from operations before income taxes, as adjusted     8,899       101,847     -91 %     61,983       319,433     -81 %
                                             
Income tax expense, as adjusted                                            
  Current     -       -             -       5        
  Deferred     3,435       39,696             23,345       123,780        
Net income excluding certain items, a non-GAAP measure   $ 5,464     $ 62,151     -91 %   $ 38,638     $ 195,648     -80 %
                                             
Non-GAAP income per common share                                            
  Basic   $ 0.03     $ 0.37     -92 %   $ 0.23     $ 1.20     -81 %
  Diluted   $ 0.03     $ 0.37     -92 %   $ 0.23     $ 1.20     -81 %
                                             
Non-GAAP diluted shares outstanding, if dilutive     166,517       166,460             166,385       163,685        
 
 
 
RANGE RESOURCES CORPORATION
 
 
 
HEDGING POSITION AS OF OCTOBER 28, 2015 -
(Unaudited)
 
  Daily Volume   Hedge Price
  Gas (Mmbtu)      
  4Q 2015 Swaps 727,500   $3.63
  4Q 2015 Collars 145,000   $4.07 - $4.56
       
  2016 Swaps 630,000   $3.42
  2017 Swaps 20,000   $3.49
       
  Oil (Bbls)      
  4Q 2015 Swaps 8,750   $98.92
       
  2016 Swaps 4,247   $65.27
       
  2017 Swaps 500   $55.00
       
  C3 Propane (Bbls)      
  4Q 2015 Swaps 12,000   $0.55
       
  2016 Swaps 5,500   $0.60
       
  C4 Normal Butane (Bbls)    
  4Q 2015 Swaps 3,500   $0.72
       
  2016 Swaps 2,500   $0.72
       
  C5 Natural Gasoline (Bbls)    
  4Q 2015 Swaps 4,000   $1.16
       
  2016 Swaps 2,500   $1.23

NOTE: SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS

Investor Contacts:

Rodney Waller
Senior Vice President
817-869-4258
rwaller@rangeresources.com

David Amend
Investor Relations Manager
817-869-4266
damend@rangeresources.com

Laith Sando
Research Manager
817-869-4267
lsando@rangeresources.com

Michael Freeman
Senior Financial Analyst
817-869-4264
mfreeman@rangeresources.com

or

Media Contact:

Matt Pitzarella
Director of Corporate Communications
724-873-3224
mpitzarella@rangeresources.com

www.rangeresources.com


Source: Marketwired (October 28, 2015 - 4:30 PM EDT)

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