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Range Announces Second Quarter 2017 Financial Results

FORT WORTH, Texas, Aug. 01, 2017 (GLOBE NEWSWIRE) -- RANGE RESOURCES CORPORATION (NYSE:RRC) today announced its second quarter 2017 financial results. 

Highlights –

  • Second quarter GAAP net income was $70 million, or $0.28 per diluted share, compared to a net loss of $225 million, or $1.35 per share in the prior-year quarter
  • Second quarter cash margins improved to $1.09 per mcfe, compared to $0.70 per mcfe in the prior-year quarter, an improvement of 55%
  • Cash flow from operations before changes in working capital, a non-GAAP measure, reached $194 million, compared to $93 million in second quarter 2016
  • Record production totaled 1.945 Bcfe per day, an increase of 37% compared to the prior-year quarter
  • Total unit costs continued to decline, with second quarter 2017 costs of $2.66 per mcfe, compared to $2.73 in the previous year quarter, an improvement of 3%
  • Seven-well Marcellus pad on the western edge of the super-rich area with average IP’s per well of 29.1 Mmcfe per day (73% liquids)
  • Four-well Marcellus pad on the eastern edge of the dry gas area with average IP’s per well of 30.0 Mmcf per day

Commenting, Jeff Ventura, the Company’s CEO said, “Range continues to improve both operationally and financially.  Second quarter financial results continue to build on the first quarter improvement in earnings and cash flow, margins and total unit costs.  Operationally, the Marcellus is continuing to see improvement in well results and capital efficiency.  In southwest Pennsylvania this year, we have drilled some of our best wells to date on our 515,000 acre position, further demonstrating the size and quality of our acreage position.  As we look forward to the next several years and beyond, with our extensive, core acreage positions, diversified low-cost transportation portfolio and talented technical team, Range is well-positioned to deliver significant shareholder value.”

Financial Discussion

Except for generally accepted accounting principles (“GAAP”) reported amounts, specific expense categories exclude non-cash impairments, unrealized mark-to-market adjustment on derivatives, non-cash stock compensation and other items shown separately on the attached tables.  “Unit costs” as used in this release are composed of direct operating, transportation, gathering, processing and compression, production and ad valorem taxes, general and administrative, interest and depletion, depreciation and amortization costs divided by production.  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.

Second Quarter 2017

GAAP revenues for the second quarter of 2017 totaled $673 million (over 6 times second quarter 2016), GAAP net cash provided from operating activities including changes in working capital was $185 million (125% increase as compared to second quarter 2016) and GAAP earnings were $70 million ($0.28 per diluted share) versus a loss of $225 million ($1.35 per diluted share) in the prior-year quarter.  Second quarter 2017 included $111 million in derivative gains due to decreased commodity prices, compared to a $163 million loss in second quarter 2016. 
                                                                                                                                  
Non-GAAP revenues for second quarter 2017 totaled $565 million (56% increase compared to second quarter 2016) and cash flow from operations before changes in working capital, a non-GAAP measure, reached $194 million, compared to $93 million in second quarter 2016, an increase of 108%.  Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $16 million ($0.06 per diluted share) compared to a loss of $23 million ($0.14 per diluted share) for second quarter 2016. 

The Company’s total unit costs were 3% lower than the second quarter of 2016, while cash unit costs were 1% higher than the prior-year quarter.  Direct operating costs increased by $0.02 per mcfe over the prior-year quarter due to higher workover and well service costs.  Transportation, gathering, processing and compression expense increased by $0.02 per mcfe over the prior-year quarter, which was more than offset by higher realized prices, as products were moved to more favorable markets with higher prices, thereby resulting in increased cash margins from the previous year.  General and administrative, interest and depletion, depreciation and amortization expenses per mcfe continued to trend lower.

Expenses   2Q 2017
(per mcfe)
  2Q 2016
(per mcfe)
     Increase
(Decrease)

 
                 
Direct operating   $ 0.17   $ 0.15     13 %  
Transportation, gathering,
  processing and compression
    1.08     1.06     2 %  
Production and ad valorem taxes     0.06     0.05     20 %  
General and administrative     0.21     0.23     (9 %)  
Interest expense     0.27     0.29     (7 %)  
Total cash unit costs(a)     1.79     1.78     1 %  
Depletion, depreciation and
  amortization
    0.86     0.95     (9 %)  
Total unit costs(a)   $ 2.66   $ 2.73     (3 %)  
                 

(a) Totals may not add due to rounding.

Second quarter 2017 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts’ estimates) averaged $2.88 per mcfe, a 15% increase from the prior-year quarter as price differentials improved for all of the Company’s products.  Additional detail on commodity price realizations can be found in the Supplemental Tables provided on the Company’s website.   

  • Production and realized prices by each commodity for second quarter 2017 were:  natural gas – 1,313 Mmcf per day ($2.82 per mcf), NGLs – 93,673 barrels per day ($14.15 per barrel) and crude oil and condensate – 11,569 barrels per day ($48.82 per barrel). 
     
  • The average Company natural gas price differential including the impact of basis hedges for second quarter 2017 improved to minus ($0.39) per mcf, compared to minus ($0.48) in second quarter 2016.  The second quarter 2017 average natural gas price, before all hedging settlements, was $2.82 per mcf as compared to $1.50 per mcf in the prior-year quarter.
     
  • Pre-hedge NGL realizations improved to 30% of West Texas Intermediate (“WTI”) crude oil in second quarter 2017, compared to 24% of WTI in second quarter 2016.  Total NGL pricing per barrel after realized cash-settled hedging improved to $14.15 for second quarter 2017 compared to $11.57 per barrel in the prior-year quarter.  Range’s realized NGL pricing includes ethane extraction and is net of processing and certain other costs.   
     
  • Crude oil and condensate price realizations, before realized hedges, for the second quarter 2017 averaged $43.52 per barrel, or $4.84 below WTI, compared to $31.74, or $13.57 below WTI in the prior-year quarter. 

Capital Expenditures

Second quarter 2017 drilling expenditures of $280 million funded the drilling and completion of 35 (32 net) wells.  A 100% success rate was achieved.  In addition, during the quarter, $8.6 million was incurred on acreage purchases, $1.4 million on gas gathering systems and $7.1 million on seismic expense.  Range is on target with its $1.15 billion capital budget for 2017. 

Financial Position and Liquidity

At June 30, 2017, Range had total debt outstanding of $3.9 billion, before amortization of debt issuance costs and premium, consisting of $2.9 billion in senior notes, $954 million in bank debt and $49 million in senior subordinated notes.  The outstanding bank debt of $954 million combined with $286 million of undrawn letters of credit provides committed liquidity of $760 million.

Operational Discussion

Range has updated its investor presentation. Please see www.rangeresources.com under the Investors tab, “Company Presentations” area, for the presentation entitled, “Company Presentation – August 1, 2017”.

The table below summarizes second quarter activity and the number of wells expected to be turned in line (TIL) for the remainder of 2017:

    2017

  Wells TIL -
First
 Quarter
Wells TIL -
Second
Quarter
Wells TIL -
3rd and 4th
Quarters
Planned Annual
Total Wells to
Sales
Super-Rich Area   6 8 18 32
Wet Area   10 5 28 43
Dry- SW   6 8 22 36
Dry- NE   2 2
Total Marcellus   22 23 68 113
           
Upper Red   19 3 12 34
Lower Red   5 3 5 13
Pink   3 3 6
Extension Area   3 3
Total N. LA.   27 6 23 56
           
Company Total   49 29 91 169
           

Appalachia Division

Division production for second quarter 2017 averaged 1.5 net Bcfe per day, a 9% increase over the prior-year quarter.  The southwest properties averaged 1,344 net Mmcfe per day during the quarter, a 13% increase over the prior-year quarter.  The northeast properties averaged 155 net Mmcf per day during the quarter, a 17% decrease over the prior-year quarter.  The division brought on line 23 wells in the second quarter, eight in the super-rich area, five in the wet area, eight in the southwest dry area and two in the northeast dry area.

Significantly, two exceptional pads were brought on line in June, one on the eastern edge and one on the western edge of Range’s southwest acreage position.  When combined with the pad announced in the first quarter on the northern portion of the super-rich area, near the planned Harmon Creek processing plant, and the pad announced in the fourth quarter on the southern edge of the wet gas area, the results bolster Range’s confidence in the quality of the 515,000 acreage position in southwest Pennsylvania.  Results from these pads are summarized below:

  • On the western edge of the super-rich area, a seven well pad was recently completed with an average IP per well of 29.1 Mmcfe per day (73% liquids), and an average lateral length of 10,685 feet with 54 stages.
  • On the eastern edge of the dry gas area, a four well pad was recently brought on line with an average IP per well of 30.0 Mmcf per day, and an average lateral length of 11,100 feet with 56 stages.  Two of the four wells have lateral lengths in excess of 15,000 feet.
  • In the northern portion of Range’s super-rich acreage, Range announced results in the first quarter from two wells brought on line from a four well pad, near the planned Harmon Creek processing plant.  An additional two wells were brought on line in the second quarter, with continued outstanding results.  The average IP per well for the 4 well pad is 29.5 Mmcfe per day (67% liquids), a 30-day average IP of 19.6 Mmcfe per day and an average lateral length of 9,197 feet with 46 stages.
  • On the southern edge of our wet gas area, Range announced a four well pad on the fourth quarter conference call now expected to average over 4.0 Bcfe per 1,000 feet of lateral.

Range continues to improve capital efficiency by drilling longer laterals, lowering costs and increasing recoveries with approximately one-third of 2017 wells expected to be drilled from existing pads.  Lateral lengths for wells brought on line in the first half of 2017 averaged approximately 7,500 feet, but are expected to average over 9,500 feet in the second half of the year.  Recent development plans have also included the application of technologies such as real-time data streaming, advanced data visualization and machine learning to optimize completions and production.  Recent well results demonstrate the potential gains from using this technology to identify opportunities for improved performance.

North Louisiana Division

Production for the division in the second quarter of 2017 averaged 416 net Mmcfe per day, an increase of 5% from the previous quarter.  Late in the second quarter, the division brought on line six wells, consisting of three Upper Red wells and three Lower Red wells.

The division continues to focus on Terryville while methodically testing and delineating other areas.  Significant progress has been made in lowering the cost to drill and complete a typical 7,500 foot lateral well in Terryville, currently at $7.4 million.  As previously discussed, production from the wells brought to sales in early 2017 were below expectations.  These included wells that were drilled prior to the acquisition, but not completed.  In addition, Range experimented with changes to completion designs and more specifically, fluid intensity, in an attempt to mitigate the impact to offset wells.  These wells on average were stimulated with approximately 40% less fluid per foot compared to typical Terryville completions, while utilizing the same proppant per foot.  The initial production response in the wells has been below expectations by a similar percentage, with a flatter decline profile, suggesting the wells were under-stimulated.  Going forward, Range is planning to return to the larger fluid designs. 

In the expansion areas, the two wells previously announced (one to the east and one to the west of Vernon field), continue to perform well.  Gas in place estimates for the area are 400 Bcf per square mile and plans are underway to offset each of these expansion wells with another horizontal well.  The offset wells are expected to spud in the third quarter with results near year-end.  In addition, the Company plans to drill two vertical wells in the area to better determine reservoir properties and identify the optimal target of the six potential intervals. 

Guidance – 2017 

2017 Production per day Guidance

Range’s third quarter production is expected to be 1,970 Mmcfe per day.  Production for the fourth quarter is expected to be 2,170 Mmcfe per day, which is a 17% increase compared to the prior-year quarter.  This results in annual production growth of 30%.

The reduction in annual production guidance is primarily driven by early 2017 production results from North Louisiana, as discussed above.  In addition, non-recurring timing delays on several well pads in southwest Pennsylvania will impact our full year 2017 production.  
           
3Q 2017 Expense Guidance                                             

Direct operating expense: $0.17 - $0.18 per mcfe
Transportation, gathering, processing and compression
  expense:
$1.05 - $1.07 per mcfe
Production tax expense: $0.05 - $0.06 per mcfe
Exploration expense: $15.0 - $18.0 million
Unproved property impairment expense: $20.0 - $23.0 million
G&A expense: $0.21 - $0.23 per mcfe
Interest expense: $0.26 - $0.28 per mcfe
DD&A expense: $0.86 - $0.88 per mcfe
Net brokered gas marketing expense: ~$3.0 million

2017 Differentials

Based on current market pricing indications, Range expects to receive the following pre-hedge differentials for its production in 2017. 

Natural Gas: NYMEX minus $0.30
Natural Gas Liquids (including ethane): 28% - 30% of WTI
Oil/Condensate: WTI minus $5.00 to $6.00

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 2017 natural gas production hedged at a weighted average floor price of approximately $3.23 per mcf, and over one Bcf per day of first quarter 2018 production hedged at $3.43.  Similarly, Range has hedged approximately 65% of its remaining 2017 projected crude oil production at a floor price of approximately $56 and approximately 65% of its composite 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

Range has also hedged basis differentials to limit volatility between NYMEX and regional prices, primarily in the Appalachian region.  The fair value of the basis hedges as of June 30, 2017 was a loss of $10.5 million.

Conference Call Information

A conference call to review the financial results is scheduled on Wednesday, August 2 at 9:00 a.m. ET. To participate in the call, please dial 866-900-7525 and provide conference code 48401322 about 10 minutes prior to the scheduled start time.

A simultaneous webcast of the call may be accessed at www.rangeresources.com. The webcast will be archived for replay on the Company's website until September 2, 2017.

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 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 and 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, processing 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, processing and compression expense, such information is now reported in various lines of the statement of operations.  The Company believes that it is important to furnish a table reflecting the details of the various components of each statement of operations 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, processing and compression expense which historically were reported as natural gas, NGLs and oil sales.  This information is intended to bridge the gap between various readers’ understanding and fully disclose the information needed.

The Company discloses in this release the detailed components of many of the single line items shown in the GAAP financial statements included in the Company’s Annual Report on Form 10-K.  The Company believes that it is important to furnish this detail of the various components comprising each line of the Statement 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 natural gas, NGL and oil producer with operations focused in stacked-pay projects in the Appalachian Basin and North Louisiana.  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 well costs, expected asset sales, well productivity, future liquidity and financial resilience, anticipated exports and related financial impact, NGL market supply and demand, improving commodity fundamentals and pricing, future capital efficiencies, future shareholder value, emerging plays, capital spending, anticipated drilling and completion activity, acreage prospectivity, expected pipeline utilization and future guidance information are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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.  Further information on risks and uncertainties is available in Range's filings with the Securities and Exchange Commission (SEC), which are incorporated by reference.  Range undertakes no obligation to publicly update or revise any forward-looking statements.

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 services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, field spacing rules, recoveries of gas in place, length of horizontal laterals, actual drilling results, including geological and mechanical factors affecting recovery rates and other factors.  Estimates of 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. 

2017-07
SOURCE: Range Resources Corporation

 
RANGE RESOURCES CORPORATION
 
STATEMENTS OF OPERATIONS                                              
Based on GAAP reported earnings with additional                                              
details of items included in each line in Form 10-Q                                              
(Unaudited, in thousands, except per share data)                                              
                                               
  Three Months Ended June 30,     Six Months Ended June 30,  
    2017       2016       %       2017       2016       %  
                                               
Revenues and other income:                                              
Natural gas, NGLs and oil sales (a) $ 506,137     $ 224,606             $ 1,065,587     $ 434,093          
Derivative fair value income (loss)   111,195       (162,798 )             276,752       (75,890 )        
Brokered natural gas, marketing and other (b)   56,016       39,473               107,597       74,331          
ARO settlement (loss) (b)   (40 )     (6 )             (40 )     (8 )        
Other (b)   (197 )     522               (130 )     684          
Total revenues and other income   673,111       101,797       561 %     1,449,766       433,210       235 %
                                               
Costs and expenses:                                              
Direct operating   30,898       19,975               58,397       43,441          
Direct operating – non-cash stock-based compensation (c)   522       696               1,046       1,284          
Transportation, gathering, processing and compression   191,590       136,844               369,238       262,107          
Production and ad valorem taxes   9,969       6,049               19,132       11,936          
Brokered natural gas and marketing   55,469       40,547               108,756       76,589          
Brokered natural gas and marketing – non-cash
stock-based compensation (c)
  388       378               651       894          
Exploration   13,970       6,414               21,967       10,637          
Exploration – non-cash stock-based compensation (c)   528       371               1,035       1,061          
Abandonment and impairment of unproved properties   5,193       7,059               9,613       17,687          
General and administrative   37,203       29,968               73,158       58,391          
General and administrative – non-cash stock-based
compensation (c)
  14,279       15,443               25,197       26,556          
General and administrative – lawsuit settlements   540       403               1,163       1,324          
General and administrative – bad debt expense   300       250               300       450          
Memorial merger expenses         2,621                     2,621          
Termination costs   (50 )     5               2,400       167          
Termination costs – non-cash stock-based compensation (c)   (46 )                   1,696                
Deferred compensation plan (d)   (14,466 )     25,746               (27,635 )     41,802          
Interest expense   47,926       37,758               95,027       75,497          
Depletion, depreciation and amortization   152,504       122,390               302,325       242,951          
Impairment of proved properties and other assets                             43,040          
(Gain) loss on sale of assets   (807 )     3,304               (23,407 )     4,947          
Total costs and expenses   545,910       456,221       20 %     1,040,059       923,382       13 %
                                               
Income (loss) before income taxes   127,201       (354,424 )             409,707       (490,172 )        
                                               
Income tax expense (benefit):                                              
Current                                      
Deferred   57,651       (129,488 )             170,046       (171,464 )        
    57,651       (129,488 )             170,046       (171,464 )        
                                               
Net  income (loss) $ 69,550     $ (224,936 )           $ 239,661     $ (318,708 )        
                                               
Net  Income (Loss) Per Common Share:                                              
Basic $ 0.28     $ (1.35 )           $ 0.97     $ (1.91 )        
Diluted $ 0.28     $ (1.35 )           $ 0.97     $ (1.91 )        
                                               
Weighted average common shares outstanding, as reported:                                              
Basic   245,177       167,126       47 %     244,916       166,964       47 %
Diluted   245,335       167,126       47 %     245,242       166,964       47 %

(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)   June 30,       December 31,  
    2017       2016  
    (Unaudited)       (Audited)  
Assets              
Current assets $ 280,055     $ 268,605  
Derivative assets   97,429       13,483  
Goodwill   1,646,710       1,654,292  
Natural gas and oil properties, successful efforts method   9,505,442       9,256,337  
Transportation and field assets   16,160       16,873  
Other   75,540       72,655  
  $ 11,621,336     $ 11,282,245  
               
Liabilities and Stockholders’ Equity              
Current liabilities $ 584,821     $ 530,373  
Asset retirement obligations   7,271       7,271  
Derivative liabilities   4,900       165,009  
               
Bank debt   949,948       876,428  
Senior notes   2,850,100       2,848,591  
Senior subordinated notes   48,541       48,498  
Total debt   3,848,589       3,773,517  
               
Deferred tax liability   1,114,583       943,343  
Derivative liabilities   541       24,491  
Deferred compensation liability   96,854       119,231  
Asset retirement obligations and other liabilities   301,886       310,642  
               
Common stock and retained earnings   5,662,490       5,409,577  
Common stock held in treasury stock   (599 )     (1,209 )
Total stockholders’ equity   5,661,891       5,408,368  
  $ 11,621,336     $ 11,282,245  
               


RECONCILIATION OF TOTAL REVENUES AND
OTHER INCOME TO TOTAL REVENUE
EXCLUDING CERTAIN ITEMS, a non-GAAP measure
    
(Unaudited, in thousands)                              
  Three Months Ended June 30,     Six Months Ended June 30,    
    2017       2016       %       2017       2016       %  
                                               
Total revenues and other income, as reported $ 673,111     $ 101,797       561 %   $ 1,449,766     $ 433,210       235 %
Adjustment for certain special items:                                              
Total change in fair value related to derivatives
prior to settlement (gain) loss
  (107,809 )     260,876               (277,547 )     283,434          
ARO settlement loss   40       6               40       8          
Total revenues, as adjusted, non-GAAP $ 565,342     $ 362,679       56 %   $ 1,172,259     $ 716,652       64 %
                                               


RANGE RESOURCES CORPORATION
 
CASH FLOWS FROM OPERATING ACTIVITIES                                
(Unaudited in thousands)                                
                                 
  Three Months Ended June 30,       Six Months Ended June 30,  
    2017       2016         2017       2016  
                               
Net income (loss) $ 69,550     $ (224,936 )   $ 239,661     $ (318,708 )
Adjustments to reconcile net cash provided from continuing operations:                              
Deferred income tax expense (benefit)    57,651       (129,488 )     170,046       (171,464 )
Depletion, depreciation, amortization and impairment   152,504       122,390       302,325       285,991  
Exploration dry hole costs   161             161        
Abandonment and impairment of unproved properties   5,193       7,059       9,613       17,687  
Derivative fair value adjustment   (111,195 )     162,798       (276,752 )     75,890  
Cash settlements on derivative financial instruments that do not qualify for hedge accounting   3,387       98,078       (794 )     207,544  
Allowance for bad debts   300       250       300       450  
Amortization of deferred issuance costs, loss on extinguishment of debt, and other   1,247       1,730       2,557       3,437  
Deferred and stock-based compensation   990       42,590       1,952       71,718  
(Gain) loss on sale of assets and other   (807 )     3,304       (23,407 )     4,947  
                               
Changes in working capital:                              
Accounts receivable   (8,920 )     23,203       (13,610 )     41,955  
Inventory and other   848       5,167       3,716       10,500  
Accounts payable   (5,958 )     (31,116 )     18,426       (19,194 )
Accrued liabilities and other   20,515       1,387       (22,866 )     (37,552 )
Net changes in working capital   6,485       (1,359 )     (14,334 )     (4,291 )
Net cash provided from operating activities $ 185,466     $ 82,416     $ 411,328     $ 173,201  
                               
                               
                               
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 June 30,       Six Months Ended June 30,  
    2017       2016         2017       2016  
Net cash provided from operating activities, as reported $ 185,466     $ 82,416     $ 411,328     $ 173,201  
Net changes in working capital   (6,485 )     1,359       14,334       4,291  
Exploration expense   13,809       6,414       21,806       10,637  
Memorial merger expenses         2,621             2,621  
Lawsuit settlements   540       403       1,163       1,324  
Termination costs   (50 )     5       2,400       167  
Non-cash compensation adjustment   801       126       1,092       42  
Cash flow from operations before changes in working capital – non-GAAP measure $ 194,081     $ 93,344     $ 452,123     $ 192,283  
                               
                               
                               
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING                              
(Unaudited, in thousands)                              
                               
  Three Months Ended June 30,         Six Months Ended June 30,  
    2017       2016         2017       2016  
Basic:                              
Weighted average shares outstanding   247,852       169,907       247,622       169,745  
Stock held by deferred compensation plan   (2,675 )     (2,781 )     (2,706 )     (2,781 )
Adjusted basic   245,177       167,126       244,916       166,964  
                               
Dilutive:                              
Weighted average shares outstanding   247,852       169,907       247,622       169,745  
Dilutive stock options under treasury method   (2,517 )     (2,781 )     (2,380 )     (2,781 )
Adjusted dilutive   245,335       167,126       245,242       166,964  
                               
                               


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 June 30,     Six Months Ended June 30,  
    2017       2016       %       2017       2016       %  
Natural gas, NGL and oil sales components:                                              
Natural gas sales $ 336,534     $ 124,187             $ 707,886     $ 266,622          
NGL sales   123,784       73,456               261,847       123,618          
Oil sales   45,819       26,963               95,854       43,853          
Total oil and gas sales, as reported $ 506,137     $ 224,606       125 %   $ 1,065,587     $ 434,093       145 %
                                               
Derivative fair value income (loss), as reported: $ 111,195     $ (162,798 )           $ 276,752     $ (75,890 )        
Cash settlements on derivative financial instruments – (gain) loss:                                              
Natural gas   (942 )     (84,648 )             (8,397 )     (170,163 )        
NGLs   3,131       (6,003 )             17,464       (16,881 )        
Crude Oil   (5,575 )     (7,427 )             (8,272 )     (20,500 )        
Total change in fair value related to derivatives prior to settlement, a
non-GAAP measure
$ 107,809     $ (260,876 )           $ 277,547     $ (283,434 )        
                                               
Transportation, gathering, processing and compression components:                                              
Natural gas $ 129,557     $ 96,298             $ 251,750     $ 188,890          
NGLs   62,033       40,546               117,488       73,217          
Total transportation, gathering, processing and compression, as reported $ 191,590     $ 136,844             $ 369,238     $ 262,107          
                                               
Natural gas, NGL and oil sales, including cash-settled derivatives: (c)                                              
Natural gas sales $ 337,476     $ 208,835             $ 716,283     $ 436,785          
NGL sales   120,653       79,459               244,383       140,499          
Oil sales   51,394       34,390               104,126       64,353          
Total $ 509,523     $ 322,684       58 %     1,064,792       641,637       66 %
                                               
Production of oil and gas during the periods (a):                                              
Natural gas (mcf)   119,487,827       82,997,371       44 %     235,744,164       167,864,741       40 %
NGL (bbl)   8,524,267       6,865,948       24 %     17,060,995       12,840,682       33 %
Oil (bbl)   1,052,784       849,538       24 %     2,118,070       1,693,879       25 %
Gas equivalent (mcfe) (b)   176,950,133       129,290,287       37 %     350,818,554       255,072,107       38 %
                                               
Production of oil and gas – average per day (a):                                              
Natural gas (mcf)   1,313,053       912,059       44 %     1,302,454       922,334       41 %
NGL (bbl)   93,673       75,450       24 %     94,260       70,553       34 %
Oil (bbl)   11,569       9,336       24 %     11,702       9,307       26 %
Gas equivalent (mcfe) (b)   1,944,507       1,420,772       37 %     1,938,224       1,401,495       38 %
                                               
Average prices, including cash-settled hedges that qualify for
hedge accounting before third party transportation costs:
                                             
Natural gas (mcf) $ 2.82     $ 1.50       88 %   $ 3.00     $ 1.59       89 %
NGL (bbl) $ 14.52     $ 10.70       36 %   $ 15.35     $ 9.63       59 %
Oil (bbl) $ 43.52     $ 31.74       37 %   $ 45.26     $ 25.89       75 %
Gas equivalent (mcfe) (b) $ 2.86     $ 1.74       64 %   $ 3.04     $ 1.70       79 %
                                               
Average prices, including cash-settled hedges and derivatives
before third party transportation costs: (c)
                                             
Natural gas (mcf) $ 2.82     $ 2.52       12 %   $ 3.04     $ 2.60       17 %
NGL (bbl) $ 14.15     $ 11.57       22 %   $ 14.32     $ 10.94       31 %
Oil (bbl) $ 48.82     $ 40.48       21 %   $ 49.16     $ 37.99       29 %
Gas equivalent (mcfe) (b) $ 2.88     $ 2.50       15 %   $ 3.04     $ 2.52       21 %
                                               
Average prices, including cash-settled hedges and derivatives: (d)                                              
Natural gas (mcf) $ 1.74     $ 1.36       28 %   $ 1.97     $ 1.48       33 %
NGL (bbl) $ 6.88     $ 5.67       21 %   $ 7.44     $ 5.24       42 %
Oil (bbl) $ 48.82     $ 40.48       21 %   $ 49.16     $ 37.99       29 %
Gas equivalent (mcfe) (b) $ 1.80     $ 1.44       25 %   $ 1.98     $ 1.49       33 %
                                               
Transportation, gathering and compression expense per mcfe $ 1.08     $ 1.06       2 %   $ 1.05     $ 1.03       2 %

(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 BEFORE INCOME TAXES
AS REPORTED TO INCOME BEFORE INCOME TAXES
EXCLUDING CERTAIN ITEMS, a non-GAAP measure
   
(Unaudited, in thousands, except per share data)                                
  Three Months Ended
June 30,
    Six Months Ended
June 30,
   
    2017       2016       2017       2016    
                                 
Income (loss) before income taxes, as reported $ 127,201     $ (354,424 )   $ 409,707     $ (490,172 )  
Adjustment for certain special items:                                
(Gain) loss on sale of assets   (807 )     3,304       (23,407 )     4,947    
Loss (gain) on ARO settlements   40       6       40       8    
Change in fair value related to derivatives prior to settlement   (107,809 )     260,876       (277,547 )     283,434    
Abandonment and impairment of unproved properties   5,193       7,059       9,613       17,687    
Impairment of proved property                     43,040    
Memorial merger expenses         2,621             2,621    
Lawsuit settlements   540       403       1,163       1,324    
Termination costs   (50 )     5       2,400       167    
Termination costs – non-cash stock-based compensation   (46 )           1,696          
Brokered natural gas and marketing – non-cash stock-based
compensation
  388       378       651       894    
Direct operating – non-cash stock-based compensation   522       696       1,046       1,284    
Exploration expenses – non-cash stock-based compensation   528       371       1,035       1,061    
General & administrative – non-cash stock-based compensation   14,279       15,443       25,197       26,556    
Deferred compensation plan – non-cash adjustment   (14,466 )     25,746       (27,635 )     41,802    
                                 
Income (loss) before income taxes, as adjusted   25,513       (37,516 )     123,959       (65,347 )  
                                 
Income tax expense, as adjusted                                
Current                        
Deferred (a)   9,622       (14,269 )     47,250       (24,966 )  
Net income (loss) excluding certain items, a non-GAAP measure $ 15,891     $ (23,247 )   $ 76,709     $ (40,381 )  
                                 
Non-GAAP income per common share                                
Basic $ 0.06     $ (0.14 )   $ 0.31     $ (0.24 )  
Diluted $ 0.06     $ (0.14 )   $ 0.31     $ (0.24 )  
                                 
Non-GAAP diluted shares outstanding, if dilutive   245,335       167,621       245,242       167,098    

(a)  Deferred taxes for 2017 and 2016 are estimated to be approximately 38%.

   
RANGE RESOURCES CORPORATION  
   
HEDGING POSITION AS OF JULY 24, 2017  
(Unaudited) –  
          Daily Volume       Hedge Price  
  Gas  1                  
                     
  3Q 2017 Swaps       841,196 Mmbtu       $3.19  
  4Q 2017 Swaps       867,935 Mmbtu       $3.20  
  1Q 2018 Swaps       1,020,000 Mmbtu       $3.43  
  2Q-4Q 2018 Swaps2       260,000 Mmbtu       $2.98  
                     
                     
  3Q 2017 Collars       122,609 Mmbtu       $3.45 x $4.11  
  4Q 2017 Collars       122,609 Mmbtu       $3.45 x $4.11  
  1Q 2018 Collars       60,000 Mmbtu       $3.40 x $3.76  
                     
                     
  3Q 2017 Puts       185,870 Mmbtu       $3.50 ($0.32) 3  
  4Q 2017 Puts       185,870 Mmbtu       $3.50 ($0.32) 3  
                     
  Oil                  
                     
  3Q 2017 Swaps       8,761 bbls       $56.38  
  4Q 2017 Swaps       8,761 bbls       $56.38  
  2018 Swaps       5,250 bbls       $53.20  
                     
  2019 Swaps       500 bbls       $51.75  
                     
  C2 Ethane                  
                     
  3Q 2017 Swaps       3,000 bbls       $0.27/gallon  
  4Q 2017 Swaps       3,000 bbls       $0.27/gallon  
  1H 2018 Swaps       250 bbls       $0.29/gallon  
                     
  C3 Propane                  
                     
  3Q 2017 Swaps       13,826 bbls       $0.56/gallon  
  4Q 2017 Swaps       14,076 bbls       $0.56/gallon  
  2018 Swaps       7,199 bbls       $0.61/gallon  
                     
  C4 Normal Butane                  
                     
  3Q 2017 Swaps       7,750 bbls       $0.74/gallon  
  4Q 2017 Swaps       8,000 bbls       $0.75/gallon  
  2018 Swaps       4,250 bbls       $0.81/gallon  
                     
  C5 Natural Gasoline                  
                     
  3Q 2017 Swaps       5,500 bbls       $1.07/gallon  
  4Q 2017 Swaps       5,500 bbls       $1.07/gallon  
  2018 Swaps       1,500 bbls       $1.19/gallon  

(1) Range has deferred calls at a strike of $3.70 for 2H17. Total volume of 4,300,000 Mmbtu with a deferred premium price of $0.27 paid to Range
(2) Includes swaps of 40,000 Mmbtu per day at $3.05 which could be extended into 2019
(3) Notes deferred premium on puts

NOTE:  SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS

Investor Contacts:

Laith Sando, Vice President – Investor Relations
817-869-4267
lsando@rangeresources.com

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

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

Josh Stevens, Financial Analyst
817-869-1564
jrstevens@rangeresources.com           

Media Contact:

Michael Mackin, Director of Public Affairs
724-873-3224
mmackin@rangeresources.com

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