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Range Announces Third Quarter 2017 Results

FORT WORTH, Texas, Oct. 24, 2017 (GLOBE NEWSWIRE) -- RANGE RESOURCES CORPORATION (NYSE:RRC) today announced its third quarter 2017 financial results.

Highlights –

  • Year to date 2017 GAAP net income was $112 million, or $0.45 per diluted share, compared to a net loss of $361 million, or $2.10 per share in the comparable period of 2016
  • Year to date net cash provided from operating activities (GAAP) was $601 million, compared to $206 million in the comparable period of 2016, an improvement of 192% while year to date cash flow from operations before changes in working capital, (non-GAAP), reached $656 million, compared to $316 million, an improvement of 108%
  • Two recently completed Marcellus super-rich pads were brought on line with average per well 24-hour IPs of 41.3 Mmcfe per day, containing 64% liquids, with 20% being condensate
  • Record third quarter production totaled 1.99 Bcfe per day, an increase of 32% compared to the prior-year quarter
  • Third quarter NGL pre-hedge realized prices improved to $16.93 per barrel versus $11.17 per barrel in the prior-year quarter, a 52% improvement
  • Third quarter natural gas price differential including the impact of basis hedges improved to minus ($0.51) per mcf, compared to minus ($0.68) in the prior-year quarter, a 25% improvement
  • Third quarter crude oil and condensate realized prices improved to $4.80 per barrel below WTI versus $5.81 per barrel below WTI in the prior-year quarter, a 17% improvement

Commenting, Jeff Ventura, the Company’s CEO said, “This is an exciting time for Range as we are nearing an inflection point in our Marcellus development and as we continue to improve well results in North Louisiana. In the Marcellus, the last of our natural gas transportation projects are coming on line over the next few months which will allow us to develop our Marcellus position over the long-term while having access to better priced markets. This buildout process has been years in the making and we believe Range’s combination of high-quality assets and infrastructure provide a solid foundation to deliver strong returns for many years.”

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. “Cash margin” as used in this release represents cash revenues related to production less cash expenses related to production, which are comprised of expense categories included in “unit costs” excluding depletion, depreciation and amortization, but including brokered natural gas and marketing. “Cash margin per mcfe” represents cash margin 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.

Third Quarter 2017

GAAP revenues for the third quarter of 2017 totaled $482 million, a 17% increase over the prior-year quarter. GAAP net cash provided from operating activities including changes in working capital was $189 million versus $33 million in third quarter 2016 and a GAAP net loss of $128 million ($0.52 per diluted share) versus a loss of $42 million ($0.23 per diluted share) in the prior-year quarter. Third quarter 2017 included $88 million in derivative losses due to increased commodity prices, compared to a $65 million gain in third quarter 2016. Third quarter 2017 also included $43 million in unproved property impairment compared to $6 million in third quarter 2016, as a result of increasing lease expirations due to budgeting constraints, primarily in North Louisiana. Proved property impairment of $64 million was recorded in third quarter 2017 on properties located in Oklahoma and the Texas Panhandle.

Non-GAAP revenues for third quarter 2017 totaled $587 million, a 46% increase compared to third quarter 2016 and cash flow from operations before changes in working capital, a non-GAAP measure, reached $204 million, compared to $123 million in third quarter 2016. Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $12 million ($0.05 per diluted share) compared to a loss of $10 million ($0.06 per diluted share) for third quarter 2016.

The Company’s total unit costs were $2.66 per mcfe, 1% lower than third quarter 2016, while cash unit costs were $1.78 per mcfe, 2% higher than the prior-year quarter. General and administrative, interest and depletion, depreciation and amortization expenses per mcfe continued to trend lower. Transportation, gathering, processing and compression expense increased by $0.05 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. Direct operating costs increased by $0.04 per mcfe over the prior-year quarter due to higher workover and well service costs. Production, and ad valorem taxes increased by $0.02 per mcfe due to a one-time production tax adjustment.

Expenses 3Q 2017
(per mcfe)
3Q 2016
(per mcfe)
Increase
(Decrease)
Direct operating $ 0.20 $ 0.16 25%
Transportation, gathering, processing and compression 1.05 1.00 5%
Production and ad valorem taxes 0.07 0.05 40%
General and administrative 0.20 0.21 (5%)
Interest expense 0.27 0.33 (18%)
Total cash unit costs(a) 1.78 1.75 2%
Depletion, depreciation and amortization 0.87 0.95 (8%)
Total unit costs(a) $ 2.66 $ 2.70 (1%)
(a) Totals may not add due to rounding.


Third 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 $2.78 per mcfe, a 27% 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 third quarter 2017 were: natural gas – 1,322 Mmcf per day ($2.48 per mcf), NGLs – 96,661 barrels per day ($16.93 per barrel) and crude oil and condensate – 14,003 barrels per day ($43.34 per barrel).
  • The average Company natural gas price differential including the impact of basis hedges for third quarter 2017 improved to minus ($0.51) per mcf, compared to minus ($0.68) in third quarter 2016. The third quarter 2017 average natural gas price, before all hedging settlements, was $2.48 per mcf as compared to $2.11 per mcf in the prior-year quarter.
  • Pre-hedge NGL realizations improved to 35% of West Texas Intermediate (“WTI”) crude oil in third quarter 2017, compared to 25% of WTI in third quarter 2016. Total NGL pricing per barrel before realized cash-settled hedging improved to $16.93 for third quarter 2017 compared to $11.17 per barrel in the prior-year quarter. Range’s realized NGL pricing includes ethane extraction and is net of processing and certain other costs. On a gross basis, without processing fees, Range's Marcellus C3+ NGL barrel for the third quarter was approximately 69% of WTI.
  • Crude oil and condensate price realizations, before realized hedges, for the third quarter 2017 improved to $43.34, or $4.80 per barrel below WTI, compared to $39.15, or $5.81 per barrel below WTI in the prior-year quarter.

Cash Margins

Third quarter cash margins improved to $1.09 per mcfe compared to $0.82 per mcfe in third quarter 2016, an improvement of 33%. Year to date cash margins improved to $1.21 per mcfe, versus $0.77 per mcfe in the comparable period of 2016, an improvement of 57%. See the attached table that reconciles income (loss) before income taxes with cash margins, a non-GAAP measure.

Capital Expenditures

Third quarter 2017 drilling expenditures of $305 million funded the drilling and completion of 35 (33 net) wells. A 97% success rate was achieved. In addition, during the quarter, $7.8 million was incurred on acreage purchases, $3.5 million on gas gathering systems and $5.1 million on seismic expense. Range is on target with its $1.15 billion capital budget for 2017.

Financial Position and Liquidity

At September 30, 2017, Range had total debt outstanding of $4.0 billion, before amortization of debt issuance costs and premium, consisting of $2.9 billion in senior notes, $1.1 billion in bank debt and $49 million in senior subordinated notes. The outstanding bank debt of $1.1 billion combined with $286 million of undrawn letters of credit provides committed liquidity of $628 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 – October 24, 2017”.

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

2017

Wells TIL –
1st and 2nd
Quarters
Wells TIL –
3rd Quarter
Wells to be
TIL –
4th Quarter
Planned Annual
Total Wells
to Sales
Super-Rich Area 1411732
Wet Area 15101540
Dry- SW 1412439
Dry- NE 22
Total Marcellus 452246113
Upper Red 223934
Lower Red 8513
Pink 336
Extension Area 123
Total N. LA. 3371656
Company Total 782962169

Appalachia Division

Division production for third quarter 2017 averaged 1.60 net Bcfe per day, a 15% increase over the prior-year quarter. The southwest properties averaged 1.45 net Bcfe per day during the quarter, an 18% increase over the prior-year quarter. The northeast properties averaged 153 net Mmcf per day during the quarter, a 9% decrease over the prior-year quarter. The division brought on line 22 wells in the third quarter, 11 in the super-rich area, 10 in the wet area, and one in the southwest dry area. As shown in the table above, the number of wells brought on line will increase in the fourth quarter when prices are expected to improve and new pipeline infrastructure becomes available.

The division continues to drill longer laterals, thereby improving capital efficiency by lowering well costs per foot and increasing recoveries. Lateral lengths in the third quarter averaged over 11,700 feet compared to an average lateral length of less than 6,171 feet in third quarter 2016. Average lateral lengths of 10,000 feet or greater is the expectation for 2018 as the Company’s goal of holding acreage and capturing resource potential is essentially complete and the focus is now on maximizing operational efficiencies and improving returns. The combination of longer laterals and additional completion efficiencies has allowed Range to lower total well costs on a normalized basis by 25%, as compared to the previous year.

Two recent four well pads were completed in the super-rich area with seven wells turned to sales in the third quarter. Both pads are examples of impressive liquids production in addition to gas. One pad had an average 24-hour IP per well of 41.7 Mmcfe per day consisting of 16.2 Mmcf of gas, 1,089 barrels of condensate and 3,172 barrels of NGLs. The wells were completed with an average lateral length of 9,478 feet with 48 stages. The other pad had an average 24-hour IP of 40.6 Mmcfe per day consisting of 12.7 Mmcf of gas, 1,755 barrels of condensate and 2,904 barrels of NGLs. The wells were completed with an average lateral length of 9,880 feet with 50 stages.

North Louisiana Division

Production for the division in the third quarter of 2017 averaged 360 net Mmcfe per day. The division brought seven wells on line during the quarter. The last three wells were previously disclosed at an energy conference in September, as they represent the first wells Range has operated from start to finish. The three wells continue to perform well, with the two Upper Red wells having 30 day rates to sales of 25.8 and 20.7 Mmcfe per day, with lateral lengths of 7,427 feet and 6,827 feet. A Lower Deep Pink well on the same pad averaged 20.2 Mmcfe per day to sales for 30 days. It appears to be the best Pink interval well drilled in the field to date.

Activity in the extension area to the south of Terryville is continuing, building upon the encouraging results previously announced. A well was recently completed in a new fault block south of Terryville and north of Driscoll field. Early production data is promising, with production rates over 3.5 Mmcf per day per 1,000 feet of lateral. Two offset horizontal wells to the east and west of Vernon field are planned with one well currently drilling.

The division expects to bring on line 16 wells in the fourth quarter.

Marketing and Transportation

During the next two quarters, several incremental natural gas transportation projects in southwest Appalachia are expected to commence operations. Once in service, Range’s natural gas transportation portfolio will be largely complete, allowing Marcellus natural gas volumes to be directed toward expanding markets, especially the Gulf Coast where significant incremental natural gas demand is expected over the next several years.

TransCanada’s Rayne/Leach Xpress project and Enbridge’s TETCO Adair Southwest project are both expected to be in service before the end of 2017, and Energy Transfer’s Rover Phase 2 project is expected to be available in early 2018. In combination, these projects will add an additional 900,000 Mmbtu per day to Range’s gross capacity and are expected to improve corporate natural gas differentials to NYMEX minus $0.15 or better during 2018. As a result of these additional transportation commitments, Range is expecting its transportation, gathering, compression and processing expense to increase to ~$1.20 per Mcfe when all three projects are fully in service before trending back down as capacity is fully utilized.

Range is also well-positioned to benefit from the improving NGL macro environment. The Company reported NGL pre-hedge pricing improved to 35% of WTI in the third quarter, compared to 25% of WTI a year ago. This substantial improvement in NGL pricing realizations was led by propane, which achieved multi-year highs in September. As the only producer with propane capacity on Mariner East 1, Range has been able to capture above Mont Belvieu prices by exporting the majority of its propane to international markets since early 2016. As a result of Range’s projects currently in place, and improving NGL market fundamentals, Range expects fourth quarter 2017 pre-hedge NGL differentials to be approximately 35% of WTI. Based on current strip prices, Range anticipates pre-hedge NGL realizations of 30% to 32% of WTI in 2018.

Guidance – 2017

2017 Production per day Guidance

Range’s fourth quarter production is expected to be 2,170 Mmcfe per day. This results in annual production growth of 30%., or organic growth of approximately 10%.

4Q 2017 Expense Guidance

Direct operating expense:$0.18 - $0.20 per mcfe
Transportation, gathering, processing and compression expense: $1.05 - $1.07 per mcfe
Production tax expense:$0.06 - $0.07 per mcfe
Exploration expense:$15.0 - $17.0 million
Unproved property impairment expense:$22.0 - $24.0 million
G&A expense:$0.21 - $0.23 per mcfe
Interest expense:$0.27 - $0.29 per mcfe
DD&A expense:$0.86 - $0.88 per mcfe
Net brokered gas marketing expense:~$3.0 million

Price Differentials

Based on current market pricing indications, Range expects to receive the following pre-hedge differentials for its production in the full year of 2017 and 2018.

20172018
Natural Gas:NYMEX minus $0.30NYMEX minus $0.15 or better
Natural Gas Liquids (with ethane): 32% of WTI30% - 32% of WTI
Oil/Condensate:WTI minus $5.00 to $6.00 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 $3.24 per mcf, and over 50% of 2018 production hedged at approximately $3.14. Similarly, Range has hedged approximately 70% of its remaining 2017 projected crude oil production at a floor price of approximately $56.00 and approximately 70% 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 September 30, 2017 was a loss of $4.7 million. Range also hedges propane prices with swap contracts that lock in the differential between Mont Belvieu and international propane indices. The fair value of these contracts was a gain of $1.1 million on September 30, 2017.

Conference Call Information

A conference call to review the financial results is scheduled on Wednesday, October 25 at 9:00 a.m. ET. To participate in the call, please dial 866-900-7525 and provide conference code 95985702 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 November 25, 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.

Cash margin as used in this release represents cash revenues related to production less cash expenses related to production as shown in the table below. Cash margin per mcfe represents cash margin divided by production, and is similar to a unit based gross profit calculation as used in other industries, which can be useful in comparing a measure of gross profitability between time periods. A reconciliation is provided in the table between cash margin and the related GAAP measure of income (loss) before income taxes. On its website, the Company provides additional comparative information on prior periods for cash flow, non-GAAP earnings and cash margin 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.

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 External Affairs
724-743-6776
mmackin@rangeresources.com

www.rangeresources.com


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,
2017 2016 % 2017 2016 %
Revenues and other income:
Natural gas, NGLs and oil sales (a)$507,541 $304,477 $1,573,128 $738,570
Derivative fair value (loss)/income (88,426) 64,556 188,326 (11,334)
Brokered natural gas, marketing and other (b) 61,145 44,114 168,742 118,445
ARO settlement gain (loss) (b) 104 (6) 64 (14)
Other (b) 1,868 66 1,738 750
Total revenues and other income 482,232 413,207 17% 1,931,998 846,417 128%
Costs and expenses:
Direct operating 36,371 21,890 94,768 65,331
Direct operating – non-cash stock-based compensation (c) 517 497 1,563 1,781
Transportation, gathering, processing and compression 191,645 138,764 560,883 400,871
Production and ad valorem taxes 11,993 6,717 31,125 18,653
Brokered natural gas and marketing 59,384 44,167 168,140 120,756
Brokered natural gas and marketing – non-cash
stock-based compensation (c)
389 455 1,040 1,349
Exploration 22,206 6,335 44,173 16,972
Exploration – non-cash stock-based compensation (c) 561 608 1,596 1,669
Abandonment and impairment of unproved properties 42,568 6,082 52,181 23,769
General and administrative 36,461 29,428 109,619 87,819
General and administrative – non-cash stock-based
compensation (c)
9,959 11,126 35,156 37,682
General and administrative – lawsuit settlements 5,865 120 7,028 1,444
General and administrative – bad debt expense 750 350 1,050 800
Memorial merger expenses 33,791 36,412
Termination costs (16) 136 2,384 303
Termination costs – non-cash stock-based compensation (c) (31) 1,665
Deferred compensation plan (d) (9,203) (11,636) (36,838) 30,166
Interest expense 49,179 45,967 144,206 121,464
Depletion, depreciation and amortization 159,749 131,489 462,074 374,440
Impairment of proved properties and other assets 63,679 63,679 43,040
(Gain) loss on sale of assets (102) 2,597 (23,509) 7,544
Total costs and expenses 681,924 468,883 45% 1,721,983 1,392,265 24%
(Loss) income before income taxes (199,692) (55,676) -259% 210,015 (545,848) 138%
Income tax (benefit) expense:
Current
Deferred (71,992) (13,705) 98,054 (185,169)
(71,992) (13,705) 98,054 (185,169)
Net (loss) income$(127,700) $(41,971) -204% $111,961 $(360,679) 131%
Net (loss) income Per Common Share:
Basic$(0.52) $(0.23) $0.45 $(2.10)
Diluted$(0.52) $(0.23) $0.45 $(2.10)
Weighted average common shares outstanding, as reported:
Basic 245,244 180,683 36% 245,027 171,571 43%
Diluted 245,244 180,683 36% 245,280 171,571 43%
(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,
2017 2016
(Unaudited) (Audited)
Assets
Current assets$307,074 $268,605
Derivative assets 30,688 13,483
Goodwill 1,641,197 1,654,292
Natural gas and oil properties, successful efforts method 9,568,776 9,256,337
Transportation and field assets 15,604 16,873
Other 74,400 72,655
$11,637,739 $11,282,245
Liabilities and Stockholders’ Equity
Current liabilities$631,562 $530,373
Asset retirement obligations 7,271 7,271
Derivative liabilities 32,533 165,009
Bank debt 1,082,708 876,428
Senior notes 2,850,692 2,848,591
Senior subordinated notes 48,562 48,498
Total debt 3,981,962 3,773,517
Deferred tax liability 1,042,889 943,343
Derivative liabilities 16,292 24,491
Deferred compensation liability 91,014 119,231
Asset retirement obligations and other liabilities 296,736 310,642
Common stock and retained earnings 5,538,079 5,409,577
Common stock held in treasury stock (599) (1,209)
Total stockholders’ equity 5,537,480 5,408,368
$11,637,739 $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
September 30,
Nine Months Ended
September 30,
2017 2016 % 2017 2016 %
Total revenues and other income, as reported$482,232 $413,207 17% $1,931,998 $846,417 128%
Adjustment for certain special items:
Total change in fair value related to derivatives prior to settlement (gain) loss 105,283 (11,443) (172,264) 271,991
ARO settlement (gain) loss (104) 6 (64) 14
Total revenues, as adjusted, non-GAAP$587,411 $401,770 46% $1,759,670 $1,118,422 57%

RANGE RESOURCES CORPORATION
CASH FLOWS FROM OPERATING ACTIVITIES
(Unaudited in thousands)
Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Net (loss) income$(127,700) $(41,971) $111,961 $(360,679)
Adjustments to reconcile net cash provided from continuing operations:
Deferred income tax (benefit) expense (71,992) (13,705) 98,054 (185,169)
Depletion, depreciation, amortization and impairment 223,428 131,489 525,753 417,480
Exploration dry hole costs 9,005 2 9,166 2
Abandonment and impairment of unproved properties 42,568 6,082 52,181 23,769
Derivative fair value loss (income) 88,426 (64,556) (188,326) 11,334
Cash settlements on derivative financial instruments 16,856 53,113 16,062 260,657
Allowance for bad debts 750 350 1,050 800
Amortization of deferred issuance costs, loss on extinguishment of debt, and other 1,627 1,946 4,184 5,383
Deferred and stock-based compensation 1,985 971 3,937 72,689
(Gain) loss on sale of assets and other (102) 2,597 (23,509) 7,544
Changes in working capital:
Accounts receivable (26,084) (9,970) (39,694) 31,985
Inventory and other (5,220) (11,276) (1,504) (776)
Accounts payable 26,289 (22,074) 44,715 (41,268)
Accrued liabilities and other 9,368 (362) (13,498) (37,914)
Net changes in working capital 4,353 (43,682) (9,981) (47,973)
Net cash provided from operating activities$189,204 $32,636 $600,532 $205,837
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,
2017 2016 2017 2016
Net cash provided from operating activities, as reported$189,204 $32,636 $600,532 $205,837
Net changes in working capital (4,353) 43,682 9,981 47,973
Exploration expense 13,200 6,333 35,006 16,970
Memorial merger expenses 33,791 36,412
Lawsuit settlements 5,865 120 7,028 1,444
Cash paid to exchange senior subordinated notes 6,600 6,600
Termination costs (16) 136 2,384 303
Non-cash compensation adjustment 291 (79) 1,383 (37)
Cash flow from operations before changes in working capital – non-GAAP measure$204,191 $123,219 $656,314 $315,502
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING
(Unaudited, in thousands)
Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Basic:
Weighted average shares outstanding 248,133 183,491 247,794 174,361
Stock held by deferred compensation plan (2,889) (2,808) (2,767) (2,790)
Adjusted basic 245,244 180,683 245,027 171,571
Dilutive:
Weighted average shares outstanding 248,133 183,491 247,794 174,361
Dilutive stock options under treasury method (2,889) (2,808) (2,514) (2,790)
Adjusted dilutive 245,244 180,683 245,280 171,571


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,
2017 2016 % 2017 2016 %
Natural gas, NGL and oil sales components:
Natural gas sales$301,114 $197,476 $1,009,000 $464,098
NGL sales 150,593 75,259 412,440 198,877
Oil sales 55,834 31,742 151,688 75,595
Total oil and gas sales, as reported$507,541 $304,477 67% $1,573,128 $738,570 113%
Derivative fair value income (loss), as reported:$(88,426) $64,556 $188,326 $(11,334)
Cash settlements on derivative financial instruments – (gain) loss:
Natural gas (26,250) (35,822) (34,647) (205,985)
NGLs 15,995 (8,514) 33,459 (25,395)
Crude Oil (6,602) (8,777) (14,874) (29,277)
Total change in fair value related to derivatives prior to settlement, a non-GAAP measure$(105,283) $11,443 $172,264 $(271,991)
Transportation, gathering, processing and compression components:
Natural gas$133,019 $99,465 $384,769 $288,355
NGLs 58,626 39,299 176,114 112,516
Total transportation, gathering, processing and compression, as reported$191,645 $138,764 $560,883 $400,871
Natural gas, NGL and oil sales, including cash-settled derivatives: (c)
Natural gas sales$327,364 $233,298 $1,043,647 $670,083
NGL sales 134,598 83,773 378,981 224,272
Oil sales 62,436 40,519 166,562 104,872
Total$524,398 $357,590 47% 1,589,190 999,227 59%
Production of oil and gas during the periods (a):
Natural gas (mcf) 121,644,949 93,466,385 30% 357,389,113 261,331,126 37%
NGL (bbl) 8,892,778 6,739,161 32% 25,953,773 19,579,843 33%
Oil (bbl) 1,288,303 810,878 59% 3,406,373 2,504,757 36%
Gas equivalent (mcfe) (b) 182,731,435 138,766,619 32% 533,549,989 393,838,726 35%
Production of oil and gas – average per day (a):
Natural gas (mcf) 1,322,228 1,015,939 30% 1,309,118 953,763 37%
NGL (bbl) 96,661 73,252 32% 95,069 71,459 33%
Oil (bbl) 14,003 8,814 59% 12,478 9,141 36%
Gas equivalent (mcfe) (b) 1,986,211 1,508,333 32% 1,954,396 1,437,368 36%
Average prices, including cash-settled hedges before third party transportation costs:
Natural gas (mcf)$2.48 $2.11 17% $2.82 $1.78 59%
NGL (bbl)$16.93 $11.17 52% $15.89 $10.16 56%
Oil (bbl)$43.34 $39.15 11% $44.53 $30.18 48%
Gas equivalent (mcfe) (b)$2.78 $2.19 27% $2.95 $1.88 57%
Average prices, including cash-settled hedges and derivatives
before third party transportation costs: (c)
Natural gas (mcf)$2.69 $2.50 8% $2.92 $2.56 14%
NGL (bbl)$15.14 $12.43 22% $14.60 $11.45 27%
Oil (bbl)$48.46 $49.97 -3% $48.90 $41.87 17%
Gas equivalent (mcfe) (b)$2.87 $2.58 11% $2.98 $2.54 17%
Average prices, including cash-settled hedges and derivatives: (d)
Natural gas (mcf)$1.60 $1.43 12% $1.84 $1.46 26%
NGL (bbl)$8.54 $6.60 29% $7.82 $5.71 37%
Oil (bbl)$48.46 $49.97 -3% $48.90 $41.87 17%
Gas equivalent (mcfe) (b)$1.82 $1.58 15% $1.93 $1.52 27%
Transportation, gathering and compression expense per mcfe$1.05 $1.00 5% $1.05 $1.02 3%
(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 NET INCOME (LOSS),
AND ADJUSTED EARNINGS PER SHARE EXCLUDING
CERTAIN ITEMS, a non-GAAP measure
(In thousands, except per share data)
Three Months Ended Nine Months Ended
September 30,September 30,
2017 2016 2017 2016
Net (loss) income, as reported$(127,700) $(41,971) $111,961) $(360,679)
Adjustment for certain special items:
(Gain) loss on sale of assets (102) 2,597 (23,509) 7,544
Loss (gain) on ARO settlements (104) 6 (64) 14
Change in fair value related to derivatives prior to settlement 105,283 (11,443) (172,264) 271,991
Impairment of proved property 63,679 63,679 43,040
Abandonment and impairment of unproved properties 42,568 6,082 52,181 23,769
MRD merger expenses 33,791 36,412
Fees paid to exchange senior subordinated notes 6,600 6,600
Lawsuit settlements 5,865 120 7,028 1,444
Termination costs (16) 136 2,384 303
Non-cash stock-based compensation 11,395 12,686 41,020 42,481
Deferred compensation plan (9,203) (11,636) (36,838) 30,166
Tax impact (80,034) (7,338) 42,762 (153,836)
Net income (loss) excluding certain items, a non-GAAP measure$11,631 $(10,370) $88,340 $(50,751)
Net (loss) income per diluted share, as reported$ (0.52) $ (0.23) $ 0.45 $ (2.10)
Adjustment for certain special items per diluted share:
(Gain) loss on sale of assets 0.01 (0.10) 0.04
Change in fair value related to derivatives prior to settlement 0.43 (0.06) (0.70) 1.59
Impairment of proved property 0.26 0.26 0.25
Abandonment and impairment of unproved properties 0.17 0.03 0.21 0.14
MRD merger expenses 0.19 0.21
Fees paid to exchange senior subordinated notes 0.04 0.04
Lawsuit settlements 0.02 0.03 0.01
Termination costs 0.01
Non-cash stock-based compensation 0.05 0.07 0.17 0.25
Deferred compensation plan (0.04) (0.06) (0.15) 0.18
Adjustment for rounding differences 0.01 (0.01) 0.01 (0.01)
Tax impact (0.33) (0.04) 0.17 (0.90)
Net income (loss) per diluted share, excluding certain items, $0.05 $(0.06) $0.36 $(0.30)
a non-GAAP measure
Adjusted income (loss) per share, a non-GAAP measure:
Basic$0.05 $(0.06) $0.36 $(0.30)
Diluted$0.05 $(0.06) $0.36 $(0.30)


RANGE RESOURCES CORPORATION
RECONCILIATION OF CASH MARGIN PER MCFE, a non-GAAP measure
(Unaudited, in thousands, except per unit data)
Three Months Ended
September 30,
Nine Months Ended
September 30,
2017 2016 2017 2016
Revenues
Natural gas, NGL and oil sales, as reported$507,541 $304,477 $1,573,128 $738,570
Derivative fair value income (loss), as reported (88,426) 64,556 188,326 (11,334)
Less non-cash fair value (gain) loss 105,283 (11,443) (172,264) 271,991
Brokered natural gas and marketing and other, as reported 63,117 44,174 170,544 119,181
Less ARO settlement and other (gains) losses (1,972) (60) (1,802) (736)
Cash revenue applicable to production 585,543 401,704 1,757,932 1,117,672
Expenses
Direct operating, as reported 36,888 22,387 96,331 67,112
Less direct operating stock-based compensation (517) (497) (1,563) (1,781)
Transportation, gathering and compression, as reported 191,645 138,764 560,883 400,871
Production and ad valorem taxes, as reported 11,993 6,717 31,125 18,653
Brokered natural gas and marketing, as reported 59,773 44,622 169,180 122,105
Less brokered natural gas and marketing stock-based
compensation
(389) (455) (1,040) (1,349)
General and administrative, as reported 53,035 41,024 152,853 127,745
Less G&A stock-based compensation (9,959) (11,126) (35,156) (37,682)
Less lawsuit settlements (5,865) (120) (7,028) (1,444)
Interest expense, as reported 49,179 45,967 144,206 121,464
Cash expenses 385,783 287,283 1,109,791 815,694
Cash margin, a non-GAAP measure$199,760 $114,421 $648,141 $301,978
Mmcfe produced during period 182,731 138,767 533,550 393,839
Cash margin per mcfe$1.09 $0.82 $1.21 $0.77


RECONCILIATION OF INCOME (LOSS) BEFORE INCOME
TAXES TO CASH MARGIN
(Unaudited, in thousands, except per unit data)
Three Months Ended
September 30,
Nine Months Ended
September 30,
2017 2016 2017 2016
(Loss) income before income taxes, as reported$(199,692) $(55,676) $ 210,015 $(545,848)
Adjustments to reconcile (loss) income before income taxes to cash margin:
ARO settlements and other (gains) losses (1,972) (60) (1,802) (736)
Derivative fair value (income) loss 88,426 (64,556) (188,326) 11,334
Net cash receipts on derivative settlements 16,857 53,113 16,062 260,657
Exploration expense 22,206 6,335 44,173 16,972
Lawsuit settlements 5,865 120 7,028 1,444
MRD merger expenses 33,791 36,412
Termination costs (16) 136 2,384 303
Deferred compensation plan (9,203) (11,636) (36,838) 30,166
Stock-based compensation (direct operating, brokered natural gas
and marketing, general and administrative and termination costs)
11,395 12,686 41,020 42,481
Depletion, depreciation and amortization 159,749 131,489 462,074 374,440
(Gain) loss on sale of assets (102) 2,597 (23,509) 7,544
Impairment of proved property and other assets 63,679 63,679 43,040
Abandonment and impairment of unproved properties 42,568 6,082 52,181 23,769


Cash margin, a non-GAAP measure
$199,760 $114,421 $648,141 $301,978


RANGE RESOURCES CORPORATION
HEDGING POSITION AS OF OCTOBER 23, 2017
(Unaudited) –

Daily Volume Hedge Price
Gas 1
4Q 2017 Swaps 867,935 Mmbtu $3.20
1Q 2018 Swaps 1,020,000 Mmbtu $3.43
2Q-4Q 2018 Swaps2 790,000 Mmbtu $3.01
2019 Swaps2 72,329 Mmbtu $3.00
4Q 2017 Collars 122,609 Mmbtu $3.45 x $4.11
1Q 2018 Collars 60,000 Mmbtu $3.40 x $3.76
4Q 2017 Puts 185,870 Mmbtu $3.50 ($0.32) 3
Oil
4Q 2017 Swaps 9,511 bbls $56.03
2018 Swaps 6,750 bbls $52.89
2019 Swaps 1,000 bbls $51.50
C2 Ethane
4Q 2017 Swaps 3,000 bbls $0.27/gallon
1H 2018 Swaps 250 bbls $0.29/gallon
C3 Propane 4
4Q 2017 Swaps 17,576 bbls $0.60/gallon
1Q 2018 Swaps 12,000 bbls $0.65/gallon
2Q-4Q 2018 Swaps 7,932 bbls $0.61/gallon
C4 Normal Butane
4Q 2017 Swaps 9,000 bbls $0.76/gallon
1Q 2018 Swaps 5,500 bbls $0.82/gallon
2Q-4Q 2018 Swaps 4,250 bbls $0.81/gallon
C5 Natural Gasoline
4Q 2017 Swaps 6,416 bbls $1.08/gallon
1Q 2018 Swaps 5,167 bbls $1.18/gallon
2Q-4Q 2018 Swaps 3,655 bbls $1.17/gallon

  1. Range has deferred calls at a strike of $3.75 for 4Q17. Total volume of 1,650,000 Mmbtu with a deferred premium price of $0.31 paid to Range
  2. Range also sold call swaptions of 160,000 Mmbtu/d for April-December 2018 and 220,000 Mmbtu/d for calendar 2019 at average strike prices of $3.02 and $3.05 per Mmbtu, respectively
  3. Notes deferred premium on puts
  4. Incorporates international propane hedges

SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS AND ADDITIONAL HEDGING DETAILS

Source:Range Resources Corporation