Range Resources (RRC) 8-K Range Announces Second Quarter 2017 Financial Results

EXHIBIT 99.1

NEWS RELEASE

RANGE ANNOUNCES SECOND QUARTER 2017 FINANCIAL RESULTS

FORT WORTH, TEXAS, AUGUST 1, 2017…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.  

2

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.

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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.  

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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.

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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.

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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

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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

www.rangeresources.com

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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.

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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	%

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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

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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.

12

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%.

13

RANGE RESOURCES CORPORATION

HEDGING POSITION AS OF JULY 24, 2017

(Unaudited) –

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

14