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

Exhibit 99.1

NEWS RELEASE

RANGE ANNOUNCES FIRST QUARTER 2017 FINANCIAL RESULTS

FORT WORTH, TEXAS, APRIL 24, 2017…RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its first quarter 2017 financial results.  

Highlights –

• First quarter GAAP net income reached $170 million, or $0.69 per diluted share, compared to a net loss of $94 million, or $0.56 per share in the prior-year quarter

• First quarter cash margins improved to $1.47 per mcfe, compared to $0.77 per mcfe in the prior-year quarter, an improvement of 91%

• Cash flow from operations before changes in working capital, a non-GAAP measure, reached $258 million, $1.05 per diluted share, compared to $99 million, $0.59 per diluted share, in first quarter 2016

• Record production of 1.93 Bcfe per day, an increase of 40% compared to the prior-year quarter

• Total unit costs continued to decline, with first quarter 2017 costs of $2.57 per mcfe, compared to $2.71 in the previous year quarter, an improvement of 5%

• Super-rich pad in northwestern Washington County, PA averages 31.4 Mmcfe per day per well

• North Louisiana well costs continue to improve, currently at $7.4 million per well, compared to $7.7 million in the previous quarter and approximately $8.7 million when the properties were acquired

Commenting, Jeff Ventura, the Company’s CEO said, “The first quarter of 2017 was an excellent quarter for Range. First quarter cash margins improved to $1.47 per mcfe, compared to $0.77 per mcfe a year ago. In addition to improved macroeconomic conditions, margin expansion is being driven by improving netbacks from better transportation arrangements and a continued focus on cost and operational improvements throughout the company.  With our extensive drilling inventory combined with expected increasing demand for natural gas and NGLs over the next several years, Range is well-positioned to generate shareholder value for years to come.”

Financial Discussion

Except for generally accepted accounting principles (“GAAP”) reported amounts, specific expense categories exclude non-cash impairments, unrealized mark-to-market 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.

First Quarter 2017

GAAP revenues for the first quarter of 2017 totaled $777 million (134% increase compared to first quarter 2016), GAAP net cash provided from operating activities including changes in working capital was $226 million (149% increase as compared to first quarter 2016) and GAAP earnings were $170 million ($0.69 per diluted share) versus a loss of $94 million ($0.56 per diluted share) in the prior-year quarter. First quarter 2017 included $166 million in derivative gains due to decreased commodity prices, compared to an $87 million gain in 2016. First quarter 2017 results also included a $23 million gain on sale of assets, while first quarter 2016 included a loss of $1.6 million. A $43 million impairment of proved property was also recorded in first quarter 2016.

Non-GAAP revenues for first quarter 2017 totaled $607 million (71% increase compared to first quarter 2016) and cash flow from operations before changes in working capital, a non-GAAP measure, reached $258 million, compared to $99 million in first quarter 2016. Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $61 million ($0.25 per diluted share) compared to a loss of $17 million ($0.10 per diluted share) for first quarter 2016.

The Company’s total unit costs were lower than the previous year quarter, with decreases in all categories, except for a $0.02 per mcfe increase in transportation, gathering, processing and compression expense and production and ad valorem taxes, which were unchanged from the prior-year quarter. Increased transportation expenses are offset by higher realized prices, as products are moved to more favorable markets with higher prices, thereby resulting in significantly increased cash margins from the previous year.

Expenses	1Q 2017 (per mcfe)	1Q 2016 (per mcfe)	Increase (Decrease)
		��
Direct operating	$  0.16	$  0.19	(16%)
Transportation, gathering, processing and compression	1.02	1.00	2%
Production and ad valorem taxes	0.05	0.05	-%
General and administrative	0.21	0.23	(9%)
Interest expense	0.27	0.30	(10%)
Total cash unit costs(a)	1.71	1.76	(3%)
Depletion, depreciation and amortization	0.86	0.96	(10%)
Total unit costs(a)	$  2.57	$  2.71	(5%)

^(a) Totals may not add due to rounding.

First 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 $3.19 per mcfe, a 26% increase from the prior-year quarter. Additional detail on commodity price realizations can be found in the Supplemental Tables provided on the Company’s website.

• Production and realized prices by each commodity for first quarter 2017 were:  natural gas – 1,292 Mmcf per day ($3.26 per mcf), NGLs – 94,853 barrels per day ($14.49 per barrel) and crude oil and condensate – 11,837 barrels per day ($49.50 per barrel).

• The average Company natural gas price differential including the impact of basis hedges for first quarter 2017 was a positive $0.01 per mcf, compared to a negative ($0.31) in first quarter 2016.  The first quarter average natural gas price, before all hedging settlements, was $3.19 per mcf as compared to $1.68 per mcf in the prior year.

• Pre-hedge NGL realizations improved to 31% of West Texas Intermediate (“WTI”) in first quarter 2017, compared to 25% of WTI in the previous year. Total NGL pricing per barrel including ethane and processing expenses after realized cash-settled hedging improved to $14.49 for first quarter 2017 compared to $10.22 per barrel in the prior year.

• Crude oil and condensate price realizations, before realized hedges, for the first quarter 2017 averaged $46.97 per barrel, or $4.84 below WTI, compared to $13.56 below WTI in the prior year.  Hedging added $2.53 per barrel in first quarter 2017.

Capital Expenditures

First quarter 2017 drilling expenditures of $228 million funded the drilling of 54 (53 net) wells.  A 100% success rate was achieved.  In addition, during the quarter, $25 million was incurred on acreage purchases, $1.5 million on gas gathering systems and $8 million on exploration expense. Range is on target with its $1.15 billion capital budget for 2017.

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Financial Position and Liquidity

The Company’s existing $3 billion borrowing base and $2 billion commitment amount under its $4 billion bank credit facility were unanimously reaffirmed by its 29 lenders with no changes to the financial covenants.  The credit facility matures on October 16, 2019 and is subject to annual redeterminations, which are required to be completed by May of each year.

At March 31, 2017, Range had total debt outstanding of $3.77 billion, before amortization of debt issuance costs and premium, consisting of $2.88 billion in senior notes, $846 million in bank debt and $49 million in senior subordinated notes. The outstanding bank debt of $846 million combined with $280 million of undrawn letters of credit provides committed liquidity of $874 million from borrowing capacity available under the facility.

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 – April 24, 2017”.

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

	2017
	Wells TIL - First Quarter	Remaining Wells to Sales	Planned Total Wells to Sales
Super-Rich Area	6	33	39
Wet Area	10	35	45
Dry- SW	6	24	30
Dry- NE	—	2	2
Total Marcellus	22	94	116
Upper Red	19	15	34
Lower Red	5	8	13
Pink	3	3	6
Extension Area	—	3	3
Total N. LA.	27	29	56
Company Total	49	123	172

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Appalachia Division

In order to streamline operations and reduce costs, the Southern Marcellus Division and Northern Marcellus Division have been combined, and going forward will be referred to as the Appalachia Division. Production for first quarter 2017 averaged 1,503 net Mmcfe per day, a 13% increase over the prior year. The southern Marcellus properties averaged 1,341 net Mmcfe per day during the quarter, a 22% increase over the prior year.  The northern Marcellus properties averaged 162 net Mmcf per day during the quarter, a 31% decrease over the prior year, or a 23% decrease over the prior year when adjusted for asset sales.

The division brought on line 22 wells in the first quarter, six in the super-rich area, 10 in the wet area and six in the southwest dry area.  The team 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.  Several recent examples are listed below, which have continued to drive lower normalized well costs and reduce operating costs per mcfe.

• Daily lateral footage drilled has increased by 67% compared to the previous year

• Drilling cost per lateral foot in first quarter 2017 decreased by 30% compared to the previous year

• One-third of wells brought on line in 2017 are expected to be drilled on existing pads, with expected savings of $200,000 to $500,000 per well

• Average lateral lengths drilled in 2017 are expected to approach 9,000 feet

During the first quarter, the division drilled and completed four super-rich wells from a pad located in a lightly drilled area, near the planned Harmon Creek processing plant in northwestern Washington County.  Due to the high initial production rates, only two of the wells were brought on line.  The two wells averaged a 24-hour rate to sales of 31.4 Mmcfe per day for each well, or a combined rate of 62.8 Mmcfe per day from an average lateral length of 10,772 feet with 54 stages.  The remaining two wells on the pad will be brought on line after the first two wells decline, when capacity in the gathering system is available.

In addition to the planned Harmon Creek complex mentioned above, the Houston processing plant is also undergoing an upgrade to support Range’s future growth.  In the second quarter, operations are beginning for the removal of the original Houston I plant that is being replaced and upgraded with a 200 Mmcf capacity cryogenic plant, which will increase processing capacity by 170 Mmcf per day. There is additional maintenance and numerous upgrades being performed during this downtime. This will impact Range’s second quarter production, and is reflected in second quarter production guidance.  

North Louisiana Division

Production for the division in the first quarter of 2017 averaged approximately 397 net Mmcfe per day.  The division continues to lower drilling and completion costs of a typical 7,500 foot lateral well in Terryville.  The Company now expects these wells will cost approximately $7.4 million, which includes a forecasted 5% to 25% increase in some service costs.  This represents a cost reduction of $300,000 from the previous quarter, and a reduction of $1.3 million since Range acquired the properties in September 2016.  The lower cost significantly improves well economics in Terryville, and adds potential locations across the field.  The savings realized from the reduction in Terryville well costs are expected to be used to fund increased seismic, research and development costs, or additional wells.

As part of the overall cost reduction, Range has optimized facility designs, which has the effect of lower initial rates, but flatter declines and overall improved economics as a result of the lower costs.  The most recent cost reduction of $300,000 has resulted from several factors including:

• Reduced day rates on drilling contracts

• Reduced casing costs by utilizing Range’s supply chain management team

• Reduced mobilization time

• Increased number of stages pumped per day, currently almost twice the previous rate

• Reduced coil tubing and flow back equipment cost

The division brought on line 27 wells in the first quarter.  The locations for this group of wells were chosen by the previous operator and 18 of the wells had already been drilled prior to Range acquiring the assets last September.  Completing this large backlog of wells, many of which had been waiting on completion for almost a year,

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required the shut-in of approximately 40 Mmcfe per day of offset production during the first quarter.  Offset wells are shut-in to reduce the effect of frac hits, and we expect production to return throughout the remainder of the year.  Going forward, the Company is planning a more balanced pace of drilling and completion activity to minimize the impact on offset production and continue driving operational efficiencies. Since taking over operations, Range has also revised production methods in accordance with Range’s safety and facilities protocol, which reduces 2017 production rates by approximately 30 Mmcfe per day. This facility change results in a production profile that has a flatter decline and does not change expected ultimate recovery. The Company expects to bring to sales 29 additional wells during the remainder of the year.

Results continue to be encouraging from two of the extension wells announced last quarter.  Each of the two wells, located in separate Terryville sized fault blocks, with one well located to the east and one well to the west of Vernon field, has cumulative production to date of approximately one Bcfe each. As a result, plans are underway to offset each well with another horizontal well.

Marketing and Transportation

Range has assembled a diversified transportation and marketing portfolio across all of its products.  Many of these transportation projects and marketing contracts were years in the making, only coming to fruition in the last twelve months.  These recent additions, including Mariner East, Gulf Markets Expansion and recent condensate sales agreements have significantly improved the Company’s realizations in 2017 for natural gas, NGLs and condensate.  As part of that continued development, Range will be adding to its gathering capacity in southwestern Pennsylvania during the second and third quarters of 2017.  The timing of this added gathering capacity fits well with anticipated natural gas long-haul transportation expected to come on line later in 2017.  Range’s long-term marketing plans and firm transportation portfolio will allow Range to sell natural gas into improving Appalachia markets as well as to growing Gulf Coast, Southwest and Midwest markets.  As a result of the increased gathering capacity, the Company expects transportation, gathering, processing and compression expense to increase in second quarter 2017 before trending down over the course of 2018 as the new gathering and transportation capacity is filled.  In addition to allowing the Company to optimize its long-haul firm transportation commitments, this gathering capacity also provides Range added flexibility in allocating future growth capital across the liquids-rich and dry areas of southwestern Pennsylvania. 

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Guidance – 2017  

Production per day Guidance

Production for the second quarter of 2017 is expected to be approximately 1.93 Bcfe per day with 30% to 32% liquids. 

Production growth for the full year of 2017 is unchanged at 33% to 35%.

2Q 2017 Expense Guidance

Direct operating expense:	$0.17 - $0.18 per mcfe
Transportation, gathering, processing and compression    expense:	$1.04 - $1.08 per mcfe
Production tax expense:	$0.05 - $0.06 per mcfe
Exploration expense:	$12.0 - $13.0 million
Unproved property impairment expense:	$4.0 - $6.0 million
G&A expense:	$0.21 - $0.23 per mcfe
Interest expense:	$0.26 - $0.28 per mcfe
DD&A expense:	$0.87 - $0.89 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 $3.22 per mcf, and over one Bcf per day of first quarter 2018 production hedged at $3.43.  Similarly, Range has hedged over 65% of its remaining 2017 projected crude oil production at a floor price of approximately $56.00 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 Marcellus and other basis differentials to limit volatility between NYMEX and regional prices. The fair value of the basis hedges as of March 31, 2017 was a loss of $20.4 million, compared to a gain of $11.8 million at December 31, 2016.

Conference Call Information

A conference call to review the financial results is scheduled on Tuesday, April 25 at 9:00 a.m. ET. To participate in the call, please dial 866-900-7525 and provide conference code 89127307 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 May 25.

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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 income statement. The Company believes that it is important to furnish a table reflecting the details of the various components of each income statement line to better inform the reader of the details of each amount and provide a summary of the realized cash-settled amounts and third-party transportation, gathering, 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 Statements of Operations to better inform the reader of the details of each amount, the changes between periods and the effect on its financial results.

Range has disclosed two primary metrics in this release to measure our ability to establish a long-term trend of adding reserves at a reasonable cost – a reserve replacement ratio and finding and development cost per unit. The reserve replacement ratio is an indicator of our ability to replace annual production volumes and grow our reserves. It is important to economically find and develop new reserves that will offset produced volumes and provide for future production given the inherent decline of hydrocarbon reserves as they are produced. We believe the ability to develop a competitive advantage over other natural gas and oil companies is dependent on adding reserves in our core areas at lower costs than our competition. The reserve replacement ratio is calculated by dividing production for the year into the total of proved reserve extensions, discoveries and additions and proved reserve revisions, excluding PUD removals based on the SEC 5-year rule.

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Finding and development cost per unit is a non-GAAP metric used in the exploration and production industry by companies, investors and analysts. The calculations presented by the Company are based on estimated and unaudited costs incurred excluding asset retirement obligations and divided by proved reserve additions (extensions, discoveries and additions) adjusted for the changes in proved reserves for acquisitions, performance revisions and/or price revisions and including or excluding acreage costs as stated in each instance in the release. Drill-bit development cost per mcfe is based on estimated and unaudited drilling, development and exploration costs incurred divided by the total of reserve additions, performance and price revisions. These calculations do not include the future development costs required for the development of proved undeveloped reserves. The SEC method of computing finding costs contains additional cost components and results in a higher number. A reconciliation of the two methods is shown on our website atwww.rangeresources.com.

The reserve replacement ratio and finding and development cost per unit are statistical indicators that have limitations, including their predictive and comparative value. As an annual measure, the reserve replacement ratio can be limited because it may vary widely based on the extent and timing of new discoveries and the varying effects of changes in prices and well performance. In addition, since the reserve replacement ratio and finding and development cost per unit do not consider the cost or timing of future production of new reserves, such measures may not be an adequate measure of value creation. These reserves metrics may not be comparable to similarly titled measurements used by other companies.

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 merger integration, 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

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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

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 March 31,
		2017			2016		%
Revenues and other income:
Natural gas, NGLs and oil sales (a)	$	559,450		$	209,487
Derivative fair value income		165,557			86,908
Brokered natural gas, marketing and other (b)		51,581			34,858
ARO loss (b)		—			(2	)
Other (b)		67			162
Total revenues and other income		776,655			331,413		134	%
Costs and expenses:
Direct operating		27,499			23,466
Direct operating – non-cash stock-based compensation (c)		524			588
Transportation, gathering, processing and compression		177,648			125,263
Production and ad valorem taxes		9,163			5,887
Brokered natural gas and marketing		53,287			36,042
Brokered natural gas and marketing – non-cash      stock-based compensation (c)		263			516
Exploration		7,997			4,223
Exploration – non-cash stock-based compensation (c)		507			690
Abandonment and impairment of unproved properties		4,420			10,628
General and administrative		35,955			28,423
General and administrative – non-cash stock-based      compensation (c)		10,918			11,113
General and administrative – lawsuit settlements		623			921
General and administrative – bad debt expense		—			200
Termination costs		2,450			162
Termination costs – non-cash stock-based compensation (c)		1,742			—
Deferred compensation plan (d)		(13,169	)		16,056
Interest expense		47,101			37,739
Depletion, depreciation and amortization		149,821			120,561
Impairment of proved properties and other assets		—			43,040
(Gain) loss on sale of assets		(22,600	)		1,643
Total costs and expenses		494,149			467,161		6	%
Income (loss) before income taxes		282,506			(135,748	)	308	%
Income tax expense (benefit):
Current		—			—
Deferred		112,395			(41,976	)
		112,395			(41,976	)
Net income (loss)	$	170,111		$	(93,772	)	281	%
Net Income (Loss) Per Common Share:
Basic	$	0.69		$	(0.56	)
Diluted	$	0.69		$	(0.56	)
Weighted average common shares outstanding, as reported:
Basic		244,652			166,803		47	%
Diluted		244,803			166,803		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)		March 31,			December 31,
		2017			2016
		(Unaudited)			(Audited)
Assets
Current assets	$	267,083		$	268,605
Derivative assets		46,245			13,483
Goodwill		1,654,292			1,654,292
Natural gas and oil properties, successful efforts method		9,359,864			9,256,337
Transportation and field assets		16,749			16,873
Other		77,512			72,655
	$	11,421,745		$	11,282,245
Liabilities and Stockholders’ Equity
Current liabilities	$	568,096		$	530,373
Asset retirement obligations		7,271			7,271
Derivative liabilities		55,713			165,009
Bank debt		841,188			876,428
Senior notes		2,849,088			2,848,591
Senior subordinated notes		48,519			48,498
Total debt		3,738,795			3,773,517
Deferred tax liability		1,055,737			943,343
Derivative liabilities		1,515			24,491
Deferred compensation liability		110,455			119,231
Asset retirement obligations and other liabilities		301,687			310,642
Common stock and retained earnings		5,583,530			5,409,577
Common stock held in treasury stock		(1,054	)		(1,209	)
Total stockholders’ equity		5,582,476			5,408,368
	$	11,421,745		$	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 March 31,
		2017			2016	%
Total revenues and other income, as reported	$	776,655		$	331,413	134	%
Adjustment for certain special items:
Total change in fair value related to derivatives prior to settlement (gain) loss		(169,738	)		22,558
ARO settlement (gain) loss		—			2
Total revenues, as adjusted, non-GAAP	$	606,917		$	353,973	71	%

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RANGE RESOURCES CORPORATION

CASH FLOWS FROM OPERATING ACTIVITIES
(Unaudited in thousands)
	Three Months Ended March 31,
		2017			2016
Net income (loss)	$	170,111		$	(93,772	)
Adjustments to reconcile net cash provided from continuing operations:
Deferred income tax expense (benefit)		112,395			(41,976	)
Depletion, depreciation, amortization and impairment		149,821			163,601
Abandonment and impairment of unproved properties		4,420			10,628
Derivative fair value (income)		(165,557	)		(86,908	)
Cash settlements on derivative financial instruments that do not qualify for hedge     accounting		(4,181	)		109,466
Allowance for bad debts		—			200
Amortization of deferred issuance costs, loss on extinguishment of debt and other		1,310			1,707
Deferred and stock-based compensation		962			29,128
(Gain) loss on sale of assets and other		(22,600	)		1,643
Changes in working capital:
Accounts receivable		(4,690)			18,752
Inventory and other		2,868			5,333
Accounts payable		24,384			11,922
Accrued liabilities and other		(43,381	)		(38,939	)
Net changes in working capital		(20,819)			(2,932	)
Net cash provided from operating activities	$	225,862		$	90,785
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 March 31,
		2017			2016
Net cash provided from operating activities, as reported	$	225,862		$	90,785
Net changes in working capital		20,819			2,932
Exploration expense		7,997			4,223
Lawsuit settlements		623			921
Termination costs		2,450			162
Non-cash compensation adjustment		291			(84	)
Cash flow from operations before changes in working capital – non-GAAP measure	$	258,042		$	98,939
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING
(Unaudited, in thousands)
	Three Months Ended March 31,
		2017			2016
Basic:
Weighted average shares outstanding		247,390			169,584
Stock held by deferred compensation plan		(2,738	)		(2,781	)
Adjusted basic		244,652			166,803
Dilutive:
Weighted average shares outstanding		247,390			169,584
Dilutive stock options under treasury method		(2,587	)		(2,781	)
Adjusted dilutive		244,803			166,803

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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 March 31,
		2017			2016		%
Natural gas, NGL and oil sales components:
Natural gas sales	$	371,352		$	142,435
NGL sales		138,063			50,162
Oil sales		50,035			16,890
Total oil and gas sales, as reported	$	559,450		$	209,487		167	%
Derivative fair value income (loss), as reported:	$	165,557		$	86,908
Cash settlements on derivative financial instruments – (gain) loss:
Natural gas		(7,455	)		(85,515	)
NGLs		14,333			(10,878	)
Crude Oil		(2,697	)		(13,073	)
Total change in fair value related to derivatives prior to settlement, a non-GAAP measure	$	169,738		$	(22,558	)
Transportation, gathering, processing and compression components:
Natural gas	$	122,194		$	92,592
NGLs		55,454			32,671
Total transportation, gathering, processing and compression, as reported	$	177,648		$	125,263
Natural gas, NGL and oil sales, including cash-settled derivatives: (c)
Natural gas sales	$	378,807		$	227,950
NGL sales		123,730			61,040
Oil sales		52,732			29,963
Total	$	555,269		$	318,953		74	%
Production of oil and gas during the periods (a):
Natural gas (mcf)		116,256,337			84,867,370		37	%
NGL (bbl)		8,536,728			5,974,734		43	%
Oil (bbl)		1,065,286			844,341		26	%
Gas equivalent (mcfe) (b)		173,868,421			125,781,820		38	%
Production of oil and gas – average per day (a):
Natural gas (mcf)		1,291,737			932,608		39	%
NGL (bbl)		94,853			65,656		44	%
Oil (bbl)		11,837			9,278		28	%
Gas equivalent (mcfe) (b)		1,931,871			1,382,218		40	%
Average prices, including cash-settled hedges that qualify for hedge accounting before third party transportation costs:
Natural gas (mcf)	$	3.19		$	1.68		90	%
NGL (bbl)	$	16.17		$	8.40		93	%
Oil (bbl)	$	46.97		$	20.00		135	%
Gas equivalent (mcfe) (b)	$	3.22		$	1.67		93	%
Average prices, including cash-settled hedges and derivatives before third party transportation costs: (c)
Natural gas (mcf)	$	3.26		$	2.69		21	%
NGL (bbl)	$	14.49		$	10.22		42	%
Oil (bbl)	$	49.50		$	35.49		39	%
Gas equivalent (mcfe) (b)	$	3.19		$	2.54		26	%
Average prices, including cash-settled hedges and derivatives: (d)
Natural gas (mcf)	$	2.21		$	1.59		38	%
NGL (bbl)	$	8.00		$	4.75		68	%
Oil (bbl)	$	49.50		$	35.49		39	%
Gas equivalent (mcfe) (b)	$	2.17		$	1.54		41	%
Transportation, gathering and compression expense per mcfe	$	1.02		$	1.00		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, processing and compression costs.

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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 March 31,
		2017			2016		%
Income (loss) from operations before income taxes, as reported	$	282,506		$	(135,748	)	308	%
Adjustment for certain special items:
(Gain) loss on sale of assets		(22,600	)		1,643
Loss on ARO settlements		—			2
Change in fair value related to derivatives prior to settlement		(169,738	)		22,558
Abandonment and impairment of unproved properties		4,420			10,628
Impairment of proved property		—			43,040
Lawsuit settlements		623			921
Termination costs		2,450			162
Termination costs – non-cash stock-based compensation		1,742			—
Brokered natural gas and marketing – non-cash stock-based compensation		263			516
Direct operating – non-cash stock-based compensation		524			588
Exploration expenses – non-cash stock-based compensation		507			690
General & administrative – non-cash stock-based compensation		10,918			11,113
Deferred compensation plan – non-cash adjustment		(13,169	)		16,056
Income (loss) before income taxes, as adjusted		98,446			(27,831	)	454	%
Income tax expense (benefit), as adjusted
Current		—			—
Deferred (a)		37,628			(10,697	)
Net income (loss) excluding certain items, a non-GAAP measure	$	60,818		$	(17,134	)	455	%
Non-GAAP income (loss) income per common share
Basic	$	0.25		$	(0.10	)	350	%
Diluted	$	0.25		$	(0.10	)	350	%
Non-GAAP diluted shares outstanding, if dilutive		244,803			166,803

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

14

RANGE RESOURCES CORPORATION

HEDGING POSITION AS OF APRIL 17, 2017

(Unaudited) –

	Daily Volume	Hedge Price
Gas 1
2Q 2017 Swaps	818,764Mmbtu	$3.16
3Q 2017 Swaps	841,196Mmbtu	$3.19
4Q 2017 Swaps	861,196Mmbtu	$3.19
1Q 2018 Swaps	1,020,000Mmbtu	$3.43
2Q-4Q 2018 Swaps	220,000Mmbtu	$2.97
2Q 2017 Collars	126,264Mmbtu	$3.47 x $4.14
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
2Q 2017 Puts	164,835Mmbtu	$3.47 ($0.31) 2
3Q 2017 Puts	185,870Mmbtu	$3.50 ($0.32) 2
4Q 2017 Puts	185,870Mmbtu	$3.50 ($0.32) 2
Oil
2Q 2017 Swaps	8,824bbls	$55.23
3Q 2017 Swaps	8,761bbls	$56.38
4Q 2017 Swaps	8,761bbls	$56.38
2018 Swaps	4,000bbls	$53.74
2019 Swaps	500bbls	$51.75
C2 Ethane
2Q 2017 Swaps	3,000bbls	$0.27/gallon
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
2Q 2017 Swaps	14,036bbls	$0.56/gallon
3Q 2017 Swaps	13,826bbls	$0.56/gallon
4Q 2017 Swaps	13,826bbls	$0.56/gallon
2018 Swaps	7,199bbls	$0.61/gallon
C4 Normal Butane
2Q 2017 Swaps	7,750bbls	$0.74/gallon
3Q 2017 Swaps	7,750bbls	$0.74/gallon
4Q 2017 Swaps	7,750bbls	$0.74/gallon
2018 Swaps	4,250bbls	$0.81/gallon
C5 Natural Gasoline
2Q 2017 Swaps	5,418bbls	$1.07/gallon
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 $3.75 for 2H17. Total volume of 3,300,000 Mmbtu with a deferred premium price of $0.31 paid to Range

(2) Notes deferred premium on puts

NOTE:  SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS

15