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Range Announces Fourth Quarter and Year-End 2018 Results


FORT WORTH, Texas, Feb. 25, 2019 (GLOBE NEWSWIRE) — RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its fourth quarter and year-end 2018 financial results.

Commenting on the results and 2019 plans, Jeff Ventura, the Company’s CEO said, “Range made solid progress on key strategic objectives in 2018.  Our capital spending was disciplined, coming in $31 million under budget due to efficient operations, longer laterals and innovative water recycling.  For the year, Range generated free cash flow, reduced absolute debt, and also made good progress on our leverage targets with contribution of the royalty sale announced in late 2018.

“I believe the Company is positioned well, with a high-quality resource base capable of generating sustainable free cash at current strip prices.  Our economic resilience is further demonstrated in the year-end PV10 reserve value of $9.9 billion using futures strip pricing from year-end, which equates to approximately $24 per share, net of debt.  Going forward, Range is committed to translating well-level returns from our high-quality asset base into corporate-level returns, including a free cash flow yield that is competitive not only within energy, but across the broader market.”

2019 Capital Spending Plans

Range’s 2019 capital budget is approximately $756 million.  At strip pricing, cash flow is projected to exceed spending for the year.  Excess cash flow is expected to be used to reduce debt.  In addition, asset sales are being pursued to further strengthen the balance sheet.

The Company expects production to average between 2,325 to 2,345 Mmcfe per day in 2019, with 30% attributed to liquids production.  Approximately 90% of the capital budget is expected to be allocated to the Appalachia division and the remainder to the North Louisiana division.  In Appalachia, over 60% of activity is planned to be directed towards liquids-rich drilling, where Range’s acreage has an extensive inventory of existing pads that reduce capital costs and gathering expenses.  The liquids-rich acreage is also in close proximity to recently built infrastructure for both natural gas takeaway and natural gas liquids (“NGL”) processing.

The 2019 capital budget includes approximately $685 million for drilling and recompletions (91% of the total), $51 million for leasehold, and $20 million for pipelines, facilities and other capital expenditures.  The budget includes 88 wells expected to be brought on line during the year in the Marcellus and eight wells in North Louisiana.  Similar to the 2018 program, approximately half of the 2019 Marcellus wells are planned to be drilled from existing pads.

2018 Capital Expenditures

Fourth quarter 2018 drilling expenditures of $158 million funded the drilling of 17 wells.  Drilling expenditures for the full year totaled $836 million and funded the drilling of 104 (100 net) wells during 2018.  A 100% success rate was achieved.  In addition, during 2018, $62 million was spent on acreage purchases and $10 million on gas gathering systems.  Total capital expenditures in 2018 were approximately $910 million, which was $31 million under budget for the year.

2018 Proved Reserves Results

Range previously announced 2018 proved reserves results on February 11, 2019.   Highlights from the announcement were:

  • 2018 PV10 value of reserves using year-end future strip prices was $9.9 billion
  • Year-end 2018 SEC PV10 value of proved reserves was $13.2 billion, up $5.1 billion from prior year
  • Proved reserves increased by 18% from the prior-year to 18.1 Tcfe
  • Drill-bit finding cost of $0.22 per mcfe, including performance revisions
  • Future development costs for proved undeveloped reserves estimated to be $0.40 per mcfe

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.

Full Year 2018

GAAP revenues for 2018 totaled $3.3 billion (26% increase compared to 2017), GAAP net cash provided from operating activities including changes in working capital was $991 million, compared to $816 million in 2017. GAAP net income was a loss of $1.75 billion ($7.10 per diluted share) versus earnings of $333 million ($1.34 per diluted share) in 2017.  Full year 2018 results include a $1.6 billion impairment of goodwill associated with the 2016 MRD merger, and a $515 million impairment of unproved properties compared to $270 million in 2017, reflecting a shift in capital allocation related to North Louisiana properties.  Full year 2018 results also included a loss of $11 million from asset sales compared to a gain of $24 million in 2017, $51 million in derivative losses due to increases in future commodity prices compared to a $213 million gain in the prior year and a $19 million mark-to-market gain related to the deferred compensation plan compared to a $51 million gain in the prior year.

Non-GAAP revenues for 2018 totaled $3.2 billion, an increase of 33% compared to 2017 and cash flow from operations before changes in working capital, a non-GAAP measure, was $1.05 billion, compared to $916 million in 2017.  Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $279 million ($1.13 per diluted share), compared to $143 million ($0.58 per diluted share) in 2017.

The following table details Range’s average production and realized pricing for full year 2018:

Net Production
Natural Gas
(Mmcf/d)
Oil
(Bbl/d)
NGLs
(Bbl/d)
Natural Gas
Equivalent
(Mmcfe/d)
 
   
1,502 11,585 105,001 2,201
Realized Pricing
  Natural Gas
($/Mcf)
Oil
($/Bbl)
NGLs
($/Bbl)
Natural Gas
Equivalent
($/Mcfe)
     
Average NYMEX price $3.07 $65.49
Differential, including basis hedging (0.05) (4.97)
Realized prices before NYMEX hedges 3.02 60.52 $24.30 $3.55
Settled NYMEX hedges (0.04) (8.92) (1.69) (0.16)
Average realized prices after hedges $2.98 $51.60 $22.61 $3.39

Full year 2018 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts’ estimates) averaged $3.39 per mcfe.  Additional detail on commodity price realizations can be found in the Supplemental Tables provided on the Company’s website.

  • The 2018 average natural gas price, including the impact of basis hedging, was $3.02 per mcf, or a ($0.05) per mcf differential to NYMEX, which was significantly better than the ($0.32) differential in the prior year.  The improvement in natural gas differentials compared to last year is a result of increased pipeline connectivity and compressed basis across the Appalachian and Midwest regions.
  • Pre-hedge NGL realizations were $24.30 per barrel, or 37% of West Texas Intermediate (“WTI”) in 2018.  Hedging decreased NGL prices by $1.69 per barrel in 2018 compared to a decrease of $2.04 per barrel in the prior year.
  • Crude oil and condensate price realizations, before realized hedges, averaged $60.52 per barrel, or $4.97 below WTI, compared to $4.77 below WTI in the prior year.  Hedging decreased price by $8.92 per barrel in 2018, compared to hedge gains of $3.19 per barrel in the prior year.

2018 Unit Costs

The following table details Range’s unit costs per mcfe(a):

Expenses Full Year
2018

(per mcfe)
Full Year
2017

(per mcfe)
 Increase
(Decrease)
Direct operating $  0.17 $  0.18 (6%)
Transportation, gathering,
processing and compression 1.39(b) 1.04 34%
Production and ad valorem taxes 0.06 0.06
General and administrative(a) 0.19 0.21 (10%)
Interest expense 0.26 0.26
Total cash unit costs(c) 2.07 1.74 19%
Depletion, depreciation and
amortization (DD&A) 0.79 0.85 (7%)
Total unit costs plus DD&A(c) $  2.86 $  2.59 10%

(a)  Excludes stock-based compensation, legal settlements and amortization of deferred financing costs.
(b)  2018 transportation, gathering, processing and compression expense reflects the change in accounting method made at the beginning of the year.  As a result of adopting the new accounting standard, expenses increased by approximately $0.22 per mcfe in 2018.  There was an equal increase to NGL revenue, resulting in zero net impact to cash flow as a result of the change in accounting method.
(c)  May not add due to rounding.

Fourth Quarter 2018

The following table details Range’s average production and realized pricing for fourth quarter 2018:

Net Production
Natural Gas
(Mmcf/d)
Oil
(Bbl/d)
NGLs
(Bbl/d)
Natural Gas
Equivalent
(Mmcfe/d)
 
   
1,482 9,932 101,263 2,149
Realized Pricing
  Natural Gas
($/Mcf)
Oil
($/Bbl)
NGLs
($/Bbl)
Natural Gas
Equivalent
($/Mcfe)
     
Average NYMEX price $3.61 $60.79
Differential, including basis hedging (0.08) (6.28)
Realized prices before NYMEX hedges 3.53 54.51 $24.21 $3.83
Settled NYMEX hedges (0.63) (4.82) (0.12) (0.46)
Average realized prices after hedges $2.90 $49.69 $24.09 $3.37

Fourth quarter 2018 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts’ estimates) averaged $3.37 per mcfe.  Additional detail on commodity price realizations can be found in the Supplemental Tables provided on the Company’s website.

  • The average natural gas price, including the impact of basis hedging, was $3.53 per mcf, or an ($0.08) per mcf differential to NYMEX, which was significantly better than the ($0.35) differential during the prior-year quarter.  The improvement in natural gas differentials compared to last year is a result of increased pipeline connectivity and compressed basis across the Appalachian and Midwest regions.
  • Pre-hedge NGL realizations were $24.21 per barrel, or 40% of WTI.  Hedging decreased NGL prices by $0.12 per barrel compared to a decrease of $4.06 per barrel in the prior-year quarter.
  • Crude oil and condensate price realizations, before realized hedges, averaged $54.51 per barrel, or $6.28 below WTI, compared to $4.63 below WTI in the prior-year quarter.  Hedging decreased price by $4.82 per barrel compared to hedge gains of $0.27 per barrel in the prior-year quarter.

Fourth Quarter Unit Costs

The following table details Range’s unit costs per mcfe(a):

Expenses   4Q 2018
(per mcfe)
4Q 2017
(per mcfe)
 Increase
(Decrease)
Direct operating $  0.18 $  0.19 (5%)
Transportation, gathering,
processing and compression 1.51(b) 1.00 51%
Production and ad valorem taxes 0.08 0.06 33%
General and administrative(a) 0.16 0.21 (24%)
Interest expense 0.25 0.25
Total cash unit costs(c) 2.18 1.70 28%
Depletion, depreciation and
amortization (DD&A) 0.75 0.82 (9%)
Total unit costs plus DD&A(c) $  2.93 $  2.52 16%

(a)  Excludes stock-based compensation, legal settlements and amortization of deferred financing costs.
(b)  Fourth quarter 2018 transportation, gathering, processing and compression expense reflects the change in accounting method made earlier this year.  As a result of adopting the new accounting standard, expenses increased by approximately $0.23 per mcfe in fourth quarter 2018.  There was an equal increase to NGL revenue, resulting in zero net impact to cash flow as a result of the change in accounting method.
(c)  May not add due to rounding.

2018 Asset Sale

As previously announced, during fourth quarter 2018, Range sold a proportionately reduced 1% overriding royalty in its Washington County, Pennsylvania leases for gross proceeds of $300 million.

Range’s Washington County properties encompass approximately 300,000 net surface acres. The overriding royalty applies to existing and future Marcellus, Utica and Upper Devonian development on the subject leases, while excluding shallower and deeper formations.  Post-close, Range maintains a net revenue interest of approximately 82% on the subject Washington County acreage. The net proceeds were used to reduce bank debt.

Operational Discussion

Range previously updated its investor presentation with economic calculations. Please see www.rangeresources.com under the Investors tab, “Company Presentations” area, for the presentation entitled, “Company Presentation – February 25, 2019”.

The table below summarizes 2018 activity and estimates for 2019 regarding the number of wells to sales for each area.

Planned Wells
TIL
in 2019
Wells TIL
in 2018
SW PA Super-Rich 14 14
SW PA Wet 41 38
SW PA Dry 33 34
Total Appalachia 88 86
Total N. LA. 8 12
Total 96 98

Appalachia Division

Production for the fourth quarter of 2018 averaged approximately 1,893 net Mmcfe per day from the Appalachia division, a 5% increase over the prior year.  The northeast area of the division averaged 113 net Mmcf per day during the quarter.  The southwest area of the division averaged 1,780 net Mmcfe per day during the quarter, a 7% increase over the prior year.  As previously announced, in December, an operational issue at the Houston facility required the extended curtailment of both the Harmon Creek and Houston processing complexes.  As a result of MarkWest’s operational downtime, Range lost approximately 10 Bcfe of production during the quarter.  Both processing complexes were returned to service in early January.

Range brought on line 16 wells in southwest Appalachia during the fourth quarter, one in the super-rich area, and 15 in the wet area.  During the year, Range turned to sales a total of 86 Marcellus wells with an average lateral length of 9,388 feet.  The Company expects to run an average of three rigs in the Marcellus during 2019, and turn to sales 88 wells with an expected average lateral length of 10,800 feet.

North Louisiana

Production for the division in the fourth quarter of 2018 averaged approximately 256 net Mmcfe per day.  Range expects to turn to sales eight wells in North Louisiana in 2019.

Marketing and Transportation

Fourth quarter 2018 marked the first full quarter where Range had access to all of its contracted natural gas transportation, as Energy Transfer’s Rover project provided additional outlets to the Midwest and Gulf Coast in September.  The fourth quarter of 2018 natural gas differential of $0.08 under NYMEX is the best fourth quarter differential Range has seen since 2012, due in large part to the addition of transportation out of Appalachia.  Going forward, Range expects to keep its natural gas transportation full and sell incremental gas production into local markets which have improved due to the recently added takeaway infrastructure.

Range has capacity on the Mariner East 1 pipeline for a combined 40,000 barrels per day of ethane and propane.  As the only producer with propane capacity on Mariner East 1, Range has been able to capture premiums to the Mont Belvieu index price by exporting the majority of its propane to international markets since early 2016.  In addition, the Company sent the majority of its normal butane and remaining propane volumes during the summer to Marcus Hook for export via local rail.  As the Company continues to develop its liquids acreage, additional outlets for NGL production are beneficial in providing stability to NGL price, especially during the summer when in-basin demand is low.  Range has taken capacity on Mariner East 2 for a combined 20,000 barrels per day of propane and butane, starting in April 2020, which gives the Company additional flexibility in marketing NGL production while participating in the expected local market improvements.  Importantly, Range expects to fill the incremental capacity with existing propane and butane volumes, leaving flexibility to sell incremental NGLs in-basin.

In January 2019, Range lost access to its capacity on Sunoco’s Mariner East 1 pipeline following the appearance of a subsidence along the pipeline route.  As a result of the outage, Range is utilizing available capacity on the recently commissioned Mariner East 2 pipeline to continue moving its propane to the Marcus Hook terminal. For ethane, Range has multiple options for marketing its production, including the ability to sell ethane as natural gas.  While not materially altering corporate cash flows, the delayed restart of MarkWest plants and the Mariner East outage have reduced production volumes, and as a result, Range’s first quarter guidance of 2,225 Mmcfe per day reflects the estimated production impact.

Guidance – 2019

Production per day Guidance

Production for the full-year 2019 is expected to average approximately 2,325 to 2,345 Mmcfe per day, or 6% year-over-year growth at the midpoint.

First quarter 2019 production is expected to average approximately 2,225 Mmcfe per day.

1Q 2019 Expense Guidance 

Direct operating expense: $0.17 – $0.19 per mcfe
Transportation, gathering, processing and compression
expense: $1.48 – $1.52 per mcfe
Production tax expense: $0.05 – $0.06 per mcfe
Exploration expense: $6.0 – $9.0 million
Unproved property impairment expense: $7.0 – $10.0 million
G&A expense: $0.20 – $0.22 per mcfe
Interest expense: $0.24 – $0.26 per mcfe
DD&A expense: $0.74 – $0.78 per mcfe
Net brokered gas marketing (gain) expense: ~ ($3.0 million)
1Q 2019 Natural Gas Price Differential Guidance  NYMEX plus $0.01

Full Year 2019 Price Guidance

Based on current market pricing indications, Range expects to average the following pre-hedge differentials for its production in 2019.

Natural Gas: NYMEX minus $0.15 to $0.20
Natural Gas Liquids (including ethane): 36% – 38% of WTI
Oil/Condensate: WTI minus $6.00 to $8.00

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. At year-end 2018, Range had over 75% of its expected 2019 natural gas production hedged at a weighted average floor price of $2.86 per mmbtu.  Similarly, Range had hedged approximately 70% of its 2019 projected crude oil production at an average floor price of $56.23.   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 December 31, 2018 was a gain of $4.8 million, compared to a loss of $7.8 million at December 31, 2017.

Conference Call Information
A conference call to review the financial results is scheduled on Tuesday, February 26 at 9:00 a.m. ET. To participate in the call, please dial 866-900-7525 and provide conference code 6972159 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 March 26.

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 were historically 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.

Finding and development cost per unit is a non-GAAP metric used in the exploration and production industry by companies, investors and analysts. 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. This reserves metric may not be comparable to similarly titled measurements used by other companies.  The U.S. Securities and Exchange Commission (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 at www.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.

We believe that the presentation of PV10 is relevant and useful to our investors as supplemental disclosure to the standardized measure, or after-tax amount, because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure. While the standardized measure is dependent on the unique tax situation of each company, PV10 is based on prices and discount factors that are consistent for all companies. Because of this, PV10 can be used within the industry and by creditors and security analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis.

RANGE RESOURCES CORPORATION (NYSE: RRC) is a leading U.S. independent oil and natural gas 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.

Included within are certain “forward-looking statements” within the meaning of the federal securities laws, including the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 that are not limited to historical facts, but reflect Range’s current beliefs, expectations or intentions regarding future events.  Words such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “outlook”, “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” and similar expressions are intended to identify such forward-looking statements.

All statements, except for statements of historical fact, made within 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), including its most recent Annual Report on Form 10-K.  Unless required by law, Range undertakes no obligation to publicly update or revise any forward-looking statements to reflect circumstances or events after the date they are made.

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 its 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.

SOURCE:   Range Resources Corporation

Investor Contacts:

Laith Sando, Vice President – Investor Relations
817-869-4267
[email protected]

Michael Freeman, Director – Investor Relations & Hedging
817-869-4264
[email protected]

John Durham, Senior Financial Analyst
817-869-1538
[email protected]

Media Contact:

Michael Mackin, Director of External Affairs
724-743-6776
[email protected]

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-K
(Unaudited, in thousands, except per share data)
Three Months Ended December 31, Twelve Months Ended December 31,
2018 2017 % 2018 2017 %
Revenues and other income:
Natural gas, NGLs and oil sales (a) $ 756,627 $ 603,159 $ 2,851,077 $ 2,176,287
Derivative fair value (loss)/income 100,698 25,024 (51,192 ) 213,350
Brokered natural gas, marketing and other (b) 215,270 50,732 482,044 219,474
ARO settlement gain (loss) (b) (59 ) (17 ) (71 ) 47
Other (b) 101 134 787 1,872
Total revenues and other income 1,072,637 679,032 58 % 3,282,645 2,611,030 26 %
Costs and expenses:
Direct operating 34,953 37,424 137,422 132,192
Direct operating – non-cash stock-based compensation (c) 442 497 2,109 2,060
Transportation, gathering, processing and compression 298,716 200,300 1,117,816 761,183
Production and ad valorem taxes 16,656 11,757 46,149 42,882
Brokered natural gas and marketing 221,175 50,734 494,595 218,874
Brokered natural gas and marketing – non-cash
stock-based compensation (c) 451 397 1,452 1,437
Exploration 10,206 6,747 32,196 50,920
Exploration – non-cash stock-based compensation (c) 394 1,146 1,921 2,742
Abandonment and impairment of unproved properties 441,750 217,544 514,994 269,725
General and administrative 30,785 41,167 152,040 150,786
General and administrative – non-cash stock-based
compensation (c) 5,474 39,717 43,806 74,873
General and administrative – lawsuit settlements 13,581 (831 ) 14,966 6,197
General and administrative – bad debt expense 250 500 (1,000 ) 1,550
Termination costs (278 ) (373 ) 2,106
Termination costs – non-cash stock-based compensation (c) (1 ) 1,664
Deferred compensation plan (d) (18,072 ) (14,077 ) (18,631 ) (50,915 )
Interest expense 50,237 49,629 205,970 188,450
Interest expense – amortization of deferred financing costs (e) (1,076 ) 1,844 4,239 7,229
Depletion, depreciation and amortization 147,909 162,918 635,467 624,992
Impairment of proved property 22,614 63,679
Impairment of goodwill 1,641,197 1,641,197
Gain on sale of assets 10,815 (207 ) 10,666 (23,716 )
Total costs and expenses 2,905,843 806,927 260 % 5,059,615 2,528,910 100 %
(Loss) income before income taxes (1,833,206 ) (127,895 ) N.M. (1,776,970 ) 82,120 N.M.
Income tax (benefit) expense:
Current 17 17
Deferred (68,784 ) (349,097 ) (30,489 ) (251,043 )
(68,784 ) (349,080 ) (30,489 ) (251,026 )
Net (loss) income $ (1,764,422 ) $ 221,185 N.M. $ (1,746,481 ) $ 333,146 N.M.
Net (Loss) Income Per Common Share:
Basic $ (7.15 ) $ 0.89 $ (7.10 ) $ 1.34
Diluted $ (7.15 ) $ 0.89 $ (7.10 ) $ 1.34
Weighted average common shares outstanding, as reported:
Basic 246,631 245,281 1 % 246,171 245,091 0 %
Diluted 246,631 245,537 0 % 246,171 245,458 0 %

(a)  See separate natural gas, NGLs and oil sales information table.
(b)  Included in Brokered natural gas, marketing and other revenues in the 10-K.
(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-K.
(d)  Reflects the change in market value of the vested Company stock held in the deferred compensation plan.
(e)  Included in interest expense in the 10-K.

RANGE RESOURCES CORPORATION

BALANCE SHEETS      
(In thousands)   December 31, December 31,
2018 2017
(Audited) (Audited)
Assets
Current assets $ 514,232 $ 370,627
Derivative assets 92,795 58,880
Goodwill 1,641,197
Natural gas and oil properties, successful efforts method 9,023,185 9,566,737
Transportation and field assets 9,776 14,666
Other 68,166 76,734
$ 9,708,154 $ 11,728,841
Liabilities and Stockholders’ Equity
Current liabilities $ 745,182 $ 704,913
Asset retirement obligations 5,485 6,327
Derivative liabilities 4,144 44,233
Bank debt 932,018 1,208,467
Senior notes 2,856,166 2,851,754
Senior subordinated notes 48,677 48,585
Total debt 3,836,861 4,108,806
Deferred tax liability 666,668 693,356
Derivative liabilities 3,462 9,789
Deferred compensation liability 67,542 101,102
Asset retirement obligations and other liabilities 319,379 286,043
Common stock and retained earnings 4,060,480 5,776,203
Other comprehensive loss (658 ) (1,332 )
Common stock held in treasury stock (391 ) (599 )
Total stockholders’ equity 4,059,431 5,774,272
$ 9,708,154 $ 11,728,841
RECONCILIATION OF TOTAL REVENUES AND OTHER INCOME TO TOTAL REVENUE EXCLUDING CERTAIN ITEMS, a non-GAAP measure
(Unaudited, in thousands)
Three Months Ended December 31, Twelve Months Ended December 31,
  2018 2017 % 2018 2017 %
Total revenues and other income, as reported $ 1,072,637 $ 679,032 58 % $ 3,282,645 $ 2,611,030 26 %
Adjustment for certain special items:
Total change in fair value related to derivatives
prior to settlement (gain) loss (191,948 ) (27,969 ) (80,330 ) (200,233 )
ARO settlement (gain) loss 59 17 71 (47 )
Total revenues, as adjusted, non-GAAP $ 880,748 $ 651,080 35 % $ 3,202,386 $ 2,410,750 33 %

RANGE RESOURCES CORPORATION

CASH FLOWS FROM OPERATING ACTIVITIES
(Unaudited in thousands)
Three Months Ended
December 31,
Twelve Months Ended
December 31,
2018 2017 2018 2017
Net (loss) income $ (1,764,422 ) $ 221,185 $ (1,746,481 ) $ 333,146
Adjustments to reconcile net cash provided from continuing operations:
Deferred income tax (benefit) expense (68,784 ) (349,097 ) (30,489 ) (251,043 )
Depletion, depreciation, amortization and impairment 147,909 162,918 658,081 688,671
Impairment of goodwill 1,641,197 1,641,197
Exploration dry hole costs 6 4 9,172
Abandonment and impairment of unproved properties 441,750 217,544 514,994 269,725
Derivative fair value (income) loss (100,698 ) (25,024 ) 51,192 (213,350 )
Cash settlements on derivative financial instruments that do not qualify for hedge
accounting (91,250 ) (2,945 ) (131,522 ) 13,117
Allowance for bad debts 250 500 (1,000 ) 1,550
Amortization of deferred issuance costs, loss on extinguishment of debt, and other (1,648 ) 1,261 2,515 5,445
Deferred and stock-based compensation (11,495 ) 26,769 29,757 30,706
Loss (gain) on sale of assets and other 10,815 (207 ) 10,666 (23,716 )
Changes in working capital:
Accounts receivable (92,668 ) (63,172 ) (142,381 ) (102,866 )
Inventory and other 960 (1,475 ) 138 (2,979 )
Accounts payable 2,255 1,197 (4,274 ) 45,912
Accrued liabilities and other 101,572 26,262 138,293 12,764
Net changes in working capital 12,119 (37,188 ) (8,224 ) (47,169 )
Net cash provided from operating activities $ 215,743 $ 215,722 $ 990,690 $ 816,254
 
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 December 31, Twelve Months Ended December 31,
2018 2017 2018 2017
Net cash provided from operating activities, as reported $ 215,743 $ 215,722 $ 990,690 $ 816,254
Net changes in working capital (12,119 ) 37,188 8,224 47,169
Exploration expense 10,206 6,741 32,192 41,748
Lawsuit settlements 13,581 (831 ) 14,966 6,197
Termination costs (278 ) (373 ) 2,106
Non-cash compensation adjustment 815 1,510 2,695 2,892
Cash flow from operations before changes in working capital – non-GAAP measure $ 228,226 $ 260,052 $ 1,048,394 $ 916,366
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING
(Unaudited, in thousands)
Three Months Ended December 31, Twelve Months Ended December 31,
  2018 2017 2018 2017
Basic:
Weighted average shares outstanding 249,515 248,140 249,228 247,882
Stock held by deferred compensation plan (2,884 ) (2,859 ) (3,057 ) (2,791 )
Adjusted basic 246,631 245,281 246,171 245,091
Dilutive:
Weighted average shares outstanding 249,515 248,140 249,228 247,882
Dilutive stock options under treasury method (2,884 ) (2,603 ) (3,057 ) (2,424 )
Adjusted dilutive 246,631 245,537 246,171 245,458

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 December 31, Twelve Months Ended December 31,
2018 2017 % 2018 2017 %
Natural gas, NGL and oil sales components:
Natural gas sales $ 481,252 $ 340,965 $ 1,663,832 $ 1,349,945
NGL sales 225,567 192,232 931,360 604,672
Oil sales 49,808 69,962 255,885 221,650
Total oil and gas sales, as reported $ 756,627 $ 603,159 25 % $ 2,851,077 $ 2,176,267 31 %
Derivative fair value income (loss), as reported: $ 100,698 $ 25,024 $ (51,192 ) $ 213,350
Cash settlements on derivative financial instruments – (gain) loss:
Natural gas 85,757 (36,412 ) 29,291 (71,059 )
NGLs 1,087 39,733 64,522 73,192
Crude Oil 4,406 (376 ) 37,709 (15,250 )
Total change in fair value related to derivatives prior to settlement, a
non-GAAP measure $ 191,948 $ 27,969 $ 80,330 $ 200,233
Transportation, gathering, processing and compression components:
Natural gas $ 180,920 $ 141,902 $ 678,489 $ 526,671
NGLs 117,796 58,398 439,327 234,512
Total transportation, gathering, processing and compression, as reported $ 298,716 $ 200,300 $ 1,117,816 $ 761,183
Natural gas, NGL and oil sales, including cash-settled derivatives: (c)
Natural gas sales $ 395,495 $ 377,377 $ 1,634,541 $ 1,421,004
NGL sales 224,480 152,499 866,838 531,480
Oil sales 45,402 70,338 218,176 236,900
Total $ 665,377 $ 600,214 11 % $ 2,719,555 $ 2,189,384 24 %
Production of oil and gas during the periods (a):
Natural gas (mcf) 136,315,861 132,864,354 3 % 548,085,437 490,253,467 12 %
NGL (bbl) 9,316,151 9,755,481 -5 % 38,325,251 35,709,254 7 %
Oil (bbl) 913,735 1,380,649 -34 % 4,228,439 4,787,022 -12 %
Gas equivalent (mcfe) (b) 197,695,177 199,681,134 -1 % 803,407,577 733,231,123 10 %
Production of oil and gas – average per day (a):
Natural gas (mcf) 1,481,694 1,444,178 3 % 1,501,604 1,343,160 12 %
NGL (bbl) 101,263 106,038 -5 % 105,001 97,834 7 %
Oil (bbl) 9,932 15,007 -34 % 11,585 13,115 -12 %
Gas equivalent (mcfe) (b) 2,148,861 2,170,447 -1 % 2,201,117 2,008,852 10 %
Average prices, excluding derivative settlements and before third party
transportation costs:
Natural gas (mcf) $ 3.53 $ 2.57 38 % $ 3.04 $ 2.75 10 %
NGL (bbl) $ 24.21 $ 19.71 23 % $ 24.30 $ 16.93 44 %
Oil (bbl) $ 54.51 $ 50.67 8 % $ 60.52 $ 46.30 31 %
Gas equivalent (mcfe) (b) $ 3.83 $ 3.02 27 % $ 3.55 $ 2.97 20 %
Average prices, including derivative settlements before third party
transportation costs: (c)
Natural gas (mcf) $ 2.90 $ 2.84 2 % $ 2.98 $ 2.90 3 %
NGL (bbl) $ 24.10 $ 15.63 54 % $ 22.62 $ 14.88 52 %
Oil (bbl) $ 49.69 $ 50.95 -2 % $ 51.60 $ 49.49 4 %
Gas equivalent (mcfe) (b) $ 3.37 $ 3.01 12 % $ 3.39 $ 2.99 13 %
Average prices, including derivative settlements and after third party
transportation costs: (d)
Natural gas (mcf) $ 1.57 $ 1.77 -11 % $ 1.74 $ 1.82 -4 %
NGL (bbl) $ 11.45 $ 9.65 19 % $ 11.15 $ 8.32 34 %
Oil (bbl) $ 49.69 $ 50.95 -2 % $ 51.60 $ 49.49 4 %
Gas equivalent (mcfe) (b) $ 1.85 $ 2.00 -7 % $ 1.99 $ 1.95 2 %
Transportation, gathering and compression expense per mcfe $ 1.51 $ 1.00 51 % $ 1.39 $ 1.04 34 %

(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.

RANGE RESOURCES CORPORATION

RECONCILIATION OF INCOME BEFORE (LOSS) 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 December 31, Twelve Months Ended December 31,
 2018  2017  %  2018  2017  %
(Loss) income from operations before income taxes, as reported $ (1,833,206 ) $ (127,895 ) N.M. $ (1,776,970 ) $ 82,120 N.M.
Adjustment for certain special items:
Loss (gain) on sale of assets 10,815 (207 ) 10,666 (23,716 )
Loss (gain) on ARO settlements 59 17 71 (47 )
Change in fair value related to derivatives prior to settlement (191,948 ) (27,969 ) (80,330 ) (200,233 )
Impairment of goodwill 1,641,197 1,641,197
Abandonment and impairment of unproved properties 441,750 217,544 514,994 269,725
Impairment of proved property 22,614 63,679
Lawsuit settlements 13,581 (831 ) 14,966 6,197
Termination costs (278 ) (373 ) 2,106
Termination costs – non-cash stock-based compensation (1 ) 1,664
Brokered natural gas and marketing – non-cash stock-based
compensation 451 397 1,452 1,437
Direct operating – non-cash stock-based compensation 442 497 2,109 2,060
Exploration expenses – non-cash stock-based compensation 394 1,146 1,921 2,742
General & administrative – non-cash stock-based compensation 5,474 39,717 43,806 74,873
Deferred compensation plan – non-cash adjustment (18,072 ) (14,077 ) (18,631 ) (50,915 )
Income before income taxes, as adjusted 70,937 88,060 -19 % 377,492 231,692 63 %
Income tax expense, as adjusted
Current 17 17
Deferred (a) 18,444 33,446 98,061 88,738
Net income excluding certain items, a non-GAAP measure $ 52,493 $ 54,597 -4 % $ 279,431 $ 142,937 95 %
Non-GAAP income per common share
Basic $ 0.21 $ 0.22 -5 % $ 1.14 $ 0.58 97 %
Diluted $ 0.21 $ 0.22 -5 % $ 1.13 $ 0.58 95 %
Non-GAAP diluted shares outstanding, if dilutive 247,719 245,537 247,220 245,458

(a)  Deferred taxes for 2018 are estimated to be approximately 26% and 38% for 2017.

RANGE RESOURCES CORPORATION

RECONCILIATION OF NET (LOSS) INCOME, EXCLUDING
CERTAIN ITEMS AND ADJUSTED EARNINGS PER SHARE, non-GAAP measures
(In thousands, except per share data)
Three Months Ended
December 31,
Twelve Months Ended
December 31,
2018 2017 2018 2017
Net (loss) income, as reported $ (1,764,422 ) $ 221,185 $ (1,746,481 ) $ 333,146
Adjustment for certain special items:
(Gain) loss on sale of assets 10,815 (207 ) 10,666 (23,716 )
Loss (gain) on ARO settlements 59 17 71 (47 )
Change in fair value related to derivatives prior to settlement (191,948 ) (27,969 ) (80,330 ) (200,233 )
Impairment of goodwill 1,641,197 1,641,197
Impairment of proved property 22,614 63,679
Abandonment and impairment of unproved properties 441,750 217,544 514,994 269,725
Lawsuit settlements 13,581 (831 ) 14,966 6,197
Termination costs (278 ) (373 ) 2,106
Non-cash stock-based compensation 6,761 41,756 49,288 82,776
Deferred compensation plan (18,072 ) (14,077 ) (18,631 ) (50,915 )
Tax impact (87,228 ) (382,543 ) (128,550 ) (339,781 )
Net income excluding certain items, a non-GAAP measure $ 52,493 $ 54,597 $ 279,431 $ 142,937
Net (loss) income per diluted share, as reported $ (7.15 ) $ 0.89 $ (7.10 ) $ 1.34
Adjustment for certain special items per diluted share:
(Gain) loss on sale of assets 0.04 (0.00 ) 0.04 (0.10 )
Loss (gain) on ARO settlements 0.00 0.00 0.00 (0.00 )
Change in fair value related to derivatives prior to settlement (0.78 ) (0.11 ) (0.33 ) (0.82 )
Impairment of goodwill 6.65 6.67
Impairment of proved property 0.09 0.26
Abandonment and impairment of unproved properties 1.79 0.89 2.09 1.10
Lawsuit settlements 0.06 (0.00 ) 0.06 0.03
Termination costs (0.00 ) (0.00 ) 0.01
Non-cash stock-based compensation 0.03 0.17 0.20 0.34
Deferred compensation plan (0.07 ) (0.06 ) (0.08 ) (0.21 )
Adjustment for rounding differences (0.01 ) 0.01 0.01
Tax impact (0.35 ) (1.56 ) (0.52 ) (1.38 )
Net income per diluted share, excluding certain items, a non-
  GAAP measure $ 0.21 $ 0.22 $ 1.13 $ 0.58
Adjusted earnings per share, a non-GAAP measure:
Basic $ 0.21 $ 0.22 $ 1.14 $ 0.58
Diluted $ 0.21 $ 0.22 $ 1.13 $ 0.58

RANGE RESOURCES CORPORATION

RECONCILIATION OF CASH MARGIN PER MCFE, a non-
GAAP measure
(Unaudited, in thousands, except per unit data)
Three Months Ended
December 31,
Twelve Months Ended
December 31,
 2018  2017  2018  2017
Revenues
Natural gas, NGL and oil sales, as reported $ 756,627 $ 603,159 $ 2,851,077 $ 2,176,287
Derivative fair value income (loss), as reported 100,698 25,024 (51,192 ) 213,350
  Less non-cash fair value (gain) loss (191,948 ) (27,969 ) (80,330 ) (200,233 )
Brokered natural gas and marketing and other, as reported 215,312 50,849   482,760 221,393
  Less ARO settlement and other (gains) losses (42 ) (117 ) (716 ) (1,919 )
  Cash revenue applicable to production 880,647 650,946 3,201,599 2,408,878
Expenses
Direct operating, as reported 35,395 37,921 139,531 134,252
  Less direct operating stock-based compensation (442 ) (497 ) (2,109 ) (2,060 )
Transportation, gathering and compression, as reported 298,716 200,300 1,117,816 761,183
Production and ad valorem taxes, as reported 16,656 11,757 46,149 42,882
Brokered natural gas and marketing, as reported 221,626 51,131 496,047 220,311
  Less brokered natural gas and marketing stock-based
  compensation   (451 ) (397 ) (1,452 ) (1,437 )
General and administrative, as reported 50,090 80,553 209,812 233,406
  Less G&A stock-based compensation (5,474 ) (39,717 ) (43,806 ) (74,873 )
  Less lawsuit settlements (13,581 ) 831 (14,966 ) (6,197 )
Interest expense, as reported 49,161 51,473 210,209 195,679
  Less amortization of deferred financing costs 1,076 (1,844 ) (4,239 ) (7,229 )
  Cash expenses 652,772 391,511 2,152,992 1,495,917
 
Cash margin, a non-GAAP measure $ 227,875 $ 259,435 $ 1,048,607 $ 912,961
Mmcfe produced during period 197,695 199,681 803,408 733,231
Cash margin per mcfe $ 1.15 $ 1.30 $ 1.31 $ 1.25
 
 
RECONCILIATION OF (LOSS) INCOME BEFORE INCOME
TAXES TO CASH MARGIN
(Unaudited, in thousands, except per unit data)
  Three Months Ended
December 31,
Twelve Months Ended
December 31,
 2018  2017  2018  2017
 
(Loss) income before income taxes, as reported $ (1,833,206 ) $ (127,895 ) $ (1,776,970 ) $ 82,120
Adjustments to reconcile income (loss) before income taxes to cash
   margin:
ARO settlements and other (gains) losses (42 ) (117 ) (716 ) (1,919 )
Derivative fair value (income) loss (100,698 ) (25,024 ) 51,192 (213,350 )
Net cash receipts on derivative settlements (91,250 ) (2,945 ) (131,522 ) 13,117
Exploration expense 10,206 6,747 32,196 50,920
Lawsuit settlements 13,581 (831 ) 14,966 6,197
Termination costs (278 ) (373 ) 2,106
Deferred compensation plan (18,072 ) (14,077 ) (18,631 ) (50,915 )
Stock-based compensation (direct operating, brokered natural gas
and marketing, general and administrative and termination costs)  6,761 41,756  49,288  82,776
Interest – amortization of deferred financing costs (1,076 ) 1,844 4,239 7,229
Depletion, depreciation and amortization 147,909 162,918 635,467 624,992
(Gain) loss on sale of assets 10,815 (207 ) 10,666 (23,716 )
Impairment of goodwill 1,641,197 1,641,197
Impairment of proved property and other assets 22,614 63,679
Abandonment and impairment of unproved properties 441,750 217,544 514,994 269,725
Cash margin, a non-GAAP measure $ 227,875 $ 259,435 $ 1,048,607 $ 912,961

RANGE RESOURCES CORPORATION

HEDGING POSITION AS OF DECEMBER 31, 2018 – (Unaudited)  

       Daily Volume    Hedge Price
Gas  1
1Q 2019 Swaps 1,385,000 Mmbtu $3.05
2Q 2019 Swaps 1,455,000 Mmbtu $2.80
3Q 2019 Swaps 1,455,000 Mmbtu $2.80
4Q 2019 Swaps 1,428,478 Mmbtu $2.81
2020 Swaps 80,000 Mmbtu $2.77
Oil
2019 Collar 1,000 bbls $63 x 73
1H 2019 Swaps 7,000 bbls $55.08
2H 2019 Swaps 7,000 bbls $55.45
2020 Swaps 1,562 bbls $61.05
C3 Propane
 
1Q 2019 Collars 7,000 bbls $0.927 x $1.029 /gallon
2Q 2019 Collars 1,000 bbls $0.90 x $0.96 /gallon
1Q 2019 Swaps 8,500 bbls $0.963/gallon
2Q 2019 Swaps 8,500 bbls $0.878/gallon
C4 Normal Butane
1Q 2019 Swaps 2,500 bbls $1.221/gallon
C5 Natural Gasoline
1Q 2019 Swaps 3,750 bbls $1.438/gallon
2Q 2019 Swaps 3,000 bbls $1.401/gallon
3Q 2019 Swaps 1,500 bbls $1.472/gallon
4Q 2019 Swaps 1,500 bbls $1.475/gallon

(1) Range also sold call swaptions of 230,000 Mmbtu/d for calendar 2020 at an average strike price of $2.80 per Mmbtu



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