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Range Announces Fourth Quarter and Year-End 2019 Results


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Source: Range Resources Corporation

FORT WORTH, Texas, Feb. 27, 2020 (GLOBE NEWSWIRE) — RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its fourth quarter and full-year 2019 financial results.

Highlights –

  • All-in 2019 capital spending was $728 million, approximately $28 million less than the original budget
  • Sold assets for gross proceeds of $785 million in 2019 to reduce debt
  • Fourth quarter cash unit costs improved by $0.26 per mcfe compared to prior year period
  • Year-end proved reserves increased to 18.2 Tcfe, with 95% from Marcellus Shale
  • All-in 2020 capital budget of $520 million maintains production at ~2.3 Bcfe per day
  • 2020 well costs expected to average less than $610 per lateral foot in 2020, lowest in Appalachia
  • Expanded credit facility to $2.4 billion in October 2019, making year-end 2019 liquidity $1.7 billion

Commenting on the results and 2020 plans, Jeff Ventura, the Company’s CEO said, “Range made solid progress on key strategic objectives in 2019.  For the year, we reduced absolute debt, lowered well costs, improved our cost structure and delivered our operational plan for $28 million less than budgeted.  During the year, Range executed approximately $785 million in asset sales and, in January, refinanced $550 million of nearer-term debt. These results reflect the organization’s continuing focus on capital discipline and further strengthening our financial position as we methodically develop the most prolific natural gas and NGL play in North America.

The durability of Range’s high-quality resource base is demonstrated in the year-end PV10 reserve value of $7.6 billion, which equates to approximately $17 per share, net of debt.  Our resilience is further demonstrated by the underlying efficiency of our 2020 capital program that can maintain production at 2.3 Bcfe per day for only $490 million of drilling and completion capital without a change in lateral inventory.  Looking forward, I believe Range’s high-quality asset base, capital discipline and peer-leading operational efficiencies provide a solid foundation for creating stockholder value in the years ahead.”

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.

Fourth Quarter 2019 Results

GAAP revenues for fourth quarter 2019 totaled $606 million, GAAP net cash provided from operating activities (including changes in working capital) was $132 million, and GAAP earnings was a loss of $1.8 billion ($7.27 per diluted share).  As previously disclosed in connection with Range’s recent notes offering, fourth quarter earnings results include a $1.1 billion proved property impairment and a $1.2 billion impairment of unproved properties associated with Range’s North Louisiana assets.  Marcellus assets were not impaired during the quarter and are not anticipated to be impaired based on the current market, as the future undiscounted cash flows are materially above book value.  Fourth quarter also included an $18 million derivative gain due to decreases in commodity prices.

Non-GAAP revenues for fourth quarter 2019 totaled $637 million, and cash flow from operations before changes in working capital, a non-GAAP measure, was $175 million.  Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $21 million ($0.08 per diluted share) in fourth quarter 2019.

The following table details Range’s average production and realized pricing for fourth quarter 2019:

4Q19 Production & Realized Pricing
  Natural Gas
(Mcf)
Oil
(Bbl)

NGLs
(Bbl)
Natural Gas
Equivalent
(Mcfe)

     
Net Production per day 1,638,135 10,461 107,381 2,345,187
     
Average NYMEX price $ 2.50 $ 56.86
Differential, including basis hedging (0.31 ) (8.21 )
Realized prices before NYMEX hedges 2.19 48.65 $ 17.52 $ 2.53
Settled NYMEX hedges 0.28 (0.12 ) 0.33 0.23
Average realized prices after hedges $ 2.47 $ 48.53 $ 17.85 $ 2.76

Fourth quarter 2019 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts’ estimates) averaged $2.76 per mcfe.

  • The average natural gas price, including the impact of basis hedging, was $2.19 per mcf, or a ($0.31) per mcf differential to NYMEX.  Fourth quarter natural gas differential was impacted by weak basis pricing in October and November.  Starting in December through early 2020, local Appalachian basis has normalized while premium northeast markets have weakened due to the warm winter season.
  • Pre-hedge NGL realizations were $17.52 per barrel, or $0.14 per barrel below the Mont Belvieu weighted barrel, as shown on Supplemental Table 9 on the Company’s website.  Range continues to improve on its NGL pricing, as the fourth quarter differential to Mont Belvieu was another best in recent Company history.  Range expects to maintain a strong NGL differential during 2020 as a result of access to international markets and its diversified portfolio of sales agreements.
  • Crude oil and condensate price realizations, before realized hedges, averaged $48.65 per barrel, or $8.21 below WTI.

The following table details Range’s fourth quarter 2019 unit costs per mcfe(a):

Expenses   4Q 2019
(per mcfe)
4Q 2018
(per mcfe)
 Increase
(Decrease)
Direct operating $ 0.15 $ 0.18 (17 %)
Transportation, gathering, processing and compression 1.39 1.51 (8 %)
Production and ad valorem taxes 0.04 0.08 (50 %)
General and administrative(a) 0.14 0.16 (13 %)
Interest expense(a) 0.19 0.25 (24 %)
Total cash unit costs(b) 1.92 2.18 (12 %)
Depletion, depreciation and amortization (DD&A) 0.61 0.75 (19 %)
Total unit costs plus DD&A(b) $   2.53 $   2.93 (14 %)

(a)  Excludes stock-based compensation, legal settlements and amortization of deferred financing costs.
(b)  May not add due to rounding.


Full-Year 2019 
Results

GAAP revenues for 2019 totaled $2.8 billion, GAAP net cash provided from operating activities (including changes in working capital) was $682 million, and GAAP net income was a loss of $1.7 billion ($6.92 per diluted share).  Full-year 2019 earnings results include $2.3 billion of impairments associated with North Louisiana assets.  Full-year 2019 results also included a $227 million derivative gain due to decreases in commodity prices.

Non-GAAP revenues for 2019 totaled $2.8 billion, and cash flow from operations before changes in working capital, a non-GAAP measure, was $729 million.  Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $98 million ($0.40 per diluted share) in 2019.

The following table details Range’s average production and realized pricing for full-year 2019:

2019 Production & Realized Pricing
  Natural Gas
(Mcf)
Oil
(Bbl)

NGLs
(Bbl)
Natural Gas
Equivalent
(Mcfe)

     
Net Production per day 1,583,875 10,109 106,439 2,283,162
   
Average NYMEX price $ 2.62 $ 57.21
Differential, including basis hedging (0.19 ) (6.95 )
Realized prices before NYMEX hedges 2.43 50.26 $ 17.53 $ 2.71
Settled NYMEX hedges 0.21 (0.52 ) 1.32 0.22
Average realized prices after hedges $ 2.64 $ 49.74 $ 18.85 $ 2.93

Full year 2019 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts’ estimates) averaged $2.93 per mcfe.  Additional detail on commodity price realizations can be found in the Supplemental Tables provided on the Company’s website.

The following table details Range’s calendar 2019 unit costs per mcfe(a):

Expenses FY 2019
(per mcfe)
FY 2018
(per mcfe)
 Increase
(Decrease)
Direct operating $ 0.16 $ 0.17 (6 %)
Transportation, gathering, processing and compression 1.44 1.39 4 %
Production and ad valorem taxes 0.05 0.06 (17 %)
General and administrative(a) 0.17 0.19 (11 %)
Interest expense 0.22 0.26 (15 %)
Total cash unit costs(b) 2.04 2.07 (1 %)
Depletion, depreciation and amortization (DD&A) 0.66 0.79 (16 %)
Total unit costs plus DD&A(b) $   2.69 $   2.86 (6 %)

(a)  Excludes stock-based compensation, legal settlements and amortization of deferred financing costs.
(b)  May not add due to rounding.


Capital Expenditures

Fourth quarter 2019 drilling and completions expenditures were $126 million and in addition $26 million was spent on acreage.  Total capital expenditures in 2019 were $728 million, including $667 million on drilling and completion, $57 million on acreage purchases and $4 million on gas gathering systems.  Total capital expenditures in 2019 were $28 million less than originally budgeted, driven by continued improvement in Range’s drilling and completion efficiencies, water recycling program, and service cost reductions.

Asset Sales

As previously announced, during 2019, Range sold proportionately reduced 2.5% overriding royalty interests in southwest Appalachia for gross proceeds totaling $750 million.  Range maintains a net revenue interest of approximately 79.5% on the subject acreage.  Separately, during the year, Range sold miscellaneous unproved property and other legacy assets for $35 million.  Net proceeds from sales during the year were used to reduce bank debt.  Additional sale processes to monetize non-core assets remain underway.

Financial Position and Repurchase Programs

In October of 2019, Range increased bank commitments from $2.0 billion to $2.4 billion. The borrowing base of $3.0 billion remained unchanged and the maximum facility amount remained $4.0 billion.  Range also initiated a share repurchase program in October, repurchasing 1.8 million shares during the fourth quarter for approximately $6.9 million.  At year-end 2019, Range had approximately $93 million remaining on the $100 million repurchase program.

Range repurchased and retired approximately $108 million in principal amount of its senior notes during the fourth quarter.  Total senior notes repurchased during 2019 was approximately $202 million in principal amount at an average weighted discount to par of 3%.

At December 31, 2019, Range had total debt outstanding of $3.2 billion, consisting of $2.7 billion in senior notes, $477 million in bank debt and $49 million in senior subordinated notes.  As of year-end, the Company had approximately $1.7 billion of borrowing capacity available under the commitment amount.

In January 2020, Range issued $550.0 million aggregate principal amount of 9.25% senior notes due 2026.  On the closing of the senior notes, proceeds were used to redeem $500 million aggregate principal amount of the Company’s senior notes due 2021 and senior notes due 2022, which was completed in February 2020.  Also announced in January, the Company suspended its dividend, which was approximately $20 million annually, to prioritize debt reduction.

Operational Discussion

Southwest Marcellus production for the fourth quarter of 2019 averaged approximately 2,063 net Mmcfe per day, a 16% increase over the prior year period.  The northeast Marcellus assets averaged 98 net Mmcf per day during the quarter, inclusive of approximately 10 net Mmcf per day of legacy acreage production.  North Louisiana production in the fourth quarter averaged approximately 183 net Mmcfe per day.

Range brought on line 23 wells in southwest Appalachia during the fourth quarter, six in the super-rich area, 10 in the wet area and seven in the dry area.  During the year, Range turned to sales a total of 84 Marcellus wells with an average lateral length of 10,550 feet and seven wells in Louisiana.

2020 Capital Spending Plans

Range’s 2020 capital budget is $520 million.  The capital budget includes approximately $490 million for drilling and recompletions (94% of the total), $30 million for leasehold and other capital expenditures.  The Company expects to turn to sales 72 Marcellus wells in 2020 with an expected average lateral length of approximately 11,200 feet.  Range anticipates drilling approximately 810,000 feet of lateral in 2020 while turning to sales approximately 806,400 feet of lateral during the year, keeping in-progress well inventory nearly unchanged going into 2021.

The table below summarizes 2019 activity and estimates for 2020 regarding the number of wells to sales in each area.

Planned Wells
TIL in 2020
Actual Wells
TIL in 2019
SW PA Super-Rich 9 25
SW PA Wet 26 26
SW PA Dry 37 33
Total Appalachia 72 84
Total N. LA. 7
Total 72 91

2019 Proved Reserves

Range previously announced 2019 proved reserves in January.   Highlights from the announcement were:

  • Year-end 2019 SEC PV10 value of proved reserves was $7.6 billion
  • Year-end 2019 proved reserves increase to 18.2 Tcfe, with 95% from Marcellus
  • Future development costs for proved undeveloped reserves estimated to be $0.35 per mcfe

Year-end 2019 reserves included 8.3 Tcfe of proved undeveloped reserves from 442 wells planned to be developed within the next five years.  Beyond the five-year reserve calculation window, Range has more than 2,800 additional Marcellus locations available for development.  Range also has a network of over 200 existing well pads designed to accommodate an average of 20 wells from any combination of Marcellus, Utica or Upper Devonian horizons.  On average, existing pads contain five producing wells, providing Range the opportunity to develop thousands of future wells while utilizing existing roads, pads and infrastructure.  Similar to prior years, approximately half of the wells planned to turn to sales in 2020 are from pad sites with existing production.

The table below reflects Range’s estimate of the remaining core drilling inventory for the Marcellus.

Estimated Future Marcellus Drilling Locations – December 31, 2019
(Excludes Utica and Upper Devonian locations)
Area Net Acres Assumed
Lateral Length
Producing
Locations(1)
Undrilled
Locations(2)
SW Marcellus – Liquids areas ~350,000 10,000 ft. 445 2,700
SW Marcellus – Dry area ~120,000 10,000 ft. 180 600
Total ~470,000   625 ~3,300

(1)   Producing locations adjusted to 10,000 foot equivalent
(2)   Includes anticipated down-spacing activity


Guidance – 2020

Production per day Guidance

Production for full-year 2020 is expected to average approximately 2.3 Bcfe per day, with ~30% attributed to liquids production.

Full Year 2020 Expense Guidance 

Direct operating expense: $0.14 – $0.16 per mcfe
Transportation, gathering, processing and compression expense: (1) $1.40 – $1.45 per mcfe (1)
Production tax expense: $0.04 – $0.05 per mcfe
Exploration expense: $30.0 – $38.0 million
G&A expense: $0.14 – $0.16 per mcfe
Interest expense: $0.22 – $0.24 per mcfe
DD&A expense: $0.48 – $0.52 per mcfe
Net brokered gas marketing expense: $10.0 – $16.0 million

(1)  Transportation guidance reflects the expected startup of Range’s Mariner East 2 capacity in April 2020, which can be filled with existing production. When this capacity starts, propane and butane volumes that had been transported by rail and sold net of transport, will be transported via pipe with sales price and transportation expense reported separately. The impact to financial statements is an increase in transportation expense, more than offset by an increase in realized NGL price. As a result of lower transport costs and elimination of other fees, the startup of this capacity provides annual uplift to cash flow in excess of $5 million.


Full Year 2020 Price Guidance

Based on current market indications, Range expects to average the following price differentials for its production in 2020.

Natural Gas:(1) NYMEX minus $0.20 to $0.26
Natural Gas Liquids (including ethane):(2) Mont Belvieu plus $0.50 to $1.50 per barrel
Oil/Condensate: WTI minus $7.00 to $8.00

(1)  Including basis hedging
(2)  Weighting based on 53% ethane, 27% propane, 7% normal butane, 4% iso-butane and 9% natural gasoline.


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 2019, Range had over 60% of its expected 2020 natural gas production hedged at a weighted average floor price of $2.64 per Mmbtu.  Similarly, Range had hedged approximately 80% of its 2020 projected crude oil production at an average floor price of $58.27 per barrel.   Please see Range’s detailed hedging schedule posted at the end of the financial tables below and on its website under Supplemental Tables.

Range has also hedged Marcellus and other basis differentials for natural gas and NGL exports to limit volatility between benchmarks and regional prices.  The combined fair value of the natural gas and NGL basis hedges as of December 31, 2019 was a net loss of $4.7 million.

Conference Call Information

A conference call to review the financial results is scheduled on Friday, February 28 at 9:00 a.m. ET. To participate in the call, please dial 866-900-7525 and provide conference code 6653428 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 28.

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 natural gas, NGL and oil producer with operations focused on stacked-pay projects in the Appalachian Basin.  The Company pursues an organic development strategy targeting high return, low-cost projects within its large inventory of low risk drilling opportunities. The Company is headquartered in Fort Worth, Texas.  More information information about Range can be found at www.rangeresources.com.

Included within this release 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.

Range Investor Contacts:

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

Range Media Contacts:

Mark Windle, Manager of Corporate Communications
724-873-3223
[email protected]

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,
2019 2018 % 2019 2018 %
Revenues and other income:
Natural gas, NGLs and oil sales (a) $ 545,438 $ 756,627 $ 2,255,425 $ 2,851,077
Derivative fair value income/(loss) 18,491 100,698 226,681 (51,192 )
Brokered natural gas, marketing and other (b) 41,524 215,270 344,372 482,044
ARO settlement gain (loss) (b) (2 ) (59 ) (13 ) (71 )
Other (b) 153 101 1,150 787
Total revenues and other income 605,604 1,072,637 -44 % 2,827,615 3,282,645 -14 %
Costs and expenses:
Direct operating 33,323 34,953 134,348 137,422
Direct operating – non-cash stock-based compensation (c) 469 442 1,928 2,109
Transportation, gathering, processing and compression 299,511 298,716 1,199,297 1,117,816
Production and ad valorem taxes 8,963 16,656 37,967 46,149
Brokered natural gas and marketing 46,199 221,175 358,036 494,595
Brokered natural gas and marketing – non-cash stock-based compensation (c) 333 451 1,856 1,452
Exploration 9,156 10,206 35,117 32,196
Exploration – non-cash stock-based compensation (c) 194 394 1,566 1,921
Abandonment and impairment of unproved properties 1,193,711 441,750 1,235,342 514,994
General and administrative 30,269 30,785 137,694 152,040
General and administrative – non-cash stock-based compensation (c) 7,500 5,474 35,061 43,806
General and administrative – lawsuit settlements 542 13,581 2,577 14,966
General and administrative – rig release penalty 1,436
General and administrative – bad debt expense 4,482 250 4,341 (1,000 )
Termination costs 4,535 7,535 (373 )
Termination costs – non-cash stock-based compensation (c) 1,946 1,971
Deferred compensation plan (d) 960 (18,072 ) (15,472 ) (18,631 )
Interest expense 42,043 50,237 186,916 205,970
Interest expense – amortization of deferred financing costs (e) 1,981 (1,076 ) 7,369 4,239
Gain on early extinguishment of debt (2,430 ) (5,415 )
Depletion, depreciation and amortization 130,869 147,909 548,843 635,467
Impairment of proved property 1,095,634 1,095,634 22,614
Goodwill impairment 1,641,197 1,641,197
(Gain) loss on sale of assets (407 ) 10,815 30,256 10,666
Total costs and expenses 2,909,783 2,905,843 0 % 5,044,203 5,059,615 0 %
Loss before income taxes (2,304,179 ) (1,833,206 ) -26 % (2,216,588 ) (1,776,970 ) -25 %
Income tax expense (benefit):
Current 2,068 6,147
Deferred (500,927 ) (68,784 ) (506,438 ) (30,489 )
(498,859 ) (68,784 ) (500,291 ) (30,489 )
Net loss $ (1,805,320 ) $ (1,764,422 ) -2 % $ (1,716,297 ) $ (1,746,481 ) 2 %
Net Loss Per Common Share:
Basic $ (7.27 ) $ (7.15 ) $ (6.92 ) $ (7.10 )
Diluted $ (7.27 ) $ (7.15 ) $ (6.92 ) $ (7.10 )
Weighted average common shares outstanding, as reported:
Basic 248,277 246,631 1 % 247,970 246,171 1 %
Diluted 248,277 246,631 1 % 247,970 246,171 1 %

(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,
2019 2018
(Audited) (Audited)
Assets
Current assets $ 290,954 $ 514,232
Derivative assets 137,554 92,795
Natural gas and oil properties, successful efforts method 6,041,035 9,023,185
Transportation and field assets 5,375 9,776
Operating lease right-of-use assets 62,053
Other 75,432 68,166
$ 6,612,403 $ 9,708,154
Liabilities and Stockholders’ Equity
Current liabilities $ 551,032 $ 745,182
Asset retirement obligations 2,393 5,485
Derivative liabilities 13,119 4,144
Bank debt 464,319 932,018
Senior notes 2,659,844 2,856,166
Senior subordinated notes 48,774 48,677
Total debt 3,172,937 3,836,861
Deferred tax liability 160,196 666,668
Derivative liabilities 949 3,462
Deferred compensation liability 64,070 67,542
Operating lease liabilities 41,068
Asset retirement obligations and other liabilities 259,151 319,379
Common stock and retained earnings 2,355,512 4,060,480
Other comprehensive loss (788 ) (658 )
Common stock held in treasury stock (7,236 ) (391 )
Total stockholders’ equity 2,347,488 4,059,431
$ 6,612,403 $ 9,708,154
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,
  2019 2018 % 2019 2018 %
Total revenues and other income, as reported $ 605,604 $ 1,072,637 -44 % $ 2,827,615 $ 3,282,645 -14 %
Adjustment for certain special items:
Total change in fair value related to derivatives prior to settlement (gain) loss 31,544 (191,948 ) (38,297 ) (80,330 )
ARO settlement (gain) loss 2 59 13 71
Total revenues, as adjusted, non-GAAP $ 637,150 $ 880,748 -28 % $ 2,789,331 $ 3,202,386 -13 %

RANGE RESOURCES CORPORATION

CASH FLOWS FROM OPERATING ACTIVITIES
(Unaudited in thousands)
Three Months Ended December 31, Twelve Months Ended December 31,
2019 2018 2019 2018
Net loss $ (1,805,320 ) $ (1,764,422 ) $ (1,716,297 ) $ (1,746,481 )
Adjustments to reconcile net cash provided from continuing operations:
Deferred income tax benefit (500,927 ) (68,784 ) (506,438 ) (30,489 )
Depletion, depreciation, amortization and impairment 1,226,503 147,909 1,644,477 658,081
Goodwill impairment 1,641,197 1,641,197
Exploration dry hole costs (11 ) (11 ) 4
Abandonment and impairment of unproved properties 1,193,711 441,750 1,235,342 514,994
Derivative fair value loss (income) (18,491 ) (100,698 ) (226,681 ) 51,192
Cash settlements on derivative financial instruments that do not qualify for hedge accounting 50,035 (91,250 ) 188,384 (131,522 )
Allowance for bad debts 4,482 250 4,341 (1,000 )
Amortization of deferred issuance costs, loss on extinguishment of debt, and other 1,593 (1,648 ) 6,455 2,515
Deferred and stock-based compensation 10,481 (11,495 ) 24,891 29,757
(Gain) loss on sale of assets and other (407 ) 10,815 30,256 10,666
Gain on early extinguishment of debt (2,430 ) (5,415 )
Changes in working capital:
Accounts receivable (27,318 ) (92,668 ) 214,196 (142,381 )
Inventory and other 8,544 960 4,520 138
Accounts payable (7,729 ) 2,255 (60,374 ) (4,274 )
Accrued liabilities and other (304 ) 101,572 (155,803 ) 138,293
Net changes in working capital (26,807 ) 12,119 2,539 (8,224 )
Net cash provided from operating activities $ 132,412 $ 215,743 $ 681,843 $ 990,690
 
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,
2019 2018 2019 2018
Net cash provided from operating activities, as reported $ 132,412 $ 215,743 $ 681,843 $ 990,690
Net changes in working capital 26,807 (12,119 ) (2,539 ) 8,224
Exploration expense 9,167 10,206 35,128 32,192
Lawsuit settlements 542 13,581 2,577 14,966
Termination costs 4,535 7,535 (373 )
Rig release penalty 1,436
Non-cash compensation adjustment 1,311 815 2,946 2,695
Cash flow from operations before changes in working capital – non-GAAP measure $ 174,774 $ 228,226 $ 728,926 $ 1,048,394
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING
(Unaudited, in thousands)
Three Months Ended December 31, Twelve Months Ended December 31,
  2019 2018 2019 2018
Basic:
Weighted average shares outstanding 251,430 249,515 251,105 249,228
Stock held by deferred compensation plan (3,153 ) (2,884 ) (3,135 ) (3,057 )
Adjusted basic 248,277 246,631 247,970 246,171
Dilutive:
Weighted average shares outstanding 251,430 249,515 251,105 249,228
Dilutive stock options under treasury method (3,153 ) (2,884 ) (3,135 ) (3,057 )
Adjusted dilutive 248,277 246,631 247,970 246,171

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,
2019 2018 % 2019 2018 %
Natural gas, NGL and oil sales components:
Natural gas sales $ 325,515 $ 481,252 $ 1,388,838 $ 1,663,832
NGL sales 173,099 225,566 681,134 931,359
Oil sales 46,824 49,808 185,453 255,885
Total oil and gas sales, as reported $ 545,438 $ 756,626 -28 % $ 2,255,425 $ 2,851,076 -21 %
Derivative fair value income (loss), as reported: $ 18,491 $ 100,698 $ 226,681 $ (51,192 )
Cash settlements on derivative financial instruments – (gain) loss:
Natural gas (46,920 ) 85,757 (139,253 ) 29,291
NGLs (3,233 ) 1,087 (51,068 ) 64,522
Crude Oil 118 4,406 1,937 37,709
Total change in fair value related to derivatives prior to settlement, a non-GAAP measure $ (31,544 ) $ 191,948 $ 38,297 $ 80,330
Transportation, gathering, processing and compression components:
Natural gas $ 185,273 $ 180,920 $ 740,061 $ 678,489
NGLs 114,238 117,796 459,236 439,327
Total transportation, gathering, processing and compression, as reported $ 299,511 $ 298,716 $ 1,199,297 $ 1,117,816
Natural gas, NGL and oil sales, including cash-settled derivatives: (c)
Natural gas sales $ 372,435 $ 395,495 $ 1,528,091 $ 1,634,541
NGL sales 176,332 224,479 732,202 866,837
Oil sales 46,706 45,402 183,516 218,176
Total $ 595,473 $ 665,376 -11 % $ 2,443,809 $ 2,719,554 -10 %
Production of oil and gas during the periods (a):
Natural gas (mcf) 150,708,420 136,315,861 11 % 578,114,351 548,085,437 5 %
NGL (bbl) 9,879,081 9,316,151 6 % 38,850,130 38,325,251 1 %
Oil (bbl) 962,390 913,735 5 % 3,689,805 4,228,429 -13 %
Gas equivalent (mcfe) (b) 215,757,246 197,695,177 9 % 833,353,961 803,407,577 4 %
Production of oil and gas – average per day (a):
Natural gas (mcf) 1,638,135 1,481,694 11 % 1,583,875 1,501,604 5 %
NGL (bbl) 107,381 101,263 6 % 106,439 105,001 1 %
Oil (bbl) 10,461 9,932 5 % 10,109 11,585 -13 %
Gas equivalent (mcfe) (b) 2,345,187 2,148,861 9 % 2,283,162 2,201,117 4 %
Average prices, excluding derivative settlements and before third party transportation costs:
Natural gas (mcf) $ 2.16 $ 3.53 -39 % $ 2.40 $ 3.04 -21 %
NGL (bbl) $ 17.52 $ 24.21 -28 % $ 17.53 $ 24.30 -28 %
Oil (bbl) $ 48.65 $ 54.51 -11 % $ 50.26 $ 60.52 -17 %
Gas equivalent (mcfe) (b) $ 2.53 $ 3.83 -34 % $ 2.71 $ 3.55 -24 %
Average prices, including derivative settlements before third party transportation costs: (c)
Natural gas (mcf) $ 2.47 $ 2.90 -15 % $ 2.64 $ 2.98 -11 %
NGL (bbl) $ 17.85 $ 24.10 -26 % $ 18.85 $ 22.62 -17 %
Oil (bbl) $ 48.53 $ 49.69 -2 % $ 49.74 $ 51.60 -4 %
Gas equivalent (mcfe) (b) $ 2.76 $ 3.37 -18 % $ 2.93 $ 3.39 -13 %
Average prices, including derivative settlements and after third party transportation costs: (d)
Natural gas (mcf) $ 1.24 $ 1.57 -21 % $ 1.36 $ 1.74 -22 %
NGL (bbl) $ 6.29 $ 11.45 -45 % $ 7.03 $ 11.15 -37 %
Oil (bbl) $ 48.53 $ 49.69 -2 % $ 49.74 $ 51.60 -4 %
Gas equivalent (mcfe) (b) $ 1.37 $ 1.85 -26 % $ 1.49 $ 1.99 -25 %
Transportation, gathering and compression expense per mcfe $ 1.39 $ 1.51 -8 % $ 1.44 $ 1.39 3 %

(a)  Represents volumes sold regardless of when produced.
(b)  Oil and NGLs volumes 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 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,
2019 2018 % 2019 2018 %
Loss from operations before income taxes, as reported $ (2,304,179 ) $ (1,833,206 ) -26 % $ (2,216,588 ) $ (1,776,970 ) -25 %
Adjustment for certain special items:
(Gain) loss on sale of assets (407 ) 10,815 30,256 10,666
Loss on ARO settlements 2 59 13 71
Change in fair value related to derivatives prior to settlement 31,544 (191,948 ) (38,297 ) (80,330 )
Rig release penalty 1,436
Goodwill impairment 1,641,197 1,641,197
Abandonment and impairment of unproved properties 1,193,711 441,750 1,235,342 514,994
Gain on early extinguishment of debt (2,430 ) (5,415 )
Impairment of proved property 1,095,634 1,095,634 22,614
Lawsuit settlements 542 13,581 2,577 14,966
Termination costs 4,535 7,535 (373 )
Termination costs – non-cash stock-based compensation 1,946 1,971
Brokered natural gas and marketing – non-cash stock-based compensation 333 451 1,856 1,452
Direct operating – non-cash stock-based compensation 469 442 1,928 2,109
Exploration expenses – non-cash stock-based compensation 194 394 1,566 1,921
General & administrative – non-cash stock-based compensation 7,500 5,474 35,061 43,806
Deferred compensation plan – non-cash adjustment 960 (18,072 ) (15,472 ) (18,631 )
Income before income taxes, as adjusted 30,354 70,937 -57 % 139,403 377,492 -63 %
Income tax expense, as adjusted
Current 2,068 6,147
Deferred (a) 7,589 18,444 34,867 98,061
Net Income excluding certain items, a non-GAAP measure $ 20,698 $ 52,493 -61 % $ 98,389 $ 279,431 -65 %
Non-GAAP income per common share
Basic $ 0.08 $ 0.21 -62 % $ 0.40 $ 1.14 -65 %
Diluted $ 0.08 $ 0.21 -62 % $ 0.40 $ 1.13 -65 %
Non-GAAP diluted shares outstanding, if dilutive 248,889 247,719 249,054 247,220

(a)  Deferred taxes are estimated to be approximately 25% for 2019 and 26% for 2018.

RANGE RESOURCES CORPORATION

RECONCILIATION OF NET INCOME (LOSS), 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,
2019 2018 2019 2018
Net loss, as reported $ (1,805,320 ) $ (1,764,422 ) $ (1,716,297 ) $ (1,746,481 )
Adjustment for certain special items:
(Gain) loss on sale of assets (407 ) 10,815 30,256 10,666
Loss (gain) on ARO settlements 2 59 13 71
Gain on early extinguishment of debt (2,430 ) (5,415 )
Change in fair value related to derivatives prior to settlement 31,544 (191,948 ) (38,297 ) (80,330 )
Goodwill impairment 1,641,197 1,641,197
Impairment of proved property 1,095,634 1,095,634 22,614
Abandonment and impairment of unproved properties 1,193,711 441,750 1,235,342 514,994
Lawsuit settlements 542 13,581 2,577 14,966
Rig release penalty 1,436
Termination costs 4,535 7,535 (373 )
Non-cash stock-based compensation 10,442 6,761 42,382 49,288
Deferred compensation plan 960 (18,072 ) (15,472 ) (18,631 )
Tax impact (508,515 ) (87,228 ) (541,305 ) (128,550 )
Net income excluding certain items, a non-GAAP measure $ 20,698 $ 52,493 $ 98,389 $ 279,431
Net loss per diluted share, as reported $ (7.27 ) $ (7.15 ) $ (6.92 ) $ (7.10 )
Adjustment for certain special items per diluted share:
(Gain) loss on sale of assets 0.00 0.04 0.12 0.04
Loss (gain) on ARO settlements 0.00 0.00 0.00 0.00
Gain on early extinguishment of debt (0.01 ) (0.02 )
Change in fair value related to derivatives prior to settlement 0.13 (0.78 ) (0.15 ) (0.33 )
Goodwill impairment 6.65 6.67
Impairment of proved property 4.41 4.42 0.09
Abandonment and impairment of unproved properties 4.81 1.79 4.98 2.09
Lawsuit settlements 0.00 0.06 0.01 0.06
Termination costs 0.02 0.03 0.00
Non-cash stock-based compensation 0.04 0.03 0.17 0.20
Deferred compensation plan 0.00 (0.07 ) (0.06 ) (0.08 )
Adjustment for rounding differences (0.01 ) 0.01
Tax impact (2.05 ) (0.35 ) (2.18 ) (0.52 )
Net income per diluted share, excluding certain items, a non-GAAP measure $ 0.08 $ 0.21 $ 0.40 $ 1.13
Adjusted earnings per share, a non-GAAP measure:
Basic $ 0.08 $ 0.21 $ 0.40 $ 1.13
Diluted $ 0.08 $ 0.21 $ 0.40 $ 1.13

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,
2019 2018 2019 2018
Revenues
Natural gas, NGL and oil sales, as reported $ 545,438 $ 756,627 $ 2,255,425 $ 2,851,077
Derivative fair value income (loss), as reported 18,491 100,698 226,681 (51,192 )
Less non-cash fair value (gain) loss 31,544 (191,948 ) (38,297 ) (80,330 )
Brokered natural gas and marketing and other, as reported 41,675 215,312 345,509 482,760
Less ARO settlement and other (gains) losses (151 ) (42 ) (1,137 ) (716 )
Cash revenue applicable to production 636,997 880,647 2,788,181 3,201,599
Expenses
Direct operating, as reported 33,792 35,395 136,276 139,531
Less direct operating stock-based compensation (469 ) (442 ) (1,928 ) (2,109 )
Transportation, gathering and compression, as reported 299,511 298,716 1,199,297 1,117,816
Production and ad valorem taxes, as reported 8,963 16,656 37,967 46,149
Brokered natural gas and marketing, as reported 46,532 221,626 359,892 496,047
Less brokered natural gas and marketing stock-based compensation (333 ) (451 ) (1,856 ) (1,452 )
General and administrative, as reported 42,793 50,090 181,109 209,812
Less G&A stock-based compensation (7,500 ) (5,474 ) (35,061 ) (43,806 )
Less lawsuit settlements (542 ) (13,581 ) (2,577 ) (14,966 )
Less rig release penalty (1,436 )
Interest expense, as reported 44,024 49,161 194,285 210,209
Less amortization of deferred financing costs (1,981 ) 1,076 (7,369 ) (4,239 )
Cash expenses 464,790 652,772 2,058,599 2,152,992
 
Cash margin, a non-GAAP measure $ 172,207 $ 227,875 $ 729,582 $ 1,048,607
Mmcfe produced during period 215,757 197,696 833,354 803,408
Cash margin per mcfe $ 0.80 $ 1.15 $ 0.88 $ 1.31
 
 
RECONCILIATION OF INCOME (LOSS) BEFORE INCOME TAXES TO CASH MARGIN
(Unaudited, in thousands, except per unit data)
  Three Months Ended
December 31,
Twelve Months Ended
December 31,
2019 2018 2019 2018
 
Loss before income taxes, as reported $ (2,304,179 ) $ (1,833,206 ) $ (2,216,588 ) $ (1,776,970 )
Adjustments to reconcile income (loss) before income taxes to cash margin:
ARO settlements and other (gains) losses (151 ) (42 ) (1,137 ) (716 )
Derivative fair value (income) loss (18,491 ) (100,698 ) (226,681 ) 51,192
Net cash receipts on derivative settlements 50,035 (91,250 ) 188,384 (131,522 )
Exploration expense 9,156 10,206 35,117 32,196
Lawsuit settlements 542 13,581 2,577 14,966
Rig release penalty 1,436
Termination costs 4,535 7,535 (373 )
Deferred compensation plan 960 (18,072 ) (15,472 ) (18,631 )
Stock-based compensation (direct operating, brokered natural gas and marketing, general and administrative and termination costs) 10,442 6,761 42,382 49,288
Interest – amortization of deferred financing costs 1,981 (1,076 ) 7,369 4,239
Depletion, depreciation and amortization 130,869 147,909 548,843 635,467
(Gain) loss on sale of assets (407 ) 10,815 30,256 10,666
Gain on early extinguishment of debt (2,430 ) (5,415 )
Goodwill impairment 1,641,197 1,641,197
Impairment of proved property and other assets 1,095,634 1,095,634 22,614
Abandonment and impairment of unproved properties 1,193,711 441,750 1,235,342 514,994
Cash margin, a non-GAAP measure $ 172,207 $ 227,875 $ 729,582 $ 1,048,607

RANGE RESOURCES CORPORATION

HEDGING POSITION AS OF DECEMBER 31, 2019 – (Unaudited)  

    Daily Volume   Hedge Price
Gas  1
1Q 2020 Swaps 1,007,253 Mmbtu $2.68
2Q 2020 Swaps 1,021,222 Mmbtu $2.62
3Q 2020 Swaps 1,010,000 Mmbtu $2.62
4Q 2020 Swaps 976,848 Mmbtu $2.63
2021 Swaps 50,000 Mmbtu $2.62
Oil 2
1Q 2020 Swaps 9,000 bbls $58.62
2Q 2020 Swaps 9,000 bbls $58.18
3Q 2020 Swaps 8,500 bbls $58.15
4Q 2020 Swaps 5,500 bbls $58.00
2021 Swaps 1,000 bbls $55.00
C4 Normal Butane
1Q 2020 Swaps 659 bbls $0.73/gallon
C5 Natural Gasoline
1Q 2020 Swaps 4,297 bbls $1.208/gallon

(1)  Range also sold natural gas call swaptions of 140,000 Mmbtu/d for March-December 2020 and 100,000 Mmbtu/d for calendar 2021 at average strike prices of $2.53 per Mmbtu and $2.69 per Mmbtu, respectively.
(2)  Range also sold WTI calls of 500 Bbls/d for April-September 2020 at a strike price of $59 per barrel and sold WTI call swaptions of 3,000 Bbls/d for calendar 2021 at an average strike price of $56.50 per barrel.

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



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