Range Announces Fourth Quarter 2020 Results
02/23/2021 - 04:44 PM
FORT WORTH, Texas, Feb. 23, 2021 (GLOBE NEWSWIRE) -- RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its fourth quarter 2020 financial results, proved reserves and plans for 2021.
Highlights –
All-in 2020 capital spending was $411 million , approximately $109 million less than original budget Fourth quarter cash unit costs improved by $0.07 per mcfe compared to prior year period Company record for lease operating expense of $0.08 per mcfe during the quarter Reduced debt in 2020 by $86 million compared to year-end 2019 All-in 2021 capital budget of $425 million maintains production at ~2.15 Bcfe per day 2021 well costs expected to average $570 per lateral foot, or less, lowest in Appalachia PV-10 of year-end proved reserves of $8.6 billion , or $22 per share net of debt, assuming NYMEX prices of $2.75 per Mmbtu of natural gas and $50 per barrel of oil In January 2021, issued $600 million in 2029 notes extending the Company’s debt maturities and enhancing liquidity to $2.0 billion Updated executive compensation framework to enhance alignment with shareholders and support the Company’s focus on financial strength, environmental leadership, cost improvements, safety and generating sustainable returns for shareholders Commenting on the results and 2021 plans, Jeff Ventura, the Company’s CEO said, “During 2020, Range reduced debt while purchasing over eight million shares, refinanced near-term maturities, lowered well costs, improved our cost structure and delivered our operational plan safely and for less than budgeted. These results reflect the organization’s continuing focus on capital discipline and further strengthening our financial position as we develop the most prolific natural gas and NGL play in North America. Our resilience is further demonstrated by the underlying efficiency of our 2021 capital program that can maintain production at 2.15 Bcfe per day for only $425 million of all-in capital. Further, our corporate sustainability report displays our industry-leading environmental and safety efforts and aggressive emissions targets. Looking forward, I believe Range’s high-quality asset base, capital discipline, operational efficiencies and leading environmental efforts provide a sustainable business generating competitive free cash flow and returns for shareholders.”
2021 Capital Program
Range’s 2021 all-in capital budget is $425 million . The capital budget includes approximately $400 million for drilling and recompletions, and $25 million for leasehold and other investments. The Company expects to turn to sales 59 Marcellus wells in 2021 with an expected average lateral length of approximately 12,000 feet. Approximately 65% of lateral feet turned to sales in 2021 is expected to be in Range’s liquids rich acreage. Range also anticipates keeping in-progress well inventory approximately unchanged going into 2022, allowing for a repeatable and capital efficient program each year.
The table below summarizes expected 2021 activity and 2020 regarding the number of wells to sales in each area.
Planned Wells Wells TIL in TIL in 2021 2020 SW PA Super-Rich 17 3 SW PA Wet 18 31 SW PA Dry 24 33 Total Appalachia 59 67
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.
Capital Expenditures
Fourth quarter 2020 drilling and completions expenditures were $93 million and $15 million was invested in acreage and gathering facilities. Total 2020 capital expenditures were $411 million , including $377 million on drilling and completion, and a combined $34 million on acreage, gas gathering systems and other.
Financial Position
Range reduced outstanding debt by $86 million during 2020, marking the third consecutive year of debt reduction which totals $1.0 billion since the end of 2017. As of December 31, 2020, Range had total debt outstanding of $3.1 billion , consisting of $702 million in bank debt, $2.4 billion in senior notes and $37 million in senior subordinated notes.
During the year, Range repurchased in the open market and retired approximately $161 million in principal amount of its senior and subordinated notes at a weighted average discount to par of 25% . Range also repurchased 8.2 million shares of the Company’s common stock during the year at an average price of $2.80 per share.
In January 2021, Range issued $600.0 million aggregate principal amount of 8.25% senior notes due 2029 and used net proceeds to repay borrowings under its bank credit facility. Proforma the offering, the Company has approximately $2.0 billion of borrowing capacity available under the commitment amount. Range has less than $0.3 billion in notes that mature through 2022, which are expected to be redeemed via free cash flow at strip pricing.
Fourth Quarter 2020 Results
GAAP revenues for fourth quarter 2020 totaled $599 million , GAAP net cash provided from operating activities (including changes in working capital) was $90 million , and GAAP net income was $38 million ($0.15 per diluted share). Fourth quarter earnings results include a $86 million mark-to-market derivative gain due to decreases in commodity prices.
Non-GAAP revenues for fourth quarter 2020 totaled $531 million , and cash flow from operations before changes in working capital, a non-GAAP measure, was $108 million . Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $4 million ($0.02 per diluted share) in fourth quarter 2020.
The following table details Range’s fourth quarter 2020 unit costs per mcfe(a) :
4Q 2020 4Q 2019 Increase Expenses (per mcfe) (per mcfe) (Decrease) Direct operating $ 0.08 $ 0.15 (47% ) Transportation, gathering, processing and compression 1.34 1.39 (4% ) Production and ad valorem taxes 0.02 0.04 (50% ) General and administrative(a) 0.16 0.14 14% Interest expense(a) 0.24 0.19 26% Total cash unit costs(b) 1.84 1.92 (4% ) Depletion, depreciation and amortization (DD&A) 0.47 0.61 (23% ) Total unit costs plus DD&A(b) $ 2.32 $ 2.53 (8% )
(a) Excludes stock-based compensation, legal settlements and amortization of deferred financing costs. (b) May not add due to rounding.
The following table details Range’s average production and realized pricing for fourth quarter 2020:
4Q20 Production & Realized Pricing Natural Gas Natural Gas Oil NGLs Equivalent (Mcf) (Bbl) (Bbl) (Mcfe) Net Production per day 1,464,834 6,356 97,453 2,087,690 Average NYMEX price $ 2.67 $ 42.70 Differential, including basis hedging (0.57 ) (10.91 ) Realized prices before NYMEX hedges 2.10 31.79 $ 18.02 $ 2.41 Settled NYMEX hedges (0.03 ) 14.33 (0.53 ) 0.00 Average realized prices after hedges $ 2.07 $ 46.12 $ 17.49 $ 2.41
Range’s fourth quarter production was approximately 2.1 Bcfe net per day, including the impact of curtailed production during fourth quarter in response to low prices and infrastructure maintenance. The deferred production has benefited from improving prices across all products into mid-December and early 2021. By area, southwest Marcellus production averaged 2.0 Bcfe per day while the northeast Marcellus assets averaged 83 net Mmcf per day during the quarter.
Fourth quarter 2020 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts’ estimates) averaged $2.41 per mcfe.
The average natural gas price, including the impact of basis hedging, was $2.10 per mcf, or a ($0.57) per mcf differential to NYMEX. The fourth quarter natural gas differential was impacted by storage levels in multiple regions as well as a late start to winter weather. Starting in December and into 2021, basis in each region has normalized, improving the Company’s first quarter 2021 natural gas differential to NYMEX within an expected range of ($0.20) t o ($0.25) per mcf. Pre-hedge NGL realizations were $18.02 per barrel, an improvement of $1.75 per barrel versus the previous quarter driven by an improving market for propane and heavier products. NGL prices have improved further in early 2021, as the Mont Belvieu weighted equivalent is currently trading above $25 per barrel in the first quarter. In addition, Range continues to see strong NGL export premiums at Marcus Hook and expects to maintain an average 2021 pre-hedge premium differential of between $0.00 - $2.00 per barrel to Mont Belvieu equivalent, as a result of access to international markets and a diversified portfolio of sales agreements. Crude oil and condensate price realizations, before realized hedges, averaged $31.79 per barrel, or $10.91 b elow WTI (West Texas Intermediate). Range expects an improving condensate differential to WTI during 2021, between $7-$9 b elow NYMEX, as regional production continues to decline and demand for transportation fuels is expected to recover. Transportation and Gathering
Since the end of 2018, Range has reduced transportation and gathering expenses per unit of production by $0.17 per mcfe, from $1.51 t o $1.34 in the fourth quarter of 2020. The two-year improvement has been driven by full utilization of both gathering and firm transport infrastructure. In 2021, Range will have an additional 5,000 barrels per day of Mariner East capacity, which is expected to be fully utilized with existing production. Range continues to expect near-term and long-term benefits of NGL exports out of the Northeast as international demand for NGL products continues to grow. NGL export out of Marcus Hook provides a unique supply option for that demand. In 2021, Range expects to export over 80% of its propane and butane, the highest percentage of propane and butane exported by any U.S. independent, leading to strong year-over-year improvements in NGL pricing and margins. Higher realized NGL prices for Range in 2021 will lead to a slight increase in processing costs as Range’s processing costs are based on the price received, providing a natural hedge against NGL price changes as the expense follows the direction of NGL prices.
Beyond 2021, Range anticipates transportation and gathering expenses to decline in absolute terms assuming continued maintenance of existing production levels. By 2025 Range expects annual gathering expense relative to 2021 to decline by approximately $70 million , and more than $100 million per year by 2030. Importantly, the cost improvements are a result of existing gathering arrangements and do not reflect targeted amounts. Further improvements are also expected beyond 2030 in a production maintenance scenario. Range also has multiple firm transportation agreements with renewal elections during this timeframe and Range will have the option of letting capacity expire depending on market conditions. Transportation renewals relative to 2021 represent an additional $175 million in potential cost improvements by 2030.
2020 Proved Reserves
Year-end 2020 proved reserves were 17.2 Tcfe, essentially unchanged year-over-year after adjusting for asset sales and price revisions. By volume, proved reserves were 65% natural gas, 33% natural gas liquids and 2% crude oil and condensate. Proved developed reserves represent 57% of the Company’s reserves.
Summary of Changes in Proved Reserves (in Bcfe)
Balance at December 31, 2019 18,192 Extensions, discoveries and additions 1,264 Performance revisions 420 Reclassification of PUD to unproved under SEC 5-year rule (961 ) Price revisions (68 ) Sales of proved reserves (828 ) Production (816 ) Balance at December 31, 2020 17,203
During 2020, Range added 1.3 Tcfe of proved reserves through the drill-bit, driven by the Marcellus shale development. Field level performance increased reserves by 312 Bcfe due to continued improvement in the well performance of existing Marcellus producing wells and 109 Bcfe of reserves associated with proved undeveloped locations which have re-entered the Company’s five-year drilling program. Range removed 961 Bcfe of proved undeveloped reserves that now fall outside the SEC mandated five-year development window, but the Company expects these proved undeveloped reserves to be added back in future years. The Company sold approximately 828 Bcfe of reserves during the year, associated with the North Louisiana asset. As shown in the table below the present value (PV10 ) of reserves under SEC methodology was $3.1 billion at December 31, 2020. The valuation was impacted by lower first-of-month pricing required under SEC methodology. For comparison, the PV10 using NYMEX reference prices of $2.75 per Mmbtu for natural gas and $50 per barrel of oil would have been $8.6 billion , assuming the same proven reserve volumes.
2020 SEC Flat Price Pricing (a) Example (b) Natural Gas Price ($/Mmbtu) $1.98 $2.75 WTI Oil Price ($/Bbl) $39.77 $50.00 NGL Price ($/Bbl) $16.14 $20.55 Proved Reserves PV10 ($ billions) $3.0 $8.6
(a) SEC benchmark prices adjusted for energy content, quality and basis differentials were $1.68 per mcf and $30.13 per barrel of crude oil (b) Example NYMEX prices adjusted for energy content, quality and basis differentials were $2.53 per mcf and $43.00 per barrel of crude oil
Year-end 2020 reserves included 7.4 Tcfe of proved undeveloped reserves from 361 wells planned to be developed within the next five years with an expected development cost of $0.32 per Mcfe. Beyond the five-year reserve calculation window, Range has approximately 2,700 additional Marcellus locations available for development in Southwest Pennsylvania. Range also has a network of over 200 existing well pads designed to accommodate an average of 20 wells per pad from any combination of Marcellus, Utica or Upper Devonian horizons. On average, existing pads currently contain six producing wells, providing Range the opportunity to develop thousands of future wells while utilizing existing roads, pads and infrastructure. In 2021, over 60% of the wells planned to turn to sales are from pad sites with existing production, similar to recent years.
The table below reflects Range’s estimate of the remaining core drilling inventory for the Marcellus.
Estimated Future Marcellus Drilling Locations - December 31, 2020 Excludes Utica and Upper Devonian locations)
Assumed Producing Undrilled Area Net Acres Lateral Length Locations (1) Locations (2) SW Marcellus - Liquids areas ~350,000 10,000 ft. 480 2,600 SW Marcellus – Dry area ~110,000 10,000 ft. 220 500 Total ~460,000 700 ~3,100
(1) Producing locations adjusted to 10,000 foot equivalent (2) Includes anticipated down-spacing activity
Guidance – 2021
Capital & Production Guidance
Range’s 2021 all-in capital budget is $425 million . Production for full-year 2021 is expected to average approximately 2.15 Bcfe per day, with ~30% attributed to liquids production.
Direct operating expense: $0.09 - $0.11 per mcfe Transportation, gathering, processing and compression expense: $1.35 - $1.40 per mcfe Production tax expense: $0.02 - $0.04 per mcfe Exploration expense: $24.0 - $30.0 million G&A expense: $0.15 - $0.16 per mcfe Interest expense: $0.26 - $0.28 per mcfe DD&A expense: $0.47 - $0.50 per mcfe Net brokered gas marketing expense: $10.0 - $16.0 million
Full Year 2021 Price Guidance
Based on current market indications, Range expects to average the following price differentials for its production in 2021.
Natural Gas:(1) NYMEX minus $0.30 t o $0.40 Natural Gas Liquids (including ethane):(2) Mont Belvieu plus $0.00 t o $2.00 per barrel Oil/Condensate: WTI minus $7.00 t o $9.00
(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. As of January 31st , Range had approximately 70% of its expected 2021 natural gas production hedged at an average ceiling price of $2.79 per Mmbtu and an average floor price of $2.60 per Mmbtu. Similarly, Range hedged approximately 50% of projected 2021 crude oil production at an average floor price of $46.84 per barrel and approximately 20% of its expected 2021 NGL revenue. Please see the detailed hedging schedule posted on the Range website under Investor Relations - Financial Information.
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 basis, NGL freight and spread hedges as of December 31, 2020 was a net gain of $5.6 million .
Conference Call Information
A conference call to review the financial results is scheduled on Wednesday, February 24 at 9:00 a.m. ET. To participate in the call, please dial (877) 928-8777 and provide conference code 1058978 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 24.
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 and NGL producer with operations focused on stacked-pay projects in the Appalachian Basin. The Company is headquartered in Fort Worth, Texas. More 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 Relationslsando@rangeresources.com
Range Media Contacts:
Mark Windle, Director of Corporate Communicationsmwindle@rangeresources.com
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, 2020 2019 % 2020 2019 % Revenues and other income: Natural gas, NGLs and oil sales (a) $ 444,806 $ 545,438 $ 1,607,713 $ 2,255,425 Derivative fair value income 85,529 18,491 187,711 226,681 Brokered natural gas, marketing and other (b) 67,771 41,524 171,622 344,372 ARO settlement loss (b) (4 ) (2 ) (22 ) (13 ) Other (b) 784 153 1,673 1,150 Total revenues and other income 598,886 605,604 -1 % 1,968,697 2,827,615 -30 % Costs and expenses: Direct operating 15,945 33,323 91,079 134,348 Direct operating – non-cash stock-based compensation (c) 268 469 1,078 1,928 Transportation, gathering, processing and compression 256,742 299,511 1,088,490 1,199,297 Production and ad valorem taxes 3,935 8,963 24,617 37,967 Brokered natural gas and marketing 69,053 46,199 186,900 358,036 Brokered natural gas and marketing – non-cash stock-based compensation (c) 511 333 1,416 1,856 Exploration 9,076 9,156 31,375 35,117 Exploration – non-cash stock-based compensation (c) 388 194 1,279 1,566 Abandonment and impairment of unproved properties 2,730 1,193,711 19,334 1,235,342 General and administrative 31,307 30,269 123,859 137,694 General and administrative – non-cash stock-based compensation (c) 8,834 7,500 32,905 35,061 General and administrative – lawsuit settlements 579 542 2,251 2,577 General and administrative – rig release penalty — — — 1,436 General and administrative – bad debt expense — 4,482 400 4,341 Exit and termination costs 13,739 4,535 545,244 7,535 Exit and termination costs – non-cash stock-based compensation (c) 145 1,946 2,165 1,971 Deferred compensation plan (d) 2,254 960 12,541 (15,472 ) Interest expense 46,389 42,043 184,201 186,916 Interest expense – amortization of deferred financing costs (e) 2,137 1,981 8,466 7,369 Gain on early extinguishment of debt 25 (2,430 ) (14,068 ) (5,415 ) Depletion, depreciation and amortization 90,551 130,869 394,330 548,843 Impairment of proved property and other assets — 1,095,634 78,955 1,095,634 Loss (gain) on sale of assets 1,652 (407 ) (110,791 ) 30,256 Total costs and expenses 556,260 2,909,783 -81 % 2,706,026 5,044,203 -46 % Income (loss) before income taxes 42,626 (2,304,179 ) 102 % (737,329 ) (2,216,588 ) 67 % Income tax (benefit) expense: Current (157 ) 2,068 (523 ) 6,147 Deferred 4,382 (500,927 ) (25,029 ) (506,438 ) 4,225 (498,859 ) (25,552 ) (500,291 ) Net income (loss) $ 38,401 $ (1,805,320 ) 102 % $ (711,777 ) $ (1,716,297 ) 59 % Net Income (Loss) Per Common Share: Basic $ 0.16 $ (7.27 ) $ (2.95 ) $ (6.92 ) Diluted $ 0.15 $ (7.27 ) $ (2.95 ) $ (6.92 ) Weighted average common shares outstanding, as reported: Basic 240,174 248,277 -3 % 241,373 247,970 -3 % Diluted 246,286 248,277 -1 % 241,373 247,970 -3 %
(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, 2020 2019 (Audited) (Audited) Assets Current assets $ 266,508 $ 290,954 Derivative assets 40,012 137,554 Natural gas and oil properties, successful efforts method 5,686,809 6,041,035 Transportation and field assets 4,161 5,375 Operating lease right-of-use assets 63,581 62,053 Other 75,865 75,432 $ 6,136,936 $ 6,612,403 Liabilities and Stockholders’ Equity Current liabilities $ 673,445 $ 551,032 Asset retirement obligations 6,689 2,393 Derivative liabilities 26,707 13,119 Bank debt 693,123 464,319 Senior notes 2,329,745 2,659,844 Senior subordinated notes 17,384 48,774 Total debt 3,040,252 3,172,937 Deferred tax liability 135,267 160,196 Derivative liabilities 9,746 949 Deferred compensation liability 81,481 64,070 Operating lease liabilities 43,155 41,068 Asset retirement obligations and other liabilities 91,157 259,151 Divestiture contract obligation 391,502 — Common stock and retained deficit 1,668,146 2,355,512 Other comprehensive loss (479 ) (788 ) Common stock held in treasury stock (30,132 ) (7,236 ) Total stockholders’ equity 1,637,535 2,347,488 $ 6,136,936 $ 6,612,403
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, 2020 2019 % 2020 2019 % Total revenues and other income, as reported $ 598,886 $ 605,604 -1 % $ 1,968,697 $ 2,827,615 -30 % Adjustment for certain special items: Total change in fair value related to derivatives prior to settlement (gain) loss (68,143 ) 31,544 134,918 (38,297 ) ARO settlement (gain) loss 4 2 22 13 Total revenues, as adjusted, non-GAAP $ 530,747 $ 637,150 -17 % $ 2,103,637 $ 2,789,331 -25 %
CASH FLOWS FROM OPERATING ACTIVITIES (Unaudited in thousands) Three Months Ended December 31, Twelve Months Ended December 31, 2020 2019 2020 2019 Net income (loss) $ 38,401 $ (1,805,320 ) $ (711,777 ) $ (1,716,297 ) Adjustments to reconcile net cash provided from continuing operations: Deferred income tax benefit 4,382 (500,927 ) (25,029 ) (506,438 ) Depletion, depreciation, amortization and impairment 90,551 1,226,503 473,285 1,644,477 Exploration dry hole and impairment costs 888 (11 ) 888 (11 ) Abandonment and impairment of unproved properties 2,730 1,193,711 19,334 1,235,342 Derivative fair value loss (income) (85,529 ) (18,491 ) (187,711 ) (226,681 ) Cash settlements on derivative financial instruments 17,386 50,035 322,629 188,384 Divestiture contract obligation 13,245 — 499,934 — Allowance for bad debts — 4,482 400 4,341 Amortization of deferred issuance costs and other 1,896 1,593 6,919 6,455 Deferred and stock-based compensation 10,172 10,481 48,552 24,891 Loss (gain) on sale of assets and other 1,652 (407 ) (110,791 ) 30,256 Loss (gain) on early extinguishment of debt 25 (2,430 ) (14,068 ) (5,415 ) Changes in working capital: Accounts receivable (66,804 ) (27,318 ) 24,539 214,196 Inventory and other 6,796 8,544 1,010 4,520 Accounts payable 20,134 (7,729 ) (32,686 ) (60,374 ) Accrued liabilities and other 33,781 (304 ) (46,748 ) (155,803 ) Net changes in working capital (6,093 ) (26,807 ) (53,885 ) 2,539 Net cash provided from operating activities $ 89,706 $ 132,412 $ 268,680 $ 681,843 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, 2020 2019 2020 2019 Net cash provided from operating activities, as reported $ 89,706 $ 132,412 $ 268,680 $ 681,843 Net changes in working capital 6,093 26,807 53,885 (2,539 ) Exploration expense 8,188 9,167 30,487 35,128 Lawsuit settlements 579 542 2,251 2,577 Exit and termination costs – severance costs only 271 4,535 5,908 7,535 Accrued transportation contract release including accretion 222 — 10,900 — One-time midstream termination payment — — 28,500 — Rig release penalty — — — 1,436 Non-cash compensation adjustment 2,474 1,311 4,403 2,946 Cash flow from operations before changes in working capital – non-GAAP measure $ 107,533 $ 174,774 $ 405,014 $ 728,926 ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING (Unaudited, in thousands) Three Months Ended December 31, Twelve Months Ended December 31, 2020 2019 2020 2019 Basic: Weighted average shares outstanding 246,320 251,430 247,050 251,105 Stock held by deferred compensation plan (6,146 ) (3,153 ) (5,677 ) (3,135 ) Adjusted basic 240,174 248,277 241,373 247,970 Dilutive: Weighted average shares outstanding 246,320 251,430 247,050 251,105 Dilutive stock options under treasury method (34 ) (3,153 ) (5,677 ) (3,135 ) Adjusted dilutive 246,286 248,277 241,373 247,970
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, 2020 2019 % 2020 2019 % Natural gas, NGL and oil sales components: Natural gas sales $ 264,646 $ 325,515 $ 943,740 $ 1,388,838 NGL sales 161,569 173,099 578,454 681,134 Oil sales 18,591 46,824 85,519 185,453 Total oil and gas sales, as reported $ 444,806 $ 545,438 -18 % $ 1,607,713 $ 2,255,425 -29 % Derivative fair value income (loss), as reported: $ 85,529 $ 18,491 $ 187,711 $ 226,681 Cash settlements on derivative financial instruments – (gain) loss: Natural gas (13,753 ) (46,920 ) (258,797 ) (139,253 ) NGLs 4,745 (3,233 ) (11,288 ) (51,068 ) Crude Oil (8,378 ) 118 (52,544 ) 1,937 Total change in fair value related to derivatives prior to settlement, a non-GAAP measure $ 68,143 $ (31,544 ) $ (134,918 ) $ 38,297 Transportation, gathering, processing and compression components: Natural gas $ 155,766 $ 185,273 $ 650,071 $ 740,061 NGLs 100,983 114,238 437,474 459,236 Oil (7 ) — 945 — Total transportation, gathering, processing and compression, as reported $ 256,742 $ 299,511 $ 1,088,490 $ 1,199,297 Natural gas, NGL and oil sales, including cash-settled derivatives: (c) Natural gas sales $ 278,399 $ 372,435 $ 1,202,537 $ 1,528,091 NGL sales 156,824 176,332 589,742 732,202 Oil sales 26,969 46,706 138,063 183,516 Total $ 462,192 $ 595,473 -22 % $ 1,930,342 $ 2,443,809 -21 % Production of oil and gas during the periods (a): Natural gas (mcf) 134,764,765 150,708,420 -11 % 574,529,290 578,114,351 -1 % NGL (bbl) 8,965,697 9,879,081 -9 % 37,491,546 38,850,130 -3 % Oil (bbl) 584,754 962,390 -39 % 2,829,495 3,689,805 -23 % Gas equivalent (mcfe) (b) 192,067,471 215,757,246 -11 % 816,455,536 833,353,961 -2 % Production of oil and gas – average per day (a): Natural gas (mcf) 1,464,834 1,638,135 -11 % 1,569,752 1,583,875 -1 % NGL (bbl) 97,453 107,381 -9 % 102,436 106,439 -4 % Oil (bbl) 6,356 10,461 -39 % 7,731 10,109 -24 % Gas equivalent (mcfe) (b) 2,087,690 2,345,187 -11 % 2,230,753 2,283,162 -2 % Average prices, excluding derivative settlements and before third party transportation costs: Natural gas (mcf) $ 1.96 $ 2.16 -9 % $ 1.64 $ 2.40 -32 % NGL (bbl) $ 18.02 $ 17.52 3 % $ 15.43 $ 17.53 -12 % Oil (bbl) $ 31.79 $ 48.65 -35 % $ 30.22 $ 50.26 -40 % Gas equivalent (mcfe) (b) $ 2.32 $ 2.53 -8 % $ 1.97 $ 2.71 -27 % Average prices, including derivative settlements before third party transportation costs: (c) Natural gas (mcf) $ 2.07 $ 2.47 -16 % $ 2.09 $ 2.64 -21 % NGL (bbl) $ 17.49 $ 17.85 -2 % $ 15.73 $ 18.85 -17 % Oil (bbl) $ 46.12 $ 48.53 -5 % $ 48.79 $ 49.74 -2 % Gas equivalent (mcfe) (b) $ 2.41 $ 2.76 -13 % $ 2.36 $ 2.93 -19 % Average prices, including derivative settlements and after third party transportation costs: (d) Natural gas (mcf) $ 0.91 $ 1.24 -27 % $ 0.96 $ 1.36 -29 % NGL (bbl) $ 6.23 $ 6.29 -1 % $ 4.06 $ 7.03 -42 % Oil (bbl) $ 46.13 $ 48.53 -5 % $ 48.46 $ 49.74 -3 % Gas equivalent (mcfe) (b) $ 1.07 $ 1.37 -22 % $ 1.03 $ 1.49 -31 % Transportation, gathering and compression expense per mcfe $ 1.34 $ 1.39 -4 % $ 1.33 $ 1.44 -7 %
(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.
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, 2020 2019 % 2020 2019 % Income (loss) from operations before income taxes, as reported $ 42,626 $ (2,304,179 ) 102 % $ (737,329 ) $ (2,216,588 ) 67 % Adjustment for certain special items: Loss (gain) on sale of assets 1,652 (407 ) (110,791 ) 30,256 Loss on ARO settlements 4 2 22 13 Change in fair value related to derivatives prior to settlement (68,143 ) 31,544 134,918 (38,297 ) Abandonment and impairment of unproved properties 2,730 1,193,711 19,334 1,235,342 Rig release penalty — — — 1,436 Loss (gain) on early extinguishment of debt 25 (2,430 ) (14,068 ) (5,415 ) Impairment of proved property and other assets — 1,095,634 78,955 1,095,634 Lawsuit settlements 579 542 2,251 2,577 Exit and termination costs 13,739 4,535 545,244 7,535 Exit and termination costs – non-cash stock-based compensation 145 1,946 2,165 1,971 Brokered natural gas and marketing – non-cash stock-based 511 333 1,416 1,856 Direct operating – non-cash stock-based compensation 268 469 1,078 1,928 Exploration expenses – non-cash stock-based compensation 388 194 1,279 1,566 General & administrative – non-cash stock-based compensation 8,834 7,500 32,905 35,061 Deferred compensation plan – non-cash adjustment 2,254 960 12,541 (15,472 ) Income (loss) before income taxes, as adjusted 5,612 30,354 -82 % (30,080 ) 139,403 -122 % Income tax expense (benefit), as adjusted Current (157 ) 2,068 (523 ) 6,147 Deferred (a) 1,403 7,588 (7,520 ) 34,867 Net income (loss) excluding certain items, a non-GAAP measure $ 4,366 $ 20,698 -79 % $ (22,037 ) $ 98,389 -122 % Non-GAAP income (loss) per common share Basic $ 0.02 $ 0.08 -75 % $ (0.09 ) $ 0.40 -123 % Diluted $ 0.02 $ 0.08 -75 % $ (0.09 ) $ 0.40 -123 % Non-GAAP diluted shares outstanding, if dilutive 246,286 248,889 241,373 249,054
(a) Deferred taxes are estimated to be approximately 25% for 2020 and 2019.
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 Twelve Months Ended 2020 2019 2020 2019 Net income (loss), as reported $ 38,401 $ (1,805,320 ) $ (711,777 ) $ (1,716,297 ) Adjustment for certain special items: Loss (gain) on sale of assets 1,652 (407 ) (110,791 ) 30,256 Loss (gain) on ARO settlements 4 2 22 13 Gain on early extinguishment of debt 25 (2,430 ) (14,068 ) (5,415 ) Change in fair value related to derivatives prior to settlement (68,143 ) 31,544 134,918 (38,297 ) Impairment of proved property — 1,095,634 78,955 1,095,634 Abandonment and impairment of unproved properties 2,730 1,193,711 19,334 1,235,342 Lawsuit settlements 579 542 2,251 2,577 Rig release penalty — — — 1,436 Exit and termination costs 13,739 4,535 545,244 7,535 Non-cash stock-based compensation 10,146 10,442 38,843 42,382 Deferred compensation plan 2,254 960 12,541 (15,472 ) Tax impact 2,979 (508,515 ) (17,509 ) (541,305 ) Net income (loss) excluding certain items, a non-GAAP measure $ 4,366 $ 20,698 $ (22,037 ) $ 98,389 Net income (loss) per diluted share, as reported $ 0.15 $ (7.27 ) $ (2.95 ) $ (6.92 ) Adjustment for certain special items per diluted share: Loss (gain) on sale of assets 0.01 (0.00 ) (0.46 ) 0.12 Loss (gain) on ARO settlements 0.00 0.00 0.00 0.00 Loss (gain) on early extinguishment of debt 0.00 (0.01 ) (0.06 ) (0.02 ) Change in fair value related to derivatives prior to settlement (0.28 ) 0.13 0.56 (0.15 ) Impairment of proved property and other assets — 4.41 0.33 4.42 Abandonment and impairment of unproved properties 0.01 4.81 0.08 4.98 Lawsuit settlements 0.00 0.00 0.01 0.01 Rig release penalty — — — 0.01 Exit and termination costs 0.06 0.02 2.26 0.03 Non-cash stock-based compensation 0.04 0.04 0.16 0.17 Deferred compensation plan 0.01 0.00 0.05 (0.06 ) Adjustment for rounding differences 0.01 — — (0.01 ) Tax impact 0.01 (2.05 ) (0.07 ) (2.18 ) Net income (loss) per diluted share, excluding certain items, a non- GAAP measure $ 0.02 $ 0.08 $ (0.09 ) $ 0.40 Adjusted earnings per share, a non-GAAP measure: Basic $ 0.02 $ 0.08 $ (0.09 ) $ 0.40 Diluted $ 0.02 $ 0.08 $ (0.09 ) $ 0.40
RECONCILIATION OF CASH MARGIN PER MCFE, a non- GAAP measure (Unaudited, in thousands, except per unit data) Three Months Ended Twelve Months Ended 2020 2019 2020 2019 Revenues Natural gas, NGL and oil sales, as reported $ 444,806 $ 545,438 $ 1,607,713 $ 2,255,425 Derivative fair value income, as reported 85,529 18,491 187,711 226,681 Less non-cash fair value (gain) loss (68,143 ) 31,544 134,918 (38,297 ) Brokered natural gas and marketing and other, as reported 68,551 41,675 173,273 345,509 Less ARO settlement and other (gains) losses (780 ) (151 ) (1,651 ) (1,137 ) Cash revenue applicable to production 529,963 636,997 2,101,964 2,788,181 Expenses Direct operating, as reported 16,213 33,792 92,157 136,276 Less direct operating stock-based compensation (268 ) (469 ) (1,078 ) (1,928 ) Transportation, gathering and compression, as reported 256,742 299,511 1,088,490 1,199,297 Production and ad valorem taxes, as reported 3,935 8,963 24,617 37,967 Brokered natural gas and marketing, as reported 69,564 46,532 188,316 359,892 Less brokered natural gas and marketing stock-based compensation (511 ) (333 ) (1,416 ) (1,856 ) General and administrative, as reported 40,720 42,793 159,415 181,109 Less G&A stock-based compensation (8,834 ) (7,500 ) (32,905 ) (35,061 ) Less lawsuit settlements (579 ) (542 ) (2,251 ) (2,577 ) Less rig release penalty — — — (1,436 ) Interest expense, as reported 48,526 44,024 192,667 194,285 Less amortization of deferred financing costs (2,137 ) (1,981 ) (8,466 ) (7,369 ) Cash expenses 423,371 464,790 1,699,546 2,058,599 Cash margin, a non-GAAP measure $ 106,592 $ 172,207 $ 402,418 $ 729,582 Mmcfe produced during period 192,067 215,757 816,456 833,354 Cash margin per mcfe $ 0.55 $ 0.80 $ 0.49 $ 0.88 RECONCILIATION OF INCOME (LOSS) BEFORE INCOME TAXES TO CASH MARGIN (Unaudited, in thousands, except per unit data) Three Months Ended Twelve Months Ended 2020 2019 2020 2019 Income (loss) before income taxes, as reported $ 42,626 $ (2,304,179 ) $ (737,329 ) $ (2,216,588 ) Adjustments to reconcile income (loss) before income taxes to cash margin: ARO settlements and other gains (780 ) (151 ) (1,651 ) (1,137 ) Derivative fair value (income) (85,529 ) (18,491 ) (187,711 ) (226,681 ) Net cash receipts on derivative settlements 17,386 50,035 322,629 188,384 Exploration expense 9,076 9,156 31,375 35,117 Lawsuit settlements 579 542 2,251 2,577 Rig release penalty — — — 1,436 Exit and termination costs 13,739 4,535 545,244 7,535 Deferred compensation plan 2,254 960 12,541 (15,472 ) Stock-based compensation (direct operating, brokered natural gas 10,146 10,442 38,843 42,382 Interest – amortization of deferred financing costs 2,137 1,981 8,466 7,369 Depletion, depreciation and amortization 90,551 130,869 394,330 548,843 Loss (gain) loss on sale of assets 1,652 (407 ) (110,791 ) 30,256 Loss (gain) on early extinguishment of debt 25 (2,430 ) (14,068 ) (5,415 ) Impairment of proved property and other assets — 1,095,634 78,955 1,095,634 Abandonment and impairment of unproved properties 2,730 1,193,711 19,334 1,235,342 Cash margin, a non-GAAP measure $ 106,592 $ 172,207 $ 402,418 $ 729,582
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