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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM 10-K

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Commission File No. 001-36120

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ANTERO RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)

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(303) 357-7310

(Registrant’s telephone number, including area code)

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Securities Registered Pursuant to Section 12(g) of the Act: None.

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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ◻ Yes ⌧ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ◻ Yes ⌧ No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ⌧ Yes ◻ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ⌧ Yes ◻ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b 2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ⌧ No

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ⌧

The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 30, 2020, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $584 million based on the $2.54 per share closing price of Antero Resources Corporation’s common stock as reported on that day on the New York Stock Exchange.

The registrant had 301,189,530 shares of common stock outstanding as of February 12, 2021.

Documents incorporated by reference: Portions of the registrant’s proxy statement for its annual meeting of stockholders to be filed pursuant to Regulation 14A within 120 days after the registrant’s fiscal year end are incorporated by reference into Part III of this Annual Report on Form 10-K.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Some of the information in this Annual Report on Form 10-K may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  All statements, other than statements of historical fact included in this Annual Report on Form 10-K, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward looking statements.  Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words.  When considering these forward-looking statements, investors should keep in mind the risk factors and other cautionary statements in this Annual Report on Form 10-K.  These forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

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We caution investors that these forward-looking statements are subject to all of the risks and uncertainties incidental to our business, most of which are difficult to predict and many of which are beyond our control.  These risks include, but are not limited to, commodity price volatility, inflation, availability of drilling, completion and production equipment and services, environmental risks, drilling and completion and other operating risks, marketing and transportation risks, regulatory changes, the uncertainty inherent in estimating natural gas, NGLs, and oil reserves and in projecting future rates of production, cash flows and access to capital, the timing of development expenditures, conflicts of interest among our stockholders, impacts of world health events, including the COVID-19 pandemic and the other risks described under the heading “Item 1A. Risk Factors” in this Annual Report on Form 10-K.

Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs, and oil that cannot be measured in an exact manner.  The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data, and the price and cost assumptions made by reservoir engineers.  In addition, the results of drilling, testing, and production activities, or changes in commodity prices, may justify revisions of estimates that were made previously.  If significant, such revisions would change the schedule of any further production and development drilling.  Accordingly, reserve estimates may differ significantly from the quantities of natural gas, NGLs, and oil that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Annual Report on Form 10-K are expressly qualified in their entirety by this cautionary statement.  This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements to reflect events or circumstances after the date of this Annual Report on Form 10-K.

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SUMMARY RISK FACTORS

Commodity Prices

Reserves

Business Operations

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Customer Concentration and Credit Risk

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Vendor Risks

Acquisitions, Divestitures and Takeovers

Capital Structure and Access to Capital

Compliance with Regulations

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GLOSSARY OF COMMONLY USED TERMS

The following are abbreviations and definitions of certain terms used in this document, some of which are commonly used in the oil and gas industry:

“ASC.” Accounting Standards Codification.

“ASU.” Accounting Standards Update.

“Basin.” A large natural depression on the earth’s surface in which sediments, generally brought by water, accumulate.

“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate, NGLs, or water.

“Bbl/d.” Bbl per day.

“Bcf.” One billion cubic feet of natural gas.

“Bcfe.” One billion cubic feet of natural gas equivalent with one barrel of oil, condensate, or NGLs converted to six thousand cubic feet of natural gas.

“Btu.” British thermal unit.

“C3+ NGLs.” Natural gas liquids excluding ethane, consisting primarily of propane, isobutane, normal butane and natural gasoline.

“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“DD&A.” Depletion, depreciation, and amortization.

“Delineation.” The process of placing a number of wells in various parts of a reservoir to determine its boundaries and production characteristics.

“Developed acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.

“Development well.” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“EPA.” United States Environmental Protection Agency.

“Exploratory well.” A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir, or to extend a known reservoir.

“FASB.” Financial Accounting Standards Board.

“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation.” A layer of rock which has distinct characteristics that differs from nearby rock.

“Gross acres or gross wells.” The total acres or wells, as the case may be, in which a working interest is owned.

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“Horizontal drilling.” A drilling technique where a well is drilled vertically to a certain depth and then drilled along a horizontal path oriented at approximately 85 to 95 degrees from a vertical direction within a specified interval.

“Joint Venture.” The joint venture entered into on February 6, 2017 between Antero Midstream Partners LP, a wholly owned subsidiary of Antero Midstream and MarkWest Energy Partners, L.P. (“MarkWest”), a wholly owned subsidiary of MPLX, LP (“MPLX”), to develop processing and fractionation assets in Appalachia.

“Liquids-rich.” Natural gas with a heating value of at least 1,100 Btu per Mcf.

“LPG.” Liquefied petroleum gas consisting of propane and butane.

“MBbl.” One thousand barrels of crude oil, condensate or NGLs.

“Mcf.” One thousand cubic feet of natural gas.

“Mcfe.” One thousand cubic feet of natural gas equivalent, with liquids converted to an equivalent volume of natural gas using the ratio of one barrel of oil to six Mcf of natural gas.

“MMBbl.” One million barrels of crude oil, condensate or NGLs.

“MMBtu.” One million British thermal units.

“MMBtu/d.” MMBtu per day.

“MMcf.” One million cubic feet of natural gas.

“MMcf/d.” MMcf per day.

“MMcfe.” One million cubic feet of natural gas equivalent with one barrel of oil, condensate or NGLs converted to six thousand cubic feet of natural gas.

“MMcfe/d.” MMcfe per day.

“Net acres.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% working interest in 100 acres owns 50 net acres.

“Net well.” The percentage ownership interest in a well that an owner has based on the working interest. An owner who has a 50% working interest in a well has a 0.50 net well.

“NGLs.” Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as purity products such as ethane, propane, isobutane and normal butane, and natural gasoline.

“NYMEX.” The New York Mercantile Exchange.

“Potential well locations.” Total gross locations that we may be able to drill on our existing acreage. Actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas, NGLs, and oil prices, costs, drilling results, and other factors.

“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Prospect.” A specific geographic area which, based on supporting geological, geophysical, or other data, and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

“Proved developed reserves.” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

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“Proved reserves.” The estimated quantities of natural gas, NGLs, and oil that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

“Proved undeveloped reserves” or “PUD.” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

“PV-10.” When used with respect to oil and gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production, future development and abandonment costs, using average yearly prices computed using Securities and Exchange Commission (“SEC”) rules, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV-10 is not a financial measure calculated in accordance with generally accepted accounting principles (“GAAP”) and generally differs from Standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized measure represents an estimate of the fair market value of our natural gas and oil properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, or distance between two horizontal well legs, and is often established by regulatory agencies.

“Standardized measure.” Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the natural gas and oil properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

“Strip prices.” The daily settlement prices of commodity futures contracts, such as those for natural gas, NGLs, and oil. Strip prices represent the prices at which a given commodity can be sold at specified future dates, which may not represent actual market prices available upon such date in the future.

“Tcf.” One trillion cubic feet of natural gas.

“Tcfe.” One trillion cubic feet of natural gas equivalent with one barrel of oil, condensate, or NGLs converted to six thousand cubic feet of natural gas.

“Undeveloped acreage.” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas, NGLs, and oil regardless of whether such acreage contains proved reserves.

“Working interest.” The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

“WTI.” West Texas Intermediate light sweet crude oil.

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PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

Our Company and Organizational Structure

Antero Resources Corporation (individually referred to as “Antero”) and its consolidated subsidiaries (collectively referred to as “Antero Resources,” the “Company,” “we,” “us” or “our”) are engaged in the development, production, exploration and acquisition of natural gas, NGLs, and oil properties located in the Appalachian Basin. The Company targets large, repeatable resource plays where horizontal drilling and advanced fracture stimulation technologies provide the means to economically develop and produce natural gas, NGLs, and oil from unconventional formations. As of December 31, 2020, we held approximately 515,000 net acres of natural gas, NGLs, and oil properties located in the Appalachian Basin primarily in West Virginia and Ohio. Our corporate headquarters are in Denver, Colorado.

Ownership in Antero Midstream

We formed Antero Midstream Partners LP (“Antero Midstream Partners”) to own, operate and develop midstream energy assets that service our production. Antero Midstream Partners’ assets consist of gathering systems and compression facilities, water handling and treatment facilities, and interests in processing and fractionation plants, through which it provides services to us under long-term, fixed-fee contracts.

On March 12, 2019, pursuant to the Simplification Agreement, dated as of October 9, 2018, by and among Antero Midstream GP LP (“AMGP”), Antero Midstream Partners and certain of their affiliates (the “Simplification Agreement”) (i) AMGP was converted from a limited partnership to a corporation under the laws of the State of Delaware and changed its name to Antero Midstream Corporation (together with its consolidated subsidiaries, as appropriate, “Antero Midstream”), and (ii) an indirect, wholly owned subsidiary of Antero Midstream was merged with and into Antero Midstream Partners, with Antero Midstream Partners surviving the merger as an indirect, wholly owned subsidiary of Antero Midstream (together, along with the other transactions contemplated by the Simplification Agreement, the “Transactions”). In connection with the Transactions, we received $297 million in cash and 158.4 million shares of Antero Midstream’s common stock in exchange for our 98,870,335 common units representing limited partner interests in Antero Midstream Partners owned immediately prior to the Transactions.

As a result of the Transactions, we no longer hold a controlling interest in Antero Midstream Partners and now have an interest in Antero Midstream that provides significant influence, but not control, over Antero Midstream. Thus, effective March 13, 2019, we no longer consolidate Antero Midstream Partners in our consolidated financial statements and account for our interest in Antero Midstream using the equity method of accounting. See Note 3—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements for more information on the Transactions.

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As of December 31, 2020, we owned 29.2% of Antero Midstream’s common stock.

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General

The following table provides a summary of selected data for our Appalachian Basin natural gas, NGLs, and oil assets as of the date and for the period indicated.

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For the year ended December 31, 2020, our total consolidated capital expenditures were approximately $785 million, including drilling and completion expenditures of $735 million, leasehold additions of $48 million and other capital expenditures of $2 million. Our net capital budget for 2021 is $635 million. Our budget includes: $590 million for drilling and completion and $45 million for leasehold expenditures. We do not budget for acquisitions. During 2021, we plan to operate an average of three drilling rigs and two completion crews, and we plan to complete 65 to 70 horizontal wells in the Appalachian Basin. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities and commodity prices.

Business Strategy and Competitive Strengths

Experienced Management Team

Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays. Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to develop our reserves and production, primarily on our existing multi-year project inventory.

Focused, Long-Lived Asset Base with Sufficient Takeaway Capacity

We have assembled a portfolio of long-lived properties that are characterized by what we believe to be low geologic risk and repeatability. Our drilling opportunities are focused in the Appalachian Basin. We have secured sufficient long-term firm takeaway capacity on major pipelines in our core operating area to accommodate our current development plans.

Integrated Business Platform

We operate in the following industry segments: (i) the exploration, development and production of natural gas, NGLs, and oil; (ii) marketing of excess firm transportation capacity; and (iii) midstream services through our equity method investment in Antero Midstream. As described above and elsewhere in this Annual Report on Form 10-K, effective March 13, 2019, the results of Antero Midstream Partners are no longer consolidated in our results. See Note 18—Segment Information to the consolidated financial statements for further discussion on our industry segment operations.

Hedge Program

We maintain an active hedging program designed to mitigate volatility in commodity prices and to protect our expected future cash flows for our future operations and capital spending plans. As of December 31, 2020, we had fixed price swap contracts in place for January 1, 2021 through December 31, 2023 for 1.2 Tcf of our projected natural gas production at a weighted average index price of $2.67 per MMBtu. These hedging contracts include contracts for the year ending December 31, 2021 of 788 Bcf of natural gas at a weighted average price of $2.77 per MMBtu. We also have fixed price swaps for the year ending December 31, 2021 for ethane for approximately 19 MMBbl at a weighted average index price of $0.20 per gallon and oil for approximately 3 MMBbl at a weighted average index price of $55.16 per Bbl. Additionally, we have basis swaps in place for January 1, 2021 through December 31, 2024 for 73 Bcf of our projected natural gas production with pricing differentials ranging from $0.414 to $0.53 per MMBtu. As of

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December 31, 2020, the estimated fair value of our commodity net derivative contracts was approximately $22 million. See Note 12—Derivative Instruments to the consolidated financial statements for more information on our current hedge position.

Asset Sales Program

In December 2019, we announced an asset sale program of $750 million to $1 billion, the proceeds of which would be used to reduce indebtedness. Since December 2019, we have announced $751 million in asset sales, which includes up to $51 million of contingent consideration related to the ORRI transaction described below that may be earned in 2021. All proceeds from these assets sales were used for debt reduction, and any additional asset sales or excess cash flows are expected to be used for further debt reduction.

Conveyance of Overriding Royalty Interest

On June 15, 2020, we announced the consummation of a transaction with an affiliate of Sixth Street Partners, LLC (“Sixth Street”) relating to certain overriding royalty interests across our existing asset base (the “ORRIs”). In connection with the transaction, we contributed the ORRIs to a newly formed subsidiary, Martica, and Sixth Street at the initial closing contributed $300 million in cash (subject to customary adjustments) and agreed to contribute up to an additional $102 million in cash if certain production thresholds attributable to the ORRIs are achieved in the third quarter of 2020 and first quarter of 2021. All cash contributed by Sixth Street was distributed to us. During the third quarter of 2020, we met the applicable production threshold and received a $51 million cash distribution during the year ended December 31, 2020.

The ORRIs include an overriding royalty interest of 1.25% of our working interest in all of our operated proved developed properties in West Virginia and Ohio, subject to certain excluded wells (the “Initial PDP Override”), and an overriding royalty interest of 3.75% of our working interest in all of our undeveloped properties in West Virginia and Ohio (the “Development Override”). Wells turned to sales after April 1, 2020 and prior to the later of (a) the date on which we turn to sales 2.2 million lateral feet (net to our interest) of horizontal wells burdened by the Development Override and (b) the earlier of (i) April 1, 2023 and (ii) the date on which we turn to sales 3.82 million lateral feet (net to our interest) of horizontal wells are subject to the Development Override.

The ORRIs also include an additional overriding royalty interest of 2.00% of our working interest in the properties underlying the Initial PDP Override (the “Incremental Override”). The Incremental Override (or a portion thereof, as applicable) may be re-conveyed to us (at our election) if certain production targets attributable to the ORRIs are achieved through March 31, 2023. Any portion of the Incremental Override that may not be re-conveyed to us based on us achieving such production volumes through March 31, 2023 will remain with Martica.

Prior to Sixth Street achieving an internal rate of return of 13% and 1.5x cash-on-cash return (the “Hurdle”), Sixth Street will receive all distributions in respect of the Initial PDP Override and the Development Override, and we will receive all distributions in respect of the Incremental Override, unless certain production targets are not achieved, in which case Sixth Street will receive some or all of the distributions in respect of the Incremental Override. Following Sixth Street achieving the Hurdle, we will receive 85% of the distributions in respect of the ORRIs to which Sixth Street was entitled immediately prior to the Hurdle being achieved.

Volumetric Production Payment Transaction

On August 10, 2020, we completed a volumetric production payment transaction and received net proceeds of approximately $216 million (the "VPP").  In connection with the VPP, we entered into a purchase and sale agreement, together with a conveyance agreement and production and marketing agreement, with J.P. Morgan Ventures Energy Corporation ("JPM-VEC") to convey, effective July 1, 2020, an overriding royalty interest in dry gas producing properties in West Virginia (the "VPP Properties") equal to 136,589,000 MMBtu over the expected seven-year term of the VPP.

We accounted for the VPP as a conveyance under Accounting Standard Codifications ASC Topic 932, Extractive Industries—Oil and Gas, and the net proceeds were recorded as deferred revenue. Revenue is recognized as volumes are delivered using the units-of-production method over the term of the VPP. Under the production and marketing agreement, we and our affiliates provide certain marketing services as JPM-VEC’s agent, and any income or expenses related to these services will be recorded as marketing revenue or marketing expenses as appropriate.

Contemporaneously with the VPP, we executed a call option related to the production volumes associated with our retained interest in the VPP properties, which is collateralized by a mortgage on the VPP properties. Additionally, the production and marketing agreement contains an embedded put option related to the production volumes for our retained interest in the VPP properties, which has been bifurcated from the production and marketing arrangement and accounted for as a derivative instrument

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recorded at fair value as of December 31, 2020. See Note 12—Derivative Instruments to the consolidated financial statements for further discussion of such derivative instruments.

Drilling Partnership

On February 17, 2021, we announced the formation of a drilling partnership with QL Capital Partners (“QL”), an affiliate of Quantum Energy Partners. Under the terms of the arrangement, QL will fund 20% of total development capital spending in 2021 and is expected to fund between 15% and 20% of total development capital spending on an annual basis from 2022 through 2024. All of the wells spud during each calendar year period will be a separate annual tranche. Capital costs in excess of, and cost savings below, a specified percentage of budgeted amounts for each annual tranche will be for our account.

For each tranche other than 2021, we will propose a capital budget and estimated internal rate of return (“IRR”) for all wells to be spud during the year and, subject to the mutual agreement of the parties that the estimated IRR for each tranche exceeds a specified return, QL will be obligated to participate in such tranche. For each annual tranche in which QL participates, QL will receive a proportionate working interest percentage in each well spud in such tranche. If we present a capital budget for an annual tranche with an estimated IRR equal to or exceeding a specified return that QL in good faith believes is less than such specified return and QL elects not to participate, we will not be obligated to offer QL the opportunity to participate in subsequent tranches. No earlier than December 31 following the expiration of each tranche year, we will calculate the tranche IRR for such tranche year and, if the tranche IRR exceeds certain specified returns, we will receive a carry in the form of a one-time payment from QL for such annual tranche.

Our Properties and Operations

Reserves

The table below summarizes our estimated proved reserves as of December 31, 2019 and 2020, which were prepared assuming partial ethane recovery, and rejection of the remaining ethane. When ethane is rejected at the processing plant, it is left in the gas stream and sold with the methane gas.

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Proved Reserves

The following table summarizes the changes in our estimated proved reserves during 2020 (in Bcfe):

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Extensions and discoveries of 1,105 Bcfe of proved reserves resulted from delineation and developmental drilling in the Appalachian Basin. Performance revisions resulted in a net upward revision of 491 Bcfe. Revisions to five-year development plan downward of 790 Bcfe include a downward revision of 922 Bcfe for locations that were not developed within five years of initial booking as proved reserves, partially offset by a net upward revision of 132 Bcfe from schedule optimization primarily driven by previously proved undeveloped properties reclassified from non-proved to proved undeveloped. Price revisions downward of 1,126 Bcfe are due to decreases in prices for natural gas, NGLs and oil. Sales of reserves of 113 Bcfe resulted from the VPP. Upward revisions to ethane recovery of 485 Bcfe are due to an increase in assumed future ethane recovery. Estimated proved reserves as of December 31, 2020 totaled 17,635 Bcfe, a decrease of 7% from the prior year.

Proved Undeveloped Reserves

Proved undeveloped reserves are included in the previous table of total proved reserves. The following table summarizes the changes in our estimated proved undeveloped reserves during 2020 (in Bcfe):

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Extensions and discoveries during 2020 of 1,105 Bcfe of proved undeveloped reserves resulted from delineation and developmental drilling in the Appalachian Basin. Performance revisions resulted in a net upward revision of 172 Bcfe. Revisions to five-year development plan downward of 735 Bcfe included a downward revision of 927 Bcfe for locations that were not developed within five years of initial booking as proved reserves, partially offset by a net upward revision of 192 Bcfe from schedule optimization primarily driven by previously proved undeveloped properties reclassified from non-proved properties to proved undeveloped. Price revisions downward of 54 Bcfe are due to decreases in prices for natural gas, NGLs and oil. Upward revisions to ethane recovery of 88 Bcfe are due to an increase in assumed future ethane recovery.

During the year ended December 31, 2020, we converted approximately 1,967 Bcfe, or 27%, of our proved undeveloped reserves to proved developed reserves at a total capital cost of approximately $570 million. We spent an additional $253 million on development costs related primarily to drilled and uncompleted wells and properties in the proved undeveloped classification as of December 31, 2019, resulting in total development spending of $823 million, as disclosed in Note 21—Supplemental Information on Oil and Gas Producing Activities to the consolidated financial statements. Estimated future development costs relating to the development of our proved undeveloped reserves as of December 31, 2020 are approximately $1.5 billion, or $0.27 per Mcfe, over the next five years. Based on strip pricing as of December 31, 2020, we believe that net cash provided by operating activities will be sufficient to finance such future development costs. While we will continue to drill leasehold delineation wells and build on our current leasehold position, we will also continue drilling our proved undeveloped reserves. See “Item 1A. Risk Factors—The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.”

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We maintain a five-year development plan, which is reviewed by our Board of Directors, which supports our corporate production target. The development plan is reviewed annually to ensure capital is allocated to the wells that have the highest risk-adjusted rates of return within our inventory of undrilled well locations. In response to lower commodity prices, we reduced the pace of activity in our five-year development plan to a maintenance capital program. This resulted in the reclassification of 790 Bcfe of reserves from proved undeveloped to non-proved during the year ended December 31, 2020 due to the five-year development rule. Based on our then-current acreage position, strip prices, anticipated well economics, and our development plans at the time these reserves were classified as proved, we believe the previous classification of these locations as proved undeveloped was appropriate.

As of December 31, 2020, an estimated 11,342 of our net leasehold acres, containing 220 locations associated with proved undeveloped reserves, are subject to renewal prior to scheduled drilling. Some of these leases have contract renewal options and some will need to be renegotiated. We estimate a potential cost of approximately $31.4 million to renew the 11,342 acres based upon current leasing authorizations and option to extend payments. Proved undeveloped reserves of 913 Bcfe are related to these leases. Historically, we have had a high success rate in renewing leases, and we expect that we will be able to renew substantially all of the leases underlying this acreage prior to the scheduled drilling dates. Based on our historical success rate in renewing leases, we estimate that we may not be able to renew leases covering approximately 137 Bcfe of these proved undeveloped reserves.

If we are not able to renew these leases prior to the scheduled drilling dates, our quantities of net proved undeveloped reserves will be somewhat reduced on those locations.

Preparation of Reserve Estimates

Our proved reserve estimates as of December 31, 2018, 2019 and 2020 included in this Annual Report on Form 10-K were prepared by our internal reserve engineers in accordance with petroleum engineering and evaluation standards published by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. These proved reserve estimates have been audited by our independent engineers, DeGolyer and MacNaughton (“D&M”). We refer to D&M as our independent engineers. A copy of the summary report of D&M with respect to our reserves as of December 31, 2020 is filed as Exhibit 99.1 to this Annual Report on Form 10 K. The technical person at D&M primarily responsible for reviewing our reserves estimates was Dilhan Ilk, P.E. Mr. Ilk is a Registered Professional Engineer in the State of Texas (License No. 139334), is a member of the Society of Petroleum Engineers, and has in excess of 10 years of experience in oil and gas reservoir studies and reserves evaluations. Mr. Ilk graduated from the Istanbul Technical University in 2003 with a Bachelor of Science degree in Petroleum Engineering, a Master of Science degree in Petroleum Engineering from Texas A&M University in 2005 and a Doctor of Philosophy degree in Petroleum Engineering from Texas A&M University in 2010. The technical persons responsible for overseeing the audit of our reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

Our internal staff of petroleum engineers and geoscience professionals works closely with D&M to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserve auditing process. Periodically, our technical team meets with D&M to review properties and discuss methods and assumptions used by us to prepare reserve estimates. Our internally prepared reserve estimates and related reports are reviewed and approved by our Senior Vice President - Reserves, Planning and Midstream, W. Patrick Ash. Mr. Ash has served as Senior Vice President-Reserves, Planning and Midstream since June 2019. Previously, he served as Vice President of Reservoir Engineering and Planning from December 2017 to June 2019. Prior to December 2017, Mr. Ash was at Ultra Petroleum for six years in management positions of increasing responsibility, most recently serving as Vice President, Development. In this position he led the reservoir engineering, geoscience, and corporate engineering groups. From 2001 to 2011, Mr. Ash served in engineering roles at Devon Energy, NFR Energy and Encana Corporation. Mr. Ash holds a B.S. in Petroleum Engineering from Texas A&M University and an MBA from Washington University in St. Louis.

Our senior management and Board of Directors also reviews our reserve estimates and related reports with Mr. Ash and other members of our technical staff. Additionally, our senior management reviews and approves any significant changes to our proved reserves on a quarterly basis.

Identification of Potential Well Locations

Our identified potential well locations represent locations to which proved, probable, or possible reserves were attributable based on SEC pricing as of December 31, 2020. We prepare internal estimates of probable and possible reserves but have not included disclosure of such reserves in this Annual Report on Form 10-K.

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Production, Price and Cost History

Natural gas, NGLs, and oil are commodities, and the prices that we receive for our production are largely a function of market supply and demand. Demand for our products is impacted by general economic conditions, weather and other seasonal conditions. Over or under supply of natural gas, NGLs, or oil can result in substantial price volatility. A substantial or extended decline in commodity prices, or poor drilling results, could have a material adverse effect on our financial position, results of operations, cash flows, quantities of reserves that may be economically produced and our ability to access capital markets. See “Item 1A. Risk Factors— Natural gas, NGLs, and oil price volatility, or a substantial or prolonged period of low natural gas, NGLs, and oil prices, may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.”

Exploration and Production and Marketing Segments

The following table sets forth information regarding our production, realized prices, and production costs for the years ended December 31, 2018, 2019 and 2020. For additional information on price calculations, see information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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Acreage

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we own an interest as of December 31, 2020.  A majority of our developed acreage is subject to liens securing the Credit Facility.  Approximately 75% of our net Appalachian Basin acreage is held by production.  Acreage related to royalty, overriding royalty, and other similar interests is excluded from this table.

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Productive Wells

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The following table summarizes gross and net productive wells as of December 31, 2020, all of which are natural gas wells.   Net wells reflect the sum of our percentage ownership in gross wells.

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