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    Table of Contents UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10‑K ☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2018 or ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File No. 001‑36120 ANTERO RESOURCES CORPORATION (Exact name of registrant as specified in its charter) Delaware 80‑0162034 (State or other jurisdiction of (IRS Employer incorporation or organization) Identification No.) 1615 Wynkoop Street Denver Colorado 80202 (Address of principal executive offices) (Zip Code) (303) 357‑7310 (Registrant’s telephone number, including area code) Securities Registered Pursuant to Section 12(b) of the Act: Title of Each Class Name of Each Exchange on which Registered Common Stock, Par Value $0.01 Per Share New York Stock Exchange Securities Registered Pursuant to Section 12(g) of the Act: None. 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S‑K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10‑K or any amendment to this Form 10‑K. ☒ 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. Large accelerated filer ☒ Accelerated filer ☐ Non‑accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐ 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 The aggregate market value of the voting common stock held by non‑affiliates of the registrant as of June 29, 2018, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $4.1 billion based on the closing price of Antero Resources Corporation’s common stock as reported on that day on the New York Stock Exchange of $21.35. The registrant had 308,651,020 shares of common stock outstanding as of February 8, 2019. 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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    Table of Contents TABLE OF CONTENTS Page CAUTIONARY STATEMENT REGARDING FORWARD‑LOOKING STATEMENTS ii PART I 1 Items 1 and 2. Business and Properties 1 Item 1A. Risk Factors 25 Item 1B. Unresolved Staff Comments 42 Item 3. Legal Proceedings 43 Item 4. Mine Safety Disclosures 45 PART II 45 Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 45 Item 6. Selected Financial Data 46 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 51 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 78 Item 8. Financial Statements and Supplementary Data 80 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 80 Item 9A. Controls and Procedures 80 Item 9B. Other Information 81 PART III 82 Item 10. Directors, Executive Officers and Corporate Governance 82 Item 11. Executive Compensation 85 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 85 Item 13. Certain Relationships and Related Transactions and Director Independence 85 Item 14. Principal Accountant Fees and Services 85 PART IV 86 Item 15. Exhibits and Financial Statement Schedules 86 SIGNATURES 90 i


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    Table of Contents CAUTIONARY STATEMENT REGARDING FORWARD‑LOOKING STATEMENTS The information in this report includes “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. These forward‑looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering these forward-looking statements, investors should keep in mind the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” in this Annual Report on Form 10‑K. These forward‑looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Forward‑looking statements may include statements about our: · business strategy; · reserves; · financial strategy, liquidity, and capital required for our development program; · natural gas, natural gas liquids (“NGLs”), and oil prices; · timing and amount of future production of natural gas, NGLs, and oil; · hedging strategy and results; · ability to successfully complete our share repurchase program; · the possibility that the proposed simplification and related transactions described elsewhere in this Annual Report on Form 10-K (the “Transactions”) are not consummated in a timely manner or at all; · the diversion of management in connection with the Transactions and the ability of the resulting entity of the Transactions to realize the anticipated benefits of the Transactions; · ability to meet minimum volume commitments and to utilize or monetize our firm transportation commitments; · future drilling plans; · competition and government regulations; · pending legal or environmental matters; · marketing of natural gas, NGLs, and oil; · leasehold or business acquisitions; · costs of developing our properties; · operations of Antero Midstream Partners LP, (“Antero Midstream”), including the operations of its unconsolidated affiliates; · general economic conditions; · credit markets; · uncertainty regarding our future operating results; and · plans, objectives, expectations and intentions. ii


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    Table of Contents We caution investors that these forward‑looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incidental to our business. 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, and the other risks described under the heading “Item 1A. Risk Factors” in our 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 report 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 report 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, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report on Form 10‑K. iii


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    Table of Contents 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: “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. “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. “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. “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. “Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval. “Joint Venture.” The joint venture entered into on February 6, 2017 between Antero Midstream Partners L.P. 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. iv


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    Table of Contents “MBbl.” One thousand barrels of crude oil, condensate or NGLs. “Mcf.” One thousand cubic feet of natural gas. “MMBbl.” One million barrels of crude oil, condensate or NGLs. “MMBtu.” One million British thermal units. “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. “NGLs.” Natural gas liquids. Hydrocarbons found in natural gas which may be extracted as purity products such as ethane, propane, isobutane and normal butane, and natural gasoline. “NYMEX.” The New York Mercantile Exchange. “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. “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. “Proved reserves.” The estimated quantities of oil, natural gas and natural gas liquids which 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 natural gas and oil 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 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. v


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    Table of Contents “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. “Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement. “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. vi


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    Table of Contents PART I Items 1 and 2. Business and Properties Our Company and Organizational Structure Antero Resources Corporation (individually referred to as “Antero”) and its subsidiaries (collectively referred to as the “Company”) are engaged in the exploration, development, production, and acquisition of natural gas, NGLs, and oil properties located in the Appalachian Basin. We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations. As of December 31, 2018, we held approximately 612,000 net acres of oil and gas properties located in the Appalachian Basin in West Virginia and Ohio. Our corporate headquarters are in Denver, Colorado. Antero’s consolidated subsidiary, Antero Midstream Partners LP (“Antero Midstream” or the “Partnership”), is a public master limited partnership formed to own, operate, and develop midstream energy assets to service Antero’s production, drilling, and completion activities under long-term service contracts. Antero’s consolidated financial statements include Antero Midstream’s financial position and results of operations. Antero Midstream GP LP (“AMGP”) was originally formed as Antero Resources Midstream Management LLC (“ARMM”) in 2013, to become the general partner of Antero Midstream Partners LP (“Antero Midstream”). On May 4, 2017, ARMM converted from a Delaware limited liability company to a Delaware limited partnership and changed its name to Antero Midstream GP LP in connection with its initial public offering (“IPO”). Subsequent to its IPO, AMGP indirectly controls the general partnership interest in Antero Midstream and directly controls Antero IDR Holdings LLC (“IDR LLC”), which owns the incentive distribution rights (“IDRs”) in Antero Midstream. Antero Resources Corporation does not hold any financial or other interests in AMGP and does not consolidate AMGP for financial reporting purposes. 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. Three months ended December 31, At December 31, 2018 2018 Net Gross Average net Proved proved potential daily Reserves PV-10 (in developed Total net drilling production (Bcfe) (1) millions)(2) wells(3) acres locations(4) (MMcfe/d) Appalachian Basin: Marcellus Shale 15,998 $10,802 805 486,199 3,240 2,607 Ohio Utica Shale 2,013 $ 1,787 201 125,477 494 606 Total 18,011 $12,589 1,006 611,676 3,734 3,213 (1) Estimated proved reserve volumes and values were calculated assuming partial ethane recovery, with rejection of the remaining ethane, and using the unweighted twelve‑month average of the first‑day‑of‑the‑month prices for the period ended December 31, 2018, which were $2.93 per MMBtu for natural gas based on a $3.09 per MMBtu NYMEX reference price, $25.05 per Bbl for NGLs and $56.62 per Bbl for oil for the Appalachian Basin based on a $65.66 per Bbl WTI reference price. (2) PV‑10 is a non‑GAAP financial measure. For a reconciliation of PV‑10 to standardized measure, please see “—Our Properties and Operations—Estimated Proved Reserves.” (3) Does not include certain vertical wells with no proved reserves booked that were primarily acquired in conjunction with leasehold acreage acquisitions. (4) Gross potential drilling locations are comprised of 427 locations classified as proved undeveloped and 3,307 locations classified as probable and possible. See “Item 1A. Risk Factors” for risks and uncertainties related to developing our potential well locations contained in our proved, probable, and possible reserve categories. 1


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    Table of Contents 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 profitably grow our reserves and production, primarily on our existing multi‑year project inventory. 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 Marcellus Shale and Utica Shale of the Appalachian Basin. We have 3,734 potential horizontal well locations on our existing leasehold acreage within our proved, probable, and possible reserve categories. We have secured sufficient long‑term firm takeaway capacity on major pipelines that are in existence or under construction in each of our core operating areas to accommodate our current development plans. Together, Antero and Antero Midstream operate in the following industry segments: (i) the exploration, development, and production of natural gas, NGLs, and oil, (ii) gathering and processing, (iii) water handling and treatment, and (iv) marketing of excess firm transportation capacity. All of our operations are conducted in the United States. Financial information for our industry segment operations is located under “Note 16 – Segment Information.” 2018 and Recent Developments and Highlights Reserves, Production, and Financial Results As of December 31, 2018, our estimated proved reserves were 18.0 Tcfe, consisting of 11.4 Tcf of natural gas, 554 MMBbl of ethane, 498 MMBbl of C3+ NGLs, and 46 MMBbl of oil. As of December 31, 2018, 63% of our estimated proved reserves by volume were natural gas, 35% were NGLs, and 2% were oil. Proved developed reserves were 10.4 Tcfe, or 58% of total proved reserves. For the year ended December 31, 2018, our net production totaled 989 Bcfe, or 2,709 MMcfe per day, a 20% increase compared to 822 Bcfe, or 2,253 MMcfe per day, for the year ended December 31, 2017. Production growth resulted from an increase in the number of producing wells as a result of our drilling and completion activity. Our average price received for production, before the effects of gains on settled commodity derivatives, for the year ended December 31, 2018 was $3.69 per Mcfe compared to $3.34 per Mcfe for the year ended December 31, 2017. Our average realized price after the effects of gains on settled commodity derivatives was $3.94 per Mcfe for the year ended December 31, 2018 as compared to $3.60 per Mcfe for the year ended December 31, 2017. For the year ended December 31, 2018, we generated consolidated cash flows from operations of $2.1 billion, a consolidated net loss of $398 million, Adjusted EBITDAX of $2.0 billion, and Stand-Alone Adjusted EBITDAX of $1.7 billion. This compares to consolidated cash flows from operations of $2.0 billion, consolidated net income of $615 million, Adjusted EBITDAX of $1.5 billion, and Stand-Alone Adjusted EBITDAX of $1.2 billion for the year ended December 31, 2017. See “Item 6. Selected Financial Data” for a definition of Adjusted EBITDAX (a non‑GAAP measure) and a reconciliation of Adjusted EBITDAX to net income (loss). See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations— Stand-Alone Exploration and Production Information” for a definition of Stand-Alone Adjusted EBITDAX and a reconciliation of Stand-Alone Adjusted EBITDAX to Antero’s stand- alone net income (loss). “Stand-alone” data represents information for Antero on an unconsolidated basis, reflecting Antero’s investment in Antero Midstream under the equity method of accounting. Consolidated net loss for 2018 included (i) commodity derivative fair value losses of $88 million, comprised of gains on settled derivatives of $243 million, gains on settled derivatives of $370 million related to derivatives that were either fully or partially monetized prior to their settlement dates, and a non-cash loss of $701 million on changes in the fair value of commodity derivatives, (ii) a non-cash charge of $70 million for equity-based compensation, (iii) a non-cash charge of $549 million for impairments of unproved properties, and (iv) a non-cash deferred tax benefit of $129 million. 2018 Capital Spending and 2019 Capital Budget For the year ended December 31, 2018, our total consolidated capital expenditures were approximately $2.2 billion, including drilling and completion expenditures of $1.5 billion, leasehold additions of $172 million, gathering and compression expenditures of $444 million, water handling and treatment expenditures of $98 million, and other capital expenditures of $8 million. In response to recent oil and NGL price declines, we have reduced our consolidated capital budget for 2019 to $1.9 billion to $2.2 billion. Our budget includes: $1.1 billion to $1.25 billion for drilling and completion, $75 million to $100 million for leasehold expenditures, and $750 million to $800 million for capital expenditures by Antero Midstream, which includes $200 million for investments in 2


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    Table of Contents unconsolidated affiliates. We do not budget for acquisitions. During 2019, we plan to operate an average of five drilling rigs and four completion crews and we plan to complete 115-125 horizontal wells in the Marcellus and Utica Shales in 2019. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities, and commodity prices. Delevering Activities In December 2018, we monetized part of our natural gas hedge portfolio through the unwinding of 68% of April through December 2019 swap volumes generating $248 million of proceeds and resetting 70% of 2020 swap volumes from contract prices of $3.25/MMBtu to a contract price of $3.00/MMBtu generating $122 million of net proceeds. The early settlement of 2019 swap volumes was replaced with collars for the period April through December 2019 for the same total notional quantities (433 Bcf) as the terminated forward swaps. The collars set a weighted average floor price of $2.50/MMBtu and a weighted average ceiling price of $3.37/MMBtu. Proceeds from the monetization were used to repay a portion of borrowings under Antero's revolving credit facility. Hedge Position At December 31, 2018, we had fixed price swap contracts in place for January 1, 2019 through December 31, 2023 for 1.5 Tcf of our projected natural gas production at a weighted average index price of $3.13 per MMBtu. These hedging contracts include contracts for the year ending December 31, 2019 of 417 Bcf of natural gas. Additionally, we have collar agreements for April 2019 through December 2019 for 433 Bcf of our projected natural gas production at a weighted average floor and ceiling of $2.50 and $3.37, respectively. We also had basis swaps for January 2019 for 7 Bcf of our projected natural gas production with pricing differentials ranging from $0.215 to $0.40. To the extent we have hedged the price of a portion of our estimated future production through 2023, we believe this hedge position provides some certainty to cash flows supporting our future operations and capital spending plans. As of December 31, 2018, the estimated fair value of our commodity derivative contracts was approximately $607 million. Credit Facilities At December 31, 2018, Antero’s borrowing base under its senior revolving credit facility (the “Credit Facility”) was $4.5 billion and lender commitments were $2.5 billion. The maturity date of the facility is the earlier of (i) October 26, 2022 and (ii) the date that is 91 days prior to the earliest stated redemption date of any series of Antero’s senior notes, unless such series of notes is refinanced. The borrowing base under our revolving credit facility is redetermined annually and is based on the estimated future cash flows from our proved oil and gas reserves and our commodity derivative positions. The next redetermination is scheduled to occur in April 2019. At December 31, 2018, we had $405 million of borrowings, with a weighted average interest rate of 3.95%, and $685 million of letters of credit outstanding under the revolving credit facility. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements and Contractual Obligations—Senior Secured Revolving Credit Facility” for a description of the Credit Facility. At December 31, 2018, lender commitments under Antero Midstream’s revolving credit facility (the “Midstream Credit Facility”) were $2.0 billion. The maturity date of the facility is October 26, 2022. At December 31, 2018, Antero Midstream had $990 million of borrowings outstanding under the Midstream Credit Facility. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements and Contractual Obligations —Midstream Credit Facility” for a description of the Midstream Credit Facility. Share Repurchase Program In October 2018, the Company’s Board of Directors authorized a $600 million share repurchase program, subject to targeted leverage ratios and cash flow generation. During the fourth quarter of 2018, we repurchased 9.1 million shares of our common stock (approximately 3% of total shares outstanding at commencement of the program) at a total cost of approximately $129 million. Simplification Transaction On October 9, 2018, we announced that AMGP, Antero Midstream and certain of their affiliates entered into a Simplification Agreement (as may be amended from time to time, the “Simplification Agreement”), pursuant to which, among other things, (1) AMGP will be converted from a limited partnership to a corporation under the laws of the State of Delaware, to be named Antero Midstream Corporation (which is referred to as “New AM” and the conversion, the “Conversion”); (2) an indirect, wholly owned subsidiary of New AM will be merged with and into Antero Midstream, with Antero Midstream surviving the merger as an indirect, 3


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    Table of Contents wholly owned subsidiary of New AM (the “Merger”) and (3) all the issued and outstanding Series B Units representing limited liability company interests of Antero IDR Holdings LLC (“IDR Holdings”), a subsidiary of AMGP and the holder of all of Antero Midstream’s incentive distribution rights, will be exchanged for an aggregate of approximately 17.35 million shares of New AM’s common stock (the “Series B Exchange”). The Conversion, the Merger, the Series B Exchange and the other transactions contemplated by the Simplification Agreement are collectively referred to as the “Transactions.” As a result of the Transactions, Antero Midstream will be a wholly owned subsidiary of New AM and former shareholders of AMGP, unitholders of Antero Midstream, including Antero, and holders of Series B Units will each own New AM’s common stock. Following the completion of the simplification transaction, Antero will no longer consolidate Antero Midstream’s financial position and results of operations in Antero’s consolidated financial statements, and Antero will account for its interest in New AM using the equity method of accounting. We currently own 98,870,335 of Antero Midstream’s common units and will be entitled to receive consideration of $3.00 in cash and 1.6023 shares of New AM’s common stock per Antero Midstream common unit. Public unitholders of Antero Midstream will be entitled to receive a combination of $3.415 in cash and 1.635 shares of New AM’s common stock per Antero Midstream common unit. All public unitholders of Antero Midstream will be entitled to elect to receive their merger consideration in all cash, all stock, or a combination of cash and stock, and we will have the ability to elect to take a larger portion of our merger consideration in cash if the public unitholders of Antero Midstream disproportionately elect to receive stock consideration, subject in each case to proration to ensure that the aggregate amount of cash consideration paid to all Antero Midstream unitholders is an amount equal to the aggregate amount of cash that would have been paid and issued if all public unitholders of Antero Midstream received $3.415 in cash per Antero Midstream common unit and we received $3.00 in cash per unit, which is approximately $598 million and the aggregate amount of equity issuable to all Antero Midstream unitholders is a number of shares of New AM’s common stock equal to the aggregate number of shares that would be issued if all public unitholders of Antero Midstream received 1.635 shares per Antero Midstream common unit and we received 1.6023 shares of New AM’s common stock per Antero Midstream common unit. If we elect to receive only $3.00 in cash per Antero Midstream common unit, we are expected to own approximately 31% of New AM’s common stock following the completion of the Transactions. Special meetings of AMGP shareholders and Antero Midstream unitholders will be held on March 8, 2019 to vote on the Simplification Agreement, the Merger and the other Transactions contemplated thereby, as applicable, and all AMGP shareholders and Antero Midstream unitholders of record as of the close of business on January 11, 2019, which is the record date for the special meetings, will be entitled to vote the AMGP common shares and Antero Midstream common units, respectively, owned by them on the record date. AMGP and Antero Midstream expect the Transactions to close shortly after the special meeting date, subject to certain closing conditions under the documentation for the Transactions. AMGP and the Partnership expect to fund the cash portion of the merger consideration with borrowings under Antero Midstream’s revolving credit facility. Also on October 9, 2018, in connection with the entry into the Simplification Agreement, (1) Antero Midstream entered into a voting agreement with AMGP’s shareholders owning a majority of the outstanding AMGP common shares, pursuant to which, among other things, such shareholders agreed to vote in favor of the Transactions, (2) AMGP entered into a voting agreement with us, pursuant to which, among other things, we agreed to vote in favor of the Transactions and (3) we, AMGP, certain funds affiliated with Warburg Pincus LLC and Yorktown Partners LLC (together, the “Sponsor Holders”), Paul M. Rady and Glen C. Warren, Jr. (Messrs. Rady and Warren together, the “Management Stockholders”) entered into a Stockholders’ Agreement, pursuant to which, among other things, we, the Sponsor Holders and the Management Holders will have the ability to designate members of the New AM board of directors under certain circumstances, effective as the closing of the Transactions. Our Properties and Operations Estimated Proved Reserves The information with respect to our estimated proved reserves presented below has been prepared in accordance with the rules and regulations of the SEC. Reserves Presentation The following table summarizes our estimated proved reserves, related Standardized measure, and PV‑10 at December 31, 2016, 2017 and 2018. Total estimated proved reserves are prepared on a consolidated basis, as required by SEC Rules, using operating and capital costs on a consolidated basis. Our estimated proved reserves are based on evaluations prepared by our internal reserve engineers, which 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 at December 31, 2018 is filed as Exhibit 99.1 to this Annual Report on Form 10‑K. Within D&M, the technical person primarily responsible for reviewing our 4


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    Table of Contents reserves estimates was Gregory K. Graves, P.E. Mr. Graves is a Registered Professional Engineer in the State of Texas (License No. 70734), is a member of both the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers, and has in excess of 33 years of experience in oil and gas reservoir studies and reserves evaluations. Mr. Graves graduated from the University of Texas at Austin in 1984 with a Bachelor of Science degree in Petroleum Engineering. Reserves at December 31, 2016, 2017, and 2018 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. At December 31, 2016 2017 2018 Estimated proved reserves: Proved developed reserves: Natural gas (Bcf) 4,426 5,587 6,669 Ethane (MMBbl) 250 268 341 C3+ NGLs (MMBbl) 151 199 259 Oil (MMBbl) 13 16 20 Total equivalent proved developed reserves (Bcfe) 6,914 8,488 10,389 Proved undeveloped reserves: Natural gas (Bcf) 4,988 5,511 4,756 Ethane (MMBbl) 304 260 213 C3+ NGLs (MMBbl) 252 262 238 Oil (MMBbl) 25 22 26 Total equivalent proved undeveloped reserves (Bcfe) 8,472 8,773 7,622 Total estimated proved reserves (Bcfe) 15,386 17,261 18,011 PV-10 (in millions)(1) $ 3,676 $10,175 $12,589 Standardized measure (in millions)(1) $ 3,287 $ 8,627 $10,478 Proved developed producing (Bcfe) 6,587 7,996 9,841 Proved developed non-producing (Bcfe) 327 492 548 Percent developed 45 % 49 % 58 % (1) PV‑10 was prepared using average yearly prices computed using SEC rules, discounted at 10% per annum, without giving effect to taxes. PV‑10 is a non‑GAAP financial measure. We believe that the presentation of PV‑10 is relevant and useful to our investors as supplemental disclosure to the standardized measure of future net cash flows, or after tax amount, because it presents the discounted future net cash flows attributable to our proved reserves prior to 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, PV‑10 is based on a pricing methodology and discount factors that are consistent for all companies. Because of this, PV‑10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. The difference between the standardized measure and the PV‑10 amount is the discounted amount of estimated future income taxes. For more information about the calculation of Standardized measure, see Note 19 to our consolidated financial statements included in Item 8 of this Annual Report on Form 10‑K. The following sets forth the estimated future net cash flows from our proved reserves (without giving effect to our commodity derivatives), the present value of those net cash flows before income tax (PV‑10), the present value of those net cash flows after income tax (Standardized measure) and the prices used in projecting future net cash flows at December 31, 2016, 2017, and 2018: At December 31, (In millions, except per Mcf data) 2016(1) 2017(2) 2018(3) Future net cash flows $11,623 $26,137 $30,739 Present value of future net cash flows: Before income tax (PV-10) $ 3,676 $10,175 $12,589 Income taxes $ (389) $(1,548) $(2,111) After income tax (Standardized measure) $ 3,287 $ 8,627 $10,478 (1) 12 month average prices used at December 31, 2016 were $2.31 per MMBtu for natural gas, $13.58 per Bbl for NGLs, and $32.63 per Bbl for oil for the Appalachian Basin based on a $42.68 WTI reference price. (2) 12 month average prices used at December 31, 2017 were $2.91 per MMBtu for natural gas, $20.40 per Bbl for NGLs, and $45.35 per Bbl for oil for the Appalachian Basin based on a $51.03 WTI reference price. 5


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    Table of Contents (3) 12‑month average prices used at December 31, 2018 were $2.93 per MMBtu for natural gas, $25.05 per Bbl for NGLs, and $56.62 per Bbl for oil for the Appalachian Basin based on a $65.66 WTI reference price. Future net cash flows represent projected revenues from the sale of proved reserves net of production and development costs (including operating expenses and production taxes). Prices for 2016, 2017, and 2018 were based on 12‑month unweighted average of the first‑day‑of‑the‑month pricing, without escalation. Costs are based on costs in effect for the applicable year without escalation. There can be no assurance that the proved reserves will be produced as estimated or that the prices and costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information, and different reservoir engineers often arrive at different estimates for the same properties. Changes in Proved Reserves During 2018 The following table summarizes the changes in our estimated proved reserves during 2018 (in Bcfe): Proved reserves, December 31, 2017 17,261 Extensions, discoveries, and other additions 2,781 Performance revisions (433) Revisions to 5-year development plan (742) Price revisions 18 Revisions to ethane recovery 115 Production (989) Proved reserves, December 31, 2018 18,011 Extensions, discoveries, and other additions of 2,781 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales. Downward revisions of 433 Bcfe related to well performance. Net downward revisions of 742 Bcfe related to optimization to our 5-year development plan. This figure includes upward revisions of 1,722 Bcfe for previously proved undeveloped properties reclassified from non-proved properties at December 31, 2017 to proved undeveloped at December 31, 2018 due to their addition to our 5-year development plan, and downward revisions of 2,464 Bcfe for locations that were not developed within 5 years of initial booking as proved reserves. Upward revisions of 18 Bcfe were due to increases in prices for natural gas, NGLs, and oil. Upward revisions of 115 Bcfe were due to an increase in our assumed future ethane recovery. Our estimated proved reserves as of December 31, 2018 totaled approximately 18.0 Tcfe, an increase of 4% 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 2018 (in Bcfe): Proved undeveloped reserves, December 31, 2017 8,773 Extension, discoveries, and other additions 2,464 Performance revisions (143) Revisions to 5-year development plan (742) Price revisions 7 Reclassifications to proved developed reserves (2,531) Revisions to ethane recovery (206) Proved undeveloped reserves, December 31, 2018 7,622 Extensions, discoveries, and other additions during 2018 of 2,464 Bcfe of proved undeveloped reserves resulted from delineation and developmental drilling in the Marcellus and Utica Shales. Downward revisions of 143 Bcfe related to well performance. Net downward revisions of 742 Bcfe related to optimization to our 5-year development plan. This figure includes upward revisions of 1,722 Bcfe for previously proved undeveloped properties reclassified from non-proved properties at December 31, 2017 to proved undeveloped at December 31, 2018 due to their addition to our 5-year development plan, and downward revisions of 2,464 Bcfe for locations that were not developed within 5 years of initial booking as proved reserves. Upward revisions of 7 Bcfe were due to increases in prices for natural gas, NGLs, and oil. During the year ended December 31, 2018, we converted approximately 2,531 Bcfe, or 29%, of our proved undeveloped reserves to proved developed reserves at a total capital cost of approximately $862 million. We spent an additional $303 million on development costs related primarily to drilled and uncompleted wells and properties in the proved undeveloped classification at December 31, 2017, resulting in total development spending of $1.2 billion, as disclosed in Note 19 to the consolidated financial 6


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    Table of Contents statements included elsewhere in this report. Estimated future development costs relating to the development of our proved undeveloped reserves at December 31, 2018 are approximately $3.3 billion, or $0.44 per Mcfe, over the next five years. Based on strip pricing as of December 31, 2018, we believe that cash flows from operations 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.” We maintain a 5-year development plan, which is reviewed by our Board of Directors, which supports our corporate production growth 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. As our well economics have changed, we have reallocated 5-year capital to areas with expected highest rates of return and optimal lateral lengths. This resulted in the reclassification of 1,722 Bcfe of reserves from proved undeveloped to probable during the year ended December 31, 2018 due to the 5-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. At December 31, 2018, an estimated 19,400 of our net leasehold acres, containing 308 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 $42 million to renew the 19,400 acres based upon current leasing authorizations and option to extend payments. Proved undeveloped reserves of 1,565 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 235 Bcfe of these proved undeveloped reserves. If we are not able to renew these leases prior to the scheduled drilling dates, our quantities of proved undeveloped reserves will be somewhat reduced. Preparation of Reserve Estimates Our reserve estimates as of December 31, 2016, 2017, and 2018 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. Our internally prepared reserve estimates were audited by our independent reserve engineers. Our independent reserve engineers were selected for their historical experience and geographic expertise in engineering unconventional resources. 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 work closely with our independent reserve engineers 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 the independent reserve engineers 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 Vice President-Reservoir Engineering and Planning, W. Patrick Ash. W. Patrick Ash has served as Vice President of Reservoir Engineering and Planning since December 2017. Prior to joining Antero, 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 2001-2011, 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 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. Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, we and the 7


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    Table of Contents independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available downhole and production data, micro‑seismic data, and well‑test data. Probable reserves are reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves which may potentially be recoverable through additional drilling or recovery techniques are, by nature, more uncertain than estimates of proved reserves and, accordingly, are subject to substantially greater risk of realization. Possible reserves are reserves that are less certain to be recovered than probable reserves. Estimates of possible reserves are also inherently imprecise. Estimates of probable and possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes, and other factors. Methodology Used to Apply Reserve Definitions In the Marcellus Shale, our estimated reserves are based on information from our large, operated proved developed producing reserve base, as well as information from other operators in the area, which can be used to confirm or supplement our internal estimates. Typically, proved undeveloped properties are booked based on applying the estimated lateral length to the average wellhead Bcf per 1,000 feet from our proved developed producing wells, then converting to a processed volume where applicable. We may attribute up to 11 proved undeveloped locations based on one proved developed producing well where analysis of geologic and engineering data can be estimated with reasonable certainty to be commercially recoverable. However, the ratio of proved undeveloped locations generated will be lower when multiple proved developed wells are drilled on a single pad. In addition, we have applied the concept of a statistically proven area to certain areas of our Marcellus Shale acreage whereby undeveloped properties are booked as proved reserves so long as well count is sufficient for statistical analysis and certain land, geologic, engineering and commercial criteria are met. Although our operating history in the Utica Shale is more limited than our Marcellus Shale operations, we expect to be able to apply a similar methodology once the well count is sufficient for statistical analysis. The primary differences between the two areas are that (i) we have not established a statistically proven area in the Utica Shale and (ii) each proved developed producing well in the Utica Shale only generates four direct offset well locations due to less relative maturity of the play. 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, 2018. We prepare internal estimates of probable and possible reserves but have not included disclosure of such reserves in this report. Production, Revenues, and Price History Because natural gas, NGLs, and oil are commodities, the prices that we receive for our production are largely a function of market supply and demand. While demand for natural gas in the United States has increased materially since 2000, natural gas and NGLs supplies have also increased significantly as a result of horizontal drilling and fracture stimulation technologies which have been used to find and recover large amounts of oil and gas from various shale formations throughout the United States. Demand 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 prices are volatile. A substantial or extended decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.” 8


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    Table of Contents Operations Data – 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, 2016, 2017 and 2018. 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.” Year ended December 31, 2016 2017 2018 Production data: Natural gas (Bcf) 505 591 710 C2 Ethane (MBbl) 6,396 10,539 14,221 C3+ NGLs (MBbl) 20,279 25,507 28,913 Oil (MBbl) 1,873 2,451 3,265 Combined (Bcfe) 676 822 989 Daily combined production (MMcfe/d) 1,847 2,253 2,709 Average prices before effects of derivative settlements: Natural gas (per Mcf) $ 2.50 $ 2.99 $ 3.22 C2 Ethane (per Bbl) $ 8.28 $ 8.83 $ 12.14 C3+ NGLs (per Bbl) $ 18.74 $ 30.48 $ 34.76 Oil (per Bbl) $ 32.73 $ 44.14 $ 57.34 Combined average sales prices before effects of derivative settlements (per Mcfe) (1) $ 2.60 $ 3.34 $ 3.69 Combined average sales prices after effects of derivative settlements (per Mcfe) (1) $ 4.08 $ 3.60 $ 3.94 Average Costs (per Mcfe) (2) : Lease operating $ 0.07 $ 0.11 $ 0.14 Gathering, compression, processing, and transportation $ 1.70 $ 1.75 $ 1.81 Production and ad valorem taxes $ 0.10 $ 0.11 $ 0.12 Marketing, net $ 0.16 $ 0.13 $ 0.23 Depletion, depreciation, amortization, and accretion $ 1.05 $ 0.86 $ 0.85 General and administrative (excluding equity-based compensation) $ 0.16 $ 0.14 $ 0.13 (1) Average sales prices shown in the table reflect both the before and after effects of our settled derivatives. Our calculation of such after effects includes gains on settlements of derivatives, (but does not include proceeds from the derivative monetizations), which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes. Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts. This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value. (2) Average costs reflect our operating costs on a standalone basis for Antero, prior to the elimination of intercompany transactions for midstream and water services provided by Antero Midstream. Productive Wells As of December 31, 2018, we held interests in a total of 1,130 gross (1,002.2 net) producing wells on our Marcellus Shale acreage, including the following: · 790 gross (778.7 net) horizontal wells, averaging a 99% working interest, operated by Antero. · 98 gross (6.1 net) horizontal wells operated by other producers. · 242 gross (217.4 net) shallow vertical wells. As of December 31, 2018, we held interests in a total of 250 gross (200.2 net) producing wells on our Ohio Utica Shale acreage, including the following: · 216 gross (200.1 net) horizontal wells, averaging a 93% working interest, operated by Antero. · 34 gross (0.1 net) horizontal wells operated by other producers. Additionally, at December 31, 2018, we had 26 net horizontal proved developed non-producing wells, and 86 gross horizontal wells (84.7 net) that were drilled and uncompleted or in the process of being completed. The shallow vertical wells and wells operated by other producers were primarily acquired in conjunction with leasehold acreage acquisitions. 9


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    Table of Contents 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, 2018. A majority of our developed acreage is subject to liens securing our revolving credit facility. Approximately 57% of our net Marcellus acreage and 50% of our net Utica acreage is held by production. Acreage related to royalty, overriding royalty, and other similar interests is excluded from this table. Developed Acres Undeveloped Acres Total Acres Basin Gross Net Gross Net Gross Net Marcellus Shale 125,894 124,492 425,768 361,707 551,662 486,199 Utica Shale 43,515 39,326 92,922 86,151 136,437 125,477 Total 169,409 163,818 518,690 447,858 688,099 611,676 The following table provides a summary of our current gross and net acreage by county in the Marcellus Shale and the Ohio Utica Shale. Marcellus Gross Net County, State Acres Acres Doddridge, WV 159,242 140,346 Fayette, PA 6,153 5,423 Gilmer, WV 12,462 10,983 Harrison, WV 103,535 91,249 Lewis, WV 48 42 Marion, WV 10,529 9,279 Monongalia, WV 2,453 2,162 Pleasants, WV 5,844 5,150 Ritchie, WV 85,421 75,285 Tyler, WV 95,048 83,770 Washington, PA 202 178 Westmoreland, PA 4,117 3,628 Wetzel, WV 66,608 58,704 Total Marcellus Shale 551,662 486,199 Ohio Utica Gross Net Acres Acres Belmont, OH 11,575 10,761 Guernsey, OH 4,206 3,766 Harrison, OH 529 529 Monroe, OH 55,726 53,840 Noble, OH 61,351 54,167 Washington, OH 3,050 2,414 Total Utica Shale 136,437 125,477 Total Marcellus and Utica Shale 688,099 611,676 Undeveloped Acreage Expirations The following table sets forth our total gross and net undeveloped acres as of December 31, 2018 that will expire over the next three years unless production is established within the spacing units covering the acreage prior to the expiration dates, or unless 10


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    Table of Contents the leases containing such acreage are extended or renewed. Marcellus Ohio Utica Total Gross Net Gross Net Gross Net Acres Acres Acres Acres Acres Acres 2019 55,228 48,674 39,077 36,140 94,305 84,814 2020 35,694 31,458 14,892 13,666 50,586 45,124 2021 46,003 40,544 6,550 5,876 52,553 46,420 Drilling Activity The following table sets forth the results of our drilling activity for wells drilled and completed during the years ended December 31, 2016, 2017, and 2018. Gross wells reflect the number of wells in which we own an interest and include historical drilling activity in the Appalachian Basin. Net wells reflect the sum of our working interests in gross wells. Year ended December 31, 2016 2017 2018 Gross Net Gross Net Gross Net Marcellus Development wells: Productive 72 71 112 111 136 134 Dry — — — — — — Total development wells 72 71 112 111 136 134 Exploratory wells: Productive 16 16 1 1 2 2 Dry — — — — — — Total exploratory wells 16 16 1 1 2 2 Utica Development wells: Productive 35 35 4 4 17 17 Dry — — — — — — Total development wells 35 35 4 4 17 17 Exploratory wells: Productive 5 5 18 18 8 8 Dry — — — — — — Total exploratory wells 5 5 18 18 8 8 Total Development wells: Productive 107 106 116 115 153 151 Dry — — — — — — Total development wells 107 106 116 115 153 151 Exploratory wells: Productive 21 21 19 19 10 10 Dry — — — — — — Total exploratory wells 21 21 19 19 10 10 The figures in the table above do not include 86 gross wells (85 net) that were drilled and uncompleted or in the process of being completed at December 31, 2018. Delivery Commitments We have entered into various firm sales contracts to deliver and sell gas. We believe we will have sufficient production quantities to meet substantially all of such commitments, but may be required to purchase gas from third parties to satisfy shortfalls should they occur. 11


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    Table of Contents As of December 31, 2018, our firm sales commitments through 2023 included: Firm Volume of Transport Volume Volume Natural Capacity of of C3+ Gas Utilized Ethane NGLs Year Ending December 31, (MMBtu/d) (MMBtu/d) (Bbl/day) (Bbl/day) 2019 1,170,000 840,000 62,500 50,000 2020 1,030,000 790,000 56,500 50,000 2021 900,000 710,000 86,500 — 2022 780,000 640,000 86,500 — 2023 690,000 600,000 86,500 — As provided in the table above, we utilize a part of our firm transportation capacity to deliver gas and NGLs under the majority of these firm sales contracts. We have firm transportation contracts that require us to either ship products on said pipelines or pay demand charges for shortfalls. The minimum demand fees are reflected in our table of contractual obligations. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements and Contractual Obligations.” If our production quantities are insufficient to meet such commitments, we may purchase third party products and/or market our excess firm transportation capacity to third parties. Gathering and Compression Our exploration and development activities are supported by the natural gas gathering and compression assets of our subsidiary, Antero Midstream, as well as by third‑party gathering and compression arrangements. Unlike many producing basins in the United States, certain portions of the Appalachian Basin do not have sufficient midstream infrastructure to support the existing and expected increasing levels of production. Our relationship with Antero Midstream allows us to obtain the necessary gathering and compression capacity for our production and we have leveraged our relationship with Antero Midstream to support our growth. For the years ended December 31, 2017 and 2018, Antero Midstream spent approximately $346 million and $444 million, respectively, on gas gathering and compression infrastructure that services our production. Subject to pre-existing dedications and other third-party commitments, we have dedicated to Antero Midstream all of our current and future acreage in West Virginia and Ohio for gathering and compression services. As of December 31, 2018, Antero Midstream owned and operated 289 miles of gas gathering pipelines in the Marcellus Shale. We also have access to additional low‑pressure and high‑pressure pipelines owned and operated by third parties. As of December 31, 2018, Antero Midstream owned and operated 17 compressor stations and we utilized 12 additional third‑party compressor stations in the Marcellus Shale. The gathering, compression, and dehydration services provided by third parties are contracted on a fixed‑fee basis. As of December 31, 2018, Antero Midstream owned and operated 108 miles of low‑pressure and high‑pressure gathering pipelines in the Utica Shale, and Antero owned and operated 8 miles of high-pressure pipelines. As of December 31, 2018, Antero Midstream owned and operated two compressor stations and we utilized four additional third‑party compressor stations in the Utica Shale. Natural Gas Processing Many of our wells in the Marcellus and Utica Shales allow us to produce liquids-rich natural gas that contain a significant amount of NGLs. Liquids-rich natural gas must be processed, which involves the removal and separation of NGLs from the wellhead natural gas. NGLs are valuable commodities once removed from the natural gas stream in a cryogenic processing facility yielding y-grade liquids. Y-grade liquids are then fractionated, thereby breaking up the y-grade liquid into its key components. Fractionation refers to the process by which a NGLs y-grade stream is separated into individual NGLs products such as ethane, propane, normal butane, isobutane, and natural gasoline. Fractionation occurs by heating the y- grade liquids to allow for the separation of the component parts based on the specific boiling points of each product. Each of the individual products has its own market price. The combination of infrastructure constraints in the Appalachian region and low ethane prices has resulted in many producers “rejecting” rather than “recovering” ethane. Ethane rejection occurs when ethane is left in the wellhead gas stream when the gas is processed, rather than being extracted and sold as a liquid after fractionation. When ethane is left in the gas stream, the Btu content of the residue gas at the tailgate of the processing plant is higher. Producers generally elect to “reject” ethane when the price received for 12


  • Page 20

    Table of Contents the ethane in the gas stream is greater than the net price received for the ethane being sold as a liquid after fractionation. When ethane is recovered, the Btu content of the residue gas is lower, but a producer is then able to recover the value of the ethane sold as a separate product. Given the existing commodity price environment and the current limited ethane market in the northeast, we are currently rejecting the majority of the ethane obtained in the natural gas stream when processing our liquids‑rich gas. However, we realize a pricing upgrade when selling the remaining NGLs product stream at current prices. We may elect to recover more ethane when ethane prices result in a value for the ethane that is greater than the Btu equivalent residue gas and incremental recovery costs. Our first international ethane sales contract commenced in November 2018. As of December 31, 2018, we had contracted with MarkWest Energy Partners L.P. to provide cryogenic processing capacity for our Marcellus and Utica Shale production as follows: Antero Plant Contracted Firm Processing Processing Capacity Capacity Completion (MMcf/d) (MMcf/d) Status Marcellus Shale: Sherwood 1 200 200 In service Sherwood 2 200 200 In service Sherwood 3 200 200 In service Sherwood 4 200 200 In service Sherwood 5 200 200 In service Sherwood 6 200 200 In service Sherwood 7 200 200 In service Sherwood 8 200 200 In service Sherwood 9 200 200 In service Sherwood 10 200 200 In service Sherwood 11 200 200 In service Sherwood 12 200 200 2Q 2019* Sherwood 13 200 200 3Q 2019* Smithburg 1 200 200 1Q 2020* Marcellus Shale Total 2,800 2,800 Utica Shale: Seneca 1 200 150 In service Seneca 2 200 50 In service Seneca 3 200 200 In service Seneca 4 200 200 In service Utica Shale Total 800 600 * Anticipated in-service date Through Antero Midstream’s investment in the Joint Venture, Antero Midstream acquired a 50% non-operated equity interest in certain of the existing and future Sherwood gas processing plants. The Joint Venture also owns a 33 1/3% interest in a fractionation facility located at the Hopedale complex in Harrison County, Ohio. The Joint Venture’s processing investment began with the seventh plant at the Sherwood facility and continues through Sherwood 13 and Smithburg 1 on the table above. The Joint Venture provides processing services to Antero under a long-term, fixed-fee arrangement, subject to annual CPI-based adjustments. 13


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    Table of Contents Transportation and Takeaway Capacity We have entered into firm transportation agreements with various pipelines that enable us to deliver natural gas to the Midwest, Gulf Coast, Eastern Regional, and Mid-Atlantic markets. Our primary firm transportation commitments include the following: · We have several firm transportation contracts with pipelines that have capacity to deliver natural gas to the Chicago and Michigan markets. The Chicago directed pipelines include the Rockies Express Pipeline (“REX”), the Midwestern Gas Transmission pipeline (“MGT”), the Natural Gas Pipeline Company of America pipeline (“NGPL”), and the ANR Pipeline Company pipeline (“ANR”). o The firm transportation contract on REX provides firm capacity for 600,000 MMBtu per day and delivers gas to downstream contracts on MGT, NGPL, and ANR. We have 290,000 MMBtu per day of firm transportation on MGT. We have 310,000 MMBtu per day of firm transportation on NGPL. Both of these contracts deliver gas to the Chicago city gate area. In addition, we have 200,000 MMBtu per day of firm transportation on ANR to deliver natural gas to Chicago in the summer and Michigan in the winter. The Chicago and Michigan contracts expire at various dates from 2021 through 2035. · To access the Gulf Coast market and Eastern Regional markets, we have firm transportation contracts with various pipelines. These contracts include firm capacity on the Columbia Gas Transmission pipeline (“TCO”), Columbia Gulf Transmission pipeline (“Columbia Gulf”), Tennessee Gas Pipeline (“Tennessee”), Energy Transfer Rover Pipeline (“ET Rover”), ANR Pipeline (“ANR-Gulf”), Equitrans pipeline (“EQT”), and DTE Energy’s Stonewall Gas Gathering (“SGG”) and Appalachia Gathering System (“AGS”). This diverse portfolio of firm capacity gives us the flexibility to move natural gas to the local Appalachia market or other preferred markets with more favorable pricing. o We have several firm transportation contracts on TCO for volumes that total to approximately 581,000 MMBtu per day. Of the 581,000 MMBtu per day of firm capacity on TCO, we have the ability to utilize 530,000 MMbtu per day of firm capacity on Columbia Gulf, which provides access to the Gulf Coast markets. These contracts expire at various dates from 2021 through 2028. o We have a firm transportation contract with SGG for 900,000 MMBtu per day which transports gas from various gathering system interconnection points and the MarkWest Sherwood plant complex to the TCO WB System. We have a firm transportation contract with TCO to transport natural gas in the western and eastern direction on TCO’s WB system. The firm transportation contract on TCO’s WB system provides firm capacity in the western direction for 800,000 MMBtu per day. This west directed firm capacity provides access to the local Appalachia market and the Gulf Coast market via the Columbia Gulf or Tennessee pipelines. The firm transportation contract on TCO’s WB system also provides firm capacity in the eastern direction, which delivers natural gas to the Cove Point LNG facility, for 330,000 MMBtu per day. These contracts expire at various dates from 2033 through 2038. o We have a firm transportation contract for 790,000 MMBtu per day on Tennessee to deliver natural gas from the Broad Run interconnect on TCO’s WB system to the Gulf Coast market. This contract expires in 2033. o We have a firm transportation contract for 600,000 MMBtu per day on ANR-Gulf to deliver natural gas from West Virginia and Ohio to the U.S Gulf Coast market. This contract expires in 2045. o We have a firm transportation contract for 800,000 MMBtu per day on the ET Rover Pipeline which connects the Marcellus and Utica Shale assets to Midwest and Gulf Coast markets via our existing firm transportation on ANR Chicago and ANR Gulf. This contract expires in 2033. o We have firm transportation contracts for 250,000 MMBtu per day on EQT to deliver Marcellus natural gas to Tetco M2 and other various delivery points. These contracts expire at various dates from 2022 through 2025. o We have firm transportation contracts for 275,000 MMBtu per day on the DTE AGS to deliver Marcellus natural gas to TETCO M2 and other various local delivery points. These contracts expire in 2023. o We have firm transportation contracts for 700,000 MMBtu per day on MXP to deliver 517,000 MMBtu per day to TCO IPP and 183,000 MMBtu per day continues on GXP to Leach, Kentucky and deliver to the U.S. Gulf Coast. These contracts expire in 2033. 14


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    Table of Contents · We have a firm transportation contract for 20,000 Bbl per day on the Enterprise Products Partners ATEX pipeline (“ATEX”), to take ethane from Appalachia to Mont Belvieu, Texas. The ATEX firm transportation commitment expires in 2028. · We have a firm transportation contract for 11,500 Bbl per day on the Sunoco pipeline (or “Mariner East 2”) to take ethane from Houston, Pennsylvania to Marcus Hook, Pennsylvania. This contract began November 2018. We also have a firm transportation contract on Mariner East 2 to take a combination of 50,000 Bbl per day of propane and butane from Hopedale, Ohio to Marcus Hook, Pennsylvania which began February 2019. These contracts expire on the tenth anniversary from the in-service date. Mariner East 2 provides access to international markets via trans-ocean LPG carriers. Under firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements and Contractual Obligations” for information on our minimum fees for such contracts. Based on current projected 2019 annual production guidance, we estimate that we could incur annual net marketing costs of $0.175 per Mcfe to $0.225 per Mcfe in 2019 for unutilized transportation capacity depending on the amount of unutilized capacity that can be marketed to third parties or utilized to transport third party gas and capture positive basis differentials. Where permitted, we continue to actively market any excess capacity in order to offset minimum commitment fees. Water Handling and Treatment Operations On September 23, 2015, Antero contributed (i) all of the outstanding limited liability company interests of Antero Water LLC (“Antero Water”) to Antero Midstream and (ii) all of the assets, contracts, rights, permits and properties owned or leased by Antero and used primarily in connection with the construction, ownership, operation, use or maintenance of its advanced wastewater treatment facility in Doddridge County, West Virginia, to Antero Treatment LLC, a wholly-owned subsidiary of Antero Midstream. Our relationship with Antero Midstream allows us to obtain the necessary fresh and recycled water for use in our drilling and completion operations, as well as services to dispose of wastewater resulting from our operations. Antero Midstream owns two independent fresh water distribution systems that distribute fresh water from the Ohio River and several regional water sources, as well as recycled water from its water treatment facility, for well completion operations in the Marcellus and Utica Shales. These systems consist of permanent buried pipelines, movable surface pipelines and fresh water storage facilitates, as well as pumping stations to transport the fresh water throughout the pipeline networks. To the extent necessary, the surface pipelines are moved to well pads for service completion operations in concert with our drilling program. As of December 31, 2018, Antero Midstream had the ability to store 5.3 million barrels of fresh water in 37 impoundments located throughout our leasehold acreage in the Marcellus and Utica Shales. Due to the extensive geographic distribution of Antero Midstream’s water pipeline systems in both West Virginia and Ohio, it is able to provide water delivery services to neighboring oil and gas producers within and adjacent to our operating area, subject to commercial arrangements, while reducing water truck traffic. As of December 31, 2018, Antero Midstream owned and operated 127 miles of buried fresh water pipelines and 76 miles of movable surface fresh water pipelines in the Marcellus Shale, as well as 25 fresh water storage facilities equipped with transfer pumps. As of December 31, 2018, Antero Midstream owned and operated 55 miles of buried fresh water pipelines and 27 miles of movable surface fresh water pipelines in the Utica Shale, as well as 12 fresh water storage facilities equipped with transfer pumps. Antero Midstream also owns a wastewater treatment facility with a designed capacity of 60,000 barrel per day for the treatment of our flowback and produced water for subsequent use or sale for well completions. To date, the facility has run at reduced operating rates below the designed capacity and therefore not met certain completion milestones under the terms of the agreement between Antero Midstream and the construction contractor. Antero Midstream has made improvements to the facility’s design and anticipates an increase in wastewater treatment volumes during 2019 as compared to 2018 and has included the final milestone completion payments under the construction contract in its 2019 capital budget. Major Customers For the year ended December 31, 2018, sales to Mercuria Energy America, Inc. and Tenaska Marketing Ventures accounted for approximately 16% and 14% of our total product revenues, respectively. For the year ended December 31, 2017, sales to Tenaska Marketing Ventures and WGL Midstream accounted for approximately 22% and 15% of our total product revenues, respectively. For the year ended December 31, 2016, sales to Tenaska Marketing Ventures and WGL Midstream accounted for approximately 29% and 13% of our total product revenues, respectively. 15


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    Table of Contents Title to Properties We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, often in the case of undeveloped properties, cursory investigation of record title is made at the time of lease acquisition. Investigations are made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use, or affect the value of, the properties. Burdens on properties may include: · customary royalty interests; · liens incident to operating agreements and for current taxes; · obligations or duties under applicable laws; · development obligations under natural gas leases; or · net profits interests. Seasonality Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. Cold winters can significantly increase demand and price fluctuations. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the spring, summer and fall. This can also reduce seasonal demand fluctuations. Seasonal anomalies can also increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations. Competition The oil and natural gas industry is intensely competitive, and we compete with other companies in our industry that have greater resources than we do. Many of these companies not only explore for and produce natural gas, but also carry on refining operations and market petroleum and other products on a regional, national, or worldwide basis. These companies may be able to pay more for productive natural gas properties and exploratory prospects or define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit, and may be able to expend greater resources to attract and maintain industry personnel. In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas market prices. Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state, and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing natural gas properties. Regulation of the Oil and Natural Gas Industry General Our oil and natural gas operations are subject to extensive, and frequently changing, laws and regulations related to well permitting, drilling, and completion, and to the production, transportation and sale of natural gas, NGLs, and oil. We believe compliance with existing requirements will not have a materially adverse effect on our financial position, cash flows or results of operations. However, such laws and regulations are frequently amended or reinterpreted. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, federal agencies, the states, local governments, and the courts. We cannot predict when or whether any such proposals may become effective. Therefore, we are unable to predict the future costs or impact of compliance. The regulatory burden on the industry increases the cost of doing business and affects profitability. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers, and marketers with which we compete. 16


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    Table of Contents Regulation of Production of Natural Gas and Oil We own interests in properties located onshore in West Virginia and Ohio, and our production activities on these properties are subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. These statutes and regulations address requirements related to permits for drilling of wells, bonding to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, the plugging and abandonment of wells, venting or flaring of natural gas, and the ratability or fair apportionment of production from fields and individual wells. In addition, all of the states in which we own and operate properties have regulations governing environmental and conservation matters, including provisions for the handling and disposing or discharge of waste materials, the unitization or pooling of natural gas and oil properties, the establishment of maximum allowable rates of production from natural gas and oil wells, and the size of drilling and spacing units or proration units and the density of wells that may be drilled. Some states also have the power to prorate production to the market demand for oil and gas. The effect of these regulations is to limit the amount of natural gas and oil that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of natural gas, NGLs, and oil within its jurisdiction. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations. Regulation of Transportation of Natural Gas The transportation and sale, or resale, of natural gas in interstate commerce are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or NGPA, and regulations issued under those statutes. FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non‑discriminatory basis. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry. Gathering services, which occurs upstream of jurisdictional transmission services, are regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has not made any formal determinations with respect to any of our facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. The distinction between FERC‑regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case‑by‑case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally include various safety, environmental and, in some circumstances, nondiscriminatory‑take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future. Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Regulation of Sales of Natural Gas, NGLs, and Oil The prices at which we sell natural gas, NGLs, and oil are not currently subject to federal regulation and, for the most part, are not subject to state regulation. FERC, however, regulates interstate natural gas transportation rates, and terms and conditions of transportation service, which affects the marketing of the natural gas we produce, as well as the prices we receive for sales of our natural gas. Similarly, the price we receive from the sale of oil and NGLs is affected by the cost of transporting those products to market. FERC regulates the transportation of oil and liquids on interstate pipelines under the provision of the Interstate Commerce Act, the Energy Policy Act of 1992 and regulations issued under those statutes. Intrastate pipeline transportation of oil, NGLs, and 17


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    Table of Contents other products, is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. In addition, while sales by producers of natural gas and all sales of crude oil, condensate, and NGLs can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. With regard to our physical sales of these energy commodities and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC as described below, the U.S. Commodity Futures Trading Commission under Commodity Exchange Act, or CEA, and the Federal Trade Commission, or FTC. We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation. Should we violate the anti-market manipulation laws and regulations, we could be subject to fines and penalties as well as related third party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities. The Domenici Barton Energy Policy Act of 2005, or EPAct of 2005 amended the NGA to add an anti‑market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provided FERC with additional civil penalty authority. In Order No. 670, FERC promulgated rules implementing the anti‑market manipulation provision of the EPAct of 2005, which make it unlawful to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The anti‑market manipulation rules do not apply to activities that relate only to intrastate or other non‑jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non‑jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704 described below. Under the EPAct of 2005, FERC has the power to assess civil penalties of up to $1,000,000 per day for each violation of the NGA and the NGPA. In January 2017, FERC issued an order (Order No. 834) increasing the maximum civil penalty amounts under the NGA and NGPA to adjust for inflation. FERC may now assess civil penalties under the NGA and NGPA of up to $1,269,500 per violation per day. Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity. In November 2009, the FTC issued regulations pursuant to the Energy Independence and Security Act of 2007 intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to approximately $2 million (adjusted annually for inflation) per violation per day. Together with FERC, these agencies have imposed broad rules and regulations prohibiting fraud and manipulation in oil and gas markets and energy futures markets. Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete. Regulation of Environmental and Occupational Safety and Health Matters General Our operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health and the discharge of materials into the environment or otherwise relating to environmental protection. Violations of these laws can result in substantial administrative, civil and criminal penalties. These laws and regulations may require the acquisition of permits before drilling or other regulated activity commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines, govern the sourcing and disposal of water used in the drilling and completion process, limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas or areas with endangered or 18


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    Table of Contents threatened species restrictions, require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits, establish specific safety and health criteria addressing worker protection and impose substantial liabilities for pollution resulting from operations or failure to comply with applicable laws and regulations. In addition, these laws and regulations may restrict the rate of production. The following is a summary of the more significant existing environmental and occupational health and workplace safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our financial position, results of operations or cash flows. Hazardous Substances and Waste Handling The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In addition, despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses crude oil and natural gas, we generate materials in the course of our operations that may be regulated as hazardous substances based on their characteristics; however, we are unaware of any liabilities arising under CERCLA for which we may be held responsible that would materially and adversely affect us. The Resource Conservation and Recovery Act, or RCRA, and analogous state laws, establish detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the U.S. Environmental Protection Agency, or the EPA, or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, or under state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas exploration, development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. The EPA would be required to complete any rulemaking revising the Subtitle D criteria by 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as waste solvents, laboratory wastes and waste compressor oils that may become regulated as hazardous wastes if such wastes have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies. We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production activities for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including offsite locations, where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under our control. We are able to control directly the operation of only those wells with respect to which we act or have acted as operator. The failure of a prior owner or operator to comply with applicable environmental regulations may, in certain circumstances, be attributed to us as current owners or operators under CERCLA. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, regardless of fault, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or waste pit closure operations to prevent future contamination. 19


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    Table of Contents Water Discharges The Federal Water Pollution Control Act, or the Clean Water Act (the “CWA”), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or a state equivalent agency. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers. In September 2015, the EPA and U.S. Army Corps of Engineers issued a final rule defining the scope of the EPA’s and the Corps’ jurisdiction over waters of the U.S. (the “WOTUS rule”). Several legal challenges to the WOTUS rule followed, and the WOTUS rule was stayed nationwide in October 2015 pending resolution of the court challenges. In January 2018, the U.S. Supreme Court determined that federal district courts have jurisdiction to review the WOTUS rule; consequently, the previously filed district court cases have been allowed to proceed, resulting in a patchwork of implementation of the rule in 22 states (including Pennsylvania and Ohio), the District of Columbia, and the U.S. territories, and stay of the rule in 28 states (including West Virginia). On December 11, 2018, the EPA and the Corps proposed a new rule that would narrow federal jurisdictional reach compared to the WOTUS rule. Several Environmental groups have signaled their intent to challenge the proposed rule. As a result of these developments, future implementation of the WOTUS rule or any new rule is uncertain at this time. To the extent the WOTUS rule expands the scope of the CWA’s jurisdiction in areas where we operate, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which could delay the development of our natural gas and oil projects. Also, pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. Air Emissions The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as, for example, compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre‑approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants, the costs of which could be significant. The need to obtain permits has the potential to delay the development of our oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard, or NAAQS, for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards, and completed attainment/non-attainment designations in July 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Separately, in June 2016, the EPA finalized rules under the federal Clean Air Act regarding criteria for aggregating multiple sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities (such as tank batteries and compressor stations), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment. The EPA has also issued final rules under the Clean Air Act that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants programs. These final rules require, among other things, the reduction of volatile organic compound (“VOC”) emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of natural gas and oil projects and increase our costs of development and production, which costs could be significant. However, we do not believe that compliance with such requirements will have a material adverse effect on our operations. Regulation of “Greenhouse Gas” Emissions In response to findings that emissions of carbon dioxide, methane and other greenhouse gases, or GHGs, present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit 20


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    Table of Contents reviews for certain large stationary sources that are already major sources of criteria pollutant emissions regulated under the statute. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA for those emissions. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. For example, in December 2015, the EPA finalized rules that added new sources to the scope of the GHG monitoring and reporting rule. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. These changes to EPA’s GHG emissions reporting rule could result in increased compliance costs. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule. In June 2016, the EPA finalized new regulations, known as Subpart OOOOa, that establish emission standards for methane and volatile organic compounds from new and modified oil and natural gas production and natural gas processing and transmission facilities. The EPA’s rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. In addition, the rule package extends existing VOC standards under the EPA’s Subpart OOOO of the NSPS, or NSPS Quad O, to include previously unregulated equipment within the oil and natural gas source category. In June 2017, the EPA proposed to delay implementation of the 2016 methane rule, but in July 2017, the U.S. Court of Appeals for the District of Columbia Circuit ruled that such a stay was unlawful. In September 2018, the EPA proposed amendments to the 2016 standards that would relax the rule’s fugitive emissions monitoring requirements and expand exceptions to pneumatic pump requirements, among other changes. Various industry and environmental groups separately challenged both the methane requirements and the EPA’s attempts to delay implementation of the rules. In addition, in April 2018, several states filed a lawsuit that seeks to compel the EPA to issue methane performance standards for existing sources in the oil and natural gas source category. As a result of these developments, substantial uncertainty exists with respect to implementation of the EPA’s 2016 methane rule. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a possibility, and several states have separately imposed their own regulations on methane emissions from oil and gas production activities. Antero has developed a program to reduce and manage its methane and air emissions by: (1) monitoring the science of climate change and air quality, (2) addressing stakeholder inquiries regarding the Company’s position on climate change, methane emissions and air quality matters, (3) monitoring the Company’s measures to reduce methane and air emissions, and (4) overseeing development of methane and air emission reductions from activities, including implementation of best-management practices and new technology. We have been making efforts to reduce methane emissions since March 2005, when we engaged local community groups in Colorado regarding our former activities in the Piceance Basin in discussions on how to minimize air emission impacts from our operations. In addition, we have been performing green completions since before the EPA’s NSPS Quad O rules became effective in January 2015. In particular, we implemented green completions on our former Piceance Basin assets in Colorado in July 2011, using equipment that our personnel helped design. After initial testing confirming the viability and effectiveness of the units, we implemented their use in the Appalachian Basin Marcellus Shale play in 2012 and later in the Utica Shale play. We have a long history of managing methane emissions from our operations, as demonstrated by our early use of green completions. When we permit a facility, we install air pollution control equipment that meets the requirements of the NSPS and EPA Best Available Control Technology standards. The control equipment includes Vapor Recovery Towers (VRTs) and Vapor Recovery Units (VRUs), which capture methane emissions and direct them down a sales line. This technology allows us to recover a valuable product and reduce emissions. Additionally, residual storage tank emissions are controlled with vapor combustors that reduce methane emissions by 98%. We also install low-bleed pneumatic controllers which minimize methane emissions. Our methane and air emission control program also includes a Leak Detection and Repair (LDAR) program. Periodic inspections are conducted to minimize emissions by detecting leaks and repairing them promptly. The LDAR program inspections utilize a state-of-the-art Optical Gas Imaging (OGI) Forward Looking Infrared Radar (FLIR) camera to identify equipment leaks. In addition, our Operations group has a maintenance program in place, which includes cleaning, greasing and replacing thief hatch seals and worn equipment to prevent leaks from occurring. Our efforts to date have resulted in a declining volume of methane emissions based on the decreasing number of leaks detected by our LDAR program. 21


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    Table of Contents In 2017, Antero joined the EPA Natural Gas Star Program. The EPA Natural Gas STAR Program provides a framework for companies with U.S. oil and gas operations to implement methane reduction technologies and practices and document their emission reduction activities. By joining the program, Antero committed to: 1) evaluate its methane emission reduction opportunities, 2) implement methane reduction projects where feasible, and 3) annually report methane emission reduction actions to the EPA. Recent methane emission reduction initiatives by Antero and Antero Midstream have included the following: 1) Facility LDAR inspections were conducted at twice the frequency required by regulations during 2018. 2) A burner management system that optimizes the efficiency of our combusters. 3) Implementation of three stages of pressure control on our storage tanks. 4) Improvements to our vapor recovery system such that we now incorporate up to three stages of vapor recovery in our process. 5) Low pressure separators (Green Completion Units) are used during initial well flowback operations to recover methane and send it down a sales line. This enables us to recover a salable product and reduce methane emissions during completion operations. 6) Pressure relief valves are tested and repaired or replaced as necessary, reducing the amount of methane that is accidently released. 7) Air actuated pneumatic controllers are used at the majority of our earlier stations and all of our new stations. The remaining stations that are not currently air actuated will be retrofitted to air. This reduces methane emissions that occur from using natural gas-operated pneumatic controllers. 8) Gas-operated compressor engine starters were replaced with air or electric starters. This reduces methane emissions that occur when using gas-operated compressor engine starters. 9) Optimized glycol recirculation rates are utilized with flash tank separators on glycol dehydration units. 10) Hot taps and pipeline pump down techniques that lower gas line pressure before maintenance are utilized. 11) Balanced well drill outs, which minimize the potential for venting of gas from our wells during the well completion process. During 2019, Antero’s methane emission reduction efforts will also include the following activities: 1) The GHG/Methane Reduction team which was established in 2018 and will begin meeting quarterly in 2019 to review emerging methane detection and quantification technologies applicable to exploration and production and Midstream Operations. 2) We periodically plug and abandon certain older vertical wells that were acquired in conjunction with property acquisitions. Plugging and abandoning older, low producing wells can reduce methane emissions. 3) Reviewing the option to replace existing gas-operated pneumatic controllers with air or electrically- operated controllers in exploration and production operations. 4) Exploring the use of lockdown thief hatches on storage tanks. These hatches reduce methane emissions. 5) Exploring applications for reducing methane emissions associated with rod packing systems in VRU compressors. 6) Reviewing options to recover gas from Midstream pigging operations. 7) Injecting blowdown gas from Midstream Operations into the fuel system at all new compressor stations. 8) Exploring the use of electric compression for new stations in our midstream operations, where feasible. 9) The replacement of TEG dehydrators with desiccant dehydrators for new stations, where feasible. 22


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    Table of Contents Antero continues to assess various opportunities for emission reductions. However, we cannot guarantee that we will be able to implement any of the opportunities that we may review or explore. For any such opportunities that we do choose to implement, we cannot guarantee that we will be able to implement them within a specific timeframe. While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of federal legislation in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could also adversely affect demand for the oil and natural gas we produce and lower the value of our reserves. Depending on the severity of any such limitations, the effect on the value of our reserves could be significant. On an international level, the United States is one of almost 200 nations that, in December 2015, agreed to an international climate change agreement in Paris, France, that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets (“Paris Agreement”). The Paris Agreement was signed by the United States in April 2016 and entered into force on November 4, 2016; however, the Paris Agreement does not impose any binding obligations on its participants. In August 2017, the U.S. Department of State officially informed the United Nations of the United States’ intent to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil and gas will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Finally, it should be noted that a number of scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other extreme climatic events; if any such effects were to occur, they have the potential to cause physical damage to our assets or affect the availability of water and thus could have an adverse effect on our exploration and production operations. Hydraulic Fracturing Activities Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure through a cased and cemented wellbore into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations, as does most of the domestic oil and natural gas industry. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act, or the SDWA, over certain hydraulic fracturing activities involving the use of diesel fuels and in February 2014 issued permitting guidance regarding such activities. Also, in May 2014, the EPA proposed rules under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; however, to date, no further action has been taken on the proposal. In addition, the EPA finalized rules in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Because the report did not find a direct link between hydraulic fracturing itself and contamination of 23


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    Table of Contents groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. For example, in July 2015, the Ohio Department of Natural Resources issued final rules for horizontal drilling well-pad construction. The Ohio Legislature has also adopted a law requiring oil and natural gas operators to disclose chemical ingredients used to hydraulically fracture wells and to conduct pre-drill baseline water quality sampling of certain water wells near a proposed horizontal well. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Some states and municipalities have banned and others seek to ban hydraulic fracturing altogether. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells. Occupational Safety and Health Act We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended, or OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities, and citizens. Endangered Species Act The federal Endangered Species Act, or ESA, provides for the protection of endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We conduct operations on natural gas and oil leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service, or the USFWS, may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for natural gas and oil development. Moreover, as a result of a settlement, the USFWS was required to make a determination as to whether more than 250 species classified as endangered or threatened should be listed under the ESA by the completion of the agency’s 2017 fiscal year. For example, in April 2015, the USFWS listed the northern long- eared bat, whose habitat includes the areas in which we operate, as a threatened species under the ESA. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases. Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. We did not have any material capital or other non‑recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2018, nor do we anticipate that such expenditures will be material in 2019. Employees As of December 31, 2018, we had 623 full‑time employees, including 43 employees in executive, finance, treasury, legal, and administration, 24 in information technology, 22 in geology, 251 in production and engineering, 152 in midstream and water, 72 in land, and 59 in accounting and internal audit. Our future success will depend partially on our ability to attract, retain, and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory. We utilize the services of independent contractors to perform various field and other services. 24


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    Table of Contents Address, Internet Website and Availability of Public Filings Our principal executive offices are located at 1615 Wynkoop Street, Denver, Colorado 80202 and our telephone number is (303) 357‑7310. Our website is located at www.anteroresources.com. We furnish or file with the Securities and Exchange Commission (the “SEC”) our Annual Reports on Form 10‑K, our Quarterly Reports on Form 10‑Q, and our Current Reports on Form 8‑K. We make these documents available free of charge at www.anteroresources.com under the “Investors Relations” link as soon as reasonably practicable after they are filed or furnished with the SEC. Information on our website is not incorporated into this Annual Report on Form 10‑K or our other filings with the SEC and is not a part of them. Item 1A. Risk Factors Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10‑K, actually occur, our business, financial condition or results of operations could suffer. Natural gas, NGLs, and oil prices are volatile. A substantial or extended decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments. The prices we receive for our natural gas, NGLs, and oil production heavily influence our revenue, profitability, access to capital and future rate of growth. Natural gas, NGLs, and oil are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for these commodities have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following: · worldwide and regional economic conditions impacting the global supply and demand for natural gas, NGLs and oil; · the price and quantity of imports of foreign oil, natural gas and NGLs, including liquefied natural gas; · the price and quantity of export of natural gas and oil, including liquefied natural gas, and NGLs; · political conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia; · the level of global exploration and production; · the level of global inventories; · prevailing prices on local price indexes in the areas in which we operate; · localized and global supply and demand fundamentals and transportation availability; · weather conditions; · technological advances affecting energy consumption; · the price and availability of alternative fuels; and · domestic, local and foreign governmental regulation and taxes. Natural gas prices are affected by storage levels, weather, and production levels. In late 2014, natural gas prices in the US declined as a result of several factors including increased production by producers. Although prices have recovered periodically since then with spikes in January 2018 and November 2018, prices remain below pre-2014 levels for natural gas. NGL prices have generally fluctuated along with oil prices. Oil prices precipitously declined in 2014 from approximately $100 per BBL to under $30 per BBL in early 2016. Oil prices have recovered periodically since then, reaching the mid $70 per BBL range in 2018, but then again 25


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    Table of Contents declined in late 2018 to below $50 per BBL as production increases from the United States and other oil producing countries led to a return of market concern regarding increasing global oil stocks and potential future supply and demand imbalances. Lower commodity prices reduce our product revenues, profitability, and our ability to borrow. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices may also reduce the amount of natural gas, NGLs and oil that we can produce economically. If commodity prices decrease, a significant portion of our exploration and development projects could become uneconomic. This may result in significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. Drilling for and producing oil and gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. Our future financial condition and results of operations will depend on the success of our exploration, development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable hydrocarbons. Our decisions to purchase, explore, or develop prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “Item 1A. — Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following: · prolonged declines in natural gas, NGLs, and oil prices; · limitations in the market for natural gas, NGLs, and oil; · delays imposed by, or resulting from, compliance with regulatory requirements; · pressure or irregularities in geological formations; · shortages of, or delays in, obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities; · equipment failures or accidents; · adverse weather conditions, such as blizzards, tornados, hurricanes and ice storms; · issues related to compliance with environmental regulations; · environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment; · limited availability of financing at acceptable terms; and · mineral interest title problems. Certain of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, environmental contamination or loss of wells and regulatory fines or penalties. Properties that we decide to drill may not yield natural gas or oil in commercially viable quantities. Properties that we decide to drill that do not yield natural gas or oil in commercially viable quantities will adversely affect our financial condition, results of operations, and cash flows. There is no way to predict in advance of drilling and testing whether any particular prospect will yield natural gas or oil in sufficient quantities to recover drilling or completion costs or to be economically 26


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    Table of Contents viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether natural gas or oil will be present or, if present, whether natural gas or oil will be present in commercial quantities. We cannot make any assurances that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including: · unexpected drilling conditions; · mineral interest title problems; · pressure or lost circulation in formations; · equipment failure or accidents; · adverse weather conditions; · compliance with environmental and other governmental or contractual requirements; and · increase in the cost of, or shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services. Market conditions or operational impediments may hinder our access to natural gas, NGLs, and oil markets or delay our production. Market conditions or the unavailability of satisfactory natural gas, NGLs, and oil transportation arrangements may hinder our access to natural gas, NGLs, and oil markets or delay our production. The availability of a ready market for our natural gas and oil production depends on a number of factors, including the demand for and supply of natural gas, NGLs, and oil and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and other transportation services owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of natural gas, NGLs, and oil pipelines or gathering or processing system capacity or third-party transportation services. In addition, if natural gas, NGLs, or oil quality specifications for the pipelines with which we connect change so as to restrict our ability to transport our production, our access to natural gas, NGLs, and oil markets could be impeded. If our production becomes shut in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market. 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. At December 31, 2018, 42% of our total estimated proved reserves were classified as proved undeveloped. Our approximately 7.6 Tcfe of estimated proved undeveloped reserves will require an estimated $3.3 billion of development capital over the next five years. Moreover, the development of probable and possible reserves will require additional capital expenditures and such reserves are less certain to be recovered than proved reserves. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV‑10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves. Our exploration and development projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our oil and gas reserves. The oil and gas industry is capital intensive. We make, and expect to continue to make, substantial capital expenditures for the exploration, development, production, and acquisition of oil and gas reserves. Our cash flow used in investing activities related to drilling, completions, and land expenditures was approximately $1.7 billion in 2018. Our board of directors has approved a capital budget for 2019 of $1.2 billion to $1.4 billion that includes $1.1 billion to $1.25 billion for drilling and completion and $75 million to $100 million for leasehold expenditures. Our capital budget excludes acquisitions. We expect to fund these capital expenditures with 27


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    Table of Contents cash generated by operations and borrowings under our revolving credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The actual amount and timing of our future capital expenditures may differ materially from our capital budget as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological, and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. For additional discussion of the risks regarding our ability to obtain funding, please read “Item 1A. Risk Factors – The borrowing base under our revolving credit facility may be reduced if commodity prices decline, which could hinder or prevent us from meeting our future capital needs.” The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions. Our cash flow from operations and access to capital are subject to a number of variables, including: · our proved reserves; · the level of hydrocarbons we are able to produce from existing wells; · the prices at which our production is sold; · our ability to acquire, locate and produce new reserves; · the value of our commodity derivative portfolio; and · our ability to borrow under our revolving credit facility, including any potential decrease in the borrowing base. If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower natural gas, NGLs, and oil prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, financial condition and results of operations. Certain of our stockholders have investments in our affiliates that may conflict with the interests of other stockholders. Certain funds affiliated with Warburg, certain funds affiliated with Yorktown, Paul M. Rady and Glen C. Warren, Jr. (collectively, the “Sponsors”) collectively own 100% of the general partner of, and a majority of the outstanding common shares representing limited partner interest in, Antero Midstream GP LP (“AMGP”), the owner of IDR LLC, the holder of the IDRs in Antero Midstream. Messrs. Rady and Warren also own a portion of the Series B Units in IDR LLC. Affiliates of Warburg and Yorktown, Mr. Rady and Mr. Warren serve as members of the board of directors of AMGP’s general partner and board of directors of Antero Midstream’s general partner, and each of Warburg and Yorktown are controlled in part by individuals who serve as members of the board of directors of AMGP’s general partner and the board of directors of Antero Midstream’s general partner. The Sponsors also own common units representing limited partner interests in Antero Midstream and shares of our common stock. As a result of their investments in AMGP, IDR LLC and Antero Midstream, the Sponsors may have conflicting interests with other stockholders. These conflicts of interest could arise in the future between us, on the one hand, and the Sponsors, on the other hand, regarding, among other things, decisions related to our financing, capital expenditures, and growth plans, decisions to modify or limit the IDRs in the future, the terms of our agreements with Antero Midstream and AMGP and their respective subsidiaries and the pursuit of potentially competitive business activities or business opportunities. We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful. Our ability to make scheduled payments on, or to refinance, our indebtedness obligations, including our revolving credit facility and our senior notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness, including the senior notes. 28


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    Table of Contents If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance our indebtedness, including the senior notes. Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets, including the market for senior unsecured notes, and our financial condition at such time. Any refinancing of our indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments, including the indentures governing our senior notes, may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our revolving credit facility and the indentures governing our senior notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. The borrowing base under our revolving credit facility may be reduced if commodity prices decline, which could hinder or prevent us from meeting our future capital needs. The borrowing base under our revolving credit facility is currently $4.5 billion, and lender commitments under our revolving credit facility are $2.5 billion. Our borrowing base is redetermined by the lenders each April based on certain factors, including our reserves and hedge position, with the next borrowing base redetermination scheduled to occur in April 2019. Our borrowing base may decrease as a result of a decline in natural gas, NGLs, or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for any other reason. We cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, we may be unable to meet our obligations as they come due and could be required to repay any indebtedness in excess of the redetermined borrowing base. In addition, we may be unable to access the equity or debt capital markets, including the market for senior unsecured notes, to meet our obligations. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out our business plan, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness. We may be unable to access the equity or debt capital markets, including the market for senior unsecured notes, to meet our obligations. Declines in commodity prices may cause the financial markets to exert downward pressure on stock prices and credit capacity for companies throughout the energy industry. For example, throughout much of 2015 and 2016, the market for senior unsecured notes was unfavorable for high-yield issuers such as us. Our plans for growth require regular access to the capital and credit markets, including the ability to issue senior unsecured notes. Although the market for high- yield debt securities improved in the latter part of 2016 and intermittently throughout 2017 and 2018, if the high-yield market deteriorates, or if we are unable to access alternative means of debt or equity financing on acceptable terms, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out our business plan, which could have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness. Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities. Our revolving credit facility contains a number of significant covenants (in addition to covenants restricting the incurrence of additional indebtedness), including restrictive covenants that may limit our ability to, among other things: · sell assets; · make loans to others; · make investments; · enter into mergers; · make certain payments; · hedge future production; · incur liens; and · engage in certain other transactions without the prior consent of the lenders. 29


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    Table of Contents The indentures governing our senior notes contain similar restrictive covenants. In addition, our revolving credit facility requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. These restrictions, together with those in the indentures governing our senior notes, may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the indentures governing our senior notes and our revolving credit facility impose on us. Our revolving credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine on an annual basis based upon projected revenues from the natural gas properties and commodity derivatives securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. If the requisite number of lenders do not agree to an increase, then the borrowing base will be the lowest borrowing base acceptable to such lenders. For additional discussion of the risks regarding our ability to obtain funding under our revolving credit facility, please read “Item 1A. Risk Factors – A sustained decline of oil and natural gas prices may affect our ability to obtain funding, obtain funding on acceptable terms or obtain funding under our revolving credit facility. This may hinder or prevent us from meeting our future capital needs.” A breach of any covenant in our revolving credit facility would result in a default under that agreement after any applicable grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under the facility and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us. Increases in interest rates could adversely affect our business. Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. For example, during 2018, we had estimated average outstanding borrowings under our revolving credit facilities of approximately $1.2 billion, and the impact of a 1.0% increase in interest rates on this amount of indebtedness would result in increased interest expense for that period of approximately $12 million and a corresponding decrease in our cash flows and net income before the effects of income taxes. Disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results. Currently, we receive significant incremental cash flows as a result of our hedging activity. To the extent we are unable to obtain future hedges at effective prices consistent with those we have received to date and natural gas prices do not improve, our cash flows may be adversely impacted. Additionally, if development drilling costs increase significantly in the future, our hedged revenues may not be sufficient to cover our costs. To achieve more predictable cash flows and reduce our exposure to downward price fluctuations, as of December 31, 2018, we had entered into forward swap contracts and collars for approximately 2.0 Tcfe of our projected natural gas, NGLs, and oil production through December 31, 2023. Historically, we have realized a significant benefit from our hedge positions. For example, for the years ended December 31, 2017 and 2018, we received approximately $964 million and $613 million, respectively, in revenues from cash settled derivatives pursuant to our hedging arrangements, including $750 million and $370 million, respectively, for certain natural gas hedges that were monetized prior to their contractual settlement dates during the years ended December 31, 2017 and 2018. Many of the hedge agreements that resulted in these realized gains for the years ended December 31, 2017 and 2018 were executed at times when spot and future prices were higher than prices that we are currently able to obtain in the futures market, and the prices at which we have been able to hedge future production have decreased as a result. Sustained weaknesses in commodity prices adversely affect our ability to hedge future production. If we are unable to enter into new hedge contracts in the future at favorable pricing and for sufficient volumes, our financial condition and results of operations could be materially adversely affected. Additionally, since we have financial derivatives in place in order to hedge against price declines for a significant part of our estimated future production, we have fixed or limited a significant part of our overall future revenues. Approximately 70% of our estimated production for 2019 is hedged through either forward swaps, basis swaps, or collars. If development drilling costs increase significantly because of inflation, increased demand for oilfield services, increased costs to comply with regulations governing our industry or other factors, the payments we receive under these derivative contracts may not be sufficient to cover our costs. 30


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    Table of Contents Our derivative activities could result in financial losses or could reduce our earnings. In certain circumstances, we may have to make cash payments under our hedging arrangements and these payments could be significant. To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of natural gas, NGLs, and oil we enter into derivative instrument contracts for a portion of our estimated future natural gas production. At December 31, 2018, derivative instruments used for hedging include fixed‑price swap agreements, basis differential swap agreements, and collar agreements that mature at various dates through 2023 and cover approximately 2.0 Tcf of our projected natural gas production. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments. Derivative instruments also expose us to the risk of financial loss in some circumstances, including when: · the counterparty to the derivative instrument defaults on its contractual obligations; · there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or · there are issues with regard to legal enforceability of such instruments. The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil, NGLs and natural gas prices, and interest rates. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for natural gas, NGLs, and oil, which could also have an adverse effect on our financial condition. If natural gas, NGLs, or oil prices upon settlement of our derivative contracts exceed the price at which we have hedged our commodities, we will be obligated to make cash payments to our hedge counterparties, which could, in certain circumstances, be significant. Our hedging transactions expose us to counterparty credit risk and may become more costly or unavailable to us. As of December 31, 2018, the estimated fair value of our commodity derivative contracts was approximately $607 million (excluding short-term commodity derivatives related to our marketing activities), including the following values by bank counterparty: Morgan Stanley - $115 million; JP Morgan - $102 million; Scotiabank - $97 million; Citigroup - $91 million; Wells Fargo - $80 million; Canadian Imperial Bank of Commerce - $51 million; BNP Paribas - $24 million; Bank of Montreal - $14 million; Toronto Dominion - $8 million; PNC - $8 million; SunTrust - $7 million; Natixis - $7 million; and Capital One - $3 million. Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. In addition, recent proposals have been made by U.S. regulators which would implement a new approach for calculating the exposure amount of derivative contracts under the applicable agencies’ regulatory capital rules, referred to as the standardized approach for counterparty credit risk or SA-CCR. If adopted as proposed, certain financial institutions would be required to comply with the new SA-CCR rules beginning on July 1, 2020 and the rules could significantly increase the capital requirements for certain participants in the over-the-counter derivatives market in which we participate. These increased capital requirements could result in significant additional costs being passed through to end-users like us or reduce the number of participants or products available to us in the over-the-counter derivatives market. The effects of these regulations could reduce our hedging opportunities, or substantially increase the cost of hedging, which could adversely affect our business, financial condition and results of operations. We are required to pay fees to our service providers based on minimum volumes under long-term contracts regardless of actual volume throughput. We have various firm transportation, gas processing, gathering and compression service and water handling and treatment agreements in place, each with minimum volume delivery commitments. Lower commodity prices may lead to reductions in our drilling program, which may result in insufficient production to fully utilize our firm transportation and processing capacity. Our firm transportation agreements expire at various dates from 2021 to 2058, our gas processing, gathering, and compression services agreements expire at various dates from 2020 to 2037, and our water services agreement expires in 2035. We are obligated to pay fees on minimum volumes to our service providers regardless of actual volume throughput. As of December 31, 2018, our long‑term 31


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    Table of Contents contractual obligations under agreements with minimum volume commitments totaled over $18.0 billion over the term of the contracts. If we have insufficient production to meet the minimum volumes, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results of operations. Based on current projected 2019 annual production guidance, we estimate that we could incur annual net marketing costs of $0.175 per Mcfe to $0.225 per Mcfe in 2019 for unutilized transportation capacity depending on the amount of unutilized capacity that can be marketed to third parties or utilized to transport third party gas and capture positive basis differentials. Additionally, in years subsequent to 2019, our commitments and obligations under firm transportation agreements continue to increase and our net marketing expense could increase depending on utilization of our transportation capacity based on future production and how much, if any, future excess transportation can be marketed to third parties. We may be limited in our ability to choose gathering operators, processing and fractionation services providers and water services providers in our areas of operations pursuant to our agreements with Antero Midstream. Pursuant to the gas gathering and compression agreement that we have entered into with Antero Midstream, we have dedicated the gathering and compression of all of our current and future natural gas production in West Virginia, Ohio and Pennsylvania to Antero Midstream, so long as such production is not otherwise subject to a pre‑existing dedication. Further, pursuant to the right of first offer agreement that we have entered into with Antero Midstream, Antero Midstream has a right to bid to provide certain processing and fractionation services in respect of all of our current and future gas production (as long as it is not subject to a pre‑existing dedication) and will be entitled to provide such services if its bid matches or is more favorable to us than terms proposed by other parties. As a result, we will be limited in our ability to use other gathering and compression operators in West Virginia, Ohio and Pennsylvania, even if such operators are able to offer us more efficient service. We will also be limited in our ability to use other processing and fractionation services providers in any area to the extent Antero Midstream is able to offer a competitive bid. Pursuant to the Water Services Agreement that we have entered into with Antero Midstream, we have dedicated the provision of fresh water and wastewater services in defined service areas in Ohio and West Virginia to Antero Midstream. Additionally, the Water Services Agreement provides Antero Midstream with a right of first offer on any future areas of operation outside of those defined areas. As a result, we will be limited in our ability to use other water services providers in the dedication areas of Ohio and West Virginia or other future areas of operation, even if such providers are able to offer us more favorable pricing or more efficient service. If additional takeaway pipelines under construction or other pipeline projects are not completed, our future growth may be limited. We have secured sufficient long-term firm takeaway capacity on major pipelines that are in existence or currently under construction in each of our core operating areas to accommodate our current development plans; however, any failure of any pipeline under construction to be completed, or any unavailability of existing takeaway pipelines, could cause us to curtail our future development and production plans, which could adversely affect our business, financial condition and results of operations. Our ability to produce oil and gas economically and in commercial quantities is dependent on the availability of adequate supplies of water for drilling and completion operations and access to Antero Midstream’s Clearwater Facility and other water and waste disposal or recycling facilities and services at a reasonable cost and in accordance with applicable environmental rules. Restrictions on our ability to obtain water or dispose of produced water and other waste may have an adverse effect on our financial condition, results of operations and cash flows. The hydraulic fracture stimulation process on which we depend to produce commercial quantities of oil and gas requires the use and disposal of significant quantities of water. The availability of Antero Midstream’s Clearwater Facility and other disposal alternatives to receive all of the water produced from our wells may affect our production. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, or to timely obtain water sourcing permits or other rights, could adversely impact our operations. Additionally, the imposition of new environmental initiatives and regulations could include restrictions on our ability to obtain water or dispose of waste and adversely affect our business and operating results. 32


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    Table of Contents Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure through a cased and cemented wellbore into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations, as does most of the domestic oil and natural gas industry. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and issued permitting guidance in February 2014 regarding such activities. Also, in May 2014, the EPA proposed rules under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; however, to date, no further action has been taken on the proposal. In addition, the EPA finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Because the report did not find a direct link between hydraulic fracturing and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. For example, in July 2015, the Ohio Department of Natural Resources issued final rules for horizontal drilling well-pad construction. The Ohio legislature has also adopted a law requiring oil and natural gas operators to disclose chemical ingredients used to hydraulically fracture wells and to conduct pre-drill baseline water quality sampling of certain water wells near a proposed horizontal well. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Some states and municipalities have banned and others seek to ban hydraulic fracturing altogether. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells. Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The process of estimating natural gas and oil reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect our estimated quantities and present value of our reserves. In order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as realized prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Actual future production, realized prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust our reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control. 33


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    Table of Contents Investors should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from our reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. Our identified potential well locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill our potential well locations. Our management team has specifically identified and scheduled certain well locations as an estimation of our future multi‑year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas, NGLs, and oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, unitization agreements, lease acquisitions, surface agreements, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other potential well locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified. For more information on our future potential acreage expirations, see “Item 1. Business and Properties—Our Properties and Operations—Acreage—Undeveloped Acreage Expirations.” As of December 31, 2018, we had 3,734 identified potential horizontal well locations located in our proved, probable, and possible reserve base. As a result of the limitations described above, we may be unable to drill many of our potential well locations. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations. For more information on our identified potential well locations, see “Item 1. Business and Properties—Our Properties and Operations— Estimated Proved Reserves—Identification of Potential Well Locations.” Approximately 73% of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income. Approximately 73% of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. In addition, approximately 43% and 50% of our natural gas leases related to our Marcellus and Utica acreage, respectively, require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage. For more information on our future potential acreage expirations, see “Item 1. Business and Properties—Our Properties and Operations—Acreage—Undeveloped Acreage Expirations.” The standardized measure of discounted future net cash flows from our proved reserves is not the same as the current market value of our estimated natural gas, NGLs and oil reserves. Investors should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated natural gas, NGLs and oil reserves. In accordance with SEC requirements, we based the discounted future net cash flows from our proved reserves on the twelve month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net cash flows from our properties will be affected by factors such as the actual prices we receive for natural gas, NGLs and oil, the amount, timing and cost of actual production and changes in governmental regulations or taxation. In addition, the 10% discount factor we use when calculating the standardized measure is based on SEC guidelines, and may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. 34


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    Table of Contents Our producing properties are concentrated in the Appalachian Basin, making us vulnerable to risks associated with operating in one major geographic area. Our producing properties are geographically concentrated in the Appalachian Basin in West Virginia and Ohio. At December 31, 2018, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, water shortages or other drought related conditions or interruption of the processing or transportation of natural gas, NGLs, or oil. Interruptions in operations at the Joint Venture’s or other third-party processing facilities may adversely affect our business, financial condition and results of operations. We have agreements with processing facilities, including those owned by the Joint Venture and other third parties, to accommodate our current operations as well as future development plans. Any significant interruptions at these facilities could cause us to curtail our future development and production plans, which could adversely affect our business, financial condition and results of operations. The operations of the processing facilities could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within the operator’s control, such as: · unscheduled turnarounds or catastrophic events, including damages to facilities, related equipment and surrounding properties caused by earthquakes, tornadoes, hurricanes, floods, fires, severe weather, explosions and other natural disasters; · restrictions imposed by governmental authorities or court proceedings; · labor difficulties that result in a work stoppage or slowdown; · disruption in the supply of power, water and other resources necessary to operate the facilities; · damage to the facilities resulting from NGLs that do not comply with applicable specifications; and · inadequate fractionation capacity or market access to support production volumes, including lack of availability of rail cars, barges, trucks and pipeline capacity, or market constraints, including reduced demand or limited markets for certain NGL products. Our failure to develop, obtain, access or maintain the necessary infrastructure to successfully deliver natural gas, NGLs and oil to market may adversely affect our business, financial condition or results of operations. Our delivery of natural gas, NGLs and oil depends upon the availability, proximity and capacity of pipelines, other transportation facilities and gathering and processing and fractionation facilities and the availability of other third-party transportation services. The capacity of transmission, gathering and processing and fractionation facilities and availability of third-party transportation services may be insufficient to accommodate potential production from existing and new wells, which may result in substantial discounts in the prices we receive for our natural gas, NGLs and oil. While our investment in midstream infrastructure through Antero Midstream is intended to address access to and potential curtailments on existing midstream infrastructure, we also deliver to and are served by third-party natural gas, NGLs and oil transmission, gathering, processing, storage and fractionation facilities and transportation services that are limited in number, geographically concentrated and subject to significant risks, including the availability of capital, materials and qualified contractors and work force, as well as weather conditions, natural gas, NGLs and oil price volatility, delays in obtaining permits and other government approvals, title and property access problems, geology, public opposition to infrastructure development, compliance by third parties with their contractual obligations to us and other factors. An extended interruption of access to or service from our or third-party pipelines and facilities or transportation services for any reason, including cyber-attacks on such pipelines and facilities or service interruptions due to gas quality, could result in adverse consequences to us, such as delays in producing and selling our natural gas, NGLs and oil. In such an event, we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell our production at prices lower than market prices or at prices lower than we currently project, all of which could adversely affect our business, financial condition and results of operations. 35


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    Table of Contents We may incur losses as a result of title defects in the properties in which we invest. It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. Leases in the Appalachian Basin are particularly vulnerable to title deficiencies due to the long history of land ownership in the area, resulting in extensive and complex chains of title. Additionally, there are claims against us alleging that certain acquired leases that are held by production are invalid due to production from the producing horizons being insufficient to hold title to the formation rights that we have purchased. The existence of a material title deficiency can render a lease worthless and can adversely affect our financial condition, results of operations, and cash flows. While we do typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property. If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write‑downs of the carrying values of our properties. Accounting rules require that we periodically review the carrying value of our properties for possible impairment if the estimated future undiscounted cash flows are less than the carrying value of our properties. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write-down the carrying value of our properties. A write-down constitutes a non‑cash charge to earnings. We may incur significant impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. Unless we replace our reserves with new reserves and develop those reserves, our reserves and, eventually, production will decline, which would adversely affect our future cash flows and results of operations. Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploration and development activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future natural gas reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected. Conservation measures and technological advances could reduce demand for oil and natural gas. Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows. The inability of our significant customers to meet their obligations to us may adversely affect our financial results. In addition to credit risk related to receivables from commodity derivative contracts, our principal exposures to credit risk are through the following: commodity derivative contracts ($607 million at December 31, 2018); the sale of our oil and gas production ($440 million at December 31, 2018) which we market to energy companies, end users, and refineries; the marketing of our excess firm transportation capacity ($34 million at December 31, 2018); and joint interest receivables ($21 million at December 31, 2018). Joint interest receivables arise from entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leased properties on which we drill. We can do very little to choose who participates in our wells. We are also subject to credit risk due to concentration of our natural gas receivables with several significant customers. The largest purchaser of our natural gas during the twelve months ended December 31, 2018 accounted for approximately 16% of our product revenues. We do not require all of our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. 36


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    Table of Contents Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities. We may incur significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our exploration, development and production activities. These delays, costs and liabilities could arise under a wide range of federal, regional, state and local laws and regulations relating to protection of the environment and occupational health and workplace safety, including regulations and enforcement policies that have tended to become increasingly strict over time resulting in longer waiting periods to receive permits and other regulatory approvals. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. Strict, joint and several liabilities may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental and occupational health and workplace safety impacts of our operations. We have been named from time to time as a defendant in litigation related to such matters. For example, we have been named as the defendant in separate lawsuits in West Virginia in which the plaintiffs have alleged that our oil and natural gas activities exposed them to hazardous substances and damaged their properties. Also, new laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we were not able to recover the resulting costs through insurance or increased revenues, our business, financial condition or results of operations could be adversely affected. We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks. We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition, results of operations, or cash flows. Our natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing natural gas, including the possibility of: · environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination; · abnormally pressured formations; · mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse; · fires, explosions and ruptures of pipelines; · personal injuries and death; · natural disasters; and · terrorist attacks targeting natural gas and oil related facilities and infrastructure. Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for: · injury or loss of life; · damage to and destruction of property, natural resources and equipment; · pollution and other environmental damage; · regulatory investigations and penalties; · suspension of our operations; and · repair and remediation costs. 37


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    Table of Contents We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations. We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities. Our natural gas exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations. Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production and transportation of, natural gas, NGLs, and oil. Failure to comply with such laws and regulations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition, results of operations, and cash flows. Changes to existing or new regulations may unfavorably impact us. Such potential regulations could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which could in turn have a material adverse effect on our financial condition, results of operations and cash flows. The unavailability or high cost of additional drilling rigs, completion services, equipment, supplies, personnel, and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis. The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers, and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition, results of operations, or cash flows. A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by the FERC as a natural gas company under the NGA. Although the FERC has not made any formal determinations with respect to any of our facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. The distinction between FERC‑regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case‑by‑case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by FERC, the courts or Congress. Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1,269,500 per day for each violation and disgorgement of profits associated with any violation. While our systems have not been regulated by FERC under the NGA, FERC has adopted regulations that may subject certain of our otherwise non‑FERC jurisdictional facilities to FERC annual reporting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability. 38


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    Table of Contents Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA for those emissions. These EPA rules could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. For example, in December 2015, the EPA finalized rules that added new sources to the scope of the GHG monitoring and reporting rule. These new sources include gathering and boosting facilities, as well as completions and workovers of hydraulically fractured wells. The revisions also include the addition of well identification reporting requirements for certain facilities. These changes to EPA’s GHG emissions reporting rule could result in increased compliance costs. In June 2016, the EPA finalized new regulations, known as Subpart OOOOa, that establish emission standards for methane and volatile organic compounds from new and modified oil and natural gas production and natural gas processing and transmission facilities. The EPA’s rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. In addition, the rule package extends existing VOC standards under the EPA’s Subpart OOOO to include previously unregulated equipment within the oil and natural gas source category. In June 2017, the EPA proposed to delay implementation of the 2016 methane rule, but in July 2017, the U.S. Court of Appeals for the District of Columbia Circuit ruled that such a stay was unlawful. In September 2018, the EPA proposed amendments to the 2016 standards that would relax the rule’s fugitive emissions monitoring requirements and expand exceptions to pneumatic pump requirements, among other changes. Various industry and environmental groups separately challenged both the methane requirements and the EPA’s attempts to delay implementation of the rules. In addition, in April 2018, several states filed a lawsuit that seeks to compel the EPA to issue methane performance standards for existing sources in the oil and natural gas source category. As a result of these developments, substantial uncertainty exists with respect to implementation of the EPA’s 2016 methane rule. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a possibility, and several states, including West Virginia and Ohio, have separately imposed or are considering imposing their own regulations on methane emissions from oil and gas production activities. While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of federal legislation in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could also adversely affect demand for the oil and natural gas we produce and lower the value of our reserves. Depending on the severity of any such limitations, the effect on the value of our reserves could be significant. On an international level, the United States is one of almost 200 nations that, in December 2015, agreed to an international climate change agreement in Paris, France, that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets (“Paris Agreement”). The Paris Agreement was signed by the United States in April 2016 and entered into force on November 4, 2016; however, the Paris Agreement does not impose any binding obligations on its participants. In August 2017, the U.S. Department of State officially informed the United Nations of the United States’ intent to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil and gas will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in 39


  • Page 47

    Table of Contents demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Finally, it should be noted that a number of scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other extreme climatic events; if any such effects were to occur, they have the potential to cause physical damage to our assets or affect the availability of water and thus could have an adverse effect on our exploration and production operations. Regulations related to the protection of wildlife adversely could adversely affect our ability to conduct drilling activities in some of the areas where we operate. Natural gas operations in our operating areas can be adversely affected by regulations designed to protect various wildlife. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in constraints on our exploration and production activities. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Competition in the natural gas industry is intense, making it more difficult for us to acquire properties, market natural gas and secure trained personnel. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business. Terrorist or cyber‑attacks and threats could have a material adverse effect on our business, financial condition or results of operations. Terrorist or cyber‑attacks may significantly affect the energy industry, including our operations and those of our suppliers and customers, as well as general economic conditions, consumer confidence and spending, and market liquidity. Strategic targets, such as energy‑related assets, may be at greater risk of future attacks than other targets in the United States. Our insurance may not protect us against such occurrences. We depend on digital technology in many areas of our business and operations, including, but not limited to, estimating quantities of natural gas, NGLs, and oil reserves, processing and recording financial and operating data, oversight and analysis of drilling operations, and communications with our employees and third-party customers or service providers. Deliberate attacks on our assets, security breaches in our systems or infrastructure, or the systems or infrastructure of third-parties or the cloud, could lead to the corruption or loss of our proprietary and potentially sensitive data, delays in production or delivery of our production to customers, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, or other operational disruptions and third-party liabilities. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, ransomware, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. As cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber-attacks. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our personnel, information, facilities and infrastructure may result in increased capital and operating costs. To date we have not experienced any material losses relating to cyber-attacks; however, there can be no assurance that we will not suffer such losses in the future. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations. 40


  • Page 48

    Table of Contents The loss of senior management or technical personnel could adversely affect operations. We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel, including Paul M. Rady, our Chairman and Chief Executive Officer, and Glen C. Warren, Jr., our President and Chief Financial Officer, could have a material adverse effect on our business, financial condition and results of operations. We may be subject to risks in connection with acquisitions of properties. The successful acquisition of producing properties requires an assessment of several factors, including: · recoverable reserves; · future natural gas, NGLs, and oil prices and their applicable differentials; · operating costs; and · potential environmental and other liabilities. The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow. In the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. The success of any completed acquisition will depend on our ability to effectively integrate the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. In addition, our revolving credit facility and the indentures governing our senior notes impose certain limitations on our ability to enter into mergers or combination transactions. Our revolving credit facility and the indentures governing our senior notes also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses. Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition and reduce our future growth rate. Our future growth prospects are dependent upon our ability to identify optimal strategies for our business. In developing our 2019 business plan, we considered allocating capital and other resources to various aspects of our businesses, including well development, reserve acquisitions, exploratory activities, midstream infrastructure, corporate items and other alternatives. We also considered our likely sources of capital. Notwithstanding the determinations made in the development of our 2019 plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies, including the appropriate corporate structure, appropriate rate of reserve development, or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business 41


  • Page 49

    Table of Contents strategies, our financial condition and growth rate may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our 2019 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives. We periodically engage in acquisitions, dispositions and other strategic transactions, including joint ventures. These transactions involve various inherent risks, such as our ability to obtain the necessary regulatory approvals; the timing of and conditions imposed upon us by regulators in connection with such approvals; the assumption of potential environmental or other liabilities; and our ability to realize the benefits expected from the transactions. In addition, various factors including prevailing market conditions could negatively impact the benefits we receive from transactions. Competition for acquisition opportunities in our industry is intense and may increase the cost of, or cause us to refrain from, completing acquisitions. Joint venture arrangements may restrict our operational and corporate flexibility. Moreover, joint venture arrangements involve various risks and uncertainties, such as committing us to fund operating and/or capital expenditures, the timing and amount of which we may have little control over, and our joint venture partners may not satisfy their obligations to the joint venture. Our inability to complete a transaction or to achieve our strategic or financial goals in any transaction could have significant adverse effects on our financial position, results of operations, and cash flows. Final regulations relating to and interpretations of provisions of the Tax Cuts and Jobs Act may vary from our current interpretation of such legislation. The U.S. federal income tax legislation recently enacted in Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, is highly complex and subject to interpretation. The presentation of our financial condition and results of operations is based upon our current interpretation of the provisions contained in the Tax Cuts and Jobs Act. In the future, the Treasury Department and the Internal Revenue Service are expected to issue final regulations and additional interpretive guidance with respect to the provisions of the Tax Cuts and Jobs Act. Any significant variance of our current interpretation of such provisions from any future final regulations or interpretive guidance could result in a change to the presentation of our financial condition and results of operations and could negatively affect our business. Our future tax liability may be greater than expected if our net operating loss (“NOL”) carryforwards are limited, we do not generate expected deductions, or tax authorities challenge certain of our tax positions. As of December 31, 2018, we have U.S. federal and state NOL carryforwards of $3.0 billion and $2.3 billion, respectively, which expire at various dates from 2019 to 2038. We expect to be able to utilize these NOL carryforwards and generate deductions to offset our future taxable income, including any gain we recognize with respect to the proposed simplification transaction. As a result, we do not expect to pay material U.S. federal and state income taxes through at least 2022. This expectation is based upon assumptions we have made regarding, among other things, our income, capital expenditures and net working capital, and the current expectation that our NOL carryforwards will not become subject to future limitations under Section 382 of the Internal Revenue Code of 1986 or otherwise. Additionally, any significant variance in our interpretation of current income tax laws, including as result of the release of final Treasury Regulations or other interpretive guidance implementing the Tax Cuts and Jobs Act, or a challenge of one or more of our tax positions by the IRS or other tax authorities could affect our tax position. While we expect to be able to utilize our NOL carryforwards and generate deductions to offset our future taxable income, in the event that deductions are not generated as expected, one or more of our tax positions are successfully challenged by the IRS (in a tax audit or otherwise), or our NOL carryforwards are subject to future limitations, our future tax liability may be greater than expected. Changes to state tax laws in response to the Tax Cuts and Jobs Act or that impose new or increased taxes or fees on natural gas and oil extraction may result in an increase in the state taxes we pay. Currently, many states conform their calculation of corporate taxable income to the calculation of corporate taxable income at the U.S. federal level. Due to recently enacted changes to U.S. federal income tax laws as a result of the Tax Cuts and Jobs Act, certain states may change or modify the calculation of corporate taxable income at the state level. Any resulting increase in costs due to such changes could have an adverse effect on our financial position, results of operations and cash flows. Additionally, states in which we operate or own assets may impose new or increased taxes or fees on natural gas and oil extraction, which could negatively affect our future cash flows and financial condition. Item 1B. Unresolved Staff Comments Not applicable. 42


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    Table of Contents Item 3. Legal Proceedings Environmental In March 2011, we received orders for compliance from federal regulatory agencies, including the U.S. Environmental Protection Agency, relating to certain of our activities in West Virginia. The orders allege that certain of our operations at several well sites are in non-compliance with certain environmental regulations, such as unpermitted discharges of fill material into wetlands or waters of the United States that are potentially in violation of the Clean Water Act. Antero voluntarily reviewed all of its pre-2011 construction sites and entered into an agreement to restore or mitigate all areas of concern. The vast majority of the sites cited by regulators were among the sites we voluntarily reviewed. On January 31, 2019, we entered into a consent decree with state and federal regulators to settle for $3.15 million and perform restoration at these sites along with mitigation at an approved mitigation site. The settlement was filed in federal court in West Virginia on February 11, 2019, and we are awaiting approval by the court. Our operations at these locations are not suspended, and management does not expect these matters to have a material adverse effect on our financial condition, results of operations, or cash flows. In June 2018, following site inspections conducted in September 2017 at certain of our facilities located in Doddridge County, Tyler County, and Ritchie County, West Virginia, we received a Notice of Violation (“NOV”) from the EPA Region III for alleged violations of the federal Clean Air Act and the West Virginia State Implementation Plan relating to permitting and control requirements for emissions of regulated pollutants at several of our natural gas production facilities. The NOV alleges that combustion devices at these facilities did not meet applicable air permitting requirements. Separately, in June 2018, we received an information request from EPA Region III pursuant to Section 114(a) of the Clean Air Act relating to the facilities that were inspected in September 2017 as well as additional Antero facilities for the purpose of determining if the additional facilities have the same alleged compliance issues that were identified during the September 2017 inspections. Since receipt of the NOV and information request, we have met with the EPA to discuss the alleged compliance issues but do not yet have any indication with respect to whether, and to what extent, the NOV and information request will result in monetary sanctions; however we believe that there is a reasonable possibility that these actions may result in monetary sanctions exceeding $100,000. Our operations at these facilities are not suspended, and management does not expect these matters to have a material adverse effect on our financial condition, results of operations, or cash flows. SJGC The Company is the plaintiff in two lawsuits against South Jersey Gas Company and South Jersey Resources Group, LLC (collectively, “SJGC”) pending in United States District Court in Colorado. In March 2015, the Company filed suit against SJGC seeking relief for breach of contract and damages in the amounts that SJGC had short paid, and continued to short pay, the Company in connection with two nearly identical long term gas contracts. Under those contracts, SJGC are long term purchasers of 80,000 MMBtu/day of the Company’s natural gas production. Deliveries under the contracts began in October 2011 and the term of the contracts continues through October 2019. The price for gas was based on specified indices in the contracts. Beginning in October 2014, SJGC began short paying the Company based on price indices unilaterally selected by SJGC and not the applicable index specified in the contracts. SJGC claimed that the index price specified in the contracts, and the index at which SJGC paid for deliveries from 2011 through September 2014, was no longer appropriate under the contracts because a market disruption event (as defined by the contract) had occurred and, as a result, a new index price was required to be determined by the parties. The Company rejected SJGC’s contention that a market disruption event occurred. SJGC’s actions constituted a breach of the contracts by failing to pay the Company based on the express price terms of the contracts and paying the Company based on unilaterally selected price indices in violation of the contracts’ remedial provisions. On May 8, 2017, a jury in the United States District Court in Colorado returned a unanimous verdict finding in favor of Antero’s positions in the lawsuit against SJGC. On July 21, 2017, final judgment on the jury’s unanimous verdict was entered by the court. On August 18, 2017, SJGC filed post- judgment motions with the court. On March 23, 2018, the court denied SJGC’s post-judgment motions. On April 20, 2018, SJGC appealed the final judgment to the United States Court of Appeals for the Tenth Circuit and the appeal remains pending. Subsequent to the entry of judgment, SJGC has continued to short pay the Company on the basis of unilaterally selected price indices and not the index specified in the contract. Accordingly, on December 21, 2017, Antero filed suit against SJGC to recover for its damages since March of 2017. The second lawsuit remains pending. Through December 31, 2018, the Company estimates that it is owed approximately $86 million (gross damages, including interest) more than SJGC has paid using the indices unilaterally selected by them. Substantially all of this amount has not been accrued in the Company’s financial statements. The Company will vigorously seek recovery from SJGC of all underpayments and damages, including interest, based on the contracted price. 43

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