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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, 2017 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 and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted 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 and post 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 ☐ (Do not check if a smaller reporting 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 30, 2017, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $5.0 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 $21.61. The registrant had 316,524,110 shares of common stock outstanding as of February 8, 2018. 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 41 Item 3. Legal Proceedings 42 Item 4. Mine Safety Disclosures 43 PART II 43 Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 43 Item 6. Selected Financial Data 45 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 49 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 76 Item 8. Financial Statements and Supplementary Data 77 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 77 Item 9A. Controls and Procedures 78 Item 9B. Other Information 79 PART III 80 Item 10. Directors, Executive Officers and Corporate Governance 80 Item 11. Executive Compensation 83 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 83 Item 13. Certain Relationships and Related Transactions and Director Independence 83 Item 14. Principal Accountant Fees and Services 83 PART IV 84 Item 15. Exhibits and Financial Statement Schedules 84 SIGNATURES 88 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 forward-looking statements, you 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 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, including the operations of its unconsolidated affiliates; · general economic conditions; · credit markets; · uncertainty regarding our future operating results; and · plans, objectives, expectations and intentions. We caution you 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, incident to the exploration for and development, production, gathering, processing, transportation, and sale of natural gas, NGLs, and oil. These risks include, but are not limited to, commodity price volatility and low commodity prices, inflation, availability of drilling and production equipment and services, environmental risks, drilling 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 flow and access to capital, the timing of development ii


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    Table of Contents expenditures, conflicts of interest among our stockholders, and the other risks described under the heading “Item 1A. Risk Factors” in this Annual Report on Form 10‑K. Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs, and oil that cannot be measured in an exact manner. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data, and the price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing, and production activities, or changes in commodity prices, may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, NGLs, and oil that are ultimately recovered. Should one or more of the risks or uncertainties described in this 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: “100% success rate.” Antero defines the term “100% success rate” to mean that all wells were completed and produce in commercially viable quantities. “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+”: 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. iv


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    Table of Contents “Liquids-rich.” Natural gas which contains a raw energy content of at least 1,100 Btu per Mcf. “LPG.” Liquefied petroleum gas consisting of propane and butane. “MBbl.” One thousand barrels of crude oil, condensate or NGLs. “Mcf.” One thousand cubic feet of natural gas. “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 v


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    Table of Contents on future net revenues. Neither PV‑10 nor Standardized Measure represents an estimate of the fair market value of our natural gas and oil properties. We and others in the industry use PV‑10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. “Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs. “Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40‑acre spacing, or distance between two horizontal well legs, and is often established by regulatory agencies. “Standardized measure.” Discounted future net cash flows estimated by applying year‑end prices to the estimated future production of year‑end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period‑end costs to determine pre‑tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre‑tax cash inflows over our tax basis in the natural gas and oil properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate. “Strip prices.” The daily settlement prices of commodity futures contracts, such as those for natural gas, NGLs, and oil. Strip prices represent the prices at which a given commodity can be sold at specified future dates, which may not represent actual market prices available upon such date in the future. “Tcf.” One trillion cubic feet of natural gas. “Tcfe.” One trillion cubic feet of natural gas equivalent with one barrel of oil, condensate, or NGLs converted to six thousand cubic feet of natural gas. “Undeveloped acreage.” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas, NGLs, and oil regardless of whether such acreage contains proved reserves. “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, 2017, we held approximately 620,000 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 which was formed to own, operate, and develop midstream energy assets to service Antero’s production 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, 2017 2017 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 15,553 $ 8,766 664 483,861 3,512 1,979 Ohio Utica Shale 1,708 $ 1,409 181 136,580 621 368 Total 17,261 $10,175 845 620,441 4,133 2,347 (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, 2017, which were $2.91 per MMBtu for natural gas based on a $3.11 per MMBtu NYMEX reference price, $20.40 per Bbl for NGLs and $45.35 per Bbl for oil for the Appalachian Basin based on a $51.03 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 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 3,706 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. From 2008 through December 31, 2017, our drilling operations in the Appalachian Basin have had a 100% success rate. We have 4,133 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 17 – Segment Information.” 2017 and Recent Developments and Highlights Reserves, Production, and Financial Results As of December 31, 2017, our estimated proved reserves were 17.3 Tcfe, consisting of 11.1 Tcf of natural gas, 528 MMBbl of ethane, 461 MMBbl of C3+ NGLs, and 38 MMBbl of oil. As of December 31, 2017, 64% of our estimated proved reserves by volume were natural gas, 34% were NGLs, and 2% were oil. Proved developed reserves were 8.5 Tcfe, or 49% of total proved reserves. For the year ended December 31, 2017, our production totaled 822 Bcfe, or 2,253 MMcfe per day, a 22% increase compared to 676 Bcfe, or 1,847 MMcfe per day, for the year ended December 31, 2016. The average realized price for 2017 production before the effects of gains on settled derivatives was $3.34 per Mcfe compared to $2.60 per Mcfe in 2016. The increase was primarily attributable to increases in energy commodity prices during the second half of 2016 that continued into 2017. Our average realized price after the effects of gains on settled derivatives was $3.60 per Mcfe during 2017 as compared to $4.08 per Mcfe during 2016. For the year ended December 31, 2017, we generated consolidated cash flow from operations of $2.0 billion, consolidated net income of $615 million, Adjusted EBITDAX of $1.5 billion, and Stand-Alone E&P Adjusted EBITDAX of $1.2 billion. This compares to consolidated cash flow from operations of $1.2 billion, a consolidated net loss of $849 million, Adjusted EBITDAX of $1.5 billion, and Stand-Alone E&P Adjusted EBITDAX of $1.4 billion for the year ended December 31, 2016. 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 (E&P) Information” for a definition of Stand-Alone E&P Adjusted EBITDAX and a reconciliation of Stand-Alone E&P 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 income for 2017 included (i) commodity derivative fair value gains of $637 million, comprised of gains on settled derivatives of $214 million, cash proceeds from derivative monetizations of $750 million, and a non- cash loss of $327 million on changes in the fair value of commodity derivatives, (ii) a noncash charge of $103 million for equity-based compensation, (iii) a noncash charge of $183 million for impairments, and (iv) a noncash tax benefit of $295 million. 2017 Capital Spending and 2018 Capital Budget For the year ended December 31, 2017, our total consolidated capital expenditures were approximately $2.2 billion, including drilling and completion expenditures of $1.3 billion, leasehold additions of $204 million, acquisitions of $176 million, gathering and compression expenditures of $346 million, water handling and treatment expenditures of $195 million, and other capital expenditures of $14 million. Our consolidated capital budget for 2018 is $2.1 billion, and includes: $1.3 billion for drilling and completion, $150 million for leasehold expenditures, and $650 million for capital expenditures by Antero Midstream, which includes $215 million for investments in unconsolidated affiliates. We do not budget for acquisitions. Approximately 80% of the drilling and completion budget is allocated to the Marcellus Shale and the remaining 20% is allocated to the Utica Shale. During 2018, we plan to operate an average of five drilling rigs and four completion crews in the Marcellus Shale, and one drilling rig and one completion crew in the 2


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    Table of Contents Utica Shale, and we plan to complete 140-150 horizontal wells in the Marcellus and Utica Shales in 2018 as compared to 135 in 2017. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities, and commodity prices. Hedge Position At December 31, 2017, we had entered into fixed price hedging contracts for January 1, 2018 through December 31, 2023 for 2.7 Tcf of our projected natural gas production at a weighted average index price of $3.34 per MMBtu, 291 million gallons of propane at a weighted average price of $0.75 per gallon, and 1.5 MMBbls of oil at a weighted average price of $55.97 per Bbl. These hedging contracts include contracts for the year ending December 31, 2018 of 731 Mcf of natural gas at a weighted average index price of $3.50 per MMBtu, 291 million gallons of propane at a weighted average price of $0.75 per gallon, and 1.5 MMBbls of oil at a weighted average price of $55.97 per Bbl. To the extent we have fixed 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, 2017, the estimated fair value of our commodity derivative contracts was approximately $1.3 billion. Credit Facilities On October 26, 2017, we entered into restated and amended senior revolving credit facilities for both Antero and Antero Midstream. Both facilities were amended to include fall away covenants and lower interest rates that are triggered if and when the companies are assigned an investment grade credit rating by either Standard and Poor’s or Moody’s. Antero’s borrowing base under its new facility (the “Credit Facility”) is $4.5 billion and lender commitments are $2.5 billion, representing a reduction from the previous borrowing base of $250 million and a reduction of $1.5 billion in lender commitments, reflecting our plan to primarily fund our drilling and completion program with cash flows from operations. The maturity date of the facility was extended from May 2019 to the earlier of (i) October 26, 2022 and (ii) the date that is 91 days prior to the earliest stated redemption 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 2018. At December 31, 2017, we had $185 million of borrowings and $705 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 our Credit Facility. Lender commitments under Antero Midstream’s new facility (the “Midstream Credit Facility”) remained at $1.5 billion. The maturity date of the facility was extended from November 2019 to October 26, 2022. At December 31, 2017, Antero Midstream had $555 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. Delevering Activities In the third quarter of 2017, we monetized over $1 billion of our non-exploration and production assets and used the proceeds to repay outstanding borrowings under our revolving credit facility. Proceeds from these activities are not expected to result in cash taxes payable due to the utilization of a portion of our net operating loss (“NOL”) carryforwards. These deleveraging activities consisted of the following transactions: · On September 11, 2017, we completed a public sale of 10,000,000 common units representing limited partner interests in Antero Midstream which were held by Antero. We received $311 million in net proceeds from the transaction. · In September 2017, we monetized portions of our hedge portfolio by reducing the average fixed index prices on certain of our natural gas hedges that settle from 2018 through 2022 while maintaining the total volumes hedged. We received total proceeds of approximately $750 million from the monetization of the natural gas hedges. Formation of Joint Venture and Issuance of Common Units by Antero Midstream On February 6, 2017, Antero Midstream formed the Joint Venture to develop processing assets in Appalachia with MarkWest, a wholly owned subsidiary of MPLX. Antero Midstream and MarkWest each own a 50% interest in the Joint Venture and 3


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    Table of Contents MarkWest operates the Joint Venture assets. The Joint Venture assets consist of processing plants in West Virginia and a one-third interest in a recently commissioned MarkWest fractionator in Ohio. In conjunction with the formation of the Joint Venture, on February 10, 2017, Antero Midstream issued 6,900,000 common units, including the underwriters’ purchase option, generating net proceeds of approximately $223 million. Antero Midstream used the net proceeds to fund the initial contribution to the Joint Venture, repay outstanding borrowings under the Midstream Credit Facility, and for general partnership purposes. Antero Midstream Equity Distribution Agreement Antero Midstream has an Equity Distribution Agreement (the “Distribution Agreement”), pursuant to which Antero Midstream may sell, from time to time through brokers acting as its sales agents, common units representing limited partner interests having an aggregate offering price of up to $250 million. Sales of the common units are made by means of ordinary brokers’ transactions on the New York Stock Exchange, at market prices, in block transactions, or as otherwise agreed to between Antero Midstream and the sales agents. Proceeds are used for general partnership purposes, which may include repayment of indebtedness and funding working capital or capital expenditures. The Partnership is under no obligation to offer and sell common units under the Distribution Agreement. During the year ended December 31, 2017, Antero Midstream issued and sold 777,262 common units under the Distribution Agreement, resulting in net proceeds of $25.5 million after deducting commissions and other offering costs. As of December 31, 2017, Antero Midstream had the capacity to issue additional common units under the Distribution Agreement up to an aggregate sales price of $157.3 million. Initial Public Offering of Antero Midstream GP LP AMGP was originally formed as ARMM in 2013 to become Antero Midstream’s general partner. In April 2017, in connection with its proposed IPO, ARMM formed Antero Midstream Partners GP LLC (“AMP GP”), a Delaware limited liability company, as a wholly owned subsidiary, and assigned it the general partner interest in Antero Midstream. Concurrent with the assignment, AMP GP was admitted as the sole general partner of Antero Midstream and ARMM ceased to be Antero Midstream’s general partner. 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 IPO. On May, 9, 2017, AMGP closed its IPO of 37,250,000 common shares held by its sole member at $23.50 per common share. Neither we nor Antero Midstream received any proceeds from the sale of common shares in the IPO. Subsequent to its IPO, AMGP indirectly controls the general partnership interest in Antero Midstream, through its ownership of AMP GP, and directly controls IDR LLC, a subsidiary of AMGP, which owns the IDRs in Antero Midstream. Antero Resources Corporation does not hold any financial or other interests in AMGP. However, certain of our directors and executive officers own AMGP common shares as well as profits interests in IDR LLC, which owns all of Antero Midstream’s IDRs. In addition, Paul M. Rady and Glen C. Warren, Jr., together with certain funds affiliated with Warburg Pincus LLC (“Warburg”) and certain funds affiliated with Yorktown Partners LLC (“Yorktown”), collectively own 100% of the membership interests in AMGP GP LLC, the general partner of AMGP. Certain of our directors and executive officers also own a portion of Antero Midstream’s common units. Tax Reform New tax legislation, commonly referred to as the Tax Cuts and Jobs Act, was enacted on December 22, 2017. ASC 740, Accounting for Income Taxes, requires companies to recognize the effect of tax law changes in the period of enactment even though the effective date for most provisions is for tax years beginning after December 31, 2017. Adjustments to our tax provision that were recorded in the three months ended December 31, 2017 principally relate to the reduction in the U.S. corporate income tax rate to 21%, which resulted in the Company recognizing an income tax benefit of $428 million to remeasure deferred tax liabilities that will reverse at the new 21% rate. Other significant provisions that are not yet effective but may impact income taxes in future years include: the repeal of the corporate Alternative Minimum Tax, the limitation on the current deductibility of net interest expense in excess of 30% of adjusted taxable income for levered balance sheets, a limitation on utilization of net operating losses generated after tax year 2017 to 80% of taxable income, the unlimited carryforward of net operating losses generated after tax year 2017, temporary 100% expensing of certain business assets, additional limitations on certain general and administrative expenses, and changes in determining the excessive compensation limitation. Currently, we do not anticipate paying cash federal income taxes in the near term due to any of the legislative changes, primarily due to our ability to expense intangible drilling costs and the utilization of our net operating loss carryforwards. Future interpretations relating to the recently enacted U.S. federal income tax legislation which vary 4


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    Table of Contents from our current interpretation and possible changes to state tax laws in response to the recently enacted federal legislation may have a significant effect on this projection. 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, 2015, 2016 and 2017. 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, 2017 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 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, 2015, 2016, and 2017 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, 2015 2016 2017 Estimated proved reserves: Proved developed reserves: Natural gas (Bcf) 3,627 4,426 5,587 Ethane (MMBbl) 247 250 268 C3+ NGLs (MMBbl) 113 151 199 Oil (MMBbl) 8 13 16 Total equivalent proved developed reserves (Bcfe) 5,838 6,914 8,488 Proved undeveloped reserves: Natural gas (Bcf) 5,906 4,988 5,511 Ethane (MMBbl) — 304 260 C3+ NGLs (MMBbl) 227 252 262 Oil (MMBbl) 18 25 22 Total equivalent proved undeveloped reserves (Bcfe) 7,377 8,472 8,773 Total estimated proved reserves (Bcfe) 13,215 15,386 17,261 PV-10 (in millions)(1) $ 3,634 $ 3,676 $10,175 Standardized measure (in millions)(1) $ 3,233 $ 3,287 $ 8,627 Proved developed producing (Bcfe) 5,553 6,587 7,996 Proved developed non-producing (Bcfe) 285 327 492 Percent developed 44 % 45 % 49 % (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 footnote 20 to our consolidated financial statements included in Item 8 of this Annual Report on Form 10‑K. 5


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    Table of Contents 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, 2015, 2016, and 2017: At December 31, (In millions, except per Mcf data) 2015(1) 2016(2) 2017(3) Future net cash flows $12,569 $11,623 $26,137 Present value of future net cash flows: Before income tax (PV-10) $ 3,634 $ 3,676 $10,175 Income taxes $ (401) $ (389) $(1,548) After income tax (Standardized measure) $ 3,233 $ 3,287 $ 8,627 (1) 12‑month average prices used at December 31, 2015 were $2.56 per MMBtu for natural gas, $14.19 per Bbl for NGLs, and $40.06 per Bbl for oil for the Appalachian Basin based on a $50.13 WTI reference price. (2) 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. (3) 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. 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 2015, 2016, and 2017 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 2017 The following table summarizes the changes in our estimated proved reserves during 2017 (in Bcfe): Proved reserves, December 31, 2016 15,386 Extensions, discoveries, and other additions 1,711 Purchase of reserves 373 Performance revisions 96 Revisions to 5-year development plan 498 Price revisions 132 Revisions to ethane recovery (113) Production (822) Proved reserves, December 31, 2017 17,261 Extensions, discoveries, and other additions of 1,711 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales. Purchases of 373 Bcfe related to the acquisition of developed and undeveloped leasehold acreage in both the Marcellus and Utica Shales. Positive revisions of 96 Bcfe related to improved well performance. Net positive revisions of 498 Bcfe related to revisions to our 5-year development plan. This figure includes positive revisions of 2,778 Bcfe for previously proved undeveloped properties reclassified from non-proved properties at December 31, 2016 to proved undeveloped at December 31, 2017 due to their addition to our 5-year development plan, and negative revisions of 2,280 Bcfe for locations that were not developed within 5 years of initial booking as proved reserves. Positive revisions of 132 Bcfe were due to increases in prices for natural gas, NGLs, and oil. Negative revisions of 113 Bcfe are due to a decrease in our assumed future ethane recovery. Our estimated proved reserves as of December 31, 2017 totaled approximately 17.3 Tcfe, an increase of 12% from the prior year. 6


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    Table of Contents 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 2017 (in Bcfe): Proved undeveloped reserves, December 31, 2016 8,472 Extension, discoveries, and other additions 1,397 Purchase of reserves 266 Performance revisions 144 Revisions to 5-year development plan 498 Price revisions 49 Reclassifications to proved developed reserves (1,860) Revisions to ethane recovery (193) Proved undeveloped reserves, December 31, 2017 8,773 Extensions, discoveries, and other additions during 2017 of 1,397 Bcfe of proved undeveloped reserves resulted from delineation and developmental drilling in the Marcellus and Utica Shales. Purchases of 266 Bcfe related to the acquisition of undeveloped leasehold acreage in both the Marcellus and Utica Shales. Positive revisions of 144 Bcfe related to improved well performance. Net positive revisions of 498 Bcfe related to revisions to our 5-year development plan. This figure includes positive revisions of 2,778 Bcfe for previously proved properties reclassified from non-proved properties at December 31, 2016 to proved undeveloped at December 31, 2017 due to their addition to our 5-year development plan, and negative revisions of 2,280 Bcfe for locations that were not developed within 5 years of initial booking as proved reserves. Positive revisions of 49 Bcfe were due to increases in prices for natural gas, NGLs, and oil. During the year ended December 31, 2017, we converted approximately 1,860 Bcfe, or 22%, of our proved undeveloped reserves to proved developed reserves at a total capital cost of approximately $584 million. We spent an additional $313 million on development costs related primarily to drilled and uncompleted wells and properties in the proved undeveloped classification at December 31, 2016, resulting in total development spending of $897 million, as disclosed in note 20 to the consolidated financial statements included elsewhere in this report. Estimated future development costs relating to the development of our proved undeveloped reserves at December 31, 2017 are approximately $3.3 billion, or $0.37 per Mcfe, over the next five years. Based on strip pricing as of December 31, 2017, 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 acreage position has grown and 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 2,280 Bcfe of reserves from proved undeveloped to probable during the year ended December 31, 2017 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, 2017, an estimated 10,200 of our net leasehold acres, containing 268 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 $29 million to renew the 10,200 acres based upon current leasing authorizations and option to extend payments. Proved undeveloped reserves of 980 Bcfe are related to these leases. Historically, we have had a high success rate in renewing Appalachian 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 be unable to renew leases covering approximately 98 Bcfe of these proved undeveloped reserves. If we are unable to renew these leases prior to the scheduled drilling dates, our quantities of proved undeveloped reserves will be somewhat reduced. 7


  • Page 15

    Table of Contents Preparation of Reserve Estimates Our reserve estimates as of December 31, 2015, 2016, and 2017 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 Senior Vice President of Reserves, Planning & Midstream, Ward D. McNeilly. Mr. McNeilly has been with the Company since October 2010. Mr. McNeilly has 38 years of experience in oil and gas operations, reservoir management, and strategic planning. From 2007 to October 2010, Mr. McNeilly was the Operations Manager for BHP Billiton’s Gulf of Mexico operations. From 1996 through 2007, Mr. McNeilly served in various North Sea and Gulf of Mexico Deepwater operations and asset management positions with Amoco and then BP. From 1979 through 1996, Mr. McNeilly served in various domestic and international operations and reservoir and asset management positions with Amoco. Mr. McNeilly holds a B.S. in Geological Engineering from the Mackay School of Mines at the University of Nevada. Our senior management also reviews our reserve estimates and related reports with Mr. McNeilly 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 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. 8


  • Page 16

    Table of Contents 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, 2017. 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 can result in substantial price volatility. A substantial or extended decline in gas 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.” 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, 2015, 2016 and 2017. 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, 2015 2016 2017 Production data: Natural gas (Bcf) 439 505 591 C2 Ethane (MBbl) 201 6,396 10,539 C3+ NGLs (MBbl) 15,350 20,279 25,507 Oil (MBbl) 2,078 1,873 2,451 Combined (Bcfe) 545 676 822 Daily combined production (MMcfe/d) 1,493 1,847 2,253 Average prices before effects of derivative settlements: Natural gas (per Mcf) $ 2.37 $ 2.50 $ 2.99 C2 Ethane (per Bbl) $ 6.17 $ 8.28 $ 8.83 C3+ NGLs (per Bbl) $ 17.15 $ 18.74 $ 30.48 Oil (per Bbl) $ 34.05 $ 32.73 $ 44.14 Combined average sales prices before effects of derivative settlements (per Mcfe)(1) $ 2.52 $ 2.60 $ 3.34 Combined average sales prices after effects of derivative settlements (per Mcfe)(1) $ 4.10 $ 4.08 $ 3.60 Average Costs (per Mcfe)(2): Lease operating $ 0.07 $ 0.07 $ 0.11 Gathering, compression, processing, and transportation $ 1.56 $ 1.70 $ 1.75 Production and ad valorem taxes $ 0.14 $ 0.10 $ 0.11 Marketing, net $ 0.23 $ 0.16 $ 0.13 Depletion, depreciation, amortization, and accretion $ 1.14 $ 1.05 $ 0.86 General and administrative (before equity-based compensation) $ 0.20 $ 0.16 $ 0.14 (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 $750 million of cash proceeds received from hedge monetizations in 2017), 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. 9


  • Page 17

    Table of Contents Productive Wells As of December 31, 2017, we held interests in a total of 958 gross (865 net) producing wells on our Marcellus Shale acreage, including the following: · 652 gross (643 net) horizontal wells, averaging a 99% working interest, operated by Antero. · 64 gross (5 net) horizontal wells operated by other producers. · 242 gross (217 net) shallow vertical wells. As of December 31, 2017, we held interests in a total of 204 gross (175 net) producing wells on our Ohio Utica Shale acreage, including the following: · 191 gross (175 net) horizontal wells, averaging a 92% working interest, operated by Antero. · 13 gross (0.04 net) horizontal wells operated by other producers. Additionally, at December 31, 2017 we had 27 net horizontal proved developed non-producing wells, and 137 gross horizontal wells (134 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. 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, 2017. A majority of our developed acreage is subject to liens securing our revolving credit facility. Approximately 56% of our net Marcellus acreage and 42% 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 101,274 99,760 452,362 384,101 553,636 483,861 Utica Shale 36,668 31,038 120,458 105,542 157,126 136,580 Total 137,942 130,798 572,820 489,643 710,762 620,441 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 169,289 147,952 Gilmer, WV 12,695 11,095 Harrison, WV 107,496 93,948 Lewis, WV 48 42 Marion, WV 9,465 8,272 Monongalia, WV 2,761 2,413 Pleasants, WV 4,505 3,938 Ritchie, WV 83,311 72,811 Tyler, WV 90,540 79,129 Wetzel, WV 62,901 54,974 Fayette, PA 6,205 5,423 Washington, PA 269 236 Westmoreland, PA 4,151 3,628 Total Marcellus Shale 553,636 483,861 10


  • Page 18

    Table of Contents Ohio Utica Gross Net Acres Acres Athens, OH 84 84 Belmont, OH 11,970 11,337 Guernsey, OH 7,957 6,743 Harrison, OH 577 577 Monroe, OH 58,673 56,150 Noble, OH 74,798 59,258 Washington, OH 3,067 2,431 Total Utica Shale 157,126 136,580 Total Marcellus and Utica Shale 710,762 620,441 Undeveloped Acreage Expirations The following table sets forth our total gross and net undeveloped acres as of December 31, 2017 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 the leases containing such acreage are extended or renewed. The Company is either planning to drill or is actively pursuing lease extensions or renewals on the majority of this acreage. Marcellus Ohio Utica Total Gross Net Gross Net Gross Net Acres Acres Acres Acres Acres Acres 2018 36,138 31,583 34,599 28,592 70,737 60,175 2019 55,977 48,923 24,054 22,507 80,031 71,430 2020 36,632 32,013 9,543 8,768 46,175 40,781 Drilling Activity The following table sets forth the results of our drilling activity for wells drilled and completed during the years ended December 31, 2015, 2016, and 2017. 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, 2015 2016 2017 Gross Net Gross Net Gross Net Marcellus Development wells: Productive 69 68 72 71 112 111 Dry — — — — — — Total development wells 69 68 72 71 112 111 Exploratory wells: Productive 5 5 16 16 1 1 Dry — — — — — — Total exploratory wells 5 5 16 16 1 1 Utica Development wells: Productive 21 18 35 35 4 4 Dry — — — — — — Total development wells 21 18 35 35 4 4 Exploratory wells: Productive 37 33 5 5 18 18 Dry — — — — — — Total exploratory wells 37 33 5 5 18 18 11


  • Page 19

    Table of Contents Year ended December 31, 2015 2016 2017 Gross Net Gross Net Gross Net Total Development wells: Productive 90 86 107 106 116 115 Dry — — — — — — Total development wells 90 86 107 106 116 115 Exploratory wells: Productive 42 38 21 21 19 19 Dry — — — — — — Total exploratory wells 42 38 21 21 19 19 The figures in the table above do not include 137 gross wells (134 net) that were drilled and uncompleted or in the process of being completed at December 31, 2017. 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. As of December 31, 2017, our firm sales commitments through 2022 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) 2018 620,000 500,000 41,500 50,000 2019 950,000 840,000 36,500 50,000 2020 830,000 790,000 36,500 50,000 2021 750,000 710,000 66,500 — 2022 680,000 640,000 66,500 — 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, 2016 and 2017, Antero Midstream spent approximately $228 million and $346 million, respectively, on gas gathering and compression infrastructure that services our production. Subject to any pre-existing dedications or 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, 2017, Antero Midstream, owned and operated 242 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, 2017, Antero Midstream owned and operated 15 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. 12


  • Page 20

    Table of Contents As of December 31, 2017, Antero Midstream owned and operated 123 miles of low‑pressure, high‑pressure, and condensate gathering pipelines in the Utica Shale, and Antero owned and operated 8 miles of high-pressure pipelines. As of December 31, 2017, Antero Midstream owned and operated one compressor station and we utilized five 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 contains a significant amount of NGLs. Natural gas containing significant amounts of NGLs 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 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. In late 2015, we began recovering some ethane as the first de-ethanizer was placed on line at the Sherwood gas processing facility. Our first international ethane sales contract is expected to commence in early 2018. As of December 31, 2017, 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 Anticipated Date (MMcf/d) (MMcf/d) of Completion Marcellus Shale: Sherwood 1 200 200 In service Sherwood 2 200 200 In service Sherwood 3 200 150 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 3Q 2018 Sherwood 11 200 200 4Q 2018 Sherwood 12 200 200 2Q 2019 Marcellus Shale Total 2,400 2,350 13


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    Table of Contents Antero Plant Contracted Firm Processing Processing Capacity Capacity Anticipated Date (MMcf/d) (MMcf/d) of Completion 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 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 12 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. 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 2034. · 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 571,000 MMBtu per day. Of the 571,000 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 2017 through 2025. o We have a firm transportation contract with SGG for 1,090,000 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 volumes that increase from the interim capacity of 355,000 MMBtu per day to 790,000 MMBtu per day in October 2018. 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 beginning in November 2018. These contracts expire at various dates from 2030 through 2038. 14


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    Table of Contents o We have a firm transportation contract for 590,000 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 increases to 790,000 MMBtu per day in June 2018. This contract expires in 2030. o We have a firm transportation contract for 600,000 MMBtu per day on ANR-Gulf to deliver natural gas from Ohio to the 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. The contracts expire at various dates from 2022 through 2025. o We have firm transportation contracts for 375,000 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. · 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. 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. Mariner East 2 is expected to be in-service in the second quarter of 2018. 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 2018 annual production levels, we estimate that we could incur total annual net marketing costs of $100 million to $125 million in 2018 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 complex 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 plant, 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, 2017, Antero Midstream had the ability to store 5.4 million barrels of fresh water in 38 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, 2017, Antero Midstream owned and operated 122 miles of buried fresh water pipelines and 68 miles of movable surface fresh water pipelines in the Marcellus Shale, as well as 25 fresh water storage facilities equipped with transfer pumps. 15


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    Table of Contents As of December 31, 2017, Antero Midstream owned and operated 55 miles of buried fresh water pipelines and 28 miles of movable surface fresh water pipelines in the Utica Shale, as well as 13 fresh water storage facilities equipped with transfer pumps. In August 2015, Antero committed to developing an advanced wastewater treatment complex in Doddridge County, West Virginia. The complex was transferred to Antero Midstream in conjunction with the sale of Antero’s water handling systems in September 2015. The wastewater treatment complex will include a 60,000 barrel per day facility that will allow Antero Midstream to treat our flowback and produced water for subsequent use or sale for well completions. The treatment facility is in its final stages of commissioning and is expected to commence full commercial operations in the first quarter of 2018. Late in 2015, Antero Midstream began providing us with wastewater services for our well completion operations, including wastewater transportation, disposal, and treatment. Major Customers 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 Venture and WGL Midstream accounted for approximately 29% and 13% of our total product revenues, respectively. For the year ended December 31, 2015, sales to Tenaska Marketing Ventures, South Jersey Resources, and Sequent Energy Management accounted for 19%, 18%, and 13% of our total product revenues, respectively. 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 summer. This can also reduce seasonal demand fluctuations. These seasonal anomalies can 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 16


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    Table of Contents 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. 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. 17


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    Table of Contents 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 transportation of oil, NGLs, and 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 $1,213,503 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 $1,000,000 per violation per 18


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    Table of Contents 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 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 19


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    Table of Contents 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. 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. To the extent the rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule, which was supposed to become effective in August 2015, has been challenged in court on the grounds that it unlawfully expands the reach of CWA programs, and implementation of the rule has been stayed pending resolution of the court challenge. In January 2018, the U.S. Supreme Court determined that federal district courts have jurisdiction to review the rule. Now that the Supreme Court has established the proper jurisdiction for the litigation, several district court cases that had been put on hold could be restarted, and it is unclear how the Trump Administration will defend the rule. Following the issuance of a presidential executive order to review the rule, the EPA and the Corps proposed a rulemaking to repeal the rule in June 2017; the EPA and Corps also announced their intent to issue a new rule defining the CWA’s jurisdiction. In November 2017, the EPA and the Corps proposed postponing by two years the effective date of the rule until at least 2020, which would provide the agencies more time to potentially repeal and replace the rule. As a result, future implementation of the rule is uncertain at this time. To the extent this rule or a revised rule expands the scope of the CWA’s jurisdiction, 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. In November 2017, the EPA published a partial list of attainment designations for the 2015 ozone standard. The EPA issued preliminary nonattainment designations in December 2017, and has announced that they plan to issue final attainment status designations during the first half of 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result 20


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    Table of Contents in increased expenditures for pollution control equipment, the costs of which could be significant. More recently, 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 reviews for certain large stationary sources. 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 on a case‑by‑case basis. 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 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 stay these requirements for two years and revisit the entirety of the 2016 standards. Comments to the EPA’s proposal were due in August 2017. The EPA has not yet published a final rule. As a result of these developments, future implementation of the 2016 standards is uncertain at this time. 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 activities in the Piceance Basin in discussions on how to minimize air emission impacts from our operations. In 2012, the EPA promulgated NSPS Quad O, which, among other actions, requires the use of reduced emission completions, or “green completions,” to control emissions of methane from hydraulically fractured natural gas wells. The green completions requirements of NSPS Quad O became effective in January 2015, but we have been performing green completions since before the EPA’s rules became effective. We were one of the first operators to implement green completions in Colorado back 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. 21


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    Table of Contents When we permit a facility, we install air pollution control equipment that meets the requirements of the NSPS and EPA Best Achievable 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. During 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 2017. 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 now used at compressor stations. This eliminates methane emissions that occur from using gas operated pneumatic controllers. 8) Gas operated compressor engine starters were replaced with air or electric starters. This eliminates 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 prevent the venting of gas from our wells during the well completion process. During 2018, Antero’s methane emission reduction efforts will also include the following activities: 1) The GHG/Methane Reduction team will meet quarterly and continue to review emerging methane detection and quantification technologies applicable to E&P and Midstream Operations. 2) Developing a plug and abandonment plan for certain older vertical wells that were acquired in conjunction with property acquisitions. Plugging and abandoning older, low producing wells will reduce methane emissions. 3) Reviewing the option to replace existing gas operated pneumatic controllers with air or electrically operated 22


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    Table of Contents controllers in E&P operations. 4) Exploring the use of lockdown thief hatches on storage tanks. These hatches eliminate 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 in our midstream operations, where feasible. 9) The replacement of TEG dehydrators with desiccant dehydrators where feasible. While Congress has from time to time considered legislation to reduce emissions of GHGs, the prospect for adoption of significant legislation at the federal level to reduce GHG emissions is perceived to be low at this time. 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. 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. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration, development, production, and acquisition activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time. 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 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. The EPA also 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 23


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    Table of Contents 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 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 January 2016, the PADEP issued new rules establishing stricter disposal requirements for wastes associated with hydraulic fracturing activities, which include, among other things, a prohibition on the use of centralized impoundments for the storage of drill cuttings and waste fluids. 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 sought 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 2017, nor do we anticipate that such expenditures will be material in 2018. Employees As of December 31, 2017, we had 593 full‑time employees, including 39 employees in executive, finance, treasury, legal, and administration, 26 in information technology, 22 in geology, 236 in production and engineering, 144 in midstream and water, 74 in land, and 52 in accounting. Our future success will depend partially on our ability to attract, retain, and motivate qualified 24


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    Table of Contents 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. 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 commodities market has been volatile. This market 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 and natural gas, including liquefied natural gas; · the price and quantity of export of natural gas, 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. 25


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    Table of Contents In late 2014, global energy commodity prices declined precipitously as a result of several factors, including an increase in worldwide commodity supplies, a stronger U.S. dollar, relatively mild weather in large portions of the U.S., and strong competition among some oil producing countries for market share. Commodity prices remained depressed in 2015 and into 2016, although a modest recovery began in late 2016, and has continued intermittently in 2017 and 2018. Lower commodity prices reduce our product revenues and borrowing ability. 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 further decrease, a significant portion of our exploration and development projects could become uneconomic. This may result in our having to make 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 “—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. 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 assure you 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, and processing facilities 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. 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, 2017, 51% of our total estimated proved reserves were classified as proved undeveloped. Our approximately 8.8 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, including acquisitions, was approximately $1.7 billion in 2017. Our board of directors has approved a capital budget for 2018 of $1.45 billion that includes $1.3 billion for drilling and completion and $150 million for core leasehold expenditures. Our capital budget excludes acquisitions. We expect to fund these capital expenditures with cash generated by operations and borrowings under our revolving credit facility or capital market transactions; however, our financing needs may require 27


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    Table of Contents 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 our reserves and hedge position, with the next borrowing base redetermination scheduled to occur in April 2018. 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. Due to the decline in commodity prices throughout 2015 and 2016, the financial markets have exerted downward pressure on stock prices and credit capacity for companies throughout the energy industry. In particular, 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 throughout most of 2017, 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; 29


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    Table of Contents · incur liens; and · engage in certain other transactions without the prior consent of the lenders. 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 a semi‑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 2017, we had estimated average outstanding borrowings under our revolving credit facilities of approximately $840 million, 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 $8 million and a corresponding decrease in our 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, 2017, we had entered into a number of hedge contracts for approximately 2.8 Tcfe of our projected natural gas, NGLs, and oil production through December 31, 2023. We are currently realizing a significant benefit from these hedge positions. For example, for the years ended December 31, 2016 and 2017, we received approximately $1.0 billion and $964 million, respectively, in revenues from cash settled derivatives pursuant to our hedging arrangements, including $750 million for certain natural gas hedges that were monetized during the year ended December 31, 2017. Many of the hedge agreements that resulted in these realized gains for the years ended December 31, 2016 and 2017 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 price at which we have been able to hedge future production has decreased as a result. Sustained weaknesses in commodity prices adversely affect our ability to hedge future production, particularly on a local basis. If we are unable to enter into new hedge contracts in the future at favorable pricing and for a sufficient amount of our production, our financial condition and results of operations could be materially adversely affected. 30


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    Table of Contents 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 a significant part of our overall future revenues. For example, for the years ended December 31, 2016 and 2017, approximately 97% and 100%, respectively, of our production was protected from price declines by our financial derivative contracts. 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. 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 significant portion of our natural gas production, including fixed‑price swaps. As of December 31, 2017, we had entered into hedging contracts through December 31, 2023 covering a total of approximately 2.8 Tcfe of our projected natural gas, NGLs, and oil production at weighted average index price of $3.39 per MMBtu. 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 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 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. As of December 31, 2017, the estimated fair value of our commodity derivative contracts was approximately $1.3 billion (excluding short-term commodity derivatives related to our marketing activities), including the following values by bank counterparty: JP Morgan—$288 million; Morgan Stanley—$285 million; Citigroup—$245 million; Scotiabank— $171 million; Wells Fargo—$136 million; Canadian Imperial Bank of Commerce—$51 million; Toronto Dominion Bank —$38 million; BNP Paribas—$30 million; Bank of Montreal—$21 million; Fifth Third Bank—$15 million; SunTrust—$9 million; Natixis—$7 million; and Capital One—$6 million. The credit ratings of certain of these banks were downgraded several years ago because of various economic factors, including the sovereign debt crisis in Europe. 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. 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 utilize our full firm transportation and processing capacity. Our firm transportation agreements expire at various dates from 2018 to 2058, our gas processing, gathering, and compression services agreements expire at various dates from 2018 to 2033, and our water services agreement with Antero Midstream expires in 2035. We 31


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    Table of Contents are obligated to pay fees on minimum volumes to our service providers regardless of actual volume throughput. As of December 31, 2017, our long‑term contractual obligations under agreements with minimum volume commitments totaled over $18.3 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 2018 annual production levels, we estimate that we could incur total annual net marketing costs of $100 million to $125 million in 2018 for 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 2018, our commitments and obligations under firm transportation agreements continue to increase and our net marketing expense could continue to 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 water and other waste disposal or recycling 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 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, 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. 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 32


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    Table of Contents 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. 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 itself 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 January 2016, the PADEP issued new rules establishing stricter disposal requirements for wastes associated with hydraulic fracturing activities, which include, among other things, a prohibition on the use of centralized impoundments for the storage of drill cuttings and waste fluids. 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 sought 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. You 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. 33


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    Table of Contents 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, 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, 2017, we had 4,133 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 79% 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 79% 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 44% and 58% 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. You 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. 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, 2017, 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, 34


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    Table of Contents NGLs, or oil. Furthermore, substantially all of our liquids-rich natural gas is processed at two processing facilities. If service interruptions are experienced at either facility, it would lead to a decline in our production and could adversely affect our business, financial condition, results of operations, and cash flows. 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. The capacity of transmission, gathering and processing and fractionation facilities 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 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 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. 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. 35


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    Table of Contents 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: the sale of our oil and gas production ($263 million in receivables at December 31, 2017), which we market to energy marketing companies, end users, and refineries; the marketing of our excess firm transportation capacity ($37 million at December 31, 2017), and joint interest receivables ($11 million at December 31, 2017). Joint interest receivables arise from billing 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, 2017 accounted for approximately 22% 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. 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 Colorado, West Virginia, Ohio, and Pennsylvania with regards to our operations or royalty payment practices. The plaintiffs have requested unspecified damages and other injunctive or equitable relief. We are not yet able to estimate what our aggregate exposure for monetary or other damages resulting from these or other similar claims might be. 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; 36


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    Table of Contents · 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. 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 37


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    Table of Contents 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 $1,213,503 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. 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. 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 on a case by case basis. 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. As noted above, in June 2016, the EPA finalized new regulations 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 stay these requirements for two years and revisit the entirety of the 2016 standards. Comments to the EPA’s proposal were due in August 2017. The EPA has not yet published a final rule. As a result of these developments, future implementation of the 2016 standards is uncertain at this time. While Congress has from time to time considered legislation to reduce emissions of GHGs, the prospect for adoption of significant legislation at the federal level to reduce GHG emissions is perceived to be low at this time. 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 38


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    Table of Contents 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. 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. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration, development, production, and acquisition activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time. 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 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 39


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    Table of Contents 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. 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. 40


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    Table of Contents 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 2018 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 2018 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 strategies, our financial condition and growth rate may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our 2018 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. Changes to state tax laws in response to recently enacted U.S. federal tax legislation or to 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, 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. Certain states may impose new or increased taxes or fees on natural gas and oil extraction. For example Ohio has previously considered, and its legislature continues to consider, proposals to increase the current severance tax imposed on natural gas or oil in Ohio. It is possible that Ohio could propose and implement a new or increased severance tax in the coming years, which would negatively affect our future cash flows and financial condition. Future regulations relating to and interpretations of recently enacted U.S. federal income tax legislation 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 release regulations relating to and interpretive guidance of the legislation contained in the Tax Cuts and Jobs Act. Any significant variance of our current interpretation of such legislation from any future 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. Item 1B. Unresolved Staff Comments Not applicable. 41


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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. We have responded to all pending orders and are actively cooperating with the relevant agencies. We believe that these actions will result in monetary sanctions exceeding $100,000. We have had ongoing settlement discussions with the relevant agencies to resolve the orders for compliance, but we are unable to estimate the total amount of monetary sanctions to resolve such orders or costs to remediate these locations in order to bring them into compliance with applicable environmental laws and regulations. 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. 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, which are currently pending. If the court denies those motions, SJGC will have 30 days from the court’s decision on these post-judgment motions to file an appeal. 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 May of 2017. Through December 31, 2017, the Company estimates that it is owed approximately $76 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. WGL The Company and Washington Gas Light Company and WGL Midstream, Inc. (collectively, “WGL”) were involved in a pricing dispute involving firm gas sales contracts executed June 20, 2014 (the “Contracts”) that the Company began delivering gas under in January 2016. From January 2016 through July 2017 and from December 2017 through January 2018, the aggregate daily gas volumes contracted for under the Contracts was 500,000 MMBtu/day, with the aggregate daily contracted volumes having increased to 600,000 MMBtu/day from August through November 2017. The Company invoiced WGL based on the natural gas index price specified in the Contracts and WGL paid the Company based on that invoice price. However, WGL asserted that the index price was no longer appropriate under the Contracts and claimed that an undefined alternative index was more appropriate for the delivery point of the gas. In July 2016, the matter was referred to arbitration by the Colorado district court. In January 2017, after hearing a week of testimony and evidence, the arbitration panel ruled in the Company’s favor. As a result, the index price has remained as specified in the Contracts and there will be no adjustments to the invoices that have been paid by WGL, nor will future invoices to WGL be adjusted based on the same claim rejected by the arbitration panel. The arbitration panel’s award was confirmed by the Colorado district court on April 14, 2017. 42

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