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Antero Resources Corporation Mining
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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, 2015 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, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b‑2 of the Exchange Act. Large accelerated filer ☒ Accelerated filer ☐ Non‑accelerated filer ☐ Smaller reporting company ☐ (Do not check if a smaller reporting company) 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, 201 5, the last business day of the registrant's most recently completed second fiscal quarter, was approximately $2.6 billion. The registrant had 277,061,336 shares of common stock outstanding as of February 19, 2016. 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.
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 22 Item 1B. Unresolved Staff Comments 38 Item 3. Legal Proceedings 38 Item 4. Mine Safety Disclosures 38 PART II 39 Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 39 Item 6. Selected Financial Data 41 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 45 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 70 Item 8. Financial Statements and Supplementary Data 71 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 71 Item 9A. Controls and Procedures 72 Item 9B. Other Information 73 PART III 75 Item 10. Directors, Executive Officers and Corporate Governance 75 Item 11. Executive Compensation 78 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 78 Item 13. Certain Relationships and Related Transactions and Director Independence 78 Item 14. Principal Accountant Fees and Services 78 PART IV 79 Item 15. Exhibits and Financial Statement Schedules 79 SIGNATURES 85 i
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. When used, the words "could," "believe," "anticipate," "intend," "estimate," "expect," "project" and similar expressions are intended 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 our 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; · 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 continued low commodity prices, inflation, lack of 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 expenditures, 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 way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and 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 ii
Table of Contents 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
Table of Contents GLOSSARY OF OIL AND NATURAL GAS TERMS The following are abbreviations and definitions of certain terms used in this document, 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. "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. "MBbl." One thousand barrels of crude oil, condensate or NGLs. "Mcf." One thousand cubic feet of natural gas. iv
Table of Contents "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 liquefied petroleum gas 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 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 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 ("PUD")." Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. "PV‑10." When used with respect to natural gas and oil reserves, PV‑10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production, future development and abandonment costs, using average yearly prices computed using SEC rules, before income taxes, and without giving effect to non‑property‑related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV‑10 is not a financial measure calculated in accordance with generally accepted accounting principles ("GAAP") and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV‑10 nor Standardized Measure represents an estimate of the fair market value of our natural gas and oil properties. We and others in the industry use PV‑10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. v
Table of Contents "Recompletion." The process of re‑entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production. "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. "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
Table of Contents PART I Items 1 and 2. Business and Properties Our Company Antero Resources Corporation ("Antero") is an independent oil and natural gas company engaged in the exploration, development, 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, 2015, we held approximately 569,000 net acres of oil and gas properties located in the Appalachian Basin in West Virginia, Ohio, and Pennsylvania. Our corporate headquarters are in Denver, Colorado. 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, 2015 2015 Net Gross Average net Proved proved potential daily Reserves PV-10 (in developed Total net drilling production (Bcfe) (1) millions)(2) wells(3) acres(4) locations(5) (MMcfe/d) Appalachian Basin: Marcellus Shale 11,399 $ 2,745 435 422,000 2,905 1,051 Upper Devonian 7 $ 4 2 — — — Deep Utica Shale rights — — — — — — Ohio Utica Shale 1,809 $ 885 110 147,000 814 446 Total 13,215 $ 3,634 547 569,000 3,719 1,497 (1) Estimated proved reserve volumes and values were calculated assuming recovery of approximately 11,500 gross barrels of ethane per day, 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, 2015, which 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) 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 that were primarily acquired in conjunction with leasehold acreage acquisitions. (4) Net acres allocable to the Upper Devonian and the deep Utica Shale rights are included in the net acres allocated to the Marcellus Shale because these multi‑horizon shale formations are generally attributable to the same leases. (5) See "Item 1A. Risk Factors" for risks and uncertainties related to developing our potential well locations. 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, 2015, our drilling operations in the Appalachian Basin have had a 100% success rate. We have approximately 3,719 potential horizontal well locations on our existing leasehold acreage, both proven and unproven. 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. 1
Table of Contents We operate in the following industry segments: (i) the exploration, development, and production of natural gas, NGLs, and oil, (ii) gathering and compression, (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 15: Segment Information." 2015 Developments and Highlights Energy Industry Environment 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. during winter months, and strong competition among oil producing countries for market share. These events continued into 2015 and early 2016 and, along with slower economic growth in China, have led to the further suppression of commodity prices. Spot prices for WTI declined from approximately $106.00 per Bbl in June 2014 to less than $50.00 per Bbl in January 2015, and declined further to less than $30.00 per Bbl in January 2016. Spot prices for Henry Hub natural gas declined from approximately $4.40 per MMBtu in January 2014 to $3.00 per MMBtu in January 2015, and declined further to less than $1.80 per MMBtu for a brief period in December 2015. Spot prices for propane, which is the largest source of our NGLs sales revenue, declined from approximately $1.55 per gallon in January 2014 to less than $0.50 per gallon in January 2015, and declined further to less than $0.35 per gallon in January 2016. In response to these market conditions and concerns about access to capital markets, many U.S. exploration and development companies significantly reduced their capital spending in 2015. Our capital spending for drilling, completions, and land for 2015 was $1.8 billion, a 44% reduction from our 2014 capital expenditures. In conjunction with the reduction in our capital expenditures during 2015, we deferred the completion of 50 wells. Our capital budget for drilling, completions, and land for 2016 is $1.4 billion (excluding the capital budget for our consolidated subsidiary, Antero Midstream LP, or "Antero Midstream"), a 24% reduction from our 2015 capital expenditures. We plan to operate an average of 7 drilling rigs in 2016 as compared to an average of 14 rigs in 2015, and we plan to complete 115 horizontal wells in the Marcellus and Utica Shales in 2016 as compared to 130 in 2015. We believe that our 2016 capital budget will be fully funded through operating cash flow and available borrowing capacity under our revolving credit facility or capital market transactions. We will continue to monitor commodity prices and may revise the capital budget if conditions warrant. Additionally, given the current commodity price environment, we have evaluated the carrying value of our proved properties. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates" for a discussion of such evaluation. Reserves, Production, and Financial Results As of December 31, 2015, our estimated proved reserves were 13.2 Tcfe, consisting of 9.5 Tcf of natural gas, 587 MMBbl of NGLs and 26 MMBbl of oil. As of December 31, 2015, 72% of our estimated proved reserves by volume were natural gas, 27% were NGLs, and 1% was oil. Proved developed reserves were 5.8 Tcfe, or 44% of total proved reserves. For the year ended December 31, 2015, our production totaled 545 Bcfe, or 1,493 MMcfe per day, a 48% increase over 2014 levels. The average price received for 2015 production before the effects of gains on settled derivatives was $2.52 per Mcfe compared to $4.73 in 2014. The decrease was primarily attributable to decreases in energy commodity prices that began in 2014 and continued into 2015. The average realized price after the effects of gains on settled derivatives was $4.10 per Mcfe for 2015 as compared to $5.10 per Mcfe for 2014. For the year ended December 31, 2015, we generated cash flow from operations of $1.01 billion, net income of $941 million, and Adjusted EBITDAX of $1.22 billion. Net income in 2015 included (i) gains on unsettled derivatives of $1.52 billion (ii) a noncash charge of $98 million for equity-based compensation, (iii) a noncash charge of $104 million for impairments of unproved properties, and (iv) a noncash tax expense of $576 million. 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). Dropdown of Water Handling and Treatment Assets On September 23, 2015, we 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 us and 2
Table of Contents used primarily in connection with the construction, ownership, operation, use or maintenance of our advanced wastewater treatment complex to be constructed in Doddridge County, West Virginia, to Antero Treatment LLC ("Antero Treatment"), a wholly-owned subsidiary of Antero Midstream (collectively, (i) and (ii) are referred to herein as the "Contributed Assets"). In consideration for the Contributed Assets, Antero Midstream (i) paid us a cash distribution equal to $552.5 million, less $171 million of assumed debt, (ii) issued to us 10,988,421 common units representing limited partner interests in Antero Midstream, (iii) distributed to us proceeds of approximately $241 million from a private placement of Antero Midstream common units, and (iv) has agreed to pay us (a) $125 million in cash if Antero Midstream delivers 176,295,000 barrels or more of fresh water during the period between January 1, 2017 and December 31, 2019 and (b) an additional $125 million in cash if Antero Midstream delivers 219,200,000 barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020. Antero Midstream borrowed $525 million on its bank credit facility in connection with this transaction. 2015 Capital Spending and 2016 Capital Budget For the year ended December 31, 2015, our total capital expenditures were approximately $2.3 billion, including drilling and completion costs of $1.7 billion, gathering and compression project costs by Antero Midstream of $360 million, water handling and treatment costs of $131 million (a portion of which were expenditures by Antero Midstream), $199 million of leasehold costs, and other capital expenditures of $7 million. Our capital budget for drilling, completions, and land for 2016 is $1.4 billion, excluding the capital budget for Antero Midstream, and includes: $1.3 billion for drilling and completion and $100 million for core leasehold acreage acquisitions. We do not budget for acquisitions. Approximately 75% of the drilling and completion budget is allocated to the Marcellus Shale and the remaining 25% is allocated to the Utica Shale. During 2016, we plan to operate an average of 5 drilling rigs in the Marcellus Shale and 2 drilling rigs in the Utica Shale. Additionally, the capital budget for Antero Midstream for 2016 is approximately $435 million. 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, 2015, we had entered into fixed price hedging contracts for January 1, 2016 through December 31, 2022 for 3.365 Tcf of our projected natural gas production at a weighted average index price of $3.80 per MMBtu and 1.036 billion gallons of propane at a weighted average price of $0.51 per gallon. These hedging contracts include contracts for the year ending December 31, 2016 of 590.2 Bcf of natural gas at a weighted average index price of $3.92 per MMBtu and 461.2 million gallons of propane at a weighted average price of $0.59 per gallon. We believe this hedge position provides protection to cash flows supporting our future operations and capital spending plans for 2016 through 2022. As of December 31, 2015, the estimated fair value of our commodity derivative contracts was approximately $3.1 billion. Credit Facilities The current borrowing base under our revolving credit facility is $4.5 billion and lender commitments are $4.0 billion. The borrowing base under our revolving credit facility is redetermined semi‑annually and is based on the estimated future cash flows from our proved reserves and our commodity hedge positions. The next redetermination is scheduled to occur in April 2016. At December 31, 2015, we had $707 million of borrowings and $702 million of letters of credit outstanding under the revolving credit facility. Our revolving credit facility matures in May 2019. 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 revolving credit facility. Our consolidated subsidiary, Antero Midstream, has a revolving credit facility agreement that provides for lender commitments of $1.5 billion. At December 31, 2015, Antero Midstream had $620 million of borrowings outstanding under its revolving credit facility. The facility will mature in November 2019. 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 this revolving credit facility. Issuance of 5.625% Senior Notes due 2022 On March 17, 2015, we issued $750 million of 5.625% senior notes due June 1, 2023 at par. The proceeds from the issuance were used to pay down amounts outstanding under our revolving credit facility. 3
Table of Contents As of December 31, 2015, we had four series of senior notes outstanding totaling $3.375 billion in aggregate principal amount. The notes bear interest at rates ranging from 5.125% to 6.00% and have maturity dates ranging from December 1, 2020 to June 1, 2023. Issuance of Common Stock On March 10, 2015, we completed an offering of 13,100,000 shares of our common stock. In connection with the offering, we granted the underwriter a 30-day option to purchase a maximum of 1,900,000 additional shares of our common stock at the offering price. On March 31, 2015, the underwriter exercised its option and purchased 1,600,000 shares. After deducting underwriting discounts and other expenses related to the offering, we received total net proceeds of approximately $538 million. The proceeds from the offering were used to pay down amounts outstanding under our revolving credit facility. 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, 2013, 2014 and 2015. 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, 2015 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 31 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, 2013 and 2014 were prepared assuming ethane rejection. Reserves at December 31, 2015 were prepared assuming recovery of approximately 11,500 gross barrels of ethane per day, 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, 2013 2014 2015 Estimated proved reserves: Proved developed reserves: Natural gas (Bcf) 1,818 3,285 3,627 NGLs (MMBbl) 33 80 360 Oil (MMBbl) 2 6 8 Total equivalent proved developed reserves (Bcfe) 2,022 3,803 5,838 Proved undeveloped reserves: Natural gas (Bcf) 4,936 7,250 5,906 NGLs (MMBbl) 105 250 227 Oil (MMBbl) 8 22 18 Total equivalent proved undeveloped reserves (Bcfe) 5,610 8,880 7,377 Total estimated proved reserves (Bcfe) 7,632 12,683 13,215 Proved developed producing (Bcfe) 1,771 3,508 5,553 Proved developed non-producing (Bcfe) 251 295 285 Percent developed 27 % 30 % 44 % PV-10 (in millions)(1) $5,998 $11,320 $ 3,634 Standardized measure (in millions)(1) $4,510 $ 7,635 $ 3,233 (1) Pre-tax PV‑10 was prepared using average yearly prices computed using SEC rules, discounted at 10% per annum, without giving effect to taxes. Pre-tax PV‑10 is a non‑GAAP financial measure. We believe that the presentation of pre-tax 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, 4
Table of Contents 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, pre-tax PV‑10 is based on a pricing methodology and discount factors that are consistent for all companies. Because of this, pre-tax 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 pre-tax PV‑10 amount is the discounted amount of estimated future income taxes. For more information about the calculation of standardized measure, see footnote 18 to our consolidated financial statements included in Item 8 of this Annual Report on Form 10‑K. The following sets forth the estimated future net cash flows from our proved reserves (without giving effect to our commodity hedges), 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, 2013, 2014, and 2015: At December 31, (In millions, except per Mcf data) 2013(1) 2014(2) 2015(3) Future net cash flows $18,797 $33,698 $12,569 Present value of future net cash flows: Before income tax (PV-10) $ 5,998 $11,320 $ 3,634 Income taxes $(1,488) $(3,685) $ (401) After income tax (Standardization measure) $ 4,510 $ 7,635 $ 3,233 (1) 12‑month average prices used at December 31, 2013 were $3.65 per MMBtu for natural gas, $47.13 per Bbl for NGLs, and $87.00 per Bbl for oil for the Appalachian Basin based on a $97.17 WTI reference price. (2) 12‑month average prices used at December 31, 2014 were $4.07 per MMBtu for natural gas, $45.89 per Bbl for NGLs, and $81.48 per Bbl for oil for the Appalachian Basin based on a $94.42 WTI reference price. (3) 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. 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 2013, 2014 and 2015 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 2015 The following table summarizes the changes in our estimated proved reserves during 2015 (in Bcfe): Proved reserves, December 31, 2014 12,683 Extensions, discoveries, and other additions 2,878 Partial ethane recovery 1,091 Performance revisions (358) Revisions due to 5-year development rule (2,332) Price revisions (202) Production (545) Proved reserves, December 31, 2015 13,215 Extensions, discoveries, and other additions of 2,878 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales. Upward revisions of 1,091 Bcfe due to partial ethane recovery is a result of changing from ethane rejection at December 31, 2014 to partial ethane recovery in 2015. In 2015, we began ethane recovery and changed our underlying production assumptions to the recovery of approximately 11,500 gross barrels per day of ethane at December 31, 2015. Negative performance revisions of 358 Bcfe resulted from the revised statistical analysis of reserves based on actual production results. Negative revisions of 2,332 Bcfe were due to the SEC 5-year development rule because we no longer expect certain locations in the eastern portion of our Marcellus acreage containing primarily dry gas to be developed within five years. Negative revisions of 202 5
Table of Contents Bcfe were due to the decreases in prices for natural gas, NGLs, and oil. Our estimated proved reserves as of December 31, 2015 totaled approximately 13.2 Tcfe and increased by 4% over the prior year. Proved Undeveloped Reserves Proved undeveloped reserves are included in the previous table of total proved reserves. The following table summarizes the changes in our estimated proved undeveloped reserves during 2015 (in Bcfe): Proved undeveloped reserves, December 31, 2014 8,880 Extension, discoveries, and other additions 2,355 Reclassifications to proved developed reserves (986) Performance revisions (445) Revisions due to 5-year development rule (2,332) Price revisions (95) Proved undeveloped reserves, December 31, 2015 7,377 Extensions, discoveries, and other additions during 2015 of 2,355 Bcfe of proved undeveloped reserves resulted from delineation and developmental drilling in the Marcellus and Utica Shales. Development drilling resulted in the reclassification of 986 Bcfe to proved developed reserves. Negative performance revisions of 445 Bcfe resulted from lower estimated ultimate recoveries from certain undeveloped wells. Negative revisions of 2,332 Bcfe were due to the SEC 5- year development rule because we no longer expect certain locations in the eastern portion of the Marcellus acreage containing primarily dry gas to be developed within five years. Negative revisions of 95 Bcfe were due to decreases in the prices for natural gas, NGLs, and oil. Proved undeveloped reserves include reserves that are expected to be drilled and developed within five years; wells that are not drilled within five years from booking are reclassified from proved reserves to probable reserves. During the year ended December 31, 2015, we converted approximately 986 Bcfe of proved undeveloped reserves to proved developed reserves at a total capital cost of approximately $577 million. Estimated future development costs relating to the development of our proved undeveloped reserves at December 31, 2015 are approximately $5.1 billion over the next five years, which we expect to finance through cash flows from operations, borrowings under our revolving credit facility, and other sources of capital financing. Our drilling programs to date have focused on proving our unproved leasehold acreage through delineation drilling. 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. All of our proved undeveloped reserves are expected to be developed over the next five years. 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." Preparation of Reserve Estimates Our reserve estimates as of December 31, 2013, 2014, and 2015 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 35 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 6
Table of Contents 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 expires, 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 Bcf per 1,000 feet from our proved developed producing wells. 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 statistical 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 statistical proven area in the Utica Shale and (ii) each proved developed producing well in the Utica Shale only generates four direct offset well locations in the Utica Shale due to less relative maturity. Identification of Potential Well Locations Our identified potential well locations include locations to which proved, probable or possible reserves were attributable based on SEC pricing as of December 31, 2015. 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 price that we receive for our production is 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. Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. The significant commodity price declines in late 2014 through 2015 and into 2016 are the most recent example of such volatility. A 7
Table of Contents 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—Appalachian Basin The following table sets forth information regarding our production, realized prices, and production costs in the Appalachian Basin for the years ended December 31, 2013, 2014 and 2015. 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, 2013 2014 2015 Production data: Natural gas (Bcf) 177 317 439 NGLs (MBbl)(1) 2,123 7,102 15,550 Oil (MBbl) 226 1,311 2,078 Combined (Bcfe) 191 368 545 Daily combined production (MMcfe/d) 522 1,007 1,493 Average prices before effects of derivative settlements: Natural gas (per Mcf) $ 3.90 $ 4.10 $ 2.37 NGLs (per Bbl)(1) $ 52.61 $ 46.23 $ 17.01 Oil (per Bbl) $ 91.27 $ 81.65 $ 34.05 Combined average sales prices before effects of derivative settlements (per Mcfe)(2) $ 4.31 $ 4.73 $ 2.52 Combined average sales prices after effects of derivative settlements (per Mcfe)(2) $ 5.17 $ 5.10 $ 4.10 Average Costs (per Mcfe): Lease operating $ 0.05 $ 0.08 $ 0.07 Gathering, compression, processing, and transportation $ 1.15 $ 1.26 $ 1.21 Production and ad valorem taxes $ 0.26 $ 0.24 $ 0.14 Depletion, depreciation, amortization, and accretion $ 1.23 $ 1.30 $ 1.31 General and administrative (before equity-based compensation) $ 0.32 $ 0.28 $ 0.25 (1) NGLs information for 2015 includes ethane production of approximately 201 MBbl at an average realized price of $6.17 per Bbl. (2) Average prices shown reflect both the before and after effects of our commodity hedging transactions. Our calculation of such effects includes gains or losses recognized on settlement of commodity derivatives, which do not qualify for hedge accounting because we do not designate them as hedges. Productive Wells As of December 31, 2015, we had a total of 708 gross (666 net) producing wells, averaging a 94% working interest, in the Marcellus Shale. This well count includes 437 gross (426 net) horizontal wells, and 271 gross (239 net) vertical wells that were primarily acquired in conjunction with leasehold acreage acquisitions. In the Utica Shale, we had 111 gross (95 net) producing horizontal wells at December 31, 2015, averaging an 85% working interest. Our wells are gas wells, many of which also produce oil, condensate, and NGLs. Additionally, at December 31, 2015 we had 118 gross horizontal wells (115 net) waiting on completion or in the process of being completed. Acreage The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of December 31, 2015. A majority of our developed acreage is subject to liens securing our revolving credit facility. 8
Table of Contents Approximately 52% of our Marcellus acreage and 28% of our 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 69,782 68,532 515,914 353,467 585,696 421,999 Utica Shale 23,212 18,813 149,640 128,661 172,852 147,474 Other — — 6,609 6,599 6,609 6,599 Total 92,994 87,345 672,163 488,727 765,157 576,072 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 Acres Acres Doddridge, WV 196,137 138,659 Gilmer, WV 15,683 10,916 Harrison, WV 117,616 99,979 Lewis, WV 89 65 Marion, WV 3,626 3,468 Monongalia, WV 1,649 1,455 Pleasants, WV 6,967 3,649 Ritchie, WV 92,401 69,070 Tyler, WV 107,423 63,514 Wetzel, WV 15,870 6,623 Fayette, PA 7,364 5,423 Greene, PA 954 454 Washington, PA 13,131 12,217 Westmoreland, PA 6,786 6,507 Total Marcellus Shale 585,696 421,999 Ohio Utica Gross Net Acres Acres Athens, OH 84 84 Belmont, OH 15,354 14,618 Guernsey, OH 5,927 4,620 Harrison, OH 577 577 Monroe, OH 59,494 55,647 Noble, OH 88,349 69,497 Washington, OH 3,067 2,431 Total Utica Shale 172,852 147,474 Total Marcellus and Utica Shale 758,548 569,473 Undeveloped Acreage Expirations The following table sets forth the number of total gross and net undeveloped acres as of December 31, 2015 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 such acreage is extended or renewed. Marcellus Ohio Utica Total Gross Net Gross Net Gross Net Acres Acres Acres Acres Acres Acres 2016 17,552 10,058 18,596 13,036 36,148 23,094 2017 62,127 38,234 51,660 42,212 113,787 80,446 2018 53,380 33,776 28,463 23,069 81,843 56,845 9
Table of Contents Drilling Activity The following table sets forth the results of our drilling activity for wells drilled and completed during the years ended December 31, 2013, 2014, and 2015. Gross wells reflect the sum of all wells in which we own an interest and includes historical drilling activity in the Appalachian Basin. Net wells reflect the sum of our working interests in gross wells. Year ended December 31, 2013 2014 2015 Gross Net Gross Net Gross Net Marcellus Development wells: Productive 49 48 77 76 69 68 Dry — — — — — — Total development wells 49 48 77 76 69 68 Exploratory wells: Productive 63 62 43 42 5 5 Dry — — — — — — Total exploratory wells 63 62 43 42 5 5 Utica Development wells: Productive 3 3 11 10 21 18 Dry — — — — — — Total development wells 3 3 11 10 21 18 Exploratory wells: Productive 13 10 23 19 37 33 Dry — — — — — — Total exploratory wells 13 10 23 19 37 33 Total Development wells: Productive 52 51 88 86 90 86 Dry — — — — — — Total development wells 52 51 88 86 90 86 Exploratory wells: Productive 76 72 66 61 42 38 Dry — — — — — — Total exploratory wells 76 72 66 61 42 38 The figures in the table above do not include 118 gross wells (115 net) waiting on completion or in the process of being completed at December 31, 2015. 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. 10
Table of Contents As of December 31, 2015, our firm sales commitments through 2020 included: Firm Volume of Transport Volume Natural Capacity of Gas Utilized Ethane Year Ending December 31, (MMBtu/d) (MMBtu/d) (Bbl/day) 2016 1,010,000 890,000 2,900 2017 950,000 830,000 11,500 2018 1,130,000 1,010,000 11,500 2019 1,150,000 1,040,000 11,500 2020 1,060,000 1,020,000 11,500 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 deliver products to pipeline transporters 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 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, compression, processing, and transportation 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. Prior to Antero Midstream's initial public offering in November 2014 (the "IPO"), we committed to developing the necessary midstream infrastructure to support our drilling schedule and production growth. We accomplished this goal through a combination of internal asset developments and contractual relationships with third‑party midstream service providers. As part of our internal developments, we invested a significant amount of capital in building low‑ and high‑pressure gathering lines, and compressor stations. Since its IPO in November 2014, we have leveraged our relationship with Antero Midstream to support our growth. In 2015, Antero Midstream spent approximately $320 million on midstream gas and condensate gathering and compression infrastructure that services our production. As of December 31, 2015, Antero Midstream, owned and operated 182 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 Crestwood, Energy Transfer Partners L.P., and Summit Midstream. As of December 31, 2015, Antero Midstream owned and operated 8 compressor stations and we utilized 14 additional third‑party compressor stations in the Marcellus Shale. The gathering, compression and dehydration services provided by third parties are contracted on a fixed‑fee basis. As of December 31, 2015, Antero Midstream owned and operated 110 miles of low‑pressure, high‑pressure, and condensate pipelines in the Utica Shale, and Antero owned and operated 8 miles of high-pressure pipelines. As of December 31, 2015, Antero Midstream owned and operated 1 compressor station and we utilized 5 third‑party compressor stations in the Utica Shale. Pursuant to our gathering and compression services agreement with Antero Midstream entered into in 2014, we dedicated substantially all of our current and future acreage for gathering and compression services for 20 years. All of our existing acreage is dedicated to Antero Midstream for gathering and compression services except for acreage attributable to third party commitments in effect prior to the Antero Midstream IPO, which includes 136,000 Marcellus Shale net leasehold acres characterized by dry gas and liquids rich reserves that have been previously dedicated to third party gatherers. In addition to our existing acreage dedication, the agreement provides that any acreage we acquire in the future will be dedicated to Antero Midstream for gathering and compression services unless such acreage is subject to a pre- existing dedication for such services. Antero Midstream also provides condensate gathering services to us under the gathering and compression agreement. 11
Table of Contents 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 and fractionated into their key components. Fractionation refers to the process by which a NGLs stream is separated into individual NGLs products such as ethane, propane, normal butane, isobutane, and natural gasoline. Fractionation occurs by heating the mixed NGL stream to allow for the separation of the component parts based on the specific boiling points of each product. Each of the individual products have their 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 separated out 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 will 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 most of the ethane when processing our liquids‑rich gas. However, we realize a pricing upgrade when selling the remaining NGL products 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 December 2015, we began recovering some ethane as the first de-ethanizer was placed on line at the Sherwood gas processing facility, and our first international ethane sales contract is expected to commence in 2017. Through third‑party contractual relationships, we have obtained committed cryogenic processing capacity for our Marcellus and Utica Shale production. We have contracted with MarkWest Energy Partners L.P. to provide processing capacity as follows: Antero Plant Contracted Firm Processing Processing Capacity Capacity Anticipated Date (MMcf/d) (MMcf/d) of Completion Marcellus Shale: Sherwood I 200 200 In service Sherwood II 200 200 In service Sherwood III 200 150 In service Sherwood IV 200 200 In service Sherwood V 200 200 In service Sherwood VI 200 200 In service Sherwood VII 200 200 2017 Marcellus Shale Total 1,400 1,350 Utica Shale: Seneca I 200 150 In service Seneca II 200 50 In service Seneca III 200 200 In service Seneca IV 200 200 In service Utica Shale Total 800 600 Transportation and Takeaway Capacity Our primary firm transportation commitments include the following: · 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. · We have several firm transportation contracts with pipelines that have capacity to deliver natural gas to the Chicago and 12
Table of Contents 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 will deliver gas to downstream contracts on MGT, NGPL, and ANR. We have 165,000 MMBtu per day of firm transportation on MGT which will increase by an additional 125,000 MMBtu per day in March 2016. We have 235,000 MMBtu per day of firm transportation on NGPL which will increase by an additional 75,000 MMBtu per day in November 2016. Both of these contracts will deliver gas to the Chicago city gate area.In addition, we have 200,000 MMBtu per day of firm transportation on ANR-Chicago to deliver natural gas to Chicago in the summer and Michigan in the winter. The 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 Company pipeline ("Tennessee"), ANR Pipeline Company pipeline ("ANR-Gulf"), Equitrans pipeline ("EQT"), and the M3 Appalachian Gathering System ("M3"). This diverse portfolio of firm capacity gives us the flexibility to move natural gas to the local Appalachia market or other preferred markets, thereby allowing the company to diversify its exposure to indices with less favorable pricing. o We have several firm transportation contracts on TCO for volumes that total to approximately 582,000 MMBtu per day. Of the 582,000 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 Stonewall Gas Gathering for 1,100,000 MMBtu per day which will transport 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 590,000 MMBtu per day to 790,000 MMBtu per day in June 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 June 2018. These contracts expire at various dates from 2030 through 2037. 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, estimated to be in-service in mid 2017, on the Energy Transfer Rover Pipeline which will connect the Marcellus and Utica Shale assets to Midwest and Gulf Coast markets, or for export to Canadian 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 other various delivery points. The contracts expire at various dates from 2021 through 2025. o We have firm transportation contracts for 375,000 MMBtu per day on the M3 Appalachian Gathering System to deliver Marcellus natural gas to TETCO M2 and other various local delivery points. · 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 50,000 Bbl per day of propane or butane from Hopedale, Ohio to Marcus Hook, Pennsylvania. 13
Table of Contents The expected in-service date of Mariner East 2 is early 2017. These contracts expire on the tenth anniversary from the in- service date. The Mariner East 2 provides access to international markets via trans-ocean cargo 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 2016 annual production levels, we estimate that we could incur total annual net marketing costs of $95 million to $125 million in 2016 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, we contributed (i) all of the outstanding limited liability company interests of Antero Water to Antero Midstream and (ii) all of the assets, contracts, rights, permits and properties owned or leased by us and used primarily in connection with the construction, ownership, operation, use or maintenance of our advanced wastewater treatment complex to be constructed in Doddridge County, West Virginia, to Antero Treatment, 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 waste water 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 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, 2015, Antero Midstream had the ability to store a total of 4.9 million barrels of fresh water in 35 impoundments. Due to the extensive geographic distribution of Antero Midstream's water pipeline systems in both West Virginia and Ohio, it has provided water delivery services to neighboring oil and gas producers within and adjacent to our operating area, and is able to provide water delivery services to other oil and gas producers in the area, subject to commercial arrangements, in an effort to further reduce water truck traffic. As of December 31, 2015, Antero Midstream owned and operated 104 miles of buried fresh water pipelines and 80 miles of movable surface fresh water pipelines in the Marcellus Shale, as well as 22 centralized water storage facilities equipped with transfer pumps. As of December 31, 2015, Antero Midstream owned and operated 49 miles of buried fresh water pipelines and 26 miles of movable surface fresh water pipelines in the Utica Shale, as well as 13 centralized water storage facilities equipped with transfer pumps. In August 2015, we 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 our water handling systems. The wastewater treatment complex, once completed, 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 expected to be in service near the end of 2017. Late in 2015, Antero Midstream began providing us with waste water services for our well completion operations, including waste water transportation, disposal, and treatment. Major Customers For the year ended December 31, 2015, three of our customers accounted for approximately 19%, 18%, and 13% of our total product revenues, respectively. For the year ended December 31, 2014, three of our customers accounted for 29%, 16%, and 12% of our total product revenues, respectively. For the year ended December 31, 2013, two of our customers accounted for 30% and 14% or our total product revenues, respectively. Although a substantial portion of our production is purchased by these major customers, we do not believe the loss of any one or several customers would have a material adverse effect on our business, as we believe other customers or markets would be accessible to us. 14
Table of Contents Title to Properties We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, often in the case of undeveloped properties, cursory investigation of record title is made at the time of lease acquisition. Investigations are made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use, or affect the value of, the properties. Burdens on properties may include: · customary royalty interests; · liens incident to operating agreements and for current taxes; · obligations or duties under applicable laws; · development obligations under natural gas leases; or · net profits interests. Seasonality Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. Cold winters can significantly increase demand and price fluctuations. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the 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 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 the production, transportation and sale of oil, natural gas and NGLs. We believe compliance with existing requirements will not have a material 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 industries 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. 15
Table of Contents Regulation of Production of Natural Gas and Oil We own interests in properties located onshore in three U.S. states, 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 oil, natural gas, and NGLs 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 for 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 service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has not made any formal determinations with respect to any of our facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to regulation as a natural gas company. The distinction between FERC‑regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case‑by‑case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally include various safety, environmental and, in some circumstances, nondiscriminatory‑take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future. Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Regulation of Sales of Natural Gas, NGLs, and Oil The prices at which we sell natural gas, NGLs, and oil is not currently subject to federal regulation and, for the most part, is 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 16
Table of Contents 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 does 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. 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 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 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 a permit 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, require some form of remedial 17
Table of Contents 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 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 capital expenditures, results of operations or financial position. 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. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as waste solvents, laboratory wastes and waste compressor oils that may become regulated as hazardous wastes if such wastes have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies. We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production activities for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off‑ site 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 18
Table of Contents 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, new EPA and U.S. Army Corps of Engineers rules defining the scope of the EPA's and the Corps' jurisdiction became effective. 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 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. The process for obtaining permits has the potential to delay the development of 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 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. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. 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, or NESHAP, programs. These final rules require, among other things, the reduction of volatile organic compound, or 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. More recently, 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 August 2015, the EPA announced proposed rules that would establish new air emission controls for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities, known as NSPS Quad Oa. The EPA's proposed 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 19
Table of Contents completions. In addition, the rule package would extend 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. More recently, in January 2016, Pennsylvania announced new rules that will require the Pennsylvania Department of Environmental Protection, or PADEP, to develop a new general permit for oil and gas exploration, development, and production facilities and liquids loading activities, requiring best available technology for equipment and processes, enhanced record-keeping, and quarterly monitoring inspections for the control of methane emissions. The PADEP also intends to issue similar methane rules for existing sources. In addition, the department has also proposed to establish Best Management Practices, including leak detection and repair, or LDAR, programs, to reduce fugitive methane emissions from production, gathering, processing, and transmission facilities. These rules have the potential to increase our compliance costs. We have been making efforts to reduce methane emissions since March 2005, when we engaged local community groups in Colorado regarding its activities in the Piceance Basin in discussions on how to minimize impacts from its operations. As noted above, 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 VOCs from hydraulically fractured natural gas wells. Green completions have the added benefit of reducing methane emissions from our operations. 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 believe we have a long history of managing methane emissions from our operations, as demonstrated by our longstanding use of green completions. When we permit a facility, we are required to install pollution control equipment at the wellsite in accordance with the requirements of the NSPS for New Stationary Sources. At wellpads, this consists of installing combustors with a control efficiency of 98% to control tank methane and VOC emissions. In addition to combustors, we also install Vapor Recovery Units, or VRUs, in order to capture methane and VOC emissions and direct them down the sales line, rather than flaring those emissions. Per applicable regulations, we also install low-bleed pneumatic controls at wellpads, which serve to reduce methane emissions. We may also install Vapor Recovery Towers, or VRTs, to further reduce methane and VOC flashing emissions from storage tanks when we have more than a nominal amount of oil production in order to produce sufficient gas to allow safe and proper running of the VRTs. At compressor stations, through the use of non-selective catalytic reduction, we reduce methane and VOC emissions from engines by at least 70%. Compressor Station tank and dehydration units are typically controlled by combustors or VRUs. We control our methane and VOC emissions consistent with available emission control technology as required by law and as applicable to our operations. Our methane and VOC control program consists of installing the emission controls described above, performing inspections, and conducting preventative maintenance and repairs to minimize emissions leakage. For example, we have implemented an LDAR program for our well pad and compressor station operations. During 2015, we added two fulltime staff members to manage the LDAR program. LDAR program inspections utilize a state of the art Forward Looking Infrared camera to identify equipment leaks. Our Operations group has a maintenance program in place, which includes cleaning, greasing and replacing thief hatch seals, and other measures as required to further minimize the potential for leaks, In 2015, we implemented new thief hatch designs with improved seals for our tanks. While the LDAR program is not mandatory in all areas of our operations, we have implemented it uniformly across all of our activities. We believe that our efforts to date have resulted in a declining volume of methane emissions based on the decreasing number of leaks detected as part of our LDAR program. In addition, since 2011 and in accordance with EPA regulations, we have monitored or calculated our GHG emissions, including emissions of methane, and reported them to the EPA on an annual basis. Our current report of GHG emissions from covered operations during 2015 will be submitted to the EPA by March 31, 2016. Overall, through the use of Green Completions we have seen significant decreases in GHG emissions from our operations. Furthermore, we believe that our efforts to comply with the 2012 NSPS Quad O have resulted in us being well positioned to comply with the EPA's recently proposed NSPS Quad Oa regulations to reduce methane and VOC emissions from oil and natural gas operations. However, additional compliance measures and expenditures will most likely be required to comply with EPA's proposal, if finalized. While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs 20
Table of Contents to reduce emissions of GHGs associated with our operations. Severe limitations on GHG emissions could also adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that some 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 and other climatic events; if any such effects were to occur, they 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 proposed in April 2015 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. 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. Certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration‑wide review of hydraulic fracturing practices. In June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources, which concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized after a public comment period and a formal review by the EPA's Science Advisory Board. In addition, the U.S. Department of the Interior published a final rule in March 2015 that would implement updated requirements for hydraulic fracturing activities on federal lands, including new requirements relating to public disclosure, well bore integrity and handling of flowback water. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule pending a final decision on whether it may be implemented. Other governmental agencies, including the U.S. Department of Energy have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. 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. 21
Table of Contents 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 is required to make a determination as to whether more than 250 species as endangered or threatened should be listed under the ESA by no later than 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 2015, nor do we anticipate that such expenditures will be material in 2016. Employees As of December 31, 2015, we had 480 full‑time employees, including 57 in executive, finance, treasury and administration, 22 in geology, 186 in production and engineering, 90 in midstream, 76 in land, and 49 in accounting. Our future success will depend partially on our ability to attract, retain, and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory. We utilize the services of independent contractors to perform various field and other services. 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. 22
Table of Contents 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 natural gas, including liquefied natural gas; · 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. 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. during winter months, and strong competition among oil producing countries for market share. These events continued into 2015 and early 2016 and, along with slower economic growth in China, have led to a further decline in commodity prices. Spot prices for WTI declined from approximately $106.00 per Bbl in June 2014 to less than $50.00 per Bbl in January 2015, and declined further to less than $30.00 per Bbl in January 2016. Spot prices for Henry Hub natural gas declined from approximately $4.40 per MMBtu in January 2014 to $3.00 per MMBtu in January 2015, and declined further to less than $1.80 per MMBtu for a brief period in December 2015. Spot prices for propane, which is the largest source of our NGLs sales revenue, declined from approximately $1.55 per gallon in January 2014 to less than $0.50 per gallon in January 2015, and declined further to less than $0.35 per gallon in January 2016. Lower commodity prices reduce our cash flows 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. 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 natural gas reserves. The natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the exploration, development, and acquisition of natural gas reserves. Our cash flow used in investing activities related to drilling, completions, and land expenditures was approximately $1.8 billion in 2015. Our board of directors has approved a capital budget for 2016 of $1.4 billion that includes $1.3 billion for drilling and completion and $100 million for core leasehold acreage acquisitions. 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 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 23
Table of Contents timing of our future capital expenditures may differ materially from our estimates 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 sustained period of commodity prices at current levels or a further reduction in commodity prices from current levels may result in an additional 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 is subject to semi-annual redetermination by our lenders, which could result in a reduction of our borrowing base. This may 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; 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 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. Drilling for and producing natural 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 natural gas production. 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: · further or prolonged declines in oil, NGLs, and natural gas prices; · limitations in the market for oil, NGLs, and natural gas; · 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; 24
Table of Contents · 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 · title problems. 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. 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 in light of recent commodity price declines, 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 $4.0 billion. Our borrowing base is redetermined by the lenders twice per year, and the next scheduled borrowing base redetermination is expected to occur in April 2016. Our borrowing base may decrease as a result of current oil and natural gas price levels, a further decline in oil or natural gas 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 current or further 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. 25
Table of Contents Due to the decline in commodity prices in 2014 and 2015 and the sustained weakness in commodity prices through the first quarter of 2016, the financial markets have exerted downward pressure on stock prices and credit capacity for companies throughout the energy industry. In particular, the market for senior unsecured notes has become 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. If the market for high-yield debt securities does not improve, or if we are unable to access alternative means of 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. 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, 2015, 56% of our total estimated proved reserves were classified as proved undeveloped. Our approximately 7.4 Tcfe of estimated proved undeveloped reserves will require an estimated $5.1 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. 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 2045, our gas processing, gathering, and compression services agreements expire at various dates from 2016 to 2028, and our water services agreement with Antero Midstream expires in 2035. We are obligated to pay fees on minimum volumes to our service providers regardless of actual volume throughput. As of December 31, 2015, our long‑term contractual obligations under agreements with minimum volume commitments totaled over $17 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 or operations. Based on current projected 2016 annual production levels, we estimate that we could incur total annual net marketing costs of $95 million to $125 million in 2016 for unutilized transportation capacity depending on the amount of unutilized capacity that can be marketed to third parties or utilized to transport third party gas and capture positive basis differentials. Additionally, in years subsequent to 2016, 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. Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure through a cased and cemented wellbore into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations, as does most of the domestic oil and natural gas industry. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and issued permitting guidance in February 2014 regarding such activities. Also, in May 2014, the EPA proposed rules under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; however, to date, no further action has 26
Table of Contents been taken on the proposal. The EPA also proposed in April 2015 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. 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. Certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration wide review of hydraulic fracturing practices. In June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources, which concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized after a public comment period and a formal review by the EPA's Science Advisory Board.. In addition, the U.S. Department of the Interior published a final rule in March 2015 that would implement updated requirements for hydraulic fracturing activities on federal lands, including new requirements relating to public disclosure, well bore integrity and handling of flowback water. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision is pending, however. Other governmental agencies, including the U.S. Department of Energy have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities. Our revolving credit facility contains a number of significant covenants (in addition to covenants restricting the incurrence of additional indebtedness), including restrictive covenants that may limit our ability to, among other things: · sell assets; · make loans to others; · make investments; · enter into mergers; · make certain payments; · hedge future production; · incur liens; and · engage in certain other transactions without the prior consent of the lenders. 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. 27
Table of Contents 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 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 2015, we had estimated average outstanding borrowings under our revolving credit facilities of approximately $1.2 billion, and the impact of a 1.0% increase in interest rates on this amount of indebtedness would result in increased interest expense for that period of approximately $12 million and a corresponding decrease in our net income before the effects of income taxes. Recent and continuing 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, 2015, we had entered into a number of hedge contracts for approximately 3.5 Tcfe of our projected natural gas, NGLs, and oil production through December 31, 2022. We are currently realizing a significant benefit from these hedge positions. For example, for the years ended December 31, 2014 and 2015, we received approximately $136 million and $857 million, respectively, in revenues from cash settled derivatives pursuant to our hedges. Many of the hedge agreements that resulted in these realized gains for the years ended December 31, 2014 and 2015 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. The sustained weakness in commodity prices in 2015 and through the first quarter of 2016 has adversely affected 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. 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, 2014 and 2015, approximately 73% and 88%, respectively, of our production was protected by price declines from 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 28
Table of Contents swaps. As of December 31, 2015, we had entered into hedging contracts through December 31, 2022 covering a total of approximately 3.5 Tcfe of our projected natural gas, NGLs, and oil production at an average index price of $3.79 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, 2015, the estimated fair value of our commodity derivative contracts was approximately $3.1 billion. Any default by the counterparties to these derivative contracts when they become due would have a material adverse effect on our financial condition and results of operations. The fair value of our commodity derivative contracts at December 31, 2015 includes the following values by bank counterparty: Morgan Stanley—$691 million; Barclays—$593 million; JP Morgan—$575 million; Citigroup—$362 million; Wells Fargo—$285 million; Scotiabank—$214 million; BNP Paribas—$188 million; Toronto Dominion Bank—$76 million; Fifth Third Bank—$41 million; Canadian Imperial Bank of Commerce—$37 million; Bank of Montreal—$29 million; SunTrust—$17 million; Capital One—$8 million; and Natixis —$1 million. The credit ratings of certain of these banks have been downgraded in recent years because of 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. 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. 29
Table of Contents 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. 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 and oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, 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, 2015, we had 3,719 identified potential horizontal well locations. 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 85% 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 85% 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 48% and 72% 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." 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, Ohio and Pennsylvania. At December 31, 2015, 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 oil, natural gas or NGLs. Furthermore, substantially all of our liquids rich natural gas is process 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 and results of operations. 30
Table of Contents We may incur losses as a result of title defects in the properties in which we invest. It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. Leases in the Appalachian Basin are particularly vulnerable to title deficiencies due to the long history of land ownership in the area, resulting in extensive and complex chains of title. Additionally, there are claims against us alleging that certain acquired leases that are held by production are invalid due to production from the producing horizons being insufficient to hold title to the formation rights that we have purchased. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. 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 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 production will decline, which would adversely affect our future cash flows and results of operations. Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploration and development activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future natural gas reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected. Conservation measures and technological advances could reduce demand for oil and natural gas. Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows. The inability of our significant customers to meet their obligations to us may adversely affect our financial results. In addition to credit risk related to receivables from commodity derivative contracts, our principal exposures to credit risk are through joint interest receivables ($35 million at December 31, 2015) and the sale of our production ($124 million in receivables at December 31, 2015), which we market to energy marketing companies, end users, and refineries. 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 wish to 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, 2015 purchased approximately 19% of our operated production. 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. 31
Table of Contents Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities. We may incur significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our exploration, development and production activities. These delays, costs and liabilities could arise under a wide range of federal, regional, state and local laws and regulations relating to protection of the environment and worker health and 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. For example, we have received a Notice of Violation, or "NOV", from the West Virginia Department of Environmental Protection, or WVDEP, related to a drilling incident that occurred in Doddridge County, West Virginia. In September 2014, while drilling a new well, our drilling contractor came into contact with an existing well, resulting in a release of methane gas and potential temporary impacts to groundwater. Groundwater monitoring to date has not identified any significant concerns related to this incident. We continue to work with the WVDEP to resolve this matter but believe it could result in monetary sanctions exceeding $100,000. 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 worker health and 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 and Pennsylvania in which the plaintiffs have alleged that our oil and natural gas activities exposed them to hazardous substances and damaged their properties. 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 or results of operations. Our natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing natural gas, including the possibility of: · environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination; · abnormally pressured formations; · mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse; · fires, explosions and ruptures of pipelines; · personal injuries and death; · natural disasters; and · terrorist attacks targeting natural gas and oil related facilities and infrastructure. 32
Table of Contents 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 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 that we have entered into with Antero Midstream, Antero Midstream has a right to bid to provide certain processing, fractionation, transportation and marketing 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 favorable pricing or more efficient service. We will also be limited in our ability to use other processing, fractionation, transportation and marketing services providers in any area to the extent Antero Midstream is able to offer a competitive bid. In connection with the closing of the sale of our water handling and treatment business to Antero Midstream on September 23, 2015, we entered into a Water Services Agreement with Antero Water. Pursuant to the Water Services Agreement, we 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 Ohio and West Virginia. 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. 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 results of operations and financial condition. 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 viable. The use of micro‑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; · title problems; 33
Table of Contents · 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, 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 system capacity. In addition, if natural gas, NGLs, or oil quality specifications for the third‑party natural gas, NGLs, or oil pipelines with which we connect change so as to restrict our ability to transport natural gas, NGLs, or oil, 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. 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 and results of operations. Changes to existing or new regulations may unfavorably impact us, could result in increased operating costs and have a material adverse effect on our financial condition and results of operations. 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, equipment, supplies, personnel, and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis. The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers, and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations. 34
Table of Contents 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 million 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. More recently, in December 2015, the EPA finalized rules added new sources to the scope of the GHG monitoring and reporting rule. These new sources include gathering and boosting facilities, as well as completions and workovers of hydraulically fractured wells. The revisions also include the addition of well identification reporting requirements for certain facilities. These changes to EPA's GHG emissions reporting rule could result in increased compliance costs. In addition, in August 2015, the EPA announced proposed rules that would establish new air emission controls for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The EPA's proposed 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 would extend existing VOC standards under the EPA's Subpart OOOO to include previously unregulated equipment within the oil and natural gas source category. More recently, in January 2016, Pennsylvania announced new rules that will require the PADEP to develop a new general permit for oil and gas exploration, development, and production facilities and liquids loading activities, requiring best available technology for equipment and processes, enhanced record-keeping, and quarterly monitoring inspections for the control of methane emissions. The PADEP also intends to issue similar methane rules for existing sources. In addition, the department has also proposed to establish Best Management Practices, including leak detection and repair, or LDAR, programs, to reduce fugitive methane emissions from production, gathering, processing, and transmission facilities. These rules have the potential to increase our compliance costs. While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or 35
Table of Contents 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. Severe limitations on GHG emissions could also adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that some 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 and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations. 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 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. 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. 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. 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; 36
Table of Contents · 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. Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to natural gas and oil exploration and production. Additionally, future federal or state legislation may impose new or increased taxes or fees on natural gas and oil extraction may be imposed, as a result of future legislation. Potential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination of certain key-U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal and state income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to natural gas and oil exploration and development, and any such change could negatively affect our financial condition and results of operations. Moreover, President Obama has proposed, as part of the Budget of the United States Government for Fiscal Year 2017, to impose an "oil fee" of $10.25 on a per barrel equivalent of crude oil. This fee would be collected on domestically produced and imported petroleum products. The fee would be phased in evenly over five years, beginning October 1, 2016. The adoption of this, or similar proposals, could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil. Pennsylvania imposes an annual natural gas impact fee on natural gas and oil operators in Pennsylvania for each well drilled for a period of fifteen years. The fee is on a sliding scale set by the Public Utility Commission and is based on two factors: changes in the Consumer Price Index and the average NYMEX natural gas prices from the last day of each month. There can be no assurance that the impact fee will remain as currently structured or that new or additional taxes will not be imposed. 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. There is currently no severance tax imposed on natural gas or oil in Pennsylvania. However, it is possible that each of these states 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. 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. 37
Table of Contents 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. Item 1B. Unresolved Staff Comments Not applicable. Item 3. Legal Proceedings In March 2011, we received orders for compliance from federal regulatory agencies, including the EPA 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. No fine or penalty relating to these matters has been proposed at this time, but we believe that these actions will result in monetary sanctions exceeding $100,000. We are unable to estimate the total amount of such monetary sanctions or costs to remediate these locations in order to bring them into compliance with applicable environmental laws and regulations. We have not, however, been required to suspend our operations at these locations to date, and management does not expect these matters to have a material adverse effect on our financial condition, results of operations, or cash flows. In September 2014, we received a NOV from the WVDEP related to a drilling incident that occurred in Doddridge County, West Virginia. While drilling a new well, our drilling contractor came into contact with an existing well, resulting in a release of methane gas and potential temporary impacts to groundwater. In July 2015, we agreed to abatement and remediation plans with the WVDEP and paid a civil administrative penalty of $203,000 in settlement of this matter. During the third quarter of 2015, the WVDEP issued Antero Midstream a NOV for improper installation of an engine catalyst at the startup of the North Canton Compressor Station. Antero Midstream continues to negotiate with the WVDEP to resolve this matter, but believes that it could result in monetary sanctions exceeding $100,000; however, we do not expect that any ultimate sanction will have a material adverse impact on the financial condition, results of operations, or cash flows of Antero Midstream. The Company is the subject of two nearly identical lawsuits brought by South Jersey Gas Company and South Jersey Resources Group, LLC (collectively "SJGC") filed on February 4, 2015 in the Superior Court of New Jersey. The lawsuits have since been consolidated into one case. SJGC are purchasers of some of the Company's natural gas production under contracts entered into in 2011. Deliveries under the contracts began in October 2011 and the delivery obligation continues through October 2019. SJGC allege that the index prices specified in the contracts, and the index prices at which SJGC paid for deliveries from 2011 through September 2014, are no longer appropriate under the contracts because a market disruption event (as defined by the contract) has occurred and, as a result, a new index price is to be determined by the parties. The lawsuit seeks a reformation of the contracts, compensatory and punitive damages to be determined at trial, and costs and expenses of the actions. Beginning in October 2014, SJGC began paying the Company under indexes unilaterally selected by SJGC and not specified in the contract. The Company contends that no market disruption event has occurred and that SJGC has breached the contracts by failing to pay the Company based on the express price terms of the contracts. The Company further contends that jurisdiction and venue are improper in New Jersey. On March 30, 2015, the Company filed suit against SJGC in United States District Court in Colorado seeking relief for breach of contract, damages in the amounts that SJGC has short paid and continues to short pay, as well as costs of the suit. Through December 31, 2015, the Company estimates that it is owed approximately $39 million more than SJGC has paid using the indexes unilaterally selected by them. We are party to various other legal proceedings and claims in the ordinary course of our business. We believe that certain of these matters will be covered by insurance and that the outcome of other matters will not have a material adverse effect on our consolidated financial condition, results of operations, or cash flows. Item 4. Mine Safety Disclosures Not applicable. 38
Table of Contents PART II Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Common Stock We have one class of common shares outstanding, our par value $0.01 per share common stock. Our common stock is traded on the New York Stock Exchange under the symbol "AR." On February 19, 2016, our common stock was held by 55 holders of record. The number of holders does not include the shareholders for whom shares are held in a "nominee" or "street" name. The table below reflects the high and low intraday sales prices per share of the common stock on the New York Stock Exchange for each period presented. Common Stock High Low 2015: Quarter ended December 31, 2015 $26.59 $18.50 Quarter ended September 30, 2015 $34.56 $20.00 Quarter ended June 30, 2015 $46.06 $33.89 Quarter ended March 31, 2015 $42.42 $33.25 2014: Quarter ended December 31, 2014 $56.81 $37.85 Quarter ended September 30, 2014 $66.10 $53.42 Quarter ended June 30, 2014 $67.92 $56.28 Quarter ended March 31, 2014 $68.43 $53.61 Issuer Purchases of Equity Securities The following table sets forth our share repurchase activity for each period presented: Total Number of Maximum Shares Number of Purchased as Shares that Part of May Yet be Total Number Average Publicly Purchased of Shares Price Paid Announced Under the Period Purchased Per Share Plans Plan October 1, 2015 - October 31, 2015 2,657 $ 23.76 — N/A November 1, 2015 - November 30, 2015 — $ — — N/A December 1, 2015 - December 31, 2015 372 $ 20.17 — N/A Shares repurchased represent shares of our common stock transferred to us in order to satisfy tax withholding obligations incurred upon the vesting of restricted stock and restricted stock units held by our employees. Dividend Restrictions Our ability to pay dividends is governed by (i) the provisions of Delaware corporation law, (ii) our Certificate of Incorporation and Bylaws, (iii) indentures related to our 6.00% senior notes due 2020, 5.375% senior notes due 2021, 5.125% senior notes due 2022, and 5.625% senior notes due 2023, and (iv) our revolving credit facility. We have not paid or declared any dividends on our common stock. The future payment of cash dividends on our common stock, if any, is within the discretion of the Board of Directors and will depend on our earnings, capital requirements, financial condition, and other relevant factors. There is no assurance that we will pay any cash dividends on our common stock. We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. 39
Table of Contents Stock Performance Graph The graph below shows the cumulative total shareholder return assuming the investment of $100 on October 10, 2013 in each of Antero common stock, the S&P 500 Index, and the Dow Jones U.S. Exploration and Production Index. We believe the Dow Jones U.S. Exploration and Production Index is meaningful because it is an independent, objective view of the performance of similarly‑sized energy companies. Comparison of Cumulative Total Returns Among Antero Resources Corporation, the S&P 500 Index, and the Dow Jones US Exploration and Production Index 40
Table of Contents Item 6. Selected Financial Data The following table shows our selected historical consolidated financial data, for the periods ended and as of the dates indicated, for Antero Resources Corporation and its subsidiaries (including Antero Midstream Partners LP). The selected statement of operations data and statement of cash flows data for the years ended December 31, 2013, 2014, and 2015 and the balance sheet data as of December 31, 2014 and 2015 are derived from our audited consolidated financial statements included in Item 8 of this Annual Report on Form 10‑K. The selected statement of operations data and statement of cash flows data for the years ended December 31, 2011 and 2012 and the balance sheet data as of December 31, 2011, 2012, and 2013 are derived from our audited consolidated financial statements not included in Item 8 of this Annual Report on Form 10‑K. The statement of operations data for all periods presented has been recast to present the results of operations from our Piceance Basin and Arkoma Basin operations in discontinued operations. The losses on the sales of these properties are also included in discontinued operations in 2012, with adjustments in 2013 and 2014 due to the resolution of certain liabilities recorded at the time of the sales and the settlement of final purchase price adjustments. The results from continuing operations reflect our remaining operations in the Appalachian Basin. No part of our general and administrative expenses or interest expense was allocated to discontinued operations. 41
Table of Contents The selected financial data presented below are qualified in their entirety by reference to, and should be read in conjunction with, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and related notes included elsewhere in this report. Year Ended December 31, (in thousands, except per share amounts) 2011 2012 2013 2014 2015 Statement of operations data: Operating revenues: Natural gas sales $ 195,116 259,743 689,198 1,301,349 1,039,892 NGLs sales — 3,719 111,663 328,323 264,483 Oil sales 173 1,520 20,584 107,080 70,753 Gathering, compression, and water handling and treatment — — — 22,075 22,000 Marketing — — — 53,604 176,229 Commodity derivative fair value gains 496,064 179,546 491,689 868,201 2,381,501 Gain on sale of assets — 291,190 — 40,000 — Total operating revenues 691,353 735,718 1,313,134 2,720,632 3,954,858 Operating expenses: Lease operating $ 4,608 6,243 9,439 29,341 36,011 Gathering, compression, processing, and transportation 37,315 91,094 218,428 461,413 659,361 Production and ad valorem taxes 11,915 20,210 50,481 87,918 78,325 Marketing — — — 103,435 299,062 Exploration 4,034 14,675 22,272 27,893 3,846 Impairment of unproved properties 4,664 12,070 10,928 15,198 104,321 Depletion, depreciation, and amortization 55,716 102,026 233,876 477,896 709,763 Accretion of asset retirement obligations 76 101 1,065 1,271 1,655 General and administrative (including $365,280, $112,252, and $97,877 of equity-based compensation expense in 2013, 2014, and 2015, respectively) 33,342 45,284 425,438 216,533 233,697 Contract termination and rig stacking — — — — 38,531 Loss on sale of compressor station 8,700 — — — — Total operating expenses 160,370 291,703 971,927 1,420,898 2,164,572 Operating income 530,983 444,015 341,207 1,299,734 1,790,286 Other Expenses: Interest expense $ (74,404) (97,510) (136,617) (160,051) (234,400) Loss on early extinguishment of debt — — (42,567) (20,386) — Interest rate derivative fair value losses (94) — — — — Total other expenses (74,498) (97,510) (179,184) (180,437) (234,400) Income before income taxes and discontinued operations 456,485 346,505 162,023 1,119,297 1,555,886 Income tax expense $ (185,297) (121,229) (186,210) (445,672) (575,890) Income (loss) from continuing operations 271,188 225,276 (24,187) 673,625 979,996 Discontinued operations: Income (loss) from results of operations and sale of discontinued operations, net of income tax 121,490 (510,345) 5,257 2,210 — Net income (loss) and comprehensive income (loss) including noncontrolling interest 392,678 (285,069) (18,930) 675,835 979,996 Net income and comprehensive income attributable to noncontrolling interest — — — 2,248 38,632 Net income (loss) attributable to Antero Resources $ 392,678 (285,069) (18,930) 673,587 941,364 Corporation Earnings (loss) per common share: Continuing operations(1) $ 1.04 0.86 (0.09) 2.56 3.43 Discontinued operations(1) $ 0.46 (1.95) 0.02 0.01 — Total $ 1.50 (1.09) (0.07) 2.57 3.43 Earnings (loss) per common share—assuming dilution: Continuing operations(1) $ 1.04 0.86 (0.09) 2.56 3.43 Discontinued operations(1) $ 0.46 (1.95) 0.02 0.01 — Total $ 1.50 (1.09) (0.07) 2.57 3.43 (1) Earnings (loss) per common share and earnings (loss) per common share—assuming dilution for each of the years in the three year period ended December 31, 2013 were calculated as if the shares issued in our IPO on October 16, 2013 were outstanding for the entire period. 42