UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10‑K

 

Commission File No. 001‑36120

ANTERO RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)

 

(303) 357‑7310

(Registrant’s telephone number, including area code)

Securities Registered Pursuant to Section 12(b) of the Act:

 

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

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

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

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S‑K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10‑K or any amendment to this Form 10‑K. ☒

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

 

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

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

The aggregate market value of the voting common stock held by non‑affiliates of the registrant as of June 29, 2018, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $4.1 billion based on the closing price of Antero Resources Corporation’s common stock as reported on that day on the New York Stock Exchange of $21.35.

The registrant had 308,651,020 shares of common stock outstanding as of February 8, 2019.

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

 

 

TABLE OF CONTENTS

 

CAUTIONARY STATEMENT REGARDING FORWARD‑LOOKING STATEMENTS

The information in this report includes “forward‑looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  All statements, other than statements of historical fact included in this Annual Report on Form 10‑K, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward‑looking statements.  Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements, although not all forward‑looking statements contain such identifying words.  These forward‑looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.  When considering these forward-looking statements, investors should keep in mind the risk factors and other cautionary statements described under the heading “Item 1A.  Risk Factors” in this Annual Report on Form 10‑K.  These forward‑looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward‑looking statements may include statements about our:

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

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

Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward‑looking statements.

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

Except as otherwise required by applicable law, we disclaim any duty to update any forward‑looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report on Form 10‑K.

 

GLOSSARY OF COMMONLY USED TERMS

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

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

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

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

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

“Btu.”  British thermal unit.

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

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

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

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

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

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

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

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

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

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

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

“Horizontal drilling.”  A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

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

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

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

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

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

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

 “MMBtu.”  One million British thermal units.

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

“MMcf/d.”  MMcf per day.

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

“MMcfe/d.”  MMcfe per day.

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

“NYMEX.”  The New York Mercantile Exchange.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

 

 

PART I

Items 1 and 2.  Business and Properties

Our Company and Organizational Structure

Antero Resources Corporation (individually referred to as “Antero”) and its subsidiaries (collectively referred to as the “Company”) are engaged in the exploration, development, production, and acquisition of natural gas, NGLs, and oil properties located in the Appalachian Basin.  We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations.  As of December 31, 2018, we held approximately 612,000 net acres of oil and gas properties located in the Appalachian Basin in West Virginia and Ohio.  Our corporate headquarters are in Denver, Colorado.

Antero’s consolidated subsidiary, Antero Midstream Partners LP (“Antero Midstream” or the “Partnership”), is a public master limited partnership formed to own, operate, and develop midstream energy assets to service Antero’s production, drilling, and completion activities under long-term service contracts.  Antero’s consolidated financial statements include Antero Midstream’s financial position and results of operations.

Antero Midstream GP LP (“AMGP”) was originally formed as Antero Resources Midstream Management LLC (“ARMM”) in 2013, to become the general partner of Antero Midstream Partners LP (“Antero Midstream”).  On May 4, 2017, ARMM converted from a Delaware limited liability company to a Delaware limited partnership and changed its name to Antero Midstream GP LP in connection with its initial public offering (“IPO”).  Subsequent to its IPO, AMGP indirectly controls the general partnership interest in Antero Midstream and directly controls Antero IDR Holdings LLC (“IDR LLC”), which owns the incentive distribution rights (“IDRs”) in Antero Midstream.  Antero Resources Corporation does not hold any financial or other interests in AMGP and does not consolidate AMGP for financial reporting purposes.

General

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

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

We have assembled a portfolio of long‑lived properties that are characterized by what we believe to be low geologic risk and repeatability.  Our drilling opportunities are focused in the Marcellus Shale and Utica Shale of the Appalachian Basin.  We have 3,734 potential horizontal well locations on our existing leasehold acreage within our proved, probable, and possible reserve categories.

We have secured sufficient long‑term firm takeaway capacity on major pipelines that are in existence or under construction in each of our core operating areas to accommodate our current development plans.

Together, Antero and Antero Midstream operate in the following industry segments: (i) the exploration, development, and production of natural gas, NGLs, and oil, (ii) gathering and processing, (iii) water handling and treatment, and (iv) marketing of excess firm transportation capacity.  All of our operations are conducted in the United States.  Financial information for our industry segment operations is located under “Note 16 – Segment Information.”

2018 and Recent Developments and Highlights

Reserves, Production, and Financial Results

As of December 31, 2018, our estimated proved reserves were 18.0 Tcfe, consisting of 11.4 Tcf of natural gas, 554 MMBbl of ethane, 498 MMBbl of C3+ NGLs, and 46 MMBbl of oil.  As of December 31, 2018, 63% of our estimated proved reserves by volume were natural gas, 35% were NGLs, and 2% were oil.  Proved developed reserves were 10.4 Tcfe, or 58% of total proved reserves.

For the year ended December 31, 2018, our net production totaled 989 Bcfe, or 2,709 MMcfe per day, a 20% increase compared to 822 Bcfe, or 2,253 MMcfe per day, for the year ended December 31, 2017.  Production growth resulted from an increase in the number of producing wells as a result of our drilling and completion activity.  Our average price received for production, before the effects of gains on settled commodity derivatives, for the year ended December 31, 2018 was $3.69 per Mcfe compared to $3.34 per Mcfe for the year ended December 31, 2017.  Our average realized price after the effects of gains on settled commodity derivatives was $3.94 per Mcfe for the year ended December 31, 2018 as compared to $3.60 per Mcfe for the year ended December 31, 2017.

For the year ended December 31, 2018, we generated consolidated cash flows from operations of $2.1 billion, a consolidated net loss of $398 million, Adjusted EBITDAX of $2.0 billion, and Stand-Alone Adjusted EBITDAX of $1.7 billion.  This compares to consolidated cash flows from operations of $2.0 billion, consolidated net income of $615 million, Adjusted EBITDAX of $1.5 billion, and Stand-Alone Adjusted EBITDAX of $1.2 billion for the year ended December 31, 2017.  See “Item 6.  Selected Financial Data” for a definition of Adjusted EBITDAX (a non‑GAAP measure) and a reconciliation of Adjusted EBITDAX to net income (loss).  See “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations— Stand-Alone Exploration and Production Information” for a definition of Stand-Alone Adjusted EBITDAX and a reconciliation of Stand-Alone Adjusted EBITDAX to Antero’s stand-alone net income (loss).  “Stand-alone” data represents information for Antero on an unconsolidated basis, reflecting Antero’s investment in Antero Midstream under the equity method of accounting.

Consolidated net loss for 2018 included (i) commodity derivative fair value losses of $88 million, comprised of gains on settled derivatives of $243 million, gains on settled derivatives of $370 million related to derivatives that were either fully or partially monetized prior to their settlement dates, and a non-cash loss of $701 million on changes in the fair value of commodity derivatives, (ii) a non-cash charge of $70 million for equity-based compensation, (iii) a non-cash charge of $549 million for impairments of unproved properties, and (iv) a non-cash deferred tax benefit of $129 million.

2018 Capital Spending and 2019 Capital Budget

For the year ended December 31, 2018, our total consolidated capital expenditures were approximately $2.2 billion, including drilling and completion expenditures of $1.5 billion, leasehold additions of $172 million, gathering and compression expenditures of $444 million, water handling and treatment expenditures of $98 million, and other capital expenditures of $8 million.  In response to recent oil and NGL price declines, we have reduced our consolidated capital budget for 2019 to $1.9 billion to $2.2 billion.  Our budget includes: $1.1 billion to $1.25 billion for drilling and completion, $75 million to $100 million for leasehold expenditures, and $750 million to $800 million for capital expenditures by Antero Midstream, which includes $200 million for investments in

unconsolidated affiliates.  We do not budget for acquisitions.  During 2019, we plan to operate an average of five drilling rigs and four completion crews and we plan to complete 115-125 horizontal wells in the Marcellus and Utica Shales in 2019.  We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities, and commodity prices.

Delevering Activities 

In December 2018, we monetized part of our natural gas hedge portfolio through the unwinding of 68% of April through December 2019 swap volumes generating $248 million of proceeds and resetting 70% of 2020 swap volumes from contract prices of $3.25/MMBtu to a contract price of $3.00/MMBtu generating $122 million of net proceeds. The early settlement of 2019 swap volumes was replaced with collars for the period April through December 2019 for the same total notional quantities (433 Bcf) as the terminated forward swaps.  The collars set a weighted average floor price of $2.50/MMBtu and a weighted average ceiling price of $3.37/MMBtu.  Proceeds from the monetization were used to repay a portion of borrowings under Antero's revolving credit facility. 

Hedge Position

At December 31, 2018, we had fixed price swap contracts in place for January 1, 2019 through December 31, 2023 for 1.5 Tcf of our projected natural gas production at a weighted average index price of $3.13 per MMBtu.  These hedging contracts include contracts for the year ending December 31, 2019 of 417 Bcf of natural gas.  Additionally, we have collar agreements for April 2019 through December 2019 for 433 Bcf of our projected natural gas production at a weighted average floor and ceiling of $2.50 and $3.37, respectively.  We also had basis swaps for January 2019 for 7 Bcf of our projected natural gas production with pricing differentials ranging from $0.215 to $0.40.

To the extent we have hedged the price of a portion of our estimated future production through 2023, we believe this hedge position provides some certainty to cash flows supporting our future operations and capital spending plans.  As of December 31, 2018, the estimated fair value of our commodity derivative contracts was approximately $607 million.

Credit Facilities

At December 31, 2018, Antero’s borrowing base under its senior revolving credit facility (the “Credit Facility”) was $4.5 billion and lender commitments were $2.5 billion.  The maturity date of the facility is the earlier of (i) October 26, 2022 and (ii) the date that is 91 days prior to the earliest stated redemption date of any series of Antero’s senior notes, unless such series of notes is refinanced.  The borrowing base under our revolving credit facility is redetermined annually and is based on the estimated future cash flows from our proved oil and gas reserves and our commodity derivative positions.  The next redetermination is scheduled to occur in April 2019.  At December 31, 2018, we had $405 million of borrowings, with a weighted average interest rate of 3.95%, and $685 million of letters of credit outstanding under the revolving credit facility.  See “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements and Contractual Obligations—Senior Secured Revolving Credit Facility” for a description of the Credit Facility.

At December 31, 2018,  lender commitments under Antero Midstream’s revolving credit facility (the “Midstream Credit Facility”) were $2.0 billion.  The maturity date of the facility is October 26, 2022.  At December 31, 2018, Antero Midstream had $990 million of borrowings outstanding under the Midstream Credit Facility.  See “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements and Contractual Obligations—Midstream Credit Facility” for a description of the Midstream Credit Facility.

Share Repurchase Program

In October 2018, the Company’s Board of Directors authorized a $600 million share repurchase program, subject to targeted leverage ratios and cash flow generation. During the fourth quarter of 2018, we repurchased 9.1 million shares of our common stock (approximately 3% of total shares outstanding at commencement of the program) at a total cost of approximately $129 million.

Simplification Transaction

On October 9, 2018, we announced that AMGP, Antero Midstream and certain of their affiliates entered into a Simplification Agreement (as may be amended from time to time, the “Simplification Agreement”), pursuant to which, among other things, (1) AMGP will be converted from a limited partnership to a corporation under the laws of the State of Delaware, to be named Antero Midstream Corporation (which is referred to as “New AM” and the conversion, the “Conversion”); (2) an indirect, wholly owned subsidiary of New AM will be merged with and into Antero Midstream, with Antero Midstream surviving the merger as an indirect,

wholly owned subsidiary of New AM (the “Merger”) and (3) all the issued and outstanding Series B Units representing limited liability company interests of Antero IDR Holdings LLC (“IDR Holdings”), a subsidiary of AMGP and the holder of all of Antero Midstream’s incentive distribution rights, will be exchanged for an aggregate of approximately 17.35 million shares of New AM’s common stock (the “Series B Exchange”). The Conversion, the Merger, the Series B Exchange and the other transactions contemplated by the Simplification Agreement are collectively referred to as the “Transactions.” As a result of the Transactions, Antero Midstream will be a wholly owned subsidiary of New AM and former shareholders of AMGP, unitholders of Antero Midstream, including Antero, and holders of Series B Units will each own New AM’s common stock.  Following the completion of the simplification transaction, Antero will no longer consolidate Antero Midstream’s financial position and results of operations in Antero’s consolidated financial statements, and Antero will account for its interest in New AM using the equity method of accounting.

We currently own 98,870,335 of Antero Midstream’s common units and will be entitled to receive consideration of $3.00 in cash and 1.6023 shares of New AM’s common stock per Antero Midstream common unit.  Public unitholders of Antero Midstream will be entitled to receive a combination of $3.415 in cash and 1.635 shares of New AM’s common stock per Antero Midstream common unit.  All public unitholders of Antero Midstream will be entitled to elect to receive their merger consideration in all cash, all stock, or a combination of cash and stock, and we will have the ability to elect to take a larger portion of our merger consideration in cash if the public unitholders of Antero Midstream disproportionately elect to receive stock consideration, subject in each case to proration to ensure that the aggregate amount of cash consideration paid to all Antero Midstream unitholders is an amount equal to the aggregate amount of cash that would have been paid and issued if all public unitholders of Antero Midstream received $3.415 in cash per Antero Midstream common unit and we received $3.00 in cash per unit, which is approximately $598 million and the aggregate amount of equity issuable to all Antero Midstream unitholders is a number of shares of New AM’s common stock equal to the aggregate number of shares that would be issued if all public unitholders of Antero Midstream received 1.635 shares per Antero Midstream common unit and we received 1.6023 shares of New AM’s common stock per Antero Midstream common unit.  If we elect to receive only $3.00 in cash per Antero Midstream common unit, we are expected to own approximately 31% of New AM’s common stock following the completion of the Transactions.

Special meetings of AMGP shareholders and Antero Midstream unitholders will be held on March 8, 2019 to vote on the Simplification Agreement, the Merger and the other Transactions contemplated thereby, as applicable, and all AMGP shareholders and Antero Midstream unitholders of record as of the close of business on January 11, 2019, which is the record date for the special meetings, will be entitled to vote the AMGP common shares and Antero Midstream common units, respectively, owned by them on the record date. AMGP and Antero Midstream expect the Transactions to close shortly after the special meeting date, subject to certain closing conditions under the documentation for the Transactions.  AMGP and the Partnership expect to fund the cash portion of the merger consideration with borrowings under Antero Midstream’s revolving credit facility.

Also on October 9, 2018, in connection with the entry into the Simplification Agreement, (1) Antero Midstream entered into a voting agreement with AMGP’s shareholders owning a majority of the outstanding AMGP common shares, pursuant to which, among other things, such shareholders agreed to vote in favor of the Transactions, (2) AMGP entered into a voting agreement with us, pursuant to which, among other things, we agreed to vote in favor of the Transactions and (3) we, AMGP, certain funds affiliated with Warburg Pincus LLC and Yorktown Partners LLC (together, the “Sponsor Holders”), Paul M. Rady and Glen C. Warren, Jr. (Messrs. Rady and Warren together, the “Management Stockholders”) entered into a Stockholders’ Agreement, pursuant to which, among other things, we, the Sponsor Holders and the Management Holders will have the ability to designate members of the New AM board of directors under certain circumstances, effective as the closing of the Transactions.

Our Properties and Operations

Estimated Proved Reserves

The information with respect to our estimated proved reserves presented below has been prepared in accordance with the rules and regulations of the SEC.

Reserves Presentation

The following table summarizes our estimated proved reserves, related Standardized measure, and PV‑10 at December 31, 2016, 2017 and 2018.  Total estimated proved reserves are prepared on a consolidated basis, as required by SEC Rules, using operating and capital costs on a consolidated basis.  Our estimated proved reserves are based on evaluations prepared by our internal reserve engineers, which have been audited by our independent engineers, DeGolyer and MacNaughton (“D&M”).  We refer to D&M as our independent engineers.  A copy of the summary report of D&M with respect to our reserves at December 31, 2018 is filed as Exhibit 99.1 to this Annual Report on Form 10‑K.  Within D&M, the technical person primarily responsible for reviewing our

reserves estimates was Gregory K. Graves, P.E.  Mr. Graves is a Registered Professional Engineer in the State of Texas (License No. 70734), is a member of both the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers, and has in excess of 33 years of experience in oil and gas reservoir studies and reserves evaluations.  Mr. Graves graduated from the University of Texas at Austin in 1984 with a Bachelor of Science degree in Petroleum Engineering.  Reserves at December 31, 2016, 2017, and 2018 were prepared assuming partial ethane recovery, and rejection of the remaining ethane.  When ethane is rejected at the processing plant, it is left in the gas stream and sold with the methane gas.

The following sets forth the estimated future net cash flows from our proved reserves (without giving effect to our commodity derivatives), the present value of those net cash flows before income tax (PV‑10), the present value of those net cash flows after income tax (Standardized measure) and the prices used in projecting future net cash flows at December 31, 2016, 2017, and 2018:

 

Future net cash flows represent projected revenues from the sale of proved reserves net of production and development costs (including operating expenses and production taxes).  Prices for 2016, 2017, and 2018 were based on 12‑month unweighted average of the first‑day‑of‑the‑month pricing, without escalation.  Costs are based on costs in effect for the applicable year without escalation.  There can be no assurance that the proved reserves will be produced as estimated or that the prices and costs will remain constant.  There are numerous uncertainties inherent in estimating reserves and related information, and different reservoir engineers often arrive at different estimates for the same properties.

Changes in Proved Reserves During 2018

The following table summarizes the changes in our estimated proved reserves during 2018 (in Bcfe):

 

Extensions, discoveries, and other additions of 2,781 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales.  Downward revisions of 433 Bcfe related to well performance.  Net downward revisions of 742 Bcfe related to optimization to our 5-year development plan.  This figure includes upward revisions of 1,722 Bcfe for previously proved undeveloped properties reclassified from non-proved properties at December 31, 2017 to proved undeveloped at December 31, 2018 due to their addition to our 5-year development plan, and downward revisions of 2,464 Bcfe for locations that were not developed within 5 years of initial booking as proved reserves.  Upward revisions of 18 Bcfe were due to increases in prices for natural gas, NGLs, and oil.  Upward revisions of 115 Bcfe were due to an increase in our assumed future ethane recovery.  Our estimated proved reserves as of December 31, 2018 totaled approximately 18.0 Tcfe, an increase of 4% from the prior year.

Proved Undeveloped Reserves

Proved undeveloped reserves are included in the previous table of total proved reserves.  The following table summarizes the changes in our estimated proved undeveloped reserves during 2018 (in Bcfe):

 

Extensions, discoveries, and other additions during 2018 of 2,464 Bcfe of proved undeveloped reserves resulted from delineation and developmental drilling in the Marcellus and Utica Shales.  Downward revisions of 143 Bcfe related to well performance.  Net downward revisions of 742 Bcfe related to optimization to our 5-year development plan.  This figure includes upward revisions of 1,722 Bcfe for previously proved undeveloped properties reclassified from non-proved properties at December 31, 2017 to proved undeveloped at December 31, 2018 due to their addition to our 5-year development plan, and downward revisions of 2,464 Bcfe for locations that were not developed within 5 years of initial booking as proved reserves.  Upward revisions of 7 Bcfe were due to increases in prices for natural gas, NGLs, and oil. 

During the year ended December 31, 2018, we converted approximately 2,531 Bcfe, or 29%, of our proved undeveloped reserves to proved developed reserves at a total capital cost of approximately $862 million.  We spent an additional $303 million on development costs related primarily to drilled and uncompleted wells and properties in the proved undeveloped classification at December 31, 2017, resulting in total development spending of $1.2 billion, as disclosed in Note 19 to the consolidated financial

statements included elsewhere in this report.  Estimated future development costs relating to the development of our proved undeveloped reserves at December 31, 2018 are approximately $3.3 billion, or $0.44 per Mcfe, over the next five years.  Based on strip pricing as of December 31, 2018, we believe that cash flows from operations will be sufficient to finance such future development costs.  While we will continue to drill leasehold delineation wells and build on our current leasehold position, we will also continue drilling our proved undeveloped reserves.  See “Item 1A.  Risk Factors—The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.  Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.”

We maintain a 5-year development plan, which is reviewed by our Board of Directors, which supports our corporate production growth target.  The development plan is reviewed annually to ensure capital is allocated to the wells that have the highest risk-adjusted rates of return within our inventory of undrilled well locations.  As our well economics have changed, we have reallocated 5-year capital to areas with expected highest rates of return and optimal lateral lengths.  This resulted in the reclassification of 1,722 Bcfe of reserves from proved undeveloped to probable during the year ended December 31, 2018 due to the 5-year development rule.  Based on our then-current acreage position, strip prices, anticipated well economics, and our development plans at the time these reserves were classified as proved, we believe the previous classification of these locations as proved undeveloped was appropriate.

At December 31, 2018, an estimated 19,400 of our net leasehold acres, containing 308 locations associated with proved undeveloped reserves, are subject to renewal prior to scheduled drilling.  Some of these leases have contract renewal options and some will need to be renegotiated.  We estimate a potential cost of approximately $42 million to renew the 19,400 acres based upon current leasing authorizations and option to extend payments.  Proved undeveloped reserves of 1,565 Bcfe are related to these leases.  Historically, we have had a high success rate in renewing leases, and we expect that we will be able to renew substantially all of the leases underlying this acreage prior to the scheduled drilling dates.  Based on our historical success rate in renewing leases, we estimate that we may not be able to renew leases covering approximately 235 Bcfe of these proved undeveloped reserves.

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

Preparation of Reserve Estimates

Our reserve estimates as of December 31, 2016, 2017, and 2018 included in this Annual Report on Form 10‑K were prepared by our internal reserve engineers in accordance with petroleum engineering and evaluation standards published by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC.  Our internally prepared reserve estimates were audited by our independent reserve engineers.  Our independent reserve engineers were selected for their historical experience and geographic expertise in engineering unconventional resources.  The technical persons responsible for overseeing the audit of our reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

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

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

Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.  The term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate.  To achieve reasonable certainty, we and the

independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability.  The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available downhole and production data, micro‑seismic data, and well‑test data.  Probable reserves are reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.  Estimates of probable reserves which may potentially be recoverable through additional drilling or recovery techniques are, by nature, more uncertain than estimates of proved reserves and, accordingly, are subject to substantially greater risk of realization.  Possible reserves are reserves that are less certain to be recovered than probable reserves.  Estimates of possible reserves are also inherently imprecise.  Estimates of probable and possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes, and other factors.

Methodology Used to Apply Reserve Definitions

In the Marcellus Shale, our estimated reserves are based on information from our large, operated proved developed producing reserve base, as well as information from other operators in the area, which can be used to confirm or supplement our internal estimates.  Typically, proved undeveloped properties are booked based on applying the estimated lateral length to the average wellhead Bcf per 1,000 feet from our proved developed producing wells, then converting to a processed volume where applicable.

We may attribute up to 11 proved undeveloped locations based on one proved developed producing well where analysis of geologic and engineering data can be estimated with reasonable certainty to be commercially recoverable.  However, the ratio of proved undeveloped locations generated will be lower when multiple proved developed wells are drilled on a single pad.  In addition, we have applied the concept of a statistically proven area to certain areas of our Marcellus Shale acreage whereby undeveloped properties are booked as proved reserves so long as well count is sufficient for statistical analysis and certain land, geologic, engineering and commercial criteria are met.

Although our operating history in the Utica Shale is more limited than our Marcellus Shale operations, we expect to be able to apply a similar methodology once the well count is sufficient for statistical analysis.  The primary differences between the two areas are that (i) we have not established a statistically proven area in the Utica Shale and (ii) each proved developed producing well in the Utica Shale only generates four direct offset well locations due to less relative maturity of the play.

Identification of Potential Well Locations

Our identified potential well locations represent locations to which proved, probable, or possible reserves were attributable based on SEC pricing as of December 31, 2018.  We prepare internal estimates of probable and possible reserves but have not included disclosure of such reserves in this report.

Production, Revenues, and Price History

Because natural gas, NGLs, and oil are commodities, the prices that we receive for our production are largely a function of market supply and demand.  While demand for natural gas in the United States has increased materially since 2000, natural gas and NGLs supplies have also increased significantly as a result of horizontal drilling and fracture stimulation technologies which have been used to find and recover large amounts of oil and gas from various shale formations throughout the United States.  Demand is impacted by general economic conditions, weather, and other seasonal conditions.  Over or under supply of natural gas, NGLs or oil can result in substantial price volatility.  A substantial or extended decline in commodity prices, or poor drilling results, could have a material adverse effect on our financial position, results of operations, cash flows, quantities of reserves that may be economically produced, and our ability to access capital markets.  See “Item 1A.  Risk Factors—Natural gas, NGLs, and oil prices are volatile.  A substantial or extended decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.”

Operations Data – Exploration and Production and Marketing Segments

The following table sets forth information regarding our production, realized prices, and production costs for the years ended December 31, 2016, 2017 and 2018.  For additional information on price calculations, see information set forth in “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Productive Wells

As of December 31, 2018, we held interests in a total of 1,130 gross (1,002.2 net) producing wells on our Marcellus Shale acreage, including the following:

As of December 31, 2018, we held interests in a total of 250 gross (200.2 net) producing wells on our Ohio Utica Shale acreage, including the following:

Additionally, at December 31, 2018, we had 26 net horizontal proved developed non-producing wells, and 86 gross horizontal wells (84.7 net) that were drilled and uncompleted or in the process of being completed.  The shallow vertical wells and wells operated by other producers were primarily acquired in conjunction with leasehold acreage acquisitions.

Acreage

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we own an interest as of December 31, 2018.  A majority of our developed acreage is subject to liens securing our revolving credit facility.  Approximately 57% of our net Marcellus acreage and 50% of our net Utica acreage is held by production.  Acreage related to royalty, overriding royalty, and other similar interests is excluded from this table.

 

The following table provides a summary of our current gross and net acreage by county in the Marcellus Shale and the Ohio Utica Shale.

 

 

Undeveloped Acreage Expirations

The following table sets forth our total gross and net undeveloped acres as of December 31, 2018 that will expire over the next three years unless production is established within the spacing units covering the acreage prior to the expiration dates, or unless

the leases containing such acreage are extended or renewed. 

 

Drilling Activity

The following table sets forth the results of our drilling activity for wells drilled and completed during the years ended December 31, 2016, 2017, and 2018.  Gross wells reflect the number of wells in which we own an interest and include historical drilling activity in the Appalachian Basin.  Net wells reflect the sum of our working interests in gross wells.

 

The figures in the table above do not include 86 gross wells (85 net) that were drilled and uncompleted or in the process of being completed at December 31, 2018.

Delivery Commitments

We have entered into various firm sales contracts to deliver and sell gas.  We believe we will have sufficient production quantities to meet substantially all of such commitments, but may be required to purchase gas from third parties to satisfy shortfalls should they occur. 

As of December 31, 2018, our firm sales commitments through 2023 included:

 

As provided in the table above, we utilize a part of our firm transportation capacity to deliver gas and NGLs under the majority of these firm sales contracts.  We have firm transportation contracts that require us to either ship products on said pipelines or pay demand charges for shortfalls.  The minimum demand fees are reflected in our table of contractual obligations.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements and Contractual Obligations.”  If our production quantities are insufficient to meet such commitments, we may purchase third party products and/or market our excess firm transportation capacity to third parties.

Gathering and Compression

Our exploration and development activities are supported by the natural gas gathering and compression assets of our subsidiary, Antero Midstream, as well as by third‑party gathering and compression arrangements.  Unlike many producing basins in the United States, certain portions of the Appalachian Basin do not have sufficient midstream infrastructure to support the existing and expected increasing levels of production.  Our relationship with Antero Midstream allows us to obtain the necessary gathering and compression capacity for our production and we have leveraged our relationship with Antero Midstream to support our growth.  For the years ended December 31, 2017 and 2018, Antero Midstream spent approximately $346 million and $444 million, respectively, on gas gathering and compression infrastructure that services our production.  Subject to pre-existing dedications and other third-party commitments, we have dedicated to Antero Midstream all of our current and future acreage in West Virginia and Ohio for gathering and compression services.

As of December 31, 2018, Antero Midstream owned and operated 289 miles of gas gathering pipelines in the Marcellus Shale.  We also have access to additional low‑pressure and high‑pressure pipelines owned and operated by third parties.  As of December 31, 2018, Antero Midstream owned and operated 17 compressor stations and we utilized 12 additional third‑party compressor stations in the Marcellus Shale.  The gathering, compression, and dehydration services provided by third parties are contracted on a fixed‑fee basis.

As of December 31, 2018, Antero Midstream owned and operated 108 miles of low‑pressure and high‑pressure gathering pipelines in the Utica Shale, and Antero owned and operated 8 miles of high-pressure pipelines.  As of December 31, 2018, Antero Midstream owned and operated two compressor stations and we utilized four additional third‑party compressor stations in the Utica Shale.

Natural Gas Processing

Many of our wells in the Marcellus and Utica Shales allow us to produce liquids-rich natural gas that contain a significant amount of NGLs.  Liquids-rich natural gas must be processed, which involves the removal and separation of NGLs from the wellhead natural gas.

NGLs are valuable commodities once removed from the natural gas stream in a cryogenic processing facility yielding y-grade liquids.  Y-grade liquids are then fractionated, thereby breaking up the y-grade liquid into its key components.  Fractionation refers to the process by which a NGLs y-grade stream is separated into individual NGLs products such as ethane, propane, normal butane, isobutane, and natural gasoline.  Fractionation occurs by heating the y-grade liquids to allow for the separation of the component parts based on the specific boiling points of each product.  Each of the individual products has its own market price.

The combination of infrastructure constraints in the Appalachian region and low ethane prices has resulted in many producers “rejecting” rather than “recovering” ethane.  Ethane rejection occurs when ethane is left in the wellhead gas stream when the gas is processed, rather than being extracted and sold as a liquid after fractionation.  When ethane is left in the gas stream, the Btu content of the residue gas at the tailgate of the processing plant is higher.  Producers generally elect to “reject” ethane when the price received for

the ethane in the gas stream is greater than the net price received for the ethane being sold as a liquid after fractionation.  When ethane is recovered, the Btu content of the residue gas is lower, but a producer is then able to recover the value of the ethane sold as a separate product.

Given the existing commodity price environment and the current limited ethane market in the northeast, we are currently rejecting the majority of the ethane obtained in the natural gas stream when processing our liquids‑rich gas.  However, we realize a pricing upgrade when selling the remaining NGLs product stream at current prices.  We may elect to recover more ethane when ethane prices result in a value for the ethane that is greater than the Btu equivalent residue gas and incremental recovery costs.  Our first international ethane sales contract commenced in November 2018.

 

As of December 31, 2018, we had contracted with MarkWest Energy Partners L.P. to provide cryogenic processing capacity for our Marcellus and Utica Shale production as follows:

*   Anticipated in-service date

Through Antero Midstream’s investment in the Joint Venture, Antero Midstream acquired a 50% non-operated equity interest in certain of the existing and future Sherwood gas processing plants.  The Joint Venture also owns a 33 1/3% interest in a fractionation facility located at the Hopedale complex in Harrison County, Ohio.  The Joint Venture’s processing investment began with the seventh plant at the Sherwood facility and continues through Sherwood 13 and Smithburg 1 on the table above.  The Joint Venture provides processing services to Antero under a long-term, fixed-fee arrangement, subject to annual CPI-based adjustments.

Transportation and Takeaway Capacity

We have entered into firm transportation agreements with various pipelines that enable us to deliver natural gas to the Midwest, Gulf Coast, Eastern Regional, and Mid-Atlantic markets.  Our primary firm transportation commitments include the following:

Under firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries.  See “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements and Contractual Obligations” for information on our minimum fees for such contracts.  Based on current projected 2019 annual production guidance, we estimate that we could incur annual net marketing costs of $0.175 per Mcfe to $0.225 per Mcfe in 2019 for unutilized transportation capacity depending on the amount of unutilized capacity that can be marketed to third parties or utilized to transport third party gas and capture positive basis differentials.  Where permitted, we continue to actively market any excess capacity in order to offset minimum commitment fees.

Water Handling and Treatment Operations

On September 23, 2015, Antero contributed (i) all of the outstanding limited liability company interests of Antero Water LLC (“Antero Water”) to Antero Midstream and (ii) all of the assets, contracts, rights, permits and properties owned or leased by Antero and used primarily in connection with the construction, ownership, operation, use or maintenance of its advanced wastewater treatment facility in Doddridge County, West Virginia, to Antero Treatment LLC, a wholly-owned subsidiary of Antero Midstream.  Our relationship with Antero Midstream allows us to obtain the necessary fresh and recycled water for use in our drilling and completion operations, as well as services to dispose of wastewater resulting from our operations.

Antero Midstream owns two independent fresh water distribution systems that distribute fresh water from the Ohio River and several regional water sources, as well as recycled water from its water treatment facility, for well completion operations in the Marcellus and Utica Shales.  These systems consist of permanent buried pipelines, movable surface pipelines and fresh water storage facilitates, as well as pumping stations to transport the fresh water throughout the pipeline networks.  To the extent necessary, the surface pipelines are moved to well pads for service completion operations in concert with our drilling program.  As of December 31, 2018, Antero Midstream had the ability to store 5.3 million barrels of fresh water in 37 impoundments located throughout our leasehold acreage in the Marcellus and Utica Shales.  Due to the extensive geographic distribution of Antero Midstream’s water pipeline systems in both West Virginia and Ohio, it is able to provide water delivery services to neighboring oil and gas producers within and adjacent to our operating area, subject to commercial arrangements, while reducing water truck traffic.

As of December 31, 2018, Antero Midstream owned and operated 127 miles of buried fresh water pipelines and 76 miles of movable surface fresh water pipelines in the Marcellus Shale, as well as 25 fresh water storage facilities equipped with transfer pumps.  As of December 31, 2018, Antero Midstream owned and operated 55 miles of buried fresh water pipelines and 27 miles of movable surface fresh water pipelines in the Utica Shale, as well as 12 fresh water storage facilities equipped with transfer pumps.

Antero Midstream also owns a wastewater treatment facility with a designed capacity of 60,000 barrel per day for the treatment of our flowback and produced water for subsequent use or sale for well completions.  To date, the facility has run at reduced operating rates below the designed capacity and therefore not met certain completion milestones under the terms of the agreement between Antero Midstream and the construction contractor.  Antero Midstream has made improvements to the facility’s design and anticipates an increase in wastewater treatment volumes during 2019 as compared to 2018 and has included the final milestone completion payments under the construction contract in its 2019 capital budget. 

Major Customers

For the year ended December 31, 2018, sales to Mercuria Energy America, Inc. and Tenaska Marketing Ventures accounted for approximately 16% and 14% of our total product revenues, respectively.  For the year ended December 31, 2017, sales to Tenaska Marketing Ventures and WGL Midstream accounted for approximately 22% and 15% of our total product revenues, respectively.  For the year ended December 31, 2016, sales to Tenaska Marketing Ventures and WGL Midstream accounted for approximately 29% and 13% of our total product revenues, respectively.

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:

Seasonality

Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months.  However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation.  Cold winters can significantly increase demand and price fluctuations.  In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the spring, summer and fall.  This can also reduce seasonal demand fluctuations.  Seasonal anomalies can also increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies in our industry that have greater resources than we do.  Many of these companies not only explore for and produce natural gas, but also carry on refining operations and market petroleum and other products on a regional, national, or worldwide basis.  These companies may be able to pay more for productive natural gas properties and exploratory prospects or define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit, and may be able to expend greater resources to attract and maintain industry personnel.  In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas market prices.  Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state, and local laws and regulations more easily than we can, which would adversely affect our competitive position.  Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.  In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing natural gas properties.

Regulation of the Oil and Natural Gas Industry

General

Our oil and natural gas operations are subject to extensive, and frequently changing, laws and regulations related to well permitting, drilling, and completion, and to the production, transportation and sale of natural gas, NGLs, and oil.  We believe compliance with existing requirements will not have a materially adverse effect on our financial position, cash flows or results of operations.  However, such laws and regulations are frequently amended or reinterpreted.  Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, federal agencies, the states, local governments, and the courts.  We cannot predict when or whether any such proposals may become effective.  Therefore, we are unable to predict the future costs or impact of compliance.  The regulatory burden on the industry increases the cost of doing business and affects profitability.  We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers, and marketers with which we compete.

Regulation of Production of Natural Gas and Oil

We own interests in properties located onshore in West Virginia and Ohio, and our production activities on these properties are subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations.  These statutes and regulations address requirements related to permits for drilling of wells, bonding to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, the plugging and abandonment of wells, venting or flaring of natural gas, and the ratability or fair apportionment of production from fields and individual wells.  In addition, all of the states in which we own and operate properties have regulations governing environmental and conservation matters, including provisions for the handling and disposing or discharge of waste materials, the unitization or pooling of natural gas and oil properties, the establishment of maximum allowable rates of production from natural gas and oil wells, and the size of drilling and spacing units or proration units and the density of wells that may be drilled.  Some states also have the power to prorate production to the market demand for oil and gas.  The effect of these regulations is to limit the amount of natural gas and oil that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density.  Moreover, each state generally imposes a production or severance tax with respect to the production and sale of natural gas, NGLs, and oil within its jurisdiction.

The failure to comply with these rules and regulations can result in substantial penalties.  Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Regulation of Transportation of Natural Gas

The transportation and sale, or resale, of natural gas in interstate commerce are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or NGPA, and regulations issued under those statutes.  FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.  Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non‑discriminatory basis.  Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

Gathering services, which occurs upstream of jurisdictional transmission services, are regulated by the states onshore and in state waters.  Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA.  Although FERC has not made any formal determinations with respect to any of our facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company.  The distinction between FERC‑regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case‑by‑case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by FERC, the courts or Congress.  State regulation of natural gas gathering facilities generally include various safety, environmental and, in some circumstances, nondiscriminatory‑take requirements.  Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies.  The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state.  Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors.  Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Regulation of Sales of Natural Gas, NGLs, and Oil

The prices at which we sell natural gas, NGLs, and oil are not currently subject to federal regulation and, for the most part, are not subject to state regulation.  FERC, however, regulates interstate natural gas transportation rates, and terms and conditions of transportation service, which affects the marketing of the natural gas we produce, as well as the prices we receive for sales of our natural gas.  Similarly, the price we receive from the sale of oil and NGLs is affected by the cost of transporting those products to market.  FERC regulates the transportation of oil and liquids on interstate pipelines under the provision of the Interstate Commerce Act, the Energy Policy Act of 1992 and regulations issued under those statutes.  Intrastate pipeline transportation of oil, NGLs, and

other products, is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes.  In addition, while sales by producers of natural gas and all sales of crude oil, condensate, and NGLs can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. 

With regard to our physical sales of these energy commodities and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC as described below, the U.S. Commodity Futures Trading Commission under Commodity Exchange Act, or CEA, and the Federal Trade Commission, or FTC.  We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation.  Should we violate the anti-market manipulation laws and regulations, we could be subject to fines and penalties as well as related third party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.

The Domenici Barton Energy Policy Act of 2005, or EPAct of 2005 amended the NGA to add an anti‑market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provided FERC with additional civil penalty authority.  In Order No. 670, FERC promulgated rules implementing the anti‑market manipulation provision of the EPAct of 2005, which make it unlawful to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The anti‑market manipulation rules do not apply to activities that relate only to intrastate or other non‑jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non‑jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704 described below.  Under the EPAct of 2005, FERC has the power to assess civil penalties of up to $1,000,000 per day for each violation of the NGA and the NGPA.  In January 2017, FERC issued an order (Order No. 834) increasing the maximum civil penalty amounts under the NGA and NGPA to adjust for inflation.  FERC may now assess civil penalties under the NGA and NGPA of up to $1,269,500 per violation per day.

Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year.  It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704.  Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity.  The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.  In November 2009, the FTC issued regulations pursuant to the Energy Independence and Security Act of 2007 intended to prohibit market manipulation in the petroleum industry.  Violators of the regulations face civil penalties of up to approximately $2 million (adjusted annually for inflation) per violation per day.  Together with FERC, these agencies have imposed broad rules and regulations prohibiting fraud and manipulation in oil and gas markets and energy futures markets.

Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take.  We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.

Regulation of Environmental and Occupational Safety and Health Matters

General

Our operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health and the discharge of materials into the environment or otherwise relating to environmental protection.  Violations of these laws can result in substantial administrative, civil and criminal penalties.  These laws and regulations may require the acquisition of permits before drilling or other regulated activity commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines, govern the sourcing and disposal of water used in the drilling and completion process, limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas or areas with endangered or

threatened species restrictions, require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits, establish specific safety and health criteria addressing worker protection and impose substantial liabilities for pollution resulting from operations or failure to comply with applicable laws and regulations. In addition, these laws and regulations may restrict the rate of production.

The following is a summary of the more significant existing environmental and occupational health and workplace safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our financial position, results of operations or cash flows.

Hazardous Substances and Waste Handling

The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment.  These persons include the current and past owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred.  Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.  In addition, despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses crude oil and natural gas, we generate materials in the course of our operations that may be regulated as hazardous substances based on their characteristics; however, we are unaware of any liabilities arising under CERCLA for which we may be held responsible that would materially and adversely affect us.

The Resource Conservation and Recovery Act, or RCRA, and analogous state laws, establish detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes.  RCRA specifically excludes drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes.  However, these wastes may be regulated by the U.S. Environmental Protection Agency, or the EPA, or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, or under state laws or other federal laws.  Moreover, it is possible that these particular oil and natural gas exploration, development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future.  For example, in December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA.  The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary.  The EPA would be required to complete any rulemaking revising the Subtitle D criteria by 2021.  A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position.  In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as waste solvents, laboratory wastes and waste compressor oils that may become regulated as hazardous wastes if such wastes have hazardous characteristics.  Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production activities for many years.  Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including offsite locations, where such substances have been taken for recycling or disposal.  In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under our control.  We are able to control directly the operation of only those wells with respect to which we act or have acted as operator.  The failure of a prior owner or operator to comply with applicable environmental regulations may, in certain circumstances, be attributed to us as current owners or operators under CERCLA.  These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws.  Under such laws, we could be required to undertake response or corrective measures, regardless of fault, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or waste pit closure operations to prevent future contamination.

Water Discharges

The Federal Water Pollution Control Act, or the Clean Water Act (the “CWA”), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into federal and state waters.  The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or a state equivalent agency.  The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers.  In September 2015, the EPA and U.S. Army Corps of Engineers issued a final rule defining the scope of the EPA’s and the Corps’ jurisdiction over waters of the U.S. (the “WOTUS rule”).  Several legal challenges to the WOTUS rule followed, and the WOTUS rule was stayed nationwide in October 2015 pending resolution of the court challenges. In January 2018, the U.S. Supreme Court determined that federal district courts have jurisdiction to review the WOTUS rule; consequently, the previously filed district court cases have been allowed to proceed, resulting in a patchwork of implementation of the rule in 22 states (including Pennsylvania and Ohio), the District of Columbia, and the U.S. territories, and stay of the rule in 28 states (including West Virginia).  On December 11, 2018, the EPA and the Corps proposed a new rule that would narrow federal jurisdictional reach compared to the WOTUS rule.  Several Environmental groups have signaled their intent to challenge the proposed rule.  As a result of these developments, future implementation of the WOTUS rule or any new rule is uncertain at this time. To the extent the WOTUS rule expands the scope of the CWA’s jurisdiction in areas where we operate, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which could delay the development of our natural gas and oil projects.  Also, pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil.  These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

Air Emissions

The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as, for example, compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements.  These laws and regulations may require us to obtain pre‑approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants, the costs of which could be significant.  The need to obtain permits has the potential to delay the development of our oil and natural gas projects.  Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues.  For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard, or NAAQS, for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards, and completed attainment/non-attainment designations in July 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.  Separately, in June 2016, the EPA finalized rules under the federal Clean Air Act regarding criteria for aggregating multiple sites into a single source for air-quality permitting purposes applicable to the oil and gas industry.  This rule could cause small facilities (such as tank batteries and compressor stations), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment.  The EPA has also issued final rules under the Clean Air Act that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants programs.  These final rules require, among other things, the reduction of volatile organic compound (“VOC”) emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.”  These regulations also establish specific new requirements regarding emissions from production related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels.  Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of natural gas and oil projects and increase our costs of development and production, which costs could be significant.  However, we do not believe that compliance with such requirements will have a material adverse effect on our operations.

Regulation of “Greenhouse Gas” Emissions

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases, or GHGs, present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit

reviews for certain large stationary sources that are already major sources of criteria pollutant emissions regulated under the statute.  Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA for those emissions.  These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.  In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations.  For example, in December 2015, the EPA finalized rules that added new sources to the scope of the GHG monitoring and reporting rule.  These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells.  The revisions also include the addition of well identification reporting requirements for certain facilities.  These changes to EPA’s GHG emissions reporting rule could result in increased compliance costs.  We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule.

In June 2016, the EPA finalized new regulations, known as Subpart OOOOa, that establish emission standards for methane and volatile organic compounds from new and modified oil and natural gas production and natural gas processing and transmission facilities.  The EPA’s rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions.  In addition, the rule package extends existing VOC standards under the EPA’s Subpart OOOO of the NSPS, or NSPS Quad O, to include previously unregulated equipment within the oil and natural gas source category.  In June 2017, the EPA proposed to delay implementation of the 2016 methane rule, but in July 2017, the U.S. Court of Appeals for the District of Columbia Circuit ruled that such a stay was unlawful.  In September 2018, the EPA proposed amendments to the 2016 standards that would relax the rule’s fugitive emissions monitoring requirements and expand exceptions to pneumatic pump requirements, among other changes.  Various industry and environmental groups separately challenged both the methane requirements and the EPA’s attempts to delay implementation of the rules.  In addition, in April 2018, several states filed a lawsuit that seeks to compel the EPA to issue methane performance standards for existing sources in the oil and natural gas source category.  As a result of these developments, substantial uncertainty exists with respect to implementation of the EPA’s 2016 methane rule.  However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a possibility, and several states have separately imposed their own regulations on methane emissions from oil and gas production activities.

Antero has developed a program to reduce and manage its methane and air emissions by: (1) monitoring the science of climate change and air quality, (2) addressing stakeholder inquiries regarding the Company’s position on climate change, methane emissions and air quality matters, (3) monitoring the Company’s measures to reduce methane and air emissions, and (4) overseeing development of methane and air emission reductions from activities, including implementation of best-management practices and new technology.

We have been making efforts to reduce methane emissions since March 2005, when we engaged local community groups in Colorado regarding our former activities in the Piceance Basin in discussions on how to minimize air emission impacts from our operations. In addition, we have been performing green completions since before the EPA’s NSPS Quad O rules became effective in January 2015.  In particular, we implemented green completions on our former Piceance Basin assets in Colorado in July 2011, using equipment that our personnel helped design.  After initial testing confirming the viability and effectiveness of the units, we implemented their use in the Appalachian Basin Marcellus Shale play in 2012 and later in the Utica Shale play.  We have a long history of managing methane emissions from our operations, as demonstrated by our early use of green completions.

When we permit a facility, we install air pollution control equipment that meets the requirements of the NSPS and EPA Best Available Control Technology standards.  The control equipment includes Vapor Recovery Towers (VRTs) and Vapor Recovery Units (VRUs), which capture methane emissions and direct them down a sales line.  This technology allows us to recover a valuable product and reduce emissions.  Additionally, residual storage tank emissions are controlled with vapor combustors that reduce methane emissions by 98%.  We also install low-bleed pneumatic controllers which minimize methane emissions.

Our methane and air emission control program also includes a Leak Detection and Repair (LDAR) program.  Periodic inspections are conducted to minimize emissions by detecting leaks and repairing them promptly.  The LDAR program inspections utilize a state-of-the-art Optical Gas Imaging (OGI) Forward Looking Infrared Radar (FLIR) camera to identify equipment leaks.  In addition, our Operations group has a maintenance program in place, which includes cleaning, greasing and replacing thief hatch seals and worn equipment to prevent leaks from occurring.  Our efforts to date have resulted in a declining volume of methane emissions based on the decreasing number of leaks detected by our LDAR program.

In 2017, Antero joined the EPA Natural Gas Star Program.  The EPA Natural Gas STAR Program provides a framework for companies with U.S. oil and gas operations to implement methane reduction technologies and practices and document their emission reduction activities.

By joining the program, Antero committed to: 1) evaluate its methane emission reduction opportunities, 2) implement methane reduction projects where feasible, and 3) annually report methane emission reduction actions to the EPA.

Recent methane emission reduction initiatives by Antero and Antero Midstream have included the following:

During 2019, Antero’s methane emission reduction efforts will also include the following activities: