10-K 1 ar-20171231x10k.htm 10-K ar_Current folio_10K

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM 10‑K


ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2017

or

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

Commission File No. 001‑36120


ANTERO RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)

80‑0162034
(IRS Employer
Identification No.)

1615 Wynkoop Street
Denver Colorado
(Address of principal executive offices)

80202
(Zip Code)

 

(303) 357‑7310

(Registrant’s telephone number, including area code)

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

Title of Each Class

Name of Each Exchange on which Registered

Common Stock, Par Value $0.01 Per Share

New York Stock Exchange

 

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


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

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

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

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

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

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

Large accelerated filer ☒

Accelerated filer ☐

Non‑accelerated filer ☐
(Do not check if a
smaller reporting company)

Smaller reporting company ☐

Emerging growth company ☐

 

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

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

The aggregate market value of the voting common stock held by non‑affiliates of the registrant as of June 30, 2017, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $5.0 billion based on the closing price of Antero Resources Corporation’s common stock as reported on that day on the New York Stock Exchange of $21.61.

The registrant had 316,524,110 shares of common stock outstanding as of February 8, 2018.

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

 

 

 


 

TABLE OF CONTENTS

 

 

 

 

 

Page

CAUTIONARY STATEMENT REGARDING FORWARD‑LOOKING STATEMENTS

ii

PART I 

1

Items 1 and 2. 

Business and Properties

1

Item 1A. 

Risk Factors

25

Item 1B. 

Unresolved Staff Comments

41

Item 3. 

Legal Proceedings

42

Item 4. 

Mine Safety Disclosures

43

PART II 

43

Item 5. 

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

43

Item 6. 

Selected Financial Data

45

Item 7. 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

49

Item 7A. 

Quantitative and Qualitative Disclosures About Market Risk

76

Item 8. 

Financial Statements and Supplementary Data

77

Item 9. 

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

77

Item 9A. 

Controls and Procedures

78

Item 9B. 

Other Information

79

PART III

80

Item 10. 

Directors, Executive Officers and Corporate Governance

80

Item 11. 

Executive Compensation

83

Item 12. 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

83

Item 13. 

Certain Relationships and Related Transactions and Director Independence

83

Item 14. 

Principal Accountant Fees and Services

83

PART IV

84

Item 15. 

Exhibits and Financial Statement Schedules

84

SIGNATURES

88

 

i


 

CAUTIONARY STATEMENT REGARDING FORWARD‑LOOKING STATEMENTS

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

Forward‑looking statements may include statements about our:

·

business strategy;

·

reserves;

·

financial strategy, liquidity, and capital required for our development program;

·

natural gas, natural gas liquids (“NGLs”), and oil prices;

·

timing and amount of future production of natural gas, NGLs, and oil;

·

hedging strategy and results;

·

ability to meet minimum volume commitments and to utilize or monetize our firm transportation commitments;

·

future drilling plans;

·

competition and government regulations;

·

pending legal or environmental matters;

·

marketing of natural gas, NGLs, and oil;

·

leasehold or business acquisitions;

·

costs of developing our properties;

·

operations of Antero Midstream Partners LP, including the operations of its unconsolidated affiliates;

·

general economic conditions;

·

credit markets;

·

uncertainty regarding our future operating results; and

·

plans, objectives, expectations and intentions.

We caution you that these forward‑looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering, processing, transportation, and sale of natural gas, NGLs, and oil. These risks include, but are not limited to, commodity price volatility and low commodity prices, inflation, availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, marketing and transportation risks, regulatory changes, the uncertainty inherent in estimating natural gas, NGLs, and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development

ii


 

expenditures, conflicts of interest among our stockholders, and the other risks described under the heading “Item 1A. Risk Factors” in this Annual Report on Form 10‑K.

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

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

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

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

 

iii


 

 

GLOSSARY OF COMMONLY USED TERMS

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

100% success rate.”  Antero defines the term “100% success rate” to mean that all wells were completed and produce in commercially viable quantities.

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

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

Bcf.”  One billion cubic feet of natural gas.

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

Btu.”  British thermal unit.

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

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

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

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

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

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

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

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

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

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

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

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

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

iv


 

Liquids-rich.”  Natural gas which contains a raw energy content of at least 1,100 Btu per Mcf.

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

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

Mcf.”  One thousand cubic feet of natural gas.

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

 “MMBtu.”  One million British thermal units.

MMcf.”  One million cubic feet of natural gas.

MMcf/d”  MMcf per day.

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

“MMcfe/d.”  MMcfe per day.

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

NYMEX.”  The New York Mercantile Exchange.

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

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

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

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

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

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

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

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

PV‑10.”  When used with respect to natural gas and oil reserves, PV‑10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production, future development, and abandonment costs, using average yearly prices computed using SEC rules, before income taxes, and without giving effect to non‑property‑related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC.  PV‑10 is not a financial measure calculated in accordance with generally accepted accounting principles (“GAAP”) and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes

v


 

on future net revenues.  Neither PV‑10 nor Standardized Measure represents an estimate of the fair market value of our natural gas and oil properties. We and others in the industry use PV‑10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

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

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

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

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

Tcf.”  One trillion cubic feet of natural gas.

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

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

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

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

WTI.”  West Texas Intermediate light sweet crude oil.

 

 

vi


 

PART I

Items 1 and 2.  Business and Properties

Our Company and Organizational Structure

Antero Resources Corporation (individually referred to as “Antero”) and its subsidiaries (collectively referred to as the “Company”) are engaged in the exploration, development, production, and acquisition of natural gas, NGLs, and oil properties located in the Appalachian Basin. We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations. As of December 31, 2017, we held approximately 620,000 net acres of oil and gas properties located in the Appalachian Basin in West Virginia and Ohio. Our corporate headquarters are in Denver, Colorado.

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

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

General

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

At December 31, 2017

 

Three months ended December 31, 2017

 

 

    

Proved Reserves (Bcfe)(1)

    

PV-10 (in millions)(2)

    

Net proved developed wells(3)

    

Total net acres

    

Gross potential drilling locations(4)

    

Average net daily production (MMcfe/d)

 

Appalachian Basin:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Marcellus Shale

 

 

15,553

 

$

8,766

 

 

664

 

 

483,861

 

 

3,512

 

 

1,979

 

Ohio Utica Shale

 

 

1,708

 

$

1,409

 

 

181

 

 

136,580

 

 

621

 

 

368

 

Total

 

 

17,261

 

$

10,175

 

 

845

 

 

620,441

 

 

4,133

 

 

2,347

 


(1)

Estimated proved reserve volumes and values were calculated assuming partial ethane recovery, with rejection of the remaining ethane, and using the unweighted twelve‑month average of the first‑day‑of‑the‑month prices for the period ended December 31, 2017, which were $2.91 per MMBtu for natural gas based on a $3.11 per MMBtu NYMEX reference price, $20.40 per Bbl for NGLs and $45.35 per Bbl for oil for the Appalachian Basin based on a $51.03 per Bbl WTI reference price.

(2)

PV‑10 is a non‑GAAP financial measure. For a reconciliation of PV‑10 to standardized measure, please see “—Our Properties and Operations—Estimated Proved Reserves.”

(3)

Does not include certain vertical wells with no proved reserves that were primarily acquired in conjunction with leasehold acreage acquisitions.

(4)

Gross potential drilling locations are comprised of 427 locations classified as proved undeveloped and 3,706 locations classified as probable and possible.  See “Item 1A. Risk Factors” for risks and uncertainties related to developing our potential well locations contained in our proved, probable, and possible reserve categories.

1


 

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

We have assembled a portfolio of long‑lived properties that are characterized by what we believe to be low geologic risk and repeatability. Our drilling opportunities are focused in the Marcellus Shale and Utica Shale of the Appalachian Basin. From 2008 through December 31, 2017, our drilling operations in the Appalachian Basin have had a 100% success rate.  We have 4,133 potential horizontal well locations on our existing leasehold acreage within our proved, probable, and possible reserve categories.

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

Together, Antero and Antero Midstream operate in the following industry segments: (i) the exploration, development, and production of natural gas, NGLs, and oil, (ii) gathering and processing, (iii) water handling and treatment, and (iv) marketing of excess firm transportation capacity.  All of our operations are conducted in the United States.  Financial information for our industry segment operations is located under “Note 17 – Segment Information.”

2017 and Recent Developments and Highlights

Reserves, Production, and Financial Results

As of December 31, 2017, our estimated proved reserves were 17.3 Tcfe, consisting of 11.1 Tcf of natural gas, 528 MMBbl of ethane, 461 MMBbl of C3+ NGLs, and 38 MMBbl of oil. As of December 31, 2017, 64% of our estimated proved reserves by volume were natural gas, 34% were NGLs, and 2% were oil. Proved developed reserves were 8.5 Tcfe, or 49% of total proved reserves.

For the year ended December 31, 2017, our production totaled 822 Bcfe, or 2,253 MMcfe per day, a 22% increase compared to 676 Bcfe, or 1,847 MMcfe per day, for the year ended December 31, 2016.  The average realized price for 2017 production before the effects of gains on settled derivatives was $3.34 per Mcfe compared to $2.60 per Mcfe in 2016.  The increase was primarily attributable to increases in energy commodity prices during the second half of 2016 that continued into 2017.  Our average realized price after the effects of gains on settled derivatives was $3.60 per Mcfe during 2017 as compared to $4.08 per Mcfe during 2016.

For the year ended December 31, 2017, we generated consolidated cash flow from operations of $2.0 billion, consolidated net income of $615 million, Adjusted EBITDAX of $1.5 billion, and Stand-Alone E&P Adjusted EBITDAX of $1.2 billion.  This compares to consolidated cash flow from operations of $1.2 billion, a consolidated net loss of $849 million, Adjusted EBITDAX of $1.5 billion, and Stand-Alone E&P Adjusted EBITDAX of $1.4 billion for the year ended December 31, 2016.  See “Item 6. Selected Financial Data” for a definition of Adjusted EBITDAX (a non‑GAAP measure) and a reconciliation of Adjusted EBITDAX to net income (loss).  See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations— Stand-Alone Exploration and Production (E&P) Information” for a definition of Stand-Alone E&P Adjusted EBITDAX and a reconciliation of Stand-Alone E&P Adjusted EBITDAX to Antero’s stand-alone net income (loss).  “Stand-alone” data represents information for Antero on an unconsolidated basis, reflecting Antero’s investment in Antero Midstream under the equity method of accounting.

Consolidated net income for 2017 included (i) commodity derivative fair value gains of $637 million, comprised of gains on settled derivatives of $214 million, cash proceeds from derivative monetizations of $750 million, and a non-cash loss of $327 million on changes in the fair value of commodity derivatives, (ii) a noncash charge of $103 million for equity-based compensation, (iii) a noncash charge of $183 million for impairments, and (iv) a noncash tax benefit of $295 million.

2017 Capital Spending and 2018 Capital Budget

For the year ended December 31, 2017, our total consolidated capital expenditures were approximately $2.2 billion, including drilling and completion expenditures of $1.3 billion, leasehold additions of $204 million, acquisitions of $176 million, gathering and compression expenditures of $346 million, water handling and treatment expenditures of $195 million, and other capital expenditures of $14 million.  Our consolidated capital budget for 2018 is $2.1 billion, and includes: $1.3 billion for drilling and completion, $150 million for leasehold expenditures, and $650 million for capital expenditures by Antero Midstream, which includes $215 million for investments in unconsolidated affiliates.  We do not budget for acquisitions.  Approximately 80% of the drilling and completion budget is allocated to the Marcellus Shale and the remaining 20% is allocated to the Utica Shale.  During 2018, we plan to operate an average of five drilling rigs and four completion crews in the Marcellus Shale, and one drilling rig and one completion crew in the

2


 

Utica Shale, and we plan to complete 140-150 horizontal wells in the Marcellus and Utica Shales in 2018 as compared to 135 in 2017.  We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities, and commodity prices.

Hedge Position

At December 31, 2017, we had entered into fixed price hedging contracts for January 1, 2018 through December 31, 2023 for 2.7 Tcf of our projected natural gas production at a weighted average index price of $3.34 per MMBtu, 291 million gallons of propane at a weighted average price of $0.75 per gallon, and 1.5 MMBbls of oil at a weighted average price of $55.97 per Bbl.  These hedging contracts include contracts for the year ending December 31, 2018 of 731 Mcf of natural gas at a weighted average index price of $3.50 per MMBtu, 291 million gallons of propane at a weighted average price of $0.75 per gallon, and 1.5 MMBbls of oil at a weighted average price of $55.97 per Bbl.

To the extent we have fixed the price of a portion of our estimated future production through 2023, we believe this hedge position provides some certainty to cash flows supporting our future operations and capital spending plans.  As of December 31, 2017, the estimated fair value of our commodity derivative contracts was approximately $1.3 billion.

Credit Facilities

On October 26, 2017, we entered into restated and amended senior revolving credit facilities for both Antero and Antero Midstream.  Both facilities were amended to include fall away covenants and lower interest rates that are triggered if and when the companies are assigned an investment grade credit rating by either Standard and Poor’s or Moody’s.

Antero’s borrowing base under its new facility (the “Credit Facility”) is $4.5 billion and lender commitments are $2.5 billion, representing a reduction from the previous borrowing base of $250 million and a reduction of $1.5 billion in lender commitments, reflecting our plan to primarily fund our drilling and completion program with cash flows from operations.  The maturity date of the facility was extended from May 2019 to the earlier of (i) October 26, 2022 and (ii) the date that is 91 days prior to the earliest stated redemption of any series of Antero’s senior notes, unless such series of notes is refinanced.  The borrowing base under our revolving credit facility is redetermined annually and is based on the estimated future cash flows from our proved oil and gas reserves and our commodity derivative positions. The next redetermination is scheduled to occur in April 2018.  At December 31, 2017, we had $185 million of borrowings and $705 million of letters of credit outstanding under the revolving credit facility.  See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements and Contractual Obligations—Senior Secured Revolving Credit Facility” for a description of our Credit Facility.

Lender commitments under Antero Midstream’s new facility (the “Midstream Credit Facility”) remained at $1.5 billion.  The maturity date of the facility was extended from November 2019 to October 26, 2022.  At December 31, 2017, Antero Midstream had $555 million of borrowings outstanding under the Midstream Credit Facility.  See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements and Contractual Obligations—Midstream Credit Facility” for a description of the Midstream Credit Facility.

Delevering Activities 

   

In the third quarter of 2017, we monetized over $1 billion of our non-exploration and production assets and used the proceeds to repay outstanding borrowings under our revolving credit facility.  Proceeds from these activities are not expected to result in cash taxes payable due to the utilization of a portion of our net operating loss (“NOL”) carryforwards.  These deleveraging activities consisted of the following transactions:

·

On September 11, 2017, we completed a public sale of 10,000,000 common units representing limited partner interests in Antero Midstream which were held by Antero.  We received $311 million in net proceeds from the transaction.

·

In September 2017, we monetized portions of our hedge portfolio by reducing the average fixed index prices on certain of our natural gas hedges that settle from 2018 through 2022 while maintaining the total volumes hedged.  We received total proceeds of approximately $750 million from the monetization of the natural gas hedges.

Formation of Joint Venture and Issuance of Common Units by Antero Midstream 

   

On February 6, 2017, Antero Midstream formed the Joint Venture to develop processing assets in Appalachia with MarkWest, a wholly owned subsidiary of MPLX.  Antero Midstream and MarkWest each own a 50% interest in the Joint Venture and

3


 

MarkWest operates the Joint Venture assets.  The Joint Venture assets consist of processing plants in West Virginia and a one-third interest in a recently commissioned MarkWest fractionator in Ohio.

In conjunction with the formation of the Joint Venture, on February 10, 2017, Antero Midstream issued 6,900,000 common units, including the underwriters’ purchase option, generating net proceeds of approximately $223 million.  Antero Midstream used the net proceeds to fund the initial contribution to the Joint Venture, repay outstanding borrowings under the Midstream Credit Facility, and for general partnership purposes.

Antero Midstream Equity Distribution Agreement 

Antero Midstream has an Equity Distribution Agreement (the “Distribution Agreement”), pursuant to which Antero Midstream may sell, from time to time through brokers acting as its sales agents, common units representing limited partner interests having an aggregate offering price of up to $250 million.  Sales of the common units are made by means of ordinary brokers’ transactions on the New York Stock Exchange, at market prices, in block transactions, or as otherwise agreed to between Antero Midstream and the sales agents.  Proceeds are used for general partnership purposes, which may include repayment of indebtedness and funding working capital or capital expenditures.  The Partnership is under no obligation to offer and sell common units under the Distribution Agreement. 

During the year ended December 31, 2017, Antero Midstream issued and sold 777,262 common units under the Distribution Agreement, resulting in net proceeds of $25.5 million after deducting commissions and other offering costs.  As of December 31, 2017, Antero Midstream had the capacity to issue additional common units under the Distribution Agreement up to an aggregate sales price of $157.3 million.

Initial Public Offering of Antero Midstream GP LP

AMGP was originally formed as ARMM in 2013 to become Antero Midstream’s general partner.  In April 2017, in connection with its proposed IPO, ARMM formed Antero Midstream Partners GP LLC (“AMP GP”), a Delaware limited liability company, as a wholly owned subsidiary, and assigned it the general partner interest in Antero Midstream.  Concurrent with the assignment, AMP GP was admitted as the sole general partner of Antero Midstream and ARMM ceased to be Antero Midstream’s general partner.  On May 4, 2017, ARMM converted from a Delaware limited liability company to a Delaware limited partnership and changed its name to Antero Midstream GP LP in connection with its IPO.  On May, 9, 2017, AMGP closed its IPO of 37,250,000 common shares held by its sole member at $23.50 per common share. Neither we nor Antero Midstream received any proceeds from the sale of common shares in the IPO. Subsequent to its IPO, AMGP indirectly controls the general partnership interest in Antero Midstream, through its ownership of AMP GP, and directly controls IDR LLC, a subsidiary of AMGP, which owns the IDRs in Antero Midstream.

Antero Resources Corporation does not hold any financial or other interests in AMGP. However, certain of our directors and executive officers own AMGP common shares as well as profits interests in IDR LLC, which owns all of Antero Midstream’s IDRs.  In addition, Paul M. Rady and Glen C. Warren, Jr., together with certain funds affiliated with Warburg Pincus LLC (“Warburg”) and certain funds affiliated with Yorktown Partners LLC (“Yorktown”), collectively own 100% of the membership interests in AMGP GP LLC, the general partner of AMGP. Certain of our directors and executive officers also own a portion of Antero Midstream’s common units.

Tax Reform

New tax legislation, commonly referred to as the Tax Cuts and Jobs Act, was enacted on December 22, 2017. ASC 740, Accounting for Income Taxes, requires companies to recognize the effect of tax law changes in the period of enactment even though the effective date for most provisions is for tax years beginning after December 31, 2017. Adjustments to our tax provision that were recorded in the three months ended December 31, 2017 principally relate to the reduction in the U.S. corporate income tax rate to 21%, which resulted in the Company recognizing an income tax benefit of $428 million to remeasure deferred tax liabilities that will reverse at the new 21% rate. Other significant provisions that are not yet effective but may impact income taxes in future years include: the repeal of the corporate Alternative Minimum Tax, the limitation on the current deductibility of net interest expense in excess of 30% of adjusted taxable income for levered balance sheets, a limitation on utilization of net operating losses generated after tax year 2017 to 80% of taxable income, the unlimited carryforward of net operating losses generated after tax year 2017, temporary 100% expensing of certain business assets, additional limitations on certain general and administrative expenses, and changes in determining the excessive compensation limitation.  Currently, we do not anticipate paying cash federal income taxes in the near term due to any of the legislative changes, primarily due to our ability to expense intangible drilling costs and the utilization of our net operating loss carryforwards.  Future interpretations relating to the recently enacted U.S. federal income tax legislation which vary

4


 

from our current interpretation and possible changes to state tax laws in response to the recently enacted federal legislation may have a significant effect on this projection.

Our Properties and Operations

Estimated Proved Reserves

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

Reserves Presentation

The following table summarizes our estimated proved reserves, related Standardized measure, and PV‑10 at December 31, 2015, 2016 and 2017.  Total estimated proved reserves are prepared on a consolidated basis, as required by SEC Rules, using operating and capital costs on a consolidated basis.  Our estimated proved reserves are based on evaluations prepared by our internal reserve engineers, which have been audited by our independent engineers, DeGolyer and MacNaughton (“D&M”).  We refer to D&M as our independent engineers.  A copy of the summary report of D&M with respect to our reserves at December 31, 2017 is filed as Exhibit 99.1 to this Annual Report on Form 10‑K.  Within D&M, the technical person primarily responsible for reviewing our reserves estimates was Gregory K. Graves, P.E.  Mr. Graves is a Registered Professional Engineer in the State of Texas (License No. 70734), is a member of both the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers, and has in excess of 33 years of experience in oil and gas reservoir studies and reserves evaluations.  Mr. Graves graduated from the University of Texas at Austin in 1984 with a Bachelor of Science degree in Petroleum Engineering.  Reserves at December 31, 2015, 2016, and 2017 were prepared assuming partial ethane recovery, and rejection of the remaining ethane.  When ethane is rejected at the processing plant, it is left in the gas stream and sold with the methane gas.

 

 

 

 

 

 

 

 

 

 

 

 

  

At December 31,

 

 

 

2015

  

2016

    

2017

 

Estimated proved reserves:

 

 

 

 

 

 

 

 

 

 

Proved developed reserves:

 

 

 

 

 

 

 

 

 

 

Natural gas (Bcf)

 

 

3,627

 

 

4,426

 

 

5,587

 

Ethane (MMBbl)

 

 

247

 

 

250

 

 

268

 

C3+ NGLs (MMBbl)

 

 

113

 

 

151

 

 

199

 

Oil (MMBbl)

 

 

 8

 

 

13

 

 

16

 

Total equivalent proved developed reserves (Bcfe)

 

 

5,838

 

 

6,914

 

 

8,488

 

Proved undeveloped reserves:

 

 

 

 

 

 

 

 

 

 

Natural gas (Bcf)

 

 

5,906

 

 

4,988

 

 

5,511

 

Ethane (MMBbl)

 

 

 —

 

 

304

 

 

260

 

C3+ NGLs (MMBbl)

 

 

227

 

 

252

 

 

262

 

Oil (MMBbl)

 

 

18

 

 

25

 

 

22

 

Total equivalent proved undeveloped reserves (Bcfe)

 

 

7,377

 

 

8,472

 

 

8,773

 

Total estimated proved reserves (Bcfe)

 

 

13,215

 

 

15,386

 

 

17,261

 

PV-10 (in millions)(1)

 

$

3,634

 

$

3,676

 

$

10,175

 

Standardized measure (in millions)(1)

 

$

3,233

 

$

3,287

 

$

8,627

 

Proved developed producing (Bcfe)

 

 

5,553

 

 

6,587

 

 

7,996

 

Proved developed non-producing (Bcfe)

 

 

285

 

 

327

 

 

492

 

Percent developed

 

 

44

%

 

45

%

 

49

%


(1)

PV‑10 was prepared using average yearly prices computed using SEC rules, discounted at 10% per annum, without giving effect to taxes. PV‑10 is a non‑GAAP financial measure. We believe that the presentation of PV‑10 is relevant and useful to our investors as supplemental disclosure to the standardized measure of future net cash flows, or after tax amount, because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account future corporate income taxes and our current tax structure. While the standardized measure is dependent on the unique tax situation of each company, PV‑10 is based on a pricing methodology and discount factors that are consistent for all companies. Because of this, PV‑10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. The difference between the standardized measure and the PV‑10 amount is the discounted amount of estimated future income taxes. For more information about the calculation of Standardized measure, see footnote 20 to our consolidated financial statements included in Item 8 of this Annual Report on Form 10‑K.

5


 

The following sets forth the estimated future net cash flows from our proved reserves (without giving effect to our commodity derivatives), the present value of those net cash flows before income tax (PV‑10), the present value of those net cash flows after income tax (Standardized measure) and the prices used in projecting future net cash flows at December 31, 2015, 2016, and 2017:

 

 

 

 

 

 

 

 

 

 

 

 

  

At December 31,

 

(In millions, except per Mcf data)

    

2015(1)

    

2016(2)

    

2017(3)

 

Future net cash flows

 

$

12,569

 

$

11,623

 

$

26,137

 

Present value of future net cash flows:

 

 

 

 

 

 

 

 

 

 

Before income tax (PV-10)

 

$

3,634

 

$

3,676

 

$

10,175

 

Income taxes

 

$

(401)

 

$

(389)

 

$

(1,548)

 

After income tax (Standardized measure)

 

$

3,233

 

$

3,287

 

$

8,627

 


(1)

12‑month average prices used at December 31, 2015 were $2.56 per MMBtu for natural gas, $14.19 per Bbl for NGLs, and $40.06 per Bbl for oil for the Appalachian Basin based on a $50.13 WTI reference price.

(2)

12‑month average prices used at December 31, 2016 were $2.31 per MMBtu for natural gas, $13.58 per Bbl for NGLs, and $32.63 per Bbl for oil for the Appalachian Basin based on a $42.68 WTI reference price.

(3)

12‑month average prices used at December 31, 2017 were $2.91 per MMBtu for natural gas, $20.40 per Bbl for NGLs, and $45.35 per Bbl for oil for the Appalachian Basin based on a $51.03 WTI reference price.

Future net cash flows represent projected revenues from the sale of proved reserves net of production and development costs (including operating expenses and production taxes).  Prices for 2015, 2016, and 2017 were based on 12‑month unweighted average of the first‑day‑of‑the‑month pricing, without escalation. Costs are based on costs in effect for the applicable year without escalation. There can be no assurance that the proved reserves will be produced as estimated or that the prices and costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information, and different reservoir engineers often arrive at different estimates for the same properties.

Changes in Proved Reserves During 2017

The following table summarizes the changes in our estimated proved reserves during 2017 (in Bcfe):

 

 

 

 

Proved reserves, December 31, 2016

 

15,386

 

Extensions, discoveries, and other additions

 

1,711

 

Purchase of reserves

 

373

 

Performance revisions

 

96

 

Revisions to 5-year development plan

 

498

 

Price revisions

 

132

 

Revisions to ethane recovery

 

(113)

 

Production

 

(822)

 

Proved reserves, December 31, 2017

 

17,261

 

 

Extensions, discoveries, and other additions of 1,711 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales.  Purchases of 373 Bcfe related to the acquisition of developed and undeveloped leasehold acreage in both the Marcellus and Utica Shales.  Positive revisions of 96 Bcfe related to improved well performance.  Net positive revisions of 498 Bcfe related to revisions to our 5-year development plan.  This figure includes positive revisions of 2,778 Bcfe for previously proved undeveloped properties reclassified from non-proved properties at December 31, 2016 to proved undeveloped at December 31, 2017 due to their addition to our 5-year development plan, and negative revisions of 2,280 Bcfe for locations that were not developed within 5 years of initial booking as proved reserves.  Positive revisions of 132 Bcfe were due to increases in prices for natural gas, NGLs, and oil.  Negative revisions of 113 Bcfe are due to a decrease in our assumed future ethane recovery.  Our estimated proved reserves as of December 31, 2017 totaled approximately 17.3 Tcfe, an increase of 12% from the prior year.

6


 

Proved Undeveloped Reserves

Proved undeveloped reserves are included in the previous table of total proved reserves. The following table summarizes the changes in our estimated proved undeveloped reserves during 2017 (in Bcfe):

 

 

 

 

Proved undeveloped reserves, December 31, 2016

 

8,472

 

Extension, discoveries, and other additions

 

1,397

 

Purchase of reserves

 

266

 

Performance revisions

 

144

 

Revisions to 5-year development plan

 

498

 

Price revisions

 

49

 

Reclassifications to proved developed reserves

 

(1,860)

 

Revisions to ethane recovery

 

(193)

 

Proved undeveloped reserves, December 31, 2017

 

8,773

 

 

Extensions, discoveries, and other additions during 2017 of 1,397 Bcfe of proved undeveloped reserves resulted from delineation and developmental drilling in the Marcellus and Utica Shales.  Purchases of 266 Bcfe related to the acquisition of undeveloped leasehold acreage in both the Marcellus and Utica Shales.  Positive revisions of 144 Bcfe related to improved well performance.  Net positive revisions of 498 Bcfe related to revisions to our 5-year development plan.  This figure includes positive revisions of 2,778 Bcfe for previously proved properties reclassified from non-proved properties at December 31, 2016 to proved undeveloped at December 31, 2017 due to their addition to our 5-year development plan, and negative revisions of 2,280 Bcfe for locations that were not developed within 5 years of initial booking as proved reserves.  Positive revisions of 49 Bcfe were due to increases in prices for natural gas, NGLs, and oil. 

During the year ended December 31, 2017, we converted approximately 1,860 Bcfe, or 22%, of our proved undeveloped reserves to proved developed reserves at a total capital cost of approximately $584 million.  We spent an additional $313 million on development costs related primarily to drilled and uncompleted wells and properties in the proved undeveloped classification at December 31, 2016, resulting in total development spending of $897 million, as disclosed in note 20 to the consolidated financial statements included elsewhere in this report.  Estimated future development costs relating to the development of our proved undeveloped reserves at December 31, 2017 are approximately $3.3 billion, or $0.37 per Mcfe, over the next five years.  Based on strip pricing as of December 31, 2017, we believe that cash flows from operations will be sufficient to finance such future development costs.  While we will continue to drill leasehold delineation wells and build on our current leasehold position, we will also continue drilling our proved undeveloped reserves.  See “Item 1A. Risk Factors—The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.”

We maintain a 5-year development plan, which is reviewed by our Board of Directors, which supports our corporate production growth target.   The development plan is reviewed annually to ensure capital is allocated to the wells that have the highest risk-adjusted rates of return within our inventory of undrilled well locations.  As our acreage position has grown and well economics have changed, we have reallocated 5-year capital to areas with expected highest rates of return and optimal lateral lengths.  This resulted in the reclassification of 2,280 Bcfe of reserves from proved undeveloped to probable during the year ended December 31, 2017 due to the 5-year development rule.  Based on our then-current acreage position, strip prices, anticipated well economics, and our development plans at the time these reserves were classified as proved, we believe the previous classification of these locations as proved undeveloped was appropriate.

At December 31, 2017, an estimated 10,200 of our net leasehold acres, containing 268 locations associated with proved undeveloped reserves, are subject to renewal prior to scheduled drilling.  Some of these leases have contract renewal options and some will need to be renegotiated.  We estimate a potential cost of approximately $29 million to renew the 10,200 acres based upon current leasing authorizations and option to extend payments.  Proved undeveloped reserves of 980 Bcfe are related to these leases.  Historically, we have had a high success rate in renewing Appalachian leases, and we expect that we will be able to renew substantially all of the leases underlying this acreage prior to the scheduled drilling dates.  Based on our historical success rate in renewing leases, we estimate that we may be unable to renew leases covering approximately 98 Bcfe of these proved undeveloped reserves.

If we are unable to renew these leases prior to the scheduled drilling dates, our quantities of proved undeveloped reserves will be somewhat reduced.

7


 

Preparation of Reserve Estimates

Our reserve estimates as of December 31, 2015, 2016, and 2017 included in this Annual Report on Form 10‑K were prepared by our internal reserve engineers in accordance with petroleum engineering and evaluation standards published by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC.  Our internally prepared reserve estimates were audited by our independent reserve engineers.  Our independent reserve engineers were selected for their historical experience and geographic expertise in engineering unconventional resources.  The technical persons responsible for overseeing the audit of our reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

Our internal staff of petroleum engineers and geoscience professionals work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserve auditing process.  Periodically, our technical team meets with the independent reserve engineers to review properties and discuss methods and assumptions used by us to prepare reserve estimates.  Our internally prepared reserve estimates and related reports are reviewed and approved by our Senior Vice President of Reserves, Planning & Midstream, Ward D. McNeilly.  Mr. McNeilly has been with the Company since October 2010.  Mr. McNeilly has 38 years of experience in oil and gas operations, reservoir management, and strategic planning.  From 2007 to October 2010, Mr. McNeilly was the Operations Manager for BHP Billiton’s Gulf of Mexico operations.  From 1996 through 2007, Mr. McNeilly served in various North Sea and Gulf of Mexico Deepwater operations and asset management positions with Amoco and then BP.  From 1979 through 1996, Mr. McNeilly served in various domestic and international operations and reservoir and asset management positions with Amoco.  Mr. McNeilly holds a B.S. in Geological Engineering from the Mackay School of Mines at the University of Nevada.

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

Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.  The term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate.  To achieve reasonable certainty, we and the independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability.  The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available downhole and production data, micro‑seismic data, and well‑test data.  Probable reserves are reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.  Estimates of probable reserves which may potentially be recoverable through additional drilling or recovery techniques are, by nature, more uncertain than estimates of proved reserves and, accordingly, are subject to substantially greater risk of realization.  Possible reserves are reserves that are less certain to be recovered than probable reserves.  Estimates of possible reserves are also inherently imprecise.  Estimates of probable and possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes, and other factors.

Methodology Used to Apply Reserve Definitions

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

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

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

8


 

Identification of Potential Well Locations

Our identified potential well locations represent locations to which proved, probable, or possible reserves were attributable based on SEC pricing as of December 31, 2017.  We prepare internal estimates of probable and possible reserves but have not included disclosure of such reserves in this report.

Production, Revenues, and Price History

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

Operations Data – Exploration and Production and Marketing Segments

The following table sets forth information regarding our production, realized prices, and production costs for the years ended December 31, 2015, 2016 and 2017.  For additional information on price calculations, see information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

 

 

 

 

 

 

 

 

 

 

 

 

Year ended December 31,

 

 

  

2015

  

2016

  

2017

 

Production data:

 

 

 

 

 

 

 

 

 

 

Natural gas (Bcf)

 

 

439

 

 

505

 

 

591

 

C2 Ethane (MBbl)

 

 

201

 

 

6,396

 

 

10,539

 

C3+ NGLs (MBbl)

 

 

15,350

 

 

20,279

 

 

25,507

 

Oil (MBbl)

 

 

2,078

 

 

1,873

 

 

2,451

 

Combined (Bcfe)

 

 

545

 

 

676

 

 

822

 

Daily combined production (MMcfe/d)

 

 

1,493

 

 

1,847

 

 

2,253

 

Average prices before effects of derivative settlements:

 

 

 

 

 

 

 

 

 

 

Natural gas (per Mcf)

 

$

2.37

 

$

2.50

 

$

2.99

 

C2 Ethane (per Bbl)

 

$

6.17

 

$

8.28

 

$

8.83

 

C3+ NGLs (per Bbl)

 

$

17.15

 

$

18.74

 

$

30.48

 

Oil (per Bbl)

 

$

34.05

 

$

32.73

 

$

44.14

 

Combined average sales prices before effects of derivative settlements (per Mcfe)(1)

 

$

2.52

 

$

2.60

 

$

3.34

 

Combined average sales prices after effects of derivative settlements (per Mcfe)(1)

 

$

4.10

 

$

4.08

 

$

3.60

 

Average Costs (per Mcfe)(2):

 

 

 

 

 

 

 

 

 

 

Lease operating

 

$

0.07

 

$

0.07

 

$

0.11

 

Gathering, compression, processing, and transportation

 

$

1.56

 

$

1.70

 

$

1.75

 

Production and ad valorem taxes

 

$

0.14

 

$

0.10

 

$

0.11

 

Marketing, net

 

$

0.23

 

$

0.16

 

$

0.13

 

Depletion, depreciation, amortization, and accretion

 

$

1.14

 

$

1.05

 

$

0.86

 

General and administrative (before equity-based compensation)

 

$

0.20

 

$

0.16

 

$

0.14

 


(1)

Average sales prices shown in the table reflect both the before and after effects of our settled derivatives.  Our calculation of such after effects includes gains on settlements of derivatives (but does not include $750 million of cash proceeds received from hedge monetizations in 2017), which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes.  Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts.  This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value.

(2)

Average costs reflect our operating costs on a standalone basis for Antero, prior to the elimination of intercompany transactions for midstream and water services provided by Antero Midstream.

9


 

Productive Wells

As of December 31, 2017, we held interests in a total of 958 gross (865 net) producing wells on our Marcellus Shale acreage, including the following:

·

652 gross (643 net) horizontal wells, averaging a 99% working interest, operated by Antero.

·

64 gross (5 net) horizontal wells operated by other producers.

·

242 gross (217 net) shallow vertical wells.

As of December 31, 2017, we held interests in a total of 204 gross (175 net) producing wells on our Ohio Utica Shale acreage, including the following:

·

191 gross (175 net) horizontal wells, averaging a 92% working interest, operated by Antero.

·

13 gross (0.04 net) horizontal wells operated by other producers.

Additionally, at December 31, 2017 we had 27 net horizontal proved developed non-producing wells, and 137 gross horizontal wells (134 net) that were drilled and uncompleted or in the process of being completed.  The shallow vertical wells and wells operated by other producers were primarily acquired in conjunction with leasehold acreage acquisitions.

Acreage

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we own an interest as of December 31, 2017.  A majority of our developed acreage is subject to liens securing our revolving credit facility. Approximately 56% of our net Marcellus acreage and 42% of our net Utica acreage is held by production.  Acreage related to royalty, overriding royalty, and other similar interests is excluded from this table.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed Acres

 

Undeveloped Acres

 

Total Acres

 

Basin

    

Gross

    

Net

    

Gross

    

Net

    

Gross

    

Net

 

Marcellus Shale

 

101,274

 

99,760

 

452,362

 

384,101

 

553,636

 

483,861

 

Utica Shale

 

36,668

 

31,038

 

120,458

 

105,542

 

157,126

 

136,580

 

Total

 

137,942

 

130,798

 

572,820

 

489,643

 

710,762

 

620,441

 

 

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

 

 

 

 

 

 

 

 

Marcellus

 

County, State

  

Gross
Acres

  

Net
Acres

 

Doddridge, WV

 

169,289

 

147,952

 

Gilmer, WV

 

12,695

 

11,095

 

Harrison, WV

 

107,496

 

93,948

 

Lewis, WV

 

48

 

42

 

Marion, WV

 

9,465

 

8,272

 

Monongalia, WV

 

2,761

 

2,413

 

Pleasants, WV

 

4,505

 

3,938

 

Ritchie, WV

 

83,311

 

72,811

 

Tyler, WV

 

90,540

 

79,129

 

Wetzel, WV

 

62,901

 

54,974

 

Fayette, PA

 

6,205

 

5,423

 

Washington, PA

 

269

 

236

 

Westmoreland, PA

 

4,151

 

3,628

 

Total Marcellus Shale

 

553,636

 

483,861

 

 

10


 

 

 

 

 

 

 

 

 

Ohio Utica

 

 

  

Gross
Acres

  

Net
Acres

 

Athens, OH

 

84

 

84

 

Belmont, OH

 

11,970

 

11,337

 

Guernsey, OH

 

7,957

 

6,743

 

Harrison, OH

 

577

 

577

 

Monroe, OH

 

58,673

 

56,150

 

Noble, OH

 

74,798

 

59,258

 

Washington, OH

 

3,067

 

2,431

 

Total Utica Shale

 

157,126

 

136,580

 

 

 

 

 

 

 

Total Marcellus and Utica Shale

 

710,762

 

620,441

 

 

Undeveloped Acreage Expirations

The following table sets forth our total gross and net undeveloped acres as of December 31, 2017 that will expire over the next three years unless production is established within the spacing units covering the acreage prior to the expiration dates, or unless the leases containing such acreage are extended or renewed.  The Company is either planning to drill or is actively pursuing lease extensions or renewals on the majority of this acreage.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Marcellus

 

Ohio Utica

 

Total

 

 

  

Gross
Acres

  

Net
Acres

  

Gross
Acres

  

Net
Acres

  

Gross
Acres

  

Net
Acres

 

2018

 

36,138

 

31,583

 

34,599

 

28,592

 

70,737

 

60,175

 

2019

 

55,977

 

48,923

 

24,054

 

22,507

 

80,031

 

71,430

 

2020

 

36,632

 

32,013

 

9,543

 

8,768

 

46,175

 

40,781

 

 

Drilling Activity

The following table sets forth the results of our drilling activity for wells drilled and completed during the years ended December 31, 2015, 2016, and 2017. Gross wells reflect the number of wells in which we own an interest and include historical drilling activity in the Appalachian Basin.  Net wells reflect the sum of our working interests in gross wells.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year ended December 31,

 

 

 

2015

 

2016

 

2017

 

 

    

Gross

 

Net

    

Gross

 

Net

    

Gross

 

Net

 

Marcellus

 

 

 

 

 

 

 

 

 

 

 

 

 

Development wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

69

 

68

 

72

 

71

 

112

 

111

 

Dry

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

 

Total development wells

 

69

 

68

 

72

 

71

 

112

 

111

 

Exploratory wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 5

 

 5

 

16

 

16

 

 1

 

 1

 

Dry

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

 

Total exploratory wells

 

 5

 

 5

 

16

 

16

 

 1

 

 1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Utica

 

 

 

 

 

 

 

 

 

 

 

 

 

Development wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

21

 

18

 

35

 

35

 

 4

 

 4

 

Dry

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

 

Total development wells

 

21

 

18

 

35

 

35

 

 4

 

 4

 

Exploratory wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

37

 

33

 

 5

 

 5

 

18

 

18

 

Dry

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

 

Total exploratory wells

 

37

 

33

 

 5

 

 5

 

18

 

18

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

11


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year ended December 31,

 

 

 

2015

 

2016

 

2017

 

 

    

Gross

 

Net

    

Gross

 

Net

    

Gross

 

Net

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

Development wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

90

 

86

 

107

 

106

 

116

 

115

 

Dry

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

 

Total development wells

 

90

 

86

 

107

 

106

 

116

 

115

 

Exploratory wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

42

 

38

 

21

 

21

 

19

 

19

 

Dry

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

 

Total exploratory wells

 

42

 

38

 

21

 

21

 

19

 

19

 

 

The figures in the table above do not include 137 gross wells (134 net) that were drilled and uncompleted or in the process of being completed at December 31, 2017.

Delivery Commitments

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

As of December 31, 2017, our firm sales commitments through 2022 included:

 

 

 

 

 

 

 

 

 

 

Year Ending December 31,

  

Volume of Natural Gas (MMBtu/d)

  

Firm Transport Capacity Utilized (MMBtu/d)

  

Volume of Ethane (Bbl/day)

  

Volume of C3+ NGLs (Bbl/day)

 

2018

 

620,000

 

500,000

 

41,500

 

50,000

 

2019

 

950,000

 

840,000

 

36,500

 

50,000

 

2020

 

830,000

 

790,000

 

36,500

 

50,000

 

2021

 

750,000

 

710,000

 

66,500

 

 —

 

2022

 

680,000

 

640,000

 

66,500

 

 —

 

 

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

Gathering and Compression

Our exploration and development activities are supported by the natural gas gathering and compression assets of our subsidiary, Antero Midstream, as well as by third‑party gathering and compression arrangements.  Unlike many producing basins in the United States, certain portions of the Appalachian Basin do not have sufficient midstream infrastructure to support the existing and expected increasing levels of production.  Our relationship with Antero Midstream allows us to obtain the necessary gathering and compression capacity for our production and we have leveraged our relationship with Antero Midstream to support our growth.  For the years ended December 31, 2016 and 2017, Antero Midstream spent approximately $228 million and $346 million, respectively, on gas gathering and compression infrastructure that services our production.  Subject to any pre-existing dedications or other third-party commitments, we have dedicated to Antero Midstream all of our current and future acreage in West Virginia and Ohio for gathering and compression services.

As of December 31, 2017, Antero Midstream, owned and operated 242 miles of gas gathering pipelines in the Marcellus Shale.  We also have access to additional low‑pressure and high‑pressure pipelines owned and operated by third parties.  As of December 31, 2017, Antero Midstream owned and operated 15 compressor stations and we utilized 12 additional third‑party compressor stations in the Marcellus Shale. The gathering, compression, and dehydration services provided by third parties are contracted on a fixed‑fee basis.

12


 

As of December 31, 2017, Antero Midstream owned and operated 123 miles of low‑pressure, high‑pressure, and condensate gathering pipelines in the Utica Shale, and Antero owned and operated 8 miles of high-pressure pipelines.  As of December 31, 2017, Antero Midstream owned and operated one compressor station and we utilized five additional third‑party compressor stations in the Utica Shale.

Natural Gas Processing

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

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

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

Given the existing commodity price environment and the current limited ethane market in the northeast, we are currently rejecting the majority of the ethane obtained in the natural gas stream when processing our liquids‑rich gas. However, we realize a pricing upgrade when selling the remaining NGLs product stream at current prices.  We may elect to recover more ethane when ethane prices result in a value for the ethane that is greater than the Btu equivalent residue gas and incremental recovery costs.  In late 2015, we began recovering some ethane as the first de-ethanizer was placed on line at the Sherwood gas processing facility.  Our first international ethane sales contract is expected to commence in early 2018.

As of December 31, 2017, we had contracted with MarkWest Energy Partners L.P. to provide cryogenic processing capacity for our Marcellus and Utica Shale production as follows:

 

 

 

 

 

 

 

 

 

Plant Processing Capacity (MMcf/d)

 

Antero Contracted Firm Processing Capacity (MMcf/d)

 

Anticipated Date of Completion

Marcellus Shale:

 

 

 

 

 

 

Sherwood 1

 

200

 

200

 

In service

Sherwood 2

 

200

 

200

 

In service

Sherwood 3

 

200

 

150

 

In service

Sherwood 4

 

200

 

200

 

In service

Sherwood 5

 

200

 

200

 

In service

Sherwood 6

 

200

 

200

 

In service

Sherwood 7

 

200

 

200

 

In service

Sherwood 8

 

200

 

200

 

In service

Sherwood 9

 

200

 

200

 

In service

Sherwood 10

 

200

 

200

 

3Q 2018

Sherwood 11

 

200

 

200

 

4Q 2018

Sherwood 12

 

200

 

200

 

2Q 2019

Marcellus Shale Total

 

2,400

 

2,350

 

 

13


 

 

 

 

 

 

 

 

 

 

Plant Processing Capacity (MMcf/d)

 

Antero Contracted Firm Processing Capacity (MMcf/d)

 

Anticipated Date of Completion

 

 

 

 

 

 

 

Utica Shale:

 

 

 

 

 

 

Seneca 1

 

200

 

150

 

In service

Seneca 2

 

200

 

50

 

In service

Seneca 3

 

200

 

200

 

In service

Seneca 4

 

200

 

200

 

In service

Utica Shale Total

 

800

 

600

 

 

 

Through Antero Midstream’s investment in the Joint Venture, Antero Midstream acquired a 50% non-operated equity interest in certain of the existing and future Sherwood gas processing plants.  The Joint Venture also owns a 33 1/3% interest in a fractionation facility located at the Hopedale complex in Harrison County, Ohio.  The Joint Venture’s processing investment began with the seventh plant at the Sherwood facility and continues through Sherwood 12 on the table above.  The Joint Venture provides processing services to Antero under a long-term, fixed-fee arrangement, subject to annual CPI-based adjustments.

Transportation and Takeaway Capacity

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

·

We have several firm transportation contracts with pipelines that have capacity to deliver natural gas to the Chicago and Michigan markets.  The Chicago directed pipelines include the Rockies Express Pipeline (“REX”), the Midwestern Gas Transmission pipeline (“MGT”), the Natural Gas Pipeline Company of America pipeline (“NGPL”), and the ANR Pipeline Company pipeline (“ANR”).

o

The firm transportation contract on REX provides firm capacity for 600,000 MMBtu per day and delivers gas to downstream contracts on MGT, NGPL, and ANR.  We have 290,000 MMBtu per day of firm transportation on MGT.  We have 310,000 MMBtu per day of firm transportation on NGPL.  Both of these contracts deliver gas to the Chicago city gate area.  In addition, we have 200,000 MMBtu per day of firm transportation on ANR to deliver natural gas to Chicago in the summer and Michigan in the winter.  The Chicago and Michigan contracts expire at various dates from 2021 through 2034. 

·

To access the Gulf Coast market and Eastern Regional markets, we have firm transportation contracts with various pipelines.  These contracts include firm capacity on the Columbia Gas Transmission pipeline (“TCO”), Columbia Gulf Transmission pipeline (“Columbia Gulf”), Tennessee Gas Pipeline (“Tennessee”), Energy Transfer Rover Pipeline (“ET Rover”), ANR Pipeline (“ANR-Gulf”), Equitrans pipeline (“EQT”), and DTE Energy’s Stonewall Gas Gathering (“SGG”) and Appalachia Gathering System (“AGS”).  This diverse portfolio of firm capacity gives us the flexibility to move natural gas to the local Appalachia market or other preferred markets with more favorable pricing.

o

We have several firm transportation contracts on TCO for volumes that total to approximately 571,000 MMBtu per day.   Of the 571,000 MMBtu per day of firm capacity on TCO, we have the ability to utilize 530,000 MMbtu per day of firm capacity on Columbia Gulf, which provides access to the Gulf Coast markets.  These contracts expire at various dates from 2017 through 2025.

o

We have a firm transportation contract with SGG for 1,090,000 MMBtu per day which transports gas from various gathering system interconnection points and the MarkWest Sherwood plant complex to the TCO WB System.  We have a firm transportation contract with TCO to transport natural gas in the western and eastern direction on TCO’s WB system.  The firm transportation contract on TCO’s WB system provides firm capacity in the western direction for volumes that increase from the interim capacity of 355,000 MMBtu per day to 790,000 MMBtu per day in October 2018.  This west directed firm capacity provides access to the local Appalachia market and the Gulf Coast market via the Columbia Gulf or Tennessee pipelines.  The firm transportation contract on TCO’s WB system also provides firm capacity in the eastern direction, which delivers natural gas to the Cove Point LNG facility, for 330,000 MMBtu per day beginning in November 2018. These contracts expire at various dates from 2030 through 2038.

14


 

o

We have a firm transportation contract for 590,000 MMBtu per day on Tennessee to deliver natural gas from the Broad Run interconnect on TCO’s WB system to the Gulf Coast market.  This contract increases to 790,000 MMBtu per day in June 2018.  This contract expires in 2030.

o

We have a firm transportation contract for 600,000 MMBtu per day on ANR-Gulf to deliver natural gas from Ohio to the Gulf Coast market.  This contract expires in 2045.

o

We have a firm transportation contract for 800,000 MMBtu per day on the ET Rover Pipeline which connects the Marcellus and Utica Shale assets to Midwest and Gulf Coast markets via our existing firm transportation on ANR Chicago and ANR Gulf.  This contract expires in 2033.

o

We have firm transportation contracts for 250,000 MMBtu per day on EQT to deliver Marcellus natural gas to Tetco M2 and other various delivery points.  The contracts expire at various dates from 2022 through 2025.

o

We have firm transportation contracts for 375,000 MMBtu per day on the DTE AGS to deliver Marcellus natural gas to TETCO M2 and other various local delivery points.  These contracts expire in 2023.

·

We have a firm transportation contract for 20,000 Bbl per day on the Enterprise Products Partners ATEX pipeline (“ATEX”), to take ethane from Appalachia to Mont Belvieu, Texas. The ATEX firm transportation commitment expires in 2028.

·

We have a firm transportation contract for 11,500 Bbl per day on the Sunoco pipeline (or “Mariner East 2”) to take ethane from Houston, Pennsylvania to Marcus Hook, Pennsylvania.  We also have a firm transportation contract on Mariner East 2 to take a combination of 50,000 Bbl per day of propane and butane from Hopedale, Ohio to Marcus Hook, Pennsylvania.  Mariner East 2 is expected to be in-service in the second quarter of 2018.  These contracts expire on the tenth anniversary from the in-service date.  Mariner East 2 provides access to international markets via trans-ocean LPG carriers.

Under firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries.  See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements and Contractual Obligations” for information on our minimum fees for such contracts.  Based on current projected 2018 annual production levels, we estimate that we could incur total annual net marketing costs of $100 million to $125 million in 2018 for unutilized transportation capacity depending on the amount of unutilized capacity that can be marketed to third parties or utilized to transport third party gas and capture positive basis differentials.  Where permitted, we continue to actively market any excess capacity in order to offset minimum commitment fees.

Water Handling and Treatment Operations

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

Antero Midstream owns two independent fresh water distribution systems that distribute fresh water from the Ohio River and several regional water sources, as well as recycled water from its water treatment plant, for well completion operations in the Marcellus and Utica Shales.  These systems consist of permanent buried pipelines, movable surface pipelines and fresh water storage facilitates, as well as pumping stations to transport the fresh water throughout the pipeline networks. To the extent necessary, the surface pipelines are moved to well pads for service completion operations in concert with our drilling program. As of December 31, 2017, Antero Midstream had the ability to store 5.4 million barrels of fresh water in 38 impoundments located throughout our leasehold acreage in the Marcellus and Utica Shales.  Due to the extensive geographic distribution of Antero Midstream’s water pipeline systems in both West Virginia and Ohio, it is able to provide water delivery services to neighboring oil and gas producers within and adjacent to our operating area, subject to commercial arrangements, while reducing water truck traffic.

As of December 31, 2017, Antero Midstream owned and operated 122 miles of buried fresh water pipelines and 68 miles of movable surface fresh water pipelines in the Marcellus Shale, as well as 25 fresh water storage facilities equipped with transfer pumps. 

15


 

As of December 31, 2017, Antero Midstream owned and operated 55 miles of buried fresh water pipelines and 28 miles of movable surface fresh water pipelines in the Utica Shale, as well as 13 fresh water storage facilities equipped with transfer pumps.

In August 2015, Antero committed to developing an advanced wastewater treatment complex in Doddridge County, West Virginia.  The complex was transferred to Antero Midstream in conjunction with the sale of Antero’s water handling systems in September 2015.  The wastewater treatment complex will include a 60,000 barrel per day facility that will allow Antero Midstream to treat our flowback and produced water for subsequent use or sale for well completions.  The treatment facility is in its final stages of commissioning and is expected to commence full commercial operations in the first quarter of 2018.  Late in 2015, Antero Midstream began providing us with wastewater services for our well completion operations, including wastewater transportation, disposal, and treatment.

Major Customers

For the year ended December 31, 2017, sales to Tenaska Marketing Ventures and WGL Midstream accounted for approximately 22% and 15% of our total product revenues, respectively.  For the year ended December 31, 2016, sales to Tenaska Marketing Venture and WGL Midstream accounted for approximately 29% and 13% of our total product revenues, respectively.  For the year ended December 31, 2015, sales to Tenaska Marketing Ventures, South Jersey Resources, and Sequent Energy Management accounted for 19%, 18%, and 13% of our total product revenues, respectively.

Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards.  As is customary in the industry, often in the case of undeveloped properties, cursory investigation of record title is made at the time of lease acquisition.  Investigations are made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.  Individual properties may be subject to burdens that we believe do not materially interfere with the use, or affect the value of, the properties.  Burdens on properties may include:

·

customary royalty interests;

·

liens incident to operating agreements and for current taxes;

·

obligations or duties under applicable laws;

·

development obligations under natural gas leases; or

·

net profits interests.

Seasonality

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

Competition

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

16


 

human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing natural gas properties.

Regulation of the Oil and Natural Gas Industry

General

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

Regulation of Production of Natural Gas and Oil

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

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

Regulation of Transportation of Natural Gas

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

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

17


 

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

Regulation of Sales of Natural Gas, NGLs, and Oil

The prices at which we sell natural gas, NGLs, and oil are not currently subject to federal regulation and, for the most part, are not subject to state regulation. FERC, however, regulates interstate natural gas transportation rates, and terms and conditions of transportation service, which affects the marketing of the natural gas we produce, as well as the prices we receive for sales of our natural gas. Similarly, the price we receive from the sale of oil and NGLs is affected by the cost of transporting those products to market.  FERC regulates the transportation of oil and liquids on interstate pipelines under the provision of the Interstate Commerce Act, the Energy Policy Act of 1992 and regulations issued under those statutes.  Intrastate transportation of oil, NGLs, and other products, is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. In addition, while sales by producers of natural gas and all sales of crude oil, condensate, and NGLs can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. 

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

The Domenici Barton Energy Policy Act of 2005, or EPAct of 2005 amended the NGA to add an anti‑market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provided FERC with additional civil penalty authority.  In Order No. 670, FERC promulgated rules implementing the anti‑market manipulation provision of the EPAct of 2005, which make it unlawful to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The anti‑market manipulation rules do not apply to activities that relate only to intrastate or other non‑jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non‑jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704 described below.  Under the EPAct of 2005, FERC has the power to assess civil penalties of up to $1,000,000 per day for each violation of the NGA and the NGPA. In January 2017, FERC issued an order (Order No. 834) increasing the maximum civil penalty amounts under the NGA and NGPA to adjust for inflation. FERC may now assess civil penalties under the NGA and NGPA of up to $1,213,503 per violation per day.

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

The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity. In November 2009, the FTC issued regulations pursuant to the Energy Independence and Security Act of 2007 intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to $1,000,000 per violation per

18


 

day.  Together with FERC, these agencies have imposed broad rules and regulations prohibiting fraud and manipulation in oil and gas markets and energy futures markets.

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

Regulation of Environmental and Occupational Safety and Health Matters

General

Our operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health and the discharge of materials into the environment or otherwise relating to environmental protection. Violations of these laws can result in substantial administrative, civil and criminal penalties. These laws and regulations may require the acquisition of permits before drilling or other regulated activity commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines, govern the sourcing and disposal of water used in the drilling and completion process, limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas or areas with endangered or threatened species restrictions, require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits, establish specific safety and health criteria addressing worker protection and impose substantial liabilities for pollution resulting from operations or failure to comply with applicable laws and regulations. In addition, these laws and regulations may restrict the rate of production.

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

Hazardous Substances and Waste Handling

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

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

19


 

compressor oils that may become regulated as hazardous wastes if such wastes have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

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

Water Discharges

The Federal Water Pollution Control Act, or the Clean Water Act (the “CWA”), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or a state equivalent agency. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers. In September 2015, the EPA and U.S. Army Corps of Engineers issued a final rule defining the scope of the EPA’s and the Corps’ jurisdiction. To the extent the rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule, which was supposed to become effective in August 2015, has been challenged in court on the grounds that it unlawfully expands the reach of CWA programs, and implementation of the rule has been stayed pending resolution of the court challenge. In January 2018, the U.S. Supreme Court determined that federal district courts have jurisdiction to review the rule. Now that the Supreme Court has established the proper jurisdiction for the litigation, several district court cases that had been put on hold could be restarted, and it is unclear how the Trump Administration will defend the rule. Following the issuance of a presidential executive order to review the rule, the EPA and the Corps proposed a rulemaking to repeal the rule in June 2017; the EPA and Corps also announced their intent to issue a new rule defining the CWA’s jurisdiction. In November 2017, the EPA and the Corps proposed postponing by two years the effective date of the rule until at least 2020, which would provide the agencies more time to potentially repeal and replace the rule. As a result, future implementation of the rule is uncertain at this time. To the extent this rule or a revised rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which could delay the development of our natural gas and oil projects. Also, pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

Air Emissions

The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as, for example, compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre‑approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants, the costs of which could be significant. The need to obtain permits has the potential to delay the development of our oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard, or NAAQS, for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. In November 2017, the EPA published a partial list of attainment designations for the 2015 ozone standard.  The EPA issued preliminary nonattainment designations in December 2017, and has announced that they plan to issue final attainment status designations during the first half of 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result

20


 

in increased expenditures for pollution control equipment, the costs of which could be significant.  More recently, in June 2016, the EPA finalized rules under the federal Clean Air Act regarding criteria for aggregating multiple sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities (such as tank batteries and compressor stations), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment.  The EPA has also issued final rules under the Clean Air Act that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants programs. These final rules require, among other things, the reduction of volatile organic compound (“VOC”) emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels.  Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of natural gas and oil projects and increase our costs of development and production, which costs could be significant. However, we do not believe that compliance with such requirements will have a material adverse effect on our operations.

Regulation of “Greenhouse Gas” Emissions

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases, or GHGs, present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case‑by‑case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. For example, in December 2015, the EPA finalized rules that added new sources to the scope of the GHG monitoring and reporting rule. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. These changes to EPA’s GHG emissions reporting rule could result in increased compliance costs. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule.

In June 2016, the EPA finalized new regulations that establish emission standards for methane and volatile organic compounds from new and modified oil and natural gas production and  natural gas processing and transmission facilities. The EPA’s rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. In addition, the rule package extends existing VOC standards under the EPA’s Subpart OOOO of the NSPS, or NSPS Quad O, to include previously unregulated equipment within the oil and natural gas source category. In June 2017, the EPA proposed to stay these requirements for two years and revisit the entirety of the 2016 standards. Comments to the EPA’s proposal were due in August 2017. The EPA has not yet published a final rule. As a result of these developments, future implementation of the 2016 standards is uncertain at this time.

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

We have been making efforts to reduce methane emissions since March 2005, when we engaged local community groups in Colorado regarding our activities in the Piceance Basin in discussions on how to minimize air emission impacts from our operations.  In 2012, the EPA promulgated NSPS Quad O, which, among other actions, requires the use of reduced emission completions, or “green completions,” to control emissions of methane from hydraulically fractured natural gas wells. The green completions requirements of NSPS Quad O became effective in January 2015, but we have been performing green completions since before the EPA’s rules became effective.  We were one of the first operators to implement green completions in Colorado back in July 2011, using equipment that our personnel helped design.  After initial testing confirming the viability and effectiveness of the units, we implemented their use in the Appalachian Basin Marcellus Shale play in 2012 and later in the Utica Shale play.  We have a long history of managing methane emissions from our operations, as demonstrated by our early use of green completions.

21


 

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

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

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

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

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

1)

Facility LDAR inspections were conducted at twice the frequency required by regulations during 2017.

2)

A burner management system that optimizes the efficiency of our combusters.

3)

Implementation of three stages of pressure control on our storage tanks.

4)

Improvements to our vapor recovery system such that we now incorporate up to three stages of vapor recovery in our process.

5)

Low pressure separators (Green Completion Units) are used during initial well flowback operations to recover methane and send it down a sales line. This enables us to recover a salable product and reduce methane emissions during completion operations.

6)

Pressure relief valves are tested and repaired or replaced as necessary, reducing the amount of methane that is accidently released.

7)

Air actuated pneumatic controllers are now used at compressor stations. This eliminates methane emissions that occur from using gas operated pneumatic controllers.

8)

Gas operated compressor engine starters were replaced with air or electric starters. This eliminates methane emissions that occur when using gas operated compressor engine starters.

9)

Optimized glycol recirculation rates are utilized with flash tank separators on glycol dehydration units.

10)

Hot taps and pipeline pump down techniques that lower gas line pressure before maintenance are utilized.

11)

Balanced well drill outs, which prevent the venting of gas from our wells during the well completion process.

During 2018, Antero’s methane emission reduction efforts will also include the following activities:

1)

The GHG/Methane Reduction team will meet quarterly and continue to review emerging methane detection and quantification technologies applicable to E&P and Midstream Operations.

2)

Developing a plug and abandonment plan for certain older vertical wells that were acquired in conjunction with property acquisitions. Plugging and abandoning older, low producing wells will reduce methane emissions.

3)

Reviewing the option to replace existing gas operated pneumatic controllers with air or electrically operated

22


 

controllers in E&P operations.

4)

Exploring the use of lockdown thief hatches on storage tanks. These hatches eliminate methane emissions.

5)

Exploring applications for reducing methane emissions associated with rod packing systems in VRU compressors.

6)

Reviewing options to recover gas from Midstream pigging operations.

7)

Injecting blowdown gas from Midstream Operations into the fuel system at all new compressor stations.

8)

Exploring the use of electric compression in our midstream operations, where feasible.

9)

The replacement of TEG dehydrators with desiccant dehydrators where feasible.

While Congress has from time to time considered legislation to reduce emissions of GHGs, the prospect for adoption of significant legislation at the federal level to reduce GHG emissions is perceived to be low at this time.  In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could also adversely affect demand for the oil and natural gas we produce and lower the value of our reserves.  Depending on the severity of any such limitations, the effect on the value of our reserves could be significant. Finally, it should be noted that a number of scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other extreme climatic events; if any such effects were to occur, they have the potential to cause physical damage to our assets or affect the availability of water and thus could have an adverse effect on our exploration and production operations.

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

Finally, it should be noted that a number of scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other extreme climatic events; if any such effects were to occur, they have the potential to cause physical damage to our assets or affect the availability of water and thus could have an adverse effect on our exploration and production operations.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure through a cased and cemented wellbore into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations, as does most of the domestic oil and natural gas industry. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act, or the SDWA, over certain hydraulic fracturing activities involving the use of diesel fuels and issued permitting guidance in February 2014 regarding such activities.  Also, in May 2014, the EPA proposed rules under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; however, to date, no further action has been taken on the proposal.  The EPA also finalized rules in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

Certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources.  The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact

23


 

drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Because the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level.

In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. For example, in January 2016, the PADEP issued new rules establishing stricter disposal requirements for wastes associated with hydraulic fracturing activities, which include, among other things, a prohibition on the use of centralized impoundments for the storage of drill cuttings and waste fluids. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Some states and municipalities have sought to ban hydraulic fracturing altogether. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

Occupational Safety and Health Act

We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended, or OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities, and citizens.

Endangered Species Act

The federal Endangered Species Act, or ESA, provides for the protection of endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We conduct operations on natural gas and oil leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service, or the USFWS, may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for natural gas and oil development. Moreover, as a result of a settlement, the USFWS was required to make a determination as to whether more than 250 species classified as endangered or threatened should be listed under the ESA by the completion of the agency’s 2017 fiscal year. For example, in April 2015, the USFWS listed the northern long-eared bat, whose habitat includes the areas in which we operate, as a threatened species under the ESA. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. We did not have any material capital or other non‑recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2017, nor do we anticipate that such expenditures will be material in 2018.

Employees

As of December 31, 2017, we had 593 full‑time employees, including 39 employees in executive, finance, treasury, legal, and administration, 26 in information technology, 22 in geology, 236 in production and engineering, 144 in midstream and water, 74 in land, and 52 in accounting.  Our future success will depend partially on our ability to attract, retain, and motivate qualified

24


 

personnel.  We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages.  We consider our relations with our employees to be satisfactory.  We utilize the services of independent contractors to perform various field and other services.

Address, Internet Website and Availability of Public Filings

Our principal executive offices are located at 1615 Wynkoop Street, Denver, Colorado 80202 and our telephone number is (303) 357‑7310.  Our website is located at www.anteroresources.com.

We furnish or file with the Securities and Exchange Commission (the “SEC”) our Annual Reports on Form 10‑K, our Quarterly Reports on Form 10‑Q, and our Current Reports on Form 8‑K.  We make these documents available free of charge at www.anteroresources.com under the “Investors Relations” link as soon as reasonably practicable after they are filed or furnished with the SEC.

Information on our website is not incorporated into this Annual Report on Form 10‑K or our other filings with the SEC and is not a part of them.

 

Item 1A.  Risk Factors

Our business involves a high degree of risk.  If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10‑K, actually occur, our business, financial condition or results of operations could suffer. 

Natural gas, NGLs, and oil prices are volatile. A substantial or extended decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we receive for our natural gas, NGLs, and oil production heavily influence our revenue, profitability, access to capital and future rate of growth. Natural gas, NGLs, and oil are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities market has been volatile. This market will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

·

worldwide and regional economic conditions impacting the global supply and demand for natural gas, NGLs and oil;

·

the price and quantity of imports of foreign oil and natural gas, including liquefied natural gas;

·

the price and quantity of export of natural gas, including liquefied natural gas, and NGLs;

·

political conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia;

·

the level of global exploration and production;

·

the level of global inventories;

·

prevailing prices on local price indexes in the areas in which we operate;

·

localized and global supply and demand fundamentals and transportation availability;

·

weather conditions;

·

technological advances affecting energy consumption;

·

the price and availability of alternative fuels; and

·

domestic, local and foreign governmental regulation and taxes.

25


 

In late 2014, global energy commodity prices declined precipitously as a result of several factors, including an increase in worldwide commodity supplies, a stronger U.S. dollar, relatively mild weather in large portions of the U.S., and strong competition among some oil producing countries for market share.  Commodity prices remained depressed in 2015 and into 2016, although a modest recovery began in late 2016, and has continued intermittently in 2017 and 2018. 

Lower commodity prices reduce our product revenues and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices may also reduce the amount of natural gas, NGLs and oil that we can produce economically.

If commodity prices further decrease, a significant portion of our exploration and development projects could become uneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

Drilling for and producing oil and gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our exploration, development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable hydrocarbons. Our decisions to purchase, explore, or develop prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences.

Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

·

prolonged declines in natural gas, NGLs, and oil prices;

·

limitations in the market for natural gas, NGLs, and oil;

·

delays imposed by, or resulting from, compliance with regulatory requirements;

·

pressure or irregularities in geological formations;

·

shortages of, or delays in, obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;

·

equipment failures or accidents;

·

adverse weather conditions, such as blizzards, tornados, hurricanes and ice storms;

·

issues related to compliance with environmental regulations;

·

environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

·

limited availability of financing at acceptable terms; and

·

mineral interest title problems.

Properties that we decide to drill may not yield natural gas or oil in commercially viable quantities.

Properties that we decide to drill that do not yield natural gas or oil in commercially viable quantities will adversely affect our financial condition, results of operations, and cash flows. There is no way to predict in advance of drilling and testing whether any particular prospect will yield natural gas or oil in sufficient quantities to recover drilling or completion costs or to be economically

26


 

viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether natural gas or oil will be present or, if present, whether natural gas or oil will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

·

unexpected drilling conditions;

·

mineral interest title problems;

·

pressure or lost circulation in formations;

·

equipment failure or accidents;

·

adverse weather conditions;

·

compliance with environmental and other governmental or contractual requirements; and

·

increase in the cost of, or shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.