UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10‑K

 

Commission File No. 001‑36120

ANTERO RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)

 

(303) 357‑7310

(Registrant’s telephone number, including area code)

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

 

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

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

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

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

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

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

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

 

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, 2016, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $4.6 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 $25.98.

The registrant had 315,006,448 shares of common stock outstanding as of February 23, 2017.

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

 

 

TABLE OF CONTENTS

 

CAUTIONARY STATEMENT REGARDING FORWARD‑LOOKING STATEMENTS

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

Forward‑looking statements may include statements about our:

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

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

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

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

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

 

 

GLOSSARY OF OIL AND NATURAL GAS 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.

“C4+”: Natural gas liquids excluding ethane and propane, consisting primarily of 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.

“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 liquefied petroleum gas such as ethane, propane, isobutane and normal butane, and natural gasoline.

“NYMEX.”  The New York Mercantile Exchange.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

 

 

PART I

Items 1 and 2.  Business and Properties

Our Company

Antero Resources Corporation (“Antero”) is an independent oil and natural gas company 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, 2016, we held approximately 616,000 net acres of oil and gas properties located in the Appalachian Basin in West Virginia, Ohio, and Pennsylvania. Our corporate headquarters are in Denver, Colorado.

Antero’s consolidated subsidiary, Antero Midstream Partners LP (“Antero Midstream”) is a public master limited partnership which owns, operates, and develops midstream energy infrastructure primarily to service Antero’s production and completion activity.  Antero’s consolidated financial statements include Antero Midstream’s financial position and results of operations.

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

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

We have assembled a portfolio of long‑lived properties that are characterized by what we believe to be low geologic risk and repeatability. Our drilling opportunities are focused in the Marcellus Shale and Utica Shale of the Appalachian Basin. From 2008 through December 31, 2016, our drilling operations in the Appalachian Basin have had a 100% success rate.  We have 3,630 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 currently under construction in each of our core operating areas to accommodate our current development plans.

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

2016 and Recent Developments and Highlights

Energy Industry Environment

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

Spot prices for WTI declined significantly since June 2014 levels of approximately $106.00 per Bbl and have ranged from less than $30.00 per Bbl in February 2016 to approximately $53.00 per Bbl in February 2017.  Spot prices for Henry Hub natural gas also declined significantly from approximately $4.40 per MMBtu in January 2014 to $2.00 per MMBtu in March 2016.  Natural gas prices have recently recovered to approximately $3.00 per MMBtu in February 2017 due to increases in demand as a result of colder winter weather in many regions of the United States.  Spot prices for propane, which is the largest portion of our NGLs sales, declined from approximately $1.55 per gallon in January 2014 to less than $0.35 per gallon in January 2016.  Prices for propane have recovered to over $0.70 per gallon in February 2017.

In response to these market conditions and concerns about access to capital markets, many U.S. exploration and development companies significantly reduced their capital spending in 2015 and 2016.  Our capital spending for drilling, completions, and land for 2016 was $2.1 billion, including drilling and completion costs of $1.3 billion and leasehold additions of $153 million, and acquisition costs of $593 million.  Excluding acquisitions, this represents a decrease of 20% from our 2015 capital expenditures and a decrease of 52% from our 2014 capital expenditures.  Although commodity prices have decreased in recent years, we have also experienced reductions in drilling and development costs as a result of decreased demand for oilfield services and increased efficiencies from improved drilling and completion technology and procedures.  In addition to the reduction in our capital expenditures during 2016, we deferred the completion of 40 wells.

Reserves, Production, and Financial Results

As of December 31, 2016, our estimated proved reserves were 15.4 Tcfe, consisting of 9.4 Tcf of natural gas, 554 MMBbl of ethane, 404 MMBbl of C3+ NGLs, and 38 MMBbl of oil. As of December 31, 2016, 61% of our estimated proved reserves by volume were natural gas, 37% were NGLs, and 2% were oil. Proved developed reserves were 6.9 Tcfe, or 45% of total proved reserves.

For the year ended December 31, 2016, our production totaled 676 Bcfe, or 1,847 MMcfe per day, a 24% increase compared to 545 Bcfe, or 1,493 MMcfe per day, for the year ended December 31, 2015.  The average price received for 2016 production before the effects of gains on settled derivatives was $2.60 per Mcfe compared to $2.52 per Mcfe in 2015.  The increase was primarily attributable to increases in energy commodity prices during the second half of 2016.  Our average realized price after the effects of gains on settled derivatives was $4.08 per Mcfe during 2016 as compared to $4.10 per Mcfe during 2015.

For the year ended December 31, 2016, we generated consolidated cash flow from operations of $1.24 billion, a consolidated net loss of $849 million, and Adjusted EBITDAX of $1.54 billion.  This compares to consolidated cash flow from operations of $1.02 billion, consolidated net income of $941 million, and Adjusted EBITDAX of $1.22 billion for the year ended December 31, 2015.  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).

The consolidated net loss for 2016 included (i) commodity derivative fair value losses of $514 million, comprised of gains on settled derivatives of $1.0 billion and a non-cash loss of $1.5 billion on changes in the fair value of commodity derivatives, (ii) a noncash charge of $102 million for equity-based compensation, (iii) a noncash charge of $163 million for impairments of unproved properties, and (iv) a noncash tax benefit of $496 million.

2016 Capital Spending and 2017 Capital Budgets

For the year ended December 31, 2016, our total consolidated capital expenditures were approximately $2.5 billion, including drilling and completion expenditures of $1.3 billion, leasehold additions of $153 million, acquisitions of $593 million, gathering and

compression expenditures of $231 million, water handling and treatment expenditures of $188 million, and other capital expenditures of $3 million.  Our consolidated capital budget for 2017 is $2.3 billion, and includes: $1.3 billion for drilling and completion, $200 million for core leasehold acreage additions and extensions, and $800 million for capital expenditures by Antero Midstream.  We do not budget for acquisitions.  Approximately 70% of the drilling and completion budget is allocated to the Marcellus Shale and the remaining 30% is allocated to the Utica Shale.  During 2017, we plan to operate an average of four drilling rigs in the Marcellus Shale and three drilling rigs in the Utica Shale, and we plan to complete 170 horizontal wells in the Marcellus and Utica Shales in 2017 as compared to 140 in 2016.  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, 2016, we had entered into fixed price hedging contracts for January 1, 2017 through December 31, 2022 for 3.3 Tcf of natural gas at a weighted average index price of $3.66 per MMBtu, 452 million gallons of propane at a weighted average price of $0.41 per gallon, 307 million gallons of ethane at a weighted average price of $0.25 per gallon, and 1.1 million Bbls of oil at a weighted average price of $54.75 per Bbl.  These hedging contracts include contracts for the year ending December 31, 2017 of 679 Bcf of natural gas at a weighted average index price of $3.63 per MMBtu, 422 million gallons of propane at a weighted average price of $0.39 per gallon, 307 million gallons of ethane at a weighted average price of $0.25 per gallon, and 1.1 million Bbls of oil at a weighted average price of $54.75 per Bbl.

To the extent we have fixed the price of a portion of our estimated future production through 2022, we believe this hedge position provides some certainty to cash flows supporting our future operations and capital spending plans.  As of December 31, 2016, the estimated fair value of our commodity derivative contracts was approximately $1.6 billion.

Credit Facilities

The current borrowing base under our revolving credit facility is $4.75 billion and lender commitments are $4.0 billion.  The borrowing base under our revolving credit facility is redetermined semi‑annually and is based on the estimated future cash flows from our proved oil and gas reserves and our commodity hedge positions. The next redetermination is scheduled to occur in April 2017.  At December 31, 2016, we had $440 million of borrowings and $710 million of letters of credit outstanding under the revolving credit facility.  Our revolving credit facility matures in May 2019.  See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements and Contractual Obligations—Senior Secured Revolving Credit Facility” for a description of our revolving credit facility.

Our consolidated subsidiary, Antero Midstream, has a revolving credit facility agreement that provides for lender commitments of $1.5 billion.  At December 31, 2016, Antero Midstream had $210 million of borrowings outstanding under its revolving credit facility.  The facility will mature in November 2019.  See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements and Contractual Obligations—Midstream Credit Facility” for a description of this revolving credit facility.

Sale of Antero Midstream Units by Antero

On March 30, 2016, we sold 8,000,000 common units representing limited partner interests in Antero Midstream.  We received net proceeds from the transaction of $178 million.  The proceeds from the offering were used to pay down amounts outstanding under our revolving credit facility and to fund a portion of our 2016 development program.

Leasehold Acquisition and Related Issuance of Common Stock by Antero

On June 9, 2016, we entered into an agreement pursuant to which we acquired approximately 46,000 net acres of Marcellus Shale leasehold located primarily in Wetzel, Tyler, and Doddridge Counties in West Virginia, including approximately 14 MMcfe per day of net production, for a purchase price of approximately $505 million, which is subject to contractual purchase price adjustments for ongoing title work on the acquired acreage.

To finance the acquisition, on June 15, 2016 we issued 26,750,000 shares of our common stock and realized proceeds from the sale of approximately $753 million, net of offering expenses.  We also granted the underwriters a 30-day option to purchase an additional 4,012,500 common shares.  On July 12, 2016 the underwriters partially exercised the option and purchased an additional 3,012,500 shares, resulting in additional net proceeds from the offering of approximately $85 million.  In addition to funding this acquisition, the offering proceeds were used for general corporate purposes including the reduction of amounts outstanding under our revolving credit facility in anticipation of future development of the purchased properties.

Private Placement of Common Stock by Antero

On October 7, 2016, we issued 6,730,769 shares of our common stock in a private placement, resulting in net proceeds of approximately $175 million.  We used the proceeds to repay a portion of outstanding borrowings under our revolving credit facility and for general corporate purposes.

Issuance of 5.00% Senior Notes due 2025 by Antero

On December 21, 2016, we issued $600 million of 5.00% senior notes due March 1, 2025 at par.  The proceeds from the issuance were used to retire the $525 million principal amount of our 6.00% senior notes due 2020 and for general corporate purposes.

As of December 31, 2016, Antero had four series of senior notes outstanding totaling $3.45 billion in aggregate principal amount.  The notes bear interest at rates ranging from 5.00% to 5.625% and have maturity dates ranging from November 21, 2021 to March 1, 2025.

Issuance of 5.375% Notes due 2024 by Antero Midstream 

On September 13, 2016, Antero Midstream issued $650 million of 5.375% senior notes due September 15, 2024 at par.  The proceeds from the issuance were used by Antero Midstream to pay down amounts outstanding under its revolving credit facility.   Antero Midstream has no other outstanding senior notes.

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

On February 6, 2017, Antero Midstream formed a joint venture (the “Joint Venture”) to develop processing assets in Appalachia with MarkWest Energy Partners, L.P. (“MarkWest”), a wholly owned subsidiary of MPLX, L.P.  Antero Midstream and MarkWest will each own a 50% interest in the Joint Venture and MarkWest will operate the Joint Venture assets.  The Joint Venture assets will 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 $155 million contribution to the Joint Venture, repay outstanding borrowings under its credit facility, and for general partnership purposes.

Antero Midstream Equity Distribution Agreement 

During the third quarter of 2016, Antero Midstream entered into an Equity Distribution Agreement (the “Distribution Agreement”).  Pursuant to the terms of the agreement, 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, 2016, Antero Midstream issued and sold 2,391,595 common units under the Distribution Agreement, resulting in net proceeds of $65.4 million after deducting commissions and other offering expenses.  As of December 31, 2016, Antero Midstream had the capacity to issue additional common units under the Distribution Agreement up to an aggregate amount of $183.8 million.

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, 2014, 2015 and 2016.  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, 2016 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 32 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, 2014 were prepared assuming ethane rejection.  Reserves at December 31, 2015 and 2016 were prepared assuming partial ethane recovery, and rejection of the remaining ethane.  When ethane is rejected at the processing plant, it is left in the gas stream and sold with the methane gas.

The following sets forth the estimated future net cash flows from our proved reserves (without giving effect to our commodity hedges), the present value of those net cash flows before income tax (PV‑10), the present value of those net cash flows after income tax (standardized measure) and the prices used in projecting future net cash flows at December 31, 2014, 2015, and 2016:

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 2014, 2015 and 2016 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 2016

The following table summarizes the changes in our estimated proved reserves during 2016 (in Bcfe):

 

Extensions, discoveries, and other additions of 2,637 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales, which was aided in 2016 by longer laterals than in previous years and the utilization of advanced completion techniques.  Purchases of 624 Bcfe relate to the acquisition of developed and undeveloped leasehold acreage in both the Marcellus and Utica Shales.  Positive revisions of 1,359 Bcfe are due to an increase in our actual and assumed future ethane recovery based on existing sales contracts for ethane.  Positive performance revisions of 762 Bcfe primarily relate to improved well performance.  Negative revisions of 2,478 Bcfe were due to the impact of the SEC 5-year development rule.  Due to the SEC 5-year development rule, these primarily dry gas reserves were displaced by our current development plan targeting more liquids-rich areas in our portfolio which have better economic returns.  Negative revisions of 47 Bcfe were due to decreases in prices for natural gas, NGLs, and oil.  Sales of 10 Bcfe was related to our sale of producing and non-producing leasehold in Pennsylvania.  Our estimated proved reserves as of December 31, 2016 totaled approximately 15.4 Tcfe and increased by 16% over the prior year.

Proved Undeveloped Reserves

Proved undeveloped reserves are included in the previous table of total proved reserves. The following table summarizes the changes in our estimated proved undeveloped reserves during 2016 (in Bcfe):

 

Extensions, discoveries, and other additions during 2016 of 2,111 Bcfe of proved undeveloped reserves resulted from delineation and developmental drilling in the Marcellus and Utica Shales.  Purchases of 572 Bcfe relate to the acquisition of undeveloped leasehold acreage in both the Marcellus and Utica Shales.  Positive revisions of 1,344 Bcfe are due to an increase in our actual and assumed future ethane recovery based on existing sales contracts for ethane.  Development drilling resulted in the reclassification of 1,208 Bcfe to proved developed reserves.  Positive performance revisions of 776 Bcfe primarily relate to improved well performance.  Negative revisions of 2,478 Bcfe were due to the SEC 5-year development rule.  Due to the SEC 5-year development rule, these primarily dry gas reserves were displaced by our current development plan targeting more liquids-rich areas in our portfolio which have better economic returns.  Negative revisions of 22 Bcfe were due to decreases in the prices for natural gas, NGLs, and oil.  Wells that are not drilled within five years from booking are reclassified from proved reserves to probable reserves.

During the year ended December 31, 2016, we converted approximately 1,208 Bcfe of proved undeveloped reserves to proved developed reserves at a total capital cost of approximately $580 million, or $0.48 per Mcfe.  We spent an additional $421 million on development costs related primarily to drilled and uncompleted wells and properties in the proved undeveloped classification at December 31, 2015, resulting in total development spending of $1.0 billion, as disclosed in note 19 to the consolidated financial statements included elsewhere in this report.  Estimated future development costs relating to the development of our proved undeveloped reserves at December 31, 2016 are approximately $3.8 billion, or $0.45 per Mcfe, over the next five years.  We believe that cash flows from operations and borrowings under our revolving credit facility will be sufficient to finance such future development costs and, to the extent that these amounts are insufficient to finance our growing development activities, we believe we will have sufficient access to the debt and equity capital markets and other sources of capital financing, as necessary.  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.”

In the past four years, we have increasingly focused our land additions on liquids-rich areas where well economics provide higher returns based on the relative prices of NGLs and oil to dry gas.  As a result of these efforts, we have built a large inventory of undrilled Marcellus and Utica Shale locations, including 3,630 locations classified as proved undeveloped, probable, or possible as of December 31, 2016. 

We maintain a 5-year drilling plan that supports our corporate production growth target.   The drilling schedule is reviewed periodically to ensure capital is allocated to the wells that have the highest 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.  This resulted in the reclassification of 2,478 Bcfe of reserves from proved undeveloped to probable during the year ended December 31, 2016 due to the 5-year development rule.  Based on our then-current acreage position, 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.  There has been no change in our view of reasonable certainty of the economic feasibility of these wells.

At December 31, 2016, our proved undeveloped locations that were scheduled for drilling over the next five years encompassed 77,000 acres.  An estimated 14,300 of these acres, containing 301 wells 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 $50 million to $65 million to renew the 14,300 acres based upon current leasing authorizations and option to extend payments.  Proved undeveloped reserves of 999 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 100 Bcfe of these proved undeveloped reserves.

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

Preparation of Reserve Estimates

Our reserve estimates as of December 31, 2014, 2015, and 2016 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 37 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 Bcf per 1,000 feet from our proved developed producing wells.

We may attribute up to 11 proved undeveloped locations based on one proved developed producing well where analysis of geologic and engineering data can be estimated with reasonable certainty to be commercially recoverable.  However, the ratio of

proved undeveloped locations generated will be lower when multiple proved developed wells are drilled on a single pad. In addition, we have applied the concept of a statistical proven area to certain areas of our Marcellus Shale acreage whereby undeveloped properties are booked as proved reserves so long as well count is sufficient for statistical analysis and certain land, geologic, engineering and commercial criteria are met.

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

Identification of Potential Well Locations

Our identified potential well locations represent locations to which proved, probable, or possible reserves were attributable based on SEC pricing as of December 31, 2016.  We prepare internal estimates of probable and possible reserves but have not included disclosure of such reserves in this report.

Production, Revenues, and Price History

Because natural gas, NGLs, and oil are commodities, the price that we receive for our production is largely a function of market supply and demand.  While demand for natural gas in the United States has increased materially since 2000, natural gas and NGLs supplies have also increased significantly as a result of horizontal drilling and fracture stimulation technologies which have been used to find and recover large amounts of oil and gas from various shale formations throughout the United States.  Demand is impacted by general economic conditions, weather, and other seasonal conditions.  Over or under supply of natural gas can result in substantial price volatility.  Historically, commodity prices have been volatile, and we expect that volatility to continue in the future.  The significant commodity price declines in late 2014 through 2015 and into 2016 are the most recent example of such volatility.  A 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

The following table sets forth information regarding our production, realized prices, and production costs for the years ended December 31, 2014, 2015 and 2016.  For additional information on price calculations, see information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Productive Wells

As of December 31, 2016, we had a total of 778 gross (736 net) producing wells, averaging a 95% working interest, in the Marcellus Shale.  This well count includes 527 gross (519 net) horizontal wells, 9 gross (0.07 net) non-operated wells in which we hold minor working interests, and 242 gross (217 net) vertical wells.  In the Utica Shale, we had 168 gross (139 net) producing wells, averaging an 83% working interest, in the Utica Shale.  This well count includes 155 gross (139 net) horizontal wells, and 13 gross (0.04 net) non-operated wells in which we hold minor working interests. 

Additionally, at December 31, 2016 we had 16 net horizontal proved developed non-producing wells, and 140 gross horizontal wells (138 net) that were drilled and uncompleted or in the process of being completed.  The non-operated wells and vertical wells in both the Marcellus and Utica Shales 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, 2016.  A majority of our developed acreage is subject to liens securing our revolving credit facility.

Approximately 55% of our net Marcellus acreage and 35% of our net Utica acreage is held by production.  Acreage related to royalty, overriding royalty, and other similar interests is excluded from this table.

 

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

 

 

Undeveloped Acreage Expirations

The following table sets forth the number of total gross and net undeveloped acres as of December 31, 2016 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.

 

Drilling Activity

The following table sets forth the results of our drilling activity for wells drilled and completed during the years ended December 31, 2014, 2015, and 2016. Gross wells reflect the sum of all wells in which we own an interest and includes historical drilling activity in the Appalachian Basin.  Net wells reflect the sum of our working interests in gross wells.

 

The figures in the table above do not include 140 gross wells (138 net) that were drilled and uncompleted or in the process of being completed at December 31, 2016.

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, 2016, our firm sales commitments through 2021 included:

 

In addition to the commitments listed in the table above, we have firm sales commitments for 100% of our C4+ NGL production from April 2017 through March 2018, and 100% of our oil and condensate production from February 2017 through March 2018.

 

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 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, 2015 and 2016, Antero Midstream spent approximately $320 million and $228 million, respectively, on gas and condensate 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, Ohio, and Pennsylvania for gathering and compression services.

As of December 31, 2016, Antero Midstream, owned and operated 213 miles of gas gathering pipelines in the Marcellus Shale.  We also have access to additional low‑pressure and high‑pressure pipelines owned and operated by Crestwood, Energy Transfer Partners L.P., and Summit Midstream.  As of December 31, 2016, Antero Midstream owned and operated 10 compressor stations and we utilized 15 additional third‑party compressor stations in the Marcellus Shale. The gathering, compression and dehydration services provided by third parties are contracted on a fixed‑fee basis.

As of December 31, 2016, Antero Midstream owned and operated 113 miles of low‑pressure, high‑pressure, and condensate pipelines in the Utica Shale, and Antero owned and operated 8 miles of high-pressure pipelines.  As of December 31, 2016, Antero Midstream owned and operated one compressor station and we utilized five 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 NGL y-grade stream is separated into individual NGL 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 have their own market price.

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

Given the existing commodity price environment and the current limited ethane market in the northeast, we are currently rejecting 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 NGL 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 late 2017.

We have contracted with MarkWest Energy Partners L.P. to provide cryogenic processing capacity for our Marcellus and Utica Shale production as follows:

 

Through our investment in the Joint Venture, we 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 activity will begin with the seventh plant at the Sherwood facility.  The Joint Venture will provide processing services to Antero Resources under a long-term fixed-fee arrangement, subject to annual CPI-based adjustments.

Transportation and Takeaway Capacity

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

Under firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries.  See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements and Contractual Obligations” for information on our minimum fees for such contracts.  Based on current projected 2017 annual production levels, we estimate that we could incur total annual net marketing costs of $60 million to $105 million in 2017 for unutilized transportation capacity depending on the amount of unutilized capacity that can be marketed to third parties or utilized to transport third party gas and capture positive basis differentials.  Where permitted, we continue to actively market any excess capacity in order to offset minimum commitment fees.

Water Handling and Treatment Operations

On September 23, 2015, we contributed (i) all of the outstanding limited liability company interests of Antero Water LLC (“Antero Water”) to Antero Midstream and (ii) all of the assets, contracts, rights, permits and properties owned or leased by us and used primarily in connection with the construction, ownership, operation, use or maintenance of our advanced waste water treatment complex currently being constructed 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 waste water resulting from our operations.

Antero Midstream owns two independent fresh water distribution systems that distribute fresh water from the Ohio River and several regional water sources for well completion operations in the Marcellus and Utica Shales.  These systems consist of permanent buried pipelines, movable surface pipelines and fresh water storage facilitates, as well as pumping stations to transport the fresh water throughout the pipeline networks. To the extent necessary, the surface pipelines are moved to well pads for service completion operations in concert with our drilling program. As of December 31, 2016, Antero Midstream had the ability to store 5.0 million barrels of fresh water in 36 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 has provided water delivery services to neighboring oil and gas producers within and adjacent to our operating area, and is able to provide water delivery services to other oil and gas producers in the area, subject to commercial arrangements, in an effort to reduce water truck traffic.

As of December 31, 2016, Antero Midstream owned and operated 116 miles of buried fresh water pipelines and 87 miles of movable surface fresh water pipelines in the Marcellus Shale, as well as 23 fresh water storage facilities equipped with transfer pumps.  As of December 31, 2016, Antero Midstream owned and operated 49 miles of buried fresh water pipelines and 34 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, we committed to developing an advanced waste water treatment complex in Doddridge County, West Virginia.  The complex was transferred to Antero Midstream in conjunction with the sale of our water handling systems in September 2015.  The waste water treatment complex, once completed, will include a 60,000 barrel per day facility that will allow Antero Midstream to treat our flowback and produced water for subsequent use or sale for well completions.  The treatment facility is expected to be in service in the fourth quarter of 2017.  Late in 2015, Antero Midstream began providing us with waste water services for our well completion operations, including waste water transportation, disposal, and treatment.

Major Customers

For the year ended December 31, 2016, two of our customers accounted for approximately 29% and 13% of our total product revenues, respectively.  For the year ended December 31, 2015, three of our customers accounted for 19%, 18%, and 13% of our total product revenues, respectively.  For the year ended December 31, 2014, three of our customers accounted for 29%, 16%, and 12% of our total product revenues, respectively.  Although a substantial portion of our production is purchased by these major customers, we do not believe the loss of any one or several customers would have a material adverse effect on our business, as we believe other customers or markets would be accessible to us.

Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards.  As is customary in the industry, often in the case of undeveloped properties, cursory investigation of record title is made at the time of lease acquisition.  Investigations are made before the consummation of an acquisition of producing properties and before

commencement of drilling operations on undeveloped properties.  Individual properties may be subject to burdens that we believe do not materially interfere with the use, or affect the value of, the properties.  Burdens on properties may include:

Seasonality

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

Competition

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

Regulation of the Oil and Natural Gas Industry

General

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

Regulation of Production of Natural Gas and Oil

We own interests in properties located onshore in three U.S. states, and our production activities on these properties are subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations.  These statutes and regulations address requirements related to permits for drilling of wells, bonding to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, the plugging and abandonment of wells, venting or flaring of natural gas, and the

ratability or fair apportionment of production from fields and individual wells.  In addition, all of the states in which we own and operate properties have regulations governing environmental and conservation matters, including provisions for the handling and disposing or discharge of waste materials, the unitization or pooling of natural gas and oil properties, the establishment of maximum allowable rates of production from natural gas and oil wells, and the size of drilling and spacing units or proration units and the density of wells that may be drilled.  Some states also have the power to prorate production to the market demand for oil and gas.  The effect of these regulations is to limit the amount of natural gas and oil that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density.  Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas, and NGLs within its jurisdiction.

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

Regulation of Transportation of Natural Gas

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

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

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

Regulation of Sales of Natural Gas, NGLs, and Oil

The prices at which we sell natural gas, NGLs, and oil 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 does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non‑jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704 described below.  Under the EPAct of 2005, FERC has the power to assess civil penalties of up to $1,000,000 per day for each violation of the NGA and the NGPA.

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

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

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

Regulation of Environmental and Occupational Safety and Health Matters

Our operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health and the discharge of materials into the environment or otherwise relating to environmental protection. Violations of these laws can result in substantial administrative, civil and criminal penalties. These laws and regulations may require the acquisition of a permit before drilling or other regulated activity commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines, govern the sourcing and disposal of water used in the drilling and completion process, limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas 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 safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous Substances and Waste Handling

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

The Resource Conservation and Recovery Act, or RCRA, and analogous state laws, establish detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the U.S. Environmental Protection Agency, or the EPA, or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, or under state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas exploration, development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. 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.  A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as waste solvents, laboratory wastes and waste compressor oils that may become regulated as hazardous wastes if such wastes have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

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

Water Discharges

The Federal Water Pollution Control Act, or the Clean Water Act (the “CWA”), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or a state equivalent agency. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers. In September 2015, new EPA and U.S. Army Corps of Engineers rules defining the scope of the EPA’s and the Corps’ jurisdiction became effective. To the extent the rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of CWA programs, and implementation of the rule has been stayed pending resolution of the court challenge. The process for obtaining

permits has the potential to delay the development of natural gas and oil projects. Also, pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of waste water or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

Air Emissions

The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as, for example, compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre‑approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants, the costs of which could be significant. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard, or NAAQS, for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.  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, or NESHAP, 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 addition, in January 2016, Pennsylvania announced new rules that will require the Pennsylvania Department of Environmental Protection, or PADEP, to develop a new general permit for oil and gas exploration, development, and

production facilities and liquids loading activities, requiring best available technology for equipment and processes, enhanced record-keeping, and quarterly monitoring inspections for the control of methane emissions.  The PADEP also intends to issue similar methane rules for existing sources. In addition, the department has also proposed to establish Best Management Practices, including leak detection and repair (“LDAR”) programs, to reduce fugitive methane emissions from production, gathering, processing, and transmission facilities. These rules have the potential to increase our compliance costs.

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

When we permit a facility, we are required to install pollution control equipment at the wellsite in accordance with the requirements of the NSPS for New Stationary Sources.  At wellpads, this consists of installing combustors with a control efficiency of 98% to control tank methane and VOC emissions.  In addition to combustors, we also install Vapor Recovery Units, or VRUs, in order to capture methane and VOC emissions and direct them down the sales line, rather than flaring those emissions.  Per applicable regulations, we also install low-bleed pneumatic controls at wellpads, which serve to reduce methane emissions.  We may also install Vapor Recovery Towers, or VRTs, to further reduce methane and VOC flashing emissions from storage tanks when we have more than a nominal amount of oil production in order to produce sufficient gas to allow safe and proper running of the VRTs. At compressor stations, through the use of non-selective catalytic reduction, we reduce methane and VOC emissions from engines by at least 70%.  Compressor Station tank and dehydration units are typically controlled by combustors or VRUs.  We control our methane and VOC emissions consistent with available emission control technology as required by law and as applicable to our operations.

Our methane and VOC control program consists of installing the emission controls described above, performing inspections, and conducting preventative maintenance and repairs to minimize emissions leakage.  For example, we have implemented an LDAR program for our well pad and compressor station operations.  During 2015, we added two fulltime staff members to manage the LDAR program.  LDAR program inspections utilize a state of the art Forward Looking Infrared Radar (FLIR) camera to identify equipment leaks.  Our Operations group has a maintenance program in place, which includes cleaning, greasing and replacing thief hatch seals, and other measures as required to further minimize the potential for leaks,  In 2015, we implemented new thief hatch designs with improved seals for our tanks.    While the LDAR program is not mandatory in all areas of our operations, we have implemented it uniformly across all of our activities.  We believe that our efforts to date have resulted in a declining volume of methane emissions based on the decreasing number of leaks detected as part of our LDAR program.  In addition, since 2011 and in accordance with EPA regulations, we have monitored or calculated our GHG emissions, including emissions of methane, and reported them to the EPA on an annual basis.  Our current report of GHG emissions from covered operations during 2016 will be submitted to the EPA by March 31, 2017. Overall, through the use of Green Completions we have seen significant decreases in GHG emissions from our operations.  Furthermore, we believe that our efforts to comply with the 2012 NSPS Quad O have resulted in us being well positioned to comply with the EPA’s recently finalized NSPS Quad Oa regulations to reduce methane and VOC emissions from oil and natural gas operations.

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.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure through a cased and cemented wellbore into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations, as does most of the domestic oil and natural gas industry. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act, or the SDWA, over certain hydraulic fracturing activities involving the use of diesel fuels and issued permitting guidance in February 2014 regarding such activities.  Also, in May 2014, the EPA proposed rules under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; however, to date, no further action has been taken on the proposal.  The EPA also proposed in April 2015 to prohibit the discharge of waste water from hydraulic fracturing operations to publicly owned waste water treatment plants.

Certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources.  The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing waste water to surface waters; and disposal or storage of fracturing waste water in unlined pits. Since 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. Also, in June 2016, the EPA finalized rules that would establish new air emission controls for methane emissions from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission, and storage activities. The final rule 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, fugitive emissions from well sites and compressors, equipment leaks at natural gas processing plants, and pneumatic pumps.  The rules also extend existing requirements for the emission of volatile organic compounds to the same equipment and processes.  In addition, the U.S. Department of the Interior published a final rule in March 2015 that would implement updated requirements for hydraulic fracturing activities on federal lands, including new requirements relating to public disclosure, well bore integrity and handling of flowback water. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule pending a final decision on whether it may be implemented. Other governmental agencies, including the U.S. Department of Energy have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

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 is required to make a determination as to whether more than 250 species classified as endangered or threatened should be listed under the ESA by no later than completion of the agency’s 2017 fiscal year. For example, in April 2015, the USFWS listed the northern long-eared bat, whose habitat includes the areas in which we operate, as a threatened species under the ESA. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. We did not have any material capital or other non‑recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2016, nor do we anticipate that such expenditures will be material in 2017.

Employees

As of December 31, 2016, we had 528 full‑time employees, including 36 in executive, finance, treasury, legal, and administration, 22 in information technology, 23 in geology, 230 in production and engineering, 93 in midstream, 79 in land, and 45 in accounting.  Our future success will depend partially on our ability to attract, retain, and motivate qualified personnel.  We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages.  We consider our relations with our employees to be satisfactory.  We utilize the services of independent contractors to perform various field and other services.

Address, Internet Website and Availability of Public Filings

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

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

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

 

Item 1A.  Risk Factors

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

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

The prices we receive for our natural gas, NGLs, and oil production heavily influence our revenue, profitability, access to capital and future rate of growth. Natural gas, NGLs, and oil are commodities and, therefore, their prices are subject to wide

fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities market has been volatile. 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:

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

Spot prices for WTI declined significantly since June 2014 levels of approximately $106.00 per Bbl and have ranged from less than $30.00 per Bbl in February 2016 to approximately $53.00 per Bbl in February 2017.  Spot prices for Henry Hub natural gas also declined significantly from approximately $4.40 per MMBtu in January 2014 to $2.00 per MMBtu in March 2016.  Natural gas prices have recently recovered to approximately $3.00 per MMBtu in February 2017 due to increases in demand as a result of colder winter weather in many regions of the United States.  Spot prices for propane, which is the largest portion of our NGLs sales, declined from approximately $1.55 per gallon in January 2014 to less than $0.35 per gallon in January 2016.  Prices for propane have recovered to over $0.70 per gallon in February 2017.

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

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

Our exploration and development projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our oil and gas reserves.

The oil and gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the exploration, development, and acquisition of oil and gas reserves. Our cash flow used in investing activities related to drilling, completions, and land expenditures, including acquisitions, was approximately $2.1 billion in 2016. Our board of directors has approved a capital budget for 2017 of $1.5 billion that includes $1.3 billion for drilling and completion and $200 million for core leasehold acreage additions and extension. Our capital budget excludes acquisitions. We expect to fund these capital expenditures with cash generated by operations and borrowings under our revolving credit facility or capital market transactions; however, our financing

needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological, and competitive developments.  A further reduction in commodity prices from current levels may result in an additional decrease in our actual capital expenditures, which would negatively impact our ability to grow production. For additional discussion of the risks regarding our ability to obtain funding, please read “Item 1A. Risk Factors – The borrowing base under our revolving credit facility is subject to semi-annual redetermination by our lenders, which could result in a reduction of our borrowing base.  This may hinder or prevent us from meeting our future capital needs.”  The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions.

Our cash flow from operations and access to capital are subject to a number of variables, including:

If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower natural gas, NGLs, and oil prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, financial condition and results of operations.

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 natural gas production. Our decisions to purchase, explore, or develop prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences.

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

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our revolving credit facility and our senior notes depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness, including the senior notes.

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance our indebtedness, including the senior notes. Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets, including the market for senior unsecured notes, and our financial condition at such time. Any refinancing of our indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments, including the indentures governing our senior notes, may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our revolving credit facility and the indentures governing our senior notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations.

The borrowing base under our revolving credit facility may be reduced if commodity prices decline, which could hinder or prevent us from meeting our future capital needs.

The borrowing base under our revolving credit facility is currently $4.75 billion, and lender commitments under our revolving credit facility are $4.0 billion. Our borrowing base is redetermined by the lenders twice per year, and the next scheduled borrowing base redetermination is expected to occur in April 2017.  Our borrowing base may decrease as a result of a further decline in oil or natural gas prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for any other reason.   We cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms.   In the event of a decrease in our borrowing base due to current or further declines in commodity prices or otherwise, we may be unable to meet our obligations as they come due and could be required to repay any indebtedness in excess of the redetermined borrowing base. In addition, we may be unable to access the equity or debt capital markets, including the market for senior unsecured notes, to meet our obligations.  As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out our business plan, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

We may be unable to access the equity or debt capital markets, including the market for senior unsecured notes, to meet our obligations. 

Due to the decline in commodity prices throughout 2015 and 2016, the financial markets have exerted downward pressure on stock prices and credit capacity for companies throughout the energy industry.  In particular, throughout much of 2015 and 2016, the market for senior unsecured notes was unfavorable for high-yield issuers such as us. Our plans for growth require regular access to the capital and credit markets, including the ability to issue senior unsecured notes. Although the market for high-yield debt securities

improved in the latter part of 2016, if the high-yield market deteriorates, or if we are unable to access alternative means of debt or equity financing on acceptable terms, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out our business plan, which could have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.

At December 31, 2016, 55% of our total estimated proved reserves were classified as proved undeveloped. Our approximately 8.5 Tcfe of estimated proved undeveloped reserves will require an estimated $3.8 billion of development capital over the next five years. Moreover, the development of probable and possible reserves will require additional capital expenditures and such reserves are less certain to be recovered than proved reserves. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV‑10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.

We are required to pay fees to our service providers based on minimum volumes under long-term contracts regardless of actual volume throughput.

We have various firm transportation, gas processing, gathering and compression service and water handling and treatment agreements in place, each with minimum volume delivery commitments. Lower commodity prices may lead to reductions in our drilling program, which may result in insufficient production to utilize our full firm transportation and processing capacity.  Our firm transportation agreements expire at various dates from 2018 to 2058, our gas processing, gathering, and compression services agreements expire at various dates from 2017 to 2029, and our water services agreement with Antero Midstream expires in 2035. We are obligated to pay fees on minimum volumes to our service providers regardless of actual volume throughput.  As of December 31, 2016, our long‑term contractual obligations under agreements with minimum volume commitments totaled over $17.8 billion over the term of the contracts.  If we have insufficient production to meet the minimum volumes, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results of operations.

Based on current projected 2017 annual production levels, we estimate that we could incur total annual net marketing costs of $60 million to $105 million in 2017 for unutilized transportation capacity depending on the amount of unutilized capacity that can be marketed to third parties or utilized to transport third party gas and capture positive basis differentials.  Additionally, in years subsequent to 2017, our commitments and obligations under firm transportation agreements continue to increase and our net marketing expense could continue to increase depending on utilization of our transportation capacity based on future production and how much, if any, future excess transportation can be marketed to third parties.

If additional takeaway pipelines under construction or other pipeline projects are not completed, our future growth may be limited.

 

We have secured sufficient long-term firm takeaway capacity on major pipelines that are in existence or currently under construction in each of our core operating areas to accommodate our current development plans; however, any failure of any pipeline under construction to be completed, or any unavailability of existing takeaway pipelines, could cause us to curtail our future development and production plans, which could adversely affect our business, financial condition and results of operations.

 

Our ability to produce oil and gas economically and in commercial quantities is dependent on the availability of adequate supplies of water for drilling and completion operations and access to water and other waste disposal or recycling services at a reasonable cost and in accordance with applicable environmental rules. Restrictions on our ability to obtain water or dispose of produced water and other waste may have an adverse effect on our financial condition, results of operations and cash flows.

The hydraulic fracture stimulation process on which we depend to produce commercial quantities of oil and gas requires the use and disposal of significant quantities of water. The availability of disposal alternatives to receive all of the water produced from our wells may affect our production. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations. Additionally, the imposition of new environmental initiatives and regulations could include restrictions on our ability to obtain water or dispose of waste and adversely affect our business and operating results.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure through a cased and cemented wellbore into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations, as does most of the domestic oil and natural gas industry. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and issued permitting guidance in February 2014 regarding such activities.  Also, in May 2014, the EPA proposed rules under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; however, to date, no further action has been taken on the proposal.  The EPA also proposed in April 2015 to prohibit the discharge of waste water from hydraulic fracturing operations to publicly owned waste water treatment plants.

Certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources.  The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing waste water to surface waters; and disposal or storage of fracturing waste water in unlined pits. Since 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. Also, in June 2016, the EPA finalized rules that would establish new air emission controls for methane emissions from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission, and storage activities. The final rule 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, fugitive emissions from well sites and compressors, equipment leaks at natural gas processing plants, and pneumatic pumps.  The rules also extend existing requirements for the emission of volatile organic compounds to the same equipment and processes. In addition, the U.S. Department of the Interior published a final rule in March 2015 that would implement updated requirements for hydraulic fracturing activities on federal lands, including new requirements relating to public disclosure, well bore integrity and handling of flowback water. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision is pending, however. Other governmental agencies, including the U.S. Department of Energy have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

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

Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

Our revolving credit facility contains a number of significant covenants (in addition to covenants restricting the incurrence of additional indebtedness), including restrictive covenants that may limit our ability to, among other things:

The indentures governing our senior notes contain similar restrictive covenants. In addition, our revolving credit facility requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. These restrictions, together with those in the indentures governing our senior notes, may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the indentures governing our senior notes and our revolving credit facility impose on us.

Our revolving credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine on a semi‑annual basis based upon projected revenues from the natural gas properties and commodity derivatives securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. If the requisite number of lenders do not agree to an increase, then the borrowing base will be the lowest borrowing base acceptable to such lenders.  For additional discussion of the risks regarding our ability to obtain funding under our revolving credit facility, please read “Item 1A. Risk Factors – A sustained decline of oil and natural gas prices may affect our ability to obtain funding, obtain funding on acceptable terms or obtain funding under our revolving credit facility. This may hinder or prevent us from meeting our future capital needs.”

A breach of any covenant in our revolving credit facility would result in a default under that agreement after any applicable grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under the facility and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.

Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. For example, during 2016, we had estimated average outstanding borrowings under our revolving credit facilities of approximately $1.1 billion, and the impact of a 1.0% increase in interest rates on this amount of indebtedness would result in increased interest expense for that period of approximately $11 million and a corresponding decrease in our net income before the effects of income taxes.  Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.