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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549



FORM 10-K



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

For the fiscal year ended December 31, 2013

or

o

 

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

Commission File No. 001-36120



ANTERO RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)
  80-0162034
(IRS Employer
Identification No.)

1625 17th St.
Denver Colorado

(Address of principal executive offices)

 

80202
(Zip Code)

(303) 357-7310
(Registrant's telephone number, including area code)

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

Title of Each Class   Name of Each Exchange on which Registered
Common Stock, Par Value $0.01 Per Share   New York Stock Exchange

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



         Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. o Yes    ý 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. o Yes    ý 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. ý Yes    o 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). ý Yes    o 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. ý

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

Large accelerated filer o   Accelerated filer o   Non-accelerated filer ý
(Do not check if a
smaller reporting company)
  Smaller reporting company o

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

         As of the last business day of the registrant's most recently completed second fiscal quarter, its common stock was not listed on any domestic exchange or over-the-counter market. The aggregate market value of the voting common stock held by non-affiliates of the registrant as of December 31, 2013, the last business day of the fiscal year, was approximately $2.6 billion.

         The registrant had 262,049,659 shares of common stock outstanding as of February 27, 2014.

         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 Form 10-K.

   


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TABLE OF CONTENTS

 
   
  Page  

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

   
ii
 

PART I

   
1
 

Items 1 and 2.

 

Business and Properties

    1  

Item 1A.

 

Risk Factors

    26  

Item 1B.

 

Unresolved Staff Comments

    44  

Item 3.

 

Legal Proceedings

    44  

Item 4.

 

Mine Safety Disclosures

    44  

PART II

   
45
 

Item 5.

 

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

    45  

Item 6.

 

Selected Financial Data

    47  

Item 7.

 

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

    51  

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

    71  

Item 8.

 

Financial Statements and Supplementary Data

    73  

Item 9.

 

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

    73  

Item 9A.

 

Controls and Procedures

    73  

Item 9B.

 

Other Information

    74  

PART III

   
77
 

Item 10.

 

Directors, Executive Officers and Corporate Governance

    77  

Item 11.

 

Executive Compensation

    81  

Item 12.

 

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

    81  

Item 13.

 

Certain Relationships and Related Transactions and Director Independence

    81  

Item 14.

 

Principal Accountant Fees and Services

    81  

PART IV

   
82
 

Item 15.

 

Exhibits and Financial Statement Schedules

    82  

SIGNATURES

   
89
 

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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 and sale of natural gas, NGLs, and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, marketing and transportation risks, regulatory changes, the uncertainty inherent in estimating natural gas, NGLs, and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in this Annual Report on Form 10-K.

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        Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs, and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities 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.

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GLOSSARY OF OIL AND NATURAL GAS TERMS

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

        "Basin."    A large natural depression on the earth's surface in which sediments generally brought by water accumulate.

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

        "Bcf."    One billion cubic feet of natural gas.

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

        "Btu."    British thermal unit.

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

        "DD&A."    Depreciation, depletion, and amortization.

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

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

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

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

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

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

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

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

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

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

        "Mcf."    One thousand cubic feet of natural gas.

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

        "MMBtu."    One million British thermal units.

        "MMcf."    One million cubic feet of natural gas.

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        "MMcf/d"    MMcf per day.

        "MMcfe."    One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs.

        "MMcfe/d."    MMcfe per day.

        "NGLs."    Natural gas liquids. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

        "NYMEX."    The New York Mercantile Exchange.

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

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

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

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

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

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

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

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

        "PV-10."    When used with respect to natural gas and oil reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production, future development and abandonment costs, using prices and costs in effect at the determination date, 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.

        "Recompletion."    The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

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        "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, and is often established by regulatory agencies.

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

        "Undeveloped acreage."    Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas 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.

        "Wellbore."    The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.

        "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.

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PART I

Items 1 and 2.    Business and Properties

Our Company

        Antero Resources Corporation is an independent oil and natural gas company engaged in the exploration, development and acquisition of natural gas, NGLs, and oil properties located in the Appalachian Basin. We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations. As of December 31, 2013, we held approximately 450,000 net acres of rich gas and dry gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. Our corporate headquarters are in Denver, Colorado.

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

 
  At December 31, 2013   Three months
ended
December 31,
2013
 
 
  Proved
reserves
(Bcfe)(1)
  PV-10
(in millions)(2)
  Net proved
developed
wells(3)
  Total net
acres(4)
  Gross
potential
drilling
locations(5)
  Average
net daily
production
(MMcfe/d)
 

Appalachian Basin:

                                     

Marcellus Shale

    7,226   $ 5,337     233     345,000     3,068     624  

Upper Devonian

    44   $ 6     2         951      

Utica Shale

    362   $ 655     15     105,000     759     54  
                           

Total

    7,632   $ 5,998     250     450,000     4,778     678  
                           

(1)
Estimated proved reserve volumes and values were calculated assuming ethane rejection and using the unweighted twelve-month average of the first-day-of-the-month reference prices for the period ended December 31, 2013, which were $3.65 per Mcf for natural gas, $47.13 per Bbl for NGLs and $87.00 per Bbl for oil for the Appalachian Basin based on a $97.17 WTI reference price.

(2)
PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to standardized measure, please see "—Our Properties and Operations—Estimated Proved Reserves."

(3)
Does not include 273 gross (241 net) shallow vertical wells that were acquired in conjunction with leasehold acreage acquisitions.

(4)
Net acres allocable to the Upper Devonian are included in the net acres allocated to the Marcellus Shale, because the Upper Devonian and the Marcellus Shale are multi-horizon shale formations attributable to the same leases.

(5)
See "Item 1A. Risk Factors" for risks and uncertainties related to developing our potential well locations.

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

        We have assembled a portfolio of long-lived properties that are characterized by what we believe to be low geologic risk and repeatability. Our drilling opportunities are focused in the Marcellus Shale and Utica Shale of the Appalachian Basin. We have drilled and operated 590 wells from inception through December 31, 2013, with a success rate of approximately 98%. We have a 24-year drilling

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inventory and have approximately 4,800 potential horizontal well locations on our existing leasehold acreage, both proven and unproven.

        We believe 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 and (ii) midstream operations consisting of gathering, compression and fresh water distribution. All of our operations are conducted in the United States.

2013 Developments and Highlights

        On October 16, 2013, we completed the initial public offering ("IPO") of our common stock. The offering was comprised of an aggregate of 41,083,750 shares of common stock at $44.00 per share, which included 3,409,091 shares of common stock sold by the selling stockholder and 1,949,659 shares of common stock sold by us pursuant to the exercise in full by the underwriters of their option to purchase additional shares of common stock.

        The gross proceeds of the IPO were approximately $1.8 billion. After subtracting (i) the net proceeds to the selling stockholders of approximately $143.3 million, (ii) underwriting discounts of approximately $81.4 million (approximately $74.6 million of which were paid by us and $6.8 million of which were paid by the selling stockholder) and (iii) offering expenses of approximately $5.0 million, we received net proceeds of approximately $1.6 billion.

        We used approximately $1.4 billion of the net proceeds to repay outstanding borrowings under our revolving credit facility and approximately $150 million to redeem $140 million aggregate principal amount of our outstanding 7.25% senior notes due 2019.

        As of December 31, 2013, our estimated proved reserves were 7.6 Tcfe, consisting of 6.8 Tcf of natural gas, 137 MMBbl of NGLs and 10 MMBbl of oil. As of December 31, 2013, 88% of our estimated proved reserves by volume were natural gas, 11% were NGLs, and 1% was oil. Proved developed reserves were 2.0 Tcfe, or 27% of total proved reserves.

        For the year ended December 31, 2013, we generated cash flow from operations of $535 million, a net loss of $19 million and EBITDAX of $649 million. Net loss in 2013 included (i) a noncash charge of $365 million for stock compensation, (ii) a noncash tax provision of $186 million, (iii) a charge of $43 million for redemption premiums and the write-off of unamortized deferred financing charges and premium associated with the retirement of $525 million of our 9.375% senior notes due 2017 and $140 million of senior notes due 2019, and (iii) income from discontinued operations of $5 million. In contrast, for the year ended December 31, 2012, we generated cash flow from operations of $332 million, a net loss of $285 million, and EBITDAX of $434 million. The net loss in 2012 included (i) a pre-tax loss of $796 million on the sale of the Arkoma and Piceance Basin properties, (ii) deferred tax benefit related to the loss on the sale of the Arkoma and Piceance properties and discontinued operations of $273 million, (iii) a pre-tax gain on the sale of certain Appalachian gathering systems of $291 million, and (iv) a noncash tax provision related to continuing operations of $121 million. See "Item 6. Selected Financial Data" for a definition of EBITDAX (a non-GAAP measure) and a reconciliation of EBITDAX to net income (loss).

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        In November 2013, we issued $1 billion aggregate principal amount of 5.375% senior notes due 2021 at par for net proceeds of approximately $987 million. We used approximately $550 million of the proceeds to retire our 9.375% senior notes due 2017 and the remainder to fund our drilling and development program.

        At December 31, 2013, we had entered into hedging contracts for January 1, 2014 through December 31, 2019 for 1.249 Tcf of our projected natural gas production at a weighted average index price of $4.64 per MMBtu and 1.1 million Bbls of oil at a weighted average price of $96.53 per Bbl. These hedging contracts include contracts for the year ended December 31, 2014 of approximately 223 Bcf of natural gas at a weighted average index price of $4.68 per MMBtu and 1.1 million Bbls of oil at $96.53 per Bbl. We believe this hedge position provides us with protection to future cash flows to support our operations and capital spending plans for 2014.

        Our current borrowing base under our revolving credit facility is $2 billion and lender commitments are $1.5 billion. Lender commitments under our revolving credit facility can be expanded from $1.5 billion to the full $2 billion borrowing base upon bank approval. The borrowing base under our revolving credit facility is redetermined semi-annually and is based on the estimated future cash flows from our proved natural gas, NGL, and oil reserves and our hedge positions. The next redetermination is scheduled to occur in April 2014. Our revolving credit facility provides for a maximum availability of $2.5 billion. At December 31, 2013, we had $320 million of borrowings and letters of credit outstanding under the revolving credit facility and $1.18 billion of available borrowing capacity. Our revolving credit facility matures in May 2016. 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.

        For the year ended December 31, 2013, our capital expenditures were approximately $2.7 billion for drilling, leasehold, and from water distribution and gathering systems. Our capital budget for 2014 is $2.6 billion and includes: $1.8 billion for drilling and completion; $600 million for the expansion of midstream facilities, including $200 million for fresh water distribution infrastructure; and $200 million for core leasehold acreage acquisitions. We do not budget for producing property acquisitions. Substantially all of the $1.8 billion allocated for drilling and completion is allocated to our operated drilling in rich gas areas. Approximately 75% of the drilling and completion budget is allocated to the Marcellus Shale, and the remaining 25% is allocated to the Utica Shale. During 2014, we plan to operate an average of 14 drilling rigs in the Marcellus Shale, including three intermediate rigs that drill the vertical section of some horizontal wells to kick-off point, and 4 drilling rigs in the Utica Shale. Consistent with our historical practice, we periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities, and commodity prices.

Address, Internet Website and Availability of Public Filings

        Our principal executive offices are located at 1625 17th Street, Denver, Colorado 80202 and our telephone number is (303) 357-7310. Our website is located at http://www.anteroresources.com.

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        We make available our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, and our Current Reports on Form 8-K. These documents are located www.anteroresources.com under the "Investors Relations" link.

        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.

Our Properties and Operations

        The information with respect to our estimated proved reserves presented below has been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (the "SEC").

        The following table summarizes our estimated proved reserves and related standardized measure and PV-10 at December 31, 2011, 2012 and 2013. Our estimated proved reserves as of December 31, 2012 and 2013 are based on evaluations prepared by our internal reserve engineers, which have been audited by our independent engineers, DeGolyer and MacNaughton ("D&M"). Our estimated proved reserves as of December 31, 2011 were based on evaluations prepared by our internal reserve engineers, which were audited by D&M and Ryder Scott & Company ("Ryder Scott"). 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, 2013 is filed as Exhibit 99.1 to this Annual Report on Form 10-K. The information in the following table does not give any effect to or reflect our commodity hedges. Reserves at December 31, 2011 and 2012 were prepared assuming ethane recovery from our production process, while reserves at December 31, 2013 were prepared assuming ethane rejection as a result of the pricing environment shifting to one that favors ethane rejection at December 31, 2013. Reserves at December 31, 2011 include reserves attributable to the Arkoma and Piceance Basin properties which were sold in 2012.

 
  At December 31,  
 
  2011   2012   2013  

Estimated proved reserves:

                   

Proved developed reserves:

                   

Natural gas (Bcf)

    718     828     1,818  

NGLs (MMBbl)

    19     36     33  

Oil (MMBbl)

    2     1     2  

Total equivalent proved developed reserves (Bcfe)

    844     1,047     2,022  

Proved undeveloped reserves:

                   

Natural gas (Bcf)

    3,213     2,866     4,936  

NGLs (MMBbl)

    145     167     105  

Oil (MMBbl)

    15     2     8  

Total equivalent proved undeveloped reserves (Bcfe)

    4,173     3,882     5,610  

Total estimated proved reserves (Bcfe)

    5,017     4,929     7,632  

Proved developed producing (Bcfe)

    804     935     1,771  

Proved developed non-producing (Bcfe)

    40     112     251  

Percent developed

    17 %   21 %   27 %

PV-10 (in millions)(1)

  $ 3,445   $ 1,923   $ 5,998  

Standardized measure (in millions)(1)

  $ 2,470   $ 1,601   $ 4,510  

(1)
PV-10 was prepared using average yearly prices computed using SEC rules, discounted at 10% per annum, without giving effect to taxes. PV-10 is a non-GAAP financial measure.

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  At December 31,  
(In millions, except per Mcf data)
  2011(1)   2012(2)   2012(3)  

Future net cash flows

  $ 11,470   $ 7,221   $ 18,797  

Present value of future net cash flows:

                   

Before income tax (PV-10)

  $ 3,445   $ 1,923   $ 5,998  

Income taxes

  $ (975 ) $ (322 ) $ (1,488 )

After income tax (Standardized measure)

  $ 2,470   $ 1,601   $ 4,510  

(1)
12-month average prices used at December 31, 2011 were $3.90 per Mcf for the Arkoma Basin, $3.84 per Mcf for the Piceance Basin and $4.16 per Mcf for the Appalachian Basin.

(2)
12-month average prices used at December 31, 2012 were $2.78 per Mcf for natural gas, $19.61 per Bbl for NGLs, and $85.05 per Bbl for oil for the Appalachian Basin based on a $95.05 WTI reference price.

(3)
12-month average prices used at December 31, 2013 were $3.65 per Mcf for natural gas, $47.13 per Bbl for NGLs, and $87.00 per Bbl for oil for the Appalachian Basin based on a $97.17 WTI reference price.

        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 2011, 2012 and 2013 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.

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        The following table summarizes the changes in our estimated proved reserves during 2013 (in Bcfe):

Proved reserves, December 31, 2012

    4,929  

Extensions, discoveries, and other additions

    3,682  

Conversion to ethane rejection

    (646 )

Price and performance revisions

    (142 )

Production

    (191 )
       

Proved reserves, December 31, 2013

    7,632  
       
       

        Extensions, discoveries, and other additions during 2013 of 3,682 Bcfe were added through exploratory and developmental drilling in the Marcellus and Utica Shales. Downward revisions of 646 Bcfe resulted from changing the underlying production assumption used to estimate reserves to ethane rejection at December 31, 2013 from ethane recovery at December 31, 2012. Negative performance revisions of 157 Bcfe were due to the reclassification of 65 wells to the probable category because they are no longer expected to be drilled within five years of initial booking partially offset by improved well performance from shorter stage length completions. Price revisions increased reserves by 15 Bcfe. Our estimated proved reserves as of December 31, 2013 totaled approximately 7.6 Tcfe and increased by 55% over the prior year. Assuming ethane rejection in both years, proved reserves increased by 78% and our proved developed reserves increased year over year by 117% to 2,022 Bcfe at December 31, 2013.

        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 2013 (in Bcfe):

Proved undeveloped reserves, December 31, 2012

    3,882  

Extensions, discoveries, and other additions

    2,844  

Price and performance revisions

    (1,116 )
       

Proved undeveloped reserves, December 31, 2013

    5,610  
       
       

        Extensions, discoveries, and other additions during 2013 of 2,844 Bcfe proved undeveloped reserves were added through exploratory and developmental drilling in the Marcellus and Utica Shales. Downward revisions of 1,116 Bcfe are net of a 10 Bcfe increase due to price revisions and are primarily due to changing the underlying production assumption to ethane rejection at December 31, 2013 from ethane recovery at December 31, 2012 as well as the reclassification of certain wells to the probable reserves category in 2013 because they are no longer expected to be drilled within five years of initial booking. Proved undeveloped reserves include reserves that are expected to be drilled and developed within five years; wells that are not drilled within five years from booking are reclassified from proved reserves to probable reserves.

        During the year ended December 31, 2013, we converted our beginning Appalachian Basin proved undeveloped reserves to proved developed reserves at a rate of 10%. Estimated future development costs relating to the development of our proved undeveloped reserves at December 31, 2013 are approximately $5.3 billion over the next five years, which we expect to finance through cash flow from operations, borrowings under our revolving credit facility, the net proceeds from our initial public offering of our midstream business, and other sources of capital financing. Our drilling programs to date have focused on proving our undeveloped leasehold acreage through delineation drilling. While we

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will continue to drill leasehold delineation wells and build on our current leasehold position, we will also focus on drilling our proved undeveloped reserves. All of our proved undeveloped reserves are expected to be developed over the next five years. See "Item 1A. Risk Factors—The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced."

        Our reserve estimates as of December 31, 2011, 2012, and 2013 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. Certain of the internally prepared reserve estimates were audited by our independent reserve engineers. Our independent reserve engineers were selected for their historical experience and geographic expertise in engineering unconventional resources. The technical persons responsible for overseeing the audit of our reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

        Our internal staff of petroleum engineers and geoscience professionals work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserve auditing process. Periodically, our technical team meets with the independent reserve engineers to review properties and discuss methods and assumptions used by us to prepare reserve estimates. Our internally prepared reserve estimates and related reports are reviewed and approved by our Vice President of Reserves, Planning & Midstream, Ward D. McNeilly, and our Vice President of Production, Kevin J. Kilstrom. Mr. McNeilly has been with the Company since October 2010. Mr. McNeilly has 34 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.

        Mr. Kilstrom has served as Vice President of Production since June 2007. Mr. Kilstrom was a Manager of Petroleum Engineering with AGL Energy of Sydney, Australia from 2006 to 2007. Prior to AGL, Mr. Kilstrom was with Marathon Oil as an Engineering Consultant and Asset Manager from 2003 to 2006 and as a Business Unit Manager for Marathon's Powder River coal bed methane assets from 2001 to 2003. Mr. Kilstrom also served as a member of the board of directors of three Marathon subsidiaries from October 2003 through May 2005. Mr. Kilstrom was an operations manager and reserve engineer at Pennaco Energy from 1999 to 2001. Mr. Kilstrom was at Amoco for more than 22 years prior to 1999 where he served in various operating roles with a focus on unconventional resources. Mr. Kilstrom holds a B.S. in Engineering from Iowa State University and an M.B.A. from DePaul University. Our senior management also reviews our reserve estimates and related reports with Mr. McNeilly and Mr. Kilstrom 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.

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

        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 Highly-Developed Area, or HDA, 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 an HDA 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.

        Our identified potential well locations include locations to which proved, probable or possible reserves were attributable based on SEC pricing as of December 31, 2013. The Company prepares estimates of its probable and possible reserves but is not including disclosure of such reserves in this report.

        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 dramatically since 2000, natural gas and NGL supplies have also increased significantly as

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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. 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 gas reserves that may be economically produced and our ability to access capital markets. See "Item 1A. Risk Factors—Natural gas, NGL 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 following table sets forth information regarding our production, revenues and realized prices, and production costs from continuing operations in the Appalachian Basin for the years ended December 31, 2011, 2012 and 2013. For additional information on price calculations, see information set forth in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

 
  Year Ended December 31,  
 
  2011   2012   2013  

Production data:

                   

Natural gas (Bcf)

    45     87     177  

NGLs (MBbl)

        71     2,123  

Oil (MBbl)

    2     19     226  

Total combined production (Bcfe)

    45     87     191  

Average daily combined production (MMcfe/d)

    124     239     522  

Average sales prices:

                   

Natural gas (per Mcf)

  $ 4.33   $ 2.99   $ 3.90  

NGLs (per Bbl)

  $   $ 52.07   $ 52.61  

Oil (per Bbl)

  $ 97.19   $ 80.34   $ 91.27  

Combined average sales prices before effects of cash settled derivatives (per Mcfe)(1)

  $ 4.33   $ 3.03   $ 4.31  

Combined average sales prices after effects of cash settled derivatives (per Mcfe)(1)

  $ 5.44   $ 5.08   $ 5.17  

Average costs per Mcfe:

                   

Lease operating costs

  $ 0.10   $ 0.07   $ 0.05  

Gathering, compression, processing, and transportation

  $ 0.83   $ 1.04   $ 1.15  

Production taxes

  $ 0.26   $ 0.23   $ 0.26  

Depreciation, depletion, amortization, and accretion

  $ 1.24   $ 1.17   $ 1.23  

General and administrative(2)

  $ 0.74   $ 0.52   $ 0.32  

(1)
Average prices shown reflect both of the before-and-after effects of our realized commodity hedging transactions. Our calculation of such effects includes realized gains or losses on cash settlements for commodity derivatives, which do not qualify for hedge accounting because we do not designate them as hedges.

(2)
Does not include noncash stock compensation in 2013.

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Discontinued Operations Data—Arkoma and Piceance Basins

        The table above does not include the following production or revenue from discontinued operations from the Arkoma and Piceance Basin properties which were sold in 2012:

 
  Year Ended
December 31,
 
 
  2011   2012   2013  

Production (combined Bcfe)

    44     35      

Natural gas, NGL and oil production revenues (in millions)

  $ 197   $ 125   $  

        See footnote 3 to the consolidated financial statements included in Item 8 of this Annual Report on Form 10-K for the results of discontinued operations.

        As of December 31, 2013, we had a total of 500 gross (460 net) producing wells, averaging a 92% working interest, in the Marcellus Shale. This well count includes 227 gross (219 net) horizontal wells and 273 gross and (241 net) shallow vertical wells that were acquired in conjunction with leasehold acreage acquisitions. In the Utica Shale we had 12 gross (10 net) producing wells at December 31, 2013, averaging an 83% working interest. Our wells are gas wells, many of which also produce oil, condensate and NGLs. Additionally, at December 31, 2013 we had 76 gross wells (69 net) waiting on completion or pipeline connection.

        The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of December 31, 2013. A majority of our developed acreage is subject to liens securing our revolving credit facility. Approximately 51% of our Marcellus acreage and 20% of our Utica acreage is held by production. Acreage related to royalty, overriding royalty and other similar interests is excluded from this table.

 
  Developed Acres   Undeveloped Acres   Total Acres  
Basin
  Gross   Net   Gross   Net   Gross   Net  

Marcellus

    30,748     30,571     417,484     314,378     448,232     344,949  

Utica

    5,108     4,024     123,608     101,049     128,716     105,073  

Other

            6,609     6,599     6,609     6,599  
                           

Total

    35,856     34,595     547,701     422,026     583,557     456,621  
                           

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

 
  Marcellus  
County
  Gross
Acres
  Net
Acres
 

Doddridge, WV

    164,881     120,239  

Gilmer, WV

    1,649     1,381  

Harrison, WV

    116,625     101,304  

Lewis, WV

    89     65  

Marion, WV

    4,155     3,911  

Monongalia, WV

    1,835     1,686  

Pleasants, WV

    1,699     810  

Ritchie, WV

    65,211     48,544  

Tyler, WV

    58,530     39,156  

Wetzel, WV

    5,351     2,822  

Fayette, PA

    7,364     5,423  

Greene, PA

    974     454  

Washington, PA

    12,710     12,235  

Westmoreland, PA

    7,159     6,919  
           

Total Marcellus Shale

    448,232     344,949  
           

 

 
  Utica  

Athens, OH

    84     84  

Belmont, OH

    13,367     12,016  

Guernsey, OH

    10,410     8,674  

Harrison, OH

    47     47  

Monroe, OH

    42,212     37,077  

Noble, OH

    62,596     47,175  
           

Total Utica Shale

    128,716     105,073  
           

Total Marcellus and Utica Shale

    576,948     450,022  
           
           

        The following table sets forth the number of total gross and net undeveloped acres as of December 31, 2013 that will expire over the next three years unless production is established within the spacing units covering the acreage prior to the expiration dates or unless such acreage is extended or renewed.

 
  Gross   Net  

2014

    13,685     7,894  

2015

    31,217     21,922  

2016

    39,057     24,732  

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        The following table summarizes our drilling activity for the years ended December 31, 2011, 2012 and 2013. Gross wells reflect the sum of all wells in which we own an interest and includes historical drilling activity in the Appalachian, Arkoma, and Piceance Basins. Net wells reflect the sum of our working interests in gross wells.

 
  Year Ended December 31,  
 
  2011   2012   2013  
 
  Gross   Net   Gross   Net   Gross   Net  

Marcellus

                                     

Development wells:

                                     

Productive

    25     23     48     45     49     48  

Dry

                         
                           

Total development wells

    25     23     48     45     49     48  
                           

Exploratory wells:

                                     

Productive

    13     13     15     15     63     62  

Dry

                         
                           

Total exploratory wells

    13     13     15     15     63     62  
                           

Utica

                                     

Development wells:

                                     

Productive

                    3     3  

Dry

                         
                           

Total development wells

                    3     3  
                           

Exploratory wells:

                                     

Productive

            1     1     13     10  

Dry

                         
                           

Total exploratory wells

            1     1     13     10  
                           

Arkoma, Piceance, and Other

                                     

Development wells:

                                     

Productive

    110     42     58     46          

Dry

                         
                           

Total development wells

    110     42     58     46          
                           

Exploratory wells:

                                     

Productive

    61     17     6     1          

Dry

                         
                           

Total exploratory wells

    61     17     6     1          
                           

Total

                                     

Development wells:

                                     

Productive

    135     65     106     91     52     51  

Dry

                         
                           

Total development wells

    135     65     106     91     52     51  
                           

Exploratory wells:

                                     

Productive

    74     30     22     17     76     72  

Dry

                         
                           

Total exploratory wells

    74     30     22     17     76     72  
                           

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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 such commitments, but may be required to purchase gas from third parties to satisfy shortfalls should they occur.

        As of December 31, 2013, our firm sales commitments through 2018 included:

Year Ending December 31,
  Volume of
Natural Gas
(MMcfe/d)
 

2014

    430  

2015

    420  

2016

    388  

2017

    212  

2018

    200  

        In addition, we have firm transportation contracts that require us to deliver products to pipeline transporters or pay demand charges for shortfalls. The minimum demand fees are reflected in our table of contractual obligations. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements and Contractual Obligations."

Midstream Operations

        Our exploration and development activities are supported by our operated natural gas gathering, compression, processing and transportation assets, as well as by third-party 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. Actively managing these midstream operations allows us to ensure that we can obtain the necessary takeaway and processing capacity for our production and, when necessary or advisable, process our liquids-rich natural gas production to maximize the value that we can obtain for our products.

        We maintain a strong commitment to developing the necessary midstream infrastructure to support our drilling schedule and production growth. We accomplish this goal through a combination of internal asset developments and contractual relationships with third-party midstream service providers. As part of our internal developments, we have invested a significant amount of capital in building low- and high-pressure gathering lines, compressor stations and water pipeline systems. In the past we have monetized certain midstream infrastructure assets for a significant return on investment and redeployed the proceeds into our ongoing operations. We will continue to invest significantly in our midstream infrastructure, as it allows us to optimize our processing and takeaway capacity to support our expected rapid production growth, affords us more control over the direction and planning of our drilling schedule and has historically created significant value for our equity owners. In 2013, we spent approximately $593 million on midstream gas, condensate and fresh water infrastructure. In addition, we believe that our midstream assets may be well suited for a MLP or similar structure. Accordingly, we are pursuing an initial public offering of limited partner interests in an entity that will indirectly own substantially all of our midstream assets. See "Item 1A. Risk Factors—Our ability to complete the proposed initial public offering of our midstream business on the terms currently contemplated, or at all, may result in a reduction in of 2014 capital budget."

Transportation and Takeaway Capacity

        Our primary firm transportation commitments include the following:

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        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.

        We continue to actively identify and evaluate additional processing and takeaway capacity to enhance the value of our Appalachian Basin position.

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 in order to meet quality specifications of long-haul intrastate and interstate pipelines.

        NGLs are valuable commodities once removed from the natural gas stream and fractionated into their key components. Fractionation refers to the process by which an NGL stream is separated into individual NGL products such as ethane, propane, normal butane, isobutane and natural gasoline. Fractionation occurs by heating the mixed NGL stream to allow for the separation of the component parts based on the specific boiling points of each product. Each of the individual products have their own market price.

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

        Given the existing commodity price environment and the limited ethane market in the northeast, we are currently rejecting ethane when processing our liquids-rich gas; however, we realize a significant pricing upgrade when selling the remaining NGL product stream at current prices. We will elect to recover ethane when ethane prices recover and the value we receive for the ethane is greater than the Btu equivalent residue gas.

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        Our typical NGL barrel, assuming ethane recovery for 1,225 Btu gas, is composed of 65% ethane, 20% propane, 9% butanes, 6% pentanes-plus. At December 31, 2013, the blended value of this NGL barrel was approximately $18.99/Bbl. When we elect to reject ethane, we sell the ethane as Btu equivalent in our residue gas and our typical NGL barrel for 1,225 Btu gas is composed of approximately 4% ethane, 56% propane, 25% butanes, and 15% pentanes plus. At December 31, 2013, the blended value of an NGL barrel while rejecting ethane was $47.56/Bbl.

        As of December 31, 2013, we owned and operated 92 miles of gas gathering pipelines in the Marcellus Shale, and had access to additional low-pressure and high-pressure pipelines owned and operated by Crestwood, Energy Transfer Partners L.P. and Summit Midstream. Additionally, as of December 31, 2013, we owned and operated four compressor stations and utilized twelve 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, 2013, we owned and operated 59 miles of low-pressure, high-pressure and condensate pipelines in the Utica Shale. As of December 31, 2013, we had three third-party compressor stations under construction in the Utica Shale.

        Through third-party contractual relationships, we have obtained committed cryogenic processing capacity for our Marcellus and Utica Shale production. For example, we have contracted with MarkWest to provide processing capacity as follows:

 
  Plant
Processing
Capacity
(MMcf/d)
  Contracted
Firm
Processing
Capacity
(MMcf/d(1)
  Anticipated Date of
Completion

Marcellus Shale:

               

Sherwood I

    200     200   In service

Sherwood II

    200     200   In service

Sherwood III

    200     150   In service

Sherwood IV

    200     200   Third Quarter 2014

Sherwood V

    200     200   Fourth Quarter 2014
             

Marcellus Shale Total

    1,000     950    
             
             

Utica Shale:

               

Seneca I

    200     200   In service

Seneca II(1)

    200     50   In service

Seneca III

    200     200   Second Quarter 2014

Seneca IV(2)

    200     200   First Quarter 2015
             

Utica Shale Total

    800     600    
             
             

(1)
We have 50 MMcf/d of interim capacity at the Seneca II processing facility until First Quarter 2015, the Seneca IV in-service date.

(2)
Contracted capacity executed January 2014.

        Our midstream infrastructure also includes 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, portable 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, we will move surface pipelines to service completion operations in concert with our drilling program. As of December 31, 2013, we also have the ability to store a total of 14.9 million barrels of fresh water in 20 impoundments.

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        The water pipeline systems are expected to deliver a reliable year-round water supply, reduce water handling costs and significantly decrease water truck traffic and associated road damage on state, county and municipal roadways. It is estimated that these water pipeline systems will reduce our well completion costs by $600,000 to $800,000 per well. In 2014, we expect that approximately 90% of our well completions will use these systems. Assuming a 7,000 foot horizontal well lateral, it is estimated that 1,850 water truckload trips per well completion will be eliminated from roadways.

        Due to the extensive geographic distribution of our water pipeline systems in both West Virginia and Ohio, we anticipate having the ability to offer water delivery services to neighboring oil and gas producers within and surrounding our operating area, subject to commercial arrangements, in an effort to further reduce water truck traffic.

        As of December 31, 2013 in West Virginia, we owned and operated 74 miles of buried fresh water pipelines. Upon full project completion, the buried pipeline system is estimated to be 171 miles long and will extend to the Ohio River and several regional waterways for water sourcing. The water pipeline system will also include an additional 150 miles of purchased, temporary and reusable surface pipeline, 47 centralized water storage facilities equipped with transfer pumps and four other major pumping stations required for transporting water through the buried pipeline system.

        As of December 31, 2013 in Ohio, we owned and operated 23 miles of buried fresh water pipelines. Upon project completion, the buried pipeline system is estimated to be 63 miles long and will rely on waterways and lakes within a close proximity to our operating area for water sourcing. The water pipeline system will also include an additional 45 miles of purchased, temporary and reusable surface pipeline and 24 centralized water storage facilities equipped with transfer pumps.

Major Customers

        For the year ended December 31, 2013, sales to South Jersey Resources Group LLC, Sequent Energy Management L.P., and Nextera Energy Powermarketing LLC represented 30%, 14%, and 8% of our total sales, respectively. For the year ended December 31, 2012, sales to South Jersey Resources Group, LLC, Nextera Energy Powermarketing LLC and Dominion Filed Services Inc. represented 23%, 13% and 10% of our total sales, respectively. For the year ended December 31, 2011, sales from our top three customers accounted for 28%, 17%, and 12% of our total sales, respectively. Although a substantial portion of 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, in the case of undeveloped properties, often 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:

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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 such as that experienced in 2013-2014 can 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 lessen 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

        Our operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing natural gas and oil properties have statutory provisions regulating the exploration for and production of natural gas and oil, including provisions related to permits for the drilling of wells, bonding requirements 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, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

        Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (the "FERC"), and the courts. We cannot predict when or whether any such proposals may become effective.

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        We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered.

Regulation of Production of Natural Gas and Oil

        The production of natural gas and oil is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of natural gas and oil properties, the establishment of maximum allowable rates of production from natural gas and oil wells, the regulation of well spacing or density, and plugging and abandonment of wells. 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.

        We own interests in properties located onshore in three U.S. states. These states regulate drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of these states also govern a number of environmental and conservation matters, including the handling and disposing or discharge of waste materials, the size of drilling and spacing units or proration units and the density of wells that may be drilled, unitization and pooling of oil and gas properties and establishment of maximum rates of production from oil and gas wells. Some states have the power to prorate production to the market demand for oil and gas.

        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 and Sales of Natural Gas

        The transportation and sale for resale of natural gas in interstate commerce are regulated by 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.

        The Domenici Barton Energy Policy Act of 2005, or EP Act 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. The EP Act of 2005 provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increased FERC's civil penalty authority under the NGPA to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued

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Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules 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 new anti-market manipulation rule does 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 704.

        On December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas gatherers and marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. 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.

        Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point of sale locations. 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.

        Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although the FERC has not made any formal determinations with respect to any of our facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to regulation as a natural gas company. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by FERC, the courts or Congress.

        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.

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        The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. In the past, the federal government has regulated the prices at which natural gas could be sold. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

        Our sales of natural gas are also subject to requirements under the Commodity Exchange Act, or CEA, and regulations promulgated thereunder by the Commodity Futures Trading Commission, or CFTC. 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.

        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 natural gas, NGL and oil exploration and production 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, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling or other regulated activity commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines, govern the sourcing and disposal of water used in the drilling and completion process, limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas, require some form of remedial 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

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substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us as owners under CERCLA. 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; however, we are unaware of any liabilities 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, impose 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, state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas exploration, development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, 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. 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, 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, 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 the state. 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. Obtaining permits has the potential to delay the development of natural gas and oil projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized

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discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

        Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as "SPCC plans," in connection with on-site storage of significant quantities of oil. We believe that we maintain all required discharge permits necessary to conduct our operations, and further believe we are in substantial compliance with the terms thereof. We are currently undertaking a review of recently acquired natural gas properties to determine the need for new or updated SPCC plans and, where necessary, we will be developing or upgrading such plans implementing the physical and operation controls imposed by these plans, the costs of which are not expected to be substantial.

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 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 August 2012, the EPA published 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. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all "other" fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare after October 15, 2012. However, the "other" wells must use reduced emission completions, also known as "green completions," with or without combustion devices, after January 1, 2015. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, effective October 2012 and from pneumatic controllers and storage vessels, effective October 2013. EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. EPA intends to issue revised rules in 2013 that are likely responsive to some of these requests. For example, in April 2013 EPA published a proposed amendment extending compliance dates for certain 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 PSD construction and Title V operating permit reviews for certain large stationary sources that are

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potential major sources of GHG emissions. 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. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations.

        While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. 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. Severe limitations on GHG emissions could also adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic event; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

Hydraulic Fracturing Activities

        Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure through a cased and cemented wellbore into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations as does most of the domestic oil and natural gas industry. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act, or the SDWA, over certain hydraulic fracturing activities involving the use of diesel fuels and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; however, to date, the agency has not yet taken any action to do so.

        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. 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. 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

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fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

        Certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released in December 2012 and a draft final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by late 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards at some point in 2014. In addition, the U.S. Department of the Interior published a revised proposed rule in May 2013 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. 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, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

Occupational Safety and Health Act

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

Endangered Species Act

        The federal Endangered Species Act, or ESA, was established to protect 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 may 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, such as the northern long-eared bat, that potentially could be listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service 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 land access for natural gas and oil development. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency's 2017 fiscal year. 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

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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.

        In summary, we believe we are in substantial compliance with currently applicable environmental laws and regulations. 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 2013, nor do we anticipate that such expenditures will be material in 2014.

Employees

        As of December 31, 2013, we had 233 full-time employees, including 20 in executive, finance, treasury and administration, 21 in geology, 84 in production and engineering, 29 in accounting, 63 in land, and 16 in midstream. We also employed approximately 104 contract personnel who assist our full-time employees with specific tasks. 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.

Legal Proceedings

        We are party to various legal proceedings and claims in the ordinary course of our business. We believe certain of these matters will be covered by insurance and that the outcome of other matters will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.

        In March 2011, we received orders for compliance from federal regulatory agencies, including the EPA, relating to certain of our activities in West Virginia. The orders allege that certain of our operations at several well sites are in non-compliance with certain environmental regulations, such as unpermitted discharges of fill material into wetlands or waters of the United States that are potentially in violation of the Clean Water Act. No fine or penalty relating to these matters has been proposed at this time, but the Company believes that these actions will result in monetary sanctions exceeding $100,000. In addition, we expect to incur additional costs to remediate these well locations in order to bring them into compliance with applicable environmental laws and regulations. We have not, however, been required to suspend our operations at these locations to date and management does not expect these matters to have a material adverse effect on our financial condition, results of operations or cash flows.

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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. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect our company.

Natural gas, NGL 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, NGL 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:

        Furthermore, the worldwide financial and credit crisis in recent years has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide resulting in a slowdown in economic activity and recession in parts of the world. This has reduced worldwide demand for energy and resulted in lower natural gas, NGL and oil prices.

        Lower commodity prices will 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 exploitation, development and exploration 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.

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

        The natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the exploitation, development and acquisition of natural gas reserves. Our cash flow used in investing activities related to capital and exploration expenditures was approximately $2.7 billion in 2013. Our board of directors has approved a capital budget for 2014 of $2.6 billion and includes $1.8 billion for drilling and completion; $600 million for expansion of midstream facilities, including $200 million for fresh water distribution infrastructure; and $200 million for core leasehold acreage acquisitions. Our capital budget excludes acquisitions. We expect to fund these capital expenditures with cash generated by operations, reimbursement for pre-contribution capital expenditures from the proposed master limited partnership, borrowings under our revolving credit facility or capital market transactions. 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 reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. We intend to finance our future capital expenditures primarily through cash flow from operations and through borrowings under our revolving credit facility; 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 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 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.

Our ability to complete the proposed initial public offering of our midstream business on the terms currently contemplated, or at all, may result in a reduction in our 2014 capital budget.

        We are pursuing an initial public offering of limited partnership interests in an entity that will indirectly own substantially all of our midstream assets. Adverse developments in our midstream business may result in our failure to complete the initial public offering, a decrease in the proceeds we

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receive from the offering or a decrease in the value of the limited partnership interests we retain upon completion of the offering. Potential adverse developments include, but are not limited to:

In addition, general market conditions, including the market for yield securities, may impact our ability to complete the initial public offering on the terms currently contemplated, or at all. Our inability to complete the initial public offering on the terms currently contemplated, or at all, may result in a reduction in our 2014 capital budget.

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

        Our future financial condition and results of operations will depend on the success of our exploitation, 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, develop or otherwise exploit 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:

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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, our $260 million of 7.25% senior notes due 2019, $525 million of 6.00% senior notes due 2020, and $1 billion of 5.375% notes due 2021 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 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 is currently $2.0 billion, and lender commitments under our revolving credit facility are $1.5 billion. Our next scheduled borrowing base redetermination is expected to occur in April 2014. In the future, we may not be able to access adequate funding under our revolving credit facility as a result of a decrease in our borrowing base due to the issuance of new indebtedness, the outcome of a subsequent semi-annual borrowing base redetermination or an unwillingness or inability on the part of our lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender's portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. 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

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material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

We are required to pay fees to our service providers based on minimum volumes regardless of actual volume throughput.

        We have various firm transportation and gas processing, gathering and compression service agreements in place, each with minimum volume delivery commitments. As of December 31, 2013, our long-term contractual obligation under these agreements was $3.5 billion. We are obligated to pay fees on minimum volumes to our service providers regardless of actual volume throughput, which could be significant and have a material adverse effect on our results of operations. If these fees on minimum volumes are substantial, we may not be able to generate sufficient cash to cover these obligations, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing.

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 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. Outstanding borrowings in excess of the borrowing base must be repaid, or we must pledge other natural gas properties as additional collateral after applicable grace periods. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make mandatory principal prepayments required under

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our revolving credit facility. The borrowing base under our revolving credit facility is currently $2.0 billion and lender commitments are $1.5 billion. Our next scheduled borrowing base redetermination is expected to occur in April 2014.

        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.

Currently, we receive significant incremental cash flows as a result of our hedging activity. To the extent we are unable to obtain future hedges at effective prices consistent with those we have received to date and natural gas prices do not improve, our cash flows may be adversely impacted. Additionally, if development drilling costs increase significantly in the future, our hedged revenues may not be sufficient to cover our costs.

        To achieve more predictable cash flows and reduce our exposure to downward price fluctuations, as of December 31, 2013, we had entered into a number of hedge contracts for approximately 1.255 Tcfe of our projected natural gas and oil production through December 31, 2019. We are currently realizing a significant benefit from these hedge positions. For example, for the years ended December 31, 2012 and 2013, we received approximately $271 million and $164 million, respectively, in revenues from cash settled derivatives pursuant to our hedges, which represented approximately 30% and 13%, respectively, of our total revenues (including revenues from discontinued operations) for such periods. Many of the hedge agreements that resulted in these realized gains for the years ended December 31, 2012 and 2013 were executed at times when spot and future prices were higher than prices that we are currently able to obtain in the futures market, and the price at which we have been able to hedge future production has decreased as a result. Therefore, we expect that this benefit will decline materially over the life of the hedges, which cover decreasing volumes at declining prices through December 2019. If we are unable to enter into new hedge contracts in the future at favorable pricing and for a sufficient amount of our production, our financial condition and results of operations could be materially adversely affected.

        Additionally, since we hedge a significant part of our estimated future production, we have fixed a significant part of our future revenue stream. For example, for the years ended December 31, 2012 and 2013, approximately 81% of our estimated future production (including production from discontinued operations) was covered by our hedge contracts. If development drilling costs increase significantly because of inflation, increased demand for oilfield services, increased costs to comply with regulations governing our industry or other factors, future hedged revenues may not be sufficient to cover our costs.

In certain circumstances we may have to make cash payments under our hedging arrangements and these payments could be significant.

        If natural gas or oil prices exceed the price at which we have hedged our commodities, we will be obligated to make cash payments to our hedge counterparties.which could, in certain circumstances, be significant. As of December 31, 2013, we had entered into hedging contracts through December 31, 2019 covering a total of approximately 1.255 Tcfe of our projected natural gas and oil production at a weighted average price of $4.61 per Mcfe. If we have to post cash collateral to meet our obligations under such arrangements, our cash otherwise available for use in our operations would be reduced.

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Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

        The process of estimating natural gas and oil reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect our estimated quantities and present value of our reserves.

        In order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary.

        The process also requires economic assumptions about matters such as natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

        Actual future production, natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust our reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control.

        You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated natural gas reserves. We generally base the estimated discounted future net cash flows from our reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

Our identified potential well locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill our potential well locations.

        Our management team has specifically identified and scheduled certain well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas and oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other potential well locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

        As of December 31, 2013, we had 4,778 identified potential horizontal well locations. As a result of the limitations described above, we may be unable to drill many of our potential well locations. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations. For more information on our identified potential well

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locations, see "Item 1. Business and Properties—Our Properties and Operations—Estimated Proved Reserves—Identification of Potential Well Locations."

Approximately 92% of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.

        Approximately 92% of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. In addition, approximately 49% and 80% of our natural gas leases related to our Marcellus and Utica acreage, respectively, require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

Our producing properties are concentrated in the Appalachian Basin, making us vulnerable to risks associated with operating in one major geographic area.

        Our producing properties are geographically concentrated in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. At December 31, 2013, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs.

Insufficient processing or takeaway capacity in the Appalachian Basin could cause significant fluctuations in our realized natural gas and NGL prices.

        The Appalachian Basin natural gas and NGL business environment has historically been characterized by periods during which production has surpassed local processing and takeaway capacity, resulting in substantial discounts in the price received. Although additional Appalachian Basin takeaway capacity has been added in 2012 and 2013, we do not believe the existing and expected capacity will be sufficient to keep pace with the increased production caused by accelerated drilling in the area. For example, in the past we have experienced capacity constraints in the Marcellus Shale due to delays in the completion of third-party gathering and compression infrastructure.

        If we are unable to secure additional gathering, compression and processing capacity and long-term firm takeaway capacity on major pipelines that are in existence or currently under construction in our core operating area to accommodate our growing production and to manage basis differentials, it could have a material adverse effect on our financial condition and results of operations.

We may incur losses as a result of title defects in the properties in which we invest.

        It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. Leases in the Appalachian Basin are particularly vulnerable to title deficiencies due the long history of land ownership in the area, resulting in extensive and complex chains of title. Additionally, there are claims against us alleging that certain acquired leases that are held by production are invalid due to

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production from the producing horizons being insufficient to hold title to the formation rights that we have purchased. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we do typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

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, 2013, 73% of our total estimated proved reserves were classified as proved undeveloped. Our approximately 5.6 Tcfe of estimated proved undeveloped reserves will require an estimated $5.3 billion of development capital over the next five years. Moreover, the development of probable and possible reserves will require additional capital expenditures and such reserves are less certain to be recovered than proved reserves. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties.

        Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A writedown constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

        Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploitation, development and exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future natural gas reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

Conservation measures and technological advances could reduce demand for oil and natural gas.

        Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation

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devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our derivative activities could result in financial losses or could reduce our earnings.

        To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of natural gas, we enter into derivative instrument contracts for a significant portion of our natural gas production, including fixed-price swaps. As of December 31, 2013, we had entered into hedging contracts through December 31, 2019 covering a total of approximately 1.255 Tcfe of our projected natural gas and oil production at a weighted average price of $4.61 per Mcfe. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

        Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

        The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates.

        As of December 31, 2013, the estimated fair value of our commodity derivative contracts was approximately $860 million. Any default by the counterparties to these derivative contracts when they become due would have a material adverse effect on our financial condition and results of operations. The fair value of our commodity derivative contracts at December 31, 2013 includes the following values by bank counterparty: BNP Paribas—$197 million; Credit Suisse—$190 million; Barclays—$147 million; Wells Fargo—$140 million; JP Morgan—$134 million; Citigroup—$34 million; Deutsche Bank—$15 million; and Toronto Dominion Bank—$3 million. The credit ratings of certain of these banks have been downgraded because of the sovereign debt crisis in Europe.

        In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for natural gas, which could also have an adverse effect on our financial condition.

Our hedging transactions expose us to counterparty credit risk.

        Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty's liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.

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The inability of our significant customers to meet their obligations to us may adversely affect our financial results.

        In addition to credit risk related to receivables from commodity derivative contracts, our principal exposures to credit risk are through joint interest receivables ($31 million at December 31, 2013) and the sale of our natural gas production ($97 million in receivables at December 31, 2013), which we market to energy marketing companies, refineries and affiliates. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leased properties on which we wish to drill. We can do very little to choose who participates in our wells. We are also subject to credit risk due to concentration of our natural gas receivables with several significant customers. The largest purchaser of our natural gas during the twelve months ended December 31, 2013 purchased approximately 30% of our operated production. We do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities.

        We may incur significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our exploration, development and production activities. These delays, costs and liabilities could arise under a wide range of federal, regional, state and local laws and regulations relating to protection of the environment and worker health and safety, including regulations and enforcement policies that have tended to become increasingly strict over time resulting in longer waiting periods to receive permits and other regulatory approvals. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations.

        For example, in March 2011, we received orders for compliance from federal regulatory agencies, including the EPA, relating to certain of our activities in West Virginia. The orders allege that certain of our operations at several well sites are in non-compliance with certain environmental regulations, such as unpermitted discharges of fill material into wetlands or waters of the United States that are potentially in violation of the Clean Water Act. We have responded to all pending orders and are actively cooperating with the relevant agencies. No fine or penalty relating to these matters has been proposed at this time, but the Company believes that these actions will result in monetary sanctions exceeding $100,000. In addition, we expect to incur additional costs to remediate these well locations in order to bring them into compliance with applicable environmental laws and regulations. We have not, however, been required to suspend our operations at these locations to date and our management team does not expect these matters to have a material adverse effect on our financial condition, results of operations or cash flows.

        Strict, joint and several liabilities may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental and worker health and safety impacts of our operations. We have been named from time to time as a defendant in litigation related to such matters. For example, we have been named as the defendant in separate lawsuits in Colorado, West Virginia and Pennsylvania in which the plaintiffs have alleged that our oil and natural gas activities exposed them to hazardous substances and damaged their properties. The plaintiffs have requested unspecified damages and other injunctive or equitable relief. We are not yet able to estimate what our aggregate exposure for monetary or other damages resulting from these or other similar claims might be. Also, new laws, regulations or enforcement policies could be more

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stringent and impose unforeseen liabilities or significantly increase compliance costs. If we were not able to recover the resulting costs through insurance or increased revenues, our business, financial condition or results of operations could be adversely affected.

We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

        We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.

        Our natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing natural gas, including the possibility of:

        Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

        We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

We may be limited in our ability to choose gathering operators and processing and fractionation services providers in our areas of operations pursuant to the agreements we will enter into with Antero Midstream.

        Pursuant to the gas gathering and compression agreement that we intend to enter into with Antero Midstream, we will dedicate the gathering and compression of all of our current and future natural gas production in West Virginia, Ohio and Pennsylvania to Antero Midstream, so long as such production is not otherwise subject to a pre-existing dedication. Further, pursuant to the right of first offer that we intend to enter into with Antero Midstream, Antero Midstream will have a right to bid to provide certain processing and fractionation services in respect of all of our current and future gas production

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(as long as it is not subject to a pre-existing dedication) and will be entitled to provide such services if its bid matches or is more favorable to us than terms proposed by other parties. As a result, we will be limited in our ability to use other gathering operators in West Virginia, Ohio and Pennsylvania, even if such operators are able to offer us more favorable pricing or more efficient service. We will also be limited in our ability to use other processing and fractionation services providers in any area to the extent Antero Midstream is able to offer a competitive bid.

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

        Properties that we decide to drill that do not yield natural gas or oil in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield natural gas or oil in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether natural gas or oil will be present or, if present, whether natural gas or oil will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

        In the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

        The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

        In addition, our revolving credit facility and the indentures governing our senior notes impose certain limitations on our ability to enter into mergers or combination transactions. Our revolving credit facility and the indentures governing our senior notes also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

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Market conditions or operational impediments may hinder our access to natural gas and oil markets or delay our production.

        Market conditions or the unavailability of satisfactory natural gas and oil transportation arrangements may hinder our access to natural gas and oil markets or delay our production. The availability of a ready market for our natural gas and oil production depends on a number of factors, including the demand for and supply of natural gas and oil and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of natural gas and oil pipeline or gathering system capacity. In addition, if natural gas or oil quality specifications for the third-party natural gas or oil pipelines with which we connect change so as to restrict our ability to transport natural gas or oil, our access to natural gas and oil markets could be impeded. If our production becomes shut in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

        Our natural gas exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations.

        Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production and transportation of, natural gas. Failure to comply with such laws and regulations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations.

        Changes to existing or new regulations may unfavorably impact us, could result in increased operating costs and have a material adverse effect on our financial condition and results of operations. Such potential regulations could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which could in turn have a material adverse effect on our financial condition, results of operations and cash flows.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

        The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

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A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

        Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by the FERC as a natural gas company under the NGA. Although the FERC has not made any formal determinations with respect to any of our facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to regulation as a natural gas company. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by FERC, the courts or Congress.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

        Under the EP Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our systems have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.

Climate change laws and regulations restricting emissions of "greenhouse gases" could result in increased operating costs and reduced demand for the oil and natural gas that we produce while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

        In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. 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. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations. While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. 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

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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. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

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 into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; however, to date, the agency has not yet taken any action to do so. Furthermore, in April 2012, the EPA adopted regulations requiring the reduction of volatile organic compound emissions from oil and natural gas production facilities by mandating the use of "green completions" for hydraulic fracturing activities. These regulations require the operator to recover rather than vent gas and natural gas liquids that return to the surface during well completion operations. 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. 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. 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.

        In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released in December 2012 and a draft final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by late 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards at some point in 2014. In addition, the U.S. Department of the Interior published a revised proposed rule in May 2013 that would implement updated requirements for hydraulic fracturing activities on federal

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lands, including new requirements relating to public disclosure, well bore integrity and handling of flowback water. 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, and could ultimately make it more difficult or costly for us to perform hydraulic fracturing activities and increase our costs of compliance and doing business.

Competition in the natural gas industry is intense, making it more difficult for us to acquire properties, market natural gas and secure trained personnel.

        Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past three years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

Terrorist or cyber-attacks and threats could have a material adverse effect on our business, financial condition or results of operations.

        Terrorist or cyber-attacks may significantly affect the energy industry, including our operations and those of our customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

The loss of senior management or technical personnel could adversely affect operations.

        We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel, including Paul M. Rady, our Chairman and Chief Executive Officer, and Glen C. Warren, Jr., our President and Chief Financial Officer, could have a material adverse effect on our business, financial condition and results of operations.

Seasonal weather conditions and regulations related to the protection of wildlife adversely affect our ability to conduct drilling activities in some of the areas where we operate.

        Natural gas operations in our operating areas can be adversely affected by seasonal weather conditions and regulations designed to protect various wildlife. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

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We have been an early entrant into new or emerging plays. As a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.

        While our costs to acquire undeveloped acreage in new or emerging plays have generally been less than those of later entrants into a developing play, our drilling results in these areas are more uncertain than drilling results in areas that are developed and producing. Since new or emerging plays have limited or no production history, we are unable to use past drilling results in those areas to help predict our future drilling results. As a result, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.

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 2013, we had estimated average outstanding borrowings under our revolving credit facility of approximately $600 million, and the impact of a 1.0% increase in interest rates on this amount of indebtedness would result in increased interest expense for that period of approximately $6 million and a corresponding decrease in our net income before the effects of income taxes. In addition, an increase in interest rates could result in our failure to complete the proposed initial public offering of our midstream business on the terms currently contemplated, or at all, a decrease in the proceeds we receive from the offering or a decrease in the value of the limited partnership interests we retain upon completion of the offering. 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.

We may be subject to risks in connection with acquisitions of properties.

        The successful acquisition of producing properties requires an assessment of several factors, including:

        The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an "as is" basis.

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Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, and additional state taxes on natural gas extraction may be imposed, as a result of future legislation.

        The Fiscal Year 2014 Budget proposed by the President of the United States recommends the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies, and legislation has been introduced in Congress that would implement many of these proposals. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities for oil and gas production; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective.

        The passage of this legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to natural gas and oil exploration and development, and any such change could negatively affect our financial condition and results of operations.

        In December 2013, the Ohio State House introduced a proposal to introduce a severance tax on production from horizontally fractured wells at a rate of 1 percent of the net value for the first five years. After that period, the rate would increase to 2 percent for high-producing wells, though the rate decreases to 1 percent when production declines. It is unclear whether this or any similar Ohio legislation will be enacted or when such legislation could be made effective.

Item 1B.    Unresolved Staff Comments

        Not applicable.

Item 3.    Legal Proceedings

        We are party to various legal proceedings and claims in the ordinary course of our business. We believe certain of these matters will be covered by insurance and that the outcome of other matters will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.

        In March 2011, we received orders for compliance from federal regulatory agencies, including the EPA, relating to certain of our activities in West Virginia. The orders allege that certain of our operations at several well sites are in non-compliance with certain environmental regulations, such as unpermitted discharges of fill material into wetlands or waters of the United States that are potentially in violation of the Clean Water Act. We paid a fine of $102,795 in December 2013 to resolve this matter. In addition, we expect to incur additional costs to remediate these well locations in order to bring them into compliance with applicable environmental laws and regulations. We have not, however, been required to suspend our operations at these locations to date and our management team does not expect these matters to have a material adverse effect on our financial condition, results of operations or cash flows.

Item 4.    Mine Safety Disclosures

        Not applicable.

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PART II

Item 5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Common Stock

        We have one class of common shares outstanding, our par value $0.01 per share Common Stock ("Common Stock"). Our Common Stock is traded on the New York Stock Exchange under the symbol "AR". On February 20, 2014, our Common Stock was held by 2 holders of record. The number of holders does not include the shareholders for whom shares are held in a "nominee" or "street" name.

        The table below reflects the high and low intraday sales prices per share of the Common Stock on the New York Stock Exchange from October 10, 2013, the date the shares were first traded, through December 31, 2013. On February XX, 2014, the closing price of our Common Stock was $XX.

 
  Common Stock  
 
  High   Low  

For the period from October 10, 2013 through December 31, 2013

  $ 63.15   $ 51.56  

Use of Proceeds

        On October 16, 2013, we completed the initial public offering of common stock. The offering was comprised of an aggregate of 41,083,750 shares of common stock at $44.00 per share, which included 3,409,091 shares of common stock sold by the selling stockholder and 1,949,659 shares of common stock sold by us pursuant to the exercise in full by the underwriters of their option to purchase additional shares of common stock. Barclays, Citigroup, J.P. Morgan, Credit Suisse, Jefferies and Wells Fargo Securities acted as joint book running managers of the offering.

        The gross proceeds of the IPO were approximately $1.8 billion. After subtracting (i) the net proceeds to the selling stockholders of approximately $143.3 million, (ii) underwriting discounts of approximately $81.4 million (approximately $74.6 million of which were paid by us and $6.8 million of which were paid by the selling stockholder) and (iii) offering expenses of approximately $5.0 million, we received net proceeds of approximately $1.6 billion.

        We used approximately $1.43 billion of the net proceeds to repay outstanding borrowings under our revolving credit facility and approximately $150 million to redeem $140 million aggregate principal amount of our outstanding 7.25% senior notes due 2019.

Recent Sales of Unregistered Securities

        On October 16, 2013, in connection with a corporate reorganization that was completed immediately prior to the closing of our initial public offering, Antero Resources LLC merged with and into Antero Resources Corporation pursuant to a merger agreement by and among Antero Resources LLC, Antero Resources Investment LLC and Antero Resources Corporation whereby, (a) Antero Resources LLC merged with and into Antero Resources Corporation, with Antero Resources Corporation surviving the merger, (b) all of the membership interests of Antero Resources LLC held by Antero Resources Investment LLC converted into 224,375,000 shares of outstanding common stock of Antero Resources Corporation, and (c) the membership interest in Antero Resources Investment LLC held by Antero Resources LLC was cancelled. The foregoing was undertaken in reliance upon an exemption from the registration requirements of the Securities Act by Section 4(a)(2) thereof.

        Immediately after the reorganization and our initial public offering, Antero Resources Investment LLC ("Antero Investment") owned approximately 84.3% of our outstanding common stock.

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Dividend Restrictions

        Our ability to pay dividends is governed by (i) the provisions of Delaware corporation law, (ii) our Certificate of Incorporation and Bylaws, (iii) indentures related to Antero's 7.25% senior notes due 2019, 6.00% senior notes due 2020, and 5.375% senior notes due 2021, and (iv) our revolving credit facility. We have not paid or declared any dividends on its Common Stock. The future payment of cash dividends on the Common Stock, if any, is within the discretion of the Board of Directors and will depend on our earnings, capital requirements, financial condition, and other relevant factors. There is no assurance that we will pay any cash dividends on our Common Stock. We do not anticipate declaring or paying any cash dividends to holders of our Common Stock in the foreseeable future.

Stock Performance Graph

        The graph below shows the cumulative total shareholder return assuming the investment of $100 on October 10, 2013 in each of Antero Common Stock, the S&P 500 Index, and the Dow Jones U.S. Exploration and Production Index. We believe the Dow Jones U.S. Exploration and Production Index is meaningful because it is an independent, objective view of the performance of similarly-sized energy companies.


Comparison of Cumulative Return Among Antero Resources Corporation, the S&P 500
Index, and the Dow Jones US Exploration & Production Index

GRAPHIC

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Item 6.    Selected Financial Data

        The following table shows our selected historical consolidated financial data, for the periods and as of the dates indicated, for Antero Resources Corporation and its subsidiary.

        The selected statement of operations data for the years ended December 31, 2011, 2012 and 2013 and the balance sheet data as of December 31, 2012 and 2013 are derived from our audited consolidated financial statements included in Item 8 of this Annual Report on Form 10-K. The selected statement of operations data for the years ended December 31, 2009 and 2010 and the balance sheet data as of December 31, 2009, 2010, and 2011 are derived from our audited consolidated financial statements not included in Item 8 of this Annual Report on Form 10-K.

        The statement of operations data for all periods presented has been recast to present the results of operations from our Piceance Basin and Arkoma Basin operations in discontinued operations. The losses on the sales of these properties are also included in discontinued operations in 2012. The results from continuing operations reflect our remaining operations in the Appalachian Basin. No part of our general and administrative expenses or interest expense was allocated to discontinued operations.

        The selected financial data presented below are qualified in their entirety by reference to, and should be read in conjunction with, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and related notes included elsewhere in this report.

 
  Year Ended December 31,  
(in thousands, except ratios)
  2009   2010   2011   2012   2013  

Statement of operations data:

                               

Operating revenues:

                               

Natural gas sales

  $ 2,252   $ 47,392   $ 195,116   $ 259,743   $ 689,198  

NGL sales

                3,719     111,663  

Oil sales

        39     173     1,520     20,584  

Commodity derivative fair value gains

    3,910     77,599     496,064     179,546     491,689  

Gain on sale of assets

                291,190      
                       

Total revenues

    6,162     125,030     691,353     735,718     1,313,134  
                       

Operating expenses:

                               

Lease operating

    28     1,158     4,608     6,243     9,439  

Gathering, compression, processing, and transportation

    421     9,237     37,315     91,094     218,428  

Production and ad valorem taxes

    128     2,885     11,915     20,210     50,481  

Exploration

    2,095     2,350     4,034     14,675     22,272  

Impairment of unproved properties

    100     6,076     4,664     12,070     10,928  

Depletion, depreciation, and amortization

    1,706     18,522     55,716     102,026     233,876  

Accretion of asset retirement obligations

        11     76     101     1,065  

Expenses related to acquisition of business

        2,544              

General and administrative (including $365,280 of stock compensation in 2013)

    20,843     21,952     33,342     45,284     425,438  

Loss on sale of compressor station

            8,700          
                       

Total operating expenses

    25,321     64,735     160,370     291,703     971,927  
                       

Operating income (loss)

    (19,159 )   60,295     530,983     444,015     341,207  
                       

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  Year Ended December 31,  
(in thousands, except ratios)
  2009   2010   2011   2012   2013  

Other expenses:

                               

Interest expense

  $ (36,053 ) $ (56,463 ) $ (74,404 ) $ (97,510 ) $ (136,617 )

Loss on early extinguishment of debt

                    (42,567 )

Interest rate derivative fair value losses

    (4,985 )   (2,677 )   (94 )        
                       

Total other expenses

    (41,038 )   (59,140 )   (74,498 )   (97,510 )   (179,184 )
                       

Income (loss) before income taxes and discontinued operations

    (60,197 )   1,155     456,485     346,505     162,023  

Income tax expense

        (939 )   (185,297 )   (121,229 )   (186,210 )
                       

Income (loss) from continuing operations

    (60,197 )   216     271,188     225,276     (24,187 )

Discontinued operations:

                               

Income (loss) from results of operations and sale of discontinued operations, net of income tax

    (45,972 )   228,412     121,490     (510,345 )   5,257  
                       

Net income (loss)

  $ (106,169 ) $ 228,628   $ 392,678   $ (285,069 ) $ (18,930 )
                       

Balance sheet data (at period end):

                               

Cash and cash equivalents

  $ 10,669   $ 8,988   $ 3,343   $ 18,989   $ 17,487  

Other current assets

    84,175     147,917     330,299     255,617     316,077  
                       

Total current assets

    94,844     156,905     333,642     274,606     333,564  

Natural gas properties, at cost (successful efforts method):

                               

Unproved properties

    596,694     737,358     834,255     1,243,237     1,513,136  

Producing properties

    1,340,827     1,762,206     2,497,306     1,682,297     3,621,672  

Fresh water distribution systems

                6,835     231,684  

Gathering systems and facilities

    185,688     85,404     142,241     168,930     584,626  

Other property and equipment

    3,302     5,975     8,314     9,517     15,757  
                       

    2,126,511     2,590,943     3,482,116     3,110,816     5,966,875  

Less accumulated depletion, depreciation, and amortization

    (322,992 )   (431,181 )   (601,702 )   (173,343 )   (407,219 )
                       

Property and equipment, net

    1,803,519     2,159,762     2,880,414     2,937,473     5,559,656  
                       

Other assets

    38,203     169,620     574,744     406,714     720,361  
                       

Total assets

  $ 1,936,566   $ 2,486,287   $ 3,788,800   $ 3,618,793   $ 6,613,581  
                       

Current liabilities

  $ 112,493   $ 152,483   $ 255,058   $ 376,296   $ 622,229  

Long-term indebtedness

    515,499     652,632     1,317,330     1,444,058     2,078,999  

Other long-term liabilities

    9,467     86,185     257,606     124,702     313,693  

Total equity

    1,299,107     1,594,987     1,958,806     1,673,737     3,598,660  
                       

Total liabilities and equity

  $ 1,936,566   $ 2,486,287   $ 3,788,800   $ 3,618,793   $ 6,613,581  
                       

Other financial data:

                               

EBITDAX from continuing operations

  $ (15,857 ) $ 27,824   $ 160,259   $ 284,710   $ 649,358  

EBITDAX from discontinued operations

    217,127     169,854     180,562     149,605      
                       

Total EBITDAX

  $ 201,270   $ 197,678   $ 340,821   $ 434,315   $ 649,358  
                       
                       

Net cash provided by operating activities

  $ 149,307   $ 127,791   $ 266,307   $ 332,255   $ 534,707  

Net cash used in investing activities

  $ (281,899 ) $ (230,672 ) $ (901,249 ) $ (463,491 ) $ (2,673,592 )

Net cash provided by financing activities

  $ 104,292   $ 101,200   $ 629,297   $ 146,882   $ 2,137,383  

Capital expenditures

  $ 281,674   $ 390,974   $ 903,422   $ 1,682,549   $ 2,671,573  

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        "EBITDAX" is a non-GAAP financial measure that we define as net income (loss) before interest expense or interest income, derivative fair value gains or losses, excluding net cash receipts or payments on derivative instruments, taxes, impairments, depletion, depreciation, amortization, exploration expense, franchise taxes, stock compensation, business acquisition and gain or loss on sale of assets. "EBITDAX," as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, our management team believes EBITDAX is useful to an investor in evaluating our financial performance because this measure:

There are significant limitations to using EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating EBITDAX reported by different companies. The following table represents a reconciliation of our net income (loss) from continuing operations to EBITDAX from continuing operations, a reconciliation of our net income (loss) from discontinued operations to EBITDAX from discontinued operations, and a reconciliation of our total EBITDAX to net cash

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provided by operating activities per our consolidated statements of cash flows, in each case for the periods presented:

 
  Year Ended December 31,  
(in thousands)
  2009   2010   2011   2012   2013  

Net income (loss) from continuing operations

  $ (60,197 ) $ 216   $ 271,188   $ 225,276   $ (24,187 )

Commodity derivative fair value gains(1)

    (3,910 )   (77,599 )   (496,064 )   (179,546 )   (491,689 )

Net cash receipts on settled derivative instruments(1)

        15,063     49,944     178,491     163,570  

Loss (gain) on sale of assets

            8,700     (291,190 )    

Interest expense, loss on early extinguishment of debt, and interest
rate derivative fair value losses

    41,038     59,140     74,498     97,510     179,184  

Provision for income taxes

        939     185,297     121,229     186,210  

Depreciation, depletion, amortization,
and accretion

    1,706     18,533     55,792     102,127     234,941  

Impairment of unproved properties

    100     6,076     4,664     12,070     10,928  

Exploration expense

    2,095     2,350     4,034     14,675     22,272  

Stock compensation expense

                    365,280  

Other

    3,311     3,106     2,206     4,068     2,849  
                       

EBITDAX from continuing operations

    (15,857 )   27,824     160,259     284,710     649,358  
                       

Net income (loss) from discontinued operations

    (45,972 )   228,412     121,490     (510,345 )   5,257  

Commodity derivative fair value gains(1)

    (51,455 )   (166,685 )   (180,130 )   (46,358 )    

Net cash receipts on settled derivative instruments(1)

    116,550     58,650     66,654     92,166      

(Gain) loss on sale of assets

        (147,559 )       795,945     (8,506 )

Provision (benefit) for income taxes

    (2,605 )   29,070     45,155     (272,553 )   3,249  

Depreciation, depletion, amortization,
and accretion

    138,372     115,739     115,164     89,124      

Impairment of unproved properties

    54,104     29,783     6,387     962      

Exploration expense

    8,133     22,444     5,842     664      
                       

EBITDAX from discontinued operations

    217,127     169,854     180,562     149,605      
                       

Total EBITDAX

  $ 201,270   $ 197,678   $ 340,821   $ 434,315   $ 649,358  

Interest expense and other

    (41,038 )   (59,140 )   (74,498 )   (97,510 )   (144,422 )

Exploration expense

    (10,228 )   (24,794 )   (9,876 )   (15,339 )   (22,272 )

Changes in current assets and current liabilities

    (2,648 )   (698 )   8,309     9,887     41,914  

Other

    1,951     14,745     1,551     902     10,129  
                       

Net cash provided by operating activities

  $ 149,307   $ 127,791   $ 266,307   $ 332,255   $ 534,707  
                       
                       

(1)
The adjustments for the derivative fair value (gains) losses and net cash receipts on settled commodity derivative instruments have the effect of adjusting net income (loss) from continuing operations for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses on a cash basis during the period the derivatives settled.

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Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations

        The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this report. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in natural gas, NGL and oil prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See "Cautionary Statement Regarding Forward-Looking Statements." Also, see the risk factors and other cautionary statements described under the heading "Item 1A. Risk Factors." We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

        In this section, references to "Antero," "Antero Resources," "we," "us," "our," and "operating entities" refer to the subsidiaries that conduct our operations, unless otherwise indicated or the context otherwise requires.

Our Company

        We are an independent oil and natural gas company engaged in the exploitation, development and acquisition of natural gas, NGLs and oil properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. We are focused on creating shareholder value through the development of our large portfolio of repeatable, low cost, liquids-rich drilling opportunities in two of the premier North American shale plays. As of December 31, 2013, we held approximately 345,000 net acres in the southwestern core of the Marcellus Shale and approximately 105,000 net acres in the core of the Utica Shale. In addition, we estimate that approximately 180,000 net acres of our Marcellus Shale leasehold are prospective for the slightly shallower Upper Devonian Shale. Finally, we own the deep rights on approximately 126,000 net acres of our Marcellus Shale acreage in West Virginia that we believe is prospective for the dry gas Utica Shale. As of December 31, 2013, our estimated proved reserves were 7.6 Tcfe and were 27% proved developed and 88% natural gas, assuming ethane rejection. As of December 31, 2013, our drilling inventory consisted of 4,778 identified potential horizontal well locations, approximately 68% of which are liquids-rich drilling opportunities.

        The statement of operations data for all periods presented in this "Management's Discussion and Analysis of Financial Condition and Results of Operations" has been recast to present the results of operations from our Arkoma Basin and Piceance operations in discontinued operations.

Source of Our Revenues

        Our revenues are derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from our natural gas during processing. Our production revenues derive entirely from the continental United States. During 2013 our revenues from production were comprised of approximately 84% from the sale of natural gas and 16% from the sale of NGLs and oil. Natural gas, NGL, and oil prices are inherently volatile and are influenced by many factors outside of our control. All of our production is derived from natural gas wells, some of which also produce NGLs, after processing, and limited quantities of oil. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we use derivative instruments to hedge future sales prices on

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a significant portion of our natural gas production. We currently use fixed price natural gas swaps in which we receive a fixed price for future production in exchange for a payment of the variable market price received at the time future production is sold. At the end of each period we estimate the fair value of these swaps and, because we have not elected hedge accounting, we recognize the changes in the fair value of unsettled commodity derivative instruments in earnings at the end of each accounting period. We expect continued volatility in the fair value of these swaps.

Principal Components of Our Cost Structure

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Results of Operations

Year Ended December 31, 2012 Compared to Year Ended December 31, 2013

        The following table sets forth selected operating data (as recast for discontinued operations) for the year ended December 31, 2012 compared to the year ended December 31, 2013:

 
  Year Ended
December 31,
   
   
 
 
  Amount
of
Increase
(Decrease)
   
 
 
  Percent
Change
 
(in thousands, except per unit data)
  2012   2013  

Operating revenues:

                         

Natural gas sales

  $ 259,743   $ 689,198   $ 429,455     165 %

NGL sales

    3,719     111,663     107,944     2,903 %

Oil sales

    1,520     20,584     19,064     1,254 %

Commodity derivative fair value gains

    179,546     491,689     312,143     174 %

Gain on sale of assets

    291,190         (291,190 )     *
                     

Total operating revenues

    735,718     1,313,134     577,416     78 %
                     

Operating expenses:

                         

Lease operating

    6,243     9,439     3,196     51 %

Gathering, compression, processing and transportation

    91,094     218,428     127,334     140 %

Production and ad valorem taxes

    20,210     50,481     30,271     150 %

Exploration

    14,675     22,272     7,597     52 %

Impairment of unproved properties

    12,070     10,928     (1,142 )   (9 )%

Depletion, depreciation, and amortization

    102,026     233,876     131,850     129 %

Accretion of asset retirement obligations

    101     1,065     964     954 %

General and administrative (before stock compensation)

    45,284     60,158     14,874     33 %

Stock compensation

        365,280     365,280       *
                     

Total operating expenses

    291,703     971,927     680,224       *
                     

Operating income

    444,015     341,207     (102,808 )     *
                     

Other expenses:

                         

Interest expense

  $ (97,510 ) $ (136,617 ) $ 39,107     40 %

Loss on early extinguishment of debt

        (42,567 )   42,567       *
                     

Total other expenses

    (97,510 )   (179,184 )   81,674     84 %
                     

Income before income taxes and discontinued operations

    346,505     162,023     (184,482 )     *

Income taxes expense

    (121,229 )   (186,210 )   (64,981 )   54 %
                     

Income from continuing operations

    225,276     (24,187 )   (249,463 )     *

Income (loss) from discontinued operations

    (510,345 )   5,257     515,602       *
                     

Net income (loss)

  $ (285,069 ) $ (18,930 ) $ 266,139       *
                     

EBITDAX from continuing operations(1)

  $ 284,710   $ 649,358   $ 364,648     128 %

EBITDAX from discontinued operations(1)

    149,605         (149,605 )     *
                     

Total EBITDAX(1)

  $ 434,315   $ 649,358   $ 215,043     50 %
                     
                     

Production data:

                         

Natural gas (Bcf)

    87     177     90     103 %

NGLs (MBbl)

    71     2,123     2,052     2,872 %

Oil (MBbl)

    19     226     207     1,094 %

Combined (Bcfe)

    87     191     104     119 %

Daily combined production (MMcfe/d)

    239     522     283     119 %

Average sales prices before effects of cash settled derivatives(2):

                         

Natural gas (per Mcf)

  $ 2.99   $ 3.90   $ 0.91     30 %

NGLs (per Bbl)

  $ 52.07   $ 52.61   $ 0.54     1 %

Oil (per Bbl)

  $ 80.34   $ 91.27   $ 10.93     14 %

Combined (per Mcfe)

  $ 3.03   $ 4.31   $ 1.28     42 %

Average realized sales prices after effects of cash settled derivatives(2):

                         

Natural gas (per Mcf)

  $ 5.05   $ 4.82   $ (0.23 )   (5 )%

NGLs (per Bbl)

  $ 52.07   $ 52.61   $ 0.54     1 %

Oil (per Bbl)

  $ 80.34   $ 99.06   $ 18.72     23 %

Combined (per Mcfe)

  $ 5.08   $ 5.17   $ 0.09     2 %

Average costs (per Mcfe):

                         

Lease operating

  $ 0.07   $ 0.05   $ (0.02 )   (29 )%

Gathering compression, processing, and transportation

  $ 1.04   $ 1.15   $ 0.11     11 %

Production taxes

  $ 0.23   $ 0.26   $ 0.03     13 %

Depletion, depreciation, amortization, and accretion

  $ 1.17   $ 1.23   $ 0.06     5 %

General and administrative(3)

  $ 0.52   $ 0.32   $ (0.20 )   (38 )%

(1)
See "Item 6. Selected Financial Data" included elsewhere in this report for a definition of EBITDAX (a non-GAAP measure) and a reconciliation of EBITDAX to net income (loss).

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(2)
Average sales prices shown in the table reflect both of the before and after effects of our cash settled derivatives. Our calculation of such after effects includes realized gains or losses on cash settlements for commodity derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes. Oil and NGL production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts. This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value.

(3)
Does not include noncash stock compensation in 2013.

*
Not meaningful or applicable.

        Natural gas, NGLs, and oil sales.    Combined revenues from production of natural gas, NGLs, and oil increased from $265 million for the year ended December 31, 2012 to $821 million for the year ended December 31, 2013, an increase of $556 million, or 210%. Our production increased by 119% from 87 Bcfe, or 239 MMcfe per day, in 2012 to 191 Bcfe, or 522 MMcfe per day, in 2013. Increased production volumes increased revenues by $313 million, or 118%, (calculated as the increase in year-to-year volumes times the prior year average price), and combined commodity price increases accounted for a $243 million, or 92% increase in revenues (calculated as the change in year-to-year average combined price times current year production volumes).

        Commodity derivative fair value gains.    To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we enter into derivative contracts using fixed for variable swap contracts when management believes that favorable future sales prices for our natural gas and oil production can be secured. Because we do not designate these derivatives as accounting hedges, they do not receive accounting hedge treatment, and all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our results of operations. For the years ended December 31, 2012 and 2013, our hedges resulted in derivative fair value gains of $180 million and $492 million, respectively. The derivative fair value gains included $178 million and $164 million of cash settlements received on derivatives for the years ended December 31, 2012 and 2013, respectively. Commodity derivative fair value gains or losses will vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled. We expect continued volatility in the fair value of our derivative instruments.

        Gain on sale of Appalachian gathering assets.    On March 26, 2012, we closed the sale of a portion of our Marcellus Shale gathering system assets along with exclusive rights to gather and compress our gas for a 20-year period within an area of dedication ("AOD") to a joint venture owned by Crestwood Midstream Partners and Crestwood Holdings Partners LLC (together, "Crestwood") for $375 million (excluding customary purchase price adjustments). The sale included approximately 25 miles of low pressure pipeline systems and gathering rights on 104,000 net acres held by us within a 250,000 acre AOD and had an effective date of January 1, 2012. Other third-party producers will also have access to the Crestwood system. During the first seven years of the contract, we are committed to deliver minimum volumes into the gathering systems, with certain carryback and carryforward adjustments for overages or deficiencies. We can earn up to an additional $40 million of sale proceeds if we meet certain volume thresholds over the first three years of the contract. Crestwood is obligated to incur all future capital costs to build out gathering systems and compression facilities within the AOD to connect our wells as we execute our drilling program and has assumed the various risks and rewards of the system build-out and operations. Because we have not retained the substantial risks and rewards of ownership associated with the gathering rights and systems transferred to Crestwood, we have recognized a gain on the sale of the gathering system and gathering rights of approximately $291 million.

        Lease operating expenses.    Lease operating expenses increased from $6 million for the year ended December 31, 2012 to $9 million in 2013, primarily as a result of increased production. On a per-Mcfe basis, lease operating expenses decreased by 29%, from $0.07 per Mcfe in 2012 to $0.05 per Mcfe in 2013 primarily because of costs increasing at a lower rate than production. Because our Appalachian Basin properties are in an early stage of production, production rates are high and per unit lease

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operating expenses are relatively low. Lease operating expenses are expected to increase on a per unit basis as the properties mature and production declines on a per well basis.

        Gathering, compression, processing, and transportation expense.    Gathering, compression, processing, and transportation expense increased from $91 million for the year ended December 31, 2012 to $218 million in 2013. The increase in these expenses resulted from the increase in production, firm transportation commitments, and third-party compression and gathering expenses. On a per-Mcfe basis, total gathering, compression, processing and transportation expenses increased from $1.04 per Mcfe for 2012 to $1.15 in 2013 due to additional processing costs and firm transportation commitments.

        Production and ad valorem tax expense.    Total production taxes increased from $20 million for the year ended December 31, 2012 to $50 million for the year ended December 31, 2013, primarily as a result of increased production. Production taxes as a percentage of natural gas, NGLs, and oil revenues before the effects of hedging were 7.6% for the year ended December 31, 2012 compared to 6.1% for the year ended December 31, 2013. Production taxes decreased as a percentage of revenues as production increased in Ohio, which has a lower severance tax rate than West Virginia, and per unit taxes also decreased as a percentage of revenues as prices increased. Ad valorem taxes increased because of the construction of the water distribution assets. Legislative proposals in the State of Ohio to increase severance taxes on production from horizontally fractured wells could increase our future production tax rates, if such legislation is enacted.

        Exploration expense.    Exploration expense increased from $15 million for the year ended December 31, 2012 to $22 million for the year ended December 31, 2013 primarily because of an increase in the cost of unsuccessful lease acquisition efforts as we materially increased the number of contract lease brokers providing services to us in the Appalachian Basin.

        Impairment of unproved properties.    Impairment of unproved properties was approximately $12 million for the year ended December 31, 2012 compared to $11 million for the year ended December 31, 2013. We charge impairment expense for expired or soon-to-be expired leases when we determine they are impaired through lack of drilling activities or based on other factors, such as remaining lease terms, reservoir performance, commodity price outlooks or future plans to develop the acreage and recognize impairment costs accordingly.

        DD&A.    DD&A increased from $102 million for the year ended December 31, 2012 to $234 million for the year ended December 31, 2013, an increase of $132 million, as a result of increased production in 2013 compared to 2012. DD&A per Mcfe increased 5%, from $1.17 per Mcfe during 2012 to $1.23 per Mcfe during 2013 as a result of increased depreciation on gathering and water systems and facilities and increased proved property costs subject to depletion.

        We evaluate the impairment of our proved natural gas, NGLs, and oil properties on a field-by-field basis whenever events or changes in circumstances indicate that a property's carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we reduce the carrying amount of the oil and gas properties to their estimated fair value. There were no impairment expenses recorded for the years ended December 31, 2012 or 2013 for proved properties. As of December 31, 2013, no significant exploratory well costs had been deferred for over one year pending proved reserves determination.

        General and administrative expense.    General and administrative expense (before stock compensation) increased from $45 million for the year ended December 31, 2012 to $60 million during 2013, an increase of $15 million. The increase is due to increased costs related to salaries, employee benefits, contract personnel and other general business expenses required to support the growth of our capital expenditure program and production levels. The number of our full-time employees grew from 150 at December 31, 2012 to 233 at December 31, 2013. On a per-Mcfe basis, general and

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administrative expense (before stock compensation) decreased by 38%, from $0.52 per Mcfe during the year ended December 31, 2012 to $0.32 per Mcfe during 2013 primarily due to a 119% growth in production. No portion of general and administrative expenses was allocated to discontinued operations as we did not expect any reduction of such expenses as a result of the sale of the Arkoma and Piceance properties. When all discontinued operations are included, general and administrative expenses were $0.37 per Mcfe in 2012.

        In 2013, we recognized noncash stock compensation expense of approximately $365 million, almost all of which was related to the interests of our employees in Antero Employee Holdings LLC ("Employee Holdings"), which owns interests in Antero Investment LLC ("Antero Investment"). Prior to our IPO, the interests of Employee Holdings were subject to performance and service conditions which could be met generally only in the event of a liquidation or distribution event. In connection with our IPO, the terms of the Antero Investment operating agreement provided for a mechanism by which the shares of our common stock to be allocated amongst the members of Antero Investment, including Employee Holdings, will be specifically determined. As a result, the satisfaction of all performance and service conditions relative to the membership interests of Employee Holdings in Antero Investment became probable. Accordingly, we recognized approximately $365 million of stock compensation expense in 2013 relative to these interests and will recognize approximately another $121 million over the remaining expected service period. The stock compensation relative to these interests is treated as a capital contribution from Antero Investment in our financial statements and is not deductible for Federal or state income tax purposes in 2013 or in the future.

        Interest expense and loss on early extinguishment of debt.    Interest expense increased from $98 million for the year ended December 31, 2012 to $137 million for the year ended December 31, 2013, an increase of $39 million as a result of an increase in the amount of senior notes outstanding and the average balance of the revolving credit facility outstanding during 2013 compared to 2012. During 2013, we incurred a loss of $43 million on the early extinguishment of debt resulting from (i) the retirement of $140 million of the 7.25% senior notes due 2019 from the proceeds of our IPO and (ii) the retirement of the 9.375% senior notes due 2017 having a principal amount of $525 million from the proceeds of the issuance of the 5.375% notes due 2021. The loss of $43 million is comprised of redemption premiums of $35 million and the write-off of deferred financing costs and unamortized premium and discounts of $8 million.

        Income tax expense.    Income tax expense related to continuing operations was $186 million (84% of pre-tax income) in 2013 compared to $121 million (35% of pre-tax income) in 2012. Income tax expense increased from 35% of pre-tax income to 115% of pre-tax income because the stock compensation expense recognized in 2013, related to the allocation of shares among the members of Antero Investment and Employee Holdings, is a nondeductible permanent difference between our taxable income and income recognized for financial statements. Although we have accrued $11 million at December 31, 2013 for unrecognized tax benefits, no taxes were due at the end of either December 31, 2012 or 2013. We have not generated current taxable income in either the current or prior years, which is primarily attributable to the differing book and tax treatment of unrealized derivative gains and intangible drilling costs. At December 31, 2013, we had approximately $1.2 billion of U.S. federal and state net operating loss carryforwards, which expire starting in 2024 and continue through 2033. At December 31, 2013, we recorded valuation allowances of approximately $27 million for deferred tax assets primarily related to state loss carryforwards in states where we no longer operate. From time to time there has been proposed legislation in the U.S. Congress to delay or limit future deductions for intangible drilling costs; such legislation could significantly affect our future taxable position if passed. The impact of any change will be recorded in the period that such legislation might be enacted.

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        The calculation of our tax liabilities involves uncertainties in the application of complex tax laws and regulations. We give financial statement recognition to those tax positions that we believe are more-likely-than-not to be sustained upon examination by the Internal Revenue Service or state revenue authorities. The financial statements include unrecognized benefits at December 31, 2013 of $11 million that, if recognized, would result in a reduction of current income taxes payable and an increase in noncurrent deferred tax liabilities. No impact to our 2013 effective tax rate would result. As of December 31, 2013, approximately $0.5 million of interest has been accrued on unrecognized tax benefits.

        The tax returns of Antero Resources Finance Corporation (which was merged with the Antero Resources Corporation in December 2013) are being examined by the Internal Revenue Service for its tax years 2011 and 2012. The Company's state tax returns are being examined by West Virginia taxing authorities for tax years 2010 through 2012. The Company does not expect any material adjustments to tax liabilities will result from either the federal or the state examination.

        Income (loss) from discontinued operations.    Income (loss) from discontinued operations includes the results of operations from the Arkoma Basin and Piceance Basin operations (including revenues and direct operating expenses and allocated income tax expense, but not general and administrative or interest expenses) and, in 2012, the loss on the sale of these assets. A detailed analysis of these operations is included in note 3 to the consolidated financial statements included elsewhere in this report. Income (loss) from discontinued operations was $(510) million in 2012, primarily as a result of the loss on the sale of the properties of $796 million and a $273 million tax benefit from the loss. Income from discontinued operations of $5 million in 2013 resulted from the reduction of various liability provisions made in connection with the sale of $8 million, net of tax benefits of $3 million and final purchase price adjustments.

        EBITDAX from continuing and discontinued operations.    EBITDAX from continuing operations increased to $649 million for the year ended December 31, 2013 from $285 million for the year ended December 31, 2012, an increase of 128%. The increase in EBITDAX resulted from a 119% increase in production, a 2% increase in the average per Mcfe price received after the impact of cash settled derivatives, net of the related increases in cash operating and general and administrative expenses. EBITDAX from discontinued operations related to the Piceance and Arkoma Basin assets disposed of in 2012 was $150 million for the year ended December 31, 2012.

        Segment information.    In 2013, we have begun reporting our midstream gathering and water distribution operations as reportable segments. Prior to 2013, such operations were immaterial and

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considered ancillary to our exploration and production activities. Following is a summary of our segment information for the year ended 2013:

 
  Exploration and
production
  Gathering and
compression
  Fresh Water
distribution
  Elimination of
intersegment
transactions
  Consolidated
total
 

2013:

                               

Sales and revenues:

                               

Third-party

  $ 1,313,134                 1,313,134  

Intersegment

        22,363     35,871     (58,234 )    
                       

  $ 1,313,134     22,363     35,871     (58,234 )   1,313,134  
                       
                       

Depletion, depreciation, and amortization

  $ 220,857     11,346     2,773     (1,100 )   233,876  

Interest expense

  $ 136,453     155     9         136,617  

Income tax expense

  $ 186,210                 186,210  

Operating income(1)

  $ 335,901     8,938     27,296     (30,928 )   341,207  

Segment assets

  $ 6,580,282     561,855     230,247     (758,803 )   6,613,581  

Capital expenditures for segment assets

  $ 2,110,358     389,453     203,790     (32,028 )   2,671,573  

(1)
All general and administrative expenses are included in the exploration and production segment.

        Intracompany midstream revenues of $58 million resulted from gathering and water distribution charges as we expanded our company-operated gathering systems and began supplying water from our water pipeline and delivery infrastructure for well completions. Capital expenditures for these midstream operations totaled $593 million in 2013.

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Year Ended December 31, 2011 Compared to Year Ended December 31, 2012

        The following table sets forth selected operating data (as recast for discontinued operations) for the year ended December 31, 2011 compared to the year ended December 31, 2012:

 
  Year Ended
December 31,
   
   
 
 
  Amount
of
Increase
(Decrease)
   
 
 
  Percent
Change
 
(in thousands, except per unit data)
  2011   2012  

Operating revenues:

                         

Natural gas sales

  $ 195,116   $ 259,743   $ 64,627     33 %

NGL sales

        3,719     3,719       *

Oil sales

    173     1,520     1,347     779 %

Commodity derivative fair value gains

    496,064     179,546     (316,518 )   (63 )%

Gain on sale of assets

        291,190     291,190       *
                     

Total operating revenues

    691,353     735,718     44,365     6 %
                     

Operating expenses:

                         

Lease operating

    4,608     6,243     1,635     35 %

Gathering, compression, processing, and transportation

    37,315     91,094     53,779     144 %

Production and ad valorem taxes

    11,915     20,210     8,295     70 %

Exploration

    4,034     14,675     10,641     264 %

Impairment of unproved properties

    4,664     12,070     7,406     159 %

Depletion, depreciation, and amortization

    55,716     102,026     46,310     83 %

Accretion of asset retirement obligations

    76     101     25     33 %

General and administrative

    33,342     45,284     11,942     36 %

Loss on sale of compressor station

    8,700         (8,700 )     *
                     

Total operating expenses

    160,370     291,703     131,333     82 %
                     

Operating income

    530,983     444,015     (86,968 )   (16 )%
                     

Other expenses:

                         

Interest expense

  $ (74,404 ) $ (97,510 ) $ 23,106     31 %

Interest rate derivative fair value loss

    (94 )       (94 )     *
                     

Total other expenses

    (74,498 )   (97,510 )   23,012     31 %
                     

Income before income taxes and discontinued operations

    456,485     346,505     (109,980 )   (24 )%

Income taxes expense

    (185,297 )   (121,229 )   (64,068 )   (35 )%
                     

Income from continuing operations

    271,188     225,276     (45,912 )   (17 )%

Income (loss) from discontinued operations

    121,490     (510,345 )   (631,835 )     *
                     

Net income (loss) attributable to Antero equity owners

  $ 392,678   $ (285,069 ) $ (677,747 )   (173 )%
                     

EBITDAX from continuing operations(1)

  $ 160,259   $ 284,710   $ 124,451     78 %

EBITDAX from discontinued operations(1)

    180,562     149,605     (30,957 )   (17 )%
                     

Total EBITDAX(1)

  $ 340,821   $ 434,315   $ 93,494     27 %
                     
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