8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 OR 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): February 4, 2014

ANTERO RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	001-36120	80-0162034
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

1625 17th Street
Denver, Colorado 80202
(Address of principal executive offices) (Zip Code)

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

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.02              Results of Operations and Financial Condition.

On February 4, 2014, Antero Resources Corporation (the “Company”) issued a press release, a copy of which is attached hereto as Exhibit 99.1 and incorporated by reference herein, announcing the Company’s total proved, probable and possible reserves as of December 31, 2013.  As described below, the Company’s proved, probable and possible reserves were audited by the Company’s independent reserve engineers.

The information in this Current Report, including Exhibit 99.1, is being furnished pursuant to Item 2.02 of Form 8-K and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of that section, and is not incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act unless specifically identified therein as being incorporated therein by reference.

Item 8.01              Other Events.

As a supplement to the information in the press release described in Item 2.02, the Company is filing herewith as Exhibits 99.2 and 99.3 the reports of DeGolyer and MacNaughton, the Company’s independent reserve engineers, with respect to the audits of the Company’s proved, probable and possible reserves as of December 31, 2013.

Item 9.01        Financial Statements and Exhibits.

(d)   Exhibits.

EXHIBIT	DESCRIPTION
23.1	Consent of DeGolyer and MacNaughton.
99.1	Antero Resources Corporation press release dated February 4, 2014.
99.2	Report of DeGolyer and MacNaughton, dated as of January 15, 2014, for proved reserves as of December 31, 2013.
99.3	Report of DeGolyer and MacNaughton, dated as of January 31, 2014, for probable and possible reserves as of December 31, 2013.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	ANTERO RESOURCES CORPORATION
	By:	/s/ GLEN C. WARREN, JR.
		Glen C. Warren, Jr.
		President and Chief Financial Officer
Dated: February 7, 2014

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EXHIBIT INDEX

EXHIBIT	DESCRIPTION
23.1	Consent of DeGolyer and MacNaughton.
99.1	Antero Resources Corporation press release dated February 4, 2014.
99.2	Report of DeGolyer and MacNaughton, dated as of January 15, 2014, for proved reserves as of December 31, 2013.
99.3	Report of DeGolyer and MacNaughton, dated as of January 31, 2014, for probable and possible reserves as of December 31, 2013.

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EX-23.1

Exhibit 23.1

DEGOLYER AND MACNAUGHTON
5001 SPRING VALLEY ROAD
SUITE 800 EAST
DALLAS, TEXAS 75244

February 7, 2014

Board of Directors of Antero Resources Corporation

1625 17th Street

Denver, Colorado 80202

Gentlemen:

We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (File No. 333-191693) of Antero Resources Corporation (the “Company”) of information taken from our reports dated January 15, 2014 and January 31, 2014 with respect to the Company’s estimated proved, probable and possible reserves as of December 31, 2013.

 Very truly yours,

/s/ DeGOLYER and MacNAUGHTON

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

EX-99.1

Exhibit 99.1

Antero Reports 78% Increase in Proved Reserves to 7.6 Tcfe

·Proved reserves increased by 78% to 7.6 Tcfe and 3P reserves increased by 62% to 35.0 Tcfe at year-end 2013

·Proved developed reserves increased by 117% to 2.0 Tcfe at year-end 2013

·Replaced 1,857% of estimated production in 2013

·Achieved all-in finding and development costs of $0.58 per proved Mcfe during 2013

·Increased proved reserves pre-tax PV10 by 133% to $7.0 billion, including hedges

Denver, CO, February 4, 2014 — Antero Resources (NYSE: AR) (“Antero” or the “Company”) today announced that proved reserves at December 31, 2013 were 7.6 Tcfe, a 78% increase compared to proved reserves at December 31, 2012, in each case assuming ethane rejection.  Proved, probable and possible (“3P”) reserves at year-end 2013 totaled 35.0 Tcfe, which represents a 62% increase compared to last year, assuming ethane rejection. Antero’s December 31, 2013 proved and 3P reserves exclude 271 and 1,399 million barrels of ethane, respectively, which are not recovered in the Securities and Exchange Commission (“SEC”) price case due to the relationship between assumed ethane and methane prices at year-end 2013.

Antero replaced 1,857% of estimated production in 2013 from all sources including performance and price revisions.  Finding and development costs for proved reserve additions from all sources including costs incurred for drilling capital, acquisitions, leasehold additions and all price and performance revisions averaged $0.58 per Mcfe, based on preliminary unaudited capital expenditure amounts for 2013.  Drill-bit only finding and development costs averaged $0.45 per Mcfe for 2013.  Antero’s proved developed reserve additions totaled 1,281 Bcfe on $1.6 billion of drilling capital for a development cost of $1.25 per Mcfe in 2013.  The Company’s reserve life of its proved reserves, based on estimated 2013 production, is approximately 40 years.

Proved Reserves

Proved reserves increased by 78% to 7.6 Tcfe as of December 31, 2013.  The Marcellus Shale accounted for 95% of Antero’s proved reserve volumes at December 31, 2013 and the Utica Shale accounted for the remaining 5%.  Also at year-end 2013, 88% of Antero’s proved reserves by volume were natural gas, 11% were natural gas liquids (“NGLs”) and 1% was oil.  As of December 31, 2013, 23% of Antero’s 450,000 net acres of leasehold in the Marcellus and Utica was classified as proved.  Based on Antero’s successful drilling results to date, as well as those of other operators in the vicinity of Antero’s leasehold, the Company believes that a substantial portion of its Marcellus and Utica Shale acreage will be added to proved reserves over time as more wells are drilled.

Antero added 3.7 Tcfe of proved reserves in 2013 primarily in the Marcellus Shale.  NGLs and oil increased by 98 million barrels and 7 million barrels, respectively, due to Antero’s 2013 drilling program targeting liquids-rich locations in the Marcellus and Utica Shales.  Negative performance revisions of 157 Bcfe of proved reserves were due to the reclassification of 65 wells, or 374 Bcfe, to the probable category due to the SEC 5-year development rule partly offset by improved Marcellus well performance from SSL completions.

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Proved developed reserves increased 117% from year-end 2012 to over 2.0 Tcfe at December 31, 2013.  The Company added 113 Marcellus wells to proved developed reserves in 2013.  These wells had an average estimated ultimate recovery (“EUR”) of 10.6 Bcfe and an average lateral length of 7,308 feet.  During 2013, Antero placed on line 26 Marcellus wells using SSL completions with encouraging results.  Based on these results, Antero has increased its EUR per 1,000 feet of lateral by 18% to 1.73 Bcf for 1,768 gross SSL undeveloped 3P Marcellus locations out of the 3,067 total gross undeveloped 3P Marcellus locations, or 58%.  Included in the gross SSL undeveloped 3P Marcellus locations are 91 gross SSL locations categorized as proved undeveloped out of the 665 total gross proved undeveloped Marcellus locations, or 14%.  Antero has recently decided to complete virtually all wells in 2014 with SSL and expects further increases to the portion of gross undeveloped 3P Marcellus locations that assume SSL completions.

Antero added 11 Utica wells to the proved developed reserves category in 2013 consisting of 2 rich gas (1100-1200 BTU), 4 highly-rich gas (1200 to 1250 BTU) and 5 highly-rich/condensate (1250 to 1300 BTU) wells. The wells located in the rich gas and highly-rich gas regimes had an average EUR of 18.8 Bcfe (15% liquids) and 20.5 Bcfe (23% liquids), respectively, normalized to a 7,000’ lateral.  These EURs are consistent with previous estimates.  Additionally, the wells located in the highly-rich/condensate regime had an average EUR of 11.3 Bcfe (32% liquids), normalized to a 7,000’ lateral, representing an 18% decrease from previous estimates.  This reduction was due to lower production performance from the highly-rich/condensate wells in 2013, which were producing in a high pressure (1100 psi) environment with no compression during the year.

The Company has provided single well economics assuming the increased Marcellus SSL type curve and the updated Utica type curves in the February 2014 corporate presentation which has been posted to its website at www.anteroresources.com.

Antero’s estimate of drilling and development costs incurred during 2013, including drilling and completion of $1.6 billion and leasehold acquisition of $0.4 billion, is $2.0 billion.  Assuming the $2.0 billion estimate of drilling and development costs, preliminary finding and development costs from all sources for 2013 averaged $0.58 per Mcfe.  Three-year finding and development costs for Antero from all sources through 2013 averaged $0.55 per Mcfe, excluding the divested Arkoma and Piceance Basin properties. The 2013 capital costs are unaudited and preliminary.  Audited and final results will be provided in Antero’s Annual Report on Form 10-K for the year ended December 31, 2013.

The percentage of proved reserves classified as proved developed increased to 27% at December 31, 2013 as compared to 22% at year-end 2012.  Proved undeveloped reserves increased by 67% as a result of the successful execution of Antero’s Marcellus Shale development drilling plan.  The 67% increase was driven by the addition of 195 gross proved undeveloped drilling locations and an increase in expected recoveries in the Marcellus Shale for 91 gross proved undeveloped locations based on SSL completions.

Under SEC reporting rules, proved undeveloped reserves are limited to reserves that are planned to be developed in the next five years.  Antero’s 5.6 Tcfe of proved undeveloped reserves will require an estimated $5.3 billion of development capital over the next five years, resulting in an estimated average development cost for proved undeveloped reserves of $0.95 per Mcfe.

SEC prices for reserves calculated as of December 31, 2013 averaged $87.00 per Bbl for oil and $3.65 per MMBtu for gas, which represent the benchmark Appalachian Basin oil and natural gas price.  Using SEC prices adjusted for energy content and quality, the pre-tax present value discounted at 10% (“pre-tax PV10”) of the December 31, 2013 proved reserves was $6.0 billion, excluding the Company’s natural gas and oil hedges.  Including Antero’s hedges as of December 31, 2013 and using SEC prices, the pre-tax PV10 value of proved reserves was $7.0 billion, a 133% increase over year-end 2012.  The pre-tax PV10 value of proved developed reserves was $2.9 billion excluding hedges and $3.9 billion including current hedges.

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Summary of Changes in Proved Reserves (in Bcfe)

Balance at December 31, 2012(1)	4,283
Extensions, discoveries and additions	3,682
Purchases	—
Performance revisions	(157	)
Price revisions	15
Sales	—
Production	(191	)
Balance at December 31, 2013	7,632

(1)Excludes 646 Bcfe of ethane volumes.

Antero’s proved reserves at December 31, 2013 were prepared by its internal reserve engineers and audited by DeGolyer and MacNaughton (D&M).  D&M’s reserve audit covered properties representing over 99% of Antero’s total proved reserves at December 31, 2013 and was within 2% of Antero’s internal reserve estimates.

Proved, Probable and Possible Reserves

Antero estimates that it had year-end 2013 3P reserves of 35.0 Tcfe, a 62% increase over year-end 2012 3P reserves of 21.6 Tcfe, in each case assuming ethane rejection.  The 3P reserves contain 29.6 Tcf of natural gas, 811 million barrels of NGLs, excluding 1,339 million barrels of ethane, and 91 million barrels of oil.  The Marcellus, Utica, and Upper Devonian Shale comprised 25.0 Tcfe, 5.8 Tcfe and 4.2 Tcfe of the 3P reserves, respectively.  The 62% increase in 3P reserves was driven by the addition of 51,000 net acres in the Marcellus Shale in northern West Virginia and 28,000 net acres in the Utica Shale in southern Ohio and the implementation of SSL completions.  Importantly, 24.1 Tcfe of Antero’s 25.0 Tcfe 3P reserves in the Marcellus, or 97%, was classified as proved and probable (“2P”), reflecting the low risk nature of Antero’s Marcellus reserves.

The table below summarizes Antero’s estimated 3P reserve volumes using SEC pricing, broken out by operating area:

	Marcellus Shale						Upper Devonian Shale
	Gas (Bcf)	Liquids (MMBoe)	Total (Bcfe)			Gross Locations	Gas (Bcf)	Liquids (MMBoe)	Total (Bcfe)			Gross Locations
Proved	6,433	132	7,226			907	44	—	44			9
Probable	13,489	570	16,906			2,221	739	—	741			157
Possible	788	11	856			181	3,129	46	3,406			787
Total 3P	20,710	713	24,988			3,309	3,912	46	4,191			953
3P PV10($Bns)(1)			$	16.7					$	0.0
% Liquids(2)			17		%				7		%

	Utica Shale						Combined
	Gas (Bcf)	Liquids (MMBoe)	Total (Bcfe)			Gross Locations	Gas (Bcf)	Liquids (MMBoe)	Total (Bcfe)			Gross Locations
Proved	276	14	362			40	6,753	147	7,632			956
Probable	1,705	82	2,196			259	15,933	652	19,843			2,637
Possible	3,000	47	3,278			479	6,918	104	7,540			1,447
Total 3P	4,981	143	5,836			778	29,603	902	35,015			5,040
3P PV10($Bns)(1)			$	4.7					$	21.4
% Liquids(2)			15		%				15		%

(1)Marcellus and Total PV10 includes $1.0 billion of Antero hedges at SEC pricing

(2)Represents liquids volumes as a % of total volumes.  Liquids comprised of 811 million barrels of NGLs and 91 million barrels of oil.

Non-GAAP Disclosure

Year-end pre-tax PV10 value is a non-GAAP financial measure as defined by the SEC.  We believe that the presentation of pre-tax PV10 value is relevant and useful to our investors because it presents the discounted

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future net cash flows attributable to our reserves prior to taking into account corporate future income taxes and our current tax structure.  We further believe investors and creditors use pre-tax PV10 value as a basis for comparison of the relative size and value of our reserves as compared with other companies.  Antero’s pre-tax PV10 value as of December 31, 2013 may be reconciled to its standard measure of discounted future net cash flows as of December 31, 2013 by reducing Antero’s pre-tax PV10 value by the discounted future income taxes associated with such reserves.

Antero Resources is an independent oil and natural gas company engaged in the acquisition, development and production of unconventional oil and liquids-rich natural gas properties primarily located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. Our website is located at www.anteroresources.com.

Cautionary Statements

This release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero’s control. All statements, other than historical facts included in this release, are forward-looking statements. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.

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, 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 “Risk Factors” in our Final Prospectus dated October 9, 2013 on file with the Securities and Exchange Commission (File No. 333-189284).

The SEC permits oil and gas companies to disclose probable and possible reserves in their filings with the SEC. Antero does not plan to include probable and possible reserve estimates in its filings with the SEC.  Antero has provided internally generated estimates that have been audited by its third party reserve engineer in this release.  Antero’s estimate of proved, probable and possible reserves is provided in this release because management believes it is useful information that is widely used by the investment community in the valuation, comparison and analysis of companies.  However, we note that the SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.

“EUR,” or Estimated Ultimate Recovery, refers to Antero’s internal estimates of per well hydrocarbon quantities that may be potentially recovered from a hypothetical future well completed as a producer in the area. These quantities do not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules.

This release provides a summary of Antero’s reserves as of December 31, 2013, assuming ethane “rejection”.  Ethane rejection occurs when ethane is left in the wellhead natural gas stream when the natural 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 natural gas at the outlet of the processing plant is higher.  Producers will generally elect to “reject” ethane at the processing plant when the price received for the ethane in the natural gas stream is greater than the price received for the ethane being sold as a liquid after fractionation, net of fractionation costs.  When ethane is recovered in the processing plant, the Btu content of the residue natural gas is lower, but a producer is then able to recover the value of the ethane sold as a separate natural gas liquid product.  In addition, natural gas processing plants can produce the other NGL products (propane, normal butane, isobutene and natural gasoline) while rejecting ethane.

For more information, contact Michael Kennedy — VP Finance, at (303) 357-6782 or mkennedy@anteroresources.com.

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EX-99.2

Exhibit 99.2

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

January 15, 2014

Antero Resources Appalachian Corporation

1625 17th Street

Suite 300

Denver, Colorado 80202

Ladies and Gentlemen:

Pursuant to your request, we have conducted an audit of the estimates of the net proved crude oil, condensate, natural gas liquids (NGL), and natural gas reserves and present worth, as of December 31, 2013, prepared by the engineering staff of Antero Resources Appalachian Corporation (Antero) for working and royalty interests in Ohio, Pennsylvania, and West Virginia that Antero has represented it owns. This evaluation was completed on January 15, 2014. Antero has represented to us that these properties account for approximately 99.90 percent on a million cubic feet equivalent basis of Antero’s net proved reserves as of December 31, 2013, and that the net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4—10(a) (1)—(32) of Regulation S—X of the Securities and Exchange Commission (SEC) of the United States. We have reviewed information provided to us by Antero that it represents to be Antero’s estimates of the net reserves, as of December 31, 2013, for the same properties as those which we evaluated. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by Antero.

Reserves included herein are expressed as net reserves as represented by Antero. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2013. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Antero after deducting all interests owned by others. NGL have been estimated for certain properties and are based on the NGL yields provided by Antero.

Future gross revenue is that revenue which will accrue to the appraised interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting production and ad valorem taxes, operating expenses, and capital costs from the future gross revenue. Present worth is defined as future net revenue discounted at a specified arbitrary rate compounded monthly over the expected period of realization.

Estimates of oil, condensate, NGL, and natural gas reserves and associated revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this audit were obtained from reviews with Antero personnel, Antero files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Antero with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geological and engineering methods that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. These assumptions, data, methods, and procedures are considered appropriate for the purpose for which this report has been prepared.

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For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

Petroleum reserves estimated by Antero and by us are classified as proved and are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment.

In the course of our audit of the estimates of net proved reserves prepared by Antero, we have participated in reviews and discussions with Antero involving Antero’s methodologies and procedures and we are in concurrence with the methodologies and procedures used by Antero.

Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as that portion of the total gas to be delivered into a gas pipeline for sale after separation, processing, fuel use, and flare. Gas reserves are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at the legal pressure base of the state in which the interest is located. Condensate reserves estimated herein are those to be recovered by conventional lease separation.

Definition of Reserves

Petroleum reserves estimated by Antero included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4—10(a) (1)—(32) of Regulation S—X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not

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including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves — Proved oil and gas reserves are those quantities of oil and gas, 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, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not

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limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves — Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves — Undeveloped oil and gas reserves are reserves of any category 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.

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(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4—10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Primary Economic Assumptions

The following economic assumptions were used for estimating existing and future prices and costs:

Oil, Condensate, and NGL Prices

Antero has represented that the oil, condensate, and NGL prices were based on NYMEX Light Sweet Crude Oil (WTI) pricing, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. The oil, condensate, and NGL prices were calculated using differentials furnished by Antero to the reference price of $97.17 per barrel. The resulting weighted-average price for oil and condensate was $87.00 per barrel. The resulting weighted-average price for NGL was $47.13 per barrel.

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Natural Gas Prices

Antero has represented that the natural gas prices were based on Columbia Gas Transmission Appalachia index pricing, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. The gas prices were calculated for each property using differentials and heating value adjustments furnished by Antero to the reference price of $3.65 per million British thermal units (MMBtu) and held constant thereafter. The resulting weighted average price was $3.38 per thousand cubic feet.

Operating Expenses and Capital Costs

Operating expenses and capital costs, based on information provided by Antero, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. Abandonment costs were included for all properties. These costs were not escalated for inflation.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2013, estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines.

Antero has represented that estimated net proved reserves and present worth at 10 percent attributable to the reviewed properties are based on the definitions of proved reserves of the SEC. Antero represents that its estimates of the net proved reserves and present worth attributable to these properties, which represent 99.90 percent of Antero’s total proved reserves on a net equivalent basis, are as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), millions of cubic feet equivalent (MMcfe), and thousands of dollars (M$):

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	Estimated by Antero Net Proved Reserves and Present Worth at 10 Percent as of December 31, 2013
	Oil and Condensate (Mbbl)	Natural Gas Liquids (Mbbl)	Natural Gas (MMcf)	Gas Equivalent (MMcfe)	Present Worth at 10 Percent (M$)
Marcellus and Upper Devonian
Proved Developed
Audited by DeGolyer and MacNaughton	447	27,247	1,695,493	1,861,660	2,571,972
Not Audited by DeGolyer and MacNaughton	0	0	7,384	7,384	5,010
Proved Undeveloped
Audited by DeGolyer and MacNaughton	6,080	98,368	4,774,354	5,401,042	2,765,612
Not Audited by DeGolyer and MacNaughton	0	0	0	0	0
Total Marcellus and Upper Devonian Proved Reserves	6,527	125,615	6,477,231	7,270,086	5,342,594
Utica
Proved Developed
Audited by DeGolyer and MacNaughton	1,247	5,210	114,887	153,628	366,099
Not Audited by DeGolyer and MacNaughton	0	0	0	0	0
Proved Undeveloped
Audited by DeGolyer and MacNaughton	1,651	6,236	161,046	208,369	288,671
Not Audited by DeGolyer and MacNaughton	0	0	0	0	0
Total Utica Proved Reserves	2,898	11,446	275,933	361,997	654,770

Notes:

(1)Liquids are converted to gas equivalent using a factor of 1 barrel of liquids per 6,000 cubic feet of gas equivalent.

(2)Numbers may not add due to rounding.

(3)Future income taxes were not taken into account in the preparation of the estimates of present worth.

In our opinion, the information relating to the audited estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries — Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4—10(a) (1)—(32) of Regulation S—X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S—K of the Securities and Exchange Commission; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth

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herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

In comparing the detailed net proved reserves estimates prepared by us and by Antero of the properties audited, we have found differences, both positive and negative resulting in an aggregate difference of 1.9 percent for the Marcellus and Upper Devonian properties and an aggregate difference of 1.1 percent for the Utica properties when compared on the basis of net gas equivalent. It is our opinion that there is no material difference between the net proved reserves estimates prepared by Antero and those prepared by us for those properties we audited. In comparing the detailed present worth at 10 percent estimates prepared by us and by Antero of the properties audited, we have found differences, both positive and negative, resulting in an aggregate difference of 3.2 percent for the Marcellus and Upper Devonian properties and an aggregate difference of 1.4 percent for the Utica properties when compared on the basis of present worth at 10 percent. It is our opinion that there is no material difference between the present worth at 10 percent estimates prepared by Antero and those prepared by us for those properties we audited.

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DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Antero. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Antero. DeGolyer and MacNaughton has used all data, assumptions, procedures, and methods that it considers necessary to prepare this report.

Very truly yours,

/s/ DeGOLYER and MacNAUGHTON

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

/s/ Gregory K. Graves, P.E.

Gregory K. Graves, P.E.

Senior Vice President

DeGolyer and MacNaughton

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CERTIFICATE of QUALIFICATION

I, Gregory K. Graves, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1.That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Antero dated January 15, 2014, and that I, as Senior Vice President, was responsible for the preparation of this report.

2.That I attended the University of Texas at Austin, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1984; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 29 years of experience in oil and gas reservoir studies and reserves evaluations.

/s/ Gregory K. Graves, P.E.

Gregory K. Graves, P.E.

Senior Vice President

DeGolyer and MacNaughton

EX-99.3

Exhibit 99.3

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

January 31, 2014

Antero Resources Appalachian Corporation

1625 17th Street

Suite 300

Denver, Colorado 80202

Ladies and Gentlemen:

Pursuant to your request, we have conducted an audit of the estimates of the net probable and possible undeveloped crude oil, condensate, natural gas liquids (NGL), and natural gas reserves and present worth, as of December 31, 2013, prepared by the engineering staff of Antero Resources Appalachian Corporation (Antero) for working and royalty interests in Ohio, Pennsylvania, and West Virginia that Antero has represented it owns. This evaluation was completed on January 31, 2014. Antero has represented to us that these properties account for approximately 100 percent on a million cubic feet equivalent basis of Antero’s net probable and possible undeveloped reserves as of December 31, 2013, and that the net probable and possible undeveloped reserves estimates have been prepared in accordance with the reserves definitions of Rules 4—10(a) (1)—(32) of Regulation S—X of the Securities and Exchange Commission (SEC) of the United States. We have reviewed information provided to us by Antero that it represents to be Antero’s estimates of the net reserves, as of December 31, 2013, for the same properties as those which we evaluated. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by Antero.

Reserves included herein are expressed as net reserves as represented by Antero. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2013. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Antero after deducting all interests owned by others. NGL have been estimated for certain properties and are based on the NGL yields provided by Antero.

Future gross revenue is that revenue which will accrue to the appraised interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting production and ad valorem taxes, operating expenses, and capital costs from the future gross revenue. Present worth is defined as future net revenue discounted at a specified arbitrary rate compounded monthly over the expected period of realization.

Estimates of oil, condensate, NGL, and natural gas reserves and associated revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this audit were obtained from reviews with Antero personnel, Antero files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Antero with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geological and engineering methods that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. These assumptions, data, methods, and procedures are considered appropriate for the purpose for which this report has been prepared.

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For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

Petroleum reserves estimated by Antero and by us are classified as probable and possible and are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment.

In the course of our audit of the estimates of net probable undeveloped and possible undeveloped reserves prepared by Antero, we have participated in reviews and discussions with Antero involving Antero’s methodologies and procedures and we are in concurrence with the methodologies and procedures used by Antero.

Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as that portion of the total gas to be delivered into a gas pipeline for sale after separation, processing, fuel use, and flare. Gas reserves are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at the legal pressure base of the state in which the interest is located. Condensate reserves estimated herein are those to be recovered by conventional lease separation. NGL reserves are those attributed to the leasehold interests according to processing agreements.

Definition of Reserves

Petroleum reserves estimated by Antero included in this report are classified as probable and possible. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4—10(a) (1)—(32) of Regulation S—X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by

3

contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves — Proved oil and gas reserves are those quantities of oil and gas, 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, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not

4

limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Probable reserves — Probable reserves are those additional 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.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher

5

than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (iv) and (vi) of the definition of possible reserves.

Possible reserves — Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within

6

the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (iii) of the proved oil and gas definition, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

Developed oil and gas reserves — Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

7

Undeveloped oil and gas reserves — Undeveloped oil and gas reserves are reserves of any category 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.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4—10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

The extent to which probable and possible reserves ultimately may be recategorized as proved reserves is dependent upon future drilling, testing, and well performance. The degree of risk to be applied in evaluating probable and possible reserves is influenced by economic and technological factors as well as the time element. Probable and possible reserves in this report have not been adjusted in consideration of these additional risks and therefore are not comparable with proved reserves. No proved reserves have been evaluated for this report.

Primary Economic Assumptions

The following economic assumptions were used for estimating existing and future prices and costs:

8

Oil, Condensate, and NGL Prices

Antero has represented that the oil, condensate, and NGL prices were based on NYMEX Light Sweet Crude Oil pricing, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. The oil, condensate, and NGL prices were calculated using differentials furnished by Antero to the reference price of $97.17 per barrel. The resulting weighted-average price attributable to the probable reserves for oil and condensate was $87.02 per barrel. The resulting weighted-average price attributable to the possible reserves for oil and condensate was $86.64 per barrel. The resulting weighted-average price attributable to the probable reserves for NGL was $48.13 per barrel. The resulting weighted-average price attributable to the possible reserves for NGL was $47.95 per barrel.

Natural Gas Prices

Antero has represented that the natural gas prices were based on Columbia Gas Transmission Appalachia index pricing, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. The gas prices were calculated for each property using differentials and heating value adjustments furnished by Antero to the reference price of $3.65 per million British thermal units (MMBtu) and held constant thereafter. The resulting weighted average price attributable to the probable reserves was $3.47 per thousand cubic feet.  The resulting weighted average price attributable to the possible reserves was $3.46 per thousand cubic feet.

Operating Expenses and Capital Costs

Operating expenses and capital costs, based on information provided by Antero, were used in estimating future costs required to operate the properties. In certain cases, future

9

costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. Abandonment costs were included for all properties. These costs were not escalated for inflation.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2013, estimated oil and gas reserves. The reserves estimated in this report can be produced under current regulatory guidelines.

Antero has represented that estimated net probable and possible undeveloped reserves and present worth at 10 percent attributable to the reviewed properties are based on the definitions of probable and possible undeveloped reserves of the SEC. Antero represents that its estimates of the net probable and possible undeveloped reserves and present worth attributable to these properties, which represent 100 percent of Antero’s total probable and possible undeveloped reserves on a net equivalent basis, are as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), millions of cubic feet equivalent (MMcfe), and thousands of dollars (M$):

	Estimated by Antero Net Probable and Possible Undeveloped Reserves and Present  Worth at 10 Percent as of December 31, 2013
	Oil and Condensate (Mbbl)	Natural Gas  Liquids (Mbbl)	Natural  Gas (MMcf)	Gas  Equivalent (MMcfe)	Present Worth at 10 Percent (M$)
Probable Undeveloped	69,564	582,205	15,932,470	19,843,083	12,686,704
Possible Undeveloped	11,694	92,076	6,917,578	7,540,195	1,677,794

Notes:

(1)Probable and possible reserves and values for probable and possible reserves have not been risk adjusted to make them comparable to proved reserves.

(2)Liquids are converted to gas equivalent using a factor of 1 barrel of liquids per 6,000 cubic feet of gas equivalent.

(3)Numbers may not add due to rounding.

(4)Future income taxes were not taken into account in the preparation of the estimates of present worth.

In our opinion, the information relating to estimated probable and possible reserves, estimated future net revenue probable and possible reserves, and present

10

worth of estimated future net revenue from probable and possible reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries — Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4—10(a) (1)—(32) of Regulation S—X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (5), (8), and 1203(a) of Regulation S—K of the Securities and Exchange Commission; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the probable and possible reserves are not presented at the beginning of the year.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

In comparing the detailed net probable undeveloped reserves estimates prepared by us and by Antero of the properties audited, we have found differences, both positive and negative, resulting in an aggregate difference of 1.8 percent compared on the basis of net gas equivalent. It is our opinion that there is no material difference between the net probable undeveloped reserves estimates prepared by Antero and those prepared by us for those properties we audited. In comparing the detailed present worth at 10 percent estimates prepared by us and by Antero of the probable undeveloped properties audited, we have found differences, both positive and negative, resulting in an aggregate difference of 1.9 percent when compared on the basis of present worth at 10 percent. It is our opinion that there is no material difference between the present worth at 10 percent estimates prepared by Antero and those prepared by us for those probable undeveloped properties we audited. In comparing the detailed net possible undeveloped reserves estimates prepared by us and by Antero of the properties audited, we have found differences, both positive and negative, resulting in an aggregate difference of 1.8 percent compared on the basis of net gas equivalent. It is our opinion that there is no material difference between the net possible undeveloped reserves estimates prepared by Antero and those prepared by us for those properties we audited. In

11

comparing the detailed present worth at 10 percent estimates prepared by us and by Antero of the possible undeveloped properties audited, we have found differences, both positive and negative, resulting in an aggregate difference of 2.1 percent when compared on the basis of present worth at 10 percent. It is our opinion that there is no material difference between the present worth at 10 percent estimates prepared by Antero and those prepared by us for those possible undeveloped properties we audited.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Antero. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Antero. DeGolyer and MacNaughton has used all data, assumptions, procedures, and methods that it considers necessary to prepare this report.

Very truly yours,

/s/ DeGOLYER and MacNAUGHTON

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

/s/ Gregory K. Graves, P.E.

Gregory K. Graves, P.E.

Senior Vice President

DeGolyer and MacNaughton

12

CERTIFICATE of QUALIFICATION

I, Gregory K. Graves, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1.That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Antero dated January 31, 2014, and that I, as Senior Vice President, was responsible for the preparation of this report.

2.That I attended the University of Texas at Austin, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1984; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 29 years of experience in oil and gas reservoir studies and reserves evaluations.

/s/ Gregory K. Graves, P.E.

Gregory K. Graves, P.E.

Senior Vice President

DeGolyer and MacNaughton