Exhibit 99.2

DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244

APPRAISAL REPORT
as of
DECEMBER 31, 2009
on
CERTAIN FAYETTEVILLE PROPERTIES
owned by
ANTERO RESOURCES CORPORATION

FOREWORD

        Scope of Investigation    This report presents an appraisal, as of December 31, 2009, of the extent and value of the proved natural gas reserves of certain properties owned by Antero Resources Corporation (Antero). The reserves estimated in this report are located in Arkansas. The properties appraised are listed in detail in Appendix A bound with this report.

        Reserves estimated in this report are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2009. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Antero after deducting royalties and interests owned by others.

        This report presents values that were estimated for proved reserves based on prices and costs provided by Antero. Future prices were estimated using guidelines established by the United States Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board (FASB). Prices were held constant for the lives of the properties. Costs were not escalated for inflation. A more detailed explanation of the prices and cost assumptions is presented in the Valuation of Reserves section of this report.

        Values of proved reserves in this report are expressed in terms of estimated future gross revenue, future net revenue, and present worth. 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 estimated production taxes, ad valorem taxes, operating expenses, and capital costs from the future gross revenue. Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. Future income tax expenses were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected period of realization. In this report, present worth values using a discount rate of 10 percent are reported in detail and values using discount rates of 5, 8, 12, 15, 20, 25, and 30 percent are reported as totals in the appendix to this report.

        Estimates of gas reserves and future net 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.

        Authority    This report was prepared at the request of Mr. Kevin J. Kilstrom, Vice President, Antero.

        Source of Information    Data used in the preparation of this report were obtained from Antero, 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 information furnished

by Antero with respect to its 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.

DEFINITION of RESERVES

        Petroleum reserves 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 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 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.

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(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 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 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.

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(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.

        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 reclassified 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. No probable or possible reserves have been evaluated for this report.

ESTIMATION of RESERVES

        Estimates of reserves were prepared by the use of geological and engineering methods generally accepted by the petroleum industry. 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.

        When applicable, the volumetric method was used to estimate original gas in place (OGIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material-balance and other engineering methods were used to estimate OGIP.

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        Estimates of ultimate recovery were obtained after applying recovery factors to OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material-balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

        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 based on economic conditions defined by the price assumptions used in this report.

        In certain cases, when the previously named methods could not be used, reserves were estimated by analogy with similar wells or reservoirs for which more complete data were available.

        Gas quantities estimated herein are expressed as wet gas and sales gas. Wet gas is the indigenous gas in the reservoir to be produced. Sales gas is defined as that portion of the wet gas to be delivered into a gas pipeline for sale after separation, processing, fuel use, and flare. Gross gas reserves are reported as wet gas. The net gas reserves are reported as sales gas. Gas quantities are expressed at a temperature base of 60 degrees Fahrenheit (°F) and a pressure base of 14.65 pounds per square inch absolute (psia).

        In the preparation of this report, as of December 31, 2009, gross production estimated through December 31, 2009, was deducted from gross ultimate recovery to arrive at the estimate of gross reserves. This generally required that the production rates be estimated for up to 1 month, since production data were available only through November 2009 for most properties. Data available from wells drilled through December 31, 2009, were used in this report.

        The following table presents estimates of proved reserves, as of December 31, 2009, of the properties appraised, expressed in thousands of barrels (Mbbl) or millions of cubic feet (MMcf):

VALUATION of RESERVES

        Revenue values in this report have been prepared using initial prices and costs estimates provided by Antero. Future prices were estimated using guidelines established by the SEC and the FASB.

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

Natural Gas Prices

        Natural gas prices were calculated using specified differentials and British thermal unit (Btu) factors for each lease supplied by Antero to a NYMEX price of $3.99 per million Btu. No escalation was applied to the prices. The NYMEX gas price of $3.99 per thousand cubic feet is the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to December 31, 2009. The weighted average price for the proved reserves over the lives of the properties was $3.710 per thousand cubic feet.

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Operating Expenses and Capital Costs

        Operating expenses and capital costs were based on information provided by Antero and were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than current costs, may have been used because of anticipated changes in operating conditions. Operating expenses include the deduction of net profits interest owned by others. Future capital costs were estimated using 2009 values and were not adjusted for inflation.

        The estimated future revenue to be derived from the production and sale of the net proved reserves, as of December 31, 2009, of the properties appraised, expressed in thousands of dollars (M$), is summarized as follows:

        Timing of capital expenditures and the resulting development of production were based on a development plan provided by Antero.

        In our opinion, the information relating to 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)(i), (ii), and (v)-(x), and 1203(a) of Regulation S-K of the Securities and Exchange Commission; provided, however, future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein.

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

        Appendix A, bound with this report, includes summaries of proved reserves and revenue by reserves status and tabulations of proved reserves and revenue by reserves status and lease. Appendix B to this report, included on CD, contains projections of proved reserves and revenue by reserves status and lease.

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SUMMARY and CONCLUSIONS

        Antero owns working and royalty interests in certain properties located in Arkansas. The estimated net proved reserves of the properties appraised, as of December 31, 2009, are summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):

        The estimated future revenue and costs attributable to Antero's leasehold interests in the net proved reserves, as of December 31, 2009, of the properties appraised under the aforementioned assumptions concerning future prices and costs, expressed in thousands of dollars (M$), are summarized as follows:

        DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 70 years. 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 report has been prepared at the request of Antero and should not be used for purposes other than those for which it is intended. DeGolyer and MacNaughton has used all procedures, data, and methods that it considers necessary to prepare this report.

        Gas quantities in this report are expressed at a temperature base of 60 °F and a pressure base of 14.65 psia.

SIGNED: March 25, 2010

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