Exhibit 99.1

 

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

January 10, 2018

Antero Resources Corporation

1615 Wynkoop Street

Denver, Colorado 80202

Ladies and Gentlemen:

Pursuant to your request, we have conducted an audit of the estimates of the net proved oil, condensate, natural gas liquids (NGL), and gas reserves and present worth, as of December 31, 2017, prepared by the engineering staff of Antero Resources Corporation (Antero) for working and royalty interests in Ohio, Pennsylvania, and West Virginia that Antero has represented that it owns. This evaluation was completed on January 10, 2018. Antero has represented to us that these properties account for approximately 99.99 percent on a million cubic feet equivalent basis of Antero’s net proved reserves as of December 31, 2017, 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, 2017, 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 estimates included herein are expressed as net reserves as represented by Antero. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2017. 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.

 

Values included herein are expressed in terms of estimated present worth. Future gross revenue is that revenue which will accrue to the evaluated interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting production taxes, ad valorem taxes, operating expenses, capital costs, and abandonment costs from the future gross revenue. Present worth is defined as future net revenue discounted at a specified arbitrary rate compounded annually over the expected period of

realization. Present worth should not be construed as fair market value because no consideration was given to additional factors that influence the prices at which properties are bought and sold.

 

Estimates of oil, condensate, NGL, and 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, from 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. It was not considered necessary to make a field examination of the physical condition and operation of the properties.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry, which are presented in the publication of the Society of Petroleum Engineers PRMS and publications of the Society of Petroleum Evaluation Engineers Monograph III and IV.

 

A performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for the evaluation of all reserves categories. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics includes data quality control, identification of flow regimes, and characteristic well performance behavior. Analysis was performed for all well groupings (or type-curve areas).

 

Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the impact of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs. The methodology used for the analysis was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, production history, and the appropriate reserves definitions.

Based on the current stage of field development, production performance, the development plans provided by Antero, and the analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.

 

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 sales gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel use, flare, and shrinkage resulting from field separation and processing. Gas reserves are expressed at a temperature base of 60 degrees Fahrenheit and at the pressure base of the state in which the reserves are located. Gas reserves included herein are expressed in thousands of cubic feet (Mcf).  Oil and condensate reserves estimated herein are those to be recovered by conventional lease separation. NGL reserves are those attributed to the lease according to yields provided by Antero. Oil, condensate, and NGL reserves included herein are expressed in barrels (bbl) representing 42 United States gallons per barrel.  For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.

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 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.

 

(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.

 

(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 assumptions were used for estimating 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 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 $51.03 per barrel. The resulting volume-weighted average prices  over the lives of the properties was $45.35 per barrel of oil and condensate and $20.40 per barrel of NGL.

Gas Prices

Antero has represented that the gas prices were based on pricing from six different indexes, 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 furnished by Antero to the aggregated price of $2.91 per million British thermal units ($/MMBtu) and held constant thereafter. British thermal unit factors provided by Antero were used to convert prices from $/MMBtu to dollars per thousand cubic feet. The resulting volume-weighted average price over the lives of the properties was $3.06 per thousand cubic feet. The indexes and prices, expressed in $/MMBtu, are shown in the following table:

 

 

Production and Ad Valorem Taxes

Production taxes were calculated using the tax rates for each state in which the reserves are located. Ad valorem taxes were estimated using rates provided by Antero based on historical payments.

Operating Expenses, Capital Costs, and Abandonment Costs

Estimates of operating expenses, provided by Antero and based on current expenses, were held constant for the lives of the properties. Future capital expenditures were estimated using 2017 values, provided by Antero, and were

not adjusted for inflation. Abandonment costs, which are those costs associated with the removal of equipment, plugging of the wells, and reclamation and restoration associated with the abandonment, were provided by Antero for all properties.

 

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 reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2017, estimated reserves.  

 

Antero has represented that its estimated net proved reserves and present worth at 10 percent attributable to the reviewed properties were based on the definitions of proved reserves of the SEC. Antero has represented that its estimates of the net proved reserves and present worth attributable to these properties, which represent 99.99 percent of Antero’s total proved reserves on a net equivalent basis, are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), millions of cubic feet equivalent (MMcfe), and thousands of dollars (M$):

 

 

Notes:

 

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 of the properties reviewed by us 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 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 2.7 percent for the Marcellus and Upper Devonian properties and an aggregate difference of 3.4 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 3.8 percent for the Marcellus and Upper Devonian properties and an aggregate difference of 1.5 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.

 

 

 

 

 

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.

 

 

 

 

 

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: