Exhibit 99.18
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
July 24, 2013
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 net possible crude oil, condensate, natural gas liquids (NGL), and natural gas reserves and present worth, as of June 30, 2013, prepared by the engineering staff of Antero Resources Appalachian Corporation (Antero) for working and royalty interests owned in Pennsylvania and West Virginia. This evaluation was completed on July 24, 2013. Antero has represented that these properties account for 100 percent on a million cubic feet equivalent basis of Antero’s net possible reserves in the Upper Devonian Shale in the Appalachian basin as of June 30, 2013. Antero has represented to us that these properties account for approximately 41.40 percent on a million cubic feet equivalent basis of Antero’s net possible reserves as of June 30, 2013, and that the net possible 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 June 30, 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 June 30, 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 and assume rejection of ethane during processing.
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.
At the request of Antero, we have prepared an audit of the estimates of net possible oil, condensate, NGL, and natural gas reserves and present worth, as of June 30, 2013, prepared by the engineering staff of Antero for the same properties assuming recovery of ethane during NGL processing, referred to as the “Ethane Recovery Sensitivity Case.” Given the volatility in ethane prices, both ethane rejection and ethane recovery cases were included as of June 30, 2013, to provide comparability between reserves and present worth at 10 percent. Additionally, at the request of Antero, we have prepared an audit of the estimates of net possible oil, condensate, NGL, and natural gas reserves and present worth, as of June 30, 2013, prepared by the engineering staff of Antero for the same properties for the ethane rejection and ethane recovery cases at forecast prices, referred to as the “Ethane Rejection Forecast Price Sensitivity Case” and the “Ethane Recovery Forecast Price Sensitivity Case,” respectively.
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.
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 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 possible 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 possible. Only possible 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.
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.
(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 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 possible reserves is influenced by economic and technological factors as well as the time element. Possible reserves in this report have not been adjusted in consideration of these additional risks and therefore are not comparable with proved reserves.
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 $91.65 per barrel. The resulting weighted-average price for oil and condensate was $81.65 per barrel. The resulting weighted-average price for NGL was $45.25 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 $3.43 per million British thermal units (MMBtu) and held
constant thereafter. The resulting weighted average price was $2.97 per thousand cubic feet.
Operating Expenses and Capital Costs
Operating expenses and capital costs, based on information provided by Antero, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. Abandonment costs were included for all properties. These costs were not escalated for inflation.
While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the June 30, 2013, estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines.
Antero has represented that estimated net possible reserves and present worth at 10 percent attributable to the reviewed properties are based on the definitions of possible reserves of the SEC. Antero represents that its estimates of the net possible reserves attributable to these properties, which represent 41.40 percent of Antero’s total possible reserves on a net equivalent basis, are as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), millions of cubic feet equivalent (MMcfe), and thousands of dollars (M$):
|
|
|
Estimated by Antero |
| ||||||||
|
|
|
Oil and |
|
Natural |
|
Natural |
|
Gas |
|
Present |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Audited by DeGolyer and MacNaughton |
|
515 |
|
37,052 |
|
2,849,999 |
|
3,075,396 |
|
(45,098 |
) |
|
Not Audited by DeGolyer and MacNaughton |
|
0 |
|
0 |
|
0 |
|
0 |
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Upper Devonian Possible |
|
515 |
|
37,052 |
|
2,849,999 |
|
3,075,396 |
|
(45,098 |
) |
Notes:
1. Possible reserves and values for 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 6,000 cubic feet of gas equivalent per 1 barrel.
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 possible reserves, estimated future net revenue from possible reserves, and present worth of estimated future net revenue from 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, (ii) estimates of the possible developed and possible undeveloped reserves are not presented at the beginning of the year, and (iii) the effective date of this report does not coincide with Antero’s fiscal 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 possible reserves estimates prepared by us and by Antero of the properties audited, we have found differences, both positive and negative, in reserves estimates for individual properties. These differences appear to be compensating to a great extent when considering the reserves of Antero, in total, for the properties reviewed, resulting in an overall difference of 2.13 percent when compared on a net gas equivalent basis. It is our opinion that there is no material difference between the net possible 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, in present worth estimates for individual properties. These differences appear to be compensating to a great extent when considering the present worth of Antero, in total, for the properties reviewed, resulting in a 3.38 percent overall difference. 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.
Ethane Recovery Sensitivity Case
The aforementioned methodology and procedures were used to determine estimates of net possible reserves for the Ethane Recovery Sensitivity Case. There were no changes to the number of locations evaluated, operating expenses, capital costs, or abandonment costs. The only adjustments made were to NGL yields and pricing to take into account ethane recovery and natural gas heating value adjustments. The following economic assumptions were used for estimating existing and future prices and costs for the Ethane Recovery Sensitivity Case:
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 $91.65 per barrel. The resulting weighted-average price for oil and condensate was $81.65 per barrel. The resulting weighted-average price for NGL was $16.77 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 $3.43 per million British thermal units (MMBtu) and held constant thereafter. The resulting weighted average price was $2.86 per thousand cubic feet.
Operating Expenses and Capital Costs
Operating expenses and capital costs, based on information provided by Antero, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. Abandonment costs were included for all properties. These costs were not escalated for inflation.
Antero represents that its estimates of the net possible reserves and present worth attributable to the properties audited, under the aforementioned Ethane Recovery Sensitivity Case assumptions, are as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), millions of cubic feet equivalent (MMcfe), and thousands of dollars (M$):
|
|
|
Ethane Recovery Sensitivity Case |
| ||||||||
|
|
|
Estimated by Antero |
| ||||||||
|
|
|
Oil and |
|
Natural |
|
Natural |
|
Gas |
|
Present |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Audited by DeGolyer and MacNaughton |
|
514 |
|
124,043 |
|
2,714,503 |
|
3,461,845 |
|
(84,274 |
) |
|
Not Audited by DeGolyer and MacNaughton |
|
0 |
|
0 |
|
0 |
|
0 |
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Upper Devonian Possible |
|
514 |
|
124,043 |
|
2,714,503 |
|
3,461,845 |
|
(84,274 |
) |
Notes:
1. Possible reserves and values for 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 6,000 cubic feet of gas equivalent per 1 barrel.
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 comparing the detailed net possible reserves estimates prepared by us and by Antero for the Ethane Recovery Sensitivity Case, we have found differences, both positive and negative, in reserves estimates for individual properties. These differences appear to be compensating to a great extent when considering the reserves of Antero, in total, for the properties reviewed, resulting in an overall difference of 2.52 percent when compared on a net gas equivalent basis. It is our opinion that for the audited properties there is no material difference between the net possible reserves estimates prepared by Antero and those prepared by us for the
Ethane Recovery Sensitivity Case. In comparing the detailed present worth at 10 percent estimates prepared by us and by Antero for the Ethane Recovery Sensitivity Case, we have found differences, both positive and negative, in present worth estimates for individual properties. These differences appear to be compensating to a great extent when considering the present worth of Antero, in total, for the properties reviewed, resulting in a 3.96 percent overall difference. It is our opinion that for the audited properties there is no material difference between the present worth at 10 percent estimates prepared by Antero and those prepared by us for the Ethane Recovery Sensitivity Case.
Ethane Rejection Forecast Price Sensitivity Case
The aforementioned methodology and procedures were used to determine estimates of net possible reserves for the Ethane Rejection Forecast Price Sensitivity Case. There were no changes to the number of locations evaluated, operating expenses, capital costs, or abandonment costs. The NGL yields and gas heating value adjustments assume ethane rejection. The following economic assumptions were used for estimating future prices and costs for the Ethane Rejection Forecast Price Sensitivity Case:
Oil, Condensate, NGL, and Natural Gas Prices
Prices were provided by Antero as shown in the following table, expressed in dollars per barrel ($/bbl) and dollars per MMBtu ($/MMBtu):
|
Date |
|
Oil, |
|
Natural |
|
|
|
|
|
|
|
|
|
2013 |
|
85.37 |
|
3.48 |
|
|
2014 |
|
80.42 |
|
3.69 |
|
|
2015 |
|
75.76 |
|
3.90 |
|
|
2016 |
|
72.76 |
|
4.05 |
|
|
2017 and thereafter |
|
70.88 |
|
4.19 |
|
As of June 30, 2013, the 5-year average prices were $77.04 per barrel for oil, condensate, and NGL and $3.86 per MMBtu for natural gas. Oil and condensate prices were adjusted for gravity and local differential based on information provided by Antero. NGL price adjustments were provided by Antero and
assume rejection of ethane during processing. The gas prices were calculated for each property using differentials and heating value adjustments furnished by Antero. The resulting weighted average price for oil and condensate was $70.88 per barrel, $36.96 per barrel of NGL, and $3.76 per thousand cubic feet of gas.
Operating Expenses and Capital Costs
Operating expenses and capital costs, based on information provided by Antero, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. Abandonment costs were included for all properties. These costs were not escalated for inflation.
Antero represents that its estimates of the net possible reserves and present worth attributable to the properties audited, under the aforementioned Ethane Rejection Forecast Price Sensitivity Case assumptions, are as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), millions of cubic feet equivalent (MMcfe), and thousands of dollars (M$):
|
|
|
Ethane Rejection Forecast Price Sensitivity Case |
| ||||||||
|
|
|
Estimated by Antero |
| ||||||||
|
|
|
Oil and |
|
Natural |
|
Natural |
|
Gas |
|
Present |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Audited by DeGolyer and MacNaughton |
|
515 |
|
37,116 |
|
2,859,613 |
|
3,085,401 |
|
185,239 |
|
|
Not Audited by DeGolyer and MacNaughton |
|
0 |
|
0 |
|
0 |
|
0 |
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Upper Devonian Possible |
|
515 |
|
37,116 |
|
2,859,613 |
|
3,085,401 |
|
185,239 |
|
Notes:
1. Possible reserves and values for 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 6,000 cubic feet of gas equivalent per 1 barrel.
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 comparing the detailed net possible reserves estimates prepared by us and by Antero for the Ethane Rejection Forecast Price Sensitivity Case, we have found differences, both positive and negative, in reserves estimates for individual properties. These differences appear to be compensating to a great extent when considering the reserves of Antero, in total, for the properties reviewed, resulting in an overall difference of 2.22 percent when compared on a net gas equivalent basis. It is our opinion that for the audited properties there is no material difference between the net possible reserves estimates prepared by Antero and those prepared by us for the Ethane Rejection Forecast Price Sensitivity Case. In comparing the detailed present worth at 10 percent estimates prepared by us and by Antero for the Ethane Rejection Forecast Price Sensitivity Case, we have found differences, both positive and negative, in present worth estimates for individual properties. These differences appear to be compensating to a great extent when considering the present worth of Antero, in total, for the properties reviewed, resulting in a 4.30 percent overall difference. It is our opinion that for the audited properties there is no material difference between the present worth at 10 percent estimates prepared by Antero and those prepared by us for the Ethane Rejection Forecast Price Sensitivity Case.
Ethane Recovery Forecast Price Sensitivity Case
The aforementioned methodology and procedures were used to determine estimates of net possible reserves for the Ethane Recovery Forecast Price Sensitivity Case. There were no changes to the number of locations evaluated, operating expenses, capital costs, or abandonment costs. The NGL yields and gas heating value adjustments assume ethane recovery. The following economic assumptions were used for estimating future prices and costs for the Ethane Recovery Forecast Sensitivity Price Case:
Oil, Condensate, NGL, and Natural Gas Prices
Prices were provided by Antero as shown in the following table, expressed in dollars per barrel ($/bbl) and dollars per MMBtu ($/MMBtu):
|
Date |
|
Oil, |
|
Natural |
|
|
|
|
|
|
|
|
|
2013 |
|
85.37 |
|
3.48 |
|
|
2014 |
|
80.42 |
|
3.69 |
|
|
2015 |
|
75.76 |
|
3.90 |
|
|
2016 |
|
72.76 |
|
4.05 |
|
|
2017 and thereafter |
|
70.88 |
|
4.19 |
|
As of June 30, 2013, the 5-year average prices were $77.04 per barrel for oil, condensate, and NGL and $3.86 per MMBtu for natural gas. Oil and condensate prices were adjusted for gravity and local differential based on information provided by Antero. NGL price adjustments were provided by Antero and assume recovery of ethane during processing. The gas prices were calculated for each property using differentials and heating value adjustments furnished by Antero. The resulting weighted average price for oil and condensate was $70.88 per barrel, $14.63 per barrel of NGL, and $3.63 per thousand cubic feet of gas.
Operating Expenses and Capital Costs
Operating expenses and capital costs, based on information provided by Antero, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. Abandonment costs were included for all properties. These costs were not escalated for inflation.
Antero represents that its estimates of the net possible reserves and present worth attributable to the properties audited, under the aforementioned Ethane Recovery Forecast Price Sensitivity Case assumptions, are as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), millions of cubic feet equivalent (MMcfe), and thousands of dollars (M$):
|
|
|
Ethane Recovery Forecast Price Sensitivity Case |
| ||||||||
|
|
|
Estimated by Antero |
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|
|
|
Oil and |
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Natural |
|
Natural |
|
Gas |
|
Present |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Audited by DeGolyer and MacNaughton |
|
515 |
|
124,246 |
|
2,723,634 |
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3,472,198 |
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121,373 |
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|
Not Audited by DeGolyer and MacNaughton |
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0 |
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0 |
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0 |
|
0 |
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Total Upper Devonian Possible |
|
515 |
|
124,246 |
|
2,723,634 |
|
3,472,198 |
|
121,373 |
|
Notes:
1. Possible reserves and values for 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 6,000 cubic feet of gas equivalent per 1 barrel.
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 comparing the detailed net possible reserves estimates prepared by us and by Antero for the Ethane Recovery Forecast Price Sensitivity Case, we have found differences, both positive and negative, in reserves estimates for individual properties. These differences appear to be compensating to a great extent when considering the reserves of Antero, in total, for the properties reviewed, resulting in an overall difference of 2.81 percent when compared on a net gas equivalent basis. It is our opinion that for the audited properties there is no material difference between the net possible reserves estimates prepared by Antero and those prepared by us for the Ethane Recovery Forecast Price Sensitivity Case. In comparing the detailed present worth at 10 percent estimates prepared by us and by Antero for the Ethane Recovery Forecast Price Sensitivity Case, we have found differences, both positive and negative, in present worth estimates for individual properties. These differences appear to be compensating to a great extent when considering the present worth of Antero, in total, for the properties reviewed, resulting in a 3.69 percent overall difference. It is our opinion that for the audited properties there is no material difference between the present worth at 10 percent estimates prepared by Antero and those prepared by us for the Ethane Recovery Forecast Price Sensitivity Case.
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.
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Very truly yours, |
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/s/ DeGOLYER and MacNAUGHTON |
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DeGOLYER and MacNAUGHTON |
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Texas Registered Engineering Firm F-716 |
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/s/ Gregory K. Graves |
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Gregory K. Graves, P.E. |
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Senior Vice President |
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DeGolyer and MacNaughton |
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 July 24, 2013, 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 28 years of experience in oil and gas reservoir studies and reserves evaluations.
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/s/ Gregory K. Graves |
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Gregory K. Graves, P.E. |
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Senior Vice President |
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DeGolyer and MacNaughton |