DENVER, Jan. 28, 2015 /PRNewswire/ —

  • Proved reserves increased by 66% to 12.7 Tcfe at year-end 2014
  • Proved developed reserves increased by 88% to 3.8 Tcfe at year-end 2014
  • 3P reserves increased by 16% to 40.7 Tcfe at year-end 2014
  • Replaced 1,465% of estimated net production in 2014
  • Achieved all-in finding and development costs of $0.61 per proved Mcfe during 2014
  • Pre-tax PV10 of proved reserves increased by 89% to $11.3 billion at year-end 2014


Antero Resources logo.

Antero Resources (NYSE: AR) (“Antero” or the “Company”) today announced that proved reserves at December 31, 2014 were 12.7 Tcfe, a 66% increase compared to proved reserves at December 31, 2013, in each case assuming ethane rejection.  Proved, probable and possible (“3P”) reserves at year-end 2014 totaled 40.7 Tcfe, which represents a 16% increase compared to the previous year, also assuming ethane rejection.  Antero’s December 31, 2014 proved and 3P reserves exclude 615 and 1,535 million barrels of ethane, respectively, due to the relationship between ethane and natural gas futures pricing which indicates that ethane will be rejected.  Additionally, the Company’s reserves exclude any reserves attributable to Antero’s Utica dry gas resource in West Virginia and Pennsylvania.

Antero replaced 1,465% of estimated net production in 2014 from all sources including performance and price revisions.  Finding and development costs for proved reserve additions from all sources including costs incurred for drilling and completion capital, acquisitions, land additions and all price and performance revisions averaged$0.61 per Mcfe, based on preliminary unaudited capital expenditures for 2014.  Drill-bit only finding and development costs averaged $0.46 per Mcfe for 2014.  Antero’s proved developed reserve additions totaled over 2.1 Tcfe on $2.5 billion of drilling and completion capital for a development cost of $1.15 per Mcfe in 2014.  The reserve life of the Company’s proved reserves, based on 2014 production, is approximately 35 years.

Proved Reserves

As of December 31, 2014, proved reserves increased by 66% to 12.7 Tcfe, which were comprised of 83% natural gas, 16% natural gas liquids (“NGLs”) and 1% oil.  The Marcellus Shale accounted for 94% of proved reserves and the Utica Shale accounted for the remaining 6%.  Excluding 2014 production, 5.0 Tcfe of the 5.4 Tcfe of proved reserves added during 2014 were attributed to the Marcellus Shale.  Total proved NGLs and oil reserves increased by 193 million barrels and 18 million barrels, respectively, due to the success of Antero’s drilling program targeting liquids-rich locations in the Marcellus and Utica Shale plays.  Positive performance revisions of 361 Bcfe were primarily due to improved Marcellus well performance from shorter stage length (“SSL”) completions.  Negative revisions of 1.4 Tcfe were due to the reclassification of 191 dry gas locations to the probable category in order to comply with the SEC five-year development rule.

Approximately 29% of Antero’s combined 543,000 net acre leasehold position was classified as proved atDecember 31, 2014.  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.

Proved developed reserves increased by 88% from year-end 2013 to over 3.8 Tcfe at December 31, 2014.  The Company added 135 Marcellus and 45 Utica wells to proved developed reserves in 2014.  The percentage of proved reserves classified as proved developed increased to 30% at December 31, 2014 as compared to 27% at year-end 2013.  Proved undeveloped reserves increased by 58% as a result of the successful execution of Antero’s Marcellus and Utica Shale development drilling plans resulting in the addition of 182 gross proved undeveloped drilling locations.

Antero’s estimate of drilling and development costs incurred during 2014, including drilling and completion of$2.5 billion and leasehold costs of $840 million, is approximately $3.3 billion.  The leasehold costs include $415 million of acquisitions and $425 million of land.  Assuming the approximate $3.3 billion estimate of drilling and development costs, preliminary finding and development costs from all sources for 2014 averaged $0.61 per Mcfe.  Antero’s three-year finding and development costs from all sources through 2014 averaged $0.65 per Mcfe, excluding the Arkoma and Piceance Basin properties that were divested in 2012. The 2014 capital costs are unaudited and preliminary.  Final cost amounts will be provided in Antero’s Annual Report on Form 10-K for the year ended December 31, 2014.

Under SEC reporting rules, proved undeveloped reserves are limited to reserves that are planned to be developed within five years of initial booking.  Antero’s 8.9 Tcfe of proved undeveloped reserves will require an estimated $8.2 billion of development capital over the next five years, resulting in an estimated average development cost for proved undeveloped reserves of $0.92 per Mcfe.  The $8.2 billion of future development capital is based on 2014 well cost assumptions and does not assume any anticipated well cost reductions in 2015.

SEC prices for reserves were calculated as of December 31, 2014 on a weighted average Appalachian index basis and were $81.48 per Bbl for oil and $4.07 per MMBtu for natural gas.  Using SEC prices, which are not indicative of current forward prices, the pre-tax present value discounted at 10% (“pre-tax PV10”) of the December 31, 2014proved reserves was $11.3 billion, an 89% increase over year-end 2013.  The pre-tax PV10 value of proved developed reserves was $5.8 billion, a 98% increase over year-end 2013.

Summary of Changes in Proved Reserves (in Bcfe)

Balance at December 31, 2013


Extensions, discoveries and additions




Performance revisions


Reclassification to probable due to SEC 5-year development rule


Price revisions





Balance at December 31, 2014


3P Reserves

Antero estimates that it had year-end 2014 3P reserves of 40.7 Tcfe, a 16% increase over year-end 2013 3P reserves of 35.0 Tcfe, in each case assuming ethane rejection.  The 3P reserves contain 34.5 Tcf of natural gas, 924 million barrels of NGLs, and 102 million barrels of oil.  The Marcellus, Utica, and Upper Devonian Shalecomprised 28.4 Tcfe, 7.6 Tcfe and 4.6 Tcfe of the 3P reserves, respectively.  The 16% increase in 3P reserves was driven by the addition of 50,000 net acres in the Marcellus Shale in northern West Virginia and 43,000 net acres in the Utica Shale in southern Ohio.

Importantly, 27.4 Tcfe of Antero’s 28.4 Tcfe of 3P reserves in the Marcellus, or 96%, were classified as proved and probable (“2P”), reflecting the low risk nature of Antero’s Marcellus reserves.  Further, 79%, or 5.1 Tcfe of Antero’s 6.5 Tcfe of 3P reserves in the Utica, were classified as 2P.

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

Marcellus Shale

Upper Devonian Shale







Gross Locations







Gross Locations



























Total 3P









3P PV10($Bns)



% Liquids(1)



Utica Shale








Gross Locations







Gross Locations




























Total 3P









3P PV10($Bns)



% Liquids(1)




Represents liquids volumes as a % of total volumes.  Combined liquids comprised of 924 million barrels of NGLs and 102 million barrels of oil.

Using SEC prices, the pre-tax PV10 of the December 31, 2014 3P reserves was $22.8 billion, a 12% increase over year-end 2013.

Antero’s proved and 3P reserves at December 31, 2014 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 3P reserves at December 31, 2014 and was within 1% of Antero’s internal reserve estimates.

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 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.

The GAAP financial measure most directly comparable to pre-tax PV10 is the standardized measure of discounted future net cash flows (“Standardized Measure”).  We are not yet able to provide a reconciliation of pre-tax PV10 to Standardized Measure because the discounted future income taxes associated with our reserves is not yet calculable.  We expect to include a full reconciliation of pre-tax PV10 to Standardized Measure in our Annual Report on Form 10-K for the year ended December 31, 2014.

Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in WestVirginia, Ohio and Pennsylvania. The Company’s website is located at

Cautionary Statements

This release includes “forward-looking statements”.  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.

Antero cautions 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 the Company’s 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 and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading “Item 1A. Risk Factors” in Antero’s Annual Report on Form 10-K for the year ended December 31, 2013.

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, the Company notes 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.

This release provides a summary of Antero’s reserves as of December 31, 2014, 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.

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SOURCE Antero Resources

Michael Kennedy – VP Finance, at (303) 357-6782 or [email protected]

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