Antero Resources (AR) Announces 12% Increase in Estimated Proved Reserves to 17.3 Tcfe
February 14, 2018
Antero Resources (NYSE: AR) (“Antero” or the “Company”) today announced estimated reserves as of December 31, 2017.
Highlights:
 Proved reserves increased by 12% to 17.3 Tcfe at yearend 2017 (36% liquids), compared to yearend 2016
 Pretax PV10 of proved reserves at yearend 2017 was $10.8 billion at SEC pricing, including hedges
 Proved developed reserves increased by 23% to 8.5 Tcfe at yearend 2017, compared to yearend 2016
 $0.54 per Mcfe proved developed finding and development cost for 2017
 $0.37 per Mcfe future development cost for yearend 2017 proved undeveloped reserves
 3P reserves increased by 18% to 54.6 Tcfe at yearend 2017 (25% liquids), compared to yearend 2016
 Pretax PV10 of 3P reserves at yearend 2017 was $18.4 billion at SEC pricing, including hedges
Antero’s estimated proved reserves at December 31, 2017 were 17.3 Tcfe, a 12% increase compared to estimated proved reserves at December 31, 2016. Proved, probable and possible (“3P”) reserves at yearend 2017 totaled 54.6 Tcfe, which represents an 18% increase compared to the previous year. For further discussion of 3P reserves, please read “NonGAAP Disclosure.”
Proved developed finding and development (“F&D”) cost for estimated proved developed reserve additions was $0.54 per Mcfe for 2017. Allin F&D cost for estimated proved reserve additions, including acquisitions, was $0.59 per Mcfe for 2017. Future development costs for proved undeveloped locations are estimated to be $0.37 per Mcfe. The reserve life of the Company’s estimated proved reserves is approximately 21 years based on 2017 production. For further discussion of allin F&D cost and proved developed F&D cost, please read “NonGAAP Disclosure.” Antero’s estimated proved and 3P reserves at December 31, 2017 were prepared by its internal reserve engineers and audited by DeGolyer and MacNaughton (“D&M”). D&M’s reserve audit covered properties representing 100% of Antero’s total 3P reserves at December 31, 2017.
Estimated Proved Reserves
As of December 31, 2017, the Company’s 17.3 Tcfe of estimated proved reserves were comprised of 64% natural gas, 35% NGLs and 1% oil. The Marcellus Shale accounted for 90% of estimated proved reserves and the Ohio Utica Shale accounted for 10%. For 2017, Antero added 1.7 Tcfe of estimated proved reserves organically, excluding acquisitions, which is reflective of the continued productivity gains from the use of advanced completion techniques and longer laterals.
All 381 proved undeveloped locations in the Marcellus at yearend 2017 were booked at an approximate 2 Bcf/1,000′ type curve. This compares to yearend 2016 at which time 81 proved undeveloped locations, or 21% of the total proved undeveloped locations in the Marcellus, were booked at the approximate 2 Bcf/1,000′ type curve. The primary driver behind the increase in the number of proved undeveloped locations booked at the higher approximate 2 Bcf/1,000′ type curve type curve is the increased production history observed from the implementation of advanced completions techniques.
Estimated proved developed reserves increased by 23% from yearend 2016 to 8.5 Tcfe at December 31, 2017. The percentage of estimated proved reserves classified as proved developed increased to 49% at December 31, 2017 from 45% at yearend 2016. The average heating content of Antero’s proved undeveloped locations is 1237 BTU, and the average lateral length is approximately 10,500 feet.
Under the Securities and Exchange Commission (“SEC”) reporting rules, proved undeveloped reserves are limited to reserves that are planned to be developed within five years of initial booking. The Company reclassified 2,778 Bcfe of formerly nonproved reserves to proved undeveloped due to their addition to Antero’s fiveyear development plan. Included in this reclassification was the revision of 286 Bcfe related to an improvement in performance from advanced completions and a 291 Bcfe revision related to a lateral extension of previously booked locations. Additionally, the Company reclassified 2,280 Bcfe of generally lower BTU proved undeveloped reserves to the probable category in 2017 to comply with the SEC fiveyear development rule. Antero’s 8.8 Tcfe of estimated proved undeveloped reserves will require an estimated $3.3 billion of future development capital over the next five years, resulting in an estimated average future development cost for proved undeveloped reserves of $0.37 per Mcfe.
Antero incurred estimated capital costs of approximately $1.7 billion during 2017, including drilling and completion costs of $1.282 billion, proved property acquisitions of $176 million and leasehold additions of $204 million. Based on the $1.7 billion of capital costs, 2017 allin F&D cost for proved reserve additions from all sources, including acquisitions and revisions, was $0.59 per Mcfe.
Summary of Changes in Estimated Proved Reserves (in Bcfe) 

Balance at December 31, 2016 
15,386 

Extensions, discoveries and additions 
1,711 

Purchases of estimated proved reserves 
373 

Revisions to prior estimates 
726 

Ethane recovery revision 
(113) 

Production 
(822) 

Balance at December 31, 2017 
17,261 

The table below summarizes both SEC and strip pricing as of December 31, 2017 and the associated PV10 for estimated proved reserves and hedge values:
2017 YearEnd 

Benchmark Pricing: 
SEC Pricing 
Strip Pricing(1) 
Variance 
% Variance 

WTI Oil Price ($/Bbl) 
$51.03 
$53.44 
$2.41 
5% 

Appalachian Oil Price ($/Bbl)(2) 
$45.35 
$47.70 
$2.35 
5% 

Nymex Natural Gas Price ($/MMBtu) 
$3.11 
$2.93 
$(0.18) 
(6)% 

Appalachian Natural Gas Price ($/MMBtu)(2) 
$2.91 
$2.63 
$(0.28) 
(10)% 

C3+ Natural Gas Liquids ($/Bbl) (3) 
$32.37 
$32.23 
$(0.14) 
0% 

C2+ Natural Gas Liquids ($/Bbl)(3) 
$20.40 
$20.62 
$0.22 
1% 

PreTax PV10 Values ($Bn): 

Estimated proved reserves PV10 
$10.2 
$9.1 
$(1.1) 
(11)% 

Hedge PV10 (4) 
0.6 
1.2 
0.6 
100% 

Total PV10 
$10.8 
$10.3 
$(0.5) 
(5)% 
1) 
Strip pricing as of December 31, 2017 for each of the first ten years and flat thereafter. 

2) 
Represents SEC and strip prices as of December 31, 2017 on a weighted average Appalachian index basis related to companyspecific sales points.
Proved, Probable and Possible Reserves Antero estimates that it had yearend 2017 3P reserves of 54.6 Tcfe, an 18% increase from yearend 2016. The 18% increase in 3P reserves was driven by a combination of increased type curves in certain areas driven by continued productivity gains from advanced completions, as well as 2017 leasehold acquisitions. As of December 31, 2017, the Company’s 54.6 Tcfe of 3P reserves were comprised of 75% natural gas, 23% NGLs and 2% oil. The Marcellus and Ohio Utica Shale comprised 48.3 Tcfe and 6.4 Tcfe of the 3P reserves, respectively. Virtually no Upper Devonian or West Virginia Utica reserves were included in 3P reserves. Importantly, 46.2 Tcfe of Antero’s 48.3 Tcfe, or 96% of estimated Marcellus 3P reserves were classified as proved and probable reserves (“2P”), reflecting the low risk and statistically repeatable nature of Antero’s resource base. The 46.2 Tcfe of Marcellus 2P reserves includes 381 proved undeveloped and 460 probable locations, or 26% of the total undeveloped 2P reserve locations in the Marcellus that were booked at the approximate 2 Bcf/1,000′ type curve. This compares to yearend 2016 where 81 proved undeveloped and 7 probable locations, or just 3% of the total undeveloped 2P reserve locations in the Marcellus were booked at the approximate 2 Bcf/1,000′ type curve. The increase in upgraded 2P locations is primarily driven by continued productivity gains from implementing advanced completions techniques across a larger subset of Antero’s acreage position. Further, 6.2 Tcfe of Antero’s 6.4 Tcfe, or 97% of estimated 3P reserves in the Ohio Utica were classified as 2P. The tables below summarize Antero’s estimated 3P reserve volumes as of December 31, 2017 using SEC pricing, categorized by operating area as well as PV10 values of Antero’s 3P reserve volumes using both SEC and strip pricing. For further discussion of 3P reserves, please read “NonGAAP Disclosure.”
NonGAAP Disclosure Certain selected financial information in this release is unaudited. Additional unaudited financial information will be provided in Antero’s Annual Report on Form 10K for the year ended December 31, 2017, which the Company filed with the SEC on February 13, 2018. In this release, Antero has provided a number of unaudited metrics, which include allin F&D cost per unit and proved developed F&D cost per unit. These nonGAAP metrics are commonly used in the exploration and production industry by companies, investors and analysts in order to measure a company’s ability of adding and developing reserves at a reasonable cost. The F&D costs per unit are statistical indicators that have limitations, including their predictive and comparative value. In addition, because the F&D costs per unit do not consider the cost or timing of future production of new reserves, such measures may not be adequate measures of value creation. These reserve metrics may not be comparable to similarly titled measurements used by other companies. There are no directly comparable financial measures presented in accordance with GAAP for allin F&D cost per unit and proved developed F&D cost per unit, and therefore a reconciliation to GAAP is not practicable. Calculations for allin and proved developed F&D cost per unit are based on costs incurred in 2017. The calculations for both allin and proved developed F&D cost per unit do not include future development costs required for the development of proved undeveloped reserves. Pretax PV–10 values and pretax PV10 values including hedges are nonGAAP financial measures as defined by the SEC. Antero believes that the presentation of these pretax PV–10 values are relevant and useful to its investors because it presents the discounted future net cash flows attributable to reserves and hedges prior to taking into account corporate future income taxes and the Company’s current tax structure. The Company further believes investors and creditors use pretax PV10 values as a basis for comparison of the relative size and value of its reserves and hedges as compared with other companies. Antero believes that PV–10 estimates using strip pricing and including hedges can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows in the current commodity price environment. PV–10 estimates using strip pricing are not adjusted for the likelihood that the pricing scenario will occur, and thus they may not be comparable to PV–10 value using SEC pricing. The GAAP financial measure most directly comparable to pretax PV–10 is the standardized measure of discounted future net cash flows (“Standardized Measure”). The following sets forth the estimated future net cash flows from our proved reserves (without giving effect to our commodity derivatives), the present value of those net cash flows before income tax (PV10) and the present value of those net cash flows after income tax (Standardized measure) at December 31, 2017:
Notwithstanding their use for comparative purposes, the Company’s nonGAAP financial measures may not be comparable to similarly titled measures employed by other companies. Antero has provided summations of its proved, probable and possible reserves and summations of its PV10 for its proved, probable and possible reserves in this press release. The SEC strictly 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. Investors should be cautioned that estimates of PV10 of probable reserves, as well as underlying volumetric estimates, are inherently more uncertain of being recovered and realized than comparable measures for proved reserves, and that the uncertainty for possible reserves is even more significant. Further, because estimates of probable and possible reserve volumes have not been adjusted for risk due to this uncertainty of recovery, their summation may be of limited use. 