Antero Resources Announces 12% Increase in Estimated Proved Reserves to 17.3 Tcfe

DENVER, Feb. 13, 2018 /PRNewswire/ -- 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 year-end 2017 (36% liquids), compared to year-end 2016
• Pre-tax PV-10 of proved reserves at year-end 2017 was $10.8 billion at SEC pricing, including hedges
• Proved developed reserves increased by 23% to 8.5 Tcfe at year-end 2017, compared to year-end 2016
• $0.54 per Mcfe proved developed finding and development cost for 2017
• $0.37 per Mcfe future development cost for year-end 2017 proved undeveloped reserves
• 3P reserves increased by 18% to 54.6 Tcfe at year-end 2017 (25% liquids), compared to year-end 2016
• Pre-tax PV-10 of 3P reserves at year-end 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 year-end 2017 totaled 54.6 Tcfe, which represents an 18% increase compared to the previous year.  For further discussion of 3P reserves, please read "Non-GAAP Disclosure."

Proved developed finding and development ("F&D") cost for estimated proved developed reserve additions was $0.54 per Mcfe for 2017. All-in 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 all-in F&D cost and proved developed F&D cost, please read "Non-GAAP 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 year-end 2017 were booked at an approximate 2 Bcf/1,000' type curve.  This compares to year-end 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 year-end 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 year-end 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 non-proved reserves to proved undeveloped due to their addition to Antero's five-year 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 five-year 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 all-in F&D cost for proved reserve additions from all sources, including acquisitions and revisions, was $0.59 per Mcfe.

The table below summarizes both SEC and strip pricing as of December 31, 2017 and the associated PV-10 for estimated proved reserves and hedge values: 

Proved, Probable and Possible Reserves

Antero estimates that it had year-end 2017 3P reserves of 54.6 Tcfe, an 18% increase from year-end 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 year-end 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 PV-10 values of Antero's 3P reserve volumes using both SEC and strip pricing.  For further discussion of 3P reserves, please read "Non-GAAP Disclosure." 

Non-GAAP Disclosure

Certain selected financial information in this release is unaudited.  Additional unaudited financial information will be provided in Antero's Annual Report on Form 10-K 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 all-in F&D cost per unit and proved developed F&D cost per unit.  These non-GAAP 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 all-in F&D cost per unit and proved developed F&D cost per unit, and therefore a reconciliation to GAAP is not practicable.

Calculations for all-in and proved developed F&D cost per unit are based on costs incurred in 2017. The calculations for both all-in and proved developed F&D cost per unit do not include future development costs required for the development of proved undeveloped reserves.   

Pre-tax PV-10 values and pre-tax PV-10 values including hedges are non-GAAP financial measures as defined by the SEC.  Antero believes that the presentation of these pre-tax 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 pre-tax PV-10 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 pre-tax 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 (PV-10) 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 non-GAAP 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 PV-10 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 PV-10 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. 

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 West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.

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, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future development costs, future capital spending plans, expected drilling and development plans, plans with respect to the rejection of ethane and the prices we will receive for future production as well as future production volumes are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  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, 2017.

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 not 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, 2017, assuming partial ethane "rejection" where sales demand for ethane is not available.  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