- Proved reserves increased by 78% to 7.6 Tcfe and 3P reserves increased by 62% to 35.0 Tcfe at year-end 2013
- Proved developed reserves increased by 117% to 2.0 Tcfe at year-end 2013
- Replaced 1,857% of estimated production in 2013
- Achieved all-in finding and development costs of
$0.58per proved Mcfe during 2013
- Increased proved reserves pre-tax PV10 by 133% to
$7.0 billion, including hedges
Antero replaced 1,857% of estimated production in 2013 from all sources including performance and price revisions. Finding and development costs for proved reserve additions from all sources including costs incurred for drilling capital, acquisitions, leasehold additions and all price and performance revisions averaged
$0.58 per Mcfe, based on preliminary unaudited capital expenditure amounts for 2013. Drill-bit only finding and development costs averaged $0.45 per Mcfe for 2013. Antero's proved developed reserve additions totaled 1,281 Bcfe on $1.6 billion of drilling capital for a development cost of $1.25 per Mcfe in 2013. The Company's reserve life of its proved reserves, based on estimated 2013 production, is approximately 40 years.
Proved reserves increased by 78% to 7.6 Tcfe as of
December 31, 2013. The Marcellus Shale accounted for 95% of Antero's proved reserve volumes at December 31, 2013 and the Utica Shale accounted for the remaining 5%. Also at year-end 2013, 88% of Antero's proved reserves by volume were natural gas, 11% were natural gas liquids ("NGLs") and 1% was oil. As of December 31, 2013, 23% of Antero's 450,000 net acres of leasehold in the Marcellus and Utica was classified as proved. 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.
Antero added 3.7 Tcfe of proved reserves in 2013 primarily in the
Marcellus Shale. NGLs and oil increased by 98 million barrels and 7 million barrels, respectively, due to Antero's 2013 drilling program targeting liquids-rich locations in the Marcellus and Utica Shales. Negative performance revisions of 157 Bcfe of proved reserves were due to the reclassification of 65 wells, or 374 Bcfe, to the probable category due to the SEC 5-year development rule partly offset by improved Marcellus well performance from SSL completions.
Proved developed reserves increased 117% from year-end 2012 to over 2.0 Tcfe at
December 31, 2013. The Company added 113 Marcellus wells to proved developed reserves in 2013. These wells had an average estimated ultimate recovery ("EUR") of 10.6 Bcfe and an average lateral length of 7,308 feet. During 2013, Antero placed on line 26 Marcellus wells using SSL completions with encouraging results. Based on these results, Antero has increased its EUR per 1,000 feet of lateral by 18% to 1.73 Bcf for 1,768 gross SSL undeveloped 3P Marcellus locations out of the 3,067 total gross undeveloped 3P Marcellus locations, or 58%. Included in the gross SSL undeveloped 3P Marcellus locations are 91 gross SSL locations categorized as proved undeveloped out of the 665 total gross proved undeveloped Marcellus locations, or 14%. Antero has recently decided to complete virtually all wells in 2014 with SSL and expects further increases to the portion of gross undeveloped 3P Marcellus locations that assume SSL completions.
Antero added 11 Utica wells to the proved developed reserves category in 2013 consisting of 2 rich gas (1100-1200 BTU), 4 highly-rich gas (1200 to 1250 BTU) and 5 highly-rich/condensate (1250 to 1300 BTU) wells. The wells located in the rich gas and highly-rich gas regimes had an average EUR of 18.8 Bcfe (15% liquids) and 20.5 Bcfe (23% liquids), respectively, normalized to a 7,000' lateral. These EURs are consistent with previous estimates. Additionally, the wells located in the highly-rich/condensate regime had an average EUR of 11.3 Bcfe (32% liquids), normalized to a 7,000' lateral, representing an 18% decrease from previous estimates. This reduction was due to lower production performance from the highly-rich/condensate wells in 2013, which were producing in a high pressure (1100 psi) environment with no compression during the year.
The Company has provided single well economics assuming the increased Marcellus SSL type curve and the updated
Utica type curves in the February 2014 corporate presentation which has been posted to its website atwww.anteroresources.com.
Antero's estimate of drilling and development costs incurred during 2013, including drilling and completion of
$1.6 billion and leasehold acquisition of $0.4 billion, is $2.0 billion. Assuming the $2.0 billion estimate of drilling and development costs, preliminary finding and development costs from all sources for 2013 averaged $0.58per Mcfe. Three-year finding and development costs for Antero from all sources through 2013 averaged $0.55per Mcfe, excluding the divested Arkoma and Piceance Basin properties. The 2013 capital costs are unaudited and preliminary. Audited and final results will be provided in Antero's Annual Report on Form 10-K for the year ended December 31, 2013.
The percentage of proved reserves classified as proved developed increased to 27% at
December 31, 2013 as compared to 22% at year-end 2012. Proved undeveloped reserves increased by 67% as a result of the successful execution of Antero's Marcellus Shale development drilling plan. The 67% increase was driven by the addition of 195 gross proved undeveloped drilling locations and an increase in expected recoveries in the Marcellus Shale for 91 gross proved undeveloped locations based on SSL completions.
SEC reporting rules, proved undeveloped reserves are limited to reserves that are planned to be developed in the next five years. Antero's 5.6 Tcfe of proved undeveloped reserves will require an estimated $5.3 billion of development capital over the next five years, resulting in an estimated average development cost for proved undeveloped reserves of $0.95 per Mcfe.
Antero's proved reserves at
December 31, 2013 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 proved reserves at December 31, 2013 and was within 2% of Antero's internal reserve estimates.
Proved, Probable and Possible Reserves
Antero estimates that it had year-end 2013 3P reserves of 35.0 Tcfe, a 62% increase over year-end 2012 3P reserves of 21.6 Tcfe, in each case assuming ethane rejection. The 3P reserves contain 29.6 Tcf of natural gas, 811 million barrels of NGLs, excluding 1,339 million barrels of ethane, and 91 million barrels of oil. The Marcellus,
Utica, and Upper Devonian Shale comprised 25.0 Tcfe, 5.8 Tcfe and 4.2 Tcfe of the 3P reserves, respectively. The 62% increase in 3P reserves was driven by the addition of 51,000 net acres in the Marcellus Shale in northern West Virginia and 28,000 net acres in the Utica Shale in southern Ohio and the implementation of SSL completions. Importantly, 24.1 Tcfe of Antero's 25.0 Tcfe 3P reserves in the Marcellus, or 97%, was classified as proved and probable ("2P"), reflecting the low risk nature of Antero's Marcellus reserves.
The table below summarizes Antero's estimated 3P reserve volumes using
SEC pricing, broken out by operating area:
Upper Devonian Shale
Marcellus and Total PV10 includes $1.0 billion of Antero hedges at SEC pricing
Represents liquids volumes as a % of total volumes. Liquids comprised of 811 million barrels of NGLs and 91 million barrels of oil.
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. Antero's pre-tax PV10 value as of
December 31, 2013 may be reconciled to its standard measure of discounted future net cash flows as of December 31, 2013 by reducing Antero's pre-tax PV10 value by the discounted future income taxes associated with such reserves.
This release includes "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. 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.
We caution 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 our 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, NGLs 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 "Risk Factors" in our Final Prospectus dated
October 9, 2013 on file with the Securities and Exchange Commission(File No. 333-189284).
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, we note 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.
"EUR," or Estimated Ultimate Recovery, refers to Antero's internal estimates of per well hydrocarbon quantities that may be potentially recovered from a hypothetical future well completed as a producer in the area. These quantities do not necessarily constitute or represent reserves within the meaning of the
Society of Petroleum Engineer's Petroleum Resource Management System or the SEC's oil and natural gas disclosure rules.
This release provides a summary of Antero's reserves as of
December 31, 2013, 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.
Michael Kennedy - VP Finance, at (303) 357-6782 or email@example.com.
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