Antero Reports 73% Increase in Appalachian Proved Reserves to 4.9 Tcfe
DENVER, Jan. 28, 2013 /PRNewswire/ — Antero Resources announced today that proved reserves at December 31, 2012 were 4.9 Tcfe, a 73% increase compared to reserves at December 31, 2011, pro forma for the 2012 divestment of Antero’s Arkoma Basin and Piceance Basin properties. Proved, probable and possible reserves (3P) increased by 94% to 26.1 Tcfe. The 3P reserves were comprised of 21.2 Tcfe in the Marcellus Shale and 5.0 Tcfe in the Utica Shale. Including ethane and other natural gas liquids (NGLs), Antero’s 3P liquids reserves increased by 170% to 1.6 billion barrels at December 31, 2012. Preliminary finding and development costs for proved reserve additions from all sources including drill bit, acquisitions, leasehold additions and all price and performance revisions averaged $0.68 per Mcfe in 2012. Antero’s proved developed reserve additions totaled 715 Bcfe on $816 million of drilling capital for a development cost of $1.14 per Mcfe in 2012. Drilling capital is defined as drilling and completion, drilling pad and water handling infrastructure costs. Antero also announced that it has increased its natural gas hedge position since November 2012 to 810 Bcfe hedged for the first quarter of 2013 through the fourth quarter of 2018 with an average NYMEX-equivalent price of $4.98 per MMBtu.
Proved reserves increased by 73% to 4.9 Tcfe as of December 31, 2012, despite a 34% decline in SEC gas prices. The Marcellus Shale accounted for 97% of Antero’s proved reserve volumes at December 31, 2012 and the Utica Shale accounted for the remaining 3%. Also at year-end 2012, 75% of Antero’s proved reserves by volume were natural gas, 24% were NGLs and 1% was crude oil. As of December 31, 2012, 21% of Antero’s 295,000 net acres of leasehold in the Marcellus was classified as proved. Given 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 Shale acreage will be added to proved reserves over time as more wells are drilled. The 61 Marcellus wells that were added to the proved developed category in 2012 had an average EUR of 11.6 Bcfe and an average lateral length of 7,381 feet.
Antero added 2.0 Tcfe of proved reserves through the drill bit in 2012 including 106 million barrels of NGLs and 3 million barrels of oil, primarily in the Marcellus Shale. Also included in the extensions category are 123 Bcfe of proved reserves added in the Utica Shale play in Ohio based on Antero’s early-stage drilling success in the play. Revisions included 324 Bcfe of proved reserves added due to improved Marcellus well performance but were partially offset by 102 Bcfe subtracted due to lower gas and NGL prices. The 2012 divestiture of the Arkoma and Piceance Basin properties resulted in a reduction of almost 2.2 Tcfe from year-end 2012 proved reserves. Net production for 2012 totaled 87 Bcfe, excluding production attributable to the Arkoma and Piceance Basins. Proved developed reserves increased 149% from year-end 2011 to over 1.0 Tcfe at December 31, 2012, excluding the Arkoma and Piceance Basin properties.
Antero’s estimate of upstream capital costs incurred in 2012, including drilling and completion, leasehold and acquisition, and drilling pad and water handling infrastructure, is $1.5 billion, subject to a year-end financial audit. Preliminary finding and development costs from all sources for 2012 averaged $0.68 per Mcfe including price revisions and acquisitions, after adding back production for the year. Three-year finding and development costs for Antero from all sources through 2012 averaged $0.53 per Mcfe, excluding the Arkoma and Piceance Basin properties.
The percentage of proved reserves classified as proved developed increased to 21% at December 31, 2012 as compared to 15% at year-end 2011, excluding the Arkoma and Piceance Basin properties. Proved undeveloped reserves increased by 60% as a result of the successful execution of Antero’s Marcellus Shale development drilling plan. The 60% increase was driven by the addition of 167 gross proved undeveloped drilling locations and an increase in expected recoveries in the Marcellus Shale based on well performance.
Under Securities and Exchange Commission (SEC) reporting rules, proved undeveloped reserves are limited to reserves that are planned to be developed in the next five years. Antero’s 3.9 Tcfe of proved undeveloped reserves will require an estimated $3.2 billion of development capital over the next five years, resulting in an estimated average development cost for proved undeveloped reserves of $0.84 per Mcfe. Antero plans to utilize a combination of operating cash flow, credit facility capacity and funds from potential future capital markets transactions and non-core asset sales to fund the development costs.
Antero’s proved reserves at December 31, 2012 were prepared by its internal reserve engineers and audited by DeGolyer and MacNaughton (D&M). D&M’s reserve audit covered properties representing over 80% of Antero’s total estimated proved reserves at December 31, 2012 and was within 1% of Antero’s internal reserve estimates.
SEC prices for reserves calculated as of December 31, 2012 averaged $2.76 per MMBtu, while the benchmark Appalachian Basin natural gas price was $2.78 per MMBtu, based on SEC pricing. Using SEC prices adjusted for energy content and quality, the pre-tax present value discounted at 10% (pre-tax PV10) of the December 31, 2012 proved reserves was $1.9 billion, excluding the Company’s natural gas and oil hedges. Including Antero’s current hedges and using SEC prices, the pre-tax PV10 value of proved reserves was $3.2 billion, a 20% increase over year-end 2011 (excluding the Arkoma and Piceance Basin properties). The pre-tax PV10 value of proved developed reserves was $1.0 billion excluding hedges and $2.3 billion including current hedges.
Using the 5-year futures NYMEX strip prices which averaged $4.16 per MMBtu at December 31, 2012, along with the corresponding benchmark producing basin natural gas prices ($4.03 per MMBtu in the Appalachian Basin), the pre-tax PV10 value of the same year-end 2012 proved reserves was $3.7 billion, excluding the company’s hedges, and $4.2 billion including the Company’s hedges. Using the same strip pricing, the pre-tax PV10 value of proved developed reserves at December 31, 2012 was $1.5 billion excluding hedges and $1.9 billion including current hedges.
Year-end pre-tax PV10 value may be considered 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 proved 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, 2012 may be reconciled to its standard measure of discounted future net cash flows as of December 31, 2012 by reducing Antero’s pre-tax PV10 value by the discounted future income taxes associated with such reserves. This reconciliation is not currently available and will be included, along with additional disclosure regarding Antero’s reserves estimates, in the Company’s 2012 Annual Report on Form 10-K for the year ended December 31, 2012.
Summary of Changes in Proved Reserves (in Bcfe) ---------------------------------------------- Balance at December 31, 2011 5,017 Extensions, discoveries and additions 1,951 Purchases - Performance revisions 324 Price revisions (102) Sales (2,174) Production (87) --- Balance at December 31, 2012 4,929
Proved, Probable and Possible Reserves
Antero estimates that it had year-end 2012 3P reserves of 26.1 Tcfe, a 94% increase over year-end 2011, excluding the Arkoma and Piceance Basin properties. The 3P reserves were comprised of 16.0 Tcf of natural gas, 1.6 billion barrels of NGLs and 55 million barrels of oil. NGLs and oil comprised 38% of 3P reserves at year-end 2012. The 94% pro forma increase in 3P reserves was primarily driven by the addition of 84,000 net acres in the Marcellus Shale in northern West Virginia and 73,000 net acres in the Utica Shale in eastern Ohio through acquisitions and leasing. Importantly, 19.6 Tcfe of Antero’s 21.2 Tcfe 3P reserves in the Marcellus, or 92%, was classified as proved and probable (2P), reflecting the lower risk nature of Antero’s Marcellus reserves. Antero’s probable and possible reserves were prepared by its internal reserve engineering staff using SEC prices and have not been reviewed or audited by any third party engineering firm.
The table below summarizes Antero’s estimated 3P reserve volumes using SEC pricing, broken out by operating area:
Marcellus Shale Utica Shale Combined --------------- ----------- -------- Gas Liquids Total Gas Liquids Total Gas Liquids Total (Bcf) (MMBoe) (Bcfe) (Bcf) (MMBoe) (Bcfe) (Bcf) (MMBoe) (Bcfe) ---- ------ ----- ---- ------ ----- ---- ------ ----- Proved 3,632 195 4,806 61 10 123 3,693 205 4,929 Probable 8,651 1,018 14,758 75 12 148 8,726 1,030 14,906 Possible 1,183 69 1,596 2,657 342 4,710 3,840 411 6,306 ----- --- ----- ----- --- ----- ----- --- ----- Total 3P 13,466 1,282 21,160 2,793 364 4,981 16,259 1,646 26,141 % Liquids(1) 36% 44% 38% (1) - Liquids comprised of 1.591 billion barrels of NGLs and 55 million barrels of oil.
Commodity Hedge Update
Antero has hedged 810 Bcfe of future production using fixed price swaps covering the period from January 1, 2013 through December 2018 at an average NYMEX?equivalent price of $4.98 per MMBtu. Over 65% of Antero’s estimated 2013 natural gas production is hedged at a NYMEX?equivalent price of $4.99 per MMBtu. Approximately 10% of Antero’s financial hedges are NYMEX hedges and 90% are tied to the Appalachian basin. For the NYMEX hedges, Antero physically delivers its hedged gas through direct firm transportation to Henry, Louisiana, the index for NYMEX pricing, which eliminates basis risk on these NYMEX hedges as well. For presentation purposes, basin prices are converted by Antero to NYMEX?equivalent prices using current basis differentials in the over-the-counter futures market. Antero has 11 different counterparties to its hedge contracts, all but one of which are lenders in Antero’s bank credit facility.
The following table summarizes Antero’s hedge positions held as of today:
Natural gas NYMEX- equivalent Equivalent Calendar Year MMBtu/day index price ------------- --------- ----------- 2013 317,020 $4.99 2014 370,000 $5.23 2015 390,000 $5.40 2016 502,500 $5.04 2017 420,000 $4.37 2018 220,000 $4.83
(The 2012 capital costs contained herein are unaudited and preliminary. Audited and final results will be provided in our Annual Report on Form 10-K for the year ended December 31, 2012.)
Antero Resources is an independent oil and natural gas company engaged in the acquisition, development and production of unconventional oil and liquids-rich natural gas properties primarily located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. Our website is located at www.anteroresources.com.
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 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 our Annual Report on Form 10-K for the year ended December 31, 2011.
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 for probable and possible reserves in this release in accordance with SEC guidelines. The estimates of probable and possible reserves included in this release have not been prepared or reviewed by Antero’s third-party engineers. Antero’s estimate of 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.
SOURCE Antero Resources