Antero Resources Announces Proved Reserves Increased 183% to 3.2 Tcfe; Provides 2011 Capital Budget and Hedging Update
DENVER, Feb. 23, 2011 /PRNewswire/ -- Antero Resources announced today that its proved reserves at December 31, 2010 increased 183% to 3.2 Tcfe. From all sources, Antero estimates that it replaced 4,447% of production in 2010 with 3,643% of the reserve replacement occurring through the drill bit and the booking of natural gas liquids (NGLs). Finding and development costs from all sources, including acquisitions, leasehold additions and all price and performance revisions averaged $0.28 per Mcfe in 2010. Additionally, Antero's board of directors has approved a preliminary 2011 capital budget of $519 million. Antero also announced that it has increased its natural gas hedge position by 52% since November 2010 to 301 Bcfe with an average NYMEX-equivalent price of $6.14 per MMBtu.
Reserves
For 2010, Antero added 1,712 Bcfe of proved reserves through the drill bit and NGL booking, and 172 Bcfe was added through acquisitions. Positive performance and price revisions increased proved reserves by 253 Bcfe. As a result, year-end 2010 proved reserves totaled 3.2 Tcfe, up 183% from 1.1 Tcfe at year-end 2009. Proved developed reserves increased 66% year over year to 457 Bcfe. Antero estimates year-end 2010 proved, probable and possible reserves (3P) of 10.4 Tcfe.
Antero has elected to report NGLs separately from natural gas, beginning with its 2010 year-end reserve report. Due to the execution of a gas processing agreement for its Piceance gas production in December 2010, Antero believes that separate disclosure of NGLs will provide more transparency to its production and reserve reporting. At year-end 2010, 79% of Antero's proved reserves by volume were natural gas, 19% were NGLs and 2% were crude oil compared to 99% natural gas and 1% oil as of year-end 2009 when the Company did not disclose NGLs separately.
The Company's 2010 proved reserves were distributed as follows: 51% in the Piceance Basin, 26% in the Woodford Shale, 21% in the Marcellus Shale and 2% in the Fayetteville Shale. As of year-end 2010, only 8% of Antero's 166,000 net Marcellus acres were classified as proved. Given Antero's successful drilling results to date as well as those of other operators, Antero believes that a substantial portion of its Marcellus Shale acreage will be classified as proved over time as more wells are drilled. The percentage of proved reserves in the proved undeveloped category increased to 86% at year-end 2010 as compared to 76% at year-end 2009. The significant increase in proved undeveloped reserves was primarily attributable to positive drilling results in the Marcellus Shale and Piceance Basin, expected improvement in price realizations in the Piceance Basin due to the recently executed gas processing agreement, the volumetric uplift realized from reporting NGLs separately in the Piceance Basin and Woodford Shale and increased well density in the East Rockpile area of the Woodford Shale.
Under Securities and Exchange Commission (SEC) reporting rules, proved reserves are limited to reserves that are planned to be developed in the next five years. Antero's 2.8 Tcfe of proved undeveloped reserves will require an estimated $4.0 billion of development capital over the next five years resulting in an average development cost of $1.45 per Mcfe. Antero plans to utilize a combination of operating cash flow, expanding credit facility capacity and capital markets to fund the development capital costs.
Antero's Piceance Basin proved reserves were engineered by Ryder Scott Company. The Company's Woodford Shale, Marcellus Shale and Fayetteville Shale proved reserves were all engineered by DeGolyer and MacNaughton. All probable and possible reserves were engineered by Antero's internal reserve engineering staff.
The table below summarizes Antero's estimated 3P reserve volumes at SEC pricing, broken out by operating area:
Reserve Estimates (Bcfe)(1) Marcellus Piceance Woodford Other(2) TOTAL Proved Reserves 677 1,654 831 69 3,231 Probable Reserves 3,628 182 207 14 4,031 Possible Reserves 2,240 141 754 40 3,175 Total Proved, Probable and Possible Reserves (3P) 6,545 1,977 1,792 123 10,437 % of 3P Volume by Basin 63% 19% 17% 1% (1) – Oil and NGLs are converted to natural gas reserves using a 6 Mcfe per Bbl ratio. (2) – Includes Fayetteville and Ardmore Woodford
Antero's estimate of cash drilling and development costs plus land, acquisitions, drilling pad and water handling infrastructure costs incurred during 2010 is $588 million. Finding and development costs from all sources for 2010 averaged $0.28 per Mcfe including price revisions and acquisitions. Three-year finding and development costs for Antero from all sources through 2010 averaged $0.59 per Mcfe, which Antero believes is one of the lowest in the industry.
The current SEC rules require that reserve calculations be based on the average first of month prices throughout the previous calendar year. Actual NYMEX prices for 2010 averaged $4.38/MMBtu, while the benchmark producing basin natural gas prices utilized were $4.18 per MMBtu in the Arkoma Basin, $3.93 per MMBtu in the Piceance Basin and $4.51 per MMBtu in Appalachian Basin. Based on SEC prices adjusted for energy content and quality, the pre-tax present value discounted at 10% ("pre-tax PV10") of the year-end 2010 proved reserves was $1.5 billion, excluding the Company's natural gas hedges. Including Antero's current hedges at 2010 SEC prices and discounted at 10%, the pre-tax PV10 value of the year-end 2010 proved reserves was $1.9 billion.
Using the 5-year futures NYMEX strip prices averaging $5.23 per MMBtu at December 31, 2010, along with the corresponding benchmark producing basin natural gas prices which were $4.84 per MMBtu in the Arkoma Basin, $4.73 per MMBtu in the Piceance Basin and $5.24 per MMBtu in the Appalachian Basin, the pre-tax PV10 value of the same year-end 2010 proved reserves was $2.7 billion, excluding the company's hedges. Including the Company's current hedges at the 5-year futures strip prices above, the pre-tax PV10 value of the year-end 2010 proved reserves was $2.9 billion.
Summary of Changes in Proved Reserves (in Bcfe) Balance at December 31, 2009 1,141 Extensions, discoveries, book NGLs and additions 1,712 Purchases 172 Price and performance revisions 253 Sales - Production (47) Balance at December 31, 2010 3,231
2011 Capital Budget and Production Guidance
Antero's preliminary capital budget for 2011 is $519 million and includes $452 million for drilling and completion, $42 million for the construction of gathering pipelines and facilities and $25 million for leasehold acquisitions. Approximately 71% of the budget is allocated to the Marcellus Shale, 15% is allocated to the Woodford Shale and Fayetteville Shale and 14% is allocated to the Piceance Basin. During 2011, Antero plans to operate five drilling rigs in the Marcellus Shale, one drilling rig in the Woodford Shale and one drilling rig in the Piceance Basin. The capital budget is expected to be funded internally from operating cash flow and through the use of the undrawn capacity under Antero's bank credit facility. At December 31, 2010, Antero had $404 million of available borrowing capacity under its bank credit facility and $9 million of cash on hand, resulting in total liquidity of $413 million.
Antero estimates that 2011 production will average 190 to 200 MMcfed, which would result in a 45% increase over estimated 2010 production. The Company anticipates that 10% of its 2011 production will be NGLs and oil.
Gas Processing
Antero recently entered into a long-term gas processing agreement in the Piceance Basin allowing it to realize a processing margin on its Piceance gas production effective January 1, 2011. Antero believes that virtually all of its Piceance gas production is liquids-rich gas that can be processed under current market conditions. Antero estimates that over 35% of its year end 2010 Piceance proved reserves are liquids, primarily comprised of NGLs. Antero has an existing gas processing agreement in the Woodford Shale under which a portion of the Company's operated and non-operated gas production is processed. Antero estimates that 9% of its year end 2010 Woodford Shale proved reserves are liquids, primarily comprised of NGLs. Antero is also reviewing gas processing and NGL market alternatives in the Marcellus Shale play where it believes that a substantial portion of its resource base is comprised of liquids-rich gas.
Commodity Hedge Update
Antero has hedged 301 Bcfe of future production using fixed price swaps covering the period from January 2011 through December 2015 at an average NYMEXequivalent price of $6.14 per MMBtu. Over 80% of Antero's estimated 2011 production is hedged at a NYMEXequivalent price of $6.17 per MMBtu. Virtually all of Antero's financial hedges are tied to the local basin. For presentation purposes, these basin prices are converted by Antero to NYMEXequivalent prices using current basis differentials in the over-the-counter futures market. Antero has eight different counterparties to its hedge contracts, all of which are lenders in Antero's bank credit facility. All of Antero's natural gas hedges are simple fixed price swaps.
The following table summarizes Antero's hedge positions held as of today:
Natural gas NYMEX-
equivalent Equivalent
Calendar Year MMBtu/day index price
2011 164,430 $6.17
2012 173,385 $6.30
2013 167,444 $6.31
2014 200,000 $6.16
2015 120,000 $5.63
The information in this release is unaudited and subject to revision. Audited and final results will be provided in the Company's Annual Report on Form 10-K for the year ended December 31, 2010 which is currently planned to be filed with the Securities and Exchange Commission by the end of March 2011.
Antero has disclosed two primary metrics in this release to measure our ability to establish a long-term trend of adding reserves at a reasonable cost – a reserve replacement ratio and finding and development cost per unit. The reserve replacement ratio is an indicator of our ability to replace annual production volumes and grow our reserves. It is important to economically find and develop new reserves that will offset produced volumes and provide for future production given the inherent decline of hydrocarbon reserves as they are produced. The reserve replacement ratio is calculated by dividing production for the year into the total of proved extensions, discoveries and additions, and the increase of reserves due to changes in prices and performance as shown in the table.
Finding and development cost per unit is a non-GAAP metric used in the exploration and production industry by companies, investors and analysts. The calculations presented by the Company are based on estimated and unaudited costs incurred excluding asset retirement obligations and divided by proved reserve additions (extensions, discoveries and additions shown in the table) adjusted for the changes in proved reserves for price and performance revisions. This calculation does not include the future development costs required for the development of proved undeveloped reserves.
The reserve replacement ratio and finding and development cost per unit are statistical indicators that have limitations, including their predictive and comparative value. As an annual measure, the reserve replacement ratio can be limited because it may vary widely based on the extent and timing of new discoveries and the varying effects of changes in prices and well performance. In addition, since the reserve replacement ratio and finding and development cost per unit do not consider the cost or timing of future production of new reserves, such measures may not be an adequate measure of value creation. The reserve metrics may not be comparable to similarly titled measurements used by other companies.
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, 2010 may be reconciled to its standardized measure of discounted future net cash flows as of December 31, 2010 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 reserve estimates, in the Company's 2010 Annual Report on Form 10-K for the year ended December 31, 2010.
Antero Resources is an independent oil and natural gas company engaged in the acquisition, development and production of unconventional natural gas properties primarily located in the Appalachian Basin in West Virginia and Pennsylvania, the Arkoma Basin in Oklahoma and the Piceance Basin in Colorado.
Cautionary Statements
This release includes forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond Antero's control. All information, other than historical facts included in this release, regarding the intended terms and use of proceeds of the offering is forward-looking information. 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.
The SEC, under its recently revised guidelines, 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.
SOURCE Antero Resources
Released February 23, 2011