Antero Resources Reports Second Quarter 2010 Results, Operating Update

DENVER, Aug. 13 /PRNewswire/ -- Antero Resources today released its second quarter 2010 results. Those financial statements are included in Antero Resources Finance Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, which has been filed with the Securities and Exchange Commission.

Financial Results

On a consolidated basis for the three months ended June 30, 2010, Antero realized net revenue of $67.4 million (including cash-settled derivatives but excluding unrealized derivative gains and losses), a 12% increase from the second quarter of 2009, primarily driven by increased production.  Reported GAAP earnings resulted in a net loss of $16.4 million. Driven by higher transportation costs and interest expense due to the issuance of senior notes, as well as lower realized gas prices including hedges, cash flow from operations before changes in working capital, a non-GAAP measure, declined 18% from the prior-year quarter to $28.5 million.

The reported GAAP loss includes the following non-cash items:

• an $18.3 million charge for impairment of unproved properties due to lease expirations.
• a $10.1 million unrealized gain on commodity derivatives.

Due primarily to higher transportation costs and lower realized gas prices including hedges, EBITDAX of $43.2 million for the second quarter of 2010 was 6% less than the prior-year quarter. See "Non-GAAP Financial Measures" below for the reconciliation of cash flow from operations before changes in working capital to net cash provided by operating activities and EBITDAX to net income.

Net Production for the quarter totaled 11.3 Bcfe, comprised of 10.5 Bcf of gas and 138,500 barrels of oil and natural gas liquids (NGLs), representing a 6% increase over the first quarter of 2010 and a 23% increase over the second quarter of 2009. Net daily production averaged 124.3 MMcfed for the quarter, a record high for the Company. While gas-equivalent realized prices before hedges increased 40% to $4.23 per Mcfe, wellhead gas-equivalent realized prices including cash-settled derivatives decreased 11% to $5.74 per Mcfe for second quarter 2010 compared to the second quarter of 2009. As a result of its commodity hedging program, Antero realized gains of $16.2 million during the second quarter of 2010, or $1.51 per Mcfe of production, from contracts hedging 90,000 MMBtu/d at a $6.21 NYMEX equivalent price. This represents a 44% decrease from the $29.0 million of realized hedging gains, $3.40 per Mcfe, in the prior year quarter.

Cash production costs (lease operating, gathering, compression and transportation and production tax) for the second quarter 2010 were $1.78 per Mcfe, a 51% increase from the prior year quarter. The increase in cash production costs was primarily driven by a $0.39 per Mcfe increase in interim transportation costs needed to move Antero's initial Marcellus Shale production as well as unexpected workover costs in the Piceance and Arkoma. Much of the Marcellus transportation cost increase will be eliminated when the Clarksburg Lateral is online, which is expected late in the third quarter of 2010. Depreciation, depletion and amortization expense decreased 25% to $3.02 per Mcfe. General and administrative expense for the second quarter 2010 was $0.44 per Mcfe, a 23% decrease from the second quarter of 2009, primarily due to a 23% increase in production while G&A expense remained flat.

For the last six months of 2010 and through the end of 2014, Antero has hedged a total of 187 Bcfe of natural gas using fixed price swaps at an average NYMEX-equivalent price of $6.54 per MMBtu. Approximately 72% of our 2010 estimated production is hedged, also at a NYMEX-equivalent price of $6.54 per MMBtu. All of Antero's financial hedges are hedged to the local basis. For presentation purposes, these prices are converted by Antero to NYMEX-equivalent prices using current basis differentials in the over-the-counter futures market. Antero has seven different counterparties to its hedge contracts, all of which are lenders in the Company's bank credit facility.

Proved Reserves

As of June 30, 2010, our estimated proved reserves were 1,513 Bcfe, representing an increase of 372 Bcfe, or 33%, compared to our estimated proved reserves at December 31, 2009. Over 90% of the reserve increase was due to extensions, discoveries and additions rather than price and performance revisions. Proved developed reserves were 348 Bcfe at June 30, 2010, a 73 Bcfe increase from December 31, 2009. The percentage of proved undeveloped reserves increased to 77% of total estimated proved reserves from 76% at December 31, 2009.

Our estimated proved reserves as of June 30, 2010 were prepared by our internal reserve engineers and technical staff consistent with the SEC's rules relating to the reporting of oil and natural gas reserves and have not been reviewed or approved by our outside independent reserve engineers. In preparing our proved reserve estimates as of June 30, 2010, our internal engineers and technical staff began with our estimated proved reserves as of December 31, 2009 prepared by our independent reserve engineers and rolled those estimates forward to reflect production since December 31, 2009, reserve additions since December 31, 2009, including the addition of proved undeveloped reserves, and certain revisions to our proved developed producing reserves. In addition, our estimated proved reserves as of June 30, 2010 were calculated based on the average first-day-of-the-month commodity prices for the 12 months ended June 30, 2010, which were $4.00 per MMBtu for the Arkoma Basin, $3.82 per MMBtu for the Piceance Basin and $4.31 per MMBtu for the Appalachian Basin.

All of our estimated proved reserves at December 31, 2009 were prepared by outside independent reserve engineers (DeGolyer and MacNaughton for the Arkoma Basin Woodford Shale and the Fayetteville Shale, Ryder Scott Company, L.P. for the Piceance Basin, and Wright & Company, Inc. for the Appalachian Basin).  Our estimated proved reserves at December 31, 2010 will also be prepared by outside independent reserve engineers.

Antero Operations

Antero's current gross operated production is 138 MMcfd (approximately 136 MMcfed net, including non-operated production and 7 MMcfed of NGLs). During the first half of 2010, Antero completed 19 gross operated wells (18 net wells). Additionally, at June 30, 2010, Antero had 21 gross operated wells (19 net wells) in various stages of drilling, completion or waiting on completion or pipeline.

Marcellus Shale—Antero has three operated drilling rigs running in the Marcellus Shale play, all of which are drilling in northern West Virginia. The Company has 38 MMcfd of gross operated production from 11 horizontal wells and one vertical well online resulting in 28 MMcfd of net production. Antero has 8 additional horizontal wells waiting on pipeline, completing or waiting on completion. Antero has 124,000 net acres in the Appalachian Basin Marcellus Shale play, an increase of 2,000 net acres since the first quarter of 2010.

Antero has secured 150 MMcfd of long-haul firm transportation capacity in Appalachia on Columbia Pipeline to move our gas to market. We have also entered into an agreement with Energy Transfer to build the 15-mile Clarksburg Lateral through the heart of Antero's West Virginia acreage to move gas from the field to long-haul pipelines including Columbia. Antero has 100 MMcfd of firm transportation capacity on the Clarksburg Lateral, which is expected to go into service in September 2010.

Woodford Shale—Antero has one operated drilling rig running in the Arkoma Woodford Shale play. The Company has 52 MMcfd of gross operated production from 117 operated horizontal wells online and 67 MMcfd of net production including net non-operated production and NGLs derived from processing third party gas. Antero has one operated horizontal Woodford well waiting on completion. In addition, we have five non-operated wells drilling with a combined 96% working interest on our Arkoma acreage. Our net non-operated production in the Arkoma is estimated to be 30 MMcfd. Antero has 80,000 net acres in the Arkoma Woodford Shale play.

Fayetteville Shale—Antero has three non-operated Fayetteville Shale wells drilling with a combined 16% working interest. The Company has 6 MMcfd of net production and 6,000 net acres in the Fayetteville Shale play.

Piceance Basin—Antero has one operated drilling rig running in the Piceance Basin. Our gross operated production in the Piceance is currently 48 MMcfed (35 MMcfed net including 1 MMcfed of non-operated production) from 171 operated wells online. Antero has 3 vertical Mesaverde wells waiting on completion in its Battlement Mesa area and 8 vertical Mesaverde wells waiting on completion in its Gravel Trend area. Antero has 66,000 net acres in the Piceance Basin.

Capital Expenditures

Antero's capital budget for 2010 is $383 million excluding acquisitions. The budget is expected to be funded internally from operating cash flow and through the use of the undrawn capacity under our $400 million credit facility. The 2010 capital program includes $331 million for drilling and completion, $28 million for leasehold acquisitions and $24 million for the construction of gathering pipelines and facilities. Approximately 51% of the budget is allocated to the Appalachian Marcellus Shale, 28% is allocated to the Arkoma Woodford Shale and 21% is allocated to the Piceance. Antero plans to continue operating 5 drilling rigs for the remainder of 2010.

2010 Outlook

The following table provides Antero's forward-looking guidance based on its updated forecasts for 2010:

Non-GAAP Financial Measures

Cash flow from operations before changes in working capital as presented in this release represents net cash provided by operations before changes in working capital and exploration expense. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operations, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity. The following table reconciles net cash provided by operating activities to cash flow from operations before changes in working capital as used in this release:

EBITDAX is a non-GAAP financial measure that we define as net income before interest expense and other income or expense, taxes, impairments, depletion, depreciation, amortization, exploration expense, unrealized hedge gains or losses, franchise taxes, noncontrolling interest and stock compensation. EBITDAX, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. EBITDAX does not represent funds available for discretionary use because those funds are required for debt service, capital expenditures, working capital, and other commitments and obligations. However, our management team believes EBITDAX is useful to an investor in evaluating our operating performance because this measure is widely used by investors in the natural gas and oil industry to measure a company's operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors; helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting and by our lenders pursuant to a covenant under our senior secured revolving credit facility. EBITDAX is also used as a measure of operating performance pursuant to a covenant under the indenture governing our outstanding 9.375% senior notes.

There are significant limitations to using EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating EBITDAX reported by different companies. The following table represents a reconciliation of our net income to EBITDAX for the three and six months ended June 30, 2010 and 2009:

The cash prices realized for oil and natural gas production including the amounts realized on cash settled derivatives is a critical component in the Company's performance tracked by investors and professional research analysts in valuing, comparing, rating and providing investment recommendations and forecasts of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Due to the GAAP disclosures of various hedging and derivative transactions, such information is now reported in various lines of the income statement.

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.  Our website is 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.

SOURCE Antero Resources