Antero Resources Reports Third Quarter 2011 Results

DENVER, Nov. 15, 2011 /PRNewswire/ -- Antero Resources today released its third quarter 2011 results. Those financial statements are included in Antero Resources Finance Corporation's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011, which has been filed with the Securities and Exchange Commission.

Recent Developments

On September 26, 2011, Antero announced that it had acquired a 7% overriding royalty interest (ORI) from CONSOL Energy in approximately 115,000 net acres located in the southwestern core of the Marcellus Shale  play on a large portion of Antero's existing West Virginia and Pennsylvania acreage position for $193 million.  The acquisition increased Antero's net revenue interest in 115,000 net acres of its 203,000 net acre Marcellus Shale position to 87%.  The cash transaction closed on September 21, 2011 with an effective date of July 1, 2011, and was funded with undrawn capacity on Antero's credit facility.

On October 27, 2011 Antero announced that the borrowing base under its credit facility had been increased from $800 million to $1.2 billion and that lender commitments were increased from $750 million to $850 million.  One new bank joined Antero's now 14-bank lending group.  As of September 30, 2011, pro forma for the increase in lender commitments, Antero had $611 million of undrawn committed capacity under its credit facility including $21 million of letters of credit.  Pro forma for the increase in the borrowing base, Antero had $961 million of undrawn borrowing base capacity, contingent upon an additional $350 million of lender commitments.  

Financial Results

Production for the third quarter of 2011 increased by 85% relative to the third quarter of 2010 to 24 Bcfe, resulting in net revenue growth of 80% to $135 million (including cash-settled derivatives but excluding unrealized derivative gains and losses).  The production increase was primarily driven by new wells in the Marcellus Shale and the Piceance Basin.  Liquids production (NGLs and oil) contributed 12% of revenues before commodity hedges.  Average natural gas prices before hedges increased 6% from the prior-year quarter to $4.20 per Mcf and average natural gas-equivalent prices before hedges increased 9% to $4.50 per Mcfe.  Average realized gas prices including hedges decreased by 2% to $5.31 per Mcf for the third quarter.  Average realized NGL prices increased by 7% to $45.97 per barrel for the same period, while average realized oil prices including hedges increased by 19% to $76.92 per barrel.  Average gas-equivalent prices including NGLs, oil and hedges, increased by 1% to $5.53 per Mcfe.  For the third quarter of 2011, Antero realized natural gas hedging gains of $25 million, or $1.05 per Mcfe.

Reported GAAP earnings resulted in net income of $111 million, including a $140 million unrealized gain on commodity derivatives as natural gas prices declined from the prior quarter and $50 million in deferred income tax expense.  Excluding the unrealized gain on commodity derivatives and deferred income tax expense, adjusted net income, a non-GAAP measure, was $20 million for the quarter.  For a reconciliation of adjusted net income, please read "—Non-GAAP Financial Measures."

Driven by an 80% increase in revenues, cash flow from operations before changes in working capital, a non-GAAP measure, increased 112% from the prior-year quarter to $71 million.  EBITDAX of $92 million for the third quarter of 2011 was 82% higher than the prior-year quarter, also due primarily to an 80% increase in revenues.  For reconciliation of EBITDAX and cash flow from operations before changes in working capital to the nearest comparable GAAP measures, please read "—Non-GAAP Financial Measures."

Net production of 24 Bcfe for the quarter was comprised of 23 Bcf of natural gas, 185,000 barrels of NGLs and 63,000 barrels of oil, representing a 20% sequential increase over the second quarter of 2011.  Net daily production averaged 264 MMcfed for the third quarter, a record high for Antero, and was comprised of 248 MMcfd of natural gas (93%), 2,011 Bbl/d of NGLs (5%) and 685 Bbl/d of crude oil (2%).  Net NGL production increased 21% over the third quarter of 2010, which had included NGLs generated by processing third party gas in the Arkoma Woodford.  As a result of the execution of a gas processing agreement effective January 1, 2011 in the Piceance Basin, Antero has more than replaced all of the NGL production generated from third party processing fees which terminated with the sale of the Arkoma midstream processing assets in the fourth quarter of 2010.

Per unit cash production costs (lease operating, gathering, compression and transportation, and production tax) for the third quarter  of 2011 were $1.46 per Mcfe, a 6% improvement from the prior year quarter and a 6% improvement over the previous quarter.  This improvement was primarily driven by increased production volumes from new high rate Marcellus Shale wells that generally have low per unit production costs relative to the Company's existing production base.  Per unit depreciation, depletion and amortization expense decreased 36% from the prior year quarter to $1.83 per Mcfe, driven by low cost reserve additions.  On a per unit basis, general and administrative expense for the third quarter 2011 was $0.30 per Mcfe, a 29% decline from the third quarter of 2010, primarily driven by the increase in gas-equivalent production somewhat offset by a growing employee base.

Antero Operations

Antero's current gross operated production is 315 MMcfd, and estimated net production is 298 MMcfed, including non-operated production, NGLs and oil.  An additional 30 MMcfd of gross operated production (23 MMcfd net) from three completed and flow tested horizontal Marcellus wells is waiting on pipeline completion in West Virginia, which is expected to occur by the end of November.  During the first nine months of 2011, Antero completed 73 gross operated wells (66 net wells) and currently has 36 gross operated wells (29 net wells) in various stages of drilling, completion, waiting on completion or waiting on pipeline.

Marcellus Shale—Antero is operating five drilling rigs in the Marcellus Shale play, all of which are drilling in northern West Virginia.  The Company has a sixth drilling rig under contract that is expected to spud its first well in December and a seventh rig is expected to spud its first well in early February 2012.  Antero has 206 MMcfd of gross operated production of which 98% is coming from 56 horizontal wells, resulting in 163 MMcfd of net production.  As mentioned above, an additional 30 MMcfd of gross operated deliverability is constrained, waiting on the completion of pipeline facilities expected by the end of November.  Antero has 11 horizontal wells either completing or waiting on completion and has one dedicated frac crew currently working in West Virginia.  A second Antero-dedicated frac crew is scheduled to arrive in the second quarter of 2012.  The 56 horizontal Marcellus wells that Antero has completed and placed online to date have an average lateral length of approximately 6,200'.

Four West Virginia infrastructure projects were completed in September and two more are close to completion and waiting on permitting.  The completed projects include the Jarvisville low pressure gathering system, the Tichenal low pressure gathering system and high pressure pipeline and the new Tichenal compressor station.  The addition of several more compressor units at Jarvisville will raise Antero's West Virginia compression capacity to 295 MMcfd.  Another tranche of compression at Jarvisville is expected to be online in January 2012 and will raise Antero's West Virginia compression capacity to 330 MMcfd.  Finally, the Pike Fork compressor station is scheduled to go online in February 2012 raising Antero's West Virginia total compression capacity to 380 MMcfd.  Based on current drilling and completion schedules, Antero believes that it will have adequate gathering and compression capacity to accommodate anticipated production growth through the second quarter of 2012.  Planning is underway for additional compression and pipeline projects to be completed in 2012 in order to continue to raise lean gas compression and pipeline capacity as well as to deliver rich gas production to a new 200 MMcfd processing plant to be completed by a third party in the third quarter of 2012.  Antero has rights to all of the processing capacity in the new plant.

Antero has 203,000 net acres in the Appalachian Basin Marcellus Shale play of which only 8% was classified as proved at mid-year 2011.

Woodford Shale—Antero is operating one drilling rig in the Arkoma Woodford Shale play. The Company has 61 MMcfd of gross operated production from 131 operated horizontal wells online and 74 MMcfed of net production including net non-operated production, NGLs and oil. The 74 MMcfed net is comprised of approximately 70 MMcfd of tailgate gas, 500 Bbls/d of NGLs and 15 Bbls/d of light oil.  Antero has one operated horizontal Woodford well located in the rich gas area of the Arkoma Woodford waiting on completion.  In addition, Antero has four non-operated wells drilling with a combined 44% working interest on its Arkoma acreage.

Antero has 67,000 net acres in the Arkoma Woodford Shale play.

Piceance Basin—Antero has one operated drilling rig running in the Piceance Basin. The Company's gross operated production in the Piceance is currently 48 MMcfd and 52 MMcfed net including 3 MMcfed of non-operated production from 193 wells online.  The 52 MMcfed net is comprised of approximately 36 MMcfd of tailgate gas, 2,100 Bbls/d of NGLs and 660 Bbls/d of light oil.  Antero has six Mesaverde wells currently in the process of completing and 11 Mesaverde wells waiting on completion in its Gravel Trend rich gas area.  The Company has one frac crew currently working in the basin.

Antero has 63,000 net acres in the Piceance.

Fayetteville Shale—Antero has 10 MMcfd of net non-operated production and 5,000 net acres in the Fayetteville Shale play.  The Company has three non-operated Fayetteville Shale wells drilling with a combined 23% working interest.

Commodity Hedges

From the beginning of the fourth quarter of 2011 through the end of 2016, Antero has hedged 588 Bcfe using simple fixed price swaps at an average NYMEX-equivalent price of $5.81 per MMBtu.  Over 60% of estimated gas production for the last quarter of 2011 is hedged at a NYMEX-equivalent price of $5.78 per MMBtu and over 65% of 2012 estimated gas production is hedged at a NYMEX-equivalent price of $5.78 per MMBtu.  Virtually all of Antero's financial hedge prices are tied to the local basin.  In the following table, these basin prices are converted to NYMEX-equivalent prices using current basis differentials in the over-the-counter futures market.  Antero has nine different counterparties to its hedge contracts, all but one of which are lenders in the Company's bank credit facility.

Non-GAAP Financial Measures

Adjusted net income as set forth in this release represents income from operations before deferred income taxes, adjusted for certain non-cash items.  We believe that adjusted net income is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies.  Adjusted net income is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income (loss) as an indicator of financial performance.  The following table reconciles income from operations to adjusted net income:

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 in isolation or as a substitute for 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, gain or loss on sale of assets, franchise taxes and expenses related to business acquisitions.  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 9.375% and 7.25% 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 nine months ended September 30, 2010 and 2011:

The cash prices realized for oil, NGLs and natural gas production including the amounts realized on cash settled derivatives are 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.

Results of Operations

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2011

The following table sets forth selected operating data for the three months ended September 30, 2010 compared to the three months ended September 30, 2011:

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2011

The following table sets forth selected operating data for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2011:

SOURCE Antero Resources