Antero Resources Reports Third Quarter 2012 Results and Delivers Operating Update

DENVER, Nov. 8, 2012 /PRNewswire/ --

• Net production averaged 308 MMcfed, up 57% over the prior-year quarter, pro forma for Arkoma sale
• Consolidated EBITDAX was $95 million, up 47% over the prior-year quarter, pro forma for Arkoma sale
• Current net production of 371 MMcfed — 314 MMcfd net from the Marcellus alone
• 13 Antero-operated drilling rigs currently running in Marcellus and Utica Shale core areas
• Announced start-up of Sherwood I processing plant in Marcellus – currently producing 1,300 Bbl/d of NGLs
• Announced gas processing agreement with MarkWest in the Utica Shale play
• Announced Piceance upstream and pipeline asset sale for $325 million plus $100 million hedge monetization
• Increased borrowing base to $1.65 billion and lender commitments to $950 million

Antero Resources today released its third quarter 2012 results. Those financial statements are included in Antero Resources LLC's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, which has been filed with the Securities and Exchange Commission.

Recent Developments

On October 26, 2012, Antero announced that the borrowing base under its bank credit facility had been increased by $300 million to the $1.65 billion level.  Lender commitments under the facility were raised to $950 million, a $200 million increase.  The $950 million commitment can be expanded to the full $1.65 billion borrowing base upon bank approval.

On October 31, 2012, Antero and MarkWest Energy Partners, L.P. (MarkWest) jointly announced the completion of certain gas processing and pipeline infrastructure in Doddridge County, West Virginia.  The first phase of this infrastructure was completed and includes Sherwood I, which is a 200 MMcfd cryogenic gas processing plant, as well as plant inlet compression.  Antero is currently delivering 110 MMcfd of liquids rich gas to the Sherwood I plant inlet.  Antero will not recover ethane from the rich gas stream but will extract the heavier products ("C3+") until ethane takeaway is available.  Antero is an anchor shipper on Enterprise Products Partners L.P.'s Appalachia to Texas ATEX pipeline (ATEX Express) enabling Antero to ship up to 20,000 Bbl/d of ethane, with the option to expand to 40,000 Bbl/d.  The ATEX Express is expected to begin service in the first quarter of 2014.  MarkWest will initially truck Sherwood NGL products until completion of a 6-inch NGL pipeline from Sherwood to MarkWest NGL fractionation facilities in Houston, Pennsylvania.  The NGL pipeline is expected to be in service by the second quarter of 2013.  Current NGL yield from the 110 MMcfd of throughput at Sherwood I is approximately 1,300 Bbld of C3+ y-grade product.

On November 5, 2012, Antero announced that it had entered into an agreement to sell all of its natural gas properties and pipeline assets in the Piceance Basin to a private company for $325 million in cash plus the assumption of all of its Rocky Mountain firm transportation obligations.  The transaction is expected to close in December 2012, subject to the satisfaction of customary closing conditions, with an effective date of October 1, 2012.  Antero has also monetized approximately 80% of its 78 Bcf of Rockies hedges for $80 million and plans to monetize the remaining 20% in the fourth quarter of 2012 resulting in $100 million of hedge proceeds.

On November 6, 2012, Antero and MarkWest Utica EMG, L.L.C. (MarkWest Utica) jointly announced the completion of definitive agreements for MarkWest to provide processing, fractionation and marketing services in the liquids-rich corridor of the Utica Shale play.  Under the terms of the agreements, MarkWest Utica will develop natural gas processing infrastructure in Noble County, Ohio to process Antero's rich gas Utica Shale production.  MarkWest Utica will initially bring online an interim 45 MMcfd refrigeration natural gas processing plant with an expected second quarter 2013 completion date.  This interim facility will be followed by Seneca I, a 200 MMcfd cryogenic gas processing facility, which is expected to begin operations in the third quarter of 2013.  The definitive agreements also provide for the construction of an additional facility, Seneca II, a 200 MMcfd cryogenic processing facility, which may be installed as soon as the end of 2013.

On November 7, 2012, Antero announced a 33% increase in the company's 2012 capital budget to $1.6 billion, which includes $838 million for drilling and completion, $639 million for leasehold acquisitions and $123 million for the construction of gathering pipelines and facilities.  The budget was revised primarily to fund the acquisition of additional leasehold in Appalachia and the construction of gathering infrastructure which will gather rich gas in Doddridge County, West Virginia and deliver gas to MarkWest's Sherwood I gas processing plant.

In this release, Antero's results are presented two ways: (1) in accordance with GAAP, where the results of operations of the Arkoma Basin assets and the loss on the sale are presented in one line as discontinued operations and (2) in a non-GAAP manner, where the results of operations of the Arkoma Basin assets (prior to the June 29, 2012 closing) and the loss on the sale are aggregated with the Company's results from continuing operations.  Investors should be cautioned that this non-GAAP presentation is not representative of Antero's future operations, which will no longer include Arkoma Basin assets and earnings.  See "Non-GAAP Financial Measures" for reconciliation between these two presentations.

Financial Results for the Third Quarter

Production for the third quarter of 2012 increased by 17% to 28 Bcfe relative to the third quarter of 2011, including third quarter 2011 production from the Arkoma Basin assets sold in June 2012.  Excluding the Arkoma Basin assets that were sold in June 2012, net production increased 57% from the third quarter of 2011. The net production increase was primarily driven by new wells brought online in the Marcellus Shale.  Net production of 28 Bcfe for the quarter was comprised of 27 Bcf of natural gas, 203,000 barrels of NGLs and 78,000 barrels of oil.  Net daily production averaged 308 MMcfed for the third quarter, and was comprised of 289 MMcfd of natural gas (94%), 2,209 Bbl/d of NGLs (4%) and 850 Bbl/d of crude oil (2%).   

GAAP revenues for the third quarter of 2012 decreased by 139% compared to the third quarter of 2011 to a negative $88 million, primarily due to a $237 million unrealized loss on commodity derivatives in third quarter of 2012 compared to a $125 million unrealized gain on commodity derivatives in the prior year quarter.  Reported GAAP earnings resulted in a net loss of $128 million for the three months ended September 30, 2012, including a $237 million unrealized loss on commodity derivatives as natural gas prices increased from the prior quarter, and an $84 million deferred income tax benefit.  EBITDAX from continuing operations of $95 million for the third quarter of 2012 was 47% higher than the prior-year quarter, primarily due to increased production.  For a description of EBITDAX, and reconciliation to the nearest comparable GAAP measures, please read "Non-GAAP Financial Measures".

(The non-GAAP amounts presented below combine the Arkoma Basin operations with the Company's other operations.  See "Non-GAAP Financial Measures" for a definition of each of these non-GAAP financial measures and tables that reconcile each of these non-GAAP measures to their most directly comparable GAAP financial measure.)

Following the sale of the Arkoma in the second quarter of 2012, Non-GAAP adjusted net revenues for the third quarter 2012 increased 10% to $148 million compared to the third quarter of 2011 (including cash-settled derivatives but excluding unrealized derivative gains and losses).  For a reconciliation of adjusted net revenues to revenues from operations (GAAP), please read "Non-GAAP Financial Measures".  Liquids production (NGLs and oil) contributed 14% of adjusted net revenues before commodity hedges during the third quarter of 2012 compared to 12% in the prior year quarter.  Average natural gas prices before hedges decreased 31% from the prior-year quarter to $2.90 per Mcf and average natural gas-equivalent prices before hedges decreased 30% to $3.17 per Mcfe.  Additionally, average realized gas prices including hedges decreased by 4% to $5.10 per Mcf.  Average realized NGL prices decreased by 32% to $31.28 per barrel, while average realized oil prices including hedges increased by 2% to $78.60 per barrel.  Gas-equivalent prices, after adjusting for all realized gains on commodity derivatives, declined by 5% to $5.24 per Mcfe for the third quarter of 2012.

For the third quarter of 2012, Antero realized natural gas hedging gains of $59 million, or $2.07 per Mcfe.  However, due to the fact that expiring financial hedges are settled and realized on a monthly basis while long-term non-expiring hedges are marked to market at the end of the quarter, we realized gains on hedges that settled during the quarter while we recognized an unrealized loss on long-term hedges as natural gas prices rose during the third quarter of 2012.

Excluding the unrealized loss on commodity derivatives and deferred income tax benefit, adjusted net income, a non-GAAP measure, was $25 million for the quarter.  Cash flow from operations before changes in working capital, a non-GAAP measure, decreased 8% from the prior-year quarter to $65 million, excluding cash tax installment payments made during the quarter for alternative minimum taxes due on the gain on sale of Antero's Appalachian midstream assets divested in March 2012.  EBITDAX of $95 million for the third quarter of 2012 was 4% higher than the prior-year quarter, primarily due to increased production.   For a description of EBITDAX, adjusted net income and cash flow from operations before changes in working capital and reconciliation to the nearest comparable GAAP measures, please read "Non-GAAP Financial Measures".

Per unit cash production costs (lease operating, gathering, compression and transportation, and production tax) for the third quarter of 2012 were $1.49 per Mcfe, a 2% increase from the prior year quarter.  This increase was primarily driven by increased costs on firm transportation commitments executed to facilitate future production growth.  Per unit lease operating expenses decreased by 55% to $0.14 per Mcfe driven by a decrease in workover expense in the Piceance, the elimination of higher operating cost Arkoma production and the addition of high rate new Marcellus wells brought online during the third quarter of 2012.  Per unit depreciation, depletion and amortization expense decreased 21% from the prior year quarter to $1.45 per Mcfe, driven by low cost reserve increases.  On a per unit basis, general and administrative expense for the third quarter 2012 was $0.42 per Mcfe, a 40% increase from the third quarter of 2011, primarily driven by an increase in staffing levels commensurate with our growth in production levels and development activities and the elimination of Arkoma production due to the second quarter 2012 divestiture.

Antero Operations

Antero's current gross operated production is 461 MMcfd and estimated net production is 371 MMcfed, including 3,600 Bbl/d of NGLs and 1,000 Bbl/d of oil.  Antero has an additional estimated 40 MMcfed of net production in the Marcellus and Utica Shales that is either shut-in or constrained waiting on pipeline, compression or processing facilities.  During the third quarter of 2012, Antero completed 28 gross operated wells (27 net wells) and currently has 37 gross operated wells (36 net wells) in various stages of drilling, completion or waiting on completion.

Marcellus Shale — Antero is operating 12 drilling rigs in the Marcellus Shale play, all of which are drilling in northern West Virginia.  The Company plans to add a 13th drilling rig in December 2012 and a 14th drilling rig in January 2013.  Antero has 405 MMcfd of gross operated production in the play of which 99% is coming from 105 horizontal Marcellus Shale wells, resulting in 314 MMcfd of net production.  The 314 MMcfed net is comprised of approximately 307 MMcfd of tailgate gas, 1,100 Bbls/d of NGLs and 100 Bbls/d of light oil.  Antero has 24 horizontal wells either completing or waiting on completion and has two fully-dedicated frac crews currently working in West Virginia along with several spot crews as needed.   The 105 horizontal Marcellus wells that Antero has completed and placed online to date have an average lateral length of 6,699 feet.  In the third quarter of 2012, Antero completed 14 horizontal Marcellus Shale wells with an average 24-hour peak rate of 15.1 MMcfd and an average lateral length of approximately 7,631 feet.

In addition to the Sherwood I plant, Antero has committed to a second 200 MMcfd gas processing plant, Sherwood II, to be located on the same site as Sherwood I.  Sherwood II is expected to go in service in the second quarter of 2013.  Antero has also committed to the fabrication of a third 200 MMcfd gas processing plant, Sherwood III, which is expected to go online in the fourth quarter of 2013, giving Antero access to a total of 600 MMcfd of Marcellus gas processing capacity by the end of 2013.

MarkWest is building the Pike Fork high pressure lateral and has completed the Zinnia high pressure pipeline lateral, both of which will transport rich gas production from western Harrison and eastern Doddridge Counties to the Sherwood processing complex.  The Pike Fork lateral is expected to be completed in December 2012 and will bring approximately 40 MMcfd of rich gas to the Sherwood processing complex.  These high pressure laterals will also move rich gas gathered by Crestwood Midstream Partners, in the area of dedication, in order to be processed.

Antero is continuing to build out the 17-mile Canton low pressure pipeline lateral which will gather rich gas in northern Doddridge County and deliver the gas to the Sherwood I plant.  The southern section of the Canton low pressure lateral is in service and currently delivering rich gas to Sherwood I, with the remainder of the pipeline expected to go in service in December 2012.  MarkWest has also constructed inlet compression facilities located at the Sherwood I plant to serve the Canton low pressure lateral.  The first inlet compressor unit is online while the remaining units are awaiting hookup to the electric grid.  Antero is building the 20 mile White Oak high pressure lateral which will transport rich gas production from western Doddridge and eastern Ritchie Counties to the Sherwood processing facilities.  The White Oak lateral is expected to be in service in the fourth quarter of 2012.  White Oak compression facilities are expected to be in-service in the first quarter of 2013.

Antero has 277,000 net acres in the Marcellus Shale play of which only 15% was associated with proved reserves at mid-year 2012.  Approximately 78% of Antero's Marcellus leasehold contains processable rich gas.  The Company has increased its Marcellus Shale leasehold position by 67,000 net acres in 2012 to date.

Utica Shale — Antero has assembled over 60,000 net acres of leasehold in the Utica Shale play of eastern Ohio and is currently operating one drilling rig.  Antero plans to add a second drilling rig in the second quarter of 2013.  Almost all of the acreage is located in the rich gas/condensate window of the Utica Shale play.  Antero has completed three horizontal wells in the Utica play with strong results.  All three completed wells are shut-in, waiting on pipeline and processing infrastructure.

Antero plans to put its first Utica Shale well online in December 2012 without access to processing followed by several additional wells by the second quarter of 2013 when the initial firm processing capacity becomes available.   Antero is in the process of laying both low and high pressure gathering pipeline to transport its initial Utica production.

Piceance Basin — Antero is no longer operating a drilling rig in the Piceance Basin as of late July 2012 when its drilling contract expired. The Company's gross operated production in the Piceance is currently 56 MMcfd and 57 MMcfed net including 2 MMcfed of non-operated production from 284 wells online.  The 57 MMcfed net is comprised of approximately 37 MMcfd of tailgate gas, 2,400 Bbls/d of NGLs and 900 Bbls/d of light oil.

Antero has 61,000 net acres in the Piceance.

Non-GAAP Financial Measures

The table below reconciles the Company's GAAP results from continuing operations to Non-GAAP results including operations of the Arkoma Basin assets (prior to the sale) and the loss on the sale.  Antero is including this presentation in order to more clearly illustrate its results of operations during the period:

Adjusted net revenue as set forth in this release represents total operating revenues adjusted for certain non-cash items including unrealized derivative gains and losses and gains and losses on asset sales.  We believe that adjusted net revenue is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies.  Adjusted net revenue is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total operating revenues as an indicator of financial performance.  The following table reconciles total operating revenues to total adjusted net revenues:

Adjusted net income as set forth in this release represents income from operations before deferred income taxes, adjusted for certain non-cash items from operations and discontinued operations.  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 in accordance with 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. 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, 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, 2011 and 2012:

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 oil and liquids-rich natural gas properties primarily located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania, and in the Piceance Basin in Colorado. 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.

SOURCE Antero Resources