Antero Resources Reports First Quarter 2012 Results

DENVER, May 14, 2012 /PRNewswire/ --

Highlights:

• Net production averaged 317 MMcfed, up 83% over the prior-year quarter
• Consolidated EBITDAX was $122 million, up 89% over the prior-year quarter
• Reported GAAP earnings were $328 million and adjusted net income was $46 million
• Current net production is 365 MMcfed including 4,400 Bbl/d of liquids
• 11 Antero operated drilling rigs currently running
• Natural gas hedges increased by 20% to 842 Bcfe through 2017 at $5.30 NYMEX-equivalent
• Credit facility borrowing base increased by 29% to $1.55 billion in May 2012 redetermination

Antero Resources today released its first quarter 2012 results. Those financial statements are included in Antero Resources LLC's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2012, which has been filed with the Securities and Exchange Commission.

Recent Developments

Antero announced on May 7, 2012 that the borrowing base under its bank credit facility had been increased to $1.55 billion.  This represents a $350 million increase over Antero's previous borrowing base which was determined in October 2011.  Lender commitments under the facility were increased by $100 million to $950 million.  The $950 million commitment can be expanded to the full $1.55 billion borrowing base upon bank approval.  Antero added three new banks to its 16-bank syndicate which is co-led by JP Morgan and Wells Fargo.

Antero has $215 million drawn under the credit facility and $21 million in letters of credit outstanding, resulting in $715 million of available liquidity and over $1.3 billion of unused borrowing base capacity.  The next regular borrowing base redetermination is expected to occur in October 2012.  Antero has $25 million of debt maturing prior to 2016.

Financial Results

Net production for the first quarter of 2012 increased by 83% relative to the first quarter of 2011 to 29 Bcfe, resulting in adjusted net revenue growth (a non-GAAP financial measure) of 76% to $173 million (including cash-settled derivatives but excluding the gain on sale of Marcellus gathering assets and rights and unrealized derivative gains and losses).  For a reconciliation of adjusted net revenue to operating revenues (GAAP), please read "Non-GAAP Financial Measures".  The net production increase was primarily driven by new wells in the Marcellus Shale and the Piceance Basin.  Liquids production (NGLs and oil) contributed 20% of oil, natural gas liquids and gas sales before commodity hedges compared to 12% during the first quarter of 2011.  Average natural gas prices before hedges decreased 34% from the prior-year quarter to $2.76 per Mcf and average natural gas-equivalent prices before hedges decreased 28% to $3.21 per Mcfe.  Average realized gas prices including hedges decreased by 6% to $5.77 per Mcf for the first quarter of 2012 as compared to the first quarter of 2011.  Average realized NGL prices decreased by 5% to $42.11 per barrel for the same period, while average realized oil prices including hedges increased by 16% to $87.00 per barrel.  Average gas-equivalent prices including NGLs, oil and hedges, decreased by only 5% to $5.99 per Mcfe for the first quarter of 2012 as compared to the first quarter of 2011.  For the first quarter of 2012, Antero realized natural gas hedging gains of $2.78 per Mcfe.

Net income for the first quarter of 2012 was $328 million, including a $291 million gain on sale of assets, a $203 million unrealized gain on commodity derivatives as natural gas prices declined from the prior quarter and $212 million in income tax expense.  Excluding the gain on asset sale, the unrealized gain on commodity derivatives and income tax expense, adjusted net income, a non-GAAP measure, was $46 million for the first quarter of 2012 as compared to $10 million for the prior year quarter.  For a description of adjusted net income and a reconciliation to net income, please read "Non-GAAP Financial Measures".

For the first quarter of 2012, cash flow from operations before changes in working capital, a non-GAAP financial measure, increased 107% from the prior-year quarter to $96 million.  EBITDAX of $122 million for the first quarter of 2012 was 89% higher than the prior-year quarter, due primarily to a 76% increase in adjusted net revenues which was driven by an 83% increase in net production.  For a description of EBITDAX and cash flow from operations before changes in working capital and reconciliation to the nearest comparable GAAP measures, please read "Non-GAAP Financial Measures".

Net production of 29 Bcfe for the quarter was comprised of 27 Bcf of natural gas, 272,000 barrels of NGLs and 80,000 barrels of oil.  Net production was flat as compared to the fourth quarter of 2011 due to an operational shift during the quarter to pad development drilling.  Rather than drill one or two wells and complete, which was typical in the earlier stages of our Marcellus drilling program, in 2012 Antero has typically drilled three or four wells prior to completing the first well on a pad.  This multi-well pad approach results in cost savings due to fewer rig moves, but also delays the completion of the first wells on a pad and first production from the pad.  The quarterly completion pace will return to normal in subsequent quarters as multi-well pads are brought online.  Accordingly, Antero brought online only nine horizontal Marcellus wells in the first quarter of 2012 while twelve Marcellus wells have been brought online thus far in the second quarter of 2012.  Net daily production averaged 317 MMcfed for the first quarter of 2012, and was comprised of 293 MMcfd of natural gas (93%), 2,990 Bbl/d of NGLs (5%) and 883 Bbl/d of crude oil (2%).  Net NGL production increased 116% over the first quarter of 2011 as a result of additional drilling in the Piceance Basin.

Per unit cash production cost (lease operating, gathering, compression and transportation, and production tax) for the first quarter of 2012 was $1.45 per Mcfe, an 18% improvement from the prior year quarter and flat compared to the previous quarter.  The improvement compared to the first quarter of 2011 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 23% from the prior year quarter to $1.66 per Mcfe, primarily driven by low cost reserve additions.  On a per unit basis, general and administrative expense for the first quarter of 2012 was $0.32 per Mcfe, a 20% decline from the first quarter of 2011, primarily driven by the increase in gas-equivalent production and somewhat offset by a growing employee base. 

Antero Operations

Antero's current gross operated production is 407 MMcfd, and estimated net production is 365 MMcfed, including non-operated production, NGLs and oil.  The estimated net production is comprised of 338 MMcfd of natural gas and 4,400 Bbl/d of NGLs and oil.  During the first three months of 2012, Antero completed 32 gross operated wells (28 net wells) and currently has 29 gross operated wells (28 net wells) in various stages of drilling, completion, or waiting on completion. 

Marcellus Shale—Antero is operating seven drilling rigs in the Marcellus Shale play, all of which are drilling in northern West Virginia.  The Company has an additional drilling rig under contract that is expected to spud its first well in June.  Currently, Antero has 293 MMcfd of gross operated production of which 98% is coming from 81 horizontal wells, resulting in 226 MMcfd of net production.  Antero has nine horizontal wells either completing or waiting on completion and has two dedicated frac crews currently working in West Virginia.  A third Antero-dedicated frac crew is scheduled to begin work in the fourth quarter of 2012.  The 81 horizontal Marcellus wells that Antero has completed and placed online to date have an average lateral length of approximately 6,500'.  In the first quarter of 2012, Antero drilled and completed nine horizontal Marcellus Shale wells with an average 24-hour peak rate of 14.0 MMcfd and an average lateral length of approximately 6,800'.

There are a number of infrastructure projects underway in Harrison and Doddridge Counties, West Virginia that will facilitate rich gas transportation to the 200 MMcfd Sherwood I gas processing plant which is scheduled to start up late in the third quarter of 2012.  MarkWest Energy Partners is building the Sherwood I processing facility as well as an NGL pipeline that will transport the plant liquids north to MarkWest fractionation facilities in Houston, Pennsylvania.  Plant liquids will initially be trucked to the fractionation facilities until the new NGL pipeline is in service which is expected in the fourth quarter of 2012.  Antero has committed to the fabrication of 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, giving Antero access to a total of 400 MMcfd of gas processing capacity.

MarkWest is also building the Zinnia high pressure pipeline lateral and the Pike Fork high pressure lateral which will transport rich gas production from western Harrison and eastern Doddridge Counties to the Sherwood I plant.  The high pressure laterals are expected to be in service when the Sherwood I plant goes in service in the third quarter of 2012 and will move rich gas that is gathered by Crestwood Midstream Partners in the recently announced area of dedication to the Sherwood gas processing facilities.

Antero is building 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 expected to be in service when the Sherwood I plant goes in service with the remainder of the pipeline expected to go in service in the fourth quarter of 2012.  MarkWest is also building compression facilities located at the Sherwood I plant to serve the Canton low pressure lateral.  Antero is also planning to build the White Oak high pressure lateral which will transport rich gas production from western Doddridge County to the Sherwood processing facilities.  The White Oak lateral is expected to be in service in the fourth quarter of 2012 along with initial compression facilities.

Antero has 233,000 net acres in the Appalachian Basin Marcellus Shale play of which only 17% was associated with proved reserves at year-end 2011.

Piceance Basin—Antero has two operated drilling rigs running in the Piceance Basin. One of the rigs continues to develop Antero's liquids-rich Mesaverde acreage, while a second rig is drilling a horizontal well targeting the Mancos/Niobrara Shale.  The Mancos/Niobrara Shale is highly over-pressured and underlies a large portion of Antero's Piceance acreage.  Antero has eight vertical completions in the Mancos/Niobrara and other Piceance operators have had good results drilling horizontal wells in the lean gas shale.  The Company's gross operated production in the Piceance is currently 56 MMcfd and 60 MMcfed net including 2 MMcfed of non-operated production from 236 wells online.  The 60 MMcfed net is comprised of approximately 39 MMcfd of tailgate gas, 2,800 Bbls/d of NGLs and 800 Bbls/d of light oil.  Antero has five Mesaverde wells currently in the process of completing and five 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.

Woodford Shale—Antero is no longer operating a drilling rig in the Arkoma Woodford Shale play and has no plans to operate a rig for the remainder of 2012.  Currently, the Company has 59 MMcfd of gross operated production from 134 operated horizontal wells online and 69 MMcfed of net production including net non-operated production, NGLs and oil. The 69 MMcfed net is comprised of approximately 64 MMcfd of tailgate gas, 800 Bbls/d of NGLs and 15 Bbls/d of light oil.   Antero has four non-operated Woodford Shale wells drilling or completing with a combined 43% working interest.

Antero has 66,000 net acres in the Arkoma Woodford Shale play.

Fayetteville Shale—Antero currently has 10 MMcfd of net non-operated production and 5,000 net acres in the Fayetteville Shale play.  The Company has nine non-operated Fayetteville Shale wells drilling or completing with a combined 30% working interest.

Commodity Hedges

From the beginning of the second quarter of 2012 through the end of 2017, Antero has hedged 842 Bcfe using simple fixed price swaps at an average NYMEX-equivalent price of $5.30 per MMBtu.  Approximately 82% of 2012 estimated gas production is hedged at a NYMEX-equivalent price of $5.68 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 ten 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 revenue as set forth in this release represents 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 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.  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 months ended March 31, 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 natural gas properties primarily located in the Appalachian Basin in West Virginia and Pennsylvania, the Piceance Basin in Colorado and the Arkoma Basin in Oklahoma.  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.

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