Exhibit 99.1

Antero Resources Reports 2011 Operating and Financial Results

2011 Highlights:

·                  Net production averaged 244 MMcfed in 2011, up 83% from 2010

·                  Consolidated EBITDAX was $341 million, up 72% from 2010

·                  Proved reserves increased to 5.0 Tcfe at year-end 2011 (22% liquids), up 55% from 2010

·                  Completed 38 horizontal Marcellus wells in 2011 with average IP of 15.5 MMcfd and average reserves of 10 Bcf

·                  2011 all-in F&D cost was $0.46 per Mcfe and 3-year all-in F&D cost was $0.36 per Mcfe

·                  Current net production is 325 MMcfed including NGLs and oil

·                  Seven Antero-operated rigs currently drilling – six in Appalachia and one in the Piceance Basin

Denver, Colorado, March 21, 2012—Antero Resources today released its 2011 results. Those financial statements are included in Antero Resources LLC’s Annual Report on Form 10-K for the year ended December 31, 2011, which has been filed with the Securities and Exchange Commission.

Recent Developments

On February 27, 2012 Antero announced an $861 million capital budget for 2012 which includes $711 million for drilling and completion, $100 million for leasehold additions and $50 million for the construction of gathering pipelines and facilities primarily in the Marcellus Shale.  The 2012 capital budget includes the planned drilling of 93 Antero-operated wells in the Appalachian Basin and 53 Antero-operated wells in the Piceance Basin.  Approximately 65% of the 2012 drilling budget is directed towards liquids rich gas and approximately 95% is allocated to Antero-operated drilling.

Also on February 27, 2012 Antero announced the execution of definitive agreements whereby Antero agreed to sell certain Marcellus Shale gathering system assets located in Harrison and Doddridge Counties, West Virginia to Crestwood Midstream Partners LP and Crestwood Holdings Partners LLC for $375 million in cash plus an earn-out (which could allow Antero to earn an additional purchase price payment of up to $40 million).  The agreements include future gathering and compression rights in an area of dedication covering almost 50% of Antero’s 222,000 net acre Marcellus Shale leasehold.  The proceeds from the sale will be used initially to repay bank debt and will ultimately be used for further development of Antero’s Appalachian drilling inventory as well as future leasehold acquisition.  The transaction is expected to close in late March 2012.

Full Year 2011

Net production for 2011 increased by 83% year over year to 89 Bcfe, which resulted in adjusted net revenue (a non-GAAP financial measure) of $509 million, a 69% increase over 2010 adjusted net revenue (which includes cash-settled derivatives but excludes unrealized derivative gains and losses and gains and losses on asset sales).  For a reconciliation of adjusted net revenue to net revenue (GAAP), please read “Non-GAAP Financial Measures”.  The net production increase was primarily driven by new wells completed in the Marcellus Shale and in the Piceance Basin.  Liquids production (NGLs and oil) contributed 13% of 2011 revenues, before commodity hedges.  Average natural gas prices before hedges decreased 4% from the prior year to $4.08 per Mcf and average natural gas-equivalent prices, including NGLs and oil, before hedges decreased 1% from the prior year to $4.40 per Mcfe.  Average realized natural gas prices including hedges decreased by 7% from the prior year to $5.48 per Mcf for 2011.  Average 2011 realized NGL prices increased by 4% from the prior year to $49.03 per barrel for the same period, while average realized oil prices including hedges increased by 16% from the prior year to $77.30 per barrel.  Average gas-equivalent prices including NGLs, oil and hedges, decreased by 5% from the prior year to $5.71 per Mcfe in 2011.  Antero realized natural gas hedging gains of $117 million, or $1.31 per Mcfe in 2011.

Reported 2011 GAAP earnings resulted in net income of $393 million, including a $560 million unrealized gain on commodity derivatives as natural gas prices declined from the prior year, a $9 million loss on the sale of a compressor station and $230 million in deferred income tax expense.  Excluding the unrealized gain on commodity derivatives, loss on sale and deferred income tax expense,

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adjusted net income, a non-GAAP measure, was $72 million for the year.  For a reconciliation of adjusted net income to the nearest comparable GAAP measure, please read “Non-GAAP Financial Measures”.

Cash flow from operations before changes in working capital, a Non-GAAP Financial Measure, increased 101% from the prior year to $258 million.  EBITDAX of $341 million for 2011 was 72% higher than the prior year, due primarily to a 69% increase in revenues which was driven by the 83% increase in net production.  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”.  Antero’s capital spending in 2011 totaled $930 million, comprised of $554 million in drilling costs, $108 million for leasehold additions, $193 million for a Marcellus Shale acquisition, $73 million in gathering costs and $2 million for other capital costs.

Net production of 89 Bcfe for the year was comprised of 84 Bcf of natural gas, 708,000 barrels of NGLs and 191,000 barrels of oil, representing an 83% increase over 2010.  Net daily production averaged 244 MMcfed for the year, a record high for Antero and was comprised of 229 MMcfd of natural gas (94%), 1,940 Bbl/d of NGLs (5%) and 522 Bbl/d of crude oil (1%).  Net NGL production increased 39% over 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 2011 were $1.52 per Mcfe, a 12% decrease from the prior year.  This decrease in per unit costs was primarily driven by increased production volumes from new Marcellus Shale wells with lower per unit lease operating expense relative to the Company’s existing production base.  Per unit depreciation, depletion and amortization expense decreased 34% from the prior year to $1.91 per Mcfe, driven by low cost reserve additions.  On a per unit basis, general and administrative expense for 2011 was $0.37 per Mcfe, a 21% decrease from 2010, with the decrease primarily driven by the increase in natural gas-equivalent production somewhat offset by a growing employee base.

Fourth Quarter 2011

Fourth quarter 2011 adjusted net revenues (including cash-settled derivatives but excluding unrealized derivative gains and losses and the gain on the sale of the Arkoma midstream assets) increased by 90% relative to the fourth quarter of 2010 to $159 million, primarily driven by a 116% increase in net production.  Reported fourth quarter GAAP earnings resulted in net income of $266 million including an unrealized commodity derivative gain of $399 million as natural gas prices declined from the prior year and $156 million in deferred income tax expense.  Driven by a 90% increase in adjusted net revenues, cash flow from operations before changes in working capital, a Non-GAAP Financial Measure, increased by 154% to $81 million.  EBITDAX for the fourth quarter was $107 million, a 105% increase over the fourth quarter of 2010.  For a reconciliation of adjusted net revenues, 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 29 Bcfe for the fourth quarter was comprised of 27 Bcf of natural gas, 247,000 barrels of NGLs and 63,000 barrels of oil, representing a 20% sequential increase over the third quarter of 2011. Net daily production averaged 317 MMcfed in the fourth quarter of 2011, a record high for Antero, and was comprised of 296 MMcfd of natural gas (94%), 2,685 Bbl/d of NGLs (5%) and 685 Bbl/d of crude oil (1%). Realized gas-equivalent prices after hedging declined 11% from the prior year quarter to $5.46 per Mcfe.

Per unit cash production costs for the fourth quarter of 2011 were $1.44 per Mcfe, a 21% improvement from the prior year quarter and a 1% improvement over the previous quarter.  Per unit depreciation, depletion and amortization expense decreased 26% from the fourth quarter of 2010 to $1.83 per Mcfe. On a per unit basis, general and administrative expense for the fourth quarter 2011 was $0.39 per Mcfe, a 30% decline from the fourth quarter of 2010.

Reserves

Proved reserves at December 31, 2011 totaled 5.0 Tcfe comprised of 3.9 Tcf of natural gas, 164 million barrels of NGLs and 17 million barrels of crude oil.  Reserves increased 1.8 Tcfe, or 55% compared to the prior year, primarily due to proved undeveloped reserve increases attributable to Antero’s Marcellus Shale drilling, partially offset by negative performance revisions.  The 346 Bcfe negative performance revision was comprised of 197 Bcfe of downward revision in the Piceance Basin due to well performance and 297 Bcfe of downward revision in the Arkoma Basin due to a spike in fracture stimulation costs, partially offset by 148 Bcfe of positive well performance revision in the Marcellus Shale.  The sharp increase in Arkoma Basin fracture stimulation costs was caused by a temporary scarcity of local completion crews.  The frac crew scarcity situation has since been alleviated and frac costs have returned to prior levels.  Liquids volumes increased by 59% from the prior year.  At year-end 2011, 78% of Antero’s proved reserves by volume were natural gas and 22% were liquids.  The percentage of proved undeveloped reserves in Antero’s proved reserve base decreased to 83% as compared to 86% at year-end 2010.  All-in finding and development costs averaged $0.46 per Mcfe in 2011,

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while drill bit only finding costs averaged $0.30 per Mcfe.  Antero’s three-year weighted average all-in finding and development cost from all sources through 2011 was $0.36 per Mcfe.

In 2011 Antero entered into a gas processing agreement with MarkWest Energy Partners, L.P. (NYSE: MWE)  in the Marcellus Shale where a new 200 MMcfd gas processing plant is being built in the heart of Antero’s leasehold position in West Virginia.  The new plant is expected to come online in the third quarter of 2012 and is fully dedicated to Antero.  Antero also recently signed an agreement to ship up to 20,000 Bbl/d of ethane on Enterprise Products Partners L.P.’s (NYSE: EPD) Appalachia to Texas ATEX pipeline (ATEX Express) as an anchor shipper.  ATEX Express will originate in southwest Pennsylvania with a delivery interconnect at MarkWest’s Houston, Pennsylvania processing and fractionation facilities.  The ATEX Express is expected to begin service in the first quarter of 2014.  As a result of these agreements, beginning at year-end 2011 Antero now reports NGLs separately from natural gas for its Marcellus Shale reserves.

Antero’s Marcellus Shale, Woodford Shale and Fayetteville Shale proved reserves at December 31, 2011 were all prepared by its internal reserve engineers and audited by DeGolyer and MacNaughton (D&M).  D&M’s reserve audit covered properties representing over 80% of Antero’s total estimated proved reserves in those areas at December 31, 2011 and was within 1% of Antero’s internal reserve estimates.  The Company’s Piceance Basin proved reserves at December 31, 2011 were prepared by its internal reserve engineers and audited by The Ryder Scott Company (Ryder Scott).  Ryder Scott’s reserve audit covered properties representing all of Antero’s total estimated proved reserves in the Piceance Basin at December 31, 2011 and was within 2% of Antero’s internal reserve estimates.  See “Non-GAAP Financial Measures” for explanation of finding and development cost per unit.

Summary of Changes in Proved Reserves (in Bcfe)

Antero Operations

Antero’s current gross operated production is 355 MMcfd, and estimated net production is 325 MMcfed, including non-operated production, NGLs and oil.  The estimated net production is comprised of 303 MMcfd of natural gas and 3,800 Bbl/d of NGLs and oil.  An additional 6 MMcfd of gross operated production (3 MMcfd net) from one completed and flow tested horizontal Arkoma Woodford well is constrained and waiting on pipeline takeaway.  During 2011, Antero completed 96 gross operated wells (85 net wells) and currently has 33 gross operated wells (31 net wells) in various stages of drilling, completion, waiting on completion or waiting on pipeline.

Marcellus Shale—Antero is operating six drilling rigs in the Marcellus Shale play, all of which are drilling in northern West Virginia.  The Company has a seventh drilling rig under contract that is expected to spud its first well in late March and two additional drilling rigs that are expected to be delivered in April 2012.  Antero has 236 MMcfd of gross operated production of which 98% is coming from 68 horizontal wells, resulting in 180 MMcfd of net production.  Antero has 17 horizontal wells either completing or waiting on completion and has one fully dedicated frac crew currently working in West Virginia.  A second Antero-dedicated frac crew is scheduled to begin service in April 2012.  In 2011 Antero drilled and completed 38 horizontal wells with an average 24-hour peak rate of 15.5 MMcfd and an average lateral length of approximately 6,700’.  Antero booked gross reserves of 10 Bcf per well on average for these 38 wells and completed well cost was $7.9 million on average, including allocated well pad costs.

Antero has 222,000 net acres of leasehold in the Appalachian Basin Marcellus Shale play of which only 17% was classified as proved at year-end 2011.

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 due to low natural gas prices. The Company has 61 MMcfd of gross operated production from 134 operated horizontal wells online and 73 MMcfed of net production including net non-operated production, NGLs and oil. The 73 MMcfed net is comprised of approximately 70 MMcfd of tailgate gas, 500 Bbls/d of NGLs and 15 Bbls/d of light oil.  Antero recently drilled and placed four wells online in the rich gas window with BTU value ranging from 1230 to 1260 and also has two non-operated Woodford Shale wells drilling with a combined 38% working interest.

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Antero has 66,000 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 59 MMcfd and 62 MMcfed net including 2 MMcfed of non-operated production from 232 wells online.  The 62 MMcfed net is comprised of approximately 43 MMcfd of tailgate gas, 2,500 Bbls/d of NGLs and 800 Bbls/d of light oil.  Antero has four Mesaverde wells currently in the process of completing and two 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 Basin.

Fayetteville Shale—Antero has 10 MMcfd of net non-operated production and 5,000 net acres in the Fayetteville Shale play.  The Company has one non-operated Fayetteville Shale well drilling with a 1% working interest.

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.

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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 twelve months ended December 31, 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.

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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.

For more information, contact Chad Green, Finance Director, at (303) 357-7339 or cgreen@anteroresources.com.

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ANTERO RESOURCES LLC

Consolidated Balance Sheets

December 31, 2010 and 2011

(In thousands)

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ANTERO RESOURCES LLC

Consolidated Statements of Operations

Years Ended December 31, 2009, 2010 and 2011

(In thousands)

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ANTERO RESOURCES LLC

Condensed Consolidated Statements of Cash Flows

Years ended December 31, 2009, 2010, and 2011

(In thousands)

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Results of Operations

Year Ended December 31, 2010 Compared to Year Ended December 31, 2011

The following table sets forth selected operating data for the year ended December 31, 2010 compared to the year ended December 31, 2011:

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(1)          Includes 333 MBbl of NGLs in 2010 retained by our midstream business as compensation for processing third-party gas under long term contracts. These amounts are not reflected in the per Mcfe data in this table.

(2)          See “Non-GAAP Financial Measures” above for a definition of EBITDAX (a non-GAAP measure) and reconciliation of EBITDAX to net income (loss).

(3)          Average prices shown in the table reflect both of the before-and-after-effects of our realized commodity hedging transactions. Our calculation of such after-effects includes realized gains or losses on cash settlements for commodity derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes. Oil and NGL production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts.  This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value.

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