Exhibit 99.1

Antero Resources Reports 2010 Results, Operating Update and 2011 Outlook Highlights:

·                  Net production averaged 133 MMcfed in 2010, up 27% from 2009

·                  Consolidated EBITDAX of $198 million in 2010

·                  Net production is currently 190 MMcfed including NGLs

·                  7 Antero-operated drilling rigs currently running in core areas

·                  Proved reserves increased 183% to 3.2 Tcfe at year-end 2010, 21% are liquids

·                  All-in 2010 F&D cost of $0.28 per Mcfe and 3-year all-in F&D cost of $0.59 per Mcfe

·                  Increased hedge position to 376 Bcfe at $5.99 NYMEX-equivalent average through 2015

Denver, Colorado, March 30, 2011 — Antero Resources today announced its 2010 results.  Antero continued to execute its strategy of low cost production and reserve growth in its core areas while hedging its future revenues to protect its capital program and balance sheet.

Full Year 2010

Year-over-year, average natural gas prices before hedging rose 22% to $4.32 per Mcf.  However, due to lower hedged prices in 2010 relative to 2009, average realized gas prices including natural gas liquids (NGLs) and hedges declined by 13% to $5.93 per Mcf.  Average realized gas-equivalent prices including oil, NGLs and hedges also declined 13% to $6.02 per Mcfe.  In 2010, Antero realized natural gas hedging gains of $74 million, or $1.59 per Mcf.  The decrease in realized prices after hedging was more than offset by a 27% increase in production in 2010, resulting in net revenue growth of 12% to $301 million (excluding unrealized commodity derivative gains and losses and the gain on sale of Arkoma midstream assets).  Reported GAAP earnings including unrealized commodity derivative gains of $171 million, the gain on the sale of Arkoma midstream assets of $148 million and property impairments of $36 million, resulted in net income of $230 million in 2010.  Cash flow from operations before changes in working capital decreased by 15% to $128 million in 2010, primarily due to lower realized prices including hedges and higher interest expense driven by the issuance of senior notes in late 2009 and early 2010.

EBITDAX for 2010 was $198 million, a 2% decrease from 2009 despite solid net revenue growth due to lower realized prices including hedges and higher expenses for workovers in the Piceance and Arkoma.  See “Non-GAAP Financial Measures” for reconciliations of cash flow from operations before changes in working capital to net cash provided by operating activities and EBITDAX to net income.  Antero’s capital spending in 2010 totaled $423 million, comprised of $332 million in drilling costs (includes $32 million of cost incurred in 2009 but paid in 2010), $41 million for leasehold, $47 million in gathering costs and $3 million for other capital costs.

Net Production for 2010 totaled 49 Bcfe, comprised of 46 Bcf (94%) of natural gas and 0.5 million barrels (6%) of natural gas liquids (NGLs) and oil, representing a 27% increase over 2009.  Net daily production averaged 133 MMcfed for the year as compared to 105 MMcfed for 2009, while realized prices after hedging declined 13% to $6.02 per Mcfe.  Per unit cash costs (lease operating, gathering, compression and transportation and production tax) for 2010 were $1.72 per Mcfe, a 21% increase over 2009 primarily

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driven by an $8 million or $0.16 per Mcfe increase in workover expenses.  Per unit depreciation, depletion and amortization expense decreased 26% from the prior year to $2.88 per Mcfe.  General and administrative expense for the year was $0.47 per Mcfe.

Fourth Quarter 2010

Fourth quarter 2010 net revenue (excluding unrealized derivative gains and losses and the gain on the sale of the Arkoma midstream assets) increased by 25% over 2009 to $84 million, primarily driven by a 42% increase in net production.  Reported fourth quarter GAAP earnings including an unrealized commodity derivative loss of $47 million, the gain on sale of midstream assets of $148 million and property impairments of $4 million, resulted in net income of $90 million.  Cash flow from operations before changes in working capital decreased by 16% to $32 million, primarily due to higher cash costs including one-time acquisition expenses and higher interest expense.  EBITDAX for the fourth quarter was $52 million, a 6% increase over 2009.  Net production increased by 42% to 147 MMcfed while realized gas-equivalent prices after hedging declined 9% to $6.12 per Mcfe.  Per unit depreciation, depletion and amortization expense decreased 28% from the prior year to $2.47 per Mcfe.

Reserves

Proved reserves at December 31, 2010 totaled 3.2 Tcfe comprised of 2.5 Tcf of natural gas, 104 million barrels of NGLs and 10 million barrels of crude oil.  Reserves increased 2.1 Tcfe or 183% compared to the prior year.  All-in finding and development costs averaged $0.28 per Mcfe in 2010, while drill bit only finding costs averaged $0.16 per Mcfe.  Antero’s three-year weighted average all-in finding and development cost from all sources through 2010 was $0.59 per Mcfe.  Antero has elected to report NGLs separately from natural gas, beginning with its 2010 year-end reserve report.  Due to the execution of a gas processing agreement for its Piceance gas production in December 2010, Antero believes that separate disclosure of NGLs will provide more transparency to its production and reserve reporting.  At year-end 2010, 79% of Antero’s proved reserves by volume were natural gas, 19% were NGLs and 2% were crude oil compared to 99% natural gas and 1% oil as of year-end 2009. The percentage of proved undeveloped reserves increased to 86% as compared to 76% at year-end 2009.  Independent petroleum consultants engineered over 99% of the Company’s proved reserves by volume.  See “Non-GAAP Financial Measures” for explanation of finding and development cost per unit.

Summary of Changes in Proved Reserves

(in Bcfe)

The current SEC rules require that reserve calculations be based on the average first of month prices throughout the previous calendar year.  Accordingly, NYMEX prices for 2010 averaged $4.38/MMBtu, while the benchmark producing basin average natural gas prices were $4.18 per MMBtu in the Arkoma Basin, $3.93 per MMBtu in the Piceance Basin and $4.51 per MMBtu in Appalachian Basin.

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Commodity Hedges

Antero has hedged 376 Bcfe of future production using fixed price swaps covering the period from January 2011 through December 2015 at an average NYMEX-equivalent price of $5.99 per MMBtu.  Antero has hedged 80% to 90% of 2011 estimated production at a NYMEX-equivalent price of $6.01 per MMBtu. Virtually all of Antero’s financial hedges are tied to the local basin. For presentation purposes, these basin prices are converted by Antero to NYMEX-equivalent prices using current basis differentials in the over-the-counter futures market. Antero has eight different counterparties to its hedge contracts, all but one of which are lenders in Antero’s bank credit facility. All of Antero’s commodity hedges are simple fixed price swaps and over 99% are natural gas hedges.  The following table summarizes Antero’s current commodity hedge position.

2011 Capital Budget and Outlook

Antero’s revised capital budget for 2011 is $559 million and includes $452 million for drilling and completion, $65 million for leasehold acquisitions and $42 million for the construction of gathering pipelines and facilities.  The budget was revised in March to fund leasehold opportunities in Antero’s core areas.  Approximately 73% of the budget is allocated to the Marcellus Shale, 14% is allocated to the Woodford Shale and Fayetteville Shale and 13% is allocated to the Piceance Basin.  During 2011, Antero plans to operate five drilling rigs in the Marcellus Shale, one drilling rig in the Woodford Shale and one drilling rig in the Piceance Basin.  The capital budget is expected to be funded internally from operating cash flow and through the use of the undrawn capacity under Antero’s bank credit facility.  Antero also anticipates closing on approximately $10 million in non-core upstream asset divestitures in the second quarter of 2011, the proceeds of which will also be used to fund the capital budget.  At December 31, 2010, Antero had $404 million of available borrowing capacity under its bank credit facility and $9 million of cash on hand, resulting in total liquidity of $413 million.  These figures are net of a $29 million tax distribution to Antero unit holders made in February 2011 following the sale of the Arkoma midstream assets in November 2010.

Antero periodically provides guidance on certain factors that affect future financial performance.  As of March 30, 2011 we are using the following key assumptions in our projections for 2011:

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Antero Operations

Antero’s current gross operated production is 222 MMcfd and 190 MMcfed net (including non-operated production), comprised of 180 MMcfd of gas and 1,700 Bbl/d of NGLs net.

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 128 MMcfd of gross operated production primarily from 34 horizontal wells online resulting in 90 MMcfd of net production.  We estimate that an additional 20 MMcfd of gross operated deliverability from two completed wells is waiting on pipeline and facilities completion.  Antero expects to turn these two wells to sales by June when the Jarvisville Lateral is completed as a southerly extension to the Bobcat Lateral (formerly known as the Clarksburg Lateral) and 46 MMcfd of compression capacity is commissioned at a new third party owned compressor station.  The Tichenal Lateral, a southerly extension to the Jarvisville Lateral, is expected to be completed in July which will add another 46 MMcfd of compression capacity to the system.  Antero has nine additional horizontal Marcellus wells either completing or waiting on completion.

Antero has 169,000 net acres in the Marcellus Shale play of which only 8% was classified as proved at year-end 2010.

Woodford Shale — Antero is operating one drilling rig in the Arkoma Basin Woodford Shale play.  Antero has 60 MMcfd of gross operated production from 124 wells online and 64 MMcfed of net production including non-operated production. The Company’s net non-operated production in the Arkoma is estimated to be 30 MMcfed.  We have five non-operated wells drilling with a combined 75% working interest on our Arkoma acreage.  Antero has one horizontal well waiting on completion.

Antero has an existing gas processing agreement in the Woodford Shale under which a portion of the Company’s operated and non-operated gas production is processed. Antero estimates that 9% of its year end 2010 Woodford Shale proved reserves are liquids, primarily comprised of NGLs.  Antero has 71,000 net acres in the Arkoma Woodford Shale play.

Piceance Basin — Antero has one operated drilling rig running in the Piceance Basin.  Our gross operated production in the Piceance is currently 35 MMcfd (28 MMcfed net including 1 MMcfed of non-operated production) from 168 wells online.  Antero has 13 vertical Mesaverde wells waiting on completion in its Rifle rich gas area.

Antero recently entered into a long-term gas processing agreement with a third party midstream company in the Piceance Basin allowing it to realize a processing margin on its Piceance gas production effective January 1, 2011. Antero believes that virtually all of its Piceance Mesaverde gas production is liquids-rich gas that can be processed under current market conditions.  Antero estimates that over 35% of its year end 2010 Piceance proved reserves are liquids, primarily comprised of NGLs.  Antero has 68,000 net acres in the Piceance.

Fayetteville Shale — Antero has three non-operated Fayetteville Shale wells drilling with a combined 1% working interest.  The Company has 8 MMcfd of net production and 5,600 net acres in the Fayetteville Shale play.

Complete financial statements are included in Antero Resources Finance Corporations Annual Report on Form 10-K for the year ended December 31, 2010, which has been filed with the Securities and Exchange Commission.

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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. 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, 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 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

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calculating EBITDAX reported by different companies. The following table represents a reconciliation of our net income to EBITDAX for the twelve months ended December 31, 2010 and 2009:

The cash prices realized for oil, NGLs 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 has disclosed several per unit capital cost metrics in this release to measure our ability to establish a long-term trend of adding reserves at a reasonable cost including all-in finding and development cost per unit and drill bit only finding cost per unit.  It is important to economically find and develop new reserves that will offset produced volumes and provide for future production given the inherent decline of hydrocarbon reserves as they are produced. We believe the ability to develop a competitive advantage over other natural gas and oil companies is dependent on adding reserves in our core areas at lower costs than our competition.

Finding and development cost per unit is a non-GAAP metric used in the exploration and production industry by companies, investors and analysts. The calculations presented by the Company are based on costs incurred excluding asset retirement obligations and certain non-cash items and divided by proved reserve additions (extensions, discoveries and additions shown in the summary of changes in proved reserves table) adjusted for the changes in proved reserves for performance revisions and/or price revisions as stated in each instance in the release. This calculation does not include the future development costs required for the development of proved undeveloped reserves.

The finding and development cost per unit is a statistical indicator that has limitations, including its  predictive and comparative value.  In addition, since the finding and development cost per unit does not consider the cost or timing of future production of new reserves, such measures may not be an adequate measure of value creation. This reserve metric may not be comparable to similarly titled measurements used by other companies.

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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 Arkoma Basin in Oklahoma and the Piceance Basin in Colorado.

This release includes forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond Antero’s control. All information, other than historical facts included in this release, is forward-looking information. 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.

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

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ANTERO RESOURCES LLC AND SUBSIDIARIES

Consolidated Balance Sheets

December 31, 2009 and 2010

(In thousands)

(Continued)

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ANTERO RESOURCES LLC AND SUBSIDIARIES

Consolidated Balance Sheets

December 31, 2009 and 2010

(In thousands)

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ANTERO RESOURCES LLC AND SUBSIDIARIES

Consolidated Statements of Operations

Years ended December 31, 2008, 2009, and 2010

(In thousands)

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ANTERO RESOURCES LLC AND SUBSIDIARIES

Consolidated Statements of Cash Flows

Years ended December 31, 2008, 2009, and 2010

(In thousands)

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Results of Operations

Year Ended December 31, 2009 Compared to Year Ended December 31, 2010

The following table sets forth selected operating data for the year ended December 31, 2009 compared to the year ended December 31, 2010:

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