Exhibit 99.1

Antero Reports Mid-Year 2014 Reserves

· Mid-year 2014 proved reserves increased by 19% to 9.1 Tcfe (13% liquids) from year-end 2013

· Proved developed reserves increased by 37% to 2.8 Tcfe (12% liquids)

· Pre-tax PV10 of proved reserves including hedges increased by 28% to $9.0 billion

· 3P reserves increased by 7% to 37.5 Tcfe (15% liquids)

· Pre-tax PV10 of 3P reserves including hedges increased by 24% to $26.4 billion

· Utica Shale dry gas position increased to 146,000 net acres and 9.5 Tcf of net resource

Denver, CO, July 15, 2014 — Antero Resources (NYSE: AR) (“Antero” or the “Company”) today announced that proved reserves at June 30, 2014 were 9.1 Tcfe, a 19% increase compared to proved reserves at December 31, 2013, in each case assuming ethane rejection. Proved, probable and possible (“3P”) reserves at June 30, 2014 totaled 37.5 Tcfe, which represents a 7% increase compared to December 31, 2013, assuming ethane rejection. Antero’s June 30, 2014 proved and 3P reserves excluded 356 and 1,425 million barrels of ethane, respectively, due to the relationship between assumed ethane and natural gas prices which indicate ethane will be rejected as of June 30, 2014. The Company’s proved and 3P reserves also excluded any reserves attributable to the Utica dry gas resource in West Virginia or Pennsylvania.

Antero’s reserves at June 30, 2014 were prepared by its internal reserve engineers and have not been reviewed or audited by its independent reserve engineers.

Proved Reserves

As of June 30, 2014, proved reserves increased by 19% from year-end 2013 to 9.1 Tcfe, of which 87% were natural gas, 12% were natural gas liquids (“NGLs”) and 1% was oil. The Marcellus Shale accounted for 94% of proved reserves and the Utica Shale accounted for the remaining 6%. Of the 1.5 Tcfe of proved reserves added in the six months ended June 30, 2014, 1.3 Tcfe was attributed to the Marcellus Shale. NGLs and oil increased by 49 million barrels and 6 million barrels, respectively, due to Antero’s drilling program targeting liquids-rich locations in the Marcellus and Utica Shale plays. Positive performance revisions of 85 Bcfe were primarily due to improved Marcellus well performance from shorter stage length (“SSL”) completions offset by the reclassification of 23 dry gas locations, representing 199 Bcfe, from proved undeveloped to the probable category due to the SEC’s five-year development rule.

Approximately 26% of Antero’s 488,000 net acres of current leasehold in the Marcellus and Utica were classified as proved at June 30, 2014. Based on Antero’s successful drilling results to date, as well as those of other operators in the vicinity of Antero’s leasehold, the Company believes that a substantial portion of its Marcellus and Utica Shale acreage will be added to proved reserves over time as more wells are drilled. Antero’s estimated Marcellus and Utica proved reserves and undeveloped locations are primarily booked assuming 660 foot and 1,000 foot interlateral distance, respectively.

Proved developed reserves increased 37% from year-end 2013 to 2.8 Tcfe at June 30, 2014. The Company added 59 Marcellus wells to proved developed reserves in the six months ended June 30, 2014. Virtually all of the wells utilized SSL completions and had an average estimated ultimate recovery (“EUR”) of 1.9 Bcfe/1,000 feet of lateral (12% liquids) which is consistent with previous estimates. Out of the 689 gross proved undeveloped Marcellus locations, 251, or 36% of the total, are booked assuming SSL completions.

Antero added 22 Utica wells to proved developed reserves in the six months ended June 30, 2014, consisting of 4 rich gas (1100-1200 Btu), 2 highly-rich gas (1200 to 1225 Btu), 3 highly-rich gas/condensate (1225 to 1250 Btu) and 13 condensate (1250 to 1300 Btu) wells. The wells located in the rich gas and highly-rich gas

regimes had an average EUR of 2.6 Bcfe/1,000 feet of lateral (14% liquids) and 2.8 Bcfe/1,000 feet of lateral (21% liquids), respectively. The wells located in the highly-rich gas/condensate and condensate regimes had an average EUR of 1.9 Bcfe/1,000 feet of lateral (26% liquids) and 1.1 Bcfe/1,000 feet of lateral (35% liquids), respectively. These EURs are consistent with previous estimates.

The percentage of proved reserves classified as proved developed increased to 30% at June 30, 2014 as compared to 27% at year-end 2013. Proved undeveloped reserves increased by 13%, primarily as a result of the successful execution of Antero’s Marcellus Shale development drilling plan. Antero’s 6.3 Tcfe of proved undeveloped reserves will require an estimated $5.8 billion of development capital over the next five years, resulting in an estimated average development cost for proved undeveloped reserves of $0.92 per Mcfe.

SEC prices for reserves were calculated as of June 30, 2014 on a weighted average Appalachian index basis and were $88.82 per Bbl for oil and $3.95 per MMBtu for natural gas. Using SEC prices, the pre-tax present value discounted at 10% (“pre-tax PV10”) of the June 30, 2014 proved reserves was $8.5 billion, excluding the value of the Company’s natural gas and oil hedges. Including the value of Antero’s hedges as of June 30, 2014 and using SEC prices, the pre-tax PV10 value of proved reserves was $9.0 billion, a 28% increase over year-end 2013. The pre-tax PV10 value of proved developed reserves was $4.4 billion excluding the value of hedges and $4.9 billion including the value of hedges, a 41% increase over year-end 2013.

Summary of Changes in Proved Reserves (in Bcfe)
Balance at December 31, 2013	7,632
Extensions, discoveries and additions	1,531
Performance revisions	85
Price revisions	11
Estimated Production	(152	)
Balance at June 30, 2014	9,107

3P Reserves

As of June 30, 2014, 3P reserves increased by 7% from year-end 2013 to 37.5 Tcfe, of which 85% were natural gas, 14% were NGLs and 1% was oil. The Marcellus, Utica, and Upper Devonian Shale comprised 26.4 Tcfe, 6.4 Tcfe and 4.7 Tcfe of the 3P reserves, respectively. The 7% increase in 3P reserves was driven primarily by the leasehold addition of 22,000 net acres in the Marcellus Shale core in northern West Virginia and 13,000 net acres in the Utica Shale core in southern Ohio, including 6,363 net acres associated with Antero’s previously announced Piedmont Lake lease acquisition.

Based on the results from SSL completions, Antero has increased the number of locations assuming SSL from 1,768 gross undeveloped 3P Marcellus locations to 1,893 gross undeveloped 3P Marcellus locations, or 62% of the 3,057 total gross undeveloped 3P Marcellus locations. Importantly, 25.5 Tcfe of Antero’s 26.4 Tcfe 3P reserves in the Marcellus, or 97%, were classified as proved or probable (2P), reflecting Antero’s extensive delineation and development activities in the Marcellus Shale.

Using SEC prices, the pre-tax PV10 of the June 30, 2014 3P reserves was $25.9 billion, excluding the value of the Company’s natural gas and oil hedges. This represents a 27% increase from the pre-tax PV10 of the year-end 2013 3P reserves. Including the value of Antero’s hedges as of June 30, 2014 and using SEC prices, the pre-tax PV10 value of 3P reserves was $26.4 billion, a 24% increase over the pre-tax PV10 of the year-end 2013 3P reserves including Antero’s hedges.

The table below summarizes Antero’s estimated reserve volumes using SEC pricing, broken out by operating area.

	Marcellus Shale						Utica Shale
	Gas	Liquids	Total			Gross	Gas	Liquids	Total			Gross
	(Bcf)	(MMBoe)	(Bcfe)			Locations	(Bcf)	(MMBoe)	(Bcfe)			Locations
Proved	7,454	179	8,530			990	406	22	537			78
Probable	13,486	581	16,969			2,193	2,844	78	3,315			445
Possible	824	15	913			175	2,313	42	2,568			353
Total 3P	21,764	775	26,412			3,358	5,563	143	6,419			876
3P PV10 ($Bn)			$	19.4					$	6.5
% Liquids (1)			18		%				13		%

	Upper Devonian Shale						Combined Total
	Gas	Liquids	Total			Gross	Gas	Liquids	Total			Gross
	(Bcf)	(MMBoe)	(Bcfe)			Locations	(Bcf)	(MMBoe)	(Bcfe)			Locations
Proved	40	0	40			9	7,900	201	9,107			1,077
Probable	811	1	816			184	17,141	660	21,100			2,822
Possible	3,502	48	3,788			928	6,640	105	7,269			1,456
Total 3P	4,353	49	4,645			1,121	31,680	966	37,476			5,355
3P PV10 ($Bn) (2)			$	0.0					$	26.4
% Liquids (1)			6		%				15		%

(1) Represents liquids volumes as a % of total 3P volumes. Combined total liquids comprised of 880 million barrels of NGLs and 86 million barrels of oil.

(2) Total PV10 includes $508 million value of Antero hedges at June 30, 2014 SEC pricing.

West Virginia and Pennsylvania Utica Shale Resource

Antero has Utica Shale dry gas rights on approximately 146,000 net acres of its West Virginia and Pennsylvania Marcellus acreage position and has identified 1,359 gross undeveloped locations with a total net resource of 9.5 Tcfe. Antero expects to drill and complete an exploratory Utica Shale dry gas well in the second half of 2014.

Non-GAAP Disclosure

Pre-tax PV10 value is a non-GAAP financial measure as defined by the SEC. Antero believes that the presentation of pre-tax PV10 value is relevant and useful to the Company’s investors because it presents the discounted future net cash flows attributable to Antero’s reserves prior to taking into account corporate future income taxes and the Company’s current tax structure. Antero further believes investors and creditors use pre-tax PV10 value as a basis for comparison of the relative size and value of Antero’s reserves as compared with other companies. With respect to PV10 calculated as of an interim date, it is not practical to calculate the taxes for the related interim period because GAAP does not provide for disclosure of standardized measure on an interim basis.

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. Antero’s website is located at www.anteroresources.com.

Cautionary Statements

This release includes “forward-looking statements”. 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.

Antero cautions 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 the Company’s control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs 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 Antero’s Annual Report on Form 10-K for the year ended December 31, 2013.

The SEC permits oil and gas companies to disclose probable and possible reserves in their filings with the SEC. Antero does not plan to include probable and possible reserve estimates in its filings with the SEC. Antero has provided internally generated estimates that have not been reviewed or audited by its third party reserve engineer in this release. Antero’s estimate of proved, probable and possible reserves is provided in this release because management believes it is useful information that is widely used by the investment community in the valuation, comparison and analysis of companies. However, the Company notes that the SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.

“EUR,” or Estimated Ultimate Recovery, refers to Antero’s internal estimates of per well hydrocarbon quantities that may be potentially recovered from a hypothetical future well completed as a producer in the area. These quantities do not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules.

Estimates of Antero’s net resource have been prepared by its internal reserve engineers and management without review by independent engineers. These estimates by their nature are more speculative than estimates of proved, probable, and possible reserves and accordingly are subject to substantially greater risk of being actually realized. Antero includes these estimates to demonstrate what it believes to be the potential for future drilling and production by the company. Ultimate recoveries will be dependent upon numerous factors including actual encountered geological conditions, the impact of future oil and gas pricing, exploration and development costs, and Antero’s future drilling decisions and budgets based upon its future evaluation of risk, returns and the availability of capital and, in many areas, the outcome of negotiation of drilling arrangements with holders of adjacent or fractional interest leases. Estimates of net resource and other figures may change significantly as development of Antero’s resource plays provide additional data and therefore actual quantities that may ultimately be recovered will likely differ materially from these estimates.”

This release provides a summary of Antero’s reserves as of June 30, 2014, assuming ethane “rejection”. Ethane rejection occurs when ethane is left in the wellhead natural gas stream when the natural gas is processed, rather than being separated out and sold as a liquid after fractionation. When ethane is left in the gas stream, the Btu content of the residue natural gas at the outlet of the processing plant is higher. Producers will generally elect to “reject” ethane at the processing plant when the price received for the ethane in the natural gas stream is greater than the price received for the ethane being sold as a liquid after fractionation, net of fractionation costs. When ethane is recovered in the processing plant, the Btu content of the residue natural gas is lower, but a producer is then able to recover the value of the ethane sold as a separate natural gas liquid product. In addition, natural gas processing plants can produce the other NGL products (propane, normal butane, isobutene and natural gasoline) while rejecting ethane.

For more information, contact Michael Kennedy — VP Finance, at (303) 357-6782 or mkennedy@anteroresources.com.