company website presentation january 2015

Company OverviewJanuary 2015

FORWARD-LOOKING STATEMENTS

This presentation contains 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. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Antero Resources Corporation and its subsidiaries (collectively, the “Company” or “Antero”) expects, believes or anticipates will or may occur in the future are forward-looking statements. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “estimate,” “project,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include estimates of the Company’s reserves, expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company’s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include the factors discussed or referenced under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013 and in the Company’s subsequent filings with the SEC.

The Company 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 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 “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013 and in the Company’s subsequent filings with the SEC.

Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

1

2

CHANGES SINCE DECEMBER 2014 PRESENTATION

Updated single well economic returns for Marcellus and Utica at 12/31/2014 strip prices

Slides 17, 26, 29,44, 45

Realized natural gas and equivalent pricing for 4Q 2014, including hedges

Updated natural gas and liquids hedge portfolio with mark-to-market value as of 1/13/2015

Slide 13

Slides 24, 25, 28

Slide 12

New drilling performance metric slides for Marcellus and Utica development programs

New slide highlighting low breakeven price of Antero’s shale plays compared to other U.S. shale plays Slide 16

Updated land position as of 12/31/2014 and Marcellus rig count position as of 1/9/2015 Slide 5

Updated “Road Map” for natural gas realizations based on 1/13/2015 strip prices Slide 14

3

Most Active Operatorin Appalachia

Most ActiveLand Organization

in Appalachia

Largest Firm Transport and Processing

Portfolio in Appalachia

Largest Gas Hedge Position in U.S. E&P +

Strong Financial Liquidity

Highest Growth Large Cap E&P

Largest Liquids-Rich Core Position in

Appalachia

Highest Realizations and Margins Among

Large Cap Appalachian Peers

Growth Land

Liquidity

Midstream

Drilling

LEADING UNCONVENTIONAL BUSINESS MODEL

MLP (NYSE: AM)Highlights

Substantial Value in Midstream Business

Realizations

Takeaway

Liquids-Rich1

2 3

4

5

67

8

Premier AppalachianE&P Company

Run by Co-Founders

Downstream LNGand NGL Sales

Production andCash Flow Growth

4

Antero has 170,000 net acres in WV and PA prospective for Utica dry gas – adjacent to current industry activity with highly encouraging initial results

CATALYSTS

45-50% production growth targeted for both 2015 and 2016 with 88% hedged at $4.42/MMBtu and 43% hedged at $4.47/MMBtu, respectively

Large, low cost core Marcellus and Utica natural gas drilling inventory with associated liquids generates attractive returns supported by long-term natural gas hedges, takeaway portfolio and downstream LNG and NGL sales agreements

Pursuing additional value enhancing long-term LNG and NGL sales agreements, supported by firm takeaway

Antero owns 70% of Antero Midstream Partners and thereby participates directly in its growth and value creation

Midstream MLP Growth

Sustainability of Antero’s Integrated

Business Model

Potential Water System Monetization

1

2

3

4

5

6

Contingent on receiving private letter ruling from the IRS, AM holds an option to acquire Antero’s fresh water system at fair market value

Utica Dry GasActivity

DRILLING – MOST ACTIVE OPERATOR IN APPALACHIA

1. All net acres allocated to the WV/PA Utica Shale Dry Gas and Upper Devonian Shale are included among the net acres allocated to the Marcellus Shale as they are stacked pay formations attributable to the same leasehold.

2. Locations as of 9/30/2014 adjusted for additional 245 locations acquired through 12/31/2014.3. Antero and industry rig locations and rig count as of 1/9/2015 per RigData.

5

COMBINED TOTAL – 6/30/14 RESERVESAssumes Ethane RejectionNet Proved Reserves 9.1 TcfeNet 3P Reserves 37.5 TcfePre-Tax 3P PV-10 $25.9 BnNet 3P Reserves & Resource 47.0 TcfeNet 3P Liquids 966 MMBbls% Liquids – Net 3P 15%3Q 2014 Net Production 1,080 MMcfe/d- 3Q 2014 Net Liquids 25,000 Bbl/dNet Acres(1) 542,000Undrilled 3P Locations(2) 5,359

UTICA SHALE CORE

Net Proved Reserves 537 BcfeNet 3P Reserves 6.4 TcfePre-Tax 3P PV-10 $6.5 BnNet Acres 148,000Undrilled 3P Locations(2) 1,112

MARCELLUS SHALE CORE

Net Proved Reserves 8.5 TcfeNet 3P Reserves 26.4 TcfePre-Tax 3P PV-10 $19.4 BnNet Acres 394,000Undrilled 3P Locations 3,131

UPPER DEVONIAN SHALE

Net Proved Reserves 40 BcfeNet 3P Reserves 4.6 TcfePre-Tax 3P PV-10 NMUndrilled 3P Locations 1,116

WV/PA UTICA SHALE DRY GASNet Resource 9.5 TcfNet Acres 170,000Undrilled Locations 1,390

0

5

10

15

20

25

Rig

Cou

nt

Operators

SW Marcellus + Utica Rigs(3)

47.5%

29.9%27.7% 26.8%

25.0%23.6%

21.3%19.7%

17.9%16.4%

9.7%

6.6%5.3%

3.8%2.8% 2.3%

0.1% (2.8%)

-10%

0%

10%

20%

30%

40%

50%

6Appalachian Peers

Source: Represents median of Wall Street research estimates for 2015E production growth vs. 2014 estimated production. 1. Includes all North American E&P companies with a market capitalization greater than $9.0 billion. 2. Based on midpoint of publicly announced 2015 production growth target range of 45% - 50%.

Antero’s 45%-50% production growth target for 2015 leads the U.S. large cap E&P industry(1)

(2)

GROWTH – HIGHEST GROWTH LARGE CAP E&P

1. 2012, 2013 and 6/30/2014 proved reserves assuming ethane rejection.2. Based on 45-50% production growth targets for 2015 and 2016. 3. Per current First Call median estimate from Bloomberg.

0

600

1,200

1,800

2,400

2010 2011 2012 2013 2014 2015E 2016E

Marcellus Utica Guidance

30 124239

522

(2)

1,500

2,200

(2)

1,007

0

2,000

4,000

6,000

8,000

10,000

2010 2011 2012 2013 6/30/2014

Marcellus Utica

677

2,844

4,283

7,632

(1) (1) (1)

9,107

7

AVERAGE NET DAILY PRODUCTION (MMcfe/d)NET PROVED SEC RESERVES (Bcfe)

0255075

100125150175200225

2010 2011 2012 2013 2014E

Marcellus Utica

29 36

86

162

215

GROWTH – STRONG TRACK RECORD

OPERATED GROSS WELLS SPUD EBITDAX ($MM)

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

2010 2011 2012 2013 2014E

$28$160

$285

$649

$1,147

(4)

45-50% Annual Growth Target

92% Growth

Assembled a 542,000 net acre position in the core of the Marcellus and Utica shale plays over the past 6 years

December 2008

Net Acreage 118,000

Net Production (MMcfe/d) NM

3P Reserves (Bcfe) NM

3P PV-10 ($MM) NM

Rigs Running NM

Dec 2008 Dec 2011 Dec 2014

December 2011(1)

Net Acreage 214,000

Net Production (MMcfe/d) 167

3P Reserves (Bcfe) 18,400

3P PV-10 ($MM) $9,000

Rigs Running 5

December 2014(1)

Net Acreage 542,000

Net Production (MMcfe/d) 1,265

6/30/14 3P Reserves (Bcfe) 37,500

6/30/14 3P PV-10 ($MM) $25,900

Rigs Running 21

1. Reserves and PV-10 data for December 2014 reflect data as of 6/30/2014. Net daily production for December 2011 and December 2014 is for fourth quarter respectively.

LAND – MOST ACTIVE LAND ORGANIZATIONIN APPALACHIA

8

118,000 118,000 118,000 162,000 189,000 213,000

285,000 371,000

420,000 450,000 486,000

542,000

0

100,000

200,000

300,000

400,000

500,000

600,000

12/2008 12/2009 6/2010 12/2010 6/2011 12/2011 6/2012 12/2012 6/2013 12/2013 6/2014 12/2014

Antero Net Acreage

Utica Marcellus

9

LIQUIDS-RICH – LARGEST CORE POSITION

Source: Core outlines and peer net acreage positions based on peer presentations, news releases and 10-K/10-Qs.

Antero has the largest liquids-rich core position in Appalachia ≈371,000 net acres (> 1100 Btu)

MIDSTREAM – MLP (NYSE: AM) HIGHLIGHTSSUBSTANTIAL VALUE IN MIDSTREAM BUSINESS

1. AR enterprise value excludes AM minority interest and cash. Values as of 1/13/2015.2. Based on First Call 9/30/2015 NTM EBITDA forecast of $142 million for Water Business included in preliminary AM S-1 and applying AR enterprise value to EBITDAX multiple derived from First Call AR

9/30/2015 NTM EBITDAX estimates.3. Represents difference between AR enterprise value and Antero Midstream net market value and Water System enterprise value.4. Based on 262.0 million AR shares outstanding.

10

Antero ResourcesCorporation (NYSE: AR)

$12.8 Billion Enterprise Value(1)

Ba3/BB Corporate Rating

Antero MidstreamPartners LP (NYSE: AM)$3.3 Billion Valuation(1)

70% Limited Partner Interest

E&P Assets

Gathering Assets

Corporate Structure Overview(1)

Market Valuation of AR Ownership in AM:• AR ownership: 69.7% LP Interest = 105.9 million units

AM Priceper Unit

AM UnitsOwnedby AR(MM)

AR Value in AM LP Units

($MMs)Value Per

AR Share(4)

$22 106 $2,332 $9$23 106 $2,445 $9$24 106 $2,544 $10$25 106 $2,647 $10$26 106 $2,753 $11$27 106 $2,858 $11$28 106 $2,964 $12

Fresh Water Distribution System

Compression Assets

= $2.3 Billion Market Valuation(1) $9.0 Billion Implied Valuation(3)$1.5 Billion Derived Valuation(2)

TAKEAWAY – LARGEST FIRM TRANSPORTATION AND PROCESSING PORTFOLIO IN APPALACHIA

Odebrecht / Braskem30 MBbl/d Commitment

Ascent Cracker(Pending Final

Investment Decision)

Antero Long Term Firm Processing & Takeaway Position (2018) – Accessing Favorable Markets

Mariner East II62 MBbl/d Commitment(2)

Marcus Hook Export

Shell25 MBbl/d CommitmentBeaver County Cracker

(Pending FinalInvestment Decision)

Sabine Pass (Trains 1-4)50 MMcf/d per Train

1. February 2015 and full year 2016 futures basis, respectively, provided by Wells Fargo dated 1/13/2015. Favorable gas markets shaded in green.2. As an anchor shipper on Mariner East II, Antero has the right to expand its NGL commitment with notice to operator.

Chicago(1)

+$0.19 / $(0.09)

CGTLA(1)

$(0.08) / $(0.10)

Dom South(1)

$(1.37) / $(1.32)

TCO(1)

$(0.20) / $(0.42)

11

4 Bcf/dFirm Gas TakeawayBy 2018

Cove Point

1,316 943 780 1,073 818 100

$4.42 $4.47 $4.34 $4.50 $4.41 $4.24

$2.95$3.33 $3.60 $3.73 $3.83 $3.94

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

0200400600800

1,0001,2001,400

2015 2016 2017 2018 2019 2020

BBtu/d $/MMBtu

12

Average Index Hedge Price(1)Hedged Volume Current NYMEX Strip(2)

COMMODITY HEDGE POSITION

1. Reflects weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio. Antero has hedged 3,000 Bbl/d of oil and 23,000 Bbl/d of propane for 2015. 2. As of 1/13/2015.3. Percentage of net gas equivalent production target hedged for respective years.

~$2.0 billion mark-to-market unrealized gain based on 1/13/2015 prices 1.8 Tcfe hedged from January 1, 2015 through year-end 2020 and 273 Bcf of TCO basis hedges from 2015 to 2017

$760 MM $539 MM $229 MM $302 MM $174 MM $11MM

Mark-to-Market Value(2)

LIQUIDITY – LARGEST GAS HEDGE POSITION IN U.S. E&P + STRONG FINANCIAL LIQUIDITY

$3,000

$2,012

($1,505)

($332) $6 $843

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

Credit Facility9/30/2014

Bank Debt9/30/2014

L/Cs Outstanding9/30/2014

Cash9/30/2014

AM IPOProceeds

to AR

Pro FormaLiquidity

9/30/2014

AR LIQUIDITY POSITION ($MM) AM LIQUIDITY POSITION ($MM)

$1,000$1,250

$0 $0 $0

$250

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

Credit Facility9/30/2014

Bank Debt9/30/2014

L/Cs Outstanding9/30/2014

Cash9/30/2014

AM IPO Proceeds

to AM

Pro FormaLiquidity

9/30/2014

≈ 88% of 2015ETarget

Production(3)

Over $3 billion of combined AR and AM financial liquidity as of 9/30/2014, pro forma for AM IPO closed on 11/10/2014

≈ 43% of 2016ETarget

Production(3)

1. Includes firm sales. 2. Price realization includes $0.05 of midstream revenues in 3Q, 2014. 3. Includes natural gas hedges.4. Source: Public data from 3Q 2014 10-Qs. Peers include Cabot Oil & Gas, CONSOL Energy, EQT Corp. and Range Resources. 5. Includes realized hedge gains and losses. Operating costs include lease operating expenses, production taxes, gathering, processing and firm transport costs and general and administrative costs. 4-year

proved reserve average all-in F&D from 2010-2013. Calculation = (Development costs + exploration costs + leasehold costs) / Total reserves added (2013 ending reserves – 2010 beginning reserves + 4-year reserve sales – 4-year reserve purchases + 4-year accumulated production). AR price realization includes $0.04 of midstream revenues.

$4.16 $3.97

$0.58 $0.95 $0.74 $0.77 $0.81

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

Antero Peer 1 Peer 2 Peer 3 Peer 4

$/M

cfe

LOE Production Taxes GPT G&A EBITDAX 4-year Avg. All-in F&D ($/Mcfe)

$4.96

$3.25

$4.48

$2.93

$2.40$2.64

$2.11 $2.09

13

REALIZATIONS – HIGHEST REALIZATIONS & MARGINSAMONG LARGE-CAP APPALACHIAN PEERS

3Q & 4Q 2014 Natural Gas Realizations ($/Mcf)

3Q 2014 Natural Gas Realizations(3) 3Q 2014 Price Realization & EBITDAX Margin vs F&D(2)(4)

$4.31

$4.12$3.66 $3.62 $3.60

$2.98 $2.87 $2.75

$0.00

$2.00

$4.00

$6.00

AR EQT GPOR RRC CNX RICE ECR COG

$/M

cf

3Q 2014 NYMEX = $4.06/Mcf

AR Peer 1 Peer 2 Peer 3 Peer 4

Average NYMEX

Price($/Mcf)

AverageDifferential(1)

($/Mcf)

AverageBTU Upgrade

($/Mcf)

Discount to NYMEX($/Mcf)

GasHedgeEffect

($/Mcf)

AverageRealized

Gas Price($/Mcf)

AverageRealized Gas

Premium/ Discount

($/Mcf)

Liquids Upgrade($/Mcfe)

Realized Equivalent

Price($/Mcfe)

Equivalent Premium($/Mcfe)

3Q 2014 $4.06 $(0.84) $0.41 $(0.43) $0.68 $4.31 $0.25 $0.60 $4.91 $0.85

4Q 2014 $4.00 $(0.71) $0.37 $(0.34) $0.73 $4.39 $0.39 $0.29 $4.68 $0.68

DOM S22%

DOM S8%

TETCO M28%

TETCO M210%

TCO19%

TCO15%

NYMEX7%

NYMEX11%

Gulf Coast24% Gulf Coast

38%

Chicago20%

Chicago18%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2015 Basis(1)

2016 Basis(1)

2015Hedges

2016Hedges

($/Mcf) 2015E 2016ENYMEX Strip Price(1) $2.95 $3.33Basis Differential to NYMEX(1) $(0.47) $(0.38)BTU Upgrade(5) $0.25 $0.30 Estimated Realized Hedge Gains (6) $1.39 $0.67Realized Gas Price with Hedges $4.12 $3.92 Premium to NYMEX +$1.17 +$0.59Liquids Impact(7) +$0.29 +$0.33Premium to NYMEX w/ Liquids +$1.46 +$0.92Realized Gas-Equivalent Price $4.41 $4.25

4. Represents 60,000 MMBtu/d of TCO index hedges and 205,000 MMBtu/d of TCO basis hedges that are matched with NYMEX hedges for presentation purposes.

5. Assumes ethane rejection resulting in 1100 BTU residue sales gas.6. Includes hedge gains associated with oil and propane hedges.7. Represents equivalent price upgrade associated with NGL (C3+) and oil production.

REALIZATIONS – REALIZED PRICE “ROAD MAP”

1. Based on 1/13/2015 strip pricing.2. Differential represents contractual deduct to NYMEX-based firm sales contract.3. Represents 120,000 MMBtu/d of TCO index hedges and 390,000 MMBtu/d of TCO basis hedges that are

matched with NYMEX hedges for presentation purposes.

Mar

kete

d %

of T

arge

t Re

sidu

e G

as P

rodu

ctio

n

+$0.05/MMBtu

$(0.25)/MMBtu(2)

$(1.33)/MMBtu

$(0.28)/MMBtu

$(0.09)/MMBtu

$(0.25)/MMBtu(2)

$(1.32)/MMBtu

$(0.42)/MMBtu

$(0.10)/MMBtu$(0.09)/MMBtu

40,000 MMBtu/d

@ $4.00/MMBtu

230,000 MMBtu/d

@ $5.60/MMBtu

510,000 MMBtu/d

@ $3.87/MMBtu(3)

170,000 MMBtu/d

@ $4.09/MMBtu

272,500 MMBtu/d

@ $5.35/MMBtu

265,000 MMBtu/d

@ $3.89/MMBtu(4)

$1.39/Mcfe in estimated hedge gains(1)

70% exposure to favorable price indices

$0.67/Mcfe in estimated hedge gains(1)

82% exposure to favorable price indices

Antero is forecasting realized gas prices including hedges at a premium to NYMEX strip prices for 2015 and 2016, assuming current strip prices and basis, existing firm transportation and hedges, and targeted 2015 and 2016 production figures

$(1.28)/MMBtu

$(1.21)/MMBtu

Wtd. Avg.Basis $(0.47)

1,160,000 MMBtu/d@ $4.34/MMBtu

Wtd. Avg.Basis $(0.38)

942,500 MMBtu/d@ $4.47/MMBtu

2015E 2016E

14

380,000 MMBtu/d

@ $3.88/MMBtu

235,000 MMBtu/d

@ $4.00/MMBtu

SECTOR POSITIONING

15

$39 $42 $44$51 $53 $54

$60 $64 $65 $68 $69 $72$83

$86

$0

$20

$40

$60

$80

$100

WTI

Pric

e ($

/Bbl

)

Antero 2015Drilling

$1.94 $2.20 $2.20

$2.37 $2.96 $3.13 $3.31 $3.48 $3.50 $3.63 $3.77 $3.85 $3.88 $3.98 $4.33 $4.38

$5.56 $5.62 $5.69 $5.71 $5.74

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

NYM

EX P

rice

($/M

MB

tu)

Antero 2015Drilling

PREMIER POSITION IN LOW-COST RICH GAS PLAYS

North American Gas Resource Play Breakeven Natural Gas Price(3)

16

North American Breakeven Oil Prices ($/Bbl)(1)

2015 NYMEX Strip: $3.01/MMBtu(2)

2015 WTI Strip: $56.26/Bbl(2)

Over 70% of Antero’s 4,243 Marcellus and Utica undeveloped 3P locations are rich gas locations which have the lowest breakeven prices for both oil and natural gas

1. Source: Credit Suisse report dated December 2014 – Break-even WTI oil price to generate 15% after-tax rate of return. Assumes NYMEX gas price of $3.66/MMBtu for 2015-2019; $4.23/MMBtu thereafter.2. 2015 one year WTI crude oil strip price as of 12/31/14; NYMEX one year natural gas strip price as of 12/31/14.3. Source: Credit Suisse report dated December 2014 – Break-even NYMEX gas price to generate 15% after-tax rate of return. Assumes WTI oil price of $64.74/Bbl for 2015-2019; $70.50/Bbl thereafter.

Antero Projects

0%

10%

20%

30%

40%

248

14387

265

369

10%

31%46%

33% 30%

0

100

200

300

400

0%

25%

50%

75%

Condensate Highly-RichGas/

Condensate

Highly-RichGas

Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

R

Locations ROR

MARCELLUS SSL WELL ECONOMICS(1)

727896

633

875

42%28%

12% 11%

02004006008001,000

0%

25%

50%

75%

100%

Highly-RichGas/

Condensate

Highly-RichGas

Rich Gas Dry Gas

Tota

l 3PL

loca

tions

RO

R

Locations ROR

MULTI-YEAR DRILLING INVENTORY SUPPORTS LOW RISK, HIGH RETURN GROWTH PROFILE

Large 3P Drilling Inventory of High Return Projects(3)

1. Pre-tax well economics based on 12/31/2014 natural gas and WTI strip pricing for 2015-2020, flat thereafter, NGLs at 55% of oil price and applicable firm transportation costs; 8,000’ lateral. 2. Adjusted for additional 245 gross locations acquired as of 12/31/2014.3. Source: Credit Suisse report dated December 2014 – After-tax internal rate of return based on 12/31/2014 strip pricing.

26% 26%31%

15%

Inte

rnal

Rat

e of

Ret

urn

(%)

20%

17

UTICA WELL ECONOMICS(1)(2)

72% of Marcellus locations are processable (1100-plus Btu) 67% of Utica locations are processable (1100-plus Btu)

3,000 Antero Liquids-Rich Locations

16%

2015Drilling Plan

Antero Projects

Antero is well positioned in the core of the highest return shale projects in the U.S. in the current commodity price environment

LNG Exports48%

Mexico/Canada Exports

18%

Power Generation

17%

Transportation1%

Industrial16%

20 Bcf/d OF INCREMENTAL GAS DEMAND BY 2020 Significant demand growth expected for U.S.

natural gas

More than 65% of the 20 Bcf/d in incremental gas demand forecast by 2020 is expected to be generated from exports:− LNG: 9.5 Bcf/d (~48%)− Mexico/Canada: 3.5 Bcf/d (~18%)

Of the 9.5 Bcf/d of expected incremental demand from LNG export projects, 5.8 Bcf/d (or 61%) of the projects have secured the necessary DOE and FERC permits

18

Incremental Demand Growth Through 2020 by Category

Projected Incremental Natural Gas Demand Through 2020

Source: Simmons & Company International, “2015 US Natural Gas Outlook and Updated Long Term Demand Forecast,” September 2014.

Sherwood 7 2

5

9

13

17

20

0

4

8

12

16

20

2015 2016 2017 2018 2019 2020Mexico/Canada Exports Power GenerationTransportation PetrochemLNG Exports

9.5 Bcf/d of the 20 Bcf/d of incremental demand is expected to come from

LNG exports

(Bcf/d)

LNG

Exports

Power Gen

Petrochem

LNG EXPORTS BY PROJECT – EXPECTED START UP

Assuming 9.5 Bcf/d of LNG exports by 2020, the U.S. would be the world’s 3rd largest LNG exporter (behind Qatar and Australia)− 7.7 Bcf/d (81%) of the 9.5 Bcf/d of expected LNG

exports have secured US DOE non-FTA (free trade agreement) permit approval

− 6.7 Bcf/d (four projects, 70%) have been awarded FERC construction permits (see next page for more detail)

The first LNG export project, Sabine Pass LNG Train 1 is expected to commence operations in early 2016− Antero has committed to 200 MMcf/d on Sabine

Pass Trains 1-4

The second LNG export project, Cove Point LNG, is expected to commence operations in 2017− Antero has committed to 330 MMcf/d on Cove

Point 1-2

19

LNG Exports by Project Through 2020

LNG Exports by Project(in Bcf/d)

2015 2016 2017 2018 2019 2020

Sabine Pass 1 - 0.6 - - - - Sabine Pass 2 - 0.6 - - - - Sabine Pass 3 - - 0.6 - - - Sabine Pass 4 - - 0.6 - - - Sabine Pass 5 - - - - 0.6 - Cove Point 1 - - 0.4 - - - Cove Point 2 - - - 0.4 - - Cameron 1 - - - 0.6 - - Cameron 2 - - - 0.6 - - Cameron 3 - - - - 0.6 - Freeport 1 - - - 0.5 - - Freeport 2 - - - - 0.5 - Freeport 3 - - - - 0.5 - Freeport 4 - - - - - 0.4Corpus Christi 1 - - - - 0.6 - Corpus Christi 2 - - - - - 0.6Lake Charles 1 - - - - - 0.6

LNG Incremental Exports - 1.2 1.6 2.2 2.9 1.7

Antero Supply Agreements for Portion of Capacity

Source: Simmons & Company International, “2015 US Natural Gas Outlook and Updated Long Term Demand Forecast,” September 2014. Data updated for recent announcements subsequent to Simmons report.

MARCELLUS/UTICA DRIVING GAS SUPPLY GROWTH

Of the 23 Bcf/d of expected incremental gas supply from 2009 to 2015, ~18 Bcf/d, or 78%, is expected to be generated from Marcellus and Utica production

Marcellus and Utica gross gas production in 2015 is expected to grow 3.6 Bcf/d, which represents the total expected growth in overall supply from all areas for 2015(1)

20

Gas Supply Growth by Area: 2009 – 2015E

Lower 48 Gas Supply by Area

Source: Simmons & Company International, “2015 US Natural Gas Outlook and Updated Long Term Demand Forecast,” September 2014; EIA.1. Other contributing areas to growth include the Permian (+0.5 Bcf/d), Eagle Ford (+0.6 Bcf/d), Williston (+0.3 Bcf/d) and DJ (+0.2 Bcf/d), offset by declines in the Barnett (-0.3 Bcf/d)

and Haynesville (-0.6 Bcf/d).

Sherwood 7

Marcellus & Utica 78%

Eagle Ford 22%

(MMcf/d)

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000Nov-12 Nov-13 Nov-14

Marcellus production has driven U.S. gas

supply growth

ASSET OVERVIEW

21

WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECT

100% operatedOperating 13 drilling rigs

including 5 intermediate rigs394,000 net acres in

Southwestern Core (73% includes processable rich gas assuming an 1100 Btu cutoff)– 50% HBP with additional 27%

not expiring for 5+ years362 horizontal wells completed

and online– Laterals average 7,400’– 100% drilling success rate5 plants in-service at Sherwood

Processing Complex capable of processing 1 Bcf/d of rich gas−Over 800 MMcf/d being

processed currentlyNet production of 937 MMcfe/d in

3Q 2014, including 17,300 Bbl/d of liquids 3,131 future drilling locations in

the Marcellus (2,256 or 72% are processable rich gas)26.4 Tcfe of net 3P (18% liquids),

includes 8.5 Tcfe of proved reserves (assuming ethane rejection) Highly-Rich Gas

128,000 Net Acres896 Gross Locations

Rich Gas92,000 Net Acres

633 Gross Locations

Dry Gas105,000 Net Acres

875 Gross Locations

Highly-Rich/Condensate69,000 Net Acres

727 Gross Locations

HEFLIN UNIT30-Day Rate

2H: 21.4 MMcfe/d (21% liquids)

CONSTABLE UNIT30-Day Rate

1H: 14.3 MMcfe/d (26% liquids)

142 Horizontals Completed30-Day Rate8.1 MMcf/d

6,915’ average lateral length

SherwoodProcessing

Complex

Source: Company presentations and press releases. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held. Note: Rates in ethane rejection.

NERO UNIT30-Day Rate

1H: 18.2 MMcfe/d(27% liquids)

BEE LEWIS PAD30-Day Rate

4-well combined 30-Day Rate of

67 MMcfe/d (26% liquids)

RJ SMITH PAD30-Day Rate



22

MHR COLLINS UNIT30-Day Rate

4-well average9.3 MMcfe/d (26% liquids)

HENDERSHOT UNIT30-Day Rate

1H: 16.3 MMcfe/d2H: 18.1 MMcfe/d

(29% liquids)

HORNET UNIT30-Day Rate

1H: 21.5 MMcfe/d2H: 17.2 MMcfe/d

(26% liquids)CARR UNIT30-Day Rate

2H: 20.6 MMcfe/d(20% liquids)

WAGNER PAD30-Day Rate



$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

$3.0

2,000 4,000 6,000 8,000 10,000

$MM

/ 1,

000'

Lateral length, ft

0.0

3.0

6.0

9.0

12.0

15.0

0.0

3.0

6.0

9.0

12.0

15.0

0 1 2 3 4 5 6 7 8 9 10

Cum

ulat

ive

Bcf

MM

cf/d

Production Year

Non-SSL Type Curve (1.5 Bcf/1,000') Non-SSL Actual Production Non-SSL Type Curve Cumulative Production

SSL Type Curve (1.7 Bcf/1,000') SSL Actual Production SSL Type Curve Cumulative Production

Antero has over five years of production history to support its Non-SSL type curve Antero has one and a half years of production history to support its SSL type curve: 1.7 Bcf/1,000’ with only 10% to 15% higher well costs vs. Non-SSL Lack of faulting and contiguous acreage position allows for drilling of long laterals; ~7,400’ average since inception and ~8,000’ in 2014− Drives down cost per 1,000’ of lateral resulting in best in class development costs

ANTERO’S MARCELLUS SHALE TYPE CURVE

1. 198 Antero Marcellus Non-SSL wells normalized to time zero, production for each well normalized to 8,000’ lateral length.2. 164 Antero Marcellus SSL wells normalized to time zero, production for each well normalized to 8,000’ lateral length.

Marcellus Type Curves – Normalized to 8,000’ Lateral(1)

EURs Increase With Lateral Length Well Cost / 1,000’ Decreases with Lateral Length

(2)

Actual Rates24-Hour

Peak Rate30-Day

Avg. Rate90-Day

Avg. Rate180-Day

Avg. RateOne-Year Avg. Rate

Two-Year Avg. Rate

Three-YearAvg. Rate

Four-Year Avg. Rate

Wellhead Gas (MMcf/d) 15.3 9.2 7.1 5.8 4.3 3.2 2.6 1.8# of Antero Wells 362 343 322 291 227 124 63 24

23

0

5

10

15

20

25

2,000 4,000 6,000 8,000 10,000

EUR

, BC

F

Lateral Length, ft

Antero’s Marcellus 30-day rates have increased by 64% over the past two years as the Company increased per well lateral lengths by 20% and shortened stage lengths by 43%

INCREASING RECOVERIES AND LOW VARIANCEIN MARCELLUS

1. Processed rates converting C3+ NGLs and condensate at 6:1. Ethane rejected and sold in gas stream.

30-Day Rates – 343 Marcellus Wells(1)

24

SSL Reserves per 1,000’ of Lateral – 164 Marcellus SSL Wells

0

5

10

15

20

25

MM

cfe/

d

2014 – 13.1 MMcfe/d

2013 – 9.4 MMcfe/d

2009–2012 – 8.0 MMcfe/d

The Marcellus is a reliable, low risk play as demonstrated by the relatively tight distribution of EURs per 1,000’ and the P10/P90 ratio of 1.5x for 164 SSL wells

05

101520253035

1.3 1.4 1.5 1.6 1.7 1.8 1.9 2 2.1 2.2 2.3 2.4 2.5 2.6 2.7 > 2.7

Wel

l Cou

nt

Bcfe/1,000‘ of Lateral

2.0

P10/P90 = 1.5x

1.5 1.6 1.5 1.62.0

$0.97 $0.89

$0.98 $1.13

$0.89

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

0.00

0.50

1.00

1.50

2.00

2.50

2010 2011 2012 2013 2014

Dev

elop

men

t Cos

t ($/

Mcf

e)

EUR

/1,0

00' L

ater

al

EUR vs. Development Cost

EUR/1,000' Lateral (Bcfe) Development Cost ($/Mcfe) 25

MARCELLUS WELL PERFORMANCE IMPROVEMENTS Increasing recoveries and efficiencies, through longer laterals, shorter stage lengths and faster drilling SSL completions drove a 21% decline in estimated development costs in 2014 while lower service costs are expected

to drive further development cost reductions in 2015

37 36 34 32 29

0

10

20

30

40

50

2010 2011 2012 2013 2014

Spud

-to-S

pud

Day

s

Average Spud-to-Spud Days

411 420

361

283

200

1416

2127

40

050100150200250300350400450

0

10

20

30

40

50

2010 2011 2012 2013 2014

Ave

rage

Sta

ge L

engt

h (F

eet)

Ave

rage

Fra

c St

ages

per

Wel

l

Increasing Frac Stages per Well

Average Stage Length Average Frac Stages/Well

5,732 6,717

7,345 7,308

8,052

19

38

59

103

136

0

20

40

60

80

100

120

140

160

0

2,000

4,000

6,000

8,000

10,000

2010 2011 2012 2013 2014

Wel

ls o

n Fi

rst S

ales

Late

ral L

engt

h (1

,000

Fee

t)

Lateral Length Improvements

Lateral Length Wells on First Sales(2)

1. Average vertical length of ~7,300’ drilled for 362 Marcellus wells.2. Based on preliminary reserve and cost estimates for 136 Marcellus wells completed in 2014 subject to completion of year-end reserves and financial audit.

(1)

0%

20%

40%

60%

80%

100%

$3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00

Pre-

Tax

RO

R (%

)

Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas

MARCELLUS ROR% AND GAS PRICE SENSITIVITY

261. Assumes 12/31/2014 strip pricing, market differentials and relevant transportation cost; 8,000’ lateral.

Large portfolio of Highly-Rich Gas/Condensate to Dry Gas locations Focused on drilling highly economic rich gas locations – rig symbols represent current rig location by Btu regime Assumes 12/31/2014 WTI strip pricing for 2015-2020, flat thereafter; NGL price 55% of WTI

NYMEX Flat Price Sensitivity(1)

ROR% at Flat 2015-2020 Strip Price

Highly-Rich Gas/Condensate: 44%

Highly-Rich Gas: 30%

Rich Gas: 12%

Dry Gas: 11%

727 Locations

896 Locations

633 Locations

875 Locations

Antero Rigs Employed

2015Drilling Plan

Source: Company presentations and press releases. Note: Antero acreage position reflects townships in which greater than 3,000 net acres are held. Note: Third party peak rates assume ethane recovery; Antero 30-day rates in ethane rejection.1. For non-Antero wells, Antero has converted rich gas rates where BTU has been disclosed to NGLs, assuming ethane recovery. Where BTU has not been disclosed, Antero has estimated BTU and gas

composition.2. 30-day rate reflects restricted choke regime.

100% operated Operating 8 rigs including 3 intermediate rigs 148,000 net acres in the core rich gas/

condensate window (72% includes processable rich gas assuming an 1100 Btu cutoff)– 20% HBP with additional 79% not expiring

for 5+ years 52 operated horizontal wells completed and

online in Antero core areas− 100% drilling success rate

3 plants at Seneca Processing Complex capable of processing 600 MMcf/d of rich gas−Over 500 MMcf/d being processed currently,

including third party production Net production of 143 MMcfe/d in 3Q 2014

including 7,700 Bbl/d of liquids− Seneca 3 processing plant online in July

2014− Fourth third party compressor station in-

service December 2014 with a capacity of 120 MMcf/d

1,112 future gross drilling locations (743 or 67% are processable gas)

6.4 Tcfe of net 3P (13% liquids), includes 537 Bcfe of proved reserves (assuming ethane rejection)

LEADING UTICA SHALE CORE POSITION DELIVERS CONDENSATE AND NGLS

27

Utica Shale Industry Activity(1)

CadizProcessing

Plant

NORMAN UNIT30-Day Rate

2 wells average20.3 MMcfe/d (17% liquids)

RUBEL UNIT30-Day Rate

3 wells average21.1 MMcfe/d(24% liquids)

GULFPORT24-Hour IP

McCort1-28H, 2-28H, Stutzman 1-14H

Average 13.1 MMcf/d + 922 Bbl/d NGL

+ 21 Bbl/d Oil

GULFPORT24-Hour IP

Wagner 1-28H, Shugert 1-1H, 1-12H

Average 21.0 MMcf/d + 2,270 Bbl/d NGL

+ 292 Bbl/d Oil

Utica Core Area

GARY UNIT30-Day Rate


Highly-Rich/Cond26,000 Net Acres

143 Gross Locations

Highly-Rich Gas15,000 Net Acres

87 Gross Locations

Rich Gas33,000 Net Acres

265 Gross Locations

Dry Gas42,000 Net Acres

369 Gross Locations

NEUHART UNIT 3H30-Day Rate18.7 MMcfe/d(58% liquids)

Condensate32,000 Net Acres

248 Gross Locations

DOLLISON UNIT 1H30-Day Rate23.3 MMcfe/d(44% liquids)

MYRON UNIT 1H30-Day Rate30.4 MMcfe/d(49% liquids)

SenecaProcessingComplex

LAW UNIT30-Day Rate


SCHAFER UNIT30-Day Rate(2)


URBAN PAD30-Day Rate



1.4 1.6

$1.64

$1.24

$0.00

$0.30

$0.60

$0.90

$1.20

$1.50

$1.80

0.000.200.400.600.801.001.201.401.60

2013 2014

Dev

elop

men

t Cos

t ($/

Mcf

e)

EUR

/1,0

00' L

ater

al

EUR vs. Development Cost

EUR/1,000' Lateral (Bcfe) Development Cost ($/Mcfe) 28

UTICA WELL PERFORMANCE IMPROVEMENTS

32

29

26

27

28

29

30

31

32

33

2013 2014

Spud

-to-S

pud

Day

s

Average Spud-to-Spud Days

289

183

26

47

-

50

100

150

200

250

300

350

0

10

20

30

40

50

60

2013 2014

Ave

rage

Sta

ge S

paci

ng (F

T)

Ave

rage

Fra

cSt

ages

per

Wel

l

Increasing Frac Stages per Well

Average Stage Length Average Frac Stages/Well

Increasing recoveries and efficiencies, through longer laterals, shorter stage lengths and faster drilling Lower service costs are expected to drive development cost reductions in 2015

6,431

8,021

11

41

051015202530354045

0

2,000

4,000

6,000

8,000

10,000

2013 2014

Wel

ls o

n Fi

rst S

ales

Late

ral L

engt

h (F

eet)

Lateral Length Improvements

Lateral Length Wells on First Sales

1. Average vertical length of ~7,800’ drilled for 53 Utica wells. 2. Based on preliminary reserve and cost estimates for 41 Utica wells completed in 2014 subject to completion of year-end reserves and financial audit.

(1) (2)

0%

20%

40%

60%

80%

100%

120%

140%

160%

180%

200%

$3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00

Pre-

Tax

RO

R (%

)

Condensate Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas

UTICA ROR% AND GAS PRICE SENSITIVITY

29

NYMEX Flat Price Sensitivity(1)

87 LocationsROR% at Flat 2015-2020 Strip Price

Condensate: 13%

Highly-Rich Gas/Condensate: 41%

Highly-Rich Gas: 63%

Rich Gas: 47%

Dry Gas: 44%

Large portfolio of Condensate to Dry Gas locations Focused on drilling highly economic rich gas locations – rig symbols represent current rig location by Btu regime Assumes 12/31/2014 WTI strip pricing for 2015-2020, flat thereafter; NGL price 55% of WTI

1. Assumes 12/31/2014 strip pricing, market differentials and relevant transportation cost; 8,000’ lateral.

265 Locations

143 Locations

369 Locations

248 Locations

2015Drilling Plan

LARGE UTICA SHALE DRY GAS POSITION

30

Antero has 212,000 net acres of exposure to Utica dry gas play− 42,000 net acres in Ohio with net 3P reserves of 1.9 Tcf as of

6/30/2014− 170,000 net acres in West Virginia and Pennsylvania with net

resource of 9.5 Tcf as of 6/30/2014 (not included in 37.5 Tcfe of net 3P reserves)

− 1,390 locations underlying current Marcellus Shale leasehold in West Virginia and Pennsylvania as of 9/30/2014

Other operators have reported strong Utica Shale dry gas results including the following wells:

ChesapeakeHubbard BRK #3H

3,550’ LateralIP 11.1 MMcf/d

HessPorterfield 1H-17


GulfportIrons #1-4H


EclipseTippens #6H5,858’ Lateral

IP 23.2 MMcf/d

Magnum HunterStalder #3UH5,050’ Lateral

IP 32.5 MMcf/d

AnteroPlanned

Utica Well2015

Well OperatorIP(MMcf/d)

Lateral Length (Ft)

Claysville SC #1 Range 59.0 5,420

Stewart Winland 1300U Magnum Hunter 46.5 5,289

Bigfoot 9H Rice Energy 41.7 6,957

Stalder #3UH Magnum Hunter 32.5 5,050

Irons #1-4H Gulfport 30.3 5,714

Pribble 6HU Stone Energy 30.0 3,605

Simms U-5H Gastar 29.4 4,447

Conner 6H Chevron 25.0 6,451

Tippens #6H Eclipse 23.2 5,858

Porterfield 1H-17 Hess 17.2 5,000

Hubbard BRK #3H Chesapeake 11.1 3,550

1. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held in OH, WV and PA.

Magnum HunterStewart Winland 1300U


RangeClaysville SC #1


ChevronConner 6H


GastarSimms U-5H4,447’ Lateral

IP 29.4 MMcf/d

Utica Shale Dry Gas Acreage in OH/WV/PA(1)

RiceBigfoot 9H


Utica Shale Dry GasWV/PA

Net Resource9.5 Tcf

1,390 Gross Locations170,000 Net Acres

Utica Shale Dry GasOhio

3P Reserves1.9 Tcf

369 Gross Locations42,000 Net Acres

Utica Shale Dry GasTotal OH/WV/PA

Net Resource11.4 Tcf

1,759 Gross Locations212,000 Net Acres

Stone EnergyPribble 6HU


ChesapeakeUtica Well

Drilling

RiceBlue Thunder

10H, 12H≈9,000’ Lateral

FRESH WATER DISTRIBUTION SYSTEMS

31

Marcellus Fresh Water Distribution System• Provides fresh water to support Marcellus well completions • Year-round water supply sources: Ohio River and local rivers• Significant growth projected over the next twelve months as summarized

below:

Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.1. Represents inception to date actuals as of 6/30/2014 and 2014 guidance.2. Estimated fee of $3.50 per barrel at an average of 200,000 Bbls of water per well.

Utica Fresh Water Distribution System• Provides fresh water to support Utica well completions • Year-round water supply sources: local reservoirs and rivers• Significant growth projected over the next twelve months as summarized

below:

Marcellus Water System YE 2014

Buried Water Pipeline (Miles) 107

Fresh Water Storage Impoundments 26

Water Fees per Well ($)(2) $600K -$800K

Utica Water System YE 2014

Buried Water Pipeline (Miles) 48

Fresh Water Storage Impoundments 8

Water Fees per Well ($)(2) $600K -$800K

OHIO

Projected Midstream Infrastructure(1)

Marcellus Shale

Utica Shale Total

YE 2014E Cumulative Fresh Water System Capex ($MM) $300 $100 $400Water Pipelines (Miles) 107 48 155Water Storage Facilities 26 8 34

-

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

4,500,000

FIRM TRANSPORTATION AND FIRM SALES PORTFOLIO

32

MMBtu/d

Columbia7/26/2009 – 9/30/2025

Firm Sales #110/1/2011– 10/31/2019

Firm Sales #2

10/1/2011 – 5/31/2017Firm Sales #3

1/1/2013 – 5/31/2022

Momentum III9/1/2012 – 12/31/2023

EQT8/1/2012 – 6/30/2025

REX/MGT/ANR7/1/2014 – 12/31/2034

Tennessee11/1/2015– 9/30/2030

Mid-Atlantic/NYMEX

Gulf Coast

Appalachia or Gulf Coast

AppalachiaAppalachia

ANR3/1/2015– 2/28/2045

Midwest

Local Distribution11/1/2015 – 9/30/2037

Gulf Coast

$0.14 $0.17 $0.23$0.33$0.11 $0.11

$0.12

$0.13

$0.00

$0.10

$0.20

$0.30

$0.40

$0.50

$0.60

$0.70

2013A 2014E 2015E 2016E

($/M

MB

tu)

Wtd. Avg. FT Demand ($/MMBtu) Wtd. Avg. FT Commodity/Fuel ($/MMBtu)

All-in Firm Transportation Costs(1)

FIRM TRANSPORTATION REDUCES APPALACHIAN BASIS EXPOSURE

Appalachia 49%Gulf Coast

51%

2013 FirmTransportation(1)(2)

2013 Firm Transportation – 647 MMcf/dAverage All-in FT Cost $0.25/MMBtu

2016 Firm Transportation – 3.1 Bcf/dAverage All-in FT Cost $0.46/MMBtu

+ $0.18/MMBtu

Antero’s firm transportation (FT) portfolio increases visibility on production growth and increases exposure to Gulf Coast and Midwest pricing, with little incremental cost per Mcf

Reduces weighted average basis by $0.22 per MMBtu compared to 2014 basis (3) – while significantly reducing Appalachian basis exposure

Utilized portion included in cash production

expense(fixed cost)

1. Assumes full utilization of firm transportation capacity; page 14 assumes Antero targeted production figures.2. Represents accessible firm transportation and sales agreements.3. Based on current strip pricing as at 1/13/2015.

Included in cash production expense

(variable cost)$0.25 $0.28 $0.35

$0.46

2016 Basis(3)

TCO – $(0.42)/MMBtu DOM S – $(1.32)/MMBtu

2016 Basis(3)

Chicago – $(0.09)/MMBtu

2016 Basis(3)

CGTLA – $(0.10)/MMBtu

33

Appalachia35%

Midwest20%

Gulf Coast45%

0

500

1,000

1,500

2,000

2,500

3,000

3,500

Firm Transportation / Firm Sales (BBtu/d)Marketable FT (BBtu/d) (3)Risked Gross Gas Production Target (Bbtu/d)

ANTERO FIRM TRANSPORTATION APPROPRIATELY DESIGNED TO ACCOMMODATE GROWTH

341. Based on production of 1,265 MMcfe/d for 4Q 2014 and 45-50% production growth targets for 2015 and 2016. 2. Assumes 1100 BTU residue sales gas.3. Represents excess firm transportation that is deemed marketable to 3rd parties based on a positive differential between the receipt and delivery points of the FT capacity, less variable transport cost.

% FT Utilization (including

marketable FT):(BBtu/d)

4Q 2014 2015 2016Net Production Target (MMcfe/d) (1) 1,265 1,500 2,200 Net Gas Production Target (MMcf/d) 1,082 1,225 1,775

Net Revenue Interest Gross-up 81% 80% 80%Gross Gas Production Target (MMcf/d) 1,336 1,525 2,223

BTU Upgrade (2) x1.100 x1.100 x1.100 Gross Gas Production Target (BBtu/d) 1,469 1,678 2,446

Firm Transportation / Firm Sales (BBtu/d) 1,775 2,225 3,150 Estimated % Utilization of FT/FS 83% 75% 78%

Marketable Firm Transport (BBtu/d) (3) 225 325 325

Estimated % Utilization of FT/FS (Including Marketable FT) 95% 88% 87%Cost of Unutilized / Unmarketable FT ($MM) $1.8 $10.8 $21.1

$ / Mcfe of Net Production Target $0.02 $0.02 $0.03


marketable FT):


marketable FT):• Antero’s firm transport (FT) is well utilized during the forecast period (75% - 83%) − Excess FT for acquisitions

and well productivity improvements

• A portion of the excess FT is highly marketable, further increasing utilization to the 87% - 95% range

• Cost of remaining unutilized FT is immaterial ($0.02 -$0.03/Mcfe assuming net production target)

• Expect to fully utilize FT portfolio by 2018

95% 88% 87%

Keys to Execution

Local Presence

Antero has more than 4,000 employees and contract personnel working full-time for Antero in West Virginia. 79% of these personnel are West Virginia residents.

Land office in Ellenboro, WV District office in Bridgeport, WV 199 (45%) of Antero’s 446 employees are located in West Virginia and Ohio

Safety & Environmental

Five company safety representatives and 56 safety consultants cover all material field operations 24/7 including drilling, completion, construction and pipelining

41 person environmental staff plus outside consultants monitor all operations and perform baseline water well testing

Central Fresh Water System & Water Recycling

Numerous sources of water – built central water system to source fresh water for completions

Antero recycled over 80% of its flowback and produced water through the first 9 months of 2014 – no discharge to water treatment plants in West Virginia

Natural Gas Vehicles (NGV)

Antero supported the first natural gas fueling station in West Virginia Antero has 30 NGV trucks and plans to continue to convert its truck fleet to NGV

Pad Impact Mitigation Closed loop mud system – no mud pits Protective liners or mats on all well pads in addition to berms

Natural Gas Powered Drilling Rigs & Frac Equipment

11 of Antero’s contracted drilling rigs are currently running on natural gas First natural gas powered clean fleet frac crew began operations this summer

Green Completion Units All Antero well completions use green completion units for completion flowback,

essentially eliminating methane emissions (full compliance with EPA 2015requirements)

LEED Gold Headquarters Building

Recently moved into new corporate headquarters in Denver, Colorado that has been LEED Gold Certified

HEALTH, SAFETY, ENVIRONMENT & COMMUNITYAntero Core Values: Protect Our People, Communities And The Environment

Strong West Virginia Presence 79% of all Antero Marcellus

employees and contract workers are West Virginia residents

Antero named Business of the Year for 2013 in Harrison County, West Virginia “For outstanding corporate citizenship and community involvement”

Antero representatives recently participated in a ribbon cutting with the Governor of West Virginia for the grand opening of the first natural gas fueling station in the state; Antero supported the station with volume commitments for its NGV truck fleet

35

CLEAN FLEET & CNG TECHNOLOGY LEADER

● Antero has contracted for two clean completion fleets to enhance the economics of its completion operations and reduce the environmental impact

● Replaces diesel engines (for pressure pumping) with electric motors powered by natural gas-fired electric generators

● A clean fleet allows Antero to fuel part of its completion operations from field gas instead of more expensive diesel fuel. Benefits of using a clean fleet include:− Reduce fuel costs by up to 80%

representing cost savings of up to $40,000/day

− Reduces NOx and CO emissions by 99%− Eliminates 25 diesel trucks from the roads

for an average well completion− Reduces silica dust to levels 90% below

OSHA permissible exposure limits resulting in a safer and cleaner work environment

− Significantly reduces noise pollution from a well site

− Is the most environmentally responsible completion solution in the oil and gas industry

• Additionally, Antero utilizes compressed natural gas (CNG) to fuel its truck fleet in Appalachia− Antero supported the first natural gas fueling

station in West Virginia− Antero has 30 NGV trucks and plans to

continue to convert its truck fleet to NGV

36

37

Antero Midstream (NYSE: AM)Asset Overview

1. Represents inception to date actuals as of 6/30/2014 and 2H 2014 and next twelve months (NTM) guidance.2. Includes $14.7 million of maintenance capex. 38

• Gathering and compression assets in core of rapidly growing Marcellus and Utica Shale plays

– Acreage dedication of ~411,000 net leasehold acres for gathering and compression services

– 100% fixed fee long term contracts

UticaShale

MarcellusShale

Projected Midstream Infrastructure(1)

Marcellus Shale

Utica Shale Total

YE 2014E Cumulative Gathering/ Compression Capex ($MM) $850 $350 $1,200

Gathering Pipelines(Miles) 180 85 265

Compression Capacity(MMcf/d) 370 - 370

Condensate Gathering Pipelines (Miles) - 20 20

NTM (9/30/2015) Gathering/ Compression Capex ($MM)(2) $473 $129 $602

Gathering Pipelines (Miles) 219 108 327

Compression Capacity(MMcf/d) 835 - 835

Condensate Gathering Pipelines (Miles) - 27 27

Midstream Assets

SUBSTANTIAL INVESTMENT IN MIDSTREAM MLP(NYSE: AM)

ANTERO MIDSTREAM ASSETS – RICH GAS MARCELLUS

39

• Provides Marcellus gathering and compression services − Liquids-rich gas is delivered to MWE’s Sherwood

Complex for processing• Significant growth projected over the next twelve

months as set out below:

• Antero sold the Harrison County portion of its gathering system to a 3rd party midstream company in 2012, which is now recognized as the 3rd Party Gathering and Compression Dedication area

• Development upside as AR continues to drill, step-out and add acreage

Marcellus Gathering & Compression

Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.

YE 2014 9/30/2015

Gathering Pipelines (Miles) 180 219

Compression Capacity (MMcf/d) 370 835

WV/PA Utica Dry Gas Gathering & Compression

• Further development upside in 167,000 net acres of Utica deep rights beneath the Marcellus Shale− Will require a separate dry gas gathering system

40

• Provides Utica natural gas and condensate gathering services− Liquids-rich gas delivered into MWE’s Seneca

Complex for processing− Condensate delivered to centralized stabilization

and truck loading facilities• Significant growth projected over the next twelve

months as set out below:

• Development upside as AR continues to drill, step-out and add acreage

Utica Gathering

Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.

ANTERO MIDSTREAM ASSETS – RICH & DRY GAS UTICA

YE 2014 9/30/2015

Gathering Pipelines (Miles) 85 108

Condensate Pipelines (Miles) 20 27

Utica Compression• Opportunity to build up to ten new compressor stations

that are planned to support AR development over the next several years− Compressor stations are not included in AM NTM

forecast

41

APPENDIX

41

PRO FORMA CAPITALIZATION($ in millions) 9/30/2014

Pro Forma $1.15 Bn AM IPO(4)

9/30/2014Cash $6 $256

Senior Secured Revolving Credit Facility 1,505 6626.00% Senior Notes Due 2020 525 5255.375% Senior Notes Due 2021 1,000 1,0005.125% Senior Notes Due 2022 1,100 1,100Net Unamortized Premium 8 8Total Debt $4,138 $3,295Net Debt $4,132 $3,039Minority Interest - $326Shareholders' Equity $3,751 $4,372Net Book Capitalization $7,883 $7,737

Enterprise Value(1) $13,631 $12,788

Financial & Operating StatisticsLTM EBITDAX $1,047 $1,047LQA EBITDAX $1,109 $1,109LTM Interest Expense(2) $155 $138Proved Reserves (Bcfe) (6/30/2014) 9,107 9,107

Proved Developed Reserves (Bcfe) (6/30/2014) 2,772 2,772

Credit Statistics

Net Debt / LTM EBITDAX 3.9x 2.9x

Net Debt / LQA EBITDAX 3.7x 2.7xLTM EBITDAX / Interest Expense 6.8x 7.6xNet Debt / Net Book Capitalization 52.4% 39.3%Net Debt / Proved Developed Reserves ($/Mcfe) $1.49 $1.10Net Debt / Proved Reserves ($/Mcfe) $0.45 $0.33

LiquidityCredit Facility Commitments(3)(4) $3,000 $4,000Less: Borrowings (1,505) (662)Less: Letters of Credit (332) (332)Plus: Cash 6 256

Liquidity (Undrawn Credit Facility + Cash) $1,169 $3,2621. Equity valuation based on 262.0 million shares outstanding and a share price of $36.28 as of 1/13/2015. AR enterprise value excludes AM minority interest and cash.2. LTM interest expense adjusted for $1,578 million net proceeds from IPO priced on 10/14/2013 and $1,000 million 5.375% Senior Notes priced on 10/24/2013 net of fees; assumes $525 million 9.375%

Senior Notes, $25 million 9.00% Senior Notes, $140 million 7.25% Senior Notes repaid at 10/31/2013 with residual cash used to repay bank debt. Adjusted for $600 million 5.125% Senior Notes priced on 4/23/2014 net of fees; $260 million of 7.25% Senior Notes and $315 million of bank debt repaid. Adjusted for $500 million 5.125% Senior Notes add-on priced on 9/4/2014 at 100.5 net of fees; $496 million of bank debt repaid.

3. AR lender commitments under the facility increased to $3.0 billion from $2.5 billion on 10/16/2014; commitments can be expanded to the full $4.0 billion borrowing base upon bank approval. AM credit facility of $1 billion as of 11/4/2014.

4. Pro forma for $1,150 million IPO of 70% post-offering owned Antero Midstream; $843 million of debt repaid, $250 million of cash left at AM and $57 million of transaction expenses. AM $1 billion credit facility currently undrawn.

42

LOWEST FINDING & DEVELOPMENT COSTAMONG U.S. PRODUCERS

43

3-Year All-In F&D Cost – Excluding Revisions ($/Mcfe) through 2013

Source: Credit Suisse research dated 4/28/2014.

Antero ranks as the most efficient finder and developer of reserves, on a per Mcfe basis, based on a 2011-2013 average all-in F&D cost analysis prepared by Credit Suisse

$10.24$7.14

$6.68$5.74

$4.66$4.66

$4.54$4.23

$4.01$3.70

$3.63$3.28

$3.12$3.07$3.05$3.05

$2.91$2.91$2.88$2.87

$2.78$2.66

$2.57$2.40

$2.06$1.94

$1.74$1.60

$1.53$1.26

$1.04$0.84

$0.79$0.58

$0 $2 $4 $6 $8 $10 $12MHRAPC

GPORMURAPAMROWLL

FANGKOGCRKEXXIEOXPVACXODVN

KWKFST

DNRNBLEOG

CRZOPXD

BCEISD

CHKROSE

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AR

MARCELLUS SINGLE WELL ECONOMICS – IN ETHANE REJECTION

44

DRY GAS LOCATIONS RICH GAS LOCATIONS

HIGHLY RICH GAS

LOCATIONS

Assumptions Natural Gas – 12/31/2014 strip Oil – 12/31/2014 strip NGLs – 55% of Oil Price

NYMEX($/MMBtu)

WTI($/Bbl)

C3+ NGL(2)

($/Bbl)

2015 $3.08 $57 $31

2016 $3.48 $63 $35

2017 $3.77 $67 $37

2018 $3.95 $69 $38

2019+ $4.08 $71 $39

Marcellus SSL Well Economics and Total Gross Locations(1)

ClassificationHighly-Rich Gas/

CondensateHighly-Rich

Gas Rich Gas Dry Gas

Modeled BTU 1313 1250 1150 1050EUR (Bcfe): 17.7 16.2 14.7 13.6EUR (MMBoe): 2.9 2.7 2.4 2.3% Liquids: 31% 22% 10% 0%Lateral Length (ft): 8,000 8,000 8,000 8,000Stage Length (ft): 225 225 225 225Well Cost ($MM): $10.6 $10.6 $10.6 $10.6Bcfe/1,000’: 2.2 2.0 1.8 1.7

Pre-Tax NPV10 ($MM): $11.9 $7.4 $0.6 $0.4Pre-Tax ROR: 42% 28% 12% 11%Net F&D ($/Mcfe): $0.70 $0.77 $0.85 $0.92Payout (Years): 2.1 3.0 6.6 6.7

Gross 3P Locations(3): 727 896 633 875

1. Well economics are based on 12/31/2014 strip differential pricing and related transportation costs. Includes gathering, compression and processing fees. 2. Pricing for a 1225 BTU y-grade ethane rejection barrel.3. Undeveloped well locations as of 9/30/2014.

727896

633

875

42% 28%

12% 11%

0

200

400

600

800

1,000

0%

15%

30%

45%

60%

Highly-Rich Gas/Condensate

Highly-Rich Gas Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

R Locations ROR2015

Drilling Plan

248

143 87

265

369

10%

31%

46%

33%

30%

0

100

200

300

400

0%

15%

30%

45%

60%

Condensate Highly-Rich Gas/Condensate

Highly-Rich Gas Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

RLocations ROR

UTICA SINGLE WELL ECONOMICS – IN ETHANE REJECTION

45

DRY GAS LOCATIONS RICH GAS LOCATIONS

HIGHLY RICH GAS

LOCATIONS

Utica Well Economics and Gross Locations(1)

Classification CondensateHighly-Rich Gas/

CondensateHighly-Rich

Gas Rich Gas Dry Gas

Modeled BTU 1275 1235 1215 1175 1050EUR (Bcfe): 8.3 15.0 22.4 21.2 19.0EUR (MMBoe): 1.4 2.5 3.7 3.5 3.2% Liquids 35% 26% 21% 14% 0%Lateral Length (ft): 8,000 8,000 8,000 8,000 8,000Stage Length (ft): 240 240 240 240 240Well Cost ($MM): $12.1 $12.1 $12.1 $12.1 $12.1Bcfe/1,000’: 1.0 1.9 2.8 2.7 2.4

Pre-Tax NPV10 ($MM): $0.0 $7.6 $13.0 $9.1 $8.0Pre-Tax ROR: 10% 31% 46% 33% 30%Net F&D ($/Mcfe): $1.79 $0.99 $0.67 $0.71 $0.79Payout (Years): 5.5 1.5 1.1 1.5 2.6

Gross 3P Locations(3): 248 143 87 265 3691. Well economics are based on 12/31/2014 strip differential pricing and related transportation costs. Includes gathering, compression and processing fees.2. Pricing for a 1225 BTU y-grade ethane rejection barrel.3. Undeveloped well locations as of 9/30/2014, adjusted for subsequent 245 gross locations acquired as of 12/31/2014. 3P locations representative of BTU regime; EUR and economics within regime

will vary based on BTU content.

2015Drilling Plan

Assumptions Natural Gas – 12/31/2014 strip Oil – 12/31/2014 strip NGLs – 55% of Oil Price

NYMEX($/MMBtu)

WTI($/Bbl)

C3+ NGL(2)

($/Bbl)

2015 $3.08 $57 $31

2016 $3.48 $63 $35

2017 $3.77 $67 $37

2018 $3.95 $69 $38

2019+ $4.08 $71 $39

3-Year Average Growth – Adjusted Recycle Ratio through 2013

0.0x

2.0x

4.0x

6.0x4.8x

3.3x3.5x

2.4x

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$1.15 $1.18 $1.21 $1.60

Other Peers

LOW DEVELOPMENT COST DRIVES BEST IN CLASS RECYCLE RATIOS

46

Source: Proved developed F&D industry data based on company presentations, 10-Ks and press releases. Defined as total drilling and completion capital expenditures for the period divided by PDP and PDNP volumes added after adding back production for the period. Includes all drilling and completion costs but excludes land and acquisition costs for all companies. 1. Antero data pro forma for Arkoma and Piceance divestitures in 2012.

3-Year Proved Development Costs ($/Mcfe) through 2013

Antero Appalachia-Focused Peers

Source: Wall Street research. Defined as 2011-2013 average (Cash Operating Netback / PD F&D costs) x (1 + 2013-2015 consensus production CAGR). Antero’s production CAGR based on guidance targets. PD F&D Costs defined as total drilling and completion capital expenditures for the period divided by PDP and PDNP volumes added after adding back production for the period Includes all drilling and completion costs but excludes land and acquisition costs for all companies.1. Antero data pro forma for Arkoma and Piceance divestitures in 2012.

Antero Appalachia-Focused Peers

$/Mcfe

Other Peers

CONSIDERABLE RESERVE BASE WITH ETHANE OPTIONALITY 30 year proved reserve life based on 1H 2014 production annualized Reserve base provides significant exposure to liquids-rich projects

– 3P reserves of over 2.3 BBbl of NGLs and condensate in ethane recovery mode; 33% liquids

1. Ethane rejection occurs when ethane is left in the wellhead gas stream as the 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 gas at the outlet of the processing plant is higher. Producers will elect to “reject” ethane when the price received for the higher BTU residue gas is greater than the price received for the ethane being sold as a liquid after fractionation. When ethane is recovered, the BTU content of the residue gas is lower, but a producer is then able to recover the value of the ethane sold as a separate NGL product.

ETHANE REJECTION(1) ETHANE RECOVERY(1)

47

Marcellus – 26.4 Tcfe

Utica – 6.4 Tcfe

Upper Devonian – 4.6 Tcfe

37.5Tcfe

Gas – 31.7 Tcf

Oil – 86 MMBbls

NGLs – 880 MMBbls

Marcellus – 31.3 Tcfe

Utica – 7.3 Tcfe

Upper Devonian – 5.1 Tcfe

43.7Tcfe

Gas – 29.3 Tcf

Oil – 86 MMBbls

NGLs – 2,305 MMBbls

15%Liquids

33%Liquids

Moody's S&P

POSITIVE RATINGS MOMENTUMMoody’s / S&P Historical Corporate Credit Ratings

“We could raise the ratings due to our assessment of an improvement inthe company's financial profile. An improvement in the financial profilewould include maintaining FFO to debt of greater than 45% andnarrowing the amount that the company outspends its cash flows by.”

- S&P Credit Research, September 2014

“An upgrade could be considered if debt / average daily production issustained below $20,000 per boe and debt / proved-developedreserves is sustained below $8.00 per boe. An upgrade would also becontingent on Antero maintaining unleveraged cash margins greaterthan $25.00 per boe and retained cash flow to debt over 40%.”

- Moody’s Credit Research, September 2014

Credit Rating (Moody’s / S&P)

Ba3 / BB-

B1 / B+

B2 / B

B3 / B-

9/1/2010 2/24/2011 10/21/2013 9/4/20145/31/13

Ba2 / BB

Ba1 / BB+

Caa1 / CCC+

(1)

___________________________1. Represents corporate credit rating of Antero Resources Corporation / Antero Resources LLC.

Baa3 / BBB-

Moody’s Upgrade Criteria S&P Upgrade Criteria

48

9/30/2014

($ in millions) As At Interest Current Maturity Maturity09/30/14 Rate Yield (2) (Years) (Date)

Senior Secured Revolving Credit Facility $662 2.440% (3) 2.440% (3) 4.6 May-196.0% Senior Notes due 2020 525 6.000% 6.204% 6.2 Dec-205.375% Senior Notes due 2021 1,000 5.375% 6.102% 7.1 Nov-215.125% Senior Notes due 2022 1,100 5.125% 6.201% 8.2 Dec-22

Total Long-Term Debt $3,287

Weighted Average: 4.800% 5.414% 6.8 Jul-21

PRO FORMA OFFERING – BALANCE SHEET POSITIONEDFOR LONG-TERM GROWTH

PRO FORMA DEBT MATURITY PROFILE (1)

PRO FORMA WEIGHTED AVERAGE INTEREST RATE AND MATURITY(1)

491. As of 9/30/2014 per 10-Q; pro forma for $1,150 million AM IPO priced on 11/4/2014; net proceeds of $843 million used to repay the credit facility.2. Current yields of senior notes tranches represent the current yield-to-worst per Bloomberg. 3. Represents weighted average interest rate under the revolving credit facility as of 9/30/2014.

Senior Secured Revolving Credit Facility Senior Notes

The recent bond offerings, at progressively lower coupons, have allowed Antero to reduce its cost of debt to approximately 5.0% and enhance liquidity while extending the pro forma average debt maturity to July 2021

Current cost of debt 4.8%, average debt maturity 6.8 years

$662 $525

$1,000 $1,100

$0

$200

$400

$600

$800

$1,000

$1,200

2014 2015 2016 2017 2018 2019 2020 2021 2022

($ in

Mill

ions

)

Needed to make up for base declines in conventional and GOM production

? ??

3,000 Antero Drilling Locations

Perm

ian

Nio

brar

a

Gra

nite

Was

h

Bar

nett

Hay

nesv

ille

U.S. INCREMENTAL GAS SUPPLY BREAK-EVEN PRICE CURVE(1)

50

Low cost, liquids-rich Utica and Marcellus Shales will remain attractive in most commodity price environments

Utica Shale

SW (Rich) Marcellus

Shale

1. Source: Credit Suisse report dated January 2014 – Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI

NE (Dry) Marcellus

ShaleEagle Ford

Shale

MARCELLUS & UTICA – ADVANTAGED ECONOMICS

LNG EXPORTS BY PROJECT – CURRENT STATUS

51

LNG Exports by Project – Current Status

Sherwood 7

Dates of Key Milestones Send Out Non-DOE Non-FTA FERC FTA Permit Underlying

Permit Construction Capacity Gas DemandProject Awarded Approval (Bcf/d) (Bcf/d) Contracts OfftakersSabine Pass 1-4 05/20/11 04/16/12 2.20 2.42 Fully Subscribed BG, GasNatural Fenosa,

Kogas, GAIL

Cove Point 09/11/13 09/29/14 0.77 0.85 Fully Subscribed Sumitomo, GAIL, Tokyo Gas

Cameron 02/11/14 06/19/14 1.70 1.87 Fully Subscribed Sempra, Misui, Mitsubishi, GDF Suez

Freeport 05/17/13 07/30/14 1.40 1.54 Fully Subscribed Osaka Gas, Chubu Electric, BP, Toshiba, SK E&S

Lake Charles 08/07/13 Expected 2015 2.00 2.20 Fully Subscribed BG

Subtotal 8.07 8.88

Freeport Phase II 11/15/13 Pending 0.40 0.44 Not Subscribed N/A

Total 8.47 9.32

Source: Simmons & Company International, “2015 US Natural Gas Outlook and Updated Long Term Demand Forecast,” September 2014. Data updated for recent announcements subsequent to Simmons report.

CAUTIONARY NOTE

The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserve estimates (collectively, “3P”). Antero has provided internally generated estimates for proved, probable and possible reserves in this presentation in accordance with SEC guidelines and definitions. The estimates of proved, probable and possible reserves as of June 30, 2014 included in this presentation have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates as of June 30, 2014 assume ethane rejection and strip pricing.

Actual quantities that may be ultimately recovered from Antero’s interests may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery include the scope of Antero’s ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates.

In this presentation:

“3P reserves” refer to Antero’s estimated aggregate proved, probable and possible reserves as of June 30, 2014. 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.

“Condensate” refers to gas having a heat content between 1250 BTU and 1300 BTU in the Utica Shale.

“Highly-Rich Gas/Condensate” refers to gas having a heat content between 1275 BTU and 1350 BTU in the Marcellus Shale and 1225 BTU and 1250 BTU in the Utica Shale.

“Highly-Rich Gas” refers to gas having a heat content between 1200 BTU and 1275 BTU in the Marcellus Shale and 1200 BTU and 1225 BTU in the Utica Shale.

“Rich Gas” refers to gas having a heat content of between 1100 BTU and 1200 BTU.

“Dry Gas” refers to gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.

Regarding Hydrocarbon Quantities

52

company website presentation january 2015

Investor Relations

statements of historical

operating risks

company overviewjanuary

environmental risks

future events

companys reserves

heading risk factors

companys drilling program