Company OverviewMarch 2014

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 the Registration Statement 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

ANTERO: A “PURE PLAY” ON THE MARCELLUS / UTICA● Marcellus is the largest gas field in the U.S., 2nd largest in the world –

Industry production approximately 14 Bcf/d today● Antero has 35 Tcfe of fully engineered and audited 3P reserves in

Marcellus and Utica Shales● 678 MMcfe/d of average net production in 4Q 2013 including approximately

11,100 Bbl/d of liquids

Critical Mass In Two World Class Shale Plays

● 159% Appalachian production CAGR for 2010 to 2013● Most active driller in Appalachia – 20 rigs running− Most active driller in Marcellus Shale – 15 rigs running− 3rd most active driller in the Utica Shale – 5 rigs running

Market Leading Growth

● Low development cost leader: $1.03/Mcfe(1)

● Industry leading growth-adjusted recycle ratio: 6.1x(1)

● Top quartile return on productive capital: 27% for 2013E

Industry Leading Capital Efficiency and Recycle Ratio

● 1.6 Bcf/d of processing capacity and 1.7 Bcf/d of gas takeaway● Liquids expected to grow from 10% of fourth quarter 2013 production to

~ 16% in 2014 due to focus on liquids-rich development

Significant Emphasis on Takeaway and

Liquids Processing

● ~$1.2 billion pro forma available liquidity with current $1.5 billion bank commitment(2)

● 1.3 Tcfe hedged through 2019 at an average index price of $4.62/MMBtuand $96.54/Bbl

Liquidity and Hedge Position Support High

Growth Story

● Over 30 years as a team (over 20 years in unconventional)● “Shale Pioneers” – early mover and driller of over 500 horizontal shale

wells in the Barnett, Woodford, Marcellus and Utica Shales

Outstanding Management Team

21. Three year average through 2012; pro forma for Arkoma and Piceance divestitures.2. See page 23 for the derivation of 12/31/2013 liquidity.

UPPER DEVONIAN SHALE

Net Proved Reserves(1) 44 BcfeNet 3P Reserves (1) 4.2 TcfePre-Tax 3P PV-10(1) NM% Liquids – Net 3P 7%4Q 2013 Net Production 3 MMcfe/dUndrilled 3P Locations 951

C

PREMIER UNCONVENTIONAL RESOURCE PLATFORM

1. Proved, probable, and possible reserves as of December 31, 2013, assuming ethane rejection using SEC methodology and SEC pricing. Evaluations prepared by our internal reserve engineers and audited by DeGolyer & MacNaughton (D&M). Pre-Tax 3P PV-10 is a non-GAAP financial measure.

2. Represents the average net daily production for the period October 1, 2013 through December 31, 2013. 3. All net acres allocated to the Dry Gas Utica 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

leases.

TOTAL – 12/31/13 RESERVES(1)

Assumes Ethane RejectionNet Proved Reserves(1) 7.6 TcfeNet 3P Reserves(1) 35.0 TcfePre-Tax 3P PV-10(1) $20,362 MM

Net 3P Liquids 902 MMBbls% Liquids – Net 3P 15%4Q 2013 Net Production(2) 678 MMcfe/d- 4Q 2013 Net Liquids(2) 11,190 Bbl/dNet Acres(3) 456,000Undrilled 3P Locations 4,778

MARCELLUS SHALE

Net Proved Reserves(1) 7.2 TcfeNet 3P Reserves (1) 25.0 TcfePre-Tax 3P PV-10(1) $15,729 MM% Liquids – Net 3P 17%4Q 2013 Net Production 621 MMcfe/dUndrilled 3P Locations 3,068

• 100% operated

• Stable acreage base− Marcellus Shale: 51% HBP, with additional 21%

not expiring for 5+ years− Utica Shale: 20% HBP, with additional 79% not

expiring for 5+ years

• Portfolio flexibility across dry gas to liquids-rich and condensate windows

• Significant investment in midstream infrastructure and secured takeaway capacity

• Financial flexibility to pursue planned 2014 and 2015 development drilling activities

• Full scale development underway− 20 rigs currently operating

A

UTICA SHALE – LIQUIDS RICH

Net Proved Reserves(1) 362 BcfeNet 3P Reserves (1) 5.8 TcfePre-Tax 3P PV-10(1) $4,666 MM % Liquids – Net 3P 15%4Q 2013 Net Production 54 MMcfe/dUndrilled 3P Locations 759

B

3

AC

B Additional Hedge Value

“Pure-Play” Appalachian-Focused Shale Company

UTICA SHALE – DRY GAS

Net Acres(3) 128,000Net Resource 5.0 TcfeUndrilled Locations 950

D

D • 1.3 Tcfe hedged from 1/1/2014 through 12/31/2019 at an average index price of $4.62/MMBtu and $96.54/Bbl

• ~ $760 million mark-to-market hedge value as of 2/24/2014

• ~ 50% hedged through NYMEX; 50% hedged through regional hubs

0

200

400

600

800

1,000

2010 2011 2012 2013 2014E

Marcellus Utica

30124

239

522

950

(4)

4

0

200

400

600

800

1,000

2006 2007 2008 2009 2010 2011 2012 2013 2014E

Woodford Piceance Marcellus Utica

6 31 87 105 133244

334

522

(4)

950

AVERAGE NET DAILY PRODUCTION (MMcfe/d) APPALACHIAN PRODUCTION (MMcfe/d)

01,0002,0003,0004,0005,0006,0007,0008,0009,000

2006 2007 2008 2009 2010 2011 2012 2013

Woodford Piceance Marcellus Utica(3)

87 235680 1,141

3,231

5,0174,283

7,632Sold Woodford and Piceance

(5) (5)

NET PROVED SEC RESERVES (Bcfe)(2)

193

0

25

50

75

100

125

150

175

200

2006 2007 2008 2009 2010 2011 2012 2013 2014E

Woodford Piceance Marcellus Utica

8596

126

18

66

91

119

162

(4)

1. CAGR = Compound Annual Growth Rate.2. Proved reserves for 2006, 2007, and 2008 represent previously effective SEC methodology. 2009, 2010, 2011, 2012 and 2013 proved reserves based on current SEC reserve methodology and SEC pricing and

are audited by independent third-party engineers. 3. Includes Upper Devonian Shale proved reserves (10 Bcfe in 2012 and 44 Bcfe in 2013). 4. Per Company press release dated January 29, 2014; production mid-point of 925-975 MMcfe/d guidance.5. 2012 and 2013 proved reserves are both in ethane rejection mode.

FinancialCrisis

STRONG TRACK RECORD OF GROWTH

OPERATED GROSS WELLS SPUD

Sold Woodford and Piceance

OUTSTANDING RESERVE GROWTH

1. 2012 and 2013 reserves assume ethane rejection.5

PROVED RESERVE GROWTH(1)

3P RESERVE GROWTH(1)

• Proved PV-10 increased 133% to $7.0 billion (including hedges)

• 3P PV-10 increased 82% to $21.4 billion (including hedges)

• Replaced 1,857% of 2013 production

• All-in finding cost of $0.58/Mcfe

• 2013 “top-down” development cost of $1.25/Mcfe

• 2013 “bottoms-up” development cost of $1.10/Mcfe

• Only 14% of 1P and 58% of 3P locations booked as SSL (1.73 Bcf/1,000’ type curve)

• No Utica Shale WV/PA dry gas reserves booked

4.1

7.20.1

0.4

0

2

4

6

8

10

2012 2013

(Tcfe)

Marcellus Utica

7.6

17.625.0

4.0

5.84.2

0

10

20

30

40

50

2012 2013

(Tcfe)

Marcellus Utica Upper Devonian

Drivers

FUTURE RESERVE GROWTH DRIVERS

2013 RESERVE UPDATE

• Marcellus SSL completions

• Full scale Utica program

• Utica increased density drilling

• Utica dry gas drilling

• Core acreage acquisitions

Driver 2014 Action

Complete transition to SSL type curve

4.2

21.6

35.0

• Successful drilling

• Expanded proved footprint (HDA)

• 80,000 net acres added in 2013

• SSL results

• Utica results

41 wells to be completed; only 21 PUD locations booked as proved at YE 2013

$200 million leasehold budget

Drilling 2 increased density pilots in Utica

Drilling first Utica dry gas well in WV (126,000 net acres WV/PA)

Drivers

$0.00 $0.00 $0.00 $0.00$0.89 $1.15

$2.47 $2.50 $2.60$2.94 $3.20 $3.27 $3.51 $3.65 $3.66 $3.70

$3.75 $3.80 $3.81 $4.13 $4.25 $4.66$5.05

$5.37 $5.49

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

637 834707

890

117%

65%

32% 21% 0

200

400

600

800

1000

0%

50%

100%

150%

Highly-RichGas/

Condensate

Highly-RichGas

Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

R

Locations ROR

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

Large Inventory of Low Breakeven Projects(3)

1. Well economics based on 12/31/2013 3P SSL reserves and strip pricing as of 12/31/2013. 2. A portion of these locations do not assume SSL completions.3. Source: Credit Suisse report dated January 2014 – Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI.4. 3-year NYMEX STRIP as of 2/24/2014.

3 Yr Strip - $4.38/MMBtu(4)

637 Locations

1,541Locations366

Locations

890Locations

$ / M

MB

tu N

YMEX

(Gas

)

182Locations

6

MARCELLUS SSL WELL ECONOMICS(1)(2) UTICA WELL ECONOMICS(1)

205 161182

211

137%169%

95%56%

0

50

100

150

200

250

0%

50%

100%

150%

200%

Highly-RichGas/

Condensate

Highly-RichGas

Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

R

Locations ROR

1,000

71% of Marcellus locations are processable (1100-plus Btu) 72% of Utica locations are processable (1100-plus Btu)

`

2,726 Antero Liquids-Rich Locations

0.0x

2.0x

4.0x

6.0x

8.0x6.1x

3.5x 3.1x 2.7x

$0.00

$1.00

$2.00

$3.00

$4.00

$1.03 $1.14 $1.41 $1.57 $1.71

LOW DEVELOPMENT COST DRIVES BEST-IN-CLASS RECYCLE RATIOS

7

Source: Proved developed F&D research prepared by JP Morgan Research report dated 07/22/2013. 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 internal estimate using JP Morgan development cost methodology; excludes Arkoma and Piceance operations.2. Antero estimate based on public information; includes Arkoma and Piceance operations.

3-Year All-in Development Costs ($/Mcfe) through 2012

Antero Appalachia-Focused Peers

Source: Wall Street research. Defined as 2010-2012 average (Cash Operating Netback / PD F&D costs) x (1 + 2012-2014 production CAGR). 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 per JP Morgan analysis. Includes all drilling and completion costs but excludes land and acquisition costs for all companies.1. Antero data pro forma for Woodford and Piceance divestitures; Antero production growth based on first half of 2013 only.

Antero Appalachia-Focused Peers

3-Year Average Growth – Adjusted Recycle Ratio through 2012

$/Mcfe

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

? ?

?Downside risks to breakeven costs for older shale plays once exploration resumes with higher natural gas prices?

?

Over 2,700 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)

8

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

INTEGRATED MIDSTREAM PROCESSING AND TAKEAWAY

Infrastructure and commitments in place to handle strong natural gas, NGL and oil production growth

– Portfolio of firm transportation and sales and West Virginia location minimizes basis risk

Producers located in northern West Virginia have seen much less basis widening and volatility than Pennsylvania producersAntero sold ~67% of its 2013 production at TCO index at

NYMEX less $0.06/MMbtu prior to the Btu upgrade

91. 80,000 MMBtu/d and 70,000 MMbtu/d also utilize firm transportation in 2014 and 2015, respectively.2. Basis data from Wells Fargo daily indications and various private quotes as of 2/24/2014.

0

200

400

600

800

1,000

1,200

1,400

1,600

(MM

cf/d

)

Sherwood I Sherwood II Sherwood III Sherwood IV Sherwood V

Seneca I Seneca II Seneca III Seneca IV

Total Capacity 1,550

MarcellusUtica

Sherwood I

Sherwood II

Sherwood III

Seneca I

Seneca II

Seneca III

TCOBasis to NYMEXCurrent 2015+$0.13 -$0.43

Dom SouthBasis to NYMEXCurrent 2015-$0.17 -$0.93

LeidyBasis to NYMEXCurrent 2015-$2.78 -$2.17

Antero Transport and Processing 2014 2015Firm Transport (FT) (MMBtu/d) 1,369,000 1,407,000Firm Sales (MMBtu/d)(1) 330,000 320,000

Firm Processing Capacity (Mcf/d) 1,400,000 1,550,000Ethane FT (Bbl/d) 20,000 20,000

Growing Processing Capacity

2014 2015 2016 2017 2018 2019

-$2.60-$2.20-$1.80-$1.40-$1.00-$0.60-$0.20

Appalachian Basis to NYMEX(2)

TETCO M2

Leidy

TCODom South

2013 % of Production Sold

TCO 67%Dom South 22%TETCO 5%NYMEX 6%

CGTLABasis to NYMEXCurrent 2015-$0.02 -$0.09

ChicagoBasis to NYMEXCurrent 2015+$3.23 -$0.07

Sherwood V

Sherwood IV

Seneca IV

0

400,000

800,000

1,200,000

1,600,000

2,000,000

RRC EQT CNX COG CHK TLM STO SWN WPX RDS APC NFG

Mcf

/d

Firm Sales Firm Transportation

(2)AR

LONG HAUL PIPELINE AND TRANSPORTATION NETWORK

10

Antero has a leading firm transportation capacity position and is well-positioned in the southern portion of the Marcellus and Utica Shale from a gas takeaway perspective

Note: Antero firm transportation and firm sales positions listed by pipeline in colored-coded boxes. 1. Firm transport as of year-end 2014. See Page 27 for timing of firm transportation graph.2. Antero firm transportation as of 2/24/2014; includes 250 MMcf/d of firm sales.

(1)

TCOBasis to NYMEXCurrent 2015+$0.13 -$0.43

Dom SouthBasis to NYMEXCurrent 2015-$0.17 -$0.93

LeidyBasis to NYMEXCurrent 2015-$2.78 -$2.17

CGTLABasis to NYMEXCurrent 2015-$0.02 -$0.09

ChicagoBasis to NYMEXCurrent 2015+$3.23 -$0.07

Appalachian Firm Transportation/Sales Commitment by Operator

Source: Tudor Pickering & Holt research report dated 9/3/2013 and company presentations, press releases.

729 550 643 740 630 358

$4.92 $4.91 $4.71$4.34 $4.65 $4.46

$4.85$4.20 $4.09 $4.10 $4.14 $4.22

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

0

200

400

600

800

2014 2015 2016 2017 2018 2019

BBtu/d

12%

18%

18%

50%

2%NYMEX

CGTLA

Dom South

TCOChicago

SIGNIFICANT LONG-TERM COMMODITY HEDGE POSITION

11

% HEDGE VOLUMES BY INDEX – 2/24/2014

Average Index Price ($/MMBtu)(1)Hedged Volume NYMEX Strip (2/24/2014) ($/MMBtu)

NATURAL GAS HEDGES – 2/24/2014

1. Reflects weighted average index price per annum based on volumes hedged and 6:1 gas to oil ratio. Antero has hedged ~3,000 Bbl/d for 2014, WTI hedges comprise ~1% of overall hedge book.

~$760 million mark-to-market unrealized gain as of February 24, 2014 1.3 Tcfe hedged from January 1, 2014 through year-end 2019

ASSET OVERVIEW

12

WORLD-CLASS POSITION IN THE CORE OF THE MARCELLUS AND UTICA LIQUIDS-RICH FAIRWAYS

Source: Company presentations and press releases.

Utica Shale Core Area

Marcellus Shale

Southwestern & Northeastern

Core Areas

Upper Devonian Shale Resource

Overlies Marcellus Acreage

13

ANTERO LIQUIDS-RICH UTICA SHALE

106,000 Net Acres18 Horizontals Completed5 Rigs Currently Running

ANTERO MARCELLUS SHALE SW PA

25,000 Net Acres2 Horizontals Completed

Strong Results

ANTERO MARCELLUS SHALE NW WV

325,000 Net Acres(Primarily Liquids-Rich Fairway)

234 Horizontals Completed15 Rigs Currently Running

Utica ShaleLiquids-Rich

Fairway

Utica Shale Dry Gas

Resource Underlies Marcellus Acreage

Marcellus Shale Liquids-Rich

Fairway

WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECTAntero Has Delineated And De-Risked Its Large Scale Acreage Position

100% operated 350,000 net acres in

Southwestern Core– 51% HBP with additional

21% not expiring for 5+ years 236 horizontal wells completed

and online– Laterals average 7,000’– 100% drilling success rate

Net production of 621 MMcfe/d in 4Q 2013, including 8,900 Bbl/d of liquids

3,068 future drilling locations in the Marcellus (71% are processable)

Operating 15 drilling rigs including 4 shallow rigs

25.0 Tcfe of net 3P (17% liquids), includes 7.2 Tcfe of proved reserves (assuming ethane rejection)

14

Highly-Rich Gas100,000 Net Acres

834 Gross Locations

Rich Gas86,000 Net Acres

707 Gross Locations

Dry Gas104,000 Net Acres

890 Gross Locations

Highly-Rich/Condensate60,000 Net Acres

637 Gross Locations

MOORE UNIT30-Day Rate

1H: 9.9 MMcfe/d 2H: 10.0 MMcfe/d

(17% liquids)

MHR WEESE UNIT30-Day Rate

4-well average9.3 MMcfe/d (31% liquids)

CHK HADLEY UNIT24-Hour IP

9.1 MMcfe/d(32% liquids)

EQT PENN 15 UNIT30-Day Rate

5-well average9.3 MMcfe/d (29% liquids)

CONSTABLE UNIT30-Day Rate

1H: 15.2 MMcfe/d (30% liquids)

142 Horizontals Completed30-Day Rate

10.3 Bcf average EUR8.1 MMcf/d

6,915’ average lateral length

PRUNTY UNIT30-Day Rate

1H: 11.0 MMcfe/d(29% liquids)

HINTERER UNIT30-Day Rate

1H: 12.9 MMcfe/d (20% liquids)

RUTH UNIT30-Day Rate

1H: 19.3 MMcfe/d (14% liquids)

SherwoodProcessing

Plant

EQT30-Day Rate

12 Recent Wells9.2 MMcfe/d (20% Liquids)

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

BLANCHE UNIT30-Day Rate

2H: 10.0 MMcfe/d(29% liquids)

DOTSON UNIT30-Day Rate

1H: 12.4 MMcfe/d2H: 11.8 MMcfe/d

(27% liquids)

MARCELLUS – SIMPLE STRUCTURE

15

Several regional anticlines in core area− Predictable “layer cake” geology− No faults at Marcellus level

• Over 1.7 million feet (315 miles) drilled horizontally without crossing a fault

− 3-D seismic not required to guide horizontal wells

Regional East-West seismic line shows gentle structure at Marcellus level

Allegheny Front and complex structure located many miles east of core area

Favorable geology allows for longer laterals

Average Marcellus Lateral Lengths

7,300

4,800 4,500 4,100

0

2,000

4,000

6,000

8,000

Antero EQT RRC COG

Feet

Source: Company presentations.

Wolf SummitArches ForkBig Moses

MarcellusOnondaga

BensonRhinestreet

Profile along regional seismic line (time)W E

Regional Seismic Line

No Data

Tully

100’ Contours Top Marcellus

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

Antero Non-SSL Type Curve Actual Non-SSL ProductionNon-SSL Type Curve Cumulative Production 1.7 Bcf/1,000' SSL Type CurveSSL Actual Production

0

5

10

15

20

25

30

MM

cf/d

1st Production from All Wells 2009 - 2013

Antero has over four years of production history to support its 1.5 Bcf/1,000’ type curve (non-SSL) Antero’s SSL type curve has been increased to 1.73 Bcf/1,000’ with only 12% higher well costs Lack of faulting and contiguous acreage position allows for drilling of long laterals ~ 7,300’− Drives down costs per 1,000’ of lateral resulting in best-in-class development costs

ANTERO’S MARCELLUS SHALE TYPE CURVE SUPPORT

1. 236 Antero Marcellus wells normalized to time zero, production for each well normalized to 7,000’ lateral length.2. 32 Antero Marcellus SSL wells normalized to time zero, production for each well normalized to 7,000’ lateral length.

Marcellus Type Curve – Normalized to 7,000’ Lateral(1)

16

24-Hour Peak Rate

30-Day Avg. Rate

90-Day Avg. Rate

180-Day Avg. Rate

One-Year Avg. Rate

Two-Year Avg. Rate

Three-YearAvg. Rate

Wellhead (MMcf/d) 14.3 8.1 6.3 5.3 4.2 3.1 2.3# of wells 236 224 221 193 131 65 26

EURs Increase With Lateral Length Well Cost / 1,000’ Decreases with Lateral Length Wellhead 24-hour Peak Rates (IPs) - 236 Wells

Average IP – 14.3 MMcf/d

(2)

0

4

8

12

16

20

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

EUR

, BC

F

Lateral Length, ft

$0.6

$0.8

$1.0

$1.2

$1.4

$1.6

$1.8

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

$MM

/ 1,

000'

Lateral length, ft

MARCELLUS SINGLE WELL ECONOMICS – ASSUMES ETHANE REJECTION

17

DRY GAS LOCATIONS RICH GAS LOCATIONS

HIGHLY RICH GAS

LOCATIONS

Assumptions 12/31/2013 Strip Pricing & SEC Reserves

NYMEX($/MMBtu)

WTI($/Bbl)

C3+ NGL(2)

($/Bbl)

2014 $4.24 $95 $54

2015 $4.16 $88 $50

2016 $4.09 $83 $50

2017 $4.09 $80 $50

2018+ $4.14 $79 $50

Marcellus SSL Well Economics and Total Locations(1)

ClassificationHighly-Rich/Condensate

Highly-Rich Gas Rich Gas Dry Gas

BTU Range 1275-1350 1200-1275 1100-1200 <1100Modeled BTU 1313 1250 1150 1050EUR (Bcfe): 16.5 14.9 13.3 12.1EUR (MMBoe): 2.8 2.5 2.2 2.0% Liquids: 34% 24% 12% 0%Lateral Length (ft): 7,000 7,000 7,000 7,000Stage Length (ft): 225 225 225 225Well Cost ($MM): $9.5 $9.5 $9.5 $9.5Bcf/1,000’: 1.7 1.7 1.7 1.7Bcfe/1,000’: 2.4 2.1 1.9 1.7

Pre-Tax NPV10 ($MM): $20.5 $13.7 $6.6 $3.7Pre-Tax ROR: 117% 65% 32% 21%Net F&D ($/Mcfe): $0.68 $0.75 $0.84 $0.92Payout (Years): 0.9 1.3 2.4 3.6

Gross 3P Locations: 637 834 707 8901. Well economics are based on 12/31/2013 proved SSL reserves (P90) and strip pricing. Includes gathering, compression and processing fees. A portion of the locations do not include SSL

completions.2. Pricing for a 1225 BTU y-grade rejection barrel.

637 834707

890

117%

65%

32% 21% 0

200

400

600

800

1,000

0%

50%

100%

150%

Highly-Rich Gas/Condensate

Highly-Rich Gas Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

R Locations ROR

1,000

10,000

0 30 60 90 120 150 180

Gas

Pro

duct

ion

(Mcf

e/d)

Days From Peak GasAntero Type Curve SSL Average Wellhead SSL Average Processed

Enhancing Recoveries Shorter stage length (SSL) summary:

– 32 SSL wells completed– 22 SSL wells have at least 30 days

of production history– 150’ to 225’ (SSL) vs. 350’ stages

previously 31% higher 30-day wellhead rate for

first 22 SSL wells vs. the Antero type curve – 27% higher 120-day rate vs. the

Antero type curve– Other Marcellus operators have

indicated 20% to 30% improvement in IPs and EURs

The 30-day processed rate for Antero’s first 22 SSL wells has averaged 42% higher than the Antero type curve

Estimated 12% increase in well costs for SSL completions as compared to non-SSL

18

SHORTER STAGE LENGTHS (“SSL”)– ENHANCING MARCELLUS RECOVERIES

1.5 Bcf/1,000’ Type Curve

Normalized production increase for 22 SSL wells vs. 1.5 Bcf/1,000' Type Curve

SSL vs Non-SSL Wellhead Average Rate Comparison

30-day Rate

60-day Rate

90-day Rate

120-day Rate

SSL Well Count 22 19 19 10SSL Avg Wellhead Rate – MMcf/d(1) 10.0 8.6 8.1 7.9Wellhead Type Curve – MMcf/d(2) 7.6 7.1 6.6 6.2SSL % Rate Improvement 31% 21% 24% 27%

SSL Avg Processed Rate – MMcfe/d(1) 11.5 9.9 9.3 9.1Processed Type Curve – MMcfe/d(3) 8.1 7.5 7.0 6.6SSL % Rate Improvement 42% 32% 34% 38%(1) Wellhead condensate production is converted on a 6:1 basis(2) 1.5 Bcf/1,000’ Type Curve.(3) 1.5 Bcf/1,000’ Type Curve processed assuming 1225 BTU.

Source: Company presentations and press releases. Note: Antero acreage position reflects townships in which greater than 3,000 net acres are owned. Note: Third party peak rates assume ethane recovery; Antero 24-hour peak rates assume ethane recovery; Antero 30-day rates assume 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.

100% operated

106,000 net acres in the core rich gas / condensate window– 20% HBP with additional 79% not expiring

for 5+ years– 75% of acreage has rich gas processing

potential

18 Antero-operated horizontal wells completed and online − 100% drilling success rate

Net production of 54 MMcfe/d in 4Q 2013 including 2,200 Bbl/d of liquids− First production in early August 2013 had

access to Cadiz pipeline and processing− Seneca I processing plant came online in

November 2013 and Seneca II came online in January 2014

− First 120 MMcf/d compressor station went into service in late January with an additional 120 MMcf/d compressor station expected by late 1Q 2014

759 future drilling locations– Approximately 15% of EUR is liquids

assuming ethane rejection

Operating 5 rigs including 1 shallow rig

5.8 Tcfe of net 3P (15% liquids), includes 362 Bcfe of proved reserves (assuming ethane rejection)

EXCITING CORE UTICA SHALE POSITION DELIVERS CONDENSATE AND NGLS

19

Utica Shale Industry Activity(1)

SenecaProcessing

Plant

CadizProcessing

Plant

CHESAPEAKE24-Hour IPBuell #8H

9.5 MMcf/d + 1,425 Bbl/d liquids

GULFPORT24-Hour IP

Boy Scout 1-33H, Ryser 1-25H, Groh 1-12H

Average 5.3 MMcf/d + 675 Bbl/d NGL + 1,411 Bbl/d Oil

REXX24-Hour IP

Guernsey 1H, 2H,Noble 1H

Average 7.9 MMcf/d + 1,192 Bbl/d NGL

+ 502 Bbl/d Oil

MILEY UNIT30-Day Rate

2 wells average3.0 MMcf/d + 187 Bbl/d NGL

+ 559 Bbl/d Oil

NORMAN UNIT 1H30-Day Rate 13.6 MMcf/d

+ 461 Bbl/d NGL + 2 Bbl/d Oil

YONTZ UNIT 1H30-Day Rate 14.6 MMcf/d

+ 392 Bbl/d NGL + 1 Bbl/d Oil

RUBEL UNIT30-Day Rate

3 wells average13.5 MMcf/d + 583 Bbl/d NGL

+ 45 Bbl/d Oil

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 AreaWAYNE UNIT

30-Day Rate3 wells average

5.4 MMcf/d + 335 Bbl/d NGL + 548 Bbl/d Oil

DOLLISON UNIT 1H 24-Hour IP

10.2 MMcf/d + 1,488 Bbl/d NGL + 1,397 Bbl/d Oil

GARY UNIT 1H30-Day Rate23.1 MMcf/d

+ 1,023 Bbl/d NGL + 65 Bbl/d Oil

Highly-Rich/Cond30,000 Net Acres

205 Locations

Highly-Rich Gas25,000 Net Acres

161 Locations

Rich Gas24,000 Net Acres

182 Locations

Dry Gas27,000 Net Acres

211 Locations

MILLIGAN UNIT24-Hour IP

3 wells average11.3 MMcf/d + 1,971 Bbl/d NGL

+ 1,586 Bbl/d Oil

COAL UNIT 1H24-Hour IP

11.8 MMcf/d + 2,063 Bbl/d NGL + 1,850 Bbl/d Oil

0.0

10.0

20.0

30.0

40.0

50.0

60.0

MM

cfe/

d

Source: Antero, press releases and company presentations.Note: Assumes ethane recovery.

ANTERO HAS MOST OF THE TOP UTICA 24-HOUR IPS– STRONG SUPPORT FOR CORE POSITION

Antero has 11 of the top 12 Utica 24-hour peak rates (IPs) announced to date

Represent some of the best 24-hour peak rates of any shale play in North America– 20 to 53 MMcfe/d per well 24-

hour peak rate in the core area

– Excellent reservoir pressure with gradients in the 0.7 psi/ft range

Liquids content ranges from 40%-70% (assumes ethane recovery) in the liquids-rich window

Antero recently announced 30-day rates on some of these wells (see page 29)

20

UTICA 24-HOUR IPsCore

12 to 53MMcfe/d IPs

Tier 16 to 12

MMcfe/d IPs

Antero Utica Wells 3rd Party Core Utica Wells 3rd Party Non-Core Utica Wells

UTICA SINGLE WELL ECONOMICS – ASSUMES ETHANE REJECTION

21

DRY GAS LOCATIONS RICH GAS LOCATIONS

HIGHLY RICH GAS

LOCATIONS

Assumptions 12/31/2013 Strip Pricing & SEC Reserves

Utica Well Economics and Locations(1)

ClassificationHighly-Rich/Condensate

Highly-Rich Gas Rich Gas Dry Gas

BTU Range 1250-1300 1200-1250 1100-1200 <1100Modeled BTU 1275 1225 1175EUR (Bcfe): 11.3 20.5 18.8 16.6EUR (MMBoe): 1.9 3.4 3.1 2.8% Liquids 32% 23% 15% 0%Lateral Length (ft): 7,000 7,000 7,000 7,000Stage Length (ft): 240 240 240 240Well Cost ($MM): $11.0 $11.0 $11.0 $11.0Bcf/1,000’: 1.2 2.4 2.4 2.4Bcfe/1,000’: 1.6 2.9 2.7 2.4

Pre-Tax NPV10 ($MM): $15.7 $26.6 $18.4 $11.7Pre-Tax ROR: 137% 169% 95% 56%Net F&D ($/Mcfe): $1.21 $0.66 $0.72 $0.82Payout (Years): 0.5 0.5 0.8 1.3

Gross 3P Locations(3): 205 161 182 2111. Well economics are based on 12/31/2013 proved (P90) reserves and strip pricing. Includes gathering, compression and processing fees.2. Pricing for a 1225 BTU y-grade rejection barrel.3. Gross 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content.

NYMEX($/MMBtu)

WTI($/Bbl)

C3+ NGL(2)

($/Bbl)

2014 $4.24 $95 $54

2015 $4.16 $88 $50

2016 $4.09 $83 $49

2017 $4.09 $80 $49

2018+ $4.14 $79 $49

205161

182211

137%169%

95%

56%

0

50

100

150

200

250

0%

50%

100%

150%

200%

Highly-Rich Gas/Condensate

Highly-Rich Gas Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

RLocations ROR

LARGE MIDSTREAM FOOTPRINT

22

Ohio River WithdrawalSystem Completed

Antero Midstream estimated cumulative YE 2014 total capital investment in midstream ~ $1,580 million– Includes gathering lines, compressor

stations and water distribution infrastructureProprietary water sourcing and distribution

system − Improves operational efficiency and reduces

water truck traffic− Cost savings of $600,000 -$800,000 per

well− One of the benefits of a consolidated

acreage position

UticaShale

MarcellusShale

Projected Midstream Infrastructure(1)

Marcellus Shale

Utica Shale Total

YE 2014E Cumulative Gathering / Compression Capex ($MM) $835 $295 $1,130Gathering Pipelines (Miles) 192 92 284Compression Capacity (MMcf/d) 410 N/A 410

YE 2014 Cumulative Water System Capex ($MM) $350 $100 $450Water Pipeline (Miles) 122 48 170Water Storage Facilities 31 16 47

YE 2014E Total Midstream ($MM) $1,185 $395 $1,580

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 9/30/2013 and remaining 2013 and 2014 budget.

CAPITALIZATION

1. Equity valuation based on 262.0 million shares outstanding and a share price of $58.27 as of 2/24/2014. Enterprise value includes net debt.2. Pro forma 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 Note and $140 million 7.25% Senior Notes repaid at beginning of year along with residual cash used to repay bank debt.3. Lender commitments under the facility reduced to $1.5 billion from $1.75 billion on 10/21/2013; commitments can be expanded to the full $2.0 billion borrowing base upon bank approval.

PRO FORMA CAPITALIZATION

($ in millions) 12/31/2013(PF Financing)

12/31/2013 (2)

Cash $17 $17

Senior Secured Revolving Credit Facility 288 2887.25% Senior Notes Due 2019 260 2606.00% Senior Notes Due 2020 525 5255.375% Senior Notes Due 2021 1,000 1,000Net Unamortized Premium 6 6Total Debt $2,079 $2,079

Net Debt $2,062 $2,062

Shareholders' Equity $3,599 $3,599Net Book Capitalization $5,660 $5,660

Net Market Capitalization(1) $17,328 $17,328

Financial & Operating StatisticsLTM EBITDAX $649 $649

LTM Interest Expense(2) $137 $106

Proved Reserves (Bcfe) (12/31/2013) 7,632 7,632

Proved Developed Reserves (Bcfe) (12/31/2013) 2,023 2,023

Credit Statistics

Net Debt / LTM EBITDAX 3.2x 3.2xLTM EBITDAX / Interest Expense 4.8x 6.1xNet Debt / Net Book Capitalization 36.4% 36.4%Net Debt / Net Market Capitalization 11.9% 11.9%Net Debt / Proved Developed Reserves ($/Mcfe) $1.02 $1.02Net Debt / Proved Reserves ($/Mcfe) $0.27 $0.27

LiquidityCredit Facility Commitments(3) $1,500 $1,500 Less: Borrowings (288) (288)Less: Letters of Credit (32) (32)Plus: Cash 17 17

Liquidity (Credit Facility + Cash) $1,197 $1,197

23

Keys to Execution

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

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

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

Central Fresh Water System & Water Recycling

Numerous sources of water – building central water system to source water forcompletion

Antero recycles over 95% of its flowback water with the remainder injected into disposal wells – no discharge to water treatment plants in West Virginia

Natural Gas Powered Drilling Rigs Nine of Antero’s contracted drilling rigs are currently running on natural gas

Natural Gas Vehicles (NGV)

Antero supported the first natural gas fueling station in West Virginia which recently opened

Antero has a dozen NGV trucks and plans to continue to convert its truck fleet to NGV

Safety & Environmental

Five company safety representatives and 45 safety consultants cover all material field operations 24/7 including drilling, completion, construction and pipelining

23-person company environmental staff plus outside consultants monitor all operations and perform baseline water well testing

Local Presence Land office in Ellenboro, WV Recently moved into new 50,000 square foot district office in Bridgeport, WV 105 of Antero’s 258 employees are located in West Virginia and Ohio

LEED Gold Headquarters Building

Antero’s new corporate headquarters in Denver has been LEED Gold Certified Completion expected by spring of 2014

HEALTH, SAFETY, ENVIRONMENT & COMMUNITYProtection Of Our People And The Environment Is An Antero Core Value

Strong West Virginia Presence Over 75% of 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

24

ANTERO KEY ATTRIBUTES

25

456,000 Net Acres in the Core Marcellus and Utica Shales

“Triple Digit” Historical Production and Reserve Growth

Low Cost Leader / High Return Projects

Significant Takeaway and Processing Capacity Already in Place

Clean Balance Sheet Supports High Growth Story

“Forward Thinking” Management Team with a History of Success

26

APPENDIX

26

ANTERO FIRM TRANSPORTATION AND FIRM SALES

27

MMBtu/d

Columbia7/26/2009 – 9/30/2025

Firm Sales #110/1/2011– 10/31/2019

Firm Sales #2

10/1/2011 – 5/31/2017

Firm Sales #3

1/1/2013 – 5/31/2022

Momentum III9/1/2012 – 12/31/2021

EQT8/1/2012 – 8/31/2021

Chicago Direct4/1/2013 – 9/30/2021

-

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

1,800,000

1. 24-hour peak rates assume full ethane recovery (assuming typical ethane plant product recoveries of 85% to 90%) however Antero is currently rejecting ethane due to current market prices. 2. Average of Antero’s first 16 core area wells, assuming ethane rejection.

ANTERO UTICA SHALE WELLS – 24 HOUR IPS

28

LateralWell Gas Equivalent Rate Wellhead Gas Shrunk Gas NGL Condensate % Total LengthName County (MMcfe/d) (MMcf/d) (MMcf/d) (Bbl/d) (Bbl/d) Liquids BTU (Feet)

Yontz 1H Monroe 53.3 38.9 33.9 3,177 52 36% 1161 5,115Rubel 1H Monroe 47.5 31.1 25.9 3,391 214 46% 1231 6,554Gary 2H Monroe 43.5 28.9 24.2 3,053 162 44% 1224 8,882Rubel 3H Monroe 42.6 28.4 23.7 3,003 142 44% 1220 6,424Milligan 2H Noble 40.2 17.2 13.5 2,361 2,087 68% 1276 5,989Rubel 2H Monroe 37.4 24.8 20.7 2,635 156 45% 1217 6,571Norman 1H Monroe 37.1 26.1 22.3 2,419 45 40% 1186 5,498Coal 3H Noble 35.3 15.1 11.8 2,063 1,850 67% 1278 7,768Wayne 3HA Noble 35.1 14.7 11.6 2,018 1,905 67% 1272 6,712Wayne 4H Noble 34.2 14.2 11.2 1,907 1,922 67% 1265 6,493Milligan 3H Noble 32.1 15.4 12.1 2,111 1,228 62% 1276 5,267Dollison 1H Noble 27.5 12.5 10.2 1,488 1,397 63% 1238 6,253Milligan 1H Noble 25.8 10.6 8.3 1,461 1,442 68% 1276 6,436Wayne 2H Noble 25.5 10.9 8.5 1,503 1,331 67% 1281 6,094Miley 2H Noble 22.4 8.6 6.7 1,172 1,450 70% 1278 6,153Miley 5HA Noble 20.2 7.7 6.0 1,090 1,285 70% 1291 6,296

35.0 19.1 15.7 2,178 1,042 58% 1248 6,40728.1 19.1 18.5 819 1,042 40% 1248 6,407

Average ‐ Ethane Recovery(1)

Average ‐ Ethane Rejection(2)

24‐hr Peak Rate

1. Average of Antero’s first 11 core area wells, assuming ethane recovery.

ANTERO UTICA SHALE WELLS – 30-DAY RATES

29

Antero’s wells have been producing against 1,100 psi line pressure due to lack of compression facilities− First 120 MMcf/d compressor station started up in late January 2014

LateralWell Gas Eq. Rate Wellhead Gas Shrunk Gas NGL Condensate % Total Estimated LengthName County (MMcfe/d) (MMcf/d) (MMcf/d) (Bbl/d) (Bbl/d) Liquids BTU (Feet)

Gary 2H Monroe 29.7 24.6 23.1 1,023 65 22% 1224 8,882Rubel 2H Monroe 19.2 15.9 15.0 625 64 22% 1217 6,571Rubel 3H Monroe 18.7 15.6 14.7 623 43 21% 1220 6,424Yontz 1H Monroe 17.0 15.2 14.6 392 1 14% 1161 5,115Norman 1H Monroe 16.4 14.3 13.6 461 2 17% 1186 5,498Rubel 1H Monroe 14.0 11.5 10.8 501 28 23% 1231 6,554Wayne 2H Noble 12.1 6.5 6.0 367 653 51% 1281 6,094Wayne 3HA Noble 11.0 6.1 5.6 354 540 49% 1272 6,712Wayne 4H Noble 9.2 5.2 4.7 284 452 48% 1265 6,493Miley 2H Noble 9.0 3.8 3.5 213 700 61% 1278 6,153Miley 5HA Noble 5.9 2.7 2.5 161 418 59% 1291 6,296

14.7 11.0 10.4 455 270 35% 1239 6,43617.9 11.0 9.2 1,189 270 53% 1239 6,436

30‐Day Rates ‐ Antero Core Area

Average ‐ Ethane RejectionAverage ‐ Ethane Recovery(1)

CONSIDERABLE RESERVE BASE WITH ETHANE OPTIONALITY 40 year proved reserve life based on 2013E production Reserve base provides significant exposure to liquids-rich projects

– 3P reserves of over 2.2 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)

30

Marcellus – 25.0 Tcfe

Utica – 5.8 Tcfe

Upper Devonian – 4.2 Tcfe

35.0Tcfe

Gas – 29.6 Tcf

Oil – 91 MMBbls

NGLs – 811 MMBbls

Marcellus – 29.5 Tcfe

Utica – 6.7 Tcfe

Upper Devonian – 4.7 Tcfe

40.8Tcfe

Gas – 27.4 Tcf

Oil – 91 MMBbls

NGLs – 2,151 MMBbls

15%Liquids

33%Liquids

Gas $4.15

Gas$3.90

Gas$3.86

Gas$3.80

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

1050 BTU

$5.19

$6.95

$8.28

$4.15

1150 BTU 1250 BTU 1300 BTU

MARCELLUS SHALE RICH GAS –LIQUIDS AND PROCESSING UPGRADE

1. Assumes $4.25/MMBtu NYMEX, $90.00/Bbl WTI and current NGL spot prices. 1.054 and 2.070 (ethane rejection) and 3.332 and 5.145 (ethane recovery) GPM s used, all processing costs, shrink and fuel included. No ethane takeaway available until Enterprise ethane pipeline is online (expected 1Q 2014). Ethane recovery well economics include fixed fee cost tariff on ATEX ethane pipeline.

2. NGL prices as of 2/3/2014 from IntercontinentalExchange.

Current – Ethane Rejection

(1076 BTU)8% shrink

(1109 BTU)12% shrink

(1119 BTU)14% shrink

$/Wellhead Mcf(1)(2)

($/Mcf)

Marcellus Shale rich gas and highly-rich gas acreage provides a significant advantage in well economics – assuming $4.25/MMBtu NYMEX, $90.00/Bbl WTI and current spot NGL pricing

31

+$1.04Upgrade

+$2.79Upgrade

+$4.13Upgrade

Highly Rich GasDry Gas

NGLs (C3+)$1.30

NGLs (C3+)$2.93

NGLs (C3+)$3.92

Condensate$0.16

Condensate$0.56

Highly Rich/ CondensateDry Gas

2013 REALIZATIONS

Ethane (C2)

Propane (C3)

Iso Butane (C4)

Normal Butane

Natural Gasoline

Total $52.61 per Bbl54% of WTI(4)

2013 NGL Y-GRADE (C3+) REALIZATIONS

2013 NATURAL GAS REALIZATIONS ($/MCF)

55%

2%

11%

15%

17%

$23.49

$6.27

$7.55

$14.57

$0.72

321. NYMEX differential represents contractual deduct to NYMEX-based sales.2. Includes firm sales.3. Based on monthly prices through 12/31/2013 WTI.

Antero Barrel

2013 % Sales

Average NYMEX Price

AverageDifferential(2)

AverageBTU Upgrade

Average 2013 Realized Price

Average Premium / (Discount)

TCO 67% $3.65 $(0.06) $0.42 $4.02 $0.37Dominion South 22% $3.65 $(0.41) $0.39 $3.64 $(0.01)NYMEX(1) 6% $3.65 $(0.40) $0.39 $3.65 −TETCO 5% $3.65 $(0.26) $0.41 $3.80 $0.15

Total 100% $3.65 $(0.16) $0.42 $3.90 $0.25

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

“We would consider a positive rating action if the company continued toconvert its PUD reserves to proved developed reserves and improvedprofitability, while maintaining leverage below 3x.”

- S&P Credit Research, October 2013

“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% as itbuilds out infrastructure needs to support production growth.”

- Moody’s Credit Research, October 2013

Moody's S&P

Credit Rating (Moody’s / S&P)

Ba3 / BB-

B1 / B+

B2 / B

B3 / B-

9/1/2010 2/24/2011 5/31/2012 10/21/2013 2/18//20142/28/2012 11/28/20118/27/20115/27/2011

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

33

ANTERO EBITDAX RECONCILIATION

34

EBITDAX Reconciliation($ in millions) (12 Months Ended)Antero Resources LLC 12/31/2012 12/31/2013

EBITDAX:Net income (loss) from continuing operations $225.3 $(24.2)Commodity derivative fair value (gains) losses (179.5) (491.7)Net cash receipts on settled commodity derivatives instruments 178.5 163.6(Gain) loss on sale of assets (291.2) -Interest expense and other 97.5 136.6Loss on early extinguishment of debt - 42.6Provision (benefit) for income taxes 121.2 186.2Depreciation, depletion, amortization and accretion 102.1 234.9Impairment of unproved properties 12.1 10.9Exploration expense 14.7 22.3Stock compensation expense - 365.3Other 4.1 2.9EBITDAX from continuing operations $284.7 $649.4

EBITDAX:Net income (loss) from discontinued operations ($510.3) 5.3Commodity derivative fair value (gains) losses (46.4) -Net cash receipts on settled commodity derivatives instruments 92.2 -(Gain) loss on sale of assets 795.9 (8.5)Provision (benefit) for income taxes (272.6) 3.2Depreciation, depletion, amortization and accretion 89.1 -Impairment of unproved properties 1.0 -Exploration expense 1.0 -EBITDAX from discontinued operations $149.6 -

EBITDAX $434.3 $649.4

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 December 31, 2013 included in this presentation have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates are as of December 31, 2013, assuming 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 December 31, 2013. 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.

“Highly-rich/condensate” refers to gas having a heat content between 1275 BTU and 1350 BTU in the Marcellus Shale and 1250 BTU and 1300 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 1250 BTU in the Utica Shale.

“Rich gas” refers to gas having a heat content of between 1100 BTU to 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

35