Company Overview March 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, forwardlooking 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 Critical Mass In Two World Class Shale Plays

● 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

Market Leading Growth

● 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

Industry Leading Capital Efficiency and Recycle Ratio

● 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

Significant Emphasis on Takeaway and Liquids Processing

● 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

Liquidity and Hedge Position Support High Growth Story

● ~$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/MMBtu and $96.54/Bbl

Outstanding Management Team 1. Three year average through 2012; pro forma for Arkoma and Piceance divestitures. 2. See page 23 for the derivation of 12/31/2013 liquidity.

● 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

2

PREMIER UNCONVENTIONAL RESOURCE PLATFORM TOTAL – 12/31/13 RESERVES(1) Assumes Ethane Rejection Net Proved Reserves(1) Net 3P Reserves(1) Pre-Tax 3P PV-10(1)

7.6 Tcfe 35.0 Tcfe $20,362 MM

Net 3P Liquids % Liquids – Net 3P 4Q 2013 Net Production(2) - 4Q 2013 Net Liquids(2) Net Acres(3) Undrilled 3P Locations

902 MMBbls 15% 678 MMcfe/d 11,190 Bbl/d 456,000 4,778

A C B

D

A MARCELLUS SHALE

“Pure-Play” Appalachian-Focused Shale Company

Reserves(1)

Net Proved Net 3P Reserves (1) Pre-Tax 3P PV-10(1)

7.2 Tcfe 25.0 Tcfe $15,729 MM

% Liquids – Net 3P 4Q 2013 Net Production Undrilled 3P Locations

17% 621 MMcfe/d 3,068

B UTICA SHALE – LIQUIDS RICH Reserves(1)

C

Net Proved Net 3P Reserves (1) Pre-Tax 3P PV-10(1)

362 Bcfe 5.8 Tcfe $4,666 MM

% Liquids – Net 3P 4Q 2013 Net Production Undrilled 3P Locations

15% 54 MMcfe/d 759

Net Proved Reserves(1) Net 3P Reserves (1) Pre-Tax 3P PV-10(1) % Liquids – Net 3P 4Q 2013 Net Production Undrilled 3P Locations

Net Acres(3) Net Resource Undrilled Locations

2. 3.

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

UPPER DEVONIAN SHALE 44 Bcfe 4.2 Tcfe NM 7% 3 MMcfe/d 951

D UTICA SHALE – DRY GAS

1.

•

128,000 5.0 Tcfe 950

Additional Hedge Value •

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

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. Represents the average net daily production for the period October 1, 2013 through December 31, 2013. 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.

3

STRONG TRACK RECORD OF GROWTH AVERAGE NET DAILY PRODUCTION (MMcfe/d) Woodford

Piceance

Marcellus

APPALACHIAN PRODUCTION (MMcfe/d)

Utica

800

Marcellus

950

1,000

600

522

400

950

800

Sold Woodford and Piceance

600

522

400

334 244

200 0

6 2006

31 2007

105

87 2008

2009

2010

2011

2012

2013

Piceance

0

(4)

2014E

2010

2011

2012

(4)

2013

2014E

OPERATED GROSS WELLS SPUD

Marcellus(3)

Utica

Woodford

Piceance

Marcellus

Utica

193

200 7,632

8,000 Sold Woodford and Piceance

7,000 6,000

5,017

5,000 4,000

87

235

2006

2007

680

1,141

2008

2009

162 126

125

4,283

100

3,231

2,000

175 150

85

96

119 91

Financial Crisis

66

75

3,000

0

124 30

9,000

1,000

239

200

133

NET PROVED SEC RESERVES (Bcfe)(2) Woodford

Utica

1,000

50 18

25 2010

2011

2012

(5)

(5)

2013

0

2006

2007

2008

2009

2010

2011

2012

2013

(4)

2014E

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.

4

OUTSTANDING RESERVE GROWTH PROVED RESERVE GROWTH(1) (Tcfe) 10 7.6 0.4

8 6 4

4.2 0.1

2

4.1

7.2

Drivers • Successful drilling • Expanded proved footprint (HDA)

2013 Marcellus

3P RESERVE GROWTH(1)

30 20 10

35.0 4.2

5.8

21.6 4.0 17.6

0 2012 Marcellus

Drivers • 80,000 net acres added in 2013 • SSL results • Utica results

25.0

• 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

FUTURE RESERVE GROWTH DRIVERS

(Tcfe)

40

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

• No Utica Shale WV/PA dry gas reserves booked

Utica

50

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

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

0 2012

2013 RESERVE UPDATE

Driver • Marcellus SSL completions

Complete transition to SSL type curve

• Full scale Utica program

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

• Utica increased density drilling

Drilling 2 increased density pilots in Utica

• Utica dry gas drilling

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

• Core acreage acquisitions

$200 million leasehold budget

2013 Utica

1. 2012 and 2013 reserves assume ethane rejection.

Upper Devonian

2014 Action

5

MULTI-YEAR DRILLING INVENTORY SUPPORTS LOW-RISK, HIGH-RETURN GROWTH PROFILE 890

834 707

ROR

100%

0%

800 600

117%

50%

400

65% Highly-Rich Gas/ Condensate

1000 1,000

200

Highly-Rich Gas

32%

21%

Rich Gas

Dry Gas

Locations

200%

100%

161

0%

ROR

250

211

182

200

169%

150

137%

100

95%

50%

0

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

205

150% ROR

637

Total 3P Locations

150%

UTICA WELL ECONOMICS(1)

50

56% Highly-Rich Gas/ Condensate

Highly-Rich Gas

Rich Gas

Locations

0

Dry Gas

Total 3P Locations

MARCELLUS SSL WELL ECONOMICS(1)(2)

ROR

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

$ / MMBtu NYMEX (Gas)

Large Inventory of Low Breakeven Projects(3) $7.00 $6.00 $5.00

$3.00 $2.00

$0.00

1,541

366

Locations

637

182 $2.47 $2.50 Locations

890

Locations

$3.75 $3.80 $3.81

$4.00

$1.00

1. 2. 3. 4.

3 Yr Strip - $4.38/MMBtu(4)

2,726 Antero Liquids-Rich Locations $2.60

$2.94

$3.20

$3.27

$3.51

$4.13 $4.25 $4.66

$5.05

$5.37 $5.49

$3.65 $3.66 $3.70

Locations

Locations $0.89

$1.15

$0.00 $0.00 $0.00 $0.00

`

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

6

LOW DEVELOPMENT COST DRIVES BEST-IN-CLASS RECYCLE RATIOS 3-Year All-in Development Costs ($/Mcfe) through 2012 $/Mcfe

$4.00 Antero

$3.00 $2.00 $1.00

$1.03

$1.14

Appalachia-Focused Peers

$1.41

$1.71

$1.57

$0.00

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 Average Growth – Adjusted Recycle Ratio through 2012 8.0x 6.0x 4.0x

6.1x Antero

3.5x

Appalachia-Focused Peers

3.1x

2.7x

2.0x 0.0x

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.

7

MARCELLUS/UTICA – ADVANTAGED ECONOMICS  Low-cost, liquids-rich Utica and Marcellus Shales will remain attractive in most commodity price environments

U.S. INCREMENTAL GAS SUPPLY BREAK-EVEN PRICE CURVE(1) Downside risks to breakeven costs for older shale plays once exploration resumes with higher natural gas prices?

?

?

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

Haynesville

?

Barnett

?

Eagle Ford Shale

Niobrara

Utica Shale

SW (Rich) Marcellus Shale

NE (Dry) Marcellus Shale

Permian

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

Granite Wash

Over 2,700 Antero Drilling Locations

8

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 producers Antero sold ~67% of its 2013 production at TCO index at NYMEX less $0.06/MMbtu prior to the Btu upgrade Antero Transport and Processing

2014

2015

Firm Transport (FT) (MMBtu/d) Firm Sales (MMBtu/d)(1)

1,369,000 330,000

1,407,000 320,000

Firm Processing Capacity (Mcf/d) Ethane FT (Bbl/d)

1,400,000 20,000

1,550,000 20,000

Leidy Basis to NYMEX Current 2015 -$2.78 -$2.17 Dom South Basis to NYMEX Current 2015 -$0.17 -$0.93

Chicago Basis to NYMEX Current 2015 +$3.23 -$0.07

TCO Basis to NYMEX Current 2015 +$0.13 -$0.43

Growing Processing Capacity Total Capacity 1,550

1,600 Seneca IV

1,400

CGTLA Basis to NYMEX Current 2015 -$0.02 -$0.09

1,200 Seneca III

(MMcf/d)

1,000 800

Seneca II

600

Seneca I

400

Sherwood III

200

Sherwood V Sherwood IV

Sherwood II Sherwood I

0

1. 2.

Appalachian Basis to NYMEX(2)

2013 % of Production Sold

Marcellus

Sherwood I

Sherwood II

Sherwood III

Sherwood IV

Utica

Seneca I

Seneca II

Seneca III

Seneca IV

2014

TCO

67%

TCO

Dom South

22%

Dom South

TETCO

5%

TETCO M2

NYMEX

6%

Sherwood V

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

2015

2016

2017

2018

2019 -$0.20 -$0.60 -$1.00 -$1.40 -$1.80

Leidy

-$2.20 -$2.60

9

LONG HAUL PIPELINE AND TRANSPORTATION NETWORK  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

Leidy Basis to NYMEX Current 2015 -$2.78 -$2.17

Chicago Basis to NYMEX Current 2015 +$3.23 -$0.07

Dom South Basis to NYMEX Current 2015 -$0.17 -$0.93

(1)

TCO Basis to NYMEX Current 2015 +$0.13 -$0.43

Appalachian Firm Transportation/Sales Commitment by Operator 2,000,000

Firm Sales

Firm Transportation

CGTLA Basis to NYMEX Current 2015 -$0.02 -$0.09

Mcf/d

1,600,000 1,200,000 800,000 400,000 0

(2)

AR

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

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

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.

10

SIGNIFICANT LONG-TERM COMMODITY HEDGE POSITION NATURAL GAS HEDGES – 2/24/2014 BBtu/d

600 400

Average Index Price ($/MMBtu)(1)

Hedged Volume

800 $4.92 $4.85

$4.91

$4.20

NYMEX Strip (2/24/2014) ($/MMBtu)

$7.00 $6.00

$4.71

$4.65

$4.34 $4.10

$4.09

$4.14

$4.46 $4.22

$4.00 $3.00 $2.00

200 0

$5.00

729

550

643

740

630

358

2014

2015

2016

2017

2018

2019

$1.00 $0.00

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

% HEDGE VOLUMES BY INDEX – 2/24/2014 Chicago 2% NYMEX

TCO 12% 18%

Dom South

50% 18%

CGTLA

11

ASSET OVERVIEW

12

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

Utica Shale Liquids-Rich Fairway

106,000 Net Acres 18 Horizontals Completed 5 Rigs Currently Running

Utica Shale Core Area

Marcellus Shale Southwestern & Northeastern Core Areas

Marcellus Shale Liquids-Rich Fairway

ANTERO MARCELLUS SHALE SW PA

25,000 Net Acres 2 Horizontals Completed Strong Results ANTERO MARCELLUS SHALE NW WV

325,000 Net Acres (Primarily Liquids-Rich Fairway) 234 Horizontals Completed 15 Rigs Currently Running

Utica Shale Dry Gas Resource Underlies Marcellus Acreage

Upper Devonian Shale Resource Overlies Marcellus Acreage

13 Source: Company presentations and press releases.

WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECT

Antero 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

MHR WEESE UNIT 30-Day Rate 4-well average 9.3 MMcfe/d (31% liquids)

BLANCHE UNIT 30-Day Rate 2H: 10.0 MMcfe/d (29% liquids)

DOTSON UNIT 30-Day Rate 1H: 12.4 MMcfe/d 2H: 11.8 MMcfe/d (27% liquids)

EQT 30-Day Rate 12 Recent Wells 9.2 MMcfe/d (20% Liquids)

CHK HADLEY UNIT 24-Hour IP 9.1 MMcfe/d (32% liquids)

MOORE UNIT 30-Day Rate 1H: 9.9 MMcfe/d 2H: 10.0 MMcfe/d (17% liquids)

Sherwood Processing Plant

EQT PENN 15 UNIT 30-Day Rate 5-well average 9.3 MMcfe/d (29% liquids)

142 Horizontals Completed 30-Day Rate 10.3 Bcf average EUR 8.1 MMcf/d 6,915’ average lateral length

 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)

CONSTABLE UNIT 30-Day Rate 1H: 15.2 MMcfe/d (30% liquids) PRUNTY UNIT 30-Day Rate 1H: 11.0 MMcfe/d (29% liquids)

Highly-Rich/Condensate 60,000 Net Acres 637 Gross Locations

Highly-Rich Gas 100,000 Net Acres 834 Gross Locations

HINTERER UNIT 30-Day Rate 1H: 12.9 MMcfe/d (20% liquids) Rich Gas 86,000 Net Acres 707 Gross Locations

RUTH UNIT 30-Day Rate 1H: 19.3 MMcfe/d (14% liquids)

Dry Gas 104,000 Net Acres 890 Gross Locations

14 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.

MARCELLUS – SIMPLE STRUCTURE  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

Regional Seismic Line

Average Marcellus Lateral Lengths 8,000

7,300

Feet

6,000

4,800

4,500

4,100

4,000

100’ Contours Top Marcellus

W

Profile along regional seismic line

(time) No Data

2,000 0 Antero

EQT

Source: Company presentations.

RRC

COG

Big Moses

Arches Fork

Wolf Summit

E

Benson Rhinestreet Tully Marcellus Onondaga

15

ANTERO’S MARCELLUS SHALE TYPE CURVE SUPPORT  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

Marcellus Type Curve – Normalized to 7,000’ Lateral Actual Non-SSL Production (1)

Non-SSL Type Curve Cumulative Production

1.7 Bcf/1,000' SSL Type Curve

15.0

SSL Actual Production (2)

12.0 MMcf/d

Antero Non-SSL Type Curve

9.0

Wellhead (MMcf/d) # of wells

12.0

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-Year Avg. Rate

14.3 236

8.1 224

6.3 221

5.3 193

4.2 131

3.1 65

2.3 26

Cumulative Bcf

15.0

9.0

6.0

6.0

3.0

3.0

0.0

0.0 0

1

2

3

4

5

6

7

8

9

10

Production Year Well Cost / 1,000’ Decreases with Lateral Length

Wellhead 24-hour Peak Rates (IPs) - 236 Wells

$1.8

30

16

$1.6

25

$1.4

20

12 8 4 0 2,000

MMcf/d

20

$MM / 1,000'

EUR, BCF

EURs Increase With Lateral Length

$1.2 $1.0 $0.8

4,000

6,000

8,000

Lateral Length, ft

10,000

$0.6 2,000

Average IP – 14.3 MMcf/d

15 10 5

4,000 6,000 8,000 Lateral length, ft

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.

10,000

0 1st Production from All Wells 2009 - 2013

16

MARCELLUS SINGLE WELL ECONOMICS – ASSUMES ETHANE REJECTION Marcellus SSL Well Economics and Total Locations(1)

 12/31/2013 Strip Pricing & SEC Reserves 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

150%

1,000

890

834

637

800

707 100% ROR

NYMEX ($/MMBtu)

117%

600

50% 0%

400

65%

200 32%

Highly-Rich Gas/ Condensate

Highly-Rich Gas Locations

21%

Rich Gas

0

Dry Gas

ROR

Classification

Highly-Rich/ Condensate

Highly-Rich Gas

Rich Gas

Dry Gas

BTU Range Modeled BTU

1275-1350 1313

1200-1275 1250

1100-1200 1150