company overview september 2014

Company OverviewSeptember 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 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

ANTERO: A “PURE PLAY” ON THE MARCELLUS / UTICA● Marcellus is one of the largest gas fields in the world today− Largest gas field in the U.S. currently producing over 15 Bcf/d

● Antero has 37.5 Tcfe of fully engineered 3P reserves in the Marcellus and Utica Shales + 9.5 Tcf of unrisked resource in the dry gas Utica

Critical Mass In Two World Class Shale Plays

● 94% organic production growth for 2Q 2014 over 2Q 2013● Most active driller in Appalachia – 22 rigs running− Most active driller in Marcellus Shale – 15 rigs running− 2nd most active driller in the Utica Shale – 7 rigs running

Market Leading Growth

● Lowest 3-year average development cost through 2013: $1.15/Mcfe● Industry leading 3-year average growth-adjusted recycle ratio: 4.8x● Top quartile return on productive capital: 26% for 2014E

Industry Leading Capital Efficiency and Recycle Ratio

● 2.0 Bcf/d of firm processing capacity by 3Q 2015 and 3.4 Bcf/d of firm gas takeaway by 2016

● Liquids contribution (NGLs and oil) expected to continue to grow from 14% of 2Q 2014 production due to focus on liquids-rich development

Leader In Liquids Processing and Takeaway Capacity

● $1.5 billion of liquidity with current $2.5 billion in bank commitments● Average cost of debt under 4.7% with first maturity in 2019● 1.5 Tcfe hedged through 2019 at an average index price of $4.56/MMBtu

and $94.13/Bbl, including basis hedges

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 600 horizontal shale

wells in the Barnett, Woodford, Marcellus and Utica Shales

Outstanding Management Team

2

566

891

0

200

400

600

800

1,000

1,200

3Q 2013 2Q 2014

57%

SIGNIFICANT MOMENTUM SINCE IPO

3

Net Production(MMcfe/d)

0

100,000

200,000

300,000

400,000

500,000

3Q 2013 Current

498k431k

7,900

0

6,000

12,000

18,000

24,000

3Q 2013 2Q 2014

156%

20,200

Net Acres Liquids Production(Bbl/d)

Note: “Current” denotes latest data per website presentation or Roadshow presentation where applicable.

Proved Reserves(Bcfe)

0

2,500

5,000

7,500

10,000

3Q 2014 6/30/2014

45%

9,107

6,282

16%

Bank Borrowing Base($MM)

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

3Q 2013 Current

$3,000

$2,000

50%

Firm Gas Takeaway Portfolio(MMcf/d)

1,302

3,430

0

1,000

2,000

3,000

4,000

3Q 2013 Current

165%

Firms Liquids Portfolio(Bbl/d)

0

30,000

60,000

90,000

120,000

150,000

3Q 2013 Current

533%

20,000

126,500

Weighted Average Debt Cost(%)

7.59%

4.65%

0.00%

2.00%

4.00%

6.00%

8.00%

10.00%

3Q 2013 Current

39%

UPPER DEVONIAN SHALE

Net Proved Reserves 40 BcfeNet 3P Reserves 4.6 TcfePre-Tax 3P PV-10 NMUndrilled 3P Locations 1,119

PREMIER UNCONVENTIONAL RESOURCE PLATFORM

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.

COMBINED TOTAL – 6/30/14 RESERVESAssuming Ethane RejectionNet Proved Reserves 9.1 Tcfe Net 3P Reserves 37.5 TcfeNet 3P Reserves & Resource 47.0 TcfePre-Tax 3P PV-10 $25.9 BnNet 3P Liquids 966 MMBbls% Liquids – Net 3P 15%2Q 2014 Net Production 891 MMcfe/d- 2Q 2014 Net Liquids 20,200 Bbl/dNet Acres(1) 498,000Undrilled 3P Locations 5,011

MARCELLUS SHALE CORE

Net Proved Reserves 8.5 TcfeNet 3P Reserves 26.4 TcfePre-Tax 3P PV-10 $19.4 BnNet Acres 378,000Undrilled 3P Locations 3,057

UTICA SHALE CORE

Net Proved Reserves 537 BcfeNet 3P Reserves 6.4 TcfePre-Tax 3P PV-10 $6.5 BnNet Acres 120,000Undrilled 3P Locations 835

4

WV/PA UTICA SHALE DRY GASNet Resource 9.5 TcfNet Acres 146,000Undrilled Locations 1,359

OUTSTANDING RESERVE GROWTH

1. 2013 and 6/30/2014 reserves assuming ethane rejection.5

PROVED RESERVE GROWTH(1)

3P RESERVE GROWTH(1)

• Proved PV-10 increased 28% to $9.0 billion (including hedges)

• 3P PV-10 increased 24% to $26.4 billion (including hedges)

• Replaced 1,070% of 1H 2014 production

• 5-year proved undeveloped reserves future estimated development cost of $0.92/Mcfe

• Only 36% of 1P and 62% of 3P Marcellus locations booked as SSL (1.7 Bcf/1,000’ type curve) at 6/30/2014

• No Utica Shale WV/PA dry gas reserves booked; estimated net resource of 9.5 Tcf

7.28.6

0.40.5

0

2

4

6

8

10

2013 6/30/2014

(Tcfe)

Marcellus Utica

9.1

25.0 26.4

5.8 6.44.7

0

10

20

30

40

2013 6/30/2014

(Tcfe)

Marcellus Utica Upper Devonian

Key Drivers

4.2

POTENTIAL RESERVE GROWTH DRIVERS

6/30/2014 RESERVE UPDATE

• Marcellus SSL completions

• Full scale Utica SSL program

• Utica increased density drilling

• WV/PA Utica dry gas drilling

• Core acreage acquisitions

Driver 2014 Activity

Complete transition to SSL type curve

7.6

35.037.5

• Successful drilling

• SSL results

• Expanded proved footprint

• 35,000 net acres added in 1H 2014

• SSL results

• Utica results

41 wells to be completed; only 37 PUD locations booked as proved at 6/30/2014

35,000 net acres added in 1H 2014; $450 MM budget for 2014

Drilling increased density pilots in Utica

Industry drilling activity in WV/PA (146,000 net acres)

Key Drivers

LARGE MIDSTREAM FOOTPRINT

6

Ohio River WithdrawalSystem In Service

Significant investment in infrastructure -estimated cumulative YE 2014 total capital investment in midstream ~$1.6 billion– Includes gathering lines, compressor stations

and fresh water distribution infrastructure Proprietary fresh water sourcing and distribution

system − Improves operational efficiency and reduces

water truck traffic− Cost savings of $600,000 to $800,000 per well− One of the benefits of a consolidated acreage

position

Generated 2Q 2014 EBITDA of $39 million and 1H 2014 EBITDA of $66 million

UticaShale

MarcellusShale

Projected Midstream Infrastructure(1)

Marcellus Shale

Utica Shale Total

YE 2014E Cumulative Gathering / Compression Capex ($MM) $850 $350 $1,200Gathering Pipelines (Miles) 180 105 285Compression Capacity (MMcf/d) 370 - 370

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

YE 2014E Total Midstream ($MM) $1,150 $450 $1,600

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.

INTEGRATED PORTFOLIO OF FIRM GAS & NGL TAKEAWAY

7

Odebrecht / Braskem30 MBbl/d Commitment

Ascent Cracker(Pending Final

Investment Decision)

Antero Long Term Firm Takeaway Position

Mariner East II51,500 Bbl/d Commitment

Marcus Hook Export

Shell25 MBbl/d CommitmentBeaver County Cracker

(Pending FinalInvestment Decision)

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

$1,800$750

$300

Drilling & Completion Midstream Land

73%

27%

Marcellus Utica

ANTERO 2014 CAPITAL BUDGET

By Area

8

$2.85 Billion - PREVIOUSBy Segment

$2,400$850

$450

Drilling & Completion Midstream Land

73%

27%

Marcellus Utica

By Area

$3.7 Billion - REVISEDBy Segment

On August 26th, Antero increased its 2014 capital budget to $3.7 billion due to the acceleration of land, drilling and midstream activities in the Marcellus and Utica Shale plays

$1,800

$330

$180

$50 $40 $2,400

$1,200

$1,400

$1,600

$1,800

$2,000

$2,200

$2,400

$2,600

2014 Capital Budget Accelerated Development WI Increase / LongerLaterals / Addl. SSL

Completions

Accelerated Pad Costs Other 2014 Updated CapitalBudget

DRILLING AND COMPLETION BUDGET DRIVERS

DRILLING AND COMPLETION CAPITAL BUDGET RECONCILIATION($ in millions)

9

Generates 2H 2014 Increased Production Guidance of

~100 MMcfe/d

Generates 2015/2016 IncreasedProduction Target of

~100 MMcfe/d

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

0

600

1,200

1,800

2,400

2010 2011 2012 2013 1H 2014 2014E 2015E 2016E

Marcellus Utica Guidance

30 124 239

522

(2)

1,000838

1,500

2,200

(3) (3)

10

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

1. 2012, 2013 and 6/30/2014 proved reserves assuming ethane rejection.2. Midpoint of increased production guidance of 990-1,010 MMcfe/d for 2014.3. Based on 45-50% production growth targets for 2015 and 2016. 4. Per current First Call median estimate.

STRONG TRACK RECORD OF GROWTH

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

$1,227

(4)

92% GrowthGuidance

45-50% Annual Growth Target

708 826

641882

109%

67% 30% 20%

0

200

400

600

800

1000

0%

25%

50%

75%

100%

125%

Highly-RichGas/

Condensate

Highly-RichGas

Rich Gas Dry Gas

Total 3PLlocations

RO

R

Locations ROR

MARCELLUS SSL WELL ECONOMICS(1)

$0.00 $0.00 $0.00 $0.29$0.83 $1.15

$2.47 $2.50 $2.57 $2.60$2.94 $3.20

$3.27 $3.50 $3.62 $3.65 $3.66 $3.70 $3.75 $3.81 $4.13 $4.25$5.05

$5.37

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

`

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

Large Inventory of Low Breakeven Price Projects(2)

1. Well economics based on 6/30/2014 strip pricing for natural gas, 6/30/2014 strip pricing for 2014-2016 and $90 flat thereafter for WTI oil, NGLs at 55% of oil price and applicable firm transportation costs. 2. Source: Credit Suisse report dated July 2014 – Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI.3. Calculated by Antero.

Current 3 Yr. NYMEX Strip - $4.02/MMBtu

708 Locations

1,467Locations405

Locations

882Locations

$ / M

MB

tu N

YMEX

(Gas

)

208Locations

11

UTICA WELL ECONOMICS(1)

204

113 88

208 222

32%

116% 171%

97%

60%0

50

100

150

200

250

0%

50%

100%

150%

200%

Condensate Highly-RichGas/

Condensate

Highly-RichGas

Rich Gas Dry Gas

Total 3P Locations

RO

R

Locations ROR

1,000

71% of Marcellus locations are processable (1100-plus Btu) 73% of Utica locations are processable (1100-plus Btu)

>2,780 Antero Liquids-Rich Locations

222Locations

2H 2014 / 2015Drilling Plan

LOWEST FINDING & DEVELOPMENT COSTAMONG U.S. PRODUCERS

12

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 recent 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

SFYATHL

EPEREXXSWN

PDCERRC

AR

-$2.00

-$1.50

-$1.00

-$0.50

$0.00

$0.502014 2015 2016Appalachian Basis to NYMEX(1)

Chicago

CGTLA

TCO

TETCO M2

Dom South

Leidy

INTEGRATED FIRM PROCESSING & GAS TAKEAWAY

Infrastructure and commitments in place to handle strong production growth

Portfolio of firm gas takeaway and sales and West Virginia and Ohio location minimizes basis risk

13

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

(MM

cf/d

)

Sherwood 1 Sherwood 2 Sherwood 3 Sherwood 4 Sherwood 5

Sherwood 6

Seneca 1 Seneca 2 Seneca 3 Seneca 4

Sherwood 7

Total Capacity 1,950

Marcellus

Utica

Sherwood 1

Sherwood 2

Sherwood 3

Seneca 1Seneca 2

Seneca 3

Growing Firm Processing Capacity

Sherwood 5

Seneca 4

Sherwood 4

Sherwood 6

Antero Long Term Firm Gas Takeaway

1. Current basis data from Wells Fargo daily indications and various private quotes.

2Q 2014 % of Production Sold

Chicago 1%

NYMEX 13%

TCO 44%

TETCO M2 6%

Dom South 36%

Sherwood 7

Primary ARSales Points

14

• Rover Pipeline – Option to Acquire Non-Op Equity Interest– Antero Midstream has the option to acquire up to a

20% interest in a new 2.2 Bcf/d, 400-mile pipeline to be constructed by Energy Transfer

– Secured 800 MMcf/d of firm transport capacity

– Connects Antero Marcellus and Utica production to ANR Gulf Coast capacity and Midwest capacity

• Regional Gathering System – Option to Acquire Non-Op Equity Interest– Antero Midstream has the option, until 6 months

after the completion of the new gathering system, to acquire up to a 15% interest in the system

– Secured 1.1 Bcf/d of firm gathering capacity

– Connects Antero Marcellus production to Tennessee Gulf Coast capacity and additional Atlantic Seaboard capacity

Rover PipelineOperator – Energy Transfer

Antero Midstream up to 20% Ownership2016 in-service

Regional Gathering PipelineOperator – TBA

Antero Midstream up to 15% Ownership4Q 2015 in-service

Potential Regional Pipeline Assets

CONNECTIVITY TO KEY PIPELINESENHANCES TAKEAWAY

Midwest 20%

2016 FirmTransportation(1)(2)

Gulf Coast48%

Appalachia32%

$0.14 $0.17 $0.23$0.36$0.11 $0.11

$0.12

$0.14

$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 – 3.4 Bcf/dAverage All-in FT Cost $0.50/MMBtu

+ $0.22/MMBtu

15

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 $0.15 per MMBtu compared to 2014 basis and by $0.15 per MMBtu applying 2014 portfolio to 2016 basis prices(3) – while significantly reducing Appalachian basis exposure

Utilized portion included in cash production

expense(fixed cost)

1. Assumes full utilization of firm transportation capacity.2. Represents accessible firm transportation and sales agreements.3. Based on current strip pricing.

Included in cash production expense

(variable cost)$0.25 $0.28 $0.35

$0.50

2016 Basis(3)

TCO – $(0.49)/MMBtu DOM S – $(1.21)/MMBtu

2016 Basis(3)

Chicago – $(0.02)/MMBtu

2016 Basis(3)

CGTLA – $(0.09)/MMBtu

738 650 643 780 903 668

$4.91$4.80 $4.72

$4.34 $4.54 $4.41

$4.09 $3.99 $4.06 $4.18 $4.28 $4.36

$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 $/MMBtu

TCO9%

Dom South15%

CGTLA15%

NYMEX59%

Chicago2%

SIGNIFICANT LONG-TERM COMMODITY HEDGE POSITION

16

% HEDGE VOLUMES BY INDEX THROUGH 2019

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

NATURAL GAS HEDGE POSITION

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.

~$893 million mark-to-market unrealized gain based on current prices; additional hedge capacity remaining through 2019 1.5 Tcfe hedged from July 1, 2014 through year-end 2019 and 237 Bcf of TCO basis hedges from 2015 to 2017

Total $54.98 per Bbl53% of WTI

2Q 2014 REALIZATIONS

Ethane

Propane

Iso Butane

Normal Butane

Natural Gasoline

2Q 2014 NGL Y-GRADE (C3+) REALIZATIONS

2Q 2014 NATURAL GAS REALIZATIONS ($/MCF)

$27.70

$5.67

$7.84

$13.20

$0.57

171. Gulf Coast differential represents contractual deduct to NYMEX-based sales.2. Includes firm sales.3. Includes natural gas hedges.4. Source: Howard Weil Research Report dated August 26, 2014.

Region2Q 2014 % Sales

Average NYMEX Price

AverageDifferential(2)

AverageBTU Upgrade

Hedge Effect

Average 2Q 2014Realized Gas Price(3)

Average Premium/Discount

Appalachia 86% $4.67 $(0.62) $0.38 $0.09 $4.52 ($0.15)Gulf Coast(1) 13% $4.67 $(0.25) $0.40 $(0.28) $4.54 $(0.13)Chicago 1% $4.67 $(0.19) $0.46 - $4.94 $0.27Total Wtd. Avg. 100% $4.67 $(0.56) $0.38 $0.04 $4.52 ($0.15)

2Q 2014 NATURAL GAS REALIZATIONS (4)

$0.18 – discount to NYMEX

% of C3+ BblEthane 1%Propane 50%Iso Butane 10%Normal Butane 14%Natural Gasoline 25%

+

$4.52

$4.10$3.88 $3.76 $3.71 $3.68 $3.60

$3.47

$4.49 $4.23

$4.09 $3.89

$4.09 $4.12 $4.43

$3.78

$2.00

$3.00

$4.00

$5.00

AR CNX RRC EQT ECR RICE GPOR COG

After Hedges Before Hedges

($/Mcf)

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

AR 2Q 2014 RRC 2Q 2014 EQT 2Q 2014 COG 2Q 2014

$/M

cfe

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

$5.35

EBITDAX$2.96/Mcfe

EBITDAX $3.29/Mcfe

$4.11$4.33$4.49

F&D$0.58/Mcfe

F&D$0.74/Mcfe

EBITDAX$2.34/Mcfe

EBITDAX $2.91/Mcfe F&D

$0.95/Mcfe F&D$0.81/Mcfe

Peer 1 Peer 2 Peer 3Antero(2)

181. Includes realized hedge gains and losses only; unrealized hedge gains and losses excluded. 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).

2. Price realization includes $0.04 of gathering and processing revenues.

BIGGEST “BANG FOR THE BUCK” Antero has the highest price realizations and EBITDAX per Mcfe combined with the lowest all-in F&D cost among its large cap

Appalachian peers based on 2Q 2014 results− Driven by liquids-rich production, firm takeaway to favorable pricing indices and low development cost per unit

2Q 2014 Price Realization & EBITDAX Per Unit vs F&D(1)

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

AR Peer 1 Peer 2 Peer 3

19

2Q 2014 Price Realizations ($/Mcfe)(2)

2014 Projected Growth (%)(1)

1. Based on midpoint of 2014 production guidance for Antero Resources and large capitalization Appalachian peers (Cabot Oil & Gas, EQT Corp and Range Resources).2. Based on 6/30/2014 10-Qs for Antero and peers.3. Based on 2011-2013 average proved developed F&D cost per 12/31/2013 10-Ks for Antero and peers; definition included on page 36.4. Based on 2011-2013 average growth adjusted recycle ratio for Antero and peers; definition included on page 36.

POSITIONED FOR GROWTH & PROFITABILITY

2Q 2014 EBITDAX/Mcfe(2)

3-Year PD F&D ($/Mcfe)(3)

3-Year Growth-Adjusted Recycle Ratio(4)

$0.00$0.20$0.40$0.60$0.80$1.00$1.20$1.40$1.60$1.80


$1.15

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00


$5.35

Highest Growth & Highest Margin Large Cap E&P Focused On Marcellus & Utica

$3.2992%

0%10%20%30%40%50%60%70%80%90%

100%


5.2x

0.0x

1.0x

2.0x

3.0x

4.0x

5.0x

6.0x


ASSET OVERVIEW

20

WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECT

100% operated 378,000 net acres in

Southwestern Core– 50% HBP with additional

23% not expiring for 5+ years 303 horizontal wells completed

and online– Laterals average 7,300’– 100% drilling success rate

Net production of 770 MMcfe/d in 2Q 2014, including 12,600 Bbl/d of liquids

3,057 future drilling locations in the Marcellus (71% are processable)

Operating 15 drilling rigs including 5 intermediate rigs

26.4 Tcfe of net 3P (18% liquids), includes 8.5 Tcfe of proved reserves (assuming ethane rejection)

21

Highly-Rich Gas113,000 Net Acres

826 Gross Locations

Rich Gas91,000 Net Acres

641 Gross Locations

Dry Gas104,000 Net Acres

882 Gross Locations

Highly-Rich/Condensate70,000 Net Acres

708 Gross Locations

HEFLIN UNIT30-Day Rate

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

EQT PENN 15 UNIT30-Day Rate

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

CONSTABLE UNIT30-Day Rate


142 Horizontals Completed30-Day Rate8.1 MMcf/d

6,915’ average lateral length

PRUNTY UNIT30-Day Rate

1H: 11.1 MMcfe/d(27% liquids)

HINTERER UNIT30-Day Rate


RUTH UNIT30-Day Rate


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 held. Note: Rates in ethane rejection.

DOTSON UNIT30-Day Rate

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

(26% liquids)

MASH UNIT30-Day Rate

1H: 14.9 MMcfe/d2H: 16.5 MMcfe/d

(28% liquids)

NERO UNIT30-Day Rate


BLANCHE UNIT30-Day Rate


BEE LEWIS PAD30-Day Rate

4-well combined 30-Day Rate of

67 MMcfe/d (26% liquids)

MARCELLUS DEVELOPMENT PROGRAM –TARGET THE LIQUIDS Antero continues to focus its development program further west to drill liquids-rich locations with higher rates of return

− From 2013 to 2015 Antero will increase the average BTU associated with wells drilled and completed from 1160 to 1245

22

2013 Program1160 avg BTU per well



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 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

0

5

10

15

20

MM

cf/d

Production From All Wells 2009 - 2014

Antero has nearly five years of production history to support its Non-SSL type curve Antero’s SSL type curve is 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 ~ 7,300’ average since inception− Drives down cost per 1,000’ of lateral resulting in best in class development costs

ANTERO’S MARCELLUS SHALE TYPE CURVE

1. 200 Antero Marcellus Non-SSL wells normalized to time zero, production for each well normalized to 7,000’ lateral length.2. 103 Antero Marcellus SSL wells normalized to time zero, production for each well normalized to 7,000’ lateral length.

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

23

EURs Increase With Lateral Length Well Cost / 1,000’ Decreases with Lateral Length Wellhead 30-day Rates - 295 Wells

2009-2012 – 7.9 MMcf/d

(2)

2013 – 8.4 MMcf/d2014 YTD – 11.7 MMcf/d

Actual Rates24-Hour

Peak Rate30-Day

Avg. Rate90-Day

Avg. Rate180-Day

Avg. RateOne-Year Avg. Rate

Two-Year Avg. Rate

Three-YearAvg. Rate

Wellhead Gas (MMcf/d) 15.1 9.0 6.7 5.5 4.2 3.1 2.4# of Antero Wells 303 295 268 245 190 95 49

$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

5

10

15

20

25

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

EUR

, BC

F

Lateral Length, ft

0%

20%

40%

60%

80%

100%

120%

140%

160%

180%

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

Pre-

Tax

RO

R%

NYMEX Gas PriceHighly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas

MARCELLUS ROR% AND GAS PRICE SENSITIVITY

241. Assumes 6/30/2014 strip pricing, market differentials and relevant transportation cost.

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 regime Assumes 6/30/2014 strip pricing for 2014-2016 and $90/Bbl WTI thereafter and NGL price of 55% of WTI

NYMEX Price Sensitivity(1)

ROR% at 3-Year NYMEX Gas Strip

Highly-Rich Gas/Condensate: 109%

Highly-Rich Gas: 67%

Rich Gas: 30%

Dry Gas: 20%

708 Locations

826 Locations

641 Locations

882 Locations

Antero Rigs Employed


MARCELLUS SINGLE WELL ECONOMICS – IN ETHANE REJECTION

25

DRY GAS LOCATIONS RICH GAS LOCATIONS

HIGHLY RICH GAS

LOCATIONS

Assumptions Natural Gas – 6/30/2014 strip Oil – 6/30/2014 strip for 2014-2016,

$90 flat thereafter NGLs – 55% of Oil Price

NYMEX($/MMBtu)

WTI($/Bbl)

C3+ NGL(2)

($/Bbl)

2014 $4.41 $103 $57

2015 $4.18 $97 $53

2016 $4.20 $91 $51

2017 $4.32 $90 $50

2018+ $4.51 $90 $50

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): 16.1 14.7 13.0 11.9EUR (MMBoe): 2.7 2.4 2.2 2.0% Liquids: 33% 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 $9.5Bcfe/1,000’: 2.3 2.1 1.9 1.7

Pre-Tax NPV10 ($MM): $20.3 $14.4 $6.2 $3.4Pre-Tax ROR: 109% 67% 30% 20%Net F&D ($/Mcfe): $0.69 $0.76 $0.86 $0.94Payout (Years): 1.0 1.3 2.7 4.0

Gross 3P Locations(3): 708 826 641 882

1. Well economics are based on 6/30/2014 strip differential pricing and related transportation costs. Well economics includes gathering, compression and processing fees. 2. Pricing for a 1225 BTU y-grade ethane rejection barrel.3. Undeveloped well locations as of 6/30/2014.

708826

641

882

109%

67%

30% 20% 0

200

400

600

800

1,000

0%

25%

50%

75%

100%

125%

Highly-Rich Gas/Condensate

Highly-Rich Gas Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

R Locations ROR2H 2014 /

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.

100% operated

120,000 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

37 operated horizontal wells completed and online in Antero core areas− 100% drilling success rate

Net production of 121 MMcfe/d in 2Q 2014 including 7,600 Bbl/d of liquids− Seneca 3 processing plant online in early

3Q 2014− The first 120 MMcf/d compressor station

went into service in late January, the second 120 MMcf/d station in late March and a third 100 MMcf/d station in early July

835 future gross drilling locations

Operating 7 rigs including 2 intermediate rigs

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

26

Utica Shale Industry Activity(1)

CadizProcessing

Plant

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 OilREXX

24-Hour IPGuernsey 1H, 2H,

Noble 1HAverage 7.9 MMcf/d + 1,192 Bbl/d NGL

+ 502 Bbl/d Oil

NORMAN UNIT30-Day Rate

2 wells average17.2 MMcfe/d (17% liquids)

YONTZ UNIT 1H30-Day Rate 17.0 MMcfe/d(14% liquids)

RUBEL UNIT30-Day Rate

3 wells average17.3 MMcfe/d(22% 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/Cond17,000 Net Acres

113 Gross Locations

Highly-Rich Gas15,000 Net Acres

88 Gross Locations

Rich Gas26,000 Net Acres

208 Gross Locations

Dry Gas29,000 Net Acres

222 Gross Locations

COAL UNIT30-Day Rate

2 wells average16.3 MMcfe/d (50% liquids)

SCHEETZ UNIT30-Day Rate


NEUHART UNIT 3H30-Day Rate16.4 MMcfe/d(56% liquids)

Condensate33,000 Net Acres

204 Gross Locations

DOLLISON UNIT 1H30-Day Rate19.0 MMcfe/d(36% liquids)

MYRON UNIT 1H30-Day Rate26.0 MMcfe/d(50% liquids)

SenecaProcessing

Plant

LAW UNIT30-Day Rate


UTICA DEVELOPMENT PROGRAM –TARGET THE RICH GAS REGIMES In the second half of 2014 and all of 2015

Antero has shifted its development plan to focus more heavily in the rich gas regimes in the Utica Shale play

At current pricing, the rich gas regimes offer the highest rates of return (100%+) in the Utica play

First 2014 Highly-Rich Gas pad (three-well Carpenter pad) recently placed on line with an average 30-day rate of approximately 61 MMcfe/d in ethane rejection (20% liquids) – 20.3 MMcfe/d average 30-day rate per well

27




0%

50%

100%

150%

200%

250%

300%

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

Pre-

Tax

RO

R%

NYMEX Gas PriceCondensate Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas Antero Rigs Employed

UTICA ROR% AND GAS PRICE SENSITIVITY

28

NYMEX Price Sensitivity(1)

88 Locations

ROR% at 3-Year NYMEX Gas Strip

Condensate: 32%

Highly-Rich Gas/Condensate: 116%

Highly-Rich Gas: 171%

Rich Gas: 97%

Dry Gas: 60%

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 regime Assumes 6/30/2014 strip pricing for 2014-2016 and $90/Bbl WTI thereafter and NGL price of 55% of WTI

1. Assumes 6/30/2014 strip pricing, market differentials and relevant transportation cost.

208 Locations

113 Locations

222 Locations

204 Locations


UTICA SINGLE WELL ECONOMICS – IN ETHANE REJECTION

29

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): 7.4 13.3 19.9 18.5 16.6EUR (MMBoe): 1.2 2.2 3.3 3.1 2.8% Liquids 35% 26% 21% 14% 0%Lateral Length (ft): 7,000 7,000 7,000 7,000 7,000Stage Length (ft): 240 240 240 240 240Well Cost ($MM): $11.0 $11.0 $11.0 $11.0 $11.0Bcfe/1,000’: 1.1 1.9 2.8 2.6 2.4

Pre-Tax NPV10 ($MM): $6.3 $17.1 $25.6 $18.3 $12.6Pre-Tax ROR: 32% 116% 171% 97% 60%Net F&D ($/Mcfe): $1.83 $1.02 $0.68 $0.73 $0.82Payout (Years): 2.2 0.8 0.7 0.9 1.2

Gross 3P Locations(3): 204 113 88 208 222

1. Well economics are based on 6/30/2014 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 6/30/2014. 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 $4.41 $103 $57

2015 $4.18 $97 $53

2016 $4.20 $91 $51

2017 $4.32 $90 $50

2018+ $4.51 $90 $50

204

113 88

208 222

32%

116% 171%

97%60%

0

50

100

150

200

250

0%

50%

100%

150%

200%

Condensate Highly-Rich Gas/Condensate

Highly-Rich Gas Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

RLocations ROR

Assumptions Natural Gas – 6/30/2014 strip Oil – 6/30/2014 strip for 2014-2016,

$90 flat thereafter NGLs – 55% of Oil Price


LARGE UTICA SHALE DRY GAS POSITION

30

Antero has 175,000 net acres of exposure to Utica dry gas play− 29,000 net acres in Ohio with net 3P reserves of 1.9 Tcf as of

6/30/2014− 146,000 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)

− 1,359 locations underlying current Marcellus Shale leasehold in West Virginia and Pennsylvania as of 6/30/2014

Expect to drill and complete a Utica Shale dry gas well in West Virginia in 2015

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 Operator IP(MMcf/d)

Lateral Length (Ft)

Bigfoot 9H Rice Energy 41.7 6,957

Stalder #3UH Magnum Hunter 32.5 5,050

Irons #1-4H Gulfport 30.3 5,714

Tippens #6H Eclipse 23.2 5,858

Conner 6H Chevron 25.0 6,451

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 HunterUtica Well

Drilling

RangeUtica Well

Drilling

ChevronConner 6H


GastarUtica Well

Drilling

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

RiceBigfoot 9H


Utica Shale Dry GasWV/PA

Net Resource9.5 Tcf

1,359 Gross Locations146,000 Net Acres

Utica Shale Dry GasOhio

3P Reserves1.9 Tcf

222 Gross Locations29,000 Net Acres

Utica Shale Dry GasTotal OH/WV/PA

Net Resource11.4 Tcf

1,581 Gross Locations175,000 Net Acres

Stone EnergyUtica Well

Drilling

ChesapeakeUtica Well

Drilling

Keys to Execution

Local Presence

Antero has more than 4,500 contract personnel working full-time for Antero in West Virginia. 79% of these contract personnel are West Virginia residents.

Land office in Ellenboro, WV District office in Bridgeport, WV 169 of Antero’s 377 employees are located in West Virginia and Ohio

Safety & Environmental

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

31 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 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 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 & FracEquipment

10 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 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

31

ANTERO KEY ATTRIBUTES

32

498,000 Net Acres in the Core Marcellus and Utica Shales

“Triple Digit” Historical Production and Reserve Growth

Low Cost Leader / High Return Projects

Leading Appalachian Processing and Takeaway Portfolio

Clean Balance Sheet Supports High Growth Story

“Forward Thinking” Management Team with a History of Success

33

APPENDIX

33

CAPITALIZATIONPRO FORMA CAPITALIZATION

34

($ in millions) 6/30/2014Pro Forma $500MM Offering(4)

6/30/2014Cash $19 $19

Senior Secured Revolving Credit Facility 1,240 7446.00% Senior Notes Due 2020 525 5255.375% Senior Notes Due 2021 1,000 1,0005.125% Senior Notes Due 2022 600 1,100Net Unamortized Premium 6 8Total Debt $3,371 $3,378Net Debt $3,352 $3,358Shareholders' Equity $3,523 $3,523Net Book Capitalization $6,875 $6,882

Enterprise Value(1) $17,898 $17,905

Financial & Operating StatisticsLTM EBITDAX $938 $938LQA EBITDAX $1,065 $1,065LTM Interest Expense(2) $135 $151Proved 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 3.6x 3.6x

Net Debt / LQA EBITDAX 3.1x 3.2xLTM EBITDAX / Interest Expense 7.0x 6.2xNet Debt / Net Book Capitalization 48.7% 48.8%Net Debt / Proved Developed Reserves ($/Mcfe) $1.21 $1.21Net Debt / Proved Reserves ($/Mcfe) $0.37 $0.37

LiquidityCredit Facility Commitments(3) $2,500 $2,500Less: Borrowings (1,240) (744)Less: Letters of Credit (237) (237)Plus: Cash 19 19

Liquidity (Credit Facility + Cash) $1,042 $1,538

1. Equity valuation based on 262.0 million shares outstanding and a share price of $55.51 as of 9/4/2014. Enterprise value includes net debt.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 9/30/2013 with residual cash used to repay bank debt. Includes further $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.

3. Lender commitments under the facility increased to $2.5 billion from $2.0 billion on 7/28/2014; commitments can be expanded to the full $3.0 billion borrowing base upon bank approval.4. Based on $500 million 5.125% Senior Notes add-on priced on 9/4/2014 at 100.5 net of fees; net proceeds used to repay $496 million of bank debt..

ANTERO – 2014 GUIDANCE

35

Key Variable 2014 Guidance Range

Natural Gas Realized Price Differential to NYMEX ($/Mcf)(2) $(0.15) – $(0.25)

Oil Realized Price Differential to WTI ($/Bbl) $(10.00) – $(12.00)

NGL Realized Price (% of WTI) 53% – 57%

Net Production (MMcfe/d) 990 – 1,010

Net Natural Gas Production (MMcf/d) 840 – 850

Net Liquids Production (Bbl/d) 25,000 – 26,000

Cash Production Expense ($/Mcfe)(3) $1.50 – $1.60

Marketing Expense, Net ($/Mcfe) $0.10 – $0.20

G&A Expense ($/Mcfe) $0.25 - $0.30

Total Wells Spud 215

Capital Expenditure ($MM)

Drilling & Completion $2,400

Midstream $850

Land $450

Total Capex ($MM) $3,700

1. Financial assumptions per Company press release dated 8/26/2014.2. Antero’s processed tailgate and unprocessed dry gas production is greater than 1000 BTU on average.3. Includes lease operating expenses, gathering, compression and transportation expenses and production taxes.

Key 2014 Operating & Financial Assumptions(1)

3-Year Average Growth – Adjusted Recycle Ratio through 2013

0.0x

2.0x

4.0x

6.0x5.2x

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

36

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

Note: * Wells on restricted rate program.1. Gas Equivalent Rate = Shrunk Gas + (NGL + Condensate) converted at 6:1.

ANTERO UTICA SHALE WELLS – 30-DAY RATES

37

Antero’s wells produced against 1,100 psi line pressure until late January 2014 due to lack of compression facilities− First 120 MMcf/d compressor station started up in late January 2014, a second 120 MMcf/d station was placed

online in late March 2014 and a third 100 MMcf/d station was placed online in early July 201430‐Day Rates ‐ Antero Core Area Lateral

Well Gas Eq. Rate(1) Wellhead Gas Shrunk Gas NGL Condensate % Total Estimated LengthName County (MMcfe/d) (MMcf/d) (MMcf/d) (Bbl/d) (Bbl/d) Liquids BTU (Feet)

CondensateMyron 1H Noble 26.0 14.1 13.0 765 1,401 50% 1265 11,690Scheetz 3H Noble 19.5 10.1 9.3 605 1,105 53% 1290 8,337Law 1H Noble 16.5 9.4 8.7 511 780 47% 1260 5,571Coal 2H Noble 16.4 8.8 8.1 492 885 51% 1278 8,036Neuhart 3H Noble 16.4 8.0 7.3 476 1,040 56% 1291 7,425Coal 3H Noble 16.2 8.8 8.1 491 872 50% 1278 7,768Schafer 2H * Noble 15.2 9.1 8.4 460 672 45% 1256 8,856Myron 2H Noble 14.9 7.9 7.3 426 849 51% 1265 10,783Law 2H Noble 14.8 8.4 7.8 456 722 48% 1260 6,445Myron 3H Noble 14.8 8.2 7.5 442 769 49% 1265 7,161Milligan 2H Noble 14.6 7.7 7.0 445 817 52% 1276 5,989Scheetz 2H Noble 13.6 6.9 6.3 413 789 53% 1290 6,197Milligan 3H Noble 12.9 7.6 7.0 444 552 46% 1276 5,267Vorhies 3H * Noble 12.7 7.3 6.8 371 613 46% 1270 8,993Schafer 1H * Noble 12.2 7.0 6.5 379 584 47% 1256 7,624Wayne 2H Noble 12.1 6.5 6.0 367 653 51% 1281 6,094Vorhies 2H * Noble 12.0 7.1 6.6 359 541 45% 1270 9,300Vorhies 1H * Noble 11.4 6.6 6.1 334 540 46% 1270 10,409Wayne 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 6,493Milligan 1H * Noble 9.1 4.6 4.2 269 538 53% 1276 6,436Miley 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

13.7 7.5 6.9 414 732 50% 1273 7,567

Highly‐Rich Gas / CondensateDollison 1H Noble 19.0 12.9 12.1 556 596 36% 1238 6,253Dollison 2H Noble 10.3 6.9 6.5 296 339 37% 1238 5,733Dollison 4H* Noble 9.7 6.5 6.1 282 310 37% 1238 6,753Dollison 3H* Noble 9.0 6.1 5.7 261 293 37% 1238 6,254

12.0 8.1 7.6 349 385 37% 1238 6,248

Highly‐Rich GasGary 2H Monroe 29.7 24.6 23.1 1,023 65 22% 1224 8,882Gary 3H Monroe 24.7 20.8 19.6 865 0 21% 1242 8,127Rubel 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 6,424Gary 1H Monroe 18.5 15.2 14.3 634 63 23% 1224 8,384Rubel 1H Monroe 14.0 11.5 10.8 501 28 23% 1231 6,554

20.8 17.3 16.3 712 44 22% 1226 7,490

Rich GasNorman 2H Monroe 17.9 15.6 14.8 502 0 17% 1168 5,901Yontz 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 5,498

17.1 15.0 14.4 451 1 16% 1172 5,505

Average ‐ Ethane Rejection




-

5.0

10.0

15.0

20.0

25.0

30.0

Gas Liquids 38

51% Avg. Liquids7,201’ Avg. Lateral

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

ANTERO UTICA SHALE WELLS – 30-DAY RATES

Outstanding 30-day average rates with high liquids content– Antero’s wells produced against 1,100 psi line pressure until late January 2014 due to lack of compression facilities– First 120 MMcf/d compressor station started up in late January 2014, a second 120 MMcf/d station was placed online in late

March 2014 and a third 100 MMcf/d station was placed online in early July 2014



16% Avg. Liquids5,505’ Avg.

Lateral

Type Curve Regimes (1)

1. Excludes wells under choke management program. 2. Normalized for 7,000’ lateral.3. In ethane rejection.

14.3 MMcfe/d 14.6 MMcfe/d

20.8 MMcfe/d

17.1 MMcfe/d

13.9 MMcfe/dNormalized(2)




Average 30-Day Production Rate(3)

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)

39

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

Gas $4.46

Gas$4.21

Gas$4.17

Gas$4.10

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

1050 BTU

$5.21

$6.63

$7.78

$4.46

1150 BTU 1250 BTU 1300 BTU

MARCELLUS SHALE RICH GAS –LIQUIDS AND PROCESSING UPGRADE

1. Based on current strip pricing.2. Assumes $4.25/MMBtu NYMEX, $90.00/Bbl WTI and current NGL spot prices. 0.900, 1.978 and 2.632 (ethane rejection) GPMs used, all processing costs, shrink and fuel included. No NYMEX basis

differential assumed.

Current – Ethane Rejection

(1075 BTU)8% shrink

(1107 BTU)11% shrink

(1117 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(1)

40

+$0.74Upgrade

+$2.17Upgrade

+$3.31Upgrade

Highly-Rich GasDry Gas

NGLs (C3+)$0.99

NGLs (C3+)$2.30

NGLs (C3+)$3.13

Condensate$0.16

Condensate$0.55

Highly-Rich/ CondensateRich Gas

-

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

41

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

POSITIVE RATINGS MOMENTUMMoody’s / S&P Historical 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

Moody's S&P

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

42

$744

$525

$1,000 $1,100

$0$200$400$600$800

$1,000$1,200$1,400

2014 2015 2016 2017 2018 2019 2020 2021 2022

($ in

Mill

ions

)PRO FORMA OFFERING – BALANCE SHEET POSITIONEDFOR LONG-TERM GROWTH

PRO FORMA DEBT MATURITY PROFILE (1)

PRO FORMA WEIGHTED AVERAGE INTEREST RATE AND MATURITY(1)

431. As at 6/30/2014, pro forma for $500MM Senior Notes 2022 offering.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 6/30/2014.

Senior Secured Revolving Credit Facility Senior Notes

($ in millions) As At Interest Current Maturity Maturity06/30/14 Rate Yield (2) (Years) (Date)

Senior Secured Revolving Credit Facility $744 2.030% (3) 2.030% (3) 4.8 May-196.0% Senior Notes due 2020 525 6.000% 4.462% 6.4 Dec-205.375% Senior Notes due 2021 1,000 5.375% 4.496% 7.3 Nov-215.125% Senior Notes due 2022 PF for Offering 1,100 5.125% 4.771% 8.4 Dec-22

Total Long-Term Debt $3,369

Weighted Average: 4.652% 4.036% 7.0 Jun-21

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 June 2021

Pro forma cost of debt below 4.7%, average debt maturity 7 years

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

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Over 2,780 Antero Drilling Locations

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

44

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

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 not 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

45