First Quarter 2016 Earnings Call Presentation April 28, 2016

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, 2015 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, 2015 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 Resources Corporation is denoted as “AR” and Antero Midstream Partners LP is denoted as “AM” in the presentation, which are their respective New York Stock Exchange ticker symbols.

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$0

$50

$100

$150

$200

$250

$300

$350

$MM

2

Hedging is a key component of Antero’s business model which includes development of a large, repeatable drilling inventory – Locks in higher returns in a low commodity price environment and reduces the amount of time for well payouts, thereby

enhancing liquidity Antero has realized $2.1 billion of gains on commodity hedges since 2009

– Gains realized in 28 of last 29 quarters, or 97% of the quarters since 2009 ● Based on Antero’s hedge position and strip pricing as of 3/31/2016, the unrealized commodity derivative value is $3.1 billion ● Significant additional hedge capacity remains under the credit facility hedging covenant for 2020 – 2022 period

Quarterly Realized Hedge Gains / (Losses)

Realized Hedge Gains Projected Hedge Gains

NYMEX Natural Gas Historical Spot Prices

($/MM

Btu)

NYMEX Natural Gas Futures Prices 03/31/16

3.6 Tcfe Hedged at average price of

$3.71/Mcfe through 2022

Average Hedge Prices ($/MMBtu)

$3.36

$3.91 $3.57

$3.91 $3.70 $3.66

$3.24

$3.1 Billion in Projected Hedge

Gains Through 2022 Realized $2.1 Billion in Hedge Gains

Since 2009

HEDGE STRATEGY PRODUCES CONSISTENT RESULTS AND STABILITY

(1)

1. Represents average hedge price for nine months ending 12/31/2016.

Pre PostIn-Service In-Service

Projected 2016 Average Volume (BBtu/d)DOMS Priced Sales 329 0TETCO M2 Priced Sales 321 0TCO Priced Sales 0 54Firm Sales (TCO / Nymex) 0 595

Total 650 650

2016 Strip Pricing ($/MMBtu)DOMS (1) $1.31 N/ATETCO M2 (1) $1.29 N/ATCO (1) N/A $2.04Firm Sales (TCO / Nymex) (2) N/A $1.94

Annual Revenue ($MM)DOMS $157.1 $0.0TETCO M2 151.7 0.0TCO Pool Sales (1) 0.0 40.6Firm Sales (TCO / Nymex) (2) 0.0 422.5

$308.7 $463.1

Incremental Revenue $154.3

Less: Incremental Firm Transport Costs: (28.7)

Projected Incremental EBITDA $125.6

PROJECTED INCREMENTAL EBITDA FROM STONEWALL

1. 2016 Strip pricing as of March 31, 2016. 2. Blended price based on contracted firm sales volumes with third parties.

Existing TCO capacity of 582 MMcf/d with additional 1.1 Bcf/d of Stonewall transportation and sales has

eliminated all Marcellus swing gas sales to Dominion South and TETCO M2 thus far in 2016 and

is expected for the full year of 2016

3

2016 DOMS Strip: $1.31Variance to Nymex ($0.87)Variance to TCO ($0.73)

2016 TETCO M2 Strip: $1.29Variance to Nymex ($0.88)Variance to TCO ($0.75)

$2.03

AR P1 P5 P3 P2 P4

$355

AR P5 P1 P3 P2 P4

3Q 2015

$1.97

AR P3 P5 P4 P2 P1

$2.03

AR P3 P2 P1 P5 P4

$2.56

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

P2 AR P5 P3 P4 P1

$308

AR P5 P3 P2 P4 P1

$1.90

AR P3 P4 P2 P5 P1

$291

P5 AR P3 P2 P4 P1

$269

P5 AR P2 P3 P4 P1

$355

$0

$100

$200

$300

$400

$500

P5 P2 AR P4 P3 P1

HIGHEST EBITDAX & MARGINS AMONG PEERS

Quarterly Appalachian Peer Group EBITDAX Margin ($/Mcfe)(1)

Quarterly Appalachian Peer Group EBITDAX ($MM)(1)

1Q 2015 2Q 2015

Note: AR and EQT EBITDAX margin excludes EBITDA from midstream MLP associated with noncontrolling interest. AR consolidated EBITDAX margin for 1Q 2016 was $2.22/Mcfe. CNX excludes EBITDAX contribution from coal operations. 1. Source: Public data from form 10-Qs and 10-Ks. Peers include COG, CNX, EQT , RRC and SWN.

4Q 2015 1Q 2016 1Q 2015 2Q 2015

AR Peer Group Ranking – Top Tier #2 #1 #1 #1 #1

AR Peer Group Ranking – Improving Over Time #3 #2 #2 #1 #1

Y-O-Y AR: ↔ $0MM Peer Avg: $170MM NYMEX Gas: 30% NYMEX Oil: 32%

Y-O-Y AR: 21% Peer Avg: 46% NYMEX Gas: 30% NYMEX Oil: 32%

4

3Q 2015

AR has ranked first for both the highest EBITDAX and EBITDAX margin among Appalachian peers for the second straight quarter

4Q 2015 1Q 2016

TBA

TBA

TBA

TBA

TBA

TBA

3.7x

4.9x

0.6x

1.5x

3.0x 3.4x

3.8x 4.6x

1.3x

2.4x

5.6x

0.0x

1.0x

2.0x

3.0x

4.0x

5.0x

6.0x

AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5

YE 2015 Leverage YE 2016E Leverage

17% 15% 19%

3% 2%

(11%)

12%

(6%) (5%)

(27%) (44%) -50%

-40%

-30%

-20%

-10%

0%

10%

20%

AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5

2016E Production Growth2016E EBITDAX Growth

CONTINUED MEASURED GROWTH

5

2015 vs. 2016E Year-End Net Debt / LTM EBITDAX(1),(2)

NOTE: Peers include CNX, COG, EQT, RRC and SWN. 1. 2015 and 2016E production and EBITDAX per Bloomberg Street Consensus estimates. Peer 5 2016E production and EBITDAX per company issued press release. 2. 2016E Debt to EBITDAX assumes year-end 2016E debt divided by 2016E EBITDAX. 2016E debt calculated as 2015 YE debt, less free cash flow. Free cash flow is equal to 2016E EBITDAX, less 2016E

interest expense per Bloomberg consensus estimates, less 2016 capital spending guidance per company press releases. 3. AR pro forma for secondary offering of 8.0 million AM units on 3/24/2016 for net proceeds of $178 million.

9.8x

Antero continues to grow its production and cash flow through the commodity price downturn while also maintaining prudent leverage metrics

2016E EBITDAX and Production Growth(1)

Antero is the only one of its Appalachian peers that is growing cash

flow in line with production

growth (66%)

(3)

6 1. Revenues represent annual mark-to-market value based on 3/31/2016 strip pricing, including 1Q 2016 actual hedge gain of $324 million. 2. Consensus EBITDAX as of 3/31/2016. 3. Includes targeted drilling and completion cost improvements.

Antero can achieve 17% year-over-year net production growth for 2016 by spending only $675 million, or approximately $500 million less than the $1.2 billion of expected hedge revenues for the year(1)

Incremental growth capital of $625 million in 2016 positions Antero to achieve its 20% year-over-year targeted net production growth in 2017, while only having to spend $875 million in 2017

LOW MAINTENANCE CAPITAL PROVIDES FLEXIBILITY AND UPSIDE

Maintenance Capital $275

Maintenance Capital $500

2016 Growth Capital $400

2017 Growth Capital $375

2017 Growth Capital $625

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

2016 2017

$1.3 Bn D&C Budget

0% Y-O-Y Growth of

1,493 MMcfe/d

17% Y-O-Y Growth

Contributes to 20% Y-O-Y Growth

Target for 2017

0% Y-O-Y Growth of

1,750 MMcfe/d

20% Y-O-Y Growth Target for $875 MM

Capex in 2017

Hedge Revenues

$1,156MM(1)

Hedge Revenues $572MM(1)

$MM 2016 2017

Prior year DUCs completed 16 70 D&C Capital – DUCs ($MM) $125 $425

Driven by the DUC inventory, continued capital efficiency and volumes sold forward at attractive prices, Antero is positioned to achieve its 2016 guidance and 2017 production target with modest outspend

2018 Growth Capital

TBD

(3)

Consensus EBITDAX(2)

Consensus EBITDAX(2)

$3.7 $11.2 $13.9

$20.4 $26.7

$3.1

$2.5 $0.9

($0.3) ($1.6)

$2.4

$2.4 $2.4 $2.4

$2.4

$9.2 $16.1 $17.3

$22.5

$27.6

($5.0)$0.0$5.0

$10.0$15.0$20.0$25.0$30.0$35.0$40.0$45.0

SEC Pricing 12/31/2015 Strip $60 Oil $67.50 Oil $75 Oil

$3.50 Gas $4.00 Gas $4.50 Gas

AR Ownership in AM shares ($B)

Hedge Value Pre-Tax PV-10 ($B)

3P Reserves Pre-Tax PV-10 ($B)

FLEXIBILITY & UPSIDE

7

As the most active operator in Appalachia, Antero has kept its workforce intact while also preserving the ability to accelerate efficiently when commodity prices recover

Accelerated development is further enhanced by Antero’s ability to flow incremental production to the most favorable price indices using Antero’s firm transport portfolio

Despite its large hedge position, Antero has tremendous leverage to natural gas and NGL prices due to scale of its 3P reserves and development infrastructure

Net 3P Reserve/Hedge pre-tax PV-10 plus AM ownership less net debt, Per Share(3)

$45 $64

$83 Increase in pre-tax

PV10 value does not include the addition of locations; represents upside in prices only on 12/31/15 locations

Note: Assumes NGL prices equal to 37.5% of WTI for 2016 and 50% of WTI thereafter. All PV-10 values are on a pre-tax basis. 1. Total 3P locations of 3,719 less 110 planned completions in 2016. 2. Strip pricing as of December 31, 2015 for each of the first ten years and flat thereafter.

$54 Oil; $3.23 Gas

Increase in reserve pre-tax PV-10 is well in excess of hedge PV-10 lost at higher

prices

3P Reserve/Hedge Pre-Tax PV-10 Upside Value(3)

Substantial Inventory Optionality to Accelerate Development

$41

Remaining Undeveloped

3P Locations(1)

3,609 85%

Producing Wells at YE 2015

540 wells producing 1.5 Bcfe/d net (13%)

2016E Well Completions

110 (2%)

3. PV-10 of 3P reserves and hedges less $4.7 billion of net debt as of 3/31/2016, plus market value of 108.9 million AM units owned by AR (as of 3/31/2016).

(2)

0

500

1,000

1,500

2,000

2,500

0

5

10

15

20

25

2013 2014 2015 2016E 2017E

Average Rigs

Ability to triple rig count from 2016 levels, as

demonstrated by historical rig utilization

# of Antero Rigs MMcfe/d

AR Net Production

2016 Guidance 2017 Target

($Bn

)

Old Borrowing Base $4,500 $4,000 $3,400 $3,250 $3,000 $4,000 $2,000 $2,000 $1,525 $2,600 $1,400 $1,750 $1,000

New Borrowing Base $4,500 $4,000 $3,200 $2,800 $3,000 $2,750 $2,000 $1,250 $1,150 $1,050 $1,050 $1,025 $1,000

Result -- -- ($200) ($450) -- ($1,250) -- ($750) ($375) ($1,550) ($350) ($725) -- Average

% change -- -- (6%) (14%) -- (31%) -- (38%) (25%) (60%) (25%) (41%) -- (30%)

SPRING 2016 BORROWING BASE REAFFIRMED

Borrowing Base Actions

(1) Note: Represents Spring 2016 borrowing base actions for all public companies with a borrowing base greater than $1 billion prior to the redetermination.

Antero’s $4.5 Billion borrowing base was reaffirmed by its lender group, representing one of only five public E&P companies that did not receive a reduction in its borrowing base thus far in the redetermination season (1)

– Driven by significant PDP reserve growth and increase in value of hedge position

8

$2,800 $3,000

$2,000

$1,150 $1,050 $1,050 $1,025

$4,000

$4,500

$4,000

$3,200

$3,250

$2,000

$1,525

$2,600

$1,400

$1,000

AR CHK COG CXO RRC WLL CNX SM OAS DNR EGN WPX MRD$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

$4,500

Bor

row

ing

Bas

e A

mou

nt ($

mm

)

$3,400

$1,250 Antero was one of only five public E&P companies (one of three

Appalachia operators) that did not receive a reduction in their

borrowing base from March’s redetermination process

Red New Borrowing Base

Borrowing Base Affirmed

$450 $1,250

$350

$ Amount of Reduction

$725 $1,550 $375

$750

$200 $2,750

$1,750

Appalachian Company

PROVEN TRACK RECORD OF WELL COST REDUCTIONS

9

Marcellus Well Cost Reductions for a 9,000’ Lateral ($MM)(1)

NOTE: Based on statistics for drilled wells within each respective period. 1. Based on 200 ft. stage spacing. 2. Based on 175 ft. stage spacing.

$5.3 $4.6 $5.3 $4.7 $4.7 $4.7

$8.7 $7.8 $7.6 $7.1 $7.1 $5.6

$-

$2

$4

$6

$8

$10

$12

$14

$16

2014 Q4 2015 Q1 2015 Q2 2015 Q3 2015 Q4 2016 Q1

$MM

DRILLING AFE COMPLETION AFE$14.0

$12.4 $12.9 $11.8 $11.8

29% Reduction in Utica well costs since

Q4 2014

Utica Well Cost Reductions for a 9,000’ Lateral ($MM)(2)

$4.0 $3.8 $3.4 $3.2 $3.2 $3.1

$8.3 $7.3 $7.4 $7.0 $7.0

$5.4

$-

$2

$4

$6

$8

$10

$12

$14

2014 Q4 2015 Q1 2015 Q2 2015 Q3 2015 Q4 2016 Q1

$MM

DRILLING AFE COMPLETION AFE$12.3

$11.1 $10.8 $10.2 $10.2 $0.95 / 1,000’ 32% Reduction in

Marcellus well costs since Q4 2014

17% Reduction vs. well costs assumed in YE

2015 reserves

13% Reduction vs. well costs assumed in YE

2015 reserves

$1.14 / 1,000’

Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016

Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016

COST COST

$8.5

$10.3

Marcellus Shale Utica Shale Ohio

10

Operating Highlights Top 10 best drilling footage days in

Marcellus since 2009 have all occurred in 2016, including 5,291’ drilled in 24 hours in West Virginia on the Charleston 3H

Recently drilled and cased longest lateral in company history at 14,024 feet

Increased sand placement during completions to 98% in Q1 2016

Stayed within targeted zone for 98% of lateral length drilled in Q1 2016

Utilizing new floating casing procedure, reducing casing run time by over 12 hours

Increased proppant loading and shorter stages in certain areas of the Marcellus

1. Based on statistics for wells completed within each respective period. 2. Year end 2016 forecast.

CONTINUOUS OPERATING IMPROVEMENT

(2)

Utica Marcellus2014 2015 Q1 2016 Q1 2016 vs. 2014 2014 2015 Q1 2016 Q1 2016 vs. 2014

Activity LevelsAverage Rigs Running 4 5 1 (75%) 14 9 7 (50%)Average Completion Crews 2.0 3.0 1.5 (25%) 5.5 2.0 4.0 (27%)

Operational ImprovementsDrilling Days 29 31 24 17% 29 24 21 28%Average Lateral Length (Ft) 8,543 8,575 9,000 5% 8,052 8,910 9,000 12%Stages per Well 47 49 51 9% 40 45 45 12%Stage Length 183 175 175 4% 200 200 200 0%Stages per Day 3.2 3.7 4.4 38% 3.2 3.5 3.8 19%

Well Cost & Performance ImprovementsD&C per 1,000' $1.55 $1.36 $1.14 (26%) $1.34 $1.18 $0.95 (29%)EUR per 1,000' (Bcf) (1) 1.4 1.6 1.6 14% 1.5 1.7 2.0 33%EUR per 1,000' (Bcfe) (1) 1.5 1.8 1.8 20% 1.8 1.9 2.3 28%

(2)

1,194

1,128 1,117

990 1,031 1,016

958 956

1,084 1,126

1,274 1,304

1,337

1,418

1,480 1,500

800

900

1,000

1,100

1,200

1,300

1,400

1,500

1,600

Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 Feb-16 Mar-16 2016Plan

Prop

pant

Pla

ced

(lbs/

ft)

MARCELLUS PROPPANT PLACEMENT

11

Increased Proppant Load by 25% While Increasing Proppant Placement to 98%

Pilot testing demonstrated improved recoveries while maintaining well density

0

5

10

15

20

25

30

35

4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000

EUR

(Bcf

e)

Lateral Length (Feet)

All Wells Q1 2016 Wells

12

MARCELLUS IMPROVEMENTS DRIVING VALUE CREATION

Antero Marcellus EUR vs. Lateral Length(1)(2)

33 wells > 10,000’ lateral length and 43 wells waiting on completion ranging from

10,000’ to 14,000’

1. All 251 wells completed since 2014 when Antero transitioned to shorter stage length completions (SSL). 2. EUR’s include NGL processing (C3+) but assume ethane rejection.

Longer Laterals Better Well Economics

TBD Current

completions using 1,500 lbs/ft of sand and 39 Bbls/ft of water

2016 wells average 2.3 Bcfe/1,000’

98% sand placement for 1,200 lbs/ft drove

outperformance in 1Q 2016 compared to type

curve

39 wells > 20 Bcfe

High correlation of EURs to lateral length

While we have not changed our 1.7 Bcf/1,000' Marcellus project-wide type curve, we are seeing stronger EURs per 1,000' in a significant portion of our Marcellus rich gas acreage as exhibited in our 2.0 Bcf/1,000' average for wells completed in the first quarter with at least 30 days of production history

$8.7 $11.7

$5.2 $7.7

35% 45%

24% 30%

0%10%20%30%40%50%

$0.0$3.0$6.0$9.0

$12.0$15.0

1.7 Bcf/1,000'2.3 Bcfe/1,000'

2.0 Bcf/1,000'2.7 Bcfe/1,000'

1.7 Bcf/1,000'2.1 Bcfe/1,000'

2.0 Bcf/1,000'2.5 Bcfe/1,000'

Pre

-Tax

RO

R

Pre

-Tax

PV

-10

Pre-Tax PV-10 Pre-Tax ROR

Classification(1) Highly-Rich Gas/Condensate Highly-Rich Gas BTU Regime 1275-1350 1275-1350 1200-1275 1200-1275 EUR (Bcfe): 20.8 24.4 18.8 22.1 EUR (MMBoe): 3.5 4.1 3.1 3.7 % Liquids: 33% 33% 24% 24% Lateral Length (ft): 9,000 9,000 9,000 9,000 Well Cost ($MM): $8.5 $8.5 $8.5 $8.5 Bcf/1,000’ 1.7 2.0 1.7 2.0 Bcfe/1,000’: 2.3 2.7 2.1 2.5 Net F&D ($/Mcfe): $0.48 $0.41 $0.53 $0.45

Pre-Tax NPV10 ($MM): $8.7 $11.7 $5.3 $7.7 Pre-Tax ROR: 35% 45% 24% 30% Payout (Years): 2.5 2.0 3.7 2.9 Breakeven NYMEX Gas Price ($/MMBtu)(5) $1.67 $1.40 $2.31 $2.05

Gross 3P Locations(3): 626 971

13

NYMEX ($/MMBtu)

WTI ($/Bbl)

C3+ NGL(2)

($/Bbl) 2016 $2.26 $41 $16 2017 $2.77 $45 $21 2018 $2.87 $47 $24 2019 $2.93 $49 $25 2020 $3.03 $50 $26 2021-25 $3.49 $51-$53 $27

Assumptions Natural Gas – 3/31/2016 strip Oil – 3/31/2016 strip NGLs – 37.5% of Oil Price

2016; 50% of Oil Price 2017+

45 35

2016 Development Plan: Completions

1. 3/31/2016 pre-tax well economics based on a 9,000’ lateral, 3/31/2016 natural gas and WTI strip pricing for 2016-2025, flat thereafter, NGLs at 37.5% of WTI for 2016 and 50% of WTI thereafter, and applicable firm transportation and operating costs including 50% of Antero Midstream fees. Well cost estimates include $1.2 million for road, pad and production facilities.

2. Pricing for a 1225 BTU y-grade ethane rejection barrel. NGLs at 37.5% of WTI for 2016 and 50% of WTI for 2017 and thereafter. NGL prices are forecast to increase in 2017 relative to WTI due to projected in-service date of Mariner East 2 project allowing for a significant increase in AR NGL exports via ship.

3. Undeveloped well locations as of 12/31/2015. 4. Represents actual results for 1Q 2016. 5. Breakeven price for 15% pre-tax rate of return.

MARCELLUS UPSIDE POTENTIAL

Highly-Rich Gas/Condensate Highly-Rich Gas (4) (4)

14

APPENDIX

14

ANTERO RESOURCES EBITDAX RECONCILIATION

15

EBITDAX Reconciliation

($ in millions) Quarter Ended LTM Ended 3/31/2016 3/31/2016

EBITDAX: Net income including noncontrolling interest $10.7 $591.5 Commodity derivative fair value (gains) (279.9) (1,901.9) Net cash receipts on settled derivatives instruments 324.3 996.1 Interest expense 63.3 244.4 Income tax expense (benefit) 4.8 333.3 Depreciation, depletion, amortization and accretion 192.2 720.9 Impairment of unproved properties 15.5 111.3 Exploration expense 1.0 3.5 Equity-based compensation expense 23.5 93.6 State franchise taxes 0.0 (0.1) Contract termination and rig stacking 0.0 29.6 Consolidated Adjusted EBITDAX $355.4 $1,222.2