company website presentation april 2016

Company OverviewApril 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.

2

CHANGES SINCE APRIL 2016 PRESENTATION

Updated AR Marcellus and Utica single well economics as of 3/31/2016 strip pricing Slides 13, 31, 62, 63

Updated AR slides highlighting net acreage position as of 3/31/2016 Slides 5, 32, 37, 39, 44

Updated AR slide showing gas and equivalent realizations as of 3/31/2016 Slide 22

New AR slide highlighting Marcellus 2.0 Bcf/1,000’ EUR and SWE as of 3/31/2016 strip pricing Slide 12

New AR slides highlighting strength of Antero credit profile with borrowing base and ratings affirmed Slides 20, 21

Updated AR slides showing 3/31/2016 hedging position and mark-to-market value Slides 15, 18, 19, 58

New AR slides highlighting improving operational performance Slides 35, 36, 38, 54

WHY OWN ANTERO?

3

$3.7 billion of consolidated liquidity available as of 12/31/15 pro forma for AM unit sale Ba2/BB corporate ratings affirmed; $4.5 billion borrowing base affirmed Stable leverage not increasing through the down cycle

Balance Sheet Strength

Production Sold Forward at

Attractive Prices

Momentum + Growth

Superior Realized Prices & Margins

Attractive & Improving Well

Economics

Largest Core Drilling Inventory

94% of forecasted production hedged through 2018 at $3.81/MMBtu $3.1 billion mark-to-market on 3.6 Tcfe hedge position as of 3/31/2016 Over 33 Tcfe of unhedged 3P inventory to drill and produce as prices improve

15% production growth guidance in 2016 and 20% growth targeted in 2017 Forecasted cash flow growth in 2016 and 2017 Flexibility to adjust activity up or down – 8 rigs currently running, 70 DUCs at YE 2016

Realized prices and EBITDAX margins lead Appalachian peers Forecast positive basis to Nymex in 2016 and beyond due to large FT portfolio with

superior pricing points; low average cost of $0.46 per MMBtu

20% to 35% ROR at 3/31/16 strip prices and 47% to 64% ROR including hedges Long laterals up to 14,000 ft.; rolling off legacy drilling and completion contracts;

multiple process improvements and higher proppant loading all improving RORs

Based on geologic interpretation of core, Antero has the largest drilling inventory in the core of the two plays with over 3,700 undrilled locations

Antero continues to consolidate its acreage position

4

Most Active Operatorin Appalachia

Largest Firm Transport and Processing

Portfolio in Appalachia

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

Strong Financial Liquidity

Prudent Growth Drives Value Creation

Current Flexibility & Upside Participation in

Commodity Price Recovery

Highest Realizations and Margins Among

Large Cap Appalachian Peers

Growth & Momentum

Flexibility & Upside

Hedging &Liquidity

Midstream

Drilling

LEADING UNCONVENTIONAL BUSINESS MODEL

MLP (NYSE: AM)Highlights

Substantial Value in Midstream Business

Realizations

Takeaway

Well Economics

1

2 3

4

5

67

8

Premier AppalachianE&P Company

Run by Co-Founders

Sustainable Business Model

Note: 2015 SEC prices were $2.56/MMBtu for natural gas and $50.13/Bbl for oil on a weighted average Appalachian index basis. 1. 3P reserve pre-tax PV-10 based on annual strip pricing for first 10-years and flat thereafter as of December 31, 2015. NGL pricing assumes 39%, 46% and 48% of WTI strip prices for 2016, 2017 and

2018 and thereafter, respectively. 2. 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. 3. Antero and industry rig locations as of 4/1/2016, per RigData.

DRILLING – MOST ACTIVE OPERATOR IN APPALACHIA

5

COMBINED TOTAL – 12/31/15 RESERVESAssumes Ethane RejectionNet Proved Reserves 13.2 TcfeNet 3P Reserves 37.1 TcfeStrip Pre-Tax 3P PV-10(1) $11.2 BnNet 3P Reserves & Resource 50 to 53 TcfeNet 3P Liquids 1,237 MMBbls% Liquids – Net 3P 20%1Q 2016 Net Production 1,758 MMcfe/d- 1Q 2016 Net Liquids 68,516 Bbl/dNet Acres(2) 573,000Undrilled 3P Locations 3,719

OHIO UTICA SHALE CORE

Net Proved Reserves 1.8 TcfeNet 3P Reserves 7.5 TcfeStrip Pre-Tax 3P PV-10(1) $2.5 BnNet Acres 148,000Undrilled 3P Locations 814

MARCELLUS SHALE CORE

Net Proved Reserves 11.4 TcfeNet 3P Reserves 29.6 TcfeStrip Pre-Tax 3P PV-10(1) $8.7 BnNet Acres 425,000Undrilled 3P Locations 2,905

WV/PA UTICA SHALE DRY GASNet Resource 12.5 to 16 TcfNet Acres 190,000Undrilled Locations 1,889

0123456789

Rig

Cou

nt

Operators

SW Marcellus + Utica Rigs(3)

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 9,232 8% 8,052 8,910 9,456 17%Stages per Well 47 49 53 12% 40 45 47 17%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 1.5 1.8 20% 1.8 1.9 2.3 28%

Marcellus ShaleUtica Shale Ohio

6

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.

$1.141.61.8

$0.952.02.31.8

9,000 9,0005% 12%

DRILLING – CONTINUOUS OPERATING IMPROVEMENT

(2) (2)

DRILLING – PROVEN TRACK RECORD OF WELL COST REDUCTIONS

7

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

$198 $341

$434

$649

$1,164 $1,351

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

2010 2011 2012 2013 2014 2015 2016E

$1,221

0

10,000

20,000

30,000

40,000

50,000

60,000

2010 2011 2012 2013 2014 2015 2016E

NGLs (C3+) Oil Ethane

5 2466,436

23,051

48,298

60,000

24% GrowthGuidance

1. Represents Bloomberg street consensus estimates as of 4/15/2016.

1,715

2,058

0

600

1,200

1,800

2,400

2010 2011 2012 2013 2014 2015 2016E 2017E

Marcellus Utica Guidance

30 124239

522

1,007

1,493

8

AVERAGE NET DAILY PRODUCTION (MMcfe/d)

0

50

100

150

200

2010 2011 2012 2013 2014 2015 2016E

Marcellus Utica Deferred Completions

1938

60

114

177 181

131110

180

OPERATED GROSS WELLS COMPLETED

AVERAGE NET DAILY LIQUIDS PRODUCTION (Bbl/d)

15% Growth

Guidance

20% GrowthTarget

Antero is in the unique position of being able to sustain growth and value creation through the price down cycle

CONSOLIDATED EBITDAX ($MM)

StreetConsensus(1)

GROWTH & MOMENTUM – THROUGH THE DOWN CYCLE

3.7x

4.9x

0.6x

1.5x

3.0x3.4x

3.8x

4.8x

1.2x1.9x

4.7x

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

15% 17% 17%

3% 2%

(11%)

12%

1%

(5%)

(27%)

-40%

-30%

-20%

-10%

0%

10%

20%


2016E Production Growth2016E EBITDAX Growth

GROWTH & MOMENTUM – CONTINUED MEASUREDGROWTH

9

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%)(40%)

(3)

$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 – ANTERO THRIVES WITH RISING PRICES

10

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)

$46$65

$83Increase in pre-tax

PV10 value does not include the addition of locations; represents upside in prices onlyon 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 InventoryOptionality to Accelerate Development

$42

Remaining Undeveloped

3P Locations(1)

3,60985%

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 $4.5 billion of net debt as of 12/31/2015 pro forma for AM unit offering, 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 Guidance2017 Target

($B

n)

111. 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 15% 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

FLEXIBILITY & UPSIDE – LOW MAINTENANCE CAPITAL

Maintenance Capital$275

Maintenance Capital$500

2016 Growth Capital$400



$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

2016 2017

$1.3 Bn D&C Budget

0% Y-O-YGrowth of

1,493 MMcfe/d

15% Y-O-YGrowth

Contributes to 2017 20% Y-O-Y Growth Target

0% Y-O-YGrowth of

1,715 MMcfe/d

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

Capex in 2017

Hedge Revenues

$1,156MM(1)

Hedge Revenues$572MM(1)

$MM2016 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)

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

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

Gross 3P Locations(3): 626 971

12

NYMEX($/MMBtu)

WTI($/Bbl)

C3+ NGL(2)

($/Bbl)

2016 $2.26 $41 $162017 $2.77 $45 $212018 $2.87 $47 $242019 $2.93 $49 $252020 $3.03 $50 $262021-25 $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+

4535

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.

WELL ECONOMICS – MARCELLUS UPSIDE POTENTIAL

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

$2.26 $2.77 $2.87 $2.93 $3.03

$4.13 $3.67 $3.84 $3.61 $3.33

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

2016 2017 2018 2019 2020

03/31/16 NYMEX Strip Pricing - Before Hedges03/31/16 NYMEX Strip Pricing - After Hedges

24% 24%

35%

20%23% 24%

13%10% 9%

64% 64% 63%56%

48% 47%

28%24%

14%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Utica Highly-Rich Gas

Utica Dry Gas - Ohio

MarcellusHighly-Rich

Gas/Condensate

Utica Rich Gas Utica Highly-Rich Gas/

Condensate

MarcellusHighly-Rich

Gas

Marcellus DryGas

Marcellus RichGas

UticaCondensate

RO

R

ROR @ 3/31/2016 Strip Pricing - Before Hedges ROR @ 3/31/2016 Strip Pricing - After Hedges

2016/2017 Antero Drilling Plan

ANTERO MARCELLUS & UTICA WELL ECONOMICS(1)(2)

108 263 626 161 98 971 755 553 184


2. ROR @ 3/31/2016 Strip Pricing – After Hedges reflects 3/31/2016 well cost ROR methodology with the 3/31/2016 hedge value allocated based on 2016-2021 projected production volumes resulting in blend of strip and hedge prices.

13

At 3/31/2016 strip pricing, Antero has 2,227 locations with well economics that exceed 20% rate of return (excluding hedges)– Including hedges, these locations generate rates of return of approximately 47% to 64%

Rates of return include pad, facilities, cash production expenses (including midstream and FT costs)– See assumptions pages in appendix for further detail

2,227 “High Grade” Drilling

Locations

NYMEX($/MMBtu)

WTI($/Bbl)

C3+ NGL($/Bbl)

2016 $2.26 $41 $162017 $2.77 $45 $212018 $2.87 $47 $242019 $2.93 $49 $252020 $3.03 $50 $262021-25 $3.17-$3.80 $51-$53 $27

3/31/16 Strip Pricing 3/31/16 Hedge PricingNYMEX

($/MMBtu)C3+ NGL

($/Bbl)

$4.13 $29$3.67 $19$3.84 $25$3.61 $25$3.33 $26

$3.17 - $3.80 $27

Locations

WELL ECONOMICS – SUSTAINABLE BUSINESS MODEL

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000 Proved Developed Production (BBtu/d)

Undeveloped Production (BBtu/d)

Hedged Volume (BBtu/d)

WELL ECONOMICS – HEDGING UNDEVELOPED PRODUCTION

141. Represents illustrative Antero production forecast, adjusted for residue gas BTU content of 1100 BTU.2. Hedged volume as of 3/31/2016.3. Represents average hedge price for nine months ending 12/31/2016.

Antero has hedged a significant portion of its forecasted undeveloped production stream from wells yet to be drilled at prices well above current strip pricing, including virtually all of its

undeveloped production forecast through the end of 2017

Natural Gas Hedged Volume vs. Production(BBtu/d)

(1)

(1)

Antero has hedged virtually all of its undeveloped production through the end of 2017

Developed (Illustrative)

Undeveloped (Illustrative)

$3.91/Mcfe(3)

$3.57/Mcfe $3.91/Mcfe$3.70/Mcfe

$3.66/Mcfe

No Production Guidance or Targets Disclosed

Beyond 2017

(2)

Antero ResourcesCorporation (NYSE: AR)

$10.8 Billion Enterprise Value(1)

Ba2/BB Corporate Rating

Antero MidstreamPartners LP (NYSE: AM)

$4.5 Billion Enterprise Value

62% LP Interest$2.4 Billion MV

$11.2 Bn 3P PV-10(3)

E&P Assets

Gathering/Compression Assets

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

1. AR enterprise value excludes AM debt, minority interest and cash. Market values (MV) as of 3/31/2016 and includes subordinated units; balance sheet data as of 12/31/2015 pro forma for AM unit sale. 2. 3.6 Tcfe hedged at $3.71/Mcfe average price through 2022 with mark-to-market (MTM) value of $3.1 billion as of 3/31/2016. 3. 3P pre-tax PV-10 based on annual strip pricing for first 10-years and flat thereafter as of December 31, 2015. NGL pricing assumes 39%, 46% and 48% of WTI strip prices for 2016, 2017 and 2018 and

thereafter, respectively. 4. Based on 277.0 million AR shares outstanding and 176.2 million AM units outstanding.

15

Corporate Structure Overview

Market Valuation of AR Ownership in AM:• AR ownership: 62% LP Interest = 108.9 million units

AM Priceper Unit

AM UnitsOwnedby AR(MM)

AR Value in AM LP Units

($MMs)Value Per

AR Share(4)

$22 109 $2,396 $9$23 109 $2,505 $9$24 109 $2,614 $9$25 109 $2,723 $10$26 109 $2,831 $10$27 109 $2,940 $11

Water Infrastructure Assets

MLP Benefits:- Funding vehicle to expand midstream business- Highlights value of Antero Midstream- Liquid asset for Antero Resources

Public

38% LP Interest$1.5 Billion MV

$3.1 Bn MTM Hedge Position(2)

TAKEAWAY – LARGEST FT AND PROCESSING PORTFOLIO IN APPALACHIA

Antero Long Term Firm Processing & Takeaway Position (YE 2018) – Accessing Favorable MarketsMariner East 2

62 MBbl/d CommitmentMarcus Hook Export

Shell20 MBbl/d Commitment

Beaver County Cracker (2)

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

Lake Charles LNG(3)

150 MMcf/d

Freeport LNG70 MMcf/d

1. May 2016 and full year 2016 futures basis, respectively, provided by Intercontinental Exchange dated 3/31/2016. Favorable markets shaded in green. 2. Subject to Shell FID expected mid-year 2016.3. Lake Charles LNG 150 MMcf/d commitment subject to BG FID expected in 2016.

Chicago(1)

$(0.03) / $(0.03)

CGTLA(1)

$(0.06) / $(0.06)

TCO(1)

$(0.11) / $(0.14)

16

Cove Point LNG4.85 Bcf/dFirm GasTakeaway

By YE 2018

Antero’s natural gas firm transportation (FT) portfolio builds to 4.85 Bcf/d by YE 2018 with 87% serving favorable markets, with an average demand fee of $0.46/MMBtu and positive weighted average basis differential to NYMEX after assumed Btu uplift for gas

YE 2018 Gas Market MixAntero 4.85 Bcf/d FT

44%Gulf Coast

17%Midwest

13%Atlantic

Seaboard

13%Dom S/TETCO

(PA)

13%TCO

Positive weighted

average basis differential

Antero Commitments

(3)

(2)

-

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

5,000,000

5,500,000

TAKEAWAY – FIRM TRANSPORTATION AND SALES PORTFOLIO

17

MMBtu/d

Columbia7/26/2009 – 9/30/2025

Momentum III9/1/2012 – 12/31/2023

EQT8/1/2012 – 6/30/2025

REX/MGT/ANR7/1/2014 – 12/31/2034

Stonewall/Tennessee11/1/2015– 9/30/2030

(Stonewall/WB) Mid-Atlantic/NYMEX

Gulf Coast

(TCO) Appalachia or Gulf Coast

AppalachiaAppalachia

(REX/ANR/NGPL/MGT) Midwest

Firm Sales #110/1/2011– 10/31/2019

Firm Sales #21/1/2013 – 5/31/2022

ANR3/1/2015– 2/28/2045

Stonewall/WB11/1/2015 – 9/30/2037

(ANR/Rover) Gulf Coast

Antero Transportation Portfolio

582 BBtu/d

590 BBtu/d

375 BBtu/d

250 BBtu/d

800 BBtu/d

600 BBtu/d

630 BBtu/d

40 BBtu/d

Gross Gas Production (Actuals)Illustrative Gross Gas Production(1)

1. Assumes production growth guidance of 15% in 2016 and targeted 20% annual production growth in 2017.2. Based on 2016 production guidance of 1.715 Bcfe/d.3. Assumes 30% to 50% mitigation on excess capacity and current spreads based on strip pricing as of 12/31/2015.

Lowest cost, local unfavorable FT not

projected to be used through 2017

2016E Net Marketing Expenses:$15 Million

2016E Net Marketing Expenses:$20 Million

2016E Net Marketing Expenses:$30 to $35 Million (3)

2016E Net Marketing Expenses:$30 to $55 Million (3)

2016E Total Net Marketing Expenses:$95 to $125 Million

($0.15 to $0.20 per Mcfe)(2)

2017E Total Net Marketing Expenses:

$ Amounts in line with 2016

While Antero has excess FT in place through 2017, the expected cost of unutilized FT is estimated to be manageable at <10% of EBITDA

Projected cost after mitigation due to positive

futures spreads

Marketed Volume (Term / Contracted)Marketed Volume (Spot / Guidance)

80 BBtu/d

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$0

$50

$100

$150

$200

$250

$300

$350

$MM

18

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 GainsProjected 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/Mcfethrough 2022

Average Hedge Prices ($/Mcfe)

$3.36

$3.91

$3.57

$3.91$3.70 $3.66

$3.24

$3.1 Billion in Projected Hedge

Gains Through 2022Realized $2.1 Billion in Hedge Gains

Since 2009

HEDGING – INTEGRAL TO BUSINESS MODEL

(1)

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

Liquid “non-E&P assets” of $5.5 Bnsignificantly exceeds total debt of $3.9 Bn

Liquidity

LIQUIDITY – STRONG BALANCE SHEET AND FLEXIBILITY Antero Resources (NYSE:AR) Antero Midstream (NYSE:AM)

12/31/2015 Debt Liquid Non-E&P Assets 12/31/2015 Debt Liquid Assets

Debt Type $MMCredit facility $529

6.00% senior notes due 2020 525

5.375% senior notes due 2021 1,000

5.125% senior notes due 2022 1,100

5.625% senior notes due 2023 750

Total $3,904

Asset Type $MMCommodity derivatives(1) $3,073

AM equity ownership(2) 2,407

Cash 16

Total $5,496

Asset Type $MMCash $16

Credit facility – commitments(3) 4,000

Credit facility – drawn (529)

Credit facility – letters of credit (702)

Total $2,785

Debt Type $MMCredit facility $620

Total $620


Total $7

Liquidity


Credit facility – capacity 1,500

Credit facility – drawn (620)

Credit facility – letters of credit -

Total $887

Approximately $2.8 billion of liquidity at AR plus an additional $2.4 billion of AM units

Approximately $900 million of liquidityat AM

19

Only 41% of AM credit facility capacity drawn

Note: All balance sheet data as of 12/31/2015. Pro forma for AR secondary offering of 8.0 million AM units on 3/24/2016 for net proceeds of $178 million. 1. Mark-to-market as of 3/31/2016.2. Based on AR ownership of AM units (108.9 million common and subordinated units) and AM’s closing price as of 3/31/2016.3. AR credit facility commitments of $4.0 billion, borrowing base of $4.5 billion.

Baa3

Ba1 Ba1 Ba1

Ba3 Ba3 Ba3 Ba3

B1 B1 B1

B2 B2 B2

B3

Caa1

Caa2

Baa2

Baa3 Baa3 Baa3

Baa2 Baa2

Ba2

Baa3 Baa3

Ba1 Ba1

Baa3

Ba1 Ba1 Ba1 Ba1

Ba3 Ba3

Ba2

Ba3

-Baa3

Baa3

Baa3

Baa3

Baa3

Baa3

Baa3

Baa3

Baa3

Baa3

Baa3

Baa3

NBL XEC EQT PXD APC HES CXO AR CLR MUR NFX RRC SWN EGN QEP SM WPX UNT EPE WLL DNR20

Moody’s Baa / Ba Ratings Review

Source: Moody’s releases on 02/11/2016 and 02/18/2016.Note: Issuers are sorted based on rating following review.

Antero’s Ba2 / BB credit ratings were affirmed by Moody’s and S&P in February 2016

Moody’s reviewed 20 high yield issuers and announced 16 downgrades ranging from 1 to 5 notches

S&P reviewed 45 high yield issuers and announced 25 downgrades ranging from 1 to 3 notches

Antero was one of only five Baa and Ba companies that received an “affirmed” rating from Moody’s

AR

Rating Affirmed

Baa1

Baa2

Baa3

Ba1

Ba2

Ba3

B1

B2

B3

Caa1

Caa2

Caa3

Gray – Previous RatingRed – New Rating

Appalachian Company

1

2 2

5

532

4433

4223

3Reduction in Ratings

LIQUIDITY – ANTERO CREDIT QUALITY AFFIRMED

Notch

Notches

Old BorrowingBase $4,500 $4,000 $3,000 $4,000 $1,800 $2,000 $1,525 $1,750 $1,175 $900 $827 $625 $375 $375 $500 $450

New BorrowingBase $4,500 $4,000 $3,000 $2,750 $1,500 $1,250 $1,150 $1,025 $925 $725 $700 $450 $335 $325 $300 $100

Result -- -- -- ($1,250) ($300) ($750) ($375) ($725) ($250) ($175) ($127) ($175) ($40) ($50) ($200) ($350) Average

% Change -- -- -- (31%) (17%) (38%) (25%) (41%) (21%) (19%) (15%) (28%) (11%) (13%) (40%) (78%) (29%)

Borrowing Base Actions

1. Represents Spring 2016 borrowing base actions for all public companies for which J.P. Morgan is a lender.

$2,750

$1,500

$1,150$925

$725 $700 $450$335 $325 $300 $100

$2,000

$4,500

$4,000

$3,000

$4,000

$1,800$1,525 $1,750

$1,175

$900 $827 $625

$375 $375 $500 $450

AR CHK RRC WLL BBEP SM OAS WPX MEMP LGCY HK EVEP BBG XCO SGY CWEI$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

)

$1,250

$1,025

Antero was one of only three public E&P companies (two

Appalachia) that did not receive a reduction in their

borrowing base from Spring redetermination process

Red – New Borrowing Base

Appalachian Company

Antero’s $4.5 Billion borrowing base was reaffirmed by its lender group, representing one of only three 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

21

$1,250

$300

$375 $725

$ Amount of Reduction

$350$50$175$127$175

$750

$250

$40 $200

LIQUIDITY – BORROWING BASE AFFIRMED

$2.03 $1.88 $1.59

$1.35 $1.14 $1.11

$0.58 $0.73 $0.88 $0.75 $0.85 $0.72

$4.34

$3.22 $3.06 $2.75

$2.21 $2.20

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

$5.00


$/M

cfe

Noncontrolling Interest of Midstream MLP EBITDA LOEProduction Taxes GPTG&A EBITDAX4-year Avg. All-in F&D

$4.40

$3.08 $3.00 $2.78

$2.07 $1.94

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

$5.00


$/M

cf

1. Includes natural gas hedges.2. Source: Public data from 4Q 2015 earnings releases. Peers include COG, CNX, EQT, RRC and SWN. 3. Includes realized hedge gains and losses. Operating costs include lease operating expenses, production taxes, gathering, processing and firm transport costs and general and administrative costs. 4-year proved

reserve average all-in F&D from 2011-2014. Calculation = (Development costs + exploration costs + leasehold costs) / Total reserves added (2014 ending reserves – 2011 beginning reserves + 4-year reserve sales – 4-year reserve purchases + 4-year accumulated production). AR price realization includes $0.06 of midstream revenues; EBITDAX excludes AR’s midstream EBITDA not attributable to AR’s ownership.

22

4Q 2015 Natural Gas Realizations(1)(2) 4Q 2015 Price Realization & EBITDAX Margin vs F&D(2)(3)

($/Mcfe)

Antero continues to be a leader in its Appalachian peer group in price realizations and EBITDAX unit margins

4Q 2015 NYMEX = $2.27/Mcf

REALIZATIONS – A LEADER IN REALIZATIONS & MARGINS

4Q 2015 and 1Q 2016 Natural Gas Realizations ($/Mcf)

Average NYMEX

Price($/Mcf)

AverageDifferential

($/Mcf)

AverageBTU Upgrade

($/Mcf)

Relative to NYMEX($/Mcf)

Gas Hedge Effect

($/Mcf)

AverageRealized

Gas Price($/Mcf)

AverageRealized Gas

Premium to NYMEX ($/Mcf)

Liquids Upgrade($/Mcfe)

Realized Equivalent

Price($/Mcfe)

Gas Equivalent

Premium to NYMEX($/Mcfe)

4Q 2015 $2.27 $(0.31) $0.17 $(0.14) $2.27 $4.40 $2.13 ($0.12) $4.28 $2.01

1Q 2016 $2.09 $(0.16) $0.15 $(0.01) $2.46 $4.54 $2.45 ($0.40) $4.14 $2.05

DOM S 23%

DOM S, 3%

TETCO M27%

TETCO M21%

TCO 40%

TCO 33% TCO, 21%

NYMEX10%

NYMEX10%

NYMEX10%

Gulf Coast2%

Gulf Coast28%

Gulf Coast49%

Chicago18%

Chicago28%

Chicago17%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

($/Mcf) 2015A 2016ENYMEX Strip Price(1) $2.66 $2.47Basis Differential to NYMEX(1) $(0.53) $(0.12)BTU Upgrade(5) $0.24 $0.24Estimated Realized Hedge Gains $1.44 $1.50 Realized Gas Price with Hedges $3.81 $4.10 Premium to NYMEX +$1.15 +$1.63Liquids Impact +$0.29 +$0.10Premium to NYMEX w/ Liquids +$1.44 +$1.73Realized Gas-Equivalent Price $4.10 $4.16

REALIZATIONS – FAVORABLE PRICE INDICES

Note: Hedge volumes as of 12/31/2015.1. Based on 12/31/2015 strip pricing and actuals for 2015. 2. Differential represents contractual deduct to NYMEX-based firm sales contract.3. Represents 120,000 MMBtu/d of TCO index hedges and 390,000 MMBtu/d of

TCO basis hedges that are matched with NYMEX hedges for presentation purposes.

4. Represents 60,000 MMBtu/d of TCO index hedges and 120,000 MMBtu/d of TCO basis hedges that are matched with NYMEX hedges for presentation purposes.

5. Based on BTU content of residue sales gas.

2015Basis(1)

2016 Basis(1)

2017 Basis(1)

2015Hedges

2016Hedges

2017Hedges

Mar

kete

d %

of T

arge

t Res

idue

Gas

Pro

duct

ion

+$0.02/MMBtu

$(0.12)/MMBtu(2)

$(1.30)/MMBtu

$(0.28)/MMBtu

$0.01/MMBtu

$(0.43)/MMBtu(2)

$(0.18)/MMBtu

$(0.04)/MMBtu

$(0.43)/MMBtu(2)

$(0.78)/MMBtu

$(0.25)/MMBtu

$(0.05)/MMBtu

$(0.06)/MMBtu

1,370,000 MMBtu/d

@ $3.40/MMBtu

40,000 MMBtu/d

@ $4.00/MMBtu

230,000 MMBtu/d

@ $5.74/MMBtu

510,000 MMBtu/d

@ $3.87/MMBtu(3)

170,000 MMBtu/d

@ $4.09/MMBtu

272,500 MMBtu/d

@ $5.35/MMBtu

180,000 MMBtu/d

@ $3.54/MMBtu(4)

99% exposure to favorable price indices69% exposure to favorable price indices 97% exposure to favorable price indices

Antero’s exposure to favorable gas price indices like Chicago, Gulf Coast, NYMEX and TCO is expected to increase to >99% in 2016 Improved 2016 realizations driven by Stonewall gathering pipeline which was placed in-service December 1, 2015 and will eliminate

virtually all swing sales at Dominion South and Tetco in 2016

$(1.00)/MMBtu

$(0.93)/MMBtu

Wtd. Avg.Basis ($0.53)

Wtd. Avg.Basis $(0.12)

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

Wtd. Avg.Basis $(0.15)

1,612,500 MMBtu/d@ $3.92/MMBtu

420,000 MMBtu/d

@ $4.27/MMBtu

2015A 2016E 2017E

23

380,000 MMBtu/d

@ $3.88/MMBtu

990,000 MMBtu/d

@ $3.49/MMBtu

70,000 MMBtu/d

@ $4.57/MMBtu

1,860,000 MMBtu/d@ $3.63/MMBtu

$(0.10)/MMBtu

Current markets indicate positive

differential in 2016

$15.17$21.89

$41.00

$0.00

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

AR NGL Pricing Mont Belvieu

Realized NGL C3+ Price WTI

$0.59

$0.42

$0.47 $0.47

$0.10

$0.20

$0.30

$0.40

$0.50

$0.60

$0.70

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

2016 2017

Hedged Volume Average Hedge Price Strip (4/11/2016)

REALIZATIONS – NGL UPSIDE REFLECTS EXPORTS AND PROPANE HEDGES

241. Based on 2016 NGL and WTI strip prices as of 12/31/2015. 2. As of 4/11/2016.

Ethane & Propane Pricing Improvement

NGL Marketing Propane Hedges Realized NGL (C3+) price was 50% of WTI in 2014 and

35% of WTI for 2015− Including propane hedges, 2015 realizations were 42%

of WTI

Antero has guided to realized C3+ NGL prices of 35% to 40% of WTI for 2016 (before hedging)− 1Q 2016 realizations were 42%, before hedges−Antero has hedged 30,000 Bbl/d of propane in 2016 at

$0.59 per gallon

By 2017, Antero will market a significant portion of its NGL volumes out of Marcus Hook to export markets once Mariner East 2 is in service – 61,500 Bbl/d firm commitment with expansion rights

(Bbl/d)

$48 MM $(13) MM

($/Gal)

Mark-to-Market Value(2)

37%

2016 C3+ NGL pricing guidance of 37% of WTI based on 12/31/15 strip pricing(1)

2016E C3+ Guidance

$0.10$0.15$0.20$0.25$0.30$0.35$0.40$0.45$0.50

$/G

al

Ethane Propane

$0.29

$0.47

$0.14$0.18

NORTHEAST NGLS ARE TRANSPORTATION CHALLENGED

1. As an anchor shipper on Mariner East 2, Antero has the right to expand its NGL commitment with notice to operator. 2. 2015 NGL production assumes ethane rejection.

Mariner East 261,500 Bbl/d AR Commitment(1)

4Q 2016 In-Service

Not so much a supply problem but more of a logistics problem for NGLs in the northeast today− The majority of northeast NGL production is being transported by expensive rail and trucking− NGLs that are transported “to the water” are also faced with high shipping rates

Export15%

Gulf Coast13%

Mid-Atlantic

6%Sarnia

3%

Northeast43%

Midwest10%

Edmonton10%

2015 NGL Marketing by Region

25

NORTHEAST NGL GROWTH IS SUPPORTED BY INCREASING TAKEAWAY OPTIONS

1. Chart 10 per BAML research dated 6/5/2015. Pipeline volumes are capacity estimates.

Industry NGL Pipelines – Actual (2015) and Projected(1)

26

ShellBeaver County Cracker(Pending FID 1H 2016)

Mariner East 262 MBbl/d Commitment

Marcus Hook Export

Gulf Coast Critical to

NGL Pricing

Appalachia

NGL transportation rates are expected to decline $0.12 to $0.15 per gallon by 2017 as pipeline options to domestic markets and export terminals go in-service (Mariner East 1 and 2, for example)

(MMBbl/d)

POSITIVE OUTLOOK FOR LONG-TERM NGL MARKETS

Steady Global LPG Demand Growth Through 2035(1)

1. Source: PIRA NGL Study, September 2015.2. Source: IHS, Waterborne, SK Gas Analysis; Wood Mackenzie; Wood Mackenzie; PDH C3 capacity based on 25 MBbl/d = 650 Mt/y.

Multiple Factors Driving Global LPG Demand Growth Through 2020(2)

MM

Bbl

/d

0.0

0.33

0.67

Forecast global LPG demand growth of 800 MBbl/d to 1 MMBbl/d by 2020 to be driven by petrochem projects in Asia and Middle East as well as residential/commercial, alkylate and power generation demand− Naphtha cracker conversion to LPG another potential demand driver that has not yet been factored into analyst estimates ≈1 MMBbl/d

China KoreaHaiwei (2016) - 21 MBbl/d C3

SK Advanced (2016) - 27 MBbl/d C3

Ningbo Fuji (2016) - 29 MBbl/d C3

Fujian Meide (2016) - 29 MBbl/d C3

Tianjin Bohua 2 (2018) - 29 MBbl/d C3 United States

Fujian Meide 2 (2018) - 29 MBbl/d C3

Enterprise (3Q 2016)- 29 MBbl/d C3

Oriental Tangshan (2019) - 25 MBbl/d C3

Formosa (2017)- 25 MBbl/d C3

Firm and Likely PDH Underway (By 2020)

Total - 243 MBbl/d C3

Million Tons, Global PDH Capacity

1990 2000 2010 2020

20

10

0

27

14.7

13.0

11.4

9.8

8.2

6.5

4.9

3.3

1.7

U.S. Driven Global LPG Supply Through 2035(1)

MMBbl/d MMBbl/d1.3

1.0

0.7

0.3

-0.3

Continued OperationalImprovement

Production andCash Flow Growth

Most active developer in the lowest cost basin with growing production base and firm transport to favorable markets; over 33 Tcfe of unhedged 3P reserves increase ~$10 billion in pre-tax PV-10 value with a 50% recovery in commodity prices

KEY CATALYSTS FOR ANTERO

Guiding to production growth of 15% in 2016 and targeting 20% in 2017 with ~100% hedged at $3.91/MMBtu for remaining nine months of 2016 and at $3.57/MMBtu for 2017, respectively

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

Current well costs estimated to be 16% to 19% lower than 2015 costs; numerous completion enhancements recently implemented to potentially increase EURs

Antero owns 62% of Antero Midstream Partners and thereby participates directly in its growth and value creation; acquisition of integrated water business from Antero expected to result in distributable cash flow per unit accretion in 2016

Midstream MLP Growth

Sustainability of Antero’s Integrated

Business Model

1

2

3

5

4Exposure to

Commodity Upside

Antero is well positioned to be a leading consolidator in Appalachia6

Consolidation

28

0

500

1,000

1,500

2,000

2,500

3,000

3,500

0200400600800

1,0001,2001,4001,6001,8002,000

AR1Q '16

EQT CHK COG AR SWN RRC CNX

-

100

200

300

400

500

600

AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6

Core Net Acres - Dry Core Net Acres - Liquids Rich

LEADER IN APPALACHIAN BASIN

Top Producers in Appalachia (Net MMcfe/d) – 4Q 2015(1)(2) Top 12 U.S. Natural Gas Producers (Net MMcf/d) – 4Q 2015(1)

Appalachian Producers by Proved Reserves (Bcfe) – YE 2015(1)(2) Appalachian Producers by Core Net Acres (000’s) – December 2015(4)

1. Based on company filings and presentations.2. Appalachian only production and reserves where available. Excludes companies that do not break out Appalachian production including CVX, HES and XOM. 3. Includes proved reserves categorized in “Northern Division” consisting of Utica Shale, Marcellus Shale and Powder River Basin.4. Based on Antero geologic interpretation supported by state well data, company presentations and public land data. Peer group includes CNX, COG, EQT, RRC, SWN, CHK.

(3)

29

4th Largest Appalachian

Producer in 4Q

Antero has the largest proved reserve base, largest core liquids-rich acreage position and is one of the largest producers in the Appalachian Basin

Appalachian Peers

11th Largest U.S. Gas

Producer in 4Q

Largest Proved Reserve Base In

Appalachia Largest Liquids-Rich Core Position

in Appalachia

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

AR EQT RRC COG CNX CHK SWN

AR1Q ’16

AR

1st

ASSET OVERVIEW

30

$1.55$1.36

$1.14

$0.000

$0.500

$1.000

$1.500

$2.000

2014 2015 Current Spot

$MM

/1,0

00’ L

ater

al

Well Cost ($MM/1,000' of Lateral)

12% Decrease vs. 2014


626 971

553 75563% 47%

24% 28%35%24%

10% 13%

0

400

800

1,200

0%

20%

40%

60%

80%

Highly-RichGas/

Condensate

Highly-Rich Gas Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

R

Total 3P Locations ROR @ 3/31/2016 Strip Pricing - After Hedges ROR @ 3/31/2016 Strip Pricing - Before Hedges

184

98 108

161263

14%

48%64% 56% 64%

9%

23% 24% 20% 24%

0

100

200

300

0%20%40%60%80%

100%

Condensate Highly-RichGas/

Condensate

Highly-RichGas

Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

R

MARCELLUS WELL ECONOMICS(1)(2)

WELL COST REDUCTIONS SUPPORTSUSTAINABLE BUSINESS MODEL

Marcellus Well Cost Improvement(3)


2. ROR @ 3/31/2016 Strip-With Hedges reflects 3/31/2016 well cost ROR methodology, with the 3/31/2016 hedge value allocated based on 2016-2021 projected production volumes resulting in blend of strip and hedge prices.

3. Current spot well costs based on $8.5 million for a 9,000’ lateral Marcellus well and $10.25 million for a 9,000’ lateral Utica well.

31

UTICA WELL ECONOMICS(1)(2)

74% of Marcellus locations are processable (1100-plus Btu) 68% of Utica locations are processable (1100-plus Btu)

2016Drilling

Plan

Antero has reduced average well costs for a 9,000’ lateral by 12% in the Marcellus and 12% in the Utica as compared to 2014 well costs At 3/31/2016 strip pricing, Antero has 2,227 locations that exceed a 20% rate of return (excluding hedges)

– Including hedges, these locations generate rates of return of approximately 50% to 80%

Utica Well Cost Improvement(3)

$1.34$1.18

$0.95

$0.000

$0.500

$1.000

$1.500

$2.000

2014 2015 Current Spot

$MM

/1,0

00’ L

ater

al

Well Cost ($MM/1,000' of Lateral)



WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECT

100% operatedOperating 7 drilling rigs including

1 intermediate rig425,000 net acres in

southwestern Marcellus core (75% includes processable rich gas assuming an 1100 Btu cutoff)– 52% HBP with additional 26%

not expiring for 5+ years452 horizontal wells completed

and online– Laterals average 7,600’– 100% drilling success rate6 plants in-service at Sherwood

Processing Complex capable of processing in excess of 1.2 Bcf/d of rich gas−Over 900 MMcf/d of Antero gas

being processed currentlyNet production of 1,232 MMcfe/d

in 1Q 2016, including 46,900 Bbl/d of liquids 2,905 future drilling locations in

the Marcellus (2,150 or 74% are processable rich gas)29.6 Tcfe of net 3P (21% liquids),

includes 11.4 Tcfe of proved reserves (assuming ethane rejection except for 1.1 Tcfe)

Highly-Rich Gas139,000 Net Acres

971 Gross Locations

Rich Gas96,000 Net Acres

553 Gross Locations

Dry Gas108,000 Net Acres

755 Gross Locations

Highly-Rich/Condensate82,000 Net Acres

626 Gross Locations

HEFLIN UNIT30-Day Rate

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

CONSTABLE UNIT30-Day Rate

1H: 14.3 MMcfe/d (25% liquids)

SherwoodProcessing

Complex

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

NERO UNIT30-Day Rate

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

BEE LEWIS PAD30-Day Rate

4-well combined 30-Day Rate of

67 MMcfe/d (26% liquids)

RJ SMITH PAD30-Day Rate



32

HENDERSHOT UNIT30-Day Rate

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

(29% liquids)

HORNET UNIT30-Day Rate

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

(26% liquids)CARR UNIT30-Day Rate

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

WAGNER PAD30-Day Rate



Antero’s Marcellus well performance has continued to improve over time with a tight statistical range of results across its entire acreage position

PROLIFIC PREDICTABLE RESULTS ACROSS ENTIREMARCELLUS POSITION

33

Marcellus PDP Locations (As of 12/31/2015)

(1)

1. Source: IHS; 3rd party producing wells include Consol, EQT, Exxon/XTO, Noble, Ascent, PDC, Magnum Hunter, Statoil, Chesapeake/SWN.

>1275 BTU2.2 Bcfe/1,000’ Lateral

10 SSL Wells

1200-1275 BTU2.0 Bcfe/1,000’ Lateral

116 SSL Wells

1100-1200 BTU1.8 Bcfe/1,000’ Lateral

104 SSL Wells

Average Antero Marcellus Well

2014 Actual

2015Actual Target

30-Day Rate (MMcfe/d): 13.1 15.0 16.1

Gross EUR (Bcfe): 15.3 16.8 19.2

Gross Well Cost ($MM): $11.8 $11.1 $8.5

Lateral Length (Feet): 8,052 8,508 9,000

Net F&D ($/Mcfe): $0.89 $0.78 $0.52

Btu: 1195 1228 1250

0

5

10

15

20

25

30

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

-

5.0

10.0

15.0

20.0

25.0

30.0

Antero’s Marcellus average 30-day rates have increased by 55% over the past two years as the Company increased per well lateral lengths by 13% and shortened stage lengths by 33% compared to year-end 2013

INCREASING RECOVERIES AND LOW VARIANCEIN MARCELLUS

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

Antero 30-Day Rates – 446 Marcellus Wells(1)

34

Antero SSL Reserves in Bcfe per 1,000’ of Lateral – 252 Marcellus Short Stage Length (SSL) Wells

2014 – 13.0 MMcfe/d

2013 – 9.4 MMcfe/d

2009–2012 – 8.0 MMcfe/d

SSL results have been highly consistent and predictable, with a standard deviation of only +/-0.3 around the 1.7 Bcf/1,000’ average (equates to 2.0 Bcfe/1,000’)

These wells provide the basis for AR’s undeveloped 3P reserve evaluations

P10: 2.42 Bcfe/1,000’P90: 1.39 Bcfe/1,000’

P10/P90: 1.7xStdDev: 0.3xP90 P10

2015 – 14.3 MMcfe/d

Antero 3P reserves are evaluated quarterly by AR engineers and audited annually by DeGolyer and MacNaughton

– Proved reserves volume delta at YE2015: 0.9%– Probable/Possible volume delta at YE2015: 1.9%

2016 YTD18.2 MMcfe/d

7,621

8,052

8,910 9,000

6,500

7,000

7,500

8,000

8,500

9,000

9,500

2013 2014 2015 2016 Forecast

34

29

24

21

15

20

25

30

35

2013 2014 2015 1Q 2016

913

1,237

1,675

2,116

0

500

1,000

1,500

2,000

2,500

2013 2014 2015 1Q 2016

$1,530

$1,340

$1,180

$950

$300

$700

$1,100

$1,500

$1,900

2013 2014 2015 2016 Forecast

MARCELLUS OPERATIONAL ADVANCES

35

Reduced Drilling Days Per Well

1. Based on statistics for drilled wells within each respective period.

Increased Lateral Length per Well (1) Increased Lateral Feet Drilled per Day

Late

ral F

eet /

Day

Dril

ling

Day

s / W

ell

Reduced Well Cost/Lateral Length ($/Feet)

Wel

l Cos

t / L

ater

al L

engt

h ($

/Fee

t)

Ave

rage

Lat

eral

Len

gth

per W

ell (

Feet

)

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

36

Increased Proppant Load by 50% While Increasing Proppant Placement to 98%

Pilot testing demonstrated improved recoveries while maintaining well density

Note: Antero acreage position reflects townships in which greater than 3,000 net acres are held. Antero 30-day rates in ethane rejection.1. 30-day rate reflects restricted choke regime.

100% operated Operating 1 drilling rig 148,000 net acres in the core rich gas/

condensate window (72% includes processable rich gas assuming an 1100 Btu cutoff)– 29% HBP with additional 60% not expiring

for 5+ years 121 operated horizontal wells completed and

online in Antero core areas− 100% drilling success rate

4 plants in-service at Seneca Processing Complex capable of processing 800 MMcf/d of rich gas− Over 500 MMcf/d being processed currently,

including third party production Net production of 526 MMcfe/d in 1Q 2016

including 21,600 Bbl/d of liquids Fifth third-party compressor station went in-

service September 2015 with a capacity of 120 MMcf/d

First AM compressor station went in-service November 2015

814 future gross drilling locations (551 or 68% are processable gas)

7.5 Tcfe of net 3P (15% liquids), includes 1.8 Tcfe of proved reserves (assuming ethane rejection)

WORLD CLASS OHIO UTICA SHALEDEVELOPMENT PROJECT

37

CadizProcessing

Plant

NORMAN UNIT30-Day Rate

2 wells average16.8 MMcfe/d (15% liquids)

RUBEL UNIT30-Day Rate

3 wells average17.2 MMcfe/d(20% liquids)

Utica Core Area

GARY UNIT30-Day Rate


Highly-Rich/Cond25,000 Net Acres

98 Gross Locations

Highly-Rich Gas16,000 Net Acres

108 Gross Locations

Rich Gas30,000 Net Acres

161 Gross Locations

Dry Gas41,000 Net Acres

263 Gross Locations

NEUHART UNIT 3H30-Day Rate16.2 MMcfe/d(57% liquids)

Condensate36,000 Net Acres

184 Gross Locations

DOLLISON UNIT 1H30-Day Rate19.8 MMcfe/d(40% liquids)

MYRON UNIT 1H30-Day Rate26.8 MMcfe/d(52% liquids)

SenecaProcessingComplex

LAW UNIT30-Day Rate


SCHAFER UNIT30-Day Rate(1)


URBAN PAD30-Day Rate

4 wells average 18.8 MMcfe/d (15% liquids)

GRAVES UNIT500’ Density Pilot

30-Day Rate4 wells average15.5 MMcfe/d(24% liquids)

FRANKLIN UNIT30-Day Rate


FRAKES UNIT30-Day Rate


8,543 8,5759,000

6,000

6,500

7,000

7,500

8,000

8,500

9,000

9,500

10,000

2014 2015 2016 Forecast

2931

24

10

20

30

40

2014 2015 1Q 2016

1,2161,406

1,606

0

400

800

1,200

1,600

2,000

2014 2015 1Q 2016

$1,550$1,360

$1,140

$300

$600

$900

$1,200

$1,500

$1,800

2014 2015 2016 Forecast

Increased Lateral Length per Well (1)

UTICA OPERATIONAL ADVANCES

38

Reduced Drilling Days Per Well

1. Based on statistics for drilled wells within each respective period.

Increased Lateral Feet Drilled per Day

Late

ral F

eet /

Day

Dril

ling

Day

s

Reduced Well Cost / Lateral Length ($/Feet)

Ave

rage

Lat

eral

Len

gth

per W

ell (

Feet

)

Wel

l Cos

t / L

ater

al L

engt

h ($

/Fee

t)

ANTERO’S FIRST UTICA DRY GAS WELL

39

Antero recently drilled and completed its first dry gas Utica well in Tyler County, WV (Rymer 4HD)− 11,409 Total Vertical Depth (TVD)− 6,620’ lateral length− 100% working interest − 20 MMcf/d restricted flow rate for first 90 days

Dry gas fairway extends from the Antero Utica acreage in eastern Ohio to the Antero Marcellus play acreage in northern West Virginia

190,000 net acres in West Virginia and Pennsylvania with net resource of 12.5 to 16 Tcf as of 9/30/2015 (not included in 37.1 Tcfe of net 3P reserves as of 12/31/2015)− 1,889 locations underlying current Marcellus Shale leasehold in

West Virginia and Pennsylvania

41,000 net acres in Ohio with net 3P reserves of 2.3 Tcf as of 12/31/2015− 263 locations in Ohio

In total, Antero has 231,000 net acres and 2,152 potential locations in the Point Pleasant high pressure, high porosity dry gas fairway in OH, WV and PA− 10,000’ to 14,500’ TVD−Density log porosity values average > 8.5% − 120’ to 130’ total thickness− 25 MMcf/d to 73 MMcf/d industry 24-hr IP flow rates− 1000 to 1040 BTU expected

NOTE: Wellbore diagram for illustrative purposes only.

Targeted Pay Zone

IP / 1,000’ Lateral (MMcf/d)

5.0 – 10.0

10.0 – 15.0

15.0 – 25.0

GulfportIrons #1-4H

5,714’ LateralIP/1,000’: 5.3 MMcf/d

RangeClaysville SC #11H

5,420’ LateralIP/1,000’: 10.9 MMcf/d

CNXGaut 4IH

5,840’ LateralIP/1,000’: 10.4 MMcf/d

EQTScotts Run

3,221’ LateralIP/1,000’: 22.6 MMcf/d

GastarBlake U-7H


GastarSims U-5H


Stone EnergyPribble 6HU


Magnum HunterStalder #3UH5,050’ Lateral

IP/1,000’: 6.4 MMcf/d

Magnum HunterStewart Winland 1300U


Utica Dry Gas Fairway

AnteroRymer 4HD

6,620’ LateralIP 20.0 MMcf/d

Keys to Execution

Local Presence

Antero has more than 3,500 employees and contract personnel working full-time for Antero in West Virginia. 79% of these personnel are West Virginia residents.

District office in Marietta, OH District office in Bridgeport, WV 227 (48%) of Antero’s 473 employees are located in West Virginia and Ohio

Safety & Environmental

Five company safety representatives and 57 safety consultants cover all material field operations 24/7 including drilling, completion, construction and pipelining

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

Central Fresh Water System & Water Recycling

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

Antero recycled over 74% of its flowback and produced water through 2014 Building state of the art wastewater treatment facility in WV (60,000 Bbl/d)

Natural Gas Vehicles (NGV)

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

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

Natural Gas Powered Drilling Rigs & Frac Equipment

6 of Antero’s contracted drilling rigs are currently running on natural gas First natural gas powered clean fleet frac crew began operations summer 2014

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 Corporate headquarters in Denver, Colorado LEED Gold Certified

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

Strong West Virginia Presence 79% of all Antero Marcellus

employees and contract workers are West Virginia residents

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

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

40

CLEAN FLEET & CNG TECHNOLOGY LEADER

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

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

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

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

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

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

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

− Significantly reduces noise pollution from a well site

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

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

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

continue to convert its truck fleet to NGV

41

42

Antero Midstream (NYSE: AM)Asset Overview

Regional Gas Pipelines

Miles Capacity In-Service

Stonewall Gathering Pipeline(2)

50 1.4 Bcf/d Yes

1. Acquired by AM from AR for a $1.05 billion upfront payment and a $125 million earn out in each of 2019 and 2020. 2. AM holds option to purchase 15% of Stonewall pipeline at cost plus cost of carry.

EndUsers

EndUsers

Gas Processing

Y-Grade Pipeline

Long-Haul Interstate

Pipeline

InterConnect

NGL Product Pipelines

Fractionation

Compression

Low Pressure Gathering

Well Pad

Terminalsand

Storage

(Miles) YE 2015 YE 2016E

Marcellus 106 114

Utica 55 56

Total 161 170

AM has option to participate in processing, fractionation,

terminaling and storage projects offered to AR


Marcellus 76 98

Utica 36 36

Total 112 134

(MMcf/d) YE 2015 YE 2016E

Marcellus 700 940

Utica 120 120

Total 820 1,060

AM Owned Assets

Condensate GatheringStabilization


Utica 19 19

EndUsers

AM Option Assets

(Ethane, Propane, Butane, etc.)

AM’S FULL VALUE CHAIN BUSINESS MODEL

43

1. Represents inception to date actuals as of 12/31/2015 and 2016 guidance.2. Includes both expansion capital and maintenance capital.

44

UticaShale

MarcellusShale

Projected Gathering and Compression Infrastructure(1)

Marcellus Shale

Utica Shale Total

YE 2015 Cumulative Gathering/ Compression Capex ($MM) $981 $462 $1,443

Gathering Pipelines(Miles) 182 91 273

Compression Capacity(MMcf/d) 700 120 820

Condensate Gathering Pipelines (Miles) - 19 19

2016E Gathering/Compression Capex Budget ($MM)(2) $235 $20 $255

Gathering Pipelines (Miles) 30 1 31

Compression Capacity(MMcf/d) 240 - 240

Condensate Gathering Pipelines (Miles) - - -

Gathering and Compression Assets

ANTERO MIDSTREAM GATHERING AND COMPRESSION ASSET OVERVIEW

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

– Acreage dedication of ~442,000 net leasehold acres for gathering and compression services

– Additional stacked pay potential with dedication on ~148,000 acres of Utica deep rights underlying the Marcellus in WV and PA

– 100% fixed fee long term contracts

• AR owns 62% of AM units (NYSE: AM)

ANTERO MIDSTREAM WATER BUSINESS OVERVIEW

45Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.1. Represents inception to date actuals as of 12/31/2015 and 2016 guidance.2. All Antero water withdrawal sites are fully permitted under long-term state regulatory permits both in WV and OH. 3. Includes both expansion capital and maintenance capital. 4. Marcellus assumes fee of $3.685 per barrel subject to annual inflation and 250,000 barrels of water per well that utilize the fresh water delivery system based on 9,000 foot lateral. Operating margin

excludes G&A. Utica assumes fee of $3.635 per barrel subject to annual inflation and 275,000 barrels of water per well that utilize the fresh water delivery system based on 9,000 foot lateral. Operating margin excludes G&A.

AM acquired AR’s integrated water business for $1.05 billion plus earn out payments of $125 million at year-end in each of 2019 and 2020− The acquired business includes Antero’s Marcellus and Utica freshwater delivery business, the fully-contracted future advanced wastewater

treatment complex and all fluid handling and disposal services for Antero

Antero advanced wastewater treatment facility to be constructed – connects to Antero freshwater delivery system

Projected Water Business Infrastructure(1)

Marcellus Shale

Utica Shale Total

YE 2015 Cumulative Fresh WaterDelivery Capex ($MM) $469 $62 $531

Water Pipelines(Miles) 184 75 259

Fresh Water StorageImpoundments 22 13 35

2016E Fresh Water Delivery Capex Budget ($MM)(3) $40 $10 $50

Water Pipelines(Miles) 20 9 29

Fresh Water StorageImpoundments 1 - 1

Cash Operating Margin per Well(4) $700k - $750k

$775k -$825k

2016E Advanced Waste Water Treatment Budget ($MM) $130

2016E Total Water Business Budget ($MM) $180

Water Business Assets

• Fresh water delivery assets provide fresh water to support Marcellus and Utica well completions– Year-round water supply sources: Clearwater Facility, Ohio

River, local rivers & reservoirs(2)

– 100% fixed fee long term contracts

010,00020,00030,00040,00050,00060,00070,00080,000

Antero Clearwater Advanced Wastewater Treatment Capacity (Bbl/d)

Produced/Flowback Volumes (Bbl/d)

Illustrative Produced & Flowback Water VolumesAdvanced Wastewater Treatment

Antero Produced Water Services and Freshwater Delivery Business

Antero AdvancedWastewater Treatment

3rd Party Recyclingand Well Disposal

(Bbl/d)

Advanced Wastewater Treatment ComplexEstimated capital expenditures ($ million)(1) ~$275Standalone EBITDA at 100% utilization(2) ~$55 – $65Implied investment to standalone EBITDA build-out multiple ~4x – 5xEstimated per well savings to Antero Resources ~$150,000Estimated in-service date Late 2017Operating capacity (Bbl/d) 60,000Operating agreement

• Antero has contracted with Veolia to integrate an advanced wastewater treatment complex into its water business

• Veolia will build and operate, and Antero will own largest advanced wastewater treatment complex in Appalachia− Will treat and recycle AR produced and flowback water− Creates additional year-round water source for completions− Will have capacity for third party business over first two years

1. Includes capital to construct pipeline to connect facility to freshwater delivery system. Includes $10 million that AR agreed to fund in the drop down transaction. 2. Standalone EBITDA projection assumes inter-company fixed fee for recycling of $4.00 per barrel and 60,000 barrels per day of capacity. Does not include potential sales of marketable byproducts.

20 Years, Extendable

46Integrated Water Business

Antero Advanced Wastewater Treatment

Freshwater delivery system

Flowback and produced

Water

Well Pad

Well Pad

CompletionOperations

Producing

Freshwater

Salt

Calcium Chloride

Marketable byproduct

Marketable byproduct used in oil and gas operations

Freshwater delivery system

ANTERO MIDSTREAM ADVANCED WASTEWATER TREATMENT ASSET OVERVIEW

10 38 80 126 266

531

908

1,134 1,197 1,216 1,195 1,222

0200400600800

1,0001,2001,4001,6001,800 Utica Marcellus

108 216 281 331 386

531

738

935 965 1,038

1,124

1,303

0

200

400

600

800

1,000

1,200

1,400

1,600 Utica Marcellus

26 31 40 36 41 116

222

358

454 435478

606

0

100

200

300

400

500

600

700

800 Utica Marcellus

$1 $5 $7 $8 $11$19

$28$36

$41

$55

$83

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

$100

Low Pressure Gathering (MMcf/d)

Compression (MMcf/d)

High Pressure Gathering (MMcf/d)

EBITDA ($MM)

47

$313

Note: Y-O-Y growth based on 1Q’15 to 1Q’16.1. Represents midpoint of 2016 guidance.

HIGH GROWTH MIDSTREAM THROUGHPUT

0.0x0.5x1.0x1.5x2.0x2.5x3.0x3.5x4.0x4.5x

Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7

Tota

l Deb

t / L

TM E

BIT

DA

• $1.5 billion revolver in place to fund future growth capital (5x Debt/EBITDA Cap)

• Liquidity of $887 million at 12/31/2015

• Sponsor (NYSE: AR) has Ba2/BB corporate ratings

AM Liquidity (12/31/2015)

AM Peer Leverage Comparison(1)

($ in millions)

Revolver Capacity $1,500

Less: Borrowings 620

Plus: Cash 7

Liquidity $887

1. As of 12/31/2015. Peers include TEP, EQM, WES, RMP, SHLX, DM, and CNNX.2. AM includes full year EBITDA contribution from water business.

Financial Flexibility

SIGNIFICANT FINANCIAL FLEXIBILITY

48

(2)

49

APPENDIX

49

($ in millions) 12/31/2015 Pro Forma for AM

Unit Sale(4)

Cash $23 $23

Senior Secured Revolving Credit Facility 707 529Midstream Bank Credit Facility 620 6206.00% Senior Notes Due 2020 525 5255.375% Senior Notes Due 2021 1,000 1,0005.125% Senior Notes Due 2022 1,100 1,1005.625% Senior Notes Due 2023 750 750Net Unamortized Premium 7 7Total Debt $4,709 $4,531Net Debt $4,686 $4,508

Financial & Operating StatisticsLTM EBITDAX(1) $1,221 $1,221LTM Interest Expense(2) $237 $234Proved Reserves (Bcfe) (12/31/2015) 13,215 13,215

Proved Developed Reserves (Bcfe) (12/31/2015) 5,838 5,838

Credit Statistics

Net Debt / LTM EBITDAX 3.8x 3.7xNet Debt / Net Book Capitalization 39% 38%Net Debt / Proved Developed Reserves ($/Mcfe) $0.80 $0.77Net Debt / Proved Reserves ($/Mcfe) $0.35 $0.34

LiquidityCredit Facility Commitments(3) $5,500 $5,500Less: Borrowings (1,327) (1,149)Less: Letters of Credit (702) (702)Plus: Cash 23 23

Liquidity (Credit Facility + Cash) $3,494 $3,672

ANTERO CAPITALIZATION – CONSOLIDATED

1. LTM and 12/31/2015 EBITDAX reconciliation provided below.2. LTM interest expense adjusted for all capital market transactions since 1/1/2015.3. AR lender commitments under the facility increased to $4.0 billion from $3.0 billion on 2/17/2015; borrowing base capacity increased to $4.5 billion from $4.0 billion on 10/26/2015. AM credit facility

increased to $1.5 billion concurrent with water drop down on 9/23/2015.4. Pro forma for AR sale of 8.0 million AM units for net proceeds of $178 million on 3/24/2016.

50

ANTERO RESOURCES – 2016 GUIDANCE

Key Variable 2016 GuidanceNet Daily Production (MMcfe/d) 1,715

Net Residue Natural Gas Production (MMcf/d) 1,355

Net C3+ NGL Production (Bbl/d) 46,500

Net Ethane Production (Bbl/d) 10,000

Net Oil Production (Bbl/d) 3,500

Net Liquids Production (Bbl/d) 60,000

Natural Gas Realized Price Premium to NYMEX Henry Hub Before Hedging ($/Mcf)(1)(2) +$0.00 to $0.10

Oil Realized Price Differential to NYMEX WTI Oil Before Hedging ($/Bbl) $(10.00) - $(11.00)

C3+ NGL Realized Price (% of NYMEX WTI)(1) 35% - 40%

Ethane Realized Price (Differential to Mont Belvieu) ($/Gal) $0.00

Operating:Cash Production Expense ($/Mcfe)(3) $1.50 - $1.60

Marketing Expense, Net of Marketing Revenue ($/Mcfe) $0.15 - $0.20

G&A Expense ($/Mcfe) $0.20 - $0.25

Operated Wells Completed 110

Drilled Uncompleted Wells 70

Average Operated Drilling Rigs ≈ 7

Capital Expenditures ($MM):Drilling & Completion $1,300

Land $100

Total Capital Expenditures ($MM) $1,4001. Based on current strip pricing as of December 31, 2015. 2. Includes Btu upgrade as 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 Operating & Financial Assumptions

51

ANTERO MIDSTREAM – 2016 GUIDANCE

Key Variable 2016 GuidanceFinancial:Adjusted EBITDA ($MM) $300 - $325

Distributable Cash Flow ($MM) $250 - $275

Year-over-Year Distribution Growth(1) 28% - 30%

Operating:Low Pressure Pipeline Added (Miles) 9

High Pressure Pipeline Added (Miles) 22

Compression Capacity Added (MMcf/d) 240

Fresh Water Pipeline Added (Miles) 30

Capital Expenditures ($MM):Gathering and Compression Infrastructure $240

Fresh Water Infrastructure $40

Advanced Wastewater Treatment $130

Maintenance Capital $25

Total Capital Expenditures ($MM) $435

1. Reflects the expected distribution growth percentage associated with the fourth quarter 2016 over the fourth quarter 2015.

Key Operating & Financial Assumptions

52

23% Common Units Held by AR

34% Common Units Held by

Public

43%Subordinated

Units Held by AR

PRO FORMA IMPACT OF AM UNIT OFFERING

Antero Midstream Pro Forma Ownership

AR Consolidated Pro Forma Capitalization (12/31/15)Transaction Details

On 3/24/2016, AR priced the sale of 8 million units of AM at $22.40 per unit raising $178 million in net proceeds to repay AR bank debt

Pro forma the monetization, AR reduced its YE 2015 consolidated leverage from 3.8x to 3.7x, while still maintaining a 62% ownership in AM– Post transaction AM ownership value of $2.4 billion

Net proceeds of $178 million will fund a significant portion of the expected outspend in 2016 (excluding 1.2 million unit shoe exercise)

Following the offering Antero Resources will maintain a 62% ownership of common

and subordinated units in Antero Midstream

As of 12/31/15 Pro Forma

43% Subordinated Units Held by

AR

19% Common Units Held by AR

38% Common Units Held by

Public

1. Net of offering costs. 2. Based on AR credit facility commitment of $4.0 billion and AM credit facility of $1.5 billion.3. Based on AM closing price of $22.11 on 03/31/2016.

Antero AnteroResources Resources

$MM 12/31/2015 Adjustment Pro FormaCash $23 $23

Credit facility (AR) $707 ($178) (1) $529Credit facility (AM) 620 $6206.00% senior notes due 2020 525 5255.375% senior notes due 2021 1,000 1,0005.125% senior notes due 2022 1,100 1,1005.625% senior notes due 2023 750 750Total Debt $4,702 ($178) (1) $4,524

Net Debt $4,679 ($178) $4,501

Financial DataLTM EBITDAX $1,221 $1,221

Credit StatisticsNet Debt / LTM EBITDAX 3.8x 3.7x

LiquidityCash $23 $23Credit facility – commitments (2) $5,500 $5,500 Credit facility – drawn (1,327) 178 (1,149) Credit facility – letters of credit (702) (702)Total Liquidity $3,494 $178 $3,672

AM Common Units Owned by AR 40.9 (8.0) 32.9AM Subordinated Units Owned by AR 75.9 75.9

Value of AR-Owned AM Units (3) $2,584 ($178) $2,407

53

522

1,007

1,493

1,758 1,715

2,058

0

500

1,000

1,500

2,000

2,500

2013 2014 2015 1Q16 2016E 2017E

MM

cfe/

d

Actual Guidance/Target

DELIVERING RECORD PRODUCTION VOLUMES

1Q 2016 net production of 1,758 MMcfe/d was 18% above 4Q 2015 Driven by excellent operational execution and strong new well results

54

118%

93%

48%

15%Guidance

20%Target

18%

$1,300

$100

Drilling & Completion Land

2016 CAPITAL BUDGET

By Area

55

$1.8 Billion – 2015(1)

By Segment ($MM)

$1,650

$160

Drilling & Completion Land

56%44%

Marcellus Utica

By Area

$1.4 Billion – 2016By Segment ($MM)

Antero’s 2016 initial capital budget is $1.4 billion, a 23% decrease from 2015 capital expenditures of $1.8 billion and a 58%decline from 2014 capital expenditures

23%

131 Completions 50 DUCs

1. Excludes $39 million for leasehold acquisitions in 2015. DUCs are drilled but uncompleted wells at year-end.

110 Completions 70 DUCs

75%

25%

Marcellus Utica

1.2x

0.0x1.0x2.0x3.0x4.0x5.0x6.0x

AR Peer 6 Peer 1 Peer 2 Peer 4 Peer 3 Peer 5 Peer 7

$3,117

$0$500

$1,000$1,500$2,000$2,500$3,000$3,500


Mark-to-Market Hedge Value ($MM)

$941 $0

$2,000$4,000$6,000$8,000

$10,000$12,000$14,000$16,000


E&P Debt (Net of Cash and M-T-M Hedge Value) ($MM)(1)

56

HEDGE BOOK SUPPORTS FINANCIAL PROFILE

Note: Data presented as filed for the year ended December 31, 2015. Peer group comprised of Ba1 and Ba3 credit peers including APC, CLR, CXO, HES, MUR, NFX, RRC. 1. Represents total E&P debt less cash and mark-to-market hedge value.

Antero exceeds closest credit peer by $2.3 billion

AR net leverage maps with strong Baa credit peers

Only credit peer with less than $1.0 billion of E&P debt

Ba1 Credit Peer

Ba3 Credit Peer

E&P Debt (Net of Cash and M-T-M Hedge Value) / LTM EBITDAX (Exclud. Realized Hedging Revenue) ($MM)

90%

83%80%

74%

69%

51%

46% 45%

39%

25%

15% 14%11%

39%

22%

13%

44%

53%

2%

23% 22%19%

1%

6%

80%

31%

14%

8%5%

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

70.0%

80.0%

90.0%

100.0%

AR Peer 1 Peer2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 12 Peer 13 Peer 14 Peer 15

2016 2017 2018

HIGHEST PROPORTION HEDGED AMONG E&P OPERATORS

57

Antero has substantially de-risked its cash flow profile and differentiated itself versus its peer group through its extensive hedge portfolio, with 100% of forecasted production hedged in

2016 and 2017 and 80% of consensus estimated production hedged in 2018

Source: Public filings. Projected production for peers based on consensus estimates. Projected production for AR based on 2016 guidance of 15% growth, 2017 target of 20% growth, and 2018 consensus estimates. Note: Peers include APC, CHK, CLR, COG, CXO, EOG, EQT, GPOR, NBL, NFX, PXD, RICE, RRC, SWN, WPX.1. As of December 31, 2015.

0% - >0% - >

100%+

2016 Average Peer Production Hedged: 43%



Total Production Hedged (% of Forecasted / Consensus Production)• Antero has 3.5 Tcfe hedged at average price of

$3.79/MMBtu and $3.1 Billion mark-to-market(1)

• 94% hedged through 2018 at $3.81/MMBtu

0% - >0% - >

Peer Group Average Production Hedged Through 2018: 20%

Antero Production Hedged Through 2018: 94%

1,793 2,079 2,015 2,330 1,378 630 120

$3.91 $3.57 $3.91 $3.70 $3.66 $3.36 $3.24

$2.26$2.77 $2.87 $2.93 $3.03 $3.17 $3.34

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

0200400600800

1,0001,2001,4001,6001,800

Bal '16 2017 2018 2019 2020 2021 2022

BBtu/d $/MMBtu

$4

-$8

$5 $25 $34 $29 $28 $26 $12 $16 $17 $28 $29 $19 $25 $43$80 $83 $59 $49 $48

$14

$47 $54

-$1

$1

$58 $78

$185 $196$206

$275$324

($2.00)($1.00)$0.00$1.00$2.00$3.00$4.00

($70.0)$0.0

$70.0$140.0$210.0$280.0$350.0

Quarterly Realized Gains/(Losses)1Q '08 - 1Q '16

58

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

COMMODITY HEDGE POSITION

~$3.1 billion mark-to-market unrealized gain based on 3/31/2016 prices 3.6 Tcfe hedged from April 1, 2016 through year-end 2022

$832 MM $558 MM $740 MM $617 MM $291 MM $39 MM

Mark-to-Market Value(2)

LARGEST GAS HEDGE POSITION IN U.S. E&P

~ 100% of 2016 Guidance Hedged

581. Weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio; excludes impact of TCO basis hedges. 30,000 Bbl/d of propane hedged in 2016, 36,500 Bbl/d hedged in 2017 and 2,000 Bbl/d hedged in 2018.

2. As of 3/31/2016.

Hedging is a key component of Antero’s business model due to the large, repeatable drilling inventory Antero has realized $2.1 billion of gains on commodity hedges since 2008

– Gains realized in 31 of last 33 quarters$MM $/Mcfe

($4) MM

~ 100% of 2017 Target Hedged

0.10.4

0.9

1.8

3.5

5.6

$0.0$0.5$1.0$1.5$2.0$2.5$3.0$3.5$4.0$4.5$5.0

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

2010 2011 2012 2013 2014 2015

Utica Marcellus Borrowing Base

$4.5 Bn

OUTSTANDING RESERVE GROWTH

1. 2012, 2013, 2014 and 2015 reserves assuming ethane rejection. 2015 SEC prices were $2.56/MMBtu for natural gas and $50.13/Bbl for oil on a weighted average Appalachian index basis.59

3P RESERVES BY VOLUME – 2015(1)NET PDP RESERVES (Tcfe)(1)

NET PROVED RESERVES (Tcfe)(1) 2015 RESERVE ADDITIONS• Proved reserves increased 4% to 13.2 Tcfe at 12/31/2015 with a pre-tax

PV-10 of $6.7 billion at SEC pricing, including $3.1 billion of hedges− Proved PV-10 at strip pricing of $8.2 billion, including $2.5 billion of

hedges• 3P reserves were 37.1 Tcfe at 12/31/2015 with a pre-tax PV-10 of $6.8

billion at SEC pricing, including $3.1 billion of hedges− 3P PV-10 at strip pricing of $13.7 billion, including $2.5 billion of hedges

• All-in finding and development cost of $0.80/Mcfe for 2015 (includes land and all price and performance revisions)

• Drill bit only finding and development cost of $0.71/Mcfe for 2015• Only 69% of 3P Marcellus locations booked as SSL (1.7 Bcf/1,000’ type

curve) at 12/31/2015• Negligible Utica Shale WV/PA dry gas reserves booked – estimated

net resource of 12.5 – 16 Tcf0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

2010 2011 2012 2013 2014 2015

Marcellus Utica

0.7

2.84.3

7.6

12.7

(Tcfe)

13.2

13.2 TcfeProved

21.4 TcfeProbable

2.5 TcfePossible

Proved

Probable

Possible

37.1 Tcfe 3P

93% 2P Reserves

(Tcfe) $Bn

$550 MM

Gas – 27.6 Tcf

Oil – 92 MMBbls

NGLs – 2,382 MMBbls

Gas – 29.7 Tcf

Oil – 92 MMBbls

NGLs – 1,145 MMBbls

CONSIDERABLE RESERVE BASE WITH ETHANE OPTIONALITY 27 year proved reserve life based on 2015 production annualized Reserve base provides significant exposure to liquids-rich projects

– 3P reserves of over 2.4 BBbl of NGLs and condensate in ethane recovery mode; 35% 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.

2. 1.1 Tcfe of ethane reserves (182 million barrels) was included in 12/31/2015 reserves from the Marcellus Shale as the first de-ethanizer was placed online at the MarkWest Sherwood facility in December 2015 and Antero’s first ethane sales contract is expected to commence in 2017 upon the completion of Mariner East 2.

ETHANE REJECTION(1)(2) ETHANE RECOVERY(1)

60

Marcellus – 29.6 Tcfe

Utica – 7.5 Tcfe

37.1Tcfe

Marcellus – 34.0 Tcfe

Utica – 8.4 Tcfe

42.4Tcfe

20%Liquids

35%Liquids

LARGE UTICA SHALE DRY GAS POSITION

61

Antero has completed its first dry gas Utica well – a 6,620’ lateral in Tyler County, WV

Antero has 231,000 net acres of exposure to Utica dry gas play in OH, WV and PA

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

ChesapeakeHubbard BRK #3H


HessPorterfield 1H-17


GulfportIrons #1-4H5,714’ Lateral

IP 30.3 MMcf/d

EclipseTippens #6H5,858’ Lateral

IP 23.2 MMcf/d

Magnum HunterStalder #3UH5,050’ Lateral

IP 32.5 MMcf/d

Well Operator24-hr IP(MMcf/d)

LateralLength

(Ft)

24-hr IP/1,000’Lateral

(MMcf/d)

Scotts Run EQT 72.9 3,221 22.633

Gaut 4IH CNX 61.0 5,840 11.131

CSC #11H RRC 59.0 5,420 10.886

Stewart-Win 1300U MHR 46.5 5,289 8.792

Bigfoot 9H RICE 41.7 6,957 5.994

Blank U-7H GST 36.8 6,617 5.561

Stalder #3UH MHR 32.5 5,050 6.436

Irons #1-4H GPOR 30.3 5,714 5.303

Pribble 6HU SGY 30.0 3,605 8.322

Simms U-5H GST 29.4 4,447 6.611

Conner 6H CVX 25.0 6,451 3.875

Messenger 3H SWN 25.0 5,889 4.245

Tippens #6H ECR 23.2 5,858 3.960

Porterfield 1H-17 HESS 17.2 5,000 3.440

1. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held in OH, WV and PA.2. The Rymer 4HD has been flowing into the sales line for 90 days with an average choke-restricted flow rate of 20 MMcf/d.

Magnum HunterStewart Winland 1300U


RangeClaysville SC #11H


ChevronConner 6H

6,451’ LateralIP 25.0 MMcf/dGastar

Simms U-5H4,447’ Lateral

IP 29.4 MMcf/d

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

RiceBigfoot 9H


AR Utica Shale Dry GasWV/PA

Net Resource12.5 to 16 Tcf

1,889 Gross Locations190,000 Net Acres

AR Utica Shale Dry GasOhio

3P Reserves2.3 Tcf

263 Gross Locations41,000 Net Acres

AR Utica Shale Dry GasTotal OH/WV/PA

Net Resource14.8 to 18.3 Tcf

2,152 Gross Locations231,000 Net Acres

Stone EnergyPribble 6HU


SouthwesternMessenger 3H5,889’ Lateral

IP 25.0 MMcf/d

RiceBlue Thunder

10H, 12H≈9,000’ Lateral

GastarBlake U-7H


EQTScotts Run


CNXGaut 4IH


AnteroRymer 4HD


(2)

626

971

553755

63%47%

24% 28%35%

24%10% 13% 0

2004006008001,0001,200

0%

20%

40%

60%

80%

Highly-Rich Gas/Condensate


Tota

l 3P

Loca

tions

RO

RTotal 3P LocationsROR @ 3/31/2016 Strip Pricing - After HedgesROR @ 3/31/2016 Strip Pricing - Before Hedges

MARCELLUS SINGLE WELL ECONOMICS – IN ETHANE REJECTION

62

DRY GAS LOCATIONS RICH GAS LOCATIONS

HIGHLY RICH GAS

LOCATIONS

Assumptions Natural Gas – 3/31/2016 strip Oil – 3/31/2016 strip NGLs – 37.5% of Oil Price 2016; 50%

of Oil Price 2017+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 $3.17-$3.80 $51-$53 $27-$27

Marcellus Well Economics and Total Gross Locations(1)

ClassificationHighly-Rich Gas/

CondensateHighly-Rich

Gas Rich Gas Dry GasModeled BTU 1313 1250 1150 1050EUR (Bcfe): 20.8 18.8 16.8 15.3EUR (MMBoe): 3.5 3.1 2.8 2.6% Liquids: 33% 24% 12% 0%Lateral Length (ft): 9,000 9,000 9,000 9,000Well Cost ($MM): $8.5 $8.5 $8.5 $8.5Bcfe/1,000’: 2.3 2.1 1.9 1.7Net F&D ($/Mcfe): $0.48 $0.53 $0.60 $0.65Direct Operating Expense ($/well/month): $1,498 $1,498 $1,498 $1,498Direct Operating Expense ($/Mcf): $0.92 $0.92 $1.17 $0.70Transportation Expense ($/Mcf): $0.28 $0.28 $0.28 $0.28

Pre-Tax NPV10 ($MM): $8.7 $5.3 $0.0 $1.0Pre-Tax ROR: 35% 24% 10% 13%Payout (Years): 2.5 3.7 8.2 6.8

Gross 3P Locations in BTU Regime(3): 626 971 553 755



3. Undeveloped well locations as of 12/31/2015.

2016Drilling

Plan

184

98108

161 263

14%

48%64%

56% 64%

9%

23% 24% 20% 24%

050100150200250300

0%

20%

40%

60%

80%

100%

Condensate Highly-Rich Gas/Condensate


Tota

l 3P

Loca

tions

RO

R

Total 3P LocationsROR @ 3/31/2016 Strip Pricing - After HedgesROR @ 3/31/2016 Strip Pricing - Before Hedges

UTICA SINGLE WELL ECONOMICS – IN ETHANE REJECTION

63

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 GasModeled BTU 1275 1235 1215 1175 1050EUR (Bcfe): 9.4 17.0 25.3 23.8 21.4EUR (MMBoe): 1.6 2.8 4.2 4.0 3.6% Liquids 35% 26% 21% 14% 0%Lateral Length (ft): 9,000 9,000 9,000 9,000 9,000Well Cost ($MM): $10.0 $10.0 $10.25 $10.25 $10.25Bcfe/1,000’: 1.0 1.9 2.8 2.7 2.4Net F&D ($/Mcfe): $1.31 $0.73 $0.50 $0.53 $0.59Fixed Operating Expense ($/well/month): $2,788 $2,788 $2,788 $2,788 $1,498Direct Operating Expense ($/Mcf): $0.99 $0.99 $0.99 $0.99 $0.50Direct Operating Expense ($/Bbl): $2.73 $2.73 $2.73 - -Transportation Expense ($/Mcf): $0.55 $0.55 $0.55 $0.55 $0.55

Pre-Tax NPV10 ($MM): ($0.8) $4.8 $6.3 $4.5 $5.8Pre-Tax ROR: 9% 23% 24% 20% 24%Payout (Years): 8.5 3.3 3.3 4.1 3.4

Gross 3P Locations in BTU Regime(3): 184 98 108 161 263



3. Undeveloped well locations as of 12/31/2015. 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content.

2016Drilling

Plan

Assumptions Natural Gas – 3/31/2016 strip Oil – 3/31/2016 strip NGLs – 37.5% of Oil Price 2016; 50%

of Oil Price 2017+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 $3.17-$3.80 $51-$53 $27-$27

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

2016 FT Portfolio and Projected Gas Sales

Net Production Target (MMcfe/d) (1) 1,715Net Gas Production Target (MMcf/d) (80% of Net Production) 1,372Net Revenue Interest Gross-up 80%Gross Gas Production Target (MMcf/d) 1,715BTU Upgrade (2) x1.100 Gross Gas Production Target (BBtu/d) 1,885

Firm Transportation / Firm Sales (BBtu/d) 3,525Estimated % Utilization of FT/FS 53%

Excess Firm Transportation 1,640Marketable Firm Transport (BBtu/d) (3) 1,015Unmarketable Firm Transportation 625

Estimated % Utilization of FT/FS Portfolio (Including Marketable FT) 82% 641. Based on 2016 net daily production guidance.2. Assumes 1100 BTU residue sales gas.3. Represents excess firm transportation that is deemed marketable to 3rd parties based on a positive differential between the receipt and delivery points of the FT capacity, less variable transport cost.

• Antero projects firm transportation in excess of equity gas production of approximately 1,640 BBtu/d in 2016

• Expect to market or mitigate a portion of the cost of approximately 1,015 BBtu/d of the excess FT with 3rd

party gas• Expect to fully utilize FT portfolio by 2019, based on

five year development plan (excludes Appalachia based FT directed to unfavorable indices)

(BBtu/d)

2016 Targeted Gross Gas

Production(1)

1,885 BBtu/d

Unmarketable Unutilized Firm Transport

~625 BBtu/d ($0.15 / MMBtu)

Marketable Unutilized Firm Transport ~1,015 BBtu/d

($0.39 / MMBtu)

Utilized Firm Transport / Firm Sales

~1,885 BBtu/d($0.45 / MMBtu)

Total Firm Transport

3,525 BBtu/d

Excess Capacity Marketable /

FT Segment (Location) (BBtu/d) Unmarketable

Columbia / TGP (Marcellus) 550 MarketableANR North / ANR South (Utica) 465 MarketableEQT / M3 (Marcellus) 625 Unmarketable

Total Excess Firm Transport 1,640

2016 Firm Transport

Dec

reas

ing

Cos

t of F

T

PORTFOLIO APPROPRIATELY DESIGNEDTO ACCOMMODATE GROWTH

($ in millions, except per unit amounts) Demand 2016E 2016E 2016EFee Marketing Marketing Marketing

($ / MMBtu) Expenses Revenue Expenses, Net"Unmarketable" Firm Transport

625 BBtu/d of EQT / M3 Appalachia FT $0.15 $35 - $35

"Marketable" Firm Transport Capacity550 BBtu/d of Columbia / TGP $0.49 $99 $43 - $72 $27 - $56465 BBtu/d of ANR North / ANR South $0.24 42 $6 - $11 $31 - $36

Sub-Total $141 $49 - $83 $58 - $92

Grand Total - 2016 Marketing Expenses, Net $176 $49 - $83 ~$95 to $125 MM

$ / Mcfe - 2016 Targeted Production (1) $0.28 $0.08 - $0.13 $0.15 - $0.20

65NOTE: Analysis based on strip pricing as of 12/31/15. 1. Represents 2016 net production growth guidance of 15% to 1,715 MMcfe/d.2. Spread for each respective “marketable” firm transport represents the difference between the gas price Antero

would receive at the delivery point of each pipeline versus the price Antero would pay to buy gas at the receipt point of each piece of capacity, less the variable costs to transport on each segment of firm transportation.

2016 Projected Marketing Expenses:

0

600

1,200

1,800

2,400

3,000

3,600

(BBt

u/d)

2016 Targeted Gross Gas Production

1,885 BBtu/d

$0.06 / Mcfe of 2016E Production (2)

$0.09 to $0.14 / Mcfe of 2016E Production (2)

Utilized FT$0.45 / Mcfe of 2016E

Production (2)

2016 FT and Marketing Expenses per Unit:

2016 Marketing Revenue Projection:

Based on the 2016 guidance of 15% annual production growth, Antero projects net marketing

expenses of $0.15 to $0.20 per Mcfe in 2016Gathering

& Transportation Costs

MarketableNet Marketing

Expense

UnmarketableNet Marketing

Expense

Unmarketable (EQT / M3) ($/MMBtu)2016 TETCO M2 Pricing (Sold Gas) $1.562016 TETCO M2 Pricing (Bought Gas) (1.56)

Total Spread $0.00

Marketable (TCO / TGP) ($/MMBtu)2016 TGP-500 Pricing (Sold Gas) $2.432016 TETCO M2 Pricing (Bought Gas) (1.56)Less: Variable FT Costs (0.15)

Total Spread ("In the Money") $0.72

Illustrative Marketing Example:

Positive Spread

No Spread

2016EMarketing 2016E Marketing Revenue

Spread Assuming % Volume Mitigated($ / MMBtu) (2) 30% 50%

"Marketable" Firm Transport Capacity550 BBtu/d of Columbia / TGP $0.72 $43 $72465 BBtu/d of ANR North / ANR South $0.12 6 11

Sub-Total $49 $83$ / Mcfe - 2016E Targeted Production (1) $0.08 $0.13

FT MARKETING EXPENSE UPDATE

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

$0.12

$0.13

$0.00

$0.10

$0.20

$0.30

$0.40

$0.50

$0.60

$0.70

2013A 2014A 2015A 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 – 3.55 Bcf/dAverage All-in FT Cost $0.46/MMBtu

+ $0.18/MMBtu

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

Reduces weighted average basis by $0.35 per MMBtu compared to 2014 basis – 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 as at 03/31/2016.

Included in cash production expense

(variable cost)$0.25 $0.28

$0.35$0.46

2016 Basis(3)

TCO – $(0.14)/MMBtu DOM S – $(0.87)/MMBtu

2016 Basis(3)

Chicago – $(0.03)/MMBtu

2016 Basis(3)

CGTLA – $(0.06)/MMBtu

66

Appalachia36%

Midwest21%

Gulf Coast43%

$525

$1,000 $1,100

$750

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

2015 2016 2017 2018 2019 2020 2021 2022 2023

($ in

Mill

ions

)

$1,500

$887

($620)

$0 $7

$0

$250

$500

$750

$1,000

$1,250

$1,500

Credit Facility12/31/2015

Bank Debt12/31/2015

L/Cs Outstanding12/31/2015

Cash12/31/2015

Liquidity 12/31/2015

67

STRONG FINANCIAL LIQUIDITY AND DEBT TERM STRUCTURE

67

$4,000$2,785

($529)($702) $16

$0

$1,000

$2,000

$3,000

$4,000

Credit Facility12/31/2015

Bank Debt12/31/2015

L/Cs Outstanding12/31/2015

Cash12/31/2015

Liquidity12/31/2015

AR LIQUIDITY POSITION ($MM)(1) AM LIQUIDITY POSITION ($MM)

Approximately $3.7 billion of combined AR and AM financial liquidity as of 12/31/2015 pro forma for AR sale of 8.0 million AM units on 3/24/2016 No leverage covenant in AR bank facility, only interest coverage and working capital covenants

AR Credit Facility AR Senior Notes

DEBT MATURITY PROFILE(1)

Recent credit facility increases and equity offerings have allowed Antero to reduce its cost of debt to 4.3% and significantly enhance liquidity with an average debt maturity is February 2021

AM Credit Facility

$620

1. Pro forma for AR sale of 8.0 million AM units for net proceeds of $178 million on 3/24/2016.

Moody's S&P

POSITIVE RATINGS MOMENTUM

Moody’s / S&P Historical Corporate Credit Ratings

“Outlook Stable. The affirmation reflects our view that Antero willmaintain funds from operations (FFO)/Debt above 20% in 2016, as itcontinues to invest and grow production in the Marcellus Shale. Thecompany has very good hedges in place, which will limit exposure tocommodity prices.”

- S&P Credit Research, February 2016

“Moody’s confirmed Antero Resources’ rating, which reflects its stronghedge book through 2018 and good liquidity. Antero has $3.1 billion inunrealized hedge gains, $3 billion of availability under its $4 billioncommitted revolving credit facility and a 67% interest in AnteroMidstream Partners LP.

- Moody’s Credit Research, February 2016

Corporate Credit Rating (Moody’s / S&P)

Ba3 / BB-

B1 / B+

B2 / B

B3 / B-

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 Rating Rationale S&P Rating Rationale

68

3/31/2015

Ba2/BB

2/12/20169/1/2010

Ratings AffirmedFebruary 2016

Antero’s corporate credit ratings were recently affirmed at Ba2/BB by Moody’s and S&P, respectively, despite the severe commodity price down cycle

69

LARGEST LIQUIDS-RICH CORE POSITION

Source: Core outlines and peer net acreage positions based on investor presentations, news releases and 10-K/10-Qs. Rig information per RigData as of 4/1/2016.1. Based on company filings and presentations. Peer group includes Ascent, CHK, CNX, CVX, ECR, EQT, GPOR, NBL, REX, RRC, STO, SWN.

• Antero controls an estimated 37% of the NGLs in the liquids-rich core of the two plays

• Antero has the largest core liquids-rich position in Appalachia with ≈377,000 net acres (> 1100 Btu)

• Represents over 21% of core liquids-rich acreage in Marcellus and Utica plays combined

Antero has over 2,700 undeveloped rich gas locations with an average lateral length of 7,580’ in its 3P reserves as of 12/31/2015

0

100

200

300

400

(000

s)

Core Liquids-Rich Net Acres(1)

LNG Exports48%

Mexico/Canada Exports

18%

Power Generation

17%

Transportation1%

Industrial16%

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

natural gas

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

Of the 9.5 Bcf/d of expected incremental demand from LNG export projects, 6.7 Bcf/d (or 70%) of the projects have secured the necessary DOE and FERC permits

70

Incremental Demand Growth Through 2020 by Category

Projected Incremental Natural Gas Demand Through 2020

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

Sherwood 7 2

5

9

13

17

20

0

4

8

12

16

20

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

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

LNG exports

(Bcf/d)

LNG

Exports

Power Gen

Petrochem

LNG Exports by Project(in Bcf/d)

2015 2016 2017 2018 2019 2020 TotalSabine Pass 1 - 0.6 - - - - Sabine Pass 2 - 0.6 - - - - Sabine Pass 3 - - 0.6 - - - Sabine Pass 4 - - 0.6 - - - Sabine Pass 5 - - - - 0.6 - 3.0 Cove Point 1 - - 0.4 - - - Cove Point 2 - - - 0.4 - - 0.8 Cameron 1 - - - 0.6 - - Cameron 2 - - - 0.6 - - Cameron 3 - - - - 0.6 - 1.8 Freeport 1 - - - 0.5 - - Freeport 2 - - - - 0.5 - Freeport 3 - - - - 0.5 - Freeport 4 - - - - - 0.4 2.1 Corpus Christi 1 - - - - 0.6 - Corpus Christi 2 - - - - - 0.6 1.2 Lake Charles 1 - - - - - 0.6 0.6

LNG Incremental Exports - 1.2 1.6 2.2 2.9 1.7LNG Cumulative Exports - 1.2 2.8 5.0 7.9 9.5

LNG EXPORTS BY PROJECT – EXPECTED START UP

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

exports have secured US DOE non-FTA (Free Trade Agreement) permit approval

− 6.7 Bcf/d (four projects, 70%) have been awarded FERC construction permits

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

Pass Trains 1-4

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

Point 1 & 2

71

LNG Exports by Project Through 2020

Antero Supply Agreements for Portion of Capacity

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

Antero Supplied

2015 GLOBAL LPG DEMANDGlobal LPG demand is 8.5 MMBbl/d and growing

72

GLOBAL LPG DEMAND DRIVEN BYPETCHEM AND RES/COMMLargest end-use sectors for LPG are residential/commercial, which tends to grow with population and improvement in

living standards in the emerging markets− PIRA forecasting >1.0 MMBbl/d over next 5 years and >4.5 MMBbl/d of global LPG demand growth over next 20 years

731. PIRA NGL Study, September 2015.

MMBbl/d14.7

13.0

11.4

9.8

8.2

6.5

4.9

3.3

1.6

GLOBAL LPG TRADE DRIVEN BY U.S. SHALEThe U.S. is the largest single driver of the rapid expansion in LPG trade accounting for over 90% in trade growth


MMBbl/d5.2

4.6

3.9

3.3

2.6

2.0

1.3

0.7

United States

U.S. SHALE NGL EURS SUPPORT LPG TRADE GROWTH


• U.S. shale play NGL reserves are 50.8 billion barrels

• Eagle Ford, Marcellus, Utica, Bakken and Permian are the work horses of U.S. shale production growth

• Marcellus/Utica NGL resource estimate by PIRA is 9.7 billion barrels, in line with Antero estimate of ≈ 11.1 billion barrels

• The growth curve of each basin will ultimately be a function of downstream solutions and investment

(1)

(1)(1)

POSITIVE OUTLOOK FOR LONG-TERM ETHANE MARKETS AS WELL

U.S. Ethane Supply/Demand Balance Through 2020(1)

1. Source: Bentek, August 2015.2. Source: Citi research dated 7/15/2015.

U.S. Ethane Exports Through 2020(2)

U.S. ethane demand is projected to increase at an annual 3.5% CAGR through 2020, primarily based on an ≈8% CAGR for U.S. petrochemdemand and a 30% growth in exports primarily to Europe− The growth in shipping exports in 2016 and 2017 is driven by Enterprise Products’ 200 MBbl/d export facility on the Gulf Coast

-

0.5

1.0

1.5

2.0

2.5

2012 2013 2014 2015 2016 2017 2018 2019 2020

MM

Bb/

d

Petchem Exports Rejection Total Supply (Net Stock Change)

U.S. Seaborne Ethane Exports Through 2020(2)

-

50

100

150

200

250

300

350

2013 2014 2015 2016 2017 2018 2019 2020

MB

bl/d

Ship Pipeline

250

200

150

100

50

MB

bl/d

U.S. exports increase significantly into 2016

and 2017 as EPD’s Morgan Point Facility

comes in-service

U.S. Ethane Rejection by Region Through 2020(1)

Access to both Marcus Hook and the Gulf Coast is

critical to optimizing ethane

netbacks

Rejection declines significantly into 2018

Unlike LPG, 80% of ethane will be

consumed in the U.S.

Petrochem demand increases at ≈8% CAGR through 2020

-

100

200

300

400

500

600

2012 2013 2014 2015 2016 2017 2018 2019 2020

MB

bl/d

Williston PADD 4 PADD 1 (East Coast) PADD 2 PADD 3

No Northeast ethane rejection after 2017

76

Northeast Ethane

Rejection

Exports

U.S. PetChem

Europe

Mariner East II

Shipping $0.25/Gal

NGL EXPORTS AND NETBACKS STEP-UP BY 2Q 2017

1. Source: Intercontinental exchange as of 12/31/2015.2. Source of graphic: Tudor Pickering Holt & Co. research presentation dated June 16, 2015.3. As an anchor shipper on Mariner East II, Antero has the right to expand its NGL commitment with

notice to operator.

4. Shipping rates based on benchmark Baltic shipping rate of $59.57/ton as of 12/31/15, adjusted for number of shipping days to NWE.

5. Pipeline fee equal to $0.0725/gal, per Mariner East I tariff. Terminal fee equal to $0.12/gal, per TPH report dated June 16, 2015.

Upon in-service of Mariner East II, Antero will have the ability to market its propane and n-butane to international buyers, which we expect will provide uplifts of $0.16/Gal and $0.18/Gal, respectively, to the current netbacks received from propane and n-butane volumes shipped to Mont Belvieu today− In the meantime, Antero has 30,000 Bbl/d of propane hedged at $0.59/Bbl in 2016

Commitment to Mariner East II results in approximately $127 million in combined incremental annualized cash flow from propane and n-butane sales (~$86 MM from propane and ~$41 MM from n-butane)

PricingPropane: $0.39/GalN-Butane: $0.56/Gal

PricingPropane: $0.56/GalN-Butane: $0.76/Gal

Mariner East II61,500 Bbl/d AR

Commitment (see table below) (3)

4Q 2016 In-Service

ShippingPropane: $0.07/GalN-Butane: $0.08/Gal

AR Mariner East II Commitment (Bbl/d)Product Base Option (3) TotalEthane (C2) 11,500 - 11,500 Propane (C3) 35,000 35,000 70,000 Butane (C4) 15,000 15,000 30,000

Total 61,500 50,000 111,500

77

Mont Belvieu Propane Netback ($/Gal)Propane N-Butane

January Mont Belvieu Price (1): $0.39 $0.56

Less: Shipping Costs to Mont Belvieu (2): (0.25) (0.25)

Appalachia Propane Netback to AR: $0.14 $0.31

NWE Netback ($/Gal)Propane N-Butane

January NWE Price (1): $0.56 $0.76

Less: Spot Freight (4): ($0.07) ($0.08)

FOB Margin at Marcus Hook: $0.49 $0.68

Less: Pipeline & Terminal Fee (5): (0.19) (0.19)

Appalachia Netback to AR: $0.30 $0.49Upside to Appalachia Netback: $0.16 $0.18

ANTERO RESOURCES DECEMBER 31, 2015 RESERVES

78

Reserves Detail – 12/31/2015

Marcellus ShaleGas(Bcf)

Liquids (MMBbl)

Total(Bcfe)

PV-10 ($MM)SEC(1) Strip(2)

Proved 8,073 555 11,406 $2,749 $4,544

Probable 14,216 458 16,961

Possible 1,025 43 1,282

Total 3P 23,314 1,056 29,649 $2,885 $8,647

% Liquids(3) 21%

Ohio Utica ShaleGas(Bcf)

Liquids (MMBbl)

Total(Bcfe)


Proved 1,459 58 1,809 $885 $1,140

Probable 3,972 83 4,468

Possible 951 40 1,191

Total 3P 6,381 181 7,468 $863 $2,535

% Liquids(3) 15%

Combined ReservesGas(Bcf)

Liquids (MMBbl)

Total(Bcfe)


Proved 9,532 614 13,215 $3,634 $5,684

Probable 18,188 540 21,429

Possible 1,975 83 2,472

Total 3P 29,695 1,237 37,117 $3,748 $11,182

% Liquids(3) 20%

Antero’s proved reserves were 13.2 Tcfe, while its 3P reserves were 37.1 Tcfe

Proved pre-tax PV-10 at strip prices was $5.7 billion, while the 3P pre-tax PV-10 was $11.2 billion− Including hedges, the proved pre-tax PV-10 was $8.2 billion while the 3P pre-tax PV-10 was $13.7 billion

1. 2015 SEC prices were $2.56/MMBtu for natural gas and $50.13/Bbl for oil on a weighted average Appalachian index basis. 2. Pre-tax PV-10 based on annual strip pricing for first 10-years and flat thereafter as of December 31, 2015. NGL pricing assumes 39%, 46% and 48% of WTI strip prices for 2016, 2017 and 2018 and

thereafter, respectively. 3. Represents liquids volumes as a percentage of total volumes. Combined liquids comprised of 1,145 million barrels of NGLs (including 182 million barrels of ethane) and 92 million barrels of oil.

ANTERO RESOURCES EBITDAX RECONCILIATION

79

EBITDAX Reconciliation

($ in millions) Quarter Ended LTM Ended12/31/2015 12/31/2015

EBITDAX:Net income including noncontrolling interest $175.6 $980.0Commodity derivative fair value (gains) (545.1) (2,381.5)Net cash receipts on settled derivatives instruments 269.9 856.6Interest expense 60.5 234.4Income tax expense (benefit) 77.2 575.9Depreciation, depletion, amortization and accretion 162.2 711.4Impairment of unproved properties 60.7 104.3Exploration expense 0.8 3.8Equity-based compensation expense 18.6 97.9State franchise taxes (0.1) 0.1Contract termination and rig stacking 27.6 38.5Consolidated Adjusted EBITDAX $307.8 $1,221.4

ANTERO MIDSTREAM EBITDA RECONCILIATION

80

EBITDA and DCF Reconciliation

$ in thousandsThree months ended

December 31,2014 2015

Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow: Net income $55,898 $49,008Add:

Interest expense 2.062 2,892Depreciation expense 17,290 23,152Contingent acquisition consideration accretion - 3,333Equity-based compensation 4,226 4,810

Adjusted EBITDA $79,476 $83,195Less:

Pre-water acquisition net income attributed to parent (22,234) -

Pre-water acquisition depreciation expense attributed to parent (3,086) -

Pre-water acquisition equity-based compensation expense attributed to parent (654) -

Pre-water acquisition interest expense attributed to parent (359) -Pre-IPO EBITDA (36,464) -

Adjusted EBITDA $16,679 83,195

Less:

Cash interest paid - attributable to Partnership (331) (2,934)

Income tax witholding upon vesting of Antero Midstream LP equity-based compensation awards - (4,806)Maintenance capital expenditures attributable to Partnership (1,157) (3,096)

Distributable Cash Flow $15,191 $72,359

CAUTIONARY NOTE

The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserve estimates (collectively, “3P”). Antero has provided internally generated estimates for proved, probable and possible reserves in this presentation in accordance with SEC guidelines and definitions. The estimates of proved, probable and possible reserves as of December 31, 2015 included in this presentation have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates as of December 31, 2015 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 December 31, 2015. 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

81

company website presentation april 2016

Investor Relations