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Company Overview

November 2017

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, 2016 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, 2016 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” in the presentation, Antero Midstream Partners LP is denoted

as “AM” and Antero Midstream GP LP is denoted as “AMGP”, which are their respective

New York Stock Exchange ticker symbols.

2

Market Cap(1)……….……....

Enterprise Value(2)…......…...

Corporate Debt Ratings……

Stand-alone Leverage(3)

Net Production (3Q 2017)…

Liquids(4).....................

3P Reserves(5)………..…....

Net Acres(6)………….…...…

Midstream Ownership(7)

1. Based on market capitalization as of 9/30/2017.

2. Market capitalization plus net debt on a stand-alone basis as of 9/30/2017.

3. Stand-alone Net debt to latest twelve months EBITDAX as of 9/30/2017

4. Oil plus NGLs

5. 3P reserves as of 6/30/2017, assuming 28% ethane recovery, of which 96% represent 2P reserves.

6. Net acres as of 9/30/2017.

7. Market value of AR’s 53% ownership of Antero Midstream Partners (NYSE: AM) as of 9/30/2017.

$6.3 billion

$9.7 billion

Ba2 / BB

2.6x

2,317 MMcfe/d

112,000 Bbl/d

53.0 Tcfe

636,000

$3.1 billion

Antero Profile

Antero’s Core Business Strategy

3

Develop World Class Resource Over the Long Term

• Run by co-founders and management with significant ownership

• Forward thinking with industry leading hedge and firm transportation portfolio designed to

reduce price volatility and facilitate consistent, repeatable asset development

• Expand core inventory opportunistically through grass roots leasing and acquisitions

Generate High Margin Cash Flow

• Disciplined capital investment driven by single well but also corporate-wide returns

• Focus on liquids-rich inventory in the lowest cost U.S. shale basins

• Continuous focus on efficiency gains through reduced cycle times and long laterals

Maintain a Strong and Flexible Stand-alone Balance Sheet

• Fund drilling and completion capital with discretionary cash flow

• Target leverage in the low to mid 2x range

• Create optionality to return capital to shareholders

Capture the Energy Value Chain

• Continue to build the most integrated natural gas and NGL story in the U.S.

• Significant value, visibility and opportunity in integrated operations and 53% midstream

ownership (NYSE: AM)

1

2

3

4

3,890

2,096

1,757

1,024 1,001 817 776 741 653 633 632 563

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

AR A B C D E F G H I J K

Un

dri

lled

Lo

cati

on

s

Core - NE Pennsylvania Dry Locations

Core - SW Marcellus & Utica Dry Locations

Core - Marcellus & Utica Liquids RichLocations

Core Liquids-Rich Appalachia Undrilled

Locations

AR 44%

B 13%

C 10%

H 8%

E 6%

I 5%

A 4%

D 3%

J 3%

G 2%

K 2%

Core outlines based upon Antero geologic interpretation, well control, drilling activity, well economics and peer acreage positions based on investor presentations, news releases, 10-K/10-Qs and various other

sources. Rig information per RigData as of 10/27/2017.

1. Peers include Ascent, CHK, CNX, COG, CVX, EQT, GPOR, HG, RICE, RRC and SWN.

* Undrilled location count net of acreage allocated to publicly disclosed joint ventures.

Based on thorough technical analysis of competitor acreage configurations, well results and geology, Antero has the

largest core drilling inventory (see core outlines) in Appalachia and holds 44% of the total liquids rich undrilled inventory

33 SW Marcellus Rigs

31 Utica Rigs

12 NE Marcellus Rigs

76 Total

Rigs

4

Largest Core Drilling Inventory in Appalachia-Liquids Focused

Undrilled Core Marcellus and Core Utica 3P Locations (1)

Avg.

Lateral

Length 6,414’ 6,416’ 8,394’ 5,868’ 8,547’ 9,339’ 7,486’ 7,301’ 8,868’ 7,157’ 8,033’ 7,812’

Capital Efficiencies and Cash Flow Growth Result in

Free Cash Flow and Declining Leverage Through 2020(1) 3

Market Leading Exposure to NGL Prices and Production Growth 1

Antero Investment Highlights

5

Maximizing Financial Returns with Enhanced Completions

and Long Laterals 2

Midstream Ownership and Integration Delivers

Tremendous Value to Antero Shareholders 4

1. Assuming flat $3.00 NYMEX gas and $54 WTI oil through 2020.

105.6

34%

30%

11% 13%

8%

12% 12% 13%

9% 7%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

45.0

55.0

65.0

75.0

85.0

95.0

105.0

115.0

AR RRC DVN APC EOG COP PXD NBL CHK OXY

NG

L %

of

Pro

du

ct

Reve

nu

es

MB

bl/d

3Q17 Daily NGL Production NGL % of Product Revenues

Largest NGL Producer in the U.S.

6

1

Source: SEC filings and company press releases. Realized prices are weighted average including ethane (C2) where applicable.

1. CHK and EOG C2+ production, realized prices and NGL percentage of product revenues based on 2Q 2017 actual results.

Antero is the largest NGL producer in the U.S and has the most NGL exposure at

34% of total upstream company revenues

Top U.S. NGL Producers (MBbl/d) – 3Q 2017

Largest NGL producer in the

U.S. in 3Q ’17 with the

Highest exposure to NGLs

among the top 10 peer group

$23.11

Pre-hedged Realized Price ($/Bbl)

$16.93 $15.15 $31.07 $18.65 $20.72 $18.96 $22.91 $18.36 $22.99

(1) (1)

0

20,000

40,000

60,000

80,000

100,000

120,000

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

MB

bls

2015 2016 2017

Source: EIA and Bentek. Data as of 10/18/17.

Antero is well positioned to capitalize on an improving propane market with low inventories,

increasing demand and tightening of Mont Belvieu pricing relative to WTI

7

Historically Isolated U.S. Markets Unlocked with LPG Export Capacity Buildout

Strong Absolute & Relative Price Improvement Driving Propane Inventories Short

26% and 37% reduction

from 2015 and 2016

“trough” inventory

levels, respectively

Strong Propane Fundamentals 1

-

200

400

600

800

1,000

1,200

1,400

1,600

00

0s

Bb

l/d

ay

Historically the U.S. has been

constrained by export capacity

Excess capacity for exports to

global markets

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

$1.60

Pro

pa

ne

% o

f W

TI

Pro

pa

ne

Pri

ce

($

/ga

llo

n)

Mont Belvieu Propane Price % of WTI

Propane Butane Export Terminal Capacity

9.4

11.0

-

2.0

4.0

6.0

8.0

10.0

12.0

Asia Europe Latin America

North America Middle East Africa

Other

8

Propane and butane increasingly becoming a globally priced product as U.S. domestic supply

has the ability to reach primary demand growth centers in Asia

Global Propane and Butane Outlook Growing Propane and Butane Demand

Source: PIRA report dated March 17, 2017.

And Healthy Global Demand 1

Global propane and butane LPG demand growing at or

above global GDP, equating to 1.6 MMBbls/d of

incremental demand forecast from 2017 – 2025

‒ Demand driven primarily by industrialization and

urbanization in Asia

‒ Asia becoming the “price setter” as the world’s largest

demand center

‒ Appalachia geographically advantaged for Europe

destination cargoes and at parity for Asia destination

cargoes vs. the Gulf Coast

MMBbl/d

Global Propane Prices Converge

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$/g

allo

n

Mont Belvieu Far East Index Northwest Europe

Asia

Europe

Latin America

North America

0

25,000

50,000

75,000

100,000

125,000

150,000

175,000

2014 2015 2016 2017EGuidance

2018ETarget

2019ETarget

2020ETarget

1. Excludes condensate.

2. Based on Antero NGL production targets from 2018 to 2020.

Total

(Bbl/d)

C5+

iC4

nC4

C3

C2

Ethane

17,476

C2

Ethane

26,500

Antero NGL Production Growth by Purity Product (Bbl/d)

Antero has market-leading exposure to NGL volume growth

9

Ethane (C2)

C3+ Production

Propane (C3)

Normal Butane (nC4)

IsoButane (iC4)

Natural Gasoline (C5+)

C2

Rapidly Growing NGL Production… 1

(2) (2) (2) (1)

$6 $9

$12

$14 $17

$15

$19

$23

$26

$30

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

$35.00

45% 50% 55% 60% 65%

NG

L P

ricin

g I

mp

rov

em

en

t ($

/Bb

l)

% of WTI

10

Despite a flat oil price environment, Antero’s pre-hedged realized C3+ NGL price has

increased 70% since 2015 and is expected to improve further

Antero C3+ NGL Realized Pricing ($/Bbl)(1)

1. WTI price and Mont Belvieu C3+ NGL price forecasts and represent strip pricing as of 9/25/2017. Antero year to date 2017 realized C3+ NGL pricing represents actuals through 6/30/2017. 2018-2020

realized C3+ NGL pricing reflects current company targets.

2. Based on unhedged contracted differentials for C4+ NGL products, guidance from midstream providers and strip pricing as of 10/27/2017.

3. Net of ME2 fees. Antero will account for ME2 fees as an expense once ME2 is placed in-service.

Improving Propane Prices Drive Increase in C3+ NGL Netbacks

$48.63

$43.14

$48.16

$54.00

$17.01 $18.74

$28.92

$35.00

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

$35.00

$40.00

$45.00

$50.00

$55.00

2015 2016 Q3 2017 2018 - 2020

WTI Price Antero Realized C3+ Price Mont Belvieu C3+ NGL Price

$25.49

$36.00 $38.50

35% of

WTI

43% of

WTI

60% of

WTI

65% of

WTI

53% of

WTI

59% of

WTI

75% of

WTI

71% of

WTI

$25.54

Antero

Forecast

Netback Price(3)

(2)

1

$147

$537

$651

$114

$0

$100

$200

$300

$400

$500

$600

$700

2017E$49 Oil

56% of WTI

2018E$54 Oil

65% of WTI

2018E$60 Oil

65% of WTI

C3+ Cash Flow Incremental C3+ Cash Flow

$6 $9

$12

$14 $17

$15

$19

$23

$26

$30

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

$35.00

45% 50% 55% 60% 65%

NG

L P

ricin

g I

mp

rov

em

en

t ($

/Bb

l)

% of WTI

11

Antero expects significant cash flow growth in 2018 from the improvement in NGL pricing

with attractive upside to further increases in liquids pricing

Significant Improvement in Cash Flow from C3+ NGLs (2018 vs. 2017)

Note: C3+ NGL cash flow represents revenue from C3+ NGL production, less processing, transportation and all other operating costs associated with C3+ NGL production and sales.

(1) Represents annualized actual results for nine months ended September 30, 2017, annualized.

C3+

NG

L

Cas

h F

low

($M

M)

Powerful C3+ NGL Pricing Upside Exposure 1

$39.00/Bbl

C3+

$35.00/Bbl

C3+ $27.56/Bbl

C3+

(1)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

0 30 60 90 120 150 180 210 240 270 300 330 360 390 420

We

llh

ea

d P

rod

uc

tio

n

(C

um

ula

tive

MM

cf)

Days From Peak Gas

Higher Intensity Completions Increasing EURs

$1,536 $1,621

$2,288

1.8

2.2

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

2016A 2017E 2018E 2019E

Pro

du

cti

on

Gu

ida

nc

e /

Targ

ets

(B

cfe

/d)

Ne

t D

eb

t/LT

M E

BIT

DA

X T

arg

ets

Co

ns

en

su

s E

BIT

DA

X E

sti

mate

s (

$M

M)

AR’s production from advanced completions is outperforming the 2.0 Bcf/1,000’ wellhead type

curve – 2,500 lb/ft completions are 17% above type curve (First 243 days)

1. Cumulative average production per well normalized to a 9,000’ lateral. Cumulative production lines excludes wellhead condensate.

2. 1,875 pounds per foot type curve represents 1,750 pounds per foot wells and 2,000 pounds per foot wells.

0

500

1,000

1,500

2,000

2,500

3,000

3,500

0 30 60 90 120 150 180 210 240 270 300 330 360 390

We

llh

ea

d P

rod

uc

tio

n

(C

um

ula

tive

MM

cfe

, g

as

+ c

on

de

ns

ate

)

Days From Peak Gas

1.7 Bcf/1,000' Type Curve 2.0 Bcf/1,000' Type Curve 1,500 lb/ft 2,000 lb/ft 2,500 lb/ft

1.7 Bcf/1,000' Type Curve Cumulative

Production

2.0 Bcf/1,000' Type Curve Cumulative

Production

1,500 lb/ft

38 wells

1,750 lb/ft

36 wells 2,000

lb/ft

29 wells 2,500

lb/ft

18 wells

12

AR Type Curve Outperformance(1)(2)

1,500 lb/ft $0.85 MM/1,000 Well Cost

38 wells

1,875 lb/ft $0.89 MM/1,000 Well Cost

90 wells

2,500 lb/ft $0.97 MM/1,000’ Well Cost

21 wells

2.0 Bcf/1,000' Type

Curve Cumulative

Production

2

13 1. Assumes Nymex Henry Hub prices of $3.00 and WTI of $54; ethane rejection; and 9,000’ lateral length. Half cycle returns burdened by full fixed and variable transportation costs. See appendix for further

assumptions. Locations as of 6/30/2017.

Integrated platform yields attractive well economics and sustainable growth

$13.2 $16.4

$19.7

107%

132%

162%

0%

20%

40%

60%

80%

100%

120%

140%

160%

180%

$0.0

$4.0

$8.0

$12.0

$16.0

$20.0

1.72.3

2.02.7

2.33.1

Un

he

dg

ed

Pre

-Ta

x R

OR

Pre

-Ta

x P

V-1

0 (

$M

M)

Pre-Tax PV-10 Pre-Tax ROR

Highly-Rich Gas/Condensate: $3.00 Gas / $54 Oil(1)

Wellhead Bcf/1,000’:

Processed Bcfe/1,000’:

2.0

2.7

632 Undrilled Locations

1313 Btu

$7.4 $9.5

$11.8

45%

55%

67%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

$0.0

$4.0

$8.0

$12.0

$16.0

$20.0

1.72.1

2.02.5

2.32.8

Un

hed

ge

d P

re-T

ax R

OR

Pre

-Ta

x P

V-1

0 (

$M

M)

Pre-Tax PV-10 Pre-Tax ROR

2.0

2.5

Wellhead Bcf/1,000’:

Processed Bcfe/1,000’:

Highly-Rich Gas: $3.00 Gas / $54 Oil(1)

1,211 Undrilled Locations

1250 Btu

2 Strong Marcellus Half-Cycle Returns

6,000 Foot Lateral 9,000 Foot Lateral

NOTE: Assumes 2.0 Bcf/1,000’ type curve for the Antero Marcellus Highly-Rich Gas (1250 Btu) and Nymex Henry Hub prices of $3.00 and WTI of $54.

1. All laterals rounded to the nearest thousand. 788 of the 894 wells have been completed

2. Represents wells placed to sales.

Antero has been a leader in drilling long laterals in Appalachia

12,000 Foot Lateral

Pre-Tax Economics

ROR (%) 39%

PV-10

($MM) $5.1

Pre-Tax Economics

ROR (%) 55%

PV-10

($MM) $9.5

Pre-Tax Economics

ROR (%) 61%

PV-10

($MM) $12.5

30 29

14

25

9 5 1

181

227

279 294

164 150

55 37

9 16

0

50

100

150

200

250

300

350

≤ 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 ≥ 15000

We

ll C

ou

nt

Lateral Length(1)

Antero Lateral Lengths To Date

14

Antero # of

Wells

Avg.

Lateral

Length

Total Drilling

Program to Date 894 8,250

2017 Program(2) 135 9,250

2018-2020

Program(2) 465 9,500

Wells to Date

≥10,000’ 230 10,750

Longer Laterals Materially Improve Economics 2

15,000 Foot Lateral

Pre-Tax Economics

ROR (%) 68%

PV-10

($MM) $16.3

Future completion

programs focused on

longer lateral

length locations

15

Antero holds over 30% of the core drilling inventory(2) in Appalachia for lateral lengths greater than

10,000 feet and has been a consistent leader in drilling long laterals in Appalachia

1. Direct Appalachian Basin peers include EQT, RRC, RICE, COG, CNX. Acreage must support ≥ 50% WI in laterals to be counted.

2. Represents estimated total location inventory of undrilled wells for the top 12 peers operating in the core Marcellus & Utica plays. Core based upon Antero geologic interpretation, well control and peer acreage

positions based on investor presentations, news releases, 10-K/10-Qs and various other sources; see page 4 for core outlines and additional information.

Antero Holds the Largest Long Lateral Inventory 2

330

475

511 515

435

376

300

239

-

100

200

300

400

500

600

6,000 7,000 8,000 9,000 10,000 11,000 12,000 >12,000

Nu

mb

er

of

We

lls

Lateral Length (in feet)

ANTERO Peer 1 Peer 2 Peer 3 Peer 4 Peer 5

Peer Core Undrilled Inventory by Lateral Length

$3.64

$3.91

$3.70 $3.63

$3.31 $3.16

$2.91

$3.50

$3.50 $3.25

$3.00 $3.00

$2.00

$3.00

$4.00

0

400

800

1,200

1,600

2,000

2,400

2017 2018 2019 2020 2021 2022 2023

BBtu/d $/Mcf

16 1. AR stand-alone LTM EBITDAX includes $127 million in distributions from AR’s ownership of AM common units.

2. Nymex strip pricing as of 9/30/2017.

$1 Billion Delevering Program Completed

AR Leverage Reduction(1)

Restructuring of hedge swap prices resulted in

no change to hedge volumes

80% of targeted natural gas production hedged

through 2020 at $3.43/MMBtu

– $1.2 billion of remaining hedge value

Utilizing a portion of net operating losses

carried forward to eliminate cash taxes on

realized gains

Antero monetized over $1 billion of non-E&P assets through the sale of $311 million of AM

common units and $750 million through hedge restructuring

- Reduced stand-alone net debt/LTM EBITDAX to 2.6x

Hedged Volume

Current NYMEX Strip(2)

Natural Gas Hedge Position

Restructured Hedge Price

Previous Hedge Price

~$750 Million of

Proceeds

No Change

to Price

Remaining Value as of 9/30/17: $1.2 Billion(2)

3.4x 3.0x 3.2x

2.6x

0.0x

1.0x

2.0x

3.0x

4.0x

6/30/2017 9/30/2017

Consolidated Standalone

3

17

Improving Capital Efficiencies

Planned Antero Well Completions by Year (2017-2020)

170 190 190

255

135 150

170 150

35

75 95

200

0

50

100

150

200

250

300

2017 2018 2019 2020

January 2017 Plan Current Plan Cumulative Well Count Reduction

Improving EURs, longer laterals and reduced cycle times results in 200 fewer well

completions saving approximately $1.5 billion through 2020 while still delivering

essentially the same production targets

Drilling and Completion Capital Budget and Targets (1)

2017 Budget 2018 Target 2019 Target 2020 Target

Drilling & Completion ($MM) $1,300 ~$1,300 $1,500 $1,500

% Production Growth Target 20% CAGR Through 2020 (4-Year CAGR)

9,300 9,250 9,100 9,600 9,000 9,200 8,600 10,200

Lateral Length Lateral Length

1. Represents a combination of 2,000 lb/ft and 2,500 lb/ft completions.

3

($1,484)

($757)

($358) ($150)

D&C $2,477

D&C $1,684 D&C

$1,472 D&C $1,300

D&C $1,300

D&C $1,500

D&C $1,500

($1,500)

($1,000)

($500)

$0

$500

$1,000

$1,500

$2,000

$2,500

2014A 2015A 2016A 2017Consensus

2018Target

2019Target

2020Target

18

Capital Efficiency Drives Elimination of Outspend

Capital efficiencies have significantly reduced E&P outspend and are expected to result in drilling

and completion (D&C) capex within E&P free cash flow by 2019

D&C Capex vs. Stand-alone E&P Cash Flow ($MM) - $3.00 Gas / $54 Oil

D&C Capital to be funded

with E&P Cash Flow (1)

Note: E&P cash flow represents E&P cash flow from operations plus AM distributions from condensed consolidating statement of cash flows in Antero Resources’ 10-K.

(1) E&P free cash flow represents AR stand alone cash flow from operations, plus distributions from LP ownership in AM, plus earn out payments associated with water drop-down ($125 MM in each of 2019

and 2020) less stand-alone D&C capex which includes water fees paid to AM for completions which are capitalized on stand-alone basis.

(2) Consolidated D&C capex excludes water fees paid to AM for completions.

Stand-alone E&P Positive

Free Cash Flow(1)

Consolidated Drilling and

Completion Capex(2)

Stand-alone E&P

Free Cash Flow

Outspend (1)

3

1.0 1.5

1.8 2.3

2.7 3.3

3.8

3.9x

3.6x

2.8x

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

3.5x

4.0x

4.5x

0.0

1.0

2.0

3.0

4.0

5.0

6.0

2014A 2015A 2016A 2017Guidance

2018Target

2019Target

2020Target

Sta

nd

-alo

ne

E&

P L

eve

rag

e N

et

Pro

du

cti

on

(B

cfe

/d)

19

Attractive Long Term Outlook

Antero Resources Stand-alone E&P Long-Term Targets(1)

Target Leverage in Low 2x

Reduce Capex &

Leverage

Generate Free

Cash Flow

Optionality to

Return Capital to

Shareholders

Stand-alone E&P Leverage Net Production (Actual)

Net Production (Guidance)

Net Production (Target)

Antero is now well positioned to generate free cash flow and peer leading growth

3

(1) Assumes WTI price of $54 and Nymex Henry Hub price of $3.00.

Accelerate trend towards investment grade quality – current corporate ratings Ba2/BB

Maintain conservative leverage profile below 3.0x near-term (on stand-alone basis) with

medium-term target of low 2x leverage

Fund drilling and completion capital with stand-alone upstream cash flow from operations

(including AM distributions and earn-out payments from water business sale in 2015)

Continue to hedge over a rolling five to six year period to support consistent production

development into long-term processing and firm transportation commitments, smoothing

volatile oil and gas prices

Maintain stand-alone AR liquidity of at least ~$1 billion on $2.5 billion credit facility

Financial Policy Overview

More Conservative Financial Policy

20

3

New $4.5 Billion Credit Facility with $2.5 Billion in Lender Commitments

- Downsized lender commitments by $1.5 billion due to reduced need for bank capital

- Supported by $4.5 billion borrowing base

- Credit facility includes fall away covenants (interest coverage ratio and proved PV-9 to total

debt ratio) triggered if and when Antero is assigned an investment grade rating

- No leverage test

$89

$112

$-

$50

$100

$150

$200

$250

$300

2015A 2016A 2017E 2018E 2019E 2020E

$1,150

$2,755

$6,123

$795 $179 $311 $320

$250

$3,118

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

AM IPO (2014) Sale of WaterBusiness (2015)

Sale of AMUnits (2016)

Sale of AMUnits (9/6/17)

AMDistributions

Received as of9/30/17

Total Proceedsto Date

ExpectedEarnout

Payments(2019E-2020E)

Pre-tax Value ofAM Units Held

by AR @$31.53

(9/30/17)

Pre-taxCumulative

Value of AnteroMidstream

Cash

Pro

ceed

s (

SM

M)

Midstream Driving Value for AR Since Inception

Midstream integration has provided tremendous value to AR shareholders

and the go-forward upside is very attractive

AM Distributions to AR(1)

Antero Midstream Return on Investment for AR (Pre-tax)(2)

Note: Represents distributions declared during fiscal year ended December 31 based on Antero Midstream guidance and long-term distribution growth targets.

1. Represents distribution growth targets for AR owned units through 2020. As of 9/30/2017, AR owns 98.9 million AM units.

2. Midstream proceeds received by AR to date plus market value of AR’s 53% ownership of AM divided by the approximate $1.3 billion of AR capital invested at time of AM IPO.

3. After-tax using 38% federal and state tax rate and $1.5 billion of AR NOLs.

AM price per

unit

After-tax value of

AM units held by

AR ($Billion) (3)

Value per AR

share

$29 $2.3 $7

$32 $2.5 $8

$35 $2.7 $9

$38 $2.9 $9

$41 $3.1 $10

Consensus AM Price Target: $41

4.7x

ROI

AM Share Price Value

21

(2)

4

Midstream Infrastructure (In Service)

Gathering Pipelines (Miles) 341

Compression Capacity (MMcf/d) 1,600

Condensate Pipelines (Miles) 19

Processing Plant (MMcf/d) 400

Fractionation Plant (Bbl/d) 20,000

Fresh Water Pipelines (Miles) 323

Fresh Water Impoundments 38

Regional Pipeline Capacity (Bcf/d) 1.4

Antero Clearwater Facility (Bbl/d)(1) 60,000

Compressor

Station

Antero

Clearwater

Facility

Sherwood

Processing

Facility

Stonewall

Pipeline

Gathering

Pipelines

Freshwater

Delivery

Pipelines`

Antero Rig

Antero Midstream Asset Overview

22

Antero

Clearwater

Facility

Sherwood

Processing

Complex

. 1. The Antero Clearwater Facility is scheduled to be placed into service in the fourth quarter of 2017.

Capturing the Midstream Value Chain

Upstream Downstream

~$4.2 Billion Organic Project

Backlog

~$800 Million JV

Project Backlog

WELL PAD

LOW PRESSURE GATHERING

HIGH PRESSURE GATHERING

COMPRESSION

GAS PROCESSING

(50% INTEREST)

REGIONAL

GATHERING

PIPELINE

(15% INTEREST)

FRACTIONATION TERMINALS & STORAGE

Y-GRADE PIPELINE

(ETHANE, PROPANE, BUTANE)

NGL PRODUCT PIPELINES

LONG HAUL PIPELINE

INTERCONNECT

END USERS

PDH PLANT

• Participating in the full value chain diversifies and sustains Antero’s integrated business model

• $5.0 billion organic project backlog and ~$1.0 billion potential downstream investment opportunity set

~$1.0 Billion

Downstream

Investment

Opportunity Set

Note: Third party logos denote company operator of respective asset.

AM Assets AM/MPLX JV Assets Potential AM Opportunities

23

4

Key Drivers Behind Long Term Outlook

Market Leading Exposure to NGLs

Largest Core Liquids-Rich Drilling Inventory

Improving Capital Efficiencies with Long Laterals and Higher

Intensity Completions

Attractive Half Cycle and Company-Wide Returns

Disciplined Spending Within Upstream Cash Flow

24

Cash Flow Growth

Capital Efficiency

Drilling Inventory

Attractive Returns

NGL Exposure

Solid Balance Sheet with Abundant Liquidity and

Optionality Balance Sheet

25

APPENDIX

25

Simplified Organizational Structure

26 Note: Enterprise Value as of 9/30/2017.

100%

Incentive

Distribution

Rights

(IDRs)

Public

(NYSE: AMGP)

Enterprise Value : $3.8 Bn

(NYSE: AM)

Enterprise Value : $6.9 Bn

(NYSE: AR)

Enterprise Value: $9.7 Bn

80% 20%

Affiliates Affiliates

53%

32%

Public

68%

47% Public

The combined enterprise value of the Antero complex is over $20 billion

Key Variable Updated

2017 Guidance(1)

Previous

2017 Guidance(1)

Q4

2017 Guidance

Net Daily Production (MMcfe/d) 2,250 – 2,300

Net Residue Natural Gas Production (MMcf/d) 1,650 – 1,675

Net C3+ NGL Production (Bbl/d) 68,000 – 71,000

Net Ethane Production (Bbl/d) 26,000 – 27,000

Net Oil Production (Bbl/d) 6,000 – 7,000

Net Liquids Production (Bbl/d) 100,000 – 105,000

Natural Gas Realized Price Differential to NYMEX Before Hedging ($/Mcf)(2)(3) ($0.15) – ($0.10) +$0.00 – $0.10 ($0.20) – ($0.15)

Oil Realized Price Differential to NYMEX WTI Oil Before Hedging ($/Bbl) ($7.00) – ($6.50) ($9.00) – ($7.00) ($5.00) – ($6.00)

C3+ NGL Realized Price (% of NYMEX WTI)(2) 57.5% – 62.5% 50% – 55% 70% – 75%

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

Consolidated EBITDAX ($MM): $410 - $440

Operating:

Cash Production Expense ($/Mcfe)(4) $1.55 – $1.65

Marketing Expense, Net of Marketing Revenue ($/Mcfe) $0.075 – $0.125

G&A Expense ($/Mcfe) $0.15 – $0.20

Capital Expenditures ($MM):

Drilling & Completion $1,300

Land $200

Total Capital Expenditures ($MM) $1,500

Antero Resources – Q4’17 and 2017 Guidance

Key Operating & Financial Assumptions

3. Includes Btu upgrade as Antero’s processed tailgate and unprocessed dry gas production is greater than 1000 Btu on average.

4. Includes lease operating expenses, gathering, compression and transportation expenses and production taxes.

1. Updated guidance per press release dated 11/02/2017.

2. Based on strip pricing as of 10/27/2017. 27

Antero NGL Barrel (September Pricing)

28

NGL Barrel Composition & Pricing – Ethane Rejection vs. Partial Recovery

1. GPM represents gallons of NGLs per wellhead unproccessed Mcf.

0.00

0.50

1.00

1.50

2.00

Composition RealizedPrice

0%

20%

40%

60%

80%

100%

Ethane Rejection

C5: 18%

IC4: 16%

C4: 9%

C3: 57%

1.5 GPM(1) 2.2 GPM

Pentane (C5): $1.17/Gallon

IsoButane (IC4): $1.02 /Gallon

Butane (C4): $0.99/Gallon

Propane (C3): $0.89/Gallon

Ethane (C2): $0.27/Gallon

$40.75/Bbl Mont Belvieu Pricing $31.63/Bbl

$(7.52)/Bbl Northeast Differential $(5.09)/Bbl

$33.23/Bbl Antero Realized Price ($/Bbl) $26.54/Bbl

67% % of WTI 53%

Mont Belvieu

September 2017 Pricing

Antero realized $33.23/Bbl for its C3+ NGL barrels in September 2017

‒ 67% of WTI oil price

Including 21% ethane recovery, Antero realized $26.54 per barrel for its NGL barrels

‒ Antero is currently leaving approximately 123,000 Bbl/d of ethane in the gas stream

21% Recovery

12%

7% 11%

39%

31%

0

100

200

300

400

500

600

700

800

900

1000

MB

bl/

d)

29

Historical Ethane Prices ($/Gallon)

Ethane Fundamentals and Improving Pricing

U.S. Domestic Steam Cracker Capacity (MBbl/d)

Ethane Outlook

Significant domestic demand growth for ethane driven

by construction and expansion of world-class steam

crackers

‒ Antero is an anchor supplier (30 MBbl/d) to Shell’s

planned ethane cracker in Beaver Co, PA

Ethane rejection rates will continue to decrease;

however, ethane supply will be partially restricted by

takeaway capacity

‒ U.S. is currently rejecting ~575 MBbl/d of ethane

240 MBbl/d of seaborne export capacity completed in

2016 provides additional outlet to global markets

‒ Additional 100 MBbl/d of demand via pipeline exports

to Canada

Shell - PA Does not include ~350 MBbl/d of

additional cracking capacity that

has been proposed but has not

reached FID

Source: Bentek and PIRA.

$-

$0.10

$0.20

$0.30

$0.40

$0.50

$0.60

$0.70

$0.80

$0.90

Ethane price collapse driven by U.S.

shale development and inability to

absorb supply until cracker demand

increases in 2018+

Most Attractive Firm Transport Portfolio in Appalachia

Antero’s natural gas takeaway position results in price certainty at attractive all-in

netbacks to Nymex: Nymex less $0.42/Mcf expected 2017-2020, after deducting FT costs

13% of FT Portfolio

$0.15/Mcf Average

Cost

(0.6 Bcf/d)

Local

Markets

Note: Strip basis differentials to Nymex Henry Hub represents October 2017 and 2017-2019 strip pricing, respectively as of October 27th, 2017 for each index.

1. Weighted average differential to Nymex calculated using 2017-2019 strip pricing as of October 27th, 2017.

Antero Firm Transportation Portfolio (2017-2019)

Weighted

Avg. FT Cost

Weighted Average

Differential to Nymex(1)

$0.46/Mcf +$0.04/Mcf Premium

with BTU Upgrade

Antero

Producing

Areas

($0.22)

($0.22)

($0.32)

($0.31)

($0.10)

($0.08)

$0.06

($0.18)

($1.19)

($0.57)

30

$4 $5 $25 $34 $29 $28 $26 $12 $16 $17 $28 $29

$19 $25 $43

$80 $83 $59

$49 $48

$14

$47 $54

$1

$58 $78

$185 $196 $206

$270

$324 $293

$197 $190

$45 $31

($2.00)

($1.00)

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$0.0

$70.0

$140.0

$210.0

$280.0

$350.0

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

2,163 2,027 2,330 1,418 710 850 90

$3.58 $3.52 $3.50

$3.25 $3.00 $3.00 $2.91

$3.10 $3.05 $2.89 $2.84 $2.83 $2.85 $2.87

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

0

400

800

1,200

1,600

2,000

2,400

2017 2018 2019 2020 2021 2022 2023

BBtu/d $/Mcfe Average Index Hedge Price(2) Hedged Volume Current NYMEX Strip(3)

Pro Forma Commodity Hedge Position(1)

$62 MM

Mark-to-Market Value(3)

~ 95% of 2017 Guidance Hedged

31

1. Pro forma for hedge monetization per press release dated 9/21/2017.

2. Weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio; excludes impact of TCO basis hedges. 27,500 Bbl/d of propane hedged in 2017 and 2,000 Bbl/d hedged in

2018. 20,000 Bbl/d of ethane hedged in 2017 and 3,000 Bbl/d of oil hedged in 2017.

3. As of 9/30/2017. Includes impact from $750 million hedge monetization in September 2017.

$/Mcfe

~ 84% of 2018 Target Hedged

Pro forma ~$1.2 billion mark-to-market unrealized gain based on 9/30/2017 prices with

2.9 Tcfe hedged from October 1, 2017 through year-end 2023 at $3.36 per MMBtu

• Hedging is a key component of Antero’s business model due to the large, repeatable drilling inventory

• Antero has realized $3.6 billion of gains on commodity hedges since 2008 with gains realized in 37 of last 39 quarters(3)

Quarterly Realized Gains/(Losses) – 1Q ‘08 - 3Q ‘17 $MM

$323 MM $39 MM $42 MM $1 MM $504 MM $202 MM

$811

$1.13 $1.04 $1.22 $1.25 $0.82

$3.26

$2.79 $2.78

$2.24 $2.05

$2.13

$1.75 $1.56

$0.99 $1.23

$-

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

AR Peer 1 Peer 2 Peer 3 Peer 4

EBITDAX GPT LOE Ad Valorem G&A Revenue Cash Costs

Peer Leading Stand-alone EBITDAX Margin On a Normalized Basis

32

3Q 2017 Stand-alone EBITDAX Margins (Pre-Hedge / Pre-Marketing)($/Mcfe)(1)

Margin Rank: 1 2 3

Source: SEC filings and company press releases. Peers include COG, EQT, RRC and SWN.

1. AR and EQT EBITDAX include distributions from midstream ownership. AR’s EBITDAX excludes net marketing expense and the hedges put in place to support firm transportation. Cash costs for AR and EQT

represent stand-alone GPT, production taxes, LOE and cash G&A.

2. Stand-alone EBITDAX divided by unprocessed units (Mcf) of production to normalize to dry gas production.

Normalized Antero Stand-alone EBITDAX Margins – 3Q 2017 ($/Unit)

Peer Rank: 3

4 5

$1.13 $0.21

$0.32 $1.34

$1.66

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

Raw EBITDAXMargin ($/Mcfe)

Add Back ContractUnderpayments(WGL & SJR)

Normalized EBITDAXMargin ($/Mcfe)

Pre-Processing UnitConversion

Normalized EBITDAXMargin ($/Mcf)

Transitory Event

(2) (2)

Net Equivalent

Production: 213 Bcfe

Net Wellhead

Production: 169 Bcfe

stand-alone

EBITDAX: $318 MM(2)

Compare to Rich Gas Peers

Compare to Dry Gas Peers

1 1

Single Well Economics: Half Cycle Cost Assumptions(1)

33

SWE Cost Type Description of Cost Marcellus Utica

Well Costs

• Drilling and completion costs

• Reflects average well costs across most

Btu regimes for a 9,000’ lateral

• Includes 50% AM water fees

• Includes $1.0 million for road, pad and

production facilities.

$8.4 mm

(Assumes 1,750 lbs of

proppant per lateral foot)

$9.6 mm

(Assumes ~2,000 lbs of

proppant per lateral foot)

Net Royalty Interest • Reflects Antero’s average NRI in the

respective plays 84% 81%

Midstream Gathering

Fees

• Midstream compression fees (50% of

AM fees, unless otherwise noted)

• Compression fuel ($0.10-$0.11 per

Mcfe)

$0.39 per Mcfe

(Crestwood: $0.79 per Mcfe)

$0.50 per Mcfe

Processing Fees

• Processing fees

• Plant fuel & electricity

• Transportation & fractionation

• Does not apply to wells under 1100 Btu

$0.62 per Mcfe $0.67 per Mcfe

Operating Expenses

• Fixed costs (monthly expenses)

• Variable costs (gas and liquids)

• Numbers reflect averages across most

Btu regimes


FT(1)

• Fully utilized FT costs (including both

demand and variable fees associated

with expected production)


Taxes • Ad valorem and severance taxes vary

depending on revenue and production $0.15 per Mcfe $0.07 per Mcfe

(1) SWE cost assumptions reflect average costs per Mcfe on the first five years of the life of a well

(2) SWEs exclude marketing expenses and related commodity hedge contracts that support Antero’s firm transportation portfolio

Marcellus Well Economics and Total Gross Locations(1)

632

1,211

673 855

161%

72%

16% 18%

132%

55%

10% 11% 0

200

400

600

800

1,000

1,200

1,400

0%20%40%60%80%

100%120%140%160%180%

Highly-Rich Gas/Condensate (4)

Highly-Rich Gas Rich Gas Dry Gas

To

tal 3P

Lo

cati

on

s

RO

R

Total 3P LocationsROR at $3 Gas / $54 Oil - After HedgesROR at $3 Gas / $54 Oil - Before Hedges

1. Pre-tax well economics reflect $3.00 Nymex Henry Hub natural gas prices, $54 WTI oil prices, and NGLs at ~65% of WTI. NGL prices are forecast to increase in 2018 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. 2. Pricing for a 1225 BTU y-grade ethane rejection barrel. 3. Undeveloped well locations as of 6/30/2017. 4. SWE cost assumptions reflect average costs per Mcfe on the first five years of the life of a well

DRY GAS LOCATIONS RICH GAS LOCATIONS

HIGHLY

RICH GAS

LOCATIONS

Assumptions

Natural Gas – $3

Oil – $54

NGLs – ~65% of Oil Price 2017+

Classification

Highly-Rich Gas/

Condensate(4)

Highly-Rich

Gas(4) Rich Gas(4) Dry Gas(4)

Modeled BTU 1313 1250 1150 1050

EUR (Bcfe): 24.4 22.1 19.4 18.0

EUR (MMBoe): 4.1 3.7 3.2 3.0

% Liquids: 32% 24% 10% 0%

Lateral Length (ft): 9,000 9,000 9,000 9,000

Proppant (lbs/ft sand): 1,750 1,750 1,750 1,750

Well Cost ($MM): $8.4 $8.4 $8.4 $8.4

Bcfe/1,000’: 2.7 2.5 2.2 2.0

Net F&D ($/Mcfe): $0.41 $0.45 $0.52 $0.55

Net Direct Operating Expense ($/Mcfe): $1.20 $1.27 $1.57 $1.08

Transportation Expense ($/Mcfe): $0.41 $0.48 $0.57 $0.63

Pre-Tax NPV10 ($MM): $16.4 $9.5 $0.0 $0.3

Pre-Tax ROR: 132% 55% 10% 11%

Payout (Years): 1.2 1.9 7.6 7.0

Gross 3P Locations in BTU Regime(3): 632 1,211 673 855

2017

Drilling

Plan

Single Well Economics: Marcellus – In Ethane Rejection

34

Utica Well Economics and Gross Locations(1)

222

59 86

128

255

27%

55%

43%

31% 35%

23%

44%

30%

20% 23%

0

50

100

150

200

250

300

0%

20%

40%

60%

80%

Condensate Highly-Rich Gas/Condensate

Highly-Rich Gas Rich Gas Dry Gas

To

tal 3P

Lo

cati

on

s

RO

R

Total 3P Locations

ROR at $3 Gas / $54 Oil - After Hedges

ROR at $3 Gas / $54 Oil - Before Hedges

Single Well Economics: Utica – In Ethane Rejection

DRY GAS LOCATIONS RICH GAS LOCATIONS

HIGHLY

RICH GAS

LOCATIONS

Classification Condensate(4)

Highly-Rich Gas/

Condensate(4)

Highly-Rich

Gas(4) Rich Gas(4) Dry Gas(4)

Modeled BTU 1275 1235 1215 1175 1050

EUR (Bcfe): 9.9 18.7 21.4 20.5 19.8

EUR (MMBoe): 1.6 3.1 3.6 3.4 3.3

% Liquids 39% 30% 21% 16% 0%

Lateral Length (ft): 9,000 9,000 9,000 9,000 9,000

Proppant (lbs/ft sand): 1,500 2,000 2,000 2,000 2,000

Well Cost ($MM): $8.7 $9.3 $9.9 $9.9 $9.9

Bcfe/1,000’: 1.1 2.1 2.4 2.3 2.2

Net F&D ($/Mcfe): $1.09 $0.62 $0.57 $0.59 $0.62

Net Direct Operating Expense ($/Mcfe): $1.17 $1.27 $1.36 $1.39 $0.74

Transportation Expense ($/Mcfe): $0.38 $0.45 $0.52 $0.55 $0.65

Pre-Tax NPV10 ($MM): $3.3 $8.1 $5.5 $3.1 $4.0

Pre-Tax ROR: 23% 44% 30% 20% 23%

Payout (Years): 3.6 2.1 2.8 3.9 3.6

Gross 3P Locations in BTU Regime(3): 222 59 86 128 255

2017

Drilling

Plan

35

1. Pre-tax well economics reflect $3.00 Nymex Henry Hub natural gas prices, $54 WTI oil prices, and NGLs at ~65% of WTI. NGL prices are forecast to increase in 2018 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. 2. Pricing for a 1225 BTU y-grade ethane rejection barrel. 3. Undeveloped well locations as of 6/30/2017, pro forma for recent acreage acquisition. 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content. 4. SWE cost assumptions reflect average costs per Mcfe on the first five years of the life of a well

Assumptions

Natural Gas – $3

Oil – $54

NGLs – ~65% of Oil Price 2017+

Liquid “non-E&P assets” of $4.7 Bn

significantly exceeds total debt of $3.5 billion

Liquidity

Antero Resources (NYSE:AR) Antero Midstream (NYSE:AM)

9/30/2017 Debt Liquid Non-E&P Assets 9/30/2017 Debt (1) Liquid Assets

Debt Type $MM

Credit facility $25

5.375% senior notes due 2021 1,000

5.125% senior notes due 2022 1,100

5.625% senior notes due 2023 750


Total $3,475

Asset Type $MM

Commodity derivatives $1,200

AM equity ownership 3,118

Cash 21

Total $4,339

Asset Type $MM

Cash $21

Credit facility – commitments(1) 2,500

Credit facility – drawn -

Credit facility – letters of credit (700)

Total $1,821

Debt Type $MM

Credit facility $427


Total $1,077

Asset Type $MM

Cash $2

Total $2

Pro Forma Liquidity

Asset Type $MM

Cash $2

Credit facility – capacity 1,500

Credit facility – drawn (427)

Credit facility – letters of credit -

Total $1,075

Approximately $1.8 billion of liquidity at AR

plus an additional $3.1 billion of AM units Approximately $1.1 billion of liquidity at AM

36

Only 28% of AM credit facility capacity drawn

1. AR credit facility commitments of $2.5 billion, borrowing base of $4.0 billion.

2. AM equity value as of 9/30/2017.

Strong Balance Sheet and High Flexibility

$1,500

$1,075

$427

$0 $2

$0

$300

$600

$900

$1,200

$1,500

Credit Facility9/30/2017

Bank Debt9/30/2017

L/CsOutstanding9/30/2017

Cash9/30/2017

Liquidity9/30/2017

37

$2,500

$25

$1,796

$700 $21

$0

$1,000

$2,000

$3,000

$4,000

Credit Facility9/30/2017

Bank Debt9/30/2017

L/CsOutstanding9/30/2017

Cash9/30/2017

Liquidity9/30/2017

AR Liquidity Position ($MM)(1) AM Liquidity Position ($MM)(1)

AR Credit Facility AR Senior Notes

Debt Maturity Profile(1)

AM Credit Facility AM Senior Notes

Liquidity & Debt Term Structure

- Approximately $2.9 billion of combined AR and AM financial liquidity as of 9/30/2017

- No leverage covenant in AR bank facility, only interest coverage and working capital covenants

New credit facilities for AR and AM have allowed Antero to extend its average debt maturity of to 2022

1. As of 9/30/2017.

$1,000

$1,100 $750

$650 $600

$25

$427

0

200

400

600

800

1000

1200

1400

1600

1800

2017 2018 2019 2020 2021 2022 2023 2024 2025

Antero Resources Stand-alone EBITDAX Reconciliation

AR Stand-alone EBITDAX Reconciliation

($ in millions)

Three Months

Ended LTM Ended

09/30/2017 09/30/2017

EBITDAX:

Operating loss $(114.1) $(235.8)

Commodity derivative fair value losses 66.0 181.3

Net cash receipts on settled derivatives instruments 61.5 326.9

Depreciation, depletion, amortization and accretion 176.9 720.1

Impairment of unproved properties and accretion 41.0 198.8

Exploration expense 1.6 9.1

Change in fair value of contingent acquisitions consideration (2.6) (15.8)

Equity-based compensation expense 19.2 78.6

Gain on sale of assets - (93.8)

AM distributions net to AR ownership 34.8 126.8

Segment Adjusted EBITDAX $284.3 $1,296.2

38

Antero Resources EBITDAX Reconciliation

39

EBITDAX Reconciliation

($ in millions) Quarter Ended LTM Ended

9/30/2017 9/30/2017

EBITDAX:

Net income including noncontrolling interest $(90.0) $(197.3)

Commodity derivative fair value gains 66.0 181.3

Net cash receipts on settled derivatives instruments 61.5 326.9

Gain of sale on assets - (97.6)

Interest expense 70.1 273.2

Loss on early extinguishment of debt - 16.9

Income tax expense (45.1) (160.5)

Depreciation, depletion, amortization and accretion 207.6 835.3

Impairment of unproved properties 41.0 198.8

Exploration expense 1.6 9.1

Equity-based compensation expense 26.4 105.7

Equity in earnings of unconsolidated affiliate (7.0) (11.3)

Distributions from unconsolidated affiliates 4.3 17.8

Consolidated Adjusted EBITDAX $336.4 $1,498.3

Antero Midstream EBITDA Reconciliation

40

EBITDA and DCF Reconciliation

($ in thousands)

Three months ended

September 30,

2016 2017

Reconciliation of Net Income to Adjusted EBITDA and Distributable

Cash Flow:

Net income $70,524 $80,893

Interest expense 5,303 9,311

Depreciation expense 26,136 30,556

Accretion of contingent acquisition consideration 3,527 2,556

Equity-based compensation 6,599 7,199

Equity in earnings from unconsolidated affiliate (1,544) (7,033)

Distributions received from unconsolidated affiliates - 4,300

Adjusted EBITDA $110,545 $127,782

Interest paid (4,043) (20,572)

Cash reserved for payment of income tax withholding upon vesting of

Antero Midstream Partners LP equity-

based compensation awards (1,000) (1,500)

Cash to be received from unconsolidated affiliates 2,221 -

Cash reserved for bond interest - 8,831

Maintenance capital expenditures (4,638) (16,000)

Distributable Cash Flow $103,085 $98,541

($MMs)

Exploration &

Production

Gathering &

Processing

Water

Handling &

Treatment Marketing

Elimination of

Intersegment

Transactions

Consolidated

Total

Revenues:

Third-Party $660 $7 $0 $51 - $718

Intersegment 1 98 93 - (191) -

Gains on settled derivatives 61 - - - - 61

Total Revenue $722 $105 $93 $51 (191) $780

Cash operating expenses:

Lease operating $24 - $52 - ($52) $23

Gathering, Processing & Transp. (3rd party) 272 - - - - 272

Gathering, Processing & Transp. (AM fees) 98 10 - - (98) 10

Production Taxes 22 0 1 - - 23

G&A (before equity-based comp) 29 4 3 - (0) 36

Marketing - - - 79 - 79

Total Cash Operating Expenses $445 $15 $55 $79 ($150) $443

Segment Adjust EBITDAX $278 $90 $38 ($28) ($41) $336

Capital Expenditures:

D&C (excluding water) $265 - - - - $265

D&C (including water) 93 - - - (41) 52

Land / Acquisitions 57 - - - - 57

G&C / Water Infrastructure - 99 48 147

Total CapEx $415 $99 $48 $0 ($41) $522

3Q 2017 Segment EBITDAX and Capital Expenditures

41

3Q 2017 Segment EBITDAX and Capital Expenditures

1

2

Gathering and compression fees paid to Antero Midstream are included in Gathering, Processing & Transportation expense on stand-alone basis (eliminated on consolidated basis); Gathering and compression operating expenses borne by AM on stand-alone basis (included in GPT on consolidated basis)

Water fees paid to Antero Midstream included in Drilling & Completion capital expenditures on stand-alone basis; water operating expenses borne by AM on stand-alone basis and AR on consolidated basis

On consolidated basis, water fees are eliminated from D&C capital, but water operating expenses are capitalized

Stand-alone EBITDAX

: $250 Million

: $128 Million

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, 2016 included in this presentation have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates as of December 31, 2016 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, 2016. 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

42

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