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Company Presentation

AUGUST 2018

Cautionary Statement

This presentation includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond AR’s control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments AR expects, believes or anticipates will or may occur in the future, such as those regarding future commodity prices, future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, Consolidated Adjusted EBITDAX, Stand-Alone E&P Adjusted EBITDAX, Consolidated Adjusted Operating Cash Flow, Stand-Alone Adjusted Operating Cash Flow, Free Cash Flow, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas, natural gas liquids and oil prices, acreage quality, access to multiple gas markets, expected drilling and development plans (including the number, type, lateral length and location of wells to be drilled, the number and type of drilling rigs and the number of wells per pad), projected well costs, future financial position, future technical improvements and future marketing opportunities, are 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 forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.

AR 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 the AR’s control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs 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 "Item 1A. Risk Factors" in AR’s Annual Report on Form 10-K for the year ended December 31, 2017.

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.

This presentation includes certain financial measures that are not calculated in accordance with U.S. generally accepted accounting principles (―GAAP‖). These measures include (i) Consolidated Adjusted EBITDAX, (ii) Stand-Alone E&P Adjusted EBITDAX, (iii) Consolidated Adjusted Operating Cash Flow, (iv) Stand-Alone E&P Adjusted Operating Cash Flow, (v) Free Cash Flow. Please see ―Antero Definitions‖ and ―Antero Non-GAAP Measures‖ for the definition of each of these measures as well as certain additional information regarding these measures, including the most comparable financial measures calculated in accordance with GAAP.

ANTERO RESOURCES | AUGUST 2018 PRESENTATION

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.

The Size and Scale to Capitalize on the Resource

3 ANTERO RESOURCES | AUGUST 2018 PRESENTATION

Market Cap……….……...........

Enterprise Value….……………

Corporate Debt Ratings………

Stand-Alone Leverage………..

Net Production (2018E)….......

Liquids................................

3P Reserves………..…...........

Net Acres………….…...………

Core Drilling Locations……….

Hedge Mark to Market………..

AR Midstream Ownership (53%)

$6.8B

$10.6B

Ba2 / BB+ / BBB-

2.6x

2.7 Bcfe/d

130,000 Bbl/d

54.6 Tcfe

620,000

3,295

$1.2B

$2.9B

Note: Equity market data as of 6/30/18. Balance sheet data, hedge mark to market, and reserves as of 6/30/18. Enterprise value excludes AM net debt. See 2018 Guidance in Appendix.

Antero Resources Profile

An $18B Integrated Natural Gas and NGL Business

Organizational Structure

4 ANTERO RESOURCES | ORGANIZATIONAL STRUCTURE

Note: Enterprise value as of 6/30/18. AR E&P enterprise value excludes $2.9 Bn of ownership value in AM and AM net debt.

(1) Sponsors represent Warburg Pincus, Yorktown & senior management.

100% Incentive

Distribution Rights

(IDRs)

NYSE: AMGP

Enterprise Value: $3.5B

No Ratings

NYSE: AM

Enterprise Value: $6.9B

Corp Ratings: Ba2 / BB+ / BBB-

NYSE: AR

E&P Enterprise Value: $7.7B

Corp Ratings: Ba2 / BB+ / BBB-

67% 33%

Sponsors(1) Sponsors(1)

53%

27% 73%

47% Public

Public Public

AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5

$5.17 $5.10

$4.09 $4.08

$3.60 $3.90

$-

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

2013 2014 2015 2016 2017 1H 2018

Source: Public data from company 10-Ks. Peers include CNX, COG, EQT, RRC and SWN. All-in realized natural gas equivalent pricing includes liquids and hedge realizations for the period. Hedge realizations is the

stippled top portion of each bar.

Integrated strategy including the most effective firm transportation portfolio, NGL production growth,

midstream build out and hedging resulted in the highest all-in realized prices amongst the peer group

The Leader in All-In Realized Pricing in Appalachia…

5 TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PROFITABILITY DRIVERS

Antero Has Been the Leader in Natural Gas Equivalent Prices For Over Five Years

($/M

cfe

)

Nymex Henry Hub

All-In Realized Pricing ($/Mcfe) – Appalachian Peers

(Includes Liquids and Hedge Realizations)

$3.36

$2.97

$2.07 $2.06

$1.61 $1.86

$-

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

2013 2014 2015 2016 2017 1H 2018

AR Peer 1 Peer 2 Peer 4 Peer 5 Peer 3

EBITDAX Margin

($/Mcfe)

6 TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | EBITDAX MARGINS

…More Importantly, a Leader in EBITDAX Margin Too

On a Stand-Alone EBITDAX Margin Basis, Antero has Consistently Outperformed its Appalachian Peers Through Up and Down Commodity Cycles

Antero’s integrated strategy has positioned Antero as a leader in

EBITDAX margin for over five years

Source: SEC filings and company press releases. AR 2017 margins exclude $0.10/Mcfe negative impact from WGL and SJR natural gas contract disputes. Peers include CNX, COG, EQT, RRC & SWN.

(1) AR and EQT EBITDAX include distributions from midstream ownership. Cash costs for AR and EQT represent stand-alone GPT, production taxes, LOE and cash G&A. Post-hedge and post

net marketing expense where applicable.

WTI Price

($/Bbl) WTI Oil Price ($/Bbl)

$0

$20

$40

$60

$80

$100

$120

EBITDAX Margin vs WTI Oil Price

A Cash Flow Inflection Point

7

Step Change in Capital

Efficiency Reduces 5-Year

D&C Capex by $2.9B

The Size & Scale to

Capitalize on Resource

Announced Longer Lateral

Development Plan

Averaging 11,500’ per Well

Highest Leverage to NGL

Prices Among Top

NGL Producers

Sustainable Cash

Flow Growth

Generating 5-Year Free Cash

Flow of $1.6B at YE Strip &

$2.8B at $60 Oil

Joining an

Elite E&P

Group With:

Scale

Double Digit

Growth

Free Cash

Flow

Low

Leverage Disciplined Returns

Focus

→33% - 37% Full Cycle Returns

→23% 5-Year Debt-Adjusted

Production CAGR per share

→22% 5-Year Cash Flow

CAGR per share

Note: See definitions for free cash flow and assumptions behind long-term targets in Appendix; free cash flow definition includes maintenance land spending, but excludes discretionary land spending.

VALUE PROPOSITION | CAPITAL DISCIPLINE AND DELEVERAGING

Long Lateral Development Plan

8 SCALE & GROWTH | COST EFFICIENCY DRIVERS: LONGER LATERALS

59% of Inventory Now

≥ 10,000’ Lateral Length 5-Year Plan Averages 11,500’

Average Lateral Length

per Completed Well Core Drilling Inventory by Lateral Length

10,800’ Average Inventory

Lateral Length

12,700

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

2018 2019 2020 2021 2022

145 155 160 165 165 Wells

Completed(1)

498

1,450

0

200

400

600

800

1,000

1,200

1,400

1,600

<6,000' 6,000' -8,000'

8,000' -10,000'

10,000' -12,000'

≥12,000'

Feet

Fee

t

(Num

be

r o

f lo

ca

tio

ns)

1) Wells completed reflects midpoint of targeted completions per year.

Step Change in Capital Efficiency

Consolidated Drilling &

Completion Capital

Expenditures

Production Targets

2.7

3.3

4.0

4.6

5.2

2.7

3.3

3.9

4.5

5.2

0.0

1.0

2.0

3.0

4.0

5.0

6.0

2018 2019 2020 2021 2022

Bcfe

/d

As of December 2016

As of December 2017

9 VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | SIGNIFICANT CAPITAL REDUCTION

$2.9B Capex Reduction

Over 5 Years

Cumulative Reduction in Drilling &

Completion Capital

Same Production

Targets 20% Production CAGR 2018-2020

15% Production CAGR 2021-2022

Same Production Growth With Much Less Capital Spending

$1.6 $1.7

$2.0

$2.2

$2.4

$1.3 $1.3 $1.3 $1.4

$1.7

$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

2018 2019 2020 2021 2022

$ B

illi

on

s

As of December 2016 As of December 2017

Breakdown of D&C Capex Savings

10

$2.9B Capital Efficiencies

Captured Within

D&C Capex From

New Development

Program

$0.9B Lateral Lengths

$0.5B Improved Cycle

Times

$1.1B Optimizing Capital

Allocation

$0.09MM/1,000’ savings

from 9,000’ to 12,000’

Reduced drilling

days, increase in

stages per day and

concurrent operations

Continued shift to high-

graded Marcellus

$0.4B Well Cost Savings

Related to reduced AFEs

including lower flowback

water handling cost due

to Clearwater Facility and

begin self-sourcing sand

D&C Capex Savings

Lateral Lengths Cycle Times Well Cost Savings Capital Allocation

& Enhanced Recoveries

VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | COST EFFICIENCY DRIVERS

Note: See appendix for further detail on D&C capital.

3,872

2,575

5,169

-

1,000

2,000

3,000

4,000

5,000

6,000

2014 2015 2016 2017 2Q 2018 RECORD

Fe

et

Marcellus Utica

9,611

15,075

12,886

17,445

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

2014 2015 2016 2017 2Q 2018 RECORD

Feet

Marcellus Utica

4.6 5.0

9.0

3.6

5.4

10.0

-

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

2014 2015 2016 2017 2Q 2018 RECORD

Sta

ges p

er

Day

Marcellus Utica

11

Drilling and Completion Efficiencies

Average Lateral Feet per Day

Drilling Days

Average Lateral Length per Well

Completion Stages per Day


8,206

Note: Percentage increase and decrease arrows represent change in Marcellus data from 2014 to 2Q 2018.

12

8

20

10

0

5

10

15

20

25

30

35

2014 2015 2016 2017 2Q 2018 RECORD

Dri

llin

g D

ays

Marcellus Utica

Drilling Best Lateral Footage in 2018

Antero Top 15 Marcellus Lateral Footage Days (24 Hour Period)

12

8,206 8,178 7,987

7,786 7,573

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

Feb.2018

Jan.2018

Jan.2018

Feb.2018

Feb.2018

Jul.2016

Jun.2016

Apr.2017

Jun.2017

Apr.2018

Jan.2018

May.2016

Oct.2017

Jun.2017

Feb.2018

2018 Drilling 2016 – 2017 Drilling

8 out of Antero’s Top 15 Marcellus Lateral Footage Days Have Occurred in 2018


Drilling efficiencies

continue in 2018

107

33%

15%

34%

8%

11% 11%

13%

15%

10%

13%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

45

55

65

75

85

95

105

115

AR DVN RRC EOG APC COP PXD NBL OXY CHK

NG

L %

of

Pro

du

ct R

eve

nu

es

MB

bl/d

2Q18 Daily NGL Production Including Recovered Ethane

Leader in Leverage to NGL Prices

13 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | TOP U.S. NGL PRODUCER

Top NGL Producers in the U.S.(1)

Source: SEC filings and company press releases.

Note: Realized prices are weighted average including ethane (C2) where applicable. Percent of total product revenues is calculated on a pre-hedge basis.

(1) EOG, NBL, OXY and PXD represent 1Q 2018 results and are denoted by asterisks.

(2) NGL revenue percentage based on unhedged revenue.

NGLs Generate 33%

of AR Revenue (2)

2Q 2018

$26.35 $24.10 $23.69 $24.46 $34.66 $26.71 $27.74 $25.53 $26.89 $20.19

Antero Is Currently the Top NGL Producer in the U.S.

Pre-hedged Realized

NGL Price ($/Bbl)

Pre-Hedge NGL % of Total Product Revenues

* * * *

0%

20%

40%

60%

80%

100%

120%

2018 CompletionProgram

2019 CompletionProgram

Full Cycle ROR at $70/Bbl Half Cycle ROR at $70/Bbl

Full Cycle ROR Half Cycle ROR

Outstanding Corporate Level Well Economics

14 VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | ATTRACTIVE WELL ECONOMICS DRIVE GROWTH

Well Economics

Support Investment

ROR Well in Excess of

Cost of Capital

33% - 37% Corporate

Level ROR

2018 & 2019 Full Cycle

Returns

Single Well Economics – Excluding Hedges

Note: Half cycle burdened with 60% of AM fees to give credit for AM ownership/distributions and firm transportation variable fees. Full cycle burdened with G&A, land costs, 100% of AM fees and full FT costs. See Appendix

for detailed assumptions for full cycle and half cycle single well economics; WACC calculated using CAPM.

AR WACC ≈ 8%

Strip

Pricing

Assumes 6/30/2018

Strip & Excludes

Hedging Impact

AR Cash Cost Returns

93% to 102%

AR Corporate Level

Returns

33% to 37%

$70 Oil

($1,500)

($1,000)

($500)

$0

$500

$1,000

$1,500

2014A 2015A 2016A 2017A 2018Guidance

2019Target

2020Target

2021Target

2022Target

Lower Capital & Higher Liquids → Free Cash Flow

VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | SUSTAINABLE CASH FLOW GROWTH

$60 Oil / $2.85 Gas Case Stand-Alone E&P Free Cash Flow Outspend

Strip Pricing Base Case

Note: See definitions for free cash flow and assumptions behind long-term targets in Appendix; free cash flow definition includes $200MM maintenance land spending, but excludes $300MM discretionary land spending.

D&C Capital Investment Fully Funded with Cash Flow

→ $1.6B of Targeted Free Cash Flow Over the Next 5 Years

$50 Oil / $2.85 Gas Case

$2.8B

$1.0B

$1.6B

We Are

Here

5-Year

Cumulative

Free Cash

Flow

15

Stand-Alone Free Cash Flow:

Resource Capture & Delineation Harvest Mode

3.9x

3.6x

2.8x 2.9x

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

3.5x

4.0x

4.5x

5.0x

2014A 2015A 2016A 2017A 2018Guidance

2019Target

2020Target

2021Target

2022Target

Sta

nd

-Alo

ne

Fin

an

cia

l L

eve

rage

12/31/17 Strip Pricing (Base Case)

$60 Oil / $2.85 Gas

$50 Oil / $2.85 Gas

Cash Flow Growth → Deleveraging Profile

23% Debt-Adjusted

Production CAGR

Generates Free

Cash Flow

Balance Sheet

Deleveraging &

Optionality

Note: See Appendix for key definitions and assumptions. Stand-alone financial leverage is calculated by dividing year-end stand-alone debt by last twelve months stand-alone EBITDAX. Note all free cash flow after land

spending is assumed to be used for debt reduction.

Leverage targets inclusive of $500 MM of maintenance and discretionary land capex from 2018 - 2022

Deleveraging Supported By:

• 2.4 Tcfe Hedge Position

• 4.7 Bcf/d FT Portfolio

• $1.4B of Targeted AM

Distributions

CAPITAL DISCIPLINE AND DELEVERAGING | CASH FLOW DRIVES LOW LEVERAGE

S&P Upgrade to BB+

Moody’s Ba2 Outlook ―Positive‖

BBB- Rating Fitch Recently Rated AR Investment

Grade

2Q 2018

Leverage: 2.6x

16

17 VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | ATTRACTIVE VALUATION

Antero Profile Should Drive Multiple Expansion

U.S. Publicly Traded E&Ps

Leverage < 3.0x

Enterprise Value

> $10B

Production Growth >15%

Leverage <2.0x

Free Cash Flow

Among an Elite Group of E&Ps With Scale, Double Digit Growth, Low Leverage & Free Cash Flow Generation

Source: Bloomberg & Antero Estimates as of 8/1/18.

(1) Adjusted EBITDAX and Adjusted Operating Cash Flow are non-GAAP measures. AR EV/EBITDAX multiple also reflects an enterprise value that excludes AR ownership of AM, and EBITDAX excludes AM distributions

received by AR, for comparative purposes with peer E&P multiples. For additional information regarding these measures, please see “Antero Definitions” and “Antero Non-GAAP Measures” in the Appendix.

# of

Companies

Median Debt/

Adjusted

EBITDAX

Median EV/

2018 Adj.

EBITDAX

52 2.4x 6.6x

34 1.7x 7.0x

18 1.7x 7.8x

10 1.4x 8.6x

6 1.0x 9.7x

6 1.0x 9.7x EOG

CXO

PXD

AR 2018E

unhedged

Stand-alone

EBITDAX

Multiple: 5.4x

Scale

Growth

Low Leverage

Permian & Appalachia

FCF Generation

FANG

COG

XEC

in 2019

in 2018

Premium for:

0%

1%

2%

3%

4%

5%

6%

7%

8%

2018 2019 2020

FC

F Y

ield

18 VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | 5-YEAR OUTLOOK

Attractive Free Cash Flow Yield

Note: See definitions for free cash flow and assumptions behind long-term targets in Appendix. “Elite” group of peers includes COG, CXO, EOG, FANG, PXD, XEC; “Integrated” group includes XOM & CVX.

Source: Bloomberg. Represents free cash flow yield for the base case at 12/31/17 strip pricing.

(1) Represents free cash flow divided by current market capitalization as of 6/30/18.

Free Cash Flow Yields Exceed Both Best-In-Class Peers & Integrated Oil & Gas Companies

AR

7% FCF Yield(1)

Surpasses Industry Leading Peers,

While Maintaining Strong Production

Growth

Assuming current stock prices, Antero should deliver free cash flow yield

well in excess of both the integrateds and the ―best in class‖ E&P peers

Scale & Growth: Liquids-Rich Resource Meets Capital Efficiency

Antero is Very Well Positioned in the Core of the Core

20 SCALE & GROWTH | CORE OF THE CORE

Positioned in the Core of the Core

Northern Rich High-Graded Core

~283,000 acres

2.24 Bcfe/1,000’ Avg. EUR

67% Undeveloped

Southern Rich High-Graded Core

~487,000 acres


70% Undeveloped

AR Holds 61% of Undeveloped

Southwest Marcellus Core

~2.9 Million Acres

~78% Undeveloped

Antero Acreage

Antero Marcellus Wells

Industry Marcellus Wells

Antero Marcellus Rig

Industry Marcellus Rig

Dry Gas High-Graded Core

~1,051,000 acres


78% Undeveloped

AR Holds 13% of Undeveloped

> 1,300 lb/ft Completions

High- Graded

Core Areas

Most Active

Operators

Percent

Undeveloped

Advanced

Completions

(>1,300 lbs/ft)

Bcfe /

1,000’ Wells

Northern Rich RRC, CNX, HG 67% 2.24 474

Southern Rich AR, EQT, SWN 70% 2.24 517

Dry Gas EQT, CVX,

RRC, CNX 78% 2.30 747

Note: Core area excludes 600,000 urban acres mostly around Pittsburgh, PA. EURs assume full ethane rejection. Based on Antero reserve engineering of most recent state and internal production data.

3,295

2,333

1,930

1,259

720 714 663 588 583 556 544

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

AR A B C D E F G H I J

Und

rille

d L

oca

tio

ns

Marcellus & Utica Liquids Rich Locations SW Marcellus & Utica Dry Locations NE Pennsylvania Dry Locations

Largest Undrilled Core Drilling Inventory

21 SCALE & GROWTH | CORE OF THE CORE

10,848’ 9,563’ 6,775’ 7,723’ 6,040’ 9,583’ 8,905’ 9,398’ 8,396’ 7,731’ 8,639’

Antero Holds 40% of Core

Undrilled Liquids-Rich Locations

Largest Inventory in Appalachia

(1) Peers include Ascent, CHK, CNX, COG, CVX, EQT, GPOR, HG, RRC and SWN. Based on Antero analysis of undeveloped acreage in the core of the Marcellus and Utica plays.

Who Can Consistently Drill

Long Laterals?

Who Has the

Running Room?

Undrilled Core Marcellus & Utica Locations(1)

Lateral Length:

A Pioneer in Longer Lateral Development in Appalachia

22

(1) All laterals rounded to the nearest thousand.

(2) Represents wells placed to sales.

Antero Historical & Future Lateral Length Program

113

85

22 12 10 4

12

13

57

103

93

107

76 81 78

77 93

0

50

100

150

200

250

300

≤ 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 > 15,000

Well

Cou

nt

Lateral Length(1)

Antero # of

Wells

Avg. Lateral

Length

Total Drilling Program

to Date 945 8,275

2018-2022 Program(2) 790 11,425

Wells to Date

≥10,000’ 245 10,700

SCALE & GROWTH | COST EFFICIENCY DRIVERS: LONGER LATERALS

0

5

10

15

20

25

30

35

40

45

3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 16,000

EU

R (

Bcfe

)

Lateral Length (ft)

EUR in Bcfe/1,000' 2.3 Bcfe/1,000'

Longer Laterals Scale the Resource


EURs by Marcellus Lateral Lengths

A 1:1 Proportional

Increase in EURs with

Longer Laterals Antero well results show no evidence of

degradation in recovery per foot of

completed lateral out to over 14,000’

R2 = .73

Note: Assumes ethane rejection.

The Longer, the Better…


Note: Represents half cycle economics at 6/30/2018 strip pricing for a 1250 Btu Marcellus well. See Appendix for further assumptions on single well economics.

Single Well Economics by Lateral Lengths

$7.1

$11.9

$16.6

$21.0

58%

77%

89% 90%

0%

20%

40%

60%

80%

100%

$-

$5.0

$10.0

$15.0

$20.0

$25.0

6,000' Lateral 9,000' Lateral 12,000' Lateral 15,000' Lateral

PV-10 ($MM) ROR (%)

~60% Improvement in ROR from a 6,000’ Lateral to a 15,000’ Lateral

$0.60

$0.80

$1.00

$1.20

$1.40

$1.60

$1.80

$2.00

$2.20

3,000 6,000 9,000 12,00015,000

$M

M/1

,000 f

t of

late

ral

Lateral Length (ft)

Marcellus

2014 2017

Declining Well Costs → Longer Laterals the Next Step


Note: Well costs reflect 2,000 pound per foot completions. See Appendix for further assumptions.

Historical Well Costs

41% | 43%

Lower Costs Marcellus | Utica reduction in well costs

from 2014 to 2017 for a 9,000’ lateral

- 54% from efficiencies

- 45% from service costs

9% | 10%

Cost Benefit Marcellus | Utica reduction in well cost

per 1,000’ lateral going from

9,000’ to 12,000’ laterals 4

1%

Red

uctio

n

$0.60

$0.80

$1.00

$1.20

$1.40

$1.60

$1.80

$2.00

$2.20

$2.40

$2.60

3,000 6,000 9,000 12,000 15,000

$M

M/1

,000 f

t of

late

ral

Lateral Length (ft)

Utica

2014 2017

43

%

Red

uctio

n

9%

Reduction

10%

Reduction

Operating Evolution Continues

26

(1) Based on Marcellus 11,000 foot lateral and 2,000 pounds per foot AFE. Assumes nine wells per pad.

Drilling

Efficiency (25%)

42%

Decline in well costs

since 2014

54% Permanent cost

efficiencies

46% Vendor-related cost

reductions

Efficiencies Expected to Offset Service Cost Inflation

Facilities, Pad & Road

Allocation 9%

Tubulars 4%

Sand 12%

Flowback Water

5%

Completion Spreads

25%

Drilling Rigs & Services

21%

Completion Services

24%

Drilling Rigs/Services

→Fit-for-purpose rigs with dual operation

capabilities to improve cycle times

→ Improved drillout efficiency

→Penetration rates still increasing with

new downhole motors

Completion Spreads/Services

→ Concurrent operations with larger

pads allowing simultaneous drilling

and completion and easier access

→ More wells per pad

→ Automated completion equipment to

increase stages per day

Sand

→ 100 mesh sand for easier pumping &

fewer screenouts

→ Self-sourcing sand to reduce

supply cost

→ Regional sand mines in the Permian

expected to reduce demand for

Northern White sand

• Fit-for-purpose rigs improves

cycle times

• Enhanced walking and dual operation

capabilities

• Concurrent operations

• Larger pads allowing for production at

one end and drilling at the other

• More wells per pad

• Automated completion equipment

→ increase stages per day

• Reduced cluster spacing

→ higher potential recoveries

• 100 Mesh Sand

→ easier pumping with fewer

screenouts and less cost

• Self-Sourcing Sand

→ reduce supply cost

• Improved Drillout Efficiency

100% of Completion

Spreads Under Contract

Through 2019

Antero has 100% of 2018 Rigs and

50% of 2019 Rigs Under Fixed

Rate Contracts with Average Rig

Rates Declining Towards

$17,500/day in 2018 as Higher Rig

Rate Contracts Roll Off

Achievements to Date

2018 Marcellus Well Cost(1) Next Steps in Efficiency Evolution

SCALE & GROWTH | OPERATING TECHNOLOGIES EVOLVE

$0.88

$0.73

$0.51

$0.42

$1.28

$0.94

$0.73 $0.74

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

2014 2015 2016 2017

Marcellus Utica

27 SCALE & GROWTH | COST EFFICIENCY DRIVERS: WELL COST REDUCTION

Dramatically Lower F&D Cost

F&D Cost per Mcfe(1)(2)

(1) Ethane rejection assumed.

(2) F&D cost is defined as current D&C cost per 1,000’ lateral divided by net EUR per 1,000’ lateral assuming 85% NRI in Marcellus and 81% NRI in Utica. Please see “Antero Definitions” and “Antero Non-GAAP Measures”

in the Appendix.

Dramatic Improvement in Operating Efficiencies, Lower Service Costs and Higher Well Recoveries Have Driven F&D Costs Materially Lower

52% | 42%

Lower F&D in Marcellus | Utica

0

50,000

100,000

150,000

200,000

250,000

2014 2015 2016 2017 2018EGuidance

2019ETarget

2020ETarget

2021ETarget

2022ETarget

Natural Gasoline (C5+) IsoButane (iC4)

Normal Butane (nC4) Propane (C3)

Ethane (C2)

245,000

Rapidly Growing NGL Production

28 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | GROWING NGL PRODUCTION

Antero NGL Production Growth by Purity Product

Note: Excludes condensate. See Appendix for further assumptions around long-term targets.

To

tal (B

bl/d

)

C5+

iC4

nC4

C3

C3+ Production

C2

C2 Ethane 17,476

C2 Ethane 26,500

C2 Ethane 43,000

Material reduction in U.S. propane

inventories relative to the 5-year average

Current propane days of supply are

12% below last year and 38%

below the 5-year average

Strong Propane Fundamentals

29 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | LPG FUNDAMENTALS

Propane Days of Supply U.S. Propane Inventories

0

10

20

30

40

50

60

70

80

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

Days o

f S

up

ply

5-Yr Range 2018 2017 5-Yr Avg 2013-2017

0

20

40

60

80

100

120

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

MM

Bb

ls

5-Yr Range 2017 2018 5-Yr Avg 2013-2017

Source: EnVantage Inc. and Energy Information Administration (EIA).

MB C3 $0.97/gallon

remainder of 2018

2017

2018

2017

2018

$0.30

$0.40

$0.50

$0.60

$0.70

$0.80

$0.90

$1.00

$1.10

Jan-1

6

Feb

-16

Ma

r-1

6

Apr-

16

Ma

y-1

6

Jun-1

6

Jul-1

6

Aug-1

6

Sep-1

6

Oct-

16

No

v-1

6

De

c-1

6

Jan-1

7

Feb

-17

Ma

r-1

7

Apr-

17

Ma

y-1

7

Jun-1

7

Jul-1

7

Aug-1

7

Sep-1

7

Oct-

17

No

v-1

7

De

c-1

7

Jan-1

8

Feb

-18

Ma

r-1

8

Apr-

18

Ma

y-1

8

Jun-1

8

Jul-1

8

Aug-1

8

Sep-1

8

Oct-

18

No

v-1

8

De

c-1

8

Jan-1

9

Feb

-19

Ma

r-1

9

$ p

er

gallo

n

Spring (Apr - Jun) Winter (Dec - Feb)

Mont Belvieu Propane Prices Mont Belvieu Propane Futures

30 PROPANE PRICES: WINTER MONTHS HISTORICALLY EXCEED SPRING LEVELS

Winter Propane Futures are Historically Conservative

Winter Propane Prices vs.

Prior Spring Prices(1): • 5-year historical prices rose +14%,

despite commodity cycle downturn

• 2016/2017 prices rose +46%

• 2018 futures prices imply only +7%

A doubling in U.S. propane exports over three years places demand dynamics on a global scale, driving favorable propane pricing

(1) Winter months reflect December-February month averages; Spring reflects April-June month averages.

(2) Implied prices are based on five year averages of rolling three month price change relative to Spring prices

?

AR C3+ Barrel 1Q 2018 Actuals 2Q 2018 Actuals Balance 2018 (1)

Propane 57% $0.87 $0.87 $0.97

N. Butane 16% $0.84 $0.89 $1.15

IsoButane 10% $1.05 $1.20 $1.15

Natural Gasoline 17% $1.39 $1.53 $1.54

Mont Belvieu Product Pricing ($/Gallon)

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

$1.60

$1.80

$2.00

2010 2011 2012 2013 2014 2015 2016 2017 2018

$/G

allo

n (

C3

+ N

GL

s)

C3+ NGLs: Price Improvement

31 NATURAL GAS LIQUIDS: LEADING POSITION & STRONG FUNDAMENTALS | MARKET DYNAMICS

Tightening Inventories and Increasing Exports, Along With an Increase in Global Product Prices, Have Resulted in an Improvement in C3+ Prices

Strong C3+ NGL Prices Expected to Continue Through 2018

Source: Intercontinental Exchange (ICE) pricing data. Assumes C3+ barrel weightings of: propane 57%, normal butane 16%, Isobutane 10%, pentanes 17%.

1) Balance 2018 represents strip pricing as of 7/25/2018.

Balance 2018 (1)

C3+ $1.11 / Gal

Note: 2H 2018 based on 2018 balance strip pricing as of 7/25/2018. Local index represents a blend of Dominion South and TETCO M2 pricing. Midwest index represents a blend of Chicago and MichCon pricing. Gulf

Coast index represents a blend of Gulf and Nymex-based pricing.

Antero 2018 Firm Transport Index Breakdown

Expected Natural Gas Price Realization Improvement

TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PROFITABILITY DRIVERS

~97% of Antero Gas Is Expected to be Sold in Favorably Priced Markets in the Balance of 2018

32

59% 60%

17% 14%

16% 23%

8% 3%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1H 2018 2H 2018

Index Differential % of Gas Sold Differential % of Gas Sold

Local Markets(1) $(0.55) 8% $(0.43) 3%

Midwest $0.07 16% $(0.07) 23%

TCO $(0.20) 17% $(0.22) 14%

Gulf Coast $(0.14) 59% $(0.11) 60%

Wtd.Avg. Differential: $(0.15) 100% $(0.13) 100%

BTU Uplift $0.24 $0.24

All-in vs. NYMEX +$0.09 +$0.11

+$0.05 - $0.10 Updated forecast

premium to NYMEX

after BTU uplift

5% decrease to

Local Markets Local

Midwest

TCO

Gulf Coast

8% increase in

exposure to Midwest

& Gulf Cost Markets

Well Hedged at High Prices Relative to Strip

TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PRODUCTIVITY DRIVERS

2,195

2,330

1,418

710 850

90

$3.70 $3.50

$3.25 $3.00 $3.00 $2.91

$2.92 $2.78 $2.66

$2.61 $2.64 $2.70

$-

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

$5.00

-100

400

900

1,400

1,900

2,400

2018 2019 2020 2021 2022 2023

MM

cfe

/da

y

Average Index Hedge Price(1) Hedged Volume Current NYMEX Strip(2) Mark-to-Market Value(2)

(1) Weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio. Includes 26,000 Bbl/d of propane hedged at $0.76/gallon and 6,000 Bbl/d of oil hedged at $56.99/Bbl for 2018 only.

(2) As of 6/30/18.

Commodity Hedge Position

~$1.2B Mark-To-Market Unrealized Gains Based On 6/30/2018 Prices

2.4 Tcfe hedged through

2023 at $3.35/MMBtu

~26 MBbl/d of propane

hedged in 2018 at $0.76/Gal

$3.9B of realized gains

on hedges since 2008

33

~100% of 2018 and 2019

Target Gas Production Hedged

at $3.50/MMBtu ($/MMBtu)

$0.10/ Mcfe

$0.15/ Mcfe < $0.10/

Mcfe

$0 $0

$0.125/Mcfe

$0.20/Mcfe

$469 $0.45/Mcfe

$585 $0.48/Mcfe

$224 $0.15/Mcfe

$37 $35

$0

$100

$200

$300

$400

$500

$600

2018Guidance

2019 Target 2020 Target 2021 Target 2022 Target

$ M

illio

ns

Net Marketing Expense (High End)

Net Marketing Expense (Low End)

Hedge Gains

34 TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | FIRM TRANSPORTATION & HEDGE BOOK

A Paired Trade – Hedges Support Firm Commitments

Hedge Gains More than Offset Marketing Expense – Hedges Support FT Commitments

Firm Transportation Portfolio

Allows Antero to achieve:

Effectively

Hedge NYMEX

Index

A key advantage as

our product is

delivered to NYMEX-

related markets

Premium Price

Certainty

Less volatility and

greater surety in

realized prices

5-Year Cumulative:

Hedge Gains: $1,350

Marketing Expense: ($461)

Net Uplift: $889

Hedge Portfolio Supports

Firm Commitments

$1,150

$2,830

$5,973

$795 $179

$311 $395

$250

$2,893

$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 of6/30/18

Total Proceedsto Date

ExpectedEarnout

Payments(2019E-2020E)

Pre-tax Valueof AM Units

Held by AR @$29.52

(06/30/18)

Pre-taxCumulative

Value of AnteroMidstream

Cash

Pro

ce

ed

s (

SM

M)

Midstream Driving Value for AR Since Inception

Antero Midstream Return on Investment for AR (Pre-tax)(1)

4.6x

ROI

Takeaway

Assurance Return on

Investment

Downstream

Visibility

(1) Midstream proceeds received by AR to date plus market value of AR’s 53% ownership of AM at 6/30/18 divided by the approximate $1.3B of AR capital invested at time of AM IPO.

35 TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | MIDSTREAM DRIVING VALUE

6/30/2018 Debt Maturity Profile

$1,000

$1,100 $750 $650

$600

$455

$770

$0

$500

$1,000

$1,500

$2,000

$2,500

2018 2019 2020 2021 2022 2023 2024 2025

Liquidity & Debt Term Structure

AR Credit Facility AM Credit Facility AR Senior Notes AM Senior Notes

New credit facilities for AR

and AM have allowed

Antero to extend its average

debt maturity out to 2022

36 ANTERO RESOURCES | CONSOLIDATED LIQUIDITY AND BALANCE SHEET

No maturities

until 2021

Deleveraging is Driving Ratings Momentum

37 ANTERO RESOURCES | TRENDING TOWARDS INVESTMENT GRADE

Moody's S&P Fitch

Corporate Credit Ratings History

Corporate Credit Rating

(Moody’s / S&P / Fitch)

Ba3 / BB-

B1 / B+

B2 / B

B3 / B-

Ba2 / BB

Ba1 / BB+

Caa1 / CCC+ / CCC

Baa3 / BBB-

2010

Investment Grade

Rating: BBB-

Fitch Jan. 2018

Stable through

commodity price crash

Credit Markets Have a Strong Appreciation for Antero Momentum

Investment Grade Rating from

Fitch (BBB-) & Recent

Upgrade from S&P (BB+)

Stable Credit Ratings with Consistent

Upgrades from the Beginning of the

Decade Through the Downturn

2011 2012 2013 2014 2015 2016 2017 2018

Upgrade to BB+

S&P Feb. 2018

Investment Grade

Outlook to Positive

Moody’s Feb. 2018

Antero Midstream Overview: Disciplined Capital Efficient Business Model

Antero Midstream At A Glance

39

Market Cap……………….......

Enterprise Value….........…….

LTM Adjusted EBITDA(1)……..

% Gathering/Compression…

% Water…..…..…..…..……..

Net Debt/LTM EBITDA……....

Corporate Debt Rating……….

$5.5B

$6.9B

$619 MM

65%

35%

2.3x

Ba2 / BB+ /BBB-

Note: Equity market data as of 6/30/2018. Balance sheet data as of 6/30/2018.

1. LTM Adjusted EBITDA as of 6/30/18. Adjusted EBITDA is a non-GAAP measure. For additional information regarding this measure, please see “Antero Midstream Non-GAAP Measures” in the Appendix.

ANTERO MIDSTREAM │ JUNE 2018 PRESENTATION

AM Highlights Antero Midstream Marcellus Assets

Compressor Station: In Service

Antero Clearwater Facility

Processing Facility

Compressor Station: 2018

Gathering Pipeline Fresh Water Pipeline Stonewall Pipeline

Sherwood Processing

Facility – 1.8 Bcf/d

Existing Capacity

Antero Clearwater

Facility Stonewall

Pipeline

AMGP Highlights

Market Cap……………….......

Net Debt/LTM EBITDA...…….

$3.5B

–

Antero Midstream Utica Assets

Smithburg Processing

Facility – Civil Work

Under Way

$280

$404

$529

$730

2.2x 2.1x

2.3x

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

$1,800

2015A 2016A 2017A 2018EGuidance

2019E 2020E 2021E 2022E

EBITDA Leverage

Disciplined EBITDA Growth

40

AM EBITDA and Leverage

2014 IPO Leverage

Target: Low 2x

DISCIPLINED CAPITAL EFFICIENT BUSINESS MODEL

2Q 2018

Leverage: 2.3x

Capital Efficiency Drives Free Cash Flow Generation

DISCIPLINED CAPITAL EFFICIENT BUSINESS MODEL 41

AM Throughput Growth

Over $2.4 billion of Free Cash Flow from 2018 – 2022 Before Distributions

($800)

($600)

($400)

($200)

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

2014A 2015A 2016A 2017A 2018Guidance

2019Target

2020Target

2021Target

2022Target

AM Cash Flow Outspend Before Distributions

With No Change

to Throughput

Volumes

~$500MM in Capital

Efficiencies

Earn-out Payments from Water Drop Down

Leverage existing asset base

and realization of ―full build-out

EBITDA multiples‖

Note: Includes water earnings and capital invested on a recast basis prior to drop down and excludes drop down purchase price

We Are

Here

AM Free Cash Flow Before Distributions

Free Cash Flow is a non-GAAP measure. For additional information regarding this measure, please see “Antero Midstream Non-GAAP Measures” in the Appendix..

Antero Midstream Project Economics

42

AM Project Economics by Investment

30%

18%

15%

30%

15% 15%

40%

28%

25%

40%

25%

18%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

LPGathering

HPGathering

Compression FreshWater

Delivery

AdvancedWastewaterTreatment

Processing/Fractionation

Inte

rna

l R

ate

of

Re

turn

“Just-in-time” capital investment philosophy drives attractive project IRR’s

17% 12% 29% 12% - 30%

% of 5-year Organic

Project Backlog

Weighted Avg: 25% IRR

ORGANIC PROJECT BACKLOG WITH PEER-LEADING RETURNS

Antero Midstream Return on Invested Capital

43

AM Return on Invested Capital (ROIC)

2017 ROIC of 15% in

only fourth year of AM

operations

Future organic growth

capital leverages

existing trunklines and

major gathering

arteries

12%

9%

13%

15%

0%

5%

10%

15%

20%

25%

2014A 2015A 2016A 2017A 2018E 2019E 2020E

Actual Consensus

Source: Factset consensus estimates. See appendix for ROIC calculation

Fewer pads to service

reduces capital with

same throughput

DISCIPLINED CAPITAL EFFICIENT BUSINESS MODEL

Return on invested capital is a non-GAAP measure. For additional information regarding this measure, please see “Antero Midstream Non-GAAP Measures” in the Appendix.

Long-Term Distribution and Coverage Targets

44

$1.03 $1.33

$1.72

$2.21

$2.85

$3.42

$4.10 1.8x

1.4x 1.3x

0.0x

0.2x

0.4x

0.6x

0.8x

1.0x

1.2x

1.4x

1.6x

1.8x

2.0x

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

2016A 2017A 2018Guidance

2019Target

2020Target

2021Target

2022Target

DC

F C

ove

rag

e R

ati

o

Dis

trib

uti

on

Pe

r U

nit

Distribution Guidance

(Mid-point)

Long-Term Distribution Targets and DCF Coverage

Unchanged capital investment philosophy with disciplined financial policies result in ability to target peer-leading distribution growth through 2022

Distribution Target

(Mid-point) DCF Coverage Targets

Note: Implied yield based on AM unit price as of 6/30/18.

Implied Yield

9.7%

5.8%

AM: PEER LEADING DISTRIBUTION GROWTH AND COVERAGE

Antero Midstream’s Premier Asset Footprint

Gathering and

Compression

Fresh Water

Delivery

Wastewater

Handling and

Treatment

Processing and

Fractionation

Antero Midstream provides a customized full value chain midstream solution in the lowest cost natural gas and liquids basins: the Marcellus and Utica Shale

• Integrated system in the core of the Marcellus

and Utica Shales delivering wellhead gas

directly to key processing plants and long haul

pipelines

• Joint Venture with MPLX (NYSE: MPLX) aligns

the largest liquids-rich resource base with the

dominant processing and fractionation

footprint in Appalachia

• Largest freshwater delivery system in

Appalachia that has a 100% track record of

timely fresh water deliveries to AR’s

completions

• Largest wastewater treatment facility in the

world for shale oil and gas operations

PREMIER INTEGRATED APPALACHIAN MIDSTREAM ASSETS 45

Northeast Value Chain Opportunity

46

~$1.9B Organic Project Backlog

~$800MM 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

>$1.0B

Downstream

Investment

Opportunity Set

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

AM Assets AM/MPLX JV Assets Potential AM Opportunities

Upstream Downstream

5-year identified project inventory of $2.7B plus an additional $1.0B of potential downstream opportunities

OUTLOOK: ORGANIC PROJECT BACKLOG WITH PEER-LEADING RETURNS

Most Integrated Natural Gas & NGL Business in the U.S.

47 ANTERO RESOURCES | SUMMARY

World Class E&P Operator in Appalachia A Leading Northeast Infrastructure Platform

Contiguous Core Acreage Position Allows for Long

Lateral Drilling and Significant Capital Efficiencies

Largest Exposure to NGLs Among Producers in the

U.S. Leads to Peer Leading Cash Flow Margins

Optimized 5-Year Plan Results in High Return Drilling

& Free Cash Flow

Midstream Ownership & Integration Delivers Value and

Just-in-Time Infrastructure Buildout

53% of LP Units

Appendix

APPENDIX | 2018 GUIDANCE

Updated 2018 Guidance

Stand-Alone Consolidated

Net Daily Production (Bcfe/d) ~2.7

Net Liquids Production (BBl/d) ~130,000

Natural Gas Realized Price Differential to

Nymex $0.05 to $0.10 Premium

C3+ NGL Realized Price

(% of Nymex WTI) 57.5% – 62.5%

Cash Production Expense ($/Mcfe) $2.05 – $2.15 $1.60 – $1.70

Marketing Expense ($/Mcfe)

(10% Mitigation Assumed) $0.10 – $0.125

G&A Expense ($/Mcfe)

(before equity-based compensation) $0.125 – $0.175 $0.15 - $0.20

Adjusted EBITDAX $1,700 – $1,800 $2,050 – $2,150

Adjusted Operating Cash Flow $1,480 – $1,600 $1,750 – $1,900

Net Debt / LTM Adjusted EBITDAX Low 2x Mid 2x

D&C Capital Expenditures ($MM) $1,500 $1,300

Land Capital Expenditures ($MM) $150

($25MM Maintenance)

$150

($25MM Maintenance)

Note: See Appendix for key definitions. Cash flow and EBITDAX guidance based on 12/31/2017 strip pricing . 2018 average NYMEX and WTI pricing was $2.83/MMBtu and $59.57/Bbl, respectively.

(1) Includes lease operating expense, gathering, compression, processing and transportation expense and production and ad valorem taxes.

49

Denotes Change in guidance

APPENDIX | 5-YEAR ASSUMPTIONS

Antero Guidance and Long-Term Target Assumptions

Stand-Alone Consolidated

Net Daily Production (MMcfe/d) 20% CAGR through 2020 and 15% Growth in each of

2021 and 2022

Natural Gas Realized Price Differential

to Nymex

$0.05 to $0.10 Premium (2018)

$0.00 to $0.10 Premium (2019 – 2022)

C3+ NGL Realized Price

(% of Nymex WTI)

57.5% – 62.5% (2018)

69% (2019+) – ME2 Fees Booked to Transport Costs

Realized Oil Price Differential to WTI ($5.00) – ($6.00)

Cash Production Expense ($/Mcfe)(1) $2.05 - $2.15 (2018)

$2.10 – $2.25 (2019 – 2022)

$1.60 - $1.70 (2018)

$1.65 – $1.75 (2019 – 2022)

Marketing Expense ($/Mcfe)

$0.10 - $0.125 (2018)

$0.15 – $0.20 (2019)

<$0.10 (2020)

$0.00 (2021 – 2022)

G&A Expense ($/Mcfe)

(before equity-based compensation)

$0.125 – $0.175 (2018 – 2019)

$0.10 – $0.15 (2020 – 2022)

$0.15 - $0.20 (2018 – 2019)

$0.10 – $0.15 (2020 – 2022)

Cash Interest Expense ($/Mcfe)

$0.175 – $0.225 (2018 – 2019)

$0.10 – $0.15 (2020 – 2021)

<$0.10 (2022)

$0.25 – $0.30 (2018 – 2019)

$0.20 – $0.25 (2020 – 2022)

Well Costs ($MM / 1,000’)

(Assumes 12,000’ completions at

2,000 lbs. per foot of proppant)

Marcellus: $0.95 MM

Utica: $1.07 MM

Marcellus: $0.80 MM

Utica: $0.95 MM

(1) Includes lease operating expense, gathering, compression, processing and transportation expense and production and ad valorem taxes.

50

Denotes Change in guidance

51 APPENDIX | 5-YEAR ASSUMPTIONS

Antero Guidance and Long-Term Target Assumptions (Cont.)

Stand-Alone E&P Consolidated

Adjusted Operating Cash Flow(1) $10.4B

(Cumulative 2018 – 2022) N/A

Annual D&C Capital Expenditures ($MM) $1,500 – $1,600 (2018 – 2020)

$1,700 – $2,000 (2021 – 2022)

$1,300 – $1,400 (2018 – 2021)

$1,600 – $1,700 (2022)

Land Maintenance Expenditures ($MM)(2) ~$200 (Cumulative 2018 – 2022)

Free Cash Flow(1) $1.6B

(Cumulative 2018 – 2022) N/A

Leasehold Growth Capital Expenditures ($MM) ~$300 (Cumulative 2018 – 2022)

Number of Well Completions 790 well completions

Marcellus EUR per 1,000’ of Lateral 2.0 Bcf/1,000’; 2.5 Bcfe/1,000’ (25% ethane recovery)

Utica EUR per 1,000’ of Lateral 2.0 Bcfe/1,000’ (ethane rejection)

Note: See Appendix for key definitions. Cash flow guidance is based on 12/31/2017 strip pricing. Average NYMEX pricing was $2.83/MMBtu, $2.81/MMBtu, $2.82/MMBtu, $2.85/MMBtu and $2.89/MMBtu in 2018, 2019,

2020, 2021 and 2022. Average WTI pricing was $59.57/Bbl, $56.19/Bbl, $53.76/Bbl, $52.29/Bbl and $51.67/Bbl for 2018, 2019, 2020, 2021 and 2022.

(1) Adjusted Operating Cash Flow and Free Cash Flow are non-GAAP financial measures. For additional information regarding these measures, please see the following pages (“Antero Definitions” and “Antero Non-GAAP

Measures”).

(2) Includes leasehold capital expenditures required to achieve targeted working interest percentage.

52 APPENDIX | PROJECT ASSUMPTIONS

Antero Long-Term Target Project Assumptions

In-Service Date

Rover Phase 2 2H 2018

Mariner East 2 2H 2018

WB Xpress West 4Q 2018

WB Xpress East 4Q 2018

Mountaineer Xpress / Gulf Xpress YE 2018

Note: Based on publicly available information.

53 APPENDIX | ASSUMPTIONS

D&C Capital Transparency

D&C Capital

(1)

(1) Based on Marcellus AFE, which assumes inflation on consumable products (i.e. sand/chemicals).

($MM)

2018 2019 2020

Total Well Completions (I.e. First Sales) 145 155 160

Average Lateral 9,700 10,500 11,600

Adjusted Well Count (I.e. Based on Capital Timing) 155 157 150

Average Lateral 9,700 10,500 11,600

Total Adjusted Lateral Feet 1,503,500 1,648,500 1,740,000

Cost per Lateral Foot ($MM/1,000) - Lateral Savings ONLY $0.86 $0.83 $0.81

Implied D&C $1,293 $1,368 $1,409

Savings from Concurrent Ops. / Increasing Stages per Day ($24) ($79)

Adjusted Capital Cost $1,293 $1,344 $1,330

Implied Cost per Lateral Foot ($MM/1,000) $0.86 $0.82 $0.76

54 APPENDIX | PRICING ASSUMPTIONS

Antero Long-Term Target Pricing Assumptions

Commodity prices: All forecasts reflect the following commodity price cases:

• Base case: Strip commodity pricing at 12/31/17 ($54.71 WTI crude oil & $2.84 Nymex Henry Hub) for 2018 - 2022

• Upside case: 12/31/17 Strip for 2018 and $60 WTI crude oil & $2.85 Nymex Henry Hub gas prices for 2019 - 2022

• Downside case: 12/31/17 Strip for 2018 $50 WTI crude oil & $2.85 Nymex Henry Hub gas prices for 2019 - 2022

Current Hedging Arrangements

• 80% Hedged on natural gas production through 2020 at $3.44/MMBtu and 52% hedged on natural gas production

through 2022 at $3.34/MMBtu

• 23% hedged on C3+ NGL production in 2018 at $0.75/gallon (Propane volume only)

Oil and Gas Strip Commodity Prices (12/31/17)

$59.62 $56.19

$53.76 $52.29 $51.67

$2.82 $2.81 $2.82 $2.85 $2.89

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$35.00

$40.00

$45.00

$50.00

$55.00

$60.00

$65.00

2018 2019 2020 2021 2022WTI Nymex

($/Bbl) ($/MMBtu)

17.3 Tcfe Proved

35.1 Tcfe Probable

2.3 Tcfe Possible

Proved

Probable

Possible

54.6 Tcfe 3P

96% 2P

Reserves

1. 2012, 2013, 2014 and 2015 reserves assuming ethane rejection. In 2016, 554 MMBbls of ethane assumed recovered to meet ethane contract. In 2017, 656 MMBbls of ethane assumed recovered to meet ethane

contract. 2017 SEC prices were $2.91/MMBtu for natural gas and $45.35/Bbl for oil on a weighted average Appalachian index basis. 2017 10-year average SEC prices are NYMEX $3.11/Mcf and WTI $51.03/Bbl.

2017 realized C3+ and C2+ prices including regional market differentials were $0.77/gal and $0.49/gal, respectively.

3P RESERVES BY VOLUME – 2017(1)

NET PROVED RESERVES (Tcfe)(1)

6/30/2017 RESERVE ADDITIONS

• Proved reserves increased 7% to 16.5 Tcfe

− Proved pre-tax PV-10 at SEC pricing of $9.3 billion, including

$1.3 billion of hedge value

−Proved pre-tax PV-10 at strip pricing of $10.1 billion, including

$1.7 billion of hedge value

− Increased Marcellus wellhead type curve to 2.0 Bcf/1,000’ of

lateral for additional 199 PUD locations

• 3P reserves increased 14% to 53.0 Tcfe

− 3P PV-10 at strip pricing of $17.0 billion, including $1.7 billion of

hedge value

− Increased Marcellus wellhead type curve to 2.0 Bcf/1,000’ of

lateral for additional 398 Probable locations

• All-in F&D cost of $0.48/Mcfe for proved reserve additions

during six months ended 6/30/2017

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

2010 2011 2012 2013 2014 2015 2016 2017

Marcellus Utica

0.7

2.8 4.3

7.6

12.7

(Tcfe)

13.2

15.4

17.3

Substantial Reserve Growth

55 APPENDIX | RESERVE GROWTH

$10.8B Proved PV-10

2017 Year-End proved pre-tax PV-10

at SEC pricing, including

$0.6B of hedge value

$18.4B 3P PV-10

2017 Year-End 3P pre-tax PV-10 at SEC

pricing, including $0.6B of hedge value

56

Competitive Gathering and Compression Fee Structure

AR Pays Competitive Gathering & Compression Fees

- AR’s gathering and compression fees paid to AM are below the Appalachian average based on extensive internal analysis of 19 publicly disclosed and undisclosed private midstream contracts

AR has Low or No MVCs with AM

- No minimum volume commitments (“MVCs”) on any low pressure gathering with AM - MVCs on high pressure gathering and compression assets put in-service after the AM

IPO (11/2014) - 75% to 70% MVCs on high pressure gathering and compression, respectively,

when a project is requested by AR - MVC levels are determined by AR’s production forecast and capacity needs; AM may

build infrastructure with capacity larger than requested for efficiency purposes that is not subject to MVCs

AR Receives Reliable and Timely Gathering and Compression from AM

- AR has complete visibility and drives AM’s planning and in-service timing for key infrastructure projects

- AR is essentially AM’s sole customer, which results in unmatched service - AR receives just-in-time customized and controlled midstream buildout - Critical to AR’s ability to execute its development plan and optimize its capital efficiency

APPENDIX | GATHERING AND COMPRESSION FEES

1

2

3

$0.53

$0.00

$0.10

$0.20

$0.30

$0.40

$0.50

$0.60

$0.70

$0.80

$0.90

$1.00

Appalachian Study Average: $0.60/MMBtu

57

Appalachia Gathering and Compression Fee Study

Note: All gathering & compression fees normalized to 1,250 Btu gas and two stage compression. Analysis based on public and private company disclosures for Appalachia

midstream contracts.

AR Fees Paid to AM Converted to MMBtu

AR Contracted Gathering/Compression Fees to AM ($/Mcf) $0.66

Typical BTU Conversion (Average BTU of 1250) for 2018/2019 Programs 1.25

AR Gathering/Compression Fees (Converted to $/MMBtu) $0.53

NOTE: Most midstream fees are disclosed on a

$/MMBtu basis. AR’s fees are disclosed on a

$/Mcf basis and must be converted to a $/MMBtu

basis to appropriately compare to others

APPENDIX | GATHERING AND COMPRESSION FEES

Private Gathering & Compression Agreements P Publicly Disclosed Agreements

Competitive Fresh Water Fee Structure

58

AR Pays Highly Competitive Fresh Water Fees - AR pays a fixed-fee per barrel to AM for fresh water pipeline service at the well pad that is firm

and is $0.50/Bbl lower cost than variable sourcing and trucking costs

Peer Challenges: - Exposure to trucking cost inflation currently observed in Appalachia, driven by continued

production growth and larger completions requiring more water

AR Receives Reliable and Timely Fresh Water Service From AM - AR has never missed a scheduled completion date due to the inability to source and transport

fresh water for completions through AM

Peer Challenges: - Unavailability of local water sources during dry season or drought - Logistical challenges accessing pads and rural roads by truck, particularly during inclement

weather

Sustainable Clean Water via Pipeline - Fresh water pipeline system eliminated >620,000 truck trips and 42,000 tons of CO2 emissions for

AR in 2017 alone - Full-cycle water system integrated with Antero Clearwater facility to reuse the fresh water by-

product of the advanced wastewaster treatment

Peer Challenges: - Utilizing produced and flowback water in completions rather than fresh water increases chemical

costs during completions and increases risk of negative impact on reservoir productivity

AR has Water MVCs with AM only through 2019 - AR has very manageable MVCs on fresh water of 120 Mbbl/d in both 2018 and 2019

1

2

3

4

APPENDIX | FRESH WATER DELIVERY FEES

AR Saved ~$0.50/Bbl on Fresh Water in 2017

59

James Webb Pad – 9 Wells

Round

Trip Miles Minutes $/Bbl

Pad Avg 15 36 $3.60

AR Costs Per Barrel $(0.09)

Stewart Pad – 4 Wells

Round


Pad

Avg 51 83 $4.38

AR Savings Per Barrel $0.69

Edna Monroe Pad – 10 Wells

Round


Pad

Avg 36 77 $4.28


Bettinger Pad – 1 Wells

Round


Pad

Avg. 56 99 $4.64


Antero 2017 Average

Loading Time (Minutes) 60

Staging Time (Minutes) 120

Trucking Cost per Hour $90

Barrels Per Truck (Bbls) 90

Avoided Cost to Truck to All Pads ($/Bbl) $4.19

Firm Delivery Fee paid to AM ($/Bbl) $3.69

AR Fresh Water Savings ($/Bbl) $0.50

Nicki Pad – 6 Wells

Round


Pad

Avg. 41 74 $4.23


Antero analyzed its 2017 completions and the “avoided cost” of utilizing AM’s fresh water pipeline system vs. trucking water for completions - Antero utilized mapping and routing expertise to find optimized routes to each pad (i.e. “best case” travel routes) - Costs on a per barrel basis can vary dramatically due to hourly trucking costs (typical delays due to: staging and loading

times, traffic congestion, completion shut-downs, bad weather, and challenging topography) - AR realized savings in 2017 alone totaled $0.50/Bbl or $28 million

Note: Select 2017 pads shown above are illustrative of the company wide development plan across AR’s acreage position.

APPENDIX | FRESH WATER DELIVERY FEES

Fresh Water MVC’s and Earn-Outs

60

• Minimum volume commitments (MVC’s) on fresh water delivery volumes were put in place to support revenues and rates of return for AM’s acquisition of the water business in September 2015

• Earn-outs at year-end 2019 and 2020 provided incentives for AR to perform long term

Fresh Water Delivery MVC’s and Earn Out Payments (MBbl/d)

90 100 120 120

161 MBbl/d

200 MBbl/d

123

153

221(1)

0

50

100

150

200

250

2016A 2017A 2018 2019 2020

MB

bl/d

MVCs Earnout #1 Earnout #2 Actual Volumes

APPENDIX | FRESH WATER DELIVERY MVCS

(1) Represents 1Q 2018 fresh water delivery volumes.

Guidance Summary - 2018

61

Guidance

2017

Guidance

2018

Guidance Change

Net Income ($MM) $305 - $345 $435 - $480 +41%

Adjusted EBITDA ($MM) $520 - $560 $705 - $755 +35%

DCF ($MM) $405 - $445 $575 - $625 +41%

Distribution Growth 28 – 30% 28 – 30% -

DCF Coverage 1.30x – 1.45x 1.25x - 1.35x -7%

Maintenance Capex ($MM) $65 $65 0%

Growth Capex ($MM) $735 $585 -20%

Total Capex ($MM) $800 $650 -19%

APPENDIX: GUIDANCE

Adjusted EBITDA and Distributable Cash Flow are non-GAAP measures. For additional information regarding these measures, please see “Antero Midstream Non-GAAP Measures” in the Appendix.

Core of the Core Development Programs

62 SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | UNDERSTANDING THE RESOURCE

EUR Regime BTU

Range

2018 Well

Completions

2019 Well

Completions

Half Cycle

Well

Economics

(Strip Price)

Total

Undrilled

Locations

Average

Lateral

Length

Marcellus

Highly-Rich Gas

Condensate 1275-1350 14 30 200% 447 12,500’

Highly-Rich Gas 1200-1275 106 101 89% 935 11,500’

Rich Gas 1100-1200 0 4 32% 495 11,150’

Ohio Utica

Condensate 1250-1300 19 2 59% 206 9,950’

Rich Gas 1100-1200 3 9 39% 102 11,550’

Dry Gas 1050 3 9 36% 187 10,450’

Total(1) 145 155

Program Stats:

93% | 98%

Strip | $70 Oil ROR

1,253 BTU Average

Program Stats:

102% | 106%

Strip | $70 Oil ROR

1,248 BTU Average

High-Grade

Inventory

Totals:

2,372

High-Grade

Inventory

Averages:

11,400’

1) Wells completed reflects midpoint of targeted completions per year.

Product Volumes

(Guidance)

Realized

Price Revenues % of Total

Revenue

1,925

MMcf/d $2.85/Mcf $2.0B 52%

44 MBbl/d $10/Bbl $0.2B 5%

77.5 MBbl/d $39/Bbl $1.1B 28%

9.5 MBbl/d $54/Bbl $0.2B 5%

N/A $0.45/Mcfe $0.4B 10%

2,700

MMcfe/d $4.00/Mcfe $3.9B 100%

63 APPENDIX | PROFITABILITY DRIVERS

2018 Product Revenue Buildup

Na

tura

l Ga

s N

GL

s C

rud

e

GAS

C2

C3+

Oil

Hed

ge

s

$1.5B Liquids Revenue

38% Liquids as a Percent

of Total Volume

43% | 38% Pre- | Post- Hedge

Liquids as Percent of

Revenue

Note: See Appendix for key assumptions

Hedged Multiple

2018E EBITDAX ($MM): $1,591 Excludes AM Distributions

EV / 2018E EBITDAX: 4.8x

Unhedged Multiple

2018E EBITDAX ($MM): $1,138 Excludes AM Distributions & Hedge Revenues

EV / 2018E EBITDAX: 5.7x

$6,770 $6,530

$5,274

$1,420

$2,920

~$1,175

$12,044

$7,705

$0

$2,000

$4,000

$6,000

$8,000

$10,000

$12,000

$14,000

ConsolidatedEnterprise Value

Antero MidstreamNet Debt

After Tax Value of AMOwned Units

AR Stand-aloneE&P Value

64 APPENDIX | VALUE CREATION

Antero Consolidated and Stand-Alone Enterprise Value

Note: Balance sheet data as of 6/30/18, except AR and AM unit price as of 6/30/18 and hedge mark-to-market as of 6/30/18.

99MM units

owned and AM

market price of

$29.52/unit

Market

Value

Net Debt

Hedge MTM

E&P

Assets

21% tax on

value of

AM units (net of

NOLs)

($MM)

Antero Assumptions: Single Well Economics

65 APPENDIX | SINGLE WELL ECONOMICS

SWE Cost Type Description of Cost Half Cycle Full Cycle

Well Costs

• Drilling and completion costs

• Assumes well costs for a 12,000’ lateral,

2,000 lbs of proppant per lateral foot and

both fresh and flowback water

• Utica Condensate regime assumes 1,500

lbs or proppant per lateral foot

Marcellus: $10.6MM

Utica South/Dry: $12.2MM

Utica Beaver: $11.5MM

(60% AM water fees)

Marcellus: $11.4MM

Utica South/Dry: $12.8MM

Utica Beaver: $12.2MM

(100% AM water fees)

Working Interest /

Net Royalty Interest

• Reflects Antero’s average WI/NRI in the

respective plays

Marcellus: 100% / 85%

Utica: 100% / 81%

Midstream Gathering

Fees

• Midstream low pressure, high pressure

and compression fees 60% of AM gathering fees 100% of AM gathering fees

Firm Transportation(1)

• FT costs may include both demand and

variable fees associated with expected

production

Variable FT costs only of

$0.06/Mcf (variable fees

associated with expected

production)

Fully utilized FT costs of

$0.54/Mcf (including both

demand and variable fees)

General & Administrative

Costs

• General and administrative costs

associated with Antero None $750,000 per well

Land

• Assumes 12,000’ well with 660’/1,000’

spacing for Marcellus/Utica respectively

and $3,600 per acre

None Marcellus - $655,000 per well

Utica - $1,087,000 per well

Spud to FP Timing • Provides a timeframe for initial spud to

first production

184 days spud to FP

(Economics based on first production at 7/1/2018)

Realized Pricing • Commodity price assumptions 06/30/2018 strip pricing (weighted)

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

Single Well Economics: Marcellus – In Ethane Rejection


Classification Highly-Rich

Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas

Modeled BTU 1313 1250 1150 1050

EUR (Bcfe): 32 29 26 24

EUR (MMBoe): 5.3 4.9 4.3 3.9

% Liquids: 33% 24% 11% 0%

Well Cost ($MM): $10.6 $10.6 $10.6 $10.6

Bcfe/1,000’: 2.7 2.5 2.2 2.0

Net F&D ($/Mcfe)(1): $0.40 $0.43 $0.49 $0.53

Net Direct Operating Expense ($/Mcfe): $1.26 $1.33 $1.39 $1.05

Transportation Expense ($/Mcfe): $0.04 $0.05 $0.06 $0.06

Pre-Tax NPV10 ($MM): $27.0 $16.5 $6.6 $3.9

Pre-Tax Half Cycle ROR: 200% 89% 32% 21%

Payout (Years): 0.5 1.5 2.8 4.1

Gross Core Locations in BTU Regime: 447 935 495 874

Cumulative

Volumes

Highly-Rich

Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas

Gas (MMcf) Oil (Mbbl) Gas (MMcf) Oil (Mbbl) Gas (MMcf) Oil (Mbbl) Gas (MMcf) Oil (Mbbl)

Year 1 4,300 116 4,300 24 4,300 0 4,300 0

Year 2 6,500 143 6,500 31 6,500 0 6,500 0

Year 3 7,900 152 7,900 36 7,900 0 7,900 0

Year 4 9,100 157 9,100 40 9,100 0 9,100 0

Year 5 10,200 161 10,200 44 10,200 0 10,200 0

Year 10 13,900 176 13,900 57 13,900 0 13,900 0

Year 20 18,500 194 18,500 73 18,500 0 18,500 0 Note: SWE cost assumptions reflect average costs per Mcfe on the first five years of the life of a well.

F&D cost is defined as current D&C cost per 1,000’ lateral divided by net EUR per 1,000’ lateral assuming 85% NRI in Marcellus. Please see “Antero Definitions” and “Antero Non-GAAP Measures” in the Appendix.

Single Well Economics: Utica – In Ethane Rejection


Note: SWE cost assumptions reflect average costs per Mcfe on the first five years of the life of a well.

F&D cost is defined as current D&C cost per 1,000’ lateral divided by net EUR per 1,000’ lateral assuming 81% NRI in Utica. Please see “Antero Definitions” and “Antero Non-GAAP Measures” in the Appendix.

Classification Condensate

Highly-Rich

Gas/

Condensate

Highly-Rich

Gas Rich Gas Dry Gas

Modeled BTU 1275 1235 1215 1175 1050

EUR (Bcfe): 13 25 29 28 26

EUR (MMBoe): 2.2 4.2 4.8 4.6 4.4

% Liquids 40% 30% 21% 16% 0%

Well Cost ($MM): $10.8 $11.5 $12.2 $12.2 $12.2

Bcfe/1,000’: 1.1 2.1 2.4 2.3 2.2

Net F&D ($/Mcfe)(1): $1.03 $0.57 $0.53 $0.55 $0.57

Net Direct Operating Expense ($/Mcfe): $1.18 $1.32 $1.44 $1.47 $0.85

Transportation Expense ($/Mcfe): $0.04 $0.05 $0.05 $0.06 $0.07

Pre-Tax NPV10 ($MM): $8.8 $17.9 $12.1 $8.4 $8.6

Pre-Tax Half Cycle ROR: 59% 139% 58% 39% 36%

Payout (Years): 1.7 0.4 1.8 2.1 2.6

Gross Core Locations in BTU Regime: 206 27 22 102 187

Cumulative

Volumes

Condensate Highly-Rich Gas/

Condensate Highly-Rich Gas Rich Gas Dry Gas

Gas (Mmcf) Oil (Bbl) Gas (Mmcf) Oil (Bbl) Gas (Mmcf) Oil (Bbl) Gas (Mmcf) Oil (Bbl) Gas (Mmcf) Oil (Bbl)

Year 1 1,600 129 4,300 110 5,600 6 5,400 0 5,500 0

Year 2 2,300 153 5,800 127 7,700 8 7,500 0 8,200 0

Year 3 2,800 166 6,900 138 9,100 9 8,800 0 10,000 0

Year 4 3,300 176 7,700 146 10,200 10 9,900 0 11,400 0

Year 5 3,600 186 8,400 152 11,100 11 10,800 0 12,500 0

Year 10 5,000 219 10,900 175 14,500 14 14,100 0 16,500 0

Year 20 6,700 258 14,000 202 18,700 19 18,200 0 21,200 0

68 APPENDIX | DISCLOSURES & RECONCILIATIONS

Antero Non-GAAP Measures Consolidated Adjusted EBITDAX, Stand-alone E&P Adjusted EBITDAX, Consolidated Adjusted Operating Cash Flow, Stand-alone E&P

Adjusted Operating Cash Flow and Free Cash Flow are financial measures that are not calculated in accordance with U.S. generally

accepted accounting principles (―GAAP‖). The non-GAAP financial measures used by the company may not be comparable to similarly

titled measures utilized by other companies. These measures should not be considered in isolation or as substitutes for their nearest

GAAP measures. The Stand-alone measures are presented to isolate the results of the operations of Antero apart from the performance

of Antero Midstream, which is otherwise consolidated into the results of Antero.

Consolidated Adjusted EBITDAX and Stand-alone E&P Adjusted EBITDAX

The GAAP financial measure nearest to Consolidated Adjusted EBITDAX is net income or loss including noncontrolling interest that will

be reported in Antero’s consolidated financial statements. The GAAP financial measure nearest to Stand-alone E&P Adjusted

EBITDAX is Stand-alone net income or loss that will be reported in the Parent column of Antero’s guarantor footnote to its financial

statements. While there are limitations associated with the use of Consolidated Adjusted EBITDAX and Stand-alone E&P Adjusted

EBITDAX described below, management believes that these measures are useful to an investor in evaluating the company’s financial

performance because these measures:

• are widely used by investors in the oil and gas industry to measure a company’s operating performance without regard to

items excluded from the calculation of such term, which can vary substantially from company to company depending upon

accounting methods and book value of assets, capital structure and the method by which assets were acquired, among

other factors;

• helps investors to more meaningfully evaluate and compare the results of Antero’s operations (both on a consolidated and

Stand-alone basis) from period to period by removing the effect of its capital structure from its operating structure; and

• is used by management for various purposes, including as a measure of Antero’s operating performance (both on a

consolidated and Stand-alone basis), in presentations to the company’s board of directors, and as a basis for strategic

planning and forecasting. Consolidated Adjusted EBITDAX is also used by the board of directors as a performance measure

in determining executive compensation. Consolidated Adjusted EBITDAX, as defined by our credit facility, is used by our

lenders pursuant to covenants under our revolving credit facility and the indentures governing the company’s senior notes.

There are significant limitations to using Consolidated Adjusted EBITDAX and Stand-alone E&P Adjusted EBITDAX as measures of

performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company’s

net income on a consolidated and Stand-alone basis, the lack of comparability of results of operations of different companies and the

different methods of calculating Adjusted EBITDAX reported by different companies. In addition, Consolidated Adjusted EBITDAX and

Stand-alone E&P Adjusted EBITDAX provide no information regarding a company’s capital structure, borrowings, interest costs, capital

expenditures, and working capital movement or tax position.


Antero Non-GAAP Measures Antero has not included a reconciliation of Consolidated Adjusted EBITDAX or Stand-alone E&P Adjusted EBITDAX to their nearest

GAAP financial measures for 2018 because it cannot do so without unreasonable effort and any attempt to do so would be inherently

imprecise. Antero is able to forecast the following reconciling items between Consolidated Adjusted EBITDAX and Stand-alone E&P

Adjusted EBITDAX to net income from continuing operations including noncontrolling interest:

Antero has a significant portfolio of commodity derivative contracts that it does not account for using hedge accounting, and forecasting

unrealized gains or losses on this portfolio is impracticable and imprecise due to the price volatility of the underlying commodities.

Antero is also forecasting no impact from franchise taxes, gain or loss on early extinguishment of debt, or gain or loss on sale of assets,

for 2018. For income tax expense (benefit), Antero is forecasting a 2018 effective tax rate of 18% to 19%.

(in thousands)

Consolidated Stand-alone E&P

Low High Low High

Interest expense $250,000 $300,000 $200,000 $220,000

Depreciation, depletion, amortization, and accretion

expense 950,000 1,050,000 800,000 900,000

Impairment expense 100,000 125,000 100,000 125,000

Exploration expense 5,000 15,000 5,000 15,000

Equity-based compensation expense 95,000 115,000 70,000 90,000

Equity in earnings of unconsolidated affiliate 30,000 40,000 N/A N/A

Distributions from unconsolidated affiliates 40,000 50,000 N/A N/A

Distributions from limited partner interest in Antero

Midstream N/A N/A 166,000 170,000


Antero Non-GAAP Measures Consolidated Adjusted Operating Cash Flow, Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow

The GAAP financial measure nearest to Consolidated Adjusted Operating Cash Flow is cash flow from operating activities as reported in

Antero’s consolidated financial statements. The GAAP financial measure nearest to Stand-alone E&P Adjusted Operating Cash Flow

and Free Cash Flow is Stand-alone cash flow from operating activities that will be reported in the Parent column of Antero’s guarantor

footnote to its financial statements. Management believes that Consolidated Adjusted Operating Cash Flow and Stand-alone E&P

Adjusted Operating Cash Flow are useful indicators of the company’s ability to internally fund its activities and to service or incur

additional debt on a consolidated and Stand-alone basis. Management believes that changes in current assets and liabilities, which are

excluded from the calculation of these measures, relate to the timing of cash receipts and disbursements and therefore may not relate to

the period in which the operating activities occurred and generally do not have a material impact on the ability of the company to fund its

operations. Management believes that Free Cash Flow is a useful measure for assessing the company’s financial performance and

measuring its ability to generate excess cash from its operations.

There are significant limitations to using Consolidated Adjusted Operating Cash Flow, Stand-alone E&P Adjusted Operating Cash Flow

and Free Cash Flow as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring

items that materially affect the company’s net income on a consolidated and Stand-alone E&P basis, the lack of comparability of results

of operations of different companies and the different methods of calculating Consolidated Adjusted Operating Cash Flow and Stand-

alone E&P Adjusted Operating Cash Flow reported by different companies. Consolidated Adjusted Operating Cash Flow and Stand-

alone E&P Adjusted Operating Cash Flow do not represent funds available for discretionary use because those funds may be required

for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and

obligations.

Antero has not included reconciliations of Consolidated Adjusted Operating Cash Flow, Stand-alone E&P Adjusted Operating Cash

Flow and Free Cash Flow to their nearest GAAP financial measures for 2018 because it would be impractical to forecast changes in

current assets and liabilities. However, Antero is able to forecast the earn out payments expected from Antero Midstream associated

with the water drop down transaction that occurred in 2015, each of which is a reconciling item between Stand-alone E&P Adjusted

Operating Cash Flow and Free Cash Flow, as applicable, and cash flow from operating activities as reported in the Parent column of

Antero’s guarantor footnote to its financial statements. Antero forecasts these items to be $125 million in each of 2019 and 2020.

Additionally, Antero is able to forecast lease maintenance expenditures and Stand-alone drilling and completion capital, each of which is

a reconciling item between Free Cash Flow and its most comparable GAAP financial measure. For the 2018 to 2022 period, Antero

forecasts cumulative lease maintenance expenditures of $200 million and cumulative Stand-alone E&P drilling and completion capital of

$8.6 billion.

Antero Resources Stand-Alone Adjusted EBITDAX Reconciliation

APPENDIX | DISCLOSURES & RECONCILIATIONS

AR Stand-Alone Adjusted EBITDAX Reconciliation

($ in millions) Three Months

Ended

LTM Ended

6/30/2018 6/30/2018

Net income (loss) including noncontrolling interest $(136,385) $230,254

Commodity derivative gains (55,336) (211,640)

Gains on settled commodity derivatives 95,884 335,252

Marketing derivative (gains) losses 110 (72,730)

Gains (losses) on settled marketing derivatives (15,884) 94,158

Interest expense 54,388 222,479

Loss on early extinguishment of debt — 1,205

Income tax expense (25,573) (461,669)

Depreciation, depletion, amortization, and accretion 202,283 759,260

Impairment of unproved properties 134,437 302,473

Impairment of gathering systems and facilities 4,470 4,470

Exploration expense 1,471 7,983

Gain on change in fair value of contingent acquisition consideration (3,947) (14,181)

Equity-based compensation expense 13,204 65,070

Distributions from Antero Midstream 38,559 143,100

Equity in net income of Antero Midstream 26,926 74,056

Total Adjusted EBITDAX $334,607 $1,479,540

71

Antero Resources Consolidated Adjusted EBITDAX Reconciliation

Consolidated Adjusted EBITDAX Reconciliation

($ in millions)

Three Months

Ended

LTM Ended

6/30/2018 6/30/2018

Net income (loss) including noncontrolling interest $(67,275) $453,149

Commodity derivative gains (55,336) (211,640)

Gains on settled commodity derivatives 95,884 335,252

Marketing derivative (gains) losses 110 (72,730)

Gains (losses) on settled marketing derivatives (15,884) 94,158


Loss on early extinguishment of debt — 1,500

Income tax benefit (25,573) (461,669)

Depreciation, depletion, amortization, and accretion 238,750 889,707

Impairment of unproved properties 134,437 302,473

Impairment of gathering systems and facilities 8,501 31,932

Exploration expense 1,471 7,983

Equity-based compensation expense 19,071 91,194

Equity in earnings of unconsolidated affiliate (9,264) (31,466)

Distributions from unconsolidated affiliate 10,810 32,270

Total Adjusted EBITDAX $405,051 $1,729,337

APPENDIX | DISCLOSURES & RECONCILIATIONS 72

Antero Midstream Non-GAAP Measures

APPENDIX 73

Non-GAAP Financial Measures and Definitions

Antero Midstream views Adjusted EBITDA as an important indicator of the Partnership’s performance. Antero Midstream defines

Adjusted EBITDA as Net Income before interest expense, depreciation expense, impairment expense, accretion of contingent

acquisition consideration, equity-based compensation expense, excluding equity in earnings of unconsolidated affiliates and including

cash distributions from unconsolidated affiliates.

Antero Midstream uses Adjusted EBITDA to assess:

• the financial performance of the Partnership’s assets, without regard to financing methods in the case of Adjusted EBITDA, capital

structure or historical cost basis;

• its operating performance and return on capital as compared to other publicly traded partnerships in the midstream energy sector,

without regard to financing or capital structure; and

• the viability of acquisitions and other capital expenditure projects.

The Partnership defines Distributable Cash Flow as Adjusted EBITDA less interest paid, income tax withholding payments and cash

reserved for payments of income tax withholding upon vesting of equity-based compensation awards, cash reserved for bond interest

and ongoing maintenance capital expenditures paid. Antero Midstream uses Distributable Cash Flow as a performance metric to

compare the cash generating performance of the Partnership from period to period and to compare the cash generating performance for

specific periods to the cash distributions (if any) that are expected to be paid to unitholders. Distributable Cash Flow does not reflect

changes in working capital balances.

The Partnership defines Free Cash Flow as cash flow from operating activities before changes in working capital less capital

expenditures. Management believes that Free Cash Flow is a useful indicator of the Partnership’s ability to internally fund infrastructure

investments, service or incur additional debt, and assess the company’s financial performance and its ability to generate excess cash

from its operations. Management believes that changes in operating assets and liabilities relate to the timing of cash receipts and

disbursements and therefore may not relate to the period in which the operating activities occurred.

The Partnership defines Return on Invested Capital as net income plus interest expense divided by average total liabilities and partners’

capital, excluding current liabilities. Management believes that Return on Invested Capital is a useful indicator of the Partnership’s

return on its infrastructure investments.

The Partnership defines Adjusted Operating Cash Flow as net cash provided by operating activities before changes in current assets

and liabilities. See ―Non-GAAP Measures‖ for additional detail.


APPENDIX 74

The GAAP financial measure nearest to Adjusted Operating Cash Flow is cash flow from operating activities as reported in

Antero Midstream’s consolidated financial statements. Management believes that Adjusted Operating Cash Flow is a useful

indicator of the company’s ability to internally fund its activities and to service or incur additional debt. Management believes

that changes in current assets and liabilities, which are excluded from the calculation of these measures, relate to the timing of

cash receipts and disbursements and therefore may not relate to the period in which the operating activities occurred and

generally do not have a material impact on the ability of the company to fund its operations. Management believes that Free

Cash Flow is a useful measure for assessing the company’s financial performance and measuring its ability to generate

excess cash from its operations.

There are significant limitations to using Adjusted Operating Cash Flow and Free Cash Flow as measures of performance,

including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company’s net

income, the lack of comparability of results of operations of different companies and the different methods of calculating

Adjusted Operating Cash Flow reported by different companies. Adjusted Operating Cash Flow does not represent funds

available for discretionary use because those funds may be required for debt service, capital expenditures, working capital,

income taxes, and other commitments and obligations.

Antero Midstream has not included reconciliations of Adjusted Operating Cash Flow and Free Cash Flow to their nearest

GAAP financial measures for 2018 because it would be impractical to forecast changes in current assets and liabilities. Antero

Midstream is able to forecast capital expenditures, which is a reconciling item between Free Cash Flow and its most

comparable GAAP financial measure. For the 2018 to 2022 period, Antero forecasts cumulative capital expenditures of $2.7

billion.

Antero Resources non-GAAP measures and definitions are included in the Antero Resources analyst day presentation, which

can be found on www.anteroresources.com.

http://www.anteroresources.com/






APPENDIX 75

Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures. The GAAP measure most directly comparable to

Adjusted EBITDA and Distributable Cash Flow is Net Income. The non-GAAP financial measures of Adjusted EBITDA and

Distributable Cash Flow should not be considered as alternatives to the GAAP measure of Net Income. Adjusted EBITDA and

Distributable Cash Flow are not presentations made in accordance with GAAP and have important limitations as an analytical tool

because they include some, but not all, items that affect Net Income and Adjusted EBITDA. You should not consider Adjusted

EBITDA and Distributable Cash Flow in isolation or as a substitute for analyses of results as reported under GAAP. Antero

Midstream’s definition of Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other

partnerships .

Antero Midstream has not included a reconciliation of Adjusted EBITDA to the nearest GAAP financial measure for 2018 because it

cannot do so without unreasonable effort and any attempt to do so would be inherently imprecise. Antero Midstream is able to

forecast the following reconciling items between Adjusted EBITDA and net income (in thousands):

The Partnership cannot forecast interest expense due to the timing and uncertainty of debt issuances and associated interest rates.

Additionally, Antero Midstream cannot reasonably forecast impairment expense as the impairment is driven by a number of factors

that will be determined in the future and are beyond Antero Midstream’s control currently.

Twelve months ended

December 31, 2018

Low High

Depreciation expense ........................................................................................... $ 160,000 — $ 170,000

Equity based compensation expense ................................................................... 25,000 — 35,000

Accretion of contingent acquisition consideration .............................................. 15,000 — 20,000

Equity in earnings of unconsolidated affiliates .................................................... 30,000 — 40,000

Distributions from unconsolidated affiliates........................................................ 40,000 — 50,000

Adjusted EBITDA and DCF Reconciliation

APPENDIX 76

Adjusted EBITDA and DCF Reconciliation ($ in thousands)

Three months ended

June 30,

2017 2018

Net income $ 87,175 $ 109,466


Impairment of property and equipment expense — 4,614

Depreciation expense 30,512 36,433

Accretion of contingent acquisition consideration 3,590 3,947

Accretion of asset retirement obligations — 34

Equity-based compensation 6,951 5,867

Equity in earnings of unconsolidated affiliates (3,623) (9,264)

Distributions from unconsolidated affiliates 5,820 10,810

Gain on sale of assets- Antero Resources — (583)

Adjusted EBITDA 139,440 175,952

Interest paid (2,308) 372

Decrease in cash reserved for bond interest (1) (8,734) (8,734)

Income tax withholding upon vesting of Antero Midstream Partners LP equity-based compensation awards(2) (2,431) (1,500)

Maintenance capital expenditures(3) (16,422) (16,000)

Distributable Cash Flow $ 109,545 $ 150,090

Distributions Declared to Antero Midstream Holders

Limited Partners 59,695 72,943

Incentive distribution rights 15,328 28,461

Total Aggregate Distributions $ 75,023 $ 101,404

DCF coverage ratio 1.5x 1.3x

1) Cash reserved for bond interest expense on Antero Midstream’s 5.375% senior notes outstanding during the period that is paid on a semi-annual basis on March 15th and September 15th of each year.

2) Estimate of current period portion of expected cash payment for income tax withholding attributable to vesting of Midstream LTIP equity-based compensation awards to be paid in the fourth quarter.

3) Maintenance capital expenditures represent the portion of our estimated capital expenditures associated with (i) the connection of new wells to our gathering and processing systems that we believe will be necessary to

offset the natural production declines Antero Resources will experience on all of its wells over time, and (ii) water delivery to new wells necessary to maintain the average throughput volume on our systems.

Cautionary Note

Regarding Hydrocarbon Quantities

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, 2017 included in this presentation have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates as of December 31, 2017 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.


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