Barclays CEO Energy Conferences1.q4cdn.com/.../09/Barclays-Energy-Conference_2018... · 0 5 10 15 20 25 $0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 2014 2015 2016 2017 2018E 2019E

Barclays CEO Energy Conference

SEPTEMBER 4, 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 | BARCLAYS 2018 CEO ENERGY CONFERENCE

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. For general assumptions and financial disclosures please see Antero Resources’ website presentation.

The Size and Scale to Capitalize on the Resource

3 ANTERO RESOURCES | BARCLAYS 2018 CEO ENERGY CONFERENCE

Market Cap……….……...........

Enterprise Value….……………

Corporate Debt Ratings………

Stand-Alone Leverage………..

Net Production (2018E)….......

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

3P Reserves………..…...........

NGLs(1)...........................

Condensate.........................

Net Acres………….…...………

Core Drilling Locations……….

Hedge Mark to Market………..

AR Midstream Ownership (53%)

$6.0B

$9.9B

Ba2 / BB+ / BBB-

2.6x

2.7 Bcfe/d

130,000 Bbl/d

54.6 Tcfe

2,131 MMBbls

131 MMBbls

620,000

3,295

$1.2B

$2.9B Note: Equity market data as of 8/30/18. Balance sheet data, hedge mark to market as of 6/30/18. Reserves as of 12/31/2017. Enterprise value excludes AM net debt. See 2018 Guidan ce in Appendix. (1) NGL 3P Reserves contain 1,318 MMBbls of C3+ NGLs and 812 MMBbls of ethane. Assumes approximately 31% ethane recovery leaving 1,808 MMBbls of ethane in the natural gas stream.

Antero Resources Profile Antero Acreage

SW Marcellus Core

Ohio Utica Core

Antero’s Unique Business Strategy

4 ANTERO RESOURCES | BARCLAYS 2018 CEO ENERGY CONFERENCE

1

Sustainable Development of World Class Liquids-Rich Resource Base • Top U.S. NGL producer with most exposure to rising NGL prices

Differentiated strategy for delivering shareholder value over the long-term:

Maintain Strong Balance Sheet & Financial Flexibility • Target leverage at or below 2.0x in 2019 driven by cash flow generation

2

Attractive Cash Flow and Debt-Adjusted Production Growth • 5-year free cash flow of $1.6 Billion at 2017 year-end strip prices

• 23% debt-adjusted annual production growth

3 Control Development & Mitigate Market Risks • Industry leading hedge book and firm transportation portfolio

• Control infrastructure buildout and capture midstream value chain through

ownership in Antero Midstream

4

5

Disciplined Focus on Returns & Capital Efficiency • Management incentives focused on rate of return metrics, disciplined growth and

free cash flow generation

0

5

10

15

20

25

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

2014 2015 2016 2017 2018E 2019E 2020E 2021E 2022E

Nu

mb

er

of

Dri

llin

g R

igs

In M

illi

on

s

Stand-Alone Adjusted Cash Flow From Operations D&C Capital Antero Rig Count

Capital Discipline Leads to Free Cash Flow

5

Stand-Alone Adjusted Cash Flow Alongside D&C Capital Expenditures

D&C Capital Investment Fully Funded with Cash Flow Note: Stand-alone adjusted cash flow from operations represents net cash provided by operating activities as reported in the Parent column of AR’s guarantor footnote to its financial statements before changes in current assets and liabilities, plus the AM cash distributions payable to AR, plus the earn out payments expected from Antero Midstream asso ciated with the 2015 water drop down transaction. Estimates assume strip pricing as of 12/31/2017.

(1) D&C maintenance capital represents $590MM per year to hold production flat at 2.3 Bcfe/d which was year-end 2017 exit rate.

(2) Free cash flow definition includes $175MM of maintenance land spending, but excludes $175MM discretionary land spending.

48% reduction in D&C capital budget

and 15 rig reduction since 2014

Future D&C capital budgets that are

measured and within cash flow

Free Cash Flow(2)

ANTERO RESOURCES | DISCIPLINED FOCUS ON RETURNS & CAPITAL EFFICIENCY

D&C Maintenance Capital(1)

Near Term Free Cash Flow Inflection Point

6

Stand-Alone Cash Flow(1)

Antero Is Approaching a Free Cash Flow Inflection Point Note: Stand-Alone Adjusted Operating Cash Flow represents net cash provided by operating activities as reported in the Parent column of AR’s guarantor footnote to its financial statements before changes in current assets and liabilities, plus the AM cash distributions payable to AR, plus the earn out payments expected from Antero Midstream associat ed with the 2015 water drop down transaction.

(1) Based on 12/31/2017 strip pricing.

Capital discipline to reduce completion

crews and D&C capex in 2H18

Production growth and strong liquids

prices drives free cash flow

in 4Q18 and beyond


Ca

sh

Ou

tsp

en

d

Fre

e C

ash

Flo

w G

en

era

tio

n

Q4 2018 represents

a free cash flow

inflection point

2019E – 2022E Q3 2018 Q4 2018

Delevering & Return of Capital Potential

Capital Efficiencies Keep D&C Capital in Check

7 ANTERO RESOURCES | DISCIPLINED FOCUS ON RETURNS & CAPITAL EFFICIENCY

42% Decline in well costs since 2014

54% Permanent cost efficiencies

Efficiencies Expected to Offset Service Cost Inflation

Achievements to Date Next Steps in Efficiency Evolution

46% Vendor-related cost reductions

Drilling Longer laterals to >12,000 average

Improved drill-out efficiency

Completions Concurrent operations with larger

pads to reduce cycles time

Supply Costs Self-sourcing sand, with potential per

well savings up to $500K

Compelling Full Cycle Well Economics

8

Single Well Economics Bridge to Corporate Level Returns

Fully Burdened Corporate Level Well Economics are Outstanding Note: See company presentation on Antero Resources investor relations website for further detail behind full cycle and half cycle single well economics; WACC calculated using CAPM. (1) ROR (D&C only) burdened with 60% of AM fees to give credit for AM ownership/distributions and variable firm transportation fe es only (i.e. excluding sunk demand costs).

(2) Incremental 40% of AM fees represent the full midstream fees AR pays to AM on complete stand-alone basis (i.e. no credit for midstream ownership). Includes increase in D&C capital to

account for full water fees paid to AM.

(3) 2.4 bcfe/1,000’ EUR assumes ethane rejection.

111%

102%

82%

61%

49%

37%

9%

20%

20%

13%

12%

0%

20%

40%

60%

80%

100%

120%

ROR(D&C only)

Pad cost& facilities

Half cycleROR

Fixed FTfees

ROR withfull FT fees

Full AMfees

ROR-fullyburdened

fees

G&A ROR post-G&A

Land costs Full cycle(corporate)

ROR

AR WACC ≈ 8%


Fully burdened well economics

support investment

Corporate ROR

well in excess of cost of capital

(1) (2)

Half cycle

ROR

Full cycle

ROR

Well Assumptions

12,000’ Lateral

1250 BTU Wellhead Gas

2.4 Bcfe/1,000’ EUR(3)

6/30/2018 Strip Pricing

Antero is Very Well Positioned in the Core of the Core

9

Positioned in the Marcellus Liquids Core of the Core

Northern Rich High-Graded Core

2.24 Bcfe/1,000’ Avg. EUR

61% Undeveloped

Southern Rich High-Graded Core


66% Undeveloped AR Holds 62% of Undeveloped

Southwest Marcellus Core ~2.9 Million Acres

~76% Undeveloped

Antero Acreage

Antero Marcellus Wells

Industry Marcellus Wells

Antero Marcellus Rig

Industry Marcellus Rig

Dry Gas High-Graded Core


74% 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: Excludes 600,000 urban acres. EURs assume full ethane rejection. Based on Antero reserve engineering of most recent state and internal production data.

ANTERO RESOURCES | SUSTAINABLE DEVELOPMENT OF WORLD CLASS LIQUIDS-RICH RESOURCE BASE

3,295

2,333

1,605

1,259

720 714 663 588 583 556

0

500

1000

1500

2000

2500

3000

3500

4000

AR A B C D E F G H I

Un

drilled

Location

s

Largest Undrilled Core Liquids Drilling Inventory

10

10,848’ 9,563’ 6,775’ 7,723’ 6,040’ 9,583’ 8,905’ 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 Ohio Utica plays. Excludes deep Utica resource in West Virginia & Pennsylvania.

Who Can Consistently Drill

Long Laterals?

Who Has the

Running Room?

Core Marcellus & Utica Undrilled Locations(1)

Lateral Length:


Rich Gas Locations

NE PA Dry Gas

Dry Gas Locations

117

33%

10%

34%

15%

11% 11%

17%

11%

13% 13%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

0

20

40

60

80

100

120

140

AR EOG RRC DVN APC COP OXY MRO NBL PXD

NG

L %

of

Pre

-Hed

ge P

rod

uct R

eve

nu

es

Con

sen

su

s C

2+

NG

Ls (

MB

bl/d

)

2018 Consensus C2+ NGL Production

(1)

Leader in Leverage to NGL Prices

11

Top NGL Producers in the U.S.

Source: Bloomberg consensus, SEC filings and company press releases. Note: Volumes represent consensus as of 8/30/2018. 2Q 2018 realized prices are weighted average including ethane (C2) where applicable. Percent of 2Q 2018 total product revenues is calculated on a pre-hedge basis.

(1) 2Q 2018 actual NGL revenue percentage based on unhedged revenue.

* Denotes consensus inclusive of international NGL production.

NGLs Generate 33%

of AR Revenue (1)

2Q 2018

$26.35 $27.86 $23.69 $24.10 $34.88 $26.71 $28.87 $25.62 $24.39 $28.83

Antero Delivers Highest Exposure to Rising NGL Prices

Pre-hedged Realized NGL Price ($/Bbl)

Pre-Hedge NGL % of Total Product Revenues


* * * *

$2.70 $2.70 $2.97

$3.53

$0.27

$0.56

$0.07 $3.60

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

Antero Weight Avg.Dry Gas Price

BTU uplift(1100 BTU Gas)

C2+ NGLs (25%Ethane Recovery)

Condensate All-in RealizedPrice

Liquids Differentiates Antero

12

Liquids Uplift Before Hedges - 2018 ($/Mcfe)


Liquids-rich acreage and production

provides upgrade vs. dry gas peers

Peer leading leverage

to rising liquids prices

$2.91

Represents

$(0.21) weighted

average

differential for AR

before BTU uplift

Note: Weighted average differential gas before BTU uplift from Antero analyst day. Updated natural gas and NGL strip prices as of 8 /30/2018.

$/Mcfe

$2.49

Tailgate of plant

gas BTU

Uplift from NGL

recovery, net of

gas shrink

Condensate

production at the

well pad

Nymex

Dominion

South

Antero’s NGL Pricing Uplift from Mariner East 2

13

31

Mont

Belvieu

Conway

Europe Netback 2019

NWE Price ($/Gal) $1.02

Pipeline, Terminal &

Shipping Cost (1) $(0.24)

NWE Netback $0.78

Blended Conway / MB

Netback $0.67

Uplift vs. 1Q18 Average

Differential +$0.11

Asia Netback 2019

FEI Price ($/Gal) $1.10

Pipeline, Terminal &

Shipping Cost (1) $(0.33)

Asia Netback $0.77

Blended Conway / MB

Netback $0.67

Uplift vs. 1Q18 Average

Differential +$0.10

International Markets Domestic Markets

Marcus

Hook

Antero Blended Netback 2019

Conway/Mt. Belvieu Price ($/Gal) $0.83

Average 1H 2018 Differential $0.16

Blended Conway/MB Netback $0.67

Source: Poten Partners. Prices reflect blended price of propane and butane based on Antero’s ME2 volume commitment. Note: Based on Baltic forward shipping rates and propane strip prices as of 08/27/18. Includes associated port and canal fees and charges.

(1) Based on Wall Street research. Antero cost may be lower.

Mariner East 2 (“ME2”)

Initial Capacity (4Q18): Committed volumes

Full Capacity (3Q19): 275 MBbl/d

AR Commitments: 35 Mbbl/d C3

15 MBbl/d C4

AR Expansion Rights: 50 Mbbl/d C3/C4


Mariner East 2 will allow AR to access

international LPG markets and realize a

~$4.20/Bbl uplift on its exported barrels

50,000 Bbl/d Mariner East 2 commitment

equates to over $75 MM of

incremental annual cash flow

4Q 2018

AR C3+ Barrel 1Q 2018 Avg Price 2Q 2018 Avg Price Balance 2018 (1) Price ∆

Propane 57% $0.87 $0.87 $1.03 $0.16

N. Butane 16% $0.84 $0.89 $1.21 $0.32

IsoButane 10% $1.05 $1.20 $1.22 $0.02

Natural Gasoline 17% $1.39 $1.53 $1.58 $0.05

C3+ Blended ($/Gal) $0.97 $1.02 $1.17 $0.15

C3+ Blended ($/Bbl) $40.81 $42.77 $49.09 $6.32

Mont Belvieu Product Pricing ($/Gallon)

Strong Propane/Butane Price Improvement

14

Strong C3+ NGL Prices 2H 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 8/30/2018.

$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

allon

(C

3+

NG

Ls)

Strong Global LPG Demand and Prices Have Driven U.S. Exports Higher and Propane Inventories to 5-Year Lows

Balance 2018 (1)

C3+ $49.09 / Bbl


+

+

+ +

$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

2020Target

2021Target

2022Target

$ M

illio

ns

Net Marketing Expense (High End)

Net Marketing Expense (Low End)

Hedge Gains

15

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

2018 - 2022 Cumulative:

Hedge Gains: $1,350

Marketing Expense: ($461)

Net Uplift: $889

Hedge Portfolio Supports

Firm Commitments

ANTERO RESOURCES | CONTROL DEVELOPMENT & MITIGATE INDUSTRY RISKS

~100% of 2018 and 2019 Target Gas Production Hedged at $3.50/MMBtu

Rover Pipeline Uplift and Optionality

16

Unlocks development optionality between

Marcellus and Utica and provides further

Chicago & Gulf Coast exposure

Rover Sherwood Lateral expected to be

placed into service in September

Rover Pipeline Map

Chicago via Rover

($/MMBtu) 2019

Chicago Price ($/MMBtu)(1) $2.64

Approximate Variable Cost $(0.06)

Netback Price $2.58

TETCO M2 Price $(2.09)

Uplift vs. TETCO M2(1) $0.49

Gulf Coast via ANR

($/MMBtu) 2019

Gulf Coast Price ($/MMBtu)(1) $2.66

Approximate Variable Cost $(0.04)

Netback Price $2.62

TETCO M2 Price $(2.09)

Uplift vs. TETCO M2(2) $0.53

Ability to utilize 800 MMcf/d Rover

capacity with both Marcellus

production (Sherwood Processing

Plant) and Utica production

(Seneca Processing Plant)

Rover Phase 1A (in-service)

Rover Phase 1B (in-service)

Rover Laterals (3Q18-4Q18)

Natural Gas Pricing Hub

1. Futures prices as of 8/30/18.

2. Based on 2019 Tetco M2 futures prices and includes $0.14 of variable cost


Midstream Driving Value for AR Since Inception

17 ANTERO RESOURCES | CONTROL DEVELOPMENT & MITIGATE INDUSTRY RISKS

~$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. (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 approx imate $1.3B

of AR capital invested at time of AM IPO.

AM Assets AM/MPLX JV Assets Potential AM Opportunities

Upstream Downstream

Capture midstream value chain →

realized 4.6x unlevered ROI through

AM ownership(1)

Control the midstream infrastructure buildout

for downstream visibility and takeaway

assurance

AR controls

midstream buildout

through AM

ownership

$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)

18

Consistent Leader in EBITDAX Margin

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

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

Stand-Alone EBITDAX Margin vs WTI Oil Price

ANTERO RESOURCES | ATTRACTIVE CASH FLOW AND DEBT-ADJUSTED PRODUCTION GROWTH

Sustainable margins through the price cycles Antero’s integrated strategy has resulted in

peer-leading EBITDAX margins for over 5 years

($1,500)

($1,000)

($500)

$0

$500

$1,000

$1,500

2014A 2015A 2016A 2017A 2018Guidance

2019Target

2020Target

2021Target

2022Target

Lower Capital & Higher Liquids Prices → Free Cash Flow

ANTERO RESOURCES | ATTRACTIVE CASH FLOW AND DEBT-ADJUSTED PRODUCTION 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 of website presentation; free cash flow calculation 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

19

Stand-Alone Free Cash Flow:

Resource Capture & Delineation Cash Flow 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 F

inan

cia

l Leve

rag

e

12/31/17 Strip Pricing (Base Case)

$60 Oil / $2.85 Gas

$50 Oil / $2.85 Gas

Cash Flow Growth → Delevering Profile

23% Debt-Adjusted

Production CAGR

Through 2022

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

Delevering Supported By:

• 2.4 Tcfe Hedge Position • 4.7 Bcf/d FT Portfolio

• $1.4B of Targeted AM

Distributions

S&P Upgrade to BB+

Moody’s Ba2 Outlook “Positive”

BBB- Rating Fitch Has Rated AR Investment Grade

2Q 2018

Leverage: 2.6x

20 ANTERO RESOURCES | MAINTAIN STRONG BALANCE SHEET & FINANCIAL FLEXIBILITY

21

Antero Profile Should Drive Multiple Expansion

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

Source: Bloomberg & Antero Estimates as of 8/30/18. (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, pleas e see “Antero Definitions” and “Antero Non-GAAP Measures” in the Appendix.

ANTERO RESOURCES | MAINTAIN STRONG BALANCE SHEET & FINANCIAL FLEXIBILITY

U.S. Publicly Traded E&Ps

Leverage < 3.0x

Enterprise Value

> $10B

Production Growth >15%

Leverage <2.0x

Free Cash Flow

# of

Companies

Median Debt/

Adjusted

EBITDAX

Median EV/

2019 Adj.

EBITDAX

53 2.2x 5.3x

37 1.5x 5.3x

17 1.5x 6.2x

9 1.5x 6.2x

6 1.0x 7.2x

5 0.8x 7.3x

EOG

CXO

PXD

AR 2019E

unhedged

EBITDAX

Multiple: 4.6x

Scale

Growth

Low Leverage

Permian & Appalachia

FCF Generation

COG

CLR

in 2019

in 2018

Premium for:

Disciplined Capital Efficient Midstream Model

Antero Midstream At A Glance

23

Market Cap……………….......

Enterprise Value….........…….

LTM Adjusted EBITDA(1)……..

% Gathering/Compression…

% Water…..…..…..…..……..

Net Debt/LTM EBITDA……....

Corporate Debt Rating……….

$5.6B

$7.0B

$619 MM

65%

35%

2.3x

Ba2 / BB+ /BBB-

Note: Equity market data as of 8/30/2018. 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 │DISCIPLINED CAPITAL EFFICIENT MIDSTREAM MODEL

AM Highlights

AMGP Highlights

Market Cap……………….......

Net Debt/LTM EBITDA...…….

$3.2B

–

Antero Midstream Utica Assets

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 Treatment Facility

60,000 Bbl/d Capacity Stonewall JV Pipeline

New Smithburg JV Processing Facility –

Civil Work Under Way

AM Long-Term Distribution and Coverage Targets

24

$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

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 8/30/18.

Implied Yield

9.6%

5.8%


AMGP Long-Term Distribution Targets

25

AMGP Long-Term Distribution Targets (Midpoint)

As a result of AM targeting 20% distribution growth in 2021 and 2022, AMGP is targeting distribution growth of 29% and 27% in 2021 and 2022

$0.54

$0.88

$1.34

$1.73

$2.20 64%

53%

29% 27%

0%

10%

20%

30%

40%

50%

60%

70%

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

2018Guidance

2019Target

2020Target

2021Target

2022Target

AMGP Distributions Per Share Year-over-Year Distribution Growth

163%

Note: Represents midpoint of target range. 2018 growth based on full year 2017 distribution of $0.205/share. Based on AMGP Share price of $17.28 as of 8/30/18.

3.1%

7.8%


Most Integrated Liquids Business in the U.S.

26

World Class E&P

Operator in Appalachia

Contiguous Core Acreage Position Allows for Long

Lateral Drilling and Significant Capital Efficiencies

Largest NGL Producer 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% Ownership

ANTERO RESOURCES | BARCLAYS 2018 CEO ENERGY CONFERENCE

A Leading Northeast

Infrastructure Platform Levered Exposure to Northeast

Infrastructure Buildout

Appendix

27

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

($25 MM Maintenance)

$150

($25 MM 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 .

28

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.

29

30 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.

Guidance Summary - 2018

31

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.

Material reduction in U.S. propane

inventories relative to the 5-year average

Current propane days of supply are

31% below last year and 42%

below the 5-year average

Strong Propane Fundamentals

32

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 $1.03/gallon

remainder of 2018

2017

2018

2017

2018


Note: 2H 2018 based on 2018 balance strip pricing as of 7/25/2018. Local index represents a blend of Dominion South and TET CO 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

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

33

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


$1,150

$2,830

$5,995

$795 $179

$311 $395

$250

$2,915

$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 @$29.74

(08/30/18)

Pre-taxCumulative

Value of AnteroMidstream

Cash

Pro

ceed

s (

SM

M)

Midstream Driving Value for AR Since Inception

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

4.6x

ROI unlevered

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.

34 ANTERO RESOURCES | CONTROL DEVELOPMENT & MITIGATE INDUSTRY RISKS

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