Am website presentation (a) june 2016

Partnership OverviewJune 2016

FORWARD-LOOKING STATEMENTSThis presentation contains forward-looking statements. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Antero Midstream Partners LP, and its subsidiaries (collectively, the “Partnership”) expect, believe or anticipate will or may occur in the future are forward-looking statements. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “estimate,” “project,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include expectations of plans, strategies, objectives, and anticipated financial and operating results of the Partnership and Antero Resources Corporation (“Antero Resources”). These statements are based on certain assumptions made by the Partnership and Antero Resources based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Partnership, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include the factors discussed or referenced under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2015 and in the Partnership’s subsequent filings with the SEC.

The Partnership cautions you that these forward-looking statements are subject to risks and uncertainties that may cause these statements to be inaccurate, and readers are cautioned not to place undue reliance on such statements. These risks include, but are not limited to, Antero Resources’ expected future growth, Antero Resources’ ability to meet its drilling and development plan, commodity price volatility, inflation, environmental risks, drilling and completion and other operating risks, regulatory changes, the uncertainty inherent in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks discussed or referenced under the heading “Item 1A. Risk Factors” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015 and in the Partnership’s subsequent filings with the SEC.

Our ability to make future distributions is substantially dependent upon the development and drilling plan of Antero Resources, which itself is substantially dependent upon the review and approval by the board of directors of Antero Resources of its capital budget on an annual basis. In connection with the review and approval of the annual capital budget by the board of directors of Antero Resources, the board of directors will take into consideration many factors, including expected commodity prices and the existing contractual obligations and capital resources and liquidity of Antero Resources at the time.

Any forward-looking statement speaks only as of the date on which such statement is made, and the Partnership undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

1

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

2

CHANGES SINCE JUNE 2016 PRESENTATION

Updated AR operational slides highlighting year-to-date improvements and pro forma location count Slides 4-8

New slide highlighting AR acreage acquisition and related benefits to AM Slide 3

Updated AR slide highlighting 3/31/2016 balance sheet and liquidity pro forma for equity offering Slide 27

491

638597

744

0100200300400500600700800900

1,000

Dedicated Acreage:Gathering & Compression

Dedicated Acreage:Water Services

ANTERO RESOURCES ACQUISITION BENEFITS AM

3

Antero Midstream Buildout

Compressor Station – In service

Districts with 3,000+ Antero Net Acres

Acquired AcreageCompressor Station – Planned on Existing Acreage

Existing Gathering Line

New Platform for Antero Midstream

Infrastructure Buildout

Fresh Water Delivery Take PointPlanned Gathering Line

1. Includes projects currently under construction.

AM Gross Dedicated Acreage (000’s)

A unique opportunity as most Appalachian core acreage is already dedicated to third party midstream providers

12/31/2015 Pro Forma

Fresh Water ImpoundmentExisting Fresh Water LinePlaned Fresh Water Line

Planned Gathering Line – Acquired Acreage

Compressor Station – Planned on Acquired Acreage

On June 9, 2016 Antero Resources acquired 55,000 net acres in the southwestern Marcellus Shale, over 95% of which will be dedicated to AM for gathering, compression, processing, and water services

Acquisition and associated equity financing allows Antero Resources to increase 2017 production target to 20% -25%, providing further support to Antero Midstream’s 2017 distribution growth target of 28% to 30%

Expands Antero Midstream footprint and identified 5-year investment opportunity set by over 15% to ~$3.5 billion(1)

– Attractive organic investment opportunities at 4x – 7x build-out EBITDA

– Additional adjacent third-party midstream opportunities

The acquired acreage is primarily located in areas where Antero is observing stronger EURs of 2.0 Bcf/1,000' or greater for wells completed in the first quarter with at least 30 days of production history

$8.7$11.7

$14.7

$5.2 $7.7 $10.1

35% 45%56%

24% 30%38%

0%10%20%30%40%50%60%

$0.0$3.0$6.0$9.0

$12.0$15.0

1.72.3

2.02.7

2.33.1

1.72.1

2.02.5

2.32.8

Pre

-Tax

RO

R

Pre

-Tax

PV

-10

Pre-Tax PV-10 Pre-Tax ROR

Classification(1) Highly-Rich Gas/Condensate Highly-Rich GasBTU Regime 1275-1350 1275-1350 1275-1350 1200-1275 1200-1275 1200-1275EUR (Bcfe): 20.8 24.4 27.9 18.8 22.1 25.2EUR (MMBoe): 3.5 4.1 4.7 3.1 3.7 4.2% Liquids: 33% 33% 33% 24% 24% 24%Well Cost ($MM): $8.5 $8.5 $8.5 $8.5 $8.5 $8.5Bcf/1,000’ 1.7 2.0 2.3 1.7 2.0 2.3Bcfe/1,000’: 2.3 2.7 3.1 2.1 2.5 2.8Net F&D ($/Mcfe): $0.48 $0.41 $0.36 $0.53 $0.45 $0.40Pre-Tax NPV10 ($MM): $8.7 $11.7 $14.7 $5.3 $7.7 $10.1Pre-Tax ROR: 35% 45% 56% 24% 30% 38%Payout (Years): 2.5 2.0 1.6 3.7 2.9 2.3Breakeven NYMEX Gas Price ($/MMBtu)(5) $1.67 $1.40 $1.18 $2.31 $2.05 $1.84

Gross 3P Locations(3): 626 971Pro Forma Gross 3P Locations(3): 733 (17% Increase) 1,154 (19% Increase)

4

NYMEX($/MMBtu)

WTI($/Bbl)

C3+ NGL(2)

($/Bbl)

2016 $2.26 $41 $162017 $2.77 $45 $212018 $2.87 $47 $242019 $2.93 $49 $252020 $3.03 $50 $262021-25 $3.49 $51-$53 $27

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

2016; 50% of Oil Price 2017+

4535

2016 Development Plan: Completions

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

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

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

WELL ECONOMICS – MARCELLUS UPSIDE POTENTIAL

Highly-Rich Gas/Condensate Highly-Rich Gas(4) (4)Bcf/1,000’

Bcfe/1,000’

Marcellus ShaleUtica Shale Ohio

5

Operating Highlights Top 20 best drilling footage days in

Marcellus since 2009 have all occurred in 2016, including 6,528’ drilled in 24 hours in West Virginia on the Rock 2H

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

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

Increased sand placement during completions to 98% in Q1 2016

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

Increased proppant and water loading by 25% in 2016 with encouraging results to date

1. Based on statistics for wells completed within each respective period.2. Ethane rejection assumed.3. Current D&C cost per 1,000’ lateral divided by net EUR per 1,000’ lateral assuming 81% NRI in Utica and 85% NRI in Marcellus.

CONTINUOUS OPERATING IMPROVEMENTS BY AR

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

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

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

Well Cost & Performance ImprovementsD&C per 1,000' of lateral ($MMs) $1.55 $1.36 $1.14 (26%) $1.34 $1.18 $0.95 (29%)Wellhead EUR per 1,000' of lateral (Bcf) (1) 1.4 1.6 1.6 14% 1.5 1.7 2.0 33%Processed EUR per 1,000' of lateral (Bcfe) (1)(2) 1.5 1.8 1.8 20% 1.8 1.9 2.3 28%Net development cost per processed Mcfe (3) $1.28 $0.94 $0.79 (39%) $0.88 $0.73 $0.49 (45%)

Acquired Acreage

1,2371,675

2,116

3,699

0

1,000

2,000

3,000

4,000

2014 2015 Q1 2016 Q2 2016

Late

ral f

t/day

Per

Rig

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

01/01/12 01/01/13 01/01/14 01/01/15 01/01/16 01/01/17

Late

ral F

eet D

rille

d Pe

r Rig

Date

24 Hour Footage

Switched to rotary

steerable system

STEP CHANGE IN AR MARCELLUS DRILLING FOOTAGE

6

Top 50 AR Marcellus Daily Footage Records

All of the top 20 daily footage records since

inception have occurred during 2016

Key Drilling Highlights:

Driven by technology and process advancements, all of the top 20 Anterodaily footage records have been achieved in 2016, quickly establishing a new benchmark in Marcellus drilling performance

Drilled 6,528’ feet in a lateral in 24 hours, exceeding previous record by over 1,000 feet

Lateral feet drilled per day has increased almost 3x since 2014 to 3,699’ in 2Q 2016

New drilling techniques and technologies are forecast to shave up to 5 days off lateral drilling times and up to 25% off drilling AFEs

Top 20 AR Marcellus Daily Footage Records

Changed lateral bit

Increased pump rates by removing heavy weight

drill pipe (small diameter increased friction)

30WELLS

90WELLS

159 WELLS

Marcellus Average Lateral Ft/Day

23 WELLS

1,1941,128 1,117

990 1,031 1,016958 956

1,0841,126

1,274 1,304 1,3371,418

1,4801,530 1,500

800

900

1,000

1,100

1,200

1,300

1,400

1,500

1,600

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

Sand

Pla

ced

Per F

oot o

f Lat

eral

32 3132 32 32 32 32

31 3132

34 3435 36 37

39 39

25

27

29

31

33

35

37

39

41

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

Bar

rels

Per

Foo

t of L

ater

al

ADVANCED COMPLETIONS DRIVE INCREASED WATER VOLUMES

7

AR Increased Proppant Load by 25% in the Marcellus and Utica, EARLY RESULTS JUST COMING IN

Pilot Testing Demonstrated Improved Recoveries While

Maintaining Well Density

New AR Completion Designs Utilizing 38 to 40 Barrels of Water Per Lateral Foot, a 25% Increase

y = 0.00199x - 0.63702

0

5

10

15

20

25

30

35

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

EUR

(Bcf

e)

Lateral Length (Feet)

All Wells

8

MARCELLUS IMPROVEMENTS DRIVING AR VALUE CREATION

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

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

10,000’ to 14,000’

1. All 255 wells completed since 2014 when Antero transitioned to shorter stage length completions (SSL).2. EUR’s include condensate and NGL processing (C3+) but assume ethane rejection.

Longer Laterals Better Well Economics

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

Bbls/ft of water

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

outperformance YTD 2016 compared to type curve 40 wells > 20 Bcfe

High correlation of EURs to lateral length

2016 wells average 2.3 Bcfe/1,000’

High correlation of EURs to lateral length – no degradation in results out to 11,000’ laterals Antero has led the way with long lateral drilling programs

ANTERO MIDSTREAM EXERCISES STONEWALL OPTION

• Antero Midstream has exercised its option to acquire a 15% non-operated equity interest in the Stonewall gathering pipeline- Capital investment: $45 million- Expected unlevered IRR: 25% - 35%- Effective date: May 26, 2016

●Another step towards becoming “full value chain” midstream provider

- Fixed fee revenues with minimum volume commitments

●Antero Resources is an anchor shipper with the ability to transport up to 1.1 Bcf/d of gas on a firm basis (900 MMcf/d minimum volume commitment) to more favorably priced markets including TCO, NYMEX and Gulf Coast markets

- Currently transporting ~950 MMcf/d

Stonewall Gathering Pipeline Option

Throughput Capacity: 1.4 Bcf/d

Pipeline Specifications: 67 miles of 36-inch pipeline

Project Capital: ≈ $400 Million

In-Service Date: 12/1/2015

AR Firm Commitment: 900 MMcf/d 9

Stonewall Gathering Pipeline Asset Details

Acquired Acreage

WHY OWN ANTERO MIDSTREAM?

10

Best-in-class distribution growth guidance of 30% in 2016 and 28% to 30% target for 2017 Strong DCF coverage of 1.60x in 1Q16 and 1.45x in 2015, above 1.1x–1.2x target

Strong Distribution Growth & Coverage

Sponsor Strength

Organic Investment Opportunity Set

Full Value Chain Midstream

Opportunity

Financial Flexibility

Aligned High Growth

Sponsor

$3.8 billion of consolidated liquidity pro forma; stable leverage through the down cycle Ba2/BB corporate ratings affirmed; $4.5 billion AR borrowing base affirmed 84% of forecasted production hedged through 2019 at $3.77/MMBtu Peer leading realized prices and EBITDAX margins

Identified organic investment opportunity set of $3.5 billion over the next five years “Just-in-time capital” results in more capital efficient project economics, while avoiding the

competitive acquisition market and reliance on capital markets Organic growth strategy results in investment build-out EBITDA multiples of 4x–7x vs.

drop-downs of 8x–12x

Opportunity to expand gathering, compression, and water services to third parties Right of first offer for processing, fractionation, transportation and marketing activities Midstream provider for the largest and most active operator in Appalachia inherently brings

additional downstream opportunities to AM

Over $800 million of liquidity and 2.3x debt to EBITDA ratio at March 31, 2016

17% production growth guidance in 2016 and 20% to 25% growth targeted for 2017 drives AM volume growth

Continuous operating improvements, including more water and sand in completions resulting in improved recoveries and well economics for AR and higher volumes for AM

AR has a 62% LP ownership in AM, resulting in direct alignment with midstream value creation

Sustainable Business

Model

High Growth Sponsor Drives AM Throughput

and Distribution Growth

Largest Dedicated Core Liquids-Rich Acreage Position in Appalachia

$800 Million ofAM Liquidity

11

Premier E&P Operator in Appalachia

100% Fixed Fee and Largest Firm Transport

and Hedge Portfolio

Opportunity to Build Out Northeast Value Chain

Growth Liquids-Rich

Value Chain

Opportunity

HighVisibility

SponsorStrength

LEADING UNCONVENTIONAL MIDSTREAM BUSINESS MODEL

“Just-in-time” Non-Speculative Capital Program

Strong Financial Position

Mitigated Commodity

Risk

1

2 3

4

5

67

8

Premier AppalachianMidstream Partnership

Run by Co-Founders

Hedges Bolster Solid Well Economics

-

100

200

300

400

500

600

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

Pro Forma Core Net Acres - DryCore Net Acres - DryPro Forma Core Net Acres - Liquids-RichCore Net Acres - Liquids-Rich

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

AR EQT RRC COG CNX CHK SWN

0

500

1,000

1,500

2,000

2,500

3,000

3,500

0200400600800

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

EQT AR CHK COG SWN RRC CNX

SPONSOR STRENGTH – LEADERSHIP IN APPALACHIAN BASIN

Top Producers in Appalachia (Net MMcfe/d) – 1Q 2016(1)(2) Top 12 U.S. Natural Gas Producers (Net MMcf/d) – 1Q 2016(1)

Appalachian Producers by Proved Reserves (Bcfe) – YE 2015(1)(2) Appalachian Producers by Core Net Acres (000’s) – June 2016(4)

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

(3)

12

2nd Largest Appalachian Producer in

1Q ‘16

Appalachian Peers

8th Largest U.S. Gas Producer in

1Q ‘16

Largest Proved Reserve Base In

AppalachiaAntero Has the Largest

Liquids-Rich Core Position in Appalachia

) ) ) )

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

$198 $341

$434

$649

$1,164

$1,374

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

2010 2011 2012 2013 2014 2015 2016E

$1,221

0

10,000

20,000

30,000

40,000

50,000

60,000

2010 2011 2012 2013 2014 2015 2016E

NGLs (C3+) Oil Ethane

5 2466,436

23,051

48,298

66,000

37% GrowthGuidance

1. Represents midpoint of updated 2017 production guidance per press release dated 6/8/2016. 2. Represents Bloomberg street consensus estimates as of 5/27/2016.

1,750

2,144

0

600

1,200

1,800

2,400

2010 2011 2012 2013 2014 2015 2016E 2017E

Marcellus Utica Guidance

30 124239

522

1,007

1,493

13

AVERAGE NET DAILY PRODUCTION (MMcfe/d)

0

50

100

150

200

2010 2011 2012 2013 2014 2015 2016E

Marcellus Utica Deferred Completions

1938

60

114

177 181

131110

180

OPERATED GROSS WELLS COMPLETED

AVERAGE NET DAILY LIQUIDS PRODUCTION (Bbl/d)

17% Growth

Guidance23% Growth

Target(1)

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

CONSOLIDATED EBITDAX ($MM)

StreetConsensus(2)

SPONSOR STRENGTH – MOMENTUM THROUGH THE DOWN CYCLE

Note: 2015 SEC prices were $2.56/MMBtu for natural gas and $50.13/Bbl for oil on a weighted average Appalachian index basis. 1. Pro forma for third-party acreage acquisition announced per press release dated 6/9/2016. 3P reserve additions are unaudited. 2. 3P reserve pre-tax PV-10 based on annual strip pricing for first 10-years and flat thereafter as of December 31, 2015. NGL pricing assumes 39%, 46% and 48% of WTI strip prices for 2016, 2017 and

2018 and thereafter, respectively. PV-10 value not adjusted for third-party asset acquisition. 3. All net acres allocated to the WV/PA Utica Shale Dry Gas and Upper Devonian Shale are included among the net acres allocated to the Marcellus Shale as they are stacked pay formations attributable to

the same leasehold. 4. Antero and industry rig locations as of 5/27/2016, per RigData.

14

COMBINED TOTAL – 12/31/15 RESERVESAssumes Ethane RejectionNet Proved Reserves 13.2 TcfeNet 3P Reserves(1) 41.2 TcfeStrip Pre-Tax 3P PV-10(2) $11.2 BnNet 3P Reserves & Resource(1) 56 to 59 TcfeNet 3P Liquids(1) 1,350 MMBbls% Liquids – Net 3P(1) 20%1Q 2016 Net Production 1,758 MMcfe/d- 1Q 2016 Net Liquids 68,516 Bbl/dNet Acres(1)(3) 628,000Undrilled 3P Locations(1) 4,344

OHIO UTICA SHALE CORE

Net Proved Reserves 1.8 TcfeNet 3P Reserves 7.5 TcfeStrip Pre-Tax 3P PV-10(2) $2.5 BnNet Acres 148,000Undrilled 3P Locations 814

MARCELLUS SHALE CORE

Net Proved Reserves 11.4 TcfeNet 3P Reserves(1) 33.7 TcfeStrip Pre-Tax 3P PV-10(2) $8.7 BnNet Acres(1) 480,000Undrilled 3P Locations(1) 3,530

WV/PA UTICA SHALE DRY GASNet Resource 14.3 to 17.8 TcfNet Acres 231,000Undrilled Locations 2,269

012345678

Rig

Cou

nt

Operators

SW Marcellus + Utica Rigs(4)

SPONSOR STRENGTH – MOST ACTIVE OPERATOR AR is operating 23% of all rigs running and 58% of rigs running in liquids rich core areas in Appalachia

$1$5 $7 $8 $11

$19$28

$36$41

$55

$83 $80

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

$100

10 38 80 126 266

531

908

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

0200400600800

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

108 216 281 331 386

531

738

935 965 1,038

1,124

1,303

0

200

400

600

800

1,000

1,200

1,400

1,600 Utica Marcellus

26 31 40 36 41 116

222

358

454 435478

606

0

100

200

300

400

500

600

700

800 Utica Marcellus

Low Pressure Gathering (MMcf/d)

Compression (MMcf/d)

High Pressure Gathering (MMcf/d)

EBITDA ($MM)

15

$338

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

GROWTH – HIGH GROWTH MIDSTREAM THROUGHPUT

$215

$0.170 $0.180 $0.190 $0.205

$0.235

1.1x

1.2x1.3x

1.4x

1.8x

1.6x

0.0x

0.2x

0.4x

0.6x

0.8x

1.0x

1.2x

1.4x

1.6x

1.8x

2.0x

$0.000

$0.050

$0.100

$0.150

$0.200

$0.250

$0.300

$0.350

$0.400

$0.450

$0.500

4Q14A 1Q15A 2Q15A 3Q15A 4Q15A 1Q16A 2Q16E 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E

Distribution Per Unit (Left Axis) DCF Coverage (Right Axis)

$0.220

16

• Antero Midstream is targeting 28% to 30% annual distribution growth through 2017• AM has delivered on those targets with DCF coverage of 1.6x in the first quarter 2016

Note: Future distributions subject to AM Board approval.1. Assumes midpoint of target distribution growth range.2. 1Q 2016 distribution per Partnership press release dated 4/14/2016.

(2)

GROWTH – TOP TIER DISTRIBUTION GROWTH

GROWTH – ORGANIC GROWTH STRATEGY DRIVES VALUE CREATION

17

• Organic growth strategy provides attractive returns and project economics, while avoiding the competitive acquisition market and reliance on capital markets

• Industry leading organic growth story

– ~$1.9 billion in capital spent through 09/30/2015 on gathering and compression and water assets

– $410 million in additional growth capital forecast for the twelve-month period ending 12/31/16 (excludes $25 million of maintenance capital)

– 5-year identified investment opportunity set of $3.5 billion

Note: Precedent data per IHS Herold’s research and public filings.1. Antero organic multiple calculated as estimated gathering and compression and water capital expended through Q3 2015 divided by midpoint of 2016 EBITDA guidance of $325 to $350 million,

assuming 12-15 month lag between capital incurred and full system utilization.2. Selected gathering and compression drop down acquisitions since 1/1/2012. Drop down multiples are based on NTM EBITDA. Source: Barclays.

5.5x

11.5x

10.8x10.5x

9.3x9.0x 8.8x 8.7x 8.6x 8.6x

8.2x7.9x 7.8x

6.9x

0.0x

1.0x

2.0x

3.0x

4.0x

5.0x

6.0x

7.0x

8.0x

9.0x

10.0x

11.0x

12.0x

Drop Down Multiple(2)

Organic EBITDA Multiple vs. Precedent Drop Down Multiples

Median: 8.8x

Value creation for the AM unit holder =Build at 4x to 7x EBITDA

vs.Drop Down / Buy at 8x to 12x EBITDA

LPGathering

HPGathering Compression

CondensateGathering

Fresh Water Delivery

Advanced Wastewater Treatment

Stonewall GatheringPipeline

Processing/Fractionation

Unlevered IRR Range: 25% - 35% 15% - 25% 10% - 20% 25% - 35% 30% - 40% 15% - 25% 25% - 35% 15% - 20% Payout (Years): 2.5 - 4.0 3.5 - 4.5 4.0 - 6.5 2.0 - 3.5 2.0 – 3.0 6.0 - 8.0 2.0 - 3.5 5.0 - 6.0 Minimum Volume Commitments: N/A 75% 70% N/A Yes N/A 80% 80%

2016 Expansion Capex(2) Total

Marcellus $433 $33 $49 $143 - $33 $130 $45 Utica 22 7 1 7 - 7 - -

Growth Capex $455 $40 $50 $150 $0 $40 $130 $45 % of Capex 100% 9% 11% 33% 0% 9% 28% 10%

Included in 2016 Budget: Marcellus & Utica

Marcellus & Utica

Marcellus & Utica

Utica Marcellus & Utica

Marcellus & Utica

Marcellus Not Included

5-year identified investment opportunity set

$3.5 B 30% - 35% 15% - 20% 30% - 35% 0% 8% - 12% 6% - 8% 1%

Additional In-hand Opportunities:

Dry Utica Dry Utica Dry Utica Utica Stabilization

Dry Utica Dry Utica Marcellus Processing/

Fractionation

25%

15%

10%

25%

30%

15%

25%

15%

35%

25%

20%

35%

25% 25%

40%

20%

0%

10%

20%

30%

40%

Inte

rnal

Rat

e of

Ret

urn

18

Project Economics by Segment(1)

GROWTH – ESTIMATED PROJECT ECONOMICS BY SEGMENT

1. Based on management capex, operating cost and throughput assumptions by project. Capex guidance updated per 2016 Partnership guidance press release. 2. Excludes $25.0 million of maintenance capex. Includes Stonewall option exercise.

Wtd. Avg. 21% IRR

AM Option Opportunities

35%

19Source: Core outlines and peer net acreage positions based on investor presentations, news releases and 10-K/10-Qs. Rig information per RigData as of 5/27/2016.1. Based on company filings and presentations. Peer group includes Ascent, CHK, CNX, CVX, ECR, EQT, GPOR, NBL, REX, RRC, STO, SWN.

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

• Antero has the largest core liquids-rich position in Appalachia with ≈420,000 net acres (> 1100 Btu)

• Represents over 24% of core liquids-rich acreage in Marcellus and Utica plays combined

Antero has over 3,080 undeveloped rich gas locations with an average lateral length of 7,870’ in its 3P reserves as of 12/31/2015 pro forma for the third-party acreage acquisition

0

100

200

300

400

500

(000

s)

Core Liquids-Rich Net Acres(1)

LIQUIDS-RICH – LARGEST CORE DRILLING INVENTORY

$1.55$1.36

$1.14

$0.000

$0.500

$1.000

$1.500

$2.000

2014 2015 Current

$MM

/1,0

00’ L

ater

al

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

12% Decrease vs. 2014


733 1,154

692 95163% 47%

24% 28%35%24%

10% 13%

0

400

800

1,200

1,600

0%

20%

40%

60%

80%

Highly-RichGas/

Condensate

Highly-Rich Gas Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

R

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

184

98 108

161263

14%

48%64% 56% 64%

9%

23% 24% 20% 24%

0

100

200

300

0%20%40%60%80%

100%

Condensate Highly-RichGas/

Condensate

Highly-RichGas

Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

R

MARCELLUS WELL ECONOMICS(1)(2)

SUSTAINABLE BUSINESS MODEL – HEDGES BOLSTER SOLID WELL ECONOMICS

Marcellus Well Cost Improvement(3)

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

2. ROR @ 3/31/2016 Strip-With Hedges reflects 3/31/2016 well cost ROR methodology, with the 3/31/2016 hedge value allocated based on 2016-2021 projected production volumes resulting in blend of strip and hedge prices. Locations pro forma for third-party acreage acquisition per press release dated 6/8/2016.

3. Current spot well costs based on $8.5 million for a 9,000’ lateral Marcellus well and $10.25 million for a 9,000’ lateral Utica well.20

UTICA WELL ECONOMICS(1)(2)

73% of Marcellus locations are processable (1100-plus Btu) 68% of Utica locations are processable (1100-plus Btu)

2016Drilling

Plan

AR multi-year drilling inventory supports low risk, high return growth profile Antero has reduced average well costs for a 9,000’ lateral by 31% in the Marcellus and 28% in the Utica as compared to 2014 well costs At 3/31/2016 strip pricing, Antero has 2,517 locations that exceed a 20% rate of return (excluding hedges)

– Including hedges, these locations generate rates of return of approximately 45% to 65%

Utica Well Cost Improvement(3)

$1.34$1.18

$0.95

$0.000

$0.500

$1.000

$1.500

$2.000

2014 2015 Current

$MM

/1,0

00’ L

ater

al

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



21

In-service 2016 Budget

HIGH VISIBILITY – PROJECTED MARCELLUSMIDSTREAM BUILDOUT

22

In-service 2016 Budget

HIGH VISIBILITY – PROJECTED UTICAMIDSTREAM BUILDOUT

7

0

4

0

3

6

02468

AM CNNX EQM CMLP SMLP RMP

Fixed Fee

100%

Fixed Fee

100%

23

MITIGATED COMMODITY RISK – 100% FIXED FEE – RICH TO DRY

Contract Mix

Fixed Fee98%

Fixed Fee

100%

Fixed Fee

100%Fixed Fee90%

(1)

.

Source: Core net acreage positions based on investor presentations, news releases and 10-K/10-Qs.1. Represents assets held at MLP.2. Rig count as of 5/27/2016, per RigData.3. Includes Antero Resources rigs located in Doddridge County, WV operating on SMLP assets.

CommodityBased

CommodityBased

Appalachian ExposureMarcellus – Dry

Marcellus – Rich

Utica – Dry

Utica – Rich

Water Services

Rigs Running on Midstream Footprint (2)

(3)

AM has no direct commodity price exposure

- 500,000

1,000,000 1,500,000 2,000,000 2,500,000 3,000,000 3,500,000 4,000,000 4,500,000 5,000,000 5,500,000

Gross Gas Production (BBtu/d)

24

BBtu/d

Antero Resources Transportation Portfolio• Antero Resources has built the largest firm transportation portfolio in Appalachian Basin with 4.85 BBtu/d by year end 2018• Realized $0.01/Mcfe differential to Nymex gas prices in 1Q16, before hedges

2015 2016E 2017E 2018EFavorable:ChicagoMichConGulf CoastNYMEXTCO

AR Increasing Access to Favorable Markets

Less favorable:TETCO M2Dominion South

74%

26%

99%

1%

97%

3%

97%

3%

(Stonewall/WB) Mid-Atlantic/NYMEX

(Stonewall/TGP) Gulf Coast

(TCO) Appalachia or Gulf Coast

AppalachiaAppalachia

(REX/ANR/NGPL/MGT) Midwest

(ANR/Rover) Gulf Coast

MITIGATED COMMODITY RISK – FIRM TRANSPORTATION & SALES PORTFOLIO

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$0

$50

$100

$150

$200

$250

$300

$350

$MM

25

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

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

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

Quarterly Realized Hedge Gains / (Losses)

Realized Hedge GainsProjected Hedge Gains

NYMEX Natural Gas Historical Spot Prices

($/MM

Btu)

NYMEX Natural Gas Futures Prices 03/31/16

3.6 Tcfe Hedged at average price of

$3.71/Mcfe through 2022

Average Hedge Prices ($/MMBtu)

$3.36

$3.91$3.57

$3.91$3.70 $3.66

$3.24

$3.1 Billion in Projected Hedge

Gains Through 2022Realized $2.1 Billion in Hedge Gains

Since 2009

HEDGING – INTEGRAL TO BUSINESS MODEL

(1)

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

Regional Gas Pipelines

Miles Capacity In-Service

Stonewall Gathering Pipeline

50 1.4 Bcf/d Yes

1. Acquired by AM from AR for a $1.05 billion upfront payment and a $125 million earn out in each of 2019 and 2020.2. Antero Midstream has a right of first offer on 220,000 dedicated net acres for processing and fractionation.

EndUsers

EndUsers

Gas Processing

Y-Grade Pipeline

Long-Haul Interstate

Pipeline

InterConnect

NGL Product Pipelines

Fractionation

Compression

Low Pressure Gathering

Well Pad

Terminalsand

Storage

(Miles) YE 2015 YE 2016E

Marcellus 106 114

Utica 55 56

Total 161 170

AM has option to participate in processing, fractionation,

terminaling and storage projects offered to AR


Marcellus 76 98

Utica 36 36

Total 112 134

(MMcf/d) YE 2015 YE 2016E

Marcellus 700 940

Utica 120 120

Total 820 1,060

AM Owned Assets

Condensate GatheringStabilization


Utica 19 19

EndUsers

(Ethane, Propane, Butane, etc.)

26

VALUE CHAIN OPPORTUNITY – FULL MIDSTREAM VALUE CHAIN

AM Option Opportunities (2)

AM recently exercised its option on 15% interest in Stonewall, adding a regional gas gathering pipeline to its portfolio

Liquid “non-E&P assets” of $5.7 Bnsignificantly exceeds total debt of $3.8 Bn pro

forma for $762 million equity offering

Pro Forma Liquidity

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

Pro Forma 3/31/2016 Debt Liquid Non-E&P Assets 3/31/2016 Debt Liquid Assets

Debt Type $MMCredit facility $377

6.00% senior notes due 2020 525

5.375% senior notes due 2021 1,000

5.125% senior notes due 2022 1,100

5.625% senior notes due 2023 750

Total $3,752

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

AM equity ownership(2) 2,644

Cash 26

Total $5,743

Asset Type $MMCash $26

Credit facility – commitments(3) 4,000

Credit facility – drawn (377)

Credit facility – letters of credit (702)

Total $2,947

Debt Type $MMCredit facility $680

Total $680


Total $14

Liquidity


Credit facility – capacity 1,500

Credit facility – drawn (680)

Credit facility – letters of credit -

Total $834

Approximately $2.9 billion of liquidity at AR pro forma for equity offering plus an

additional $2.6 billion of AM units

Approximately $800 million of liquidityat AM

Only 45% of AM credit facility capacity drawn

Note: All balance sheet data as of 3/31/2016. Antero Resources pro forma for $762 million equity offering, less transaction costs, per press release dated 6/9/2016. 1. Mark-to-market as of 3/31/2016.2. Based on AR ownership of AM units (108.9 million common and subordinated units) and AM’s closing price as of 6/9/2016.3. AR credit facility commitments of $4.0 billion, borrowing base of $4.5 billion.

27

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

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

Tota

l Deb

t / L

TM A

djus

ted

EBIT

DA

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

• Liquidity of $834 million at 3/31/2016

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

AM Liquidity (3/31/2016)

AM Peer Leverage Comparison(1)

($ in millions)

Revolver Capacity $1,500

Less: Borrowings 680

Plus: Cash 14

Liquidity $834

1. As of 3/31/2016. Peers include TEP, EQM, WES, RMP, SHLX, DM, and CNNX.2. AM includes full year EBITDA contribution from water business.

Financial Flexibility

28

(2)

STRONG FINANCIAL POSITION – SIGNIFICANT FINANCIAL FLEXIBILITY

TOP TIER DISTRIBUTION GROWTH & HEALTHY COVERAGE

29

3–Year Street Consenus Distribution Growth Rate and DCF Coverage(1)

1. Based on Bloomberg 2015-2018 Bloomberg consensus estimates as of 3/31/2016.

31%

26% 25% 25%23%

19%

15%13% 12%

8%

1.5x

1.3x

1.4x

1.8x

1.3x1.4x

1.2x

1.3x1.3x

1.2x

0.00x

0.20x

0.40x

0.60x

0.80x

1.00x

1.20x

1.40x

1.60x

1.80x

2.00x

0%

5%

10%

15%

20%

25%

30%

35%

SHLX PSXP AM VLP DM EQM TEP MPLX CNNX WES

EQM

DM SHLX

CNNXWES

TEPMPLX

PSXPVLP

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

8.0%

9.0%

10.0%

3% 8% 13% 18% 23% 28% 33%

Yiel

d (%

)

2016-2018 Distribution Growth CAGRBubble Size Reflects Market Capitalization

ATTRACTIVE VALUE PROPOSITION

30

AM – 03/31/15 Yield: 4.03%

Price: $21.81

AM - ImpliedYield: 2.85%Price: $30.84

• Attractive appreciation potential on a relative basis

1. Based on Bloomberg 2015-2018 Bloomberg consensus distribution estimates and market data as of 3/31/2016.

R-squared = 88%

Antero Midstream (NYSE: AM)Asset Overview

31

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

32

UticaShale

MarcellusShale

Projected Gathering and Compression Infrastructure(1)

Marcellus Shale

Utica Shale Total

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

Gathering Pipelines(Miles) 182 91 273

Compression Capacity(MMcf/d) 700 120 820

Condensate Gathering Pipelines (Miles) - 19 19

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

Gathering Pipelines (Miles) 30 1 31

Compression Capacity(MMcf/d) 240 - 240

Condensate Gathering Pipelines (Miles) - - -

Gathering and Compression Assets

ANTERO MIDSTREAM GATHERING AND COMPRESSION ASSET OVERVIEW

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

– Acreage dedication of ~597,000 gross leasehold acres for gathering and compression services

– Additional stacked pay potential with dedication on ~277,000 gross acres of Utica deep rights underlying the Marcellus in WV and PA

– 100% fixed fee long term contracts

• AR owns 62% of AM units (NYSE: AM)

Acquired Acreage

ANTERO MIDSTREAM ASSETS – RICH GAS MARCELLUS

33

• Provides Marcellus gathering and compression services

− Liquids-rich gas is delivered to MWE’s 1.2 Bcf/d Sherwood processing complex

• Significant growth projected over the next twelve months as set out below:

• Antero plans to operate an average of five drilling rigs in the Marcellus Shale during 2016, including intermediate rigs

− 100% of rigs targeting the highly-rich gas/condensate and highly-rich gas regimes

• All 80 gross wells targeted to be completed in 2016 are in the AM dedicated area

− AM dedicated acreage contains 2,126 gross undeveloped Marcellus locations

• Antero will defer an additional 62 completions, with 20 being wells dedicated to a third-party midstream provider that were originally scheduled for completion in 2016 but will now be carried into 2017, in order to limit natural gas volumes sold into unfavorable pricing markets

Marcellus Gathering & Compression

Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.

YE 2015 YE 2016E

Low Pressure Gathering Pipelines (Miles)

106 114

High Pressure Gathering Pipelines (Miles)

76 98

Compression Capacity (MMcf/d) 700 940

Acquired Acreage

34

• Provides Utica gathering and compression services− Liquids-rich gas delivered into MWE’s 800 MMcf/d

Seneca processing complex− Condensate delivered to centralized stabilization and

truck loading facilities• Significant growth projected over the next twelve months

as set out below:

• Antero plans to operate an average of two drilling rigs in the Utica Shale during 2016, including intermediate rigs

− 100% of rigs targeting the highly-rich gas/condensate and highly-rich gas regimes

• All 30 gross wells targeted to be completed in 2016 are on Antero Midstream’s footprint

• Antero will defer an additional 8 completions in order to limit natural gas volumes sold into unfavorable pricing markets

Utica Gathering & Compression

Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.

ANTERO MIDSTREAM ASSETS – RICH & DRY GAS UTICA

YE 2015 YE 2016E

Low Pressure Gathering Pipelines (Miles)

55 56

High Pressure Gathering Pipelines (Miles)

36 36

Condensate Pipelines (Miles) 19 19

Compression Capacity (MMcf/d) 120 120

ANTERO MIDSTREAM WATER BUSINESS OVERVIEW

35Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.1. Represents inception to date actuals as of 12/31/2015 and 2016 guidance.2. All Antero water withdrawal sites are fully permitted under long-term state regulatory permits both in WV and OH. 3. Includes both expansion capital and maintenance capital. 4. Marcellus assumes fee of $3.69 per barrel subject to annual inflation and 351,000 barrels of water per well that utilize the fresh water delivery system based on 9,000 foot lateral. Operating margin excludes

G&A. Utica assumes fee of $3.64 per barrel subject to annual inflation and 306,000 barrels of water per well that utilize the fresh water delivery system based on 9,000 foot lateral. Operating margin excludes G&A.

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

treatment complex and all fluid handling and disposal services for Antero

Projected Water Business Infrastructure(1)

Marcellus Shale

Utica Shale Total

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

Water Pipelines(Miles) 184 75 259

Fresh Water StorageImpoundments 22 13 35

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

Water Pipelines(Miles) 20 9 29

Fresh Water StorageImpoundments 1 - 1

Cash Operating Margin per Well(4)

$950k -$1,000k

$825k -$875k

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

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

Water Business Assets

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

River, local rivers & reservoirs(2)

– 100% fixed fee long term contracts

Antero Clearwater advanced wastewater treatment facility currently under construction –connects to Antero freshwater delivery system

Acquired Acreage

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

Antero Clearwater Advanced Wastewater Treatment Capacity (Bbl/d)

Produced/Flowback Volumes (Bbl/d)

Illustrative Produced & Flowback Water VolumesAdvanced Wastewater Treatment

Antero Produced Water Services and Freshwater Delivery Business

Antero AdvancedWastewater Treatment

3rd Party Recyclingand Well Disposal

(Bbl/d)

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

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

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

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

20 Years, Extendable

36Integrated Water Business

Antero Advanced Wastewater Treatment

Freshwater delivery system

Flowback and produced

Water

Well Pad

Well Pad

CompletionOperations

Producing

Freshwater

Salt

Calcium Chloride

Marketable byproduct

Marketable byproduct used in oil and gas operations

Freshwater delivery system

ANTERO MIDSTREAM ADVANCED WASTEWATER TREATMENT ASSET OVERVIEW

AM UPSIDE OPPORTUNITY SET

37

ACTIVITY CURRENTLY DEDICATED TO AM

Third Party Business

Processing, Fractionation, Transportation and Marketing

• Opportunity to expand fresh water, waste water and gathering/compression services to third parties in Marcellus and Utica to enhance asset utilization

• AR must request a bid from AM and can only reject if third party service fees are lower. AM has right to match lower fee offer.

WV/PA Utica Dry Gas• 277,000 gross acres of AR Utica dry gas acreage underlying

the Marcellus in West Virginia and Pennsylvania dedicated to AM

• AR has drilled and completed its first WV Utica well

AR Acreage Consolidation• 55,000 net acres acquired in 2016 by AR primarily

undedicated for gathering, compression, processing and water services

• Future acreage acquisitions by AR are dedicated to AM

AR Gross Processable

Acres

Gross 3P NGL Reserves

(MMBbls)(1)

AR 3P GrossWellhead Gas (Tcf)

Potential Processing AOD for AM

Tyler 94,000 655.7 12.2

Ritchie 51,000 295.1 6.3

Gilmer 14,000 42.7 1.1

Wetzel 54,000 204.3 8.8

Pleasants 7,000 20.9 0.4

Total 220,000 1,218.7 28.8

PROCESSING – VALUE CHAIN POTENTIALFOR UNDEDICATED ACREAGE

SherwoodProcessing

Complex

AR acreage position on map reflects tax districts in which greater than 3,000 net acres are held.1. Antero gross 3P C3+ NGL volumes and 3P Gross Wellhead Gas reserves as of 12/31/2015, pro forma for AR acreage acquisition. Gross acres as of 3/31/2016.

Processing Area Of Dedication for AM

MarkWest Processing AOD – 198,000 Gross

Acres

Tyler County78,000 Gross Acres

Ritchie County51,000 Gross Acres

Antero Resources has 29 Tcf of processable gross 3P gas reserves and 1.2 billion Bbls of gross 3P NGL reserves across [195,000] gross processable Marcellus acres that are dedicated to Antero Midstream for processing

38

Gilmer County14,000 Gross Acres

Wetzel County52,000 Gross Acres

Pleasants County7,000 Gross Acres

LARGE UTICA SHALE DRY GAS POSITION

39

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

Antero has 272,000 net acres of exposure to Utica dry gas play in OH, WV and PA

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

Well Operator24-hr IP(MMcf/d)

LateralLength

(Ft)

24-hr IP/1,000’Lateral

(MMcf/d)

Scotts Run EQT 72.9 3,221 22.633

Gaut GH9 CNX 61.9 6,141 11.131

Claysville Sportsman

RRC 59.0 5,420 10.886

Stewart-Winland MHR 46.5 5,289 8.792

Bigfoot 9H RICE 41.7 6,957 5.994

Blake U-7H GST 36.8 6,617 5.561

Stalder #3UH MHR 32.5 5,050 6.436

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

Pribble 6HU SGY 30.0 3,605 8.322

Simms U-5H GST 29.4 4,447 6.611

Conner 6H CVX 25.0 6,451 3.875

Messenger 3H SWN 25.0 5,889 4.245

Tippens #6H ECR 23.2 5,858 3.960

Porterfield 1H-17 HESS 17.2 5,000 3.440

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

RRC – Claysville Sportsman5,420’ Lateral

24-hr IP: 59.0 MMcf/d

EQT – Scotts Run3,221’ Lateral


CNX – GH96,141’ Lateral


EQT – Big 1906,300’ LateralCompleting

MHR – Stewart Winland5,289’ Lateral


SGY – Pribble3,605’ Lateral


Tughill – Blake6,617’ Lateral


Tughill – Simms4,447’ Lateral


Antero – Rymer 4HD6,620’ Lateral

90-day IP: 20 MMcf/d

SWN – Messenger 5,889’ Lateral


ECR – Tippens5,858’ Lateral


MHR – Stalder5,050’ Lateral


CVX – Conner6,451’ Lateral


Low Cost Marcellus/Utica Focus

“Best-in-Class” Distribution Growth

40

CATALYSTS

• 30% for 2016 and 28% to 30% for 2017 targeted based on Sponsor planned development; additional third party business expansion opportunities

• AM Sponsor is the most active operator in Appalachia; • 17% production growth guidance for 2016 supported by $1.4 billion

capital budget, firm processing and takeaway, long-term natural gas hedges and $2.9 billion of liquidity

• Targeting 20% to 25% production growth in 2017

• Sponsor operations target two of the lowest cost shale plays in North America

• Attractive well economics support continued drilling at current prices

• $3.5 billion of capital investment opportunities over the next five years, pro forma for the AR acreage acquisition

Appalachian Basin Midstream Growth

High Growth Sponsor Production Profile

1

2

3

4

5

6

• Acquisition of integrated water business from AR expected to result in distributable cash flow per unit accretion in 2016

Consolidation and Stacked Pay

Upside

• AR plans to continue to consolidate Marcellus/Utica acreage• Development of Utica Shale Dry Gas resource will provide further

midstream infrastructure expansion opportunities

Integrated WaterBusiness Drop Down

APPENDIX

41

Key VariableOriginal

2016 GuidanceUpdated

2016 Guidance

Financial:

Net Income ($MM) N/A $165 - $190

Adjusted EBITDA ($MM) $300 - $325 $325 - $350

Distributable Cash Flow ($MM) $250 - $275 $275 - $300

Year-over-Year Distribution Growth 28% - 30% 30%

Operating:

Low Pressure Pipeline Added (Miles) 9 9

High Pressure Pipeline Added (Miles) 22 22

Compression Capacity Added (MMcf/d) 240 240

Fresh Water Pipeline Added (Miles) 30 30

Capital Expenditures ($MM):

Gathering and Compression Infrastructure $240 $240

Fresh Water Infrastructure $40 $40

Advanced Wastewater Treatment $130 $130

Stonewall Gathering Pipeline Option(1) NA $45

Maintenance Capital $25 $25

Total Capital Expenditures ($MM) $435 $480

ANTERO MIDSTREAM – UPDATED 2016 GUIDANCE

Key Operating & Financial Assumptions

421. Antero Midstream closed on the acquisition of 15% interest in the Stonewall pipeline on 5/26/2016.

2016 UPDATED CAPITAL BUDGET

By Area

43

$423 Million – 2015(1)

By Segment ($MM)

$349

$6

$55$13

Gathering & Compression Fresh Water InfrastructureAdvanced Wastewater Treatment Maintenance Capital

74%

26%

Marcellus Utica

By Area

$480 Million – 2016By Segment ($MM)

Antero Midstream’s 2016 updated capital budget is $480 million, a 13% increase from 2015 capital expenditures of $423 million

13%

130 Completions

1. Excludes $1.05 billion water drop down in September 2015. Water capex values only from 4Q 2015.

$240

$40

$130

$45$25

Gathering & Compression Fresh Water InfrastructureAdvanced Wastewater Treatment Stonewall PipelineMaintenance Capital

95%

5%

Marcellus Utica

ANTERO RESOURCES – UPDATED 2016 GUIDANCE

Key Variable 2016 Guidance(1)

Net Daily Production (MMcfe/d) 1,750

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

Net C3+ NGL Production (Bbl/d) 52,500

Net Ethane Production (Bbl/d) 10,000

Net Oil Production (Bbl/d) 3,500

Net Liquids Production (Bbl/d) 66,000

Natural Gas Realized Price Premium to NYMEX Henry Hub Before Hedging ($/Mcf)(2)(3) +$0.00 to $0.10

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

C3+ NGL Realized Price (% of NYMEX WTI)(2) 35% - 40%

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

Operating:Cash Production Expense ($/Mcfe)(4) $1.50 - $1.60

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

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

Operated Wells Completed 110

Drilled Uncompleted Wells 70

Average Operated Drilling Rigs ≈ 7

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

Land $100

Total Capital Expenditures ($MM) $1,4001. Updated guidance per press release dated 4/27/2016. 2. Based on current strip pricing as of December 31, 2015. 3. Includes Btu upgrade as Antero’s processed tailgate and unprocessed dry gas production is greater than 1000 Btu on average. 4. Includes lease operating expenses, gathering, compression and transportation expenses and production taxes.

Key Operating & Financial Assumptions

44

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

62 MBbl/d CommitmentMarcus Hook Export

Shell30 MBbl/d Commitment

Beaver County Cracker (2)

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

(T1 in-service)

Lake Charles LNG(3)

150 MMcf/d

Freeport LNG70 MMcf/d

1. May 2016 and full year 2016 futures basis, respectively, provided by Intercontinental Exchange dated 3/31/2016. Favorable markets shaded in green. 2. Shell announced FID on 6/7/2016.3. Lake Charles LNG 150 MMcf/d commitment subject to BG FID expected in 2016.

Chicago(1)

$(0.03) / $(0.03)

CGTLA(1)

$(0.06) / $(0.06)

TCO(1)

$(0.11) / $(0.14)

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Cove Point LNG4.85 Bcf/dFirm GasTakeaway

By YE 2018

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

YE 2018 Gas Market MixAntero 4.85 Bcf/d FT

44%Gulf Coast

17%Midwest

13%Atlantic

Seaboard

13%Dom S/TETCO

(PA)

13%TCO

Positive weighted

average basis differential

Antero Commitments

(3)

(2)

LARGEST FIRM TRANSPORTATION AND PROCESSINGPORTFOLIO IN APPALACHIA

NORTHEAST NGL GROWTH IS SUPPORTED BY INCREASING TAKEAWAY OPTIONS

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

Industry NGL Pipelines – Actual and Projected(1)

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ShellBeaver County Cracker

(Received FID June 2016)

Mariner East 262 MBbl/d Commitment

Marcus Hook Export

Gulf Coast Critical to

NGL Pricing

Appalachia

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

(MMBbl/d)

Mariner West50 MBbl/d C2

POSITIVE OUTLOOK FOR LONG-TERM NGL MARKETS

Steady Global LPG Demand Growth Through 2035(1)

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

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

MM

Bbl

/d

0.0

0.33

0.67

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

China KoreaHaiwei (2016) - 21 MBbl/d C3

SK Advanced (2016) - 27 MBbl/d C3

Ningbo Fuji (2016) - 29 MBbl/d C3

Fujian Meide (2016) - 29 MBbl/d C3

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

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

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

Oriental Tangshan (2019) - 25 MBbl/d C3

Formosa (2017)- 25 MBbl/d C3

Firm and Likely PDH Underway (By 2020)

Total - 243 MBbl/d C3

Million Tons, Global PDH Capacity

1990 2000 2010 2020

20

10

0

47

14.7

13.0

11.4

9.8

8.2

6.5

4.9

3.3

1.7

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

MMBbl/d MMBbl/d1.3

1.0

0.7

0.3

-0.3

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

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

481. PIRA NGL Study, September 2015.

MMBbl/d14.7

13.0

11.4

9.8

8.2

6.5

4.9

3.3

1.6

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


MMBbl/d5.2

4.6

3.9

3.3

2.6

2.0

1.3

0.7

United States

U.S. SHALE NGL EURS SUPPORT LPG TRADE GROWTH


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

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

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

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

(1)

(1)(1)

POSITIVE OUTLOOK FOR LONG-TERM ETHANE MARKETS AS WELL

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

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

U.S. Ethane Exports Through 2020(2)

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

-

0.5

1.0

1.5

2.0

2.5

2012 2013 2014 2015 2016 2017 2018 2019 2020

MM

Bb/

d

Petchem Exports Rejection Total Supply (Net Stock Change)

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

-

50

100

150

200

250

300

350

2013 2014 2015 2016 2017 2018 2019 2020

MB

bl/d

Ship Pipeline

250

200

150

100

50

MB

bl/d

U.S. exports increase significantly into 2016

and 2017 as EPD’s Morgan Point Facility

comes in-service

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

Access to both Marcus Hook and the Gulf Coast is

critical to optimizing ethane

netbacks

Rejection declines significantly into 2018

Unlike LPG, 80% of ethane will be

consumed in the U.S.

Petrochem demand increases at ≈8% CAGR through 2020

-

100

200

300

400

500

600

2012 2013 2014 2015 2016 2017 2018 2019 2020

MB

bl/d

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

No Northeast rejection after 2017

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Northeast Ethane

Rejection

Exports

U.S. PetChem

LTM ProductionNTM Production ForecastAverage LTM Production

MAINTENANCE CAPITAL METHODOLOGY• Maintenance Capital Calculation Methodology – Low Pressure Gathering

– Estimate the number of new well connections needed during the forecast period in order to offset the natural production decline and maintain the average throughput volume on our system over the LTM period

– (1) Compare this number of well connections to the total number of well connections estimated to be made during such period, and

– (2) Designate an equal percentage of our estimated low pressure gathering capital expenditures as maintenance capital expenditures

Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our operating capacity or revenue

• Illustrative Example

LTM Forecast Period

Decline of LTM average throughput to be replaced with production volume

from new well connections

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• Maintenance Capital Calculation Methodology – Fresh Water Distribution− Estimate the number of wells to which we would need to distribute fresh water during the forecast period in order to maintain

the average fresh water throughput volume on our system over the LTM period− (1) Compare this number of wells to the total number of new wells to which we expect to distribute fresh water during such

period, and− (2) Designate an equal percentage of our estimated water line capital expenditures as maintenance capital expenditures

ANTERO RESOURCES EBITDAX RECONCILIATION

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EBITDAX Reconciliation

($ in millions) Quarter Ended LTM Ended3/31/2016 3/31/2016

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

ANTERO MIDSTREAM EBITDA RECONCILIATION

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EBITDA and DCF Reconciliation

$ in thousandsThree months ended

March 31,2015 2016

Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow: Net income $32,327 $42,918Add:

Interest expense 1,586 3,461Depreciation expense 20,702 23,823Contingent acquisition consideration accretion - 3,396Equity-based compensation 5,779 5,972

Adjusted EBITDA $60,394 $79,570

Pre-Water Acquisition net income attributed to parent (16,679) -

Pre-Water Acquisition depreciation expense attributed to parent (6,120) -

Pre-Water Acquisition equity-based compensation expense attributed to parent (1,156) -

Pre-Water Acquisition interest expense attributed to parent (763) -

Adjusted EBITDA attributable to the Partnership 35,676 79,570

Less:

Cash interest paid - attributable to Partnership (579) (3,444)Cash reserved for payment of income tax witholding upon vesting of Antero Midstream LP equity-basedcompensation awards - (1,000)

Maintenance capital expenditures attributable to Partnership (2,408) (5,808)

Distributable Cash Flow $32,689 $69,318

CAUTIONARY NOTE

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

Actual quantities that may be ultimately recovered from Antero’s interests may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery include the scope of Antero’s ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates.

In this presentation:

• “3P reserves” refer to Antero’s estimated aggregate proved, probable and possible reserves as of December 31, 2015. The SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.

• “EUR,” or “Estimated Ultimate Recovery,” refers to Antero’s internal estimates of per well hydrocarbon quantities that may bepotentially recovered from a hypothetical future well completed as a producer in the area. These quantities do not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules.

• “Condensate” refers to gas having a heat content between 1250 BTU and 1300 BTU in the Utica Shale.

• “Highly-rich gas/condensate” refers to gas having a heat content between 1275 BTU and 1350 BTU in the Marcellus Shale and 1225 BTU and 1250 BTU in the Utica Shale.

• “Highly-rich gas” refers to gas having a heat content between 1200 BTU and 1275 BTU in the Marcellus Shale and 1200 BTU and 1225 BTU in the Utica Shale.

• “Rich gas” refers to gas having a heat content of between 1100 BTU and 1200 BTU.

• “Dry gas” refers to gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.

Regarding Hydrocarbon Quantities

55

Am website presentation (a) june 2016

Investor Relations

Transcript of Am website presentation (a) june 2016