Am website presentation october 2016

Partnership OverviewOctober 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 SEPTEMBER 2016 PRESENTATION

Updated AR slides showing improving well economics based on 9/30/2016 strip pricing and lower well costs Slides 6, 19

Updated AR slide showing 3Q 2016 operational performance and declining development costs Slide 4

Updated AR slide showing 6/30/2016 balance sheet pro forma for recent transactions Slide 24

491

638597

744

0100200300400500600700800900

1,000

Dedicated Acreage:Gathering & Compression

Dedicated Acreage:Water Services

ANTERO RESOURCES ACQUISITION BENEFITS AM

Antero Midstream Buildout

Compressor Station – In service

Districts with 3,000+ Antero Net Acres

Acquisition 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 9/30/2016

Fresh Water ImpoundmentExisting Fresh Water LinePlaned Fresh Water Line

Planned Gathering Line –Acquisition Acreage

Compressor Station – Planned on Acquisition Acreage

Antero Resources recently closed the acquisition of 66,500 net acres in the southwestern Marcellus Shale, over 95% of which will be dedicated to AM for gathering, compression, processing, and water services

Antero Resources’ 2017 production growth target of 20% to 25% provides 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 ~$3.2 billion(1)

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

– Additional adjacent third-party midstream opportunities

3

Marcellus ShaleUtica Shale OhioOperating Highlights Top 20 best drilling footage days in

Marcellus since 2009 have all occurred in 2016, including 7,274’ drilled in 24 hours in West Virginia on the Hunter 1H

Currently completing longest lateral in company history at 14,024 feet

Stayed within targeted zone for 98% of lateral length of all wells drilled in Q3 2016

Increased sand placement during completions to 99% in Q3 2016

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

Utilizing zipper fracs to increase frequency to 7 to 8 stages per day

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.

4

CONTINUOUS OPERATING IMPROVEMENTS BY AR

Utica Marcellus2014 2015 Q3 2016 Q3 2016 vs. 2014 2014 2015 Q3 2016 Q3 2016 vs. 2014

Activity LevelsAverage Rigs Running 4 5 1 (75%) 14 9 5 (64%)Average Completion Crews 2.0 3.0 1.0 (50%) 5.5 2.0 3.0 (45%)

Operational ImprovementsDrilling Days 29 31 16 (45%) 29 24 14 (53%)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 5.0 56% 3.2 3.5 4.5 41%

Well Cost & Performance ImprovementsD&C per 1,000' of lateral ($MMs) $1.55 $1.36 $1.01 (35%) $1.34 $1.18 $0.86 (36%)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 2.4 33%Net development cost (F&D) per Mcfe (2)(3) $1.28 $0.94 $0.70 (46%) $0.88 $0.73 $0.42 (52%)

32 32 3234

3639

4440

20

25

30

35

40

45

50

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 2016E

Bar

rels

of W

ater

Per

Fo

ot o

f Lat

eral

1,146 1,012 999

1,235 1,412

1,603 1,672 1,650

- 200 400 600 800

1,000 1,200 1,400 1,600 1,800 2,000

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 2016E

Sand

Pla

ced

Per F

oot o

f La

tera

l

5

AR Has Increased Proppant Load by over 33% in the Marcellus and Utica

Pilot Testing Demonstrated Improved Recoveries While

Maintaining Well Density

New AR Marcellus Completion Designs Utilizing 38 to 45 Barrels of Water Per Lateral Foot, a 19% to 41% Increase

New AR completion designs result in more water utilization driving higher AM fees, while increased proppant generating encouraging results with potential long-term benefits to AM

ADVANCED COMPLETIONS DRIVE INCREASED WATER VOLUMES

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): $7.8 $7.8 $7.8 $7.8 $7.8 $7.8Wellhead Bcf/1,000’ 1.7 2.0 2.3 1.7 2.0 2.3Processed Bcfe/1,000’: 2.3 2.7 3.1 2.1 2.5 2.8Net F&D ($/Mcfe): $0.44 $0.38 $0.33 $0.49 $0.42 $0.36Pre-Tax NPV10 ($MM): $11.5 $15.0 $18.4 $7.4 $10.1 $12.8Pre-Tax ROR: 58% 78% 100% 38% 50% 65%Payout (Years): 1.5 1.1 0.9 2.2 1.6 1.3Breakeven NYMEX Gas Price ($/MMBtu)(5) $1.15 $0.89 $0.70 $1.96 $1.71 $1.51

Gross 3P Locations(3): 557 1,052

$11.5 $15.0 $18.4

$7.4$10.1 $12.8

58%78%

100%

38% 50%65%

0%20%40%60%80%100%

-$1.0$2.0$5.0$8.0

$11.0$14.0$17.0$20.0

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

6

Assumptions Natural Gas – 9/30/2016 strip Oil – 9/30/2016 strip NGLs – 37.5% of Oil Price

2016; ~50% of Oil Price 2017+

45/8435/24

2016/2017 Development Plan: Completions

1. 9/30/2016 pre-tax well economics based on a 9,000’ lateral, 9/30/2016 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. Assumes ethane rejection.

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 Marcellus well locations as of 12/31/2015 adjusted for 6/30/2016 net acreage and pro forma for recent acreage acquisition.4. Represents actual results for first nine months of 2016. 5. Breakeven price for 15% pre-tax rate of return.

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

Bcfe/1,000’

36% lower well cost per 1,000’ lateral and 33% higher EUR per 1,000’ since 2014 are driving rates of return significantly higherdespite lower strip pricing

MARCELLUS WELL ECONOMICS – UPSIDE POTENTIAL

NYMEX($/MMBtu)

WTI($/Bbl)

C3+ NGL(2)

($/Bbl)

2016 $3.02 $49 $222017 $3.09 $51 $252018 $2.91 $53 $272019 $2.81 $55 $282020 $2.84 $56 $292021-25 $3.26 $59 $30

ANTERO MIDSTREAM EXERCISES STONEWALL OPTION

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

●DTE recently announced the acquisition of Momentum and Vega’s 55% interest in Stonewall resulting in a change of operator from Momentum to DTE upon closing

●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 ~900 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 7

Stonewall Gathering Pipeline Asset Details

WHY OWN ANTERO MIDSTREAM?

8

Best-in-class distribution growth guidance of 30% in 2016 and 28% to 30% target for 2017 Strong DCF coverage of 1.7x in 2Q16 and 1.5x 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

$3.9 billion of consolidated pro forma liquidity; stable leverage through the down cycle Ba2/BB corporate ratings affirmed; $4.5 billion AR borrowing base affirmed 86% of targeted production hedged through 2019 at $3.72/MMBtu Peer leading realized prices and EBITDAX margins

Identified organic investment opportunity set of $3.2 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

~$900 million of liquidity and 2.4x debt to EBITDA ratio at June 30, 2016 pro forma

20% 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 61% LP ownership in AM, resulting in direct alignment with midstream value creation

$0.170 $0.180 $0.190 $0.205

$0.235 $0.250

$0.265 1.1x

1.2x1.3x

1.4x

1.8x

1.6x1.7x

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 2Q16A 3Q16A 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E

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

$0.220

9

• Antero Midstream is targeting 28% to 30% annual distribution growth through 2017• AM has delivered on 28% to 30% distribution growth while maintaining DCF coverage

of 1.7x in the second quarter 2016

Note: Future distributions subject to AM Board approval. Assumes midpoint of target distribution growth range.

TOP TIER DISTRIBUTION GROWTH AND COVERAGE

Sustainable Business

Model

High Growth Sponsor Drives AM Throughput

Growth

Largest Dedicated Core Liquids-Rich Acreage Position in Appalachia

~$900 Million ofAM Liquidity

10

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

0

500

1,000

1,500

2,000

2,500

3,000

3,500

-

100

200

300

400

500

600

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

Core Net Acres - Dry

Core 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

0200400600800

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

EQT AR CHK COG RRC SWN CNX

SPONSOR STRENGTH – LEADERSHIP IN APPALACHIAN BASIN

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

Pro forma for AR announced acreage acquisition.

(3)

11

2nd Largest Appalachian Producer in

2Q ‘16

Appalachian Peers

8th Largest U.S. Gas Producer in

2Q ‘16

Largest Proved Reserve Base In

Appalachia Antero 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 and the U.S.

$198 $341

$434

$649

$1,164 $1,221

$1,394

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

2010 2011 2012 2013 2014 2015 2016E

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

2010 2011 2012 2013 2014 2015 2016E

NGLs (C3+) Oil Ethane

5 2466,436

23,051

48,298

73,000

51% GrowthGuidance

1. Represents midpoint of updated 2017 production guidance of 20% to 25% per press release dated 6/9/2016. 2. Represents Bloomberg street consensus estimates as of 9/30/2016.

1,800

2,205

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

12

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)

20% Growth

Guidance

23% GrowthTarget(1)

Antero is in the unique position of sustaining 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 recent acreage acquisition announced per press release dated 6/9/2016, updated for exercise of tag along right. 3P reserve additions are unaudited. 14 to 18 Tcf Utica dry resource in WV/PA. 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. $1.5 billion 3P PV-10 unaudited estimate for recent acreage acquisition, using 12/31/2015 strip pricing and same year end 2015 assumptions. Strip pre-tax PV-10 is a non-GAAP financial measure. The standardized measure was $3.2 billion as of 12/31/2015.

3. Virtually all WV/PA Utica Shale net acres are included among the net acres of Marcellus Shale rights as they are stacked pay formations attributable to the same leasehold. 13

AR COMBINED TOTAL – 12/31/15 RESERVESAssumes Ethane RejectionNet Proved Reserves 13.2 TcfeNet 3P Reserves(1) 42.1 TcfeStrip Pre-Tax 3P PV-10(2) $12.7 BnNet 3P Reserves & Resource(1) 57 to 60 TcfeNet 3P Liquids(1) 1,377 MMBbls% Liquids – Net 3P(1) 20%2Q 2016 Net Production 1,762 MMcfe/d- 2Q 2016 Net Liquids 75,041 Bbl/dNet Acres(1)(3) 641,000Undrilled 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 147,000Undrilled 3P Locations 814

MARCELLUS SHALE CORE

Net Proved Reserves 11.4 TcfeNet 3P Reserves(1) 34.6 TcfeStrip Pre-Tax 3P PV-10(2) $10.2 BnNet Acres(1) 494,000Undrilled 3P Locations(1) 3,530

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

SPONSOR STRENGTH – MOST ACTIVE OPERATOR

Gas74%

1,762 MMcfe/d

C3+18%

Oil2%

2Q 2016 Production

C26%

Condensate, 5%

Highly-Rich Gas/Condens

ate(8%)

Highly-Rich Gas33%

Rich Gas, 20%

Dry Gas, 34%

Highly-Rich Gas/Condensate

8%

110

050

100150200250300350400

2016E 2017E 2018E 2019E 2020E

Ann

ual C

ompl

etio

ns

Marcellus Completions Ohio Utica Completions

SPONSOR STRENGTH – SIGNIFICANT SPONSOR DRILLING INVENTORY TO DRIVE VALUE FOR ANTERO MIDSTREAMAntero plans to develop over 1,000 horizontal locations in the Marcellus and Ohio Utica by the end of the decade while utilizing less than 25% of its current 3P drilling inventory

PLANNED ANTERO WELL COMPLETIONS BY YEAR

CURRENT UNDRILLED 3P LOCATIONS BY BTU REGIME (1) ESTIMATED YE 2020 UNDRILLED 3P LOCATIONS

4,344 Locations ~3,300 Locations YE 2020

Expect to place >1,000 Marcellus and Utica wells

to sales by YE 2020

Condensate4%

Highly-Rich Gas29%Rich Gas

20%

Dry Gas28%

Highly-Rich Gas/Condensate

19%

1. Marcellus and Utica 3P locations pro forma for recent acreage acquisition announced 6/9/2016. Excludes WV/PA Utica Dry locations.

Average Lateral Length ~8,800 feet

14

38% to 62% IRRs

17% to 49% IRRs

58% to 66% IRRs 19% to 44%

IRRs

21%

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

$28$36 $41

$55

$83 $80$88

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

$100

26 31 40 36 41 116

222

358

454 435478

606 657

0

100

200

300

400

500

600

700

800Utica Marcellus

10 38 80 126 266

531

908

1,134 1,197 1,216 1,195 1,222 1,253

0200400600800

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

108 216 281 331 386

531

738 935

965 1,038 1,124

1,303 1,353

0200400600800

1,0001,2001,4001,6001,800

Utica Marcellus

Low Pressure Gathering (MMcf/d)

Compression (MMcf/d)

High Pressure Gathering (MMcf/d)

EBITDA ($MM)

15

$375

Note: Y-O-Y growth based on 2Q’15 to 2Q’16.1. Represents midpoint of updated 2016 guidance.

GROWTH – HIGH GROWTH MIDSTREAM THROUGHPUT

$215

GROWTH – ORGANIC GROWTH STRATEGY DRIVES VALUE CREATION

16

• 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 and $45 million acquisition of Stonewall pipeline interest)

– 5-year identified investment opportunity set of $3.2 billion through 2020

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 6/1/2014. Drop down multiples are based on NTM EBITDA. Source: Barclays.

5.0x

10.0x9.6x 9.5x 9.5x 9.4x 9.3x

9.0x 8.8x 8.7x 8.7x 8.6x 8.6x 8.6x 8.5x 8.3x

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

$3.2 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% 15%

35%

25%

20%

35%

25% 25%

40%

20%

0%

10%

20%

30%

40%

Inte

rnal

Rat

e of

Ret

urn

17

Project Economics by Segment(1)

GROWTH – ESTIMATED PROJECT ECONOMICS BY SEGMENT

1. Based on management capex, operating cost and throughput assumptions by project. 2. Excludes $25.0 million of maintenance capex. Includes Stonewall option exercise.

Wtd. Avg. 21% IRR

AM Option Opportunities

35%

Source: Core outlines and peer net acreage positions based on investor presentations, news releases and 10-K/10-Qs. Rig information per RigData as of 7/22/2016.1. Based on company filings and presentations. Peers include: Ascent, CHK, CNX, CVX, ECR, EQT, GPOR, NBL, REX, RRC and SWN.

• Pro forma for the recent acreage acquisition, Antero controls an estimated 39% 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 in its 3P reserves as of 12/31/2015, pro forma for the pending acreage acquisition

0

100

200

300

400

500

(000

s)

Core Liquids-Rich Net Acres(1)

18

Incremental core liquids-rich acreage included in pending acquisition

LIQUIDS-RICH – LARGEST CORE DRILLING INVENTORY

$1.55$1.36

$0.99

$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


664 1,235

691 940

76%

53%

24% 28%58%

38%

15% 17% 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 @ 9/30/2016 Strip Pricing - After Hedges ROR @ 9/30/2016 Strip Pricing - Before Hedges

184

98 108 161

263

27%

93% 98%80% 76%

24%

74% 66%50%

42%

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)(3)

Marcellus Well Cost Improvement(4)

1. 9/30/2016 pre-tax well economics based on 1.7 Bcf/1,000’ type curve for Marcellus 9,000’ lateral, 9/30/2016 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 @ 9/30/2016 Strip-With Hedges reflects 9/30/2016 well cost ROR methodology, with the 9/30/2016 hedge value allocated based on 2016-2021 projected production volumes resulting in blend of strip and hedge prices.

3. Marcellus undeveloped well locations as of 12/31/2015 adjusted for 6/30/2016 net acreage and pro forma for third-party acreage acquisition per press release dated 6/9/2016. 4. Current spot well costs based on $7.8 million for a 9,000’ lateral Marcellus well and $8.9 million for a 9,000’ lateral Utica well.

19

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

Antero has reduced average well costs for a 9,000’ lateral by 36% in the Marcellus and 35% in the Utica as compared to 2014 well costs At 9/30/2016 strip pricing, Antero has 2,713 locations that exceed a 20% rate of return (excluding hedges)

– Including hedges, these locations generate rates of return of approximately 27% to 98%

Utica Well Cost Improvement(4)

$1.34$1.18

$0.86

$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)



SUSTAINABLE BUSINESS MODEL – HEDGES BOLSTER SOLID WELL ECONOMICS

20

In-service 2016 Budget

HIGH VISIBILITY – PROJECTED MIDSTREAM BUILDOUT

Utica Marcellus

- 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

Jul-1

4S

ep-1

4N

ov-1

4Ja

n-15

Mar

-15

May

-15

Jul-1

5S

ep-1

5N

ov-1

5Ja

n-16

Mar

-16

May

-16

Jul-1

6S

ep-1

6N

ov-1

6Ja

n-17

Mar

-17

May

-17

Jul-1

7S

ep-1

7N

ov-1

7Ja

n-18

Mar

-18

May

-18

Jul-1

8S

ep-1

8N

ov-1

8Ja

n-19

Mar

-19

May

-19

Jul-1

9S

ep-1

9N

ov-1

9Ja

n-20

Mar

-20

May

-20

Jul-2

0S

ep-2

0N

ov-2

0

21

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 pricing in line with Nymex gas prices year-to-date in 2016, 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

Gross Gas Production (BBtu/d) 2017 Production Target: 20 – 25%(1)

1. Per press release dated 09/06/16.

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$0

$50

$100

$150

$200

$250

$300

$350

$MM

22

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 $2.4 billion of gains on commodity hedges since 2009

– Gains realized in 29 of last 30 quarters, or 97% of the quarters since 2009● Based on Antero’s hedge position and strip pricing as of 6/30/2016, the unrealized commodity derivative value is $2.1 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 06/30/16

3.4 Tcfe Hedged at average price of

$3.71/Mcfe through 2022

Average Hedge Prices ($/MMBtu)

$3.36

$3.96

$3.57$3.91

$3.70 $3.66$3.24

$2.1 Billion in Projected Hedge

Gains Through 2022Realized $2.4 Billion in Hedge Gains

Since 2009

HEDGING – INTEGRAL TO BUSINESS MODEL

(1)

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

Regional Gas Pipelines – 15% Ownership

Miles Capacity In-Service

Stonewall Gathering Pipeline(3)

67 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 pro forma for pending third-party acreage acquisition.3. Antero Midstream owns 15% ownership in Stonewall pipeline.

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.)

23

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 $5.0 Bnsignificantly exceeds total debt of $3.7 billion pro forma for private placement

Pro Forma Liquidity

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

Pro Forma 6/30/2016 Debt Liquid Non-E&P Assets Pro Forma 6/30/2016 Debt (4) Liquid Assets

Debt Type $MMCredit facility $353

6.00% senior notes due 2020 525

5.375% senior notes due 2021 1,000

5.125% senior notes due 2022 1,100


Total $3,728

Asset Type $MMCommodity derivatives(1) $2,096

AM equity ownership(2) 2,892

Cash 19

Total $5,007

Asset Type $MMCash $19

Credit facility – commitments(3) 4,000

Credit facility – drawn (353)

Credit facility – letters of credit (708)

Total $2,958

Debt Type $MMCredit facility $120


Total $770


Total $9

Pro Forma Liquidity


Credit facility – capacity 1,020

Credit facility – drawn (120)

Credit facility – letters of credit -

Total $909

Approximately $3.0 billion of liquidity at AR pro forma for private placement plus an additional

$2.9 billion of AM units

Over $900 million of liquidity at AM pro forma for senior notes offering

24

Only 12% of AM credit facility capacity drawn pro forma for recent $650 million senior notes offering

Note: All balance sheet data as of 6/30/2016. Antero Resources pro forma for $175 million private placement and $518 million cost for recent acreage acquisition. 1. Mark-to-market as of 6/30/2016.2. Based on AR ownership of AM units and closing price as of 9/30/2016.3. AR credit facility commitments of $4.0 billion, borrowing base of $4.5 billion. 4. Pro forma for $650 million senior notes offering on 9/8/2016 with net proceeds used to repay the credit facility.

LIQUIDITY – STRONG BALANCE SHEET AND FLEXIBILITY

2.4x

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

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

Tota

l Deb

t / L

TM E

BIT

DA

• $1.5 billion revolver in place to fund future growth capital (5.0x Debt/EBITDA Cap)

• Liquidity of $909 million at 6/30/2016 pro forma for $650 million senior notes offering as of 9/8/2016

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

• AM corporate debt ratings also Ba2/BB

Pro Forma AM Liquidity (6/30/2016)

AM Peer Leverage Comparison(2)

($ in millions)

Revolver Capacity $1,020

Less: Borrowings(1) 120

Plus: Cash 9

Liquidity $909

1. Pro forma for $650 million senior notes offering as of 9/8/2016 with net proceeds used to repay credit facility. 2. As of 6/30/2016. Peers include TEP, EQM, WES, RMP, SHLX, DM, and CNNX.3. AM includes full year EBITDA contribution from water business.

Financial Flexibility

25

(3)

STRONG FINANCIAL POSITION – SIGNIFICANT FINANCIAL FLEXIBILITY

TOP TIER DISTRIBUTION GROWTH & HEALTHY COVERAGE

26

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

1. Based on Bloomberg 2016-2018 Bloomberg consensus estimates as of 9/30/2016.

29%26%

24% 23% 23% 22%20% 19%

13% 12%8%

1.5x

1.2x

1.9x

1.4x

1.3x 1.2x

1.6x

1.5x1.4x

1.3x1.2x

0.0x

0.2x

0.4x

0.6x

0.8x

1.0x

1.2x

1.4x

1.6x

1.8x

2.0x

0%

5%

10%

15%

20%

25%

30%

35%

40%

SHLX AM VLP PSXP DM TEP RMP EQM CNNX MPLX WES

Distribution Growth DCF Coverage Ratio

Antero Midstream (NYSE: AM)Asset Overview

27

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

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 ~278,000 gross acres of Utica deep rights underlying the Marcellus in WV and PA

– 100% fixed fee long term contracts

• AR owns 61% of AM units (NYSE: AM)

Acquisition Acreage

28

ANTERO MIDSTREAM ASSETS – RICH GAS MARCELLUS

• Provides Marcellus gathering and compression services

− Liquids-rich gas is delivered to MPLX’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 over 2,000 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

Acquisition Acreage

29

• Provides Utica gathering and compression services− Liquids-rich gas delivered into MPLX’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

30

ANTERO MIDSTREAM WATER BUSINESS OVERVIEW

Note: 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 38 barrels of water per lateral foot 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 34 barrels of water per lateral foot that utilize the fresh water delivery system based on 9,000 foot lateral. Water volumes assume 5% recycling. 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 -$1,050k

$825k -$925k

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

31

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 build the largest advanced wastewater treatment complex in the world for oil and gas produced water

• Veolia will build and operate, and Antero will fund and own the Clearwater facility− Will treat and recycle AR produced and flowback water− Creates additional year-round water source for completions− Will have capacity for significant third party business

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

Integrated 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

Capacity for third party business

32

ANTERO CLEARWATER FACILITY UPDATE

Antero Clearwater Facility – September 2016

Antero Clearwater advanced wastewater treatment facility is on schedule to be placed on line in late 2017‒ 2016 capital budget includes $130 million to be invested in 2016‒ Approximately 75% of total $275 million project cost invested by year-end 2016

Trucking bays

Crystallizers

Grit removal and pre-treatment

Crystallizer feed tank

Solids removal

33

AM UPSIDE OPPORTUNITY SET

34

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• 278,000 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• 66,500 net acre acquisition announced by AR substantially

undedicated for gathering, compression, processing and water services

• Future acreage acquisitions by AR are dedicated to AM

PROCESSING – VALUE CHAIN POTENTIALFOR UNDEDICATED ACREAGE

SherwoodProcessing

Complex

Processing Area Of Dedication for AM

MarkWest Processing AOD – 192,000 Gross

Acres

Tyler County94,000 Gross Acres

Ritchie County53,000 Gross Acres

Gilmer County14,000 Gross Acres

Wetzel County57,000 Gross Acres

Pleasants County7,000 Gross Acres

AR Gross Processble

Acres (1)

AR C3+ 3P Reserves

(MMBbls)(2)

AR 3P Gross

Wellhead Gas (Tcf)

Total 225,000 1,022 21.4

Antero Resources has over 21 Tcf of processable gross 3P gas reserves and 1.0 billion Bbls of gross 3P NGL reserves across 225,000 gross processable Marcellus acres that are dedicated to Antero Midstream for processing

1. Gross Processable Acres defined as acres with expected Btu greater than 1,1002. Antero gross 3P C3+ NGL volumes and 3P Gross Wellhead Gas reserves as of 12/31/2015 including AR announced acreage acquisition. Gross acres as of 9/30/2016.

Undedicated Acreage

35

LARGE UTICA SHALE DRY GAS POSITION

36

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

Antero has 285,000 net acres of exposure to Utica dry gas play in OH, WV and PA pro forma

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

Big 190 EQT 31.3 6,335 4.941

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 1906,335’ Lateral


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

37

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; • 20% production growth guidance for 2016 supported by $1.4 billion

capital budget, firm processing and takeaway, long-term natural gas hedges and $3.8 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

• $3.2 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

38

Key VariableUpdated

2016 Guidance(1)Previous

2016 Guidance

Financial:

Net Income ($MM) $205 - $225 $165 - $190

Adjusted EBITDA ($MM) $365 - $385 $325 - $350

Distributable Cash Flow ($MM) $315 - $335 $275 - $300

Year-over-Year Distribution Growth 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 $45 $45

Maintenance Capital $25 $25

Total Capital Expenditures ($MM) $480 $480

ANTERO MIDSTREAM – UPDATED 2016 GUIDANCEKey Operating & Financial Assumptions

1. Updated guidance per press release dated 09/06/2016. 39

2016 UPDATED CAPITAL BUDGET

By Area

40

$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 VariableUpdated

2016 Guidance(1)Previous

2016 Guidance

Net Daily Production (MMcfe/d) 1,800 1,750

Net Residue Natural Gas Production (MMcf/d) 1,365 1,355

Net C3+ NGL Production (Bbl/d) 53,500 52,500

Net Ethane Production (Bbl/d) 15,000 10,000

Net Oil Production (Bbl/d) 4,500 3,500

Net Liquids Production (Bbl/d) 73,000 66,000

Natural Gas Realized Price Premium to NYMEX Henry Hub Before Hedging ($/Mcf)(2)(3) +$0.00 to $0.05 +$0.00 to $0.10

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

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

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

Operating:Cash Production Expense ($/Mcfe)(4) $1.40 - $1.50 $1.50 - $1.60

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

G&A Expense ($/Mcfe) $0.20 - $0.22 $0.20 - $0.25

Operated Wells Completed 110 110

Drilled Uncompleted Wells 70 70

Average Operated Drilling Rigs ≈ 7 ≈ 7

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

Land $100 $100

Total Capital Expenditures ($MM) $1,400 $1,400

1. Updated guidance per press release dated 09/06/2016. 2. Based on current strip pricing as of August 30, 2016.

Key Operating & Financial Assumptions

3. Includes Btu upgrade as Antero’s processed tailgate and unprocessed dry gas production is greater than 1000 Btu on average. 4. Includes lease operating expenses, gathering, compression and transportation expenses and production taxes.

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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 and T2 in-service)Lake Charles LNG(3)

150 MMcf/dFreeport LNG

70 MMcf/d

1. November 2016 and full year 2017 futures basis, respectively, provided by Intercontinental Exchange dated 9/30/2016. Favorable markets shaded in green. 2. Shell announced final investment decision (FID) on 6/7/2016.3. Lake Charles LNG 150 MMcf/d commitment subject to Shell FID.

Chicago(1)

$0.05 / $0.03

CGTLA(1)

$(0.06) / $(0.06)

TCO(1)

$(0.19) / $(0.18)

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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, for 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

Expect NYMEX-plus pricing per

Mcf

Antero Commitments

(3)

(2)

Dom South(1)

$(1.79) / $(1.20)

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

0

500

1,000

1,500

2,000

2,500

2Q16 Actual 2016 Guidance 2017 Target

Gro

ss W

ellh

ead

Gas

Pro

duct

ion

(MM

cf/d

)AM VOLUME THROUGHPUT VS. AR PRODUCTION

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1,755 MMcf/d

Third Party Gathering:402 MMcf/d

AM Compression Capacity

@ YE 2016:1,060 MMcf/d

AM Compression Capacity

@ YE 2017:1,420 MMcf/d

AM Compression: 658 MMcf/d

(80% Utilization)

AM LP: 1,353 MMcf/d(78% of AR Gross Wellhead Volume)

AR does not expect material growth in third party gathered

volumes through 2017

Third Party Gathering

Third Party Gathering

AM HP: 1,253 MMcf/d(93% of LP

Volume)

1,783 MMcf/d

2,184 MMcf/d

AR Gross Wellhead Gas Production (Including 3rd Party Gathering) Antero Midstream Volumes

• AM continues to gather and compress an increasing percentage of the total gross gas production

1. Assumes 3% fuel.

AM Compression Capacity:

820 MMcf/d

Production/Throughput Reconciliation (MMcf/d) 2Q16 AR Net Gas Production 1,311

Net Revenue Interest Gross-Up 80%Average Processing Shrink Gross-Up 94%

AR Gross Gas Production (MMcf/d) 1,755 - Third Party LP Gathering Volumes 402 = AM LP Gathering Volumes 1,353 - Fuel/Third Party HP Gathering Volumes(1) 7% = AM HP Gathering Volumes 1,253

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96 MVC90

MVC100

MVC120

MVC120

0

20

40

60

80

100

120

140

160

180

200

2014 2015 2016 2017 2018 2019 2020

MB

bl/d

2017 MVC2017-2019 Earnout

Fresh Water Volumes (MBbl/d) 100 161Fresh Water Volumes (MBbls) 36,500 58,765

Volumes per Well Completion (MBbls)(2) 345 345Implied Well Completions (Annual) 105 170

SUSTAINABLE WATER BUSINESS GROWTH

451. Includes 70 deferred completions.2. Assumes 9,000 foot lateral and 39 Bbl/ft and 34 Bbl/ft of water for Marcellus and Utica, respectively.

Deferred completions drive substantial growth in 2017 and beyond, underpinned by minimum volume commitments

177

Com

plet

ions

~ 11

0 C

ompl

etio

ns(G

uida

nce)

2020 Earn Out – 200 MBbl/d Avg

131

Com

plet

ions

170-

180

Com

plet

ions

Targ

eted

(1)

Fresh Water Delivery Volumes (MBbl/d)“Traditional” Completions “Advanced” Completions

utilizing 25% more water

2017 targeted activity implies 155-165 MBbl/d of delivered water

2019 Earn Out – 161 MBbl/d Avg

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 Ended6/30/2016 6/30/2016

EBITDAX:Net income including noncontrolling interest $(575.5) $155.5Commodity derivative fair value (gains) 684.6 (1,219.5)Net cash receipts on settled derivatives instruments 292.5 1,092.7Interest expense 62.6 247.2Income tax expense (benefit) (376.5) 41.0Depreciation, depletion, amortization and accretion 198.0 741.4Impairment of unproved properties 19.9 104.9Exploration expense 1.1 4.0Equity-based compensation expense 25.8 91.8Equity in earnings of unconsolidated affiliate (0.5) (0.5)Contract termination and rig stacking 0.0 27.6Consolidated Adjusted EBITDAX $332.1 $1,286.1

ANTERO MIDSTREAM EBITDA RECONCILIATION

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EBITDA and DCF Reconciliation

$ in thousandsSix months ended

June 30,2015 2016

Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow: Net income $67,451 $92,829

Interest expense 3,222 7,582Depreciation expense 41,955 47,963Accretion of contingent acquisition consideration - 6,857Equity-based compensation 12,376 12,766Equity in earnings from unconsolidated affiliate - (484)

Adjusted EBITDA $125,004 $167,513

Pre-Water Acquisition net income attributed to parent (32,353) -

Pre-Water Acquisition depreciation expense attributed to parent (12,282) -

Pre-Water Acquisition equity-based compensation expense attributed to parent (2,365) -

Pre-Water Acquisition interest expense attributed to parent (1,556) -

Adjusted EBITDA attributable to the Partnership 76,448 167,513

Cash interest paid - attributable to Partnership (1,177) (7,708)Cash reserved for payment of income tax witholding upon vesting of Antero Midstream LP equity-basedcompensation awards - (2,000)

Cash to be received from unconsolidated affiliate - 778Maintenance capital expenditures attributable to Partnership (5,787) (11,518)

Distributable Cash Flow $69,484 $147,065

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

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Am website presentation october 2016

Investor Relations

Transcript of Am website presentation october 2016