am website presentation february 2015

Partnership OverviewFebruary 2015

FORWARD-LOOKING STATEMENTS

This 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”). These statements are based on certain assumptions made by the Partnership and Antero 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.

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’s 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 ofproduction, cash flow and access to capital, the timing of development expenditures, and the other risks discussed in the registration statement on Form S-1 (No. 333-193798) filed by the Partnership under the heading “Risk Factors.”

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 – A GROWTH FOCUSED MLP

2

• AM sponsor is the most active operator in Appalachia• Highest recycle ratio and low F&D cost supports sponsor production growth expectations• Sponsor maintains strong liquidity and significant hedging position• Highly incentivized to maximize value of AM to support AR growth

• Midstream assets located in lowest cost per Mcfe rich gas plays in North America• ~80% of midstream “footprint” is associated with rich gas production• Substantial AR and third-party future infrastructure required• Gathering and compression provide core asset portfolio with additional option to

expand into freshwater distribution and regional pipelines

• Pure play, fee-based midstream MLP with top tier growth rate• Cash flows are supported by 20-year, fee-based agreements with AR• “Best in class” anchor tenant with 92% net production growth in 2014 and 40%

growth projected for 2015• Growth not dependent on drop-downs, 3rd party business or acquisitions for growth

• Consolidated Marcellus and Utica rich gas acreage dedications• Multiple gathering and compression, processing, pipeline and other expansion

opportunities• Option to acquire AR Fresh Water Distribution system

• Antero Midstream MLP had no leverage at IPO closing plus $250 million cash • $1 billion of undrawn borrowing capacity commitments and $230 million of cash at

12/31/2014• Good high yield access with “Ba3/BB” rated parent (corporate ratings)• Structured to pursue organic growth opportunities

PremierE&P Sponsorship1

“Pure Play” Marcellus/UticaMidstream MLP

2

Top Tier MLP Organic Growth3

Appalachian Midstream Value Chain Opportunity

4

Stacked-Pay Basin Potential Upside5

Financial Flexibility & Strong Capital Structure

6

• Stacked-pay opportunities – Utica, Marcellus, Upper Devonian• Opportunity to develop Utica Shale dry gas pipeline and compression systems in

West Virginia• Future Upper Devonian development will require existing water resource for

completions and gathering and compression systems

ANTERO MIDSTREAM – 2015 GUIDANCE

Key Variable 2015 Guidance Range

Adjusted EBITDA ($MM) $150 - $160

Distributable Cash Flow ($MM) $135 - $145

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

Low Pressure Pipelines Added (Miles) 46

High Pressure Pipelines Added (Miles) 18

Compression Capacity Added (MMcf/d) 545

Capital Expenditures ($MM)

Low Pressure Gathering $165 - $170

High Pressure Gathering $85 - $90

Compression $160 - $165

Condensate Gathering $5 - $10

Maintenance Capital $10 - $15

Total Capital Expenditures ($MM) $425 - $450

1. Financial assumptions per Partnership press release dated 1/20/2015.

Key Operating & Financial Assumptions

3

AnteroMidstream Management

ANTERO MIDSTREAM OWNERSHIP STRUCTURE

4

Antero ResourcesCorporation (NYSE: AR)

$13.0 Billion Enterprise Value(1)

Ba3/BB Corporate Rating

Antero MidstreamPartners LP (NYSE: AM)

$3.4 Billion Market Cap.(1)

Public

$1 BillionCredit Facility

Midstream Entity

PartnershipCorporation

MarcellusGathering

& Compression

UticaGathering &

Compression

Option(3)

Antero Fresh WaterDistribution System

Option

69.7% Limited Partner Interest

1. As of 1/16/2015. AR enterprise value excludes AM minority interest and cash. 2. Option to acquire up to a 15% non-operating equity interest in a new build Regional Gathering Pipeline.3. Option to acquire 100% interest at fair market value.

100% 100% 100%

Option(2)

Regional GatheringPipeline

15%

Midstream Option

1. Represents inception to date actuals as of 6/30/2014 and 2015 midpoint guidance.2. Includes $12.5 million of maintenance capex at 2015 midpoint guidance.

5

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

– Acreage dedication of ~412,000 net leasehold acres for gathering and compression services

– 100% fixed fee long term contracts

UticaShale

MarcellusShale

Projected Midstream Infrastructure(1)

Marcellus Shale

Utica Shale Total

YE 2014E Cumulative Gathering/ Compression Capex ($MM) $850 $350 $1,200

Gathering Pipelines(Miles) 153 80 233

Compression Capacity(MMcf/d) 375 - 375

Condensate Gathering Pipelines (Miles) - 16 16

YE 2015E Gathering/ Compression Capex ($MM)(2) $256 $182 $438

Gathering Pipelines (Miles) 46 18 64

Compression Capacity(MMcf/d) 425 120 545

Condensate Gathering Pipelines (Miles) - 4 4

Midstream Assets

ANTERO MIDSTREAM PARTNERS OVERVIEW

ANTERO MIDSTREAM ASSETS – RICH GAS MARCELLUS

6

• Provides Marcellus gathering and compression services − Liquids-rich gas is delivered to MWE’s Sherwood

Complex for processing• Significant growth projected over the next twelve

months as set out below:

• Antero sold the Harrison County portion of its gathering system to a 3rd party midstream company in 2012, which is now recognized as the 3rd Party Gathering and Compression Dedication area

• Development upside as AR continues to drill, step-out and add acreage

Marcellus Gathering & Compression

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

YE 2014 YE 2015

Gathering Pipelines (Miles) 153 199

Compression Capacity (MMcf/d) 375 800

WV/PA Utica Dry Gas Gathering & Compression

• Further development upside in 170,000 net acres of Utica deep rights beneath the Marcellus Shale− Will require a separate dry gas gathering system

7

• Provides Utica natural gas and condensate gathering services− Liquids-rich gas delivered into MWE’s Seneca

Complex for processing− Condensate delivered to centralized stabilization

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

months as set out below:

• Development upside as AR continues to drill, step-out and add acreage

Utica Gathering

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 2014 YE 2015

Gathering Pipelines (Miles) 80 98

Condensate Pipelines (Miles) 16 20

Compression (MMcf/d) 0 120

Utica Compression• Opportunity to build up to ten new compressor stations

that are planned to support AR development over the next several years

108

216 281 331

386

531

964

0

200

400

600

800

1,000

2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q'14 NTM9/30/15

Utica Marcellus

$1.4 $5.0 $6.8 $8.4 $11.4 $18.8

$136.2

0

20

40

60

80

100

120

140

160

2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 NTM9/30/15

EBITDA

HIGH GROWTH THROUGHPUT

Low Pressure Gathering (MMcf/d) Compression (MMcf/d)

High Pressure Gathering (MMcf/d) Antero Midstream Partners EBITDA ($MM)

1. Midstream EBITDA does not include EBITDA contribution from fresh water distribution

(1)

8

26 31 40 36 41

116

249

0

50

100

150

200

250

2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 NTM9/30/15

Marcellus

10 38 80

126

266

531

773

0

200

400

600

800

2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 NTM9/30/15

Utica Marcellus

ORGANIC GROWTH STRATEGY: “BUILD VS. BUY”

9

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

• Industry leading organic growth story

– ~$1.04 billion in estimated capital spent through 9/30/2014

– $425 million in additional growth capital forecast for the twelve-month period ending 12/31/15 (excludes $12.5 million of maintenance capital)

Note: Precedent data per IHS Herold’s research and public filings.1. Antero organic multiple calculated as estimated gathering and compression capital expended through Q3 2014 divided by 12/31/15 projected gathering and compression EBITDA assuming 12-15

month lag between capital incurred and full system utilization.2. Selected gathering and compression drop down acquisitions since 1/1/2011. Drop down multiples are based on NTM EBITDA. Source: Barclays.

6.3x

11.9x

10.7x

10.0x

9.3x9.0x 9.0x 9.0x 8.9x 8.9x 8.8x 8.6x

8.0x 7.9x

7.0x 6.9x

5.5x

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: 8.9x

Value creation for the AM unit holder =Build at 4-6x EBITDA

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

Fresh Water

Distribution(1)

Regional Gas Pipelines

Miles Capacity In-Service

Unnamed Regional Pipeline

50 1.4 Bcf/d 4Q 2015

101. Currently owned by AR; AM holds option to purchase 100% of assets at fair market value.

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 2014 YE 2015

Marcellus 91 118

Utica 45 62

Total 136 180

AM has option to participate in processing, fractionation,

terminaling and storage projects offered to AR

FULL MIDSTREAM VALUE CHAIN POTENTIAL

(Miles) YE 2014 YE 2015

Marcellus 62 81

Utica 35 36

Total 97 117

(MMcf/d) YE 2014 YE 2015

Marcellus 375 800

Utica 0 120

Total 375 920

AM Owned Assets

Condensate GatheringStabilization

(Miles) YE 2014 YE 2015

Utica 16 20

EndUsers

AM Option Assets

(Ethane, Propane, Butane, etc.)

(De-ethanization)

AM OPTION – FRESH WATER DISTRIBUTION SYSTEMS

11

Marcellus Fresh Water Distribution System• Provides fresh water to support ongoing Marcellus completion

activity • Year-round water supply sources: Ohio River and local rivers• Significant growth projected over the next twelve months as

summarized below:

Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.1. Estimated fee of $3.50 per barrel at an average of 200,000 Bbls of water per well.

Utica Fresh Water Distribution System• Provides fresh water to support ongoing Utica completion activity • Year-round water supply sources: local reservoirs and rivers• Significant growth projected over the next twelve months as

summarized below:

• Currently owned by AR – AM holds option to purchase 100% of assets at fair market value

Marcellus Water System YE 2014 YE 2015

Water Pipeline (Miles) 177 49

Fresh Water Storage Impoundments 22 24

YE 2015 Projected Wells 80

Water Fees per Well ($)(1) $600K -$800K

Utica Water System YE 2014 YE 2015

Water Pipeline (Miles) 61 29

Fresh Water Storage Impoundments

8 14

YE 2015 Projected Wells 50

Water Fees per Well ($)(1) $600K -$800K

OHIO

25%

15%

10%

25%

30%

15% 15%

35%

25%

20%

35%

25%20%

40%

0%

10%

20%

30%

40%

Inte

rnal

Rat

e of

Ret

urn

12

DRY GAS LOCATIONS RICH GAS LOCATIONS

HIGHLY RICH GAS

LOCATIONS

Project Economics by Segment(1)

ESTIMATED PROJECT ECONOMICS BY SEGMENT

LPGathering

HPGathering Compression

CondensateGathering

Water Distribution

RegionalPipeline

Processing/Fractionation

Unlevered IRR Range: 25% - 35% 15% - 25% 10% - 20% 25% - 35% 30% - 40% 15% - 25% 15% - 20% Payout (Years): 2.5 - 4.0 3.5 - 4.5 4.0 - 6.5 2.0 - 3.5 2.0 – 3.0 3.5 - 7.0 5.0 - 6.0 Minimum Volume Commitments: N/A 75% 70% N/A N/A 100% 60%

12/31/2015 Capex(2) TotalMarcellus $248.4 $72.6 $73.3 $102.5 -Utica 176.5 104.1 12.1 55.1 5.2

Expansion Capex $424.9 $176.7 $85.4 $157.6 $5.2 % of Capex 100% 42% 20% 37% 1%

Included in NTM Period: Marcellus & Utica

Marcellus & Utica

Marcellus Utica Not Included Not Included Not Included

Additional Opportunities: Dry Utica Dry Utica Rich & Dry Utica

Utica Stabilization

Drop-Downof Water

Distribution System

Regional Gathering

Pipeline

Marcellus Processing/

Fractionation1. Based on management capex, operating cost and throughput assumptions by project.2. Excludes $12.5 million of maintenance capex.

Wtd. Avg. 23% IRR

AM Option Opportunities

SIGNIFICANT FINANCIAL FLEXIBILITY

13

• Unfunded $1 billion revolver in place at time of IPO to fund future growth capital (5x Debt/EBITDA Cap)

• No leverage and $250 million of cash “post-IPO” provides significant financial flexibility

• $230 million of cash at 12/31/2014

• Sponsor (NYSE: AR) has Ba3/BB corporate ratings

AM Liquidity

AM Peer Leverage Comparison(2)

($ in millions) At IPO(1)

Revolver Capacity $1,000

Less: Borrowings -

Plus: Cash 250

Liquidity $1,250

0.0x 0.0x 0.1x

1.1x 1.3x 1.5x2.2x 2.4x

3.1x 3.1x 3.3x 3.3x4.0x 4.1x

0.0x

2.0x

4.0x

6.0x

Deb

t / L

TM E

BIT

DA

1. IPO completed on 11/10/2014. 2. Peers include ACMP, EQM, MPLX, MWE, OILT, PSXP, QEPM, RRMS, SXL, TEP, TLLP, VLP and WES.

Sources ($ in millions)

Primary IPO Proceeds $1,150

Total Sources $1,150

Uses

Proceeds to AR $843

Proceeds retained by AM 250

Fees & Expenses 57

Total Uses $1,150

Sources & Uses (11/10/2014)

Financial Flexibility

14

ANTERO MIDSTREAM MLP INVESTMENT HIGHLIGHTS

Premier E&P Sponsorship

“Pure Play” Marcellus/UticaMidstream MLP

Top Tier MLP Organic Growth

Full Midstream Value Chain Potential

Financial Flexibility & Strong Capital Structure “Best in Class”

Distribution Growth Expected

15

Antero Resources (NYSE: AR)Overview

16

Most Active Operatorin Appalachia

Most ActiveLand Organization

in Appalachia

Largest Firm Transport and Processing

Portfolio in Appalachia

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

Strong Financial Liquidity

Highest Growth Large Cap E&P

Largest Liquids-Rich Core Position in

Appalachia

Highest Realizations and Margins Among

Large Cap Appalachian Peers

Growth Land

Liquidity

Midstream

Drilling

LEADING UNCONVENTIONAL BUSINESS MODEL

MLP (NYSE: AM)Highlights

Substantial Value in Midstream Business

Realizations

Takeaway

Liquids-Rich1

2 3

4

5

67

8

Premier AppalachianE&P Company

Run by Co-Founders

DRILLING – MOST ACTIVE OPERATOR IN APPALACHIA

1. 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.

2. Antero and industry rig locations and rig count as of 1/23/2015 per RigData. 17

COMBINED TOTAL – 12/31/14 RESERVESAssumes Ethane RejectionNet Proved Reserves 12.7 TcfeNet 3P Reserves 40.7 TcfePre-Tax 3P PV-10 $22.8 BnNet 3P Reserves & Resource 51.8 TcfeNet 3P Liquids 1,026 MMBbls% Liquids – Net 3P 15%4Q 2014E Net Production 1,265 MMcfe/d- 4Q 2014E Net Liquids 30,400 Bbl/dNet Acres(1) 543,000Undrilled 3P Locations 5,331

UTICA SHALE CORE

Net Proved Reserves 758 BcfeNet 3P Reserves 7.6 TcfePre-Tax 3P PV-10 $6.1 BnNet Acres 148,000Undrilled 3P Locations 1,024

MARCELLUS SHALE CORE

Net Proved Reserves 11.9 TcfeNet 3P Reserves 28.4 TcfePre-Tax 3P PV-10 $16.8 BnNet Acres 395,000Undrilled 3P Locations 3,191

UPPER DEVONIAN SHALE

Net Proved Reserves 8 BcfeNet 3P Reserves 4.6 TcfePre-Tax 3P PV-10 NMUndrilled 3P Locations 1,116

WV/PA UTICA SHALE DRY GASNet Resource 11.1 TcfNet Acres 170,000Undrilled Locations 1,616

0

5

10

15

20

25

Rig

Cou

nt

Operators

SW Marcellus & Utica(2)

0

600

1,200

1,800

2010 2011 2012 2013 2014 2015E

Marcellus Utica Guidance

30124

239

522

1,400

1,007

1. 2012, 2013 and 2014 proved reserves assuming ethane rejection.2. Per current First Call median estimate from Bloomberg.

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

2010 2011 2012 2013 2014

Marcellus Utica

677

2,8444,283

7,632

(1) (1) (1)

12,683

18

AVERAGE NET DAILY PRODUCTION (MMcfe/d)NET PROVED SEC RESERVES (Bcfe)

0

25

50

75

100

125

150

175

200

2010 2011 2012 2013 2014 2015E

Marcellus Utica Deferred Completions

1938

60

114

177 180

130

GROWTH – STRONG TRACK RECORD

OPERATED GROSS WELLS COMPLETED EBITDAX ($MM)

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

2010 2011 2012 2013 2014E

$28$160

$285

$649

$1,144

(2)

40% GrowthGuidance

92% Growth

Assembled a 543,000 net acre position in the core of the Marcellus and Utica shale plays over the past 6 years

December 2008

Net Acreage 118,000

Net Production (MMcfe/d) NM

3P Reserves (Bcfe) NM

3P PV-10 ($MM) NM

Rigs Running NM

Dec 2008 Dec 2011 Dec 2014

December 2011(1)

Net Acreage 213,000

Net Production (MMcfe/d) 167

3P Reserves (Bcfe) 18,400

3P PV-10 ($MM) $9,000

Rigs Running 5

December 2014(1)

Net Acreage 543,000

Net Production (MMcfe/d) 1,265

3P Reserves (Bcfe) 40,700

3P PV-10 ($MM) $22,800

Rigs Running 21

1. Net daily production for December 2011 and December 2014 is for the fourth quarter, respectively.

LAND – MOST ACTIVE LAND ORGANIZATIONIN APPALACHIA

19

118,000 118,000 118,000 162,000 189,000 213,000

285,000 371,000

420,000 450,000 486,000

543,000

0

100,000

200,000

300,000

400,000

500,000

600,000

12/2008 12/2009 6/2010 12/2010 6/2011 12/2011 6/2012 12/2012 6/2013 12/2013 6/2014 12/2014

Antero Net Acreage

Utica Marcellus

20

LIQUIDS-RICH – LARGEST CORE POSITION

Source: Core outlines and peer net acreage positions based on peer presentations, news releases and 10-K/10-Qs.

Antero has the largest liquids-rich core position in Appalachia ≈371,000 net acres

TAKEAWAY – LARGEST FIRM TRANSPORTATION AND PROCESSING PORTFOLIO IN APPALACHIA

Odebrecht / Braskem30 MBbl/d Commitment

Ascent Cracker(Pending Final

Investment Decision)

Antero Long Term Firm Processing & Takeaway Position (2018) – Accessing Favorable Markets

Mariner East II62 MBbl/d Commitment(2)

Marcus Hook Export

Shell25 MBbl/d CommitmentBeaver County Cracker

(Pending FinalInvestment Decision)

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

1. February 2015 and full year 2016 futures basis, respectively, provided by Wells Fargo dated 12/31/2014. Favorable gas markets shaded in green.2. As an anchor shipper on Mariner East II, Antero has the right to expand its NGL commitment with notice to operator.

Chicago(1)

+$0.23 / $(0.08)

CGTLA(1)

$(0.08) / $(0.09)

Dom South(1)

$(1.38) / $(1.11)

TCO(1)

$(0.13) / $(0.41)

21

4 Bcf/dFirm Gas TakeawayBy 2018

Cove Point

1,316 943 780 1,073 818 40

$4.42 $4.47 $4.34 $4.50 $4.41 $4.41

$3.09$3.48 $3.77 $3.95 $4.08 $4.21

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

0200400600800

1,0001,2001,400

2015 2016 2017 2018 2019 2020

BBtu/d $/MMBtu

22

Average Index Hedge Price(1)Hedged Volume Current NYMEX Strip(2)

COMMODITY HEDGE POSITION

1. Reflects weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio. Antero has hedged 3,000 Bbl/d of oil and 23,000 Bbl/d of propane for 2015. 2. As of 12/31/2014.3. Percentage of net gas equivalent production target hedged for respective years.

~$1.6 billion mark-to-market unrealized gain based on 12/31/2014 prices 1.8 Tcfe hedged from January 1, 2015 through year-end 2020 and 262 Bcf of TCO basis hedges from 2015 to 2017

$689 MM $464 MM $176 MM $214 MM $98 MM $3 MM

Mark-to-Market Value(2)

LIQUIDITY – LARGEST GAS HEDGE POSITION IN U.S. E&P + STRONG FINANCIAL LIQUIDITY

$3,000

$2,012

($1,505)

($332) $6 $843

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

Credit Facility9/30/2014

Bank Debt9/30/2014

L/Cs Outstanding9/30/2014

Cash9/30/2014

AM IPOProceeds

to AR

Pro FormaLiquidity

9/30/2014

AR LIQUIDITY POSITION ($MM) AM LIQUIDITY POSITION ($MM)

$1,000$1,250

$0 $0 $0

$250

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

Credit Facility9/30/2014

Bank Debt9/30/2014

L/Cs Outstanding9/30/2014

Cash9/30/2014

AM IPO Proceeds

to AM

Pro FormaLiquidity

9/30/2014

≈ 94% of 2015ETarget

Production(3)

Over $3 billion of combined AR and AM financial liquidity as of 9/30/2014, pro forma for AM IPO closed on 11/10/2014

1. Includes firm sales. 2. Price realization includes $0.05 of midstream revenues in 3Q, 2014. 3. Includes natural gas hedges.4. Source: Public data from 3Q 2014 10-Qs. Peers include Cabot Oil & Gas, CONSOL Energy, EQT Corp. and Range Resources. 5. Includes realized hedge gains and losses. Operating costs include lease operating expenses, production taxes, gathering, processing and firm transport costs and general and administrative costs. 4-year

proved reserve average all-in F&D from 2010-2013. Calculation = (Development costs + exploration costs + leasehold costs) / Total reserves added (2013 ending reserves – 2010 beginning reserves + 4-year reserve sales – 4-year reserve purchases + 4-year accumulated production). AR price realization includes $0.04 of midstream revenues.

$4.16 $3.97

$0.58 $0.95 $0.74 $0.77 $0.81

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

Antero Peer 1 Peer 2 Peer 3 Peer 4

$/M

cfe

LOE Production Taxes GPT G&A EBITDAX 4-year Avg. All-in F&D ($/Mcfe)

$4.96

$3.25

$4.48

$2.93

$2.40$2.64

$2.11 $2.09

23

REALIZATIONS – HIGHEST REALIZATIONS & MARGINSAMONG LARGE-CAP APPALACHIAN PEERS

3Q & 4Q 2014 Natural Gas Realizations ($/Mcf)

3Q 2014 Natural Gas Realizations(3) 3Q 2014 Price Realization & EBITDAX Margin vs F&D(2)(4)

$4.31

$4.12$3.66 $3.62 $3.60

$2.98 $2.87 $2.75

$0.00

$2.00

$4.00

$6.00

AR EQT GPOR RRC CNX RICE ECR COG

$/M

cf

3Q 2014 NYMEX = $4.06/Mcf

AR Peer 1 Peer 2 Peer 3 Peer 4

Average NYMEX

Price($/Mcf)

AverageDifferential(1)

($/Mcf)

AverageBTU Upgrade

($/Mcf)

Discount to NYMEX($/Mcf)

GasHedgeEffect

($/Mcf)

AverageRealized

Gas Price($/Mcf)

AverageRealized Gas

Premium/ Discount

($/Mcf)

Liquids Upgrade($/Mcfe)

Realized Equivalent

Price($/Mcfe)

Equivalent Premium($/Mcfe)

3Q 2014 $4.06 $(0.84) $0.41 $(0.43) $0.68 $4.31 $0.25 $0.60 $4.91 $0.85

4Q 2014 $4.00 $(0.71) $0.37 $(0.34) $0.73 $4.39 $0.39 $0.29 $4.68 $0.68

DOM S 22%

DOM S - 9% DOM S - 6%

TETCO M2 - 7%

TETCO M2 - 6%

TCO 24%

TCO 16%

TCO - 9%

NYMEX8%

NYMEX11%

NYMEX10%

Gulf Coast18%

Gulf Coast38%

Gulf Coast56%

Chicago21%

Chicago20%

Chicago19%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

($/Mcf) 2015ENYMEX Strip Price(1) $3.09Basis Differential to NYMEX(1) $(0.46)BTU Upgrade(6) $0.26 Estimated Realized Hedge Gains $1.35 Realized Gas Price with Hedges $4.24 Premium to NYMEX +$1.15Liquids Impact +$0.39Premium to NYMEX w/ Liquids +$1.54Realized Gas-Equivalent Price $4.63

4. Represents 60,000 MMBtu/d of TCO index hedges and 270,000 MMBtu/d of TCO basis hedges that are matched with NYMEX hedges for presentation purposes.

5. Represents 107,500 MMBtu/d of TCO basis hedges matched with NYMEX hedges.6. Assumes ethane rejection resulting in 1100 BTU residue sales gas.

REALIZATIONS – REALIZED PRICE “ROAD MAP”

1. Based on 12/31/14 strip pricing. 2. Differential represents contractual deduct to NYMEX-based firm sales contract.3. Represents 120,000 MMBtu/d of TCO index hedges and 390,000 MMBtu/d of TCO basis hedges that are

matched with NYMEX hedges for presentation purposes.

2015Basis(1)

2016 Basis(1)

2017 Basis(1)

2015Hedges

2016Hedges

2017Hedges

Mar

kete

d %

of T

arge

t Re

sidu

e G

as P

rodu

ctio

n

+$0.05/MMBtu

$(0.25)/MMBtu(2)

$(1.28)/MMBtu

$(0.24)/MMBtu

$(0.07)/MMBtu

$(0.25)/MMBtu(2)

$(1.11)/MMBtu

$(0.41)/MMBtu

$(0.20)/MMBtu

$(0.25)/MMBtu(2)

$(0.83)/MMBtu

$(0.50)/MMBtu

$(0.09)/MMBtu

$(0.07)/MMBtu

182,500 MMBtu/d

@ $4.38/MMBtu

107,500 MMBtu/d

@ $3.88/MMBtu (5)

40,000 MMBtu/d

@ $4.00/MMBtu

230,000 MMBtu/d

@ $5.60/MMBtu

510,000 MMBtu/d

@ $3.87/MMBtu(3)

170,000 MMBtu/d

@ $4.09/MMBtu

272,500 MMBtu/d

@ $5.35/MMBtu

330,000 MMBtu/d

@ $3.82/MMBtu(4)

85% exposure to favorable price indices$1.35/Mcfe in estimated hedge gains(1)

71% exposure to favorable price indices94% exposure to favorable price indices

Antero is forecasting realized gas prices including hedges at a premium to NYMEX for 2015, assuming current strip pricing,(1)

current basis differentials, existing firm transportation and hedges

$(1.35)/MMBtu

$(1.26)/MMBtu

Wtd. Avg.Basis ($0.46)

Wtd. Avg.Basis $(0.32)

1,160,000 MMBtu/d@ $4.34/MMBtu

Wtd. Avg.Basis $(0.18)

942,500 MMBtu/d@ $4.47/MMBtu

420,000 MMBtu/d

@ $4.27/MMBtu

2015E 2016E 2017E

24

380,000 MMBtu/d

@ $3.88/MMBtu

170,000 MMBtu/d

@ $3.35/MMBtu

70,000 MMBtu/d

@ $4.57/MMBtu

780,000 MMBtu/d@ $4.34/MMBtu

$(0.10)/MMBtu

0%

10%

20%

30%

40%

248

139 94

254289

10%

31%

46%

33% 30%

0

100

200

300

0%

20%

40%

60%

Condensate Highly-RichGas/

Condensate

Highly-RichGas

Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

R

Locations ROR

MARCELLUS SSL WELL ECONOMICS(1)

664

1,010

62888942%

28%

12% 11%

0

300

600

900

1,200

0%

15%

30%

45%

60%

Highly-RichGas/

Condensate

Highly-RichGas

Rich Gas Dry Gas

Tota

l 3PL

loca

tions

RO

R

Locations ROR

MULTI-YEAR DRILLING INVENTORY SUPPORTS LOW RISK, HIGH RETURN GROWTH PROFILE

Large 3P Drilling Inventory of High Return Projects(2)

1. Pre-tax well economics based on 12/31/2014 natural gas and WTI strip pricing for 2015-2020, flat thereafter, NGLs at 55% of oil price and applicable firm transportation costs; 8,000’ lateral. 2. Source: Credit Suisse report dated December 2014 – After-tax internal rate of return based on 12/31/2014 strip pricing.

26% 26%31%

15%

Inte

rnal

Rat

e of

Ret

urn

(%)

20%

25

UTICA WELL ECONOMICS(1)

72% of Marcellus locations are processable (1100-plus Btu) 72% of Utica locations are processable (1100-plus Btu)

3,037 Antero Liquids-Rich Locations

16%

2015Drilling Plan

Antero Projects

Antero is well positioned in the core of the highest return shale projects in the U.S. in the current commodity price environment

WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECT

100% operatedOperating 13 drilling rigs

including 5 intermediate rigs395,000 net acres in

Southwestern Core (73% includes processable rich gas assuming an 1100 Btu cutoff)– 50% HBP with additional 27%

not expiring for 5+ years362 horizontal wells completed

and online– Laterals average 7,400’– 100% drilling success rate5 plants in-service at Sherwood

Processing Complex capable of processing 1 Bcf/d of rich gas−Over 800 MMcf/d being

processed currentlyNet production of 937 MMcfe/d in

3Q 2014, including 17,300 Bbl/d of liquids 3,191 future drilling locations in

the Marcellus (2,302 or 72% are processable rich gas)28.4 Tcfe of net 3P (17% liquids),

includes 11.9 Tcfe of proved reserves (assuming ethane rejection) Highly-Rich Gas

130,000 Net Acres1,010 Gross Locations

Rich Gas91,000 Net Acres

628 Gross Locations

Dry Gas105,000 Net Acres

889 Gross Locations

Highly-Rich/Condensate69,000 Net Acres

664 Gross Locations

HEFLIN UNIT30-Day Rate

2H: 21.4 MMcfe/d (21% liquids)

CONSTABLE UNIT30-Day Rate

1H: 14.3 MMcfe/d (26% liquids)

142 Horizontals Completed30-Day Rate8.1 MMcf/d

6,915’ average lateral length

SherwoodProcessing

Complex

Source: Company presentations and press releases. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held. Note: Rates in ethane rejection.

NERO UNIT30-Day Rate

1H: 18.2 MMcfe/d(27% liquids)

BEE LEWIS PAD30-Day Rate

4-well combined 30-Day Rate of

67 MMcfe/d (26% liquids)

RJ SMITH PAD30-Day Rate



26

MHR COLLINS UNIT30-Day Rate

4-well average9.3 MMcfe/d (26% liquids)

HENDERSHOT UNIT30-Day Rate

1H: 16.3 MMcfe/d2H: 18.1 MMcfe/d

(29% liquids)

HORNET UNIT30-Day Rate

1H: 21.5 MMcfe/d2H: 17.2 MMcfe/d

(26% liquids)CARR UNIT30-Day Rate

2H: 20.6 MMcfe/d(20% liquids)

WAGNER PAD30-Day Rate



Source: Company presentations and press releases. Note: Antero acreage position reflects townships in which greater than 3,000 net acres are held. Note: Third party peak rates assume ethane recovery; Antero 30-day rates in ethane rejection.1. For non-Antero wells, Antero has converted rich gas rates where BTU has been disclosed to NGLs, assuming ethane recovery. Where BTU has not been disclosed, Antero has estimated BTU and gas

composition.2. 30-day rate reflects restricted choke regime.

• 100% operated• Operating 8 rigs including 3 intermediate rigs• 148,000 net acres in the core rich gas/

condensate window (72% includes processable rich gas assuming an 1100 Btu cutoff)

– 20% HBP with additional 79% not expiring for 5+ years

• 52 operated horizontal wells completed and online in Antero core areas

− 100% drilling success rate• 3 plants at Seneca Processing Complex capable

of processing 600 MMcf/d of rich gas

− Over 500 MMcf/d being processed currently, including third party production

• Net production of 143 MMcfe/d in 3Q 2014 including 7,700 Bbl/d of liquids− Seneca 3 processing plant online in July

2014− Fourth third party compressor station in-

service December 2014 with a capacity of 120 MMcf/d

• 1,024 future gross drilling locations (735 or 72% are processable gas)

• 7.6 Tcfe of net 3P (15% liquids), includes 758 Bcfe of proved reserves (assuming ethane rejection)

LEADING UTICA SHALE CORE POSITION DELIVERS CONDENSATE AND NGLS

27

Utica Shale Industry Activity(1)

CadizProcessing

Plant

NORMAN UNIT30-Day Rate

2 wells average20.3 MMcfe/d (17% liquids)

RUBEL UNIT30-Day Rate

3 wells average21.1 MMcfe/d(24% liquids)

GULFPORT24-Hour IP

McCort1-28H, 2-28H, Stutzman 1-14H

Average 13.1 MMcf/d + 922 Bbl/d NGL

+ 21 Bbl/d Oil

GULFPORT24-Hour IP

Wagner 1-28H, Shugert 1-1H, 1-12H

Average 21.0 MMcf/d + 2,270 Bbl/d NGL

+ 292 Bbl/d Oil

Utica Core Area

GARY UNIT30-Day Rate


Highly-Rich/Cond26,000 Net Acres

139 Gross Locations

Highly-Rich Gas15,000 Net Acres

94 Gross Locations

Rich Gas33,000 Net Acres

254 Gross Locations

Dry Gas42,000 Net Acres

289 Gross Locations

NEUHART UNIT 3H30-Day Rate18.7 MMcfe/d(58% liquids)

Condensate32,000 Net Acres

248 Gross Locations

DOLLISON UNIT 1H30-Day Rate23.3 MMcfe/d(44% liquids)

MYRON UNIT 1H30-Day Rate30.4 MMcfe/d(49% liquids)

SenecaProcessingComplex

LAW UNIT30-Day Rate


SCHAFER UNIT30-Day Rate(2)


URBAN PAD30-Day Rate



APPENDIX

28

LTM Production

NTM Production Forecast

Average LTM Production

MAINTENANCE CAPITAL METHODOLOGY

• Maintenance Capital Calculation Methodology– 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 gathering capital expenditures as maintenance capital expenditures

29

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

CONTRACTUAL ARRANGEMENTS WITH ANTERO PROVIDE SIGNIFICANT GROWTH OPPORTUNITIES

30

• Gathering and Compression – 20-year agreement

– Dedication of all current and future AR acreage in West Virginia, Ohio, and Pennsylvania, outside of current

third-party commitments

– Option to gather and compress natural gas produced by Antero on any future acquired acreage outside of the

aforementioned areas

– Low-pressure gathering fee of $0.30/Mcf(1)

– High-pressure gathering fee of $0.18/Mcf(1)

– Compression fee of $0.18/Mcf(1)

– Minimum volume commitments on newly constructed high-pressure lines and compressor stations, respectively

– Compression minimum volume commitments of 70% of design capacity

– High-pressure gathering minimum volume commitments of 75% of design capacity

• Processing (“ROFO”)– Right of first offer on future processing services

– Agreement stipulates that AR has agreed not to procure any gas processing or NGLs fractionation,

transportation or marketing services (other than production subject to a pre-existing dedication) without first

offering AM the right to provide such services

1. All subject to CPI-based adjustments.

FORECASTED CASH FLOW AVAILABLEFOR DISTRIBUTIONS

31

12 Months Ending($ in millions) December 31, 2015

Antero Midstream Adjusted EBITDA(1) $150 – $160

Less:

Cash interest, net ($2.5)

Expansion capital expenditures ($425 – $450)

Ongoing maintenance capital expenditures ($10 – $15)

Add:

Borrowings and cash to fund expansion capital expenditures $425 – $450

Minimum estimated cash available for distribution $135 – $145

Distributable Cash Flow Coverage Ratio 1.1x – 1.2x

Year-over-Year Distribution Growth(2) 28% – 30%

1. Includes incremental public company expenses.2. Year-over-year distribution growth reflects the expected distribution in the fourth quarter of 2015 vs. the minimum quarterly distribution (“MQD”) of $0.17/unit (not full year 2015

distributions vs. the annualized MQD).

AM OPPORTUNITY SET

32

ACTIVITY CURRENTLY DEDICATED TO AM

Gas Gathering and Compression (High-Pressure and Low-Pressure)

Condensate and Liquids Gathering

Fresh Water Distribution System

Processing, Fractionation, Transportation, Marketing

and Other Services

• Existing dedication of ≈412,000 acres• Option to expand outside dedicated area, including ROFR• Minimum Volume Commitments on newly constructed

compression (70%) and high pressure gathering (75%)

Regional Pipeline Project • Option to participate up to 15% in another regional pipeline project

• Relevant liquids production can be added to the existing dedication; AR must request AM to provide a fee proposal

• Option to acquire at fair market value 100% of AR’s fresh water distribution assets covering 543,000 net acres, including ROFO on future services

• 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.

0%

20%

40%

60%

80%

100%

$3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00

Pre-

Tax

RO

R (%

)

Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas

MARCELLUS ROR% AND GAS PRICE SENSITIVITY

331. Assumes 12/31/2014 strip pricing, market differentials and relevant transportation cost; 8,000’ lateral.

• Large portfolio of Highly-Rich Gas/Condensate to Dry Gas locations• Focused on drilling highly economic rich gas locations – rig symbols represent current rig location by Btu regime• Assumes 12/31/2014 WTI strip pricing for 2015-2020, flat thereafter; NGL price 55% of WTI

NYMEX Flat Price Sensitivity(1)

ROR% at Flat 2015-2020 Strip Price

Highly-Rich Gas/Condensate: 44%

Highly-Rich Gas: 30%

Rich Gas: 12%

Dry Gas: 11%

664 Locations

1,010 Locations

628 Locations

889 Locations

Antero Rigs Employed

2015Drilling Plan

0%

20%

40%

60%

80%

100%

120%

140%

160%

180%

200%

$3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00

Pre-

Tax

RO

R (%

)

Condensate Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas

UTICA ROR% AND GAS PRICE SENSITIVITY

34

NYMEX Flat Price Sensitivity(1)

94 LocationsROR% at Flat 2015-2020 Strip Price

Condensate: 13%

Highly-Rich Gas/Condensate: 41%

Highly-Rich Gas: 63%

Rich Gas: 47%

Dry Gas: 44%

• Large portfolio of Condensate to Dry Gas locations• Focused on drilling highly economic rich gas locations – rig symbols represent current rig location by Btu regime• Assumes 12/31/2014 WTI strip pricing for 2015-2020, flat thereafter; NGL price 55% of WTI

1. Assumes 12/31/2014 strip pricing, market differentials and relevant transportation cost; 8,000’ lateral.

254 Locations

139 Locations

289 Locations

248 Locations

2015Drilling Plan

LARGE UTICA SHALE DRY GAS POSITION

35

Antero has 212,000 net acres of exposure to Utica dry gas play− 42,000 net acres in Ohio with net 3P reserves of 2.4 Tcf as of

12/31/2014− 170,000 net acres in West Virginia and Pennsylvania with net

resource of 11.1 Tcf as of 12/31/2014 (not included in 40.7 Tcfe of net 3P reserves)

− 1,616 locations underlying current Marcellus Shale leasehold in West Virginia and Pennsylvania as of 12/31/2014

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

ChesapeakeHubbard BRK #3H

3,550’ LateralIP 11.1 MMcf/d

HessPorterfield 1H-17


GulfportIrons #1-4H


EclipseTippens #6H5,858’ Lateral

IP 23.2 MMcf/d

Magnum HunterStalder #3UH5,050’ Lateral

IP 32.5 MMcf/d

AnteroPlanned

Utica Well2015

Well OperatorIP(MMcf/d)

Lateral Length (Ft)

Claysville SC #1 Range 59.0 5,420

Stewart Winland 1300U Magnum Hunter 46.5 5,289

Bigfoot 9H Rice Energy 41.7 6,957

Stalder #3UH Magnum Hunter 32.5 5,050

Irons #1-4H Gulfport 30.3 5,714

Pribble 6HU Stone Energy 30.0 3,605

Simms U-5H Gastar 29.4 4,447

Conner 6H Chevron 25.0 6,451

Tippens #6H Eclipse 23.2 5,858

Porterfield 1H-17 Hess 17.2 5,000

Hubbard BRK #3H Chesapeake 11.1 3,550

1. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held in OH, WV and PA.

Magnum HunterStewart Winland 1300U


RangeClaysville SC #1


ChevronConner 6H


GastarSimms U-5H4,447’ Lateral

IP 29.4 MMcf/d

Utica Shale Dry Gas Acreage in OH/WV/PA(1)

RiceBigfoot 9H


Utica Shale Dry GasWV/PA

Net Resource11.1 Tcf

1,616 Gross Locations170,000 Net Acres

Utica Shale Dry GasOhio

3P Reserves2.4 Tcf

289 Gross Locations42,000 Net Acres

Utica Shale Dry GasTotal OH/WV/PA

Net Resource13.5 Tcf

1,905 Gross Locations212,000 Net Acres

Stone EnergyPribble 6HU


ChesapeakeUtica Well

Drilling

RiceBlue Thunder

10H, 12H≈9,000’ Lateral

Needed to make up for base declines in conventional and GOM production

? ??

3,000 Antero Drilling Locations

Perm

ian

Nio

brar

a

Gra

nite

Was

h

Bar

nett

Hay

nesv

ille

U.S. INCREMENTAL GAS SUPPLY BREAK-EVEN PRICE CURVE(1)

36

Low cost, liquids-rich Utica and Marcellus Shales will remain attractive in most commodity price environments

Utica Shale

SW (Rich) Marcellus

Shale

1. Source: Credit Suisse report dated January 2014 – Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI

NE (Dry) Marcellus

ShaleEagle Ford

Shale

MARCELLUS & UTICA – ADVANTAGED ECONOMICS

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, 2014 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, 2014. 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.

37

Regarding Hydrocarbon Quantities

am website presentation february 2015

Career

statements of historical

partnership overviewfebruary

operating risks

future events

environmental risks

antero midstream partners

ar growth midstream

midstream footprint