Am website presentation (b) june 2016

Partnership Overview
June 2016

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 Resources”). These statements are
based on certain assumptions made by the Partnership and Antero Resources based on management’s experience and perception of historical
trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a
number of assumptions, risks and uncertainties, many of which are beyond the control of the Partnership, which may cause actual results to
differ materially from those implied or expressed by the forward-looking statements. These include the factors discussed or referenced under
the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2015 and in the Partnership’s
subsequent filings with the SEC.
The Partnership cautions you that these forward-looking statements are subject to risks and uncertainties that may cause these statements to
be inaccurate, and readers are cautioned not to place undue reliance on such statements. These risks include, but are not limited to, Antero
Resources’ expected future growth, Antero Resources’ ability to meet its drilling and development plan, commodity price volatility, inflation,
environmental risks, drilling and completion and other operating risks, regulatory changes, the uncertainty inherent in projecting future rates of
production, cash flow and access to capital, the timing of development expenditures, and the other risks discussed or referenced under the
heading “Item 1A. Risk Factors” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015 and in the
Partnership’s subsequent filings with the SEC.
Our ability to make future distributions is substantially dependent upon the development and drilling plan of Antero Resources, which itself is
substantially dependent upon the review and approval by the board of directors of Antero Resources of its capital budget on an annual
basis. In connection with the review and approval of the annual capital budget by the board of directors of Antero Resources, the board of
directors will take into consideration many factors, including expected commodity prices and the existing contractual obligations and capital
resources and liquidity of Antero Resources at the time.
Any forward-looking statement speaks only as of the date on which such statement is made, and the Partnership undertakes no obligation to
correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by
applicable law.
1
Antero Midstream Partners LP is denoted as “AM” and Antero Resources Corporation is denoted as “AR” in
the presentation, which are their respective New York Stock Exchange ticker symbols.

2
CHANGES SINCE JUNE 2016 PRESENTATION
Updated AR operational slides highlighting year-to-date
improvements and pro forma location count
Slides 4-8
New slide highlighting AR acreage acquisition and
related benefits to AM
Slide 3
Updated AR slide highlighting 3/31/2016 balance sheet
and liquidity pro forma for equity offering
Slide 27

491
638
597
744
0
100
200
300
400
500
600
700
800
900
1,000
Dedicated Acreage:
Gathering & Compression
Dedicated Acreage:
Water Services
ANTERO RESOURCES ACQUISITION BENEFITS AM
3
Antero Midstream Buildout
Compressor Station – In service
Districts with 3,000+ Antero
Net Acres
Acquired Acreage
Compressor Station – Planned
on Existing Acreage
Existing Gathering Line
New Platform for
Antero Midstream
Infrastructure
Buildout
Fresh Water Delivery Take Point
Planned Gathering Line
1. Includes projects currently under construction.
AM Gross Dedicated Acreage (000’s)
A unique opportunity as most Appalachian core acreage is already dedicated to third party midstream providers
12/31/2015 Pro Forma
Fresh Water ImpoundmentExisting Fresh Water Line
Planed Fresh Water Line
Planned Gathering Line – Acquired
Acreage
Compressor Station – Planned on
Acquired Acreage
On June 9, 2016 Antero Resources acquired 55,000 net acres
in the southwestern Marcellus Shale, over 95% of which will
be dedicated to AM for gathering, compression, processing,
and water services
 Acquisition and associated equity financing allows Antero
Resources to increase 2017 production target to 20% -
25%, providing further support to Antero Midstream’s
2017 distribution growth target of 28% to 30%
 Expands Antero Midstream footprint and identified 5-year
investment opportunity set by over 15% to ~$3.5 billion(1)
– Attractive organic investment opportunities at 4x – 7x
build-out EBITDA
– Additional adjacent third-party midstream
opportunities

The acquired acreage is primarily located in areas where Antero is observing stronger EURs of 2.0 Bcf/1,000' or
greater for wells completed in the first quarter with at least 30 days of production history
$8.7
$11.7
$14.7
$5.2
$7.7
$10.1
35%
45%
56%
24%
30%
38%
0%
10%
20%
30%
40%
50%
60%
$0.0
$3.0
$6.0
$9.0
$12.0
$15.0
1.7
2.3
2.0
2.7
2.3
3.1
1.7
2.1
2.0
2.5
2.3
2.8
Pre-TaxROR
Pre-TaxPV-10
Pre-Tax PV-10 Pre-Tax ROR
Classification(1) Highly-Rich Gas/Condensate Highly-Rich Gas
BTU Regime 1275-1350 1275-1350 1275-1350 1200-1275 1200-1275 1200-1275
EUR (Bcfe): 20.8 24.4 27.9 18.8 22.1 25.2
EUR (MMBoe): 3.5 4.1 4.7 3.1 3.7 4.2
% Liquids: 33% 33% 33% 24% 24% 24%
Well Cost ($MM): $8.5 $8.5 $8.5 $8.5 $8.5 $8.5
Bcf/1,000’ 1.7 2.0 2.3 1.7 2.0 2.3
Bcfe/1,000’: 2.3 2.7 3.1 2.1 2.5 2.8
Net F&D ($/Mcfe): $0.48 $0.41 $0.36 $0.53 $0.45 $0.40
Pre-Tax NPV10 ($MM): $8.7 $11.7 $14.7 $5.3 $7.7 $10.1
Pre-Tax ROR: 35% 45% 56% 24% 30% 38%
Payout (Years): 2.5 2.0 1.6 3.7 2.9 2.3
Breakeven NYMEX Gas Price
($/MMBtu)(5) $1.67 $1.40 $1.18 $2.31 $2.05 $1.84
Gross 3P Locations(3): 626 971
Pro Forma Gross 3P Locations(3): 733 (17% Increase) 1,154 (19% Increase)
4
NYMEX
($/MMBtu)
WTI
($/Bbl)
C3+ NGL(2)
($/Bbl)
2016 $2.26 $41 $16
2017 $2.77 $45 $21
2018 $2.87 $47 $24
2019 $2.93 $49 $25
2020 $3.03 $50 $26
2021-25 $3.49 $51-$53 $27
Assumptions
 Natural Gas – 3/31/2016 strip
 Oil – 3/31/2016 strip
 NGLs – 37.5% of Oil Price
2016; 50% of Oil Price 2017+
4535
2016 Development Plan: Completions
1. 3/31/2016 pre-tax well economics based on a 9,000’ lateral, 3/31/2016 natural gas and WTI strip pricing for 2016-2025, flat thereafter, NGLs at 37.5% of WTI for 2016 and 50% of WTI thereafter, and
applicable firm transportation and operating costs including 50% of Antero Midstream fees. Well cost estimates include $1.2 million for road, pad and production facilities.
2. Pricing for a 1225 BTU y-grade ethane rejection barrel. NGLs at 37.5% of WTI for 2016 and 50% of WTI for 2017 and thereafter. NGL prices are forecast to increase in 2017 relative to WTI due to
projected in-service date of Mariner East 2 project allowing for a significant increase in AR NGL exports via ship.
3. Undeveloped well locations as of 12/31/2015.
4. Represents actual results for 1Q 2016.
5. Breakeven price for 15% pre-tax rate of return.
WELL ECONOMICS – MARCELLUS UPSIDE POTENTIAL
Highly-Rich Gas/Condensate Highly-Rich Gas
(4) (4)Bcf/1,000’
Bcfe/1,000’

Marcellus ShaleUtica Shale Ohio
5
Operating Highlights
 Top 20 best drilling footage days in
Marcellus since 2009 have all occurred in
2016, including 6,528’ drilled in 24 hours in
West Virginia on the Rock 2H
 Recently drilled and cased longest lateral
in company history at 14,024 feet
 Stayed within targeted zone for 98% of
lateral length drilled in Q1 2016
 Increased sand placement during
completions to 98% in Q1 2016
 Utilizing new floating casing procedure,
reducing casing run time by over 12 hours
 Increased proppant and water loading by
25% in 2016 with encouraging results to
date
1. Based on statistics for wells completed within each respective period.
2. Ethane rejection assumed.
3. Current D&C cost per 1,000’ lateral divided by net EUR per 1,000’ lateral assuming 81% NRI in Utica and 85% NRI in Marcellus.
CONTINUOUS OPERATING IMPROVEMENTS BY AR
Utica Marcellus
2014 2015 Q1 2016 Q1 2016 vs. 2014 2014 2015 Q1 2016 Q1 2016 vs. 2014
Activity Levels
Average Rigs Running 4 5 1 (75%) 14 9 7 (50%)
Average Completion Crews 2.0 3.0 1.5 (25%) 5.5 2.0 4.0 (27%)
Operational Improvements
Drilling Days 29 31 24 17% 29 24 21 28%
Average Lateral Length (Ft) 8,543 8,575 9,000 5% 8,052 8,910 9,000 12%
Stages per Well 47 49 51 9% 40 45 45 12%
Stage Length 183 175 175 4% 200 200 200 0%
Stages per Day 3.2 3.7 4.4 38% 3.2 3.5 3.8 19%
Well Cost & Performance Improvements
D&C per 1,000' of lateral ($MMs) $1.55 $1.36 $1.14 (26%) $1.34 $1.18 $0.95 (29%)
Wellhead EUR per 1,000' of lateral (Bcf)
(1)
1.4 1.6 1.6 14% 1.5 1.7 2.0 33%
Processed EUR per 1,000' of lateral (Bcfe)
(1)(2)
1.5 1.8 1.8 20% 1.8 1.9 2.3 28%
Net development cost per processed Mcfe
(3)
$1.28 $0.94 $0.79 (39%) $0.88 $0.73 $0.49 (45%)
Acquired Acreage

1,237
1,675
2,116
3,699
0
1,000
2,000
3,000
4,000
2014 2015 Q1 2016 Q2 2016
Lateralft/dayPerRig
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
01/01/12 01/01/13 01/01/14 01/01/15 01/01/16 01/01/17
LateralFeetDrilledPerRig
Date
24 Hour Footage
Switched to
rotary
steerable
system
STEP CHANGE IN AR MARCELLUS DRILLING FOOTAGE
6
Top 50 AR Marcellus Daily Footage Records
All of the top 20 daily
footage records since
inception have occurred
during 2016
Key Drilling Highlights:
 Driven by technology and process
advancements, all of the top 20 Antero
daily footage records have been
achieved in 2016, quickly establishing a
new benchmark in Marcellus drilling
performance
 Drilled 6,528’ feet in a lateral in 24 hours,
exceeding previous record by over 1,000
feet
 Lateral feet drilled per day has increased
almost 3x since 2014 to 3,699’ in 2Q 2016
New drilling techniques and technologies are forecast to shave up to 5 days off lateral
drilling times and up to 25% off drilling AFEs
Top 20 AR Marcellus Daily Footage
Records
Changed
lateral bit
Increased pump rates by
removing heavy weight
drill pipe (small diameter
increased friction)
30
WELLS
90
WELLS
159
WELLS
Marcellus Average Lateral Ft/Day
23
WELLS

1,194
1,128 1,117
990
1,031 1,016
958 956
1,084
1,126
1,274
1,304
1,337
1,418
1,480
1,530
1,500
800
900
1,000
1,100
1,200
1,300
1,400
1,500
1,600
Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 Feb-16 Mar-16 Apr-16 2016
Plan
SandPlacedPerFootofLateral
32 31
32 32 32 32 32
31 31
32
34 34
35
36 37
39 39
25
27
29
31
33
35
37
39
41
Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 Feb-16 Mar-16 Apr-16 2016
Plan
BarrelsPerFootofLateral
ADVANCED COMPLETIONS DRIVE INCREASED WATER VOLUMES
7
AR Increased Proppant Load by 25% in the Marcellus and Utica, EARLY RESULTS JUST COMING IN
Pilot Testing Demonstrated
Improved Recoveries While
Maintaining Well Density
New AR Completion Designs Utilizing 38 to 40 Barrels of Water Per Lateral Foot, a 25% Increase

y = 0.00199x - 0.63702
0
5
10
15
20
25
30
35
4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000
EUR(Bcfe)
Lateral Length (Feet)
All Wells
8
MARCELLUS IMPROVEMENTS DRIVING AR VALUE CREATION
Antero Marcellus EUR vs. Lateral Length(1)(2)
33 wells > 10,000’ lateral
length and 43 wells waiting
on completion ranging from
10,000’ to 14,000’
1. All 255 wells completed since 2014 when Antero transitioned to shorter stage length completions (SSL).
2. EUR’s include condensate and NGL processing (C3+) but assume ethane rejection.
Longer Laterals Better Well Economics
TBA
Current completions using
1,500 lbs/ft of sand and 39
Bbls/ft of water
98% sand placement for
1,200 lbs/ft drove
outperformance YTD 2016
compared to type curve
40 wells > 20 Bcfe
High correlation of EURs
to lateral length
2016 wells
average 2.3
Bcfe/1,000’
High correlation of EURs to lateral length – no degradation in results out to 11,000’ laterals
 Antero has led the way with long lateral drilling programs

ANTERO MIDSTREAM EXERCISES STONEWALL OPTION
• Antero Midstream has exercised its option to
acquire a 15% non-operated equity interest in
the Stonewall gathering pipeline
- Capital investment: $45 million
- Expected unlevered IRR: 25% - 35%
- Effective date: May 26, 2016
● Another step towards becoming “full value
chain” midstream provider
- Fixed fee revenues with minimum volume
commitments
● Antero Resources is an anchor shipper with
the ability to transport up to 1.1 Bcf/d of gas on
a firm basis (900 MMcf/d minimum volume
commitment) to more favorably priced markets
including TCO, NYMEX and Gulf Coast
markets
- Currently transporting ~950 MMcf/d
Stonewall Gathering Pipeline Option
Throughput Capacity: 1.4 Bcf/d
Pipeline
Specifications: 67 miles of 36-inch pipeline
Project Capital: ≈ $400 Million
In-Service Date: 12/1/2015
AR Firm Commitment: 900 MMcf/d 9
Stonewall Gathering Pipeline Asset Details
Acquired Acreage

WHY OWN ANTERO MIDSTREAM?
10
 Best-in-class distribution growth guidance of 30% in 2016 and 28% to 30% target for 2017
 Strong DCF coverage of 1.60x in 1Q16 and 1.45x in 2015, above 1.1x–1.2x target
Strong Distribution
Growth & Coverage
Sponsor Strength
Organic Investment
Opportunity Set
Full Value Chain
Midstream
Opportunity
Financial Flexibility
Aligned
High Growth
Sponsor
 $3.8 billion of consolidated liquidity pro forma; stable leverage through the down cycle
 Ba2/BB corporate ratings affirmed; $4.5 billion AR borrowing base affirmed
 84% of forecasted production hedged through 2019 at $3.77/MMBtu
 Peer leading realized prices and EBITDAX margins
 Identified organic investment opportunity set of $3.5 billion over the next five years
 “Just-in-time capital” results in more capital efficient project economics, while avoiding the
competitive acquisition market and reliance on capital markets
 Organic growth strategy results in investment build-out EBITDA multiples of 4x–7x vs.
drop-downs of 8x–12x
 Opportunity to expand gathering, compression, and water services to third parties
 Right of first offer for processing, fractionation, transportation and marketing activities
 Midstream provider for the largest and most active operator in Appalachia inherently brings
additional downstream opportunities to AM
 Over $800 million of liquidity and 2.3x debt to EBITDA ratio at March 31, 2016
 17% production growth guidance in 2016 and 20% to 25% growth targeted for 2017 drives
AM volume growth
 Continuous operating improvements, including more water and sand in completions
resulting in improved recoveries and well economics for AR and higher volumes for AM
 AR has a 62% LP ownership in AM, resulting in direct alignment with midstream value
creation

Sustainable
Business
Model
High Growth Sponsor
Drives AM Throughput
and Distribution Growth
Largest Dedicated Core
Liquids-Rich Acreage
Position in Appalachia
$800 Million of
AM Liquidity
11
Premier E&P Operator
in Appalachia
100% Fixed Fee and
Largest Firm Transport
and Hedge Portfolio
Opportunity to Build Out
Northeast Value Chain
Growth Liquids-
Rich
Value
Chain
Opportunity
High
Visibility
Sponsor
Strength
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 Appalachian
Midstream Partnership
Run by Co-Founders
Hedges Bolster Solid
Well Economics

-
100
200
300
400
500
600
AR Peer 1 Peer 2 Peer 3 Peer 5 Peer 4 Peer 6
Pro Forma Core Net Acres - Dry
Core Net Acres - Dry
Pro Forma Core Net Acres - Liquids-Rich
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
0
500
1,000
1,500
2,000
2,500
3,000
3,500
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
EQT AR CHK COG SWN RRC CNX
SPONSOR STRENGTH – LEADERSHIP IN APPALACHIAN BASIN
Top Producers in Appalachia (Net MMcfe/d) – 1Q 2016(1)(2)
Top 12 U.S. Natural Gas Producers (Net MMcf/d) – 1Q 2016(1)
Appalachian Producers by Proved Reserves (Bcfe) – YE 2015(1)(2) Appalachian Producers by Core Net Acres (000’s) – June 2016(4)
1. Based on company filings and presentations. Excludes pro forma additions via acquisitions.
2. Appalachian only production and reserves where available. Excludes companies that do not break out Appalachian production including CVX, HES and XOM.
3. Includes proved reserves categorized in “Northern Division” consisting of Utica Shale, Marcellus Shale and Powder River Basin.
4. Based on Antero geologic interpretation supported by state well data, company presentations and public land data. Peer group includes CNX, COG, EQT, RRC, SWN, CHK. EQT adjusted for STO acreage acquisition.
(3)
12
2nd Largest
Appalachian
Producer in
1Q ‘16
Appalachian Peers
8th Largest U.S.
Gas Producer in
1Q ‘16
Largest Proved
Reserve Base In
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

$198
$341
$434
$649
$1,164
$1,374
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
$1,600
2010 2011 2012 2013 2014 2015 2016E
$1,221
0
10,000
20,000
30,000
40,000
50,000
60,000
2010 2011 2012 2013 2014 2015 2016E
NGLs (C3+) Oil Ethane
5 246
6,436
23,051
48,298
66,000
37% Growth
Guidance
1. Represents midpoint of updated 2017 production guidance per press release dated 6/8/2016.
2. Represents Bloomberg street consensus estimates as of 5/27/2016.
1,750
2,144
0
600
1,200
1,800
2,400
2010 2011 2012 2013 2014 2015 2016E 2017E
Marcellus Utica Guidance
30 124
239
522
1,007
1,493
13
AVERAGE NET DAILY PRODUCTION (MMcfe/d)
0
50
100
150
200
2010 2011 2012 2013 2014 2015 2016E
Marcellus Utica Deferred Completions
19
38
60
114
177 181
131
110
180
OPERATED GROSS WELLS COMPLETED
AVERAGE NET DAILY LIQUIDS PRODUCTION (Bbl/d)
17%
Growth
Guidance
23% Growth
Target(1)
 Antero is in the unique position of being able to sustain growth and value creation through the price down cycle
CONSOLIDATED EBITDAX ($MM)
Street
Consensus(2)
SPONSOR STRENGTH – MOMENTUM THROUGH THE DOWN CYCLE

Note: 2015 SEC prices were $2.56/MMBtu for natural gas and $50.13/Bbl for oil on a weighted average Appalachian index basis.
1. Pro forma for third-party acreage acquisition announced per press release dated 6/9/2016. 3P reserve additions are unaudited.
2. 3P reserve pre-tax PV-10 based on annual strip pricing for first 10-years and flat thereafter as of December 31, 2015. NGL pricing assumes 39%, 46% and 48% of WTI strip prices for 2016, 2017 and
2018 and thereafter, respectively. PV-10 value not adjusted for third-party asset acquisition.
3. All net acres allocated to the WV/PA Utica Shale Dry Gas and Upper Devonian Shale are included among the net acres allocated to the Marcellus Shale as they are stacked pay formations attributable to
the same leasehold.
4. Antero and industry rig locations as of 5/27/2016, per RigData.
14
COMBINED TOTAL – 12/31/15 RESERVES
Assumes Ethane Rejection
Net Proved Reserves 13.2 Tcfe
Net 3P Reserves(1) 41.2 Tcfe
Strip Pre-Tax 3P PV-10(2) $11.2 Bn
Net 3P Reserves & Resource(1) 56 to 59 Tcfe
Net 3P Liquids(1) 1,350 MMBbls
% Liquids – Net 3P(1) 20%
1Q 2016 Net Production 1,758 MMcfe/d
- 1Q 2016 Net Liquids 68,516 Bbl/d
Net Acres(1)(3) 628,000
Undrilled 3P Locations(1) 4,344
OHIO UTICA SHALE CORE
Net 3P Reserves 7.5 Tcfe
Net Acres 148,000
Undrilled 3P Locations 814
MARCELLUS SHALE CORE
Net 3P Reserves(1) 33.7 Tcfe
Net Acres(1) 480,000
Undrilled 3P Locations(1) 3,530
WV/PA UTICA SHALE DRY GAS
Net Resource 14.3 to 17.8 Tcf
Net Acres 231,000
Undrilled Locations 2,269
0
1
2
3
4
5
6
7
8
RigCount
Operators
SW Marcellus + Utica Rigs(4)
SPONSOR STRENGTH – MOST ACTIVE OPERATOR
 AR is operating 23% of all rigs running and 58% of rigs running in liquids rich core areas in Appalachia

$1
$5 $7 $8
$11
$19
$28
$36
$41
$55
$83 $80
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
10 38 80 126
266
531
908
1,134
1,1971,216 1,195 1,222
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800 Utica Marcellus
108
216
281 331
386
531
738
935 965
1,038
1,124
1,303
0
200
400
600
800
1,000
1,200
1,400
1,600 Utica Marcellus
26 31 40 36 41
116
222
358
454 435
478
606
0
100
200
300
400
500
600
700
800 Utica Marcellus
Low Pressure Gathering (MMcf/d)
Compression (MMcf/d)
High Pressure Gathering (MMcf/d)
EBITDA ($MM)
15
$338
Note: Y-O-Y growth based on 1Q’15 to 1Q’16.
1. Represents midpoint of updated 2016 guidance.
GROWTH – HIGH GROWTH MIDSTREAM THROUGHPUT
$215

$0.170
$0.180
$0.190
$0.205
$0.235
1.1x
1.2x
1.3x
1.4x
1.8x
1.6x
0.0x
0.2x
0.4x
0.6x
0.8x
1.0x
1.2x
1.4x
1.6x
1.8x
2.0x
$0.000
$0.050
$0.100
$0.150
$0.200
$0.250
$0.300
$0.350
$0.400
$0.450
$0.500
4Q14A 1Q15A 2Q15A 3Q15A 4Q15A 1Q16A 2Q16E 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E
Distribution Per Unit (Left Axis) DCF Coverage (Right Axis)
$0.220
16
• Antero Midstream is targeting 28% to 30% annual distribution growth through 2017
• AM has delivered on those targets with DCF coverage of 1.6x in the first quarter 2016
Note: Future distributions subject to AM Board approval.
1. Assumes midpoint of target distribution growth range.
2. 1Q 2016 distribution per Partnership press release dated 4/14/2016.
(2)
GROWTH – TOP TIER DISTRIBUTION GROWTH

GROWTH – ORGANIC GROWTH STRATEGY DRIVES VALUE
CREATION
17
• Organic growth strategy provides attractive
returns and project economics, while
avoiding the competitive acquisition market
and reliance on capital markets
• Industry leading organic growth story
– ~$1.9 billion in capital spent through
09/30/2015 on gathering and compression
and water assets
– $410 million in additional growth capital
forecast for the twelve-month period
ending 12/31/16 (excludes $25 million of
maintenance capital)
– 5-year identified investment opportunity
set of $3.5 billion
Note: Precedent data per IHS Herold’s research and public filings.
1. Antero organic multiple calculated as estimated gathering and compression and water capital expended through Q3 2015 divided by midpoint of 2016 EBITDA guidance of $325 to $350 million,
assuming 12-15 month lag between capital incurred and full system utilization.
2. Selected gathering and compression drop down acquisitions since 1/1/2012. Drop down multiples are based on NTM EBITDA. Source: Barclays.
5.5x
11.5x
10.8x
10.5x
9.3x
9.0x
8.8x 8.7x 8.6x 8.6x
8.2x
7.9x 7.8x
6.9x
0.0x
1.0x
2.0x
3.0x
4.0x
5.0x
6.0x
7.0x
8.0x
9.0x
10.0x
11.0x
12.0x
Drop Down Multiple(2)
Organic EBITDA Multiple vs. Precedent Drop Down Multiples
Median: 8.8x
Value creation for the AM unit holder =
Build at 4x to 7x EBITDA
vs.
Drop Down / Buy at 8x to 12x EBITDA

LP
Gathering
HP
Gathering Compression
Condensate
Gathering
Fresh Water
Delivery
Advanced
Wastewater
Treatment
Stonewall
Gathering
Pipeline
Processing/
Fractionation
Unlevered IRR Range: 25% - 35% 15% - 25% 10% - 20% 25% - 35% 30% - 40% 15% - 25% 25% - 35% 15% - 20%
Payout (Years): 2.5 - 4.0 3.5 - 4.5 4.0 - 6.5 2.0 - 3.5 2.0 – 3.0 6.0 - 8.0 2.0 - 3.5 5.0 - 6.0
Minimum Volume Commitments: N/A 75% 70% N/A Yes N/A 80% 80%
2016 Expansion
Capex(2) Total
Marcellus $433 $33 $49 $143 - $33 $130 $45
Utica 22 7 1 7 - 7 - -
Growth Capex $455 $40 $50 $150 $0 $40 $130 $45
% of Capex 100% 9% 11% 33% 0% 9% 28% 10%
Included in 2016 Budget: Marcellus &
Utica
Marcellus &
Utica
Marcellus &
Utica
Utica Marcellus &
Utica
Marcellus &
Utica
Marcellus Not Included
5-year identified
investment
opportunity set
$3.5 B 30% - 35% 15% - 20% 30% - 35% 0% 8% - 12% 6% - 8% 1%
Additional In-hand
Opportunities:
Dry Utica Dry Utica Dry Utica Utica
Stabilization
Dry Utica Dry Utica Marcellus
Processing/
Fractionation
25%
15%
10%
25%
30%
15%
25%
15%
35%
25%
20%
35%
25% 25%
40%
20%
0%
10%
20%
30%
40%
InternalRateofReturn
18
Project Economics by Segment(1)
GROWTH – ESTIMATED PROJECT ECONOMICS BY SEGMENT
1. Based on management capex, operating cost and throughput assumptions by project. Capex guidance updated per 2016 Partnership guidance press release.
2. Excludes $25.0 million of maintenance capex. Includes Stonewall option exercise.
Wtd. Avg. 21% IRR
AM Option
Opportunities
35%

19Source: Core outlines and peer net acreage positions based on investor presentations, news releases and 10-K/10-Qs. Rig information per RigData as of 5/27/2016.
1. Based on company filings and presentations. Peer group includes Ascent, CHK, CNX, CVX, ECR, EQT, GPOR, NBL, REX, RRC, STO, SWN.
• Antero controls an estimated 37% of
the NGLs in the liquids-rich core of
the two plays
• Antero has the largest core liquids-
rich position in Appalachia with
≈420,000 net acres (> 1100 Btu)
• Represents over 24% of core liquids-
rich acreage in Marcellus and Utica
plays combined
 Antero has over 3,080 undeveloped rich gas locations with an average lateral length of 7,870’ in its 3P reserves as of 12/31/2015 pro
forma for the third-party acreage acquisition
0
100
200
300
400
500
(000s)
Core Liquids-Rich Net Acres(1)
LIQUIDS-RICH – LARGEST CORE DRILLING INVENTORY

$1.55
$1.36
$1.14
$0.000
$0.500
$1.000
$1.500
$2.000
2014 2015 Current
$MM/1,000’Lateral
Well Cost ($MM/1,000' of Lateral)
12%
Decrease
vs. 2014
16%
Decrease
vs. 2015
733 1,154
692 951
63% 47%
24%
28%35%
24%
10% 13%
0
400
800
1,200
1,600
0%
20%
40%
60%
80%
Highly-Rich
Gas/
Condensate
Highly-Rich Gas Rich Gas Dry Gas
Total3PLocations
ROR
Total 3P Locations ROR @ 3/31/2016 Strip Pricing - After Hedges ROR @ 3/31/2016 Strip Pricing - Before Hedges
184
98
108
161
263
14%
48%
64%
56%
64%
9%
23% 24% 20% 24%
0
100
200
300
0%
20%
40%
60%
80%
100%
Condensate Highly-Rich
Gas/
Condensate
Highly-Rich
Gas
Rich Gas Dry Gas
Total3PLocations
ROR
MARCELLUS WELL ECONOMICS(1)(2)
SUSTAINABLE BUSINESS MODEL – HEDGES BOLSTER
SOLID WELL ECONOMICS
Marcellus Well Cost Improvement(3)
1. 3/31/2016 pre-tax well economics based on a 9,000’ lateral, 3/31/2016 natural gas and WTI strip pricing for 2016-2025, flat thereafter, NGLs at 37.5% of WTI for 2016 and 50% of WTI thereafter, and
applicable firm transportation and operating costs including 50% of Antero Midstream fees. Well cost estimates include $1.2 million for road, pad and production facilities.
2. ROR @ 3/31/2016 Strip-With Hedges reflects 3/31/2016 well cost ROR methodology, with the 3/31/2016 hedge value allocated based on 2016-2021 projected production volumes resulting in blend of strip
and hedge prices. Locations pro forma for third-party acreage acquisition per press release dated 6/8/2016.
3. Current spot well costs based on $8.5 million for a 9,000’ lateral Marcellus well and $10.25 million for a 9,000’ lateral Utica well.
20
UTICA WELL ECONOMICS(1)(2)
 73% of Marcellus locations are processable (1100-plus Btu)  68% of Utica locations are processable (1100-plus Btu)
2016
Drilling
Plan
 AR multi-year drilling inventory supports low risk, high return growth profile
 Antero has reduced average well costs for a 9,000’ lateral by 31% in the Marcellus and 28% in the Utica as compared to 2014 well costs
 At 3/31/2016 strip pricing, Antero has 2,517 locations that exceed a 20% rate of return (excluding hedges)
– Including hedges, these locations generate rates of return of approximately 45% to 65%
Utica Well Cost Improvement(3)
$1.34
$1.18
$0.95
$0.000
$0.500
$1.000
$1.500
$2.000
2014 2015 Current
$MM/1,000’Lateral
Well Cost ($MM/1,000' of Lateral)
12%
Decrease
vs. 2014
19%
Decrease
vs. 2015

21
In-service 2016 Budget
HIGH VISIBILITY – PROJECTED MARCELLUS
MIDSTREAM BUILDOUT

22
In-service 2016 Budget
HIGH VISIBILITY – PROJECTED UTICA
MIDSTREAM BUILDOUT

7
0
4
0
3
6
0
2
4
6
8
AM CNNX EQM CMLP SMLP RMP
Fixed
Fee
100%
Fixed
Fee
100%
23
MITIGATED COMMODITY RISK – 100% FIXED FEE – RICH TO DRY
Contract Mix
Fixed
Fee
98%
Fixed
Fee
100%
Fixed
Fee
100%
Fixed
Fee
90%
(1)
.
Source: Core net acreage positions based on investor presentations, news releases and 10-K/10-Qs.
1. Represents assets held at MLP.
2. Rig count as of 5/27/2016, per RigData.
3. Includes Antero Resources rigs located in Doddridge County, WV operating on SMLP assets.
Commodity
Based
Commodity
Based
Appalachian Exposure
Marcellus – Dry      
Marcellus – Rich    
Utica – Dry   
Utica – Rich  
Water Services   
Rigs Running on Midstream Footprint (2)
(3)
AM has no direct commodity price exposure

-
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
3,500,000
4,000,000
4,500,000
5,000,000
5,500,000
Gross Gas Production (BBtu/d)
24
BBtu/d
Antero Resources Transportation Portfolio
• Antero Resources has built the largest firm transportation portfolio in Appalachian Basin with 4.85 BBtu/d by year end 2018
• Realized $0.01/Mcfe differential to Nymex gas prices in 1Q16, before hedges
2015 2016E 2017E 2018E
Favorable:
Chicago
MichCon
Gulf Coast
NYMEX
TCO
AR Increasing Access to Favorable Markets
Less
favorable:
TETCO M2
Dominion South
74%
26%
99%
1%
97%
3%
97%
3%
(Stonewall/WB) Mid-Atlantic/NYMEX
(Stonewall/TGP) Gulf Coast
(TCO) Appalachia or Gulf Coast
Appalachia
Appalachia
(REX/ANR/NGPL/MGT) Midwest
(ANR/Rover) Gulf Coast
MITIGATED COMMODITY RISK – FIRM TRANSPORTATION &
SALES PORTFOLIO

$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$0
$50
$100
$150
$200
$250
$300
$350
$MM
25
 Hedging is a key component of Antero’s business model which includes development of a large, repeatable drilling inventory
– Locks in higher returns in a low commodity price environment and reduces the amount of time for well payouts, thereby
enhancing liquidity
 Antero has realized $2.1 billion of gains on commodity hedges since 2009
– Gains realized in 28 of last 29 quarters, or 97% of the quarters since 2009
● Based on Antero’s hedge position and strip pricing as of 3/31/2016, the unrealized commodity derivative value is $3.1 billion
● Significant additional hedge capacity remains under the credit facility hedging covenant for 2020 – 2022 period
Quarterly Realized Hedge Gains / (Losses)
Realized Hedge Gains
Projected Hedge Gains
NYMEX Natural Gas
Historical Spot Prices
($/MMBtu)
NYMEX Natural Gas
Futures Prices 03/31/16
3.6 Tcfe Hedged at
average price of
$3.71/Mcfe through
2022
Average Hedge Prices
($/MMBtu)
$3.36
$3.91
$3.57
$3.91
$3.70 $3.66
$3.24
$3.1 Billion in
Projected Hedge
Gains Through 2022Realized $2.1 Billion
in Hedge Gains
Since 2009
HEDGING – INTEGRAL TO BUSINESS MODEL
(1)
1. Represents average hedge price for nine months ending 12/31/2016.

Regional Gas Pipelines
Miles Capacity In-Service
Stonewall Gathering
Pipeline
50 1.4 Bcf/d Yes
1. Acquired by AM from AR for a $1.05 billion upfront payment and a $125 million earn out in each of 2019 and 2020.
2. Antero Midstream has a right of first offer on 220,000 dedicated net acres for processing and fractionation.
End
Users
End
Users
Gas Processing
Y-Grade Pipeline
Long-Haul Interstate
Pipeline
Inter
Connect
NGL Product
Pipelines
Fractionation
Compression
Low Pressure Gathering
Well Pad
Terminals
and
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 Gathering
Stabilization
Utica 19 19
End
Users
(Ethane, Propane,
Butane, etc.)
26
VALUE CHAIN OPPORTUNITY – FULL MIDSTREAM VALUE CHAIN
AM Option Opportunities (2)
AM recently exercised its option on 15% interest in Stonewall, adding a regional gas gathering
pipeline to its portfolio

Liquid “non-E&P assets” of $5.7 Bn
significantly exceeds total debt of $3.8 Bn pro
forma for $762 million equity offering
Pro Forma Liquidity
LIQUIDITY – STRONG BALANCE SHEET AND FLEXIBILITY
Antero Resources (NYSE:AR) Antero Midstream (NYSE:AM)
Pro Forma 3/31/2016 Debt Liquid Non-E&P Assets 3/31/2016 Debt Liquid Assets
Debt Type $MM
Credit facility $377
6.00% senior notes due 2020 525
5.375% senior notes due 2021 1,000
5.125% senior notes due 2022 1,100
5.625% senior notes due 2023 750
Total $3,752
Asset Type $MM
Commodity derivatives(1) $3,073
AM equity ownership(2) 2,644
Cash 26
Total $5,743
Asset Type $MM
Cash $26
Credit facility – commitments(3) 4,000
Credit facility – drawn (377)
Credit facility – letters of credit (702)
Total $2,947
Debt Type $MM
Credit facility $680
Total $680
Asset Type $MM
Cash $14
Total $14
Liquidity
Asset Type $MM
Cash $14
Credit facility – capacity 1,500
Credit facility – drawn (680)
Credit facility – letters of credit -
Total $834
Approximately $2.9 billion of liquidity at
AR pro forma for equity offering plus an
additional $2.6 billion of AM units
Approximately $800 million of liquidity
at AM
Only 45% of AM credit facility capacity drawn
Note: All balance sheet data as of 3/31/2016. Antero Resources pro forma for $762 million equity offering, less transaction costs, per press release dated 6/9/2016.
1. Mark-to-market as of 3/31/2016.
2. Based on AR ownership of AM units (108.9 million common and subordinated units) and AM’s closing price as of 6/9/2016.
3. AR credit facility commitments of $4.0 billion, borrowing base of $4.5 billion.
27

0.0x
0.5x
1.0x
1.5x
2.0x
2.5x
3.0x
3.5x
4.0x
4.5x
Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7
TotalDebt/LTMAdjusted
EBITDA
• $1.5 billion revolver in place to fund future growth capital
(5x Debt/EBITDA Cap)
• Liquidity of $834 million at 3/31/2016
• Sponsor (NYSE: AR) has Ba2/BB corporate debt ratings
AM Liquidity (3/31/2016)
AM Peer Leverage Comparison(1)
($ in millions)
Revolver Capacity $1,500
Less: Borrowings 680
Plus: Cash 14
Liquidity $834
1. As of 3/31/2016. Peers include TEP, EQM, WES, RMP, SHLX, DM, and CNNX.
2. AM includes full year EBITDA contribution from water business.
Financial Flexibility
28
(2)
STRONG FINANCIAL POSITION – SIGNIFICANT FINANCIAL
FLEXIBILITY

TOP TIER DISTRIBUTION GROWTH & HEALTHY COVERAGE
29
3–Year Street Consenus Distribution Growth Rate and DCF Coverage(1)
1. Based on Bloomberg 2015-2018 Bloomberg consensus estimates as of 3/31/2016.
31%
26% 25% 25%
23%
19%
15%
13% 12%
8%
1.5x
1.3x
1.4x
1.8x
1.3x
1.4x
1.2x
1.3x
1.3x
1.2x
0.00x
0.20x
0.40x
0.60x
0.80x
1.00x
1.20x
1.40x
1.60x
1.80x
2.00x
0%
5%
10%
15%
20%
25%
30%
35%
SHLX PSXP AM VLP DM EQM TEP MPLX CNNX WES

EQM
DM SHLX
CNNXWES
TEPMPLX
PSXP
VLP
0.0%
1.0%
2.0%
3.0%
4.0%
5.0%
6.0%
7.0%
8.0%
9.0%
10.0%
3% 8% 13% 18% 23% 28% 33%
Yield(%)
2016-2018 Distribution Growth CAGR
Bubble Size Reflects Market Capitalization
ATTRACTIVE VALUE PROPOSITION
30
AM – 03/31/15
Yield: 4.03%
Price: $21.81
AM - Implied
Yield: 2.85%
Price: $30.84
• Attractive appreciation potential on a relative basis
1. Based on Bloomberg 2015-2018 Bloomberg consensus distribution estimates and market data as of 3/31/2016.
R-squared = 88%

Antero Midstream (NYSE: AM)
Asset Overview
31

1. Represents inception to date actuals as of 12/31/2015 and 2016 guidance.
2. Includes both expansion capital and maintenance capital.
32
Utica
Shale
Marcellus
Shale
Projected Gathering and Compression Infrastructure(1)
Marcellus
Shale
Utica
Shale Total
YE 2015 Cumulative Gathering/
Compression Capex ($MM) $981 $462 $1,443
Gathering Pipelines
(Miles) 182 91 273
Compression Capacity
(MMcf/d) 700 120 820
Condensate Gathering Pipelines
(Miles) - 19 19
2016E Gathering/Compression
Capex Budget ($MM)(2) $235 $20 $255
Gathering Pipelines
(Miles) 30 1 31
Compression Capacity
(MMcf/d) 240 - 240
Condensate Gathering Pipelines
(Miles) - - -
Gathering and Compression Assets
ANTERO MIDSTREAM GATHERING AND COMPRESSION
ASSET OVERVIEW
• Gathering and compression assets in core of rapidly
growing Marcellus and Utica Shale plays
– Acreage dedication of ~597,000 gross leasehold
acres for gathering and compression services
– Additional stacked pay potential with dedication on
~277,000 gross acres of Utica deep rights
underlying the Marcellus in WV and PA
– 100% fixed fee long term contracts
• AR owns 62% of AM units (NYSE: AM)
Acquired Acreage

ANTERO MIDSTREAM ASSETS – RICH GAS MARCELLUS
33
• Provides Marcellus gathering and compression services
− Liquids-rich gas is delivered to MWE’s 1.2 Bcf/d
Sherwood processing complex
• Significant growth projected over the next twelve months as
set out below:
• Antero plans to operate an average of five drilling rigs in the
Marcellus Shale during 2016, including intermediate rigs
− 100% of rigs targeting the highly-rich gas/condensate
and highly-rich gas regimes
• All 80 gross wells targeted to be completed in 2016 are in
the AM dedicated area
− AM dedicated acreage contains 2,126 gross
undeveloped Marcellus locations
• Antero will defer an additional 62 completions, with 20 being
wells dedicated to a third-party midstream provider that were
originally scheduled for completion in 2016 but will now be
carried into 2017, in order to limit natural gas volumes sold
into unfavorable pricing markets
Marcellus Gathering & Compression
Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.
YE 2015 YE 2016E
Pipelines (Miles)
106 114
High Pressure Gathering
Pipelines (Miles)
76 98
Compression Capacity (MMcf/d) 700 940
Acquired Acreage

34
• Provides Utica gathering and compression services
− Liquids-rich gas delivered into MWE’s 800 MMcf/d
Seneca processing complex
− Condensate delivered to centralized stabilization and
truck loading facilities
• Significant growth projected over the next twelve months
as set out below:
• Antero plans to operate an average of two drilling rigs in the
Utica Shale during 2016, including intermediate rigs
− 100% of rigs targeting the highly-rich gas/condensate
and highly-rich gas regimes
• All 30 gross wells targeted to be completed in 2016 are on
Antero Midstream’s footprint
• Antero will defer an additional 8 completions in order to
limit natural gas volumes sold into unfavorable pricing
markets
Utica Gathering & Compression
ANTERO MIDSTREAM ASSETS – RICH & DRY GAS UTICA
YE 2015 YE 2016E
Pipelines (Miles)
55 56
High Pressure Gathering
Pipelines (Miles)
36 36
Condensate Pipelines (Miles) 19 19
Compression Capacity (MMcf/d) 120 120

ANTERO MIDSTREAM WATER BUSINESS OVERVIEW
35
1. Represents inception to date actuals as of 12/31/2015 and 2016 guidance.
2. All Antero water withdrawal sites are fully permitted under long-term state regulatory permits both in WV and OH.
3. Includes both expansion capital and maintenance capital.
4. Marcellus assumes fee of $3.69 per barrel subject to annual inflation and 351,000 barrels of water per well that utilize the fresh water delivery system based on 9,000 foot lateral. Operating margin excludes
G&A. Utica assumes fee of $3.64 per barrel subject to annual inflation and 306,000 barrels of water per well that utilize the fresh water delivery system based on 9,000 foot lateral. Operating margin
excludes G&A.
 AM acquired AR’s integrated water business for $1.05 billion plus earn out payments of $125 million at year-end in each of 2019 and 2020
− The acquired business includes Antero’s Marcellus and Utica freshwater delivery business, the fully-contracted future advanced wastewater
treatment complex and all fluid handling and disposal services for Antero
Projected Water Business Infrastructure(1)
Marcellus
Shale
Utica
Shale Total
YE 2015 Cumulative Fresh Water
Delivery Capex ($MM) $469 $62 $531
Water Pipelines
(Miles) 184 75 259
Fresh Water Storage
Impoundments 22 13 35
2016E Fresh Water Delivery Capex
Budget ($MM)(3) $40 $10 $50
Water Pipelines
(Miles) 20 9 29
Fresh Water Storage
Impoundments 1 - 1
Cash Operating
Margin per Well(4)
$950k -
$1,000k
$825k -
$875k
2016E Advanced Waste Water
Treatment Budget ($MM) $130
2016E Total Water Business
Budget ($MM) $180
Water Business Assets
• Fresh water delivery assets provide fresh water to support
Marcellus and Utica well completions
– Year-round water supply sources: Clearwater Facility, Ohio
River, local rivers & reservoirs(2)
– 100% fixed fee long term contracts
Antero Clearwater advanced wastewater
treatment facility currently under construction –
connects to Antero freshwater delivery system
Acquired Acreage

0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
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 Advanced
Wastewater Treatment
3rd Party Recycling
and Well Disposal
(Bbl/d)
Advanced Wastewater Treatment Complex
Estimated capital expenditures ($ million)(1) ~$275
Standalone EBITDA at 100% utilization(2) ~$55 – $65
Implied investment to standalone EBITDA build-out multiple ~4x – 5x
Estimated per well savings to Antero Resources ~$150,000
Estimated in-service date Late 2017
Operating capacity (Bbl/d) 60,000
Operating agreement
•Antero has contracted with Veolia to integrate an advanced wastewater treatment complex into its water business
• Veolia will build and operate, and Antero will own largest
advanced wastewater treatment complex in Appalachia
− Will treat and recycle AR produced and flowback water
− Creates additional year-round water source for completions
− Will have capacity for third party business over first two years
1. Includes capital to construct pipeline to connect facility to freshwater delivery system. Includes $10 million that AR agreed to fund in the drop down transaction.
2. Standalone EBITDA projection assumes inter-company fixed fee for recycling of $4.00 per barrel and 60,000 barrels per day of capacity. Does not include potential sales of marketable byproducts.
20 Years, Extendable
36Integrated Water Business
Antero Advanced
Wastewater Treatment
Freshwater delivery system
Flowback and
produced
Water
Well Pad
Well Pad
Completion
Operations
Producing
Freshwater
Salt
Calcium Chloride
Marketable byproduct
Marketable byproduct used in oil
and gas operations
Freshwater delivery system
ANTERO MIDSTREAM ADVANCED WASTEWATER TREATMENT
ASSET OVERVIEW

AM UPSIDE OPPORTUNITY SET
37
ACTIVITY CURRENTLY DEDICATED TO AM
Third Party Business
Processing, Fractionation,
Transportation and Marketing
• Opportunity to expand fresh water, waste water and
gathering/compression services to third parties in Marcellus
and Utica to enhance asset utilization
• AR must request a bid from AM and can only reject if third
party service fees are lower. AM has right to match
lower fee offer.
WV/PA Utica Dry Gas
• 277,000 gross acres of AR Utica dry gas acreage underlying
the Marcellus in West Virginia and Pennsylvania dedicated
to AM
• AR has drilled and completed its first WV Utica well
AR Acreage Consolidation
• 55,000 net acres acquired in 2016 by AR primarily
undedicated for gathering, compression, processing and
water services
• Future acreage acquisitions by AR are dedicated to AM

AR Gross
Processable
Acres
Gross 3P NGL
Reserves
(MMBbls)(1)
AR 3P Gross
Wellhead
Gas (Tcf)
Potential Processing AOD for AM
Tyler 94,000 655.7 12.2
Ritchie 51,000 295.1 6.3
Gilmer 14,000 42.7 1.1
Wetzel 54,000 204.3 8.8
Pleasants 7,000 20.9 0.4
Total 220,000 1,218.7 28.8
PROCESSING – VALUE CHAIN POTENTIAL
FOR UNDEDICATED ACREAGE
Sherwood
Processing
Complex
AR acreage position on map reflects tax districts in which greater than 3,000 net acres are held.
1. Antero gross 3P C3+ NGL volumes and 3P Gross Wellhead Gas reserves as of 12/31/2015, pro forma for AR acreage acquisition. Gross acres as of 3/31/2016.
Processing Area Of
Dedication for AM
MarkWest
Processing AOD
– 198,000 Gross
Acres
Tyler County
94,000 Gross Acres
Ritchie County
51,000 Gross Acres
 Antero Resources has 29 Tcf of processable gross 3P gas reserves and 1.2 billion Bbls of gross 3P NGL reserves
across 220,000 gross processable Marcellus acres that are dedicated to Antero Midstream for processing
38
Gilmer County
14,000 Gross Acres
Wetzel County
54,000 Gross Acres
Pleasants County
7,000 Gross Acres

LARGE UTICA SHALE DRY GAS POSITION
39
 Antero has completed its first dry gas Utica well – a 6,620’
lateral in Tyler County, WV
 Antero has 272,000 net acres of exposure to Utica dry gas
play in OH, WV and PA
 Other operators have reported strong Utica Shale dry gas
results including the following wells:
Well Operator
24-hr IP
(MMcf/d)
Lateral
Length
(Ft)
24-hr
IP/1,000’
Lateral
(MMcf/d)
Scotts Run EQT 72.9 3,221 22.633
Gaut GH9 CNX 61.9 6,141 11.131
Claysville
Sportsman
RRC 59.0 5,420 10.886
Stewart-Winland MHR 46.5 5,289 8.792
Bigfoot 9H RICE 41.7 6,957 5.994
Blake U-7H GST 36.8 6,617 5.561
Stalder #3UH MHR 32.5 5,050 6.436
Irons #1-4H GPOR 30.3 5,714 5.303
Pribble 6HU SGY 30.0 3,605 8.322
Simms U-5H GST 29.4 4,447 6.611
Conner 6H CVX 25.0 6,451 3.875
Messenger 3H SWN 25.0 5,889 4.245
Tippens #6H ECR 23.2 5,858 3.960
Porterfield 1H-17 HESS 17.2 5,000 3.440
1. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held in OH, WV and PA.
2. The Rymer 4HD has been flowing into the sales line for 90 days with an average choke-restricted flow rate of 20 MMcf/d.
RRC – Claysville Sportsman
5,420’ Lateral
24-hr IP: 59.0 MMcf/d
EQT – Scotts Run
3,221’ Lateral
CNX – GH9
6,141’ Lateral
EQT – Big 190
6,300’ Lateral
Completing
MHR – Stewart Winland
5,289’ Lateral
SGY – Pribble
3,605’ Lateral
Tughill – Blake
6,617’ Lateral
Tughill – Simms
4,447’ Lateral
Antero – Rymer 4HD
6,620’ Lateral
90-day IP: 20 MMcf/d
SWN – Messenger
5,889’ Lateral
ECR – Tippens
5,858’ Lateral
MHR – Stalder
5,050’ Lateral
CVX – Conner
6,451’ Lateral

Low Cost
Marcellus/Utica Focus
“Best-in-Class”
Distribution Growth
40
CATALYSTS
• 30% for 2016 and 28% to 30% for 2017 targeted based on Sponsor
planned development; additional third party business expansion
opportunities
• AM Sponsor is the most active operator in Appalachia;
• 17% production growth guidance for 2016 supported by $1.4 billion
capital budget, firm processing and takeaway, long-term natural gas
hedges and $2.9 billion of liquidity
• Targeting 20% to 25% production growth in 2017
• Sponsor operations target two of the lowest cost shale plays in
North America
• Attractive well economics support continued drilling at current prices
• $3.5 billion of capital investment opportunities over the next five
years, pro forma for the AR acreage acquisition
Appalachian Basin
Midstream Growth
High Growth Sponsor
Production Profile
1
2
3
4
5
6
• Acquisition of integrated water business from AR expected to result
in distributable cash flow per unit accretion in 2016
Consolidation and
Stacked Pay
Upside
• AR plans to continue to consolidate Marcellus/Utica acreage
• Development of Utica Shale Dry Gas resource will provide further
midstream infrastructure expansion opportunities
Integrated Water
Business Drop Down

Key Variable
Original
2016 Guidance
Updated
2016 Guidance
Financial:
Net Income ($MM) N/A $165 - $190
Adjusted EBITDA ($MM) $300 - $325 $325 - $350
Distributable Cash Flow ($MM) $250 - $275 $275 - $300
Year-over-Year Distribution Growth 28% - 30% 30%
Operating:
Low Pressure Pipeline Added (Miles) 9 9
High Pressure Pipeline Added (Miles) 22 22
Compression Capacity Added (MMcf/d) 240 240
Fresh Water Pipeline Added (Miles) 30 30
Capital Expenditures ($MM):
Gathering and Compression Infrastructure $240 $240
Fresh Water Infrastructure $40 $40
Advanced Wastewater Treatment $130 $130
Stonewall Gathering Pipeline Option(1) NA $45
Maintenance Capital $25 $25
Total Capital Expenditures ($MM) $435 $480
ANTERO MIDSTREAM – UPDATED 2016 GUIDANCE
Key Operating & Financial Assumptions
421. Antero Midstream closed on the acquisition of 15% interest in the Stonewall pipeline on 5/26/2016.

2016 UPDATED CAPITAL BUDGET
By Area
43
$423 Million – 2015(1)
By Segment ($MM)
$349
$6
$55
$13
Gathering & Compression Fresh Water Infrastructure
Advanced Wastewater Treatment Maintenance Capital
74%
26%
Marcellus Utica
By Area
$480 Million – 2016
By Segment ($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 Infrastructure
Advanced Wastewater Treatment Stonewall Pipeline
Maintenance Capital
95%
5%
Marcellus Utica

ANTERO RESOURCES – UPDATED 2016 GUIDANCE
Key Variable 2016 Guidance(1)
Net Daily Production (MMcfe/d) 1,750
Net Residue Natural Gas Production (MMcf/d) 1,355
Net C3+ NGL Production (Bbl/d) 52,500
Net Ethane Production (Bbl/d) 10,000
Net Oil Production (Bbl/d) 3,500
Net Liquids Production (Bbl/d) 66,000
Natural Gas Realized Price Premium to NYMEX Henry Hub Before Hedging ($/Mcf)(2)(3) +$0.00 to $0.10
Oil Realized Price Differential to NYMEX WTI Oil Before Hedging ($/Bbl) $(10.00) - $(11.00)
C3+ NGL Realized Price (% of NYMEX WTI)(2) 35% - 40%
Ethane Realized Price (Differential to Mont Belvieu) ($/Gal) $0.00
Operating:
Cash Production Expense ($/Mcfe)(4) $1.50 - $1.60
Marketing Expense, Net of Marketing Revenue ($/Mcfe) $0.15 - $0.20
G&A Expense ($/Mcfe) $0.20 - $0.25
Operated Wells Completed 110
Drilled Uncompleted Wells 70
Average Operated Drilling Rigs ≈ 7
Capital Expenditures ($MM):
Drilling & Completion $1,300
Land $100
Total Capital Expenditures ($MM) $1,400
1. Updated guidance per press release dated 4/27/2016.
2. Based on current strip pricing as of December 31, 2015.
3. Includes Btu upgrade as Antero’s processed tailgate and unprocessed dry gas production is greater than 1000 Btu on average.
4. Includes lease operating expenses, gathering, compression and transportation expenses and production taxes.
Key Operating & Financial Assumptions
44

Antero Long Term Firm Processing & Takeaway Position (YE 2018) – Accessing Favorable Markets
Mariner East 2
62 MBbl/d Commitment
Marcus Hook Export
Shell
Beaver County Cracker (2)
Sabine Pass (Trains 1-4)
50 MMcf/d per Train
(T1 in-service)
Lake Charles LNG(3)
150 MMcf/d
Freeport LNG
70 MMcf/d
1. May 2016 and full year 2016 futures basis, respectively, provided by Intercontinental Exchange dated 3/31/2016. Favorable markets shaded in green.
2. Shell announced FID on 6/7/2016.
3. Lake Charles LNG 150 MMcf/d commitment subject to BG FID expected in 2016.
Chicago(1)
$(0.03) /
$(0.03)
CGTLA(1)
$(0.06) /
$(0.06)
TCO(1)
$(0.11) /
$(0.14)
45
Cove Point LNG4.85 Bcf/d
Firm Gas
Takeaway
By YE 2018
 Antero’s natural gas firm transportation (FT) portfolio builds to 4.85 Bcf/d by YE 2018 with 87% serving favorable markets, with an average demand
fee of $0.46/MMBtu and positive weighted average basis differential to NYMEX after assumed Btu uplift for gas
YE 2018 Gas Market Mix
Antero 4.85 Bcf/d FT
44%
Gulf Coast
17%
Midwest
13%
Atlantic
Seaboard
13%
Dom S/TETCO
(PA)
13%
TCO
Positive
weighted
average basis
differential
Antero Commitments
(3)
(2)
LARGEST FIRM TRANSPORTATION AND PROCESSING
PORTFOLIO 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)
46
Shell
Beaver County Cracker
(Received FID June 2016)
Mariner East 2
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 West
50 MBbl/d C2

POSITIVE OUTLOOK FOR LONG-TERM NGL MARKETS
Steady Global LPG Demand Growth Through 2035(1)
1. Source: PIRA NGL Study, September 2015.
2. Source: IHS, Waterborne, SK Gas Analysis; Wood Mackenzie; Wood Mackenzie; PDH C3 capacity based on 25 MBbl/d = 650 Mt/y.
Multiple Factors Driving Global LPG Demand Growth Through 2020(2)
MMBbl/d
0.0
0.33
0.67
 Forecast global LPG demand growth of 800 MBbl/d to 1 MMBbl/d by 2020 to be driven by petrochem projects in Asia and Middle East as well as
residential/commercial, alkylate and power generation demand
− Naphtha cracker conversion to LPG another potential demand driver that has not yet been factored into analyst estimates ≈1 MMBbl/d
China Korea
Haiwei (2016)
- 21 MBbl/d C3
SK Advanced (2016)
- 27 MBbl/d C3
Ningbo Fuji (2016)
- 29 MBbl/d C3
Fujian Meide (2016)
- 29 MBbl/d C3
Tianjin Bohua 2 (2018)
- 29 MBbl/d C3 United States
Fujian Meide 2 (2018)
- 29 MBbl/d C3
Enterprise (3Q 2016)
- 29 MBbl/d C3
Oriental Tangshan (2019)
- 25 MBbl/d C3
Formosa (2017)
- 25 MBbl/d C3
Firm and Likely PDH Underway
(By 2020)
Total - 243 MBbl/d C3
Million Tons, Global PDH Capacity
1990 2000 2010 2020
20
10
0
47
14.7
13.0
11.4
9.8
8.2
6.5
4.9
3.3
1.7
U.S. Driven Global LPG Supply Through 2035(1)
MMBbl/d MMBbl/d
1.3
1.0
0.7
0.3
-0.3

GLOBAL LPG DEMAND DRIVEN BY
PETCHEM AND RES/COMM
 Largest end-use sectors for LPG are residential/commercial, which tends to grow with population and improvement in
living standards in the emerging markets
− PIRA forecasting >1.0 MMBbl/d over next 5 years and >4.5 MMBbl/d of global LPG demand growth over next 20 years
48
1. PIRA NGL Study, September 2015.
MMBbl/d
14.7
13.0
11.4
9.8
8.2
6.5
4.9
3.3
1.6

GLOBAL LPG TRADE DRIVEN BY U.S. SHALE
 The U.S. is the largest single driver of the rapid expansion in LPG trade accounting for over 90% in trade growth
49
MMBbl/d
5.2
4.6
3.9
3.3
2.6
2.0
1.3
0.7
United States

U.S. SHALE NGL EURS SUPPORT LPG TRADE GROWTH
50
• U.S. shale play NGL reserves are 50.8 billion barrels
• Eagle Ford, Marcellus, Utica, Bakken and Permian are the
work horses of U.S. shale production growth
• Marcellus/Utica NGL resource estimate by PIRA is 9.7 billion
barrels, in line with Antero estimate of ≈ 11.1 billion barrels
• The growth curve of each basin will ultimately be a function
of downstream solutions and investment
(1)
(1)
(1)

POSITIVE OUTLOOK FOR LONG-TERM
ETHANE MARKETS AS WELL
U.S. Ethane Supply/Demand Balance Through 2020(1)
1. Source: Bentek, August 2015.
2. Source: Citi research dated 7/15/2015.
U.S. Ethane Exports Through 2020(2)
 U.S. ethane demand is projected to increase at an annual 3.5% CAGR through 2020, primarily based on an ≈8% CAGR for U.S. petrochem
demand and a 30% growth in exports primarily to Europe
− The growth in shipping exports in 2016 and 2017 is driven by Enterprise Products’ 200 MBbl/d export facility on the Gulf Coast
-
0.5
1.0
1.5
2.0
2.5
2012 2013 2014 2015 2016 2017 2018 2019 2020
MMBb/d
Petchem Exports Rejection Total Supply (Net Stock Change)
U.S. Seaborne Ethane Exports Through 2020(2)
-
50
100
150
200
250
300
350
2013 2014 2015 2016 2017 2018 2019 2020
MBbl/d
Ship Pipeline
250
200
150
100
50
MBbl/d
U.S. exports increase
significantly into 2016
and 2017 as EPD’s
Morgan Point Facility
comes in-service
U.S. Ethane Rejection by Region Through 2020(1)
Access to both
Marcus Hook and
the Gulf Coast is
critical to
optimizing ethane
netbacks
Rejection declines
significantly into 2018
Unlike LPG, 80% of
ethane will be
consumed in the U.S.
Petrochem demand increases at
≈8% CAGR through 2020
-
100
200
300
400
500
600
2012 2013 2014 2015 2016 2017 2018 2019 2020
MBbl/d
Williston PADD 4 PADD 1 (East Coast) PADD 2 PADD 3
No Northeast
rejection after 2017
51
Northeast
Ethane
Rejection
Exports
U.S.
PetChem

LTM Production
NTM Production Forecast
Average 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
52
• 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
53
EBITDAX Reconciliation
($ in millions) Quarter Ended LTM Ended
3/31/2016 3/31/2016
EBITDAX:
Net income including noncontrolling interest $10.7 $591.5
Commodity derivative fair value (gains) (279.9) (1,901.9)
Net cash receipts on settled derivatives instruments 324.3 996.1
Interest expense 63.3 244.4
Income tax expense (benefit) 4.8 333.3
Depreciation, depletion, amortization and accretion 192.2 720.9
Impairment of unproved properties 15.5 111.3
Exploration expense 1.0 3.5
Equity-based compensation expense 23.5 93.6
State franchise taxes 0.0 (0.1)
Contract termination and rig stacking 0.0 29.6
Consolidated Adjusted EBITDAX $355.4 $1,222.2

ANTERO MIDSTREAM EBITDA RECONCILIATION
54
EBITDA and DCF Reconciliation
$ in thousands
Three months ended
March 31,
2015 2016
Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow:
Net income $32,327 $42,918
Add:
Interest expense 1,586 3,461
Depreciation expense 20,702 23,823
Contingent acquisition consideration accretion - 3,396
Equity-based compensation 5,779 5,972
Adjusted EBITDA $60,394 $79,570
Pre-Water Acquisition net income attributed to parent (16,679) -
Pre-Water Acquisition depreciation expense attributed to parent (6,120) -
Pre-Water Acquisition equity-based compensation expense attributed to parent (1,156) -
Pre-Water Acquisition interest expense attributed to parent (763) -
Adjusted EBITDA attributable to the Partnership 35,676 79,570
Less:
Cash interest paid - attributable to Partnership (579) (3,444)
Cash reserved for payment of income tax witholding upon vesting of Antero Midstream LP equity-based
compensation awards - (1,000)
Maintenance capital expenditures attributable to Partnership (2,408) (5,808)
Distributable Cash Flow $32,689 $69,318

CAUTIONARY NOTE
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserve estimates
(collectively, “3P”). Antero has provided internally generated estimates for proved, probable and possible reserves in this presentation in
accordance with SEC guidelines and definitions, which have been audited by Antero’s third-party engineers. Unless otherwise noted,
reserve estimates as of December 31, 2015 assume ethane rejection and strip pricing.
Actual quantities that may be ultimately recovered from Antero’s interests may differ substantially from the estimates in this presentation.
Factors affecting ultimate recovery include the scope of Antero’s ongoing drilling program, which will be directly affected by commodity
prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease
expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and
mechanical factors affecting recovery rates.
In this presentation:
• “3P reserves” refer to Antero’s estimated aggregate proved, probable and possible reserves as of December 31, 2015. The SEC
prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of
certainty associated with each reserve category.
• “EUR,” or “Estimated Ultimate Recovery,” refers to Antero’s internal estimates of per well hydrocarbon quantities that may be
potentially recovered from a hypothetical future well completed as a producer in the area. These quantities do not necessarily
constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management
System or the SEC’s oil and natural gas disclosure rules.
• “Condensate” refers to gas having a heat content between 1250 BTU and 1300 BTU in the Utica Shale.
• “Highly-rich gas/condensate” refers to gas having a heat content between 1275 BTU and 1350 BTU in the Marcellus Shale and 1225
BTU and 1250 BTU in the Utica Shale.
• “Highly-rich gas” refers to gas having a heat content between 1200 BTU and 1275 BTU in the Marcellus Shale and 1200 BTU and
1225 BTU in the Utica Shale.
• “Rich gas” refers to gas having a heat content of between 1100 BTU and 1200 BTU.
• “Dry gas” refers to gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or
to require their removal in order to render the gas suitable for fuel use.
Regarding Hydrocarbon Quantities
55

Am website presentation (b) june 2016

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Am website presentation (b) june 2016