Am website presentation (a) march 2016

1. Partnership Overview
March 2016

2. 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.

3. 2
CHANGES SINCE MARCH 2016 PRESENTATION
Updated AR slide showing Marcellus and Utica single
well economics for new well costs
Slide 9

4. Sustainable
Business
Model
High Growth Sponsor
Drives AM Throughput
and Distribution Growth
Largest Dedicated Core
Liquids-Rich Acreage
Position in Appalachia
$900 Million of
AM Liquidity
3
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
Consolidated Acreage
Position in Lowest
Unit Cost Basin

5. 0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
EQT CHK COG AR SWN RRC CNX
-
100
200
300
400
500
600
AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6
Core Net Acres - Dry Core Net Acres - Liquids Rich
Top Producers in Appalachia (Net MMcfe/d) – 4Q 2015(1)(2)
Top 12 U.S. Natural Gas Producers (Net MMcf/d) – 4Q 2015(1)
Appalachian Producers by Proved Reserves (Bcfe) – YE 2015(1)(2) Appalachian Producers by Core Net Acres (000’s) – December 2015(4)
1. Based on company filings and presentations.
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.
(3)
4
4th Largest
Appalachian
Producer
 Antero has the largest proved reserve base, largest core liquids-rich acreage position and is one of the largest producers in the Appalachian Basin
Appalachian Peers
11th Largest
U.S. Gas
Producer
Largest Proved
Reserve Base In
Appalachia Largest Liquids-
Rich Core Position
in Appalachia
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
SPONSOR STRENGTH – LEADERSHIP IN APPALACHIAN BASIN

6. 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. 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.
2. 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.
3. Antero and industry rig locations as of 3/11/2016, per RigData.
5
COMBINED TOTAL – 12/31/15 RESERVES
Assumes Ethane Rejection
Net Proved Reserves 13.2 Tcfe
Net 3P Reserves 37.1 Tcfe
Strip Pre-Tax 3P PV-10(1) $11.2 Bn
Net 3P Reserves & Resource 50 to 53 Tcfe
Net 3P Liquids 1,237 MMBbls
% Liquids – Net 3P 20%
4Q 2015 Net Production 1,497 MMcfe/d
- 4Q 2015 Net Liquids 54,750 Bbl/d
Net Acres(2) 569,000
Undrilled 3P Locations 3,719
OHIO UTICA SHALE CORE
Net Proved Reserves 1.8 Tcfe
Net 3P Reserves 7.5 Tcfe
Strip Pre-Tax 3P PV-10(1) $2.5 Bn
Net Acres 147,000
Undrilled 3P Locations 814
MARCELLUS SHALE CORE
Net Proved Reserves 11.4 Tcfe
Net 3P Reserves 29.6 Tcfe
Strip Pre-Tax 3P PV-10(1) $8.7 Bn
Net Acres 422,000
Undrilled 3P Locations 2,905
WV/PA UTICA SHALE DRY GAS
Net Resource 12.5 to 16 Tcf
Net Acres 188,000
Undrilled Locations 1,889
0
1
2
3
4
5
6
7
8
9
RigCount
Operators
Current SW Marcellus & Utica(3)
SPONSOR STRENGTH – MOST ACTIVE OPERATOR
IN APPALACHIA

7. $1
$5 $7 $8
$11
$19
$28
$36
$41
$55
$83
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
26 31 40 36 41
116
222
358
454 435
478
0
100
200
300
400
500
600
700
800 Utica Marcellus
10 38 80 126
266
531
908
1,134 1,197 1,216 1,195
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800 Utica Marcellus
108
216
281 331 386
531
738
935 965
1,038
1,124
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800 Utica Marcellus
Low Pressure Gathering (MMcf/d)
Compression (MMcf/d)
High Pressure Gathering (MMcf/d)
EBITDA ($MM)
6
$313
Note: Y-O-Y growth based on 4Q’14 to 4Q’15.
1. Represents midpoint of 2016 guidance .
GROWTH – HIGH GROWTH MIDSTREAM THROUGHPUT

8. $0.170
$0.180
$0.190
$0.205
1.1x
1.2x
1.3x
1.4x
1.8x
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 1Q16E 2Q16E 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E
Distribution Per Unit (Left Axis) DCF Coverage (Right Axis)
$0.220
7
• Antero Midstream is targeting 28% to 30% annual distribution growth through 2017
• AM has delivered on those targets with DCF coverage of 1.4x in the third quarter 2015
Note: Future distributions subject to AM Board approval.
1. Assumes midpoint of target distribution growth range.
2. 4Q 2015 distribution per Partnership press release dated 1/13/2016.
(2)
GROWTH – TOP TIER DISTRIBUTION GROWTH

9. 8
LIQUIDS-RICH – LARGEST CORE POSITION
Source: Core outlines and peer net acreage positions based on investor presentations, news releases and 10-K/10-Qs. Rig information per RigData as of 1/1/2016.
1. Based on company filings and presentations. Peer group includes Ascent, CHK, CNX, CVX, ECR, EQT, GPOR, NBL, 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
≈371,000 net acres (> 1100 Btu)
• Represents over 21% of core liquids-
rich acreage in Marcellus and Utica
plays combined
 Antero has over 3,000 undeveloped rich gas locations with an average lateral length of 6,800’ in its 3P reserves as of 12/31/2014
0
100
200
300
400
(000s)
Core Liquids-Rich Net Acres(1)

10. 626 971
553
755
70% 52%
27%
32%37%
25%
10% 13%
0
400
800
1,200
0%
20%
40%
60%
80%
Highly-Rich
Gas/
Condensate
Highly-Rich Gas Rich Gas Dry Gas
Total3PLocations
ROR
Total 3P Locations ROR @ 12/31/2015 Strip Pricing - After Hedges ROR @ 12/31/2015 Strip Pricing - Before Hedges
184
98
108
161
263
17%
62%
85%
73%
82%
11%
28% 29%
24% 27%
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)
Marcellus Well Cost Improvement(3)
1. 12/31/2015 pre-tax well economics based on a 9,000’ lateral, 12/31/2015 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, which include $1.2 million for road, pad and production facilities.
2. ROR @ 12/31/2015 Strip-With Hedges reflects 12/31/2015 well cost ROR methodology, with the 12/31/2015 hedge value allocated based on 2016-2021 projected production volumes resulting in blend of
strip and hedge prices.
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.
9
UTICA WELL ECONOMICS(1)(2)
 74% of Marcellus locations are processable (1100-plus Btu)  68% of Utica locations are processable (1100-plus Btu)
2016
Drilling
Plan
 Antero has reduced average well costs for a 9,000’ lateral by 16% in the Marcellus and 18% in the Utica as compared to 2014 well costs
 At 12/31/2015 strip pricing, Antero has 2,227 locations that exceed a 20% rate of return (excluding hedges)
– Including hedges, these locations generate rates of return of approximately 50% to 80%
Utica Well Cost Improvement(3)
$1.36
$1.14
$0.95
$0.000
$0.500
$1.000
$1.500
$2.000
2014 2015 Current Spot
$MM/1,000’Lateral
Well Cost ($MM/1,000' of Lateral)
16%
Decrease
vs. 2014
$1.57
$1.29
$1.14
$0.000
$0.500
$1.000
$1.500
$2.000
2014 2015 Current Spot
$MM/1,000’Lateral
Well Cost ($MM/1,000' of Lateral)
18%
Decrease
vs. 2014
12%
Decrease
vs. 2015
17%
Decrease
vs. 2015
SUSTAINABLE BUSINESS MODEL – AR MULTI-YEAR DRILLING
INVENTORY SUPPORTS LOW RISK, HIGH RETURN GROWTH PROFILE

11. 10
In-service 2016 Budget
HIGH VISIBILITY – PROJECTED MARCELLUS
MIDSTREAM BUILDOUT

12. 11
In-service 2016 Budget
HIGH VISIBILITY – PROJECTED UTICA
MIDSTREAM BUILDOUT

13. 10
0
5
0 0
7
0
5
10
15
AM CNNX EQM CMLP SMLP RMP
Fixed
Fee
100%
Fixed
Fee
100%
12
MITIGATED COMMODITY RISK – 100% FIXED FEE – RICH TO DRY
Contract Mix
Fixed
Fee
97%
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 1/1/2016, 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)

14. -
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
13
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
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

15. $0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$0
$50
$100
$150
$200
$250
$300
$MM
14
HEDGING – INTEGRAL TO BUSINESS MODEL
 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 well payout thereby enhancing liquidity
 Antero has realized $1.7 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 12/31/2015, the unrealized commodity derivative value is $3.1 billion
● Significant additional hedge capacity remains under the credit facility hedging covenant for 2018 – 2022 period
Quarterly Realized Hedge Gains / (Losses)
Realized Hedge Gains
Projected Hedge Gains
NYMEX Natural Gas
Historical Spot Prices
($/MMBtu)
NYMEX Natural Gas
Futures Prices
3.5 Tcfe Hedged at
average price of
$3.79/Mcfe
through 2022
Average Hedge Prices
($/Mcfe)
$3.50
$3.94
$3.57
$3.88 $3.89
$3.73
$3.30
$3.1 Billion on
Balance Sheet in
Hedge Gains
Through 2022Realized $1.7 Billion
in Hedge Gains
Since 2009

16. Regional Gas Pipelines
Miles Capacity In-Service
Stonewall Gathering
Pipeline(2)
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. AM holds option to purchase 15% of Stonewall pipeline at cost plus cost of carry.
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
(Miles) YE 2015 YE 2016E
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
(Miles) YE 2015 YE 2016E
Utica 19 19
End
Users
AM Option Assets
(Ethane, Propane,
Butane, etc.)
15
VALUE CHAIN OPPORTUNITY – FULL MIDSTREAM VALUE CHAIN

17. Note: All balance sheet data as of 12/31/2015.
1. Mark-to-market as of 12/31/2015.
2. Based on AR ownership of AM units (116.9 million common and subordinated units) and AM’s closing price as of 3/16/2016.
3. AR credit facility commitments of $4.0 billion, borrowing base of $4.5 billion.
Liquid “non-E&P assets” of $6.1 Bn
significantly exceeds total debt of $4.1 Bn
Liquidity
Antero Resources (NYSE:AR) Antero Midstream (NYSE:AM)
12/31/2015 Debt Liquid Non-E&P Assets 12/31/2015 Debt Liquid Assets
Debt Type $MM
Credit facility $707
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 $4,082
Asset Type $MM
Commodity derivatives(1) $3,117
AM equity ownership(2) 2,960
Cash 16
Total $6,093
Asset Type $MM
Cash $16
Credit facility – commitments(3) 4,000
Credit facility – drawn (707)
Credit facility – letters of credit (702)
Total $2,607
Debt Type $MM
Credit facility $620
Total $620
Asset Type $MM
Cash $7
Total $7
Liquidity
Asset Type $MM
Cash $7
Credit facility – capacity 1,500
Credit facility – drawn (620)
Credit facility – letters of credit -
Total $887
Approximately $2.6 billion of liquidity at AR
plus an additional $3.0 billion of AM units
Approximately $900 million of liquidity
at AM
16
Only 41% of AM credit facility capacity drawn
STRONG FINANCIAL POSITION – STRONG BALANCE SHEET
AND FLEXIBILITY

18. 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/LTMEBITDA
• $1.5 billion revolver in place to fund future growth capital
(5x Debt/EBITDA Cap)
• Liquidity of $887 million at 12/31/2015
• Sponsor (NYSE: AR) has Ba2/BB corporate ratings
AM Liquidity (12/31/2015)
AM Peer Leverage Comparison(1)
($ in millions)
Revolver Capacity $1,500
Less: Borrowings 620
Plus: Cash 7
Liquidity $887
1. As of 12/31/2015. Peers include TEP, EQM, WES, RMP, SHLX, DM, and CNNX.
2. AM includes full year EBITDA contribution from water business.
Financial Flexibility
17
(2)
STRONG FINANCIAL POSITION – SIGNIFICANT FINANCIAL
FLEXIBILITY

19. TOP TIER DISTRIBUTION GROWTH & HEALTHY COVERAGE
18
3–Year Street Consenus Distribution Growth Rate and DCF Coverage(1)
28% 28% 27%
26%
24% 23%
20%
17%
13%
11%
1.7x
1.5x
1.3x
1.7x
1.1x
1.4x
1.3x 1.3x
1.4x
1.3x
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%
SHLX AM PSXP VLP MPLX DM EQM TEP CNNX WES
1. Based on Bloomberg 2015-2018 Bloomberg consensus estimates as of 12/31/2015.

20. WES
CNNX
TEP
EQM
MPLX
DM
VLP
PSXP
SHLX
0.0%
1.0%
2.0%
3.0%
4.0%
5.0%
6.0%
7.0%
8.0%
9.0%
10.0%
3.0% 8.0% 13.0% 18.0% 23.0% 28.0% 33.0%
Yield(%)
2015-2018 Distribution Growth CAGR(1)
Bubble Size Reflects Relative Market Capitalization
R-squared = .76
ATTRACTIVE VALUE PROPOSITION
19
AM – 12/31/15
Yield: 3.59%
Price: $22.82
AM - Implied
Yield: 2.39%
Price: $34.34
• Attractive appreciation potential on a relative basis
1. Based on Bloomberg 2015-2018 Bloomberg consensus distribution estimates and market data as of 12/31/2015.

21. Antero Midstream (NYSE: AM)
Asset Overview
20

22. 1. Represents inception to date actuals as of 12/31/2015 and 2016 guidance.
2. Includes both expansion capital and maintenance capital.
21
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 ~438,000 net leasehold
acres for gathering and compression services
– Additional stacked pay potential with dedication on
~147,000 acres of Utica deep rights underlying the
Marcellus in WV and PA
– 100% fixed fee long term contracts
• AR owns 66% of AM units (NYSE: AM)

23. ANTERO MIDSTREAM ASSETS – RICH GAS MARCELLUS
22
• Provides Marcellus gathering and compression services
− Liquids-rich gas is delivered to MWE’s 1.2 Bcf/d
Sherwood processing complex
• Significant growth projected over the next twelve months as
set out below:
• Antero plans to operate an average of five drilling rigs in the
Marcellus Shale during 2016, including intermediate rigs
− 100% of rigs targeting the highly-rich gas/condensate
and highly-rich gas regimes
• All 80 gross wells targeted to be completed in 2016 are in
the AM dedicated area
− AM dedicated acreage contains 2,126 gross
undeveloped Marcellus locations
• Antero will defer an additional 62 completions, with 20 being
wells dedicated to a third-party midstream provider that were
originally scheduled for completion in 2016 but will now be
carried into 2017, in order to limit natural gas volumes sold
into unfavorable pricing markets
Marcellus Gathering & Compression
Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.
YE 2015 YE 2016E
Low Pressure Gathering
Pipelines (Miles)
106 114
High Pressure Gathering
Pipelines (Miles)
76 98
Compression Capacity (MMcf/d) 700 940

24. 23
• 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 35 gross wells targeted to be completed in 2016 are on
Antero Midstream’s footprint
• Antero will defer an additional 8 completions in order to
limit natural gas volumes sold into unfavorable pricing
markets
Utica Gathering & Compression
Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.
ANTERO MIDSTREAM ASSETS – RICH & DRY GAS UTICA
YE 2015 YE 2016E
Low Pressure Gathering
Pipelines (Miles)
55 56
High Pressure Gathering
Pipelines (Miles)
36 36
Condensate Pipelines (Miles) 19 19
Compression Capacity (MMcf/d) 120 120

25. ANTERO MIDSTREAM WATER BUSINESS OVERVIEW
24
Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.
1. Represents inception to date actuals as of 12/31/2015 and 2016 guidance.
2. All Antero water withdrawal sites are fully permitted under long-term state regulatory permits both in WV and OH.
3. Includes both expansion capital and maintenance capital.
4. Marcellus assumes fee of $3.685 per barrel subject to annual inflation and 250,000 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 $3.635 per barrel subject to annual inflation and 275,000 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 $125 million at year-end in each of 2019 and 2020
− The acquired business includes Antero’s Marcellus and Utica freshwater delivery business, the fully-contracted future advanced wastewater
treatment complex and all fluid handling and disposal services for Antero
Antero advanced wastewater treatment facility to be
constructed – connects to Antero freshwater delivery system
Projected Water Business Infrastructure(1)
Marcellus
Shale
Utica
Shale Total
YE 2015 Cumulative Fresh Water
Delivery Capex ($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) $700k - $750k
$775k -
$825k
2016E Advanced Waste Water
Treatment Budget ($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

26. 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
25Integrated 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

27. ORGANIC GROWTH STRATEGY: “BUILD VS. BUY”
26
• Organic growth strategy provides attractive
returns and project economics, while
avoiding the competitive acquisition market
• Industry leading organic growth story
– ~$1.06 billion in 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 2015 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.
6.8x
11.9x
10.7x
10.0x
9.3x
9.0x 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 4x to 7x EBITDA
vs.
Drop Down / Buy at 8x to 12x EBITDA

28. LP
Gathering
HP
Gathering Compression
Condensate
Gathering
Fresh Water
Delivery
Advanced
Wastewater
Treatment
Regional
Pipeline
Processing/
Fractionation
Unlevered IRR Range: 25% - 35% 15% - 25% 10% - 20% 25% - 35% 30% - 40% 15% - 25% 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 6.0 - 8.0 3.5 - 7.0 5.0 - 6.0
Minimum Volume Commitments: N/A 75% 70% N/A Yes N/A 80% 80%
2016 Expansion
Capex(2) Total
Marcellus $388 $33 $49 $143 - $33 $130
Utica 22 7 1 7 - 7 -
Growth Capex $410 $40 $50 $150 $0 $40 $130
% of Capex 100% 10% 12% 37% 0% 10% 32%
Included in 2016 Budget: Marcellus &
Utica
Marcellus &
Utica
Marcellus &
Utica
Utica Marcellus &
Utica
Marcellus &
Utica
Not Included Not Included
Additional In-hand
Opportunities:
Dry Utica Dry Utica Dry Utica Utica
Stabilization
Dry Utica Dry Utica Regional
Gathering
Pipeline
Marcellus
Processing/
Fractionation
25%
15%
10%
25%
30%
15% 15% 15%
35%
25%
20%
35%
25% 25%
40%
20%
0%
10%
20%
30%
40%
InternalRateofReturn
27
Project Economics by Segment(1)
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.
Wtd. Avg. 21% IRR
AM Option Opportunities

29. AM UPSIDE OPPORTUNITY SET
28
ACTIVITY CURRENTLY DEDICATED TO AM
Third Party Business
Processing, Fractionation,
Transportation and Marketing
Regional Pipeline Project
• Option to participate for up to 15% in regional gathering
pipeline project in West Virginia that went in-service
12/1/2015
• Additive to full value chain model
• 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
• 188,000 net 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
Active AR Leasing
• Future acreage acquisitions by AR are dedicated to AM
• Added 92,000 net acres in 2014 and added 26,000 net
acres in 2015

30. REGIONAL PIPELINE PROJECT
•Option to Acquire Up To 15% Non-Op Equity
Interest
●Enables Antero Resources to move 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 moving ~950 MMcf/d
Regional Gathering Pipeline
Throughput Capacity: 1.4 Bcf/d
Pipeline
Specifications:
50 miles of 36 inch pipeline
Project Capital: ≈ $400 Million
In-Service Date: 12/1/2015
AR Firm Commitment: 900 MMcf/d
29

31. AR Gross
Processable
Acres
Gross 3P NGL
Reserves
(MMBbls)(1)
AR 3P Gross
Wellhead
Gas (Tcf)
Potential Processing AOD for AM
Tyler 78,000 406.8 7.4
Ritchie 49,000 295.1 6.3
Gilmer 14,000 42.7 1.1
Total 141,000 744.6 14.8
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.
Processing Area Of
Dedication for AM
MarkWest
Processing AOD
– 194,500 Gross
Acres
Tyler County
78,000 Gross Acres
Ritchie County
49,000 Gross Acres
 Antero Resources has 14.8 Tcf of processable gross 3P gas reserves and 745 Million Bbls of gross 3P NGL
reserves across 141,000 gross processable Marcellus acres that are dedicated to Antero Midstream for processing
30
Gilmer County
14,000 Gross Acres

32. LARGE UTICA SHALE DRY GAS POSITION
31
 Antero has completed its first dry gas Utica well – a 6,620’
lateral in Tyler County, WV
 Antero has 229,000 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:
Chesapeake
Hubbard BRK #3H
3,550’ Lateral
IP 11.1 MMcf/d
Hess
Porterfield 1H-17
5,000’ Lateral
IP 17.2 MMcf/d
Gulfport
Irons #1-4H
5,714’ Lateral
IP 30.3 MMcf/d
Eclipse
Tippens #6H
5,858’ Lateral
IP 23.2 MMcf/d
Magnum Hunter
Stalder #3UH
5,050’ Lateral
IP 32.5 MMcf/d
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 4IH CNX 61.0 5,840 11.131
CSC #11H RRC 59.0 5,420 10.886
Stewart-Win 1300U MHR 46.5 5,289 8.792
Bigfoot 9H RICE 41.7 6,957 5.994
Blank 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.
Magnum Hunter
Stewart Winland 1300U
5,289’ Lateral
IP 46.5 MMcf/d
Range
Claysville SC #11H
5,420’ Lateral
IP 59.0 MMcf/d
Chevron
Conner 6H
6,451’ Lateral
IP 25.0 MMcf/d
Gastar
Simms U-5H
4,447’ Lateral
IP 29.4 MMcf/d
Utica Shale Dry Gas Acreage in OH/WV/PA(1)
Rice
Bigfoot 9H
6,957’ Lateral
IP 41.7 MMcf/d
AR Utica Shale Dry Gas
WV/PA
Net Resource
12.5 to 16 Tcf
1,889 Gross Locations
188,000 Net Acres
AR Utica Shale Dry Gas
Ohio
3P Reserves
2.3 Tcf
263 Gross Locations
41,000 Net Acres
AR Utica Shale Dry Gas
Total OH/WV/PA
Net Resource
14.8 to 18.3 Tcf
2,152 Gross Locations
229,000 Net Acres
Stone Energy
Pribble 6HU
3,605’ Lateral
IP 30.0 MMcf/d
Southwestern
Messenger 3H
5,889’ Lateral
IP 25.0 MMcf/d
Rice
Blue Thunder
10H, 12H
≈9,000’ Lateral
Gastar
Blake U-7H
6,617’ Lateral
IP 36.8 MMcf/d
EQT
Scotts Run
3,221’ Lateral
IP 72.9 MMcf/d
CNX
Gaut 4IH
5,840’ Lateral
IP 61.0 MMcf/d
Antero
Rymer 4HD
6,620’ Lateral
IP 20.0 MMcf/d
(2)

33. Low Cost
Marcellus/Utica Focus
“Best-in-Class”
Distribution Growth
32
CATALYSTS
28% to 30% per year for 2016 and 2017 targeted based on Sponsor
planned development; additional third party business expansion
opportunities
AM Sponsor is the most active operator in Appalachia; 15% production
growth guidance for 2016 supported by $1.4 billion capital budget, firm
processing and takeaway, long-term natural gas hedges and $2.6 billion
of liquidity; targeting 20% 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
Multiple opportunities exist for additional gathering and compression,
processing and pipeline assets for Sponsor and third party use
Appalachian Basin
Midstream Growth
High Growth Sponsor
Production Profile
1
2
3
4
5
6
Acquisition of integrated water business from Antero expected to result
in distributable cash flow per unit accretion in 2016
Stacked Pay Basin
Upside
Development of Utica Shale Dry Gas and Upper Devonian resources
provide further midstream infrastructure expansion opportunities
Integrated Water
Business Drop Down

34. APPENDIX
33

35. ANTERO MIDSTREAM – 2016 GUIDANCE
Key Variable 2016 Guidance
Financial:
Adjusted EBITDA ($MM) $300 - $325
Distributable Cash Flow ($MM) $250 - $275
Year-over-Year Distribution Growth(1) 28% - 30%
Operating:
Low Pressure Pipeline Added (Miles) 9
High Pressure Pipeline Added (Miles) 22
Compression Capacity Added (MMcf/d) 240
Fresh Water Pipeline Added (Miles) 30
Capital Expenditures ($MM):
Gathering and Compression Infrastructure $240
Fresh Water Infrastructure $40
Advanced Wastewater Treatment $130
Maintenance Capital $25
Total Capital Expenditures ($MM) $435
1. Reflects the expected distribution growth percentage associated with the fourth quarter 2016 over the fourth quarter 2015.
Key Operating & Financial Assumptions
34

36. 2016 CAPITAL BUDGET
By Area
35
$423 Million – 2015(1)
By Segment ($MM)
$349
$6
$55
$13
Gathering & Compression Fresh Water Infrastructure
Advanced Wastewater Treatment Maintenance Capital
74%
26%
Marcellus Utica
By Area
$435 Million – 2016
By Segment ($MM)
 Antero Midstream’s 2016 initial capital budget is $435 million, a 3% increase from 2015 capital expenditures of $423 million
3%
130 Completions
1. Excludes $1.05 billion water drop down in September 2015. Water capex values only from 4Q 2015.
$240
$40
$130
$25
Gathering & Compression Fresh Water Infrastructure
Advanced Wastewater Treatment Maintenance Capital
92%
8%
Marcellus Utica

37. ANTERO RESOURCES – 2016 GUIDANCE
Key Variable 2016 Guidance
Net Daily Production (MMcfe/d) 1,715
Net Residue Natural Gas Production (MMcf/d) 1,355
Net C3+ NGL Production (Bbl/d) 46,500
Net Ethane Production (Bbl/d) 10,000
Net Oil Production (Bbl/d) 3,500
Net Liquids Production (Bbl/d) 60,000
Natural Gas Realized Price Premium to NYMEX Henry Hub Before Hedging ($/Mcf)(1)(2) +$0.00 to $0.10
Oil Realized Price Differential to NYMEX WTI Oil Before Hedging ($/Bbl) $(10.00) - $(11.00)
C3+ NGL Realized Price (% of NYMEX WTI)(1) 35% - 40%
Ethane Realized Price (Differential to Mont Belvieu) ($/Gal) $0.00
Operating:
Cash Production Expense ($/Mcfe)(3) $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. Based on current strip pricing as of December 31, 2015.
2. Includes Btu upgrade as Antero’s processed tailgate and unprocessed dry gas production is greater than 1000 Btu on average.
3. Includes lease operating expenses, gathering, compression and transportation expenses and production taxes.
Key Operating & Financial Assumptions
36

38. Antero Long Term Firm Processing & Takeaway Position (YE 2018) – Accessing Favorable Markets
Mariner East 2
62 MBbl/d Commitment
Marcus Hook Export
Shell
20 MBbl/d Commitment
Beaver County Cracker (2)
Sabine Pass (Trains 1-4)
50 MMcf/d per Train
Lake Charles LNG(3)
150 MMcf/d
Freeport LNG
70 MMcf/d
1. February 2016 and full year 2016 futures basis, respectively, provided by Intercontinental Exchange dated 12/31/2015. Favorable markets shaded in green.
2. Subject to Shell FID expected mid-year 2016.
3. Lake Charles LNG 150 MMcf/d commitment subject to BG FID expected in 2016.
Chicago(1)
$0.25 /
$0.02
CGTLA(1)
$(0.07) /
$(0.06)
TCO(1)
$(0.16) /
$(0.18)
37
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

39. NORTHEAST NGLS ARE TRANSPORTATION CHALLENGED
1. As an anchor shipper on Mariner East 2, Antero has the right to expand its NGL commitment with notice to operator.
2. 2015 NGL production assumes ethane rejection.
Mariner East 2
61,500 Bbl/d AR
Commitment(1)
4Q 2016 In-Service
 Not so much a supply problem but more of a logistics problem for NGLs in the northeast today
− The majority of northeast NGL production is being transported by expensive rail and trucking
− NGLs that are transported “to the water” are also faced with high shipping rates
Export
15%
Gulf
Coast
13%
Mid-
Atlantic
6%
Sarnia
3%
Northeast
43%
Midwest
10%
Edmonton
10%
2015 NGL Marketing by Region
38

40. 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 (2015) and Projected(1)
39
Shell
Beaver County Cracker
(Pending FID 1H 2016)
Mariner East 2
62 MBbl/d Commitment
Marcus Hook Export
Gulf Coast
Critical to
NGL Pricing
Appalachia
 NGL transportation rates are expected to decline $0.12 to $0.15 per gallon by 2017 as pipeline options to domestic markets and
export terminals go in-service (Mariner East 1 and 2, for example)
(MMBbl/d)

41. $0.00
$0.10
$0.20
$0.30
$0.40
$0.50
$/Gallon
Baltic Exchange LPG Freight Futures
Baltic LPG Rate ($/gal) Marcus Hook to Europe ($/gal)
Marcus Hook to Far East ($/gal)
U.S. EXPORTS ARE SUPPORTED BY EXCESS
DOCK CAPACITY AND FLEET GROWTH
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
MBbl/d
Butane Exports Propane Exports Total Export Capacity
Excess LPG Export Terminal Capacity vs. Expected Export Volumes(1)
Excess dock capacity supports
growing LPG export volumes
through 2025
Fleet Growth Supports U.S. LPG Export Growth(2) LPG Freight Futures Show Declining Freight Costs(3)
Baltic LPG shipping cost declines from
$0.14/gal to $0.09-$0.10/gal in early 2017
on fleet supply growth numbers
Projected growth in VLGC
fleet supports increasing
LPG export volumes and
lower shipping costs
1. Source: Bentek.
2. Source: Poten & Partners, August 2015.
3. Baltic Rate based on 9/30/2015 Baltic Futures converted to cost per gallon of LPGs, assuming 75/25 propane/butane.
 LPG transportation rates from northeast fractionation to Europe and Asia should improve by $0.05 to $0.15 per gallon by YE 2016,
driven both by pipelines replacing rail and by lower shipping costs
Excess Dock Capacity
Current Fleet 168
New builds +85
40

42. 2015 GLOBAL LPG DEMAND
 Global LPG demand is 8.5 MMBbl/d and growing
41

43. 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
42
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

44. 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
43
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

45. 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
44
1. PIRA NGL Study, September 2015.
MMBbl/d
5.2
4.6
3.9
3.3
2.6
2.0
1.3
0.7
United States

46. U.S. SHALE NGL EURS SUPPORT LPG TRADE GROWTH
45
1. PIRA NGL Study, September 2015.
• 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)

47. 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
46
Northeast
Ethane
Rejection
Exports
U.S.
PetChem

48. 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
47
• 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

49. ANTERO RESOURCES EBITDAX RECONCILIATION
48
EBITDAX Reconciliation
($ in millions) Quarter Ended LTM Ended
12/31/2015 12/31/2015
EBITDAX:
Net income including noncontrolling interest $175.6 $980.0
Commodity derivative fair value (gains) (545.1) (2,381.5)
Net cash receipts on settled derivatives instruments 269.9 856.6
Interest expense 60.5 234.4
Income tax expense (benefit) 77.2 575.9
Depreciation, depletion, amortization and accretion 162.2 711.4
Impairment of unproved properties 60.7 104.3
Exploration expense 0.8 3.8
Equity-based compensation expense 18.6 97.9
State franchise taxes (0.1) 0.1
Contract termination and rig stacking 27.6 38.5
Consolidated Adjusted EBITDAX $307.8 $1,221.4

50. ANTERO MIDSTREAM EBITDA RECONCILIATION
49
EBITDA and DCF Reconciliation
$ in thousands
Three months ended
December 31,
2014 2015
Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow:
Net income $55,898 $49,008
Add:
Interest expense 2.062 2,892
Depreciation expense 17,290 23,152
Contingent acquisition consideration accretion - 3,333
Equity-based compensation 4,226 4,810
Adjusted EBITDA $79,476 $83,195
Less:
Pre-water acquisition net income attributed to parent (22,234) -
Pre-water acquisition depreciation expense attributed to parent (3,086) -
Pre-water acquisition equity-based compensation expense attributed to parent (654) -
Pre-water acquisition interest expense attributed to parent (359) -
Pre-IPO EBITDA (36,464) -
Adjusted EBITDA $16,679 83,195
Less:
Cash interest paid - attributable to Partnership (331) (2,934)
Income tax witholding upon vesting of Antero Midstream LP equity-based compensation awards - (4,806)
Maintenance capital expenditures attributable to Partnership (1,157) (3,096)
Distributable Cash Flow $15,191 $72,359

51. 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
50