MLPA 2017 Investor Conference

June 1, 2017

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”) or Antero Midstream GP LP and its subsidiaries other than the Partnership (collectively, “AMGP”) as applicable 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 AMGP, the Partnership and Antero Resources Corporation (“Antero Resources”). These statements are based on certain assumptions made by the AMGP, 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 AMGP or the Partnership, as applicable, 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, 2016 and in the Partnership’s subsequent filings with the SEC, as well as the factors discussed under “Risk Factors” in AMGP’s final prospectus dated May 3, 2017 and filed with the SEC on May 5, 2017. AMGP and the Partnership caution 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, 2016 and in the Partnership’s subsequent filings with the SEC. The Partnership’s 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. In addition, AMGP’s ability to make future distributions is substantially dependent on the Partnership’s business, financial conditions and the ability to make distributions. Any forward-looking statement speaks only as of the date on which such statement is made, and neither AMGP or the Partnership undertakes any 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.

2

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

Exchange ticker symbols.

Antero Simplified Organizational Structure

3 Note: Enterprise Value as of May 30, 2017. AR enterprise value excludes minority interest.

100% Incentive

Distribution Rights (IDRs)

Public

(NYSE: AMGP) Enterprise Value : $4.1 Bn

(NYSE: AM) Enterprise Value : $7.3 Bn

(NYSE: AR) Enterprise Value: $10.5 Bn

80% 20%

Affiliates Affiliates

59%

32%

Public

68%

41% Public

The combined enterprise value of the Antero complex is over $18 billion

Delivering on Antero IPO Promises

4

At IPO (October 2013)

1. Represents 2Q 2013 and 1Q 2017 net production, respectively. 2. Represents consolidated LTM EBITDAX as of 6/30/2013 and 3/31/2017, respectively. 3. Current 3P reserves are as of 12/31/2016, assuming partial ethane recovery. 3P Reserves for 2013 include 6.3 Tcfe Proved, 14.0 Tcfe Probable and 7.4 Tcfe Possible. 3P Reserves for 2016 include 15.4

Tcfe Proved, 29.1 Tcfe Probable and 1.9 Tcfe Possible.

Net Production (1):

458 MMcfe/d 2,144 MMcfe/d

Acreage:

Current

$457 Million $1,546 Million LTM EBITDAX (2):

431,000 Net Acres

+368%

+238%

+68%

634,000 Net Acres(6) +47%

Leading consolidator since AR IPO adding

203,000 net acres

Growth

Distribution / Coverage:

Gathering Throughput(5):

LTM EBITDA(4):

$0.17 (MQD) Target: 1.1x – 1.2x $0.30 / Actual: 1.4x

Low Pressure: 532 MMcf/d Low Pressure: 1,659 MMcf/d

$45 $444

+76%

+887%

+212% 4. For the three months ended 9/30/2014, annualized and 3/31/17, respectively. 5. For the three months ended 9/30/2014 and 3/31/2017, respectively. 6. Net acres as of 12/31/2016, pro forma for additional leasing and acquisitions.

At IPO (November 2014) Current

27.7 Tcfe 46.4 Tcfe 3P Reserves (3):

Most Integrated Natural Gas and NGL Story in the U.S.

5

World Class E&P Operator in Appalachia

1. Multi-decade, economic development program - Largest core acreage position in Appalachia - Low risk, core drilling inventory representing 46.4 Tcfe of 3P

reserves (1)

- Controls 43% of all core liquids-rich undrilled locations in Appalachia

- Strong trend of improved recoveries and well economics and lower F&D costs

2. Peer-leading, visible growth - 15-year drilling inventory generating 20% ROR @ $3.00/MMbtu or less - Largest firm transport portfolio delivers NYMEX-plus pricing - 85% of target natural gas production hedged through 2020 @

$3.72/MMbtu 3. Strong balance sheet and financial liquidity (Ba2 / BB)

1. Long-term, 100% fixed fee contracts - No direct commodity price exposure

2. Organic, “just-in-time” investment strategy - Efficient, organic return on capital (3x to 6x capex to

buildout EBITDA multiples) - $5.0 Bn project backlog through 2026

3. Diversified asset mix - Gathering, compression, processing, fractionation, fresh

water distribution and wastewater treatment

4. Highest LP distribution growth among MLPs

5. Abundant upside growth opportunities - Downstream NGL infrastructure, 3rd party business,

stacked pay drilling, acreage additions

A Leading Northeast Infrastructure Platform

Levered Exposure to Northeast Infrastructure Buildout 1. Combination of growth and yield is unmatched 2. Early stage 100% pure IDR vehicle 3. AM LP unit issuance for potential accretive transactions provides

secondary growth driver 4. Debt-free balance sheet at AMGP

- Limited dependence on AM capital markets activity due to organic model 5. Maximum exposure to decrease in corporate tax rate

- LP structure but treated as a corporation for tax purposes

1. 3P Reserves for 2016 include 15.4 Tcfe Proved, 29.1 Tcfe Probable and 1.9 Tcfe Possible.

Organic Growth Drives the Business

6

6.9x 6.1x

4.5x 4.4x

0.0x

2.0x

4.0x

6.0x

8.0x

10.0x

12.0x

2014 2015 2016 2017E DropDown

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

• Industry leading organic growth story

– ~$2.3 billion in capital spent through 9/30/2016 on gathering and compression and water assets

– Assumes midpoint guidance EBITDA for 2017 (excluding JV)

– 4.4x Capital expenditures to buildout EBITDA

– 10-year identified project inventory of $5.0 billion

– 24% weighted average project IRR

Organic Adjusted EBITDA Multiple vs. Drop Down Multiples

Drop Down Median: 8.8x

AM Organic EBITDA Multiple(1)

AM Builds at 3x to 6x EBITDA vs.

Other MLPs that Drop Down/Buy at 8x to 12x+ EBITDA

Antero Midstream Project Unlevered IRRs

25%

15%

10%

30%

15% 15%

35%

25%

20%

40%

25%

18%

0%5%

10%15%20%25%30%35%40%45%

LPGathering

HPGathering

Compression FreshWater

Delivery

AdvancedWastewaterTreatment

Processing/Fractionation

Inte

rnal

Rat

e of

Ret

urn

Wtd. Avg. 24% IRR

(2)

Note: Precedent data per IHS Herold’s research and public filings. 1. Antero Midstream organic multiples calculated as gathering and compression and water capital expended through Q3 of each respective year divided by Adjusted EBITDA, assuming 12-15 month lag between capital

incurred and full system utilization. 2. Selected gathering and compression drop down acquisitions since 1/1/2015. Drop down multiples are based on NTM EBITDA. Source: Public company filings and press releases.

Capturing the Midstream Value Chain

7

Upstream Downstream

~$4.2 Billion Organic Project Backlog

~$800 Million JV Project Backlog

WELL PAD

LOW PRESSURE GATHERING

HIGH PRESSURE GATHERING

COMPRESSION

GAS PROCESSING

(50% INTEREST)

REGIONAL GATHERING

PIPELINE (15% INTEREST)

FRACTIONATION TERMINALS & STORAGE

Y-GRADE PIPELINE

(ETHANE, PROPANE, BUTANE)

NGL PRODUCT PIPELINES

LONG HAUL PIPELINE

INTERCONNECT

END USERS

PDH PLANT

• Participating in the full value chain diversifies and sustains Antero’s integrated business model • $5.0 billion organic project backlog and ~$1.0 billion downstream investment opportunity set

~$1.0 Billion Downstream Investment

Opportunity Set

Note: Third party logos denote company operator of respective asset.

AM Assets AM/MPLX JV Assets Potential AM Opportunities

NGL Infrastructure Buildout in the Northeast

8

Mariner West (50 Mbbl/d C2)

Mariner East (70 Mbbl/d)

61,500 MBbl/d Mariner East 2

Antero / MPLX Joint Venture (1)

1. Represents processing and fractionation joint venture between Antero Midstream and MPLX LP that was announced February 6th, 2017.

• Over $4 Billion of downstream NGL infrastructure projects currently under construction or proposed for the Northeast adjacent to Antero’s position

Utopia (50 Mbbl/d C2) (1Q 2018)

The Northeast NGL infrastructure buildout

potentially presents additional investment opportunities

9

Antero Resources – Sponsor Strength

$198 $341 $434

$649

$1,164 $1,221

$1,536 $1,540

$2,236

$0

$400

$800

$1,200

$1,600

$2,000

$2,400

2010 2011 2012 2013 2014 2015 2016 2017E 2018E$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$1,164

10

10

17

26

35 41

37

46

05

101520253035404550

2010 2011 2012 2013 2014 2015 2016

Actual 2.7

0.0 0.1 0.2 0.5

1.0

1.5

1.8

2.2

0.0

0.5

1.0

1.5

2.0

2.5

3.0

2010 2011 2012 2013 2014 2015 2016 2017E 2018E

Marcellus Utica

1. 2016 acreage count represents year-end 2016 net acres pro forma for any 2017 acreage acquisitions to date. 2. 2012, 2013, 2014 and 2015 reserves assuming ethane rejection. 2016 net 3P reserves assume partial ethane recovery. 3. Production represents midpoint of 2017 production guidance of 2.2 Bcfe/d, including 92,500 Bbl/d liquids, per press release dated 1/4/2017. 4. Represents Henry Hub spot price from 1/1/2010 through 03/31/2017.

Guidance(3)

Antero Resources has uniquely sustained growth and value creation through the down cycle

Henry Hub Gas Price(4) $/MMBtu

162 214

371 450

543 569

634(1)

0

100

200

300

400

500

600

700

2010 2011 2012 2013 2014 2015 2016

Marcellus Utica Proved Probable Possible

Growth Through the Down Cycle

Net Acres (000’s) Net 3P Reserves (Tcfe) (2)

Consolidated Adjusted EBITDAX ($MM) Average Net Daily Production (Bcfe/d)

Target Consensus(5)

5. Based on consensus estimates as of 5/30/17.

11

A Leading Consolidator in Appalachia

46,500 net acres – Sept. 2016

3,900 net acres – Dec. 2016

6,200 net acres – Jan. 2017 10,100 net acres – Dec. 2016

Antero has capitalized on the industry environment and acquired approximately 78,000 net acres in the core of the Marcellus and Utica Shale plays since the beginning of 2016

Vast majority of the acreage was undedicated at closing and has been dedicated to AM

Consolidated acreage position drives efficiencies:

– Longer laterals – More wells per pad – Higher utilization of gathering, compression

and water infrastructure – Facilitates central water treatment avoiding

reinjection

$200 million land capital budget for 2017 to further consolidate core acreage

Supports long-term growth outlook

Acquisitions Since 1/1/2016 Activity

11,000 net acres – May 2017

Largest Core Acreage Position in Appalachia

604

464 458

366

238 226 221 216 186 177 167 155

-

100

200

300

400

500

600

700Core - NE Pennsylvania Dry Net Acres

Core - SW Marcellus & Utica Dry Net Acres

Core - Marcellus & Utica Liquids Rich Net Acres

Cor

e N

et A

cres

(000

s)

Largest Core Acreage Position in Appalachia (1)

Source: Core outlines based upon Antero geologic interpretation, well control and peer acreage positions based on investor presentations, news releases, 10-K/10-Qs and other sources. Rig information per RigData as of 5/19/2017. 1. Peers include Ascent, CHK, CNX, COG, CVX, EQT, GPOR, HG Energy, RICE, RRC, and SWN.

Antero has the largest core acreage position in Appalachia and the largest liquids-rich position

31 Utica Rigs

15 Marcellus Rigs

74 Total Rigs

12

31 Marcellus Rigs

Yields Largest Core Drilling Inventory In Appalachia

13

3,502

1,967 1,937

1,161

913 867 824 736 692 683 635 548

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

AR A B C D E J H K F L I

Und

rille

d Lo

catio

ns

Core - NE Pennsylvania Dry Locations Core - SW Marcellus and Ohio Utica Dry Locations Core - Marcellus & Ohio Utica Liquids-Rich Locations

1. Location count determined by Antero technical review of geology and well control to delineate core areas and peer acreage positions both drilled and undrilled. Pro forma for all acreage acquisitions to date. 2. Peers include Ascent, CHK, CNX, COG, CVX, EQT, GPOR, HG Energy, RICE, RRC, and SWN.* Undrilled location count net of acreage allocated to publicly disclosed joint ventures.

Undrilled Core Marcellus and Utica Locations (1)(2)

Large, repeatable core drilling inventory that averages 8,000’ in lateral length and includes 43% of all liquids-rich undrilled locations in Appalachia

Core Liquids-Rich Appalachia Undrilled Locations (1)

*

* *

* *

Avg. Lateral Length 8,081’ 6,429’ 6,355’ 7,762’ 8,601’ 5,758’ 8,594’ 9,262’ 7,085’ 7,550’ 8,880’ 6,225’

43%

B 13%

C 10%

J 8%

E 6%

F 6%

A 4%

D 3%

K 3%

H 2%

I 2%

Substantial Drilling Inventory at Low Breakeven Prices

14

247

1,091

1,815

2,595

3,478 3,670 3,704

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

$1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.00

Loca

tions

Marcellus Rich Gas Marcellus Dry Gas Ohio Utica Rich Gas Ohio Utica Dry Gas

1. Marcellus and Utica 3P locations as of 12/31/2016 pro forma for any acreage acquisitions to date. Categorized by breakeven price solving for a 20% BTAX ROR and assuming 50% of AM fees due to AR ownership of AM. Assumes $55.00/Bbl WTI over the next five years and strip pricing for C3+ NGLs, which is ~53% of WTI.

2. Includes 3,502 total core locations plus 202 non-core 3P locations.

Marcellus Rich Gas

Marcellus Dry Gas

Ohio Utica Rich Gas

< < < < < < <

Antero has a 15-year drilling inventory that generates a 20% rate of return at $3.00/MMbtu NYMEX or less, assuming the 2017 development pace (170 completions)

~70% of total locations generate a 20% rate of return at

$3.00/MMbtu NYMEX or less

~30% of total locations generate a 20% rate of return at

$2.00/MMbtu NYMEX or less

8,253’ 8,062’ 8,177’ 8,607’ 8,630’ 9,109 9,229’

Average Lateral Length

Ohio Utica Dry Gas

NYMEX Natural Gas Price ($/MMBtu)

Cumulative 3P Drilling Inventory – Breakeven Prices at 20% ROR (1)(2)

Marcellus Completion Evolution

15

500

750

1,000

1,250

1,500

1,750

2,000

2,250

2,500

2,750

3,000

Ante

ro C

ompl

etio

n Si

ze (l

bs/ft

)

Completion Start Date

Testing higher proppant loads in 2017 – Early results are encouraging

Supports 2.0 Bcf/1,000’ type curve and 81 PUD bookings at

YE2016

0

1,000

2,000

3,000

4,000

5,000

Days

Supports 1.7 Bcf/1,000’ type curve and historical reserve bookings

2,500

2,000

1,750

1,500

Antero is continuing to increase proppant intensity in 2017 primarily utilizing 1,750 and 2,000 lb/ft completions in the Marcellus

Per Well Frac Size Design (lb/ft)

1,250

1,500

1,750

2,000

2,500

1.5

1.7

2.0 1,750 lb/ft

Completions

1,500 lb/ft Completions

32 Bbl/ft Water

34 Bbl/ft Water

36 Bbl/ft Water

42 Bbl/ft Water

48 Bbl/ft Water

Recent Marcellus Well Results

16

Dry Gas High-Graded Core Average 2.2 Bcf / 1,000’

Wellhead EUR

Southern Rich High-Graded Core

Average 2.0 Bcf / 1,000’ Wellhead EUR

Antero Acreage

Antero Horizontal Marcellus Wells Industry Horizontal Marcellus Wells

Wellhead EURs from Antero’s recent 1,750 pound per foot completions have continued to outperform legacy style completions and range from 2.0 to 2.4 Bcf/1,000’ at the wellhead • Recent 4-well pad with 2,500 lb/ft completions potentially extends high-graded core areas

Antero - 10 Well Average

Advanced 1,700# Completion

Wellhead:

Processed:

C2 Recovery:

Lateral:

Net F&D Cost:

Antero - 4 Well Average

Advanced 1,700# Completion

Wellhead:

Processed:

C2 Recovery:

Lateral:

Net F&D Cost:

2.4 Bcf/1,000’

2.9 Bcfe/1,000’

3.6 Bcfe/1,000’

10,017’

$0.39/Mcfe

2.1 Bcf/1,000’

2.6 Bcfe/1,000’

3.3 Bcfe/1,000’

10,468’

$0.35/Mcfe

Antero - 4 Well Average

Advanced 2,500# Completion

Wellhead:

Processed:

C2 Recovery:

Lateral:

Net F&D Cost:

2.3 Bcf/1,000’

2.6 Bcfe/1,000’

3.2 Bcfe/1,000’

5,365’

$0.47/Mcfe (1)

Antero - 2 Well Average

Advanced 1,750# Completion

Wellhead:

Processed:

C2 Recovery:

Lateral:

Net F&D Cost:

2.3 Bcf/1,000’

2.9 Bcfe/1,000’

3.7 Bcfe/1,000’

11,567’

$0.38/Mcfe

1. Represents actual completion costs and Q1 2017 AFE drilling costs.

Net F&D Cost: $0.38/Mcfe

Net F&D Cost: $0.35/Mcfe

Net F&D Cost: $0.39/Mcfe

Net F&D Cost: $0.45/Mcfe(1)

Rapidly Growing NGL Production

17

19,500

42,500

73,000

86,500

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

2014 2015 2016 2017Guidance

2018ETarget

2019ETarget

2020ETarget

Ethane (C2) C3+ Production Propane (C3) Normal Butane (nC4) IsoButane (iC4) Natural Gasoline (C5+)

1. Excludes condensate. 2. Assumes midpoint of 20 – 22% year-over-year equivalent production growth in 2018-2020. For illustrative purposes C3+ production growth assumed at same rate.

(1)

(Bbl/d)

C5+

iC4

nC4

C3

C2 Ethane

17,476

C2 Ethane 19,000

Antero is the largest NGL producer in the Northeast

(2) (2) (2)

20–22% Y-O-Y

Long-Term Growth Target

NGL Production Growth by Purity Product (Bbl/d)

Liquids Pricing Upgrade in the Marcellus

Gas $3.15 Gas

$3.05 Gas

$3.05

Condensate $0.14

Condensate $0.18

NGLs (C3+) $0.89

NGLs (C3+) $1.12

$0.00$0.50$1.00$1.50$2.00$2.50$3.00$3.50$4.00$4.50$5.00

1050 BTU 1250 BTU /$55 WTI

1250 BTU /$65 WTI

1. Assumes $3.00/MMBtu NYMEX, $55/Bbl to $65/Bbl WTI and NGL prices equal to 52.5% of WTI (midpoint of 2017 guidance). 45 Bbl/MMcf (ethane rejection) recovery for NGLs and 3 Bbl/MMcf for condensate, processing shrink included.

Assuming Ethane Rejection

(1100 BTU Tailgate) 8% shrink

Realized Price Per Mcf(1)

($/Mcf) +$0.90 Upgrade

+$1.17 Upgrade

Rich Gas Dry Gas

$3.00/MMBtu NYMEX

Antero realizes a significant upgrade to assumed $3.00/MMBtu NYMEX gas price by producing liquids-rich gas and condensate

18

$4.32 $4.05

Attractive Liquids-Rich Marcellus Well Economics

19

$5.1 $7.9

$9.7

30%

45%

56%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

$0.0

$6.0

$12.0

$18.0

1.72.1

2.02.5

2.32.8

Unh

edge

d Pr

e-Ta

x R

OR

Pre-

Tax

PV-1

0 ($

MM

)

Pre-Tax PV-10 Pre-Tax ROR

$9.4

$12.4

$15.4

53%

72%

95%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

$0.0

$6.0

$12.0

$18.0

1.72.3

2.02.7

2.33.1

Unh

edge

d Pr

e-Ta

x R

OR

Pre-

Tax

PV-1

0 ($

MM

)

Pre-Tax PV-10 Pre-Tax ROR

1. Assumes ethane rejection. Based on commodity pricing as of 3/31/17. Assumes 9,000’ lateral length.

Processed Bcfe/1,000’:

Integrated platform yields attractive well economics and sustainable growth

2.0 2.7

2.0 2.5

683 Undrilled Locations

Wellhead Bcf/1,000’: Processed Bcfe/1,000’:

1,184 Undrilled Locations

2016 Advanced Completion

Results

1313 Btu 1250 Btu

Wellhead Bcf/1,000’:

Highly-Rich Gas/Condensate (3/31/17 Pricing) (1) Highly-Rich Gas (3/31/17 Pricing) (1)

Largest Firm Transportation Portfolio in the Northeast

20 1. Shell announced final investment decision (FID) on 6/7/2016. 2. Lake Charles LNG 150 MMcf/d commitment subject to Shell FID.

Antero transportation commitments yield NYMEX-plus pricing for natural gas and are expected to yield Mont Belvieu-plus pricing for NGLs

Antero 2.8 Bcf/d Firm Processing 1,400 MMcf/d To Midwest

800 MMcf/d To TCO Pool 689 MMcf/d

4.85 Bcf/d Firm Gas Takeaway

By YE 2018

YE 2018 Gas Market Mix Antero 4.85 Bcf/d FT

44% Gulf Coast

17% Midwest

13% Atlantic

Seaboard

13% Regional

(PA)

13% TCO

Expect NYMEX-

plus pricing per Mcf in aggregate

To Atlantic Seaboard

630 MMcf/d

625 MMcf/d 30 MBbl/d Ethane

Local Petchem

Mariner East 2 (4Q 2017) 62 MBbl/d Commitment

Marcus Hook Export Shell (2021)

30 MBbl/d Commitment Pennsylvania Cracker (1)

Sabine Pass (Trains 1-4) 200 MMcf/d

(T1, T2 and T3 in-service)

Freeport LNG (3Q 2018) 70 MMcf/d

Lake Charles LNG(2)

150 MMcf/d

Cove Point LNG (4Q 2017) 330 MMcf/d

420 MMcf/d LNG Export

330 MMcf/d LNG Export

62 MBbl/d NGL Export

Midwest Markets

Regional Markets

Gulf Coast Markets

Antero Commitments Firm Processing: = 2.8 Bcf/d Firm Gas Takeaway: = 4.85 Bcf/d LNG Firm Sales: (2) = 750 MMcf/d

Firm Ethane Takeaway: = 20 MBbl/d

Ethane Cracker: = 30 MBbl/d Firm NGL Takeaway: = 62 MBbl/d

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

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

21

2,163 2,015

2,330

710 810

$3.47 $3.91

$3.70 $3.63 $3.31 $3.18

$3.32 $3.03

$2.83 $2.82 $2.83 $2.84

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

0

400

800

1,200

1,600

2,000

2,400

2017 2018 2019 2020 2021 2022

BBtu/d $/Mcfe Average Index Hedge Price(1) Hedged Volume Current NYMEX Strip(2)

$81 MM $627 MM $702 MM $390 MM $110 MM

Mark-to-Market Value(2)

~ 100% of 2017 Guidance Hedged

$85 MM

~$2.1 billion mark-to-market unrealized gain based on 3/31/2017 prices with 3.4 Tcfe hedged through year-end 2022 at $3.63 per MMBtu

• Hedging is a key component of Antero’s business model due to the large, repeatable drilling inventory

• Antero has realized $2.8 billion of gains on commodity hedges since 2008 with gains realized in 34 of last 36 quarters

~ 75% of 2018 Target

Hedged

Commodity Hedge Position

~ 72% of 2019 Target

Hedged

Significant Cash Flow Growth → Declining Leverage

22

$1,536 $1,621

$2,288

1.8

2.2

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

2016A 2017E 2018E 2019E 2020E

Prod

uctio

n G

uida

nce

/ Tar

gets

(Bcf

e/d)

N

et D

ebt/L

TM E

BIT

DAX

Tar

gets

Con

sens

us E

BIT

DAX

Est

imat

es ($

MM

)

Visible cash flow growth given hedges, firm transportation portfolio, and capital efficient long-term development plan targeting 20% to 22% production CAGR

Consensus EBITDAX Production Guidance (Bcfe) Production Targets (Bcfe)

1. Bloomberg Consensus EBITDAX estimates as of 3/31/2017.

Leverage Targets

Declining Leverage

(1)

23

Antero Midstream – High Visibility Growth

Antero Clearwater Facility Expected In Service 4Q 2017

Antero Midstream Asset Overview

24

Midstream Infrastructure (In Service)

Gathering Pipelines (Miles) 307

Compression Capacity (MMcf/d) 1,135

Condensate Pipelines (Miles) 19

Processing Plant (MMcf/d) 200

Fractionation Plant (Bbl/d) 20,000

Fresh Water Pipelines (Miles) 286

Fresh Water Impoundments 36

Regional Pipeline Capacity (Bcf/d) 1.4

Antero Clearwater Facility (Bbl/d)(1) 60,000

Compressor Station

Antero Clearwater Facility

Sherwood Processing Facility

Note: Infrastructure in service as of year-end 2016. 1. The Antero Clearwater Facility is scheduled to be placed into service in the fourth quarter of 2017.

An integrated system for natural gas and NGL production, gathering and processing

High Growth Midstream Throughput

25

460

1,186 1,316

1,581

- 200 400 600 800

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

2014 2015 2016 1Q 2017

132

96

123 148

-

50

100

150

200

2014 2015 2016 1Q 2017

104

432

741

1,028

-

200

400

600

800

1,000

1,200

1,400

2014 2015 2016 1Q 2017

498

1,016

1,403

1,659

- 200 400 600 800

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

2014 2015 2016 1Q 2017

Note: Growth based on 2-year CAGR. All fees are as of year end 2016.

Marcellus Utica

Fixed Fee: $0.31/Mcf Fixed Fee: $0.19/Mcf

Fixed Fee: $0.19/Mcf Fixed Fee: $3.68/Bbl

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

High Pressure Gathering (MMcf/d) Fresh Water Delivery (MBbl/d)

Antero Midstream Upside Opportunity Set

26

OPPORTUNITY POSITIONING

• Fresh water delivery, waste water treatment and gathering/compression services to capture third party business in Appalachia and enhance asset utilization

• 400 Deep Utica locations underlying the Marcellus in West Virginia dedicated to AM and will require some new dry gas infrastructure

• Industry is continuing to delineate deep Utica resource

• Undedicated acreage acquisitions by AR are dedicated to AM for gathering, compression, processing and water services

• AR has added over 200,000 net acres since 2013 IPO

• Antero leverages its resource and production to provide investment opportunities for AR and AM

• Natural gas and NGL pipelines, terminals and storage

• ~1,000 incremental locations prospective for Upper Devonian dedicated to AM for gathering and water services

• Industry is developing Upper Devonian now

• Volumes can go to Marcellus system already in place

• AM has multiple pathways to upside beyond its $5.0 billion organic project backlog

Downstream Infrastructure Buildout 1

AR Acreage Consolidation 2

Third Party Business 3

Upper Devonian 4

WV/PA Utica Dry Gas 5

Long Term Growth Outlook Through 2020

27

$1.03

$1.33

1.8x

1.4x

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

2016A 2017Guidance

2018ETarget

2019ETarget

2020ETarget

DC

F C

over

age

Rat

io a

nd L

ever

age

Rat

io

Dis

trib

utio

n Pe

r Uni

t

DCF Coverage >1.25x

Note: Future distributions subject to Board approval.

AM’s $2.6 billion organic opportunity set through 2020 and visible cash flow growth allow it to target a 28% to 30% distribution CAGR through 2020 and maintain leverage in the low 2-times

Distribution Guidance

Distribution Target

DCF Coverage

Stable Leverage

AMGP Highly Levered to AM Distribution Growth

28

$0 $0 $8

$41

$82

$136

$205

$0.00 $0.00 $0.04

$0.22

$0.44

$0.73

$1.10

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$0

$50

$100

$150

$200

$250

$0.68 $0.80 $1.03 $1.33 $1.71 $2.21 $2.85

AMG

P D

istr

ibut

ions

Per

Sha

re ($

/Sha

re)

AMG

P C

ash

Avai

labl

e fo

r Dis

trib

utio

n ($

MM

)

1. Assumes 185.8 million AM units outstanding as of February 28,2017; Assumes 186.2 million AMGP shares outstanding. AMGP cash available for distribution (CAFD) is net of (i) Series B unit distributions, (ii) general and administrative expense, and (iii) U.S. federal and state income taxes (assuming 38% effective income tax rate)

AMGP Cash Available for Distribution AMGP Distributions per Share(1)

AM distributions drive IDR cash flow which drives AMGP distributions

AM Distribution Per Unit Hypothetical AM Distribution Growth

Antero Midstream Investment Highlights

29

Combination of High Growth and Yield is Unmatched

Most Integrated Natural Gas and NGL Story in the U.S.

$5 Billion Project Backlog + $1 Billion Downstream Opportunity Set

Cash Flow Driven by Visible Low Risk Production Growth at AR

Fixed-Fee Tolling Business Eliminates Direct Commodity Price Exposure

30

Appendix

Processing and Fractionation JV

31

Antero Midstream (NYSE: AM) and MPLX (NYSE: MPLX) formed a joint venture for processing and fractionation infrastructure in the core of the liquids-rich Marcellus and Utica Shales in February 2017

Strategic Rationale • Further aligns the largest core liquids-rich

resource base with the largest processing and fractionation footprint in Appalachia

‒ Up to 11 additional processing plants

‒ 20,000 Bbl/d of capacity at Hopedale 3 fractionation facility with option to invest in future fractionation capacity

‒ Over $800 million project backlog through 2020 (net to AM), including ~$155 million contribution upfront for processing and fractionation infrastructure

• Fits with AM’s “full value chain organic growth”

strategy ‒ Long-term 100% fixed-fee revenues

‒ Significant MVCs on processing

‒ 15% – 18% unlevered IRR

• Improved visibility throughout vertical value chain and ability to deploy “just-in-time” capital supporting Antero Resources’ rich gas development

Note: RigData as of 04/14/17. Rigs drilling in rich gas areas only. 1. New West Virginia site location still to be determined.

MarkWest / Antero Midstream Hopedale Fractionation Complex C3+ Fractionation 1 & 2: 120 MBbl/d In Service C3+ Fractionation 3: 60 MBbl/d In Service 20 MBbl/d In Service JV

MarkWest / Antero Midstream Sherwood Complex: 11 x 200 MMcf/d Sherwood 1 – 6: 1.2 Bcf/d In Service Sherwood 7: 200 MMcf/d In Service Sherwood 8: 200 MMcf/d 4Q 2017 Sherwood 9: 200 MMcf/d 1Q 2018 Sherwood 10: 200 MMcf/d 3Q 2018 Sherwood 11: 200 MMcf/d 4Q 2018 De-ethanization: 40 MBbl/d In Service Future Processing Complex

TBD 1 – 6 – Potential – 1,200 MMcf/d (1)

2017 Guidance and Long Term Targets

32

$1.03 $1.33

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

2016E 2017E 2018E 2019E 2020E

Updated 2017 Guidance(2)

DCF Coverage: 1.30x – 1.45x > 1.25x

Distribution Growth(1):

$520 – $560 Peer Leading Growth EBITDA ($MM):

$800 $2.6 Billion organic opportunity set from 2017 – 2020 Capital Expenditures ($MM):

2.0x – 2.5x Low 2-times range Leverage:

2018 - 2020 Long-Term Targets

1. Assumes midpoint of 2017 distribution growth guidance and long-term target. Future distributions subject to Board approval. 2. Per press release dated 2/6/2017.

Guidance

Long Term Targets

2016A

Estimated Project Economics by Segment

33

25%

15%

10%

30%

15% 15%

35%

25%

20%

40%

25%

18%

0%5%

10%15%20%25%30%35%40%45%

Inte

rnal

Rat

e of

Ret

urn

LP Gathering

HP Gathering Compression

Fresh Water Delivery

Advanced Wastewater Treatment

Processing/ Fractionation

Unlevered IRR Range: 25% - 35% 15% - 25% 10% - 20% 30% - 40% 15% - 25% 15% - 18% Payout (Years): 2.5 - 4.0 3.5 - 4.5 4.0 - 6.5 2.0 - 3.0 6.0 - 8.0 5.0 - 6.0 Minimum Volume Commitments: N/A 75% 70% Yes N/A Yes

2017 Capex Total Marcellus $655 $80 $60 $115 $50 $75 $275 Utica 145 45 10 40 25 25 -

Total Capex $800 $125 $70 $155 $75 $100 $275 % of Capex 100% 16% 9% 19% 9% 13% 34%

Included in 2017 Budget: Marcellus & Utica

Marcellus & Utica Marcellus & Utica

Marcellus & Utica

Marcellus & Utica Marcellus & Utica

10-year identified investment opportunity set

$5.0 B 35% - 40% 10% - 12% 20% - 25% 10% - 12% 1% - 3% 15% - 17%

Additional In-hand Opportunities: Dry Utica Upper Devonian

Dry Utica Upper Devonian

Dry Utica Upper Devonian

Dry Utica Upper Devonian

Dry Utica Upper Devonian

Third Party Fractionation

Project Economics by Segment(1)

1. Based on management capex, operating cost and throughput assumptions by project. These objectives are forward-looking, are subject to significant business, economic, regulatory and competitive

uncertainties and contingencies, many of which are beyond the control of the Company and its management, and are based upon assumptions with respect to future decisions, which are subject to change. Actual results will vary and those variations may be material. For discussion of some of the important factors that could cause these variations, please consult the “Risk Factors” section of the preliminary prospectus. Nothing in this presentation should be regarded as a representation by any person that these objectives will be achieved and the Company undertakes no duty to update its objectives.

Wtd. Avg. 24% IRR

2017 Guidance and Long Term Outlook

34

1.8 2.2

2.7

3.2

3.9

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

2016A 2017E 2018E 2019E 2020E

Net

Dai

ly P

rodu

ctio

n

2017 Guidance

D&C Capital:

$1.3 Billion Flat with prior year

Modest annual increases within Cash Flow from Operations

Production Growth:

In line with D&C capital Doubling by 2020 Consolidated Cash Flow from Operations(1):

3.0x to 3.5x Declining to mid-2s by 2018 Leverage(1):

98% Hedged at $3.51/Mcfe 58% Hedged at $3.76/Mcfe Hedging:

2018 - 2020 Long Term Targets

(Bcfe/d)

$3.47 $3.91

$3.70

$3.66

Hedged Volume (Bcfe) Hedged Price ($/Mcfe)

Guidance Long-Term Targets

$

(2) (2) (2)

Key Appalachian Natural Gas Takeaway Projects

35

Tran

sco

Atla

ntic

Sun

rise

–

M

id-2

018

(1.7

Bcf

/d)

4.8 Bcf/d

4.2 Bcf/d

5.2 Bcf/d

1.8 Bcf/d

Antero Producing

Areas

Source: Public filings and press releases. Excludes TETCO expansions (972 MMcf/d) that are currently under construction. 1. 1.05 Bcf/d capacity available to move gas from Leach to the Gulf on CGT Rayne Xpress. 2. 860 MMcf/d of capacity available on CGT Gulf Xpress to move gas to the Gulf Coast markets.

Antero firm transportation commitment

Growth in natural gas infrastructure by the end of 2019, resulting in 16.8 Bcf/d of incremental capacity, will support expected supply growth

Potential Appalachian Gas Production vs. Future FT – Southwest Portion of the Basin

36 1. Assumes ethane rejection. Based on commodity pricing as of 3/31/17. Assumes 9,000’ lateral length.

0

5

10

15

20

25

30

35

Gro

ss R

esid

ue B

cf/d

and

FT

Cap

acity

Mountain Valley Pipeline

WB Xpress

Atlantic Coast Pipeline Gulf XPress Mountaineer XPress

7/1/18 Δ = 4 Bcf/d

Rig Assumptions: Assumes 10 days spud to spud (36.5 wells/rig year) Four-pack drilling 195 days average spud to first sales 7,000' laterals Type curve shape per Antero type curve

Rover Phase 1

Rayne XPress NEXUS Leach XPress Adair Southwest Access South Rover Pipeline Phase2 80 Rigs

56 Rigs - Current

24 Rigs required to hold production flat at 14 Bcf/d

Base Decline of Current Production of 13.5 Bcf/d

56 Rigs - Current + 20% Incremental Rigs per Year

27 Bcf/d

14 Bcf/d

23 Bcf/d

30 Bcf/d

Rig Type Performance (Bcf/1,000') Average LateralDry Gas (SW PA & WV Marcellus) 2.0 7,000'Dry Gas (Utica) 2.0 7,000'Rich Gas (SW PA & WV Marcellus) 2.0 7,000'Rich Gas (Utica) 1.7 7,000'

Current Rig CountRich Dry Total

SW Marcellus: 14 18 32 Utica: 4 20 24 Grand Total SW: 18 38 56

Current Takeaway Estimated at 13.7 Bcf/d per Bentek

7/1/19 = 6 Bcf/d

(Bcf/d)

$1.34 $1.18

$0.90 $0.87

$1.55 $1.36

$1.05 $1.01

0.0

0.5

1.0

1.5

2.0

2014 2015 2016 Q1 2017

D&

C C

apita

l per

1,0

00' o

f La

tera

l ($M

M)

8,052 8,910 9,196

10,515 8,543

8,575 9,250

10,293

0

2,000

4,000

6,000

8,000

10,000

12,000

2014 2015 2016 Q1 2017 Record

Late

ral L

engt

h (fe

et)

29 24

15 12

9

29 31

17 18

05

1015202530354045

2014 2015 2016 Q1 2017 Record

Dril

ling

Day

s

3.2 3.5 4.0 4.0

3.2 3.7

4.8 4.8

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

2014 2015 2016 Q1 2017 Record

Day

s

Continuous Operating Improvement

37

Increasing Completion Stages per Day

Drilling Longer Laterals

Dramatic Decrease in Drilling Days

Declining Well Costs per 1,000’

Drilling longer laterals while reducing drilling days by 60%

More efficient completions (“zipper fracs”) are increasing

stages per day

Reducing well costs by ~35% since 2014 Continuing to be an industry leader in drilling longer laterals

Driving drilling and completion efficiencies which continues to lower well costs

14,014

10.0

Marcellus Utica

1.8 1.9

2.4 2.5 2.9

1.5 1.8 1.7 1.8

0.0

0.5

1.0

1.5

2.0

2.5

3.0

2014 2015 2016 Q1 2017 RecordProc

esse

d EU

R p

er 1

,000

' of

Lat

eral

(Bcf

e)

Improved Productivity Drives Lower F&D Costs

38 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 85% NRI in Marcellus and 81% NRI in Utica.

Increasing Water Per Foot

Much Lower F&D Cost per Mcfe(2)(3)

Increasing Proppant Per Foot

Increasing EUR per 1,000’ (Bcfe)(1)(2)

Since 2014, Antero has increased EURs by 39% in the Marcellus and 20% in the Utica

Bottom line: F&D costs per Mcfe have declined by 44% in the Marcellus and

28% in the Utica since 2015

Enhanced completion designs have contributed to improved recoveries and capital efficiency

Marcellus Utica

32 33

42 45

62

35 34 37 43

0

10

20

30

40

50

60

70

2014 2015 2016 Q1 2017

Bar

rels

of W

ater

Per

Foo

t

1,165 1,163

1,702 2,055

2,757

1,267 1,298

1,648

2,529

-

500

1,000

1,500

2,000

2,500

3,000

2014 2015 2016 Q1 2017

Poun

ds o

f Pro

ppan

t Per

Foo

t

Higher proppant concentration has contributed to higher recoveries

Higher proppant concentration requires increased water usage

Record Record

$0.88 $0.73

$0.45 $0.41

$1.28

$0.94 $0.78 $0.70

$0.00

$0.50

$1.00

$1.50

$2.00

2014 2015 2016 Q1 2017

F&D

Cos

t per

1,0

00' o

f La

tera

l ($M

M)

Record

Longer Laterals Improve Rates of Return

39

6,500 Foot Lateral(2)

9,000’

Antero 2016 average lateral: 9,000 feet

NOTE: Assumes 2.0 Bcf/1,000’ type curve for the Antero Marcellus Highly-Rich Gas/Condensate (1275 – 1350 Btu) and 3/31/2017 strip pricing. 1. Assumes ethane rejection and 2.0 Bcf/1,000’ recovery at the wellhead. 2. Represents 2016 Marcellus average for peers including: CNX, COG, EQT, RICE, RRC based on public guidance.

6,500’

Antero’s typical Marcellus well in 2017 will have a 9,200 lateral length, an EUR of 22.3 Bcfe, including 857 MBbls of NGLS and 66 MBbls of oil and cost $7.7 MM(1)

11,500 Foot Lateral

Pre-Tax Economics

ROR (%) 83%

PV-10 ($MM) $16.5

Breakeven Nymex ($/MMBtu) $1.01

Dev. Cost ($/Mcfe) $0.35

11,500’

Pre-Tax Economics

ROR (%) 58%

PV-10 ($MM) $8.3

Breakeven Nymex ($/MMBtu) $1.29

Dev. Cost ($/Mcfe) $0.42

Pre-Tax Economics

ROR (%) 72%

PV-10 ($MM) $12.4

Breakeven Nymex ($/MMBtu) $1.11

Dev. Cost ($/Mcfe) $0.38

Antero Resources EBITDAX Reconciliation

40

EBITDAX Reconciliation

($ in millions) Quarter Ended LTM Ended 3/31/2017 3/31/2017

EBITDAX: Net income (loss) including noncontrolling interest $305.6 $(454.5) Commodity derivative fair value (gains) losses (438.8) 355.3 Net cash receipts on settled derivatives instruments 44.8 723.6 Gain of sale on assets - (97.6) Interest expense 66.7 256.9 Loss on early extinguishment of debt - 16.9 Income tax expense (benefit) 131.3 (369.8) Depreciation, depletion, amortization and accretion 203.4 823.5 Impairment of unproved properties 26.9 174.3 Exploration expense 2.1 8.0 Equity-based compensation expense 25.5 104.4 Equity in earnings of unconsolidated affiliate (2.2) (2.7) Distributions from unconsolidated affiliates - 7.7 Consolidated Adjusted EBITDAX $365.3 $1,546.0

Antero Midstream EBITDA Reconciliation

41

EBITDA and DCF Reconciliation

$ in thousands Three months ended

March 31, 2016 2017 Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow: Net income $42,918 $75,091 Interest expense 3,704 8,836 Depreciation expense 23,823 27,536 Accretion of contingent acquisition consideration 3,396 3,526 Equity-based compensation 5,972 6,286 Equity in earnings from unconsolidated affiliate - (2,231) Adjusted EBITDA $79,813 $119,044 Interest paid (3,444) (9,187) Cash reserved for payment of income tax withholding upon vesting of Antero Midstream Partners LP equity- based compensation awards (1,000) (1,500) Cash reserved for bond interest - (1,552) Maintenance capital expenditures (5,808) (15,903)

Distributable Cash Flow $69,561 $90,902