Third Quarter 2016 Earnings Call Presentation October 27, 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.

$0.170 $0.180 $0.190 $0.205

$0.235 $0.250

$0.265 1.1x

1.2x 1.3x

1.4x

1.8x

1.6x 1.7x

2.0x

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

$0.000

$0.100

$0.200

$0.300

$0.400

$0.500

$0.600

4Q14A 1Q15A 2Q15A 3Q15A 4Q15A 1Q16A 2Q16A 3Q16A 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E

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

$0.220

2

• Antero Midstream is targeting 28% to 30% annual distribution growth through 2017 • AM has delivered on those targets with DCF coverage of 2.0x in the third quarter of 2016

Note: Future distributions subject to AM Board approval.

TOP TIER DISTRIBUTION GROWTH AND COVERAGE

77

125 140

186

105 95 67

113 97 105

140

0

50

100

150

200

250 Utica Marcellus

36 41 116

222 358

454 435 478 606 658

777

0

200

400

600

800

1,000

1,200 Utica Marcellus

126 266

531

908 1,134 1,197 1,216 1,195 1,222 1,253

1,351

0200400600800

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

331 386 532

738 935 965 1,038 1,124

1,303 1,353 1,431

0200400600800

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

Low Pressure Gathering (MMcf/d)

Compression (MMcf/d)

High Pressure Gathering (MMcf/d)

Fresh Water Delivery Volumes (MBbl/d)

3

Note: Y-O-Y growth based on 3Q’15 to 3Q’16.

HIGH GROWTH MIDSTREAM THROUGHPUT

32 32 32 34

36 39

43 40

20

25

30

35

40

45

50

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

Bar

rels

of W

ater

Per

Fo

ot o

f Lat

eral

1,146 1,012 999

1,235 1,412

1,603 1,672 1,650

- 200 400 600 800

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

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

Sand

Pla

ced

Per F

oot o

f La

tera

l

4

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

Pilot Testing Demonstrated Improved Recoveries While

Maintaining Well Density

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

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

ADVANCED COMPLETIONS DRIVE INCREASED WATER VOLUMES

ANTERO CLEARWATER FACILITY UPDATE

Antero Clearwater Facility – October 2016

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

Trucking bays

Crystallizers

Grit removal and pre-treatment

Crystallizer feed tank

Solids removal

5

Largest Oil and Gas Wastewater Treatment Facility in the World

$5.3 $4.6 $5.3 $4.7 $4.7 $4.7 $4.0 $3.9

$8.7 $7.8 $7.6

$7.1 $7.1 $5.6

$5.4 $5.2

$14.0

$12.4 $12.9 $11.8 $11.8

$10.3 $9.4 $9.1

$0

$2

$4

$6

$8

$10

$12

$14

$16

Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016 Q3 2016

($M

M)

COMPLETION COST DRILLING COST

PROVEN TRACK RECORD OF WELL COST REDUCTIONS

6

Marcellus Well Cost Reductions for a 9,000’ Lateral ($MM)(1)

NOTE: Based on statistics for drilled and completed wells within each respective period. 1. Based on 200 ft. stage spacing. 2. Based on 175 ft. stage spacing.

35% Reduction in Utica well costs since

Q4 2014

Utica Well Cost Reductions for a 9,000’ Lateral ($MM)(2)

36% Reduction in Marcellus well costs

since Q4 2014

18% Reduction vs. well costs assumed in YE

2015 reserves

15% Reduction vs. well costs assumed in YE

2015 reserves

$4.0 $3.8 $3.4 $3.2 $3.2 $3.1 $2.8 $2.6

$8.3 $7.3 $7.4 $7.0 $7.0

$5.4 $5.3 $5.2

$12.3 $11.1 $10.8 $10.2 $10.2

$8.5 $8.1 $7.8

$0

$2

$4

$6

$8

$10

$12

$14

Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016 Q3 2016

($M

M)

COMPLETION COST DRILLING COST

$0.86 / 1,000’

$1.01 / 1,000’

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

Cum

ulat

ive

Wel

lhea

d G

as P

rodu

ctio

n (M

Mcf

)

Days

OPTIMIZING WELL RECOVERIES WITH ADVANCED COMPLETIONS

7

Vintage 2013 2014 2015 2016E Change Stage Length (Feet) 280 196 196 185 (34)% Proppant (Pounds/ft) 913 1,158 1,134 1,500 64% Water (Bbl/ft) 26 32 34 40 54% Wellhead EUR/1,000' 1.5 1.7 1.7 2.0 33% 1st Year Production (MMcf Cum.) 2,215 2,461 2,461 2,895 33% 2nd Year Production (MMcf Cum.) 3,357 3,730 3,730 4,389 33%

Marcellus Cumulative Gas Production Curves (Normalized to 9,000’ Lateral)

1.5

1.7

2.0

Wellhead EUR/1,000’

2016 Advanced Completions

Year 1

Driving value by drilling more productive wells in the Marcellus

Year 2

2.0 Bcf/1,000’ at the wellhead equates to 2.5 Bcfe/1,000’ after C3+ processing assuming 1275 Btu gas, and 3.2 Bcfe/1,000’ processed with

full ethane recovery

118 118 118 162 214 371

450 543 569

44 52

157

79 93

26 60

118 118 162 214

371 450

543 569 629

0

100

200

300

400

500

600

700

2008 2009 2010 2011 2012 2013 2014 2015 2016 PF

Net Acres Added Annually

Marcellus/Utica Net Acres Year-End

Antero continues to consolidate acreage in the core and expand its footprint in Appalachia as a pure-play operator

December 2008

Net Acreage 118,000

Net Production (MMcfe/d)

NM

3P Reserves (Bcfe)

NM

Dec 2008 Dec 2011

December 2011(1)

Net Acreage 214,000

Net Production (MMcfe/d)

167

3P Reserves (Bcfe)

18,400

December 2014(1)

Net Acreage 543,000

Net Production (MMcfe/d)

1,265

3P Reserves (Bcfe)

40,700

1. Net daily production for December 2011 and December 2014 is for the fourth quarter, respectively. 2. Pro forma for Pennsylvania divestiture announced on October 26th, 2016 and additional leasing and acquisitions year-to-date. 3. Net daily production represents third quarter 2016. 4. 3P reserves are as of year-end 2015, pro forma for announced acreage acquisitions.

LEADING CONSOLIDATOR IN APPALACHIA

8

YTD 2016

Net Acreage (2) 629,000

Net Production (MMcfe/d)(3)

1,875

3P Reserves (Bcfe) (4)

42,100

Dec 2014 2016 Pro Forma

Net Acres (000’s)

APPENDIX

9

ANTERO MIDSTREAM EBITDA RECONCILIATION

10

EBITDA Reconciliation Reconciliation of Net Income to Adjusted EBITDA and DCF (Dollars in thousands):

Three months ended September 30,

2015 2016

Net income $ 42,648 $

70,524

Add: Interest expense 2,044 5,303 Depreciation expense 21,561 26,136 Accretion of contingent acquisition consideration — 3,527 Equity-based compensation 5,284 6,599 Less: Equity in earnings of unconsolidated affiliate — (1,544) Adjusted EBITDA $ 71,537 $ 110,545

Less: Pre-water acquisition net income attributed to parent (7,841) —

Pre-water acquisition depreciation expense attributed to parent (6,485)

—

Pre-water acquisition equity-based compensation expense attributed to parent (1,079)

—

Pre-water acquisition interest expense attributed to parent (770) — Adjusted EBITDA attributable to the Partnership $ 55,362 $ 110,545 Less:

Cash interest paid, net – attributable to the Partnership (1,038) (4,043) Cash reserved for payment of income tax withholding upon vesting of Antero Midstream equity–based compensation awards — (1,000)

Maintenance capital expenditures (4,214) (4,638)

Add:

Cash distribution to be received from unconsolidated affiliate — 2,221

Distributable cash flow $ 50,110 $ 103,085

Total distributions declared $ 36,333 $ 51,702

DCF coverage ratio 1.38x 1.99x