3Q17 Earnings Call

November 2, 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.

1

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.

0

500

1,000

1,500

2,000

2,500

3,000

3,500

0 30 60 90 120 150 180 210 240 270 300 330 360 390 420

We

llh

ea

d P

rod

uc

tio

n

(C

um

ula

tive

MM

cf)

Days From Peak Gas

AR’s production from advanced completions is outperforming the 2.0 Bcf/1,000’ wellhead

type curve – 2,500 lb/ft completions are 17% above type curve (First 243 days)

Well Recoveries Continue to Improve

2

AR Type Curve Outperformance

1,500 lb/ft $0.85 MM/1,000 Well Cost

38 wells

34 Bbl/ft of Water

1,875 lb/ft $0.89 MM/1,000 Well Cost

90 wells

40 Bbl/ft of Water

2,500 lb/ft $0.97 MM/1,000’ Well Cost

21 wells

48 Bbl/ft of Water

2.0 Bcf/1,000' Type

Curve Cumulative

Production

1. Cumulative average production per well normalized to a 9,000’ lateral. Cumulative production lines excludes wellhead condensate.

2. 1,875 pounds per foot type curve represents 1,750 pounds per foot wells and 2,000 pounds per foot wells.

8,300

10,300

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

2014A 2017E Record

Increasing Lateral Lengths (Feet) Increasing Wells Per Pad

Increasing Recoveries Per 1,000’ (Bcfe) Increasing Water Per Foot (Bbl/ft)

Midstream Capital Efficiencies Continue to Improve

Longer lateral wells, increasing recoveries per well, and more wells per pad result in more

efficient gathering, compression and freshwater delivery capital investment

3

6

9

14

-

2

4

6

8

10

12

14

16

2014A 2017E Record

1.7

2.4

3.6

-

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

2014A 2017E Record

33

42

62

-

10

20

30

40

50

60

70

2014A 2017E Record

17,400

4

• Largest shale oil and gas related water treatment facility in the world

–60,000 Bbls/d capacity

• 100% fixed fee long term contracts

• Compliments fresh water delivery infrastructure ($800 million investment)

• At full capacity, will eliminate ~172,000 water truck trips per year, or ~15 MMBbls

Antero Clearwater Facility Nearing Completion

1,351

1,918

- 200 400 600 800

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

3Q 2016 3Q 2017

140 142

-

50

100

150

200

3Q 2016 3Q 2017

777

1,207

-

200

400

600

800

1,000

1,200

1,400

3Q 2016 3Q 2017

1,431 1,587

- 200 400 600 800

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

3Q 2016 3Q 2017

Note: All fees are as of year end 2016. Marcellus Utica

Fixed Fee: $0.32/Mcf Fixed Fee: $0.19/Mcf

Fixed Fee: $0.19/Mcf Fixed Fee: $3.69/Bbl

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

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

High Growth Midstream Throughput

High growth throughput driven by de-risked sponsor development plan

5

Return on Invested Capital =

Net Income + Interest Expense + Taxes

Average Total Liabilities and Partners

Capital – Current Liabilities

Attractive Return on Invested Capital

Attractive project rates of return and increasing capital efficiencies result in

economic and rapidly improving Partnership-wide return on invested capital (ROIC)

6

12%

9%

12%

15%

17%

19% 20%

0%

5%

10%

15%

20%

25%

2014A 2015A 2016A 2017E 2018E 2019E 2020E

AM Return on Invested Capital (ROIC)

Actual Consensus

• AM’s focus on organic growth and

capital efficiencies results in an

increasing returns on invested

capital through 2020 based on

consensus estimates

‒ Antero Midstream’s ROIC

declined in 2015 due to the

water drop-down transaction

and associated earn-out

payment included in liabilities

on balance sheet

• 2017 estimated ROIC of 15% in

fourth year of operations

Source: Factset consensus estimates.

7 1. AR standalone LTM EBITDAX includes $119 million in distributions from AR’s ownership of AM common units.

2. Nymex strip pricing as of 9/30/2017.

AR Leverage Reduction(1) Restructuring of hedge swap prices resulted in

no change to hedge volumes

80% of targeted natural gas production hedged

through 2020 at $3.43/MMBtu

– $1.2 billion of remaining hedge value

Utilizing a portion of net operating losses

carried forward to eliminate cash taxes on

realized gains

Antero monetized over $1 billion of non-E&P assets through the sale of $311 million of AM

common units and $750 million through hedge restructuring

3.4x 3.0x 3.2x

2.6x

0.0x

1.0x

2.0x

3.0x

4.0x

6/30/2017 9/30/2017

Consolidated Standalone

$1 Billion Delevering Program Completed

$3.64

$3.91

$3.70 $3.63

$3.31 $3.16

$2.91

$3.50

$3.50 $3.25

$3.00 $3.00

$2.00

$3.00

$4.00

0

400

800

1,200

1,600

2,000

2,400

2017 2018 2019 2020 2021 2022 2023

BBtu/d $/Mcf Hedged Volume

Current NYMEX Strip(2)

Natural Gas Hedge Position

Restructured Hedge Price

Previous Hedge Price

~$750 Million of

Proceeds

No Change

to Price

Remaining Value as of 9/30/17: $1.2 Billion(2)

Appendix

8

Antero Midstream EBITDA Reconciliation

EBITDA and DCF Reconciliation

$ in thousands

Three months ended

June 30,

2016 2017

Reconciliation of Net Income to Adjusted EBITDA and Distributable

Cash Flow:

Net income $49,912 $87,175

Interest expense 3,879 9,015

Depreciation expense 24,140 30,512

Accretion of contingent acquisition consideration 3,461 3,590

Equity-based compensation 6,793 6,951

Equity in earnings from unconsolidated affiliate (484) (3,623)

- 5,820

Adjusted EBITDA $87,701 $139,440

Interest paid (4,264) (2,308)

Cash reserved for payment of income tax withholding upon vesting of

Antero Midstream Partners LP equity-

based compensation awards (1,000) (2,431)

Cash to be received from unconsolidated affiliates 778 -

Cash reserved for bond interest - (8,734)

Maintenance capital expenditures (5,710) (16,422)

Distributable Cash Flow $77,505 $109,545

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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, 2016 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, 2016. 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

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