Am website presentation (a) february 2016

Partnership OverviewFebruary 2016

FORWARD-LOOKING STATEMENTSThis presentation contains forward-looking statements. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Antero Midstream Partners LP, and its subsidiaries (collectively, the “Partnership”) expect, believe or anticipate will or may occur in the future are forward-looking statements. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “estimate,” “project,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include expectations of plans, strategies, objectives, and anticipated financial and operating results of the Partnership and Antero Resources Corporation (“Antero Resources”). These statements are based on certain assumptions made by the Partnership and Antero Resources based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Partnership, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include the factors discussed or referenced under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2015 and in the Partnership’s subsequent filings with the SEC.

The Partnership cautions you that these forward-looking statements are subject to risks and uncertainties that may cause these statements to be inaccurate, and readers are cautioned not to place undue reliance on such statements. These risks include, but are not limited to, Antero Resources’ expected future growth, Antero Resources’ ability to meet its drilling and development plan, commodity price volatility, inflation, environmental risks, drilling and completion and other operating risks, regulatory changes, the uncertainty inherent in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks discussed or referenced under the heading “Item 1A. Risk Factors” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015 and in the Partnership’s subsequent filings with the SEC.

Our ability to make future distributions is substantially dependent upon the development and drilling plan of Antero Resources, which itself is substantially dependent upon the review and approval by the board of directors of Antero Resources of its capital budget on an annual basis. In connection with the review and approval of the annual capital budget by the board of directors of Antero Resources, the board of directors will take into consideration many factors, including expected commodity prices and the existing contractual obligations and capital resources and liquidity of Antero Resources at the time.

Any forward-looking statement speaks only as of the date on which such statement is made, and the Partnership undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

1

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

2

CHANGES SINCE FEBRUARY 2016 PRESENTATION

Updated AM slides for 12/31/2015 balance sheet and liquidity results Slides 16, 17

Updated AR slide for 12/31/2015 balance sheet and liquidity results Slide 16

Sustainable Business

Model

High Growth Sponsor Drives AM Throughput

and Distribution Growth

Largest Dedicated Core Liquids-Rich Acreage Position in Appalachia

$1.0 Billion ofAM 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

HighVisibility

SponsorStrength

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 AppalachianMidstream Partnership

Run by Co-Founders

Consolidated Acreage Position in Lowest

Unit Cost Basin

-

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

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

EQT AR CHK COG SWN RRC CNX

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

AR EQT RRC COG CNX SWN CHK

Top Producers in Appalachia (Net MMcfe/d) – 3Q 2015(1)(2) Top 12 U.S. Natural Gas Producers (Net MMcf/d) – 3Q 2015(1)

Appalachian Producers by Proved Reserves (Bcfe) – YE 2014(1)(2) Appalachian Producers by Core Net Acres (000’s) – December 2015(3)(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. 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.4. Southwestern leasehold and reserves include the impact from STO and WPX property acquisitions closed in January 2015. 5. Includes proved reserves categorized in “Northern Division” consisting of Utica Shale, Marcellus Shale and Powder River Basin.

(4)

4

2nd Largest Appalachian

Producer

Antero has the largest proved reserve base, the 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

500

1,000

1,500

2,000

2,500

3,000

3,500

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SPONSOR STRENGTH – LEADERSHIP IN APPALACHIAN BASIN

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 1/29/2016, and average rig count for January 2016, per RigData.

5

COMBINED TOTAL – 12/31/15 RESERVESAssumes Ethane RejectionNet Proved Reserves 13.2 TcfeNet 3P Reserves 37.1 TcfeStrip Pre-Tax 3P PV-10(1) $11.2 BnNet 3P Reserves & Resource 50 to 53 TcfeNet 3P Liquids 1,237 MMBbls% Liquids – Net 3P 20%4Q 2015 Net Production 1,497 MMcfe/d- 4Q 2015 Net Liquids 54,750 Bbl/dNet Acres(2) 569,000Undrilled 3P Locations 3,719

OHIO UTICA SHALE CORE

Net Proved Reserves 1.8 TcfeNet 3P Reserves 7.5 TcfeStrip Pre-Tax 3P PV-10(1) $2.5 BnNet Acres 147,000Undrilled 3P Locations 814

MARCELLUS SHALE CORE

Net Proved Reserves 11.4 TcfeNet 3P Reserves 29.6 TcfeStrip Pre-Tax 3P PV-10(1) $8.7 BnNet Acres 422,000Undrilled 3P Locations 2,905

WV/PA UTICA SHALE DRY GASNet Resource 12.5 to 16 TcfNet Acres 188,000Undrilled Locations 1,889

02468

1012

Rig

Cou

nt

Operators

January 2016 SW Marcellus & Utica(3)

SPONSOR STRENGTH – MOST ACTIVE OPERATORIN APPALACHIA

$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 435478

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

0200400600800

1,0001,2001,4001,6001,800 Utica Marcellus

108 216 281 331 386

531 738

935 965 1,038 1,124

0200400600800

1,0001,2001,4001,6001,800 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.

GROWTH – HIGH GROWTH MIDSTREAM THROUGHPUT

$0.170 $0.180 $0.190 $0.205

1.1x

1.2x1.3x

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.

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GROWTH – TOP TIER DISTRIBUTION GROWTH

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

(000

s)

Core Liquids-Rich Net Acres(1)

626 971

553 75563% 47%

24% 28%34%22%

9% 11%

0

400

800

1,200

0%15%30%45%60%75%

Highly-RichGas/

Condensate

Highly-Rich Gas Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

R

Total 3P Locations ROR @ 12/31/2015 Strip Pricing - After Hedges ROR @ 12/31/2015 Strip Pricing - Before Hedges

184

98 108

161263

16%

57%

83%

71% 80%

10%

27% 29% 23% 26%

0

100

200

300

0%20%40%60%80%

100%

Condensate Highly-RichGas/

Condensate

Highly-RichGas

Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

R

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 $9.1 million for a 9,000’ lateral Marcellus well and $10.2 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)

2016Drilling

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

$1.01

$0.000

$0.500

$1.000

$1.500

$2.000

2014 2015 Current Spot

$MM

/1,0

00’ L

ater

al

Well Cost ($MM/1,000' of Lateral)

16% Decrease vs. 2014

$1.57

$1.29$1.13

$0.000

$0.500

$1.000

$1.500

$2.000

2014 2015 Current Spot

$MM

/1,0

00’ L

ater

al

Well Cost ($MM/1,000' of Lateral)




SUSTAINABLE BUSINESS MODEL – AR MULTI-YEAR DRILLING INVENTORY SUPPORTS LOW RISK, HIGH RETURN GROWTH PROFILE

10

In-service 2016 Budget

HIGH VISIBILITY – PROJECTED MARCELLUSMIDSTREAM BUILDOUT

11

In-service 2016 Budget

HIGH VISIBILITY – PROJECTED UTICAMIDSTREAM BUILDOUT

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 Fee97%

Fixed Fee

100%

Fixed Fee

100%Fixed Fee90%

(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.

CommodityBased

CommodityBased

Appalachian ExposureMarcellus – Dry

Marcellus – Rich

Utica – Dry

Utica – Rich

Water Services

Rigs Running on Midstream Footprint (2)

(3)

- 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 2018EFavorable:ChicagoMichConGulf CoastNYMEXTCO

AR Increasing Access to Favorable Markets

Less favorable:TETCO M2Dominion South

74%

26%

99%

1%

97%

3%

97%

3%

(Stonewall/WB) Mid-Atlantic/NYMEX

(Stonewall/TGP) Gulf Coast

(TCO) Appalachia or Gulf Coast

AppalachiaAppalachia

(REX/ANR/NGPL/MGT) Midwest

(ANR/Rover) Gulf Coast

MITIGATED COMMODITY RISK – FIRM TRANSPORTATION & SALES PORTFOLIO

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$0

$50

$100

$150

$200

$250

$300

$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 GainsProjected Hedge Gains

NYMEX Natural Gas Historical Spot Prices

($/MM

Btu)

NYMEX Natural Gas Futures Prices

3.5 Tcfe Hedged at average price of

$3.79/Mcfethrough 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

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.

EndUsers

EndUsers

Gas Processing

Y-Grade Pipeline

Long-Haul Interstate

Pipeline

InterConnect

NGL Product Pipelines

Fractionation

Compression

Low Pressure Gathering

Well Pad

Terminalsand

Storage

(Miles) YE 2015 YE 2016E

Marcellus 106 114

Utica 55 56

Total 161 170

AM has option to participate in processing, fractionation,

terminaling and storage projects offered to AR


Marcellus 76 98

Utica 36 36

Total 112 134

(MMcf/d) YE 2015 YE 2016E

Marcellus 700 940

Utica 120 120

Total 820 1,060

AM Owned Assets

Condensate GatheringStabilization


Utica 19 19

EndUsers

AM Option Assets

(Ethane, Propane, Butane, etc.)

15

VALUE CHAIN OPPORTUNITY – FULL MIDSTREAM VALUE CHAIN

Liquid “non-E&P assets” of $5.5 Bnsignificantly 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 $MMCredit 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 $MMCommodity derivatives(1) $3,117

AM equity ownership(2) 2,318

Cash 16

Total $5,451

Asset Type $MMCash $16

Credit facility – commitments(3) 4,000

Credit facility – drawn (707)

Credit facility – letters of credit (702)

Total $2,607

Debt Type $MMCredit facility $620

Total $620


Total $7

Liquidity


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 $2.3 billion of AM units

Approximately $900 million of liquidityat AM

16

Only 41% of AM credit facility capacity drawn

Note: All balance sheet data as of 12/31/2015, inclusive of water drop down and associated financing. 1. Mark-to-market as of 12/31/2015.2. Based on AR ownership of AM units (116.7 million common and subordinated units) and AM’s closing price as of 1/31/2015.3. AR credit facility commitments of $4.0 billion, borrowing base of $4.5 billion.

STRONG FINANCIAL POSITION – STRONG BALANCE SHEETAND FLEXIBILITY

0.0x

1.0x

2.0x

3.0x

4.0x

5.0x

6.0x

Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8

Tota

l Deb

t / L

QA

EB

ITD

A

• $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 9/30/2015. Peers include TEP, EQM, MWE, WES, RMP, SHLX, DM, and CNNX.2. AM pro forma for water drop down; LQA EBITDA for water based on 2016E midpoint of 8.5x – 9.0x purchase price multiple announced.

Financial Flexibility

17

(2)

STRONG FINANCIAL POSITION – SIGNIFICANT FINANCIAL FLEXIBILITY

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

1.4x1.3x 1.3x

1.4x1.3x

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.

WES

CNNX

TEP

EQM

MPLX

DM

VLPPSXP

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%

Yiel

d (%

)

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 - ImpliedYield: 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.

Antero Midstream (NYSE: AM)Asset Overview

20

1. Represents inception to date actuals as of 12/31/2015 and 2016 midpoint guidance.2. Includes both expansion capital and maintenance capital.

21

UticaShale

MarcellusShale

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 0 240

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)

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

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

ANTERO MIDSTREAM WATER BUSINESS OVERVIEW

24Note: 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 midpoint 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 WaterDelivery Capex ($MM) $469 $62 $531

Water Pipelines(Miles) 184 75 259

Fresh Water StorageImpoundments 22 13 35

2016E Fresh Water Delivery Capex Budget ($MM)(3) $40 $10 $50Water Pipelines

(Miles) 20 9 29

Fresh Water StorageImpoundments 1 - 1

Cash Operating Margin per Well(4)

$700k -$750k

$775k -$825k

2016E Advanced Waste Water Treatment Budget ($MM) $130

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)

– Ozone water treatment facility expected in-service February 2016– 100% fixed fee long term contracts

● Advanced wastewater capex of $130 million budgeted in 2016

010,00020,00030,00040,00050,00060,00070,00080,000

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 AdvancedWastewater Treatment

3rd Party Recyclingand Well Disposal

(Bbl/d)

Advanced Wastewater Treatment ComplexEstimated capital expenditures ($ million)(1) ~$275Standalone EBITDA at 100% utilization(2) ~$55 – $65Implied investment to standalone EBITDA build-out multiple ~4x – 5xEstimated per well savings to Antero Resources ~$150,000Estimated in-service date Late 2017Operating capacity (Bbl/d) 60,000Operating 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

CompletionOperations

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

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

9.3x9.0x 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

LPGathering

HPGathering Compression

CondensateGathering

Fresh Water Delivery

Advanced Wastewater Treatment

RegionalPipeline

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%In

tern

al R

ate

of R

etur

n

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

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

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

AR Gross Processable

Acres

Gross 3P NGL Reserves

(MMBbls)(1)

AR 3P GrossWellhead 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 POTENTIALFOR UNDEDICATED ACREAGE

SherwoodProcessing

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 County78,000 Gross Acres

Ritchie County49,000 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 County14,000 Gross Acres

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:

ChesapeakeHubbard BRK #3H

3,550’ LateralIP 11.1 MMcf/d

HessPorterfield 1H-17


GulfportIrons #1-4H5,714’ Lateral

IP 30.3 MMcf/d

EclipseTippens #6H5,858’ Lateral

IP 23.2 MMcf/d

Magnum HunterStalder #3UH5,050’ Lateral

IP 32.5 MMcf/d

Well Operator24-hr IP(MMcf/d)

LateralLength

(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 60 days with an average choke-restricted flow rate of 20 MMcf/d.

Magnum HunterStewart Winland 1300U


RangeClaysville SC #11H


ChevronConner 6H

6,451’ LateralIP 25.0 MMcf/dGastar

Simms U-5H4,447’ Lateral

IP 29.4 MMcf/d

Utica Shale Dry Gas Acreage in OH/WV/PA(1)

RiceBigfoot 9H


AR Utica Shale Dry GasWV/PA

Net Resource12.5 to 16 Tcf

1,889 Gross Locations188,000 Net Acres

AR Utica Shale Dry GasOhio

3P Reserves2.3 Tcf

263 Gross Locations41,000 Net Acres

AR Utica Shale Dry GasTotal OH/WV/PA

Net Resource14.8 to 18.3 Tcf

2,152 Gross Locations229,000 Net Acres

Stone EnergyPribble 6HU


SouthwesternMessenger 3H5,889’ Lateral

IP 25.0 MMcf/d

RiceBlue Thunder

10H, 12H≈9,000’ Lateral

GastarBlake U-7H


EQTScotts Run


CNXGaut 4IH


AnteroRymer 4HD


(2)

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 targeted 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 WaterBusiness Drop Down

APPENDIX

33

ANTERO MIDSTREAM – 2016 GUIDANCE

Key Variable 2016 GuidanceFinancial: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

2016 CAPITAL BUDGET

By Area

35

$423 Million – 2015(1)

By Segment ($MM)

$349

$6

$55$13

Gathering & Compression Fresh Water InfrastructureAdvanced Wastewater Treatment Maintenance Capital

74%

26%

Marcellus Utica

By Area

$435 Million – 2016By Segment ($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 InfrastructureAdvanced Wastewater Treatment Maintenance Capital

92%

8%

Marcellus Utica

ANTERO RESOURCES – 2016 GUIDANCE

Key Variable 2016 GuidanceNet 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) $1,4001. 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

Antero Long Term Firm Processing & Takeaway Position (YE 2018) – Accessing Favorable MarketsMariner East 2

62 MBbl/d CommitmentMarcus Hook Export

Shell20 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 LNG70 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/dFirm GasTakeaway

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 $0.40/MMBtu and positive weighted average basis differential to NYMEX after assumed Btu uplift for gas

YE 2018 Gas Market MixAntero 4.85 Bcf/d FT

44%Gulf Coast

17%Midwest

13%Atlantic

Seaboard

13%Dom S/TETCO

(PA)

13%TCO

Positive weighted

average basis differential

Antero Commitments

(3)

(2)

LARGEST FIRM TRANSPORTATION AND PROCESSING PORTFOLIO IN APPALACHIA

NORTHEAST 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 261,500 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

Export15%

Gulf Coast13%

Mid-Atlantic

6%Sarnia

3%

Northeast43%

Midwest10%

Edmonton10%

2015 NGL Marketing by Region

38

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

ShellBeaver County Cracker(Pending FID 1H 2016)

Mariner East 262 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)

$0.00

$0.10

$0.20

$0.30

$0.40

$0.50

$/G

allo

n

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 EXCESSDOCK CAPACITY AND FLEET GROWTH

0200400600800

1,0001,2001,4001,6001,800

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

MB

bl/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 168New builds +85

40

2015 GLOBAL LPG DEMANDGlobal LPG demand is 8.5 MMBbl/d and growing

41

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)

MM

Bbl

/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 KoreaHaiwei (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/d1.3

1.0

0.7

0.3

-0.3

GLOBAL LPG DEMAND DRIVEN BYPETCHEM AND RES/COMMLargest 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

431. PIRA NGL Study, September 2015.

MMBbl/d14.7

13.0

11.4

9.8

8.2

6.5

4.9

3.3

1.6

GLOBAL LPG TRADE DRIVEN BY U.S. SHALEThe U.S. is the largest single driver of the rapid expansion in LPG trade accounting for over 90% in trade growth


MMBbl/d5.2

4.6

3.9

3.3

2.6

2.0

1.3

0.7

United States

U.S. SHALE NGL EURS SUPPORT LPG TRADE GROWTH


• U.S. shale play NGL reserves are 50.8 billion barrels

• Eagle Ford, Marcellus, Utica, Bakken and Permian are the work horses of U.S. shale production growth

• Marcellus/Utica NGL resource estimate by PIRA is 9.7 billion barrels, in line with Antero estimate of ≈ 11.1 billion barrels

• The growth curve of each basin will ultimately be a function of downstream solutions and investment

(1)

(1)(1)

POSITIVE OUTLOOK FOR LONG-TERM ETHANE MARKETS AS WELL

U.S. Ethane Supply/Demand Balance Through 2020(1)

1. Source: Bentek, August 2015.2. Source: Citi research dated 7/15/2015.

U.S. Ethane Exports Through 2020(2)

U.S. ethane demand is projected to increase at an annual 3.5% CAGR through 2020, primarily based on an ≈8% CAGR for U.S. petrochemdemand 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

MM

Bb/

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

MB

bl/d

Ship Pipeline

250

200

150

100

50

MB

bl/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

MB

bl/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

LTM ProductionNTM Production ForecastAverage 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

ANTERO RESOURCES EBITDAX RECONCILIATION

48

EBITDAX Reconciliation

($ in millions) Quarter Ended LTM Ended12/31/2015 12/31/2015

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

ANTERO MIDSTREAM EBITDA RECONCILIATION

49

EBITDA and DCF Reconciliation

$ in thousandsThree months ended

December 31,2014 2015

Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow: Net income $55,898 $49,008Add:

Interest expense 2.062 2,892Depreciation expense 17,290 23,152Contingent acquisition consideration accretion - 3,333Equity-based compensation 4,226 4,810

Adjusted EBITDA $79,476 $83,195Less:

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

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 bepotentially 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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Am website presentation (a) february 2016

Investor Relations

Transcript of Am website presentation (a) february 2016