Am website presentation october 2015

Partnership OverviewOctober 2015

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, 2014 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, 2014 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.

ANTERO MIDSTREAM – 2015 GUIDANCE

Key Variable Initial Guidance(1) Updated Guidance(2)

Adjusted EBITDA ($MM) $150 - $160 $180 - $190

Distributable Cash Flow ($MM) $135 - $145 $160 - $170

Year-over-Year Distribution Growth(3) 28% - 30% 28% - 30%

Low Pressure Pipelines Added (Miles) 44 27

High Pressure Pipelines Added (Miles) 20 15

Compression Capacity Added (MMcf/d) 545 545

Capital Expenditures ($MM)

Low Pressure Gathering $165 - $170 $90 - $95

High Pressure Gathering $85 - $90 $70 - $75

Compression $160 - $165 $165 - $170

Condensate Gathering $5 - $10 $5

Water Infrastructure(4) - $80 - $90

Maintenance Capital $10 - $15 $15

Total Capital Expenditures ($MM) $425 - $450 $425 - $4501. Financial guidance per Partnership press release dated 1/20/2015.2. Updated financial guidance per Partnership press release dated 10/13/2015. 3. Reflects the expected distribution growth associated with the fourth quarter 2015 over the fourth quarter 2014.4. Includes fresh water delivery system plus waste water treatment capital expenditures.

Key Operating & Financial Assumptions

2

3

0.9x

1.2x

1.3x

0.0x

0.2x

0.4x

0.6x

0.8x

1.0x

1.2x

1.4x

$0.00

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

$0.35

$0.40

$0.45

$0.50

4Q14A 1Q15A 2Q15A 3Q15A 4Q15E 1Q16E 2Q16E 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E

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

GROWTH – HIGH GROWTH MIDSTREAM THROUGHPUT

• Antero Midstream is targeting 28% to 30% annual distribution growth through 2017

Note: Future distributions subject to AM Board approval.1. Assumes midpoint of target distribution growth range.2. 3Q 2015 distribution per Partnership press release dated 10/13/2015.

$0.17$0.18

$0.19$0.205

(2)

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

4

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 Core Net Acres - Dry Core Net Acres - Liquids-Rich

Largest Liquids-Rich Core Position in

Appalachia

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000Largest Proved Reserve Base in Appalachia

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

Appalachian Producers by Proved Reserves (Bcfe) – YE 2014(1)(2)Appalachian Producers by Core Net Acres (000’s) – August 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 CHK, CVX, HES and XOM. 3. Based on Antero geologic interpretation supported by state well data, company presentations and public land data. Peer group includes AEP, CHK, CNX, COG, CVX, EQT, NBL, RICE, RRC, STO, SWN.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.

0200400600800

1,0001,2001,4001,6001,800

0

500

1,000

1,500

2,000

2,500

3,000

3,500Appalachian Peers

11th Largest U.S. Gas Producer

5

3rd Largest Appalachian

Producer

SPONSOR STRENGTH – LEADERSHIP IN APPALACHIAN BASIN

Note: 2014 SEC prices were $4.07/MMBtu for natural gas and $81.48/Bbl for oil on a weighted average Appalachian index basis.1. 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. 2. Antero and industry rig locations as of 10/2/2015, and average rig count for 1H 2015, per RigData.

6

COMBINED TOTAL – 12/31/14 RESERVESAssumes Ethane RejectionNet Proved Reserves 12.7 TcfeNet 3P Reserves 40.7 TcfePre-Tax 3P PV-10 $22.8 BnNet 3P Reserves & Resource 53 to 57 TcfeNet 3P Liquids 1,026 MMBbls% Liquids – Net 3P 15%3Q 2015 Net Production 1,506 MMcfe/d- 3Q 2015 Net Liquids 52,250 Bbl/dNet Acres(1) 565,000Undrilled 3P Locations 5,331

UTICA SHALE CORE

Net Proved Reserves 758 BcfeNet 3P Reserves 7.6 TcfePre-Tax 3P PV-10 $6.1 BnNet Acres 147,000Undrilled 3P Locations 1,024

MARCELLUS SHALE CORE

Net Proved Reserves 11.9 TcfeNet 3P Reserves 28.4 TcfePre-Tax 3P PV-10 $16.8 BnNet Acres 418,000Undrilled 3P Locations 3,191

UPPER DEVONIAN SHALE

Net Proved Reserves 8 BcfeNet 3P Reserves 4.6 TcfePre-Tax 3P PV-10 NMUndrilled 3P Locations 1,116

WV/PA UTICA SHALE DRY GASNet Resource 12.5 to 16 TcfNet Acres 186,000Undrilled Locations 1,889

02468

101214

Rig

Cou

nt

Operators

1H 2015 Avg SW Marcellus & Utica(2)

SPONSOR STRENGTH – MOST ACTIVE OPERATORIN APPALACHIA

27.4% 26.3% 26.2%

22.8%

19.7%

15.2%12.5% 11.7% 11.2%

8.7%

2.5%

(0.3%) (1.2%) (1.5%)(4.0%) (4.1%)

(13.6%)

(19.9%)

-25%

-15%

-5%

5%

15%

25%

35%

45%

40%+

7Appalachian Peers

Source: Represents median of Wall Street research estimates for 2015E production growth vs. 2014 actual production. 1. Includes all North American E&P companies with a market capitalization greater than $4.5 billion. 2. Based on publicly announced 2015 production growth target of 40%+.

Antero’s 40%+ production growth guidance for 2015 leads the U.S. large cap E&P industry and drives AM growth(1)

GROWTH – HIGHEST GROWTH LARGE CAP E&P

(2)

$1$5 $7 $8

$11$19

$28$36

$41

$0

$10

$20

$30

$40

$50

$60

$70

26 31 40 36 41 116

222

358

454 435

0

100

200

300

400

500

600

700 Utica Marcellus

10 38 80 126 266

531

908

1,134 1,197 1,216

0

200

400

600

800

1,000

1,200

1,400

1,600Utica Marcellus

108 216

281 331 386 531

738

935 965 1,038

0

200

400

600

800

1,000

1,200

1,400 Utica Marcellus

Low Pressure Gathering (MMcf/d)

Compression (MMcf/d)

High Pressure Gathering (MMcf/d)

EBITDA ($MM)(1)

8

$185

GROWTH – HIGH GROWTH MIDSTREAM THROUGHPUT

1. 2015E EBITDA guidance updated per 9/18/2015 Partnership press release based on 10/1/2015 effective date for water drop down. Y-O-Y growth based on 3Q’14 to 3Q’15.

9

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 10/2/2015.1. Based on company filings and presentations. Peer group includes AEP, CHK, CNX, CVX, ECR, EQT, GPOR, NBL, RRC, STO, SWN.

• 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

• 2x its closest competitor

Antero has over 3,000 undeveloped rich gas locations with an average lateral length of 6,800’ in its 3P reserves

0

100

200

300

400

(000

s)

Core Liquids-Rich Net Acres(1)

248

13994

254 289

15%

38%47%

35% 40%

11%

29%38%

28% 32%

0

100

200

300

0%

15%

30%

45%

60%

Condensate Highly-RichGas/

Condensate

Highly-RichGas

Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

R

Total 3P Locations ROR @ 6/30/2015 Strip-Spot ROR @ 6/30/2015 Strip-Current

664

1,010

628 889

45%31%

14% 16%38%

26%

10% 13%0

500

1,000

1,500

0%

15%

30%

45%

60%

Highly-RichGas/

Condensate

Highly-RichGas

Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

R

Total 3P Locations ROR @ 6/30/2015 Strip-Spot ROR @ 6/30/2015 Strip-Current

MARCELLUS WELL ECONOMICS(1)

Marcellus Well Cost Improvement(2)

1. 6/30/2015 pre-tax well economics based on a 9,000’ lateral, 6/30/2015 natural gas and WTI strip pricing for 2015-2024, flat thereafter, NGLs at 32.5% of WTI for 2015–2016 and 50% of WTI thereafter, and applicable firm transportation and operating costs . Well cost estimates include $1.2 million assumed for road, pad and production facilities. Current well costs include legacy contracts. Spot well costs are adjusted for current market drilling and completion rates resulting in a $1.2 million cost saving vs. current well costs. Antero will begin to realize spot well costs as the company utilizes incremental completion crews for deferred completions beginning at year end 2015 and as existing drilling rig contracts begin to roll off during 2016.

2. 2015E well costs based on $10.3 million for a 9,000’ lateral Marcellus well and $11.6 million for a 9,000’ lateral Utica well.

10

UTICA WELL ECONOMICS(1)

72% of Marcellus locations are processable (1100-plus Btu) 72% of Utica locations are processable (1100-plus Btu)

2015Drilling

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, through a combination of service cost reductions and drilling and completion efficiencies−Well economics on some wells expected to improve further starting in early 2016 as the Company utilizes incremental market based

contracts for drilling and completion operations which is expected to reduce well costs by another 10 to 12% over time

Utica Well Cost Improvement(2)

$1.357 $1.144

$0.000

$0.500

$1.000

$1.500

$2.000

2014 2015E

$MM

/1,0

00’ L

ater

al

Well Cost ($MM/1,000')

16% Decrease vs. 2014 $1.571

$1.289

$0.000

$0.500

$1.000

$1.500

$2.000

2014 2015E

$MM

/1,0

00’ L

ater

al

Well Cost ($MM/1,000')

18% Decrease vs. 2014

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

11

HIGH VISIBILITY – PROJECTED MARCELLUS MIDSTREAM BUILDOUT

2014 2015 2016 2017 2018+

12

HIGH VISIBILITY – PROJECTED UTICA MIDSTREAM BUILDOUT2014 2015 2016 2017 2018+

Fixed Fee

100%

13

MITIGATED COMMODITY RISK – 100% FIXED FEE – RICH TO DRY

Contract Mix

Fixed Fee97%

Fixed Fee

100%

Fixed Fee

100%Fixed Fee94%

(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 6/26/2015, per RigData.3. Includes Antero Resources rigs located in Doddridge County, WV. 4. Includes Antero Resources and Range Resources rigs.

CommodityBased

CommodityBased

CommodityBased

Appalachian ExposureMarcellus – Dry Marcellus – Rich Utica – Dry Utica – Rich Rigs Running on Liquids-Rich Core Acreage Midstream Footprint (2)

Fixed Fee90%

CommodityBased

(3) (4)

10

2 2 1 1

13

0

5

10

15

AM CNNX EQM CMLP SMLP MWE

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

Jan-

13M

ar-1

3

May

-13

Jul-1

3

Sep

-13

Nov

-13

Jan-

14M

ar-1

4

May

-14

Jul-1

4

Sep

-14

Nov

-14

Jan-

15M

ar-1

5

May

-15

Jul-1

5

Sep

-15

Nov

-15

Jan-

16

Mar

-16

May

-16

Jul-1

6

Sep

-16

Nov

-16

Jan-

17M

ar-1

7

May

-17

Jul-1

7

Sep

-17

Nov

-17

Jan-

18M

ar-1

8

May

-18

Jul-1

8

Sep

-18

Nov

-18

AR Gross Gas Production

MITIGATED COMMODITY RISK – FIRM TRANSPORTATION & SALES PORTFOLIO

14

BBtu/d

Antero Resources Transportation Portfolio• Antero Resources has built the largest firm transportation portfolio with 4.85 BBtu/d by year end 2018

71%

29%

85%

15%

94%

6%

2015E 2016E 2017E 2018EFavorable:ChicagoMichConGulf CoastNYMEXTCO

AR Increasing Access to Favorable Markets

94%

6%

(NYMEX/TCO) Mid-Atlantic (NYMEX)(ANR) Gulf Coast

(REX/ANR/NGLP/MGT) Midwest(DOM S) Appalachia

(TETCO M2) Appalachia

(Tennessee) Gulf Coast

(TCO) Appalachia or Gulf Coast

Less favorable:TETCO M2Dominion South

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$0

$50

$100

$150

$200

$250

$MM

15

HEDGING – INTEGRAL TO BUSINESS MODEL

1. 4Q 2015 – 4Q 2021 hedge gains based on current mark-to-market hedge gains.2. Based on NYMEX strip as of 9/30/2015.

Hedging is a key component of Antero’s business model which includes development of a large, repeatable drilling inventory

Antero has realized almost $1.5 billion of gains on commodity hedges since 2009– Gains realized in 26 of last 27 quarters, or 96% of the quarters since 2009

● Based on Antero’s hedge position and assuming strip pricing as of 9/30/2015(2), a further $3.1 billion in hedge gains are projected to be realized through the end of 2021

● Significant additional hedge capacity remains under the credit facility hedging covenant for the 2017 – 2021 period

Quarterly Realized Hedge Gains / (Losses)(1)

Realized Hedge GainsProjected Hedge Gains(2)

NYMEX Natural Gas Historical Spot Prices

($/Mcf)

NYMEX Natural Gas Futures Prices(2)

3.1 Tcfe Hedged at average index price

of $3.93/Mcfethrough 2021

$3.1 Billion in Projected Hedge Gains Through

2021(1)

Average Hedge Prices ($/Mcfe)

$3.94 $3.83$4.06 $3.94

$3.75 $3.67

$4.51

Realized $1.5 Billion in Hedge

Gains Since 2009

Regional Gas Pipelines

Miles Capacity In-Service

Regional Gathering Pipeline(2)

50 1.4 Bcf/d 4Q 2015

161. 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 regional gathering 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 2014 YE 2015E

Marcellus 91 108

Utica 45 56

Total 136 164

AM has option to participate in processing, fractionation,

terminaling and storage projects offered to AR


Marcellus 62 76

Utica 35 36

Total 97 112

(MMcf/d) YE 2014 YE 2015E

Marcellus 375 800

Utica 0 120

Total 375 920

AM Owned Assets

Condensate GatheringStabilization


Utica 16 19

EndUsers

AM Option Assets

(Ethane, Propane, Butane, etc.)

VALUE CHAIN OPPORTUNITY – FULL MIDSTREAM VALUE CHAIN

Water Drop Down Completed

Liquidity

STRONG FINANCIAL POSITION – STRONG BALANCE SHEETAND FLEXIBILITY

Antero Resources (NYSE:AR) Antero Midstream (NYSE:AM)(4)

6/30/15 Debt Liquid Non-E&P Assets 6/30/15 Debt Liquid Assets

Debt Type $MMPF Credit facility(1) $324

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 $3,699

Asset Type $MMCommodity derivatives $3,096

PF AM equity ownership(3) 2,790

Cash 30

Total $5,916

Liquid non-E&P assets of $5.9 Bn pro forma for water drop down significantly exceed total pro forma debt of $3.7 Bn

Asset Type $MMCash (including from water drop down) $30

Credit facility – borrowing base capacity 4,000

Credit facility – drawn (324)

Credit facility – letters of credit (475)

Total $3,231

Debt Type $MMPF Credit facility(4) $439

Total $439

Asset Type $MMPF Cash $0

Total $0

Liquidity

Asset Type $MMCash $-

Credit facility – capacity(5) 1,500

Credit facility – drawn (439)

Credit facility – letters of credit -

Total $1,061

Over $6.0 billion of liquidity at AR including $2.8 billion of liquid AM units Over $1 billion of liquidity at AM

Note: All balance sheet data as of 6/30/2015, except where pro forma.1. Pro forma credit facility outstanding reduced by $794 million of net proceeds from $1.05 billion water drop down to Antero Midstream; additional consideration of 11.0 million AM units also received. 2. Mark-to-market as of 9/30/2015.3. Based on AR ownership of AM units (105.9 million common and subordinated units) plus 11.0 million AM units received in AR water drop down. AM price as of 10/9/2015. 4. Pro forma for $1.05 billion water drop down funded with $113 million of cash, $439 million of debt and net proceeds from 11.0 million units to AR and 12.9 million units from PIPE transaction.5. Credit facility increased to $1.5 billion upon water drop down – 3 new banks added to existing bank group of 17 banks.

17

Only 29% of AM credit facility capacity drawn

(2)

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

(4)

• $1.5 billion revolver in place to fund future growth capital (5x Debt/EBITDA Cap)

• Pro forma liquidity of $1,061 million at 6/30/2015

• Sponsor (NYSE: AR) has Ba2/BB corporate ratings

AM Liquidity (6/30/2015)(1)

AM Peer Leverage Comparison(3)

($ in millions)

Revolver Capacity(2) $1,500

Less: Borrowings 439

Plus: Cash -

Liquidity $1,061

Financial Flexibility

STRONG FINANCIAL POSITION – SIGNIFICANT FINANCIAL FLEXIBILITY

181. Pro forma for $1.05 billion water drop down funded with $113 million of cash, $439 million of debt and net proceeds from 11.0 million units to AR and 12.9 million units from PIPE transaction. 2. Revolver capacity increased to $1.5 billion at water drop down. 3. As of 6/30/2015. Peers include TEP, EQM, MWE, WES, RMP, SHLX, DM, and CNNX.4. AM pro forma for water drop down; LQA EBITDA for water based on 2016E midpoint of 8.5x – 9.0x purchase price multiple announced.

TOP TIER DISTRIBUTION GROWTH & HEALTHY COVERAGE

19

26% 26%24% 25% 24% 25%

18%

15%

10%12%

6%

1.6x 1.5x

1.2x

1.8x

1.2x 1.2x

1.6x

1.3x

1.2x 1.3x

1.0x

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%

AM SHLX PSXP VLP DM MPLX EQM TEP CNNX WES MWE

3–Year Expected Distribution Growth Rate and DCF Coverage(1)

1. Based on Bloomberg 2015-2017 consensus distribution and DCF coverage estimates data as of 10/9/2015.

MWE

WES

CNNX

TEP

EQM

MPLX

VLPPSXP

DM

SHLX

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

10%

3% 8% 13% 18% 23% 28% 33%

Yiel

d (%

)

2015-2018 Distribution Growth CAGRBubble Size Reflects Market Capitalization

R-squared = .83

Note: Based on Bloomberg consensus estimates and market prices as of 10/9/2015.

ATTRACTIVE VALUE PROPOSITION

20

AM - Current Yield: 3.18%Price: $23.87

AM - ImpliedYield: 2.53%Price: $30.05

• Attractive appreciation potential on a relative basis

Antero Midstream (NYSE: AM)Asset Overview

21

1. Represents inception to date actuals as of 12/31/2014 and 2015 midpoint guidance.2. Pro forma for water drop down. Includes $15.0 million of maintenance capex at 2015 midpoint guidance.

22

UticaShale

MarcellusShale

Projected Midstream Infrastructure(1)

Marcellus Shale

Utica Shale Total

YE 2014 Cumulative Gathering/ Compression Capex ($MM) $836 $345 $1,181

Gathering Pipelines(Miles) 153 80 233

Compression Capacity(MMcf/d) 375 - 375

Condensate Gathering Pipelines (Miles) - 16 16

2015E Capex Budget ($MM)(2) $256 $182 $438Gathering Pipelines

(Miles) 31 12 43

Compression Capacity(MMcf/d) 425 120 545

Condensate Gathering Pipelines (Miles) - 3 3

Midstream Assets

ANTERO MIDSTREAM ASSET OVERVIEW

• Gathering and compression assets in core of rapidly growing Marcellus and Utica Shale plays

– Acreage dedication of ~434,000 net leasehold acres for gathering and compression services

– Additional stacked pay potential with dedication on 186,000 acres of Utica deep rights underlying the Marcellus in WV and PA

– 100% fixed fee long term contracts

• AR owns 67% of AM units (NYSE: AM) pro forma

ANTERO MIDSTREAM ASSETS – RICH GAS MARCELLUS

23

• 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 nine drilling rigs in the Marcellus Shale during 2015, including intermediate rigs

− 100% of rigs targeting the highly-rich gas/condensate and highly-rich gas regimes

• Of the 80 gross wells targeted to be completed in 2015, 90% (72 gross wells) are forecast to be completed in the AM dedicated area

− AM dedicated acreage contains 2,165 gross undeveloped Marcellus locations and 313 Upper Devonian locations

• Antero will defer 50 completions originally scheduled to occur in the second and third quarters of 2015 into 2016 in order to limit natural gas volumes sold into unfavorable pricing markets

− 28 of the deferred completions are in the AM dedicated area

Marcellus Gathering & Compression

Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.

YE 2014 YE 2015E

Low Pressure Gathering Pipelines (Miles)

91 108

High Pressure Gathering Pipelines (Miles)

62 76

Compression Capacity (MMcf/d) 375 800

24

• 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 five drilling rigs in the Utica Shale during 2015, including intermediate rigs

− 100% of rigs targeting the highly-rich gas/condensate and highly-rich gas regimes

• All of the 50 gross wells targeted to be completed in 2015 are on Antero Midstream’s footprint

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 2014 YE 2015E

Low Pressure Gathering Pipelines (Miles)

45 56

High Pressure Gathering Pipelines (Miles)

35 36

Condensate Pipelines (Miles) 16 19

Compression Capacity (MMcf/d) 0 120

ANTERO INTEGRATED WATER BUSINESS

25

Marcellus Fresh Water System(2)

• Provides fresh water to support Marcellus well completions • Year-round water supply sources: Ohio River and local rivers• Ozone Water treatment facility to be in-service by 3Q 2015• Significant asset growth in 2015 as summarized below:

Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.1. Represents inception to date actuals as of 06/30/2015 and 2015 guidance.2. All Antero water withdrawal sites are fully permitted under long-term state regulatory permits both in WV and OH. 3. 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.4. 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.

Utica Fresh Water System(2)

• Provides fresh water to support Utica well completions • Year-round water supply sources: local reservoirs and rivers• Significant asset growth in 2015 as summarized below:

Marcellus Water System YE 2014 YE 2015E

Water Pipeline (Miles) 177 226

Fresh Water Storage Impoundments 22 24

Cash Operating Margin per Well ($)(3) $700K -$750K

Utica Water System YE 2014 YE 2015E

Water Pipeline (Miles) 61 90

Fresh Water Storage Impoundments 8 14

Cash Operating Margin per Well ($)(4) $775K -$825K

Projected Fresh Water Delivery Infrastructure(1)

Marcellus Shale

Utica Shale Total

YE 2015E Cumulative Water System Capex ($MM) $340 $113 $453Water Pipelines (Miles) 226 90 316Water Storage Facilities 24 14 38

AM has 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

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

Antero Clearwater Advanced Wastewater Treatment Capacity (Bbl/d)

Produced/Flowback Volumes (Bbl/d)

ADVANCED WASTEWATER TREATMENT

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

26Integrated Water Business

ORGANIC GROWTH STRATEGY: “BUILD VS. BUY”

27

• 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

Water Business

RegionalPipeline

Processing/Fractionation

Unlevered IRR Range: 25% - 35% 15% - 25% 10% - 20% 25% - 35% 30% - 40% 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 3.5 - 7.0 5.0 - 6.0 Minimum Volume Commitments: N/A 75% 70% N/A Yes 80% 80%

2015 Capex(2) TotalMarcellus $298 $49 $62 $105 - $82 Utica 125 44 11 63 5 3

Growth Capex $423 $93 $73 $168 $5 $85 % of Capex 100% 22% 17% 40% 1% 20%

Included in 2015 Budget: Marcellus & Utica

Marcellus & Utica

Marcellus & Utica

Utica Marcellus & Utica

Not Included Not Included

Additional In-hand Opportunities:

Dry Utica Dry Utica Dry Utica Utica Stabilization

Dry Utica Regional Gathering

Pipeline

Marcellus Processing/

Fractionation

25%

15%

10%

25%

30%

15% 15%

35%

25%

20%

35%

25%20%

40%

0%

10%

20%

30%

40%

Inte

rnal

Rat

e of

Ret

urn

28

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 9/18/2015 Partnership press release. 2. Excludes $15.0 million of maintenance capex.

Wtd. Avg. 24% IRR

AM Option Opportunities

AM UPSIDE OPPORTUNITY SET

29

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 expected to go in-service in 4Q 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• 186,000 net acres of AR Utica dry gas acreage underlying

the Marcellus in West Virginia and Pennsylvania dedicated to AM

• AR drilling 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 have added 20,000

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 to more favorably priced markets including TCO, NYMEX and Gulf Coast markets

●Once the Regional Pipeline is placed into service, Antero Resources plans to complete the previously deferred 50 Marcellus wells, resulting in approximately 350 MMcf/d of incremental gross gas production at its peak

Regional Gathering Pipeline

Throughput Capacity: 1.4 Bcf/d

Pipeline Specifications:

50 miles of 36 inch pipeline

Project Capital: ≈ $400 Million

In-Service Date: 4Q 2015

AR Firm Commitment: 900 MMcf/d

30

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 12/31/2014.

Processing Area Of Dedication for AM

MarkWest Processing AOD – 194,500 Gross

Acres

Tyler County70,000 Gross Acres

Ritchie County46,500 Gross Acres

Antero Resources has 11.6 Tcf of processable gross 3P gas reserves and 616 Million Bbls of gross 3P NGL reserves across 128,500 gross processable Marcellus acres that are dedicated to Antero Midstream for processing

31

Gilmer County12,000 Gross Acres

AR Gross Gross 3P NGL AR 3P GrossProcessable Reserves Wellhead Gas

Acres (MMBbls) (1) (Tcf)Potential Processing AOD for AMTyler 70,000 382.2 6.6

Ritchie 46,500 196.6 4.0

Gilmer 12,000 37.1 1.0

Total 128,500 615.9 11.6

LARGE UTICA SHALE DRY GAS POSITION

32

Antero has the right to build gathering and compression infrastructure to move Antero’s future dry gas Utica production− AM pro forma water business would also serve Antero’s

dry gas Utica development Antero drilled and cased its first dry gas Utica well in 3Q

2015 Antero has 226,000 net acres of exposure to Utica dry gas

play 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

AnteroUtica Well

Drilling

Well Operator24-hr IP(MMcf/d)

LateralLength

(Ft)

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.

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 Locations186,000 Net Acres

AR Utica Shale Dry GasOhio

3P Reserves2.4 Tcf

289 Gross Locations40,000 Net Acres

AR Utica Shale Dry GasTotal OH/WV/PA

Net Resource14.9 to 18.4 Tcf

2,178 Gross Locations226,000 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


Low Cost Marcellus/Utica Focus

“Best-in-Class” Distribution Growth

33

CATALYSTS

28% to 30% per year from 2015 to 2017 targeted based on Sponsor planned development; additional third party business expansion opportunities

AM Sponsor is the most active operator in Appalachia; 40%+ production growth targeted for 2015 supported by $1.8 billion capital budget, firm processing and takeaway, long-term natural gas hedges and $3.2 billion of liquidity; targeting 25% to 30% production growth in 2016

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

34

Transaction Specifics

ASSETS:• Antero’s Marcellus and Utica freshwater delivery business, the fully contracted future

advanced wastewater treatment complex and 20-year agreement to cover all fluid handling and disposal services for Antero

PURCHASE PRICE: • $1.05 billion initial payment at closing and earn out payments at year-end 2019 and 2020 of $125 million each if 3-year volume threshold is met

MINIMUM VOLUME COMMITMENTS: • 90,000 Bbl/d in 2016, 100,000 Bbl/d in 2017 and 120,000 Bbl/d in 2018 and 2019

FINANCING:• $243 million of units issued via PIPE, $257 million of units issued to Antero Resources and

$552 million from existing cash and revolving credit facility; 23.9 million partnership units issued in total

CLOSING: • Expected to close concurrently with AM PIPE unit offering on September 23, 2015

Transaction Rationale

SCALE/GROWTH:

• Accretive to AM growth story and adds largest Appalachian integrated water business to high growth gathering and compressions assets to create one of the highest growth midstream MLPs in the U.S.

• PIPE cash proceeds to be used by AR to repay debt and fund future development plan

VALUATION: • Accretive purchase price at 8.5x to 9.0x projected 2016 EBITDA

MIDSTREAMINTEGRATION:

• Integrates water delivery, water services and waste water treatment business with existing gas gathering and compression business

THIRD PARTY BUSINESS: • Enhances AM’s ability to attract third party business – fresh water supply to completions and treatment of produced and flowback water

PRO FORMA LEVERAGE: • Net Debt/LTM EBITDAX 1.7x; over $1 billion of AM liquidity post transaction

WATER DROP DOWN COMPLETED

35

MVCS SUPPORT AND EARN OUTS DRIVE RETURNS

361. The 2019 earn out is based on a trailing 36 month fresh water delivery volume average at the end of 2019 of 161,000 Bbl/d while the 2020 earn out is based on a trailing 36 month fresh water delivery volume average at the end of 2020 of 200,000 Bbl/d.

Minimum volume commitments (MVCs) on fresh water delivery volumes, at $3.68 and $3.63 per barrel for the Marcellus and Utica respectively (with CPI adjustments), support revenues and rates of return for the water business acquisition

Earn out payments at year-end 2019 and 2020 provide incentives for the sponsor to perform long-term

0

40

80

120

160

200

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

MB

bl/d

Actual Volumes Estimated Volumes MVCs

Fresh Water Delivery MVCs and Earn Out Payments(1)17

7 C

ompl

etio

ns

≈ 13

0 C

ompl

etio

ns

≈ 12

5 -1

35 C

ompl

etio

ns

2020 Earn Out – 200 MBbl/d Avg

2019 Earn Out – 161 MBbl/d Avg

MVC90K

MVC100K

MVC120K

MVC120K

125K

80K - 85K

50 Deferred Completions

Transaction Metrics2016E EBITDA: $115MM - $125MM

Estimated Volume: 115K - 125K Bbl/d 2016E Completions: 160 - 170

2016E VolumeMidpoint 120K

IMPACT OF DROP DOWN TRANSACTION ON ANTERO FINANCIAL STATEMENTS

37

Metrics

Pre-Drop DownAntero Resources

(Consolidated)

Pro Forma Drop DownAntero Resources

(Consolidated)Antero Midstream

Partners

Fresh Water Distribution Fees N/A - Eliminated Upon Consolidation

N/A - Eliminated Upon Consolidation Revenue

Fresh Water Operating Expenses ("Opex") Drilling & Completion Capital

Drilling & Completion Capital

Operating Expenses

Fresh Water Infrastructure Capital Water Capital Water Capital Water Capital

Advanced Wastewater Treatment Fees(Upon 4Q ‘17 Expected In-Service) N/A N/A - Eliminated Upon

Consolidation Revenue

Advanced Wastewater Treatment Opex (Upon 4Q ‘17 Expected In-Service) N/A Drilling & Completion

Capital and LOEOperating Expenses

Advanced Wastewater Treatment Capital(Upon 4Q ‘17 Expected In-Service) Water Capital Water Capital Water Capital

2016E EBITDA Multiple of Drop Down N/AN/A - Water Fees are

Eliminated and Opex is Capitalized

8.5x - 9.0x

Implied 2016 EBITDA of Water Business N/AN/A - Water Fees are

Eliminated and Opex is Capitalized

~ $115 - $125 Million

LARGEST FIRM TRANSPORTATION AND PROCESSING PORTFOLIO IN APPALACHIA

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

62 MBbl/d CommitmentMarcus Hook Export

Shell20 MBbl/d CommitmentBeaver County Cracker

(Pending FID YE‘15)

Sabine Pass (Trains 1-4)50 MMcf/d per Train

Freeport LNG70 MMcf/d

1. November 2015 and full year 2016 futures basis, respectively, provided by Wells Fargo dated 9/30/2015. Favorable markets shaded in green.

Chicago(1)

$.22 / $0.04

CGTLA(1)

$(0.09) / $(0.08)

Dom South(1)

$(1.55) / $(1.05)

TCO(1)

$(0.18) / $(0.22)

38

Cove Point

4.85 Bcf/dFirm GasTakeaway

By YE 2018

4.85 Bcf/d natural gas FT portfolio by YE 2018 with 85% serving favorable markets and an average demand fee of $0.40/MMBtu

YE 2018 Gas Market MixAR 4.85 Bcf/d FT

43%Gulf Coast

16%Midwest

13%Atlantic

Seaboard

12%Dom S/TETCO

(PA)

15%TCO

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

39

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)

40

ShellBeaver County Cracker

(Pending FID YE’15)

Mariner East 262 MBbl/d Commitment

Marcus Hook ExportAR Has Doubling Rights

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

41

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

42

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

43

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

441. 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

47

Northeast Ethane

Rejection

Exports

U.S. PetChem

Plan to defer 50 Marcellus well completions into 2016 to achieve higher gas price realizations, approximately half of which are located on AM areas of dedication− Regional gathering pipeline expected in-service late 2015 will connect incremental Marcellus production to CGTLA (Gulf

Coast) and TCO pricing

AR COMPLETION DEFERRALS – 2016 VOLUME IMPACT

0

50

100

150

200

250

300

350

400

450

500

Jan-16 Mar-16 May-16

Gro

ss W

ellh

ead

Prod

uctio

n (M

Mcf

/d)

Completion Deferral Impact on 2016 Production

Production From 50 Deferred

Completions

48

ANTERO RESOURCES – UPDATED 2015 GUIDANCE

Key Variable 2015 GuidanceNet Daily Production (MMcfe/d) 1,400

Net Residue Natural Gas Production (MMcf/d) 1,175

Net Liquids Production (Bbl/d) 33,000

Net Oil Production (Bbl/d) 4,000

Natural Gas Realized Price Differential to NYMEX Henry Hub Before Hedging ($/Mcf) $(0.20) - $(0.30)

Oil Realized Price Differential to NYMEX WTI Before Hedging ($/Bbl) $(12.00) - $(14.00)

NGL Realized Price (% of WTI)(1) 30% - 35%

Cash Production Expense ($/Mcfe)(2) $1.50 - $1.60

Marketing Expense, Net of Marketing Revenue ($/Mcfe) $0.20 - $0.30

G&A Expense ($/Mcfe) $0.23 - $0.27

Net Income Attributable to Non-Controlling Interest ($MM) $23 - $27

Operated Wells Completed 130

Average Operated Drilling Rigs 14

Capital Expenditures ($MM)

Drilling & Completion $1,600

Water Infrastructure $50

Land $150

Total Capital Expenditures ($MM) $1,800

1. Updated NGL pricing guidance for 2015; 1Q 2015 NGL prices before hedges were 50% of WTI per press release dated 4/29/2015.2. Includes lease operating expenses, gathering, compression and transportation expenses and production taxes. Excludes net marketing expense.

Key Operating & Financial Assumptions

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LTM Production

NTM Production Forecast

Average LTM Production

MAINTENANCE CAPITAL METHODOLOGY

• Maintenance Capital Calculation Methodology– 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

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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, 2014 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, 2014. 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 october 2015

Investor Relations

Transcript of Am website presentation october 2015