am website presentation september 2015

53
Partnership Overview September 2015

Upload: anteromidstream

Post on 22-Jan-2018

809 views

Category:

Business


3 download

TRANSCRIPT

Page 1: Am website presentation   september 2015

Partnership OverviewSeptember 2015

Page 2: Am website presentation   september 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.

Page 3: Am website presentation   september 2015

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 ANNOUNCED

2

Page 4: Am website presentation   september 2015

MVCS SUPPORT AND EARN OUTS DRIVE RETURNS

31. 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

Page 5: Am website presentation   september 2015

ANTERO MIDSTREAM – 2015 GUIDANCE

Key Variable 2015 Guidance(1) 2015 Revised Guidance(2)

Adjusted EBITDA ($MM) $150 - $160 $170 - $180

Distributable Cash Flow ($MM) $135 - $145 $150 - $160

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 for water drop down. 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

4

Page 6: Am website presentation   september 2015

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

5

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

Page 7: Am website presentation   september 2015

-

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

6

3rd Largest Appalachian

Producer

SPONSOR STRENGTH – LEADERSHIP IN APPALACHIAN BASIN

Page 8: Am website presentation   september 2015

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 8/28/2015, and average rig count for 1H 2015, per RigData.

SPONSOR STRENGTH – MOST ACTIVE OPERATORIN APPALACHIA

7

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%2Q 2015 Net Production 1,484 MMcfe/d- 2Q 2015 Net Liquids 45,900 Bbl/dNet Acres(1) 559,000Undrilled 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 149,000Undrilled 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 410,000Undrilled 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 181,000Undrilled Locations 1,889

02468

101214

Rig

Cou

nt

Operators

1H 2015 Avg SW Marcellus & Utica(2)

Page 9: Am website presentation   september 2015

27.4% 26.3% 26.2%

22.8%

19.7%

15.3%

12.4% 11.7% 11.2%8.7%

2.5%

(0.3%) (1.2%) (1.5%)(3.8%) (4.1%)

(13.7%)(16.2%)

-25%

-15%

-5%

5%

15%

25%

35%

45%

40%+

8Appalachian 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 $5.0 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(1) and drives AM growth(1)

GROWTH – HIGHEST GROWTH LARGE CAP E&P

(2)

Page 10: Am website presentation   september 2015

108 216

281 331 386

531

738

935 965

0

200

400

600

800

1,000

1,200

2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 4Q '14 1Q '15 2Q' 15

Utica Marcellus

$1$5 $7 $8

$11

$19

$28

$36

$41

$0$5

$10$15$20$25$30$35$40$45$50

2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 4Q '14 1Q '15 2Q' 15 2015E

26 31 40 36 41

116

222

358

454

0

100

200

300

400

500

2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 4Q '14 1Q '15 2Q' 15

Marcellus

10 38 80 126

266

531

908

1,134 1,197

0

200

400

600

800

1,000

1,200

2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 4Q '14 1Q '15 2Q' 15

Utica Marcellus

Low Pressure Gathering (MMcf/d)

Compression (MMcf/d)

High Pressure Gathering (MMcf/d)

EBITDA ($MM)(1)

9

$175

GROWTH – HIGH GROWTH MIDSTREAM THROUGHPUT

1. 2015E EBITDA guidance updated per 9/18/2015 press release based on 10/1/2015 effective date for water drop down. Y-O-Y growth based on 2Q’14 to 2Q’15.

Page 11: Am website presentation   september 2015

10

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 8/28/2015.1. 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)

Page 12: Am website presentation   september 2015

248

13994

254 289

14%

37%49%

39% 43%

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 @ 12/31/2014 Strip ROR @ 6/30/2015 Strip

664

1,010

628 88942%

30%

16% 17%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 @ 12/31/2014 Strip ROR @ 6/30/2015 Strip

MARCELLUS WELL ECONOMICS(1)

Marcellus Well Cost Improvement(2)

1. 12/31/2014 pre-tax well economics based on a 9,000’ lateral, 12/31/2014 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. 6/30/2015 pre-tax well economics based on a 9,000’ lateral and 6/30/2015 strip pricing with same pricing assumptions as used for 12/31/2014 pricing. Well cost estimates include $1.2 million assumed for road, pad and production facilities.

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.

11

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− 2015 drilling plans generate 26% to 49% rates of return including all pad, road and production facilities costs, depending on which strip price

deck is assumed (6/30/2015 vs. 12/31/2014)

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

Page 13: Am website presentation   september 2015

Marcellus and Utica undeveloped 3P rich-gas locations have the lowest break-even prices for both oil and natural gas compared to other U.S. shale plays

$39 $42 $44$51 $53 $54

$60 $64 $65 $68 $69 $72$83

$86

$0

$20

$40

$60

$80

$100

WTI

Pric

e ($

/Bbl

)

Antero 2015Drilling Plan

1. Source: Credit Suisse report dated December 2014 – Break-even WTI oil price to generate 15% after-tax rate of return. Assumes NYMEX gas price of $3.66/MMBtu for 2015-2019; $4.23/MMBtu thereafter.2. 2015 one year WTI crude oil strip price as of 12/31/14; NYMEX one year natural gas strip price as of 12/31/14.3. Source: Credit Suisse report dated December 2014 – Break-even NYMEX gas price to generate 15% after-tax rate of return. Assumes WTI oil price of $64.74/Bbl for 2015-2019; $70.50/Bbl thereafter; NGLs at

35% of WTI vs. Antero guidance of 30%-35% of WTI for 2015-2016 and 50% of WTI for 2017 and thereafter, driven by completion of Mariner East II project expected by year-end 2016.

$1.94 $2.20 $2.20 $2.37

$2.96 $3.13 $3.31 $3.48 $3.50 $3.63 $3.77 $3.85 $3.88 $3.98 $4.33 $4.38

$5.56 $5.62 $5.69 $5.71 $5.74

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

NYM

EX P

rice

($/M

MB

tu)

Antero 2015Drilling Plan

Assumes $65/Bbl WTI Oil(3)

SUSTAINABLE BUSINESS MODEL– LOW BREAK-EVEN PRICE ECONOMICS

North American Break-even Natural Gas Prices ($/MMBtu)(3)

12

North American Break-even Oil Prices ($/Bbl)(1)

2015 NYMEX Strip: $3.01/MMBtu(2)

2015 WTI Strip: $56.26/Bbl(2)

Antero Projects

Assumes $3.66/MMBtu NYMEX Gas(1)

Page 14: Am website presentation   september 2015

13

HIGH VISIBILITY – PROJECTED MARCELLUS MIDSTREAM BUILDOUT

2014 2015 2016 2017 2018+

Page 15: Am website presentation   september 2015

14

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

Page 16: Am website presentation   september 2015

Fixed Fee

100%

15

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

Page 17: Am website presentation   september 2015

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

16

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

Page 18: Am website presentation   september 2015

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$0

$50

$100

$150

$200

$250

$MM

MITIGATED COMMODITY RISK – INTEGRAL TO BUSINESS MODEL

1. 3Q 2015 – 4Q 2021 hedge gains based on current mark-to-market hedge gains.2. Based on NYMEX strip as of 6/30/2015.

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

Antero has realized $1.3 billion of gains on commodity hedges over the past 6 ½ years– Gains realized in 25 of last 26 quarters, or 96% of the quarters since 2009

● Based on Antero’s hedge position and strip pricing as of 6/30/2015(2), a further $2.0 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 2016 – 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)

2.8 Tcfe Hedged at average price of

$4.08/Mcfethrough 2021

$4.43

$4.02 $4.03$4.25

$4.05$3.82

Realized $1.3 Billion in Hedge Gains

Since 2009

$2.0 Billion in Projected Hedge Gains Through

2021(1)

Average Hedge Prices ($/Mcfe)

$3.74

17

Page 19: Am website presentation   september 2015

Regional Gas Pipelines

Miles Capacity In-Service

Regional Gathering Pipeline(2)

50 1.4 Bcf/d 4Q 2015

181. 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

(Miles) YE 2014 YE 2015E

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

(Miles) YE 2014 YE 2015E

Utica 16 19

EndUsers

AM Option Assets

(Ethane, Propane, Butane, etc.)

VALUE CHAIN OPPORTUNITY – FULL MIDSTREAM VALUE CHAIN

Water Drop Down

Page 20: Am website presentation   september 2015

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)

• 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

1. 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. As of 6/30/2015. Peers include TEP, EQM, MWE, WES, RMP, SHLX, DM, and CNNX.

Financial Flexibility

STRONG FINANCIAL POSITION – SIGNIFICANT FINANCIAL FLEXIBILITY

19

Page 21: Am website presentation   september 2015

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

201. Based on Bloomberg 2015-2017 consensus distribution and DCF coverage estimates. Data as of 6/30/2015.

TOP TIER DISTRIBUTION GROWTH & HEALTHY COVERAGE

35%

28%25% 25% 24% 24%

17% 16% 14% 14% 12%8%

1.17x 1.20x 1.21x

1.46x 1.44x

1.63x

1.50x

1.25x1.18x

1.25x

1.15x1.10x

0.00x

0.20x

0.40x

0.60x

0.80x

1.00x

1.20x

1.40x

1.60x

1.80x

0%

5%

10%

15%

20%

25%

30%

35%

40%

SHLX AM DM PSXP MPLX VLP EQM CNNX TEP SXL WES MWE

Page 22: Am website presentation   september 2015

EQM

DM

SHLX

CNNX

MWE

WES TEP

MPLX

PSXP

VLP

AM - CurrentYield: 3.67%

Price: $20.70/unit

AM - ImpliedYield: 2.76%

Price: $27.59unit

y = -0.038ln(x) - 0.0228R² = 0.7155

0.00%

1.00%

2.00%

3.00%

4.00%

5.00%

6.00%

7.00%

8.00%

9.00%

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

Yiel

d (%

)

2015-2018 Distribution Growth CAGRBubble Size Reflects Market Capitalization

ATTRACTIVE VALUE PROPOSITION

Note: Based on Bloomberg consensus estimates and current market prices as of 9/14/2015. 21

• Attractive appreciation potential on a relative basis

R-squared = .72

Page 23: Am website presentation   september 2015

Antero Midstream (NYSE: AM)Asset Overview

22

Page 24: Am website presentation   september 2015

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.

23

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 ~428,000 net leasehold acres for gathering and compression services

– Additional stacked pay potential with dedication on 181,000 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

Page 25: Am website presentation   september 2015

ANTERO MIDSTREAM ASSETS – RICH GAS MARCELLUS

24

• 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

Page 26: Am website presentation   september 2015

25

• 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

Page 27: Am website presentation   september 2015

ANTERO INTEGRATED WATER BUSINESS

26

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

Page 28: Am website presentation   september 2015

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

27Integrated Water Business

Page 29: Am website presentation   september 2015

ORGANIC GROWTH STRATEGY: “BUILD VS. BUY”

28

• 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

Page 30: Am website presentation   september 2015

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

29

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 press release. 2. Excludes $15.0 million of maintenance capex.

Wtd. Avg. 24% IRR

AM Option Opportunities

Page 31: Am website presentation   september 2015

AM UPSIDE OPPORTUNITY SET

30

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• 181,000 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

Page 32: Am website presentation   september 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

31

Page 33: Am website presentation   september 2015

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

32

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

Page 34: Am website presentation   september 2015

LARGE UTICA SHALE DRY GAS POSITION

33

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 spud its first dry gas Utica well in 3Q 2015 Antero has 224,000 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

5,000’ LateralIP 17.2 MMcf/d

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

5,289’ LateralIP 46.5 MMcf/d

RangeClaysville SC #11H

5,420’ LateralIP 59.0 MMcf/d

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

6,957’ LateralIP 41.7 MMcf/d

AR Utica Shale Dry GasWV/PA

Net Resource12.5 to 16 Tcf

1,889 Gross Locations181,000 Net Acres

AR Utica Shale Dry GasOhio

3P Reserves2.4 Tcf

289 Gross Locations43,000 Net Acres

AR Utica Shale Dry GasTotal OH/WV/PA

Net Resource14.9 to 18.4 Tcf

2,178 Gross Locations224,000 Net Acres

Stone EnergyPribble 6HU

3,605’ LateralIP 30.0 MMcf/d

SouthwesternMessenger 3H5,889’ Lateral

IP 25.0 MMcf/d

RiceBlue Thunder

10H, 12H≈9,000’ Lateral

GastarBlake U-7H

6,617’ LateralIP 36.8 MMcf/d

EQTScotts Run

3,221’ LateralIP 72.9 MMcf/d

CNXGaut 4IH

5,840’ LateralIP 61.0 MMcf/d

Page 35: Am website presentation   september 2015

Low Cost Marcellus/Utica Focus

“Best-in-Class” Distribution Growth

34

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

Page 36: Am website presentation   september 2015

$0.17 $0.18 $0.19

$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 3Q15E 4Q15E 1Q16E 2Q16E 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E

TOP TIER DISTRIBUTION GROWTH

35

Distribution Per Unit(1)

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

Note: Future distributions subject to AM Board approval1. Assumes midpoint of target distribution growth range

Page 37: Am website presentation   september 2015

APPENDIX

36

Page 38: Am website presentation   september 2015

LARGEST FIRM TRANSPORTATION AND PROCESSING PORTFOLIO IN APPALACHIA

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

Mariner East 262 MBbl/d Commitment

Marcus Hook Export

Shell20 MBbl/d CommitmentBeaver County Cracker

(Pending FID YE‘15)

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

1. August 2015 and full year 2016 futures basis, respectively, provided by Wells Fargo dated 6/30/2015. Favorable markets shaded in green.

Chicago(1)

$(0.04) / $(0.06)

CGTLA(1)

$(0.07) / $(0.08)

Dom South(1)

$(1.52) / $(1.17)

TCO(1)

$(0.12) / $(0.31)

37

Cove Point

4.85 Bcf/dFirm GasTakeaway

By YE 2018

4.85 Bcf/d portfolio by YE 2018 with 85% serving favorable markets with 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

Page 39: Am website presentation   september 2015

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.

38

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− 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

Page 40: Am website presentation   september 2015

NORTHEAST NGL GROWTH IS SUPPORTED BY INCREASING TAKEAWAY OPTIONS

1. Figure 13 per Citi research dated 7/15/2015; Chart 10 per BAML research dated 6/5/2015. Mont Belvieu forward prices as at 9/2/2015 per ICE. Pipeline volumes are capacity estimates.

NGL Pipelines – Actual (2015) and Projected(1)

39

Shell20 MBbl/d CommitmentBeaver 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 significantly as pipeline options to domestic markets and export terminals go in-service (Mariner East 2, for example)

(MMBbl/d)

MMBbl/d

Page 41: Am website presentation   september 2015

$0.00

$0.10

$0.20

$0.30

$0.40

$0.50

$/G

allo

n

Baltic Rate LPG Freight Futures

Baltic Rate ($/Gal) Marcus Hook to Europe ($/Gal)Marcus Hook to Far East ($/Gal)

U.S. LPG EXPORTS ARE SUPPORTED BY EXCESSDOCK CAPACITY AND FLEET GROWTH

40

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

Significant U.S. Total LPG Export Terminal Capacity vs. 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 $0.40/gal to $0.20-$0.25/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 8/20/2015 Baltic Futures converted to cost per gallon of LPGs, assuming 75/25 propane/butane.

LPG transportation rates from northeast fractionation to Europe and Asia expected to improve by $0.15 to $0.20 per gallon by YE 2016, driven both by pipelines replacing rail and lower shipping costs

Excess Dock Capacity

Current Fleet 168Newbuilds +85

Page 42: Am website presentation   september 2015

POSITIVE FOR LONG-TERM LPG MARKETS

41

Robust Global LPG Demand Growth Through 2020(1)

1. Source: PIRA NGL Outlook, 7/23/2015.2. Source: Poten & Partners, August 2015. MM Tons conversion to MMBbl/d conversion based on 75% propane/25% butane barrel assuming 42 gallons/Bbl.3. Source: IHS, Waterborne, SK Gas Analysis; Wood Mackenzie; Wood Mackenzie, PDH C3 capacity based on 25 MBbl/d = 650 Mt/y.

U.S. Driven Global LPG Seaborne Supply Through 2020(2)

China, India andSaudi Arabiaare main 

demand growth

Multiple Factors Driving Global LPG Demand Growth Through 2020(3)

MB

bl/d

MM

Bbl

/d

0.0

1.0

2.0

3.0

4.0

MM

Bbl

/d

0.0

0.33

0.67

Forecast global LPG demand growth of 800 MBbl/d to 1 MMBbl/d 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

U.S. exports are main supply 

growth

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

Page 43: Am website presentation   september 2015

POSITIVE FOR LONG-TERM ETHANE MARKETS

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

42

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 PADD 2 PADD 3 (East Coast)

No Northeast rejection after 2016

Page 44: Am website presentation   september 2015

Europe

Mariner East II

Shipping $0.25/Gal

NGL EXPORTS AND NETBACKS STEP-UP BY 4Q 2016

1. Source: Intercontinental exchange as of 6/30/2015.2. Source of graphic: Tudor Pickering Holt & Co. research presentation dated June 16, 20153. As an anchor shipper on Mariner East II, Antero has the right to expand its NGL commitment with

notice to operator.

4. Shipping rates based on benchmark Baltic shipping rate of $129/ton as of 6/30/15, adjusted for number of shipping days to NWE.

5. Pipeline fee equal to $0.0725/gal, per Mariner East I tariff. Terminal fee equal to $0.12/gal, per TPH report dated June 16, 2015.

Upon in-service of Mariner East II, Antero will have the ability to market its propane and n-butane to international buyers, which we expect will provide uplifts of $0.14/Gal and $0.12/Gal, respectively, to the current netbacks received from propane and n-butane volumes shipped to Mont Belvieu today− In the meantime, Antero has 23,000 Bbl/d of propane hedged at $0.63/Bbl in 2015 and 30,000 Bbl/d

hedged at $0.59/Bbl in 2016

Commitment to Mariner East II results in over $100 million in combined incremental annualized cash flow from sales of propane and n-butane (~$75 MM from propane and ~$28 MM from n-butane)

PricingPropane: $0.43/GalN-Butane: $0.60/Gal

PricingPropane: $0.69/GalN-Butane: $0.87/Gal

Mariner East II61,500 Bbl/d AR

Commitment (see table below) (3)

4Q 2016 In-Service

ShippingPropane: $0.18/GalN-Butane: $0.21/Gal

Mont Belvieu Netback ($/Gal)Propane N-Butane

August Mont Belvieu (1): $0.43 $0.60Less: Shipping Costs to Mont Belvieu (2): (0.25) (0.25)Appalachia Netback to AR: $0.18 $0.35

AR Mariner East II Commitment (Bbl/d)Product Base Option (3) TotalEthane (C2) 11,500 - 11,500 Propane (C3) 35,000 35,000 70,000 Butane (C4) 15,000 15,000 30,000

Total 61,500 50,000 111,500

NWE Netback ($/Gal)Propane N-Butane

August NWE Price (1): $0.69 $0.87Less: Spot Freight (4): (0.18) (0.21)FOB Margin at Marcus Hook: $0.51 $0.66Less: Pipeline & Terminal Fee (5): (0.19) (0.19)NWE Netback to AR: $0.32 $0.47Upside to Appalachia Netback: $0.14 $0.12

43

Page 45: Am website presentation   september 2015

WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECT

100% operatedOperating 7 drilling rigs including

2 intermediate rigs410,000 net acres in

Southwestern Core (75% includes processable rich gas assuming an 1100 Btu cutoff)– 50% HBP with additional 23%

not expiring for 5+ years413 horizontal wells completed

and online– Laterals average 7,500’– 100% drilling success rate6 plants in-service at Sherwood

Processing Complex capable of processing in excess of 1.2 Bcf/d of rich gas−Over 1 Bcf/d of Antero gas

being processed currentlyNet production of 1,240 MMcfe/d

in 2Q 2015, including 34,000 Bbl/d of liquids 3,191 future drilling locations in

the Marcellus (2,302 or 72% are processable rich gas)28.4 Tcfe of net 3P (17% liquids),

includes 11.9 Tcfe of proved reserves (assuming ethane rejection)

Highly-Rich Gas135,000 Net Acres

1,010 Gross Locations

Rich Gas92,000 Net Acres

628 Gross Locations

Dry Gas103,000 Net Acres

889 Gross Locations

Highly-Rich/Condensate80,000 Net Acres

664 Gross Locations

HEFLIN UNIT30-Day Rate

2H: 21.4 MMcfe/d (20% liquids)

CONSTABLE UNIT30-Day Rate

1H: 14.3 MMcfe/d (25% liquids)

142 Horizontals Completed30-Day Rate8.1 MMcf/d

6,915’ average lateral length

SherwoodProcessing

Complex

Source: Company presentations and press releases. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held. Note: Rates in ethane rejection.

NERO UNIT30-Day Rate

1H: 18.2 MMcfe/d(27% liquids)

BEE LEWIS PAD30-Day Rate

4-well combined 30-Day Rate of

67 MMcfe/d (26% liquids)

RJ SMITH PAD30-Day Rate

4-well combined 30-Day Rate of

56 MMcfe/d (21% liquids)

44

HENDERSHOT UNIT30-Day Rate

1H: 16.3 MMcfe/d2H: 18.1 MMcfe/d

(29% liquids)

HORNET UNIT30-Day Rate

1H: 21.5 MMcfe/d2H: 17.2 MMcfe/d

(26% liquids)CARR UNIT30-Day Rate

2H: 20.6 MMcfe/d(20% liquids)

WAGNER PAD30-Day Rate

4-well combined 30-Day Rate of

59 MMcfe/d (14% liquids)

Page 46: Am website presentation   september 2015

0.0%

20.0%

40.0%

60.0%

80.0%

100.0%

$3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00

Pre-

Tax

RO

R (%

)

Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas

MARCELLUS ROR% AND GAS PRICE SENSITIVITY

451. Assumes 12/31/2014 strip pricing, market differentials and relevant transportation cost; 9,000’ lateral.

• Large portfolio of Highly-Rich Gas/Condensate to Dry Gas locations• Focused on drilling highly economic rich gas locations – rig symbols represent current rig location by Btu regime• Assumes 12/31/2014 WTI strip pricing for 2015-2024, flat thereafter averaging $72/Bbl; NGL price 32.5% of WTI for 2015-2016

and 50% of WTI thereafter following expected in-service date of Mariner East II in late 2016NYMEX Flat Price Sensitivity(1)

ROR% at Flat 2015-2024 Strip Price

Highly-Rich Gas/Condensate: 49%

Highly-Rich Gas: 36%

Rich Gas: 18%

Dry Gas: 20%

664 Locations

1,010 Locations

628 Locations

889 Locations

Antero Rigs Employed

2015Drilling Plan

Page 47: Am website presentation   september 2015

Note: Antero acreage position reflects townships in which greater than 3,000 net acres are held. Antero 30-day rates in ethane rejection.1. 30-day rate reflects restricted choke regime.

• 100% operated• Operating 4 drilling rigs• 149,000 net acres in the core rich gas/

condensate window (71% includes processable rich gas assuming an 1100 Btu cutoff)

– 24% HBP with additional 65% not expiring for 5+ years

• 68 operated horizontal wells completed and online in Antero core areas

− 100% drilling success rate• 4 plants at Seneca Processing Complex

capable of processing 800 MMcf/d of rich gas

− Over 500 MMcf/d being processed currently, including third party production

• Net production of 244 MMcfe/d in 2Q 2015 including 11,900 Bbl/d of liquids

• Fourth third party compressor station in-service December 2014 with a capacity of 120 MMcf/d

• 1,024 future gross drilling locations (735 or 72% are processable gas)

• 7.6 Tcfe of net 3P (15% liquids), includes 758 Bcfe of proved reserves (assuming ethane rejection)

WORLD CLASS OHIO UTICA SHALEDEVELOPMENT PROJECT

46

CadizProcessing

Plant

NORMAN UNIT30-Day Rate

2 wells average16.8 MMcfe/d (15% liquids)

RUBEL UNIT30-Day Rate

3 wells average17.2 MMcfe/d(20% liquids)

Utica Core Area

GARY UNIT30-Day Rate

3 wells average24.2 MMcfe/d(21% liquids)

Highly-Rich/Cond27,000 Net Acres

139 Gross Locations

Highly-Rich Gas16,000 Net Acres

94 Gross Locations

Rich Gas33,000 Net Acres

254 Gross Locations

Dry Gas43,000 Net Acres

289 Gross Locations

NEUHART UNIT 3H30-Day Rate16.2 MMcfe/d(57% liquids)

Condensate30,000 Net Acres

248 Gross Locations

DOLLISON UNIT 1H30-Day Rate19.8 MMcfe/d(40% liquids)

MYRON UNIT 1H30-Day Rate26.8 MMcfe/d(52% liquids)

SenecaProcessingComplex

LAW UNIT30-Day Rate

2 wells average16.1 MMcfe/d(50% liquids)

SCHAFER UNIT30-Day Rate(1)

2 wells average14.2 MMcfe/d(49% liquids)

URBAN PAD30-Day Rate

4 wells average 18.8 MMcfe/d (15% liquids)

GRAVES UNIT500’ Density Pilot

30-Day Rate4 wells average15.5 MMcfe/d(24% liquids)

FRANKLIN UNIT30-Day Rate

3 wells average17.6 MMcfe/d(16% liquids)

FRAKES UNIT30-Day Rate

2 wells average18.6 MMcfe/d(42% liquids)

Page 48: Am website presentation   september 2015

0.0%

20.0%

40.0%

60.0%

80.0%

100.0%

120.0%

140.0%

160.0%

180.0%

200.0%

220.0%

$3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00

Pre-

Tax

RO

R (%

)

Condensate Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas

UTICA OHIO ROR% AND GAS PRICE SENSITIVITY

47

NYMEX Flat Price Sensitivity(1)

94 Locations

ROR% at Flat 2015-2024 Strip Price

Condensate: 16%

Highly-Rich Gas/Condensate: 49%

Highly-Rich Gas: 71%

Rich Gas: 57%

Dry Gas: 65%

• Large portfolio of Condensate to Dry Gas locations• Focused on drilling highly economic rich gas locations – rig symbols represent current rig location by Btu regime• Assumes 12/31/2014 WTI strip pricing for 2015-2024, flat thereafter averaging $72/Bbl; NGL price 32.5% of WTI for 2015-2016

and 50% of WTI thereafter following expected in-service date of Mariner East II in late 2016

1. Assumes 12/31/2014 strip pricing, market differentials and relevant transportation cost; 9,000’ lateral.

254 Locations

139 Locations

289 Locations

248 Locations

2015Drilling Plan

Antero Rigs Employed

Page 49: Am website presentation   september 2015

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

Page 50: Am website presentation   september 2015

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

49

Page 51: Am website presentation   september 2015

IMPACT OF DROP DOWN TRANSACTION ON ANTERO FINANCIAL STATEMENTS

50

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

Page 52: Am website presentation   september 2015

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

51

Page 53: Am website presentation   september 2015

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

52