Am website presentation (b) january 2016

Partnership OverviewJanuary 2016

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

$0.170 $0.180 $0.190 $0.205

0.9x

1.2x

1.3x

1.4x

0.0x

0.2x

0.4x

0.6x

0.8x

1.0x

1.2x

1.4x

1.6x

$0.000

$0.050

$0.100

$0.150

$0.200

$0.250

$0.300

$0.350

$0.400

$0.450

$0.500

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

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

$0.220

3

• Antero Midstream is targeting 28% to 30% annual distribution growth through 2017• AM has delivered on those targets to-date with DCF coverage of 1.60x in the latest quarter

Note: Future distributions subject to AM Board approval.1. Assumes midpoint of target distribution growth range.2. 4Q 2015 distribution per Partnership press release dated 1/13/2016.

(2)

GROWTH – HIGH GROWTH MIDSTREAM THROUGHPUT

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

AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5

Core Net Acres - Dry Core Net Acres - Liquids Rich

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

AR EQT RRC COG CNX SWN

0200400600800

1,0001,2001,4001,6001,800

EQT COG AR SWN RRC CNX

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

Appalachian Producers by Proved Reserves (Bcfe) – YE 2014(1)(2) Appalachian Producers by Core Net Acres (000’s) – 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 CVX, HES and XOM. 3. Based on Antero geologic interpretation supported by state well data, company presentations and public land data. Peer group includes CNX, COG, EQT, RRC, SWN.4. Southwestern leasehold and reserves include the impact from STO and WPX property acquisitions closed in January 2015. 5. Includes proved reserves categorized in “Northern Division” consisting of Utica Shale, Marcellus Shale and Powder River Basin.

(4)

5

3rd Largest Appalachian

Producer

Antero has the largest proved reserve base, the largest core liquids-rich acreage position and is one of the largest producers in the Appalachian Basin

Appalachian Peers

11th Largest U.S. Gas Producer

Largest Proved Reserve Base In

Appalachia

0

500

1,000

1,500

2,000

2,500

3,000

3,500

Largest Liquids-Rich Core Position

in Appalachia

SPONSOR STRENGTH – LEADERSHIP IN APPALACHIAN BASIN

Note: 2015 SEC prices were $2.56/MMBtu for natural gas and $50.13/Bbl for oil on a weighted average Appalachian index basis. 1. 3P reserve pre-tax PV-10 based on annual strip pricing for first 10-years and flat thereafter as of December 31, 2015. NGL pricing assumes 39%, 46% and 48% of WTI strip prices for 2016, 2017 and

2018 and thereafter, respectively. 2. All net acres allocated to the WV/PA Utica Shale Dry Gas and Upper Devonian Shale are included among the net acres allocated to the Marcellus Shale as they are stacked pay formations attributable to

the same leasehold. 3. Antero and industry rig locations as of 1/1/2016, and average rig count for 4Q 2015, per RigData.

6

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

OHIO UTICA SHALE CORE

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

MARCELLUS SHALE CORE

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

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

02468

1012

Rig

Cou

nt

Operators

4Q Average SW Marcellus & Utica(3)

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)

26 31 40 36 41 116

222

358

454 435478

0

100

200

300

400

500

600

700

800 Utica Marcellus

10 38 80 126 266

531

908

1,134 1,197 1,216 1,195

0200400600800

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

108 216 281 331 386

531 738

935 965 1,038 1,124

0200400600800

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

$1$5 $7 $8 $11

$19

$28

$36$41

$55

$0

$10

$20

$30

$40

$50

$60

Low Pressure Gathering (MMcf/d)

Compression (MMcf/d)

High Pressure Gathering (MMcf/d)

EBITDA ($MM)(1)

8

$185

Note: Y-O-Y growth based on 4Q’14 to 4Q’15. 1. 2015E EBITDA guidance updated per 10/13/2015 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.

GROWTH – HIGH GROWTH MIDSTREAM THROUGHPUT

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 1/1/2016.1. Based on company filings and presentations. Peer group includes Ascent, CHK, CNX, CVX, ECR, EQT, GPOR, NBL, RRC, STO, SWN.

• Antero controls an estimated 37% of the NGLs in the liquids-rich core of the two plays

• Antero has the largest core liquids-rich position in Appalachia with ≈371,000 net acres (> 1100 Btu)

• Represents over 21% of core liquids-rich acreage in Marcellus and Utica plays combined

Antero has over 3,000 undeveloped rich gas locations with an average lateral length of 6,800’ in its 3P reserves as of 12/31/2014

0

100

200

300

400

(000

s)

Core Liquids-Rich Net Acres(1)

626 971

553 75563% 47%

24% 28%34%22%

9% 11%

0

400

800

1,200

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

Highly-RichGas/

Condensate

Highly-Rich Gas Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

R

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

184

98 108

161263

16%

57%

83%

71% 80%

10%

27% 29% 23% 26%

0

100

200

300

0%20%40%60%80%

100%

Condensate Highly-RichGas/

Condensate

Highly-RichGas

Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

R

MARCELLUS WELL ECONOMICS(1)(2)

Marcellus Well Cost Improvement(3)

1. 12/31/2015 pre-tax well economics based on a 9,000’ lateral, 12/31/2015 natural gas and WTI strip pricing for 2016-2025, flat thereafter, NGLs at 37.5% of WTI for 2016 and 50% of WTI thereafter, and applicable firm transportation and operating costs including 50% of Antero Midstream fees. Well cost estimates, which include $1.2 million for road, pad and production facilities.

2. ROR @ 12/31/2015 Strip-With Hedges reflects 12/31/2015 well cost ROR methodology, with the 12/31/2015 hedge value allocated based on 2016-2021 projected production volumes resulting in blend of strip and hedge prices.

3. 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)(2)

74% of Marcellus locations are processable (1100-plus Btu) 68% of Utica locations are processable (1100-plus Btu)

2016Drilling

Plan

Antero has reduced average well costs for a 9,000’ lateral by 16% in the Marcellus and 18% in the Utica as compared to 2014 well costs At 12/31/2015 strip pricing, Antero has 2,227 locations that exceed 20% rate of return (excluding hedges)

– Including hedges, these locations generate rates of return of approximately 50% to 90%

Utica Well Cost Improvement(3)

$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

MITIGATED COMMODITY RISK – FIRM TRANSPORTATION & SALES PORTFOLIO

14

MMBtu/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

- 500,000

1,000,000 1,500,000 2,000,000 2,500,000 3,000,000 3,500,000 4,000,000 4,500,000 5,000,000 5,500,000

(TCO) Appalachia or Gulf Coast

(Stonewall/WB) Mid-Atlantic/NYMEX

(Stonewall/TGP) Gulf Coast

AppalachiaAppalachia

(REX/ANR/NGPL/MGT) Midwest

(ANR/Rover) Gulf Coast

AR Gross Gas Production

15

HEDGING – INTEGRAL TO BUSINESS MODEL Hedging is a key component of Antero’s business model which includes development of a large, repeatable drilling inventory

– Locks in higher returns in a low commodity price environment and reduces well payout thereby enhancing liquidity

Antero has realized $1.7 billion of gains on commodity hedges since 2009– Gains realized in 28 of last 29 quarters, or 97% of the quarters since 2009

● Based on Antero’s hedge position and strip pricing as of 12/31/2015, the unrealized commodity derivative value is $3.1 billion

● Significant additional hedge capacity remains under the credit facility hedging covenant for 2018 – 2022 period

Quarterly Realized Hedge Gains / (Losses)

Realized Hedge GainsProjected Hedge Gains

NYMEX Natural Gas Historical Spot Prices

($/Mcf)

NYMEX Natural Gas Futures Prices

3.5 Tcfe Hedged at average price of

$3.79/Mcfethrough 2022

Average Hedge Prices ($/Mcfe)

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$0

$50

$100

$150

$200

$250

$300

$MM

$3.50

$4.51

$3.94

$3.57$3.88 $3.89

$3.73$3.30

$3.1 Billion on Balance Sheet in

Hedge Gains Through 2022Realized $1.7 Billion

in Hedge Gains Since 2009

Regional Gas Pipelines

Miles Capacity In-Service

Stonewall Gathering Pipeline(2)

50 1.4 Bcf/d Yes

1. Acquired by AM from AR for a $1.05 billion upfront payment and a $125 million earn out in each of 2019 and 2020. 2. AM holds option to purchase 15% of Stonewall pipeline at cost plus cost of carry.

EndUsers

EndUsers

Gas Processing

Y-Grade Pipeline

Long-Haul Interstate

Pipeline

InterConnect

NGL Product Pipelines

Fractionation

Compression

Low Pressure Gathering

Well Pad

Terminalsand

Storage

(Miles) YE 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.)

Water Drop Down

16

VALUE CHAIN OPPORTUNITY – FULL MIDSTREAM VALUE CHAIN

Note: All balance sheet data as of 9/30/2015, inclusive of water drop down and associated financing. 1. Mark-to-market as of 12/31/2015.2. Based on AR ownership of AM units (116.9 million common and subordinated units) and AM’s closing price as of 12/31/2015.3. AR credit facility commitments of $4.0 billion, borrowing base of $4.5 billion.

Liquid “non-E&P assets” of $5.8 Bnsignificantly exceeds total debt of $3.9 Bn

Liquidity

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

9/30/2015 Debt Liquid Non-E&P Assets 9/30/2015 Debt Liquid Assets

Debt Type $MMCredit facility $500

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 $3,875

Asset Type $MMCommodity derivatives(1) $3,117

AM equity ownership(2) 2,668

Cash 10

Total $5,795

Asset Type $MMCash $10

Credit facility – commitments(3) 4,000

Credit facility – drawn (500)

Credit facility – letters of credit (535)

Total $2,975

Debt Type $MMCredit facility $525

Total $525


Total $18

Liquidity


Credit facility – capacity 1,500

Credit facility – drawn (525)

Credit facility – letters of credit -

Total $993

Approximately $3.0 billion of liquidity at AR plus an additional $2.7 billion of AM units

Approximately $1 billion of liquidityat AM

17

Only 35% of AM credit facility capacity drawn

STRONG FINANCIAL POSITION – STRONG BALANCE SHEETAND FLEXIBILITY

0.0x

1.0x

2.0x

3.0x

4.0x

5.0x

6.0x

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

Tota

l Deb

t / L

QA

EB

ITD

A

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

• Liquidity of $993 million at 9/30/2015

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

AM Liquidity (9/30/2015)

AM Peer Leverage Comparison(1)

($ in millions)

Revolver Capacity $1,500

Less: Borrowings 525

Plus: Cash 18

Liquidity $993

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

Financial Flexibility

18

(2)

STRONG FINANCIAL POSITION – SIGNIFICANT FINANCIAL FLEXIBILITY

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. Includes water drop down and $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 ~147,000 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)

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 expected in-service January 2016• 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 9/30/2015 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 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

Antero Advanced Wastewater Treatment

Freshwater delivery system

Flowback and produced

Water

Well Pad

Well Pad

CompletionOperations

Producing

Freshwater

Salt

Calcium Chloride

Marketable byproduct

Marketable byproduct used in oil and gas operations

Freshwater delivery system

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• 188,000 net acres of AR Utica dry gas acreage underlying

the Marcellus in West Virginia and Pennsylvania dedicated to AM

• AR has drilled and completed its first WV Utica well

Active AR Leasing• Future acreage acquisitions by AR are dedicated to AM• Added 92,000 net acres in 2014 and 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 completed its first dry gas Utica well – a 6,620’ lateral in Tyler County, WV

Antero has 229,000 net acres of exposure to Utica dry gas play in OH, WV and PA

Other operators have reported strong Utica Shale dry gas results including the following wells:

ChesapeakeHubbard BRK #3H

3,550’ LateralIP 11.1 MMcf/d

HessPorterfield 1H-17


GulfportIrons #1-4H5,714’ Lateral

IP 30.3 MMcf/d

EclipseTippens #6H5,858’ Lateral

IP 23.2 MMcf/d

Magnum HunterStalder #3UH5,050’ Lateral

IP 32.5 MMcf/d

Well Operator24-hr IP(MMcf/d)

LateralLength

(Ft)

24-hr IP/1,000’Lateral

(MMcf/d)

Scotts Run EQT 72.9 3,221 22.633

Gaut 4IH CNX 61.0 5,840 11.131

CSC #11H RRC 59.0 5,420 10.886

Stewart-Win 1300U MHR 46.5 5,289 8.792

Bigfoot 9H RICE 41.7 6,957 5.994

Blank U-7H GST 36.8 6,617 5.561

Stalder #3UH MHR 32.5 5,050 6.436

Irons #1-4H GPOR 30.3 5,714 5.303

Pribble 6HU SGY 30.0 3,605 8.322

Simms U-5H GST 29.4 4,447 6.611

Conner 6H CVX 25.0 6,451 3.875

Messenger 3H SWN 25.0 5,889 4.245

Tippens #6H ECR 23.2 5,858 3.960

Porterfield 1H-17 HESS 17.2 5,000 3.440

1. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held in OH, WV and PA.2. Stewart-Winland well is most proximate Utica test to Antero’s Tyler County, WV well which is currently being completed.3. The Rymer 4HD has been flowing into the sales line for 20 days with an average choke-restricted flow rate of 20 MMcf/d.

Magnum HunterStewart Winland 1300U


RangeClaysville SC #11H


ChevronConner 6H

6,451’ LateralIP 25.0 MMcf/dGastar

Simms U-5H4,447’ Lateral

IP 29.4 MMcf/d

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

RiceBigfoot 9H


AR Utica Shale Dry GasWV/PA

Net Resource12.5 to 16 Tcf

1,889 Gross Locations188,000 Net Acres

AR Utica Shale Dry GasOhio

3P Reserves2.3 Tcf

263 Gross Locations41,000 Net Acres

AR Utica Shale Dry GasTotal OH/WV/PA

Net Resource14.8 to 18.3 Tcf

2,152 Gross Locations229,000 Net Acres

Stone EnergyPribble 6HU


SouthwesternMessenger 3H5,889’ Lateral

IP 25.0 MMcf/d

RiceBlue Thunder

10H, 12H≈9,000’ Lateral

GastarBlake U-7H


EQTScotts Run


CNXGaut 4IH


(2)

AnteroRymer 4HD


(3)

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 $3.0 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

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

62 MBbl/d CommitmentMarcus Hook Export

Shell20 MBbl/d Commitment

Beaver County Cracker (2)

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

Lake Charles LNG(3)

150 MMcf/d

Freeport LNG70 MMcf/d

1. February 2016 and full year 2016 futures basis, respectively, provided by Intercontinental Exchange dated 12/31/2015. Favorable markets shaded in green.2. Subject to Shell FID expected mid-year 2016.3. Lake Charles LNG 150 MMcf/d commitment subject to BG FID expected in 2016.

Chicago(1)

$0.25 / $0.02

CGTLA(1)

$(0.07) / $(0.06)

TCO(1)

$(0.16) / $(0.18)

38

Cove Point LNG4.85 Bcf/dFirm GasTakeaway

By YE 2018

Antero’s natural gas firm transportation (FT) portfolio builds to 4.85 Bcf/d by YE 2018 with 87% serving favorable markets, with an average demand fee of $0.40/MMBtu and positive weighted average basis differential to NYMEX after assumed Btu uplift for gas

YE 2018 Gas Market MixAR 4.85 Bcf/d FT

44%Gulf Coast

17%Midwest

13%Atlantic

Seaboard

13%Dom S/TETCO

(PA)

13%TCO

Positive weighted

average basis differential

Antero Commitments

(3)

(2)

LARGEST FIRM TRANSPORTATION AND PROCESSING PORTFOLIO IN APPALACHIA

NORTHEAST NGLS ARE TRANSPORTATION CHALLENGED

1. As an anchor shipper on Mariner East 2, Antero has the right to expand its NGL commitment with notice to operator. 2. 2015 NGL production assumes ethane rejection.

Mariner East 261,500 Bbl/d AR Commitment(1)

4Q 2016 In-Service

Not so much a supply problem but more of a logistics problem for NGLs in the northeast today− The majority of northeast NGL production is being transported by expensive rail and trucking− NGLs that are transported “to the water” are also faced with high shipping rates

Export15%

Gulf Coast13%

Mid-Atlantic

6%Sarnia

3%

Northeast43%

Midwest10%

Edmonton10%

2015 NGL Marketing by Region

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 1H 2016)

Mariner East 262 MBbl/d Commitment

Marcus Hook Export

Gulf Coast Critical to

NGL Pricing

Appalachia

NGL transportation rates are expected to decline $0.12 to $0.15 per gallon by 2017 as pipeline options to domestic markets and export terminals go in-service (Mariner East 1 and 2, for example)

(MMBbl/d)

$0.00

$0.10

$0.20

$0.30

$0.40

$0.50

$/G

allo

n

Baltic Exchange LPG Freight Futures

Baltic LPG Rate ($/gal) Marcus Hook to Europe ($/gal)

Marcus Hook to Far East ($/gal)

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

0200400600800

1,0001,2001,4001,6001,800

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

MB

bl/d

Butane Exports Propane Exports Total Export Capacity

Excess LPG Export Terminal Capacity vs. Expected Export Volumes(1)

Excess dock capacity supports growing LPG export volumes

through 2025

Fleet Growth Supports U.S. LPG Export Growth(2) LPG Freight Futures Show Declining Freight Costs(3)

Baltic LPG shipping cost declines from $0.14/gal to $0.09-$0.10/gal in early 2017

on fleet supply growth numbers

Projected growth in VLGC fleet supports increasing LPG export volumes and

lower shipping costs

1. Source: Bentek.2. Source: Poten & Partners, August 2015.3. Baltic Rate based on 9/30/2015 Baltic Futures converted to cost per gallon of LPGs, assuming 75/25 propane/butane.

LPG transportation rates from northeast fractionation to Europe and Asia should improve by $0.05 to $0.15 per gallon by YE 2016,driven both by pipelines replacing rail and by lower shipping costs

Excess Dock Capacity

Current Fleet 168New builds +85

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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ANTERO RESOURCES EBITDAX RECONCILIATION

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EBITDAX Reconciliation

($ in millions) Quarter Ended LTM Ended9/30/2015 9/30/2015

EBITDAX:Net income (loss) including noncontrolling interest $544.7 $1,413.4Commodity derivative fair value (gains) (1,079.1) (2,768.3)Net cash receipts (payments) on settled derivatives instruments 205.9 665.1(Gain) loss on sale of assets - (40.0)Interest expense 60.9 222.9Loss on early extinguishment of debt - -Income tax expense (benefit) 335.5 868.5Depreciation, depletion, amortization and accretion 189.1 706.5Impairment of unproved properties 8.8 51.0Exploration expense 1.1 9.8Equity-based compensation expense 23.9 105.6State franchise taxes - 0.6Contract termination and rig stacking - 10.9Consolidated Adjusted EBITDAX $290.8 $1,245.9

EBITDAX:Net income from discontinued operations - -(Gain) on sale of assets - -Provision for income taxes - -Adjusted EBITDAX from discontinued operations - -

Total Adjusted EBITDAX $290.8 $1,245.9

ANTERO MIDSTREAM EBITDA RECONCILIATION

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EBITDA Reconciliation

Three months ended September 30,

2014 2015Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow: Net income $ 34,290 $ 42,648Add:

Interest expense 2,455 2,044Less:

Pre-water acquisition net income attributed to parent (29,211) (7,841)

Pre-water acquisition interest expense attributed to parent (522) (770)Pre-water acquisition operating income attributed to parent (29,733) (8,611)

Operating income - attributable to Partnership $ 7,012 $ 36,081Add:

Depreciation expense - attributable to Partnership 10,227 15,076

Equity-based compensation expense - attributable to Partnership 1,562 4,205 Adjusted EBITDA $ 18,801 $ 55,362

Less:Cash interest paid - attributable to Partnership (1,038)Maintenance capital expenditures attributable to Partnership (4,214)

Distributable cash flow $ 50,110

Reconciliation of Adjusted EBITDA to Net Cash Provided by Operating Activities:Adjusted EBITDA $ 18,801 $ 55,362 Add:

Pre-water acquisition net income attributed to parent 29,211 7,841

Pre-water acquisition depreciation expense attributed to parent 4,390 6,485

Pre-water acquisition equity based compensation expense attributed to parent 549 1,079Pre-water acquisition interest expense attributed to parent 522 770

Amortization of deferred financing costs attributed to parent — 285Less:

Interest expense (2,455) (2,044)Changes in operating assets and liabilities (8,258) (15,311)

Net cash provided by operating activities $ 42,760 $ 54,467

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 (b) january 2016

Business

Transcript of Am website presentation (b) january 2016