Am website presentation december 2014

Partnership OverviewDecember 2014

FORWARD-LOOKING STATEMENTS

This presentation contains forward-looking statements. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Antero Midstream Partners LP, and its subsidiaries (collectively, the “Partnership”) 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”). These statements are based on certain assumptions made by the Partnership and Antero 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.

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’s 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 ofproduction, cash flow and access to capital, the timing of development expenditures, and the other risks discussed in the registration statement on Form S-1 (No. 333-193798) filed by the Partnership under the heading “Risk Factors.”

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 – A GROWTH FOCUSED MLP

2

• AM sponsor is the most active operator in Appalachia• Highest recycle ratio and low F&D cost supports sponsor production growth expectations• Sponsor maintains strong liquidity and significant hedging position• Highly incentivized to maximize value of AM to support AR growth

• Midstream assets located in lowest cost per Mcfe rich gas plays in North America• ~80% of midstream “footprint” is associated with rich gas production• Substantial AR and third-party future infrastructure required• Gathering and compression provide core asset portfolio with additional option to

expand into freshwater distribution and regional pipelines

• Pure play, fee-based midstream MLP with top tier growth rate• Cash flows are supported by 20-year, fee-based agreements with AR• “Best in class” anchor tenant with 90% expected net production growth in 2014 and

45-50% growth in both 2015 and 2016• Growth not dependent on drop-downs, 3rd party business or acquisitions for growth

• Consolidated Marcellus and Utica rich gas acreage dedications• Multiple gathering and compression, processing, pipeline and other expansion

opportunities• Option to acquire AR Fresh Water Distribution system

• Antero Midstream MLP had no leverage at IPO closing plus $250 million cash • $1 billion of undrawn borrowing capacity commitments at IPO• Good high yield access with “Ba3/BB” rated parent (corporate ratings)• Structured to pursue organic growth opportunities

PremierE&P Sponsorship1

“Pure Play” Marcellus/UticaMidstream MLP

2

Top Tier MLP Organic Growth3

Appalachian Midstream Value Chain Opportunity

4

Stacked-Pay Basin Potential Upside5

Financial Flexibility & Strong Capital Structure

6

• Stacked-pay opportunities – Utica, Marcellus, Upper Devonian• Opportunity to develop Utica Shale dry gas pipeline and compression systems in

West Virginia• Future Upper Devonian development will require existing water resource for

completions and gathering and compression systems

AnteroMidstream Management

ANTERO MIDSTREAM OWNERSHIP STRUCTURE

3

Antero ResourcesCorporation (NYSE: AR)

$13.4 Billion Enterprise Value(1)

Ba3/BB Corporate Rating

Antero MidstreamPartners LP (NYSE: AM)

$3.9 Billion Market Cap.(1)

Public

$1 BillionCredit Facility

Midstream Entity

PartnershipCorporation

MarcellusGathering

& Compression

UticaGathering &

Compression

Option(3)

Antero Fresh WaterDistribution System

Option

69.7% Limited Partner Interest

1. As of 12/8/2014. AR enterprise value excludes AM minority interest and cash. 2. Option to acquire up to a 15% non-operating equity interest in a new build Regional Gathering Pipeline.3. Option to acquire 100% interest at fair market value.

100% 100% 100%

Option(2)

Regional GatheringPipeline

15%

Midstream Option

1. Represents inception to date actuals as of 9/30/2014 and 4Q 2014 and next twelve months (NTM) guidance.2. Includes $14.7 million of maintenance capex.

4

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

– Acreage dedication of ~390,000 net leasehold acres for gathering and compression services

– 100% fixed fee long term contracts

UticaShale

MarcellusShale

Projected Midstream Infrastructure(1)

Marcellus Shale

Utica Shale Total

YE 2014E Cumulative Gathering/ Compression Capex ($MM) $850 $350 $1,200

Gathering Pipelines(Miles) 180 85 265

Compression Capacity(MMcf/d) 370 - 370

Condensate Gathering Pipelines (Miles) - 20 20

NTM (9/30/2015) Gathering/ Compression Capex ($MM)(2) $473 $129 $602

Gathering Pipelines (Miles) 219 108 327

Compression Capacity(MMcf/d) 835 - 835

Condensate Gathering Pipelines (Miles) - 27 27

Midstream Assets

ANTERO MIDSTREAM PARTNERS OVERVIEW

ANTERO MIDSTREAM ASSETS – RICH GAS MARCELLUS

5

• Provides Marcellus gathering and compression services − Liquids-rich gas is delivered to MWE’s Sherwood

Complex for processing• Significant growth projected over the next twelve

months as set out below:

• Antero sold the Harrison County portion of its gathering system to a 3rd party midstream company in 2012, which is now recognized as the 3rd Party Gathering and Compression Dedication area

• Development upside as AR continues to drill, step-out and add acreage

Marcellus Gathering & Compression

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

YE 2014 9/30/2015

Gathering Pipelines (Miles) 180 219

Compression Capacity (MMcf/d) 370 835

WV/PA Utica Dry Gas Gathering & Compression

• Further development upside in 167,000 net acres of Utica deep rights beneath the Marcellus Shale− Will require a separate dry gas gathering system

6

• Provides Utica natural gas and condensate gathering services− Liquids-rich gas delivered into MWE’s Seneca

Complex for processing− Condensate delivered to centralized stabilization

and truck loading facilities• Significant growth projected over the next twelve

months as set out below:

• Development upside as AR continues to drill, step-out and add acreage

Utica Gathering

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 9/30/2015

Gathering Pipelines (Miles) 85 108

Condensate Pipelines (Miles) 20 27

Utica Compression• Opportunity to build up to ten new compressor stations

that are planned to support AR development over the next several years− Compressor stations are not included in AM NTM

forecast

108

216 281 331

386

531

964

0

200

400

600

800

1,000

2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q'14 NTM9/30/15

Utica Marcellus

$1.4 $5.0 $6.8 $8.4 $11.4 $18.8

$136.2

0

20

40

60

80

100

120

140

160

2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 NTM9/30/15

EBITDA

HIGH GROWTH THROUGHPUT

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

High Pressure Gathering (MMcf/d) Antero Midstream Partners EBITDA ($MM)

1. Midstream EBITDA does not include EBITDA contribution from fresh water distribution

(1)

7

26 31 40 36 41

116

249

0

50

100

150

200

250

2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 NTM9/30/15

Marcellus

10 38 80

126

266

531

773

0

200

400

600

800

2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 NTM9/30/15

Utica Marcellus

ORGANIC GROWTH STRATEGY: “BUILD VS. BUY”

8

• Organic growth strategy provides attractive returns and project economics, while avoiding the competitive acquisition market

• Industry leading organic growth story

– ~$875 million in estimated capital spent through 6/30/2014

– $587 million in additional growth capital forecast for the twelve-month period ending 9/30/15 (excludes $15 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 Q2 2014 divided by NTM 9/30/15 projected gathering and compression EBITDA.2. Selected gathering and compression drop down acquisitions since 1/1/2011. Drop down multiples are based on NTM EBITDA. Source: Barclays.

6.4x

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 4-6x EBITDA

vs.Drop-Down / Buy at 8-12x EBITDA

Fresh Water

Distribution(1)

Regional Gas Pipelines

Miles Capacity In-Service

Unnamed Regional Pipeline

50 1.4 Bcf/d 4Q 2015

91. Currently owned by AR; AM holds option to purchase 100% of assets at fair market value.

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 9/30/2015

Marcellus 110 130

Utica 51 72

Total 161 202

AM has option to participate in processing, fractionation,

terminaling and storage projects offered to AR

FULL MIDSTREAM VALUE CHAIN POTENTIAL

(Miles) YE 2014 9/30/2015

Marcellus 70 89

Utica 34 36

Total 104 125

(MMcf/d) YE 2014 9/30/2015

Marcellus 370 835

Utica 0 0

Total 370 835

AM Owned Assets

Condensate GatheringStabilization

(Miles) YE 2014 9/30/2015

Utica 20 27

EndUsers

AM Option Assets

(Ethane, Propane, Butane, etc.)

(De-ethanization)

AM OPTION – FRESH WATER DISTRIBUTION SYSTEMS

10

Marcellus Fresh Water Distribution System• Provides fresh water to support ongoing Marcellus completion

activity • Year-round water supply sources: Ohio River and local rivers• Significant growth projected over the next twelve months as

summarized below:

Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.1. Estimated fee of $3.50 per barrel at an average of 200,000 Bbls of water per well.

Utica Fresh Water Distribution System• Provides fresh water to support ongoing Utica completion activity • Year-round water supply sources: local reservoirs and rivers• Significant growth projected over the next twelve months as

summarized below:

• Currently owned by AR – AM holds option to purchase 100% of assets at fair market value

Marcellus Water System YE 2014 9/30/2015

Buried Water Pipeline (Miles) 107 127

Fresh Water Storage Impoundments 26 32

NTM 9/30/2015 Projected Wells 162

Water Fees per Well ($)(1) $600K -$800K

Utica Water System YE 2014 9/30/2015

Buried Water Pipeline (Miles) 48 63

Fresh Water Storage Impoundments

8 13

NTM 9/30/2015 Projected Wells 56

Water Fees per Well ($)(1) $600K -$800K

OHIO

25%

15%

10%

25%

30%

10% 15%

35%

25%

20%

35%

25%

20%

40%

0%

10%

20%

30%

40%

Inte

rnal

Rat

e of

Ret

urn

11

DRY GAS LOCATIONS RICH GAS LOCATIONS

HIGHLY RICH GAS

LOCATIONS

Project Economics by Segment(1)

ESTIMATED PROJECT ECONOMICS BY SEGMENT

LPGathering

HPGathering Compression

CondensateGathering

Water Distribution

RegionalPipeline

Processing/Fractionation

Unlevered IRR Range: 25% - 35% 15% - 25% 10% - 20% 25% - 35% 30% - 40% 10% - 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 N/A 100% 60%

9/30/15 NTM Capex(2) TotalMarcellus $473.3 $155.9 $131.8 $185.6 -Utica 114.0 89.8 15.9 - 8.3

Expansion Capex $587.3 $245.7 $147.7 $185.6 $8.3 % of Capex 100% 42% 25% 32% 1%

Included in NTM Period: Marcellus & Utica

Marcellus & Utica

Marcellus Utica Not Included Not Included Not Included

Additional Opportunities: Dry Utica Dry Utica Rich & Dry Utica

Utica Stabilization

Drop-Downof Water

Distribution System

Regional Gathering

Pipeline

Marcellus Processing/

Fractionation

1. Based on management capex, operating cost and throughput assumptions by project.2. Excludes $14.7 million of maintenance capex.

Wtd. Avg. 23% IRR

AM Option Opportunities

SIGNIFICANT FINANCIAL FLEXIBILITY

12

• Unfunded $1 billion revolver in place at time of IPO to fund future growth capital (5x Debt/EBITDA Cap)

• No leverage and $250 million of cash “post-IPO” provides significant financial flexibility

• Sponsor (NYSE: AR) has Ba3/BB corporate ratings

AM Liquidity

AM Peer Leverage Comparison(2)

($ in millions) At IPO(1)

Revolver Capacity $1,000

Less: Borrowings -

Plus: Cash 250

Liquidity $1,250

0.0x 0.0x 0.1x

1.1x 1.3x 1.5x2.2x 2.4x

3.1x 3.1x 3.3x 3.3x4.0x 4.1x

0.0x

2.0x

4.0x

6.0x

Deb

t / L

TM E

BIT

DA

1. IPO completed on 11/10/2014. 2. Peers include ACMP, EQM, MPLX, MWE, OILT, PSXP, QEPM, RRMS, SXL, TEP, TLLP, VLP and WES.

Sources ($ in millions)

Primary IPO Proceeds $1,150

Total Sources $1,150

Uses

Proceeds to AR $843

Proceeds retained by AM 250

Fees & Expenses 57

Total Uses $1,150

Sources & Uses

Financial Flexibility

13

ANTERO MIDSTREAM MLP INVESTMENT HIGHLIGHTS

Premier E&P Sponsorship

“Pure Play” Marcellus/UticaMidstream MLP

Top Tier MLP Organic Growth

Full Midstream Value Chain Potential

Financial Flexibility & Strong Capital Structure “Best in Class”

Distribution Growth Expected

14

Antero Resources (NYSE: AR)Overview

15

Most Active Operatorin Appalachia

Most ActiveLand Organization

in Appalachia

Largest Firm Transport and Processing

Portfolio in Appalachia

Largest Gas Hedge Position in U.S. E&P +

Strong Financial Liquidity

Highest Growth Large Cap E&P

Largest Liquids-Rich Core Position in

Appalachia

Highest Realizations and Margins Among

Large Cap Appalachian Peers

Growth Land

Liquidity

Midstream

Drilling

LEADING UNCONVENTIONAL BUSINESS MODEL

MLP (NYSE: AM)Highlights

Substantial Value in Midstream Business

Realizations

Takeaway

Liquids-Rich1

2 3

4

5

67

8

Premier AppalachianE&P Company

Run by Co-Founders

DRILLING – MOST ACTIVE OPERATOR IN APPALACHIA

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. Locations as of 9/30/2014 adjusted for additional 130 locations acquired through 11/3/2014.3. Antero and industry rig locations and rig count as of 11/28/2014 per RigData.

16

COMBINED TOTAL – 6/30/14 RESERVESAssumes Ethane RejectionNet Proved Reserves 9.1 TcfeNet 3P Reserves 37.5 TcfePre-Tax 3P PV-10 $25.9 BnNet 3P Reserves & Resource 47.0 TcfeNet 3P Liquids 966 MMBbls% Liquids – Net 3P 15%3Q 2014 Net Production 1,080 MMcfe/d- 3Q 2014 Net Liquids 25,000 Bbl/dNet Acres(1) 524,000Undrilled 3P Locations(2) 5,244

UTICA SHALE CORE

Net Proved Reserves 537 BcfeNet 3P Reserves 6.4 TcfePre-Tax 3P PV-10 $6.5 BnNet Acres 135,000Undrilled 3P Locations(2) 997

MARCELLUS SHALE CORE

Net Proved Reserves 8.5 TcfeNet 3P Reserves 26.4 TcfePre-Tax 3P PV-10 $19.4 BnNet Acres 389,000Undrilled 3P Locations 3,131

UPPER DEVONIAN SHALE

Net Proved Reserves 40 BcfeNet 3P Reserves 4.6 TcfePre-Tax 3P PV-10 NMUndrilled 3P Locations 1,116

WV/PA UTICA SHALE DRY GASNet Resource 9.5 TcfNet Acres 167,000Undrilled Locations 1,390

0

5

10

15

20

25

Rig

Cou

nt

Operators

SW Marcellus + Utica Rigs(3)

1. 2012, 2013 and 6/30/2014 proved reserves assuming ethane rejection.2. Midpoint of production guidance of 990-1,010 MMcfe/d for 2014.3. Based on 45-50% production growth targets for 2015 and 2016. 4. Per current First Call median estimate from Bloomberg.

0

600

1,200

1,800

2,400

2010 2011 2012 2013 1H 2014 3Q2014

4Q 2014

2015E 2016E

Marcellus Utica Guidance

30 124 239522

(2)

1,237

838

1,500

2,200

(3) (3)

1,080

0

2,000

4,000

6,000

8,000

10,000

2010 2011 2012 2013 6/30/2014

Marcellus Utica

677

2,844

4,283

7,632

(1) (1) (1)

9,107

17

AVERAGE NET DAILY PRODUCTION (MMcfe/d)NET PROVED SEC RESERVES (Bcfe)

0255075

100125150175200225

2010 2011 2012 2013 2014E

Marcellus Utica

29 36

86

162

215

GROWTH – STRONG TRACK RECORD

OPERATED GROSS WELLS SPUD EBITDAX ($MM)

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

2010 2011 2012 2013 2014E

$28$160

$285

$649

$1,145

(4)

45-50% Annual Growth Target

92% Growth –Guidance of

1,000 MMcfe/dfor 2014E

Assembled a 524,000 net acre position in the core of the Marcellus and Utica shale plays over the past 6 years

December 2008

Net Acreage 118,000

Net Production (MMcfe/d) NM

3P Reserves (Bcfe) NM

3P PV-10 ($MM) NM

Rigs Running NM

Dec 2008 Dec 2011 Dec 2014

December 2011(1)

Net Acreage 214,000

Net Production (MMcfe/d) 167

3P Reserves (Bcfe) 18,400

3P PV-10 ($MM) $9,000

Rigs Running 5

December 2014(1)

Net Acreage 524,000

Net Production (MMcfe/d) 1,080

6/30/14 3P Reserves (Bcfe) 37,500

6/30/14 3P PV-10 ($MM) $25,900

Rigs Running 21

1. Reserves and PV-10 data for December 2014 reflect data as of 6/30/2014 and for December 2011 reflects data as of 12/31/2011. Daily net production for December 2011 and December 2014 is for third quarter respectively.

LAND – MOST ACTIVE LAND ORGANIZATIONIN APPALACHIA

18

118,000 118,000 118,000 162,000 189,000 213,000

285,000 371,000

420,000 450,000 486,000

524,000

0

100,000

200,000

300,000

400,000

500,000

600,000

12/2008 12/2009 6/2010 12/2010 6/2011 12/2011 6/2012 12/2012 6/2013 12/2013 6/2014 12/2014

Antero Net Acreage

Utica Marcellus

19

LIQUIDS-RICH – LARGEST CORE POSITION

Source: Core outlines and peer net acreage positions based on peer presentations, news releases and 10-K/10-Qs.1. Pending Southwestern Energy acquisition of Chesapeake southern Marcellus acreage position.

(1)

Antero has the largest liquids-rich core position in Appalachia ≈366,000 net acres

TAKEAWAY – LARGEST FIRM TRANSPORTATION AND PROCESSING PORTFOLIO IN APPALACHIA

Odebrecht / Braskem30 MBbl/d Commitment

Ascent Cracker(Pending Final

Investment Decision)

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

Mariner East II62 MBbl/d Commitment(2)

Marcus Hook Export

Shell25 MBbl/d CommitmentBeaver County Cracker

(Pending FinalInvestment Decision)

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

1. 2015 and 2016 futures basis, respectively, provided by Wells Fargo dated 11/28/2014. Favorable gas markets shaded in green.2. As an anchor shipper on Mariner East II, Antero has the right to expand its NGL commitment with notice to operator.

Chicago(1)

+$0.18 / $(0.04)

CGTLA(1)

$(0.10) / $(0.09)

Dom South(1)

$(1.32) / $(1.16)

TCO(1)

$(0.29) / $(0.47)

20

4 Bcf/dFirm Gas TakeawayBy 2018

Cove Point

788 1,168 943 780 1,073 818

$4.97$4.38 $4.46 $4.34 $4.50 $4.41

$4.07 $3.82 $3.83 $3.96 $4.09 $4.21

$0.00$1.00$2.00$3.00$4.00$5.00$6.00$7.00

0

200

400

600

800

1,000

1,200

4Q 2014 2015 2016 2017 2018 2019

BBtu/d $/MMBtu

21

Average Index Hedge Price(1)Hedged Volume Current NYMEX Strip(2)

COMMODITY HEDGE POSITION

1. Reflects weighted average index price per annum based on volumes hedged and 6:1 gas to oil ratio. Antero has hedged 3,000 Bbl/d of oil for 2014 and 2,000 Bbl/d of propane for 2015. 2. As of 11/28/2014.3. Percentage of net gas equivalent production target hedged for respective years.

~$1,109 million mark-to-market unrealized gain based on current prices 1.8 Tcfe hedged from October 1, 2014 through year-end 2019 and 256 Bcf of TCO basis hedges from 2015 to 2017

$72 MM $345 MM $349 MM $123 MM $160 MM $60 MM

Mark-to-Market Value(2)

LIQUIDITY – LARGEST GAS HEDGE POSITION IN U.S. E&P + STRONG FINANCIAL LIQUIDITY

$3,000

$2,012

($1,505)

($332) $6 $843

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

Credit Facility9/30/2014

Bank Debt9/30/2014

L/Cs Outstanding9/30/2014

Cash9/30/2014

AM IPOProceeds

to AR

Pro FormaLiquidity

9/30/2014

AR LIQUIDITY POSITION ($MM) AM LIQUIDITY POSITION ($MM)

$1,000$1,250

$0 $0 $0

$250

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

Credit Facility9/30/2014

Bank Debt9/30/2014

L/Cs Outstanding9/30/2014

Cash9/30/2014

AM IPO Proceeds

to AM

Pro FormaLiquidity

9/30/2014

≈ 78% of 2015ETarget

Production(3)

≈ 43% of 2015ETarget

Production(3)

Over $3 billion of combined AR and AM financial liquidity as of 9/30/2014, pro forma for AM IPO closed on 11/10/2014

1. Gulf Coast differential represents contractual deduct to NYMEX-based sales.2. Includes firm sales. 3. Includes natural gas hedges.4. Source: Public data from 3Q 2014 10-Qs. Peers include Cabot Oil & Gas, CONSOL Energy, EQT Corp. and Range Resources. 5. Includes realized hedge gains and losses. Operating costs include lease operating expenses, production taxes, gathering, processing and firm transport costs and general and administrative costs. 4-year

proved reserve average all-in F&D from 2010-2013. Calculation = (Development costs + exploration costs + leasehold costs) / Total reserves added (2013 ending reserves – 2010 beginning reserves + 4-year reserve sales – 4-year reserve purchases + 4-year accumulated production). AR price realization includes $0.04 of midstream revenues.

$4.16 $3.97

$0.58 $0.95 $0.74 $0.77 $0.81

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

Antero Peer 1 Peer 2 Peer 3 Peer 4

$/M

cfe

LOE Production Taxes GPT G&A EBITDAX 4-year Avg. All-in F&D ($/Mcfe)

$4.96

$3.25

$4.48

$2.93

$2.40$2.64

$2.11 $2.09

22

Region3Q 2014 % Sales

Average NYMEX Price

AverageDifferential(2)

AverageBTU Upgrade

Hedge Effect

Average 3Q 2014Realized Gas Price(3)

Average Premium/Discount

TCO 39% $4.06 $(0.12) $0.48 $0.58 $5.00 $0.94Dom South/TETCO 41% $4.06 $(1.83) $0.32 $1.10 $3.65 $(0.41)Gulf Coast(1) 10% $4.06 $(0.25) $0.39 $0.01 $4.21 $0.15Chicago 10% $4.06 $(0.07) $0.52 - $4.51 $0.45Total Wtd. Avg. 100% $4.06 $(0.84) $0.41 $0.68 $4.31 $0.25

REALIZATIONS – HIGHEST REALIZATIONS & MARGINSAMONG LARGE-CAP APPALACHIAN PEERS

3Q 2014 Natural Gas Realizations ($/Mcf)

3Q 2014 Natural Gas Realizations(3) 3Q 2014 Price Realization & EBITDAX Margin vs F&D(4)

$4.31

$4.12$3.66 $3.62 $3.60

$2.98 $2.87 $2.75

$0.00

$2.00

$4.00

$6.00

AR EQT GPOR RRC CNX RICE ECR COG

$/M

cf

3Q 2014 NYMEX = $4.06/Mcf

AR Peer 1 Peer 2 Peer 3 Peer 4

DOM S28% DOM S

22% DOM S8%

TETCO M24% TETCO M2

8%

TETCO M210%

TCO43%

TCO23%

TCO15%

NYMEX9%

NYMEX7%

NYMEX10%

Gulf Coast18% Gulf Coast

47%

Chicago16% Chicago

22%

Chicago10%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

($/Mcf) 4Q 2014E 2015E 2016ENYMEX Strip Price(1) $4.00 $3.82 $3.83Basis Differential to NYMEX(1) $(0.52) $(0.45) $(0.35)BTU Upgrade(5) $0.35 $0.34 $0.35 Estimated Realized Hedge Gains $0.67 $0.63 $0.45Realized Gas Price with Hedges $4.50 $4.34 $4.28 Premium to NYMEX +$0.50 +$0.52 +$0.45Liquids Impact(6) +$0.54 +$0.50 +$0.58Premium to NYMEX w/ Liquids +$1.04 +$1.02 +$1.03Realized Gas-Equivalent Price $5.04 $4.84 $4.86

4. Represents 60,000 MMBtu/d of TCO index hedges and 205,000 MMBtu/d of TCO basis hedges that are matched with NYMEX hedges for presentation purposes.

5. Assumes ethane rejection resulting in 1100 BTU residue sales gas.6. Represents equivalent price upgrade associated with NGL (C3+) and oil production.

REALIZATIONS – REALIZED PRICE “ROAD MAP”

1. Based on 11/28/2014 strip pricing.2. Differential represents contractual deduct to NYMEX-based firm sales contract.3. Represents 120,000 MMBtu/d of TCO index hedges and 390,000 MMBtu/d of TCO basis hedges that are

matched with NYMEX hedges for presentation purposes.

4Q 2014Basis(1)

2015 Basis(1)

2016 Basis(1)

4Q 2014Hedges

2015Hedges

2016Hedges

Mar

kete

d %

of T

arge

t Re

sidu

e G

as P

rodu

ctio

n

+$0.33/MMBtu

$(0.25)/MMBtu(2)

$(1.63)/MMBtu

$(0.07)/MMBtu

+$0.18/MMBtu

$(0.25)/MMBtu(2)

$(1.32)/MMBtu

$(0.29)/MMBtu

$(0.04)/MMBtu

$(0.25)/MMBtu(2)

$(1.16)/MMBtu

$(0.46)/MMBtu

$(0.10)/MMBtu

$(0.09)/MMBtu

340,000 MMBtu/d

@ $4.18/MMBtu

160,000 MMBtu/d

@ $5.27/MMBtu

210,000 MMBtu/d

@ $5.24/MMBtu

40,000 MMBtu/d

@ $4.00/MMBtu

230,000 MMBtu/d

@ $5.60/MMBtu

510,000 MMBtu/d

@ $3.87/MMBtu(3)

170,000 MMBtu/d

@ $4.09/MMBtu

272,500 MMBtu/d

@ $5.35/MMBtu

265,000 MMBtu/d

@ $3.89/MMBtu(4)

$0.56/Mcfe in estimated hedge gains(1)

70% exposure to favorable price indices





Antero is forecasting realized gas prices including hedges at a premium to NYMEX strip prices for Q4 2014 through 2016, assuming current strip prices and basis, existing firm transportation and hedges, and targeted 2015 and 2016 production figures

$(1.57)/MMBtu

$(1.18)/MMBtu

$(1.05)/MMBtu

Wtd. Avg.Basis ($0.52)

770,000 MMBtu/d@ $4.97/MMBtu

Wtd. Avg.Basis $(0.45)

1,160,000 MMBtu/d@ $4.34/MMBtu

Wtd. Avg.Basis $(0.35)

942,500 MMBtu/d@ $4.46/MMBtu

10,000 MMBtu/d

@ $3.98/MMBtu

4Q 2014E 2015E 2016E

23

380,000 MMBtu/d

@ $3.88/MMBtu

235,000 MMBtu/d

@ $4.00/MMBtu

50,000 MMBtu/d

@ $4.72/MMBtu

0%

20%

40%

60%

80%

248

143 87

265 254

14%

57%76%

50% 45%

050100150200250300

0%

25%

50%

75%

100%

Condensate Highly-RichGas/

Condensate

Highly-RichGas

Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

R

Locations ROR

MARCELLUS SSL WELL ECONOMICS(1)

727896

633

875

55%37%

17% 16%

0

200

400

600

800

1000

0%

25%

50%

75%

100%

Highly-RichGas/

Condensate

Highly-RichGas

Rich Gas Dry Gas

Tota

l 3PL

loca

tions

RO

R

Locations ROR

MULTI-YEAR DRILLING INVENTORY SUPPORTS LOW RISK, HIGH RETURN GROWTH PROFILE

Large 3P Drilling Inventory of High Return Projects(3)

1. Pre-tax well economics based on 11/28/2014 natural gas and WTI strip pricing for 2014-2019, flat thereafter, NGLs at 55% of oil price and applicable firm transportation costs. 2. Adjusted for additional 130 gross locations acquired as of 11/3/2014.3. Source: Credit Suisse report dated October 2014 – After-tax internal rate of return based on 10/27/2014 strip pricing.

59%57%

71%

21%

Inte

rnal

Rat

e of

Ret

urn

(%)

37%

24

UTICA WELL ECONOMICS(1)(2)

1,000

72% of Marcellus locations are processable (1100-plus Btu) 75% of Utica locations are processable (1100-plus Btu)

3,000 Antero Liquids-Rich Locations

37%

2H 2014 / 2015Drilling Plan

1,129 Antero Dry Gas Locations

WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECT

100% operatedOperating 14 drilling rigs

including 5 intermediate rigs389,000 net acres in

Southwestern Core (73% includes processable rich gas assuming an 1100 Btu cutoff)– 50% HBP with additional 27%

not expiring for 5+ years339 horizontal wells completed

and online– Laterals average 7,400’– 100% drilling success rate5 plants in-service at Sherwood

Processing Complex capable of processing 1 Bcf/d of rich gas−Over 800 MMcf/d being

processed currentlyNet production of 937 MMcfe/d in

3Q 2014, including 17,300 Bbl/d of liquids 3,131 future drilling locations in

the Marcellus (2,256 or 72% are processable rich gas)26.4 Tcfe of net 3P (18% liquids),

includes 8.5 Tcfe of proved reserves (assuming ethane rejection) Highly-Rich Gas

119,000 Net Acres896 Gross Locations

Rich Gas91,000 Net Acres

633 Gross Locations

Dry Gas104,000 Net Acres

875 Gross Locations

Highly-Rich/Condensate75,000 Net Acres

727 Gross Locations

HEFLIN UNIT30-Day Rate

2H: 21.4 MMcfe/d (21% liquids)

CONSTABLE UNIT30-Day Rate


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)

25

MHR COLLINS UNIT30-Day Rate

4-well average9.3 MMcfe/d (26% liquids)

HENDERSHOT UNIT30-Day Rate

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

(29% liquids)

HORNET UNIT30-Day Rate


HINTERER UNIT30-Day Rate

1H: 12.9 MMcfe/d(20% liquids)

Source: Company presentations and press releases. Note: Antero acreage position reflects townships in which greater than 3,000 net acres are held. Note: Third party peak rates assume ethane recovery; Antero 30-day rates in ethane rejection.1. For non-Antero wells, Antero has converted rich gas rates where BTU has been disclosed to NGLs, assuming ethane recovery. Where BTU has not been disclosed, Antero has estimated BTU and gas

composition.2. 30-day rate reflects restricted choke regime.

• 100% operated• Operating 7 rigs including 2 intermediate rigs• 135,000 net acres in the core rich gas/

condensate window (76% includes processable rich gas assuming an 1100 Btu cutoff)

– 20% HBP with additional 79% not expiring for 5+ years

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

− 100% drilling success rate• 3 plants at Seneca Processing Complex capable

of processing 600 MMcf/d of rich gas

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

• Net production of 143 MMcfe/d in 3Q 2014 including 7,700 Bbl/d of liquids− Seneca 3 processing plant online in July

2014− Fourth third party compressor station

expected in-service December 2014 with a capacity of 120 MMcf/d

• 997 future gross drilling locations (743 or 75% are processable gas)

• 6.4 Tcfe of net 3P (13% liquids), includes 537 Bcfe of proved reserves (assuming ethane rejection)

LEADING UTICA SHALE CORE POSITION DELIVERS CONDENSATE AND NGLS

26

Utica Shale Industry Activity(1)

CadizProcessing

Plant

NORMAN UNIT30-Day Rate

2 wells average17.2 MMcfe/d (17% liquids)

RUBEL UNIT30-Day Rate

3 wells average17.3 MMcfe/d(22% liquids)

GULFPORT24-Hour IP

McCort1-28H, 2-28H, Stutzman 1-14H

Average 13.1 MMcf/d + 922 Bbl/d NGL

+ 21 Bbl/d Oil

GULFPORT24-Hour IP

Wagner 1-28H, Shugert 1-1H, 1-12H

Average 21.0 MMcf/d + 2,270 Bbl/d NGL

+ 292 Bbl/d Oil

Utica Core Area

GARY UNIT30-Day Rate


Highly-Rich/Cond19,000 Net Acres

143 Gross Locations

Highly-Rich Gas20,000 Net Acres

87 Gross Locations

Rich Gas31,000 Net Acres

265 Gross Locations

Dry Gas32,000 Net Acres

254 Gross Locations

NEUHART UNIT 3H30-Day Rate16.4 MMcfe/d(56% liquids)

Condensate33,000 Net Acres

248 Gross Locations

DOLLISON UNIT 1H30-Day Rate19.0 MMcfe/d(36% liquids)

MYRON UNIT 1H30-Day Rate26.0 MMcfe/d(50% liquids)

SenecaProcessingComplex

LAW UNIT30-Day Rate


SCHAFER UNIT30-Day Rate(2)


McDOUGAL UNIT30-Day Rate


APPENDIX

27

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 gathering capital expenditures as maintenance capital expenditures

28Source: Antero Midstream S-1; maintenance capital calculation per management estimates.

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

• NTM Maintenance Capital ($ in millions)

NTM Wells to be placed online 183Wells required to maintain LTM throughput 10.3

% of total wells to be placed online 5.6%

NTM Low-Pressure Gathering Capital $260.4

Forecasted NTM Maintenance Capital $14.7

LTM ProductionNTM Production ForecastAverage LTM Production

CONTRACTUAL ARRANGEMENTS WITH ANTERO PROVIDE SIGNIFICANT GROWTH OPPORTUNITIES

29

• Gathering and Compression – 20-year agreement

– Dedication of all current and future AR acreage in West Virginia, Ohio, and Pennsylvania, outside of current

third-party commitments

– Option to gather and compress natural gas produced by Antero on any future acquired acreage outside of the

aforementioned areas

– Low-pressure gathering fee of $0.30/Mcf(1)

– High-pressure gathering fee of $0.18/Mcf(1)

– Compression fee of $0.18/Mcf(1)

– Minimum volume commitments on newly constructed high-pressure lines and compressor stations, respectively

– Compression minimum volume commitments of 70% of design capacity

– High-pressure gathering minimum volume commitments of 75% of design capacity

• Processing (“ROFO”)– Right of first offer on future processing services

– Agreement stipulates that AR has agreed not to procure any gas processing or NGLs fractionation,

transportation or marketing services (other than production subject to a pre-existing dedication) without first

offering AM the right to provide such services

1. All subject to CPI-based adjustments.

FORECASTED CASH FLOW AVAILABLEFOR DISTRIBUTIONS

30

Next 12 Months Ending($ in millions) September 30, 2015

Antero Midstream Adjusted EBITDA(1) $136.2

Less:

Cash interest, net ($2.7)

Expansion capital expenditures ($587.3)

Ongoing maintenance capital expenditures ($14.7)

Add:

Borrowings and cash to fund expansion capital expenditures $587.3

Minimum estimated cash available for distribution $118.8

Assumed Coverage 1.15x

Distributed Cash Flow $103.3

Distribution per Unit(2) $0.68

1. Includes incremental public company expenses.2. Based on 151.9 million units outstanding.

AM OPPORTUNITY SET

31

ACTIVITY CURRENTLY DEDICATED TO AM

Gas Gathering and Compression (High-Pressure and Low-Pressure)

Condensate and Liquids Gathering

Fresh Water Distribution System

Processing, Fractionation, Transportation, Marketing

and Other Services

• Existing dedication of ≈390,000 acres• Option to expand outside dedicated area, including ROFR• Minimum Volume Commitments on newly constructed

compression (70%) and high pressure gathering (75%)

Regional Pipeline Projects • Option to participate up to 15% in another regional pipeline project

• Relevant liquids production can be added to the existing dedication; AR must request AM to provide a fee proposal

• Option to acquire at fair market value 100% of AR’s fresh water distribution assets covering 524,000 net acres, including ROFO on future services

• 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.

0.0%

25.0%

50.0%

75.0%

100.0%

125.0%

150.0%

$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

321. Assumes 11/28/2014 strip pricing, market differentials and relevant transportation cost.

• 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 11/28/2014 WTI strip pricing for 2014-2019, flat thereafter; NGL price of 55% of WTI

NYMEX Price Sensitivity(1)

ROR% at 5-Year Strip

Highly-Rich Gas/Condensate: 55%

Highly-Rich Gas: 37%

Rich Gas: 17%

Dry Gas: 16%727 Locations

896 Locations

633 Locations

875 Locations

Antero Rigs Employed


0.0%

50.0%

100.0%

150.0%

200.0%

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

Condensate Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas Antero Rigs Employed

UTICA ROR% AND GAS PRICE SENSITIVITY

33

NYMEX Price Sensitivity(1)

87 LocationsROR% at 5-Year Strip

Condensate: 14%

Highly-Rich Gas/Condensate: 57%

Highly-Rich Gas: 76%

Rich Gas: 50%

Dry Gas: 45%

• 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 11/28/2014 WTI strip pricing for 2014-2019, flat thereafter; NGL price of 55% of WTI

1. Assumes 11/28/2014 strip pricing, market differentials and relevant transportation cost.

265 Locations

143 Locations

254 Locations

248 Locations


LARGE UTICA SHALE DRY GAS POSITION

34

Antero has ≈200,000 net acres of exposure to Utica dry gas play− 32,000 net acres in Ohio with net 3P reserves of 1.9 Tcf as of

6/30/2014− 167,000 net acres in West Virginia and Pennsylvania with net

resource of 9.5 Tcf as of 6/30/2014 (not included in 37.5 Tcfe of net 3P reserves)

− 1,390 locations underlying current Marcellus Shale leasehold in West Virginia and Pennsylvania as of 9/30/2014

Expect to drill and complete a Utica Shale dry gas well in West Virginia in 2015

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 #1-4H


EclipseTippens #6H5,858’ Lateral

IP 23.2 MMcf/d

Magnum HunterStalder #3UH5,050’ Lateral

IP 32.5 MMcf/d

AnteroPlanned

Utica Well2015Well Operator

IP(MMcf/d)

Lateral Length (Ft)

Stewart Winland 1300U Magnum Hunter 46.5 5,289

Bigfoot 9H Rice Energy 41.7 6,957

Stalder #3UH Magnum Hunter 32.5 5,050

Irons #1-4H Gulfport 30.3 5,714

Pribble 6HU Stone Energy ≈30 3,605

Simms U-5H Gastar 29.4 4,447

Conner 6H Chevron 25.0 6,451

Tippens #6H Eclipse 23.2 5,858

Porterfield 1H-17 Hess 17.2 5,000

Hubbard BRK #3H Chesapeake 11.1 3,550

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


RangeUtica Well

Flow Testing

ChevronConner 6H


GastarSimms U-5H4,447’ Lateral

IP 29.4 MMcf/d

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

RiceBigfoot 9H


Utica Shale Dry GasWV/PA

Net Resource9.5 Tcf

1,390 Gross Locations167,000 Net Acres

Utica Shale Dry GasOhio

3P Reserves1.9 Tcf

226 Gross Locations32,000 Net Acres

Utica Shale Dry GasTotal OH/WV/PA

Net Resource11.4 Tcf

1,616 Gross Locations≈200,000 Net Acres

Stone EnergyPribble 6HU

3,605’ LateralIP ≈30 MMcf/d

ChesapeakeUtica Well

Drilling

RiceBlue Thunder

10H, 12H≈9,000’ Lateral

Needed to make up for base declines in conventional and GOM production

? ??

3,000 Antero Drilling Locations

Perm

ian

Nio

brar

a

Gra

nite

Was

h

Bar

nett

Hay

nesv

ille

U.S. INCREMENTAL GAS SUPPLY BREAK-EVEN PRICE CURVE(1)

35

Low cost, liquids-rich Utica and Marcellus Shales will remain attractive in most commodity price environments

Utica Shale

SW (Rich) Marcellus

Shale

1. Source: Credit Suisse report dated January 2014 – Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI

NE (Dry) Marcellus

ShaleEagle Ford

Shale

MARCELLUS & UTICA – ADVANTAGED ECONOMICS

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 June 30, 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 June 30, 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.

36

Regarding Hydrocarbon Quantities

Am website presentation december 2014

Investor Relations

Transcript of Am website presentation december 2014