Am website presentation september 2016

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  • Partnership OverviewSeptember 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 managements experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Partnership, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include the factors discussed or referenced under the heading Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2015 and in the Partnerships 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 Partnerships Annual Report on Form 10-K for the year ended December 31, 2015 and in the Partnerships subsequent filings with the SEC.

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

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

    1

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

  • 2

    CHANGES SINCE AUGUST 2016 PRESENTATION

    Updated AR 2016 production and operating cost guidance Slides 13, 44

    Updated AM 2016 Net Income, EBITDA and Distributable Cash Flow guidance Slides 16, 42

  • 491

    638597

    744

    0100200300400500600700800900

    1,000

    Dedicated Acreage:Gathering & Compression

    Dedicated Acreage:Water Services

    ANTERO RESOURCES ACQUISITION BENEFITS AM

    3

    Antero Midstream Buildout

    Compressor Station In service

    Districts with 3,000+ Antero Net Acres

    Acquisition AcreageCompressor Station Planned on Existing Acreage

    Existing Gathering Line

    New Platform for Antero Midstream

    Infrastructure Buildout

    Fresh Water Delivery Take PointPlanned Gathering Line

    1. Includes projects currently under construction.

    AM Gross Dedicated Acreage (000s)

    A unique opportunity as most Appalachian core acreage is already dedicated to third party midstream providers

    12/31/2015 Pro Forma

    Fresh Water ImpoundmentExisting Fresh Water LinePlaned Fresh Water Line

    Planned Gathering Line Acquisition Acreage

    Compressor Station Planned on Acquisition Acreage

    On June 9, 2016 Antero Resources announced the acquisition of 66,500 net acres in the southwestern Marcellus Shale, over 95% of which will be dedicated to AM for gathering, compression, processing, and water services

    Acquisition and associated equity financing allows Antero Resources to increase 2017 production target to 20% to 25%, providing further support to Antero Midstreams 2017 distribution growth target of 28% to 30%

    Expands Antero Midstream footprint and identified 5-year investment opportunity set by over 15% to ~$3.2 billion(1)

    Attractive organic investment opportunities at 4x to 7x build-out EBITDA

    Additional adjacent third-party midstream opportunities

  • Classification(1) Highly-Rich Gas/Condensate Highly-Rich GasBTU Regime 1275-1350 1275-1350 1275-1350 1200-1275 1200-1275 1200-1275EUR (Bcfe): 20.8 24.4 27.9 18.8 22.1 25.2EUR (MMBoe): 3.5 4.1 4.7 3.1 3.7 4.2% Liquids: 33% 33% 33% 24% 24% 24%Well Cost ($MM): $8.1 $8.1 $8.1 $8.1 $8.1 $8.1Bcf/1,000 1.7 2.0 2.3 1.7 2.0 2.3Bcfe/1,000: 2.3 2.7 3.1 2.1 2.5 2.8Net F&D ($/Mcfe): $0.46 $0.39 $0.34 $0.51 $0.43 $0.38Pre-Tax NPV10 ($MM): $12.3 $15.9 $19.5 $8.2 $11.1 $13.9Pre-Tax ROR: 58% 77% 99% 38% 51% 66%Payout (Years): 1.5 1.1 0.9 2.1 1.6 1.3Breakeven NYMEX Gas Price ($/MMBtu)(5) $1.22 $0.95 $0.76 $2.02 $1.77 $1.57

    Gross 3P Locations(3): 557 1,052Pro Forma Gross 3P Locations(3): 664 (19% Increase) 1,235 (17% Increase)

    $12.3 $15.9$19.5

    $8.2$11.1 $13.9

    58%77%

    99%

    38% 51%66%

    0%20%40%60%80%100%

    -$1.0$2.0$5.0$8.0

    $11.0$14.0$17.0$20.0

    1.72.3

    2.02.7

    2.33.1

    1.72.1

    2.02.5

    2.32.8

    Pre

    -Tax

    RO

    R

    Pre

    -Tax

    PV

    -10

    Pre-Tax PV-10 Pre-Tax ROR

    NYMEX($/MMBtu)

    WTI($/Bbl)

    C3+ NGL(2)($/Bbl)

    2016 $3.04 $50 $222017 $3.18 $52 $262018 $3.02 $54 $272019 $3.00 $55 $282020 $3.06 $55 $282021-25 $3.53 $58 $30

    Assumptions Natural Gas 6/30/2016 strip Oil 6/30/2016 strip NGLs 37.5% of Oil Price

    2016; ~50% of Oil Price 2017+

    45/8435/24

    2016/2017 Development Plan: Completions

    1. 6/30/2016 pre-tax well economics based on a 9,000 lateral, 6/30/2016 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 include $1.2 million for road, pad and production facilities. Assumes ethane rejection.

    2. Pricing for a 1225 BTU y-grade ethane rejection barrel. NGLs at 37.5% of WTI for 2016 and ~50% of WTI for 2017 and thereafter. NGL prices are forecast to increase in 2017 relative to WTI due to projected in-service date of Mariner East 2 project allowing for a significant increase in AR NGL exports via ship.

    3. Undeveloped Marcellus well locations as of 12/31/2015 adjusted for 6/30/2016 net acreage and pending acreage acquisition. 4. Represents actual results for 1Q 2016. 5. Breakeven price for 15% pre-tax rate of return.

    Highly-Rich Gas/Condensate Highly-Rich Gas(4) (4)Bcf/1,000

    Bcfe/1,000

    MARCELLUS UPSIDE POTENTIAL

    4

    33% lower well cost per 1,000 lateral and 33% higher EUR per 1,000 since 2014 are driving rates of return significantly higherdespite lower strip pricing

  • Marcellus ShaleUtica Shale OhioOperating Highlights Top 20 best drilling footage days in

    Marcellus since 2009 have all occurred in 2016, including 7,274 drilled in 24 hours in West Virginia on the Hunter 1H

    Recently drilled and cased longest lateral in company history at 14,024 feet

    Stayed within targeted zone for 95% of lateral length of all wells drilled in Q2 2016

    Increased sand placement during completions to 99% in Q2 2016

    Utilizing new floating casing procedure, reducing casing run time by over 12 hours

    Increased proppant and water loading by 25% in 2016 with encouraging results to date

    1. Based on statistics for wells completed within each respective period.2. Ethane rejection assumed.3. Current D&C cost per 1,000 lateral divided by net EUR per 1,000 lateral assuming 81% NRI in Utica and 85% NRI in Marcellus.

    Acquired Acreage

    CONTINUOUS OPERATING IMPROVEMENTS BY AR

    Utica Marcellus2014 2015 Q2 2016 Q2 2016 vs. 2014 2014 2015 Q2 2016 Q2 2016 vs. 2014

    Activity LevelsAverage Rigs Running 4 5 1 (75%) 14 9 6 (57%)Average Completion Crews 2.0 3.0 1.0 (50%) 5.5 2.0 3.5 (36%)

    Operational ImprovementsDrilling Days 29 31 16 (45%) 29 24 15 (48%)Average Lateral Length (Ft) 8,543 8,575 9,000 5% 8,052 8,910 9,000 12%Stages per Well 47 49 51 9% 40 45 45 12%Stage Length 183 175 175 4% 200 200 200 0%Stages per Day 3.2 3.7 4.4 38% 3.2 3.5 3.9 22%

    Well Cost & Performance ImprovementsD&C per 1,000' of lateral ($MMs) $1