MLPA 2017 Investor Conference June 1, 2017

Transcription

1 MLPA 2017 Investor Conference June 1, 2017

2 2 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 ) or Antero Midstream GP LP and its subsidiaries other than the Partnership (collectively, AMGP ) as applicable 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 AMGP, the Partnership and Antero Resources Corporation ( Antero Resources ). These statements are based on certain assumptions made by the AMGP, 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 AMGP or the Partnership, as applicable, 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, 2016 and in the Partnership s subsequent filings with the SEC, as well as the factors discussed under Risk Factors in AMGP s final prospectus dated May 3, 2017 and filed with the SEC on May 5, AMGP and the Partnership caution 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, 2016 and in the Partnership s subsequent filings with the SEC. The Partnership s 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. In addition, AMGP s ability to make future distributions is substantially dependent on the Partnership s business, financial conditions and the ability to make distributions. Any forward-looking statement speaks only as of the date on which such statement is made, and neither AMGP or the Partnership undertakes any 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. Antero Midstream Partners LP is denoted as AM, Antero Midstream GP LP is denoted as AMGP and Antero Resources Corporation is denoted as AR in the presentation, which are their respective New York Stock Exchange ticker symbols.

3 Antero Simplified Organizational Structure The combined enterprise value of the Antero complex is over $18 billion Affiliates Public Affiliates Public 32% 68% 80% 20% (NYSE: AR) Enterprise Value: $10.5 Bn 59% 100% Incentive Distribution Rights (IDRs) (NYSE: AMGP) Enterprise Value : $4.1 Bn Public 41% (NYSE: AM) Enterprise Value : $7.3 Bn Note: Enterprise Value as of May 30, AR enterprise value excludes minority interest. 3

4 Delivering on Antero IPO Promises At IPO (October 2013) Current Growth Acreage: 431,000 Net Acres 634,000 Net Acres (6) +47% Leading consolidator since AR IPO adding 203,000 net acres Net Production (1) : 458 MMcfe/d 2,144 MMcfe/d +368% LTM EBITDAX (2) : 3P Reserves (3) : $457 Million $1,546 Million 27.7 Tcfe 46.4 Tcfe +238% +68% At IPO (November 2014) Current Distribution / Coverage: LTM EBITDA (4) : Gathering Throughput (5) : $0.17 (MQD) Target: 1.1x 1.2x $0.30 / Actual: 1.4x $45 $444 Low Pressure: 532 MMcf/d Low Pressure: 1,659 MMcf/d 1. Represents 2Q 2013 and 1Q 2017 net production, respectively. 4. For the three months ended 9/30/2014, annualized and 3/31/17, respectively. 2. Represents consolidated LTM EBITDAX as of 6/30/2013 and 3/31/2017, respectively. 5. For the three months ended 9/30/2014 and 3/31/2017, respectively. 3. Current 3P reserves are as of 12/31/2016, assuming partial ethane recovery. 3P Reserves for 2013 include 6.3 Tcfe Proved, 14.0 Tcfe Probable and 7.4 Tcfe Possible. 3P Reserves for 2016 include 15.4 Tcfe Proved, 29.1 Tcfe Probable and 1.9 Tcfe Possible. 6. Net acres as of 12/31/2016, pro forma for additional leasing and acquisitions. +76% +887% +212% 4

5 Most Integrated Natural Gas and NGL Story in the U.S. World Class E&P Operator in Appalachia 1. Multi-decade, economic development program - Largest core acreage position in Appalachia - Low risk, core drilling inventory representing 46.4 Tcfe of 3P reserves (1) - Controls 43% of all core liquids-rich undrilled locations in Appalachia - Strong trend of improved recoveries and well economics and lower F&D costs 2. Peer-leading, visible growth - 15-year drilling inventory generating 20% $3.00/MMbtu or less - Largest firm transport portfolio delivers NYMEX-plus pricing - 85% of target natural gas production hedged through $3.72/MMbtu 3. Strong balance sheet and financial liquidity (Ba2 / BB) A Leading Northeast Infrastructure Platform 1. Long-term, 100% fixed fee contracts - No direct commodity price exposure 2. Organic, just-in-time investment strategy - Efficient, organic return on capital (3x to 6x capex to buildout EBITDA multiples) - $5.0 Bn project backlog through Diversified asset mix - Gathering, compression, processing, fractionation, fresh water distribution and wastewater treatment 4. Highest LP distribution growth among MLPs 5. Abundant upside growth opportunities - Downstream NGL infrastructure, 3 rd party business, stacked pay drilling, acreage additions Levered Exposure to Northeast Infrastructure Buildout 1. Combination of growth and yield is unmatched 2. Early stage 100% pure IDR vehicle 3. AM LP unit issuance for potential accretive transactions provides secondary growth driver 4. Debt-free balance sheet at AMGP - Limited dependence on AM capital markets activity due to organic model 5. Maximum exposure to decrease in corporate tax rate - LP structure but treated as a corporation for tax purposes 1. 3P Reserves for 2016 include 15.4 Tcfe Proved, 29.1 Tcfe Probable and 1.9 Tcfe Possible. 5

6 Internal Rate of Return Organic Growth Drives the Business Organic growth strategy provides attractive returns while avoiding the competitive acquisition market and reliance on capital markets 12.0x 10.0x Organic Adjusted EBITDA Multiple vs. Drop Down Multiples Drop Down Median: 8.8x Industry leading organic growth story ~$2.3 billion in capital spent through 9/30/2016 on gathering and compression and water assets Assumes midpoint guidance EBITDA for 2017 (excluding JV) 4.4x Capital expenditures to buildout EBITDA 10-year identified project inventory of $5.0 billion 24% weighted average project IRR AM Builds at 3x to 6x EBITDA vs. Other MLPs that Drop Down/Buy at 8x to 12x+ EBITDA 8.0x 6.0x 4.0x 2.0x 0.0x 45% 40% 35% 30% 25% 20% 15% 10% 5% 0% 6.9x 6.1x 4.5x 4.4x E Drop Down AM Organic EBITDA Multiple (1) Antero Midstream Project Unlevered IRRs 35% 25% LP Gathering Wtd. Avg. 24% IRR 25% 15% HP Gathering 20% 10% Compression 40% 30% Fresh Water Delivery 25% 18% 15% 15% Advanced Wastewater Treatment Note: Precedent data per IHS Herold s research and public filings. 1. Antero Midstream organic multiples calculated as gathering and compression and water capital expended through Q3 of each respective year divided by Adjusted EBITDA, assuming month lag between capital incurred and full system utilization. 2. Selected gathering and compression drop down acquisitions since 1/1/2015. Drop down multiples are based on NTM EBITDA. Source: Public company filings and press releases. (2) Processing/ Fractionation 6

7 Capturing the Midstream Value Chain Participating in the full value chain diversifies and sustains Antero s integrated business model $5.0 billion organic project backlog and ~$1.0 billion downstream investment opportunity set Upstream Downstream AM Assets AM/MPLX JV Assets Potential AM Opportunities ~$800 Million JV Project Backlog FRACTIONATION NGL PRODUCT PIPELINES TERMINALS & STORAGE (ETHANE, PROPANE, BUTANE) WELL PAD LOW PRESSURE GATHERING COMPRESSION HIGH PRESSURE GATHERING ~$4.2 Billion Organic Project Backlog GAS PROCESSING (50% INTEREST) REGIONAL GATHERING PIPELINE (15% INTEREST) Y-GRADE PIPELINE ~$1.0 Billion Downstream Investment Opportunity Set PDH PLANT LONG HAUL PIPELINE END USERS Note: Third party logos denote company operator of respective asset. INTERCONNECT 7

8 NGL Infrastructure Buildout in the Northeast Over $4 Billion of downstream NGL infrastructure projects currently under construction or proposed for the Northeast adjacent to Antero s position The Northeast NGL infrastructure buildout potentially presents additional investment opportunities Utopia (50 Mbbl/d C2) (1Q 2018) Mariner West (50 Mbbl/d C2) 61,500 MBbl/d Mariner East 2 Mariner East (70 Mbbl/d) Antero / MPLX Joint Venture (1) 1. Represents processing and fractionation joint venture between Antero Midstream and MPLX LP that was announced February 6 th,

9 Antero Resources Sponsor Strength 9

10 Growth Through the Down Cycle Antero Resources has uniquely sustained growth and value creation through the down cycle Marcellus Marcellus Net Acres (000 s) Net 3P Reserves (Tcfe) (2) Utica Actual Henry Hub Gas Price (4) $/MMBtu Utica Guidance (3) $ $2,400 Consensus $2,236 Target (5) $ $2,000 $ $1,536 $1,540 $1, $1,221 $4.00 $1,164 $1,200 $ $800 $649 $ $434 $341 $400 $ $ E 2018E acreage count represents year-end 2016 net acres pro forma for any 2017 acreage acquisitions to date , 2013, 2014 and 2015 reserves assuming ethane rejection net 3P reserves assume partial ethane recovery. 3. Production represents midpoint of 2017 production guidance of 2.2 Bcfe/d, including 92,500 Bbl/d liquids, per press release dated 1/4/ Represents Henry Hub spot price from 1/1/2010 through 03/31/ (1) Average Net Daily Production (Bcfe/d) $0 Proved Probable Possible E 2018E Consolidated Adjusted EBITDAX ($MM) Based on consensus estimates as of 5/30/ $

11 11 A Leading Consolidator in Appalachia Activity Antero has capitalized on the industry environment and acquired approximately 78,000 net acres in the core of the Marcellus and Utica Shale plays since the beginning of 2016 Vast majority of the acreage was undedicated at closing and has been dedicated to AM Acquisitions Since 1/1/ ,500 net acres Sept ,900 net acres Dec ,100 net acres Dec ,200 net acres Jan ,000 net acres May 2017 Consolidated acreage position drives efficiencies: Longer laterals More wells per pad Higher utilization of gathering, compression and water infrastructure Facilitates central water treatment avoiding reinjection $200 million land capital budget for 2017 to further consolidate core acreage Supports long-term growth outlook

12 Core Net Acres (000s) Source: Core outlines based upon Antero geologic interpretation, well control and peer acreage positions based on investor presentations, news releases, 10-K/10-Qs and other sources. Rig information per RigData as of 5/19/ Peers include Ascent, CHK, CNX, COG, CVX, EQT, GPOR, HG Energy, RICE, RRC, and SWN. 12 Largest Core Acreage Position in Appalachia Antero has the largest core acreage position in Appalachia and the largest liquids-rich position 15 Marcellus Rigs Largest Core Acreage Position in Appalachia (1) Core - NE Pennsylvania Dry Net Acres 604 Core - SW Marcellus & Utica Dry Net Acres Core - Marcellus & Utica Liquids Rich Net Acres Utica Rigs 31 Marcellus Rigs Total Rigs 100 -

13 Undrilled Locations Yields Largest Core Drilling Inventory In Appalachia Large, repeatable core drilling inventory that averages 8,000 in lateral length and includes 43% of all liquids-rich undrilled locations in Appalachia Undrilled Core Marcellus and Utica Locations (1)(2) 4,000 3,500 3,000 2,500 3,502 Core - NE Pennsylvania Dry Locations Core - SW Marcellus and Ohio Utica Dry Locations Core - Marcellus & Ohio Utica Liquids-Rich Locations Core Liquids-Rich Appalachia Undrilled Locations (1) J 8% E 6% F 6% A 4% D 3% K H 3% 2% I 2% 43% 2,000 * 1,967 1,937 C 10% B 13% 1,500 1,161 1, * * * 548 * - Avg. Lateral Length AR A B C D E J H K F L I 8,081 6,429 6,355 6,225 8,601 7,762 5,758 8,594 9,262 7,550 7,085 8, Location count determined by Antero technical review of geology and well control to delineate core areas and peer acreage positions both drilled and undrilled. Pro forma for all acreage acquisitions to date. 2. Peers include Ascent, CHK, CNX, COG, CVX, EQT, GPOR, HG Energy, RICE, RRC, and SWN.* Undrilled location count net of acreage allocated to publicly disclosed joint ventures. 13

14 Locations Substantial Drilling Inventory at Low Breakeven Prices Antero has a 15-year drilling inventory that generates a 20% rate of return at $3.00/MMbtu NYMEX or less, assuming the 2017 development pace (170 completions) Cumulative 3P Drilling Inventory Breakeven Prices at 20% ROR (1)(2) 4,000 3,500 3,000 2,500 Marcellus Rich Gas Marcellus Dry Gas Ohio Utica Rich Gas Ohio Utica Dry Gas ~70% of total locations generate a 20% rate of return at $3.00/MMbtu NYMEX or less 2,595 3,478 Average Lateral Length 3,670 3,704 Ohio Utica Dry Gas Ohio Utica Rich Gas Marcellus Dry Gas 2,000 ~30% of total locations generate a 20% rate of return at $2.00/MMbtu NYMEX or less 1,815 1,500 1,000 1,091 Marcellus Rich Gas ,229 9,109 8,630 < $1.50 < $2.00 < $2.50 < $3.00 < $3.50 < $4.00 $4.00 NYMEX Natural Gas Price ($/MMBtu) 1. Marcellus and Utica 3P locations as of 12/31/2016 pro forma for any acreage acquisitions to date. Categorized by breakeven price solving for a 20% BTAX ROR and assuming 50% of AM fees due to AR ownership of AM. Assumes $55.00/Bbl WTI over the next five years and strip pricing for C3+ NGLs, which is ~53% of WTI. 2. Includes 3,502 total core locations plus 202 non-core 3P locations. 8,607 8,177 8,062 < 8,253 14

15 Antero Completion Size (lbs/ft) Marcellus Completion Evolution Antero is continuing to increase proppant intensity in 2017 primarily utilizing 1,750 and 2,000 lb/ft completions in the Marcellus 3,000 2,750 5,000 4,000 1,750 lb/ft Completions 1,500 lb/ft Completions Testing higher proppant loads in 2017 Early results are encouraging 2,500 3,000 2, Bbl/ft Water 2,250 1,000 2,000 1,750 0 Days 42 Bbl/ft Water 36 Bbl/ft Water 1,500 1,250 1,000 Supports 2.0 Bcf/1,000 type curve and 81 PUD bookings at YE2016 Per Well Frac Size Design (lb/ft) 1,250 1,500 1, Bbl/ft Water 32 Bbl/ft Water Supports 1.7 Bcf/1,000 type curve and historical reserve bookings 2,000 2,500 Completion Start Date 15

16 Recent Marcellus Well Results Wellhead EURs from Antero s recent 1,750 pound per foot completions have continued to outperform legacy style completions and range from 2.0 to 2.4 Bcf/1,000 at the wellhead Recent 4-well pad with 2,500 lb/ft completions potentially extends high-graded core areas Antero - 2 Well Average Advanced 1,750# Completion Wellhead: Processed: C2 Recovery: Lateral: 2.3 Bcf/1, Bcfe/1, Bcfe/1,000 11,567 Net F&D Cost: $0.38/Mcfe Southern Rich High-Graded Core Average 2.0 Bcf / 1,000 Wellhead EUR Dry Gas High-Graded Core Average 2.2 Bcf / 1,000 Wellhead EUR Antero - 4 Well Average Advanced 1,700# Completion Wellhead: Processed: C2 Recovery: 2.4 Bcf/1, Bcfe/1, Bcfe/1,000 Antero - 10 Well Average Advanced 1,700# Completion Lateral: Net F&D Cost: 10,017 $0.39/Mcfe Wellhead: 2.1 Bcf/1,000 Processed: 2.6 Bcfe/1,000 C2 Recovery: 3.3 Bcfe/1,000 Lateral: 10,468 Net F&D Cost: $0.35/Mcfe Antero - 4 Well Average Advanced 2,500# Completion Wellhead: Processed: C2 Recovery: 2.3 Bcf/1, Bcfe/1, Bcfe/1,000 Lateral: 5,365 Net F&D Cost: $0.45/Mcfe $0.47/Mcfe (1) (1) 1. Represents actual completion costs and Q AFE drilling costs. Antero Acreage Antero Horizontal Marcellus Wells Industry Horizontal Marcellus Wells 16

17 Rapidly Growing NGL Production Antero is the largest NGL producer in the Northeast NGL Production Growth by Purity Product (Bbl/d ) (Bbl/d) 160, , ,000 Ethane (C2) C3+ Production Propane (C3) Normal Butane (nc4) IsoButane (ic4) Natural Gasoline (C5+) 100,000 80,000 60,000 40,000 20,000 19,500 42,500 73,000 C2 Ethane 17,476 86,500 C2 Ethane 19,000 C3 nc4 ic % Y-O-Y Long-Term Growth Target Guidance 2018E Target 2019E Target 1. Excludes condensate. 2. Assumes midpoint of 20 22% year-over-year equivalent production growth in For illustrative purposes C3+ production growth assumed at same rate. (1) C5+ (2) (2) (2) 2020E Target 17

18 Liquids Pricing Upgrade in the Marcellus Antero realizes a significant upgrade to assumed $3.00/MMBtu NYMEX gas price by producing liquids-rich gas and condensate $4.50 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 Gas $3.15 Realized Price Per Mcf (1) ($/Mcf) +$0.90 Upgrade $5.00 $4.05 NGLs (C3+) $0.89 Condensate $0.14 Gas $ BTU 1250 BTU / $55 WTI +$1.17 Upgrade $4.32 NGLs (C3+) $1.12 Condensate $0.18 Gas $ BTU / $65 WTI $3.00/MMBtu NYMEX (1100 BTU Tailgate) 8% shrink Dry Gas Rich Gas Assuming Ethane Rejection 1. Assumes $3.00/MMBtu NYMEX, $55/Bbl to $65/Bbl WTI and NGL prices equal to 52.5% of WTI (midpoint of 2017 guidance). 45 Bbl/MMcf (ethane rejection) recovery for NGLs and 3 Bbl/MMcf for condensate, processing shrink included. 18

19 Pre-Tax PV-10 ($MM) Unhedged Pre-Tax ROR Pre-Tax PV-10 ($MM) Unhedged Pre-Tax ROR Attractive Liquids-Rich Marcellus Well Economics Integrated platform yields attractive well economics and sustainable growth Highly-Rich Gas/Condensate (3/31/17 Pricing) (1) Highly-Rich Gas (3/31/17 Pricing) (1) $18.0 $12.0 $6.0 $0.0 Wellhead Bcf/1,000 : Processed Bcfe/1,000 : Pre-Tax PV-10 53% $ % $12.4 Pre-Tax ROR 95% $ % 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% $18.0 $12.0 $6.0 $0.0 Pre-Tax PV Btu 1250 Btu Undrilled Locations Wellhead Bcf/1,000 : Processed Bcfe/1,000 : 2016 Advanced Completion Results 30% $ % $ Pre-Tax ROR 56% $ ,184 Undrilled Locations 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% 1. Assumes ethane rejection. Based on commodity pricing as of 3/31/17. Assumes 9,000 lateral length. 19

20 Largest Firm Transportation Portfolio in the Northeast Antero transportation commitments yield NYMEX-plus pricing for natural gas and are expected to yield Mont Belvieu-plus pricing for NGLs Antero Long Term Firm Processing & Takeaway Position (YE 2018) Accessing Favorable Markets YE 2018 Gas Market Mix Antero 4.85 Bcf/d FT 13% TCO 13% Atlantic Seaboard 13% Regional (PA) 17% Midwest Expect NYMEXplus pricing per Mcf in aggregate 44% Gulf Coast Gulf Coast Markets To Midwest 800 MMcf/d 4.85 Bcf/d Firm Gas Takeaway By YE 2018 Midwest Markets 1. Shell announced final investment decision (FID) on 6/7/ Lake Charles LNG 150 MMcf/d commitment subject to Shell FID. 30 MBbl/d Ethane Local Petchem 1,400 MMcf/d To TCO Pool 689 MMcf/d Sabine Pass (Trains 1-4) 200 MMcf/d (T1, T2 and T3 in-service) 420 MMcf/d LNG Export Freeport LNG (3Q 2018) 70 MMcf/d Lake Charles LNG (2) 150 MMcf/d Shell (2021) 30 MBbl/d Commitment Pennsylvania Cracker (1) Antero 2.8 Bcf/d Firm Processing 625 MMcf/d To Atlantic Seaboard 630 MMcf/d Regional Markets Antero Commitments Firm Processing: Firm Gas Takeaway: LNG Firm Sales: (2) Mariner East 2 (4Q 2017) 62 MBbl/d Commitment Marcus Hook Export 62 MBbl/d NGL Export 330 MMcf/d LNG Export Cove Point LNG (4Q 2017) 330 MMcf/d = 2.8 Bcf/d = 4.85 Bcf/d = 750 MMcf/d Firm Ethane Takeaway: = 20 MBbl/d Ethane Cracker: Firm NGL Takeaway: = 30 MBbl/d = 62 MBbl/d 20

21 21 Largest Gas Hedge Position in U.S. E&P ~$2.1 billion mark-to-market unrealized gain based on 3/31/2017 prices with 3.4 Tcfe hedged through year-end 2022 at $3.63 per MMBtu Commodity Hedge Position BBtu/d Hedged Volume Average Index Hedge Price (1) Current NYMEX Strip (2) Mark-to-Market Value (2) $/Mcfe 2,400 2,000 1,600 2,163 $3.47 2,015 $3.91 2,330 $3.70 $3.63 Hedging is a key component of Antero s business model due to the large, repeatable drilling inventory Antero has realized $2.8 billion of gains on commodity hedges since 2008 with gains realized in 34 of last 36 quarters $3.31 $3.18 $6.00 $5.00 $4.00 1, $3.32 $3.03 $2.83 $2.82 $2.83 $ $3.00 $ $ $81 MM $627 MM $702 MM $390 MM $110 MM ~ 100% of 2017 Guidance Hedged ~ 75% of 2018 Target Hedged ~ 72% of 2019 Target Hedged $85 MM $0.00

22 Consensus EBITDAX Estimates ($MM) Production Guidance / Targets (Bcfe/d) Net Debt/LTM EBITDAX Targets Significant Cash Flow Growth Declining Leverage Visible cash flow growth given hedges, firm transportation portfolio, and capital efficient long-term development plan targeting 20% to 22% production CAGR $3,000 Consensus EBITDAX (1) Production Guidance (Bcfe) 4.5 $2,500 Production Targets (Bcfe) Leverage Targets $2, $2, $1,500 $1,536 $1, Declining Leverage $1, $ $0 1. Bloomberg Consensus EBITDAX estimates as of 3/31/ A 2017E 2018E 2019E 2020E

23 23 Antero Clearwater Facility Expected In Service 4Q 2017 Antero Midstream High Visibility Growth

24 Antero Midstream Asset Overview An integrated system for natural gas and NGL production, gathering and processing Midstream Infrastructure (In Service) Gathering Pipelines (Miles) 307 Compression Capacity (MMcf/d) 1,135 Condensate Pipelines (Miles) 19 Processing Plant (MMcf/d) 200 Fractionation Plant (Bbl/d) 20,000 Fresh Water Pipelines (Miles) 286 Fresh Water Impoundments 36 Regional Pipeline Capacity (Bcf/d) 1.4 Antero Clearwater Facility (Bbl/d) (1) 60,000 Note: Infrastructure in service as of year-end The Antero Clearwater Facility is scheduled to be placed into service in the fourth quarter of Compressor Station Antero Clearwater Facility Sherwood Processing Facility 24

25 High Growth Midstream Throughput 2,000 1,800 1,600 1,400 1,200 1, Low Pressure Gathering (MMcf/d) Fixed Fee: $0.31/Mcf 1,659 1,403 1, Q ,400 1,200 1, Compression (MMcf/d) Fixed Fee: $0.19/Mcf 1, Q 2017 High Pressure Gathering (MMcf/d) Fresh Water Delivery (MBbl/d) 2,000 1,800 1,600 1,400 1,200 1, Fixed Fee: $0.19/Mcf 1,581 1,316 1, Q Fixed Fee: $3.68/Bbl Q 2017 Marcellus Utica Note: Growth based on 2-year CAGR. All fees are as of year end

26 26 Antero Midstream Upside Opportunity Set AM has multiple pathways to upside beyond its $5.0 billion organic project backlog 1 OPPORTUNITY Downstream Infrastructure Buildout POSITIONING Antero leverages its resource and production to provide investment opportunities for AR and AM Natural gas and NGL pipelines, terminals and storage 2 AR Acreage Consolidation Undedicated acreage acquisitions by AR are dedicated to AM for gathering, compression, processing and water services AR has added over 200,000 net acres since 2013 IPO 3 Third Party Business Fresh water delivery, waste water treatment and gathering/compression services to capture third party business in Appalachia and enhance asset utilization 4 Upper Devonian ~1,000 incremental locations prospective for Upper Devonian dedicated to AM for gathering and water services Industry is developing Upper Devonian now Volumes can go to Marcellus system already in place 5 WV/PA Utica Dry Gas 400 Deep Utica locations underlying the Marcellus in West Virginia dedicated to AM and will require some new dry gas infrastructure Industry is continuing to delineate deep Utica resource

27 Distribution Per Unit DCF Coverage Ratio and Leverage Ratio Long Term Growth Outlook Through 2020 AM s $2.6 billion organic opportunity set through 2020 and visible cash flow growth allow it to target a 28% to 30% distribution CAGR through 2020 and maintain leverage in the low 2-times $3.00 $2.50 Distribution Guidance Distribution Target DCF Coverage 3.0x 2.5x $2.00 Stable Leverage $ x $ x $1.00 $ x DCF Coverage >1.25x 1.5x $ x $ A 2017 Guidance 2018E Target 2019E Target 2020E Target 0.5x Note: Future distributions subject to Board approval. 27

28 AMGP Cash Available for Distribution ($MM) AMGP Distributions Per Share ($/Share) AMGP Highly Levered to AM Distribution Growth AM distributions drive IDR cash flow which drives AMGP distributions $250 AMGP Cash Available for Distribution AMGP Distributions per Share (1) $1.10 $1.20 $200 $205 $1.00 $150 $100 $50 $0 $0.73 $136 $0.44 $82 $0.22 $41 $0.04 $0.00 $0.00 $8 $0.68 $0.80 $1.03 $1.33 $1.71 $2.21 $2.85 AM Distribution Per Unit Hypothetical AM Distribution Growth $0.80 $0.60 $0.40 $0.20 $ Assumes million AM units outstanding as of February 28,2017; Assumes million AMGP shares outstanding. AMGP cash available for distribution (CAFD) is net of (i) Series B unit distributions, (ii) general and administrative expense, and (iii) U.S. federal and state income taxes (assuming 38% effective income tax rate) 28

29 29 Antero Midstream Investment Highlights Combination of High Growth and Yield is Unmatched Most Integrated Natural Gas and NGL Story in the U.S. Cash Flow Driven by Visible Low Risk Production Growth at AR Fixed-Fee Tolling Business Eliminates Direct Commodity Price Exposure $5 Billion Project Backlog + $1 Billion Downstream Opportunity Set

30 Appendix 30

31 Processing and Fractionation JV Antero Midstream (NYSE: AM) and MPLX (NYSE: MPLX) formed a joint venture for processing and fractionation infrastructure in the core of the liquids-rich Marcellus and Utica Shales in February 2017 Strategic Rationale Further aligns the largest core liquids-rich resource base with the largest processing and fractionation footprint in Appalachia Up to 11 additional processing plants 20,000 Bbl/d of capacity at Hopedale 3 fractionation facility with option to invest in future fractionation capacity Over $800 million project backlog through 2020 (net to AM), including ~$155 million contribution upfront for processing and fractionation infrastructure Fits with AM s full value chain organic growth strategy Long-term 100% fixed-fee revenues Significant MVCs on processing 15% 18% unlevered IRR Improved visibility throughout vertical value chain and ability to deploy just-in-time capital supporting Antero Resources rich gas development Future Processing Complex TBD 1 6 Potential 1,200 MMcf/d (1) MarkWest / Antero Midstream Hopedale Fractionation Complex C3+ Fractionation 1 & 2: 120 MBbl/d In Service C3+ Fractionation 3: 60 MBbl/d In Service 20 MBbl/d In Service JV MarkWest / Antero Midstream Sherwood Complex: 11 x 200 MMcf/d Sherwood 1 6: 1.2 Bcf/d In Service Sherwood 7: 200 MMcf/d In Service Sherwood 8: 200 MMcf/d 4Q 2017 Sherwood 9: 200 MMcf/d 1Q 2018 Sherwood 10: 200 MMcf/d 3Q 2018 Sherwood 11: 200 MMcf/d 4Q 2018 De-ethanization: 40 MBbl/d In Service Note: RigData as of 04/14/17. Rigs drilling in rich gas areas only. 1. New West Virginia site location still to be determined. 31

32 2017 Guidance and Long Term Targets Distribution Growth (1) : $3.50 $3.00 $2.50 Guidance Long Term Targets $2.00 $1.50 $1.00 $0.50 $1.03 $1.33 $ A 2016E 2017E 2018E 2019E 2020E Updated 2017 Guidance (2) Long-Term Targets DCF Coverage: 1.30x 1.45x > 1.25x EBITDA ($MM): $520 $560 Peer Leading Growth Capital Expenditures ($MM): $800 $2.6 Billion organic opportunity set from Leverage: 2.0x 2.5x Low 2-times range 1. Assumes midpoint of 2017 distribution growth guidance and long-term target. Future distributions subject to Board approval. 2. Per press release dated 2/6/

33 Internal Rate of Return Estimated Project Economics by Segment Project Economics by Segment (1) 45% 40% 35% 30% 25% 20% 15% 10% 5% 0% 35% 25% LP Gathering 25% 15% HP Gathering Wtd. Avg. 24% IRR 20% 10% Compression 40% 30% Fresh Water Delivery 25% 18% 15% 15% Advanced Wastewater Treatment Processing/ Fractionation Unlevered IRR Range: 25% - 35% 15% - 25% 10% - 20% 30% - 40% 15% - 25% 15% - 18% Payout (Years): Minimum Volume Commitments: N/A 75% 70% Yes N/A Yes 2017 Capex Total Marcellus $655 $80 $60 $115 $50 $75 $275 Utica Total Capex $800 $125 $70 $155 $75 $100 $275 % of Capex 100% 16% 9% 19% 9% 13% 34% Included in 2017 Budget: Marcellus & Utica Marcellus & Utica Marcellus & Utica Marcellus & Utica Marcellus & Utica Marcellus & Utica 10-year identified investment opportunity set $5.0 B 35% - 40% 10% - 12% 20% - 25% 10% - 12% 1% - 3% 15% - 17% Additional In-hand Opportunities: Dry Utica Upper Devonian Dry Utica Upper Devonian Dry Utica Upper Devonian Dry Utica Upper Devonian Dry Utica Upper Devonian Third Party Fractionation 1. Based on management capex, operating cost and throughput assumptions by project. These objectives are forward-looking, are subject to significant business, economic, regulatory and competitive uncertainties and contingencies, many of which are beyond the control of the Company and its management, and are based upon assumptions with respect to future decisions, which are subject to change. Actual results will vary and those variations may be material. For discussion of some of the important factors that could cause these variations, please consult the Risk Factors section of the preliminary prospectus. Nothing in this presentation should be regarded as a representation by any person that these objectives will be achieved and the Company undertakes no duty to update its objectives. 33

34 Net Daily Production Guidance and Long Term Outlook Production Growth: (Bcfe/d) $ Guidance Long-Term Targets Hedged Volume (Bcfe) Hedged Price ($/Mcfe) $ $3.91 $ $ (2) (2) (2) 2016A 2017E 2018E 2019E 2020E 2017 Guidance Long Term Targets D&C Capital: Consolidated Cash Flow from Operations (1) : $1.3 Billion Flat with prior year Modest annual increases within Cash Flow from Operations In line with D&C capital Doubling by 2020 Leverage (1) : 3.0x to 3.5x Declining to mid-2s by 2018 Hedging: 98% Hedged at $3.51/Mcfe 58% Hedged at $3.76/Mcfe

35 Source: Public filings and press releases. Excludes TETCO expansions (972 MMcf/d) that are currently under construction Bcf/d capacity available to move gas from Leach to the Gulf on CGT Rayne Xpress MMcf/d of capacity available on CGT Gulf Xpress to move gas to the Gulf Coast markets. Transco Atlantic Sunrise Mid-2018 (1.7 Bcf/d) 35 Key Appalachian Natural Gas Takeaway Projects Growth in natural gas infrastructure by the end of 2019, resulting in 16.8 Bcf/d of incremental capacity, will support expected supply growth 4.8 Bcf/d 1.8 Bcf/d Antero Producing Areas 5.2 Bcf/d 4.2 Bcf/d Antero firm transportation commitment

36 Gross Residue Bcf/d and FT Capacity Potential Appalachian Gas Production vs. Future FT Southwest Portion of the Basin (Bcf/d) Rayne XPress NEXUS Leach XPress Adair Southwest Access South Rover Pipeline Phase2 Mountain Valley Pipeline WB Xpress Atlantic Coast Pipeline Gulf XPress Mountaineer XPress 80 Rigs 56 Rigs - Current + 20% Incremental Rigs per Year 7/1/19 = 6 Bcf/d 30 Bcf/d 27 Bcf/d 20 Rover Phase 1 7/1/18 Δ = 4 Bcf/d 56 Rigs - Current 23 Bcf/d Current Takeaway Estimated at 13.7 Bcf/d per Bentek Rig Assumptions: Assumes 10 days spud to spud (36.5 wells/rig year) Four-pack drilling 195 days average spud to first sales 7,000' laterals Type curve shape per Antero type curve 24 Rigs required to hold production flat at 14 Bcf/d Base Decline of Current Production of 13.5 Bcf/d Rig Type Performance (Bcf/1,000') Average Lateral Dry Gas (SW PA & WV Marcellus) 2.0 7,000' Dry Gas (Utica) 2.0 7,000' Rich Gas (SW PA & WV Marcellus) 2.0 7,000' Rich Gas (Utica) 1.7 7,000' Current Rig Count Rich Dry Total SW Marcellus: Utica: Grand Total SW: Bcf/d 1. Assumes ethane rejection. Based on commodity pricing as of 3/31/17. Assumes 9,000 lateral length. 36

37 Lateral Length (feet) D&C Capital per 1,000' of Lateral ($MM) Drilling Days Days Continuous Operating Improvement Driving drilling and completion efficiencies which continues to lower well costs Dramatic Decrease in Drilling Days Drilling longer laterals while reducing drilling days by 60% Q Record 12 9 Increasing Completion Stages per Day More efficient completions ( zipper fracs ) are increasing stages per day Q Record Drilling Longer Laterals Declining Well Costs per 1,000 12,000 10,000 8,000 Continuing to be an industry leader in drilling longer laterals 10,51510,293 8,543 8,910 9,196 9,250 8,052 8,575 14, Reducing well costs by ~35% since 2014 $1.55 $1.34 $1.36 $1.18 $1.05 $1.01 $0.90 $0.87 6,000 4, , Q Record Marcellus 0.0 Utica Q1 2017

38 Processed EUR per 1,000' of Lateral (Bcfe) F&D Cost per 1,000' of Lateral ($MM) Pounds of Proppant Per Foot Barrels of Water Per Foot Improved Productivity Drives Lower F&D Costs Enhanced completion designs have contributed to improved recoveries and capital efficiency Increasing Proppant Per Foot Increasing Water Per Foot 3,000 2,500 2,000 1,500 1, Higher proppant concentration has contributed to higher recoveries 1,702 1,648 1,267 1,165 1,298 1,163 2,055 2,529 2, Higher proppant concentration requires increased water usage Q Record Q Record Increasing EUR per 1,000 (Bcfe) (1)(2) Since 2014, Antero has increased EURs by 39% in the Marcellus and 20% in the Utica $2.00 $1.50 $1.00 $0.50 Much Lower F&D Cost per Mcfe (2)(3) $0.88 $1.28 Bottom line: F&D costs per Mcfe have declined by 44% in the Marcellus and 28% in the Utica since 2015 $0.94 $0.73 $0.78 $0.45 $0.41 $ Q Record Record Marcellus Utica $ 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 85% NRI in Marcellus and 81% NRI in Utica Q

39 Longer Laterals Improve Rates of Return Antero s typical Marcellus well in 2017 will have a 9,200 lateral length, an EUR of 22.3 Bcfe, including 857 MBbls of NGLS and 66 MBbls of oil and cost $7.7 MM (1) 6,500 Foot Lateral (2) Antero 2016 average lateral: 9,000 feet 11,500 Foot Lateral Pre-Tax Economics ROR (%) 58% PV-10 ($MM) $8.3 Breakeven Nymex ($/MMBtu) $1.29 Dev. Cost ($/Mcfe) $0.42 Pre-Tax Economics ROR (%) 72% PV-10 ($MM) $12.4 Breakeven Nymex ($/MMBtu) $1.11 Dev. Cost ($/Mcfe) $0.38 Pre-Tax Economics ROR (%) 83% PV-10 ($MM) $16.5 Breakeven Nymex ($/MMBtu) $1.01 Dev. Cost ($/Mcfe) $0.35 6,500 9,000 11,500 NOTE: Assumes 2.0 Bcf/1,000 type curve for the Antero Marcellus Highly-Rich Gas/Condensate ( Btu) and 3/31/2017 strip pricing. 1. Assumes ethane rejection and 2.0 Bcf/1,000 recovery at the wellhead. 2. Represents 2016 Marcellus average for peers including: CNX, COG, EQT, RICE, RRC based on public guidance. 39

40 Antero Resources EBITDAX Reconciliation EBITDAX Reconciliation ($ in millions) Quarter Ended LTM Ended 3/31/2017 3/31/2017 EBITDAX: Net income (loss) including noncontrolling interest $305.6 $(454.5) Commodity derivative fair value (gains) losses (438.8) Net cash receipts on settled derivatives instruments Gain of sale on assets - (97.6) Interest expense Loss on early extinguishment of debt Income tax expense (benefit) (369.8) Depreciation, depletion, amortization and accretion Impairment of unproved properties Exploration expense Equity-based compensation expense Equity in earnings of unconsolidated affiliate (2.2) (2.7) Distributions from unconsolidated affiliates Consolidated Adjusted EBITDAX $365.3 $1,

41 41 Antero Midstream EBITDA Reconciliation EBITDA and DCF Reconciliation Three months ended $ in thousands March 31, Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow: Net income $42,918 $75,091 Interest expense 3,704 8,836 Depreciation expense 23,823 27,536 Accretion of contingent acquisition consideration 3,396 3,526 Equity-based compensation 5,972 6,286 Equity in earnings from unconsolidated affiliate - (2,231) Adjusted EBITDA $79,813 $119,044 Interest paid (3,444) (9,187) Cash reserved for payment of income tax withholding upon vesting of Antero Midstream Partners LP equitybased compensation awards (1,000) (1,500) Cash reserved for bond interest - (1,552) Maintenance capital expenditures (5,808) (15,903) Distributable Cash Flow $69,561 $90,902