47
MLPA 2016 Annual Investor Conference June 2, 2016
MLPA 2016 Annual Investor Conference June 2, 2016
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 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, 2015 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, 2015 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.
WHY OWN ANTERO MIDSTREAM?
2
Best-in-class distribution growth guidance of 30% in 2016 and 28% to 30% target for 2017 Strong DCF coverage of 1.60x in 1Q16 and 1.45x in 2015, above 1.1x–1.2x target
Strong Distribution Growth & Coverage
Sponsor Strength
Organic Investment Opportunity Set
Full Value Chain Midstream
Opportunity
Financial Flexibility
Aligned High Growth
Sponsor
$3.5 billion of consolidated liquidity; stable leverage through the down cycle Ba2/BB corporate ratings affirmed; $4.5 billion AR borrowing base affirmed 84% of forecasted production hedged through 2019 at $3.77/MMBtu Peer leading realized prices and EBITDAX margins
Identified organic investment opportunity set of $3.0 billion over the next five years “Just-in-time capital” results in more capital efficient project economics, while avoiding the
competitive acquisition market and reliance on capital markets Organic growth strategy results in investment build-out EBITDA multiples of 4x–7x vs.
drop-downs of 8x–12x
Opportunity to expand gathering, compression, and water services to third parties Right of first offer for processing, fractionation, transportation and marketing activities Midstream provider for the largest and most active operator in Appalachia inherently brings
additional downstream opportunities to AM
Over $800 million of liquidity and 2.3x debt to EBITDA ratio at March 31, 2016
17% production growth guidance in 2016 and 20% growth targeted for 2017 drives AM volume growth
Continuous operating improvements, including more water and sand in completions resulting in improved recoveries and well economics for AR and higher volumes for AM
AR has a 62% LP ownership in AM, resulting in direct alignment with midstream value creation
Marcellus Shale Utica Shale Ohio
3
Operating Highlights Top 20 best drilling footage days in
Marcellus since 2009 have all occurred in 2016, including 6,528’ drilled in 24 hours in West Virginia on the Rock 2H
Recently drilled and cased longest lateral in company history at 14,024 feet
Stayed within targeted zone for 98% of lateral length drilled in Q1 2016
Increased sand placement during completions to 98% in Q1 2016
Utilizing new floating casing procedure, reducing casing run time by over 12 hours
Increased proppant and water loading by 25% in 2016 with encouraging results to date
1. Based on statistics for wells completed within each respective period. 2. Ethane rejection assumed. 3. Current D&C cost per 1,000’ lateral divided by net EUR per 1,000’ lateral assuming 81% NRI in Utica and 85% NRI in Marcellus.
CONTINUOUS OPERATING IMPROVEMENTS BY AR
Utica Marcellus2014 2015 Q1 2016 Q1 2016 vs. 2014 2014 2015 Q1 2016 Q1 2016 vs. 2014
Activity LevelsAverage Rigs Running 4 5 1 (75%) 14 9 7 (50%)Average Completion Crews 2.0 3.0 1.5 (25%) 5.5 2.0 4.0 (27%)
Operational ImprovementsDrilling Days 29 31 24 17% 29 24 21 28%Average Lateral Length (Ft) 8,543 8,575 9,000 5% 8,052 8,910 9,000 12%Stages per Well 47 49 51 9% 40 45 45 12%Stage Length 183 175 175 4% 200 200 200 0%Stages per Day 3.2 3.7 4.4 38% 3.2 3.5 3.8 19%
Well Cost & Performance ImprovementsD&C per 1,000' of lateral ($MMs) $1.55 $1.36 $1.14 (26%) $1.34 $1.18 $0.95 (29%)Wellhead EUR per 1,000' of lateral (Bcf) (1) 1.4 1.6 1.6 14% 1.5 1.7 2.0 33%Processed EUR per 1,000' of lateral (Bcfe) (1)(2) 1.5 1.8 1.8 20% 1.8 1.9 2.3 28%Net development cost per processed Mcfe (3) $1.28 $0.94 $0.79 (39%) $0.88 $0.73 $0.49 (45%)
1,237 1,675
2,116
3,699
0
1,000
2,000
3,000
4,000
2014 2015 Q1 2016 Q2 2016
Late
ral f
t/day
Per
Rig
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
01/01/12 01/01/13 01/01/14 01/01/15 01/01/16 01/01/17
Late
ral F
eet D
rille
d Pe
r Rig
Date
24 Hour Footage
Switched to rotary
steerable system
STEP CHANGE IN AR MARCELLUS DRILLING FOOTAGE
4
Top 50 AR Marcellus Daily Footage Records
All of the top 20 daily footage records since
inception have occurred during 2016
Key Drilling Highlights:
Driven by technology and process advancements, all of the top 20 Antero daily footage records have been achieved in 2016, quickly establishing a new benchmark in Marcellus drilling performance
Drilled 6,528’ feet in a lateral in 24 hours, exceeding previous record by over 1,000 feet
Lateral feet drilled per day has increased almost 3x since 2014 to 3,699’ in 2Q 2016
New drilling techniques and technologies are forecast to shave up to 5 days off lateral drilling times and up to 25% off drilling AFEs
Top 20 AR Marcellus Daily Footage Records
Changed lateral bit
Increased pump rates by removing heavy weight
drill pipe (small diameter increased friction)
30 WELLS
90 WELLS
159 WELLS
Marcellus Average Lateral Ft/Day
23 WELLS
1,194 1,128 1,117
990 1,031 1,016 958 956
1,084 1,126
1,274 1,304 1,337 1,418
1,480 1,530 1,500
800
900
1,000
1,100
1,200
1,300
1,400
1,500
1,600
Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 Feb-16 Mar-16 Apr-16 2016Plan
Sand
Pla
ced
Per F
oot o
f Lat
eral
32 31 32 32 32 32 32
31 31 32
34 34 35 36 37
39 39
25
27
29
31
33
35
37
39
41
Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 Feb-16 Mar-16 Apr-16 2016Plan
Bar
rels
Per
Foo
t of L
ater
al
ADVANCED COMPLETIONS DRIVE INCREASED WATER VOLUMES
5
AR Increased Proppant Load by 25% in the Marcellus and Utica, EARLY RESULTS JUST COMING IN
Pilot Testing Demonstrated Improved Recoveries While
Maintaining Well Density
New AR Completion Designs Utilizing 38 to 40 Barrels of Water Per Lateral Foot, a 25% Increase
0
5
10
15
20
25
30
35
4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000
EUR
(Bcf
e)
Lateral Length (Feet)
All Wells2016 Wells
6
MARCELLUS IMPROVEMENTS DRIVING AR VALUE CREATION
Antero Marcellus EUR vs. Lateral Length(1)(2)
33 wells > 10,000’ lateral length and 43 wells waiting on completion ranging from
10,000’ to 14,000’
1. All 255 wells completed since 2014 when Antero transitioned to shorter stage length completions (SSL). 2. EUR’s include condensate and NGL processing (C3+) but assume ethane rejection.
Longer Laterals Better Well Economics
TBA Current completions using 1,500 lbs/ft of sand and 39
Bbls/ft of water
98% sand placement for 1,200 lbs/ft drove
outperformance YTD 2016 compared to type curve
40 wells > 20 Bcfe
High correlation of EURs to lateral length
2016 wells average 2.3 Bcfe/1,000’
High correlation of EURs to lateral length – no degradation in results out to 11,000’ laterals Antero has led the way with long lateral drilling programs
While AR has not changed its 1.7 Bcf/1,000' of lateral Marcellus type curve, AR is seeing stronger EURs per 1,000' in a significant portion of the Marcellus rich gas acreage as exhibited in our 2.0 Bcf/1,000' average for wells brought on line in the first quarter
$8.7 $11.7 $5.2 $7.7
35% 45%
24% 30%
0%10%20%30%40%50%
$0.0$3.0$6.0$9.0
$12.0$15.0
1.7 Bcf/1,000'2.3 Bcfe/1,000'
2.0 Bcf/1,000'2.7 Bcfe/1,000'
1.7 Bcf/1,000'2.1 Bcfe/1,000'
2.0 Bcf/1,000'2.5 Bcfe/1,000'
Pre
-Tax
RO
R
Pre
-Tax
PV
-10
Pre-Tax PV-10 Pre-Tax ROR
Classification(1) Highly-Rich Gas/Condensate Highly-Rich Gas BTU Regime 1275-1350 1275-1350 1200-1275 1200-1275 EUR (Bcfe): 20.8 24.4 18.8 22.1 EUR (MMBoe): 3.5 4.1 3.1 3.7 % Liquids: 33% 33% 24% 24% Lateral Length (ft): 9,000 9,000 9,000 9,000 Well Cost ($MM): $8.5 $8.5 $8.5 $8.5 Bcf/1,000’ 1.7 2.0 1.7 2.0 Bcfe/1,000’: 2.3 2.7 2.1 2.5 Net Development Cost ($/Mcfe): $0.48 $0.41 $0.53 $0.45
Pre-Tax NPV10 ($MM): $8.7 $11.7 $5.3 $7.7 Pre-Tax ROR: 35% 45% 24% 30% Payout (Years): 2.5 2.0 3.7 2.9 Breakeven NYMEX Gas Price ($/MMBtu)(5) $1.67 $1.40 $2.31 $2.05
Gross 3P Locations(3): 626 971
7
NYMEX ($/MMBtu)
WTI ($/Bbl)
C3+ NGL(2)
($/Bbl) 2016 $2.26 $41 $16 2017 $2.77 $45 $21 2018 $2.87 $47 $24 2019 $2.93 $49 $25 2020 $3.03 $50 $26 2021-25 $3.49 $51-$53 $27
Assumptions Natural Gas – 3/31/2016 strip Oil – 3/31/2016 strip NGLs – 37.5% of Oil Price
2016; 50% of Oil Price 2017+
45 35
2016 Development Plan: Completions
1. 3/31/2016 pre-tax well economics based on a 9,000’ lateral, 3/31/2016 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.
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 well locations as of 12/31/2015. 4. Represents actual results for 1Q 2016. 5. Breakeven price for 15% pre-tax rate of return.
WELL ECONOMICS – MARCELLUS UPSIDE POTENTIAL
Highly-Rich Gas/Condensate Highly-Rich Gas
(4) (4) Wellhead: Processed:
Type Curve Upside Type Curve Upside
ANTERO MIDSTREAM EXERCISES STONEWALL OPTION
• Antero Midstream has exercised its option to acquire a 15% non-operated equity interest in the Stonewall gathering pipeline - Capital investment: $45 million - Expected unlevered IRR: 25% - 35% - Effective date: May 26, 2016
●Another step towards becoming “full value chain” midstream provider
- Fixed fee revenues with minimum volume commitments
●Antero Resources is an anchor shipper with the ability to transport up to 1.1 Bcf/d of gas on a firm basis (900 MMcf/d minimum volume commitment) to more favorably priced markets including TCO, NYMEX and Gulf Coast markets
- Currently transporting ~950 MMcf/d
Stonewall Gathering Pipeline Option
Throughput Capacity: 1.4 Bcf/d
Pipeline Specifications: 67 miles of 36-inch pipeline
Project Capital: ≈ $400 Million
In-Service Date: 12/1/2015
AR Firm Commitment: 900 MMcf/d 8
Stonewall Gathering Pipeline Asset Details
Key Variable Original
2016 Guidance Updated
2016 Guidance
Financial:
Net Income ($MM) N/A $165 - $190
Adjusted EBITDA ($MM) $300 - $325 $325 - $350
Distributable Cash Flow ($MM) $250 - $275 $275 - $300
Year-over-Year Distribution Growth 28% - 30% 30%
Operating:
Low Pressure Pipeline Added (Miles) 9 9
High Pressure Pipeline Added (Miles) 22 22
Compression Capacity Added (MMcf/d) 240 240
Fresh Water Pipeline Added (Miles) 30 30
Capital Expenditures ($MM):
Gathering and Compression Infrastructure $240 $240
Fresh Water Infrastructure $40 $40
Advanced Wastewater Treatment $130 $130
Stonewall Gathering Pipeline Option NA $45
Maintenance Capital $25 $25
Total Capital Expenditures ($MM) $435 $480
ANTERO MIDSTREAM – UPDATED 2016 GUIDANCE Key Operating & Financial Assumptions
9
Sustainable Business
Model
High Growth Sponsor Drives AM Throughput
and Distribution Growth
Largest Dedicated Core Liquids-Rich Acreage Position in Appalachia
$800 Million of AM Liquidity
10
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
High Visibility
Sponsor Strength
LEADING UNCONVENTIONAL MIDSTREAM BUSINESS MODEL
“Just-in-time”
Non-Speculative Capital Program
Strong Financial Position
Mitigated Commodity
Risk
1
2 3
4
5
6 7
8
Premier Appalachian Midstream Partnership
Run by Co-Founders
Hedges Bolster Solid
Well Economics
0
500
1,000
1,500
2,000
2,500
3,000
3,500
0200400600800
1,0001,2001,4001,6001,8002,000
EQT AR CHK COG SWN RRC CNX
-
100
200
300
400
500
600
AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6
Core Net Acres - Dry Core Net Acres - Liquids-Rich
Top Producers in Appalachia (Net MMcfe/d) – 1Q 2016(1)(2) Top 12 U.S. Natural Gas Producers (Net MMcf/d) – 1Q 2016(1)
Appalachian Producers by Proved Reserves (Bcfe) – YE 2015(1)(2) Appalachian Producers by Core Net Acres (000’s) – December 2015(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. Includes proved reserves categorized in “Northern Division” consisting of Utica Shale, Marcellus Shale and Powder River Basin. 4. Based on Antero geologic interpretation supported by state well data, company presentations and public land data. Peer group includes CNX, COG, EQT, RRC, SWN, CHK.
(3)
11
2nd Largest Appalachian Producer in
1Q ‘16
Antero has the largest proved reserve base, largest core liquids-rich acreage position and is one of the largest producers in the Appalachian Basin
Appalachian Peers
8th Largest U.S. Gas Producer in
1Q ‘16
Largest Proved Reserve Base In
Appalachia Largest Liquids-Rich Core Position
in Appalachia
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
AR EQT RRC COG CNX CHK SWN
SPONSOR STRENGTH – LEADERSHIP IN APPALACHIAN BASIN
$198 $341
$434
$649
$1,164
$1,374
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
$1,600
2010 2011 2012 2013 2014 2015 2016E
$1,221
0
10,000
20,000
30,000
40,000
50,000
60,000
2010 2011 2012 2013 2014 2015 2016E
NGLs (C3+) Oil Ethane
5 246 6,436
23,051
48,298
66,000
37% Growth Guidance
1. Represents Bloomberg street consensus estimates as of 5/27/2016.
1,750
2,100
0
600
1,200
1,800
2,400
2010 2011 2012 2013 2014 2015 2016E 2017E
Marcellus Utica Guidance
30 124 239
522
1,007
1,493
12
AVERAGE NET DAILY PRODUCTION (MMcfe/d)
0
50
100
150
200
2010 2011 2012 2013 2014 2015 2016E
Marcellus Utica Deferred Completions
19 38
60
114
177 181
131 110
180
OPERATED GROSS WELLS COMPLETED
AVERAGE NET DAILY LIQUIDS PRODUCTION (Bbl/d)
17% Growth
Guidance
20% Growth Target
Antero is in the unique position of being able to sustain growth and value creation through the price down cycle
CONSOLIDATED EBITDAX ($MM)
Street Consensus(1)
SPONSOR STRENGTH – MOMENTUM THROUGH THE DOWN CYCLE
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 5/27/2016, per RigData.
13
COMBINED TOTAL – 12/31/15 RESERVES
Assumes Ethane Rejection
Net Proved Reserves 13.2 Tcfe Net 3P Reserves 37.1 Tcfe Strip Pre-Tax 3P PV-10(1) $11.2 Bn Net 3P Reserves & Resource 50 to 53 Tcfe Net 3P Liquids 1,237 MMBbls % Liquids – Net 3P 20% 1Q 2016 Net Production 1,758 MMcfe/d - 1Q 2016 Net Liquids 68,516 Bbl/d Net Acres(2) 573,000 Undrilled 3P Locations 3,719
OHIO UTICA SHALE CORE
Net Proved Reserves 1.8 Tcfe Net 3P Reserves 7.5 Tcfe Strip Pre-Tax 3P PV-10(1) $2.5 Bn Net Acres 148,000 Undrilled 3P Locations 814
MARCELLUS SHALE CORE
Net Proved Reserves 11.4 Tcfe Net 3P Reserves 29.6 Tcfe Strip Pre-Tax 3P PV-10(1) $8.7 Bn Net Acres 425,000 Undrilled 3P Locations 2,905
WV/PA UTICA SHALE DRY GAS Net Resource 12.5 to 16 Tcf Net Acres 190,000 Undrilled Locations 1,889
012345678
Rig
Cou
nt
Operators
SW Marcellus + Utica Rigs(3)
SPONSOR STRENGTH – MOST ACTIVE OPERATOR AR is operating 23% of all rigs running and 58% of rigs running in liquids rich core areas in Appalachia
$1 $5 $7 $8 $11
$19 $28
$36 $41
$55
$83 $80
$0$10$20$30$40$50$60$70$80$90
$100
10 38 80 126 266
531
908
1,134 1,197 1,216 1,195 1,222
0200400600800
1,0001,2001,4001,6001,800 Utica Marcellus
108 216 281 331 386
531
738
935 965 1,038
1,124
1,303
0
200
400
600
800
1,000
1,200
1,400
1,600 Utica Marcellus
26 31 40 36 41 116
222
358
454 435 478
606
0
100
200
300
400
500
600
700
800 Utica Marcellus
Low Pressure Gathering (MMcf/d)
Compression (MMcf/d)
High Pressure Gathering (MMcf/d)
EBITDA ($MM)
14
$338
Note: Y-O-Y growth based on 1Q’15 to 1Q’16. 1. Represents midpoint of updated 2016 guidance.
GROWTH – HIGH GROWTH MIDSTREAM THROUGHPUT
$215
$0.170 $0.180 $0.190 $0.205
$0.235
1.1x
1.2x 1.3x
1.4x
1.8x
1.6x
0.0x
0.2x
0.4x
0.6x
0.8x
1.0x
1.2x
1.4x
1.6x
1.8x
2.0x
$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 1Q16A 2Q16E 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E
Distribution Per Unit (Left Axis) DCF Coverage (Right Axis)
$0.220
15
• Antero Midstream is targeting 28% to 30% annual distribution growth through 2017 • AM has delivered on those targets with DCF coverage of 1.6x in the first quarter of 2016
Note: Future distributions subject to AM Board approval. 1. Assumes midpoint of target distribution growth range. 2. 1Q 2016 distribution per Partnership press release dated 4/14/2016.
(2)
GROWTH – TOP TIER DISTRIBUTION GROWTH
(1)
GROWTH – ORGANIC GROWTH STRATEGY DRIVES VALUE CREATION
16
• Organic growth strategy provides attractive returns and project economics, while avoiding the competitive acquisition market and reliance on capital markets
• Industry leading organic growth story
– ~$1.9 billion in capital spent through 09/30/2015 on gathering and compression and water assets
– $410 million in additional growth capital forecast for the twelve-month period ending 12/31/16 (excludes $25 million of maintenance capital)
– 5-year identified investment opportunity set of $3.0 billion
Note: Precedent data per IHS Herold’s research and public filings. 1. Antero organic multiple calculated as estimated gathering and compression and water capital expended through Q3 2015 divided by midpoint of 2016 EBITDA guidance of $325 to $350 million,
assuming 12-15 month lag between capital incurred and full system utilization. 2. Selected gathering and compression drop down acquisitions since 1/1/2012. Drop down multiples are based on NTM EBITDA. Source: Barclays.
5.5x
11.5x
10.8x 10.5x
9.3x 9.0x 8.8x 8.7x 8.6x 8.6x
8.2x 7.9x 7.8x
6.9x
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: 8.8x
Value creation for the AM unit holder = Build at 4x to 7x EBITDA
vs. Drop Down / Buy at 8x to 12x EBITDA
LP Gathering
HP Gathering Compression
Condensate Gathering
Fresh Water Delivery
Advanced Wastewater Treatment
Stonewall Gathering Pipeline
Processing/ Fractionation
Unlevered IRR Range: 25% - 35% 15% - 25% 10% - 20% 25% - 35% 30% - 40% 15% - 25% 25% - 35% 15% - 20% Payout (Years): 2.5 - 4.0 3.5 - 4.5 4.0 - 6.5 2.0 - 3.5 2.0 – 3.0 6.0 - 8.0 2.0 - 3.5 5.0 - 6.0 Minimum Volume Commitments: N/A 75% 70% N/A Yes N/A 80% 80%
2016 Expansion Capex(2) Total
Marcellus $433 $33 $49 $143 - $33 $130 $45 Utica 22 7 1 7 - 7 - -
Growth Capex $455 $40 $50 $150 $0 $40 $130 $45 % of Capex 100% 9% 11% 33% 0% 9% 28% 10%
Included in 2016 Budget: Marcellus & Utica
Marcellus & Utica
Marcellus & Utica
Utica Marcellus & Utica
Marcellus & Utica
Marcellus Not Included
5-year identified investment opportunity set
$3.0 B 30% - 35% 15% - 20% 30% - 35% 0% 8% - 12% 6% - 8% 1%
Additional In-hand Opportunities:
Dry Utica Dry Utica
Dry Utica Utica Stabilization
Dry Utica Dry Utica Marcellus Processing/
Fractionation
25%
15%
10%
25%
30%
15%
25%
15%
35%
25%
20%
35%
25% 25%
40%
20%
0%
10%
20%
30%
40%
Inte
rnal
Rat
e of
Ret
urn
17
Project Economics by Segment(1)
GROWTH – ESTIMATED PROJECT ECONOMICS BY SEGMENT
1. Based on management capex, operating cost and throughput assumptions by project. Capex guidance updated per 2016 Partnership guidance press release. 2. Excludes $25.0 million of maintenance capex. Includes Stonewall option exercise.
Wtd. Avg. 21% IRR
AM Option Opportunities
35%
18 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 5/27/2016. 1. Based on company filings and presentations. Peer group includes Ascent, CHK, CNX, CVX, ECR, EQT, GPOR, NBL, REX, 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 ≈377,000 net acres (> 1100 Btu)
• Represents over 21% of core liquids-rich acreage in Marcellus and Utica plays combined
Antero has over 2,700 undeveloped rich gas locations with an average lateral length of 7,580’ in its 3P reserves as of 12/31/2015
0
100
200
300
400
(000
s)
Core Liquids-Rich Net Acres(1)
LIQUIDS-RICH – LARGEST CORE DRILLING INVENTORY
$1.55 $1.36
$1.14
$0.000
$0.500
$1.000
$1.500
$2.000
2014 2015 Current
$MM
/1,0
00’ L
ater
al
Well Cost ($MM/1,000' of Lateral)
626 971
553 755
63% 47%
24% 28% 35% 24%
10% 13%
0
400
800
1,200
0%
20%
40%
60%
80%
Highly-RichGas/
Condensate
Highly-RichGas
Rich Gas Dry Gas
Tota
l 3P
Loca
tions
RO
R
Total 3P Locations ROR @ 3/31/2016 Strip Pricing - After Hedges ROR @ 3/31/2016 Strip Pricing - Before Hedges
184
98 108
161 263
14%
48% 64% 56% 64%
9%
23% 24% 20% 24%
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. 3/31/2016 pre-tax well economics based on a 9,000’ lateral, 3/31/2016 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.
2. ROR @ 3/31/2016 Strip-With Hedges reflects 3/31/2016 well cost ROR methodology, with the 3/31/2016 hedge value allocated based on 2016-2021 projected production volumes resulting in blend of strip and hedge prices.
3. Current spot well costs based on $8.5 million for a 9,000’ lateral Marcellus well and $10.25 million for a 9,000’ lateral Utica well. 19
UTICA WELL ECONOMICS(1)(2)
74% of Marcellus locations are processable (1100-plus Btu) 68% of Utica locations are processable (1100-plus Btu)
2016 Drilling
Plan
AR multi-year drilling inventory supports low risk, high return growth profile Antero has reduced average well costs for a 9,000’ lateral by 29% in the Marcellus and 26% in the Utica as compared to 2014 well costs At 3/31/2016 strip pricing, Antero has 2,227 locations that exceed a 20% rate of return (excluding hedges)
– Including hedges, these locations generate rates of return of approximately 45% to 65%
Utica Well Cost Improvement(3)
$1.34 $1.18
$0.95
$0.000
$0.500
$1.000
$1.500
$2.000
2014 2015 Current
$MM
/1,0
00’ L
ater
al
Well Cost ($MM/1,000' of Lateral)
SUSTAINABLE BUSINESS MODEL – HEDGES BOLSTER SOLID WELL ECONOMICS
1. Represents inception to date actuals as of 12/31/2015 and 2016 guidance. 2. Includes both expansion capital and maintenance capital. Excludes Stonewall pipeline option.
20
Utica Shale
Marcellus Shale
Projected Gathering and Compression Infrastructure(1) Marcellus
Shale Utica Shale Total
YE 2015 Cumulative Gathering/ Compression Capex ($MM) $981 $462 $1,443
Gathering Pipelines (Miles) 182 91 273
Compression Capacity (MMcf/d) 700 120 820
Condensate Gathering Pipelines (Miles) - 19 19
2016E Gathering/Compression Capex Budget ($MM)(2) $235 $20 $255
Gathering Pipelines (Miles) 30 1 31
Compression Capacity (MMcf/d) 240 - 240
Condensate Gathering Pipelines (Miles) - - -
Gathering and Compression Assets
HIGH VISIBILITY – “JUST IN TIME” GATHERING AND COMPRESSION
• Gathering and compression assets in core of rapidly growing Marcellus and Utica Shale plays
– Acreage dedication of ~442,000 net leasehold acres for gathering and compression services
– Additional stacked pay potential with dedication on ~148,000 acres of Utica deep rights underlying the Marcellus in WV and PA
– 100% fixed fee long term contracts
• AR owns 62% of AM units (NYSE: AM)
21
HIGH VISIBILITY – PROJECTED MARCELLUS MIDSTREAM BUILDOUT
2016 2017 2018+ In-service
22
HIGH VISIBILITY – PROJECTED UTICA MIDSTREAM BUILDOUT
2016 2017 2018+ In-service
HIGH VISIBILITY – “JUST IN TIME” WATER INFRASTRUCTURE
23 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 12/31/2015 and 2016 guidance. 2. All Antero water withdrawal sites are fully permitted under long-term state regulatory permits both in WV and OH. 3. Includes both expansion capital and maintenance capital. 4. Marcellus assumes fee of $3.69 per barrel subject to annual inflation and 351,000 barrels of water per well that utilize the fresh water delivery system based on 9,000 foot lateral. Operating margin excludes
G&A. Utica assumes fee of $3.64 per barrel subject to annual inflation and 306,000 barrels of water per well that utilize the fresh water delivery system based on 9,000 foot lateral. Operating margin excludes G&A.
All of AR’s 570,000 net acres in Appalachia are dedicated to AM for fresh water delivery to well pads and fluid handling and disposal services
Antero Clearwater advanced wastewater treatment facility currently under construction – connects to Antero
freshwater delivery system
Projected Water Business Infrastructure(1) Marcellus
Shale Utica Shale Total
YE 2015 Cumulative Fresh Water Delivery Capex ($MM) $469 $62 $531
Water Pipelines (Miles) 184 75 259
Fresh Water Storage Impoundments 22 13 35
2016E Fresh Water Delivery Capex Budget ($MM)(3) $40 $10 $50
Water Pipelines (Miles) 20 9 29
Fresh Water Storage Impoundments 1 - 1
Cash Operating Margin per Well(4)
$950k - $1,000k
$825k - $875k
2016E Advanced Waste Water Treatment Budget ($MM) $130
2016E Total Water Business Budget ($MM) $180
Water Business Assets • Fresh water delivery assets provide fresh water to support
Marcellus and Utica well completions – Year-round water supply sources: Ohio River, local rivers &
reservoirs(2), Clearwater Facility (under construction) 100% fixed fee long term contracts
• Antero will own and Veolia is building and operating the largest advanced wastewater treatment complex in Appalachia – the Clearwater Facility
7
0
4
0
3
6
02468
AM CNNX EQM CMLP SMLP RMP
Fixed Fee
100%
Fixed Fee
100%
24
MITIGATED COMMODITY RISK – 100% FIXED FEE – RICH TO DRY
Contract Mix
Fixed Fee 98%
Fixed Fee
100%
Fixed Fee
100% Fixed Fee 90%
(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 5/27/2016, per RigData. 3. Includes Antero Resources rigs located in Doddridge County, WV operating on SMLP assets.
Commodity Based
Commodity Based
Appalachian Exposure Marcellus – Dry Marcellus – Rich Utica – Dry
Utica – Rich Water Services
Rigs Running on Midstream Footprint (2)
(3)
AM has no direct commodity price exposure
- 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
Gross Gas Production (BBtu/d)
25
BBtu/d
Antero Resources Transportation Portfolio • Antero Resources has built the largest firm transportation portfolio in Appalachian Basin with 4.85 BBtu/d by year end 2018 • Realized $0.01/Mcfe differential to Nymex gas prices in 1Q16, before hedges
2015 2016E 2017E 2018E Favorable: Chicago MichCon Gulf Coast NYMEX TCO
AR Increasing Access to Favorable Markets
Less favorable: TETCO M2 Dominion South
74%
26%
99%
1%
97%
3%
97%
3%
(Stonewall/WB) Mid-Atlantic/NYMEX
(Stonewall/TGP) Gulf Coast
(TCO) Appalachia or Gulf Coast
Appalachia Appalachia
(REX/ANR/NGPL/MGT) Midwest
(ANR/Rover) Gulf Coast
MITIGATED COMMODITY RISK – FIRM TRANSPORTATION & SALES PORTFOLIO
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$0
$50
$100
$150
$200
$250
$300
$350
$MM
26
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 the amount of time for well payouts, thereby
enhancing liquidity Antero has realized $2.1 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 3/31/2016, the unrealized commodity derivative value is $3.1 billion ● Significant additional hedge capacity remains under the credit facility hedging covenant for 2020 – 2022 period
Quarterly Realized Hedge Gains / (Losses)
Realized Hedge Gains Projected Hedge Gains
NYMEX Natural Gas Historical Spot Prices
($/MM
Btu)
NYMEX Natural Gas Futures Prices 03/31/16
3.6 Tcfe Hedged at average price of
$3.71/Mcfe through 2022
Average Hedge Prices ($/MMBtu)
$3.36
$3.91 $3.57
$3.91 $3.70 $3.66
$3.24
$3.1 Billion in Projected Hedge
Gains Through 2022 Realized $2.1 Billion in Hedge Gains
Since 2009
MITIGATED COMMODITY RISK – HEDGING INTEGRAL TO BUSINESS MODEL
(1)
1. Represents average hedge price for nine months ending 12/31/2016.
Regional Gas Pipelines
Miles Capacity In-Service
Stonewall Gathering Pipeline
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. Antero Midstream has a right of first offer on 143,000 dedicated net acres for processing and fractionation.
End Users
End Users
Gas Processing
Y-Grade Pipeline
Long-Haul Interstate
Pipeline
Inter Connect
NGL Product Pipelines
Fractionation
Compression
Low Pressure Gathering
Well Pad
Terminals and
Storage
(Miles) YE 2015 YE 2016E
Marcellus 106 114
Utica 55 56
Total 161 170
AM has option to participate in processing, fractionation,
terminaling and storage projects offered to AR
(Miles) YE 2015 YE 2016E
Marcellus 76 98
Utica 36 36
Total 112 134
(MMcf/d) YE 2015 YE 2016E
Marcellus 700 940
Utica 120 120
Total 820 1,060
AM Owned Assets
Condensate Gathering Stabilization
(Miles) YE 2015 YE 2016E
Utica 19 19
End Users
(Ethane, Propane, Butane, etc.)
27
VALUE CHAIN OPPORTUNITY – FULL MIDSTREAM VALUE CHAIN
AM Option Opportunities (2)
AM recently exercised its option on 15% interest in Stonewall, adding a regional gas gathering pipeline to its portfolio
Note: All balance sheet data as of 3/31/2016. 1. Mark-to-market as of 3/31/2016. 2. Based on AR ownership of AM units (108.9 million common and subordinated units) and AM’s closing price as of 5/27/2016. 3. AR credit facility commitments of $4.0 billion, borrowing base of $4.5 billion.
Liquid “non-E&P assets” of $5.8 Bn significantly exceeds total debt of $4.1 Bn
Liquidity
Antero Resources (NYSE:AR) Antero Midstream (NYSE:AM)
3/31/2016 Debt Liquid Non-E&P Assets 3/31/2016 Debt Liquid Assets
Debt Type $MM Credit facility $680
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 $4,055
Asset Type $MM Commodity derivatives(1) $3,073
AM equity ownership(2) 2,722
Cash 26
Total $5,821
Asset Type $MM Cash $26
Credit facility – commitments(3) 4,000
Credit facility – drawn (680)
Credit facility – letters of credit (702)
Total $2,644
Debt Type $MM Credit facility $680
Total $680
Asset Type $MM Cash $14
Total $14
Liquidity
Asset Type $MM Cash $14
Credit facility – capacity 1,500
Credit facility – drawn (680)
Credit facility – letters of credit -
Total $834
Approximately $2.6 billion of liquidity at AR plus an additional $2.4 billion of AM units
Approximately $800 million of liquidity at AM
28
Only 45% of AM credit facility capacity drawn
STRONG FINANCIAL POSITION – STRONG BALANCE SHEET AND FLEXIBILITY
0.0x0.5x1.0x1.5x2.0x2.5x3.0x3.5x4.0x4.5x
Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7
Tota
l Deb
t / L
TM A
djus
ted
EBIT
DA
• $1.5 billion revolver in place to fund future growth capital (5x Debt/EBITDA Cap)
• Liquidity of $834 million at 3/31/2016
• Sponsor (NYSE: AR) has Ba2/BB corporate debt ratings
AM Liquidity (3/31/2016)
AM Peer Leverage Comparison(1)
($ in millions)
Revolver Capacity $1,500
Less: Borrowings 680
Plus: Cash 14
Liquidity $834
1. As of 3/31/2016. Peers include TEP, EQM, WES, RMP, SHLX, DM, and CNNX. 2. AM includes full year EBITDA contribution from water business.
Financial Flexibility
29
(2)
STRONG FINANCIAL POSITION – SIGNIFICANT FINANCIAL FLEXIBILITY
TOP TIER DISTRIBUTION GROWTH & HEALTHY COVERAGE
30
3–Year Street Consenus Distribution Growth Rate and DCF Coverage(1)
1. Based on Bloomberg 2015-2018 Bloomberg consensus estimates as of 3/31/2016.
31%
26% 25% 25% 23%
19%
15% 13% 12%
8%
1.5x
1.3x
1.4x
1.8x
1.3x 1.4x
1.2x
1.3x 1.3x
1.2x
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%
35%
SHLX PSXP AM VLP DM EQM TEP MPLX CNNX WES
Low Cost Marcellus/Utica Focus
“Best-in-Class” Distribution Growth
31
CATALYSTS
• 30% for 2016 and 28% to 30% for 2017 targeted based on Sponsor planned development; additional third party business expansion opportunities
• AM Sponsor is the most active operator in Appalachia; • 17% production growth guidance for 2016 supported by $1.4 billion
capital budget, firm processing and takeaway, long-term natural gas hedges and $2.6 billion of liquidity
• Targeting 20% production growth in 2017
• 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, water, and downstream value chain buildout
Appalachian Basin Midstream Growth
High Growth Sponsor Production Profile
1
2
3
4
5
6
• Acquisition of integrated water business from AR expected to result in distributable cash flow per unit accretion in 2016
Consolidation and Stacked Pay
Upside
• AR plans to continue to consolidate Marcellus/Utica acreage • Development of Utica Shale Dry Gas resource will provide further
midstream infrastructure expansion opportunities
Integrated Water Business Drop Down
APPENDIX
32
AM UPSIDE OPPORTUNITY SET
33
ACTIVITY CURRENTLY DEDICATED TO AM
Third Party Business
Processing, Fractionation, Transportation and Marketing
• 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 • 148,000 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
AR Acreage Consolidation • Future acreage acquisitions by AR are dedicated to AM • Added 92,000 net acres in 2014 and 26,000 net acres in
2015
2016 UPDATED CAPITAL BUDGET
By Area
34
$423 Million – 2015(1)
By Segment ($MM)
$349
$6
$55 $13
Gathering & Compression Fresh Water InfrastructureAdvanced Wastewater Treatment Maintenance Capital
74%
26%
Marcellus Utica
By Area
$480 Million – 2016 By Segment ($MM)
Antero Midstream’s 2016 updated capital budget is $480 million, a 13% increase from 2015 capital expenditures of $423 million
13%
130 Completions
1. Excludes $1.05 billion water drop down in September 2015. Water capex values only from 4Q 2015.
$240
$40
$130
$45 $25
Gathering & Compression Fresh Water InfrastructureAdvanced Wastewater Treatment Stonewall PipelineMaintenance Capital
95%
5%
Marcellus Utica
ANTERO MIDSTREAM ASSETS – RICH GAS MARCELLUS
35
• 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 five drilling rigs in the Marcellus Shale during 2016, including intermediate rigs
− 100% of rigs targeting the highly-rich gas/condensate and highly-rich gas regimes
• All 80 gross wells targeted to be completed in 2016 are in the AM dedicated area
− AM dedicated acreage contains 2,126 gross undeveloped Marcellus locations
• Antero will defer an additional 62 completions, with 20 being wells dedicated to a third-party midstream provider that were originally scheduled for completion in 2016 but will now be carried into 2017, in order to limit natural gas volumes sold into unfavorable pricing markets
Marcellus Gathering & Compression
Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.
YE 2015 YE 2016E
Low Pressure Gathering Pipelines (Miles)
106 114
High Pressure Gathering Pipelines (Miles)
76 98
Compression Capacity (MMcf/d) 700 940
36
• 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 two drilling rigs in the Utica Shale during 2016, including intermediate rigs
− 100% of rigs targeting the highly-rich gas/condensate and highly-rich gas regimes
• All 30 gross wells targeted to be completed in 2016 are on Antero Midstream’s footprint
• Antero will defer an additional 8 completions in order to limit natural gas volumes sold into unfavorable pricing markets
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 2015 YE 2016E
Low Pressure Gathering Pipelines (Miles)
55 56
High Pressure Gathering Pipelines (Miles)
36 36
Condensate Pipelines (Miles) 19 19
Compression Capacity (MMcf/d) 120 120
010,00020,00030,00040,00050,00060,00070,00080,000
Antero Clearwater Advanced Wastewater Treatment Capacity (Bbl/d)
Produced/Flowback Volumes (Bbl/d)
Illustrative Produced & Flowback Water Volumes Advanced Wastewater Treatment
Antero Produced Water Services and Freshwater Delivery Business
Antero Advanced Wastewater Treatment
3rd Party Recycling and Well Disposal
(Bbl/d)
Advanced Wastewater Treatment Complex Estimated capital expenditures ($ million)(1) ~$275 Standalone EBITDA at 100% utilization(2) ~$55 – $65 Implied investment to standalone EBITDA build-out multiple ~4x – 5x Estimated per well savings to Antero Resources ~$150,000 Estimated in-service date Late 2017 Operating capacity (Bbl/d) 60,000 Operating 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
37 Integrated Water Business
Antero Advanced Wastewater Treatment
Freshwater delivery system
Flowback and produced
Water
Well Pad
Well Pad
Completion Operations
Producing
Freshwater
Salt
Calcium Chloride
Marketable byproduct
Marketable byproduct used in oil and gas operations
Freshwater delivery system
ANTERO MIDSTREAM ADVANCED WASTEWATER TREATMENT ASSET OVERVIEW
EQM
DM SHLX
CNNX WES
TEP MPLX
PSXP VLP
0.0%
1.0%
2.0%
3.0%
4.0%
5.0%
6.0%
7.0%
8.0%
9.0%
10.0%
3% 8% 13% 18% 23% 28% 33%
Yiel
d (%
)
2016-2018 Distribution Growth CAGR Bubble Size Reflects Market Capitalization
ATTRACTIVE VALUE PROPOSITION
38
AM – 03/31/15 Yield: 4.03%
Price: $21.81
AM - Implied Yield: 2.85% Price: $30.84
• Attractive appreciation potential on a relative basis
1. Based on Bloomberg 2015-2018 Bloomberg consensus distribution estimates and market data as of 3/31/2016.
R-squared = 88%
LARGEST FIRM TRANSPORTATION AND PROCESSING PORTFOLIO IN APPALACHIA
Antero Long Term Firm Processing & Takeaway Position (YE 2018) – Accessing Favorable Markets
Mariner East 2 62 MBbl/d Commitment
Marcus Hook Export
Shell 20 MBbl/d Commitment
Beaver County Cracker (2)
1. May 2016 and full year 2016 futures basis, respectively, provided by Intercontinental Exchange dated 3/31/2016. 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)
$(0.03) / $(0.03)
CGTLA(1)
$(0.06) / $(0.06)
TCO(1)
$(0.11) / $(0.14)
39
Cove Point LNG 4.85 Bcf/d Firm Gas Takeaway
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 $0.46/MMBtu and positive weighted average basis differential to NYMEX after assumed Btu uplift for gas
YE 2018 Gas Market Mix Antero 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)
Sabine Pass (Trains 1-4) 50 MMcf/d per Train
(T1 in-service)
Lake Charles LNG(3)
150 MMcf/d
Freeport LNG 70 MMcf/d
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 and Projected(1)
40
Shell Beaver County Cracker (Pending FID 2H 2016)
Mariner East 2 62 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 in 2017 as pipeline options to domestic markets and export terminals go in-service (Mariner East)
(MMBbl/d)
Mariner West 50 MBbl/d C2
Chart 10: The bulk of NGLs is currently produced in the Gulf Coast
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
41
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/d 1.3
1.0
0.7
0.3
-0.3
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. petrochem demand 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
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Northeast Ethane
Rejection
Exports
U.S. PetChem
LTM ProductionNTM Production ForecastAverage LTM Production
MAINTENANCE CAPITAL METHODOLOGY • Maintenance Capital Calculation Methodology – Low Pressure Gathering
– 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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• Maintenance Capital Calculation Methodology – Fresh Water Distribution − Estimate the number of wells to which we would need to distribute fresh water during the forecast period in order to maintain
the average fresh water throughput volume on our system over the LTM period − (1) Compare this number of wells to the total number of new wells to which we expect to distribute fresh water during such
period, and − (2) Designate an equal percentage of our estimated water line capital expenditures as maintenance capital expenditures
ANTERO RESOURCES EBITDAX RECONCILIATION
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EBITDAX Reconciliation
($ in millions) Quarter Ended LTM Ended 3/31/2016 3/31/2016
EBITDAX: Net income including noncontrolling interest $10.7 $591.5 Commodity derivative fair value (gains) (279.9) (1,901.9) Net cash receipts on settled derivatives instruments 324.3 996.1 Interest expense 63.3 244.4 Income tax expense (benefit) 4.8 333.3 Depreciation, depletion, amortization and accretion 192.2 720.9 Impairment of unproved properties 15.5 111.3 Exploration expense 1.0 3.5 Equity-based compensation expense 23.5 93.6 State franchise taxes 0.0 (0.1) Contract termination and rig stacking 0.0 29.6 Consolidated Adjusted EBITDAX $355.4 $1,222.2
ANTERO MIDSTREAM EBITDA RECONCILIATION
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EBITDA and DCF Reconciliation
$ in thousands Three months ended
March 31, 2015 2016 Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow: Net income $32,327 $42,918 Add: Interest expense 1,586 3,461 Depreciation expense 20,702 23,823 Contingent acquisition consideration accretion - 3,396 Equity-based compensation 5,779 5,972 Adjusted EBITDA $60,394 $79,570
Pre-Water Acquisition net income attributed to parent (16,679) -
Pre-Water Acquisition depreciation expense attributed to parent (6,120) -
Pre-Water Acquisition equity-based compensation expense attributed to parent (1,156) -
Pre-Water Acquisition interest expense attributed to parent (763) -
Adjusted EBITDA attributable to the Partnership 35,676 79,570
Less:
Cash interest paid - attributable to Partnership (579) (3,444) Cash reserved for payment of income tax witholding upon vesting of Antero Midstream LP equity-based compensation awards - (1,000) Maintenance capital expenditures attributable to Partnership (2,408) (5,808)
Distributable Cash Flow
$32,689 $69,318
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, 2015 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, 2015. 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 be potentially 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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