MLPA 2017 Investor Conference
June 1, 2017
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, 2017. 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.
2
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.
Antero Simplified Organizational Structure
3 Note: Enterprise Value as of May 30, 2017. AR enterprise value excludes minority interest.
100% Incentive
Distribution Rights (IDRs)
Public
(NYSE: AMGP) Enterprise Value : $4.1 Bn
(NYSE: AM) Enterprise Value : $7.3 Bn
(NYSE: AR) Enterprise Value: $10.5 Bn
80% 20%
Affiliates Affiliates
59%
32%
Public
68%
41% Public
The combined enterprise value of the Antero complex is over $18 billion
Delivering on Antero IPO Promises
4
At IPO (October 2013)
1. Represents 2Q 2013 and 1Q 2017 net production, respectively. 2. Represents consolidated LTM EBITDAX as of 6/30/2013 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.
Net Production (1):
458 MMcfe/d 2,144 MMcfe/d
Acreage:
Current
$457 Million $1,546 Million LTM EBITDAX (2):
431,000 Net Acres
+368%
+238%
+68%
634,000 Net Acres(6) +47%
Leading consolidator since AR IPO adding
203,000 net acres
Growth
Distribution / Coverage:
Gathering Throughput(5):
LTM EBITDA(4):
$0.17 (MQD) Target: 1.1x – 1.2x $0.30 / Actual: 1.4x
Low Pressure: 532 MMcf/d Low Pressure: 1,659 MMcf/d
$45 $444
+76%
+887%
+212% 4. For the three months ended 9/30/2014, annualized and 3/31/17, respectively. 5. For the three months ended 9/30/2014 and 3/31/2017, respectively. 6. Net acres as of 12/31/2016, pro forma for additional leasing and acquisitions.
At IPO (November 2014) Current
27.7 Tcfe 46.4 Tcfe 3P Reserves (3):
Most Integrated Natural Gas and NGL Story in the U.S.
5
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% ROR @ $3.00/MMbtu or less - Largest firm transport portfolio delivers NYMEX-plus pricing - 85% of target natural gas production hedged through 2020 @
$3.72/MMbtu 3. Strong balance sheet and financial liquidity (Ba2 / BB)
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 2026
3. 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, 3rd party business,
stacked pay drilling, acreage additions
A Leading Northeast Infrastructure Platform
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.
Organic Growth Drives the Business
6
6.9x 6.1x
4.5x 4.4x
0.0x
2.0x
4.0x
6.0x
8.0x
10.0x
12.0x
2014 2015 2016 2017E DropDown
• Organic growth strategy provides attractive returns while avoiding the competitive acquisition market and reliance on capital markets
• 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
Organic Adjusted EBITDA Multiple vs. Drop Down Multiples
Drop Down Median: 8.8x
AM Organic EBITDA Multiple(1)
AM Builds at 3x to 6x EBITDA vs.
Other MLPs that Drop Down/Buy at 8x to 12x+ EBITDA
Antero Midstream Project Unlevered IRRs
25%
15%
10%
30%
15% 15%
35%
25%
20%
40%
25%
18%
0%5%
10%15%20%25%30%35%40%45%
LPGathering
HPGathering
Compression FreshWater
Delivery
AdvancedWastewaterTreatment
Processing/Fractionation
Inte
rnal
Rat
e of
Ret
urn
Wtd. Avg. 24% IRR
(2)
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 12-15 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.
Capturing the Midstream Value Chain
7
Upstream Downstream
~$4.2 Billion Organic Project Backlog
~$800 Million JV Project Backlog
WELL PAD
LOW PRESSURE GATHERING
HIGH PRESSURE GATHERING
COMPRESSION
GAS PROCESSING
(50% INTEREST)
REGIONAL GATHERING
PIPELINE (15% INTEREST)
FRACTIONATION TERMINALS & STORAGE
Y-GRADE PIPELINE
(ETHANE, PROPANE, BUTANE)
NGL PRODUCT PIPELINES
LONG HAUL PIPELINE
INTERCONNECT
END USERS
PDH PLANT
• 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
~$1.0 Billion Downstream Investment
Opportunity Set
Note: Third party logos denote company operator of respective asset.
AM Assets AM/MPLX JV Assets Potential AM Opportunities
NGL Infrastructure Buildout in the Northeast
8
Mariner West (50 Mbbl/d C2)
Mariner East (70 Mbbl/d)
61,500 MBbl/d Mariner East 2
Antero / MPLX Joint Venture (1)
1. Represents processing and fractionation joint venture between Antero Midstream and MPLX LP that was announced February 6th, 2017.
• Over $4 Billion of downstream NGL infrastructure projects currently under construction or proposed for the Northeast adjacent to Antero’s position
Utopia (50 Mbbl/d C2) (1Q 2018)
The Northeast NGL infrastructure buildout
potentially presents additional investment opportunities
9
Antero Resources – Sponsor Strength
$198 $341 $434
$649
$1,164 $1,221
$1,536 $1,540
$2,236
$0
$400
$800
$1,200
$1,600
$2,000
$2,400
2010 2011 2012 2013 2014 2015 2016 2017E 2018E$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$1,164
10
10
17
26
35 41
37
46
05
101520253035404550
2010 2011 2012 2013 2014 2015 2016
Actual 2.7
0.0 0.1 0.2 0.5
1.0
1.5
1.8
2.2
0.0
0.5
1.0
1.5
2.0
2.5
3.0
2010 2011 2012 2013 2014 2015 2016 2017E 2018E
Marcellus Utica
1. 2016 acreage count represents year-end 2016 net acres pro forma for any 2017 acreage acquisitions to date. 2. 2012, 2013, 2014 and 2015 reserves assuming ethane rejection. 2016 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 1/4/2017. 4. Represents Henry Hub spot price from 1/1/2010 through 03/31/2017.
Guidance(3)
Antero Resources has uniquely sustained growth and value creation through the down cycle
Henry Hub Gas Price(4) $/MMBtu
162 214
371 450
543 569
634(1)
0
100
200
300
400
500
600
700
2010 2011 2012 2013 2014 2015 2016
Marcellus Utica Proved Probable Possible
Growth Through the Down Cycle
Net Acres (000’s) Net 3P Reserves (Tcfe) (2)
Consolidated Adjusted EBITDAX ($MM) Average Net Daily Production (Bcfe/d)
Target Consensus(5)
5. Based on consensus estimates as of 5/30/17.
11
A Leading Consolidator in Appalachia
46,500 net acres – Sept. 2016
3,900 net acres – Dec. 2016
6,200 net acres – Jan. 2017 10,100 net acres – Dec. 2016
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
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
Acquisitions Since 1/1/2016 Activity
11,000 net acres – May 2017
Largest Core Acreage Position in Appalachia
604
464 458
366
238 226 221 216 186 177 167 155
-
100
200
300
400
500
600
700Core - NE Pennsylvania Dry Net Acres
Core - SW Marcellus & Utica Dry Net Acres
Core - Marcellus & Utica Liquids Rich Net Acres
Cor
e N
et A
cres
(000
s)
Largest Core Acreage Position in Appalachia (1)
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 5/19/2017. 1. Peers include Ascent, CHK, CNX, COG, CVX, EQT, GPOR, HG Energy, RICE, RRC, and SWN.
Antero has the largest core acreage position in Appalachia and the largest liquids-rich position
31 Utica Rigs
15 Marcellus Rigs
74 Total Rigs
12
31 Marcellus Rigs
Yields Largest Core Drilling Inventory In Appalachia
13
3,502
1,967 1,937
1,161
913 867 824 736 692 683 635 548
-
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
AR A B C D E J H K F L I
Und
rille
d Lo
catio
ns
Core - NE Pennsylvania Dry Locations Core - SW Marcellus and Ohio Utica Dry Locations Core - Marcellus & Ohio Utica Liquids-Rich Locations
1. 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.
Undrilled Core Marcellus and Utica Locations (1)(2)
Large, repeatable core drilling inventory that averages 8,000’ in lateral length and includes 43% of all liquids-rich undrilled locations in Appalachia
Core Liquids-Rich Appalachia Undrilled Locations (1)
*
* *
* *
Avg. Lateral Length 8,081’ 6,429’ 6,355’ 7,762’ 8,601’ 5,758’ 8,594’ 9,262’ 7,085’ 7,550’ 8,880’ 6,225’
43%
B 13%
C 10%
J 8%
E 6%
F 6%
A 4%
D 3%
K 3%
H 2%
I 2%
Substantial Drilling Inventory at Low Breakeven Prices
14
247
1,091
1,815
2,595
3,478 3,670 3,704
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
$1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.00
Loca
tions
Marcellus Rich Gas Marcellus Dry Gas Ohio Utica Rich Gas Ohio Utica Dry Gas
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.
Marcellus Rich Gas
Marcellus Dry Gas
Ohio Utica Rich Gas
< < < < < < <
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)
~70% of total locations generate a 20% rate of return at
$3.00/MMbtu NYMEX or less
~30% of total locations generate a 20% rate of return at
$2.00/MMbtu NYMEX or less
8,253’ 8,062’ 8,177’ 8,607’ 8,630’ 9,109 9,229’
Average Lateral Length
Ohio Utica Dry Gas
NYMEX Natural Gas Price ($/MMBtu)
Cumulative 3P Drilling Inventory – Breakeven Prices at 20% ROR (1)(2)
Marcellus Completion Evolution
15
500
750
1,000
1,250
1,500
1,750
2,000
2,250
2,500
2,750
3,000
Ante
ro C
ompl
etio
n Si
ze (l
bs/ft
)
Completion Start Date
Testing higher proppant loads in 2017 – Early results are encouraging
Supports 2.0 Bcf/1,000’ type curve and 81 PUD bookings at
YE2016
0
1,000
2,000
3,000
4,000
5,000
Days
Supports 1.7 Bcf/1,000’ type curve and historical reserve bookings
2,500
2,000
1,750
1,500
Antero is continuing to increase proppant intensity in 2017 primarily utilizing 1,750 and 2,000 lb/ft completions in the Marcellus
Per Well Frac Size Design (lb/ft)
1,250
1,500
1,750
2,000
2,500
1.5
1.7
2.0 1,750 lb/ft
Completions
1,500 lb/ft Completions
32 Bbl/ft Water
34 Bbl/ft Water
36 Bbl/ft Water
42 Bbl/ft Water
48 Bbl/ft Water
Recent Marcellus Well Results
16
Dry Gas High-Graded Core Average 2.2 Bcf / 1,000’
Wellhead EUR
Southern Rich High-Graded Core
Average 2.0 Bcf / 1,000’ Wellhead EUR
Antero Acreage
Antero Horizontal Marcellus Wells Industry Horizontal Marcellus Wells
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 - 10 Well Average
Advanced 1,700# Completion
Wellhead:
Processed:
C2 Recovery:
Lateral:
Net F&D Cost:
Antero - 4 Well Average
Advanced 1,700# Completion
Wellhead:
Processed:
C2 Recovery:
Lateral:
Net F&D Cost:
2.4 Bcf/1,000’
2.9 Bcfe/1,000’
3.6 Bcfe/1,000’
10,017’
$0.39/Mcfe
2.1 Bcf/1,000’
2.6 Bcfe/1,000’
3.3 Bcfe/1,000’
10,468’
$0.35/Mcfe
Antero - 4 Well Average
Advanced 2,500# Completion
Wellhead:
Processed:
C2 Recovery:
Lateral:
Net F&D Cost:
2.3 Bcf/1,000’
2.6 Bcfe/1,000’
3.2 Bcfe/1,000’
5,365’
$0.47/Mcfe (1)
Antero - 2 Well Average
Advanced 1,750# Completion
Wellhead:
Processed:
C2 Recovery:
Lateral:
Net F&D Cost:
2.3 Bcf/1,000’
2.9 Bcfe/1,000’
3.7 Bcfe/1,000’
11,567’
$0.38/Mcfe
1. Represents actual completion costs and Q1 2017 AFE drilling costs.
Net F&D Cost: $0.38/Mcfe
Net F&D Cost: $0.35/Mcfe
Net F&D Cost: $0.39/Mcfe
Net F&D Cost: $0.45/Mcfe(1)
Rapidly Growing NGL Production
17
19,500
42,500
73,000
86,500
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
2014 2015 2016 2017Guidance
2018ETarget
2019ETarget
2020ETarget
Ethane (C2) C3+ Production Propane (C3) Normal Butane (nC4) IsoButane (iC4) Natural Gasoline (C5+)
1. Excludes condensate. 2. Assumes midpoint of 20 – 22% year-over-year equivalent production growth in 2018-2020. For illustrative purposes C3+ production growth assumed at same rate.
(1)
(Bbl/d)
C5+
iC4
nC4
C3
C2 Ethane
17,476
C2 Ethane 19,000
Antero is the largest NGL producer in the Northeast
(2) (2) (2)
20–22% Y-O-Y
Long-Term Growth Target
NGL Production Growth by Purity Product (Bbl/d)
Liquids Pricing Upgrade in the Marcellus
Gas $3.15 Gas
$3.05 Gas
$3.05
Condensate $0.14
Condensate $0.18
NGLs (C3+) $0.89
NGLs (C3+) $1.12
$0.00$0.50$1.00$1.50$2.00$2.50$3.00$3.50$4.00$4.50$5.00
1050 BTU 1250 BTU /$55 WTI
1250 BTU /$65 WTI
1. Assumes $3.00/MMBtu NYMEX, $55/Bbl to $65/Bbl WTI and NGL prices equal to 52.5% of WTI (midpoint of 2017 guidance). 45 Bbl/MMcf (ethane rejection) recovery for NGLs and 3 Bbl/MMcf for condensate, processing shrink included.
Assuming Ethane Rejection
(1100 BTU Tailgate) 8% shrink
Realized Price Per Mcf(1)
($/Mcf) +$0.90 Upgrade
+$1.17 Upgrade
Rich Gas Dry Gas
$3.00/MMBtu NYMEX
Antero realizes a significant upgrade to assumed $3.00/MMBtu NYMEX gas price by producing liquids-rich gas and condensate
18
$4.32 $4.05
Attractive Liquids-Rich Marcellus Well Economics
19
$5.1 $7.9
$9.7
30%
45%
56%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
$0.0
$6.0
$12.0
$18.0
1.72.1
2.02.5
2.32.8
Unh
edge
d Pr
e-Ta
x R
OR
Pre-
Tax
PV-1
0 ($
MM
)
Pre-Tax PV-10 Pre-Tax ROR
$9.4
$12.4
$15.4
53%
72%
95%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
$0.0
$6.0
$12.0
$18.0
1.72.3
2.02.7
2.33.1
Unh
edge
d Pr
e-Ta
x R
OR
Pre-
Tax
PV-1
0 ($
MM
)
Pre-Tax PV-10 Pre-Tax ROR
1. Assumes ethane rejection. Based on commodity pricing as of 3/31/17. Assumes 9,000’ lateral length.
Processed Bcfe/1,000’:
Integrated platform yields attractive well economics and sustainable growth
2.0 2.7
2.0 2.5
683 Undrilled Locations
Wellhead Bcf/1,000’: Processed Bcfe/1,000’:
1,184 Undrilled Locations
2016 Advanced Completion
Results
1313 Btu 1250 Btu
Wellhead Bcf/1,000’:
Highly-Rich Gas/Condensate (3/31/17 Pricing) (1) Highly-Rich Gas (3/31/17 Pricing) (1)
Largest Firm Transportation Portfolio in the Northeast
20 1. Shell announced final investment decision (FID) on 6/7/2016. 2. Lake Charles LNG 150 MMcf/d commitment subject to Shell FID.
Antero transportation commitments yield NYMEX-plus pricing for natural gas and are expected to yield Mont Belvieu-plus pricing for NGLs
Antero 2.8 Bcf/d Firm Processing 1,400 MMcf/d To Midwest
800 MMcf/d To TCO Pool 689 MMcf/d
4.85 Bcf/d Firm Gas Takeaway
By YE 2018
YE 2018 Gas Market Mix Antero 4.85 Bcf/d FT
44% Gulf Coast
17% Midwest
13% Atlantic
Seaboard
13% Regional
(PA)
13% TCO
Expect NYMEX-
plus pricing per Mcf in aggregate
To Atlantic Seaboard
630 MMcf/d
625 MMcf/d 30 MBbl/d Ethane
Local Petchem
Mariner East 2 (4Q 2017) 62 MBbl/d Commitment
Marcus Hook Export Shell (2021)
30 MBbl/d Commitment Pennsylvania Cracker (1)
Sabine Pass (Trains 1-4) 200 MMcf/d
(T1, T2 and T3 in-service)
Freeport LNG (3Q 2018) 70 MMcf/d
Lake Charles LNG(2)
150 MMcf/d
Cove Point LNG (4Q 2017) 330 MMcf/d
420 MMcf/d LNG Export
330 MMcf/d LNG Export
62 MBbl/d NGL Export
Midwest Markets
Regional Markets
Gulf Coast Markets
Antero Commitments Firm Processing: = 2.8 Bcf/d Firm Gas Takeaway: = 4.85 Bcf/d LNG Firm Sales: (2) = 750 MMcf/d
Firm Ethane Takeaway: = 20 MBbl/d
Ethane Cracker: = 30 MBbl/d Firm NGL Takeaway: = 62 MBbl/d
Antero Long Term Firm Processing & Takeaway Position (YE 2018) – Accessing Favorable Markets
Largest Gas Hedge Position in U.S. E&P
21
2,163 2,015
2,330
710 810
$3.47 $3.91
$3.70 $3.63 $3.31 $3.18
$3.32 $3.03
$2.83 $2.82 $2.83 $2.84
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
0
400
800
1,200
1,600
2,000
2,400
2017 2018 2019 2020 2021 2022
BBtu/d $/Mcfe Average Index Hedge Price(1) Hedged Volume Current NYMEX Strip(2)
$81 MM $627 MM $702 MM $390 MM $110 MM
Mark-to-Market Value(2)
~ 100% of 2017 Guidance Hedged
$85 MM
~$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
• 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
~ 75% of 2018 Target
Hedged
Commodity Hedge Position
~ 72% of 2019 Target
Hedged
Significant Cash Flow Growth → Declining Leverage
22
$1,536 $1,621
$2,288
1.8
2.2
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
2016A 2017E 2018E 2019E 2020E
Prod
uctio
n G
uida
nce
/ Tar
gets
(Bcf
e/d)
N
et D
ebt/L
TM E
BIT
DAX
Tar
gets
Con
sens
us E
BIT
DAX
Est
imat
es ($
MM
)
Visible cash flow growth given hedges, firm transportation portfolio, and capital efficient long-term development plan targeting 20% to 22% production CAGR
Consensus EBITDAX Production Guidance (Bcfe) Production Targets (Bcfe)
1. Bloomberg Consensus EBITDAX estimates as of 3/31/2017.
Leverage Targets
Declining Leverage
(1)
23
Antero Midstream – High Visibility Growth
Antero Clearwater Facility Expected In Service 4Q 2017
Antero Midstream Asset Overview
24
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
Compressor Station
Antero Clearwater Facility
Sherwood Processing Facility
Note: Infrastructure in service as of year-end 2016. 1. The Antero Clearwater Facility is scheduled to be placed into service in the fourth quarter of 2017.
An integrated system for natural gas and NGL production, gathering and processing
High Growth Midstream Throughput
25
460
1,186 1,316
1,581
- 200 400 600 800
1,000 1,200 1,400 1,600 1,800 2,000
2014 2015 2016 1Q 2017
132
96
123 148
-
50
100
150
200
2014 2015 2016 1Q 2017
104
432
741
1,028
-
200
400
600
800
1,000
1,200
1,400
2014 2015 2016 1Q 2017
498
1,016
1,403
1,659
- 200 400 600 800
1,000 1,200 1,400 1,600 1,800 2,000
2014 2015 2016 1Q 2017
Note: Growth based on 2-year CAGR. All fees are as of year end 2016.
Marcellus Utica
Fixed Fee: $0.31/Mcf Fixed Fee: $0.19/Mcf
Fixed Fee: $0.19/Mcf Fixed Fee: $3.68/Bbl
Low Pressure Gathering (MMcf/d) Compression (MMcf/d)
High Pressure Gathering (MMcf/d) Fresh Water Delivery (MBbl/d)
Antero Midstream Upside Opportunity Set
26
OPPORTUNITY POSITIONING
• Fresh water delivery, waste water treatment and gathering/compression services to capture third party business in Appalachia and enhance asset utilization
• 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
• 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
• Antero leverages its resource and production to provide investment opportunities for AR and AM
• Natural gas and NGL pipelines, terminals and storage
• ~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
• AM has multiple pathways to upside beyond its $5.0 billion organic project backlog
Downstream Infrastructure Buildout 1
AR Acreage Consolidation 2
Third Party Business 3
Upper Devonian 4
WV/PA Utica Dry Gas 5
Long Term Growth Outlook Through 2020
27
$1.03
$1.33
1.8x
1.4x
0.5x
1.0x
1.5x
2.0x
2.5x
3.0x
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
2016A 2017Guidance
2018ETarget
2019ETarget
2020ETarget
DC
F C
over
age
Rat
io a
nd L
ever
age
Rat
io
Dis
trib
utio
n Pe
r Uni
t
DCF Coverage >1.25x
Note: Future distributions subject to Board approval.
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
Distribution Guidance
Distribution Target
DCF Coverage
Stable Leverage
AMGP Highly Levered to AM Distribution Growth
28
$0 $0 $8
$41
$82
$136
$205
$0.00 $0.00 $0.04
$0.22
$0.44
$0.73
$1.10
$0.00
$0.20
$0.40
$0.60
$0.80
$1.00
$1.20
$0
$50
$100
$150
$200
$250
$0.68 $0.80 $1.03 $1.33 $1.71 $2.21 $2.85
AMG
P D
istr
ibut
ions
Per
Sha
re ($
/Sha
re)
AMG
P C
ash
Avai
labl
e fo
r Dis
trib
utio
n ($
MM
)
1. Assumes 185.8 million AM units outstanding as of February 28,2017; Assumes 186.2 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)
AMGP Cash Available for Distribution AMGP Distributions per Share(1)
AM distributions drive IDR cash flow which drives AMGP distributions
AM Distribution Per Unit Hypothetical AM Distribution Growth
Antero Midstream Investment Highlights
29
Combination of High Growth and Yield is Unmatched
Most Integrated Natural Gas and NGL Story in the U.S.
$5 Billion Project Backlog + $1 Billion Downstream Opportunity Set
Cash Flow Driven by Visible Low Risk Production Growth at AR
Fixed-Fee Tolling Business Eliminates Direct Commodity Price Exposure
30
Appendix
Processing and Fractionation JV
31
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
Note: RigData as of 04/14/17. Rigs drilling in rich gas areas only. 1. New West Virginia site location still to be determined.
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 Future Processing Complex
TBD 1 – 6 – Potential – 1,200 MMcf/d (1)
2017 Guidance and Long Term Targets
32
$1.03 $1.33
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
2016E 2017E 2018E 2019E 2020E
Updated 2017 Guidance(2)
DCF Coverage: 1.30x – 1.45x > 1.25x
Distribution Growth(1):
$520 – $560 Peer Leading Growth EBITDA ($MM):
$800 $2.6 Billion organic opportunity set from 2017 – 2020 Capital Expenditures ($MM):
2.0x – 2.5x Low 2-times range Leverage:
2018 - 2020 Long-Term Targets
1. Assumes midpoint of 2017 distribution growth guidance and long-term target. Future distributions subject to Board approval. 2. Per press release dated 2/6/2017.
Guidance
Long Term Targets
2016A
Estimated Project Economics by Segment
33
25%
15%
10%
30%
15% 15%
35%
25%
20%
40%
25%
18%
0%5%
10%15%20%25%30%35%40%45%
Inte
rnal
Rat
e of
Ret
urn
LP Gathering
HP Gathering Compression
Fresh Water Delivery
Advanced Wastewater Treatment
Processing/ Fractionation
Unlevered IRR Range: 25% - 35% 15% - 25% 10% - 20% 30% - 40% 15% - 25% 15% - 18% Payout (Years): 2.5 - 4.0 3.5 - 4.5 4.0 - 6.5 2.0 - 3.0 6.0 - 8.0 5.0 - 6.0 Minimum Volume Commitments: N/A 75% 70% Yes N/A Yes
2017 Capex Total Marcellus $655 $80 $60 $115 $50 $75 $275 Utica 145 45 10 40 25 25 -
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
Project Economics by Segment(1)
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.
Wtd. Avg. 24% IRR
2017 Guidance and Long Term Outlook
34
1.8 2.2
2.7
3.2
3.9
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
2016A 2017E 2018E 2019E 2020E
Net
Dai
ly P
rodu
ctio
n
2017 Guidance
D&C Capital:
$1.3 Billion Flat with prior year
Modest annual increases within Cash Flow from Operations
Production Growth:
In line with D&C capital Doubling by 2020 Consolidated Cash Flow from Operations(1):
3.0x to 3.5x Declining to mid-2s by 2018 Leverage(1):
98% Hedged at $3.51/Mcfe 58% Hedged at $3.76/Mcfe Hedging:
2018 - 2020 Long Term Targets
(Bcfe/d)
$3.47 $3.91
$3.70
$3.66
Hedged Volume (Bcfe) Hedged Price ($/Mcfe)
Guidance Long-Term Targets
$
(2) (2) (2)
Key Appalachian Natural Gas Takeaway Projects
35
Tran
sco
Atla
ntic
Sun
rise
–
M
id-2
018
(1.7
Bcf
/d)
4.8 Bcf/d
4.2 Bcf/d
5.2 Bcf/d
1.8 Bcf/d
Antero Producing
Areas
Source: Public filings and press releases. Excludes TETCO expansions (972 MMcf/d) that are currently under construction. 1. 1.05 Bcf/d capacity available to move gas from Leach to the Gulf on CGT Rayne Xpress. 2. 860 MMcf/d of capacity available on CGT Gulf Xpress to move gas to the Gulf Coast markets.
Antero firm transportation commitment
Growth in natural gas infrastructure by the end of 2019, resulting in 16.8 Bcf/d of incremental capacity, will support expected supply growth
Potential Appalachian Gas Production vs. Future FT – Southwest Portion of the Basin
36 1. Assumes ethane rejection. Based on commodity pricing as of 3/31/17. Assumes 9,000’ lateral length.
0
5
10
15
20
25
30
35
Gro
ss R
esid
ue B
cf/d
and
FT
Cap
acity
Mountain Valley Pipeline
WB Xpress
Atlantic Coast Pipeline Gulf XPress Mountaineer XPress
7/1/18 Δ = 4 Bcf/d
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
Rover Phase 1
Rayne XPress NEXUS Leach XPress Adair Southwest Access South Rover Pipeline Phase2 80 Rigs
56 Rigs - Current
24 Rigs required to hold production flat at 14 Bcf/d
Base Decline of Current Production of 13.5 Bcf/d
56 Rigs - Current + 20% Incremental Rigs per Year
27 Bcf/d
14 Bcf/d
23 Bcf/d
30 Bcf/d
Rig Type Performance (Bcf/1,000') Average LateralDry 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 CountRich Dry Total
SW Marcellus: 14 18 32 Utica: 4 20 24 Grand Total SW: 18 38 56
Current Takeaway Estimated at 13.7 Bcf/d per Bentek
7/1/19 = 6 Bcf/d
(Bcf/d)
$1.34 $1.18
$0.90 $0.87
$1.55 $1.36
$1.05 $1.01
0.0
0.5
1.0
1.5
2.0
2014 2015 2016 Q1 2017
D&
C C
apita
l per
1,0
00' o
f La
tera
l ($M
M)
8,052 8,910 9,196
10,515 8,543
8,575 9,250
10,293
0
2,000
4,000
6,000
8,000
10,000
12,000
2014 2015 2016 Q1 2017 Record
Late
ral L
engt
h (fe
et)
29 24
15 12
9
29 31
17 18
05
1015202530354045
2014 2015 2016 Q1 2017 Record
Dril
ling
Day
s
3.2 3.5 4.0 4.0
3.2 3.7
4.8 4.8
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
2014 2015 2016 Q1 2017 Record
Day
s
Continuous Operating Improvement
37
Increasing Completion Stages per Day
Drilling Longer Laterals
Dramatic Decrease in Drilling Days
Declining Well Costs per 1,000’
Drilling longer laterals while reducing drilling days by 60%
More efficient completions (“zipper fracs”) are increasing
stages per day
Reducing well costs by ~35% since 2014 Continuing to be an industry leader in drilling longer laterals
Driving drilling and completion efficiencies which continues to lower well costs
14,014
10.0
Marcellus Utica
1.8 1.9
2.4 2.5 2.9
1.5 1.8 1.7 1.8
0.0
0.5
1.0
1.5
2.0
2.5
3.0
2014 2015 2016 Q1 2017 RecordProc
esse
d EU
R p
er 1
,000
' of
Lat
eral
(Bcf
e)
Improved Productivity Drives Lower F&D Costs
38 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 85% NRI in Marcellus and 81% NRI in Utica.
Increasing Water Per Foot
Much Lower F&D Cost per Mcfe(2)(3)
Increasing Proppant Per Foot
Increasing EUR per 1,000’ (Bcfe)(1)(2)
Since 2014, Antero has increased EURs by 39% in the Marcellus and 20% in the Utica
Bottom line: F&D costs per Mcfe have declined by 44% in the Marcellus and
28% in the Utica since 2015
Enhanced completion designs have contributed to improved recoveries and capital efficiency
Marcellus Utica
32 33
42 45
62
35 34 37 43
0
10
20
30
40
50
60
70
2014 2015 2016 Q1 2017
Bar
rels
of W
ater
Per
Foo
t
1,165 1,163
1,702 2,055
2,757
1,267 1,298
1,648
2,529
-
500
1,000
1,500
2,000
2,500
3,000
2014 2015 2016 Q1 2017
Poun
ds o
f Pro
ppan
t Per
Foo
t
Higher proppant concentration has contributed to higher recoveries
Higher proppant concentration requires increased water usage
Record Record
$0.88 $0.73
$0.45 $0.41
$1.28
$0.94 $0.78 $0.70
$0.00
$0.50
$1.00
$1.50
$2.00
2014 2015 2016 Q1 2017
F&D
Cos
t per
1,0
00' o
f La
tera
l ($M
M)
Record
Longer Laterals Improve Rates of Return
39
6,500 Foot Lateral(2)
9,000’
Antero 2016 average lateral: 9,000 feet
NOTE: Assumes 2.0 Bcf/1,000’ type curve for the Antero Marcellus Highly-Rich Gas/Condensate (1275 – 1350 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.
6,500’
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 $7.7 MM(1)
11,500 Foot Lateral
Pre-Tax Economics
ROR (%) 83%
PV-10 ($MM) $16.5
Breakeven Nymex ($/MMBtu) $1.01
Dev. Cost ($/Mcfe) $0.35
11,500’
Pre-Tax Economics
ROR (%) 58%
PV-10 ($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) $0.38
Antero Resources EBITDAX Reconciliation
40
EBITDAX Reconciliation
($ 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) 355.3 Net cash receipts on settled derivatives instruments 44.8 723.6 Gain of sale on assets - (97.6) Interest expense 66.7 256.9 Loss on early extinguishment of debt - 16.9 Income tax expense (benefit) 131.3 (369.8) Depreciation, depletion, amortization and accretion 203.4 823.5 Impairment of unproved properties 26.9 174.3 Exploration expense 2.1 8.0 Equity-based compensation expense 25.5 104.4 Equity in earnings of unconsolidated affiliate (2.2) (2.7) Distributions from unconsolidated affiliates - 7.7 Consolidated Adjusted EBITDAX $365.3 $1,546.0
Antero Midstream EBITDA Reconciliation
41
EBITDA and DCF Reconciliation
$ in thousands Three months ended
March 31, 2016 2017 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 equity- based 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
Top Related