Partnership OverviewSeptember 2015
FORWARD-LOOKING STATEMENTSThis presentation contains forward-looking statements. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Antero Midstream Partners LP, and its subsidiaries (collectively, the “Partnership”) expect, believe or anticipate will or may occur in the future are forward-looking statements. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “estimate,” “project,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include expectations of plans, strategies, objectives, and anticipated financial and operating results of the Partnership and Antero Resources Corporation (“Antero Resources”). These statements are based on certain assumptions made by the Partnership and Antero Resources based on 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, 2014 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, 2014 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.
Transaction Specifics
ASSETS:• Antero’s Marcellus and Utica freshwater delivery business, the fully contracted future
advanced wastewater treatment complex and 20-year agreement to cover all fluid handling and disposal services for Antero
PURCHASE PRICE: • $1.05 billion initial payment at closing and earn out payments at year-end 2019 and 2020 of $125 million each if 3-year volume threshold is met
MINIMUM VOLUME COMMITMENTS: • 90,000 Bbl/d in 2016, 100,000 Bbl/d in 2017 and 120,000 Bbl/d in 2018 and 2019
FINANCING:• $243 million of units issued via PIPE, $257 million of units issued to Antero Resources and
$552 million from existing cash and revolving credit facility; 23.9 million partnership units issued in total
CLOSING: • Expected to close concurrently with AM PIPE unit offering on September 23, 2015
Transaction Rationale
SCALE/GROWTH:
• Accretive to AM growth story and adds largest Appalachian integrated water business to high growth gathering and compressions assets to create one of the highest growth midstream MLPs in the U.S.
• PIPE cash proceeds to be used by AR to repay debt and fund future development plan
VALUATION: • Accretive purchase price at 8.5x to 9.0x projected 2016 EBITDA
MIDSTREAMINTEGRATION:
• Integrates water delivery, water services and waste water treatment business with existing gas gathering and compression business
THIRD PARTY BUSINESS: • Enhances AM’s ability to attract third party business – fresh water supply to completions and treatment of produced and flowback water
PRO FORMA LEVERAGE: • Net Debt/LTM EBITDAX 1.7x; over $1 billion of AM liquidity post transaction
WATER DROP DOWN ANNOUNCED
2
MVCS SUPPORT AND EARN OUTS DRIVE RETURNS
31. The 2019 earn out is based on a trailing 36 month fresh water delivery volume average at the end of 2019 of 161,000 Bbl/d while the 2020 earn out is based on a trailing 36 month fresh water delivery volume average at the end of 2020 of 200,000 Bbl/d.
Minimum volume commitments (MVCs) on fresh water delivery volumes, at $3.68 and $3.63 per barrel for the Marcellus and Utica respectively (with CPI adjustments), support revenues and rates of return for the water business acquisition
Earn out payments at year-end 2019 and 2020 provide incentives for the sponsor to perform long-term
0
40
80
120
160
200
2014 2015E 2016E 2017E 2018E 2019E 2020E
MB
bl/d
Actual Volumes Estimated Volumes MVCs
Fresh Water Delivery MVCs and Earn Out Payments(1)17
7 C
ompl
etio
ns
≈ 13
0 C
ompl
etio
ns
≈ 12
5 -1
35 C
ompl
etio
ns
2020 Earn Out – 200 MBbl/d Avg
2019 Earn Out – 161 MBbl/d Avg
MVC90K
MVC100K
MVC120K
MVC120K
125K
80K - 85K
50 Deferred Completions
Transaction Metrics2016E EBITDA: $115MM - $125MM
Estimated Volume: 115K - 125K Bbl/d 2016E Completions: 160 - 170
2016E VolumeMidpoint 120K
ANTERO MIDSTREAM – 2015 GUIDANCE
Key Variable 2015 Guidance(1) 2015 Revised Guidance(2)
Adjusted EBITDA ($MM) $150 - $160 $170 - $180
Distributable Cash Flow ($MM) $135 - $145 $150 - $160
Year-over-Year Distribution Growth(3) 28% - 30% 28% - 30%
Low Pressure Pipelines Added (Miles) 44 27
High Pressure Pipelines Added (Miles) 20 15
Compression Capacity Added (MMcf/d) 545 545
Capital Expenditures ($MM)
Low Pressure Gathering $165 - $170 $90 - $95
High Pressure Gathering $85 - $90 $70 - $75
Compression $160 - $165 $165 - $170
Condensate Gathering $5 - $10 $5
Water Infrastructure(4) - $80 - $90
Maintenance Capital $10 - $15 $15
Total Capital Expenditures ($MM) $425 - $450 $425 - $4501. Financial guidance per Partnership press release dated 1/20/2015.2. Updated financial guidance for water drop down. 3. Reflects the expected distribution growth associated with the fourth quarter 2015 over the fourth quarter 2014.4. Includes fresh water delivery system plus waste water treatment capital expenditures.
Key Operating & Financial Assumptions
4
Sustainable Business
Model
High Growth Sponsor Drives AM Throughput
and Distribution Growth
Largest Dedicated Core Liquids-Rich Acreage Position in Appalachia
$1.0+ Billion ofAM Liquidity
5
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
HighVisibility
SponsorStrength
LEADING UNCONVENTIONAL MIDSTREAM BUSINESS MODEL
“Just-in Time” Non-Speculative Capital Program
Strong Financial Position
Mitigated Commodity
Risk
1
2 3
4
5
67
8
Premier AppalachianMidstream Partnership
Run by Co-Founders
Consolidated Acreage Position in Lowest
Unit Cost Basin
-
100
200
300
400
500
600 Core Net Acres - Dry Core Net Acres - Liquids-Rich
Largest Liquids-Rich Core Position in
Appalachia
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000Largest Proved Reserve Base in Appalachia
Top Producers in Appalachia (Net MMcfe/d) – 2Q 2015(1)(2) Top 12 U.S. Natural Gas Producers (Net MMcf/d) – 2Q 2015(1)
Appalachian Producers by Proved Reserves (Bcfe) – YE 2014(1)(2)Appalachian Producers by Core Net Acres (000’s) – August 2015(3)(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 CHK, CVX, HES and XOM. 3. Based on Antero geologic interpretation supported by state well data, company presentations and public land data. Peer group includes AEP, CHK, CNX, COG, CVX, EQT, NBL, RICE, RRC, STO, SWN.4. Southwestern leasehold and reserves include the impact from STO and WPX property acquisitions closed in January 2015. 5. Includes proved reserves categorized in “Northern Division” consisting of Utica Shale, Marcellus Shale and Powder River Basin.
0200400600800
1,0001,2001,4001,6001,800
0
500
1,000
1,500
2,000
2,500
3,000
3,500Appalachian Peers
11th Largest U.S. Gas Producer
6
3rd Largest Appalachian
Producer
SPONSOR STRENGTH – LEADERSHIP IN APPALACHIAN BASIN
Note: 2014 SEC prices were $4.07/MMBtu for natural gas and $81.48/Bbl for oil on a weighted average Appalachian index basis.1. All net acres allocated to the WV/PA Utica Shale Dry Gas and Upper Devonian Shale are included among the net acres allocated to the Marcellus Shale as they are stacked pay formations attributable
to the same leasehold. 2. Antero and industry rig locations as of 8/28/2015, and average rig count for 1H 2015, per RigData.
SPONSOR STRENGTH – MOST ACTIVE OPERATORIN APPALACHIA
7
COMBINED TOTAL – 12/31/14 RESERVESAssumes Ethane RejectionNet Proved Reserves 12.7 TcfeNet 3P Reserves 40.7 TcfePre-Tax 3P PV-10 $22.8 BnNet 3P Reserves & Resource 53 to 57 TcfeNet 3P Liquids 1,026 MMBbls% Liquids – Net 3P 15%2Q 2015 Net Production 1,484 MMcfe/d- 2Q 2015 Net Liquids 45,900 Bbl/dNet Acres(1) 559,000Undrilled 3P Locations 5,331
UTICA SHALE CORE
Net Proved Reserves 758 BcfeNet 3P Reserves 7.6 TcfePre-Tax 3P PV-10 $6.1 BnNet Acres 149,000Undrilled 3P Locations 1,024
MARCELLUS SHALE CORE
Net Proved Reserves 11.9 TcfeNet 3P Reserves 28.4 TcfePre-Tax 3P PV-10 $16.8 BnNet Acres 410,000Undrilled 3P Locations 3,191
UPPER DEVONIAN SHALE
Net Proved Reserves 8 BcfeNet 3P Reserves 4.6 TcfePre-Tax 3P PV-10 NMUndrilled 3P Locations 1,116
WV/PA UTICA SHALE DRY GASNet Resource 12.5 to 16 TcfNet Acres 181,000Undrilled Locations 1,889
02468
101214
Rig
Cou
nt
Operators
1H 2015 Avg SW Marcellus & Utica(2)
27.4% 26.3% 26.2%
22.8%
19.7%
15.3%
12.4% 11.7% 11.2%8.7%
2.5%
(0.3%) (1.2%) (1.5%)(3.8%) (4.1%)
(13.7%)(16.2%)
-25%
-15%
-5%
5%
15%
25%
35%
45%
40%+
8Appalachian Peers
Source: Represents median of Wall Street research estimates for 2015E production growth vs. 2014 actual production. 1. Includes all North American E&P companies with a market capitalization greater than $5.0 billion. 2. Based on publicly announced 2015 production growth target of 40%+.
Antero’s 40%+ production growth guidance for 2015 leads the U.S. large cap E&P industry(1) and drives AM growth(1)
GROWTH – HIGHEST GROWTH LARGE CAP E&P
(2)
108 216
281 331 386
531
738
935 965
0
200
400
600
800
1,000
1,200
2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 4Q '14 1Q '15 2Q' 15
Utica Marcellus
$1$5 $7 $8
$11
$19
$28
$36
$41
$0$5
$10$15$20$25$30$35$40$45$50
2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 4Q '14 1Q '15 2Q' 15 2015E
26 31 40 36 41
116
222
358
454
0
100
200
300
400
500
2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 4Q '14 1Q '15 2Q' 15
Marcellus
10 38 80 126
266
531
908
1,134 1,197
0
200
400
600
800
1,000
1,200
2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 4Q '14 1Q '15 2Q' 15
Utica Marcellus
Low Pressure Gathering (MMcf/d)
Compression (MMcf/d)
High Pressure Gathering (MMcf/d)
EBITDA ($MM)(1)
9
$175
GROWTH – HIGH GROWTH MIDSTREAM THROUGHPUT
1. 2015E EBITDA guidance updated per 9/18/2015 press release based on 10/1/2015 effective date for water drop down. Y-O-Y growth based on 2Q’14 to 2Q’15.
10
LIQUIDS-RICH – LARGEST CORE POSITION
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 8/28/2015.1. Based on company filings and presentations. Peer group includes AEP, CHK, CNX, CVX, ECR, EQT, GPOR, NBL, RRC, STO, SWN.
• Antero has the largest core liquids-rich position in Appalachia with ≈371,000 net acres (> 1100 Btu)
• Represents over 21% of core liquids-rich acreage in Marcellus and Utica plays combined
• 2x its closest competitor
Antero has over 3,000 undeveloped rich gas locations with an average lateral length of 6,800’ in its 3P reserves
0
100
200
300
400
(000
s)
Core Liquids-Rich Net Acres(1)
248
13994
254 289
14%
37%49%
39% 43%
11%
29%38%
28% 32%
0
100
200
300
0%
15%
30%
45%
60%
Condensate Highly-RichGas/
Condensate
Highly-RichGas
Rich Gas Dry Gas
Tota
l 3P
Loca
tions
RO
R
Total 3P Locations ROR @ 12/31/2014 Strip ROR @ 6/30/2015 Strip
664
1,010
628 88942%
30%
16% 17%38%
26%
10% 13%0
500
1,000
1,500
0%
15%
30%
45%
60%
Highly-RichGas/
Condensate
Highly-RichGas
Rich Gas Dry Gas
Tota
l 3P
Loca
tions
RO
R
Total 3P Locations ROR @ 12/31/2014 Strip ROR @ 6/30/2015 Strip
MARCELLUS WELL ECONOMICS(1)
Marcellus Well Cost Improvement(2)
1. 12/31/2014 pre-tax well economics based on a 9,000’ lateral, 12/31/2014 natural gas and WTI strip pricing for 2015-2024, flat thereafter, NGLs at 32.5% of WTI for 2015–2016 and 50% of WTI thereafter, and applicable firm transportation and operating costs. 6/30/2015 pre-tax well economics based on a 9,000’ lateral and 6/30/2015 strip pricing with same pricing assumptions as used for 12/31/2014 pricing. Well cost estimates include $1.2 million assumed for road, pad and production facilities.
2. 2015E well costs based on $10.3 million for a 9,000’ lateral Marcellus well and $11.6 million for a 9,000’ lateral Utica well.
11
UTICA WELL ECONOMICS(1)
72% of Marcellus locations are processable (1100-plus Btu) 72% of Utica locations are processable (1100-plus Btu)
2015Drilling
Plan
Antero has reduced average well costs for a 9,000’ lateral by 16% in the Marcellus and 18% in the Utica as compared to 2014 well costs, through a combination of service cost reductions and drilling and completion efficiencies− 2015 drilling plans generate 26% to 49% rates of return including all pad, road and production facilities costs, depending on which strip price
deck is assumed (6/30/2015 vs. 12/31/2014)
Utica Well Cost Improvement(2)
$1.357 $1.144
$0.000
$0.500
$1.000
$1.500
$2.000
2014 2015E
$MM
/1,0
00’ L
ater
al
Well Cost ($MM/1,000')
16% Decrease vs. 2014 $1.571
$1.289
$0.000
$0.500
$1.000
$1.500
$2.000
2014 2015E
$MM
/1,0
00’ L
ater
al
Well Cost ($MM/1,000')
18% Decrease vs. 2014
SUSTAINABLE BUSINESS MODEL – AR MULTI-YEAR DRILLING INVENTORY SUPPORTS LOW RISK, HIGH RETURN GROWTH PROFILE
Marcellus and Utica undeveloped 3P rich-gas locations have the lowest break-even prices for both oil and natural gas compared to other U.S. shale plays
$39 $42 $44$51 $53 $54
$60 $64 $65 $68 $69 $72$83
$86
$0
$20
$40
$60
$80
$100
WTI
Pric
e ($
/Bbl
)
Antero 2015Drilling Plan
1. Source: Credit Suisse report dated December 2014 – Break-even WTI oil price to generate 15% after-tax rate of return. Assumes NYMEX gas price of $3.66/MMBtu for 2015-2019; $4.23/MMBtu thereafter.2. 2015 one year WTI crude oil strip price as of 12/31/14; NYMEX one year natural gas strip price as of 12/31/14.3. Source: Credit Suisse report dated December 2014 – Break-even NYMEX gas price to generate 15% after-tax rate of return. Assumes WTI oil price of $64.74/Bbl for 2015-2019; $70.50/Bbl thereafter; NGLs at
35% of WTI vs. Antero guidance of 30%-35% of WTI for 2015-2016 and 50% of WTI for 2017 and thereafter, driven by completion of Mariner East II project expected by year-end 2016.
$1.94 $2.20 $2.20 $2.37
$2.96 $3.13 $3.31 $3.48 $3.50 $3.63 $3.77 $3.85 $3.88 $3.98 $4.33 $4.38
$5.56 $5.62 $5.69 $5.71 $5.74
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
NYM
EX P
rice
($/M
MB
tu)
Antero 2015Drilling Plan
Assumes $65/Bbl WTI Oil(3)
SUSTAINABLE BUSINESS MODEL– LOW BREAK-EVEN PRICE ECONOMICS
North American Break-even Natural Gas Prices ($/MMBtu)(3)
12
North American Break-even Oil Prices ($/Bbl)(1)
2015 NYMEX Strip: $3.01/MMBtu(2)
2015 WTI Strip: $56.26/Bbl(2)
Antero Projects
Assumes $3.66/MMBtu NYMEX Gas(1)
13
HIGH VISIBILITY – PROJECTED MARCELLUS MIDSTREAM BUILDOUT
2014 2015 2016 2017 2018+
14
HIGH VISIBILITY – PROJECTED UTICA MIDSTREAM BUILDOUT2014 2015 2016 2017 2018+
Fixed Fee
100%
15
MITIGATED COMMODITY RISK – 100% FIXED FEE – RICH TO DRY
Contract Mix
Fixed Fee97%
Fixed Fee
100%
Fixed Fee
100%Fixed Fee94%
(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 6/26/2015, per RigData.3. Includes Antero Resources rigs located in Doddridge County, WV. 4. Includes Antero Resources and Range Resources rigs.
CommodityBased
CommodityBased
CommodityBased
Appalachian ExposureMarcellus – Dry Marcellus – Rich Utica – Dry Utica – Rich Rigs Running on Liquids-Rich Core Acreage Midstream Footprint (2)
Fixed Fee90%
CommodityBased
(3) (4)
10
2 2 1 1
13
0
5
10
15
AM CNNX EQM CMLP SMLP MWE
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
5.0
Jan-
13M
ar-1
3
May
-13
Jul-1
3
Sep
-13
Nov
-13
Jan-
14M
ar-1
4
May
-14
Jul-1
4
Sep
-14
Nov
-14
Jan-
15M
ar-1
5
May
-15
Jul-1
5
Sep
-15
Nov
-15
Jan-
16
Mar
-16
May
-16
Jul-1
6
Sep
-16
Nov
-16
Jan-
17M
ar-1
7
May
-17
Jul-1
7
Sep
-17
Nov
-17
Jan-
18M
ar-1
8
May
-18
Jul-1
8
Sep
-18
Nov
-18
AR Gross Gas Production
MITIGATED COMMODITY RISK – FIRM TRANSPORTATION & SALES PORTFOLIO
16
BBtu/d
Antero Resources Transportation Portfolio• Antero Resources has built the largest firm transportation portfolio with 4.85 BBtu/d by year end 2018
71%
29%
85%
15%
94%
6%
2015E 2016E 2017E 2018EFavorable:ChicagoMichConGulf CoastNYMEXTCO
AR Increasing Access to Favorable Markets
94%
6%
(NYMEX/TCO) Mid-Atlantic (NYMEX)(ANR) Gulf Coast
(REX/ANR/NGLP/MGT) Midwest(DOM S) Appalachia
(TETCO M2) Appalachia
(Tennessee) Gulf Coast
(TCO) Appalachia or Gulf Coast
Less favorable:TETCO M2Dominion South
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$0
$50
$100
$150
$200
$250
$MM
MITIGATED COMMODITY RISK – INTEGRAL TO BUSINESS MODEL
1. 3Q 2015 – 4Q 2021 hedge gains based on current mark-to-market hedge gains.2. Based on NYMEX strip as of 6/30/2015.
Hedging is a key component of Antero’s business model which includes development of a large, repeatable drilling inventory
Antero has realized $1.3 billion of gains on commodity hedges over the past 6 ½ years– Gains realized in 25 of last 26 quarters, or 96% of the quarters since 2009
● Based on Antero’s hedge position and strip pricing as of 6/30/2015(2), a further $2.0 billion in hedge gains are projected to be realized through the end of 2021
● Significant additional hedge capacity remains under the credit facility hedging covenant for 2016 – 2021 period
Quarterly Realized Hedge Gains / (Losses)(1)
Realized Hedge GainsProjected Hedge Gains(2)
NYMEX Natural Gas Historical Spot Prices
($/Mcf)
NYMEX Natural Gas Futures Prices (2)
2.8 Tcfe Hedged at average price of
$4.08/Mcfethrough 2021
$4.43
$4.02 $4.03$4.25
$4.05$3.82
Realized $1.3 Billion in Hedge Gains
Since 2009
$2.0 Billion in Projected Hedge Gains Through
2021(1)
Average Hedge Prices ($/Mcfe)
$3.74
17
Regional Gas Pipelines
Miles Capacity In-Service
Regional Gathering Pipeline(2)
50 1.4 Bcf/d 4Q 2015
181. 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. AM holds option to purchase 15% of regional gathering pipeline at cost plus cost of carry.
EndUsers
EndUsers
Gas Processing
Y-Grade Pipeline
Long-Haul Interstate
Pipeline
InterConnect
NGL Product Pipelines
Fractionation
Compression
Low Pressure Gathering
Well Pad
Terminalsand
Storage
(Miles) YE 2014 YE 2015E
Marcellus 91 108
Utica 45 56
Total 136 164
AM has option to participate in processing, fractionation,
terminaling and storage projects offered to AR
(Miles) YE 2014 YE 2015E
Marcellus 62 76
Utica 35 36
Total 97 112
(MMcf/d) YE 2014 YE 2015E
Marcellus 375 800
Utica 0 120
Total 375 920
AM Owned Assets
Condensate GatheringStabilization
(Miles) YE 2014 YE 2015E
Utica 16 19
EndUsers
AM Option Assets
(Ethane, Propane, Butane, etc.)
VALUE CHAIN OPPORTUNITY – FULL MIDSTREAM VALUE CHAIN
Water Drop Down
0.0x
1.0x
2.0x
3.0x
4.0x
5.0x
6.0x
Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8
Tota
l Deb
t / L
QA
EB
ITD
A
• $1.5 billion revolver in place to fund future growth capital (5x Debt/EBITDA Cap)
• Pro forma liquidity of $1,061 million at 6/30/2015
• Sponsor (NYSE: AR) has Ba2/BB corporate ratings
AM Liquidity (6/30/2015)(1)
AM Peer Leverage Comparison(3)
($ in millions)
Revolver Capacity(2) $1,500
Less: Borrowings 439
Plus: Cash -
Liquidity $1,061
1. Pro forma for $1.05 billion water drop down funded with $113 million of cash, $439 million of debt and net proceeds from 11.0 million units to AR and 12.9 million units from PIPE transaction.2. As of 6/30/2015. Peers include TEP, EQM, MWE, WES, RMP, SHLX, DM, and CNNX.
Financial Flexibility
STRONG FINANCIAL POSITION – SIGNIFICANT FINANCIAL FLEXIBILITY
19
3–Year Expected Distribution Growth Rate and DCF Coverage(1)
201. Based on Bloomberg 2015-2017 consensus distribution and DCF coverage estimates. Data as of 6/30/2015.
TOP TIER DISTRIBUTION GROWTH & HEALTHY COVERAGE
35%
28%25% 25% 24% 24%
17% 16% 14% 14% 12%8%
1.17x 1.20x 1.21x
1.46x 1.44x
1.63x
1.50x
1.25x1.18x
1.25x
1.15x1.10x
0.00x
0.20x
0.40x
0.60x
0.80x
1.00x
1.20x
1.40x
1.60x
1.80x
0%
5%
10%
15%
20%
25%
30%
35%
40%
SHLX AM DM PSXP MPLX VLP EQM CNNX TEP SXL WES MWE
EQM
DM
SHLX
CNNX
MWE
WES TEP
MPLX
PSXP
VLP
AM - CurrentYield: 3.67%
Price: $20.70/unit
AM - ImpliedYield: 2.76%
Price: $27.59unit
y = -0.038ln(x) - 0.0228R² = 0.7155
0.00%
1.00%
2.00%
3.00%
4.00%
5.00%
6.00%
7.00%
8.00%
9.00%
3% 8% 13% 18% 23% 28% 33%
Yiel
d (%
)
2015-2018 Distribution Growth CAGRBubble Size Reflects Market Capitalization
ATTRACTIVE VALUE PROPOSITION
Note: Based on Bloomberg consensus estimates and current market prices as of 9/14/2015. 21
• Attractive appreciation potential on a relative basis
R-squared = .72
Antero Midstream (NYSE: AM)Asset Overview
22
1. Represents inception to date actuals as of 12/31/2014 and 2015 midpoint guidance.2. Pro forma for water drop down. Includes $15.0 million of maintenance capex at 2015 midpoint guidance.
23
UticaShale
MarcellusShale
Projected Midstream Infrastructure(1)
Marcellus Shale
Utica Shale Total
YE 2014 Cumulative Gathering/ Compression Capex ($MM) $836 $345 $1,181
Gathering Pipelines(Miles) 153 80 233
Compression Capacity(MMcf/d) 375 - 375
Condensate Gathering Pipelines (Miles) - 16 16
2015E Capex Budget ($MM)(2) $256 $182 $438Gathering Pipelines
(Miles) 31 12 43
Compression Capacity(MMcf/d) 425 120 545
Condensate Gathering Pipelines (Miles) - 3 3
Midstream Assets
ANTERO MIDSTREAM ASSET OVERVIEW
• Gathering and compression assets in core of rapidly growing Marcellus and Utica Shale plays
– Acreage dedication of ~428,000 net leasehold acres for gathering and compression services
– Additional stacked pay potential with dedication on 181,000 acres of Utica deep rights underlying the Marcellus in WV and PA
– 100% fixed fee long term contracts
• AR owns 67% of AM units (NYSE: AM) pro forma
ANTERO MIDSTREAM ASSETS – RICH GAS MARCELLUS
24
• 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 nine drilling rigs in the Marcellus Shale during 2015, including intermediate rigs
− 100% of rigs targeting the highly-rich gas/condensate and highly-rich gas regimes
• Of the 80 gross wells targeted to be completed in 2015, 90% (72 gross wells) are forecast to be completed in the AM dedicated area
− AM dedicated acreage contains 2,165 gross undeveloped Marcellus locations and 313 Upper Devonian locations
• Antero will defer 50 completions originally scheduled to occur in the second and third quarters of 2015 into 2016 in order to limit natural gas volumes sold into unfavorable pricing markets
− 28 of the deferred completions are in the AM dedicated area
Marcellus Gathering & Compression
Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.
YE 2014 YE 2015E
Low Pressure Gathering Pipelines (Miles)
91 108
High Pressure Gathering Pipelines (Miles)
62 76
Compression Capacity (MMcf/d) 375 800
25
• 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 five drilling rigs in the Utica Shale during 2015, including intermediate rigs
− 100% of rigs targeting the highly-rich gas/condensate and highly-rich gas regimes
• All of the 50 gross wells targeted to be completed in 2015 are on Antero Midstream’s footprint
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 2014 YE 2015E
Low Pressure Gathering Pipelines (Miles)
45 56
High Pressure Gathering Pipelines (Miles)
35 36
Condensate Pipelines (Miles) 16 19
Compression Capacity (MMcf/d) 0 120
ANTERO INTEGRATED WATER BUSINESS
26
Marcellus Fresh Water System(2)
• Provides fresh water to support Marcellus well completions • Year-round water supply sources: Ohio River and local rivers• Ozone Water treatment facility to be in-service by 3Q 2015• Significant asset growth in 2015 as summarized below:
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 06/30/2015 and 2015 guidance.2. All Antero water withdrawal sites are fully permitted under long-term state regulatory permits both in WV and OH. 3. Assumes fee of $3.685 per barrel subject to annual inflation and 250,000 barrels of water per well that utilize the fresh water delivery system based on 9,000 foot lateral. Operating margin excludes G&A.4. Assumes fee of $3.635 per barrel subject to annual inflation and 275,000 barrels of water per well that utilize the fresh water delivery system based on 9,000 foot lateral. Operating margin excludes G&A.
Utica Fresh Water System(2)
• Provides fresh water to support Utica well completions • Year-round water supply sources: local reservoirs and rivers• Significant asset growth in 2015 as summarized below:
Marcellus Water System YE 2014 YE 2015E
Water Pipeline (Miles) 177 226
Fresh Water Storage Impoundments 22 24
Cash Operating Margin per Well ($)(3) $700K -$750K
Utica Water System YE 2014 YE 2015E
Water Pipeline (Miles) 61 90
Fresh Water Storage Impoundments 8 14
Cash Operating Margin per Well ($)(4) $775K -$825K
Projected Fresh Water Delivery Infrastructure(1)
Marcellus Shale
Utica Shale Total
YE 2015E Cumulative Water System Capex ($MM) $340 $113 $453Water Pipelines (Miles) 226 90 316Water Storage Facilities 24 14 38
AM has acquired AR’s integrated water business for $1.05 billion plus earn out payments of $125 million at year-end in each of 2019 and 2020− The acquired business includes Antero’s Marcellus and Utica freshwater delivery business, the fully-contracted future advanced wastewater
treatment complex and all fluid handling and disposal services for Antero
Antero advanced wastewater treatment facility to be constructed – connects to Antero
freshwater delivery system
010,00020,00030,00040,00050,00060,00070,00080,000
Antero Clearwater Advanced Wastewater Treatment Capacity (Bbl/d)
Produced/Flowback Volumes (Bbl/d)
ADVANCED WASTEWATER TREATMENT
Illustrative Produced & Flowback Water VolumesAdvanced Wastewater Treatment
Antero Produced Water Services and Freshwater Delivery Business
Antero AdvancedWastewater Treatment
3rd Party Recyclingand Well Disposal
(Bbl/d)
Advanced Wastewater Treatment ComplexEstimated capital expenditures ($ million)(1) ~$275Standalone EBITDA at 100% utilization(2) ~$55 – $65Implied investment to standalone EBITDA build-out multiple ~4x – 5xEstimated per well savings to Antero Resources ~$150,000Estimated in-service date Late 2017Operating capacity (Bbl/d) 60,000Operating 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
27Integrated Water Business
ORGANIC GROWTH STRATEGY: “BUILD VS. BUY”
28
• Organic growth strategy provides attractive returns and project economics, while avoiding the competitive acquisition market
• Industry leading organic growth story
– ~$1.06 billion in capital spent through 9/30/2014
– $425 million in additional growth capital forecast for the twelve-month period ending 12/31/15 (excludes $12.5 million of maintenance capital)
Note: Precedent data per IHS Herold’s research and public filings.1. Antero organic multiple calculated as estimated gathering and compression capital expended through Q3 2014 divided by 2015 projected gathering and compression EBITDA, assuming 12-15 month
lag between capital incurred and full system utilization.2. Selected gathering and compression drop down acquisitions since 1/1/2011. Drop down multiples are based on NTM EBITDA. Source: Barclays.
6.8x
11.9x
10.7x
10.0x
9.3x9.0x 9.0x 9.0x 8.9x 8.9x 8.8x 8.6x
8.0x 7.9x
7.0x 6.9x
5.5x
0.0x
1.0x
2.0x
3.0x
4.0x
5.0x
6.0x
7.0x
8.0x
9.0x
10.0x
11.0x
12.0x
Drop Down Multiple(2)
Organic EBITDA Multiple vs. Precedent Drop Down Multiples
Median: 8.9x
Value creation for the AM unit holder =Build at 4x to 7x EBITDA
vs.Drop Down / Buy at 8x to 12x EBITDA
LPGathering
HPGathering Compression
CondensateGathering
Water Business
RegionalPipeline
Processing/Fractionation
Unlevered IRR Range: 25% - 35% 15% - 25% 10% - 20% 25% - 35% 30% - 40% 15% - 25% 15% - 20% Payout (Years): 2.5 - 4.0 3.5 - 4.5 4.0 - 6.5 2.0 - 3.5 2.0 – 3.0 3.5 - 7.0 5.0 - 6.0 Minimum Volume Commitments: N/A 75% 70% N/A Yes 80% 80%
2015 Capex(2) TotalMarcellus $298 $49 $62 $105 - $82 Utica 125 44 11 63 5 3
Growth Capex $423 $93 $73 $168 $5 $85 % of Capex 100% 22% 17% 40% 1% 20%
Included in 2015 Budget: Marcellus & Utica
Marcellus & Utica
Marcellus & Utica
Utica Marcellus & Utica
Not Included Not Included
Additional In-hand Opportunities:
Dry Utica Dry Utica Dry Utica Utica Stabilization
Dry Utica Regional Gathering
Pipeline
Marcellus Processing/
Fractionation
25%
15%
10%
25%
30%
15% 15%
35%
25%
20%
35%
25%20%
40%
0%
10%
20%
30%
40%
Inte
rnal
Rat
e of
Ret
urn
29
Project Economics by Segment(1)
ESTIMATED PROJECT ECONOMICS BY SEGMENT
1. Based on management capex, operating cost and throughput assumptions by project. Capex guidance updated per 9/18/2015 press release. 2. Excludes $15.0 million of maintenance capex.
Wtd. Avg. 24% IRR
AM Option Opportunities
AM UPSIDE OPPORTUNITY SET
30
ACTIVITY CURRENTLY DEDICATED TO AM
Third Party Business
Processing, Fractionation, Transportation and Marketing
Regional Pipeline Project• Option to participate for up to 15% in regional gathering
pipeline project in West Virginia expected to go in-service in 4Q 2015
• Additive to full value chain model
• 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• 181,000 net acres of AR Utica dry gas acreage underlying
the Marcellus in West Virginia and Pennsylvania dedicated to AM
• AR drilling its first WV Utica well
Active AR Leasing• Future acreage acquisitions by AR are dedicated to AM• Added 92,000 net acres in 2014 and have added 20,000
net acres in 2015
REGIONAL PIPELINE PROJECT
• Option to Acquire Up To 15% Non-Op Equity Interest
●Enables Antero Resources to move up to 1.1 Bcf/d of gas on a firm basis to more favorably priced markets including TCO, NYMEX and Gulf Coast markets
●Once the Regional Pipeline is placed into service, Antero Resources plans to complete the previously deferred 50 Marcellus wells, resulting in approximately 350 MMcf/d of incremental gross gas production at its peak
Regional Gathering Pipeline
Throughput Capacity: 1.4 Bcf/d
Pipeline Specifications:
50 miles of 36 inch pipeline
Project Capital: ≈ $400 Million
In-Service Date: 4Q 2015
AR Firm Commitment: 900 MMcf/d
31
PROCESSING – VALUE CHAIN POTENTIALFOR UNDEDICATED ACREAGE
SherwoodProcessing
Complex
AR acreage position on map reflects tax districts in which greater than 3,000 net acres are held.1. Antero gross 3P C3+ NGL volumes and 3P Gross Wellhead Gas reserves as of 12/31/2014.
Processing Area Of Dedication for AM
MarkWest Processing AOD – 194,500 Gross
Acres
Tyler County70,000 Gross Acres
Ritchie County46,500 Gross Acres
Antero Resources has 11.6 Tcf of processable gross 3P gas reserves and 616 Million Bbls of gross 3P NGL reserves across 128,500 gross processable Marcellus acres that are dedicated to Antero Midstream for processing
32
Gilmer County12,000 Gross Acres
AR Gross Gross 3P NGL AR 3P GrossProcessable Reserves Wellhead Gas
Acres (MMBbls) (1) (Tcf)Potential Processing AOD for AMTyler 70,000 382.2 6.6
Ritchie 46,500 196.6 4.0
Gilmer 12,000 37.1 1.0
Total 128,500 615.9 11.6
LARGE UTICA SHALE DRY GAS POSITION
33
Antero has the right to build gathering and compression infrastructure to move Antero’s future dry gas Utica production− AM pro forma water business would also serve Antero’s
dry gas Utica development Antero spud its first dry gas Utica well in 3Q 2015 Antero has 224,000 net acres of exposure to Utica dry gas
play Other operators have reported strong Utica Shale dry gas
results including the following wells:
ChesapeakeHubbard BRK #3H
3,550’ LateralIP 11.1 MMcf/d
HessPorterfield 1H-17
5,000’ LateralIP 17.2 MMcf/d
GulfportIrons #1-4H5,714’ Lateral
IP 30.3 MMcf/d
EclipseTippens #6H5,858’ Lateral
IP 23.2 MMcf/d
Magnum HunterStalder #3UH5,050’ Lateral
IP 32.5 MMcf/d
AnteroUtica Well
Drilling
Well Operator24-hr IP(MMcf/d)
LateralLength
(Ft)
IP/1,000’Lateral
(MMcf/d)
Scotts Run EQT 72.9 3,221 22.633
Gaut 4IH CNX 61.0 5,840 11.131
CSC #11H RRC 59.0 5,420 10.886
Stewart-Win 1300U MHR 46.5 5,289 8.792
Bigfoot 9H RICE 41.7 6,957 5.994
Blank U-7H GST 36.8 6,617 5.561
Stalder #3UH MHR 32.5 5,050 6.436
Irons #1-4H GPOR 30.3 5,714 5.303
Pribble 6HU SGY 30.0 3,605 8.322
Simms U-5H GST 29.4 4,447 6.611
Conner 6H CVX 25.0 6,451 3.875
Messenger 3H SWN 25.0 5,889 4.245
Tippens #6H ECR 23.2 5,858 3.960
Porterfield 1H-17 HESS 17.2 5,000 3.440
1. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held in OH, WV and PA.
Magnum HunterStewart Winland 1300U
5,289’ LateralIP 46.5 MMcf/d
RangeClaysville SC #11H
5,420’ LateralIP 59.0 MMcf/d
ChevronConner 6H
6,451’ LateralIP 25.0 MMcf/dGastar
Simms U-5H4,447’ Lateral
IP 29.4 MMcf/d
Utica Shale Dry Gas Acreage in OH/WV/PA(1)
RiceBigfoot 9H
6,957’ LateralIP 41.7 MMcf/d
AR Utica Shale Dry GasWV/PA
Net Resource12.5 to 16 Tcf
1,889 Gross Locations181,000 Net Acres
AR Utica Shale Dry GasOhio
3P Reserves2.4 Tcf
289 Gross Locations43,000 Net Acres
AR Utica Shale Dry GasTotal OH/WV/PA
Net Resource14.9 to 18.4 Tcf
2,178 Gross Locations224,000 Net Acres
Stone EnergyPribble 6HU
3,605’ LateralIP 30.0 MMcf/d
SouthwesternMessenger 3H5,889’ Lateral
IP 25.0 MMcf/d
RiceBlue Thunder
10H, 12H≈9,000’ Lateral
GastarBlake U-7H
6,617’ LateralIP 36.8 MMcf/d
EQTScotts Run
3,221’ LateralIP 72.9 MMcf/d
CNXGaut 4IH
5,840’ LateralIP 61.0 MMcf/d
Low Cost Marcellus/Utica Focus
“Best-in-Class” Distribution Growth
34
CATALYSTS
28% to 30% per year from 2015 to 2017 targeted based on Sponsor planned development; additional third party business expansion opportunities
AM Sponsor is the most active operator in Appalachia; 40%+ production growth targeted for 2015 supported by $1.8 billion capital budget, firm processing and takeaway, long-term natural gas hedges and $3.2 billion of liquidity; targeting 25% to 30% production growth in 2016
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, processing and pipeline assets for Sponsor and third party use
Appalachian Basin Midstream Growth
High Growth Sponsor Production Profile
1
2
3
4
5
6
Acquisition of integrated water business from Antero expected to result in distributable cash flow per unit accretion in 2016
Stacked Pay Basin Upside
Development of Utica Shale Dry Gas and Upper Devonian resources provide further midstream infrastructure expansion opportunities
Integrated WaterBusiness Drop Down
$0.17 $0.18 $0.19
$0.00
$0.05
$0.10
$0.15
$0.20
$0.25
$0.30
$0.35
$0.40
$0.45
$0.50
4Q14A 1Q15A 2Q15A 3Q15E 4Q15E 1Q16E 2Q16E 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E
TOP TIER DISTRIBUTION GROWTH
35
Distribution Per Unit(1)
• Antero Midstream is targeting 28% to 30% annual distribution growth through 2017
Note: Future distributions subject to AM Board approval1. Assumes midpoint of target distribution growth range
APPENDIX
36
LARGEST FIRM TRANSPORTATION AND PROCESSING PORTFOLIO IN APPALACHIA
Antero Long Term Firm Processing & Takeaway Position (YE 2018) – Accessing Favorable Markets
Mariner East 262 MBbl/d Commitment
Marcus Hook Export
Shell20 MBbl/d CommitmentBeaver County Cracker
(Pending FID YE‘15)
Sabine Pass (Trains 1-4)50 MMcf/d per Train
1. August 2015 and full year 2016 futures basis, respectively, provided by Wells Fargo dated 6/30/2015. Favorable markets shaded in green.
Chicago(1)
$(0.04) / $(0.06)
CGTLA(1)
$(0.07) / $(0.08)
Dom South(1)
$(1.52) / $(1.17)
TCO(1)
$(0.12) / $(0.31)
37
Cove Point
4.85 Bcf/dFirm GasTakeaway
By YE 2018
4.85 Bcf/d portfolio by YE 2018 with 85% serving favorable markets with an average demand fee of $0.40/MMBtu
YE 2018 Gas Market MixAR 4.85 Bcf/d FT
43%Gulf Coast
16%Midwest
13%Atlantic
Seaboard
12%Dom S/TETCO
(PA)
15%TCO
NORTHEAST NGLS ARE TRANSPORTATION CHALLENGED
1. As an anchor shipper on Mariner East 2, Antero has the right to expand its NGL commitment with notice to operator. 2. 2015 NGL production assumes ethane rejection.
38
Mariner East 261,500 Bbl/d AR Commitment (1)
4Q 2016 In-Service
Not so much a supply problem but more of a logistics problem for NGLs in the northeast− The majority of northeast NGL production is being transported by expensive rail and trucking− NGLs that are transported “to the water” are also faced with high shipping rates
Export15%
Gulf Coast13%
Mid-Atlantic
6%Sarnia
3%
Northeast43%
Midwest10%
Edmonton10%
2015 NGL Marketing by Region
NORTHEAST NGL GROWTH IS SUPPORTED BY INCREASING TAKEAWAY OPTIONS
1. Figure 13 per Citi research dated 7/15/2015; Chart 10 per BAML research dated 6/5/2015. Mont Belvieu forward prices as at 9/2/2015 per ICE. Pipeline volumes are capacity estimates.
NGL Pipelines – Actual (2015) and Projected(1)
39
Shell20 MBbl/d CommitmentBeaver County Cracker
(Pending FID YE’15)
Mariner East 262 MBbl/d Commitment
Marcus Hook ExportAR Has Doubling Rights
Gulf Coast Critical to
NGL Pricing
Appalachia
NGL transportation rates are expected to decline significantly as pipeline options to domestic markets and export terminals go in-service (Mariner East 2, for example)
(MMBbl/d)
MMBbl/d
$0.00
$0.10
$0.20
$0.30
$0.40
$0.50
$/G
allo
n
Baltic Rate LPG Freight Futures
Baltic Rate ($/Gal) Marcus Hook to Europe ($/Gal)Marcus Hook to Far East ($/Gal)
U.S. LPG EXPORTS ARE SUPPORTED BY EXCESSDOCK CAPACITY AND FLEET GROWTH
40
0200400600800
1,0001,2001,4001,6001,800
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
MB
bl/d
Butane Exports Propane Exports Total Export Capacity
Significant U.S. Total LPG Export Terminal Capacity vs. Export Volumes(1)
Excess dock capacity supports growing LPG export volumes
through 2025
Fleet Growth Supports U.S. LPG Export Growth(2) LPG Freight Futures Show Declining Freight Costs(3)
Baltic LPG shipping cost declines from $0.40/gal to $0.20-$0.25/gal in early
2017 on fleet supply growth numbers
Projected growth in VLGC fleet supports increasing LPG export volumes and
lower shipping costs
1. Source: Bentek.2. Source: Poten & Partners, August 2015.3. Baltic Rate based on 8/20/2015 Baltic Futures converted to cost per gallon of LPGs, assuming 75/25 propane/butane.
LPG transportation rates from northeast fractionation to Europe and Asia expected to improve by $0.15 to $0.20 per gallon by YE 2016, driven both by pipelines replacing rail and lower shipping costs
Excess Dock Capacity
Current Fleet 168Newbuilds +85
POSITIVE FOR LONG-TERM LPG MARKETS
41
Robust Global LPG Demand Growth Through 2020(1)
1. Source: PIRA NGL Outlook, 7/23/2015.2. Source: Poten & Partners, August 2015. MM Tons conversion to MMBbl/d conversion based on 75% propane/25% butane barrel assuming 42 gallons/Bbl.3. Source: IHS, Waterborne, SK Gas Analysis; Wood Mackenzie; Wood Mackenzie, PDH C3 capacity based on 25 MBbl/d = 650 Mt/y.
U.S. Driven Global LPG Seaborne Supply Through 2020(2)
China, India andSaudi Arabiaare main
demand growth
Multiple Factors Driving Global LPG Demand Growth Through 2020(3)
MB
bl/d
MM
Bbl
/d
0.0
1.0
2.0
3.0
4.0
MM
Bbl
/d
0.0
0.33
0.67
Forecast global LPG demand growth of 800 MBbl/d to 1 MMBbl/d 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
U.S. exports are main supply
growth
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
POSITIVE FOR LONG-TERM ETHANE MARKETS
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. petrochemdemand 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
42
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 PADD 2 PADD 3 (East Coast)
No Northeast rejection after 2016
Europe
Mariner East II
Shipping $0.25/Gal
NGL EXPORTS AND NETBACKS STEP-UP BY 4Q 2016
1. Source: Intercontinental exchange as of 6/30/2015.2. Source of graphic: Tudor Pickering Holt & Co. research presentation dated June 16, 20153. As an anchor shipper on Mariner East II, Antero has the right to expand its NGL commitment with
notice to operator.
4. Shipping rates based on benchmark Baltic shipping rate of $129/ton as of 6/30/15, adjusted for number of shipping days to NWE.
5. Pipeline fee equal to $0.0725/gal, per Mariner East I tariff. Terminal fee equal to $0.12/gal, per TPH report dated June 16, 2015.
Upon in-service of Mariner East II, Antero will have the ability to market its propane and n-butane to international buyers, which we expect will provide uplifts of $0.14/Gal and $0.12/Gal, respectively, to the current netbacks received from propane and n-butane volumes shipped to Mont Belvieu today− In the meantime, Antero has 23,000 Bbl/d of propane hedged at $0.63/Bbl in 2015 and 30,000 Bbl/d
hedged at $0.59/Bbl in 2016
Commitment to Mariner East II results in over $100 million in combined incremental annualized cash flow from sales of propane and n-butane (~$75 MM from propane and ~$28 MM from n-butane)
PricingPropane: $0.43/GalN-Butane: $0.60/Gal
PricingPropane: $0.69/GalN-Butane: $0.87/Gal
Mariner East II61,500 Bbl/d AR
Commitment (see table below) (3)
4Q 2016 In-Service
ShippingPropane: $0.18/GalN-Butane: $0.21/Gal
Mont Belvieu Netback ($/Gal)Propane N-Butane
August Mont Belvieu (1): $0.43 $0.60Less: Shipping Costs to Mont Belvieu (2): (0.25) (0.25)Appalachia Netback to AR: $0.18 $0.35
AR Mariner East II Commitment (Bbl/d)Product Base Option (3) TotalEthane (C2) 11,500 - 11,500 Propane (C3) 35,000 35,000 70,000 Butane (C4) 15,000 15,000 30,000
Total 61,500 50,000 111,500
NWE Netback ($/Gal)Propane N-Butane
August NWE Price (1): $0.69 $0.87Less: Spot Freight (4): (0.18) (0.21)FOB Margin at Marcus Hook: $0.51 $0.66Less: Pipeline & Terminal Fee (5): (0.19) (0.19)NWE Netback to AR: $0.32 $0.47Upside to Appalachia Netback: $0.14 $0.12
43
WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECT
100% operatedOperating 7 drilling rigs including
2 intermediate rigs410,000 net acres in
Southwestern Core (75% includes processable rich gas assuming an 1100 Btu cutoff)– 50% HBP with additional 23%
not expiring for 5+ years413 horizontal wells completed
and online– Laterals average 7,500’– 100% drilling success rate6 plants in-service at Sherwood
Processing Complex capable of processing in excess of 1.2 Bcf/d of rich gas−Over 1 Bcf/d of Antero gas
being processed currentlyNet production of 1,240 MMcfe/d
in 2Q 2015, including 34,000 Bbl/d of liquids 3,191 future drilling locations in
the Marcellus (2,302 or 72% are processable rich gas)28.4 Tcfe of net 3P (17% liquids),
includes 11.9 Tcfe of proved reserves (assuming ethane rejection)
Highly-Rich Gas135,000 Net Acres
1,010 Gross Locations
Rich Gas92,000 Net Acres
628 Gross Locations
Dry Gas103,000 Net Acres
889 Gross Locations
Highly-Rich/Condensate80,000 Net Acres
664 Gross Locations
HEFLIN UNIT30-Day Rate
2H: 21.4 MMcfe/d (20% liquids)
CONSTABLE UNIT30-Day Rate
1H: 14.3 MMcfe/d (25% liquids)
142 Horizontals Completed30-Day Rate8.1 MMcf/d
6,915’ average lateral length
SherwoodProcessing
Complex
Source: Company presentations and press releases. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held. Note: Rates in ethane rejection.
NERO UNIT30-Day Rate
1H: 18.2 MMcfe/d(27% liquids)
BEE LEWIS PAD30-Day Rate
4-well combined 30-Day Rate of
67 MMcfe/d (26% liquids)
RJ SMITH PAD30-Day Rate
4-well combined 30-Day Rate of
56 MMcfe/d (21% liquids)
44
HENDERSHOT UNIT30-Day Rate
1H: 16.3 MMcfe/d2H: 18.1 MMcfe/d
(29% liquids)
HORNET UNIT30-Day Rate
1H: 21.5 MMcfe/d2H: 17.2 MMcfe/d
(26% liquids)CARR UNIT30-Day Rate
2H: 20.6 MMcfe/d(20% liquids)
WAGNER PAD30-Day Rate
4-well combined 30-Day Rate of
59 MMcfe/d (14% liquids)
0.0%
20.0%
40.0%
60.0%
80.0%
100.0%
$3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00
Pre-
Tax
RO
R (%
)
Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas
MARCELLUS ROR% AND GAS PRICE SENSITIVITY
451. Assumes 12/31/2014 strip pricing, market differentials and relevant transportation cost; 9,000’ lateral.
• Large portfolio of Highly-Rich Gas/Condensate to Dry Gas locations• Focused on drilling highly economic rich gas locations – rig symbols represent current rig location by Btu regime• Assumes 12/31/2014 WTI strip pricing for 2015-2024, flat thereafter averaging $72/Bbl; NGL price 32.5% of WTI for 2015-2016
and 50% of WTI thereafter following expected in-service date of Mariner East II in late 2016NYMEX Flat Price Sensitivity(1)
ROR% at Flat 2015-2024 Strip Price
Highly-Rich Gas/Condensate: 49%
Highly-Rich Gas: 36%
Rich Gas: 18%
Dry Gas: 20%
664 Locations
1,010 Locations
628 Locations
889 Locations
Antero Rigs Employed
2015Drilling Plan
Note: Antero acreage position reflects townships in which greater than 3,000 net acres are held. Antero 30-day rates in ethane rejection.1. 30-day rate reflects restricted choke regime.
• 100% operated• Operating 4 drilling rigs• 149,000 net acres in the core rich gas/
condensate window (71% includes processable rich gas assuming an 1100 Btu cutoff)
– 24% HBP with additional 65% not expiring for 5+ years
• 68 operated horizontal wells completed and online in Antero core areas
− 100% drilling success rate• 4 plants at Seneca Processing Complex
capable of processing 800 MMcf/d of rich gas
− Over 500 MMcf/d being processed currently, including third party production
• Net production of 244 MMcfe/d in 2Q 2015 including 11,900 Bbl/d of liquids
• Fourth third party compressor station in-service December 2014 with a capacity of 120 MMcf/d
• 1,024 future gross drilling locations (735 or 72% are processable gas)
• 7.6 Tcfe of net 3P (15% liquids), includes 758 Bcfe of proved reserves (assuming ethane rejection)
WORLD CLASS OHIO UTICA SHALEDEVELOPMENT PROJECT
46
CadizProcessing
Plant
NORMAN UNIT30-Day Rate
2 wells average16.8 MMcfe/d (15% liquids)
RUBEL UNIT30-Day Rate
3 wells average17.2 MMcfe/d(20% liquids)
Utica Core Area
GARY UNIT30-Day Rate
3 wells average24.2 MMcfe/d(21% liquids)
Highly-Rich/Cond27,000 Net Acres
139 Gross Locations
Highly-Rich Gas16,000 Net Acres
94 Gross Locations
Rich Gas33,000 Net Acres
254 Gross Locations
Dry Gas43,000 Net Acres
289 Gross Locations
NEUHART UNIT 3H30-Day Rate16.2 MMcfe/d(57% liquids)
Condensate30,000 Net Acres
248 Gross Locations
DOLLISON UNIT 1H30-Day Rate19.8 MMcfe/d(40% liquids)
MYRON UNIT 1H30-Day Rate26.8 MMcfe/d(52% liquids)
SenecaProcessingComplex
LAW UNIT30-Day Rate
2 wells average16.1 MMcfe/d(50% liquids)
SCHAFER UNIT30-Day Rate(1)
2 wells average14.2 MMcfe/d(49% liquids)
URBAN PAD30-Day Rate
4 wells average 18.8 MMcfe/d (15% liquids)
GRAVES UNIT500’ Density Pilot
30-Day Rate4 wells average15.5 MMcfe/d(24% liquids)
FRANKLIN UNIT30-Day Rate
3 wells average17.6 MMcfe/d(16% liquids)
FRAKES UNIT30-Day Rate
2 wells average18.6 MMcfe/d(42% liquids)
0.0%
20.0%
40.0%
60.0%
80.0%
100.0%
120.0%
140.0%
160.0%
180.0%
200.0%
220.0%
$3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00
Pre-
Tax
RO
R (%
)
Condensate Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas
UTICA OHIO ROR% AND GAS PRICE SENSITIVITY
47
NYMEX Flat Price Sensitivity(1)
94 Locations
ROR% at Flat 2015-2024 Strip Price
Condensate: 16%
Highly-Rich Gas/Condensate: 49%
Highly-Rich Gas: 71%
Rich Gas: 57%
Dry Gas: 65%
• Large portfolio of Condensate to Dry Gas locations• Focused on drilling highly economic rich gas locations – rig symbols represent current rig location by Btu regime• Assumes 12/31/2014 WTI strip pricing for 2015-2024, flat thereafter averaging $72/Bbl; NGL price 32.5% of WTI for 2015-2016
and 50% of WTI thereafter following expected in-service date of Mariner East II in late 2016
1. Assumes 12/31/2014 strip pricing, market differentials and relevant transportation cost; 9,000’ lateral.
254 Locations
139 Locations
289 Locations
248 Locations
2015Drilling Plan
Antero Rigs Employed
Plan to defer 50 Marcellus well completions into 2016 to achieve higher gas price realizations, approximately half of which are located on AM areas of dedication− Regional gathering pipeline expected in-service late 2015 will connect incremental Marcellus production to CGTLA (Gulf
Coast) and TCO pricing
AR COMPLETION DEFERRALS – 2016 VOLUME IMPACT
0
50
100
150
200
250
300
350
400
450
500
Jan-16 Mar-16 May-16
Gro
ss W
ellh
ead
Prod
uctio
n (M
Mcf
/d)
Completion Deferral Impact on 2016 Production
Production From 50 Deferred
Completions
48
ANTERO RESOURCES – UPDATED 2015 GUIDANCE
Key Variable 2015 GuidanceNet Daily Production (MMcfe/d) 1,400
Net Residue Natural Gas Production (MMcf/d) 1,175
Net Liquids Production (Bbl/d) 33,000
Net Oil Production (Bbl/d) 4,000
Natural Gas Realized Price Differential to NYMEX Henry Hub Before Hedging ($/Mcf) $(0.20) - $(0.30)
Oil Realized Price Differential to NYMEX WTI Before Hedging ($/Bbl) $(12.00) - $(14.00)
NGL Realized Price (% of WTI)(1) 30% - 35%
Cash Production Expense ($/Mcfe)(2) $1.50 - $1.60
Marketing Expense, Net of Marketing Revenue ($/Mcfe) $0.20 - $0.30
G&A Expense ($/Mcfe) $0.23 - $0.27
Net Income Attributable to Non-Controlling Interest ($MM) $23 - $27
Operated Wells Completed 130
Average Operated Drilling Rigs 14
Capital Expenditures ($MM)
Drilling & Completion $1,600
Water Infrastructure $50
Land $150
Total Capital Expenditures ($MM) $1,800
1. Updated NGL pricing guidance for 2015; 1Q 2015 NGL prices before hedges were 50% of WTI per press release dated 4/29/2015.2. Includes lease operating expenses, gathering, compression and transportation expenses and production taxes. Excludes net marketing expense.
Key Operating & Financial Assumptions
49
IMPACT OF DROP DOWN TRANSACTION ON ANTERO FINANCIAL STATEMENTS
50
Metrics
Pre-Drop DownAntero Resources
(Consolidated)
Pro Forma Drop DownAntero Resources
(Consolidated)Antero Midstream
Partners
Fresh Water Distribution Fees N/A - Eliminated Upon Consolidation
N/A - Eliminated Upon Consolidation Revenue
Fresh Water Operating Expenses ("Opex") Drilling & Completion Capital
Drilling & Completion Capital
Operating Expenses
Fresh Water Infrastructure Capital Water Capital Water Capital Water Capital
Advanced Wastewater Treatment Fees(Upon 4Q ‘17 Expected In-Service) N/A N/A - Eliminated Upon
Consolidation Revenue
Advanced Wastewater Treatment Opex (Upon 4Q ‘17 Expected In-Service) N/A Drilling & Completion
Capital and LOEOperating Expenses
Advanced Wastewater Treatment Capital(Upon 4Q ‘17 Expected In-Service) Water Capital Water Capital Water Capital
2016E EBITDA Multiple of Drop Down N/AN/A - Water Fees are
Eliminated and Opex is Capitalized
8.5x - 9.0x
Implied 2016 EBITDA of Water Business N/AN/A - Water Fees are
Eliminated and Opex is Capitalized
~ $115 - $125 Million
LTM Production
NTM Production Forecast
Average LTM Production
MAINTENANCE CAPITAL METHODOLOGY
• Maintenance Capital Calculation Methodology– Estimate the number of new well connections needed during the forecast period in order to offset the natural
production decline and maintain the average throughput volume on our system over the LTM period
– (1) Compare this number of well connections to the total number of well connections estimated to be made during such period and
– (2) Designate an equal percentage of our estimated 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
51
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, 2014 assume ethane rejection and strip pricing.
Actual quantities that may be ultimately recovered from Antero’s interests may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery include the scope of Antero’s ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates.
In this presentation:
• “3P reserves” refer to Antero’s estimated aggregate proved, probable and possible reserves as of December 31, 2014. The SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.
• “EUR,” or “Estimated Ultimate Recovery,” refers to Antero’s internal estimates of per well hydrocarbon quantities that may bepotentially recovered from a hypothetical future well completed as a producer in the area. These quantities do not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules.
• “Condensate” refers to gas having a heat content between 1250 BTU and 1300 BTU in the Utica Shale.
• “Highly-rich gas/condensate” refers to gas having a heat content between 1275 BTU and 1350 BTU in the Marcellus Shale and 1225 BTU and 1250 BTU in the Utica Shale.
• “Highly-rich gas” refers to gas having a heat content between 1200 BTU and 1275 BTU in the Marcellus Shale and 1200 BTU and 1225 BTU in the Utica Shale.
• “Rich gas” refers to gas having a heat content of between 1100 BTU and 1200 BTU.
• “Dry gas” refers to gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.
Regarding Hydrocarbon Quantities
52