Download - Company website presentation february 2015
FORWARD-LOOKING STATEMENTS
This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Antero Resources Corporation and its subsidiaries (collectively, the “Company” or “Antero”) expects, believes or anticipates 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 estimates of the Company’s reserves, expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company’s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company 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 Company, 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, 2013 and in the Company’s subsequent filings with the SEC.
The Company cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013 and in the Company’s subsequent filings with the SEC.
Any forward-looking statement speaks only as of the date on which such statement is made and the Company 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
OUTSTANDING RESERVE GROWTH
1. 2013 and 2014 reserves assuming ethane rejection.2
PROVED RESERVE GROWTH(1)
3P RESERVE GROWTH(1)
• Proved reserves increased 66% to 12.7 Tcfe
• 3P reserves increased 16% to 40.7 Tcfe
• Replaced 1,465% of 2014 production
• All-in finding and development cost of $0.61/Mcfe for 2014
• Only 66% of 3P Marcellus locations booked as SSL (1.7 Bcf/1,000’ type curve) at 12/31/2014
• No Utica Shale WV/PA dry gas reserves booked; estimated net resource of 11.1 Tcf
7.2
11.90.4
0.6
0
3
6
9
12
15
2013 2014
(Tcfe)
Marcellus Utica
12.7
25.0 28.4
5.87.64.24.6
05
1015202530354045
2013 2014
(Tcfe)
Marcellus Utica Upper Devonian
Key Drivers
4.2
POTENTIAL RESERVE GROWTH DRIVERS
2014 RESERVE ANNOUNCEMENT
• Marcellus SSL completions
• Marcellus rich gas drilling
• Utica increased density andstep-out drilling
• WV/PA Utica dry gas drilling
• Core acreage acquisitions
Driver 2015 ActivityComplete transition to SSL type curve
7.6
35.040.7
• Successful drilling
• SSL results
• Expanded proved footprint
• 93,000 net acres added in 2014
• SSL results
• Utica results
$150 MM budget for 2015
Drilling and monitoring of Utica density and step-out pilots
Industry drilling activity in WV/PA (170,000 net acres)
Key Drivers
New rich gas delineation wells
ANTERO RESOURCES – 2015 GUIDANCE
Key Variable 2015 Guidance Range
Net Daily Production (MMcfe/d) 1,400
Net Residue Natural Gas Production (MMcf/d) 1,175
Net Liquids Production (Bbl/d) 33,000
Net Oil Production (Bbl/d) 4,000
Natural Gas Realized Price Differential to NYMEX Henry Hub Before Hedging ($/Mcf) $(0.20) - $(0.30)
Oil Realized Price Differential to NYMEX WTI Before Hedging ($/Bbl) $(12.00) - $(14.00)
NGL Realized Price (% of WTI) 48% - 52%
Cash Production Expense ($/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. Financial assumptions per Company press release dated 1/20/2015.2. Includes lease operating expenses, gathering, compression and transportation expenses and production taxes. Excludes net marketing expense.
Key Operating & Financial Assumptions
3
4
Most Active Operatorin Appalachia
Most ActiveLand Organization
in Appalachia
Largest Firm Transport and Processing
Portfolio in Appalachia
Largest Gas Hedge Position in U.S. E&P +
Strong Financial Liquidity
Highest Growth Large Cap E&P
Largest Liquids-Rich Core Position in
Appalachia
Highest Realizations and Margins Among
Large Cap Appalachian Peers
Growth Land
Liquidity
Midstream
Drilling
LEADING UNCONVENTIONAL BUSINESS MODEL
MLP (NYSE: AM)Highlights
Substantial Value in Midstream Business
Realizations
Takeaway
Liquids-Rich1
2 3
4
5
67
8
Premier AppalachianE&P Company
Run by Co-Founders
Downstream LNGand NGL Sales
Production andCash Flow Growth
5
Antero has 170,000 net acres in WV and PA prospective for Utica dry gas – adjacent to current industry activity with highly encouraging initial results
CATALYSTS
40% production growth targeted for 2015 with 94% hedged at $4.42/MMBtu; capital budget flexibility to commodity price changes
Large, low cost core Marcellus and Utica natural gas drilling inventory with associated liquids generates attractive returns supported by long-term natural gas hedges, takeaway portfolio and downstream LNG and NGL sales agreements
Pursuing additional value enhancing long-term LNG and NGL sales agreements, supported by firm takeaway
Antero owns 70% of Antero Midstream Partners and thereby participates directly in its growth and value creation
Midstream MLP Growth
Sustainability of Antero’s Integrated
Business Model
Potential Water System Monetization
1
2
3
4
5
6
Contingent on receiving private letter ruling from the IRS, AM holds an option to acquire Antero’s fresh water system at fair market value
Utica Dry GasActivity
DRILLING – MOST ACTIVE OPERATOR IN APPALACHIA
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 and rig count as of 1/23/2015 per RigData. 6
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 51.8 TcfeNet 3P Liquids 1,026 MMBbls% Liquids – Net 3P 15%4Q 2014E Net Production 1,265 MMcfe/d- 4Q 2014E Net Liquids 30,400 Bbl/dNet Acres(1) 543,000Undrilled 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 148,000Undrilled 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 395,000Undrilled 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 11.1 TcfNet Acres 170,000Undrilled Locations 1,616
0
5
10
15
20
25
Rig
Cou
nt
Operators
SW Marcellus & Utica(2)
40.0%
27.3% 26.8%
23.6%
21.1%20.0% 19.3% 19.1%
16.2%
12.4%
8.5%
5.3% 5.1%3.8%
2.1% 1.8%
(0.3%) (2.8%)
-5%
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
7Appalachian Peers
Source: Represents median of Wall Street research estimates for 2015E production growth vs. 2014 estimated production. 1. Includes all North American E&P companies with a market capitalization greater than $8.0 billion. 2. Based on publicly announced 2015 production growth target.
Antero’s 40% production growth target for 2015 leads the U.S. large cap E&P industry(1)
GROWTH – HIGHEST GROWTH LARGE CAP E&P
(2)
(2)
0
600
1,200
1,800
2010 2011 2012 2013 2014 2015E
Marcellus Utica Guidance
30124
239
522
1,400
1,007
1. 2012, 2013 and 2014 proved reserves assuming ethane rejection.2. Per current First Call median estimate from Bloomberg.
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
2010 2011 2012 2013 2014
Marcellus Utica
677
2,8444,283
7,632
(1) (1) (1)
12,683
8
AVERAGE NET DAILY PRODUCTION (MMcfe/d)NET PROVED SEC RESERVES (Bcfe)
0
25
50
75
100
125
150
175
200
2010 2011 2012 2013 2014 2015E
Marcellus Utica Deferred Completions
1938
60
114
177 180
130
GROWTH – STRONG TRACK RECORD
OPERATED GROSS WELLS COMPLETED EBITDAX ($MM)
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
2010 2011 2012 2013 2014E
$28$160
$285
$649
$1,144
(2)
40% GrowthGuidance
92% Growth
Assembled a 543,000 net acre position in the core of the Marcellus and Utica shale plays over the past 6 years
December 2008
Net Acreage 118,000
Net Production (MMcfe/d) NM
3P Reserves (Bcfe) NM
3P PV-10 ($MM) NM
Rigs Running NM
Dec 2008 Dec 2011 Dec 2014
December 2011(1)
Net Acreage 213,000
Net Production (MMcfe/d) 167
3P Reserves (Bcfe) 18,400
3P PV-10 ($MM) $9,000
Rigs Running 5
December 2014(1)
Net Acreage 543,000
Net Production (MMcfe/d) 1,265
3P Reserves (Bcfe) 40,700
3P PV-10 ($MM) $22,800
Rigs Running 21
1. Net daily production for December 2011 and December 2014 is for the fourth quarter, respectively.
LAND – MOST ACTIVE LAND ORGANIZATIONIN APPALACHIA
9
118,000 118,000 118,000 162,000 189,000 213,000
285,000 371,000
420,000 450,000 486,000
543,000
0
100,000
200,000
300,000
400,000
500,000
600,000
12/2008 12/2009 6/2010 12/2010 6/2011 12/2011 6/2012 12/2012 6/2013 12/2013 6/2014 12/2014
Antero Net Acreage
Utica Marcellus
10
LIQUIDS-RICH – LARGEST CORE POSITION
Source: Core outlines and peer net acreage positions based on peer presentations, news releases and 10-K/10-Qs.
Antero has the largest liquids-rich core position in Appalachia ≈371,000 net acres (> 1100 Btu)
MIDSTREAM – MLP (NYSE: AM) HIGHLIGHTSSUBSTANTIAL VALUE IN MIDSTREAM BUSINESS
1. AR enterprise value excludes AM minority interest and cash. Values as of 1/16/2015.2. Based on First Call 9/30/2015 NTM EBITDA forecast of $142 million for Water Business included in preliminary AM S-1 and applying AR enterprise value to EBITDAX multiple derived from First Call AR
9/30/2015 NTM EBITDAX estimates.3. Represents difference between AR enterprise value and Antero Midstream net market value and Water System enterprise value.4. Based on 262.0 million AR shares outstanding.
11
Antero ResourcesCorporation (NYSE: AR)
$13.0 Billion Enterprise Value(1)
Ba3/BB Corporate Rating
Antero MidstreamPartners LP (NYSE: AM)$3.4 Billion Valuation(1)
70% Limited Partner Interest
E&P Assets
Gathering Assets
Corporate Structure Overview(1)
Market Valuation of AR Ownership in AM:• AR ownership: 69.7% LP Interest = 105.9 million units
AM Priceper Unit
AM UnitsOwnedby AR(MM)
AR Value in AM LP Units
($MMs)Value Per
AR Share(4)
$22 106 $2,332 $9$23 106 $2,445 $9$24 106 $2,544 $10$25 106 $2,647 $10$26 106 $2,753 $11$27 106 $2,858 $11$28 106 $2,964 $12
Fresh Water Distribution System
Compression Assets
= $2.4 Billion Market Valuation(1) $9.1 Billion Implied Valuation(3)$1.5 Billion Derived Valuation(2)
TAKEAWAY – LARGEST FIRM TRANSPORTATION AND PROCESSING PORTFOLIO IN APPALACHIA
Odebrecht / Braskem30 MBbl/d Commitment
Ascent Cracker(Pending Final
Investment Decision)
Antero Long Term Firm Processing & Takeaway Position (2018) – Accessing Favorable Markets
Mariner East II62 MBbl/d Commitment(2)
Marcus Hook Export
Shell25 MBbl/d CommitmentBeaver County Cracker
(Pending FinalInvestment Decision)
Sabine Pass (Trains 1-4)50 MMcf/d per Train
1. February 2015 and full year 2016 futures basis, respectively, provided by Wells Fargo dated 12/31/2014. Favorable gas markets shaded in green.2. As an anchor shipper on Mariner East II, Antero has the right to expand its NGL commitment with notice to operator.
Chicago(1)
+$0.23 / $(0.08)
CGTLA(1)
$(0.08) / $(0.09)
Dom South(1)
$(1.38) / $(1.11)
TCO(1)
$(0.13) / $(0.41)
12
4 Bcf/dFirm Gas TakeawayBy 2018
Cove Point
1,316 943 780 1,073 818 40
$4.42 $4.47 $4.34 $4.50 $4.41 $4.41
$3.09$3.48 $3.77 $3.95 $4.08 $4.21
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
0200400600800
1,0001,2001,400
2015 2016 2017 2018 2019 2020
BBtu/d $/MMBtu
13
Average Index Hedge Price(1)Hedged Volume Current NYMEX Strip(2)
COMMODITY HEDGE POSITION
1. Reflects weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio. Antero has hedged 3,000 Bbl/d of oil and 23,000 Bbl/d of propane for 2015. 2. As of 12/31/2014.3. Percentage of net gas equivalent production target hedged for respective years.
~$1.6 billion mark-to-market unrealized gain based on 12/31/2014 prices 1.8 Tcfe hedged from January 1, 2015 through year-end 2020 and 262 Bcf of TCO basis hedges from 2015 to 2017
$689 MM $464 MM $176 MM $214 MM $98 MM $3 MM
Mark-to-Market Value(2)
LIQUIDITY – LARGEST GAS HEDGE POSITION IN U.S. E&P + STRONG FINANCIAL LIQUIDITY
$3,000
$2,012
($1,505)
($332) $6 $843
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
Credit Facility9/30/2014
Bank Debt9/30/2014
L/Cs Outstanding9/30/2014
Cash9/30/2014
AM IPOProceeds
to AR
Pro FormaLiquidity
9/30/2014
AR LIQUIDITY POSITION ($MM) AM LIQUIDITY POSITION ($MM)
$1,000$1,250
$0 $0 $0
$250
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
Credit Facility9/30/2014
Bank Debt9/30/2014
L/Cs Outstanding9/30/2014
Cash9/30/2014
AM IPO Proceeds
to AM
Pro FormaLiquidity
9/30/2014
≈ 94% of 2015ETarget
Production(3)
Over $3 billion of combined AR and AM financial liquidity as of 9/30/2014, pro forma for AM IPO closed on 11/10/2014
1. Includes firm sales. 2. Price realization includes $0.05 of midstream revenues in 3Q, 2014. 3. Includes natural gas hedges.4. Source: Public data from 3Q 2014 10-Qs. Peers include Cabot Oil & Gas, CONSOL Energy, EQT Corp. and Range Resources. 5. Includes realized hedge gains and losses. Operating costs include lease operating expenses, production taxes, gathering, processing and firm transport costs and general and administrative costs. 4-year
proved reserve average all-in F&D from 2010-2013. Calculation = (Development costs + exploration costs + leasehold costs) / Total reserves added (2013 ending reserves – 2010 beginning reserves + 4-year reserve sales – 4-year reserve purchases + 4-year accumulated production). AR price realization includes $0.04 of midstream revenues.
$4.16 $3.97
$0.58 $0.95 $0.74 $0.77 $0.81
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
Antero Peer 1 Peer 2 Peer 3 Peer 4
$/M
cfe
LOE Production Taxes GPT G&A EBITDAX 4-year Avg. All-in F&D ($/Mcfe)
$4.96
$3.25
$4.48
$2.93
$2.40$2.64
$2.11 $2.09
14
REALIZATIONS – HIGHEST REALIZATIONS & MARGINSAMONG LARGE-CAP APPALACHIAN PEERS
3Q & 4Q 2014 Natural Gas Realizations ($/Mcf)
3Q 2014 Natural Gas Realizations(3) 3Q 2014 Price Realization & EBITDAX Margin vs F&D(2)(4)
$4.31
$4.12$3.66 $3.62 $3.60
$2.98 $2.87 $2.75
$0.00
$2.00
$4.00
$6.00
AR EQT GPOR RRC CNX RICE ECR COG
$/M
cf
3Q 2014 NYMEX = $4.06/Mcf
AR Peer 1 Peer 2 Peer 3 Peer 4
Average NYMEX
Price($/Mcf)
AverageDifferential(1)
($/Mcf)
AverageBTU Upgrade
($/Mcf)
Discount to NYMEX($/Mcf)
GasHedgeEffect
($/Mcf)
AverageRealized
Gas Price($/Mcf)
AverageRealized Gas
Premium/ Discount
($/Mcf)
Liquids Upgrade($/Mcfe)
Realized Equivalent
Price($/Mcfe)
Equivalent Premium($/Mcfe)
3Q 2014 $4.06 $(0.84) $0.41 $(0.43) $0.68 $4.31 $0.25 $0.60 $4.91 $0.85
4Q 2014 $4.00 $(0.71) $0.37 $(0.34) $0.73 $4.39 $0.39 $0.29 $4.68 $0.68
DOM S 22%
DOM S - 9% DOM S - 6%
TETCO M2 - 7%
TETCO M2 - 6%
TCO 24%
TCO 16%
TCO - 9%
NYMEX8%
NYMEX11%
NYMEX10%
Gulf Coast18%
Gulf Coast38%
Gulf Coast56%
Chicago21%
Chicago20%
Chicago19%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
($/Mcf) 2015ENYMEX Strip Price(1) $3.09Basis Differential to NYMEX(1) $(0.46)BTU Upgrade(6) $0.26 Estimated Realized Hedge Gains $1.35 Realized Gas Price with Hedges $4.24 Premium to NYMEX +$1.15Liquids Impact +$0.39Premium to NYMEX w/ Liquids +$1.54Realized Gas-Equivalent Price $4.63
4. Represents 60,000 MMBtu/d of TCO index hedges and 270,000 MMBtu/d of TCO basis hedges that are matched with NYMEX hedges for presentation purposes.
5. Represents 107,500 MMBtu/d of TCO basis hedges matched with NYMEX hedges.6. Assumes ethane rejection resulting in 1100 BTU residue sales gas.
REALIZATIONS – REALIZED PRICE “ROAD MAP”
1. Based on 12/31/14 strip pricing. 2. Differential represents contractual deduct to NYMEX-based firm sales contract.3. Represents 120,000 MMBtu/d of TCO index hedges and 390,000 MMBtu/d of TCO basis hedges that are
matched with NYMEX hedges for presentation purposes.
2015Basis(1)
2016 Basis(1)
2017 Basis(1)
2015Hedges
2016Hedges
2017Hedges
Mar
kete
d %
of T
arge
t Re
sidu
e G
as P
rodu
ctio
n
+$0.05/MMBtu
$(0.25)/MMBtu(2)
$(1.28)/MMBtu
$(0.24)/MMBtu
$(0.07)/MMBtu
$(0.25)/MMBtu(2)
$(1.11)/MMBtu
$(0.41)/MMBtu
$(0.20)/MMBtu
$(0.25)/MMBtu(2)
$(0.83)/MMBtu
$(0.50)/MMBtu
$(0.09)/MMBtu
$(0.07)/MMBtu
182,500 MMBtu/d
@ $4.38/MMBtu
107,500 MMBtu/d
@ $3.88/MMBtu (5)
40,000 MMBtu/d
@ $4.00/MMBtu
230,000 MMBtu/d
@ $5.60/MMBtu
510,000 MMBtu/d
@ $3.87/MMBtu(3)
170,000 MMBtu/d
@ $4.09/MMBtu
272,500 MMBtu/d
@ $5.35/MMBtu
330,000 MMBtu/d
@ $3.82/MMBtu(4)
85% exposure to favorable price indices$1.35/Mcfe in estimated hedge gains(1)
71% exposure to favorable price indices94% exposure to favorable price indices
Antero is forecasting realized gas prices including hedges at a premium to NYMEX for 2015, assuming current strip pricing,(1)
current basis differentials, existing firm transportation and hedges
$(1.35)/MMBtu
$(1.26)/MMBtu
Wtd. Avg.Basis ($0.46)
Wtd. Avg.Basis $(0.32)
1,160,000 MMBtu/d@ $4.34/MMBtu
Wtd. Avg.Basis $(0.18)
942,500 MMBtu/d@ $4.47/MMBtu
420,000 MMBtu/d
@ $4.27/MMBtu
2015E 2016E 2017E
15
380,000 MMBtu/d
@ $3.88/MMBtu
170,000 MMBtu/d
@ $3.35/MMBtu
70,000 MMBtu/d
@ $4.57/MMBtu
780,000 MMBtu/d@ $4.34/MMBtu
$(0.10)/MMBtu
$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
$1.94 $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
PREMIER POSITION IN LOW-COST RICH GAS PLAYS
North American Gas Resource Play Breakeven Natural Gas Price(3)
17
North American Breakeven Oil Prices ($/Bbl)(1)
2015 NYMEX Strip: $3.01/MMBtu(2)
2015 WTI Strip: $56.26/Bbl(2)
Over 70% of Antero’s 4,243 Marcellus and Utica undeveloped 3P locations are rich gas locations which have the lowest breakeven prices for both oil and natural gas compared to other U.S. shale plays
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% WTI vs. 48%-52% for Antero per guidance.
Antero Projects
0%
10%
20%
30%
40%
248
139 94
254289
10%
31%
46%
33% 30%
0
100
200
300
0%
20%
40%
60%
Condensate Highly-RichGas/
Condensate
Highly-RichGas
Rich Gas Dry Gas
Tota
l 3P
Loca
tions
RO
R
Locations ROR
MARCELLUS SSL WELL ECONOMICS(1)
664
1,010
62888942%
28%
12% 11%
0
300
600
900
1,200
0%
15%
30%
45%
60%
Highly-RichGas/
Condensate
Highly-RichGas
Rich Gas Dry Gas
Tota
l 3PL
loca
tions
RO
R
Locations ROR
MULTI-YEAR DRILLING INVENTORY SUPPORTS LOW RISK, HIGH RETURN GROWTH PROFILE
Large 3P Drilling Inventory of High Return Projects(2)
1. Pre-tax well economics based on 12/31/2014 natural gas and WTI strip pricing for 2015-2020, flat thereafter, NGLs at 55% of oil price and applicable firm transportation costs; 8,000’ lateral. 2. Source: Credit Suisse report dated December 2014 – After-tax internal rate of return based on 12/31/2014 strip pricing.
26% 26%31%
15%
Inte
rnal
Rat
e of
Ret
urn
(%)
20%
18
UTICA WELL ECONOMICS(1)
72% of Marcellus locations are processable (1100-plus Btu) 72% of Utica locations are processable (1100-plus Btu)
3,037 Antero Liquids-Rich Locations
16%
2015Drilling Plan
Antero Projects
Antero is well positioned in the core of the highest return shale projects in the U.S. in the current commodity price environment
LNG Exports48%
Mexico/Canada Exports
18%
Power Generation
17%
Transportation1%
Industrial16%
20 Bcf/d OF INCREMENTAL GAS DEMAND BY 2020 Significant demand growth expected for U.S.
natural gas
More than 65% of the 20 Bcf/d in incremental gas demand forecast by 2020 is expected to be generated from exports:− LNG: 9.5 Bcf/d (~48%)− Mexico/Canada: 3.5 Bcf/d (~18%)
Of the 9.5 Bcf/d of expected incremental demand from LNG export projects, 5.8 Bcf/d (or 61%) of the projects have secured the necessary DOE and FERC permits
19
Incremental Demand Growth Through 2020 by Category
Projected Incremental Natural Gas Demand Through 2020
Source: Simmons & Company International, “2015 US Natural Gas Outlook and Updated Long Term Demand Forecast,” September 2014.
Sherwood 7 2
5
9
13
17
20
0
4
8
12
16
20
2015 2016 2017 2018 2019 2020Mexico/Canada Exports Power GenerationTransportation PetrochemLNG Exports
9.5 Bcf/d of the 20 Bcf/d of incremental demand is expected to come from
LNG exports
(Bcf/d)
LNG
Exports
Power Gen
Petrochem
LNG EXPORTS BY PROJECT – EXPECTED START UP
Assuming 9.5 Bcf/d of LNG exports by 2020, the U.S. would be the world’s 3rd largest LNG exporter (behind Qatar and Australia)− 7.7 Bcf/d (81%) of the 9.5 Bcf/d of expected LNG
exports have secured US DOE non-FTA (free trade agreement) permit approval
− 6.7 Bcf/d (four projects, 70%) have been awarded FERC construction permits (see next page for more detail)
The first LNG export project, Sabine Pass LNG Train 1 is expected to commence operations in early 2016− Antero has committed to 200 MMcf/d on Sabine
Pass Trains 1-4
The second LNG export project, Cove Point LNG, is expected to commence operations in 2017− Antero has committed to 330 MMcf/d on Cove
Point 1-2
20
LNG Exports by Project Through 2020
LNG Exports by Project(in Bcf/d)
2015 2016 2017 2018 2019 2020
Sabine Pass 1 - 0.6 - - - - Sabine Pass 2 - 0.6 - - - - Sabine Pass 3 - - 0.6 - - - Sabine Pass 4 - - 0.6 - - - Sabine Pass 5 - - - - 0.6 - Cove Point 1 - - 0.4 - - - Cove Point 2 - - - 0.4 - - Cameron 1 - - - 0.6 - - Cameron 2 - - - 0.6 - - Cameron 3 - - - - 0.6 - Freeport 1 - - - 0.5 - - Freeport 2 - - - - 0.5 - Freeport 3 - - - - 0.5 - Freeport 4 - - - - - 0.4Corpus Christi 1 - - - - 0.6 - Corpus Christi 2 - - - - - 0.6Lake Charles 1 - - - - - 0.6
LNG Incremental Exports - 1.2 1.6 2.2 2.9 1.7
Antero Supply Agreements for Portion of Capacity
Source: Simmons & Company International, “2015 US Natural Gas Outlook and Updated Long Term Demand Forecast,” September 2014. Note: Data updated for recent announcements subsequent to Simmons report.
Antero Supplied
MARCELLUS/UTICA DRIVING GAS SUPPLY GROWTH
Of the 23 Bcf/d of expected incremental gas supply from 2009 to 2015, ~18 Bcf/d, or 78%, is expected to be generated from Marcellus and Utica production
Marcellus and Utica gross gas production in 2015 is expected to grow 3.6 Bcf/d, which represents the total expected growth in overall supply from all areas for 2015(1)
21
Gas Supply Growth by Area: 2009 – 2015E
Lower 48 Gas Supply by Area
Source: Simmons & Company International, “2015 US Natural Gas Outlook and Updated Long Term Demand Forecast,” September 2014; EIA.1. Other contributing areas to growth include the Permian (+0.5 Bcf/d), Eagle Ford (+0.6 Bcf/d), Williston (+0.3 Bcf/d) and DJ (+0.2 Bcf/d), offset by declines in the Barnett (-0.3 Bcf/d)
and Haynesville (-0.6 Bcf/d).
Sherwood 7
Marcellus & Utica 78%
Eagle Ford 22%
(MMcf/d)
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000Nov-12 Nov-13 Nov-14
Marcellus production has driven U.S. gas
supply growth
WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECT
100% operatedOperating 13 drilling rigs
including 5 intermediate rigs395,000 net acres in
Southwestern Core (73% includes processable rich gas assuming an 1100 Btu cutoff)– 50% HBP with additional 27%
not expiring for 5+ years362 horizontal wells completed
and online– Laterals average 7,400’– 100% drilling success rate5 plants in-service at Sherwood
Processing Complex capable of processing 1 Bcf/d of rich gas−Over 800 MMcf/d being
processed currentlyNet production of 937 MMcfe/d in
3Q 2014, including 17,300 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 Gas
130,000 Net Acres1,010 Gross Locations
Rich Gas91,000 Net Acres
628 Gross Locations
Dry Gas105,000 Net Acres
889 Gross Locations
Highly-Rich/Condensate69,000 Net Acres
664 Gross Locations
HEFLIN UNIT30-Day Rate
2H: 21.4 MMcfe/d (21% liquids)
CONSTABLE UNIT30-Day Rate
1H: 14.3 MMcfe/d (26% 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)
23
MHR COLLINS UNIT30-Day Rate
4-well average9.3 MMcfe/d (26% liquids)
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
$0.5
$1.0
$1.5
$2.0
$2.5
$3.0
2,000 4,000 6,000 8,000 10,000
$MM
/ 1,
000'
Lateral length, ft
0.0
3.0
6.0
9.0
12.0
15.0
0.0
3.0
6.0
9.0
12.0
15.0
0 1 2 3 4 5 6 7 8 9 10
Cum
ulat
ive
Bcf
MM
cf/d
Production Year
Non-SSL Type Curve (1.5 Bcf/1,000') Non-SSL Actual Production Non-SSL Type Curve Cumulative Production
SSL Type Curve (1.7 Bcf/1,000') SSL Actual Production SSL Type Curve Cumulative Production
Antero has over five years of production history to support its Non-SSL type curve Antero has one and a half years of production history to support its SSL type curve: 1.7 Bcf/1,000’ with only 10% to 15% higher well costs vs. Non-SSL Lack of faulting and contiguous acreage position allows for drilling of long laterals; ~7,400’ average since inception and ~8,000’ in 2014− Drives down cost per 1,000’ of lateral resulting in best in class development costs
ANTERO’S MARCELLUS SHALE TYPE CURVE
1. 198 Antero Marcellus Non-SSL wells normalized to time zero, production for each well normalized to 8,000’ lateral length.2. 164 Antero Marcellus SSL wells normalized to time zero, production for each well normalized to 8,000’ lateral length.
Marcellus Type Curves – Normalized to 8,000’ Lateral(1)
EURs Increase With Lateral Length Well Cost / 1,000’ Decreases with Lateral Length
(2)
Actual Rates24-Hour
Peak Rate30-Day
Avg. Rate90-Day
Avg. Rate180-Day
Avg. RateOne-Year Avg. Rate
Two-Year Avg. Rate
Three-YearAvg. Rate
Four-Year Avg. Rate
Wellhead Gas (MMcf/d) 15.3 9.2 7.1 5.8 4.3 3.2 2.6 1.8# of Antero Wells 362 343 322 291 227 124 63 24
24
0
5
10
15
20
25
2,000 4,000 6,000 8,000 10,000
EUR
, BC
F
Lateral Length, ft
Antero’s Marcellus average 30-day rates have increased by 64% over the past two years as the Company increased per well lateral lengths by 20% and shortened stage lengths by 43%
INCREASING RECOVERIES AND LOW VARIANCEIN MARCELLUS
1. Processed rates converting C3+ NGLs and condensate at 6:1. Ethane rejected and sold in gas stream.
30-Day Rates – 343 Marcellus Wells(1)
25
SSL Reserves per 1,000’ of Lateral – 164 Marcellus SSL Wells
0
5
10
15
20
25
MM
cfe/
d
2014 – 13.1 MMcfe/d
2013 – 9.4 MMcfe/d
2009–2012 – 8.0 MMcfe/d
The Marcellus is a reliable, low risk play as demonstrated by the relatively tight distribution of EURs per 1,000’ and the P10/P90 ratio of only 1.5x for 164 SSL wells
05
101520253035
1.3 1.4 1.5 1.6 1.7 1.8 1.9 2 2.1 2.2 2.3 2.4 2.5 2.6 2.7 > 2.7
Wel
l Cou
nt
Bcfe/1,000‘ of Lateral
2.0
P10/P90 = 1.5x
P90 P10
411 420
361
283
200 185
14 16
21
27
40 45
- 5 10 15 20 25 30 35 40 45 50
- 50
100 150 200 250 300 350 400 450
2010 2011 2012 2013 2014 2015E
Ave
rage
Fra
c St
ages
per
Wel
l
Ave
rage
Sta
ge L
engt
h (F
eet)
Increasing Frac Stages per Well
Average Stage Length (Feet) Average Frac Stages per Well
(1)
1.5 1.6 1.5 1.62.0
$0.97 $0.89
$0.98 $1.13
$0.89
$0.00
$0.20
$0.40
$0.60
$0.80
$1.00
$1.20
0.00
0.50
1.00
1.50
2.00
2.50
2010 2011 2012 2013 2014
Dev
elop
men
t Cos
t ($/
Mcf
e)
EUR
/1,0
00' L
ater
al
EUR vs. Development Cost
EUR/1,000' Lateral (Bcfe) Development Cost ($/Mcfe) 26
MARCELLUS WELL PERFORMANCE IMPROVEMENTS Increasing recoveries and efficiencies, through longer laterals, shorter stage lengths and faster drilling SSL completions drove a 21% decline in estimated development costs in 2014 while lower service costs are expected
to drive further development cost reductions in 2015
1. 2015 reflects Antero guidance per 1/20/2015 press release.
37 36 34 32 29
13,181 14,067 14,658 14,607 15,355
-
4,000
8,000
12,000
16,000
20,000
0
10
20
30
40
50
2010 2011 2012 2013 2014
Tota
l Mea
sure
d D
epth
(Fee
t)
Spud
-to-S
pud
Day
s
Increasing Drilling Efficiency
Avg Spud-to-Spud Days Total Measured Depth (Feet)
5,732 6,717
7,345 7,308
8,052 8,400
19
38
59
103
136
80
0
20
40
60
80
100
120
140
160
0
2,000
4,000
6,000
8,000
10,000
2010 2011 2012 2013 2014 2015E
Wel
ls o
n Fi
rst S
ales
Late
ral L
engt
h (1
,000
Fee
t)
Lateral Length Improvements
Average Lateral Length (Feet) Wells on First Sales
(1)
0%
20%
40%
60%
80%
100%
$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
271. Assumes 12/31/2014 strip pricing, market differentials and relevant transportation cost; 8,000’ 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 2015-2020, flat thereafter; NGL price 55% of WTI
NYMEX Flat Price Sensitivity(1)
ROR% at Flat 2015-2020 Strip Price
Highly-Rich Gas/Condensate: 44%
Highly-Rich Gas: 30%
Rich Gas: 12%
Dry Gas: 11%
664 Locations
1,010 Locations
628 Locations
889 Locations
Antero Rigs Employed
2015Drilling Plan
Source: Company presentations and press releases. Note: Antero acreage position reflects townships in which greater than 3,000 net acres are held. Note: Third party peak rates assume ethane recovery; Antero 30-day rates in ethane rejection.1. For non-Antero wells, Antero has converted rich gas rates where BTU has been disclosed to NGLs, assuming ethane recovery. Where BTU has not been disclosed, Antero has estimated BTU and gas
composition.2. 30-day rate reflects restricted choke regime.
100% operated Operating 8 rigs including 3 intermediate rigs 148,000 net acres in the core rich gas/
condensate window (72% includes processable rich gas assuming an 1100 Btu cutoff)– 20% HBP with additional 79% not expiring
for 5+ years 52 operated horizontal wells completed and
online in Antero core areas− 100% drilling success rate
3 plants at Seneca Processing Complex capable of processing 600 MMcf/d of rich gas−Over 500 MMcf/d being processed currently,
including third party production Net production of 143 MMcfe/d in 3Q 2014
including 7,700 Bbl/d of liquids− Seneca 3 processing plant online in July
2014− 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)
LEADING UTICA SHALE CORE POSITION DELIVERS CONDENSATE AND NGLS
28
Utica Shale Industry Activity(1)
CadizProcessing
Plant
NORMAN UNIT30-Day Rate
2 wells average20.3 MMcfe/d (17% liquids)
RUBEL UNIT30-Day Rate
3 wells average21.1 MMcfe/d(24% liquids)
GULFPORT24-Hour IP
McCort1-28H, 2-28H, Stutzman 1-14H
Average 13.1 MMcf/d + 922 Bbl/d NGL
+ 21 Bbl/d Oil
GULFPORT24-Hour IP
Wagner 1-28H, Shugert 1-1H, 1-12H
Average 21.0 MMcf/d + 2,270 Bbl/d NGL
+ 292 Bbl/d Oil
Utica Core Area
GARY UNIT30-Day Rate
3 wells average29.8 MMcfe/d(22% liquids)
Highly-Rich/Cond26,000 Net Acres
139 Gross Locations
Highly-Rich Gas15,000 Net Acres
94 Gross Locations
Rich Gas33,000 Net Acres
254 Gross Locations
Dry Gas42,000 Net Acres
289 Gross Locations
NEUHART UNIT 3H30-Day Rate18.7 MMcfe/d(58% liquids)
Condensate32,000 Net Acres
248 Gross Locations
DOLLISON UNIT 1H30-Day Rate23.3 MMcfe/d(44% liquids)
MYRON UNIT 1H30-Day Rate30.4 MMcfe/d(49% liquids)
SenecaProcessingComplex
LAW UNIT30-Day Rate
2 wells average18.4 MMcfe/d(50% liquids)
SCHAFER UNIT30-Day Rate(2)
2 wells average16.2 MMcfe/d(49% liquids)
URBAN PAD30-Day Rate
4-well combined 30-Day Rate of
74 MMcfe/d (16% liquids)
1.4 1.6
$1.64
$1.24
$0.00
$0.30
$0.60
$0.90
$1.20
$1.50
$1.80
0.000.200.400.600.801.001.201.401.60
2013 2014
Dev
elop
men
t Cos
t ($/
Mcf
e)
EUR
/1,0
00' L
ater
al
EUR vs. Development Cost
EUR/1,000' Lateral (Bcfe) Development Cost ($/Mcfe) 29
UTICA WELL PERFORMANCE IMPROVEMENTS Increasing recoveries and efficiencies, through longer laterals, shorter stage lengths and faster drilling Lower service costs are expected to drive development cost reductions in 2015
1. 2015 reflects Antero guidance per 1/20/2015 press release.
32 29
14,643 16,321
-
3,000
6,000
9,000
12,000
15,000
18,000
0
10
20
30
40
2013 2014
Tota
l Mea
sure
d D
epth
(Fee
t)
Spud
-to-S
pud
Day
s
Increasing Drilling Efficiency
Spud-to-Spud Days Total Measured Depth (Feet)
6,431
8,021 8,700
11
41
50
0
10
20
30
40
50
60
0
2,000
4,000
6,000
8,000
10,000
2013 2014 2015E
Wel
ls o
n Fi
rst S
ales
Late
ral L
engt
h (F
eet)
Lateral Length Improvements
Average Lateral Length Wells on First Sales
(1)
289
183 175
26
47 50
-
10
20
30
40
50
60
-
50
100
150
200
250
300
350
2013 2014 2015E
Ave
rage
Fra
c St
ages
per
Wel
l
Ave
rage
Sta
ge L
engt
h (F
eet)
Increasing Frac Stages per Well
Average Stage Length (Feet) Average Frac Stages per Well
(1)
0%
20%
40%
60%
80%
100%
120%
140%
160%
180%
200%
$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 ROR% AND GAS PRICE SENSITIVITY
30
NYMEX Flat Price Sensitivity(1)
94 LocationsROR% at Flat 2015-2020 Strip Price
Condensate: 13%
Highly-Rich Gas/Condensate: 41%
Highly-Rich Gas: 63%
Rich Gas: 47%
Dry Gas: 44%
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 2015-2020, flat thereafter; NGL price 55% of WTI
1. Assumes 12/31/2014 strip pricing, market differentials and relevant transportation cost; 8,000’ lateral.
254 Locations
139 Locations
289 Locations
248 Locations
2015Drilling Plan
LARGE UTICA SHALE DRY GAS POSITION
31
Antero has 212,000 net acres of exposure to Utica dry gas play− 42,000 net acres in Ohio with net 3P reserves of 2.4 Tcf as of
12/31/2014− 170,000 net acres in West Virginia and Pennsylvania with net
resource of 11.1 Tcf as of 12/31/2014 (not included in 40.7 Tcfe of net 3P reserves)
− 1,616 locations underlying current Marcellus Shale leasehold in West Virginia and Pennsylvania as of 12/31/2014
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 #1-4H
5,714’ LateralIP 30.3 MMcf/d
EclipseTippens #6H5,858’ Lateral
IP 23.2 MMcf/d
Magnum HunterStalder #3UH5,050’ Lateral
IP 32.5 MMcf/d
AnteroPlanned
Utica Well2015
Well OperatorIP(MMcf/d)
Lateral Length (Ft)
Claysville SC #1 Range 59.0 5,420
Stewart Winland 1300U Magnum Hunter 46.5 5,289
Bigfoot 9H Rice Energy 41.7 6,957
Stalder #3UH Magnum Hunter 32.5 5,050
Irons #1-4H Gulfport 30.3 5,714
Pribble 6HU Stone Energy 30.0 3,605
Simms U-5H Gastar 29.4 4,447
Conner 6H Chevron 25.0 6,451
Tippens #6H Eclipse 23.2 5,858
Porterfield 1H-17 Hess 17.2 5,000
Hubbard BRK #3H Chesapeake 11.1 3,550
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 #1
5,420’ LateralIP 59.0 MMcf/d
ChevronConner 6H
6,451’ LateralIP 25.0 MMcf/d
GastarSimms 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
Utica Shale Dry GasWV/PA
Net Resource11.1 Tcf
1,616 Gross Locations170,000 Net Acres
Utica Shale Dry GasOhio
3P Reserves2.4 Tcf
289 Gross Locations42,000 Net Acres
Utica Shale Dry GasTotal OH/WV/PA
Net Resource13.5 Tcf
1,905 Gross Locations212,000 Net Acres
Stone EnergyPribble 6HU
3,605’ LateralIP 30.0 MMcf/d
ChesapeakeUtica Well
Drilling
RiceBlue Thunder
10H, 12H≈9,000’ Lateral
FRESH WATER DISTRIBUTION SYSTEMS
32
Marcellus Fresh Water Distribution System• Provides fresh water to support Marcellus well completions • Year-round water supply sources: Ohio River and local rivers• Significant growth projected over the next twelve months 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 6/30/2014 and 2015 guidance.2. Estimated fee of $3.50 per barrel at an average of 200,000 Bbls of water per well.
Utica Fresh Water Distribution System• Provides fresh water to support Utica well completions • Year-round water supply sources: local reservoirs and rivers• Significant growth projected over the next twelve months as summarized
below:
Marcellus Water System YE 2015
Water Pipeline (Miles) 49
Fresh Water Storage Impoundments 2
Water Fees per Well ($)(2) $600K -$800K
Utica Water System YE 2015
Water Pipeline (Miles) 29
Fresh Water Storage Impoundments 6
Water Fees per Well ($)(2) $600K -$800K
OHIO
Projected Midstream Infrastructure(1)
Marcellus Shale
Utica Shale Total
YE 2015E Cumulative Fresh Water System Capex ($MM) $338 $112 $450Water Pipelines (Miles) 226 90 316Water Storage Facilities 24 14 38
-
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
3,500,000
4,000,000
4,500,000
FIRM TRANSPORTATION AND FIRM SALES PORTFOLIO
33
MMBtu/d
Columbia7/26/2009 – 9/30/2025
Firm Sales #110/1/2011– 10/31/2019
Firm Sales #2
10/1/2011 – 5/31/2017Firm Sales #3
1/1/2013 – 5/31/2022
Momentum III9/1/2012 – 12/31/2023
EQT8/1/2012 – 6/30/2025
REX/MGT/ANR7/1/2014 – 12/31/2034
Tennessee11/1/2015– 9/30/2030
Mid-Atlantic/NYMEX
Gulf Coast
Appalachia or Gulf Coast
AppalachiaAppalachia
ANR3/1/2015– 2/28/2045
Midwest
Local Distribution11/1/2015 – 9/30/2037
Gulf Coast
$0.14 $0.17 $0.23$0.33$0.11 $0.11
$0.12
$0.13
$0.00
$0.10
$0.20
$0.30
$0.40
$0.50
$0.60
$0.70
2013A 2014E 2015E 2016E
($/M
MB
tu)
Wtd. Avg. FT Demand ($/MMBtu) Wtd. Avg. FT Commodity/Fuel ($/MMBtu)
All-in Firm Transportation Costs(1)
FIRM TRANSPORTATION REDUCES APPALACHIAN BASIS EXPOSURE
Appalachia 49%Gulf Coast
51%
2013 FirmTransportation(1)(2)
2013 Firm Transportation – 647 MMcf/dAverage All-in FT Cost $0.25/MMBtu
2016 Firm Transportation – 3.1 Bcf/dAverage All-in FT Cost $0.46/MMBtu
+ $0.18/MMBtu
Antero’s firm transportation (FT) portfolio increases visibility on production growth and increases exposure to Gulf Coast and Midwest pricing, with little incremental cost per Mcf
Reduces weighted average basis by $0.28 per MMBtu compared to 2014 basis(3) – while significantly reducing Appalachian basis exposure
Utilized portion included in cash production
expense(fixed cost)
1. Assumes full utilization of firm transportation capacity; page 15 assumes Antero targeted production figures.2. Represents accessible firm transportation and sales agreements.3. Based on current strip pricing as at 12/31/2014.
Included in cash production expense
(variable cost)$0.25 $0.28 $0.35
$0.46
2016 Basis(3)
TCO – $(0.41)/MMBtu DOM S – $(1.11)/MMBtu
2016 Basis(3)
Chicago – $(0.08)/MMBtu
2016 Basis(3)
CGTLA – $(0.09)/MMBtu
34
Appalachia35%
Midwest20%
Gulf Coast45%
ANTERO FIRM TRANSPORTATION APPROPRIATELY DESIGNED TO ACCOMMODATE GROWTH
351. Based on production target for 2015 of 1.4 Bcfe/d, per Antero guidance press release dated January 20, 2015. 2. Assumes 1100 BTU residue sales gas.3. Represents excess firm transportation that is deemed marketable to 3rd parties based on a positive differential between the receipt and delivery points of the FT capacity, less variable transport cost.
(BBtu/d)
2015Net Production Target (MMcfe/d) (1) 1,400 Net Gas Production Target (MMcf/d) 1,190
Net Revenue Interest Gross-up 80%Gross Gas Production Target (MMcf/d) 1,485
BTU Upgrade (2) x1.100 Gross Gas Production Target (BBtu/d) 1,630
Firm Transportation / Firm Sales (BBtu/d) 2,250 Estimated % Utilization of FT/FS 72%
Marketable Firm Transport (BBtu/d) (3) 350
Estimated % Utilization of FT/FS (Including Marketable FT) 86%
% FT Utilization (including
marketable FT):• Antero’s firm transport (FT) is well
utilized during 2015 (72%) − Excess FT for acquisitions and well
productivity improvements
• A portion of the excess FT is highly marketable, further increasing utilization to 86%
• Expect to fully utilize FT portfolio by 2018
86%
0
500
1,000
1,500
2,000
2,500
Marketable FT (BBtu/d) (3)Firm Transportation / Firm Sales (BBtu/d)Risked Gross Gas Production Target (BBtu/d)
Keys to Execution
Local Presence
Antero has more than 3,500 employees and contract personnel working full-time for Antero in West Virginia. 79% of these personnel are West Virginia residents.
Land office in Ellenboro, WV District office in Bridgeport, WV 200 (45%) of Antero’s 446 employees are located in West Virginia and Ohio
Safety & Environmental
Five company safety representatives and 56 safety consultants cover all material field operations 24/7 including drilling, completion, construction and pipelining
41 person environmental staff plus outside consultants monitor all operations and perform baseline water well testing
Central Fresh Water System & Water Recycling
Numerous sources of water – built central water system to source fresh water for completions
Antero recycled over 80% of its flowback and produced water through the first 9 months of 2014 – no discharge to water treatment plants in West Virginia
Natural Gas Vehicles (NGV)
Antero supported the first natural gas fueling station in West Virginia Antero has 30 NGV trucks and plans to continue to convert its truck fleet to NGV
Pad Impact Mitigation Closed loop mud system – no mud pits Protective liners or mats on all well pads in addition to berms
Natural Gas Powered Drilling Rigs & Frac Equipment
11 of Antero’s contracted drilling rigs are currently running on natural gas First natural gas powered clean fleet frac crew began operations summer 2014
Green Completion Units All Antero well completions use green completion units for completion flowback,
essentially eliminating methane emissions (full compliance with EPA 2015requirements)
LEED Gold Headquarters Building
Recently moved into new corporate headquarters in Denver, Colorado that has been LEED Gold Certified
HEALTH, SAFETY, ENVIRONMENT & COMMUNITYAntero Core Values: Protect Our People, Communities And The Environment
Strong West Virginia Presence 79% of all Antero Marcellus
employees and contract workers are West Virginia residents
Antero named Business of the Year for 2013 in Harrison County, West Virginia “For outstanding corporate citizenship and community involvement”
Antero representatives recently participated in a ribbon cutting with the Governor of West Virginia for the grand opening of the first natural gas fueling station in the state; Antero supported the station with volume commitments for its NGV truck fleet
36
CLEAN FLEET & CNG TECHNOLOGY LEADER
● Antero has contracted for two clean completion fleets to enhance the economics of its completion operations and reduce the environmental impact
● Replaces diesel engines (for pressure pumping) with electric motors powered by natural gas-fired electric generators
● A clean fleet allows Antero to fuel part of its completion operations from field gas instead of more expensive diesel fuel. Benefits of using a clean fleet include:− Reduce fuel costs by up to 80%
representing cost savings of up to $40,000/day
− Reduces NOx and CO emissions by 99%− Eliminates 25 diesel trucks from the roads
for an average well completion− Reduces silica dust to levels 90% below
OSHA permissible exposure limits resulting in a safer and cleaner work environment
− Significantly reduces noise pollution from a well site
− Is the most environmentally responsible completion solution in the oil and gas industry
• Additionally, Antero utilizes compressed natural gas (CNG) to fuel its truck fleet in Appalachia− Antero supported the first natural gas fueling
station in West Virginia− Antero has 30 NGV trucks and plans to
continue to convert its truck fleet to NGV
37
1. Represents inception to date actuals as of 6/30/2014 and 2015 guidance.2. Includes $12.5 million of maintenance capex at 2015 midpoint guidance. 39
• Gathering and compression assets in core of rapidly growing Marcellus and Utica Shale plays
– Acreage dedication of ~412,000 net leasehold acres for gathering and compression services
– 100% fixed fee long term contracts
UticaShale
MarcellusShale
Projected Midstream Infrastructure(1)
Marcellus Shale
Utica Shale Total
YE 2014E Cumulative Gathering/ Compression Capex ($MM) $850 $350 $1,200
Gathering Pipelines(Miles) 153 80 233
Compression Capacity(MMcf/d) 375 - 375
Condensate Gathering Pipelines (Miles) - 16 16
YE 2015E Gathering/ Compression Capex ($MM)(2) $256 $182 $438
Gathering Pipelines (Miles) 46 18 64
Compression Capacity(MMcf/d) 425 120 545
Condensate Gathering Pipelines (Miles) - 4 4
Midstream Assets
SUBSTANTIAL INVESTMENT IN MIDSTREAM MLP(NYSE: AM)
ANTERO MIDSTREAM ASSETS – RICH GAS MARCELLUS
40
• Provides Marcellus gathering and compression services − Liquids-rich gas is delivered to MWE’s Sherwood
Complex for processing• Significant growth projected over the next twelve
months as set out below:
• Antero sold the Harrison County portion of its gathering system to a 3rd party midstream company in 2012, which is now recognized as the 3rd Party Gathering and Compression Dedication area
• Development upside as AR continues to drill, step-out and add acreage
Marcellus Gathering & Compression
Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.
YE 2014 YE 2015
Gathering Pipelines (Miles) 153 199
Compression Capacity (MMcf/d) 375 800
WV/PA Utica Dry Gas Gathering & Compression
• Further development upside in 170,000 net acres of Utica deep rights beneath the Marcellus Shale− Will require a separate dry gas gathering system
41
• Provides Utica natural gas and condensate gathering services− Liquids-rich gas delivered into MWE’s Seneca
Complex for processing− Condensate delivered to centralized stabilization
and truck loading facilities• Significant growth projected over the next twelve
months as set out below:
• Development upside as AR continues to drill, step-out and add acreage
Utica Gathering
Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.
ANTERO MIDSTREAM ASSETS – RICH & DRY GAS UTICA
YE 2014 YE 2015
Gathering Pipelines (Miles) 80 98
Condensate Pipelines (Miles) 16 20
Compression (MMcf/d) 0 120
Utica Compression• Opportunity to build up to ten new compressor stations
that are planned to support AR development over the next several years
PRO FORMA CAPITALIZATION($ in millions) 9/30/2014
Pro Forma $1.15 Bn AM IPO(4)
9/30/2014Cash $6 $256
Senior Secured Revolving Credit Facility 1,505 6626.00% Senior Notes Due 2020 525 5255.375% Senior Notes Due 2021 1,000 1,0005.125% Senior Notes Due 2022 1,100 1,100Net Unamortized Premium 8 8Total Debt $4,138 $3,295Net Debt $4,132 $3,039Minority Interest - $326Shareholders' Equity $3,751 $4,372Net Book Capitalization $7,883 $7,737
Enterprise Value(1) $13,631 $12,788
Financial & Operating StatisticsLTM EBITDAX $1,047 $1,047LQA EBITDAX $1,109 $1,109LTM Interest Expense(2) $155 $138Proved Reserves (Bcfe) (12/31/2014) 12,683 12,683
Proved Developed Reserves (Bcfe) (12/31/2014) 3,803 3,803
Credit Statistics
Net Debt / LTM EBITDAX 3.9x 2.9x
Net Debt / LQA EBITDAX 3.7x 2.7xLTM EBITDAX / Interest Expense 6.8x 7.6xNet Debt / Net Book Capitalization 52.4% 39.3%Net Debt / Proved Developed Reserves ($/Mcfe) $1.09 $0.80Net Debt / Proved Reserves ($/Mcfe) $0.33 $0.24
LiquidityCredit Facility Commitments(3)(4) $3,000 $4,000Less: Borrowings (1,505) (662)Less: Letters of Credit (332) (332)Plus: Cash 6 256
Liquidity (Undrawn Credit Facility + Cash) $1,169 $3,2621. Equity valuation based on 262.0 million shares outstanding and a share price of $37.22 as of 1/16/2015. AR enterprise value excludes AM minority interest and cash.2. LTM interest expense adjusted for $1,578 million net proceeds from IPO priced on 10/14/2013 and $1,000 million 5.375% Senior Notes priced on 10/24/2013 net of fees; assumes $525 million 9.375%
Senior Notes, $25 million 9.00% Senior Notes, $140 million 7.25% Senior Notes repaid at 10/31/2013 with residual cash used to repay bank debt. Adjusted for $600 million 5.125% Senior Notes priced on 4/23/2014 net of fees; $260 million of 7.25% Senior Notes and $315 million of bank debt repaid. Adjusted for $500 million 5.125% Senior Notes add-on priced on 9/4/2014 at 100.5 net of fees; $496 million of bank debt repaid.
3. AR lender commitments under the facility increased to $3.0 billion from $2.5 billion on 10/16/2014; commitments can be expanded to the full $4.0 billion borrowing base upon bank approval. AM credit facility of $1 billion as of 11/4/2014.
4. Pro forma for $1,150 million IPO of 70% post-offering owned Antero Midstream; $843 million of debt repaid, $250 million of cash left at AM and $57 million of transaction expenses. AM $1 billion credit facility currently undrawn.
43
LOWEST FINDING & DEVELOPMENT COSTAMONG U.S. PRODUCERS
44
3-Year All-In F&D Cost – Excluding Revisions ($/Mcfe) through 2013
Source: Credit Suisse research dated 4/28/2014.
Antero ranks as the most efficient finder and developer of reserves, on a per Mcfe basis, based on a 2011-2013 average all-in F&D cost analysis prepared by Credit Suisse
$10.24$7.14
$6.68$5.74
$4.66$4.66
$4.54$4.23
$4.01$3.70
$3.63$3.28
$3.12$3.07$3.05$3.05
$2.91$2.91$2.88$2.87
$2.78$2.66
$2.57$2.40
$2.06$1.94
$1.74$1.60
$1.53$1.26
$1.04$0.84
$0.79$0.58
$0 $2 $4 $6 $8 $10 $12MHRAPC
GPORMURAPAMROWLL
FANGKOGCRKEXXIEOXPVACXODVN
KWKFST
DNRNBLEOG
CRZOPXD
BCEISD
CHKROSE
SFYATHL
EPEREXXSWN
PDCERRC
AR
MARCELLUS SINGLE WELL ECONOMICS – IN ETHANE REJECTION
45
DRY GAS LOCATIONS RICH GAS LOCATIONS
HIGHLY RICH GAS
LOCATIONS
Assumptions Natural Gas – 12/31/2014 strip Oil – 12/31/2014 strip NGLs – 55% of Oil Price
NYMEX($/MMBtu)
WTI($/Bbl)
C3+ NGL(2)
($/Bbl)
2015 $3.08 $57 $31
2016 $3.48 $63 $35
2017 $3.77 $67 $37
2018 $3.95 $69 $38
2019+ $4.08 $71 $39
Marcellus SSL Well Economics and Total Gross Locations(1)
ClassificationHighly-Rich Gas/
CondensateHighly-Rich
Gas Rich Gas Dry Gas
Modeled BTU 1313 1250 1150 1050EUR (Bcfe): 17.7 16.2 14.7 13.6EUR (MMBoe): 2.9 2.7 2.4 2.3% Liquids: 31% 22% 10% 0%Lateral Length (ft): 8,000 8,000 8,000 8,000Stage Length (ft): 225 225 225 225Well Cost ($MM): $10.6 $10.6 $10.6 $10.6Bcfe/1,000’: 2.2 2.0 1.8 1.7
Pre-Tax NPV10 ($MM): $11.9 $7.4 $0.6 $0.4Pre-Tax ROR: 42% 28% 12% 11%Net F&D ($/Mcfe): $0.70 $0.77 $0.85 $0.92Payout (Years): 2.1 3.0 6.6 6.7
Gross 3P Locations(3): 664 1,010 628 889
1. Well economics are based on 12/31/2014 strip differential pricing and related transportation costs. Includes gathering, compression and processing fees. 2. Pricing for a 1225 BTU y-grade ethane rejection barrel.3. Undeveloped well locations as of 12/31/2014.
6641,010
628
889
42% 28%
12% 11%
0
300
600
900
1,200
0%
15%
30%
45%
60%
Highly-Rich Gas/Condensate
Highly-Rich Gas Rich Gas Dry Gas
Tota
l 3P
Loca
tions
RO
R Locations ROR2015
Drilling Plan
248
13994
254289
10%
31%
46%
33%
30%
0
100
200
300
400
0%
15%
30%
45%
60%
Condensate Highly-Rich Gas/Condensate
Highly-Rich Gas Rich Gas Dry Gas
Tota
l 3P
Loca
tions
RO
RLocations ROR
UTICA SINGLE WELL ECONOMICS – IN ETHANE REJECTION
46
DRY GAS LOCATIONS RICH GAS LOCATIONS
HIGHLY RICH GAS
LOCATIONS
Utica Well Economics and Gross Locations(1)
Classification CondensateHighly-Rich Gas/
CondensateHighly-Rich
Gas Rich Gas Dry Gas
Modeled BTU 1275 1235 1215 1175 1050EUR (Bcfe): 8.3 15.0 22.4 21.2 19.0EUR (MMBoe): 1.4 2.5 3.7 3.5 3.2% Liquids 35% 26% 21% 14% 0%Lateral Length (ft): 8,000 8,000 8,000 8,000 8,000Stage Length (ft): 240 240 240 240 240Well Cost ($MM): $12.1 $12.1 $12.1 $12.1 $12.1Bcfe/1,000’: 1.0 1.9 2.8 2.7 2.4
Pre-Tax NPV10 ($MM): $0.0 $7.6 $13.0 $9.1 $8.0Pre-Tax ROR: 10% 31% 46% 33% 30%Net F&D ($/Mcfe): $1.79 $0.99 $0.67 $0.71 $0.79Payout (Years): 5.5 1.5 1.1 1.5 2.6
Gross 3P Locations(3): 248 139 94 254 289
1. Well economics are based on 12/31/2014 strip differential pricing and related transportation costs. Includes gathering, compression and processing fees.2. Pricing for a 1225 BTU y-grade ethane rejection barrel.3. Undeveloped well locations as of 12/31/2014. 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content.
2015Drilling Plan
Assumptions Natural Gas – 12/31/2014 strip Oil – 12/31/2014 strip NGLs – 55% of Oil Price
NYMEX($/MMBtu)
WTI($/Bbl)
C3+ NGL(2)
($/Bbl)
2015 $3.08 $57 $31
2016 $3.48 $63 $35
2017 $3.77 $67 $37
2018 $3.95 $69 $38
2019+ $4.08 $71 $39
3-Year Average Growth – Adjusted Recycle Ratio through 2013
0.0x
2.0x
4.0x
6.0x4.8x
3.3x3.5x
2.4x
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$1.15 $1.18 $1.21 $1.60
Other Peers
LOW DEVELOPMENT COST DRIVES BEST IN CLASS RECYCLE RATIOS
47
Source: Proved developed F&D industry data based on company presentations, 10-Ks and press releases. Defined as total drilling and completion capital expenditures for the period divided by PDP and PDNP volumes added after adding back production for the period. Includes all drilling and completion costs but excludes land and acquisition costs for all companies. 1. Antero data pro forma for Arkoma and Piceance divestitures in 2012.
3-Year Proved Development Costs ($/Mcfe) through 2013
Antero Appalachia-Focused Peers
Source: Wall Street research. Defined as 2011-2013 average (Cash Operating Netback / PD F&D costs) x (1 + 2013-2015 consensus production CAGR). Antero’s production CAGR based on guidance targets. PD F&D Costs defined as total drilling and completion capital expenditures for the period divided by PDP and PDNP volumes added after adding back production for the period Includes all drilling and completion costs but excludes land and acquisition costs for all companies.1. Antero data pro forma for Arkoma and Piceance divestitures in 2012.
Antero Appalachia-Focused Peers
$/Mcfe
Other Peers
CONSIDERABLE RESERVE BASE WITH ETHANE OPTIONALITY 35 year proved reserve life based on 2014 production annualized Reserve base provides significant exposure to liquids-rich projects
– 3P reserves of over 2.5 BBbl of NGLs and condensate in ethane recovery mode; 32% liquids
1. Ethane rejection occurs when ethane is left in the wellhead gas stream as the gas is processed, rather than being separated out and sold as a liquid after fractionation. When ethane is left in the gas stream, the BTU content of the residue gas at the outlet of the processing plant is higher. Producers will elect to “reject” ethane when the price received for the higher BTU residue gas is greater than the price received for the ethane being sold as a liquid after fractionation. When ethane is recovered, the BTU content of the residue gas is lower, but a producer is then able to recover the value of the ethane sold as a separate NGL product.
ETHANE REJECTION(1) ETHANE RECOVERY(1)
48
Marcellus – 28.4 Tcfe
Utica – 7.6 Tcfe
Upper Devonian – 4.6 Tcfe
40.7Tcfe
Gas – 34.5 Tcf
Oil – 102 MMBbls
NGLs – 924 MMBbls
Marcellus – 33.7 Tcfe
Utica – 8.6 Tcfe
Upper Devonian – 5.1 Tcfe
47.4Tcfe
Gas – 32.0 Tcf
Oil – 102 MMBbls
NGLs – 2,459 MMBbls
15%Liquids
32%Liquids
Moody's S&P
POSITIVE RATINGS MOMENTUMMoody’s / S&P Historical Corporate Credit Ratings
“We could raise the ratings due to our assessment of an improvement inthe company's financial profile. An improvement in the financial profilewould include maintaining FFO to debt of greater than 45% andnarrowing the amount that the company outspends its cash flows by.”
- S&P Credit Research, September 2014
“An upgrade could be considered if debt / average daily production issustained below $20,000 per boe and debt / proved-developedreserves is sustained below $8.00 per boe. An upgrade would also becontingent on Antero maintaining unleveraged cash margins greaterthan $25.00 per boe and retained cash flow to debt over 40%.”
- Moody’s Credit Research, September 2014
Credit Rating (Moody’s / S&P)
Ba3 / BB-
B1 / B+
B2 / B
B3 / B-
9/1/2010 2/24/2011 10/21/2013 9/4/20145/31/13
Ba2 / BB
Ba1 / BB+
Caa1 / CCC+
(1)
1. Represents corporate credit rating of Antero Resources Corporation / Antero Resources LLC.
Baa3 / BBB-
Moody’s Upgrade Criteria S&P Upgrade Criteria
49
12/31/2014
($ in millions) As At Interest Current Maturity Maturity09/30/14 Rate Yield (2) (Years) (Date)
Senior Secured Revolving Credit Facility $662 2.440% (3) 2.440% (3) 4.6 May-196.0% Senior Notes due 2020 525 6.000% 6.204% 6.2 Dec-205.375% Senior Notes due 2021 1,000 5.375% 6.102% 7.1 Nov-215.125% Senior Notes due 2022 1,100 5.125% 6.201% 8.2 Dec-22
Total Long-Term Debt $3,287
Weighted Average: 4.800% 5.414% 6.8 Jul-21
PRO FORMA OFFERING – BALANCE SHEET POSITIONEDFOR LONG-TERM GROWTH
PRO FORMA DEBT MATURITY PROFILE (1)
PRO FORMA WEIGHTED AVERAGE INTEREST RATE AND MATURITY(1)
501. As of 9/30/2014 per 10-Q; pro forma for $1,150 million AM IPO priced on 11/4/2014; net proceeds of $843 million used to repay the credit facility.2. Current yields of senior notes tranches represent the current yield-to-worst per Bloomberg. 3. Represents weighted average interest rate under the revolving credit facility as of 9/30/2014.
Senior Secured Revolving Credit Facility Senior Notes
The recent bond offerings, at progressively lower coupons, have allowed Antero to reduce its cost of debt to approximately 5.0% and enhance liquidity while extending the pro forma average debt maturity to July 2021
Current cost of debt 4.8%, average debt maturity 6.8 years
$662 $525
$1,000 $1,100
$0
$200
$400
$600
$800
$1,000
$1,200
2014 2015 2016 2017 2018 2019 2020 2021 2022
($ in
Mill
ions
)
Needed to make up for base declines in conventional and GOM production
? ??
3,000 Antero Drilling Locations
Perm
ian
Nio
brar
a
Gra
nite
Was
h
Bar
nett
Hay
nesv
ille
U.S. INCREMENTAL GAS SUPPLY BREAK-EVEN PRICE CURVE(1)
51
Low cost, liquids-rich Utica and Marcellus Shales will remain attractive in most commodity price environments
Utica Shale
SW (Rich) Marcellus
Shale
1. Source: Credit Suisse report dated January 2014 – Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI
NE (Dry) Marcellus
ShaleEagle Ford
Shale
MARCELLUS & UTICA – ADVANTAGED ECONOMICS
LNG EXPORTS BY PROJECT – CURRENT STATUS
52
LNG Exports by Project – Current Status
Sherwood 7
Dates of Key Milestones Send Out Non-DOE Non-FTA FERC FTA Permit Underlying
Permit Construction Capacity Gas DemandProject Awarded Approval (Bcf/d) (Bcf/d) Contracts OfftakersSabine Pass 1-4 05/20/11 04/16/12 2.20 2.42 Fully Subscribed BG, GasNatural Fenosa,
Kogas, GAIL
Cove Point 09/11/13 09/29/14 0.77 0.85 Fully Subscribed Sumitomo, GAIL, Tokyo Gas
Cameron 02/11/14 06/19/14 1.70 1.87 Fully Subscribed Sempra, Misui, Mitsubishi, GDF Suez
Freeport 05/17/13 07/30/14 1.40 1.54 Fully Subscribed Osaka Gas, Chubu Electric, BP, Toshiba, SK E&S
Lake Charles 08/07/13 Expected 2015 2.00 2.20 Fully Subscribed BG
Subtotal 8.07 8.88
Freeport Phase II 11/15/13 Pending 0.40 0.44 Not Subscribed N/A
Total 8.47 9.32
Source: Simmons & Company International, “2015 US Natural Gas Outlook and Updated Long Term Demand Forecast,” September 2014. Data updated for recent announcements subsequent to Simmons report.
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. The estimates of proved, probable and possible reserves as of December 31, 2014 included in this presentation 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 be potentially recovered from a hypothetical future well completed as a producer in the area. These quantities do not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules.
“Condensate” refers to gas having a heat content between 1250 BTU and 1300 BTU in the Utica Shale.
“Highly-Rich Gas/Condensate” refers to gas having a heat content between 1275 BTU and 1350 BTU in the Marcellus Shale and 1225 BTU and 1250 BTU in the Utica Shale.
“Highly-Rich Gas” refers to gas having a heat content between 1200 BTU and 1275 BTU in the Marcellus Shale and 1200 BTU and 1225 BTU in the Utica Shale.
“Rich Gas” refers to gas having a heat content of between 1100 BTU and 1200 BTU.
“Dry Gas” refers to gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.
Regarding Hydrocarbon Quantities
53