1. Ingeniería

Company Overview
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, forwardlooking 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
PROVED RESERVE GROWTH(1)
• Proved reserves increased 66% to 12.7 Tcfe
(Tcfe)
15
12.7
0.6
12
9
6
3
7.6
Key Drivers
• Successful
drilling
• SSL results
0.4
11.9
7.2
• Expanded
proved
footprint
0
2013
• 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
2014
Marcellus
Utica
3P RESERVE GROWTH(1)
POTENTIAL RESERVE GROWTH DRIVERS
(Tcfe)
45
40
35
30
25
20
15
10
5
0
2014 RESERVE ANNOUNCEMENT
40.7
35.0
4.2
4.6
4.2
7.6
5.8
Key Drivers
• 93,000 net
acres added
in 2014
• SSL results
28.4
25.0
2013
Marcellus
2014
Utica
• Utica results
Driver
2015 Activity
• Marcellus SSL completions
Complete transition to SSL type
curve
• Marcellus rich gas drilling
New rich gas delineation wells
• Utica increased density and
step-out drilling
Drilling and monitoring of Utica
density and step-out pilots
• WV/PA Utica dry gas drilling
Industry drilling activity in
WV/PA (170,000 net acres)
• Core acreage acquisitions
$150 MM budget for 2015
Upper Devonian
1. 2013 and 2014 reserves assuming ethane rejection.
2
ANTERO RESOURCES – 2015 GUIDANCE
Key Operating & Financial Assumptions
Key Variable
Net Daily Production (MMcfe/d)
Net Residue Natural Gas Production (MMcf/d)
2015 Guidance Range
1,400
1,175
Net Liquids Production (Bbl/d)
33,000
Net Oil Production (Bbl/d)
4,000
Natural Gas Realized Price Differential to NYMEX Henry Hub Before Hedging ($/Mcf)
Oil Realized Price Differential to NYMEX WTI Before Hedging ($/Bbl)
NGL Realized Price (% of WTI)
$(0.20) - $(0.30)
$(12.00) - $(14.00)
48% - 52%
Cash Production Expense ($/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. 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.
$1,800
3
LEADING UNCONVENTIONAL BUSINESS MODEL
Most Active
Land Organization
in Appalachia
Highest Growth
Large Cap E&P
3
2
Land
Growth
Most Active Operator
in Appalachia
4
1
Liquids-Rich
Drilling
Largest Liquids-Rich
Core Position in
Appalachia
Premier Appalachian
E&P Company
Highest Realizations
and Margins Among
Large Cap
Appalachian Peers
Run by Co-Founders
8
Realizations
5
Midstream
MLP (NYSE: AM)
Highlights
Substantial Value in
Midstream Business
6
7
Liquidity
Largest Gas Hedge
Position in U.S. E&P +
Strong Financial
Liquidity
Takeaway
Largest Firm Transport
and Processing
Portfolio in Appalachia
4
CATALYSTS
1
Sustainability of
Antero’s Integrated
Business Model
Large, low cost core Marcellus and Utica natural gas drilling inventory
with associated liquids generates attractive returns supported by longterm natural gas hedges, takeaway portfolio and downstream LNG and
NGL sales agreements
2
Production and
Cash Flow Growth
40% production growth targeted for 2015 with 94% hedged at
$4.47/MMBtu; capital budget flexibility to commodity price changes
3
Downstream LNG
and NGL Sales
Pursuing additional value enhancing long-term LNG and NGL sales
agreements, supported by firm takeaway
4
5
6
Midstream MLP
Growth
Potential Water
System Monetization
Utica Dry Gas
Activity
Antero owns 70% of Antero Midstream Partners and thereby
participates directly in its growth and value creation
Contingent on receiving private letter ruling from the IRS, AM holds an
option to acquire Antero’s fresh water system at fair market value
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
5
DRILLING – MOST ACTIVE OPERATOR IN APPALACHIA
COMBINED TOTAL – 12/31/14 RESERVES
Assumes Ethane Rejection
Net Proved Reserves
Net 3P Reserves
Pre-Tax 3P PV-10
12.7 Tcfe
40.7 Tcfe
$22.8 Bn
Net 3P Reserves & Resource
51.8 Tcfe
1,026 MMBbls
15%
1,265 MMcfe/d
30,400 Bbl/d
543,000
5,331
SW Marcellus & Utica(2)
20
Rig Count
Net 3P Liquids
% Liquids – Net 3P
4Q 2014E Net Production
- 4Q 2014E Net Liquids
Net Acres(1)
Undrilled 3P Locations
25
15
10
5
0
Operators
UTICA SHALE CORE
Net Proved Reserves
Net 3P Reserves
758 Bcfe
7.6 Tcfe
MARCELLUS SHALE CORE
Pre-Tax 3P PV-10
$6.1 Bn
Net Proved Reserves
11.9 Tcfe
Net Acres
Undrilled 3P Locations
148,000
1,024
Net 3P Reserves
28.4 Tcfe
Pre-Tax 3P PV-10
$16.8 Bn
Net Acres
Undrilled 3P Locations
395,000
3,191
UPPER DEVONIAN SHALE
WV/PA UTICA SHALE DRY GAS
Net Proved Reserves
Net Resource
Net Acres
Undrilled Locations
Net 3P Reserves
11.1 Tcf
170,000
1,616
Pre-Tax 3P PV-10
Undrilled 3P Locations
8 Bcfe
4.6 Tcfe
NM
1,116
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
GROWTH – HIGHEST GROWTH LARGE CAP E&P
 Antero’s 40% production growth target for 2015 leads the U.S. large cap E&P industry(1)
45%
40%
40.0%
35%
30%
27.3%
26.8%
23.6%
25%
21.1%
20%
20.0%
19.3%
19.1%
16.2%
15%
12.4%
10%
8.5%
5.3%
5%
5.1%
3.8%
2.1%
1.8%
(0.3%)
0%
(2.8%)
-5%
(2)
(2)
Appalachian 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 $8.0 billion.
2. Based on publicly announced 2015 production growth target.
7
GROWTH – STRONG TRACK RECORD
NET PROVED SEC RESERVES (Bcfe)
Marcellus
AVERAGE NET DAILY PRODUCTION (MMcfe/d)
Utica
Marcellus
14,000
12,683
Utica
Guidance
1,800
12,000
1,400
10,000
6,000
4,283
4,000
2,000
1,200
7,632
8,000
522
600
2,844
677
0
2010
2012(1)
2011
(1)
2013
(1)
2014
OPERATED GROSS WELLS COMPLETED
Marcellus
200
Utica
0
30
2010
124
2011
239
2012
2013
EBITDAX ($MM)
2014
177
92% Growth 40% Growth
Guidance
180
$1,400
$1,144
$1,200
150
130
114
125
$400
38
$200
19
$0
0
2010
2011
2012
$649
$600
60
50
$1,000
$800
100
75
2015E
Deferred Completions
175
25
1,007
2013
1. 2012, 2013 and 2014 proved reserves assuming ethane rejection.
2. Per current First Call median estimate from Bloomberg.
2014
2015E
$285
$160
$28
2010
2011
2012
2013
(2)
2014E
8
LAND – MOST ACTIVE LAND ORGANIZATION
IN APPALACHIA
 Assembled a 543,000 net acre position in the core of the Marcellus and Utica shale plays over the past 6 years
Dec 2008
December 2008
Net Acreage
118,000
Dec 2011
Dec 2014
December 2011(1)
December 2014(1)
Net Acreage
213,000
Net Production (MMcfe/d)
NM
Net Production (MMcfe/d)
3P Reserves (Bcfe)
NM
3P Reserves (Bcfe)
3P PV-10 ($MM)
NM
3P PV-10 ($MM)
Rigs Running
NM
Rigs Running
600,000
167
543,000
Net Production (MMcfe/d)
1,265
18,400
3P Reserves (Bcfe)
40,700
$9,000
3P PV-10 ($MM)
$22,800
5
Rigs Running
371,000
400,000
21
543,000
Antero Net Acreage
500,000
420,000
450,000
486,000
285,000
300,000
200,000
Net Acreage
118,000
118,000
118,000
12/2008
12/2009
6/2010
162,000
189,000
213,000
100,000
0
12/2010
6/2011
Utica
12/2011
1. Net daily production for December 2011 and December 2014 is for the fourth quarter, respectively.
6/2012
12/2012
Marcellus
6/2013
12/2013
6/2014
12/2014
9
LIQUIDS-RICH – LARGEST CORE POSITION
 Antero has the largest liquids-rich core position in Appalachia ≈371,000 net acres (> 1100 Btu)
Source: Core outlines and peer net acreage positions based on peer presentations, news releases and 10-K/10-Qs.
10
MIDSTREAM – MLP (NYSE: AM) HIGHLIGHTS
SUBSTANTIAL VALUE IN MIDSTREAM BUSINESS
Corporate Structure Overview(1)
Antero Resources
Corporation (NYSE: AR)
$13.0 Billion Enterprise Value(1)
Ba3/BB Corporate Rating
70% Limited
Partner Interest
= $2.4 Billion Market Valuation(1)
$1.5 Billion Derived Valuation(2)
Antero Midstream
Partners LP (NYSE: AM)
$3.4 Billion Valuation(1)
$9.1 Billion Implied Valuation(3)
Fresh Water
E&P Assets
Distribution System
Market Valuation of AR Ownership in AM:
Gathering Assets
Compression Assets
•
AR ownership: 69.7% LP Interest = 105.9 million units
AM Price
per Unit
$22
$23
$24
$25
$26
$27
$28
AM Units
Owned
by AR
(MM)
106
106
106
106
106
106
106
AR Value in
AM LP Units
($MMs)
$2,332
$2,445
$2,544
$2,647
$2,753
$2,858
$2,964
Value Per
AR Share(4)
$9
$9
$10
$10
$11
$11
$12
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
TAKEAWAY – LARGEST FIRM TRANSPORTATION AND
PROCESSING PORTFOLIO IN APPALACHIA
Antero Long Term Firm Processing & Takeaway Position (2018) – Accessing Favorable Markets
4 Bcf/d
Firm Gas
Takeaway
By 2018
Mariner East II
62 MBbl/d Commitment(2)
Marcus Hook Export
Chicago(1)
+$0.23 /
$(0.08)
Dom South(1)
$(1.38) /
$(1.11)
TCO(1)
$(0.13) /
$(0.41)
Odebrecht / Braskem
30 MBbl/d Commitment
Ascent Cracker
(Pending Final
Investment Decision)
Cove Point
Shell
25 MBbl/d Commitment
Beaver County Cracker
(Pending Final
Investment Decision)
Sabine Pass (Trains 1-4)
50 MMcf/d per Train
CGTLA(1)
$(0.08) /
$(0.09)
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.
12
LIQUIDITY – LARGEST GAS HEDGE POSITION IN U.S. E&P
+ STRONG FINANCIAL LIQUIDITY
 ~$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
COMMODITY HEDGE POSITION
BBtu/d
1,400
1,200
1,000
800
600
400
200
0
Average Index Hedge Price(1)
Hedged Volume
Current NYMEX Strip(2)
Mark-to-Market Value(2)
$/MMBtu
$6.00
$4.34
$4.50
$4.41
$4.41
$3.77
$4.08
$4.21
$3.48
$3.95
$689 MM
$464 MM
$176 MM
$214 MM
$98 MM
$3 MM
1,316
943
780
1,073
818
40
2015
≈ 94% of 2015E
Target
Production(3)
2016
2017
2018
2019
2020
$4.42
$3.09
$4.47
$5.00
$4.00
$3.00
$2.00
$1.00
$0.00
 Over $3 billion of combined AR and AM financial liquidity as of 9/30/2014, pro forma for AM IPO closed on 11/10/2014
AR LIQUIDITY POSITION ($MM)
AM LIQUIDITY POSITION ($MM)
$3,000
$3,000
$2,500
$2,000
$1,500
$2,500
($1,505)
$3,000
$2,000
($332)
$1,000
$6
$2,012
$1,000
$500
$500
$0
$0
Credit Facility
9/30/2014
Bank Debt
9/30/2014
L/Cs
Outstanding
9/30/2014
Cash
9/30/2014
AM IPO
Proceeds
to AR
$250
$1,500
$843
Pro Forma
Liquidity
9/30/2014
$1,000
Credit Facility
9/30/2014
$1,250
$0
$0
$0
Bank Debt
9/30/2014
L/Cs
Outstanding
9/30/2014
Cash
9/30/2014
1. Reflects weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio. Antero has hedged 3,000 Bbl/d of oil and 23,000 Bbl/d of propane for 2015.
2. As of 12/31/2014.
3. Percentage of net gas equivalent production target hedged for respective years.
AM IPO
Proceeds
to AM
Pro Forma
Liquidity
9/30/2014
13
REALIZATIONS – HIGHEST REALIZATIONS & MARGINS
AMONG LARGE-CAP APPALACHIAN PEERS
3Q & 4Q 2014 Natural Gas Realizations ($/Mcf)
Average
NYMEX
Average
Average Discount to
Price Differential(1) BTU Upgrade
NYMEX
($/Mcf)
($/Mcf)
($/Mcf)
($/Mcf)
Gas
Hedge
Effect
($/Mcf)
Average
Realized
Gas Price
($/Mcf)
Average
Realized
Realized Gas
Premium/ Liquids Equivalent
Discount Upgrade
Price
($/Mcf) ($/Mcfe)
($/Mcfe)
Equivalent
Premium
($/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
3Q 2014 Natural Gas Realizations(3)
3Q 2014 Price Realization & EBITDAX Margin vs F&D(2)(4)
$6.00
$6.00
$5.00
$4.31
$4.00
$4.96
$4.48
3Q 2014 NYMEX = $4.06/Mcf
$3.62
$3.60
$2.98
$2.87
$2.00
$2.75
$/Mcfe
$3.66
$/Mcf
$4.16
$4.00
$4.12
$3.25
$3.00
$2.93
$2.40
$2.00
$0.95
$1.00
$0.00
$0.00
AR
1.
2.
3.
4.
5.
EQT
GPOR
RRC
CNX
RICE
ECR
COG
$3.97
$0.58
AR
Antero
Peer
Peer11
$2.64
$2.11
$2.09
$0.74
$0.77
$0.81
Peer 22
Peer
Peer 33
Peer
Peer 44
Peer
Includes firm sales.
LOE
Production Taxes
GPT
G&A
EBITDAX
4-year Avg. All-in F&D ($/Mcfe)
Price realization includes $0.05 of midstream revenues in 3Q, 2014.
Includes natural gas hedges.
Source: Public data from 3Q 2014 10-Qs. Peers include Cabot Oil & Gas, CONSOL Energy, EQT Corp. and Range Resources.
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.
14
REALIZATIONS – REALIZED PRICE “ROAD MAP”
 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/Mcfe in estimated hedge gains(1)
85% exposure to favorable price indices
94% exposure to favorable price indices
71% exposure to favorable price indices
2015
Basis(1)
100%
Marketed % of Target Residue Gas Production
90%
2015E
Wtd. Avg.
Basis ($0.46)
2015
Hedges
2016
Basis(1)
Wtd. Avg.
1,160,000 MMBtu/d
Basis $(0.32)
@ $4.34/MMBtu
+$0.05/MMBtu
Chicago
21%
$(0.10)/MMBtu
Gulf Coast
18%
2016
Hedges
2016E
Wtd. Avg.
942,500 MMBtu/d
@ $4.47/MMBtu Basis $(0.18)
Chicago
20%
$(0.07)/MMBtu
2017
Basis(1)
$(0.20)/MMBtu
2017E
2017
Hedges
780,000 MMBtu/d
@ $4.34/MMBtu
Chicago
19%
70,000 MMBtu/d
@ $4.57/MMBtu
80%
70%
60%
50%
40%
$(0.25)/MMBtu(2)
NYMEX
8%
40,000 MMBtu/d
@ $4.00/MMBtu
$(0.09)/MMBtu
170,000 MMBtu/d
Gulf Coast
38%
@ $4.09/MMBtu
Gulf Coast
56%
@ $3.88/MMBtu
$(0.24)/MMBtu
TCO
24%
510,000 MMBtu/d
@ $3.87/MMBtu(3)
$(0.25)/MMBtu(2)
NYMEX
11%
170,000 MMBtu/d
TCO
16%
330,000 MMBtu/d
$(1.35)/MMBtu
$(0.41)/MMBtu
TETCO M2 - 7%
20%
$(1.28)/MMBtu
DOM S
22%
@ $3.82/MMBtu(4)
230,000 MMBtu/d
$(1.26)/MMBtu
TETCO M2 - 6%
@ $5.60/MMBtu
272,500 MMBtu/d
$(1.11)/MMBtu
DOM S - 9%
@ $5.35/MMBtu
0%
($/Mcf)
NYMEX Strip Price(1)
Basis Differential to NYMEX(1)
BTU Upgrade(6)
Estimated Realized Hedge Gains
Realized Gas Price with Hedges
Premium to NYMEX
Liquids Impact
Premium to NYMEX w/ Liquids
Realized Gas-Equivalent Price
2015E
$3.09
$(0.46)
$0.26
$1.35
$4.24
+$1.15
+$0.39
+$1.54
$4.63
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.
420,000 MMBtu/d
@ $4.27/MMBtu
@ $3.35/MMBtu
30%
10%
$(0.07)/MMBtu
380,000 MMBtu/d
182,500 MMBtu/d
$(0.25)/MMBtu(2)
NYMEX
10%
$(0.50)/MMBtu
TCO - 9%
$(0.83)/MMBtu
DOM S - 6%
@ $4.38/MMBtu
107,500 MMBtu/d
@ $3.88/MMBtu
(5)
15
4. Represents 60,000 MMBtu/d of TCO index hedges and 270,000 MMBtu/d of TCO
basis hedges that are matched with NYMEX hedges for presentation purposes.
5. Represents 107,500 MMBtu/d of TCO basis hedges matched with NYMEX hedges.
6. Assumes ethane rejection resulting in 1100 BTU residue sales gas.
SECTOR POSITIONING
16
PREMIER POSITION IN LOW-COST RICH GAS PLAYS
 Over 70% of Antero’s 4,243 Marcellus and Utica undeveloped 3P locations are rich gas locations which have the lowest breakeven prices
for both oil and natural gas compared to other U.S. shale plays
North American Breakeven Oil Prices ($/Bbl)(1)
$100
Antero Projects
2015 WTI Strip: $56.26/Bbl(2)
WTI Price ($/Bbl)
$83
$80
Antero 2015
Drilling Plan
$60
$40
$42
$39
$51
$54
$53
$60
$64
$65
$68
$69
$86
$72
$44
$20
$0
North American Gas Resource Play Breakeven Natural Gas Price(3)
NYMEX Price ($/MMBtu)
$7.00
$6.00
2015 NYMEX Strip: $3.01/MMBtu(2)
$5.00
Antero 2015
Drilling Plan
$4.00
$2.96
$3.00
$2.00
$1.94
$2.20
$2.20
$3.13
$5.56
$3.31
$3.48
$3.50
$3.63
$3.77
$3.85
$3.88
$3.98
$4.33
$5.62
$5.69
$5.71
$5.74
$4.38
$2.37
$1.00
$0.00
17
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.
MULTI-YEAR DRILLING INVENTORY SUPPORTS
LOW RISK, HIGH RETURN GROWTH PROFILE
 Antero is well positioned in the core of the highest return shale projects in the U.S. in the current commodity price environment
30%
42%
664
889
600
12%
15%
0%
Highly-Rich
Gas/
Condensate
900
628
28%
Highly-Rich
Gas
Locations
Rich Gas
11%
Dry Gas
300
0
ROR
ROR
ROR
45%
60%
1,200
1,010
Total 3PLlocations
60%
UTICA WELL ECONOMICS(1)
20%
46%
10%
139
254
33%
31%
40%
0%
2015
Drilling Plan
248
289
300
30%
200
94
Condensate Highly-Rich Highly-Rich
Gas/
Gas
Condensate
Locations
100
Rich Gas
Dry Gas
0
Total 3P Locations
MARCELLUS SSL WELL ECONOMICS(1)
ROR
 72% of Utica locations are processable (1100-plus Btu)
 72% of Marcellus locations are processable (1100-plus Btu)
Large 3P Drilling Inventory of High Return Projects(2)
Internal Rate of Return (%)
3,037 Antero Liquids-Rich Locations
40%
30%
20%
31%
26% 26%
Antero Projects
20%
16%
15%
10%
0%
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.
18
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%)
Projected Incremental Natural Gas Demand Through 2020
(Bcf/d) 9.5 Bcf/d of the 20 Bcf/d of
incremental demand is
20
expected to come from
LNG exports
17
16
13
 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
20
12
LNG
9
Petrochem
8
Incremental Demand Growth Through 2020 by Category
5
Power Gen
4
2
Sherwood 7
Transportation
1%
Exports
Industrial
16%
0
2015
Power
Generation
17%
LNG Exports
48%
2016
2017
Mexico/Canada Exports
Transportation
LNG Exports
2018
2019
2020
Power Generation
Petrochem
Mexico/Canada
Exports
18%
Source: Simmons & Company International, “2015 US Natural Gas Outlook and Updated Long Term Demand Forecast,” September 2014.
19
LNG EXPORTS BY PROJECT – EXPECTED START UP
LNG Exports by Project Through 2020
 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
LNG Exports by Project
Antero Supplied
(in Bcf/d)
2015
Sabine Pass 1
Sabine Pass 2
Sabine Pass 3
Sabine Pass 4
Sabine Pass 5
Cove Point 1
Cove Point 2
Cameron 1
Cameron 2
Cameron 3
Freeport 1
Freeport 2
Freeport 3
Freeport 4
Corpus Christi 1
Corpus Christi 2
Lake Charles 1
LNG Incremental Exports
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.
2016
-
0.6
0.6
1.2
2017
0.6
0.6
0.4
1.6
2018
2019
0.4
0.6
0.6
0.5
2.2
0.6
0.6
0.5
0.5
0.6
2.9
2020
0.4
0.6
0.6
1.7
Antero Supply Agreements
for Portion of Capacity
20
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)
Lower 48 Gas Supply by Area
(MMcf/d)
18,000
16,000
14,000
Nov-12
Nov-13
Nov-14
Marcellus production
has driven U.S. gas
supply growth
12,000
Gas Supply Growth by Area: 2009 – 2015E
10,000
8,000
Sherwood 7
6,000
Eagle Ford
22%
4,000
Marcellus &
Utica
78%
2,000
0
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).
21
ASSET OVERVIEW
22
WORLD CLASS MARCELLUS SHALE
DEVELOPMENT PROJECT
100% operated
Operating 13 drilling rigs
including 5 intermediate rigs
395,000 net acres in
Southwestern Core (73%
includes processable rich gas
assuming an 1100 Btu cutoff)
– 50% HBP with additional 27%
not expiring for 5+ years
362 horizontal wells completed
and online
– Laterals average 7,400’
– 100% drilling success rate
BEE LEWIS PAD
30-Day Rate
4-well combined
30-Day Rate of
67 MMcfe/d
(26% liquids)
MHR COLLINS UNIT
30-Day Rate
4-well average
9.3 MMcfe/d
(26% liquids)
RJ SMITH PAD
30-Day Rate
4-well combined
30-Day Rate of
56 MMcfe/d
(21% liquids)
HENDERSHOT UNIT
30-Day Rate
1H: 16.3 MMcfe/d
2H: 18.1 MMcfe/d
(29% liquids)
HEFLIN UNIT
30-Day Rate
2H: 21.4 MMcfe/d
(21% liquids)
Sherwood
Processing
Complex
142 Horizontals Completed
30-Day Rate
8.1 MMcf/d
6,915’ average lateral length
5 plants in-service at Sherwood
Processing Complex capable of
processing 1 Bcf/d of rich gas
− Over 800 MMcf/d being
processed currently
WAGNER PAD
30-Day Rate
4-well combined
30-Day Rate of
59 MMcfe/d
(14% liquids)
Net 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)
HORNET UNIT
30-Day Rate
1H: 21.5 MMcfe/d
2H: 17.2 MMcfe/d
(26% liquids)
Highly-Rich/Condensate
69,000 Net Acres
664 Gross Locations
CONSTABLE UNIT
30-Day Rate
1H: 14.3 MMcfe/d
(26% liquids)
Highly-Rich Gas
130,000 Net Acres
1,010 Gross Locations
NERO UNIT
30-Day Rate
1H: 18.2 MMcfe/d
(27% liquids)
Rich Gas
91,000 Net Acres
628 Gross Locations
CARR UNIT
30-Day Rate
2H: 20.6 MMcfe/d
(20% liquids)
Dry Gas
105,000 Net Acres
889 Gross Locations
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.
23
ANTERO’S MARCELLUS SHALE TYPE CURVE
 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
15.0
Non-SSL Actual Production (1)
Non-SSL Type Curve Cumulative Production
SSL Type Curve (1.7 Bcf/1,000')
SSL Actual Production (2)
SSL Type Curve Cumulative Production
Actual Rates
12.0
MMcf/d
Non-SSL Type Curve (1.5 Bcf/1,000')
24-Hour
Peak Rate
30-Day
Avg. Rate
90-Day
Avg. Rate
180-Day
Avg. Rate
One-Year
Avg. Rate
Two-Year
Avg. Rate
Three-Year
Avg. Rate
Four-Year
Avg. Rate
15.0
15.3
362
9.2
343
7.1
322
5.8
291
4.3
227
3.2
124
2.6
63
1.8
24
12.0
Wellhead Gas (MMcf/d)
# of Antero Wells
9.0
9.0
6.0
6.0
3.0
3.0
0.0
0.0
0
1
2
3
4
5
Production Year
EURs Increase With Lateral Length
$3.0
20
$2.5
15
10
5
0
6
7
8
9
10
8,000
10,000
Well Cost / 1,000’ Decreases with Lateral Length
25
$MM / 1,000'
EUR, BCF
Cumulative Bcf
Marcellus Type Curves – Normalized to 8,000’ Lateral
$2.0
$1.5
$1.0
$0.5
2,000
4,000
6,000
8,000
10,000
$0.0
2,000
Lateral Length, ft
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.
4,000
6,000
Lateral length, ft
24
INCREASING RECOVERIES AND LOW VARIANCE
IN MARCELLUS
 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%
30-Day Rates – 343 Marcellus Wells(1)
25
2014 – 13.1 MMcfe/d
2013 – 9.4 MMcfe/d
MMcfe/d
20
2009–2012 – 8.0 MMcfe/d
15
10
5
0
 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
SSL Reserves per 1,000’ of Lateral – 164 Marcellus SSL Wells
35
P10/P90 = 1.5x
Well Count
30
25
P90
20
P10
15
10
5
0
1.3
1.4
1.5
1.6
1.7
1.8
1.9
2.0
2
2.1
2.2
2.3
2.4
2.5
2.6
2.7
> 2.7
Bcfe/1,000‘ of Lateral
1. Processed rates converting C3+ NGLs and condensate at 6:1. Ethane rejected and sold in gas stream.
25
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)
6,717
6,000
7,345
7,308
400
80
80
4,000
60
59
40
38
20
19
2010
140
100
103
0
450
120
136
5,732
2,000
160
0
2011
2012
2013
250
16,000
20
8,000
34
32
29
4,000
10
-
0
2010
2011
2012
Avg Spud-to-Spud Days
2013
2014
Total Measured Depth (Feet)
1. 2015 reflects Antero guidance per 1/20/2015 press release.
14
2015E
50
2011
2012
2013
Average Frac Stages per Well
$1.13
2.50
$0.98
$0.97
EUR/1,000' Lateral
15,355
12,000
36
2014
16
50
45
40
35
30
25
20
15
10
5
-
EUR vs. Development Cost
30
37
185
21
150
100
200
27
200
2010
Total Measured Depth (Feet)
Spud-to-Spud Days
13,181
14,607
283
Average Stage Length (Feet)
20,000
14,658
40
300
Wells on First Sales
50
14,067
45
361
350
Increasing Drilling Efficiency
40
420
-
2014 2015E
Average Lateral Length (Feet)
411
2.00
1.50
$0.89
$0.89
1.5
1.6
1.5
$1.20
1.6
2.0
$1.00
$0.80
$0.60
1.00
$0.40
0.50
$0.20
0.00
Development Cost ($/Mcfe)
8,000
8,400
Average Stage Length (Feet)
Lateral Length (1,000 Feet)
8,052
Wells on First Sales
10,000
Average Frac Stages per Well
Increasing Frac Stages per Well
Lateral Length Improvements (1)
$0.00
2010
2011
2012
EUR/1,000' Lateral (Bcfe)
2013
2014
Development Cost ($/Mcfe)
26
MARCELLUS ROR% AND GAS PRICE SENSITIVITY
 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
100%
Highly-Rich Gas/Condensate: 44%
664 Locations
Highly-Rich Gas: 30%
80%
Rich Gas: 12%
Pre-Tax ROR (%)
2015
Drilling Plan
Dry Gas: 11%
1,010 Locations
60%
628 Locations
40%
889 Locations
20%
0%
$3.00
$3.50
Highly-Rich Gas/Condensate
$4.00
$4.50
Highly-Rich Gas
1. Assumes 12/31/2014 strip pricing, market differentials and relevant transportation cost; 8,000’ lateral.
$5.00
$5.50
Rich Gas
Dry Gas
$6.00
Antero Rigs Employed
27
LEADING UTICA SHALE CORE POSITION DELIVERS
CONDENSATE AND NGLS
Utica Shale Industry Activity(1)
 100% operated
 Operating 8 rigs including 3 intermediate rigs
GULFPORT
24-Hour IP
Wagner 1-28H,
Shugert 1-1H, 1-12H
Average 21.0 MMcf/d
+ 2,270 Bbl/d NGL
+ 292 Bbl/d Oil
 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
NEUHART UNIT 3H
30-Day Rate
18.7 MMcfe/d
(58% liquids)
GULFPORT
24-Hour IP
McCort1-28H, 2-28H,
Stutzman 1-14H
Average 13.1 MMcf/d
+ 922 Bbl/d NGL
+ 21 Bbl/d Oil
DOLLISON UNIT 1H
30-Day Rate
23.3 MMcfe/d
(44% liquids)
MYRON UNIT 1H
30-Day Rate
30.4 MMcfe/d
(49% liquids)
Seneca
Processing
Complex
Utica
Core
Area
URBAN PAD
30-Day Rate
4-well combined
30-Day Rate of
74 MMcfe/d
(16% liquids)
 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 inservice 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)
LAW UNIT
30-Day Rate
2 wells average
18.4 MMcfe/d
(50% liquids)
Condensate
32,000 Net Acres
248 Gross Locations
Cadiz
Processing
Plant
RUBEL UNIT
30-Day Rate
3 wells average
21.1 MMcfe/d
(24% liquids)
SCHAFER UNIT
30-Day Rate(2)
2 wells average
16.2 MMcfe/d
(49% liquids)
GARY UNIT
30-Day Rate
3 wells average
29.8 MMcfe/d
(22% liquids)
Highly-Rich/Cond
26,000 Net Acres
139 Gross Locations
Highly-Rich Gas
15,000 Net Acres
94 Gross Locations
NORMAN UNIT
30-Day Rate
2 wells average
20.3 MMcfe/d
(17% liquids)
Rich Gas
33,000 Net Acres
254 Gross Locations
Dry Gas
42,000 Net Acres
289 Gross Locations
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.
28
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)
50
50
6,431
6,000
40
41
30
4,000
20
2,000
10
11
0
0
2013
2014
100
18,000
12,000
20
9,000
32
29
10
6,000
3,000
0
2013
2014
Total Measured Depth (Feet)
1. 2015 reflects Antero guidance per 1/20/2015 press release.
30
20
26
10
50
-
2014
2015E
Average Frac Stages per Well
EUR vs. Development Cost
15,000
30
175
150
1.60
$1.80
$1.64
1.40
EUR/1,000' Lateral
Spud-to-Spud Days
14,643
183
50
40
200
Average Stage Length (Feet)
Total Measured Depth (Feet)
16,321
47
50
250
Wells on First Sales
40
289
2013
Increasing Drilling Efficiency
Spud-to-Spud Days
300
2015E
Average Lateral Length
60
350
$1.24
1.20
$1.20
1.00
0.80
0.60
0.40
$1.50
$0.90
1.4
1.6
$0.60
$0.30
0.20
0.00
$0.00
2013
EUR/1,000' Lateral (Bcfe)
2014
Development Cost ($/Mcfe)
29
Development Cost ($/Mcfe)
8,021
Average Stage Length (Feet)
8,000
60
8,700
Wells on First Sales
Lateral Length (Feet)
10,000
Average Frac Stages per Well
Increasing Frac Stages per Well
Lateral Length Improvements (1)
UTICA ROR% AND GAS PRICE SENSITIVITY
 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
NYMEX Flat Price Sensitivity(1)
200%
ROR% at Flat 2015-2020 Strip Price
94 Locations
Condensate: 13%
180%
Highly-Rich Gas/Condensate: 41%
160%
254 Locations
Rich Gas: 47%
140%
Pre-Tax ROR (%)
289 Locations
Highly-Rich Gas: 63%
Dry Gas: 44%
120%
2015
Drilling Plan
100%
139 Locations
80%
60%
40%
248 Locations
20%
0%
$3.00
Condensate
$3.50
$4.00
Highly-Rich Gas/Condensate
1. Assumes 12/31/2014 strip pricing, market differentials and relevant transportation cost; 8,000’ lateral.
$4.50
Highly-Rich Gas
$5.00
$5.50
Rich Gas
$6.00
Dry Gas
30
LARGE UTICA SHALE DRY GAS POSITION
 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:
Well
Operator
IP
(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
Utica Shale Dry Gas Acreage in OH/WV/PA(1)
Rice
Blue Thunder
10H, 12H
≈9,000’ Lateral
Rice
Bigfoot 9H
6,957’ Lateral
IP 41.7 MMcf/d
Hess
Porterfield 1H-17
5,000’ Lateral
IP 17.2 MMcf/d
Gulfport
Irons #1-4H
5,714’ Lateral
IP 30.3 MMcf/d
Chesapeake
Utica Well
Drilling
Stone Energy
Pribble 6HU
3,605’ Lateral
IP 30.0 MMcf/d
Antero
Planned
Utica Well
2015
Eclipse
Tippens #6H
5,858’ Lateral
IP 23.2 MMcf/d
Magnum Hunter
Stewart Winland 1300U
5,289’ Lateral
IP 46.5 MMcf/d
Utica Shale Dry Gas
Ohio
3P Reserves
2.4 Tcf
289 Gross Locations
42,000 Net Acres
1. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held in OH, WV and PA.
Range
Claysville SC #1
5,420’ Lateral
IP 59.0 MMcf/d
Chevron
Conner 6H
6,451’ Lateral
IP 25.0 MMcf/d
Gastar
Simms U-5H
4,447’ Lateral
IP 29.4 MMcf/d
Magnum Hunter
Stalder #3UH
5,050’ Lateral
IP 32.5 MMcf/d
Chesapeake
Hubbard BRK #3H
3,550’ Lateral
IP 11.1 MMcf/d
Utica Shale Dry Gas
Total OH/WV/PA
Net Resource
13.5 Tcf
1,905 Gross Locations
212,000 Net Acres
Utica Shale Dry Gas
WV/PA
Net Resource
11.1 Tcf
1,616 Gross Locations
170,000 Net Acres
31
FRESH WATER DISTRIBUTION SYSTEMS
Projected Midstream Infrastructure(1)
Marcellus
Shale
YE 2015E Cumulative
Fresh Water System Capex ($MM)
Water Pipelines (Miles)
Water Storage Facilities
$338
226
24
Utica
Shale
Total
$112
90
14
$450
316
38
Marcellus Fresh Water Distribution System
•
•
•
Provides fresh water to support Marcellus well completions
Year-round water supply sources: Ohio River and local rivers
Significant growth projected over the next twelve months as summarized
below:
Marcellus Water System
YE 2015
Water Pipeline (Miles)
49
Fresh Water Storage Impoundments
2
Water Fees per Well
($)(2)
$600K $800K
OHIO
Utica Fresh Water Distribution System
•
•
•
Provides fresh water to support Utica well completions
Year-round water supply sources: local reservoirs and rivers
Significant growth projected over the next twelve months as summarized
below:
Utica Water System
YE 2015
Water Pipeline (Miles)
29
Fresh Water Storage Impoundments
6
Water Fees per Well
($)(2)
$600K $800K
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.
32
FIRM TRANSPORTATION AND FIRM SALES PORTFOLIO
Columbia
Tennessee
Momentum III
EQT
REX/MGT/ANR
7/26/2009 – 9/30/2025
11/1/2015– 9/30/2030
9/1/2012 – 12/31/2023
8/1/2012 – 6/30/2025
7/1/2014 – 12/31/2034
ANR
Local Distribution
Firm Sales #1
Firm Sales #2
Firm Sales #3
10/1/2011– 10/31/2019
10/1/2011 – 5/31/2017
1/1/2013 – 5/31/2022
3/1/2015– 2/28/2045
11/1/2015 – 9/30/2037
MMBtu/d
4,500,000
4,000,000
3,500,000
Mid-Atlantic/NYMEX
3,000,000
Gulf Coast
2,500,000
2,000,000
1,500,000
1,000,000
500,000
Midwest
Appalachia
Appalachia
Gulf Coast
Appalachia or Gulf Coast
-
33
FIRM TRANSPORTATION REDUCES APPALACHIAN
BASIS EXPOSURE
 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
All-in Firm Transportation Costs(1)
+ $0.18/MMBtu
$0.70
$0.60
$0.46
($/MMBtu)
$0.50
$0.40
$0.30
$0.20
$0.10
$0.25
$0.35
$0.28
$0.13
$0.12
$0.11
$0.11
$0.33
$0.23
$0.14
$0.17
2013A
2014E
$0.00
Wtd. Avg. FT Demand ($/MMBtu)
2015E
Gulf Coast
51%
Utilized portion included
in cash production
expense
(fixed cost)
2016E
Wtd. Avg. FT Commodity/Fuel ($/MMBtu)
2013 Firm Transportation – 647 MMcf/d
Average All-in FT Cost $0.25/MMBtu
2013 Firm
Transportation(1)(2)
Included in cash
production expense
(variable cost)
2016 Firm Transportation – 3.1 Bcf/d
Average All-in FT Cost $0.46/MMBtu
2016 Basis(3)
TCO – $(0.41)/MMBtu
DOM S – $(1.11)/MMBtu
2016 Basis(3)
Chicago – $(0.08)/MMBtu
Appalachia
49%
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.
Midwest
20%
Appalachia
35%
Gulf Coast
45%
2016 Basis(3)
CGTLA – $(0.09)/MMBtu
34
ANTERO FIRM TRANSPORTATION APPROPRIATELY
DESIGNED TO ACCOMMODATE GROWTH
•
•
•
Antero’s firm transport (FT) is well
utilized during 2015 (72%)
Marketable FT (BBtu/d) (3)
(BBtu/d)
− Excess FT for acquisitions and well
productivity improvements
2,500
A portion of the excess FT is highly
marketable, further increasing
utilization to 86%
2,000
Expect to fully utilize FT portfolio by
2018
Firm Transportation / Firm Sales (BBtu/d)
Risked Gross Gas Production Target (BBtu/d)
% FT Utilization
(including
marketable FT):
86%
1,500
1,000
500
0
Net Production Target (MMcfe/d) (1)
Net Gas Production Target (MMcf/d)
Net Revenue Interest Gross-up
Gross Gas Production Target (MMcf/d)
BTU Upgrade (2)
Gross Gas Production Target (BBtu/d)
2015
1,400
1,190
80%
1,485
x1.100
1,630
Firm Transportation / Firm Sales (BBtu/d)
Estimated % Utilization of FT/FS
Marketable Firm Transport (BBtu/d) (3)
2,250
72%
350
Estimated % Utilization of FT/FS (Including Marketable FT)
86%
1. 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.
35
HEALTH, SAFETY, ENVIRONMENT & COMMUNITY
Antero 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
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 2015
requirements)
LEED Gold Headquarters
Building
 Recently moved into new corporate headquarters in Denver, Colorado that has
been LEED Gold Certified
 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
$40,000/day
− Reduces NOx and CO emissions by 99%
− Eliminates 25 diesel trucks from the roads
for an average well completion
− Reduces silica dust to levels 90% below
OSHA permissible exposure limits resulting
in a safer and cleaner work environment
− Significantly reduces noise pollution from a
well site
− Is the most environmentally responsible
completion solution in the oil and gas
industry
•
Additionally, Antero utilizes compressed natural
gas (CNG) to fuel its truck fleet in Appalachia
− Antero supported the first natural gas fueling
station in West Virginia
− Antero has 30 NGV trucks and plans to
continue to convert its truck fleet to NGV
37
Antero Midstream (NYSE: AM)
Asset Overview
38
SUBSTANTIAL INVESTMENT IN MIDSTREAM MLP
(NYSE: AM)
Midstream Assets
Utica
Shale
• Gathering and compression assets in core of rapidly
growing Marcellus and Utica Shale plays
– Acreage dedication of ~412,000 net leasehold
acres for gathering and compression services
– 100% fixed fee long term contracts
Projected Midstream Infrastructure(1)
Marcellus Utica
Shale Shale
Total
YE 2014E Cumulative Gathering/
Compression Capex ($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
1. Represents inception to date actuals as of 6/30/2014 and 2015 guidance.
2. Includes $12.5 million of maintenance capex at 2015 midpoint guidance.
Marcellus
Shale
39
ANTERO MIDSTREAM ASSETS – RICH GAS MARCELLUS
Marcellus Gathering & Compression
•
Provides Marcellus gathering and compression
services
−
•
Liquids-rich gas is delivered to MWE’s Sherwood
Complex for processing
Significant growth projected over the next twelve
months as set out below:
YE 2014
YE 2015
Gathering Pipelines (Miles)
153
199
Compression Capacity (MMcf/d)
375
800
•
Antero sold the Harrison County portion of its gathering
system to a 3rd party midstream company in 2012,
which is now recognized as the 3rd Party Gathering and
Compression Dedication area
•
Development upside as AR continues to drill, step-out
and add acreage
WV/PA Utica Dry Gas Gathering & Compression
•
Further development upside in 170,000 net acres of
Utica deep rights beneath the Marcellus Shale
−
Will require a separate dry gas gathering system
Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.
40
ANTERO MIDSTREAM ASSETS – RICH & DRY GAS UTICA
Utica Gathering
•
•
•
Provides Utica natural gas and condensate gathering
services
− Liquids-rich gas delivered into MWE’s Seneca
Complex for processing
− Condensate delivered to centralized stabilization
and truck loading facilities
Significant growth projected over the next twelve
months as set out below:
YE 2014
YE 2015
Gathering Pipelines (Miles)
80
98
Condensate Pipelines (Miles)
16
20
Compression (MMcf/d)
0
120
Development upside as AR continues to drill, step-out
and add acreage
Utica Compression
•
Opportunity to build up to ten new compressor stations
that are planned to support AR development over the
next several years
Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.
41
APPENDIX
42
PRO FORMA CAPITALIZATION
($ in millions)
Cash
Senior Secured Revolving Credit Facility
6.00% Senior Notes Due 2020
9/30/2014
Pro Forma $1.15 Bn AM IPO(4)
9/30/2014
$6
$256
1,505
662
525
525
5.375% Senior Notes Due 2021
1,000
1,000
5.125% Senior Notes Due 2022
1,100
1,100
Net Unamortized Premium
8
8
Total Debt
$4,138
$3,295
Net Debt
$4,132
$3,039
Minority Interest
-
$326
Shareholders' Equity
$3,751
$4,372
Net Book Capitalization
$7,883
$7,737
$13,631
$12,788
LTM EBITDAX
$1,047
$1,047
LQA EBITDAX
$1,109
$1,109
Enterprise
Value(1)
Financial & Operating Statistics
LTM Interest Expense(2)
Proved Reserves (Bcfe) (12/31/2014)
Proved Developed Reserves (Bcfe) (12/31/2014)
$155
$138
12,683
12,683
3,803
3,803
3.9x
2.9x
Credit Statistics
Net Debt / LTM EBITDAX
Net Debt / LQA EBITDAX
3.7x
2.7x
LTM EBITDAX / Interest Expense
6.8x
7.6x
Net Debt / Net Book Capitalization
52.4%
39.3%
Net Debt / Proved Developed Reserves ($/Mcfe)
$1.09
$0.80
Net Debt / Proved Reserves ($/Mcfe)
$0.33
$0.24
Credit Facility Commitments(3)(4)
$3,000
$4,000
Less: Borrowings
(1,505)
(662)
(332)
(332)
6
256
$1,169
$3,262
Liquidity
Less: Letters of Credit
Plus: Cash
Liquidity (Undrawn Credit Facility + Cash)
1. 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 $1 billion credit
facility currently undrawn.
43
LOWEST FINDING & DEVELOPMENT COST
AMONG U.S. PRODUCERS
 Antero ranks as the most efficient finder and developer of reserves, on a per Mcfe basis, based on a 2011-2013 average all-in F&D cost
analysis prepared by Credit Suisse
3-Year All-In F&D Cost – Excluding Revisions ($/Mcfe) through 2013
AR
RRC
PDCE
SWN
REXX
EPE
ATHL
SFY
ROSE
CHK
SD
BCEI
PXD
CRZO
EOG
NBL
DNR
FST
KWK
DVN
CXO
PVA
EOX
EXXI
CRK
KOG
FANG
WLL
MRO
APA
MUR
GPOR
APC
MHR
$0.58
$0.79
$0.84
$1.04
$1.26
$1.53
$1.60
$1.74
$1.94
$2.06
$2.40
$2.57
$2.66
$2.78
$2.87
$2.88
$2.91
$2.91
$3.05
$3.05
$3.07
$3.12
$3.28
$3.63
$3.70
$4.01
$4.23
$4.54
$4.66
$4.66
$0
$2
Source: Credit Suisse research dated 4/28/2014.
$4
$5.74
$6
$6.68
$7.14
$10.24
$8
$10
$12
44
MARCELLUS SINGLE WELL ECONOMICS
– IN ETHANE REJECTION
Marcellus SSL Well Economics and Total Gross Locations(1)
 Natural Gas – 12/31/2014 strip
 Oil – 12/31/2014 strip
 NGLs – 55% of Oil Price
60%
NYMEX
($/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
$39
ROR
45%
30%
2015
Drilling Plan
889
664
42%
12%
Highly-Rich Gas/
Condensate
900
628
28%
15%
0%
1,200
1,010
Highly-Rich Gas
Locations
Rich Gas
600
11%
Dry Gas
Highly-Rich Gas/
Condensate
Highly-Rich
Gas
Rich Gas
Dry Gas
Modeled BTU
1313
1250
1150
1050
EUR (Bcfe):
EUR (MMBoe):
% Liquids:
Lateral Length (ft):
Stage Length (ft):
Well Cost ($MM):
Bcfe/1,000’:
17.7
2.9
31%
8,000
225
$10.6
2.2
16.2
2.7
22%
8,000
225
$10.6
2.0
14.7
2.4
10%
8,000
225
$10.6
1.8
13.6
2.3
0%
8,000
225
$10.6
1.7
$7.4
28%
$0.77
3.0
HIGHLY
$0.6
RICH GAS
12%
LOCATIONS
$0.85
6.6
$0.4
11%
$0.92
6.7
Gross 3P Locations(3):
$11.9
RICH42%
GAS LOCATIONS
$0.70
2.1
664
1,010
0
ROR
Classification
Pre-Tax NPV10 ($MM):
Pre-Tax ROR: DRY GAS LOCATIONS
Net F&D ($/Mcfe):
Payout (Years):
300
Total 3P Locations
Assumptions
628
1. Well economics are based on 12/31/2014 strip differential pricing and related transportation costs. Includes gathering, compression and processing fees.
2. Pricing for a 1225 BTU y-grade ethane rejection barrel.
3. Undeveloped well locations as of 12/31/2014.
889
45
UTICA SINGLE WELL ECONOMICS
– IN ETHANE REJECTION
Utica Well Economics and Gross Locations(1)
 Natural Gas – 12/31/2014 strip
 Oil – 12/31/2014 strip
 NGLs – 55% of Oil Price
60%
400
46%
NYMEX
($/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
$39
ROR
45%
248
254
31%
30%
0%
200
94
10%
Condensate
Highly-Rich Gas/
Condensate
2015
Drilling Plan
100
Highly-Rich Gas
Rich Gas
Locations
ROR
Dry Gas
Classification
Condensate
Highly-Rich Gas/
Condensate
Highly-Rich
Gas
Rich Gas
Dry Gas
Modeled BTU
1275
1235
1215
1175
1050
EUR (Bcfe):
EUR (MMBoe):
% Liquids
Lateral Length (ft):
Stage Length (ft):
Well Cost ($MM):
Bcfe/1,000’:
8.3
1.4
35%
8,000
240
$12.1
1.0
15.0
2.5
26%
8,000
240
$12.1
1.9
22.4
3.7
21%
8,000
240
$12.1
2.8
21.2
3.5
14%
8,000
240
$12.1
2.7
19.0
3.2
0%
8,000
240
$12.1
2.4
$0.0
$7.6
10%
31%
RICH GAS LOCATIONS
$1.79
$0.99
5.5
1.5
$13.0
46%
$0.67
1.1
HIGHLY
$9.1
RICH GAS
33%
LOCATIONS
$0.71
1.5
$8.0
30%
$0.79
2.6
94
254
289
Pre-Tax NPV10 ($MM):
Pre-Tax ROR: DRY GAS LOCATIONS
Net F&D ($/Mcfe):
Payout (Years):
Gross 3P Locations(3):
248
139
300
30%
33%
139
15%
289
1. Well economics are based on 12/31/2014 strip differential pricing and related transportation costs. Includes gathering, compression and processing fees.
2. Pricing for a 1225 BTU y-grade ethane rejection barrel.
3. Undeveloped well locations as of 12/31/2014. 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content.
Total 3P Locations
Assumptions
0
46
LOW DEVELOPMENT COST DRIVES BEST IN CLASS
RECYCLE RATIOS
3-Year Proved Development Costs ($/Mcfe) through 2013
$/Mcfe
$6.00
Antero
Appalachia-Focused Peers
Other Peers
$5.00
$4.00
$3.00
$2.00
$1.00
$1.15
$1.18
$1.21
$1.60
$0.00
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 Average Growth – Adjusted Recycle Ratio through 2013
6.0x
Antero
Appalachia-Focused Peers
Other Peers
4.8x
4.0x
3.5x
3.3x
2.4x
2.0x
0.0x
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.
47
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
ETHANE REJECTION(1)
ETHANE RECOVERY(1)
Marcellus – 28.4 Tcfe
Marcellus – 33.7 Tcfe
Utica – 7.6 Tcfe
Utica – 8.6 Tcfe
Upper Devonian – 4.6 Tcfe
Upper Devonian – 5.1 Tcfe
40.7
Tcfe
47.4
Tcfe
Gas – 34.5 Tcf
Gas – 32.0 Tcf
Oil – 102 MMBbls
Oil – 102 MMBbls
NGLs – 924 MMBbls
NGLs – 2,459 MMBbls
15%
Liquids
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.
48
POSITIVE RATINGS MOMENTUM
Moody’s / S&P Historical Corporate Credit Ratings
Moody’s Upgrade Criteria
S&P Upgrade Criteria
“An upgrade could be considered if debt / average daily production is
sustained below $20,000 per boe and debt / proved-developed
reserves is sustained below $8.00 per boe. An upgrade would also be
contingent on Antero maintaining unleveraged cash margins greater
than $25.00 per boe and retained cash flow to debt over 40%.”
“We could raise the ratings due to our assessment of an improvement in
the company's financial profile. An improvement in the financial profile
would include maintaining FFO to debt of greater than 45% and
narrowing the amount that the company outspends its cash flows by.”
- S&P Credit Research, September 2014
- Moody’s Credit Research, September 2014
Credit Rating
(Moody’s / S&P)
Baa3 / BBBBa1 / BB+
Ba2 / BB
Ba3 / BBB1 / B+
B2 / B
B3 / BCaa1 / CCC+
9/1/2010
5/31/13
2/24/2011
Moody's
1. Represents corporate credit rating of Antero Resources Corporation / Antero Resources LLC.
10/21/2013
9/4/2014
12/31/2014
(1)
S&P
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PRO FORMA OFFERING – BALANCE SHEET POSITIONED
FOR LONG-TERM GROWTH
 The recent bond offerings, at progressively lower coupons, have allowed Antero to reduce its cost of debt to approximately 5.0% and
enhance liquidity while extending the pro forma average debt maturity to July 2021
 Current cost of debt 4.8%, average debt maturity 6.8 years
PRO FORMA WEIGHTED AVERAGE INTEREST RATE AND MATURITY(1)
As At
09/30/14
($ in millions)
Senior Secured Revolving Credit Facility
6.0% Senior Notes due 2020
5.375% Senior Notes due 2021
5.125% Senior Notes due 2022
Total Long-Term Debt
Interest
Rate
$662
525
1,000
1,100
$3,287
Current
(2)
Yield
2.440%
6.000%
5.375%
5.125%
Weighted Average:
(3)
4.800%
2.440%
6.204%
6.102%
6.201%
Maturity
(Years)
(3)
5.414%
PRO FORMA DEBT MATURITY PROFILE
$1,200
Senior Secured Revolving Credit Facility
Senior Notes
($ in Millions)
$800
4.6
6.2
7.1
8.2
May-19
Dec-20
Nov-21
Dec-22
6.8
Jul-21
(1)
$1,000
$1,000
Maturity
(Date)
$1,100
$662
$525
$600
$400
$200
$0
2014
2015
2016
2017
2018
2019
1. 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.
2020
2021
2022
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MARCELLUS & UTICA – ADVANTAGED ECONOMICS
 Low cost, liquids-rich Utica and Marcellus Shales will remain attractive in most commodity price environments
U.S. INCREMENTAL GAS SUPPLY BREAK-EVEN PRICE CURVE(1)
?
1. Source: Credit Suisse report dated January 2014 – Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI
Haynesville
?
Barnett
?
Eagle Ford
Shale
Niobrara
Utica
Shale
SW (Rich)
Marcellus
Shale
NE (Dry)
Marcellus
Shale
Permian
Needed to make up
for base declines in
conventional and
GOM production
Granite Wash
3,000 Antero
Drilling Locations
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LNG EXPORTS BY PROJECT – CURRENT STATUS
LNG Exports by Project – Current Status
Dates of Key Milestones
DOE Non-FTA
FERC
Permit
Construction
Send Out NonFTA Permit
Capacity
Underlying
Gas Demand
Project
Sabine Pass 1-4
Awarded
05/20/11
Approval
04/16/12
(Bcf/d)
2.20
(Bcf/d)
2.42
Contracts
Fully Subscribed
Offtakers
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
Lake Charles
08/07/13
Expected 2015
2.00
2.20
Fully Subscribed
Osaka Gas, Chubu Electric,
BP, Toshiba, SK E&S
BG
8.07
8.88
0.40
0.44
Not Subscribed
N/A
8.47
9.32
Sherwood 7
Subtotal
Freeport Phase II
Total
11/15/13
Pending
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.
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CAUTIONARY NOTE
Regarding Hydrocarbon Quantities
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.
53