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Company OverviewFebruary 2014
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 in the Company’s Registration Statement on Form S-1 (File No. 333 – 189284) (the “Registration Statement”) with the U.S. Securities and Exchange Commission (the “SEC”) 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 the Registration Statement 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
ANTERO: A “PURE PLAY” ON THE MARCELLUS / UTICA● Marcellus is the largest gas field in the U.S., 2nd largest in the world –
Industry production approximately 14 Bcf/d today● Antero has 35 Tcfe of 3P reserves in Marcellus and Utica Shales● 566 MMcfe/d of average net production in 3Q 2013 including 7,900 Bbl/d of
liquids; 675–680 MMcfe/d net production guidance for 4Q 2013
Critical Mass In Two World Class Shale Plays
● 159% Appalachian production CAGR since 2010 to YE 2013● Most active driller in Appalachia – 20 rigs running● Most active driller in Marcellus Shale – 15 rigs running● 3rd most active driller in the Utica Shale – 5 rigs running
Market Leading Growth
● Low development cost leader: $1.03/Mcfe(1)
● Industry leading growth-adjusted recycle ratio: 6.1x(1)
● Top quartile return on productive capital: 27% for 2013E
Industry Leading Capital Efficiency and Recycle Ratio
● 1.6 Bcf/d of processing capacity and 1.5 Bcf/d of gas takeaway● Liquids expected to grow from 8% of third quarter 2013 production
due to focus on liquids-rich development
Significant Emphasis on Takeaway and
Liquids Processing
● ~$1.8 billion pro forma available liquidity with current $1.5 billion bank commitment(2)
● 1.3 Tcfe hedged through 2019 at an average index price of $4.64/MMBtuand $96.54/Bbl
Liquidity and Hedge Position Support High
Growth Story
● Over 30 years as a team (over 20 years in unconventional)● “Shale Pioneers” – early mover and driller of over 500 horizontal shale
wells in the Barnett, Woodford, Marcellus and Utica Shales
Outstanding Management Team
21. Three year average through 2012; pro forma for Arkoma and Piceance divestitures.2. See page 21 for the derivation of 9/30/2013 liquidity.
UPPER DEVONIAN SHALE
Net Proved Reserves(1) 44 BcfeNet 3P Reserves (1) 4.2 TcfePre-Tax 3P PV-10(1) NM% Liquids – Net 3P 7%3Q 2013 Net Production 3 MMcfe/dUndrilled 3P Locations 951
C
PREMIER UNCONVENTIONAL RESOURCE PLATFORM
1. Proved, probable, and possible reserves as of December 31, 2013, assuming ethane rejection using SEC methodology and SEC pricing. Evaluations prepared by our internal reserve engineers and audited by DeGolyer & MacNaughton (D&M). Pre-Tax 3P PV-10 is a non-GAAP financial measure.
2. Represents the average net daily production for the period July 1, 2013 through September 30, 2013. 3. All net acres allocated to the Dry Gas Utica 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
leases.
TOTAL – 12/31/13 RESERVES(1)
Assumes Ethane RejectionNet Proved Reserves(1) 7.6 TcfeNet 3P Reserves(1) 35.0 TcfePre-Tax 3P PV-10(1) $20,362 MM
Net 3P Liquids 902 MMBbls% Liquids – Net 3P 15%3Q 2013 Net Production(2) 566 MMcfe/d- 3Q 2013 Net Liquids(2) 7,900 Bbl/dNet Acres(3) 454,000Undrilled 3P Locations 4,778
MARCELLUS SHALE
Net Proved Reserves(1) 7.2 TcfeNet 3P Reserves (1) 25.0 TcfePre-Tax 3P PV-10(1) $15,729 MM% Liquids – Net 3P 17%3Q 2013 Net Production 519 MMcfe/dUndrilled 3P Locations 3,068
• 100% operated
• Stable acreage base− Marcellus Shale: 51% HBP, with additional 21%
not expiring for 5+ years− Utica Shale: 20% HBP, with additional 79% not
expiring for 5+ years
• Portfolio flexibility across dry gas to liquids-rich and condensate windows
• Significant investment in midstream infrastructure and secured takeaway capacity
• Financial flexibility to pursue planned 2014 and 2015 development drilling activities
• Full scale development underway− 20 rigs currently operating
A
UTICA SHALE – LIQUIDS RICH
Net Proved Reserves(1) 362 BcfeNet 3P Reserves (1) 5.8 TcfePre-Tax 3P PV-10(1) $4,666 MM % Liquids – Net 3P 15%3Q 2013 Net Production 44 MMcfe/dUndrilled 3P Locations 759
B
3
AC
B Additional Hedge Value
“Pure-Play” Appalachian-Focused Shale Company
UTICA SHALE – DRY GAS
Net Acres(3) 126,000Net Resource 5.0 TcfeUndrilled Locations 950
D
D • 1.3 Tcfe hedged from 1/1/2014 through 12/31/2019 at an average index price of $4.64/MMBtu and $96.54/Bbl
• ~ $1.0 billion mark-to-market hedge value as of 12/31/2013
• ~ 50% hedged through NYMEX; 50% hedged through regional hubs
0
200
400
600
800
1,000
2010 2011 2012 2013E 2014E
Marcellus Utica
30124
239
522
950
(5)(4)
4
0
200
400
600
800
1,000
2006 2007 2008 2009 2010 2011 2012 2013E 2014E
Woodford Piceance Marcellus Utica
6 31 87 105 133244
334
522
(5)
950
(4)
AVERAGE NET DAILY PRODUCTION (MMcfe/d) APPALACHIAN PRODUCTION (MMcfe/d)
01,0002,0003,0004,0005,0006,0007,0008,0009,000
2006 2007 2008 2009 2010 2011 2012 2013
Woodford Piceance Marcellus Utica(3)
87 235680 1,141
3,231
5,0174,283
7,632Sold Woodford and Piceance
(6) (6)
NET PROVED SEC RESERVES (Bcfe)(2)
193
0
25
50
75
100
125
150
175
200
2006 2007 2008 2009 2010 2011 2012 2013E 2014E
Woodford Piceance Marcellus Utica
8596
126
18
66
91
119
157
(5)(4)
1. CAGR = Compound Annual Growth Rate.2. Proved reserves for 2006, 2007, and 2008 represent previously effective SEC methodology. 2009, 2010, 2011, 2012 and 2013 proved reserves based on current SEC reserve methodology and SEC pricing and
are audited by independent third-party engineers. 3. Includes Upper Devonian Shale proved reserves (10 Bcfe in 2012 and 44 Bcfe in 2013).4. Per Company press release dated January 27, 2014. 5. Per Company press release dated January 29, 2014; production mid-point of 925-975 MMcfe/d guidance.6. 2012 and 2013 proved reserves are both in ethane rejection mode.
FinancialCrisis
STRONG TRACK RECORD OF GROWTH
OPERATED GROSS WELLS SPUD
Sold Woodford and Piceance
$0.00 $0.00 $0.00 $0.00$0.89 $1.15
$2.47 $2.50 $2.60$2.94 $3.20 $3.27 $3.51
$3.65 $3.66 $3.70 $3.75 $3.80 $3.81 $4.13 $4.25 $4.66$5.05
$5.37 $5.49
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
637 834707
890
117%
65%
32% 21% 0
200
400
600
800
1000
0%
50%
100%
150%
Highly-RichGas/
Condensate
Highly-RichGas
Rich Gas Dry Gas
Tota
l 3P
Loca
tions
RO
R
Locations ROR
MULTI-YEAR DRILLING INVENTORY SUPPORTS LOW-RISK, HIGH-RETURN GROWTH PROFILE
Large Inventory of Low Breakeven Projects(3)
1. Well economics based on 12/31/2013 3P SSL reserves and strip pricing as of 12/31/2013. 2. A portion of these locations do not assume SSL completions.3. Source: Credit Suisse report dated January 2014 – Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI.4. 3-year NYMEX STRIP as of 2/7/2014.
3 Yr Strip - $4.29/MMBtu(4)
637 Locations
1,541Locations366
Locations
890Locations
$ / M
MB
tu N
YMEX
(Gas
)
182Locations
5
MARCELLUS SSL WELL ECONOMICS(1)(2) UTICA WELL ECONOMICS(1)
205 161182
211
137%169%
95%56%
0
50
100
150
200
250
0%
50%
100%
150%
200%
Highly-RichGas/
Condensate
Highly-RichGas
Rich Gas Dry Gas
Tota
l 3P
Loca
tions
RO
R
Locations ROR
1,000
71% of Marcellus locations are processable (1100-plus Btu) 72% of Utica locations are processable (1100-plus Btu)
`
2,726 Liquids-Rich Locations
0.0x
2.0x
4.0x
6.0x
8.0x6.1x
3.5x 3.1x 2.7x
$0.00
$1.00
$2.00
$3.00
$4.00
$1.03 $1.14 $1.41 $1.57 $1.71
LOW DEVELOPMENT COST DRIVES BEST-IN-CLASS RECYCLE RATIOS
6
Source: Proved developed F&D research prepared by JP Morgan Research report dated 07/22/2013. Defined as total drilling and completion capital expenditures for the period divided by PDP and PDNP volumes added after adding back production for the period. Includes all drilling and completion costs but excludes land and acquisition costs for all companies. 1. Antero internal estimate using JP Morgan development cost methodology; excludes Arkoma and Piceance operations.2. Antero estimate based on public information; includes Arkoma and Piceance operations.
3-Year All-in Development Costs ($/Mcfe) through 2012
Antero Appalachia-Focused Peers
Source: Wall Street research. Defined as 2010-2012 average (Cash Operating Netback / PD F&D costs) x (1 + 2012-2014 production CAGR). 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 per JP Morgan analysis. Includes all drilling and completion costs but excludes land and acquisition costs for all companies.1. Antero data pro forma for Woodford and Piceance divestitures; Antero production growth based on first half of 2013 only.
Antero Appalachia-Focused Peers
3-Year Average Growth – Adjusted Recycle Ratio through 2012
$/Mcfe
INTEGRATED MIDSTREAM PROCESSING AND TAKEAWAY
Infrastructure and commitments in place to handle strong natural gas, NGL and oil production growth
– Portfolio of firm transportation and sales and West Virginia location minimizes basis risk
Producers located at the southern end of the Marcellus have seen much less basis widening and volatility than Pennsylvania producersAntero has sold ~76% of its year-to-date production
through September 30, 2013 at TCO index at NYMEX less $0.07/MMbtu
71. 80,000 MMBtu/d and 70,000 MMbtu/d also utilize firm transportation in 2014 and 2015, respectively.2. Basis data from Wells Fargo daily indications and various private quotes as of 2/7/2014.
0
200
400
600
800
1,000
1,200
1,400
1,600
(MM
cf/d
)
Sherwood I Sherwood II Sherwood III Sherwood IV Sherwood V
Seneca I Seneca II Seneca III Seneca IV
Total Capacity 1,550
MarcellusUtica
Sherwood I
Sherwood II
Sherwood III
Seneca I
Seneca II
Seneca III
TCOBasis to NYMEXCurrent 2015+$0.04 -$0.47
Dom SouthBasis to NYMEXCurrent 2015-$0.40 -$1.11
LeidyBasis to NYMEXCurrent 2015-$2.25 -$2.00
Antero Transport and Processing 2014 2015Firm Transport (FT) (MMBtu/d) 1,227,000 1,227,000Firm Sales (MMBtu/d)(1) 330,000 320,000
Firm Processing Capacity (Mcf/d) 1,400,000 1,550,000Ethane FT (Bbl/d) 20,000 20,000
Growing Processing Capacity
2014 2015 2016 2017 2018 2019
-$2.20
-$1.80
-$1.40
-$1.00
-$0.60
-$0.20
Appalachian Basis to NYMEX(2)
TETCO M2
Leidy
TCODom South
YTD % of Production Sold
TCO 76%Dom South 18%
NYMEX 5%
CGTLABasis to NYMEXCurrent 2015-$0.01 -$0.09
ChicagoBasis to NYMEXCurrent 2015+$0.68 -$0.08
Sherwood V
Sherwood IV
Seneca IV
0
400,000
800,000
1,200,000
1,600,000
EQT RRC CNX COG CHK TLM STO SWN WPX RDS APC NFG
Mcf
/d
Firm Sales Firm Transportation
(2)AR
LONG HAUL PIPELINE AND TRANSPORTATION NETWORK
8
Antero has a leading firm transportation capacity position and is well-positioned in the southern portion of the Marcellus and Utica Shale from a gas takeaway perspective
Note: Antero firm transportation and firm sales positions listed by pipeline in colored-coded boxes. 1. Firm transport as of year-end 2014. See Page 25 for timing of firm transportation graph.2. Antero firm transportation as of 2/7/2014; includes 250 MMcf/d of firm sales.
(1)
TCOBasis to NYMEXCurrent 2015+$0.04 -$0.47
Dom SouthBasis to NYMEXCurrent 2015-$0.40 -$1.11
LeidyBasis to NYMEXCurrent 2015-$2.25 -$2.00
CGTLABasis to NYMEXCurrent 2015-$0.01 -$0.09
ChicagoBasis to NYMEXCurrent 2015+$0.68 -$0.08
Appalachian Firm Transportation/Sales Commitment by Operator
Source: Tudor Pickering & Holt research report dated 9/3/2013 and company presentations, press releases.
628 550 633 750 650 288
$4.70 $4.92 $4.73$4.34
$4.65 $4.51
$4.57 $4.20 $4.09 $4.08 $4.12 $4.21
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
0
200
400
600
800
2014 2015 2016 2017 2018 2019
BBtu/d
11%
19%
18%
50%
2%NYMEX
CGTLA
Dom South
TCOChicago
SIGNIFICANT LONG-TERM COMMODITY HEDGE POSITION
9
% HEDGE VOLUMES BY INDEX – 12/31/2013
Average Index Price ($/MMBtu)(1)Hedged Volume NYMEX Strip (2/7/2014) ($/MMBtu)
NATURAL GAS HEDGES – 12/31/2013
1. Reflects weighted average index price per annum based on volumes hedged and 6:1 gas to oil ratio. Antero has hedged ~3,000 Bbl/d for 2014, WTI hedges comprise ~1% of overall hedge book.
~$940 million mark-to-market unrealized gain as of January 31, 2014. 1.3 Tcfe hedged from January 1, 2014 through year-end 2019.
ASSET OVERVIEW
10
WORLD-CLASS POSITION IN THE CORE OF THE MARCELLUS AND UTICA LIQUIDS-RICH FAIRWAYS
Source: Company presentations and press releases.
Utica Shale Core Area
Marcellus Shale
Southwestern & Northeastern
Core Areas
Upper Devonian Shale Resource
Overlies Marcellus Acreage
11
ANTERO LIQUIDS-RICH UTICA SHALE
106,000 Net Acres17 Horizontals Completed5 Rigs Currently Running
ANTERO MARCELLUS SHALE SW PA
25,000 Net Acres2 Horizontals Completed
Strong Results
ANTERO MARCELLUS SHALE NW WV
323,000 Net Acres(Primarily Liquids-Rich Fairway)
221 Horizontals Completed15 Rigs Currently Running
Utica ShaleLiquids-Rich
Fairway
Utica Shale Dry Gas
Resource Underlies Marcellus Acreage
Marcellus Shale Liquids-Rich
Fairway
WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECTAntero Has Delineated And De-Risked Its Large Scale Acreage Position
100% operated 348,000 net acres in
Southwestern Core– 51% HBP with additional
21% not expiring for 5+ years 223 horizontal wells completed
and online– Laterals average 7,000’– 100% drilling success rate
Net production of 522 MMcfe/d in 3Q 2013, including 6,100 Bbl/d of liquids
3,068 future drilling locations in the Marcellus (71% are processable)
Operating 15 drilling rigs including 4 shallow rigs
25.0 Tcfe of net 3P (17% liquids), includes 7.2 Tcfe of proved reserves (ethane rejection)
12
Highly-Rich Gas99,000 Net Acres
834 Gross Locations
Rich Gas86,000 Net Acres
707 Gross Locations
Dry Gas104,000 Net Acres
890 Gross Locations
Highly-Rich/Condensate59,000 Net Acres
637 Gross Locations
MOORE UNIT30-Day Rate
1H: 9.9 MMcfe/d 2H: 10.0 MMcfe/d
(17% liquids)
MHR WEESE UNIT30-Day Rate
4-well average9.3 MMcfe/d (31% liquids)
CHK HADLEY UNIT24-Hour IP
9.1 MMcfe/d(32% liquids)
EQT PENN 15 UNIT30-Day Rate
5-well average9.3 MMcfe/d (29% liquids)
CONSTABLE UNIT30-Day Rate
1H: 15.2 MMcfe/d (30% liquids)
142 Horizontals Completed30-Day Rate
10.3 Bcf average EUR8.1 MMcf/d
6,915’ average lateral length
PRUNTY UNIT30-Day Rate
1H: 11.0 MMcfe/d(29% liquids)
HINTERER UNIT30-Day Rate
1H: 12.9 MMcfe/d (20% liquids)
RUTH UNIT30-Day Rate
1H: 19.3 MMcfe/d (14% liquids)
SherwoodProcessing
Plant
EQT30-Day Rate
12 Recent Wells9.2 MMcfe/d (20% Liquids)
Source: Company presentations and press releases. Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned. Note: Rates assume ethane rejection.
BLANCHE UNIT30-Day Rate
2H: 10.0 MMcfe/d(29% liquids)
DOTSON UNIT30-Day Rate
1H: 12.4 MMcfe/d2H: 11.8 MMcfe/d
(27% liquids)
MARCELLUS – SIMPLE STRUCTURE
13
Several regional anticlines in core area− Predictable “layer cake” geology− No faults at Marcellus level
• Over 1.5 million feet (295 miles) drilled horizontally without crossing a fault
− 3-D seismic not required to guide horizontal wells
Regional East-West seismic line shows gentle structure at Marcellus level
Allegheny Front and complex structure located many miles east of core area
Favorable geology allows for longer laterals
Average Marcellus Lateral Lengths
7,300
4,800 4,500 4,100
0
2,000
4,000
6,000
8,000
Antero EQT RRC COG
Feet
Source: Company presentations.
Wolf SummitArches ForkBig Moses
MarcellusOnondaga
BensonRhinestreet
Profile along regional seismic line (time)W E
Regional Seismic Line
No Data
Tully
100’ Contours Top Marcellus
0.01.02.03.04.05.06.07.08.09.010.011.012.013.014.015.0
0.01.02.03.04.05.06.07.08.09.0
10.011.012.013.014.015.0
0 1 2 3 4 5 6 7 8 9 10
Cum
ulat
ive
Bcf
MM
cf/d
Production Year
Antero Type Curve (7,000' Lateral) Actual Production (Normalized to 7,000' Lateral)Type Curve Cumulative Production (7,000' Lateral) 1.7 Bcf/1,000' SSL Type Curve (7,000' Lateral)SSL Actual Production (Normalized to 7,000' Lateral)
$0.6
$0.8
$1.0
$1.2
$1.4
$1.6
$1.8
2,000 4,000 6,000 8,000 10,000
$MM
/ 1,
000'
Lateral length, ft
0
5
10
15
20
25
30
MM
cfd
1st Production from All Wells 2009 - 2013
Antero has over four years of production history to support its 1.5 Bcf/1,000’ type curve (non-SSL) Antero’s SSL type curve has been increased to 1.73 Bcf/1,000’ with only 12% higher well costs Lack of faulting and contiguous acreage position allows for drilling of long laterals ~ 7,300’− Drives down costs per 1,000’ of lateral resulting in best-in-class development costs
ANTERO’S MARCELLUS SHALE TYPE CURVE SUPPORT
1. 223 Antero Marcellus wells normalized to time zero, production for each well normalized to 7,000’ lateral length.2. 32 Antero Marcellus SSL wells normalized to time zero, production for each well normalized to 7,000’ lateral length.
Marcellus Type Curve Support(1)
14
24-Hour Peak Rate
30-Day Avg. Rate
90-Day Avg. Rate
180-Day Avg. Rate
One-Year Avg. Rate
Two-Year Avg. Rate
Three-YearAvg. Rate
Wellhead (MMcf/d) 14.1 8.1 6.3 5.3 4.2 3.1 2.2# of wells 223 217 221 179 127 63 25
EURs Increase With Lateral Length Well Cost / 1,000’ Decreases with Lateral Length Wellhead 24-hour Peak Rates (IPs) - 223 Wells
Average IP – 14.1 MMcf/d
(2)
0
4
8
12
16
20
2,000 4,000 6,000 8,000 10,000
EUR
, BC
F
Lateral Length, ft
MARCELLUS SINGLE WELL ECONOMICS – ASSUMES ETHANE REJECTION
15
DRY GAS LOCATIONS RICH GAS LOCATIONS
HIGHLY RICH GAS
LOCATIONS
Assumptions 12/31/2013 Strip Pricing & SEC Reserves
NYMEX($/MMBtu)
WTI($/Bbl)
C3+ NGL(2)
($/Bbl)
2014 $4.24 $95 $54
2015 $4.16 $88 $50
2016 $4.09 $83 $50
2017 $4.09 $80 $50
2018+ $4.14 $79 $50
Marcellus SSL Well Economics and Total Locations(1)
ClassificationHighly-Rich/Condensate
Highly-Rich Gas Rich Gas Dry Gas
BTU Range 1275-1350 1200-1275 1100-1200 <1100Modeled BTU 1313 1250 1150 1050EUR (Bcfe): 16.5 14.9 13.3 12.1EUR (MMBoe): 2.8 2.5 2.2 2.0% Liquids: 34% 24% 12% 0%Lateral Length (ft): 7,000 7,000 7,000 7,000Stage Length (ft): 225 225 225 225Well Cost ($MM): $9.5 $9.5 $9.5 $9.5Bcf/1,000’: 1.7 1.7 1.7 1.7Bcfe/1,000’: 2.4 2.1 1.9 1.7
Pre-Tax NPV10 ($MM): $20.5 $13.7 $6.6 $3.7Pre-Tax ROR: 117% 65% 32% 21%Net F&D ($/Mcfe): $0.68 $0.75 $0.84 $0.92Payout (Years): 0.9 1.3 2.4 3.6
Gross 3P Locations: 637 834 707 8901. Well economics are based on 12/31/2013 proved SSL reserves (P90) and strip pricing. Includes gathering, compression and processing fees. A portion of the locations do not include SSL
completions.2. Pricing for a 1225 BTU y-grade rejection barrel.
637 834707
890
117%
65%
32% 21% 0
200
400
600
800
1,000
0%
50%
100%
150%
Highly-Rich Gas/Condensate
Highly-Rich Gas Rich Gas Dry Gas
Tota
l 3P
Loca
tions
RO
R Locations ROR
1,000
10,000
0 30 60 90 120 150 180
Gas
Pro
duct
ion
(Mcf
e/d)
Days From Peak GasAntero Type Curve SSL Average Wellhead SSL Average Processed
Enhancing Recoveries Shorter stage length (SSL) summary:
– 32 SSL wells completed– 22 SSL wells have at least 30 days
of production history– 150’ to 225’ (SSL) vs. 350’ stages
previously 31% higher 30-day wellhead rate for
first 22 SSL wells vs. the Antero type curve – 27% higher 120-day rate vs. the
Antero type curve– Other Marcellus operators have
indicated 20% to 30% improvement in IPs and EURs
The 30-day processed rate for Antero’s first 22 SSL wells has averaged 42% higher than the Antero type curve
Estimated 12% increase in well costs for SSL completions as compared to non-SSL
16
SHORTER STAGE LENGTHS (“SSL”)– ENHANCING MARCELLUS RECOVERIES
1.5 Bcf/1,000’ Type Curve
Normalized production increase for 22 SSL wells vs. 1.5 Bcf/1,000' Type Curve
SSL vs Non-SSL Wellhead Average Rate Comparison
30-day Rate
60-day Rate
90-day Rate
120-day Rate
SSL Well Count 22 19 19 10SSL Avg Wellhead Rate – MMcf/d(1) 10.0 8.6 8.1 7.9Wellhead Type Curve – MMcf/d(2) 7.6 7.1 6.6 6.2SSL % Rate Improvement 31% 21% 24% 27%
SSL Avg Processed Rate – MMcfe/d(1) 11.5 9.9 9.3 9.1Processed Type Curve – MMcfe/d(3) 8.1 7.5 7.0 6.6SSL % Rate Improvement 42% 32% 34% 38%(1) Wellhead condensate production is converted on a 6:1 basis(2) 1.5 Bcf/1,000’ Type Curve.(3) 1.5 Bcf/1,000’ Type Curve processed assuming 1225 BTU.
Source: Company presentations and press releases. Note: Antero acreage position reflects townships in which greater than 3,000 net acres are owned. Note: Third party peak rates assume ethane recovery; Antero 24-hour peak rates assume ethane recovery; Antero 30-day rates assume 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.
100% operated
106,000 net acres in the core rich gas / condensate window– 20% HBP with additional 79% not expiring
for 5+ years– 75% of acreage has rich gas processing
potential
17 Antero-operated horizontal wells completed with 16 currently online − 100% drilling success rate
Net production of 44 MMcfe/d in 3Q 2013 including 1,800 Bbl/d of liquids− First production in early August 2013 had
access to Cadiz pipeline and processing− Seneca I processing plant came online in
November 2013 and Seneca II came online in January 2014
− First 120 MMcf/d compressor station went into service in late January with an additional 120 MMcf/d compression station expected by late 1Q 2014
759 future drilling locations– Approximately 15% of EUR is liquids
assuming ethane rejection
Operating 5 rigs including 1 shallow rig
5.8 Tcfe of net 3P (15% liquids), includes 362 Bcfe of proved reserves (ethane rejection)
EXCITING CORE UTICA SHALE POSITION DELIVERS CONDENSATE AND NGLS
17
Utica Shale Industry Activity(1)
SenecaProcessing
Plant
CadizProcessing
Plant
CHESAPEAKE24-Hour IPBuell #8H
9.5 MMcf/d + 1,425 Bbl/d liquids
GULFPORT24-Hour IP
Boy Scout 1-33H, Ryser 1-25H, Groh 1-12H
Average 5.3 MMcf/d + 675 Bbl/d NGL + 1,411 Bbl/d Oil
REXX24-Hour IP
Guernsey 1H, 2H,Noble 1H
Average 7.9 MMcf/d + 1,192 Bbl/d NGL
+ 502 Bbl/d Oil
MILEY UNIT30-Day Rate
2 wells average3.0 MMcf/d + 187 Bbl/d NGL
+ 559 Bbl/d Oil
NORMAN UNIT 1H30-Day Rate 13.6 MMcf/d
+ 461 Bbl/d NGL + 2 Bbl/d Oil
YONTZ UNIT 1H30-Day Rate 14.6 MMcf/d
+ 392 Bbl/d NGL + 1 Bbl/d Oil
RUBEL UNIT30-Day Rate
3 wells average13.5 MMcf/d + 583 Bbl/d NGL
+ 45 Bbl/d Oil
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 AreaWAYNE UNIT
30-Day Rate3 wells average
5.4 MMcf/d + 335 Bbl/d NGL + 548 Bbl/d Oil
DOLLISON UNIT 1H 24-Hour IP
10.2 MMcf/d + 1,488 Bbl/d NGL + 1,397 Bbl/d Oil
GARY UNIT 1H30-Day Rate23.1 MMcf/d
+ 1,023 Bbl/d NGL + 65 Bbl/d Oil
Highly-Rich/Cond30,000 Net Acres
205 Locations
Highly-Rich Gas25,000 Net Acres
161 Locations
Rich Gas24,000 Net Acres
182 Locations
Dry Gas27,000 Net Acres
211 Locations
MILLIGAN UNIT24-Hour IP
3 wells average11.3 MMcf/d + 1,971 Bbl/d NGL
+ 1,586 Bbl/d Oil
COAL UNIT 1H24-Hour IP
11.8 MMcf/d + 2,063 Bbl/d NGL + 1,850 Bbl/d Oil
0.0
10.0
20.0
30.0
40.0
50.0
60.0
MM
cfe/
d
Source: Antero, press releases and company presentations.Note: Assumes ethane recovery.
ANTERO HAS MOST OF THE TOP UTICA 24-HOUR IPS– STRONG SUPPORT FOR CORE POSITION
Antero has 11 of the top 12 Utica 24-hour peak rates (IPs) announced to date
Represent some of the best 24-hour peak rates of any shale play in North America– 20 to 53 MMcfe/d per well 24-
hour peak rate in the core area
– Excellent reservoir pressure with gradients in the 0.7 psi/ft range
Liquids content ranges from 40%-70% (assumes ethane recovery) in the liquids-rich window
Antero recently announced 30-day rates on some of these wells (see page 27)
18
UTICA 24-HOUR IPsCore
12 to 53MMcfe/d IPs
Tier 16 to 12
MMcfe/d IPs
Antero Utica Wells 3rd Party Core Utica Wells 3rd Party Non-Core Utica Wells
UTICA SINGLE WELL ECONOMICS – ASSUMES ETHANE REJECTION
19
DRY GAS LOCATIONS RICH GAS LOCATIONS
HIGHLY RICH GAS
LOCATIONS
Assumptions 12/31/2013 Strip Pricing & SEC Reserves
Utica Well Economics and Locations(1)
ClassificationHighly-Rich/Condensate
Highly-Rich Gas Rich Gas Dry Gas
BTU Range 1250-1300 1200-1250 1100-1200 <1100Modeled BTU 1275 1225 1175EUR (Bcfe): 11.3 20.5 18.8 16.6EUR (MMBoe): 1.9 3.4 3.1 2.8% Liquids 32% 23% 15% 0%Lateral Length (ft): 7,000 7,000 7,000 7,000Stage Length (ft): 240 240 240 240Well Cost ($MM): $11.0 $11.0 $11.0 $11.0Bcf/1,000’: 1.2 2.4 2.4 2.4Bcfe/1,000’: 1.6 2.9 2.7 2.4
Pre-Tax NPV10 ($MM): $15.7 $26.6 $18.4 $11.7Pre-Tax ROR: 137% 169% 95% 56%Net F&D ($/Mcfe): $1.21 $0.66 $0.72 $0.82Payout (Years): 0.5 0.5 0.8 1.3
Gross 3P Locations(3): 205 161 182 2111. Well economics are based on 12/31/2013 proved (P90) reserves and strip pricing. Includes gathering, compression and processing fees.2. Pricing for a 1225 BTU y-grade rejection barrel.3. Gross 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content.
NYMEX($/MMBtu)
WTI($/Bbl)
C3+ NGL(2)
($/Bbl)
2014 $4.24 $95 $54
2015 $4.16 $88 $50
2016 $4.09 $83 $49
2017 $4.09 $80 $49
2018+ $4.14 $79 $49
205161
182211
137%169%
95%
56%
0
50
100
150
200
250
0%
50%
100%
150%
200%
Highly-Rich Gas/Condensate
Highly-Rich Gas Rich Gas Dry Gas
Tota
l 3P
Loca
tions
RO
RLocations ROR
LARGE MIDSTREAM FOOTPRINT
20
Ohio River WithdrawalSystem Completed
Antero Midstream estimated cumulative YE 2014 total capital investment in midstream ~ $1,580 million– Includes gathering lines, compressor
stations and water distribution infrastructureProprietary water sourcing and distribution
system − Improves operational efficiency and reduces
water truck traffic− Cost savings of $600,000 -$800,000 per
well− One of the benefits of a consolidated
acreage position
UticaShale
MarcellusShale
Projected Midstream Infrastructure(1)
Marcellus Shale
Utica Shale Total
YE 2014E Cumulative Gathering / Compression Capex ($MM) $835 $295 $1,130Gathering Pipelines (Miles) 192 92 284Compression Capacity (MMcf/d) 410 N/A 410
YE 2014 Cumulative Water System Capex ($MM) $350 $100 $450Water Pipeline (Miles) 122 48 170Water Storage Facilities 31 16 47
YE 2014E Total Midstream ($MM) $1,185 $395 $1,580
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 9/30/2013 and remaining 2013 and 2014 budget.
CAPITALIZATION
1. Initial public offering priced on 10/10/2013; equity valuation based on 262.0 million shares outstanding and a share price of $57.05 as of 2/6/2014. Enterprise value includes net debt. 2. Lender commitments under the facility reduced to $1.5 billion from $1.75 billion on 10/21/2013; commitments can be expanded to the full $2.0 billion borrowing base upon bank approval.3. $1,000 million 5.375% Senior Notes priced on 10/24/2013, $525 million 9.375% Senior Notes called, $25 million 9.00% Senior Note redeemed, 35% of $400 million 7.25% Senior Notes redeemed and
transaction fees.
PRO FORMA CAPITALIZATION
($ in millions) 9/30/2013(PF IPO)
9/30/2013 (1)(PF Bond Offering)
9/30/2013(3)
Cash $12 $77 $339
Senior Secured Revolving Credit Facility 1,513 – –9.375% Senior Notes Due 2017 525 525 –9.00% Senior Note 25 25 –7.25% Senior Notes Due 2019 400 400 2606.00% Senior Notes Due 2020 525 525 5255.375% Senior Notes Due 2021 – – 1,000Net Unamortized Premium 8 8 6Total Debt $2,996 $1,483 $1,791
Net Debt $2,984 $1,406 $1,452
Shareholders' Equity $1,875 $3,453 $3,427Net Book Capitalization $4,859 $4,859 $4,879
Net Market Capitalization(1) N/M $15,735 $16,400
Financial & Operating StatisticsLTM EBITDAX $521 $521 $521
Proved Reserves (Bcfe) (12/31/2013) 7,632 7,632 7,632
Proved Developed Reserves (Bcfe) (12/31/2013) 2,023 2,023 2,023
Credit Statistics
Net Debt / LTM EBITDAX 5.7x 2.7x 2.8xLTM EBITDAX / Interest Expense 4.1x 4.7x 5.1xNet Debt / Net Book Capitalization 61.4% 28.9% 29.8%Net Debt / Net Market Capitalization N/M 8.9% 8.9%Net Debt / Proved Developed Reserves ($/Mcfe) $1.48 $0.71 $0.72Net Debt / Proved Reserves ($/Mcfe) $0.39 $0.19 $0.19
LiquidityCredit Facility Commitments(2) $1,750 $1,500 $1,500Less: Borrowings (1,513) – –Less: Letters of Credit (32) (32) (32)Plus: Cash 12 77 339
Liquidity (Credit Facility + Cash) $217 $1,545 $1,807
21
Keys to Execution
Pad Impact Mitigation Closed loop mud system – no mud pits Protective liners or mats on all well pads in addition to berms
Green Completion Units All Antero well completions use green completion units for completion flowback,
essentially eliminating methane emissions (full compliance with EPA 2015requirements)
Central Fresh Water System & Water Recycling
Numerous sources of water – building central water system to source water forcompletion
Antero recycles over 95% of its flowback water with the remainder injected into disposal wells – no discharge to water treatment plants in West Virginia
Natural Gas Powered Drilling Rigs Eight of Antero’s contracted drilling rigs are currently running on natural gas
Natural Gas Vehicles (NGV)
Antero supported the first natural gas fueling station in West Virginia which recently opened
Antero has a dozen NGV trucks and plans to continue to convert its truck fleet to NGV
Safety & Environmental
Five company safety representatives and 45 safety consultants cover all material field operations 24/7 including drilling, completion, construction and pipelining
23-person company environmental staff plus outside consultants monitor all operations and perform baseline water well testing
Local Presence Land office in Ellenboro, WV Recently moved into new 50,000 square foot district office in Bridgeport, WV 101 of Antero’s 251 employees are located in West Virginia and Ohio
LEED Gold Headquarters Building
Antero’s new corporate headquarters in Denver has been LEED Gold Certified Completion expected by spring of 2014
HEALTH, SAFETY, ENVIRONMENT & COMMUNITYProtection Of Our People And The Environment Is An Antero Core Value
Strong West Virginia Presence Over 75% of 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
22
ANTERO KEY ATTRIBUTES
23
454,000 Net Acres in the Core Marcellus and Utica Shales
“Triple Digit” Historical Production and Reserve Growth
Low Cost Leader / High Return Projects
Significant Takeaway and Processing Capacity Already in Place
Clean Balance Sheet Supports High Growth Story
“Forward Thinking” Management Team with a History of Success
24
APPENDIX
24
ANTERO FIRM TRANSPORTATION AND FIRM SALES
25
MMBtu/d
Columbia7/26/2009 – 9/30/2025
Firm Sales #110/1/2011– 10/31/2019
Firm Sales #2
10/1/2011 – 5/31/2017
Firm Sales #3
1/1/2013 – 5/31/2022
Momentum III9/1/2012 – 12/31/2021
EQT8/1/2012 – 8/31/2021
Chicago Direct4/1/2013 – 9/30/2021
-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
1. 24-hour peak rates assume full ethane recovery (assuming typical ethane plant product recoveries of 85% to 90%) however Antero is currently rejecting ethane due to current market prices. 2. Average of Antero’s first 16 core area wells, assuming ethane rejection.
ANTERO UTICA SHALE WELLS – 24 HOUR IPS
26
LateralWell Gas Equivalent Rate Wellhead Gas Shrunk Gas NGL Condensate % Total LengthName County (MMcfe/d) (MMcf/d) (MMcf/d) (Bbl/d) (Bbl/d) Liquids BTU (Feet)
Yontz 1H Monroe 53.3 38.9 33.9 3,177 52 36% 1161 5,115Rubel 1H Monroe 47.5 31.1 25.9 3,391 214 46% 1231 6,554Gary 2H Monroe 43.5 28.9 24.2 3,053 162 44% 1224 8,882Rubel 3H Monroe 42.6 28.4 23.7 3,003 142 44% 1220 6,424Milligan 2H Noble 40.2 17.2 13.5 2,361 2,087 68% 1276 5,989Rubel 2H Monroe 37.4 24.8 20.7 2,635 156 45% 1217 6,571Norman 1H Monroe 37.1 26.1 22.3 2,419 45 40% 1186 5,498Coal 3H Noble 35.3 15.1 11.8 2,063 1,850 67% 1278 7,768Wayne 3HA Noble 35.1 14.7 11.6 2,018 1,905 67% 1272 6,712Wayne 4H Noble 34.2 14.2 11.2 1,907 1,922 67% 1265 6,493Milligan 3H Noble 32.1 15.4 12.1 2,111 1,228 62% 1276 5,267Dollison 1H Noble 27.5 12.5 10.2 1,488 1,397 63% 1238 6,253Milligan 1H Noble 25.8 10.6 8.3 1,461 1,442 68% 1276 6,436Wayne 2H Noble 25.5 10.9 8.5 1,503 1,331 67% 1281 6,094Miley 2H Noble 22.4 8.6 6.7 1,172 1,450 70% 1278 6,153Miley 5HA Noble 20.2 7.7 6.0 1,090 1,285 70% 1291 6,296
35.0 19.1 15.7 2,178 1,042 58% 1248 6,40728.1 19.1 18.5 819 776 40% 1248 6,407
Average ‐ Ethane Recovery(1)
Average ‐ Ethane Rejection(2)
24‐hr Peak Rate
1. Average of Antero’s first 11 core area wells, assuming ethane recovery.
ANTERO UTICA SHALE WELLS – 30-DAY RATES
27
Antero’s wells have been producing against 1,100 psi line pressure due to lack of compression facilities− First 120 MMcf/d compressor station started up in late January 2014
LateralWell Gas Eq. Rate Wellhead Gas Shrunk Gas NGL Condensate % Total Estimated LengthName County (MMcfe/d) (MMcf/d) (MMcf/d) (Bbl/d) (Bbl/d) Liquids BTU (Feet)
Gary 2H Monroe 29.7 24.6 23.1 1,023 65 22% 1224 8,882Rubel 2H Monroe 19.2 15.9 15.0 625 64 22% 1217 6,571Rubel 3H Monroe 18.7 15.6 14.7 623 43 21% 1220 6,424Yontz 1H Monroe 17.0 15.2 14.6 392 1 14% 1161 5,115Norman 1H Monroe 16.4 14.3 13.6 461 2 17% 1186 5,498Rubel 1H Monroe 14.0 11.5 10.8 501 28 23% 1231 6,554Wayne 2H Noble 12.1 6.5 6.0 367 653 51% 1281 6,094Wayne 3HA Noble 11.0 6.1 5.6 354 540 49% 1272 6,712Wayne 4H Noble 9.2 5.2 4.7 284 452 48% 1265 6,493Miley 2H Noble 9.0 3.8 3.5 213 700 61% 1278 6,153Miley 5HA Noble 5.9 2.7 2.5 161 418 59% 1291 6,296
14.7 11.0 10.4 455 270 35% 1239 6,43617.9 11.0 9.2 1,189 270 53% 1239 6,436
30‐Day Rates ‐ Antero Core Area
Average ‐ Ethane RejectionAverage ‐ Ethane Recovery(1)
CONSIDERABLE RESERVE BASE WITH ETHANE OPTIONALITY 40 year proved reserve life based on 2013E production Reserve base provides significant exposure to liquids-rich projects
– 3P reserves of over 2.2 BBbl of NGLs and condensate in ethane recovery mode; 33% 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)
28
Marcellus – 25.0 Tcfe
Utica – 5.8 Tcfe
Upper Devonian – 4.2 Tcfe
35.0Tcfe
Gas – 29.6 Tcf
Oil – 91 MMBbls
NGLs – 811 MMBbls
Marcellus – 29.5 Tcfe
Utica – 6.7 Tcfe
Upper Devonian – 4.7 Tcfe
40.8Tcfe
Gas – 27.4 Tcf
Oil – 91 MMBbls
NGLs – 2,151 MMBbls
15%Liquids
33%Liquids
Gas $4.15
Gas$3.90
Gas$3.86
Gas$3.80
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
$9.00
1050 BTU
$5.19
$6.95
$8.28
$4.15
1150 BTU 1250 BTU 1300 BTU
MARCELLUS SHALE RICH GAS –LIQUIDS AND PROCESSING UPGRADE
1. Assumes $4.25/MMBtu NYMEX, $90.00/Bbl WTI and current NGL spot prices. 1.054 and 2.070 (ethane rejection) and 3.332 and 5.145 (ethane recovery) GPM s used, all processing costs, shrink and fuel included. No ethane takeaway available until Enterprise ethane pipeline is online (expected 1Q 2014). Ethane recovery well economics include fixed fee cost tariff on ATEX ethane pipeline.
2. NGL prices as of 2/3/2014 from IntercontinentalExchange.
Current – Ethane Rejection
(1076 BTU)8% shrink
(1109 BTU)12% shrink
(1119 BTU)14% shrink
$/Wellhead Mcf(1)(2)
($/Mcf)
Marcellus Shale rich gas and highly-rich gas acreage provides a significant advantage in well economics – assuming $4.25/MMBtu NYMEX, $90.00/Bbl WTI and current spot NGL pricing
29
+$1.04Upgrade
+$2.79Upgrade
+$4.13Upgrade
Highly Rich GasDry Gas
NGLs (C3+)$1.30
NGLs (C3+)$2.93
NGLs (C3+)$3.92
Condensate$0.16
Condensate$0.56
Highly Rich/ CondensateDry Gas
2013 YEAR-TO-DATE REALIZATIONS
Ethane (C2)
Propane (C3)
Iso Butane (C4)
Normal Butane
Natural Gasoline
Total $50.73 per Bbl48% of WTI(3)
9/30/2013 YTD NGL Y-GRADE (C3+) REALIZATIONS
9/30/2013 YTD NATURAL GAS REALIZATIONS
55%
1%
11%
16%
17%
$27.69
$5.72
$8.04
$8.69
$0.59
301. NYMEX differential represents contractual deduct to NYMEX-based sales.2. Includes firm sales.3. Based on monthly prices through 9/30/2013 WTI.
Antero Barrel
YTD % Sales
Average NYMEX Price
AverageDifferential(2)
AverageBTU Upgrade
Average YTD Realized Price
TCO 76% $3.68 $(0.07) $0.44 $4.05Dominion South 18% $3.68 $(0.39) $0.42 $3.71NYMEX(1) 5% $3.68 $(0.40) $0.41 $3.69TETCO 1% $3.68 $(0.34) $0.47 $3.80
Total 100% $3.68 $(0.15) $0.44 $3.97
Needed to make up for base declines in conventional and GOM production
? ?
?Downside risks to breakeven costs for older shale plays once exploration resumes with higher natural gas prices?
?
Almost 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)
31
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 $90.00/Bbl WTI
NE (Dry) Marcellus
ShaleEagle Ford
Shale
MARCELLUS/UTICA – ADVANTAGED ECONOMICS
ANTERO EBITDAX RECONCILIATION
32
EBITDAX Reconciliation($ in millions) (9 Months Ended)Antero Resources LLC 9/30/12 9/30/2013
EBITDAX:Net income (loss) from continuing operations $140.4 $201.0Commodity derivative fair value (gains) losses (52.2) (285.5)Net cash receipts on settled commodity derivatives instruments 141.5 109.3(Gain) loss on sale of assets (291.2) -Interest expense and other 71.0 100.8Provision (benefit) for income taxes 108.5 120.7Depreciation, depletion, amortization and accretion 65.4 159.4Impairment of unproved properties 4.0 9.6Exploration expense 7.9 17.0Other 3.0 2.0EBITDAX from continuing operations $198.4 $434.2
EBITDAX:Net income (loss) from discontinued operations ($418.5)Commodity derivative fair value (gains) losses (46.4)Net cash receipts on settled commodity derivatives instruments 79.7(Gain) loss on sale of assets 427.2Provision (benefit) for income taxes 4.1Depreciation, depletion, amortization and accretion 77.7Impairment of unproved properties 1.0Exploration expense 1.0EBITDAX from discontinued operations $125.4
EBITDAX $323.7 $434.2
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 June 30, 2013 included in this presentation have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates are as of June 30, 2013, assuming 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 June 30, 2013. 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.
“Highly-rich/condensate” refers to gas having a heat content between 1275 BTU and 1350 BTU in the Marcellus Shale and 1250 BTU and 1300 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 1250 BTU in the Utica Shale.
“Rich gas” refers to gas having a heat content of between 1100 BTU to 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
33
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