2. FORWARD-LOOKING STATEMENTS
This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities,
events or developments that Antero Resources Corporation and its subsidiaries (collectively, the “Company” or “Antero”) expects, believes or
anticipates will or may occur in the future are forward-looking statements. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “estimate,”
“project,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements. However, the
absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-
looking statements contained in this presentation specifically include estimates of the Company’s reserves, expectations of plans, strategies,
objectives and anticipated financial and operating results of the Company, including as to the Company’s drilling program, production, hedging
activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made
by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and
other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are
beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking
statements. These include the factors discussed or referenced under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for
the year ended December 31, 2013 and in the Company’s subsequent filings with the SEC.
The Company cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to
predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas
and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and
services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil
reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks
described under the heading “Risk Factors” in 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
3. 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 fully engineered and audited 3P reserves in
Marcellus and Utica Shales
● 678 MMcfe/d of average net production in 4Q 2013 including approximately
11,100 Bbl/d of liquids
Critical Mass In Two
World Class Shale Plays
● 159% Appalachian production CAGR for 2010 to 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: 5.4x(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 2.1 Bcf/d of gas takeaway
● Liquids expected to grow from 10% of fourth quarter 2013 production to
~ 16% in 2014 due to focus on liquids-rich development
Significant Emphasis on
Takeaway and
Liquids Processing
● ~$1.2 billion pro forma available liquidity with current $1.5 billion bank
commitment(2)
● 1.5 Tcfe hedged through 2019 at an average index price of $4.58/MMBtu
and $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 2013; pro forma for Arkoma and Piceance divestitures.
2. See page 23 for the derivation of 12/31/2013 liquidity.
4. UPPER DEVONIAN SHALE
Net Proved Reserves(1) 44 Bcfe
Net 3P Reserves (1) 4.2 Tcfe
Pre-Tax 3P PV-10(1) NM
% Liquids – Net 3P 7%
4Q 2013 Net Production 3 MMcfe/d
Undrilled 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. 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 Rejection
Net Proved Reserves(1) 7.6 Tcfe
Net 3P Reserves(1) 35.0 Tcfe
Pre-Tax 3P PV-10(1) $20,362 MM
Net 3P Liquids 902 MMBbls
% Liquids – Net 3P 15%
4Q 2013 Net Production 678 MMcfe/d
- 4Q 2013 Net Liquids 11,190 Bbl/d
Net Acres(2) 459,000
Undrilled 3P Locations 4,778
MARCELLUS SHALE
Net Proved Reserves(1) 7.2 Tcfe
Net 3P Reserves (1) 25.0 Tcfe
Pre-Tax 3P PV-10(1) $15,729 MM
% Liquids – Net 3P 17%
4Q 2013 Net Production 621 MMcfe/d
Undrilled 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 Bcfe
Net 3P Reserves (1) 5.8 Tcfe
Pre-Tax 3P PV-10(1) $4,666 MM
% Liquids – Net 3P 15%
4Q 2013 Net Production 54 MMcfe/d
Undrilled 3P Locations 759
B
3
A
C
B
“Pure-Play” Appalachian-Focused Shale Company
UTICA SHALE – DRY GAS
Net Acres(2) 128,000
Net Resource 7-11 Tcf
Undrilled Locations 1,080
D
D
Additional Hedge Value
• 1.5 Tcfe hedged from 1/1/2014 through 12/31/2019 at an
average index price of $4.58/MMBtu and $96.54/Bbl
• ~ $750 million mark-to-market hedge value as of 3/18/2014
• ~ 55% hedged through NYMEX; 45% hedged through
regional hubs
5. 0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
2006 2007 2008 2009 2010 2011 2012 2013
Woodford Piceance Marcellus Utica(3)
87 235
680 1,141
3,231
5,017
4,283
7,632
(5) (5)
Sold Woodford
and Piceance
4
0
200
400
600
800
1,000
2006 2007 2008 2009 2010 2011 2012 2013 2014E
Woodford Piceance Marcellus Utica
6
31 87 105 133
244
334
522
(4)
950
AVERAGE NET DAILY PRODUCTION (MMcfe/d) NET PROVED SEC RESERVES (Bcfe)(2)
193
0
25
50
75
100
125
150
175
200
2006 2007 2008 2009 2010 2011 2012 2013 2014E
Woodford Piceance Marcellus Utica
85
96
126
18
66
91
119
162
(4)
1. CAGR = Compound Annual Growth Rate.
2. Proved reserves for 2006, 2007, and 2008 represent previously effective SEC methodology. 2009, 2010, 2011, 2012 and 2013 proved reserves based on current SEC reserve methodology and SEC pricing and
are audited by independent third-party engineers.
3. Includes Upper Devonian Shale proved reserves (10 Bcfe in 2012 and 44 Bcfe in 2013).
4. Per Company press release dated January 29, 2014; production mid-point of 925-975 MMcfe/d guidance.
5. 2012 and 2013 proved reserves are both in ethane rejection mode.
6. Per First Call estimate as at 3/20/2014.
Financial
Crisis
STRONG TRACK RECORD OF GROWTH
OPERATED GROSS WELLS SPUD
Sold Woodford
and Piceance
EBITDAX ($MM)
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
2006 2007 2008 2009 2010 2011 2012 2013 2014E
Discontinued Operations Continuing Operations
$0
$60
$209 $201 $198
$341
$434
$649
$1,272
(6)
6. OUTSTANDING RESERVE GROWTH
1. 2012 and 2013 reserves assume ethane rejection.
5
PROVED RESERVE GROWTH(1)
3P RESERVE GROWTH(1)
• Proved PV-10 increased 133% to $7.0 billion (including
hedges)
• 3P PV-10 increased 82% to $21.4 billion (including hedges)
• Replaced 1,857% of 2013 production
• All-in finding cost of $0.58/Mcfe
• 2013 “top-down” development cost of $1.25/Mcfe
• 2013 “bottoms-up” development cost of $1.10/Mcfe
• Only 14% of 1P and 58% of 3P locations booked as SSL
(1.73 Bcf/1,000’ type curve)
• No Utica Shale WV/PA dry gas reserves booked
4.2
7.2
0.1
0.4
0
2
4
6
8
10
2012 2013
(Tcfe)
Marcellus Utica
7.6
17.6
25.0
4.0
5.8
4.2
0
10
20
30
40
50
2012 2013
(Tcfe)
Marcellus Utica Upper Devonian
Drivers
POTENTIAL RESERVE GROWTH DRIVERS
2013 RESERVE UPDATE
• Marcellus SSL completions
• Full scale Utica program
• Utica increased density drilling
• Utica dry gas drilling
• Core acreage acquisitions
Driver 2014 Action
Complete transition to SSL type
curve
4.3
21.6
35.0
• Successful
drilling
• Expanded
proved
footprint
• 79,000 net
acres added
in 2013
• SSL results
• Utica results
41 wells to be completed; only
21 PUD locations booked as
proved at YE 2013
$200 million leasehold budget
Drilling 2 increased density
pilots in Utica
Drilling first Utica dry gas well in
WV (128,000 net acres WV/PA)
Drivers
7. $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
637 834
707
890
117%
65%
32% 21% 0
200
400
600
800
1000
0%
50%
100%
150%
Highly-Rich
Gas/
Condensate
Highly-Rich
Gas
Rich Gas Dry Gas
Total3PLocations
ROR
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 3/18/2014.
3 Yr Strip - $4.29/MMBtu(4)
637
Locations
1,541
Locations
366
Locations
890
Locations
$/MMBtuNYMEX(Gas)
182
Locations
6
MARCELLUS SSL WELL ECONOMICS(1)(2) UTICA WELL ECONOMICS(1)
205 161
182
211
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
Total3PLocations
ROR
Locations ROR
1,000
71% of Marcellus locations are processable (1100-plus Btu) 72% of Utica locations are processable (1100-plus Btu)
`
>2,700 Antero Liquids-Rich Locations
8. 0.0x
2.0x
4.0x
6.0x
8.0x
5.4x
2.7x2.9x
2.3x
$0.00
$1.00
$2.00
$3.00
$4.00
$1.03 $1.14
$1.41 $1.57
$1.71
Other Peers
LOW DEVELOPMENT COST DRIVES
BEST-IN-CLASS RECYCLE RATIOS
7
Source: Proved developed F&D research prepared by JP Morgan Research report dated 07/22/2013. Defined as total drilling and completion capital expenditures for the period divided by PDP and PDNP volumes added after adding back
production for the period. Includes all drilling and completion costs but excludes land and acquisition costs for all companies.
1. Antero internal estimate using JP Morgan development cost methodology; excludes Arkoma and Piceance operations.
2. Antero estimate based on public information; includes Arkoma and Piceance operations.
3-Year All-in Development Costs ($/Mcfe) through 2012
Antero Appalachia-Focused Peers
Source: Wall Street research. Defined as 2011-2013 average (Cash Operating Netback / PD F&D costs) x (1 + 2013-2015 consensus 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 Appalachia-Focused Peers
3-Year Average Growth – Adjusted Recycle Ratio through 2013
$/Mcfe
Other Peers
9. Needed to make up
for base declines in
conventional and
GOM production
? ??
Over 2,700 Antero
Drilling Locations
Permian
Niobrara
GraniteWash
Barnett
Haynesville
U.S. INCREMENTAL GAS SUPPLY BREAK-EVEN PRICE CURVE(1)
8
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
Shale
Eagle Ford
Shale
MARCELLUS & UTICA – ADVANTAGED ECONOMICS
10. 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
91. Antero firm transportation as of 3/18/2014.
0
200
400
600
800
1,000
1,200
1,400
1,600
(MMcf/d)
Sherwood I Sherwood II Sherwood III Sherwood IV Sherwood V
Seneca I Seneca II Seneca III Seneca IV
Total Capacity
1,550
Marcellus
Utica
Sherwood I
Sherwood II
Sherwood III
Seneca I
Seneca II
Seneca III
Growing Processing Capacity
Sherwood V
Seneca IV
Appalachian Firm Transportation/Sales Commitment by Operator
Sherwood IV
Source: Company presentations, press releases.
0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
RRC EQT COG CNX CHK TLM STO SWN WPX RDS APC NFG
Mcf/d
Firm Sales Firm Transportation
(1)
AR
11. -$2.50
-$2.00
-$1.50
-$1.00
-$0.50
$0.00
$0.50
2014 2015 2016 2017 2018 2019
Appalachian Basis to NYMEX(2)
LONG HAUL PIPELINE AND TRANSPORTATION NETWORK
10
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 color-coded boxes.
1. Firm transport as of year-end 2014. See Page 27 for timing of firm transportation graph.
2. Basis data from Wells Fargo daily indications and various private quotes as of 3/18/2014.
(1)
TCO
Basis to NYMEX
Current 2015
-$0.01 -$0.46
Dom South
Basis to NYMEX
Current 2015
-$0.31 -$0.89
Leidy
Basis to NYMEX
Current 2015
-$1.45 -$2.16
CGTLA
Basis to NYMEX
Current 2015
-$0.03 -$0.08
Chicago
Basis to NYMEX
Current 2015
+$0.22 -$0.04
TCO
Dom South
TETCO M2
Leidy
Chicago
2013 % of
Production Sold
TCO 67%
Dom South 22%
TETCO M2 5%
NYMEX 6%
+
12. 729 650 643 780 710 468
$4.92
$4.80 $4.71
$4.33
$4.60 $4.41
$4.49 $4.23 $4.16 $4.15 $4.29 $4.38
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
0
200
400
600
800
2014 2015 2016 2017 2018 2019
BBtu/d
11%
17%
16%
54%
2%
NYMEX
CGTLA
Dom South
TCO
Chicago
SIGNIFICANT LONG-TERM
COMMODITY HEDGE POSITION
11
% HEDGE VOLUMES BY INDEX – 3/18/2014
Average Index Hedge Price ($/MMBtu)(1)Hedged Volume NYMEX Strip (3/18/2014) ($/MMBtu)
NATURAL GAS HEDGES – 3/18/2014
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.
~$750 million mark-to-market unrealized gain as of March 18, 2014
1.5 Tcfe hedged from January 1, 2014 through year-end 2019
14. 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
13
ANTERO LIQUIDS-RICH UTICA SHALE
107,000 Net Acres
18 Horizontals Completed
5 Rigs Currently Running
ANTERO MARCELLUS SHALE SW PA
25,000 Net Acres
2 Horizontals Completed
Strong Results
ANTERO MARCELLUS SHALE NW WV
327,000 Net Acres
(Primarily Liquids-Rich Fairway)
234 Horizontals Completed
15 Rigs Currently Running
Utica Shale
Liquids-Rich
Fairway
Utica Shale
Dry Gas
Resource
Underlies
Marcellus
Acreage
Marcellus Shale
Liquids-Rich
Fairway
15. WORLD CLASS MARCELLUS SHALE
DEVELOPMENT PROJECT
Antero Has Delineated And De-Risked Its Large Scale Acreage Position
100% operated
352,000 net acres in
Southwestern Core
– 51% HBP with additional
21% not expiring for 5+ years
236 horizontal wells completed
and online
– Laterals average 7,000’
– 100% drilling success rate
Net production of 621 MMcfe/d
in 4Q 2013, including 8,900
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 (assuming
ethane rejection)
14
Highly-Rich Gas
101,000 Net Acres
834 Gross Locations
Rich Gas
86,000 Net Acres
707 Gross Locations
Dry Gas
104,000 Net Acres
890 Gross Locations
Highly-Rich/Condensate
61,000 Net Acres
637 Gross Locations
MOORE UNIT
30-Day Rate
1H: 10.3 MMcfe/d
2H: 10.3 MMcfe/d
(20% liquids)
MHR WEESE UNIT
30-Day Rate
4-well average
9.3 MMcfe/d
(31% liquids)
CHK HADLEY UNIT
24-Hour IP
9.1 MMcfe/d
(32% liquids)
EQT PENN 15 UNIT
30-Day Rate
5-well average
9.3 MMcfe/d
(26% liquids)
CONSTABLE UNIT
30-Day Rate
1H: 15.3 MMcfe/d
(26% liquids)
142 Horizontals Completed
30-Day Rate
10.3 Bcf average EUR
8.1 MMcf/d
6,915’ average lateral length
PRUNTY UNIT
30-Day Rate
1H: 12.2 MMcfe/d
(27% liquids)
HINTERER UNIT
30-Day Rate
1H: 12.9 MMcfe/d
(20% liquids)
RUTH UNIT
30-Day Rate
1H: 19.2 MMcfe/d
(14% liquids)
Sherwood
Processing
Plant
EQT
30-Day Rate
12 Recent Wells
9.2 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 held. Note: Rates assume ethane rejection.
BLANCHE UNIT
30-Day Rate
2H: 10.2 MMcfe/d
(30% liquids)
DOTSON UNIT
30-Day Rate
1H: 12.4 MMcfe/d
2H: 11.8 MMcfe/d
(26% liquids)
16. MARCELLUS – SIMPLE STRUCTURE
15
Several regional anticlines in core area
− Predictable “layer cake” geology
− No faults at Marcellus level
• Over 1.7 million feet (315 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
Marcellus
Onondaga
Benson
Rhinestreet
Profile along regional seismic line (time)W E
Regional Seismic Line
No Data
Tully
100’ Contours Top Marcellus
17. 0
4
8
12
16
20
MMcf/d 30-Day Average Production Rates
0.0
3.0
6.0
9.0
12.0
15.0
0.0
3.0
6.0
9.0
12.0
15.0
0 1 2 3 4 5 6 7 8 9 10
CumulativeBcf
MMcf/d
Production Year
Antero Non-SSL Type Curve Actual Non-SSL Production
Non-SSL Type Curve Cumulative Production 1.7 Bcf/1,000' SSL Type Curve
SSL Actual Production
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% to 15% 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. 236 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 – Normalized to 7,000’ Lateral
(1)
16
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
Wellhead (MMcf/d) 14.3 8.1 6.3 5.3 4.2 3.1 2.3
# of wells 236 224 221 193 131 65 26
EURs Increase With Lateral Length Well Cost / 1,000’ Decreases with Lateral Length Wellhead 30-day Rates - 224 Wells
Average 30-Day Rate – 8.1 MMcf/d
(2)
0
4
8
12
16
20
2,000 4,000 6,000 8,000 10,000
EUR,BCF
Lateral Length, ft
$0.6
$0.8
$1.0
$1.2
$1.4
$1.6
$1.8
2,000 4,000 6,000 8,000 10,000
$MM/1,000'
Lateral length, ft
18. MARCELLUS SINGLE WELL ECONOMICS
– ASSUMES ETHANE REJECTION
17
DRY GAS LOCATIONS RICH GAS LOCATIONS
HIGHLY
RICH GAS
LOCATIONS
Assumptions
12/31/2013 Strip Pricing & SEC Reserves
NYMEX
($/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 $50
Marcellus SSL Well Economics and Total Locations(1)
Classification
Highly-Rich/
Condensate
Highly-Rich
Gas Rich Gas Dry Gas
BTU Range 1275-1350 1200-1275 1100-1200 <1100
Modeled BTU 1313 1250 1150 1050
EUR (Bcfe): 16.5 14.9 13.3 12.1
EUR (MMBoe): 2.8 2.5 2.2 2.0
% Liquids: 34% 24% 12% 0%
Lateral Length (ft): 7,000 7,000 7,000 7,000
Stage Length (ft): 225 225 225 225
Well Cost ($MM): $9.5 $9.5 $9.5 $9.5
Bcf/1,000’: 1.7 1.7 1.7 1.7
Bcfe/1,000’: 2.4 2.1 1.9 1.7
Pre-Tax NPV10 ($MM): $20.5 $13.7 $6.6 $3.7
Pre-Tax ROR: 117% 65% 32% 21%
Net F&D ($/Mcfe): $0.68 $0.75 $0.84 $0.92
Payout (Years): 0.9 1.3 2.4 3.6
Gross 3P Locations: 637 834 707 890
1. Well economics are based on 12/31/2013 proved SSL reserves (P90) and strip pricing. Includes gathering, compression and processing fees.
2. Pricing for a 1225 BTU y-grade rejection barrel.
637 834
707
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
Total3PLocations
ROR
Locations ROR
19. 1,000
10,000
0 30 60 90 120 150 180 210 240
GasProduction(Mcfe/d)
Days From Peak Gas
Antero Type Curve SSL Average Wellhead SSL Average Processed
Enhancing Recoveries
Shorter stage length (SSL) summary:
– 36 SSL wells completed
– 32 SSL wells have at least 30 days
of production history
– 150’ to 225’ (SSL) vs. 350’ stages
previously
28% higher 30-day wellhead rate for
first 32 SSL wells vs. the Antero type
curve
– 29% higher 180-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 32 SSL wells has
averaged 38% higher than the Antero
type curve
Estimated 12% to 15% increase in
well costs for SSL completions as
compared to non-SSL
18
SHORTER STAGE LENGTHS (“SSL”)
– ENHANCING MARCELLUS RECOVERIES
1.5 Bcf/1,000’ Type Curve
Normalized production increase for 36 SSL wells vs. 1.5 Bcf/1,000' Type Curve
SSL vs Non-SSL Wellhead
Average Rate Comparison
30-day
Rate
90-day
Rate
120-day
Rate
180-day
Rate
SSL Well Count 32 19 18 10
SSL Avg. Wellhead Rate – MMcf/d(1) 9.8 8.0 7.7 7.3
Wellhead Type Curve – MMcf/d(2) 7.6 6.6 6.2 5.7
SSL % Rate Improvement 28% 22% 24% 29%
SSL Avg. Processed Rate – MMcfe/d(1) 11.2 9.2 8.7 8.3
Processed Type Curve – MMcfe/d(3) 8.1 7.0 6.6 6.0
SSL % Rate Improvement 38% 31% 33% 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
20. 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 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
107,000 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
18 Antero-operated horizontal wells completed
and online
− 100% drilling success rate
Net production of 54 MMcfe/d in 4Q 2013
including 2,200 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 compressor 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 (assuming ethane
rejection)
EXCITING CORE UTICA SHALE POSITION DELIVERS
CONDENSATE AND NGLS
19
Utica Shale Industry Activity(1)
Seneca
Processing
Plant
Cadiz
Processing
Plant
CHESAPEAKE
24-Hour IP
Buell #8H
9.5 MMcf/d
+ 1,425 Bbl/d liquids
GULFPORT
24-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
REXX
24-Hour IP
Guernsey 1H, 2H,
Noble 1H
Average 7.9 MMcf/d
+ 1,192 Bbl/d NGL
+ 502 Bbl/d Oil
MILEY UNIT
30-Day Rate
2 wells average
7.5 MMcfe/d
(60% liquids) NORMAN UNIT 1H
30-Day Rate
16.4 MMcfe/d
(17% liquids)
YONTZ UNIT 1H
30-Day Rate
17.0 MMcfe/d
(14% liquids)
RUBEL UNIT
30-Day Rate
3 wells average
17.3 MMcfe/d
(22% 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
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
Utica
Core
Area
WAYNE UNIT
30-Day Rate
3 wells average
10.8 MMcfe/d
(49% liquids)
GARY UNIT 1H
30-Day Rate
29.7 MMcfe/d
(22% liquids)
Highly-Rich/Cond
30,000 Net Acres
205 Locations
Highly-Rich Gas
26,000 Net Acres
161 Locations
Rich Gas
24,000 Net Acres
182 Locations
Dry Gas
27,000 Net Acres
211 Locations
21. 0.0
10.0
20.0
30.0
40.0
50.0
60.0
MMcfe/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 12 of the top 13
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 29)
20
UTICA 24-HOUR IPs
Core
12 to 53
MMcfe/d IPs
Tier 1
6 to 12
MMcfe/d IPs
Antero Utica Wells 3rd Party Core Utica Wells 3rd Party Non-Core Utica Wells
22. UTICA SINGLE WELL ECONOMICS
– ASSUMES ETHANE REJECTION
21
DRY GAS LOCATIONS RICH GAS LOCATIONS
HIGHLY
RICH GAS
LOCATIONS
Assumptions
12/31/2013 Strip Pricing & SEC Reserves
Utica Well Economics and Locations(1)
Classification
Highly-Rich/
Condensate
Highly-Rich
Gas Rich Gas Dry Gas
BTU Range 1250-1300 1200-1250 1100-1200 <1100
Modeled BTU 1275 1225 1175
EUR (Bcfe): 11.3 20.5 18.8 16.6
EUR (MMBoe): 1.9 3.4 3.1 2.8
% Liquids 32% 23% 15% 0%
Lateral Length (ft): 7,000 7,000 7,000 7,000
Stage Length (ft): 240 240 240 240
Well Cost ($MM): $11.0 $11.0 $11.0 $11.0
Bcf/1,000’: 1.2 2.4 2.4 2.4
Bcfe/1,000’: 1.6 2.9 2.7 2.4
Pre-Tax NPV10 ($MM): $15.7 $26.6 $18.4 $11.7
Pre-Tax ROR: 137% 169% 95% 56%
Net F&D ($/Mcfe): $1.21 $0.66 $0.72 $0.82
Payout (Years): 0.5 0.5 0.8 1.3
Gross 3P Locations(3): 205 161 182 211
1. Well economics are based on 12/31/2013 proved (P90) reserves and strip pricing. Includes gathering, compression and processing fees.
2. Pricing for a 1225 BTU y-grade rejection barrel.
3. Gross 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content.
NYMEX
($/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
205
161
182
211
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
Total3PLocations
ROR
Locations ROR
23. LARGE MIDSTREAM FOOTPRINT
22
Ohio River Withdrawal
System Completed
Antero Midstream estimated cumulative YE
2014 total capital investment in midstream
~ $1.5 billion
– Includes gathering lines, compressor
stations and water distribution infrastructure
Proprietary water sourcing and distribution
system
− Improves operational efficiency and reduces
water truck traffic
− Cost savings of $600,000 to $800,000 per
well
− One of the benefits of a consolidated
acreage position
Utica
Shale
Marcellus
Shale
Projected Midstream Infrastructure(1)
Marcellus
Shale
Utica
Shale Total
YE 2014E Cumulative Gathering /
Compression Capex ($MM) $750 $350 $1,100
Gathering Pipelines (Miles) 192 92 284
Compression Capacity (MMcf/d) 410 120 530
YE 2014 Cumulative
Water System Capex ($MM) $300 $100 $400
Water Pipeline (Miles) 122 48 170
Water Storage Facilities 31 16 47
YE 2014E Total Midstream ($MM) $1,050 $450 $1,500
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 12/31/2013 and 2014 guidance.
24. CAPITALIZATION
1. Equity valuation based on 262.0 million shares outstanding and a share price of $63.95 as of 3/20/2014. Enterprise value includes net debt.
2. Pro forma 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 Note and $140 million 7.25% Senior Notes repaid at beginning of year along with residual cash used to repay bank debt.
3. 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 $2.0 billion borrowing base upon bank approval.
PRO FORMA CAPITALIZATION
($ in millions) 12/31/2013
(PF Financing)
12/31/2013 (2)
Cash $17 $17
Senior Secured Revolving Credit Facility 288 288
7.25% Senior Notes Due 2019 260 260
6.00% Senior Notes Due 2020 525 525
5.375% Senior Notes Due 2021 1,000 1,000
Net Unamortized Premium 6 6
Total Debt $2,079 $2,079
Net Debt $2,062 $2,062
Shareholders' Equity $3,599 $3,599
Net Book Capitalization $5,660 $5,660
Net Market Capitalization(1) $18,816 $18,816
Financial & Operating Statistics
LTM EBITDAX $649 $649
LTM Interest Expense(2) $137 $106
Proved Reserves (Bcfe) (12/31/2013) 7,632 7,632
Proved Developed Reserves (Bcfe) (12/31/2013) 2,023 2,023
Credit Statistics
Net Debt / LTM EBITDAX 3.2x 3.2x
LTM EBITDAX / Interest Expense 4.8x 6.1x
Net Debt / Net Book Capitalization 36.4% 36.4%
Net Debt / Net Market Capitalization 11.0% 11.0%
Net Debt / Proved Developed Reserves ($/Mcfe) $1.02 $1.02
Net Debt / Proved Reserves ($/Mcfe) $0.27 $0.27
Liquidity
Credit Facility Commitments(3) $1,500 $1,500
Less: Borrowings (288) (288)
Less: Letters of Credit (32) (32)
Plus: Cash 17 17
Liquidity (Credit Facility + Cash) $1,197 $1,197
23
25. 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 2015
requirements)
Central Fresh Water
System & Water
Recycling
Numerous sources of water – building central water system to source water for
completion
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
Nine 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
109 of Antero’s 264 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 & COMMUNITY
Antero Core Values: Protect Our People and the Environment
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
24
26. ANTERO KEY ATTRIBUTES
25
459,000 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
29. 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 15 core area wells, assuming ethane rejection.
ANTERO UTICA SHALE WELLS – 24 HOUR IPS
28
Lateral
Well Gas Equivalent Rate Wellhead Gas Shrunk Gas NGL Condensate % Total Length
Name 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 5,115
Rubel 1H Monroe 47.5 31.1 25.9 3,391 214 46% 1231 6,554
Gary 2H Monroe 43.5 28.9 24.2 3,053 162 44% 1224 8,882
Rubel 3H Monroe 42.6 28.4 23.7 3,003 142 44% 1220 6,424
Milligan 2H Noble 40.2 17.2 13.5 2,361 2,087 68% 1276 5,989
Rubel 2H Monroe 37.4 24.8 20.7 2,635 156 45% 1217 6,571
Norman 1H Monroe 37.1 26.1 22.3 2,419 45 40% 1186 5,498
Coal 3H Noble 35.3 15.1 11.8 2,063 1,850 67% 1278 7,768
Wayne 3HA Noble 35.1 14.7 11.6 2,018 1,905 67% 1272 6,712
Wayne 4H Noble 34.2 14.2 11.2 1,907 1,922 67% 1265 6,493
Milligan 3H Noble 32.1 15.4 12.1 2,111 1,228 62% 1276 5,267
Milligan 1H Noble 25.8 10.6 8.3 1,461 1,442 68% 1276 6,436
Wayne 2H Noble 25.5 10.9 8.5 1,503 1,331 67% 1281 6,094
Miley 2H Noble 22.4 8.6 6.7 1,172 1,450 70% 1278 6,153
Miley 5HA Noble 20.2 7.7 6.0 1,090 1,285 70% 1291 6,296
35.5 19.5 16.0 2,224 1,018 57% 1249 6,417
28.7 18.8 17.6 844 1,018 42% 1251 6,518
Average ‐ Ethane Recovery(1)
Average ‐ Ethane Rejection(2)
24‐hr Peak Rate
30. 1. Average of Antero’s first 11 core area wells, assuming ethane rejection.
ANTERO UTICA SHALE WELLS – 30-DAY RATES
29
Antero’s wells produced against 1,100 psi line pressure until late January 2014 due to lack of compression facilities
− First 120 MMcf/d compressor station started up in late January 2014
Lateral
Well Gas Eq. Rate Wellhead Gas Shrunk Gas NGL Condensate % Total Estimated Length
Name 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 8,882
Rubel 2H Monroe 19.2 15.9 15.0 625 64 22% 1217 6,571
Rubel 3H Monroe 18.7 15.6 14.7 623 43 21% 1220 6,424
Yontz 1H Monroe 17.0 15.2 14.6 392 1 14% 1161 5,115
Norman 1H Monroe 16.4 14.3 13.6 461 2 17% 1186 5,498
Rubel 1H Monroe 14.0 11.5 10.8 501 28 23% 1231 6,554
Wayne 2H Noble 12.1 6.5 6.0 367 653 51% 1281 6,094
Wayne 3HA Noble 11.0 6.1 5.6 354 540 49% 1272 6,712
Wayne 4H Noble 9.2 5.2 4.7 284 452 48% 1265 6,493
Miley 2H Noble 9.0 3.8 3.5 213 700 61% 1278 6,153
Miley 5HA Noble 5.9 2.7 2.5 161 418 59% 1291 6,296
14.7 11.0 10.4 455 270 35% 1239 6,436
17.9 11.0 9.2 1,189 270 53% 1239 6,436
30‐Day Rates ‐ Antero Core Area
Average ‐ Ethane Rejection
Average ‐ Ethane Recovery(1)
31. 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)
30
Marcellus – 25.0 Tcfe
Utica – 5.8 Tcfe
Upper Devonian – 4.2 Tcfe
35.0
Tcfe
Gas – 29.6 Tcf
Oil – 91 MMBbls
NGLs – 811 MMBbls
Marcellus – 29.5 Tcfe
Utica – 6.7 Tcfe
Upper Devonian – 4.7 Tcfe
40.8
Tcfe
Gas – 27.4 Tcf
Oil – 91 MMBbls
NGLs – 2,151 MMBbls
15%
Liquids
33%
Liquids
32. Gas
$4.46
Gas
$4.19
Gas
$4.15
Gas
$4.08
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
$9.00
1050 BTU
$5.15
$6.55
$7.68
$4.46
1150 BTU 1250 BTU 1300 BTU
MARCELLUS SHALE RICH GAS –
LIQUIDS AND PROCESSING UPGRADE
1. NGL prices as of 3/18/2014 from IntercontinentalExchange.
2. Assumes $4.25/MMBtu NYMEX, $90.00/Bbl WTI and current NGL spot prices. 0.886, 1.972 and 2.632 (ethane rejection) GPMs used, all processing costs, shrink and fuel included. No NYMEX basis
differential assumed.
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(1)
31
+$0.69
Upgrade
+$2.08
Upgrade
+$3.22
Upgrade
Highly-Rich GasDry Gas
NGLs (C3+)
$0.96
NGLs (C3+)
$2.24
NGLs (C3+)
$3.03
Condensate
$0.16
Condensate
$0.56
Highly-Rich/
Condensate
Dry Gas
33. 2013 REALIZATIONS
Ethane (C2)
Propane (C3)
Iso Butane (C4)
Normal Butane
Natural Gasoline
Total $52.61 per Bbl
54% of WTI(4)
2013 NGL Y-GRADE (C3+) REALIZATIONS
2013 NATURAL GAS REALIZATIONS ($/MCF)
55%
2%
11%
15%
17%
$23.49
$6.27
$7.55
$14.57
$0.72
32
1. NYMEX differential represents contractual deduct to NYMEX-based sales.
2. Includes firm sales.
3. Price excludes hedges.
4. Based on monthly prices through 12/31/2013 WTI.
Antero Barrel
2013
% Sales
Average
NYMEX Price
Average
Differential(2)
Average
BTU Upgrade
Average 2013
Realized Price(3)
Average
Premium /
(Discount)
TCO 67% $3.65 $(0.06) $0.42 $4.02 $0.37
Dominion South 22% $3.65 $(0.41) $0.39 $3.64 $(0.01)
NYMEX(1) 6% $3.65 $(0.40) $0.39 $3.65 −
TETCO 5% $3.65 $(0.26) $0.41 $3.80 $0.15
Total 100% $3.65 $(0.16) $0.42 $3.90 $0.25
34. POSITIVE RATINGS MOMENTUM
Moody’s / S&P Historical Credit Ratings
“We would consider a positive rating action if the company continued to
convert its PUD reserves to proved developed reserves and improved
profitability, while maintaining leverage below 3x.”
- S&P Credit Research, October 2013
“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 $25.00 per boe and retained cash flow to debt over 40% as it
builds out infrastructure needs to support production growth.”
- Moody’s Credit Research, October 2013
Moody's S&P
Credit Rating
(Moody’s / S&P)
Ba3 / BB-
B1 / B+
B2 / B
B3 / B-
9/1/2010 2/24/2011 5/31/2012 10/21/2013 2/18//20142/28/2012 11/28/20118/27/20115/27/2011
Ba2 / BB
Ba1 / BB+
Caa1 / CCC+
(1)
___________________________
1. Represents corporate credit rating of Antero Resources Corporation / Antero Resources LLC.
Baa3 / BBB-
Moody’s Upgrade Criteria S&P Upgrade Criteria
33
35. ANTERO EBITDAX RECONCILIATION
34
EBITDAX Reconciliation
($ in millions) (12 Months Ended)
Antero Resources LLC 12/31/2012 12/31/2013
EBITDAX:
Net income (loss) from continuing operations $225.3 $(24.2)
Commodity derivative fair value (gains) losses (179.5) (491.7)
Net cash receipts on settled commodity derivatives instruments 178.5 163.6
(Gain) loss on sale of assets (291.2) -
Interest expense and other 97.5 136.6
Loss on early extinguishment of debt - 42.6
Provision (benefit) for income taxes 121.2 186.2
Depreciation, depletion, amortization and accretion 102.1 234.9
Impairment of unproved properties 12.1 10.9
Exploration expense 14.7 22.3
Stock compensation expense - 365.3
Other 4.1 2.9
EBITDAX from continuing operations $284.7 $649.4
EBITDAX:
Net income (loss) from discontinued operations ($510.3) 5.3
Commodity derivative fair value (gains) losses (46.4) -
Net cash receipts on settled commodity derivatives instruments 92.2 -
(Gain) loss on sale of assets 795.9 (8.5)
Provision (benefit) for income taxes (272.6) 3.2
Depreciation, depletion, amortization and accretion 89.1 -
Impairment of unproved properties 1.0 -
Exploration expense 1.0 -
EBITDAX from discontinued operations $149.6 -
EBITDAX $434.3 $649.4
36. CAUTIONARY NOTE
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserve estimates
(collectively, “3P”). Antero has provided internally generated estimates for proved, probable and possible reserves in this presentation in
accordance with SEC guidelines and definitions. The estimates of proved, probable and possible reserves as of December 31, 2013 included in
this presentation have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates are as of December 31, 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 December 31, 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
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