company website presentation (b) january 2016
TRANSCRIPT
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, 2014 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, 2014 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 Resources Corporation is denoted as “AR” and Antero Midstream Partners LP is denoted as “AM” in the presentation, which are their respective New York Stock Exchange ticker symbols.
2
CHANGES SINCE JANUARY 2016 PRESENTATION
Updated AR slides for 2015 reserve data, including Marcellus and Utica
Slides 5, 7, 25, 29, 49, 50, 65
Updated AR slides for 2015 undrilled gross locations, including Marcellus and Utica Slides 5, 9, 24, 51, 52
ANTERO – “THE BRIDGE” TO BETTER OIL & GAS PRICES
2015E 2016E 2017E
Large and Growing Production Base
Declining Development Costs
Production Sold Forward
Strong Liquidity
Firm Transport to Favorable Markets
48% growth1.493 Bcfe/d
25% - 30% growth target on 2015 guidance;midpoint 1.785 Bcfe/d
Continue to target peer-leading production growth
~$0.88/Mcfe YTD down 10% from 2014
• 2,227 “high grade” horizontal locations with similar economics
• Target 12% cost reduction
Continue to target peer-leading development costs
1,316 BBtu/d hedged at $4.43/MMBtu(94% of guidance)
1,793 BBtu/d hedged at $3.94/MMBtu(≈100% of target)
2,073 BBtu/d hedged at $3.57/MMBtu
• $3.0 billion at 9/30/2015• Additional $2.7 billion of
AM units
Continue to target growth in PDP reserves, midstream assets and hedge portfolio
Continue to target growth in PDP reserves, midstream assets and hedge portfolio
• 2.3 Bcf/d of FT• Expect 71% of sales volumes
priced at favorable markets
• 3.5 Bcf/d of FT• Expect 95% of sales volumes
priced at favorable markets
• 3.8 Bcf/d of FT• Expect 95% of sales volumes
priced at favorable markets• 61,500 Bbl/d of FT on
Mariner East 2 for export
Highly Sustainable Business Model - Antero holds a leading position within the lowest cost U.S. basin, a large and growing production base, a substantial long-term hedge position, over $5.0 billion of direct and indirect liquidity, and an increasing percentage of volumes sold to favorable markets
3
4
Most Active Operatorin Appalachia
Largest Firm Transport and Processing
Portfolio in Appalachia
Largest Gas Hedge Position in U.S. E&P +
Strong Financial Liquidity
Highest Growth Large Cap E&P
Largest Core Liquids-Rich Position in
Appalachia
Highest Realizations and Margins Among
Large Cap Appalachian Peers
Growth Liquids-Rich
Hedging &Liquidity
Midstream
Drilling
LEADING UNCONVENTIONAL BUSINESS MODEL
MLP (NYSE: AM)Highlights
Substantial Value in Midstream Business
Realizations
Takeaway
WellEconomics
1
2 3
4
5
67
8
Premier AppalachianE&P Company
Run by Co-Founders
High ReturnLocations
Note: 2015 SEC prices were $2.56/MMBtu for natural gas and $50.13/Bbl for oil on a weighted average Appalachian index basis. 1. 3P reserve pre-tax PV-10 based on annual strip pricing for first 10-years and flat thereafter as of December 31, 2015. NGL pricing assumes 39%, 46% and 48% of WTI strip prices for 2016, 2017 and
2018 and thereafter, respectively. 2. 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. 3. Antero and industry rig locations as of 1/1/2016, and average rig count for 4Q 2015, per RigData.
DRILLING – MOST ACTIVE OPERATOR IN APPALACHIA
5
COMBINED TOTAL – 12/31/15 RESERVESAssumes Ethane RejectionNet Proved Reserves 13.2 TcfeNet 3P Reserves 37.1 TcfeStrip Pre-Tax 3P PV-10(1) $11.2 BnNet 3P Reserves & Resource 50 to 53 TcfeNet 3P Liquids 1,237 MMBbls% Liquids – Net 3P 20%4Q 2015 Net Production 1,497 MMcfe/d- 4Q 2015 Net Liquids 54,750 Bbl/dNet Acres(2) 569,000Undrilled 3P Locations 3,719
OHIO UTICA SHALE CORE
Net Proved Reserves 1.8 TcfeNet 3P Reserves 7.5 TcfeStrip Pre-Tax 3P PV-10(1) $2.5 BnNet Acres 147,000Undrilled 3P Locations 814
MARCELLUS SHALE CORE
Net Proved Reserves 11.4 TcfeNet 3P Reserves 29.6 TcfeStrip Pre-Tax 3P PV-10(1) $8.7 BnNet Acres 422,000Undrilled 3P Locations 2,905
WV/PA UTICA SHALE DRY GASNet Resource 12.5 to 16 TcfNet Acres 188,000Undrilled Locations 1,889
02468
1012
Rig
Cou
nt
Operators
4Q Average SW Marcellus & Utica(3)
28%
21% 21%
15%
5%
-6%-10%
-5%
0%
5%
10%
15%
20%
25%
30%
AR EQT CNX COG RRC SWN0.25
0.50
0.75
1.00
1.25
1.50
4Q'13 Annualized 2014A 2015
6
Based on the strength of its drilling program, and focus on the highly prolific Marcellus and Utica Shale core areas, Antero has delivered 28% compounded annual growth in net debt-adjusted production per share since its IPO in October 2013
Antero’s net debt-adjusted production per share growth rate is seven percentage points higher than the next closest Appalachian peer
NOTE: Production/Net Debt-Adjusted Share = total production divided by net debt-adjusted shares outstanding each period. Data based on balance sheet as of 9/30/15, average share price from 1/1/2015 – 12/31/2015, consensus peer 2015 production estimates as of 12/31/2015.1. Net debt-adjusted shares = net debt at end of each period/stock price average for each respective period, plus average common shares outstanding each respective period.
AR Annualized Production / Net Debt-Adjusted Share(1)
Mcf
e/Sh
are
Net Debt-Adjusted Production per Share Growth vs. Peers(Since AR IPO)
GROWTH – DEBT-ADJUSTED PER SHARE PRODUCTION
0
10,000
20,000
30,000
40,000
50,000
60,000
2010 2011 2012 2013 2014 2015
NGLs (C3+) Oil
5 246
6,436
23,051
48,298
110% Production Growth
1. Assumes ethane rejection. 2015 proved reserves include 1.1 Tcfe of ethane due to de-ethanizer being placed online at Sherwood facility and commencement of ethane delivery contracts.2. Reflects midpoint of 2016 production growth target of 25%-30% based on 2015 guidance.
1,785
0
600
1,200
1,800
2010 2011 2012 2013 2014 2015 2016E
Marcellus Utica Guidance
30124
239
522
1,007
1,493
7
AVERAGE NET DAILY PRODUCTION (MMcfe/d)
0
50
100
150
200
2010 2011 2012 2013 2014 2015E
Marcellus Utica Deferred Completions
1938
60
114
177 180
130
GROWTH – STRONG TRACK RECORD
OPERATED GROSS WELLS COMPLETED
0
3,000
6,000
9,000
12,000
15,000
2010 2011 2012 2013 2014 2015
Marcellus Utica
6772,844
4,283
7,632
(1) (1)
12,683
(1)
13,215
(1)
NET PROVED RESERVES (Bcfe)
AVERAGE NET DAILY LIQUIDS PRODUCTION (Bbl/d)
25%-30% GrowthTarget
(2)
48% ProductionGrowth
8
LIQUIDS-RICH – LARGEST CORE POSITION
Source: Core outlines and peer net acreage positions based on investor presentations, news releases and 10-K/10-Qs. Rig information per RigData as of 1/1/2016.1. Based on company filings and presentations. Peer group includes Ascent, CHK, CNX, CVX, ECR, EQT, GPOR, NBL, RRC, STO, SWN.
• Antero controls an estimated 37% of the NGLs in the liquids-rich core of the two plays
• Antero has the largest core liquids-rich position in Appalachia with ≈371,000 net acres (> 1100 Btu)
• Represents over 21% of core liquids-rich acreage in Marcellus and Utica plays combined
Antero has over 2,700 undeveloped rich gas locations with an average lateral length of 7,580’ in its 3P reserves as of 12/31/2015
0
100
200
300
400
(000
s)
Core Liquids-Rich Net Acres(1)
29%26% 23%
34%27%
22%
11% 9% 10%
83% 80%
71%
63%57%
47%
28%24%
16%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Utica Highly-Rich Gas
Utica Dry Gas - Ohio
Utica Rich Gas MarcellusHighly-Rich
Gas/Condensate
Utica Highly-Rich Gas/
Condensate
MarcellusHighly-Rich
Gas
Marcellus DryGas
Marcellus RichGas
UticaCondensate
RO
R
ROR @ 12/31/2015 Strip Pricing - Before Hedges ROR @ 12/31/2015 Strip Pricing - After Hedges
2016 Antero Drilling Plan
ANTERO MARCELLUS & UTICA WELL ECONOMICS(1)(2)
108 263 161 626 98 971 755 553 184
1. 12/31/2015 pre-tax well economics based on a 9,000’ lateral, 12/31/2015 natural gas and WTI strip pricing for 2016-2024, flat thereafter, NGLs at 37.5% of WTI for 2016 and 50% of WTI thereafter, and applicable firm transportation and operating costs including 50% of Antero Midstream fees. Well cost estimates, which include $1.2 million for road, pad and production facilities, assume Antero will begin to realize lower well costs in 2016 as the company utilizes incremental completion crews for deferred completions beginning at year end 2015 and as existing drilling rig contracts begin to roll off during 2016.
2. ROR @ 12/31/2015 Strip Pricing – After Hedges reflects 12/31/2015 well cost ROR methodology with the 12/31/2015 hedge value allocated based on 2016-2021 projected production volumes resulting in blend of strip and hedge prices.
9
At 12/31/2015 strip pricing, Antero has 2,227 locations with well economics that exceed 20% rate of return (excluding hedges)– Including hedges, these locations generate rates of return of approximately 47% to 83%
Rates of return include pad, facilities, cash production expenses (including midstream and FT costs)– See assumptions pages in appendix for further detail
2,227 “High Grade” Drilling
Locations
NYMEX($/MMBtu)
WTI($/Bbl)
C3+ NGL($/Bbl)
2016 $2.50 $41 $152017 $2.79 $46 $232018 $2.91 $49 $252019 $3.03 $52 $262020 $3.18 $54 $272021-25 $3.31-$3.88 $55-$56 $27-$28
12/31/15 Strip Pricing 12/31/15 Hedge PricingNYMEX
($/MMBtu)C3+ NGL
($/Bbl)
$4.19 $18$3.72 $22$3.70 $25$3.60 $26$3.38 $27
$3.31 - $3.88 $27-$28
$2.50 $2.79 $2.91 $3.03 $3.18
$4.19$3.72 $3.70 $3.60 $3.38
$0.00$1.00$2.00$3.00$4.00$5.00
2016 2017 2018 2019 2020
12/31/15 NYMEX Strip Pricing - Before Hedges12/31/15 Strip Pricing - After Hedges
Locations
WELL ECONOMICS – WELL COST REDUCTIONS SUPPORTSUSTAINABLE BUSINESS MODEL
Antero ResourcesCorporation (NYSE: AR)
$9.9 Billion Enterprise Value(1)
Ba2/BB Corporate Rating
Antero MidstreamPartners LP (NYSE: AM)
$4.5 Billion Enterprise Value(1)
67% LP Interest$2.7 Billion MV(1)
$11.2 Bn 3P PV-10(4)
E&P Assets
Gathering/Compression Assets
MIDSTREAM – MLP (NYSE: AM) HIGHLIGHTSSUBSTANTIAL VALUE IN MIDSTREAM BUSINESS
1. AR enterprise value excludes AM debt, minority interest and cash. Market values (MV) as of 12/31/2015 and includes subordinated units; balance sheet data as of 9/30/2015. 2. Based on 277.0 million AR shares outstanding and 175.8 million AM units outstanding.3. 3.5 Tcfe hedged at $3.81/Mcfe average price through 2022 with mark-to-market (MTM) value of $3.1 billion as of 12/31/2015. 4. 3P pre-tax PV-10 based on annual strip pricing for first 10-years and flat thereafter as of December 31, 2015. NGL pricing assumes 39%, 46% and 48% of WTI strip prices for 2016, 2017 and 2018 and
thereafter, respectively. 10
Corporate Structure Overview(1)
Market Valuation of AR Ownership in AM:• AR ownership: 67% LP Interest = 116.9 million units
AM Priceper Unit
AM UnitsOwnedby AR(MM)
AR Value in AM LP Units
($MMs)Value Per
AR Share(2)
$20 117 $2,338 $8$21 117 $2,455 $9$22 117 $2,572 $9$23 117 $2,689 $10$24 117 $2,806 $10$25 117 $2,923 $11
Water Infrastructure Assets
MLP Benefits:- Funding vehicle to expand midstream business- Highlights value of Antero Midstream- Liquid asset for Antero Resources
Public
33% LP Interest$1.3 Billion MV(1)
$3.1 Bn MTM Hedge Position(3)
TAKEAWAY – LARGEST FIRM TRANSPORTATION AND PROCESSING PORTFOLIO IN APPALACHIA
Antero Long Term Firm Processing & Takeaway Position (YE 2018) – Accessing Favorable MarketsMariner East 2
62 MBbl/d CommitmentMarcus Hook Export
Shell20 MBbl/d Commitment
Beaver County Cracker (2)
Sabine Pass (Trains 1-4)50 MMcf/d per Train
Lake Charles LNG(3)
150 MMcf/d
Freeport LNG70 MMcf/d
1. February 2016 and full year 2016 futures basis, respectively, provided by Intercontinental Exchange dated 12/31/2015. Favorable markets shaded in green.2. Subject to Shell FID expected mid-year 2016.3. Lake Charles LNG 150 MMcf/d commitment subject to BG FID expected in 2016.
Chicago(1)
$0.25 / $0.02
CGTLA(1)
$(0.07) / $(0.06)
TCO(1)
$(0.16) / $(0.18)
11
Cove Point LNG4.85 Bcf/dFirm GasTakeaway
By YE 2018
Antero’s natural gas firm transportation (FT) portfolio builds to 4.85 Bcf/d by YE 2018 with 87% serving favorable markets, with an average demand fee of $0.40/MMBtu and positive weighted average basis differential to NYMEX after assumed Btu uplift for gas
YE 2018 Gas Market MixAR 4.85 Bcf/d FT
44%Gulf Coast
17%Midwest
13%Atlantic
Seaboard
13%Dom S/TETCO
(PA)
13%TCO
Positive weighted
average basis differential
Antero Commitments
(3)
(2)
12
HEDGING – INTEGRAL TO BUSINESS MODEL Hedging is a key component of Antero’s business model which includes development of a large, repeatable drilling inventory
– Locks in higher returns in a low commodity price environment and reduces well payout thereby enhancing liquidity
Antero has realized $1.7 billion of gains on commodity hedges since 2009– Gains realized in 28 of last 29 quarters, or 97% of the quarters since 2009
● Based on Antero’s hedge position and strip pricing as of 12/31/2015, the unrealized commodity derivative value is $3.1 billion
● Significant additional hedge capacity remains under the credit facility hedging covenant for 2018 – 2022 period
Quarterly Realized Hedge Gains / (Losses)
Realized Hedge GainsProjected Hedge Gains
NYMEX Natural Gas Historical Spot Prices
($/Mcf)
NYMEX Natural Gas Futures Prices
3.5 Tcfe Hedged at average price of
$3.79/Mcfethrough 2022
Average Hedge Prices ($/Mcfe)
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$0
$50
$100
$150
$200
$250
$300
$MM
$3.50
$4.51
$3.94
$3.57$3.88 $3.89
$3.73$3.30
$3.1 Billion on Balance Sheet in
Hedge Gains Through 2022Realized $1.7 Billion
in Hedge Gains Since 2009
Liquid “non-E&P assets” of $5.8 Bnsignificantly exceeds total debt of $3.9 Bn
Liquidity
LIQUIDITY – STRONG BALANCE SHEET AND FLEXIBILITY Antero Resources (NYSE:AR) Antero Midstream (NYSE:AM)
9/30/2015 Debt Liquid Non-E&P Assets 9/30/2015 Debt Liquid Assets
Debt Type $MMCredit facility $500
6.00% senior notes due 2020 525
5.375% senior notes due 2021 1,000
5.125% senior notes due 2022 1,100
5.625% senior notes due 2023 750
Total $3,875
Asset Type $MMCommodity derivatives(1) $3,117
AM equity ownership(2) 2,668
Cash 10
Total $5,795
Asset Type $MMCash $10
Credit facility – commitments(3) 4,000
Credit facility – drawn (500)
Credit facility – letters of credit (535)
Total $2,975
Debt Type $MMCredit facility $525
Total $525
Asset Type $MMCash $18
Total $18
Liquidity
Asset Type $MMCash $18
Credit facility – capacity 1,500
Credit facility – drawn (525)
Credit facility – letters of credit -
Total $993
Approximately $3.0 billion of liquidity at AR plus an additional $2.7 billion of AM units
Approximately $1 billion of liquidityat AM
13
Only 35% of AM credit facility capacity drawn
Note: All balance sheet data as of 9/30/2015, inclusive of water drop down and associated financing. 1. Mark-to-market as of 12/31/2015.2. Based on AR ownership of AM units (116.9 million common and subordinated units) and AM’s closing price as of 12/31/2015.3. AR credit facility commitments of $4.0 billion, borrowing base of $4.5 billion.
Average NYMEX
Price($/Mcf)
AverageDifferential
($/Mcf)
AverageBTU Upgrade
($/Mcf)
Discount to NYMEX($/Mcf)
Gas Hedge Effect
($/Mcf)
AverageRealized
Gas Price($/Mcf)
AverageRealized Gas
Premium to NYMEX ($/Mcf)
Liquids Upgrade($/Mcfe)
Realized Equivalent
Price($/Mcfe)
Gas Equivalent
Premium to NYMEX($/Mcfe)
3Q 2015 $2.77 $(0.62) $0.17 $(0.45) $1.67 $3.99 $1.22 ($0.16) $3.83 $1.06
4Q 2015 $2.27 $(0.31) $0.17 $(0.14) $2.27 $4.40 $2.13 ($0.12) $4.28 $2.01
$1.97 $1.62
$1.30 $1.18 $1.17 $0.66
$0.58 $0.73 $0.85 $0.72 $0.88$0.75
$3.86
$2.93
$2.33 $2.34 $2.55
$2.35
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
$4.50
AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5
$/M
cfe
Noncontrolling Interest of Midstream MLP EBITDA LOEProduction Taxes GPTG&A EBITDAX4-year Avg. All-in F&D
$3.99
$2.77 $2.63 $2.46 $2.21 $2.02
$0.00$0.50$1.00$1.50$2.00$2.50$3.00$3.50$4.00$4.50
AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5
1. Gulf Coast differential includes contractual deduct to NYMEX-based sales.2. Includes firm sales. 3. Includes natural gas hedges.4. Source: Public data from 3Q 2015 10-Qs. Peers include Cabot Oil & Gas, CONSOL Energy, EQT Corp. and Southwestern. 5. Includes realized hedge gains and losses. Operating costs include lease operating expenses, production taxes, gathering, processing and firm transport costs and general and administrative costs. 4-year proved
reserve average all-in F&D from 2011-2014. Calculation = (Development costs + exploration costs + leasehold costs) / Total reserves added (2014 ending reserves – 2011 beginning reserves + 4-year reserve sales – 4-year reserve purchases + 4-year accumulated production). AR price realization includes $0.03 of midstream revenues; EBITDAX excludes AR’s midstream EBITDA not attributable to AR’s ownership.
14
REALIZATIONS – A LEADER IN REALIZATIONS & MARGINSAMONG LARGE-CAP APPALACHIAN PEERS
3Q 2015 Natural Gas Realizations(1)(2) 3Q 2015 Price Realization & EBITDAX Margin vs F&D(2)(3)
($/Mcfe)
Antero continues to be a leader in its peer group in price realizations and EBITDAX unit margins
3Q 2015 NYMEX = $2.77/Mcf
3Q and 4Q 2015 Natural Gas Realizations ($/Mcf)
DOM S 23%
DOM S, 4% DOM S, 4%
TETCO M27%
TETCO M21%
TETCO M21%
TCO 40%
TCO 32%
TCO, 21%
NYMEX10%
NYMEX14%
NYMEX10%
Gulf Coast2%
Gulf Coast21% Gulf Coast
39%
Chicago18% Chicago
28%Chicago
25%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
($/Mcf) 2015E 2016ENYMEX Strip Price(1) $2.66 $2.49Basis Differential to NYMEX(1) $(0.53) $(0.17)BTU Upgrade(5) $0.25 $0.24Estimated Realized Hedge Gains $1.47 $1.49 Realized Gas Price with Hedges $3.86 $4.05 Premium to NYMEX +$1.29 +$1.56Liquids Impact +$0.25 +$0.11Premium to NYMEX w/ Liquids +$1.45 +$1.67Realized Gas-Equivalent Price $4.11 $4.16
REALIZATIONS – REALIZED PRICE “ROAD MAP”
Note: Hedge volumes as of 12/31/2015.1. Based on 12/31/2015 strip pricing and YTD actuals for 2015. 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.
4. Represents 60,000 MMBtu/d of TCO index hedges and 120,000 MMBtu/d of TCO basis hedges that are matched with NYMEX hedges for presentation purposes.
5. Assumes ethane rejection resulting in 1100 BTU residue sales gas.
2015Basis(1)
2016 Basis(1)
2017 Basis(1)
2015Hedges
2016Hedges
2017Hedges
Mar
kete
d %
of T
arge
t Res
idue
Gas
Pro
duct
ion
+$0.02/MMBtu
$(0.12)/MMBtu(2)
$(1.30)/MMBtu
$(0.28)/MMBtu
$0.02/MMBtu
$(0.43)/MMBtu(2)
$(0.95)/MMBtu
$(0.18)/MMBtu
$(0.04)/MMBtu
$(0.43)/MMBtu(2)
$(0.78)/MMBtu
$(0.25)/MMBtu
$(0.05)/MMBtu
$(0.06)/MMBtu
1,370,000 MMBtu/d
@ $3.40/MMBtu
40,000 MMBtu/d
@ $4.00/MMBtu
230,000 MMBtu/d
@ $5.74/MMBtu
510,000 MMBtu/d
@ $3.87/MMBtu(3)
170,000 MMBtu/d
@ $4.09/MMBtu
272,500 MMBtu/d
@ $5.35/MMBtu
180,000 MMBtu/d
@ $3.54/MMBtu(4)
95% exposure to favorable price indices71% exposure to favorable price indices 95% exposure to favorable price indices
Antero’s exposure to favorable gas price indices like Chicago, Gulf Coast, NYMEX and TCO is expected to increase to 95% by 2016 Improved 2016 realizations driven by Stonewall gathering pipeline which was placed in-service in early December 2015 and will eliminate
virtually all swing sales at Dominion South and Tetco in 2016
$(1.00)/MMBtu
$(0.93)/MMBtu
Wtd. Avg.Basis ($0.53)
Wtd. Avg.Basis $(0.17)
1,160,000 MMBtu/d@ $4.34/MMBtu
Wtd. Avg.Basis $(0.17)
1,612,500 MMBtu/d@ $3.92/MMBtu
420,000 MMBtu/d
@ $4.27/MMBtu
2015E 2016E 2017E
15
380,000 MMBtu/d
@ $3.88/MMBtu
990,000 MMBtu/d
@ $3.49/MMBtu
70,000 MMBtu/d
@ $4.57/MMBtu
1,860,000 MMBtu/d@ $3.64/MMBtu
$(0.10)/MMBtu
$(0.75)/MMBtu
Current markets indicate positive
differential in 2016
$0.59
$0.43 $0.40
$0.41
$0.10
$0.20
$0.30
$0.40
$0.50
$0.60
$0.70
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
2016 2017
Hedged Volume Average Hedge Price Strip (12/31/2015)
$52.61 $53.71 $46.23 $51.98
$16.53$25.23
$15.17$21.89
$98.01 $93.03
$48.63 $41.00
$0.00
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
AR NGL Pricing Mont Belvieu AR NGL Pricing Mont Belvieu AR NGL Pricing Mont Belvieu AR NGL Pricing Mont Belvieu
2013 2014 2015 YTD 2016E
Realized NGL C3+ Price WTI
REALIZATIONS – NGL REALIZATIONS AND PROPANE HEDGES
161. Based on 2016 NGL and WTI strip prices as of 12/31/2015. 2. YTD as of 10/31/2015. 3. As of 12/31/2015.
Realized NGL Prices as % of WTI(1)
54% 50%
34% 37%
($/Bbl)
NGL Marketing Propane Hedges Realized NGL (C3+) price was 50% of WTI in 2014 and
Antero is forecasting 30% to 35% of WTI for 2015−YTD 2015(2) NGL realizations were 34% of WTI− Including propane hedges, first ten months of 2015
realizations were 40% of WTI
By year-end 2016, Antero will market a significant portion of its NGL volumes out of Marcus Hook to export markets once Mariner East 2 is in service – 61,500 Bbl/d firm commitment with expansion rights
(Bbl/d)
$82 MM $7 MM
($/Gal)
Mark-to-Market Value(3)
Target 2016 NGL pricing of 37% of WTI based on 12/31/15 strip pricing
(2)
NORTHEAST NGLS ARE TRANSPORTATION CHALLENGED
1. As an anchor shipper on Mariner East 2, Antero has the right to expand its NGL commitment with notice to operator. 2. 2015 NGL production assumes ethane rejection.
Mariner East 261,500 Bbl/d AR Commitment(1)
4Q 2016 In-Service
Not so much a supply problem but more of a logistics problem for NGLs in the northeast today− The majority of northeast NGL production is being transported by expensive rail and trucking− NGLs that are transported “to the water” are also faced with high shipping rates
Export15%
Gulf Coast13%
Mid-Atlantic
6%Sarnia
3%
Northeast43%
Midwest10%
Edmonton10%
2015 NGL Marketing by Region
17
NORTHEAST NGL GROWTH IS SUPPORTED BY INCREASING TAKEAWAY OPTIONS
1. Chart 10 per BAML research dated 6/5/2015. Pipeline volumes are capacity estimates.
Industry NGL Pipelines – Actual (2015) and Projected(1)
18
ShellBeaver County Cracker(Pending FID 1H 2016)
Mariner East 262 MBbl/d Commitment
Marcus Hook Export
Gulf Coast Critical to
NGL Pricing
Appalachia
NGL transportation rates are expected to decline $0.12 to $0.15 per gallon by 2017 as pipeline options to domestic markets and export terminals go in-service (Mariner East 1 and 2, for example)
(MMBbl/d)
$0.00
$0.10
$0.20
$0.30
$0.40
$0.50
$/G
allo
n
Baltic Exchange LPG Freight Futures
Baltic LPG Rate ($/gal) Marcus Hook to Europe ($/gal)
Marcus Hook to Far East ($/gal)
U.S. EXPORTS ARE SUPPORTED BY EXCESSDOCK CAPACITY AND FLEET GROWTH
0200400600800
1,0001,2001,4001,6001,800
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
MB
bl/d
Butane Exports Propane Exports Total Export Capacity
Excess LPG Export Terminal Capacity vs. Expected Export Volumes(1)
Excess dock capacity supports growing LPG export volumes
through 2025
Fleet Growth Supports U.S. LPG Export Growth(2) LPG Freight Futures Show Declining Freight Costs(3)
Baltic LPG shipping cost to NWE declines from $0.14/gal to $0.09-$0.10/gal in early
2017 on fleet supply growth numbers
Projected growth in VLGC fleet supports increasing LPG export volumes and
lower shipping costs
1. Source: Bentek.2. Source: Poten & Partners, August 2015.3. Baltic Rate based on 9/30/2015 Baltic Futures converted to cost per gallon of LPGs, assuming 75/25 propane/butane.
LPG transportation rates from northeast fractionation to Europe and Asia should improve by $0.05 to $0.15 per gallon by YE 2016,driven both by pipelines replacing rail and by lower shipping costs
Excess Dock Capacity
Current Fleet 168New builds +85
19
POSITIVE OUTLOOK FOR LONG-TERM NGL MARKETS
Steady Global LPG Demand Growth Through 2035(1)
1. Source: PIRA NGL Study, September 2015.2. Source: IHS, Waterborne, SK Gas Analysis; Wood Mackenzie; Wood Mackenzie; PDH C3 capacity based on 25 MBbl/d = 650 Mt/y.
Multiple Factors Driving Global LPG Demand Growth Through 2020(2)
MM
Bbl
/d
0.0
0.33
0.67
Forecast global LPG demand growth of 800 MBbl/d to 1 MMBbl/d by 2020 to be driven by petrochem projects in Asia and Middle East as well as residential/commercial, alkylate and power generation demand− Naphtha cracker conversion to LPG another potential demand driver that has not yet been factored into analyst estimates ≈1 MMBbl/d
China KoreaHaiwei (2016) - 21 MBbl/d C3
SK Advanced (2016) - 27 MBbl/d C3
Ningbo Fuji (2016) - 29 MBbl/d C3
Fujian Meide (2016) - 29 MBbl/d C3
Tianjin Bohua 2 (2018) - 29 MBbl/d C3 United States
Fujian Meide 2 (2018) - 29 MBbl/d C3
Enterprise (3Q 2016)- 29 MBbl/d C3
Oriental Tangshan (2019) - 25 MBbl/d C3
Formosa (2017)- 25 MBbl/d C3
Firm and Likely PDH Underway (By 2020)
Total - 243 MBbl/d C3
Million Tons, Global PDH Capacity
1990 2000 2010 2020
20
10
0
20
14.7
13.0
11.4
9.8
8.2
6.5
4.9
3.3
1.7
U.S. Driven Global LPG Supply Through 2035(1)
MMBbl/d MMBbl/d1.3
1.0
0.7
0.3
-0.3
Downstream LNGand NGL Sales
Production andCash Flow Growth
21
Antero has completed its first Utica dry gas well with encouraging early results; has 229,000 net acres in OH, WV and PA highly prospective for Utica dry gas
KEY CATALYSTS
Targeting 25% to 30% production growth in 2016 with ~100% hedged at $3.94/MMBtu; capital budget flexibility to commodity price changes
Large, low unit cost core Marcellus and Utica natural gas drilling inventory with associated liquids generates attractive returns supported by long-term natural gas hedges, takeaway portfolio and downstream LNG and NGL sales agreements
Pursuing additional value enhancing long-term LNG and NGL sales agreements, as well as additional NGL firm takeaway
Antero owns 67% of Antero Midstream Partners and thereby participates directly in its growth and value creation; acquisition of integrated water business from Antero expected to result in distributable cash flow per unit accretion in 2016
Midstream MLP Growth
Sustainability of Antero’s Integrated
Business Model
1
2
3
5
4Utica Dry Gas
Activity
-
100
200
300
400
500
600
AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5
Core Net Acres - Dry Core Net Acres - Liquids Rich
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
AR EQT RRC COG CNX SWN
0200400600800
1,0001,2001,4001,6001,800
EQT COG AR SWN RRC CNX
LEADERSHIP IN APPALACHIAN BASIN
Top Producers in Appalachia (Net MMcfe/d) – 3Q 2015(1)(2) Top 12 U.S. Natural Gas Producers (Net MMcf/d) – 3Q 2015(1)
Appalachian Producers by Proved Reserves (Bcfe) – YE 2014(1)(2) Appalachian Producers by Core Net Acres (000’s) – August 2015(3)(4)
1. Based on company filings and presentations.2. Appalachian only production and reserves where available. Excludes companies that do not break out Appalachian production including CVX, HES and XOM. 3. Based on Antero geologic interpretation supported by state well data, company presentations and public land data. Peer group includes CNX, COG, EQT, RRC, SWN.4. Southwestern leasehold and reserves include the impact from STO and WPX property acquisitions closed in January 2015. 5. Includes proved reserves categorized in “Northern Division” consisting of Utica Shale, Marcellus Shale and Powder River Basin.
(4)
22
3rd Largest Appalachian
Producer
Antero has the largest proved reserve base, the largest core liquids-rich acreage position and is one of the largest producers in the Appalachian Basin
Appalachian Peers
11th Largest U.S. Gas Producer
Largest Proved Reserve Base In
Appalachia
0
500
1,000
1,500
2,000
2,500
3,000
3,500
Largest Liquids-Rich Core Position
in Appalachia
626 971
553 75563% 47%
24% 28%34%22%
9% 11%
0
400
800
1,200
0%15%30%45%60%75%
Highly-RichGas/
Condensate
Highly-Rich Gas Rich Gas Dry Gas
Tota
l 3P
Loca
tions
RO
R
Total 3P Locations ROR @ 12/31/2015 Strip Pricing - After Hedges ROR @ 12/31/2015 Strip Pricing - Before Hedges
184
98 108
161263
16%
57%
83%
71% 80%
10%
27% 29% 23% 26%
0
100
200
300
0%20%40%60%80%
100%
Condensate Highly-RichGas/
Condensate
Highly-RichGas
Rich Gas Dry Gas
Tota
l 3P
Loca
tions
RO
R
MARCELLUS WELL ECONOMICS(1)(2)
WELL COST REDUCTIONS SUPPORTSUSTAINABLE BUSINESS MODEL
Marcellus Well Cost Improvement(3)
1. 12/31/2015 pre-tax well economics based on a 9,000’ lateral, 12/31/2015 natural gas and WTI strip pricing for 2016-2025, flat thereafter, NGLs at 37.5% of WTI for 2016 and 50% of WTI thereafter, and applicable firm transportation and operating costs including 50% of Antero Midstream fees. Well cost estimates, which include $1.2 million for road, pad and production facilities.
2. ROR @ 12/31/2015 Strip-With Hedges reflects 12/31/2015 well cost ROR methodology, with the 12/31/2015 hedge value allocated based on 2016-2021 projected production volumes resulting in blend of strip and hedge prices.
3. 2015E well costs based on $10.3 million for a 9,000’ lateral Marcellus well and $11.6 million for a 9,000’ lateral Utica well.
24
UTICA WELL ECONOMICS(1)(2)
74% of Marcellus locations are processable (1100-plus Btu) 68% of Utica locations are processable (1100-plus Btu)
2016Drilling
Plan
Antero has reduced average well costs for a 9,000’ lateral by 16% in the Marcellus and 18% in the Utica as compared to 2014 well costs At 12/31/2015 strip pricing, Antero has 2,227 locations that exceed 20% rate of return (excluding hedges)
– Including hedges, these locations generate rates of return of approximately 50% to 90%
Utica Well Cost Improvement(3)
$1.357 $1.144
$0.000
$0.500
$1.000
$1.500
$2.000
2014 2015E
$MM
/1,0
00’ L
ater
al
Well Cost ($MM/1,000')
16% Decrease vs. 2014 $1.571
$1.289
$0.000
$0.500
$1.000
$1.500
$2.000
2014 2015E
$MM
/1,0
00’ L
ater
al
Well Cost ($MM/1,000')
18% Decrease vs. 2014
WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECT
100% operatedOperating 7 drilling rigs including
1 intermediate rig422,000 net acres in
southwestern Marcellus core (75% includes processable rich gas assuming an 1100 Btu cutoff)– 52% HBP with additional 25%
not expiring for 5+ years419 horizontal wells completed
and online– Laterals average 7,500’– 100% drilling success rate6 plants in-service at Sherwood
Processing Complex capable of processing in excess of 1.2 Bcf/d of rich gas−Over 900 MMcf/d of Antero gas
being processed currentlyNet production of 1,051 MMcfe/d
in 4Q 2015, including 33,750 Bbl/d of liquids 2,905 future drilling locations in
the Marcellus (2,150 or 74% are processable rich gas)29.6 Tcfe of net 3P (21% liquids),
includes 11.4 Tcfe of proved reserves (assuming ethane rejection except for 1.1 Tcfe)
Highly-Rich Gas138,000 Net Acres
971 Gross Locations
Rich Gas91,000 Net Acres
553 Gross Locations
Dry Gas107,000 Net Acres
755 Gross Locations
Highly-Rich/Condensate86,000 Net Acres
626 Gross Locations
HEFLIN UNIT30-Day Rate
2H: 21.4 MMcfe/d (21% liquids)
CONSTABLE UNIT30-Day Rate
1H: 14.3 MMcfe/d (25% liquids)
SherwoodProcessing
Complex
Source: Company presentations and press releases. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held. Note: Rates in ethane rejection.
NERO UNIT30-Day Rate
1H: 18.2 MMcfe/d(27% liquids)
BEE LEWIS PAD30-Day Rate
4-well combined 30-Day Rate of
67 MMcfe/d (26% liquids)
RJ SMITH PAD30-Day Rate
4-well combined 30-Day Rate of
56 MMcfe/d (21% liquids)
25
HENDERSHOT UNIT30-Day Rate
1H: 16.3 MMcfe/d2H: 18.1 MMcfe/d
(29% liquids)
HORNET UNIT30-Day Rate
1H: 21.5 MMcfe/d2H: 17.2 MMcfe/d
(26% liquids)CARR UNIT30-Day Rate
2H: 20.6 MMcfe/d(20% liquids)
WAGNER PAD30-Day Rate
4-well combined 30-Day Rate of
59 MMcfe/d (14% liquids)
Antero’s Marcellus well performance has continued to improve over time with a tight statistical range of results across its entire acreage position
PROLIFIC PREDICTABLE RESULTS ACROSS ENTIREMARCELLUS POSITION
26
Marcellus PDP Locations (As of 12/31/2015)
(1)
1. Source: IHS; 3rd party producing wells include Consol, EQT, Exxon/XTO, Noble, Ascent, PDC, Magnum Hunter, Statoil, Chesapeake / SWN.
>1275 BTU2.2 Bcfe/1,000’ Lateral
10 SSL Wells
1200-1275 BTU2.0 Bcfe/1,000’ Lateral
116 SSL Wells
1100-1200 BTU1.8 Bcfe/1,000’ Lateral
104 SSL Wells
Average Antero Marcellus Well
2014 Actual
2H 2015Budget Current
30-Day Rate (MMcfe/d): 13.1 16.1 16.1
Gross EUR (Bcfe): 15.3 19.2 19.2
Gross Well Cost ($MM): $11.8 $10.3 $9.1
Lateral Length (Feet): 8,052 9,000 9,000
Net F&D ($/Mcfe): $0.89 $0.63 $0.56
Btu: 1195 1250 1250
05
101520253035404550
1.3 1.4 1.5 1.6 1.7 1.8 1.9 2.0 2.1 2.2 2.3 2.4 2.5 2.6 2.7 More
Wel
l Cou
nt
Bcfe/1,000' of Lateral
0
5
10
15
20
25
30
MM
cfe/
d
Antero’s Marcellus average 30-day rates have increased by 55% over the past two years as the Company increased per well lateral lengths by 13% and shortened stage lengths by 33% compared to year-end 2013
INCREASING RECOVERIES AND LOW VARIANCEIN MARCELLUS
1. Processed rates converting C3+ NGLs and condensate at 6:1. Ethane rejected and sold in gas stream.
Antero 30-Day Rates – 429 Marcellus Wells(1)
27
Antero SSL Reserves per 1,000’ of Lateral – 236 Marcellus Short Stage Length (SSL) Wells
2014 – 13.0 MMcfe/d
2013 – 9.4 MMcfe/d
2009–2012 – 8.0 MMcfe/d
SSL results have been highly consistent and predictable, with a standard deviation of only +/-0.3 around the 1.7 Bcf/1,000’ average (equates to 2.0 Bcfe/1,000’)
These wells provide the basis for AR’s undeveloped 3P reserve evaluations
P10: 2.37 Bcfe/1,000’P90: 1.45 Bcfe/1,000’
P10/P90: 1.6xStdDev: 0.3x
P90P10
2015 – 14.6 MMcfe/d
Antero 3P reserves are evaluated quarterly by AR engineers and audited annually by DeGolyer and MacNaughton
– Proved reserves volume delta at YE2015: 0.9%– Probable/Possible volume delta at YE2015: 1.9%
1.5 1.6 1.5 1.6
2.0 2.0
$0.97 $0.89
$0.98 $1.13
$0.89 $0.78
$0.00
$0.20
$0.40
$0.60
$0.80
$1.00
$1.20
0.00
0.50
1.00
1.50
2.00
2.50
2010 2011 2012 2013 2014 2015
Dev
elop
men
t Cos
t ($/
Mcf
e)
EUR
/1,0
00' L
ater
al
EUR vs. Development Cost Per Unit
EUR/1,000' Lateral (Bcfe) Development Cost ($/Mcfe)
411 420
361
283
200 200
14 16
21
27
40 43
- 5 10 15 20 25 30 35 40 45
- 50
100 150 200 250 300 350 400 450
2010 2011 2012 2013 2014 2015
Ave
rage
Fra
c St
ages
per
Wel
l
Ave
rage
Sta
ge L
engt
h (F
eet)
Increasing Frac Stages per Well
Average Stage Length (Feet) Average Frac Stages per Well
28
MARCELLUS WELL PERFORMANCE IMPROVEMENTS Increasing recoveries and efficiencies, through longer laterals, shorter stage lengths and faster drilling SSL completions drove a 12% decline in development costs in 2015 while lower service costs and efficiencies are driving further
development cost reductions in 2016
5,732 6,717
7,345 7,308
8,052 8,508
19
38
59
103
136
74
0
20
40
60
80
100
120
140
160
0
2,000
4,000
6,000
8,000
10,000
2010 2011 2012 2013 2014 2015
Wel
ls o
n Fi
rst S
ales
Late
ral L
engt
h (F
eet)
Increasing Lateral Lengths
Average Lateral Length (Feet) Wells on First Sales
37 36 34 32 29 24
13,181 14,067 14,658 14,607 15,355 15,623
-
4,000
8,000
12,000
16,000
20,000
0
10
20
30
40
50
2010 2011 2012 2013 2014 2015
Tota
l Mea
sure
d D
epth
Spud
-to-R
ig R
elea
se D
ays
Increasing Drilling Efficiency
Avg Spud-to-RR Days Total Measured Depth (Feet)
Note: Antero acreage position reflects townships in which greater than 3,000 net acres are held. Antero 30-day rates in ethane rejection.1. 30-day rate reflects restricted choke regime.
100% operated Operating 3 drilling rigs 147,000 net acres in the core rich gas/
condensate window (73% includes processable rich gas assuming an 1100 Btu cutoff)– 28% HBP with additional 61% not expiring
for 5+ years 93 operated horizontal wells completed and
online in Antero core areas− 100% drilling success rate
4 plants in-service at Seneca Processing Complex capable of processing 800 MMcf/d of rich gas− Over 500 MMcf/d being processed currently,
including third party production Net production of 446 MMcfe/d in 4Q 2015
including 21,000 Bbl/d of liquids Fifth third-party compressor station went in-
service September 2015 with a capacity of 120 MMcf/d
First AM compressor station went in-service November 2015
814 future gross drilling locations (551 or 68% are processable gas)
7.5 Tcfe of net 3P (15% liquids), includes 1.8 Tcfe of proved reserves (assuming ethane rejection)
WORLD CLASS OHIO UTICA SHALEDEVELOPMENT PROJECT
29
CadizProcessing
Plant
NORMAN UNIT30-Day Rate
2 wells average16.8 MMcfe/d (15% liquids)
RUBEL UNIT30-Day Rate
3 wells average17.2 MMcfe/d(20% liquids)
Utica Core Area
GARY UNIT30-Day Rate
3 wells average24.2 MMcfe/d(21% liquids)
Highly-Rich/Cond29,000 Net Acres
98 Gross Locations
Highly-Rich Gas11,000 Net Acres
108 Gross Locations
Rich Gas30,000 Net Acres
161 Gross Locations
Dry Gas41,000 Net Acres
263 Gross Locations
NEUHART UNIT 3H30-Day Rate16.2 MMcfe/d(57% liquids)
Condensate36,000 Net Acres
184 Gross Locations
DOLLISON UNIT 1H30-Day Rate19.8 MMcfe/d(40% liquids)
MYRON UNIT 1H30-Day Rate26.8 MMcfe/d(52% liquids)
SenecaProcessingComplex
LAW UNIT30-Day Rate
2 wells average16.1 MMcfe/d(50% liquids)
SCHAFER UNIT30-Day Rate(1)
2 wells average14.2 MMcfe/d(49% liquids)
URBAN PAD30-Day Rate
4 wells average 18.8 MMcfe/d (15% liquids)
GRAVES UNIT500’ Density Pilot
30-Day Rate4 wells average15.5 MMcfe/d(24% liquids)
FRANKLIN UNIT30-Day Rate
3 wells average17.6 MMcfe/d(16% liquids)
FRAKES UNIT30-Day Rate
2 wells average18.6 MMcfe/d(42% liquids)
1.4 1.6 1.6
$1.64
$1.24
$1.05
$0.00
$0.30
$0.60
$0.90
$1.20
$1.50
$1.80
0.00
0.50
1.00
1.50
2.00
2013 2014 2015
Dev
elop
men
t Cos
t ($/
Mcf
e)
EUR
/1,0
00' L
ater
al
EUR vs. Development Cost Per Unit
EUR/1,000' Lateral (Bcfe) Development Cost ($/Mcfe) 30
OHIO UTICA WELL PERFORMANCE IMPROVEMENTS Increasing recoveries and efficiencies through longer laterals, shorter stage lengths and faster drilling Lower service costs and efficiencies, and focus on liquids-rich locations, driving further development cost reductions in 2016
6,431
8,021 8,662
11
41
57
0
10
20
30
40
50
60
70
0
2,000
4,000
6,000
8,000
10,000
2013 2014 2015
Wel
ls o
n Fi
rst S
ales
Late
ral L
engt
h (F
eet)
Increasing Lateral Lengths
Average Lateral Length Wells on First Sales
289
183 175 26
47 49
-
10
20
30
40
50
60
-
50
100
150
200
250
300
350
2013 2014 2015
Ave
rage
Fra
c St
ages
per
Wel
l
Ave
rage
Sta
ge L
engt
h (F
eet)
Increasing Frac Stages per Well
Average Stage Length (Feet) Average Frac Stages per Well
32 29 31
14,643 16,321 17,169
-
3,000
6,000
9,000
12,000
15,000
18,000
0
10
20
30
40
2013 2014 2015
Tota
l Mea
sure
d D
epth
(Fee
t)
Spud
-to-R
ig R
elea
se D
ays
Increasing Drilling Efficiency
Spud-to-RR Days Total Measured Depth (Feet)
LARGE UTICA SHALE DRY GAS POSITION
31
Antero has completed its first dry gas Utica well – a 6,620’ lateral in Tyler County, WV
Antero has 229,000 net acres of exposure to Utica dry gas play in OH, WV and PA
Other operators have reported strong Utica Shale dry gas results including the following wells:
ChesapeakeHubbard BRK #3H
3,550’ LateralIP 11.1 MMcf/d
HessPorterfield 1H-17
5,000’ LateralIP 17.2 MMcf/d
GulfportIrons #1-4H5,714’ Lateral
IP 30.3 MMcf/d
EclipseTippens #6H5,858’ Lateral
IP 23.2 MMcf/d
Magnum HunterStalder #3UH5,050’ Lateral
IP 32.5 MMcf/d
Well Operator24-hr IP(MMcf/d)
LateralLength
(Ft)
24-hr IP/1,000’Lateral
(MMcf/d)
Scotts Run EQT 72.9 3,221 22.633
Gaut 4IH CNX 61.0 5,840 11.131
CSC #11H RRC 59.0 5,420 10.886
Stewart-Win 1300U MHR 46.5 5,289 8.792
Bigfoot 9H RICE 41.7 6,957 5.994
Blank U-7H GST 36.8 6,617 5.561
Stalder #3UH MHR 32.5 5,050 6.436
Irons #1-4H GPOR 30.3 5,714 5.303
Pribble 6HU SGY 30.0 3,605 8.322
Simms U-5H GST 29.4 4,447 6.611
Conner 6H CVX 25.0 6,451 3.875
Messenger 3H SWN 25.0 5,889 4.245
Tippens #6H ECR 23.2 5,858 3.960
Porterfield 1H-17 HESS 17.2 5,000 3.440
1. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held in OH, WV and PA.2. Stewart-Winland well is most proximate Utica test to Antero’s Tyler County, WV well which is currently being completed.3. The Rymer 4HD has been flowing into the sales line for 20 days with an average choke-restricted flow rate of 20 MMcf/d.
Magnum HunterStewart Winland 1300U
5,289’ LateralIP 46.5 MMcf/d
RangeClaysville SC #11H
5,420’ LateralIP 59.0 MMcf/d
ChevronConner 6H
6,451’ LateralIP 25.0 MMcf/dGastar
Simms U-5H4,447’ Lateral
IP 29.4 MMcf/d
Utica Shale Dry Gas Acreage in OH/WV/PA(1)
RiceBigfoot 9H
6,957’ LateralIP 41.7 MMcf/d
AR Utica Shale Dry GasWV/PA
Net Resource12.5 to 16 Tcf
1,889 Gross Locations188,000 Net Acres
AR Utica Shale Dry GasOhio
3P Reserves2.3 Tcf
263 Gross Locations41,000 Net Acres
AR Utica Shale Dry GasTotal OH/WV/PA
Net Resource14.8 to 18.3 Tcf
2,152 Gross Locations229,000 Net Acres
Stone EnergyPribble 6HU
3,605’ LateralIP 30.0 MMcf/d
SouthwesternMessenger 3H5,889’ Lateral
IP 25.0 MMcf/d
RiceBlue Thunder
10H, 12H≈9,000’ Lateral
GastarBlake U-7H
6,617’ LateralIP 36.8 MMcf/d
EQTScotts Run
3,221’ LateralIP 72.9 MMcf/d
CNXGaut 4IH
5,840’ LateralIP 61.0 MMcf/d
(2)
AnteroRymer 4HD
6,620’ LateralIP 20.0 MMcf/d
(3)
ANTERO’S FIRST UTICA DRY GAS WELL
32
Antero recently drilled and completed its first dry gas Utica well in Tyler County, WV (Rymer 4HD)− 11,409 Total Vertical Depth (TVD)− 6,620’ lateral length− 100% working interest − 20 MMcf/d restricted flow rate
Dry gas fairway extends from the Antero Utica acreage in eastern Ohio to the Antero Marcellus play acreage in northern West Virginia
188,000 net acres in West Virginia and Pennsylvania with net resource of 12.5 to 16 Tcf as of 9/30/2015 (not included in 37.1 Tcfe of net 3P reserves as of 12/31/2015)− 1,889 locations underlying current Marcellus Shale leasehold in
West Virginia and Pennsylvania
41,000 net acres in Ohio with net 3P reserves of 2.3 Tcf as of 12/31/2015− 263 locations in Ohio
In total, Antero has 229,000 net acres and 2,152 potential locations in the Point Pleasant high pressure, high porosity dry gas fairway in OH, WV and PA− 10,000’ to 14,500’ TVD−Density log porosity values average > 8.5% − 120’ to 130’ total thickness− 25 MMcf/d to 73 MMcf/d industry 24-hr IP flow rates− 1000 to 1040 BTU expected
NOTE: Wellbore diagram for illustrative purposes only.
Targeted Pay Zone
IP / 1,000’ Lateral (MMcf/d)
5.0 – 10.0
10.0 – 15.0
15.0 – 25.0
GulfportIrons #1-4H
5,714’ LateralIP/1,000’: 5.3 MMcf/d
RangeClaysville SC #11H
5,420’ LateralIP/1,000’: 10.9 MMcf/d
CNXGaut 4IH
5,840’ LateralIP/1,000’: 10.4 MMcf/d
EQTScotts Run
3,221’ LateralIP/1,000’: 22.6 MMcf/d
GastarBlake U-7H
6,617’ LateralIP/1,000’: 5.6 MMcf/d
GastarSims U-5H
4,447’ LateralIP/1,000’: 6.6 MMcf/d
Stone EnergyPribble 6HU
3,605’ LateralIP/1,000’: 8.3 MMcf/d
Magnum HunterStalder #3UH5,050’ Lateral
IP/1,000’: 6.4 MMcf/d
Magnum HunterStewart Winland 1300U
5,280’ LateralIP/1,000’: 8.8 MMcf/d
Utica Dry Gas Fairway
AnteroRymer 4HD
6,620’ LateralIP 20.0 MMcf/d
-
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
3,500,000
4,000,000
4,500,000
5,000,000
5,500,000
FIRM TRANSPORTATION AND FIRM SALES PORTFOLIO
33
MMBtu/d
Columbia7/26/2009 – 9/30/2025
Firm Sales #110/1/2011– 10/31/2019
Firm Sales #210/1/2011 – 11/30/2015
Firm Sales #31/1/2013 – 5/31/2022
Momentum III9/1/2012 – 12/31/2023
EQT8/1/2012 – 6/30/2025
REX/MGT/ANR7/1/2014 – 12/31/2034
Tennessee11/1/2015– 9/30/2030
(Stonewall/WB) Mid-Atlantic/NYMEX
(Stonewall/TGP) Gulf Coast
(TCO) Appalachia or Gulf Coast
AppalachiaAppalachia
ANR3/1/2015– 2/28/2045
(REX/ANR/NGPL/MGT) Midwest
Local Distribution11/1/2015 – 9/30/2037
(ANR/Rover) Gulf Coast
Antero Transportation Portfolio
1,280 BBtu/d
790 BBtu/d
375 BBtu/d
250 BBtu/d
800 BBtu/d
600 BBtu/d
630 BBtu/d
40 BBtu/d
Gross gas production would fill Antero’s market leading firm transportation / sales portfolio by 2019 (excluding unfavorable
Appalachia based firm transport) (1)
Gross Gas Production (Actuals) Illustrative Gross Gas Production (25% Annual Growth CAGR Assumed) (1)
1. Assumes midpoint of preliminary production growth target of 25% to 30% in 2016 and targeted 25% annual production growth CAGR through 2020.
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.
District office in Marietta, OH District office in Bridgeport, WV 227 (48%) of Antero’s 473 employees are located in West Virginia and Ohio
Safety & Environmental
Five company safety representatives and 57 safety consultants cover all material field operations 24/7 including drilling, completion, construction and pipelining
37 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 74% of its flowback and produced water through 2014 Building state of the art wastewater treatment facility in WV (60,000 Bbl/d)
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
8 of Antero’s contracted drilling rigs are currently running on natural gas First natural gas powered clean fleet frac crew began operations summer 2014
Green Completion Units All Antero well completions use green completion units for completion flowback,
essentially eliminating methane emissions (full compliance with EPA 2015requirements)
LEED Gold Headquarters Building Corporate headquarters in Denver, Colorado LEED Gold Certified
HEALTH, SAFETY, ENVIRONMENT & COMMUNITYAntero Core Values: Protect Our People, Communities And The Environment
Strong West Virginia Presence 79% of all Antero Marcellus
employees and contract workers are West Virginia residents
Antero named Business of the Year for 2013 in Harrison County, West Virginia “For outstanding corporate citizenship and community involvement”
Antero representatives recently participated in a ribbon cutting with the Governor of West Virginia for the grand opening of the first natural gas fueling station in the state; Antero supported the station with volume commitments for its NGV truck fleet
34
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 truckloads 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
35
Regional Gas Pipelines
Miles Capacity In-Service
Stonewall Gathering Pipeline(2)
50 1.4 Bcf/d Yes
1. Acquired by AM from AR for a $1.05 billion upfront payment and a $125 million earn out in each of 2019 and 2020. 2. AM holds option to purchase 15% of Stonewall pipeline at cost plus cost of carry.
EndUsers
EndUsers
Gas Processing
Y-Grade Pipeline
Long-Haul Interstate
Pipeline
InterConnect
NGL Product Pipelines
Fractionation
Compression
Low Pressure Gathering
Well Pad
Terminalsand
Storage
(Miles) YE 2014 YE 2015E
Marcellus 91 108
Utica 45 56
Total 136 164
AM has option to participate in processing, fractionation,
terminaling and storage projects offered to AR
(Miles) YE 2014 YE 2015E
Marcellus 62 76
Utica 35 36
Total 97 112
(MMcf/d) YE 2014 YE 2015E
Marcellus 375 800
Utica 0 120
Total 375 920
AM Owned Assets
Condensate GatheringStabilization
(Miles) YE 2014 YE 2015E
Utica 16 19
EndUsers
AM Option Assets
(Ethane, Propane, Butane, etc.)
AM’S FULL VALUE CHAIN BUSINESS MODEL
Water Drop Down
37
1. Represents inception to date actuals as of 12/31/2014 and 2015 midpoint guidance.2. Includes water drop down and $15.0 million of maintenance capex at 2015 midpoint guidance.
38
UticaShale
MarcellusShale
Projected Midstream Infrastructure(1)
Marcellus Shale
Utica Shale Total
YE 2014 Cumulative Gathering/ Compression Capex ($MM) $836 $345 $1,181
Gathering Pipelines(Miles) 153 80 233
Compression Capacity(MMcf/d) 375 - 375
Condensate Gathering Pipelines (Miles) - 16 16
2015E Capex Budget ($MM)(2) $256 $182 $438Gathering Pipelines
(Miles) 31 12 43
Compression Capacity(MMcf/d) 425 120 545
Condensate Gathering Pipelines (Miles) - 3 3
Midstream Assets
ANTERO MIDSTREAM ASSET OVERVIEW
• Gathering and compression assets in core of rapidly growing Marcellus and Utica Shale plays
– Acreage dedication of ~434,000 net leasehold acres for gathering and compression services
– Additional stacked pay potential with dedication on ~147,000 acres of Utica deep rights underlying the Marcellus in WV and PA
– 100% fixed fee long term contracts
• AR owns 67% of AM units (NYSE: AM)
ANTERO INTEGRATED WATER BUSINESS
39
Marcellus Fresh Water System(2)
• Provides fresh water to support Marcellus well completions • Year-round water supply sources: Ohio River and local rivers• Ozone Water treatment facility expected in-service January 2016• Significant asset growth in 2015 as summarized below:
Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.1. Represents inception to date actuals as of 9/30/2015 and 2015 guidance.2. All Antero water withdrawal sites are fully permitted under long-term state regulatory permits both in WV and OH. 3. Assumes fee of $3.685 per barrel subject to annual inflation and 250,000 barrels of water per well that utilize the fresh water delivery system based on 9,000 foot lateral. Operating margin excludes G&A.4. Assumes fee of $3.635 per barrel subject to annual inflation and 275,000 barrels of water per well that utilize the fresh water delivery system based on 9,000 foot lateral. Operating margin excludes G&A.
Utica Fresh Water System(2)
• Provides fresh water to support Utica well completions • Year-round water supply sources: local reservoirs and rivers• Significant asset growth in 2015 as summarized below:
Marcellus Water System YE 2014 YE 2015E
Water Pipeline (Miles) 177 226
Fresh Water Storage Impoundments 22 24
Cash Operating Margin per Well ($)(3) $700K -$750K
Utica Water System YE 2014 YE 2015E
Water Pipeline (Miles) 61 90
Fresh Water Storage Impoundments 8 14
Cash Operating Margin per Well ($)(4) $775K -$825K
Projected Fresh Water Delivery Infrastructure(1)
Marcellus Shale
Utica Shale Total
YE 2015E Cumulative Water System Capex ($MM) $340 $113 $453Water Pipelines (Miles) 226 90 316Water Storage Facilities 24 14 38
AM acquired AR’s integrated water business for $1.05 billion plus earn out payments of $125 million at year-end in each of 2019 and 2020− The acquired business includes Antero’s Marcellus and Utica freshwater delivery business, the fully-contracted future advanced wastewater
treatment complex and all fluid handling and disposal services for Antero
Antero advanced wastewater treatment facility to be constructed – connects to Antero
freshwater delivery system
010,00020,00030,00040,00050,00060,00070,00080,000
Antero Clearwater Advanced Wastewater Treatment Capacity (Bbl/d)
Produced/Flowback Volumes (Bbl/d)
ADVANCED WASTEWATER TREATMENT
Illustrative Produced & Flowback Water VolumesAdvanced Wastewater Treatment
Antero Produced Water Services and Freshwater Delivery Business
Antero AdvancedWastewater Treatment
3rd Party Recyclingand Well Disposal
(Bbl/d)
Advanced Wastewater Treatment ComplexEstimated capital expenditures ($ million)(1) ~$275Standalone EBITDA at 100% utilization(2) ~$55 – $65Implied investment to standalone EBITDA build-out multiple ~4x – 5xEstimated per well savings to Antero Resources ~$150,000Estimated in-service date Late 2017Operating capacity (Bbl/d) 60,000Operating agreement
• Antero has contracted with Veolia to integrate an advanced wastewater treatment complex into its water business
• Veolia will build and operate, and Antero will own largest advanced wastewater treatment complex in Appalachia− Will treat and recycle AR produced and flowback water− Creates additional year-round water source for completions− Will have capacity for third party business over first two years
1. Includes capital to construct pipeline to connect facility to freshwater delivery system. Includes $10 million that AR agreed to fund in the drop down transaction. 2. Standalone EBITDA projection assumes inter-company fixed fee for recycling of $4.00 per barrel and 60,000 barrels per day of capacity. Does not include potential sales of marketable byproducts.
20 Years, Extendable
40Integrated Water Business
Antero Advanced Wastewater Treatment
Freshwater delivery system
Flowback and produced
Water
Well Pad
Well Pad
CompletionOperations
Producing
Freshwater
Salt
Calcium Chloride
Marketable byproduct
Marketable byproduct used in oil and gas operations
Freshwater delivery system
26 31 40 36 41 116
222
358
454 435478
0
100
200
300
400
500
600
700
800 Utica Marcellus
10 38 80 126 266
531
908
1,134 1,197 1,216 1,195
0200400600800
1,0001,2001,4001,6001,800 Utica Marcellus
108 216 281 331 386
531 738
935 965 1,038 1,124
0200400600800
1,0001,2001,4001,6001,800 Utica Marcellus
$1$5 $7 $8 $11
$19
$28
$36$41
$55
$0
$10
$20
$30
$40
$50
$60
Low Pressure Gathering (MMcf/d)
Compression (MMcf/d)
High Pressure Gathering (MMcf/d)
EBITDA ($MM)(1)
41
$185
HIGH GROWTH MIDSTREAM THROUGHPUT
Note: Y-O-Y growth based on 4Q’14 to 4Q’15. 1. 2015E EBITDA guidance updated per 10/13/2015 Partnership press release based on 10/1/2015 effective date for water drop down. Y-O-Y growth based on 3Q’14 to 3Q’15.
0.0x
1.0x
2.0x
3.0x
4.0x
5.0x
6.0x
Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8
Tota
l Deb
t / L
QA
EB
ITD
A
• $1.5 billion revolver in place to fund future growth capital (5x Debt/EBITDA Cap)
• Liquidity of $993 million at 9/30/2015
• Sponsor (NYSE: AR) has Ba2/BB corporate ratings
AM Liquidity (9/30/2015)
AM Peer Leverage Comparison(1)
($ in millions)
Revolver Capacity $1,500
Less: Borrowings 525
Plus: Cash 18
Liquidity $993
1. As of 9/30/2015. Peers include TEP, EQM, MWE, WES, RMP, SHLX, DM, and CNNX.2. AM pro forma for water drop down; LQA EBITDA for water based on 2016E midpoint of 8.5x – 9.0x purchase price multiple announced.
Financial Flexibility
SIGNIFICANT FINANCIAL FLEXIBILITY
42
(2)
($ in millions) 9/30/2015 Cash $27
Senior Secured Revolving Credit Facility 500Midstream Bank Credit Facility 5256.00% Senior Notes Due 2020 5255.375% Senior Notes Due 2021 1,0005.125% Senior Notes Due 2022 1,1005.625% Senior Notes Due 2023 750Net Unamortized Premium 7Total Debt $4,407Net Debt $4,380
Financial & Operating StatisticsLTM EBITDAX(1) $1,246LTM Interest Expense(2) $219Proved Reserves (Bcfe) (12/31/2015) 13,215
Proved Developed Reserves (Bcfe) (12/31/2015) 5,838
Credit Statistics
Net Debt / LTM EBITDAX 3.5xNet Debt / Net Book Capitalization 38%Net Debt / Proved Developed Reserves ($/Mcfe) $0.75Net Debt / Proved Reserves ($/Mcfe) $0.33
LiquidityCredit Facility Commitments(3) $5,500Less: Borrowings (1,025)Less: Letters of Credit (535)Plus: Cash 27
Liquidity (Credit Facility + Cash) $3,968
ANTERO CAPITALIZATION – CONSOLIDATED
1. LTM and 9/30/2015 EBITDAX reconciliation provided on page 65.2. LTM interest expense adjusted for all capital market transactions since 1/1/2014.3. AR lender commitments under the facility increased to $4.0 billion from $3.0 billion on 2/17/2015; borrowing base capacity increased to $4.5 billion from $4.0 billion on 10/26/2015. AM credit facility
increased to $1.5 billion concurrent with water drop down on 9/23/2015.44
ANTERO RESOURCES – UPDATED 2015 GUIDANCE
Key Variable 2015 GuidanceNet Daily Production (MMcfe/d) 1,400
Net Residue Natural Gas Production (MMcf/d) 1,175
Net Liquids Production (Bbl/d) 33,000
Net Oil Production (Bbl/d) 4,000
Natural Gas Realized Price Differential to NYMEX Henry Hub Before Hedging ($/Mcf) $(0.20) - $(0.30)
Oil Realized Price Differential to NYMEX WTI Before Hedging ($/Bbl) $(12.00) - $(14.00)
NGL Realized Price (% of WTI) 30% - 35%
Cash Production Expense ($/Mcfe)(1) $1.50 - $1.60
Marketing Expense, Net of Marketing Revenue ($/Mcfe) $0.20 - $0.30
G&A Expense ($/Mcfe) $0.23 - $0.27
Net Income Attributable to Non-Controlling Interest ($MM) $23 - $27
Operated Wells Completed 130
Average Operated Drilling Rigs 14
Capital Expenditures ($MM)
Drilling & Completion $1,600
Water Infrastructure $50
Land $150
Total Capital Expenditures ($MM) $1,800
1. Includes lease operating expenses, gathering, compression and transportation expenses and production taxes. Excludes net marketing expense.
Key Operating & Financial Assumptions
45
ANTERO MIDSTREAM – 2015 GUIDANCE
Key Variable Initial Guidance(1) Updated Guidance(2)
Adjusted EBITDA ($MM) $150 - $160 $180 - $190
Distributable Cash Flow ($MM) $135 - $145 $160 - $170
Year-over-Year Distribution Growth(3) 28% - 30% 28% - 30%
Low Pressure Pipelines Added (Miles) 44 27
High Pressure Pipelines Added (Miles) 20 15
Compression Capacity Added (MMcf/d) 545 545
Capital Expenditures ($MM)
Low Pressure Gathering $165 - $170 $90 - $95
High Pressure Gathering $85 - $90 $70 - $75
Compression $160 - $165 $165 - $170
Condensate Gathering $5 - $10 $5
Water Infrastructure(4) - $80 - $90
Maintenance Capital $10 - $15 $15
Total Capital Expenditures ($MM) $425 - $450 $425 - $4501. Financial guidance per Partnership press release dated 1/20/2015.2. Updated financial guidance per Partnership press release dated 10/13/2015. 3. Reflects the expected distribution growth associated with the fourth quarter 2015 over the fourth quarter 2014.4. Includes fresh water delivery system plus waste water treatment capital expenditures.
Key Operating & Financial Assumptions
46
$2,477$197
$841
Drilling & Completion Water Infrastructure Land
65%
35%
Marcellus Utica
2015 CAPITAL BUDGET
By Area
47
$3.5 Billion - 2014By Segment ($MM)
$1,600
$50 $150
Drilling & Completion Water Infrastructure Land
59%41%
Marcellus Utica
By Area
$1.8 Billion – 2015By Segment ($MM)
Antero’s 2015 capital budget is $1.8 billion, a 49% decrease from 2014 capital expenditures of $3.5 billion
49%
177 Completions 130 Completions
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
2015 2015 2016 2016 2017
Gas
Pric
e $/
MM
Btu
Completion Deferral Impact on Realized Gas Price
TETCO CGTLA
TETCO Cal 2015:$1.88/MMBtu
CGTLA Cal 2016: $3.27/MMBtu
BTAX IRR:57%
48
Plan to defer 50 Marcellus well completions into 2016 to achieve higher gas price realizations− Stonewall gathering pipeline placed on line 12/1/2015 connects incremental Marcellus production to CGTLA (Gulf Coast) and
TCO pricing− Results in estimated pre-tax IRR of 57% vs. 39% from 2015 TETCO pricing in first year, excluding sunk drilling costs
COMPLETION DEFERRALS – OPTIMIZING PRICING
0
50
100
150
200
250
300
350
400
450
500
Jan-16 Mar-16 May-16
Gro
ss W
ellh
ead
Prod
uctio
n (M
Mcf
/d)
Completion Deferral Impact on 2016 Production
Production From 50 Deferred
Completions
+$1.39/MMBtu Pickupin Price =
18% BTAX IRR Increase
BTAX IRR:39%
OUTSTANDING RESERVE GROWTH
1. 2012, 2013, 2014 and 2015 reserves assuming ethane rejection. 2015 SEC prices were $2.56/MMBtu for natural gas and $50.13/Bbl for oil on a weighted average Appalachian index basis.49
3P RESERVES BY VOLUME – 2015(1)3P RESERVE GROWTH(1)
25.0 28.4 29.6
5.87.6 7.54.24.6
05
1015202530354045
2013 2014 2015
(Tcfe)
Marcellus Utica Upper Devonian
NET PROVED RESERVES (Tcfe)(1) 2015 RESERVE ADDITIONS
35.040.7
• Proved reserves increased 4% to 13.2 Tcfe at 12/31/2015 with a PV-10 of $6.7 billion, including $3.1 billion of hedges
• 3P reserves were 37.1 Tcfe at 12/31/2015 with a PV-10 of $6.8 billion, including $3.1 billion of hedges
• All-in finding and development cost of $0.80/Mcfe for 2015 (includes land and all price and performance revisions)
• Drill bit only development cost of $0.71/Mcfe for 2015
• Only 69% of 3P Marcellus locations booked as SSL (1.7 Bcf/1,000’ type curve) at 12/31/2015
• Negligible Utica Shale WV/PA dry gas reserves booked –estimated net resource of 12.5 – 16 Tcf
0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
2010 2011 2012 2013 2014 2015
Marcellus Utica
0.7
2.84.3
7.6
12.7
(Tcfe)
13.2
37.113.2 TcfeProved
21.4 TcfeProbable
2.5 TcfePossible
Proved
Probable
Possible
37.1 Tcfe 3P
93% 2P Reserves
Gas – 27.6 Tcf
Oil – 92 MMBbls
NGLs – 2,382 MMBbls
Gas – 29.7 Tcf
Oil – 92 MMBbls
NGLs – 1,145 MMBbls
CONSIDERABLE RESERVE BASE WITH ETHANE OPTIONALITY 27 year proved reserve life based on 2015 production annualized Reserve base provides significant exposure to liquids-rich projects
– 3P reserves of over 2.4 BBbl of NGLs and condensate in ethane recovery mode; 35% 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.
2. 1.1 Tcfe of ethane reserves (182 million barrels) was included in 12/31/2015 reserves from the Marcellus Shale as the first de-ethanizer was placed online at the MarkWest Sherwood facility in December 2015 and Antero’s first ethane sales contract is expected to commence in 2017 upon the completion of Mariner East 2.
ETHANE REJECTION(1)(2) ETHANE RECOVERY(1)
50
Marcellus – 29.6 Tcfe
Utica – 7.5 Tcfe
Upper Devonian – 0.0 Tcfe
37.1Tcfe
Marcellus – 34.0 Tcfe
Utica – 8.4 Tcfe
Upper Devonian – 0.0 Tcfe
42.4Tcfe
20%Liquids
35%Liquids
626
971
553755
63%47%
24% 28%34%
22%9% 11% 0
2004006008001,0001,200
0%
20%
40%
60%
80%
Highly-Rich Gas/Condensate
Highly-Rich Gas Rich Gas Dry Gas
Tota
l 3P
Loca
tions
RO
RTotal 3P LocationsROR @ 12/31/2015 Strip Pricing - After HedgesROR @ 12/31/2015 Strip Pricing - Before Hedges
MARCELLUS SINGLE WELL ECONOMICS – IN ETHANE REJECTION
51
DRY GAS LOCATIONS RICH GAS LOCATIONS
HIGHLY RICH GAS
LOCATIONS
Assumptions Natural Gas – 12/31/2015 strip Oil – 12/31/2015 strip NGLs – 37% of Oil Price 2016; 50% of
Oil Price 2017+
NYMEX($/MMBtu)
WTI($/Bbl)
C3+ NGL(2)
($/Bbl)
2016 $2.50 $41 $15
2017 $2.79 $46 $23
2018 $2.91 $49 $25
2019 $3.03 $52 $26
2020 $3.18 $54 $27
2021-25 $3.31-$3.88 $55-$56 $27-$28
Marcellus Well Economics and Total Gross Locations(1)
ClassificationHighly-Rich Gas/
CondensateHighly-Rich
Gas Rich Gas Dry GasModeled BTU 1313 1250 1150 1050EUR (Bcfe): 20.8 18.8 16.8 15.3EUR (MMBoe): 3.5 3.1 2.8 2.6% Liquids: 33% 24% 12% 0%Lateral Length (ft): 9,000 9,000 9,000 9,000Well Cost ($MM): $9.1 $9.1 $9.1 $9.1Bcfe/1,000’: 2.3 2.1 1.9 1.7Net F&D ($/Mcfe): $0.52 $0.57 $0.64 $0.70Direct Operating Expense ($/well/month): $1,498 $1,498 $1,498 $1,498Direct Operating Expense ($/Mcf): $0.92 $0.92 $1.17 $0.70Transportation Expense ($/Mcf): $0.28 $0.28 $0.28 $0.28
Pre-Tax NPV10 ($MM): $8.9 $5.1 ($0.7) $0.2Pre-Tax ROR: 34% 22% 9% 11%Payout (Years): 2.0 2.8 6.5 5.5
Gross 3P Locations(3): 626 971 553 7551. 12/31/2015 pre-tax well economics based on a 9,000’ lateral, 12/31/2015 natural gas and WTI strip pricing for 2016-2025, flat thereafter, NGLs at 37.5% of WTI for 2016 and 50% of WTI thereafter,
and applicable firm transportation and operating costs including 50% of Antero Midstream fees. Well cost estimates, which include $1.2 million for road, pad and production facilities, assume Antero will begin to realize lower well costs in 2016 as the company utilizes incremental completion crews for deferred completions beginning at year end 2015 and as existing drilling rig contracts begin to roll off during 2016.
2. Pricing for a 1225 BTU y-grade ethane rejection barrel. NGLs at 37.5% of WTI for 2016 and 50% of WTI for 2017 and thereafter. NGL prices are forecast to increase in 2017 relative to WTI due to projected in-service date of Mariner East 2 project allowing for a significant increase in AR NGL exports via ship.
3. Undeveloped well locations as of 12/31/2015.
2016Drilling
Plan
184
98108
161 263
16%
57%
83%71%
80%
10%
27% 29%23% 26%
050100150200250300
0%
20%
40%
60%
80%
100%
Condensate Highly-Rich Gas/Condensate
Highly-Rich Gas Rich Gas Dry Gas
Tota
l 3P
Loca
tions
RO
R
Total 3P LocationsROR @ 12/31/2015 Strip Pricing - After HedgesROR @ 12/31/2015 Strip Pricing - Before Hedges
UTICA SINGLE WELL ECONOMICS – IN ETHANE REJECTION
52
DRY GAS LOCATIONS RICH GAS LOCATIONS
HIGHLY RICH GAS
LOCATIONS
Utica Well Economics and Gross Locations(1)
Classification CondensateHighly-Rich Gas/
CondensateHighly-Rich
Gas Rich Gas Dry GasModeled BTU 1275 1235 1215 1175 1050EUR (Bcfe): 9.4 17.0 25.3 23.8 21.4EUR (MMBoe): 1.6 2.8 4.2 4.0 3.6% Liquids 35% 26% 21% 14% 0%Lateral Length (ft): 9,000 9,000 9,000 9,000 9,000Well Cost ($MM): $10.2 $10.2 $10.2 $10.2 $10.2Bcfe/1,000’: 1.0 1.9 2.8 2.7 2.4Net F&D ($/Mcfe): $1.34 $0.74 $0.50 $0.53 $0.59Fixed Operating Expense ($/well/month): $2,788 $2,788 $2,788 $2,788 $1,498Direct Operating Expense ($/Mcf): $0.99 $0.99 $0.99 $0.99 $0.50Direct Operating Expense ($/Bbl): $2.73 $2.73 $2.73 - -Transportation Expense ($/Mcf): $0.55 $0.55 $0.55 $0.55 $0.55
Pre-Tax NPV10 ($MM): $0.0 $5.8 $7.6 $5.6 $6.4Pre-Tax ROR: 10% 27% 29% 23% 26%Payout (Years): 7.8 3.1 2.9 3.7 3.2
Gross 3P Locations(3): 184 98 108 161 2631. 12/31/2015 pre-tax well economics based on a 9,000’ lateral, 12/31/2015 natural gas and WTI strip pricing for 2016-2025, flat thereafter, NGLs at 37.5% of WTI for 2016 and 50% of WTI thereafter,
and applicable firm transportation and operating costs including 50% of Antero Midstream fees. Well cost estimates, which include $1.2 million for road, pad and production facilities, assume Antero will begin to realize lower well costs in 2016 as the company utilizes incremental completion crews for deferred completions beginning at year end 2015 and as existing drilling rig contracts begin to roll off during 2016.
2. Pricing for a 1225 BTU y-grade ethane rejection barrel. NGLs at 37.5% of WTI for 2016 and 50% of WTI for 2017 and thereafter. NGL prices are forecast to increase in 2017 relative to WTI due to projected in-service date of Mariner East 2 project allowing for a significant increase in AR NGL exports via ship.
3. Undeveloped well locations as of 12/31/2015. 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content.
2016Drilling
Plan
Assumptions Natural Gas – 12/31/2015 strip Oil – 12/31/2015 strip NGLs – 37% of Oil Price 2016; 50% of
Oil Price 2017+NYMEX
($/MMBtu)WTI
($/Bbl)C3+ NGL(2)
($/Bbl)
2016 $2.50 $41 $15
2017 $2.79 $46 $23
2018 $2.91 $49 $25
2019 $3.03 $52 $26
2020 $3.18 $54 $27
2021-25 $3.31-$3.88 $55-$56 $27-$28
$4
$8
$5$25 $34 $29 $28 $26 $12 $16 $17 $28 $29 $19 $25
$43
$80 $83$59 $49 $48
$14
$47 $54
$1
$1
$58$78
$185$196$206
($2.00)
($1.00)
$0.00
$1.00
$2.00
$3.00
$4.00
($20.0)
$30.0
$80.0
$130.0
$180.0
$230.0
Quarterly Realized Gains/(Losses)1Q '08 - 4Q '15
1,793 2,073 2,015 1,960 1,288 480 10
$3.94$3.57
$3.88 $3.89 $3.73 $3.50
$3.30$2.50 $2.79 $2.91 $3.03 $3.18 $3.31
$3.46
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
-
500
1,000
1,500
2,000
2,500
2016 2017 2018 2019 2020 2021 2022
53
Average Index Hedge Price(1)Hedged Volume Current NYMEX Strip(2)
COMMODITY HEDGE POSITION
~$3.1 billion mark-to-market unrealized gain based on 12/31/2015 prices 3.5 Tcfe hedged from January 1, 2016 through year-end 2022
$1,009 MM $572 MM $711 MM $567 MM $232 MM $26 MM
Mark-to-Market Value(2)
LARGEST GAS HEDGE POSITION IN U.S. E&P
~ 100% of 2016 Target Hedged
531. Weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio; excludes impact of TCO basis hedges. 3,000 Bbl/d of oil and 23,000 Bbl/d of propane hedged for 2015. 2. As of 12/31/2015.
Hedging is a key component of Antero’s business model due to the large, repeatable drilling inventory Antero has realized $1.7 billion of gains on commodity hedges since 2008
– Gains realized in 30 of last 32 quarters$MM
$/Mcfe
$0 MM
$0.14 $0.17 $0.23$0.33$0.11 $0.11
$0.12
$0.13
$0.00
$0.10
$0.20
$0.30
$0.40
$0.50
$0.60
$0.70
2013A 2014A 2015E 2016E
($/M
MB
tu)
Wtd. Avg. FT Demand ($/MMBtu) Wtd. Avg. FT Commodity/Fuel ($/MMBtu)
All-in Firm Transportation Costs(1)
FIRM TRANSPORTATION REDUCES APPALACHIAN BASIS EXPOSURE
Appalachia 49%Gulf Coast
51%
2013 FirmTransportation(1)(2)
2013 Firm Transportation – 647 MMcf/dAverage All-in FT Cost $0.25/MMBtu
2016 Firm Transportation – 3.5 Bcf/dAverage All-in FT Cost $0.46/MMBtu
+ $0.18/MMBtu
Antero’s firm transportation (FT) portfolio increases visibility on production growth and increases exposure to Gulf Coast and Midwest pricing, with little incremental cost per Mcf
Reduces weighted average basis by $0.35 per MMBtu compared to 2014 basis – while significantly reducing Appalachian basis exposure
Utilized portion included in cash production
expense(fixed cost)
1. Assumes full utilization of firm transportation capacity. 2. Represents accessible firm transportation and sales agreements.3. Based on current strip pricing as at 12/3012015.
Included in cash production expense
(variable cost)$0.25 $0.28 $0.35
$0.46
2016 Basis(3)
TCO – $(0.18)/MMBtu DOM S – $(0.94)/MMBtu
2016 Basis(3)
Chicago – $0.02/MMBtu
2016 Basis(3)
CGTLA – $(0.06)/MMBtu
54
Appalachia35%
Midwest20%
Gulf Coast45%
$525
$1,000 $1,100
$750
$0
$200
$400
$600
$800
$1,000
$1,200
2015 2016 2017 2018 2019 2020 2021 2022 2023
($ in
Mill
ions
)
$1,500
$993
($525)
$0 $18
$0
$250
$500
$750
$1,000
$1,250
$1,500
Credit Facility9/30/2015
Bank Debt9/30/2015
L/Cs Outstanding9/30/2015
Cash9/30/2015
Liquidity 9/30/2015
55
STRONG FINANCIAL LIQUIDITY AND DEBT TERM STRUCTURE
55
$4,000$2,975
($500)($535) $10
$0
$1,000
$2,000
$3,000
$4,000
Credit Facility9/30/2015
Bank Debt9/30/2015
L/Cs Outstanding9/30/2015
Cash9/30/2015
Liquidity9/30/2015
AR LIQUIDITY POSITION ($MM) AM LIQUIDITY POSITION ($MM)
Over $3.9 billion of combined AR and AM financial liquidity as of 9/30/2015 No leverage covenant in AR bank facility, only interest coverage and working capital covenants
AR Credit Facility AR Senior Notes
DEBT MATURITY PROFILE
Recent credit facility increases and equity offerings have allowed Antero to reduce its cost of debt to 4.4% and significantly enhance liquidity while the average debt maturity is April 2021
AM Credit Facility
Moody's S&P
POSITIVE RATINGS MOMENTUMMoody’s / S&P Historical Corporate Credit Ratings
“We could raise the ratings due to our assessment of an improvement inthe company's financial profile. An improvement in the financial profilewould include maintaining FFO to debt of greater than 45% andnarrowing the amount that the company outspends its cash flows by.”
- S&P Credit Research, September 2014
"The upgrade reflects Moody's expectation that Antero will continue toreport strong production growth and increasing reserves despitechallenging market conditions and without a significant increase inleverage. Antero's low finding and development costs and significantcommodity hedge position should allow the company to continue toprosper despite today's low commodity price environment.“
- Moody’s Credit Research, February 2015
Corporate Credit Rating (Moody’s / S&P)
Ba3 / BB-
B1 / B+
B2 / B
B3 / B-
2/24/2011 10/21/2013 9/4/20145/31/13
Ba2 / BB
Ba1 / BB+
Caa1 / CCC+
(1)
1. Represents corporate credit rating of Antero Resources Corporation / Antero Resources LLC.
Baa3 / BBB-
Moody’s Upgrade Rationale S&P Upgrade Criteria
56
3/31/2015
Ba2/BB
9/30/20159/1/2010
LNG Exports48%
Mexico/Canada Exports
18%
Power Generation
17%
Transportation1%
Industrial16%
20 BCF/D OF INCREMENTAL GAS DEMAND BY 2020 Significant demand growth expected for U.S.
natural gas
More than 65% of the 20 Bcf/d in incremental gas demand forecast by 2020 is expected to be generated from exports:− LNG: 9.5 Bcf/d (~48%)− Mexico/Canada: 3.5 Bcf/d (~18%)
Of the 9.5 Bcf/d of expected incremental demand from LNG export projects, 6.7 Bcf/d (or 70%) of the projects have secured the necessary DOE and FERC permits
57
Incremental Demand Growth Through 2020 by Category
Projected Incremental Natural Gas Demand Through 2020
Source: Simmons & Company International, “2015 US Natural Gas Outlook and Updated Long Term Demand Forecast,” September 2014.
Sherwood 7 2
5
9
13
17
20
0
4
8
12
16
20
2015 2016 2017 2018 2019 2020Mexico/Canada Exports Power GenerationTransportation PetrochemLNG Exports
9.5 Bcf/d of the 20 Bcf/d of incremental demand is expected to come from
LNG exports
(Bcf/d)
LNG
Exports
Power Gen
Petrochem
LNG Exports by Project(in Bcf/d)
2015 2016 2017 2018 2019 2020 TotalSabine Pass 1 - 0.6 - - - - Sabine Pass 2 - 0.6 - - - - Sabine Pass 3 - - 0.6 - - - Sabine Pass 4 - - 0.6 - - - Sabine Pass 5 - - - - 0.6 - 3.0 Cove Point 1 - - 0.4 - - - Cove Point 2 - - - 0.4 - - 0.8 Cameron 1 - - - 0.6 - - Cameron 2 - - - 0.6 - - Cameron 3 - - - - 0.6 - 1.8 Freeport 1 - - - 0.5 - - Freeport 2 - - - - 0.5 - Freeport 3 - - - - 0.5 - Freeport 4 - - - - - 0.4 2.1 Corpus Christi 1 - - - - 0.6 - Corpus Christi 2 - - - - - 0.6 1.2 Lake Charles 1 - - - - - 0.6 0.6
LNG Incremental Exports - 1.2 1.6 2.2 2.9 1.7LNG Cumulative Exports - 1.2 2.8 5.0 7.9 9.5
LNG EXPORTS BY PROJECT – EXPECTED START UP
Assuming 9.5 Bcf/d of LNG exports by 2020, the U.S. will 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
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 mid-2017− Antero has committed to 330 MMcf/d on Cove
Point 1 & 2
58
LNG Exports by Project Through 2020
Antero Supply Agreements for Portion of Capacity
Source: Simmons & Company International, “2015 US Natural Gas Outlook and Updated Long Term Demand Forecast,” September 2014. Note: Data updated for recent announcements subsequent to Simmons report.
Antero Supplied
GLOBAL LPG DEMAND DRIVEN BYPETCHEM AND RES/COMMLargest end-use sectors for LPG are residential/commercial, which tends to grow with population and improvement in
living standards in the emerging markets− PIRA forecasting >1.0 MMBbl/d over next 5 years and >4.5 MMBbl/d of global LPG demand growth over next 20 years
601. PIRA NGL Study, September 2015.
MMBbl/d14.7
13.0
11.4
9.8
8.2
6.5
4.9
3.3
1.6
GLOBAL LPG TRADE DRIVEN BY U.S. SHALEThe U.S. is the largest single driver of the rapid expansion in LPG trade accounting for over 90% in trade growth
611. PIRA NGL Study, September 2015.
MMBbl/d5.2
4.6
3.9
3.3
2.6
2.0
1.3
0.7
United States
U.S. SHALE NGL EURS SUPPORT LPG TRADE GROWTH
621. PIRA NGL Study, September 2015.
• U.S. shale play NGL reserves are 50.8 billion barrels
• Eagle Ford, Marcellus, Utica, Bakken and Permian are the work horses of U.S. shale production growth
• Marcellus/Utica NGL resource estimate by PIRA is 9.7 billion barrels, in line with Antero estimate of ≈ 11.1 billion barrels
• The growth curve of each basin will ultimately be a function of downstream solutions and investment
(1)
(1)(1)
POSITIVE OUTLOOK FOR LONG-TERM ETHANE MARKETS AS WELL
U.S. Ethane Supply/Demand Balance Through 2020(1)
1. Source: Bentek, August 2015.2. Source: Citi research dated 7/15/2015.
U.S. Ethane Exports Through 2020(2)
U.S. ethane demand is projected to increase at an annual 3.5% CAGR through 2020, primarily based on an ≈8% CAGR for U.S. petrochemdemand and a 30% growth in exports primarily to Europe− The growth in shipping exports in 2016 and 2017 is driven by Enterprise Products’ 200 MBbl/d export facility on the Gulf Coast
-
0.5
1.0
1.5
2.0
2.5
2012 2013 2014 2015 2016 2017 2018 2019 2020
MM
Bb/
d
Petchem Exports Rejection Total Supply (Net Stock Change)
U.S. Seaborne Ethane Exports Through 2020(2)
-
50
100
150
200
250
300
350
2013 2014 2015 2016 2017 2018 2019 2020
MB
bl/d
Ship Pipeline
250
200
150
100
50
MB
bl/d
U.S. exports increase significantly into 2016
and 2017 as EPD’s Morgan Point Facility
comes in-service
U.S. Ethane Rejection by Region Through 2020(1)
Access to both Marcus Hook and the Gulf Coast is
critical to optimizing ethane
netbacks
Rejection declines significantly into 2018
Unlike LPG, 80% of ethane will be
consumed in the U.S.
Petrochem demand increases at ≈8% CAGR through 2020
-
100
200
300
400
500
600
2012 2013 2014 2015 2016 2017 2018 2019 2020
MB
bl/d
Williston PADD 4 PADD 1 (East Coast) PADD 2 PADD 3
No Northeast rejection after 2017
63
Northeast Ethane
Rejection
Exports
U.S. PetChem
Europe
Mariner East II
Shipping $0.25/Gal
NGL EXPORTS AND NETBACKS STEP-UP BY 4Q 2016
1. Source: Intercontinental exchange as of 12/31/2015.2. Source of graphic: Tudor Pickering Holt & Co. research presentation dated June 16, 2015.3. As an anchor shipper on Mariner East II, Antero has the right to expand its NGL commitment with
notice to operator.
4. Shipping rates based on benchmark Baltic shipping rate of $59.57/ton as of 12/31/15, adjusted for number of shipping days to NWE.
5. Pipeline fee equal to $0.0725/gal, per Mariner East I tariff. Terminal fee equal to $0.12/gal, per TPH report dated June 16, 2015.
Upon in-service of Mariner East II, Antero will have the ability to market its propane and n-butane to international buyers, which we expect will provide uplifts of $0.16/Gal and $0.18/Gal, respectively, to the current netbacks received from propane and n-butane volumes shipped to Mont Belvieu today− In the meantime, Antero has 30,000 Bbl/d of propane hedged at $0.59/Bbl in 2016
Commitment to Mariner East II results in approximately $127 million in combined incremental annualized cash flow from propane and n-butane sales (~$86 MM from propane and ~$41 MM from n-butane)
PricingPropane: $0.39/GalN-Butane: $0.56/Gal
PricingPropane: $0.56/GalN-Butane: $0.76/Gal
Mariner East II61,500 Bbl/d AR
Commitment (see table below) (3)
4Q 2016 In-Service
ShippingPropane: $0.07/GalN-Butane: $0.08/Gal
AR Mariner East II Commitment (Bbl/d)Product Base Option (3) TotalEthane (C2) 11,500 - 11,500 Propane (C3) 35,000 35,000 70,000 Butane (C4) 15,000 15,000 30,000
Total 61,500 50,000 111,500
64
Mont Belvieu Propane Netback ($/Gal)Propane N-Butane
January Mont Belvieu Price (1): $0.39 $0.56
Less: Shipping Costs to Mont Belvieu (2): (0.25) (0.25)
Appalachia Propane Netback to AR: $0.14 $0.31
NWE Netback ($/Gal)Propane N-Butane
January NWE Price (1): $0.56 $0.76
Less: Spot Freight (4): ($0.07) ($0.08)
FOB Margin at Marcus Hook: $0.49 $0.68
Less: Pipeline & Terminal Fee (5): (0.19) (0.19)
Appalachia Netback to AR: $0.30 $0.49Upside to Appalachia Netback: $0.16 $0.18
ANTERO RESOURCES DECEMBER 31, 2015 RESERVES
65
Reserves Detail – 12/31/2015
Marcellus ShaleGas(Bcf)
Liquids (MMBbl)
Total(Bcfe)
PV-10 ($MM)SEC(1) Strip(2)
Proved 8,073 555 11,406 $2,749 $4,544
Probable 14,216 458 16,961
Possible 1,025 43 1,282
Total 3P 23,314 1,056 29,649 $2,885 $8,647
% Liquids(3) 21%
Ohio Utica ShaleGas(Bcf)
Liquids (MMBbl)
Total(Bcfe)
PV-10 ($MM)SEC(1) Strip(2)
Proved 1,459 58 1,809 $885 $1,140
Probable 3,972 83 4,468
Possible 951 40 1,191
Total 3P 6,381 181 7,468 $863 $2,535
% Liquids(3) 15%
Combined ReservesGas(Bcf)
Liquids (MMBbl)
Total(Bcfe)
PV-10 ($MM)SEC(1) Strip(2)
Proved 9,532 614 13,215 $3,634 $5,684
Probable 18,188 540 21,429
Possible 1,975 83 2,472
Total 3P 29,695 1,237 37,117 $3,748 $11,182
% Liquids(3) 20%
Antero’s proved reserves were 13.2 Tcfe, while its 3P reserves were 37.1 Tcfe
Proved pre-tax PV-10 at strip prices was $5.7 billion, while the 3P pre-tax PV-10 was $11.2 billion− Including hedges, the proved pre-tax PV-10 was $8.2 billion while the 3P pre-tax PV-10 was $13.7 billion
1. 2015 SEC prices were $2.56/MMBtu for natural gas and $50.13/Bbl for oil on a weighted average Appalachian index basis. 2. Pre-tax PV-10 based on annual strip pricing for first 10-years and flat thereafter as of December 31, 2015. NGL pricing assumes 39%, 46% and 48% of WTI strip prices for 2016, 2017 and 2018 and
thereafter, respectively. 3. Represents liquids volumes as a percentage of total volumes. Combined liquids comprised of 1,145 million barrels of NGLs (including 182 million barrels of ethane) and 92 million barrels of oil.
ANTERO RESOURCES EBITDAX RECONCILIATION
66
EBITDAX Reconciliation
($ in millions) Quarter Ended LTM Ended9/30/2015 9/30/2015
EBITDAX:Net income (loss) including noncontrolling interest $544.7 $1,413.4Commodity derivative fair value (gains) (1,079.1) (2,768.3)Net cash receipts (payments) on settled derivatives instruments 205.9 665.1(Gain) loss on sale of assets - (40.0)Interest expense 60.9 222.9Loss on early extinguishment of debt - -Income tax expense (benefit) 335.5 868.5Depreciation, depletion, amortization and accretion 189.1 706.5Impairment of unproved properties 8.8 51.0Exploration expense 1.1 9.8Equity-based compensation expense 23.9 105.6State franchise taxes - 0.6Contract termination and rig stacking - 10.9Consolidated Adjusted EBITDAX $290.8 $1,245.9
EBITDAX:Net income from discontinued operations - -(Gain) on sale of assets - -Provision for income taxes - -Adjusted EBITDAX from discontinued operations - -
Total Adjusted EBITDAX $290.8 $1,245.9
ANTERO MIDSTREAM EBITDA RECONCILIATION
67
EBITDA Reconciliation
Three months ended September 30,
2014 2015Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow: Net income $ 34,290 $ 42,648Add:
Interest expense 2,455 2,044Less:
Pre-water acquisition net income attributed to parent (29,211) (7,841)
Pre-water acquisition interest expense attributed to parent (522) (770)Pre-water acquisition operating income attributed to parent (29,733) (8,611)
Operating income - attributable to Partnership $ 7,012 $ 36,081Add:
Depreciation expense - attributable to Partnership 10,227 15,076
Equity-based compensation expense - attributable to Partnership 1,562 4,205 Adjusted EBITDA $ 18,801 $ 55,362
Less:Cash interest paid - attributable to Partnership (1,038)Maintenance capital expenditures attributable to Partnership (4,214)
Distributable cash flow $ 50,110
Reconciliation of Adjusted EBITDA to Net Cash Provided by Operating Activities:Adjusted EBITDA $ 18,801 $ 55,362 Add:
Pre-water acquisition net income attributed to parent 29,211 7,841
Pre-water acquisition depreciation expense attributed to parent 4,390 6,485
Pre-water acquisition equity based compensation expense attributed to parent 549 1,079Pre-water acquisition interest expense attributed to parent 522 770
Amortization of deferred financing costs attributed to parent — 285Less:
Interest expense (2,455) (2,044)Changes in operating assets and liabilities (8,258) (15,311)
Net cash provided by operating activities $ 42,760 $ 54,467
CAUTIONARY NOTE
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserve estimates (collectively, “3P”). Antero has provided internally generated estimates for proved, probable and possible reserves in this presentation in accordance with SEC guidelines and definitions. The estimates of proved, probable and possible reserves as of December 31, 2014 included in this presentation have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates as of December 31, 2014 assume ethane rejection and strip pricing.
Actual quantities that may be ultimately recovered from Antero’s interests may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery include the scope of Antero’s ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates.
In this presentation:
“3P reserves” refer to Antero’s estimated aggregate proved, probable and possible reserves as of December 31, 2014. The SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.
“EUR,” or “Estimated Ultimate Recovery,” refers to Antero’s internal estimates of per well hydrocarbon quantities that may be potentially recovered from a hypothetical future well completed as a producer in the area. These quantities do not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules.
“Condensate” refers to gas having a heat content between 1250 BTU and 1300 BTU in the Utica Shale.
“Highly-Rich Gas/Condensate” refers to gas having a heat content between 1275 BTU and 1350 BTU in the Marcellus Shale and 1225 BTU and 1250 BTU in the Utica Shale.
“Highly-Rich Gas” refers to gas having a heat content between 1200 BTU and 1275 BTU in the Marcellus Shale and 1200 BTU and 1225 BTU in the Utica Shale.
“Rich Gas” refers to gas having a heat content of between 1100 BTU and 1200 BTU.
“Dry Gas” refers to gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.
Regarding Hydrocarbon Quantities
68