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Goldman Sachs Global Energy ConferenceJanuary 7, 2016
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.
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
40%+ growth1.4 Bcfe/d+
25% - 30% growth targetmidpoint 1.785 Bcfe/d
Continue to target peer-leading production growth
~$0.88/Mcfe YTD down 10% from 2014
• 2,450 “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
2
94 289 254 664 139 1,010 889 628 248
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
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 $1.2 million for road, pad and production facilities, assume Antero will begin to realize lower well costs in 2016 as the company utilizes incremental completion crews for deferred completions beginning at year end 2015 and as existing drilling rig contracts begin to roll off during 2016.
2. ROR @ 12/31/2015 Strip Pricing – After Hedges reflects 12/31/2015 well cost ROR methodology with the 12/31/2015 hedge value allocated based on 2016-2021 projected production volumes resulting in blend of strip and hedge prices.
HIGH RETURN LOCATIONS DRIVE VALUE CREATION
3
At 12/31/2015 strip pricing, Antero has 2,450 locations with well economics that exceed 20% rate of return (excluding hedges)– Including hedges, these locations generate rates of return of approximately 47% to 83%
Rates of return include pad, facilities, cash production expenses (including midstream and FT costs)– See assumptions pages in appendix for further detail
ANTERO MARCELLUS & UTICA WELL ECONOMICS(1)(2)
2,450 “High Grade” Drilling
Locations
NYMEX($/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
4
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
$3.81/Mcfethrough 2022
Average Hedge Prices ($/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 $1.7 Billion
in Hedge Gains Since 2009
2.1x
0.0x1.0x2.0x3.0x4.0x5.0x6.0x7.0x
Peer 5 AR Peer 1 Peer 6 Peer 2 Peer 3 Peer 4
E&P Debt (net of Cash and M-T-M Hedge Value)(1) / LTM EBITDA (excl. Realized Hedging Revenue)
5
HEDGE BOOK SUPPORTS FINANCIAL PROFILE
Note: Data presented as filed for the quarter ended September 30, 2015 ($ in millions), prepared by Antero management. Peer group comprised primarily of gas weighted E&P names with comparable credit profiles, including NFX, QEP, RRC, SM, SWN, WPX.1. Represents total E&P debt less cash and mark-to-market hedge value.
Antero exceeds closest credit peer by $2.3 billion
AR net leverage maps with strong BB credit peers
Only credit peer with less than $1.5 billion of E&P debt
$2,842(9/30/15)
$0$500
$1,000$1,500$2,000$2,500$3,000$3,500
AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6
Mark-to-Market Hedge Value (9/30/15) for BB / BBB E&P Credits ($MM)$3,117
(12/31/15)
$0
$1,000
$2,000
$3,000
$4,000
$5,000
AR Peer 5 Peer 2 Peer 1 Peer 3 Peer 4 Peer 6
E&P Debt (net of Cash and M-T-M Hedge Value)
BB Credit Peer
BBB Credit Peer
Pre PostIn-Service In-Service
Projected 2016 Average Volume (BBtu/d)DOMS Priced Sales 329 0TETCO M2 Priced Sales 321 0TCO Priced Sales 0 80Firm Sales (TCO / Nymex) 0 570
Total 650 650
2016 Strip Pricing ($/MMBtu)DOMS (1) $1.54 N/ATETCO M2 (1) $1.56 N/ATCO (1) N/A $2.31Firm Sales (TCO / Nymex) (2) N/A $2.21
Annual Revenue ($MM)DOMS $185.1 $0.0TETCO M2 183.0 0.0TCO Pool Sales (1) 0.0 67.1Firm Sales (TCO / Nymex) (2) 0.0 461.2
$368.1 $528.3
Incremental Revenue $160.2Less: Incremental Firm Transport Costs: (25.2)
Projected Incremental EBITDA $135.0
STONEWALL PIPELINE IN SERVICE – EBITDA IMPACT
1. 2016 Strip pricing as of 12/31/2015.2. Blended price based on contracted firm sales volumes with third parties.
Existing TCO capacity of 582 MMcf/d with additional 1.1 Bcf/d of Stonewall Gathering firm transportation
and sales should eliminate virtually all Marcellus swing gas sales to Dominion South and TETCO M2
in 2016
6
2016 DOMS Strip: $1.54Variance to Nymex ($0.95)Variance to TCO ($0.77)
2016 TETCO M2 Strip: $1.56Variance to Nymex ($0.93)Variance to TCO ($0.75)
DOM S 23%
DOM S, 4% DOM S, 4%
TETCO M27%
TETCO M21%
TETCO M21%
TCO 40%
TCO 32%
TCO, 21%
NYMEX10%
NYMEX14%
NYMEX10%
Gulf Coast2%
Gulf Coast21% Gulf Coast
39%
Chicago18% Chicago
28%Chicago
25%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
($/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
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
7
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
$120.00
AR NGL Pricing Mont Belvieu AR NGL Pricing Mont Belvieu AR NGL Pricing Mont Belvieu AR NGL Pricing Mont Belvieu
2013 2014 2015 YTD 2016E
Realized NGL C3+ Price WTI
NGL REALIZATIONS AND PROPANE HEDGES
81. Based on 2016 NGL and WTI strip prices as of 12/31/2015. 2. YTD as of 10/31/2015. 3. As of 12/31/2015.
Realized NGL Prices as % of WTI(1)
54% 50%
34% 37%
($/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)
2016 FT Portfolio and Projected Gas Sales
Net Production Target (MMcfe/d) (1) 1,785Net Gas Production Target (MMcf/d) (80% of Net Production) 1,430Net Revenue Interest Gross-up 80%Gross Gas Production Target (MMcf/d) 1,785BTU Upgrade (2) x1.100 Gross Gas Production Target (BBtu/d) 1,975
Firm Transportation / Firm Sales (BBtu/d) 3,525Estimated % Utilization of FT/FS 56%
Excess Firm Transportation 1,550Marketable Firm Transport (BBtu/d) (3) 1075Unmarketable Firm Transportation 475
Estimated % Utilization of FT/FS Portfolio (Including Marketable FT) 87%
ANTERO FIRM TRANSPORTATION APPROPRIATELY DESIGNED TO ACCOMMODATE GROWTH
91. Represents midpoint of 2016 preliminary targeted net daily production growth of 25% to 30%.2. Assumes 1100 BTU residue sales gas.3. Represents excess firm transportation that is deemed marketable to 3rd parties based on a positive differential between the receipt and delivery points of the FT capacity, less variable transport cost.
• Antero projects firm transportation in excess of equity gas production of approximately 1,550 BBtu/d in 2016
• Expects to market or mitigate the cost of approximately 1,075 Bbtu/d of the excess FT with 3rd party gas
• Expect to fully utilize FT portfolio by 2019, assuming 2016 targeted production growth is maintained long-term (excludes Appalachia based FT directed to unfavorable indices)
0
600
1,200
1,800
2,400
3,000
3,600
(BBtu/d)
2016 Targeted Gross Gas
Production(1)
1,975 BBtu/d
Unmarketable Unutilized Firm Transport
~475 BBtu/d ($0.15 / MMBtu)
Marketable Unutilized Firm Transport ~1,075 BBtu/d
($0.39 / MMBtu)
Utilized Firm Transport / Firm Sales
~1,975 BBtu/d($0.45 / MMBtu)
Total Firm Transport (4)
3,525 BBtu/d
Excess Capacity Marketable /
FT Segment (Location) (BBtu/d) Unmarketable
Columbia / TGP (Marcellus) 625 MarketableANR North / ANR South (Utica) 450 MarketableEQT / M3 (Marcellus) 475 Unmarketable
Total Excess Firm Transport 1,550
2016 Firm Transport
Dec
reas
ing
Cos
t of F
T
2016EMarketing 2016E Marketing Revenue
Spread Assuming % Volume Mitigated($ / MMBtu) (2) 25% 50%
"Marketable" Firm Transport Capacity625 BBtu/d of Columbia / TGP $0.72 $41 $82450 BBtu/d of ANR North / ANR South $0.12 4 10
Sub-Total $45 $92$ / Mcfe - 2016E Targeted Production (1) $0.07 $0.14
Unmarketable (EQT / M3) ($/MMBtu)2016 TETCO M2 Pricing (Sold Gas) $1.562016 TETCO M2 Pricing (Bought Gas) (1.56)
Total Spread $0.00
Marketable (TCO / TGP) ($/MMBtu)2016 TGP-500 Pricing (Sold Gas) $2.432016 TETCO M2 Pricing (Bought Gas) (1.56)Less: Variable FT Costs (0.15)
Total Spread ("In the Money") $0.72
FIRM TRANSPORTATION PORTFOLIO PRESENTS MARKETING OPPORTUNITIES
10NOTE: Analysis based on current strip pricing as of 12/31/15. 1. Represents midpoint of 2016 preliminary targeted net daily production growth of 25% to 30%.2. Spread for each respective “marketable” firm transport represents the difference between the gas price Antero
would receive at the delivery point of each pipeline versus the price Antero would pay to buy gas at the receipt point of each piece of capacity, less the variable costs to transport on each segment of firm transportation.
2016 Projected Marketing Expenses:
0
600
1,200
1,800
2,400
3,000
3,600
(BBt
u/d)
2016 Targeted Gross Gas Production (2)
1,975 BBtu/d
$0.06 / Mcfe of 2016E Production (2)
$0.10 to $0.17 / Mcfe of 2016E Production (2)
Utilized FT$0.45 / Mcfe of 2016E
Production (2)
Illustrative Marketing Example:
2016 FT and Marketing Expenses per Unit:
2016 Marketing Revenue Projection:
Based on the midpoint of 2016 preliminary targeted net daily production growth of 25% to
30%, Antero projects net marketing expenses of ~$0.13 to $0.20 per Mcfe in 2016
Gathering& Transportation
Costs
MarketableNet Marketing
Expense
UnmarketableNet Marketing
Expense
Positive Spread
No Spread
($ in millions, except per unit amounts) 2016E 2016E 2016EDemand Marketing Marketing Marketing
Cost Expenses Revenue Expenses, Net"Unmarketable" Firm Transport
475 BBtu/d of EQT / M3 Appalachia FT $0.15 / MMBtu $26 - $26
"Marketable" Firm Transport Capacity625 BBtu/d of Columbia / TGP $0.49 / MMBtu $112 $41 - $82 $30 - $71450 BBtu/d of ANR North / ANR South $0.24 / MMBtu 40 $4 - $10 $30 - $36
Sub-Total $152 $45 - $92 $60 - $107
Grand Total - 2016 Marketing Expenses, Net $177 $45 - $92 ~$85 to $132 MM
$ / Mcfe - 2016 Targeted Production (1) $0.27 $0.07 - $0.14 $0.13 - $0.20
$1.97
AR P3 P4 P2 P1
“THE BRIDGE” RESULTS IN OUTPERFORMANCE VS. PEERS
Quarterly Appalachian Peer Group EBITDAX Margin ($/Mcfe)(1)
Quarterly Appalachian Peer Group EBITDAX ($MM)(1)
3Q 2014 4Q 2014 1Q 2015 2Q 2015
Note: AR and EQT EBITDAX margin excludes EBITDA from midstream MLP associated with noncontrolling interest. CNX excludes EBITDAX contribution from coal operations. 1. Source: Public data from form 10-Qs and 10-Ks. Peers include COG, CNX, EQT and RRC.
3Q 2014 4Q 2014 1Q 2015 2Q 2015AR Peer Group Ranking – Top Tier
#1 #1 #2 #1 #1
AR Peer Group Ranking – Improving Over Time#2 #3 #2 #1 #1
Y-O-Y AR: $1MMPeer Avg: $103MMNYMEX Gas: 32%NYMEX Oil: 53%
Y-O-Y AR: 33%Peer Avg: 51%NYMEX Gas: 32%NYMEX Oil: 53%
11
$292
$0$50
$100$150$200$250$300$350$400
P2 AR P3 P4 P1
$330
P2 P4 AR P3 P1
$355
P2 AR P4 P3 P1
$269
AR P2 P3 P4 P1
$291
AR P3 P2 P4 P13Q 2015
$2.93
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
AR P3 P2 P1 P4
$2.84
AR P2 P3 P4 P1
$2.56
P2 AR P3 P4 P1
$1.90
AR P3 P4 P2 P1(2)3Q 2015
For the second straight quarter, Antero has both the highest EBITDAX and EBITDAX margin among Appalachian peers
12
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: 2014 SEC prices were $4.07/MMBtu for natural gas and $81.48/Bbl for oil on a weighted average Appalachian index basis. 2015 SEC prices expected to be lower. 1. All net acres allocated to the WV/PA Utica Shale Dry Gas and Upper Devonian Shale are included among the net acres allocated to the Marcellus Shale as they are stacked pay formations attributable to
the same leasehold. 2. Antero and industry rig locations as of 1/1/2016, and average rig count for 4Q 2015, per RigData.
DRILLING – MOST ACTIVE OPERATOR IN APPALACHIA
13
COMBINED TOTAL – 12/31/14 RESERVESAssumes Ethane RejectionNet Proved Reserves 12.7 TcfeNet 3P Reserves 40.7 TcfePre-Tax 3P PV-10 $22.8 BnNet 3P Reserves & Resource 53 to 57 TcfeNet 3P Liquids 1,026 MMBbls% Liquids – Net 3P 15%3Q 2015 Net Production 1,506 MMcfe/d- 3Q 2015 Net Liquids 52,250 Bbl/dNet Acres(1) 569,000Undrilled 3P Locations 5,331
UTICA SHALE CORE
Net Proved Reserves 758 BcfeNet 3P Reserves 7.6 TcfePre-Tax 3P PV-10 $6.1 BnNet Acres 147,000Undrilled 3P Locations 1,024
MARCELLUS SHALE CORE
Net Proved Reserves 11.9 TcfeNet 3P Reserves 28.4 TcfePre-Tax 3P PV-10 $16.8 BnNet Acres 422,000Undrilled 3P Locations 3,191
UPPER DEVONIAN SHALE
Net Proved Reserves 8 BcfeNet 3P Reserves 4.6 TcfePre-Tax 3P PV-10 NMUndrilled 3P Locations 1,116
WV/PA UTICA SHALE DRY GASNet Resource 12.5 to 16 TcfNet Acres 188,000Undrilled Locations 1,889
02468
1012
Rig
Cou
nt
Operators
4Q Average SW Marcellus & Utica
0
10,000
20,000
30,000
40,000
2010 2011 2012 2013 2014 2015E
NGLs (C3+) Oil
5 246
6,436
23,051
37,000+
61%+ GrowthGuidance1. Assumes ethane rejection.
2. Reflects midpoint of 2016 production growth target of 25%-30%.
1,400
1,785
0
600
1,200
1,800
2010 2011 2012 2013 2014 2015E 2016E
Marcellus Utica Guidance
30124
239
522
1,007
14
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
40%+ GrowthGuidance
0
3,000
6,000
9,000
12,000
15,000
2010 2011 2012 2013 2014
Marcellus Utica
677
2,8444,283
7,632
(1) (1)
12,683
(1)
NET PROVED RESERVES (Bcfe)
AVERAGE NET DAILY LIQUIDS PRODUCTION (Bbl/d)
+
25%-30% GrowthTarget
(2)
15
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 3,000 undeveloped rich gas locations with an average lateral length of 6,800’ in its 3P reserves as of 12/31/2014
0
100
200
300
400
(000
s)
Core Liquids-Rich Net Acres(1)
248
139 94
254289
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
664 1,010
62888963% 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
MARCELLUS WELL ECONOMICS(1)(2)
WELL ECONOMICS – 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.
16
UTICA WELL ECONOMICS(1)(2)
72% of Marcellus locations are processable (1100-plus Btu) 72% 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 2,450 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
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)
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 $3.1 billion as of 12/31/2015. 17
Corporate Structure Overview(1)
Market Valuation of AR Ownership in AM:• AR ownership: 67% LP Interest = 116.9 million units
AM Priceper Unit
AM UnitsOwnedby AR(MM)
AR Value in AM LP Units
($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)
As of 3Q 2015: 1,506 MMcfe/d Net 40.7 Tcfe 3P Reserves 5,331 Undrilled Locations
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)
18
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)
$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
19
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)
HEDGING – LARGEST GAS HEDGE POSITION IN U.S. E&P
~ 100% of 2016 Target Hedged
191. 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
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
20
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.
$2.32 $2.32
$1.94 $1.95 $1.86 $1.77
$3.99
$3.18 $2.77 $2.63
$2.46 $2.21
$2.55/Mcf Midpoint
$0.00$0.50$1.00$1.50$2.00$2.50$3.00$3.50$4.00$4.50
AR RICE RRC EQT CNX SWN
Natural Gas Price Realization - Before Hedges Natural Gas Price Realization - After Hedges Median - After Hedges
$12.08
$8.10 $6.23
$4.75 $4.72
$16.47
$8.10 $9.45
$4.75 $4.72
$6.43/Bbl Midpoint
$0.00$2.00$4.00$6.00$8.00
$10.00$12.00$14.00$16.00$18.00
AR EQT RRC CNX SWN COG
NGL Realization - Before Hedges NGL Realization - After Hedges Median - After Hedges
REALIZATIONS – 3Q 2015 LEADING NATURAL GAS AND NGL REALIZATIONS
Note: Excludes peer that does not report a standalone NGL price.1) Public data from form 10-Qs and 10-Ks. Peers include COG, CNX, EQT, RRC and SWN.
NATURAL GAS PRICE REALIZATIONS(1) 3Q 2015 NYMEX: $2.77/MMbtu
NGL PRICE REALIZATIONS(1) 3Q15 NYMEX WTI: $46.42/Bbl
($/Mcf)
($/Bbl)
68% of sales to favorable markets, expected to increase to 95% in 2016 (TCO, Chicago, Nymex)
26% of
WTI 17% of WTI 10% of WTI 10% of WTI
21
• Antero’s realized NGL price, including hedges, was approximately 3x greater than the peer group average during the quarter.
• Outperformance expected to continue into 2016 as AR has 30,000 Bbl/d of propane hedged along with contracted C4+ pricing – expect NGL price realizations to be 37% of WTI
• Further improvement expected beyond 2016 when Mariner East 2 is placed into service35% of
WTI
87% hedged in 3Q15, expected to increase to ~100% in 2016
13% of
WTI
21% of
WTI N/A
-
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
ASSET OVERVIEW
23
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 1,140 MMcfe/d
in 3Q 2015, including 33,000 Bbl/d of liquids 3,191 future drilling locations in
the Marcellus (2,302 or 72% are processable rich gas)28.4 Tcfe of net 3P (17% liquids),
includes 11.9 Tcfe of proved reserves (assuming ethane rejection)
Highly-Rich Gas138,000 Net Acres
1,010 Gross Locations
Rich Gas91,000 Net Acres
628 Gross Locations
Dry Gas107,000 Net Acres
889 Gross Locations
Highly-Rich/Condensate86,000 Net Acres
664 Gross Locations
HEFLIN UNIT30-Day Rate
2H: 21.4 MMcfe/d (21% liquids)
CONSTABLE UNIT30-Day Rate
1H: 14.3 MMcfe/d (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)
24
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
25
Marcellus PDP Locations (As of 9/30/2015)
(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
7 SSL Wells
1200-1275 BTU2.0 Bcfe/1,000’ Lateral
106 SSL Wells
1100-1200 BTU1.8 Bcfe/1,000’ Lateral
110 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
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 366 MMcfe/d in 3Q 2015
including 19,250 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
1,024 future gross drilling locations (735 or 72% are processable gas)
7.6 Tcfe of net 3P (15% liquids), includes 758 Bcfe of proved reserves (assuming ethane rejection)
WORLD CLASS OHIO UTICA SHALEDEVELOPMENT PROJECT
26
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
139 Gross Locations
Highly-Rich Gas11,000 Net Acres
94 Gross Locations
Rich Gas30,000 Net Acres
254 Gross Locations
Dry Gas41,000 Net Acres
289 Gross Locations
NEUHART UNIT 3H30-Day Rate16.2 MMcfe/d(57% liquids)
Condensate36,000 Net Acres
248 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)
LARGE UTICA SHALE DRY GAS POSITION
27
Antero has completed its first dry gas Utica well – a 6,619’ 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
AnteroUtica Well Completing
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.
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 Reserves2.4 Tcf
289 Gross Locations41,000 Net Acres
AR Utica Shale Dry GasTotal OH/WV/PA
Net Resource14.9 to 18.4 Tcf
2,178 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)
ANTERO’S FIRST UTICA DRY GAS WELL
28
Antero recently drilled and completed its first dry gas Utica well in Tyler County, WV (Rymer 4HD)− 11,409 Total Vertical Depth (TVD)− 6,619’ lateral length− 100% working interest
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 40.7 Tcfe of net 3P reserves)− 1,889 locations underlying current Marcellus Shale leasehold in
West Virginia and Pennsylvania
41,000 net acres in Ohio with net 3P reserves of 2.4 Tcf as of 12/31/2014− 289 locations in Ohio
In total, Antero has 229,000 net acres and 2,178 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
AnteroUtica Well Completed
Rymer 4HD
Utica Dry Gas Fairway
29
Antero Midstream (NYSE: AM)Asset Overview
1. Represents inception to date actuals as of 12/31/2014 and 2015 midpoint guidance.2. Includes water drop down and $15.0 million of maintenance capex at 2015 midpoint guidance.
30
UticaShale
MarcellusShale
Projected Midstream Infrastructure(1)
Marcellus Shale
Utica Shale Total
YE 2014 Cumulative Gathering/ Compression Capex ($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
31
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
32Integrated 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
$1$5 $7 $8 $11
$19
$28
$36$41
$55
$0
$10
$20
$30
$40
$50
$60
26 31 40 36 41 116
222
358
454 435
0
100
200
300
400
500
600
700 Marcellus
10 38 80 126 266
531
908
1,134 1,197 1,216
0
200
400
600
800
1,000
1,200
1,400
1,600 Utica Marcellus
108 216
281 331 386 531
738
935 965 1,038
0
200
400
600
800
1,000
1,200
1,400 Utica Marcellus
Low Pressure Gathering (MMcf/d)
Compression (MMcf/d)
High Pressure Gathering (MMcf/d)
EBITDA ($MM)(1)
33
$185
HIGH GROWTH MIDSTREAM THROUGHPUT
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.
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
34
Downstream LNGand NGL Sales
Production andCash Flow Growth
35
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 $3.94/MMBtu; capital budget flexibility to commodity price changes
Large, low unit cost core Marcellus and Utica natural gas drilling inventory with associated liquids generates attractive returns supported by long-term natural gas hedges, takeaway portfolio and downstream LNG and NGL sales agreements
Pursuing additional value enhancing long-term LNG and NGL sales agreements, as well as additional NGL firm takeaway
Antero owns 67% of Antero Midstream Partners and thereby participates directly in its growth and value creation; acquisition of integrated water business from Antero expected to result in distributable cash flow per unit accretion in 2016
Midstream MLP Growth
Sustainability of Antero’s Integrated
Business Model
1
2
3
5
4Utica Dry Gas
Activity
36
APPENDIX
36
($ 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) $219Proved Reserves (Bcfe) (12/31/2014) 12,683
Proved Developed Reserves (Bcfe) (12/31/2014) 3,803
Credit Statistics
Net Debt / LTM EBITDAX 3.5xNet Debt / Net Book Capitalization 38%Net Debt / Proved Developed Reserves ($/Mcfe) $1.15Net Debt / Proved Reserves ($/Mcfe) $0.35
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 43.2. 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 $1.5 billion concurrent with water drop down on 9/23/2015.37
-
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
3,500,000
4,000,000
4,500,000
5,000,000
5,500,000
FIRM TRANSPORTATION AND FIRM SALES PORTFOLIO
38
MMBtu/d
Columbia7/26/2009 – 9/30/2025
Firm Sales #110/1/2011– 10/31/2019
Firm Sales #210/1/2011 – 11/30/2015
Firm Sales #31/1/2013 – 5/31/2022
Momentum III9/1/2012 – 12/31/2023
EQT8/1/2012 – 6/30/2025
REX/MGT/ANR7/1/2014 – 12/31/2034
Tennessee11/1/2015– 9/30/2030
(Stonewall/WB) Mid-Atlantic/NYMEX
(Stonewall/TGP) Gulf Coast
(TCO) Appalachia or Gulf Coast
AppalachiaAppalachia
ANR3/1/2015– 2/28/2045
(REX/ANR/NGPL/MGT) Midwest
Local Distribution11/1/2015 – 9/30/2037
(ANR/Rover) Gulf Coast
Antero Transportation Portfolio
1,280 BBtu/d
790 BBtu/d
375 BBtu/d
250 BBtu/d
800 BBtu/d
600 BBtu/d
630 BBtu/d
40 BBtu/d
Illustrative gross gas production fills Antero’s market-leading firm transportation / sales portfolio by 2019 (excluding
unfavorable Appalachia-based firm transport) (1)
Gross Gas Production (Actuals) Illustrative Gross Gas Production (25% Annual Growth CAGR Assumed) (1)
1. Assumes midpoint of preliminary production growth target of 25% to 30% in 2016 and targeted 25% annual production growth CAGR through 2020.
664
1,010
628
88963%
47%
24% 28%34%
22%9% 11% 0
2004006008001,0001,200
0%
20%
40%
60%
80%
Highly-Rich Gas/Condensate
Highly-Rich Gas Rich Gas Dry Gas
Tota
l 3P
Loca
tions
RO
RTotal 3P LocationsROR @ 12/31/2015 Strip Pricing - After HedgesROR @ 12/31/2015 Strip Pricing - Before Hedges
MARCELLUS SINGLE WELL ECONOMICS – IN ETHANE REJECTION
39
DRY GAS LOCATIONS RICH GAS LOCATIONS
HIGHLY RICH GAS
LOCATIONS
Assumptions Natural Gas – 12/31/2015 strip Oil – 12/31/2015 strip NGLs – 37% of Oil Price 2016; 50% of
Oil Price 2017+
NYMEX($/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): $0.44 $0.48 $0.54 $0.59Direct Operating Expense ($/well/month): $1,498 $1,498 $1,498 $1,498Direct Operating Expense ($/Mcf): $0.92 $0.92 $1.17 $0.71Transportation Expense ($/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): 664 1,010 628 8891. 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 $1.2 million for road, pad and production facilities, assume Antero will begin to realize lower well costs in 2016 as the company utilizes incremental completion crews for deferred completions beginning at year end 2015 and as existing drilling rig contracts begin to roll off during 2016.
2. Pricing for a 1225 BTU y-grade ethane rejection barrel. NGLs at 37.5% of WTI for 2016 and 50% of WTI for 2017 and thereafter. NGL prices are forecast to increase in 2017 relative to WTI due to projected in-service date of Mariner East 2 project allowing for a significant increase in AR NGL exports via ship.
3. Undeveloped well locations as of 12/31/2014.
2016Drilling
Plan
248
13994
254 289
16%
57%
83%71%
80%
10%
27% 29%23% 26%
050100150200250300
0%
20%
40%
60%
80%
100%
Condensate Highly-Rich Gas/Condensate
Highly-Rich Gas Rich Gas Dry Gas
Tota
l 3P
Loca
tions
RO
R
Total 3P LocationsROR @ 12/31/2015 Strip Pricing - After HedgesROR @ 12/31/2015 Strip Pricing - Before Hedges
UTICA SINGLE WELL ECONOMICS – IN ETHANE REJECTION
40
DRY GAS LOCATIONS RICH GAS LOCATIONS
HIGHLY RICH GAS
LOCATIONS
Utica Well Economics and Gross Locations(1)
Classification CondensateHighly-Rich Gas/
CondensateHighly-Rich
Gas Rich Gas Dry GasModeled BTU 1275 1235 1215 1175 1050EUR (Bcfe): 9.4 17.0 25.3 23.8 21.4EUR (MMBoe): 1.6 2.8 4.2 4.0 3.6% Liquids 35% 26% 21% 14% 0%Lateral Length (ft): 9,000 9,000 9,000 9,000 9,000Well Cost ($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): $1.08 $0.60 $0.40 $0.43 $0.48Fixed Operating Expense ($/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): 248 139 94 254 2891. 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 $1.2 million for road, pad and production facilities, assume Antero will begin to realize lower well costs in 2016 as the company utilizes incremental completion crews for deferred completions beginning at year end 2015 and as existing drilling rig contracts begin to roll off during 2016.
2. Pricing for a 1225 BTU y-grade ethane rejection barrel. NGLs at 37.5% of WTI for 2016 and 50% of WTI for 2017 and thereafter. NGL prices are forecast to increase in 2017 relative to WTI due to projected in-service date of Mariner East 2 project allowing for a significant increase in AR NGL exports via ship.
3. Undeveloped well locations as of 12/31/2014. 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content.
2016Drilling
Plan
Assumptions Natural Gas – 12/31/2015 strip Oil – 12/31/2015 strip NGLs – 37% of Oil Price 2016; 50% of
Oil Price 2017+NYMEX
($/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
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 2, 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: $0.08/Gal
AR Mariner East II Commitment (Bbl/d)Product Base Option (3) TotalEthane (C2) 11,500 - 11,500 Propane (C3) 35,000 35,000 70,000 Butane (C4) 15,000 15,000 30,000
Total 61,500 50,000 111,500
41
Mont Belvieu Propane Netback ($/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 $0.18
Moody's S&P
POSITIVE RATINGS MOMENTUMMoody’s / S&P Historical Corporate Credit Ratings
“We could raise the ratings due to our assessment of an improvement inthe company's financial profile. An improvement in the financial profilewould include maintaining FFO to debt of greater than 45% andnarrowing the amount that the company outspends its cash flows by.”
- S&P Credit Research, September 2014
"The upgrade reflects Moody's expectation that Antero will continue toreport strong production growth and increasing reserves despitechallenging market conditions and without a significant increase inleverage. Antero's low finding and development costs and significantcommodity hedge position should allow the company to continue toprosper despite today's low commodity price environment.“
- Moody’s Credit Research, February 2015
Corporate Credit Rating (Moody’s / S&P)
Ba3 / BB-
B1 / B+
B2 / B
B3 / B-
9/1/2010 2/24/2011 10/21/2013 9/4/20145/31/13
Ba2 / BB
Ba1 / BB+
Caa1 / CCC+
(1)
1. Represents corporate credit rating of Antero Resources Corporation / Antero Resources LLC.
Baa3 / BBB-
Moody’s Upgrade Rationale S&P Upgrade Criteria
42
3/31/2015
Ba2/BB
ANTERO RESOURCES EBITDAX RECONCILIATION
43
EBITDAX Reconciliation
($ 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
44
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
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