Company website presentation march 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, 2015 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, 2015 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 FEBRUARY 2016 PRESENTATION
Updated AR peer comparison slide for reserves, core
net acres and production as of 12/31/2015
Slide 26
Updated AR peer realizations and EBITDAX comparison
as of 12/31/2015
Slide 18

ANTERO – “THE BRIDGE” TO BETTER OIL & GAS PRICES
2015A 2016E 2017E
Large and Growing
Production Base
Declining Development
Costs
Production Sold
Forward
Strong Liquidity
Firm Transport to
Favorable Markets
48% growth to
1.493 Bcfe/d
15% growth guidance to
1.715 Bcfe/d
20% growth target on 2016E
guidance
~$0.88/Mcfe in 2015 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)
$3.94/MMBtu
(≈100% of guidance)
$3.57/MMBtu
(≈100% of target)
• $2.6 billion at 12/31/2015
• Additional $2.3 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
• 74% of sales volumes priced
at favorable markets
• 3.5 Bcf/d of FT
• Expect 99% of sales volumes
priced at favorable markets
• 3.6 Bcf/d of FT
• Expect 97% of sales volumes
priced at favorable markets
• 61,500 Bbl/d of FT on Mariner
East 2 for NGL 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
virtually all of its production volumes sold to favorable markets
3

4
Most Active Operator
in 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
Well
Economics
1
2 3
4
5
67
8
Premier Appalachian
E&P Company
Run by Co-Founders
High Return
Locations

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 1/29/2016, and average rig count for January 2016, per RigData.
DRILLING – MOST ACTIVE OPERATOR IN APPALACHIA
5
COMBINED TOTAL – 12/31/15 RESERVES
Assumes Ethane Rejection
Net Proved Reserves 13.2 Tcfe
Net 3P Reserves 37.1 Tcfe
Strip Pre-Tax 3P PV-10(1) $11.2 Bn
Net 3P Reserves & Resource 50 to 53 Tcfe
Net 3P Liquids 1,237 MMBbls
% Liquids – Net 3P 20%
4Q 2015 Net Production 1,497 MMcfe/d
- 4Q 2015 Net Liquids 54,750 Bbl/d
Net Acres(2) 569,000
Undrilled 3P Locations 3,719
OHIO UTICA SHALE CORE
Net Acres 147,000
Undrilled 3P Locations 814
MARCELLUS SHALE CORE
Net Acres 422,000
Undrilled 3P Locations 2,905
WV/PA UTICA SHALE DRY GAS
Net Resource 12.5 to 16 Tcf
Net Acres 188,000
Undrilled Locations 1,889
0
2
4
6
8
10
12
RigCount
Operators
January 2016 SW Marcellus & Utica(3)

28%
21% 21%
15%
5%
-6%
-10%
-5%
0%
5%
10%
15%
20%
25%
30%
AR EQT CNX COG RRC SWN
0.25
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 9/30/2015, 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)
Mcfe/Share
Net Debt-Adjusted Production per Share Growth vs. Peers
(Since AR IPO)
GROWTH – DEBT-ADJUSTED PER SHARE PRODUCTION

$198
$341
$434
$649
$1,164
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
$1,600
2010 2011 2012 2013 2014 2015 2016E
$1,221
0
10,000
20,000
30,000
40,000
50,000
60,000
2010 2011 2012 2013 2014 2015 2016E
NGLs (C3+) Oil
5 246
6,436
23,051
48,298
60,000
24% Growth
Guidance
1. Assumes ethane rejection. 2015 proved reserves include 1.1 Tcfe of ethane due to de-ethanizer being placed online at Sherwood facility and commencement of ethane delivery contracts in 2017.
2. Represents Bloomberg street consensus estimates as of 2/19/2016.
1,715
0
600
1,200
1,800
2,400
2010 2011 2012 2013 2014 2015 2016E 2017E
Marcellus Utica Guidance
30 124
239
522
1,007
1,493
7
AVERAGE NET DAILY PRODUCTION (MMcfe/d)
0
50
100
150
200
2010 2011 2012 2013 2014 2015 2016E
Marcellus Utica Deferred Completions
19
38
60
114
177 181
131
110
180
GROWTH – GROWING THROUGH THE DOWN CYCLE
OPERATED GROSS WELLS COMPLETED
AVERAGE NET DAILY LIQUIDS PRODUCTION (Bbl/d)
15%
Growth
Guidance
20%
Growth
Target
 Antero is in the unique position of being able to sustain growth and value creation through the price down cycle
CONSOLIDATED EBITDAX ($MM)
Street
Consensus(2)

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
(000s)
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 Marcellus
Highly-Rich
Gas/
Condensate
Utica Highly-
Rich Gas/
Condensate
Marcellus
Highly-Rich
Gas
Marcellus Dry
Gas
Marcellus Rich
Gas
Utica
Condensate
ROR
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 $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-$28
12/31/15 Strip Pricing 12/31/15 Hedge Pricing
NYMEX
($/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 Hedges
12/31/15 Strip Pricing - After Hedges
Locations
WELL ECONOMICS – WELL COST REDUCTIONS SUPPORT
SUSTAINABLE BUSINESS MODEL

0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000 Proved Developed Production (BBtu/d)
Undeveloped Production (BBtu/d)
Hedged Volume (BBtu/d)
WELL ECONOMICS – HEDGING UNDEVELOPED
PRODUCTION
10
1. Represents illustrative Antero production forecast, adjusted for residue gas BTU content of 1100 BTU.
Antero has hedged a significant portion of its forecasted undeveloped production stream from
wells yet to be drilled at prices well above current strip pricing, including virtually all of its
undeveloped production forecast through the end of 2017
Natural Gas Hedged Volume vs. Production
(BBtu/d)
(1)
(1)
Antero has hedged virtually all of its
undeveloped production through
the end of 2017
Developed (Illustrative)
Undeveloped (Illustrative)
$3.94/Mcfe
$3.57/Mcfe $3.91/Mcfe
$3.87/Mcfe
$3.72/Mcfe
No Production Guidance
or Targets Disclosed
Beyond 2017

Antero Resources
Corporation (NYSE: AR)
$11.6 Billion Enterprise Value(1)
Ba2/BB Corporate Rating
Antero Midstream
Partners LP (NYSE: AM)
$4.1 Billion Enterprise Value(1)
66% LP Interest
$2.3 Billion MV(1)
$11.2 Bn 3P PV-10(4)
E&P Assets
Gathering/Compression
Assets
MIDSTREAM – MLP (NYSE: AM) HIGHLIGHTS
SUBSTANTIAL VALUE IN MIDSTREAM BUSINESS
1. AR enterprise value excludes AM debt, minority interest and cash. Market values (MV) as of 1/31/2015 and includes subordinated units; balance sheet data as of 12/31/2015.
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 $3.1 billion as of 12/31/2015.
4. 3P pre-tax PV-10 based on annual strip pricing for first 10-years and flat thereafter as of December 31, 2015. NGL pricing assumes 39%, 46% and 48% of WTI strip prices for 2016, 2017 and 2018 and
thereafter, respectively.
11
Corporate Structure Overview(1)
Market Valuation of AR Ownership in AM:
• AR ownership: 66% LP Interest = 116.7 million units
AM Price
per Unit
AM Units
Owned
by AR
(MM)
AR Value in
AM LP Units
($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
34% LP Interest
$1.2 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 Markets
Mariner East 2
62 MBbl/d Commitment
Marcus Hook Export
Shell
Beaver County Cracker (2)
Sabine Pass (Trains 1-4)
50 MMcf/d per Train
Lake Charles LNG(3)
150 MMcf/d
Freeport LNG
70 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)
12
Cove Point LNG4.85 Bcf/d
Firm Gas
Takeaway
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 Mix
Antero 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)

0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
2016 FT Portfolio and
Projected Gas Sales
Net Production Target (MMcfe/d) (1) 1,715
Net Gas Production Target (MMcf/d) (80% of Net Production) 1,372
Net Revenue Interest Gross-up 80%
Gross Gas Production Target (MMcf/d) 1,715
BTU Upgrade (2) x1.100
Gross Gas Production Target (BBtu/d) 1,885
Firm Transportation / Firm Sales (BBtu/d) 3,525
Estimated % Utilization of FT/FS 53%
Excess Firm Transportation 1,640
Marketable Firm Transport (BBtu/d) (3) 1,015
Unmarketable Firm Transportation 625
Estimated % Utilization of FT/FS Portfolio (Including Marketable FT) 82%
TAKEAWAY – PORTFOLIO APPROPRIATELY
DESIGNED TO ACCOMMODATE GROWTH
131. Represents 2016 forecasted net daily production.
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 1,640 BBtu/d
in 2016
• Expects to market or mitigate the cost of
approximately 1,015 BBtu/d of the excess FT with 3rd
party gas
• Expect to fully utilize FT portfolio by 2019, based on
five year development plan (excludes Appalachia
based FT directed to unfavorable indices)
(BBtu/d)
2016 Targeted
Gross Gas
Production(1)
1,885 BBtu/d
Unmarketable Unutilized
Firm Transport
~625 BBtu/d ($0.15 / MMBtu)
Marketable Unutilized
Firm Transport
~1,015 BBtu/d
($0.39 / MMBtu)
Utilized Firm Transport /
Firm Sales
~1,885 BBtu/d
($0.45 / MMBtu)
Total Firm Transport
3,525 BBtu/d
Excess
Capacity Marketable /
FT Segment (Location) (BBtu/d) Unmarketable
Columbia / TGP (Marcellus) 550 Marketable
ANR North / ANR South (Utica) 465 Marketable
EQT / M3 (Marcellus) 625 Unmarketable
Total Excess Firm Transport 1,640
2016 Firm Transport
DecreasingCostofFT

($ in millions, except per unit amounts) Demand 2016E 2016E 2016E
Fee Marketing Marketing Marketing
($ / MMBtu) Expenses Revenue Expenses, Net
"Unmarketable" Firm Transport
625 BBtu/d of EQT / M3 Appalachia FT $0.15 $35 - $35
"Marketable" Firm Transport Capacity
550 BBtu/d of Columbia / TGP $0.49 $99 $43 - $72 $27 - $56
465 BBtu/d of ANR North / ANR South $0.24 42 $6 - $11 $31 - $36
Sub-Total $141 $49 - $83 $58 - $92
Grand Total - 2016 Marketing Expenses, Net $176 $49 - $83 ~$95 to $125 MM
$ / Mcfe - 2016 Targeted Production (1)
$0.28 $0.08 - $0.13 $0.15 - $0.20
TAKEAWAY – FT MARKETING EXPENSE UPDATE
14
NOTE: Analysis based on strip pricing as of 12/31/2015.
1. Represents 2016 production growth guidance of 15% to 1,715 MMcfe/d.
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
(BBtu/d)
2016 Targeted Gross
Gas Production
1,885 BBtu/d
$0.06 / Mcfe of 2016E
Production (2)
$0.09 to $0.14 /
Mcfe of 2016E
Production (2)
Utilized FT
$0.45 / Mcfe of 2016E
Production (2)
2016 FT and Marketing Expenses per Unit:
2016 Marketing Revenue Projection:
Based on the 2016 guidance of 15% annual
production growth, Antero projects net marketing
expenses of $0.15 to $0.20 per Mcfe in 2016
Gathering
& Transportation
Costs
Marketable
Net Marketing
Expense
Unmarketable
Net Marketing
Expense
Unmarketable (EQT / M3) ($/MMBtu)
2016 TETCO M2 Pricing (Sold Gas) $1.56
2016 TETCO M2 Pricing (Bought Gas) (1.56)
Total Spread $0.00
Marketable (TCO / TGP) ($/MMBtu)
2016 TGP-500 Pricing (Sold Gas) $2.43
2016 TETCO M2 Pricing (Bought Gas) (1.56)
Less: Variable FT Costs (0.15)
Total Spread ("In the Money") $0.72
Illustrative Marketing Example:
Positive Spread
No Spread
2016E
Marketing 2016E Marketing Revenue
Spread Assuming % Volume Mitigated
($ / MMBtu) (2)
30% 50%
"Marketable" Firm Transport Capacity
550 BBtu/d of Columbia / TGP $0.72 $43 $72
465 BBtu/d of ANR North / ANR South $0.12 6 11
Sub-Total $49 $83
$ / Mcfe - 2016E Targeted Production (1)
$0.08 $0.13

$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$0
$50
$100
$150
$200
$250
$300
$MM
15
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 $3.1 billion
● Significant additional hedge capacity remains under the credit facility hedging covenant for 2018 – 2022 period
Quarterly Realized Hedge Gains / (Losses)
Realized Hedge Gains
Projected Hedge Gains
NYMEX Natural Gas
Historical Spot Prices
($/MMBtu)
NYMEX Natural Gas
Futures Prices
3.5 Tcfe Hedged at
average price of
$3.79/Mcfe
through 2022
Average Hedge Prices
($/Mcfe)
$3.50
$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 $5.5 Bn
significantly exceeds total debt of $4.1 Bn
Liquidity
LIQUIDITY – STRONG BALANCE SHEET AND FLEXIBILITY
Antero Resources (NYSE:AR) Antero Midstream (NYSE:AM)
12/31/2015 Debt Liquid Non-E&P Assets 12/31/2015 Debt Liquid Assets
Debt Type $MM
Credit facility $707
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 $4,082
Asset Type $MM
Commodity derivatives(1) $3,117
AM equity ownership(2) 2,318
Cash 16
Total $5,451
Asset Type $MM
Cash $16
Credit facility – commitments(3) 4,000
Credit facility – drawn (707)
Credit facility – letters of credit (702)
Total $2,607
Debt Type $MM
Credit facility $620
Total $620
Asset Type $MM
Cash $7
Total $7
Liquidity
Asset Type $MM
Cash $7
Credit facility – capacity 1,500
Credit facility – drawn (620)
Credit facility – letters of credit -
Total $887
Approximately $2.6 billion of liquidity at AR
plus an additional $2.3 billion of AM units
Approximately $900 million of liquidity
at AM
16
Only 41% of AM credit facility capacity drawn
Note: All balance sheet data as of 12/31/2015, 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 (116.7 million common and subordinated units) and AM’s closing price as of 1/31/2015.
3. AR credit facility commitments of $4.0 billion, borrowing base of $4.5 billion.

Baa3
Ba1 Ba1 Ba1
Ba3 Ba3 Ba3 Ba3
B1 B1 B1
B2 B2 B2
B3
Caa1
Caa2
Baa2
Baa3 Baa3 Baa3
Baa2 Baa2
Ba2
Baa3 Baa3
Ba1 Ba1
Baa3
Ba1 Ba1 Ba1 Ba1
Ba3 Ba3
Ba2
Ba3
-Baa3
Baa3
Baa3
Baa3
Baa3
Baa3
Baa3
Baa3
Baa3
Baa3
Baa3
Baa3
NBL XEC EQT PXD APC HES CXO AR CLR MUR NFX RRC SWN EGN QEP SM WPX UNT EPE WLL DNR
LIQUIDITY – ANTERO CREDIT QUALITY AFFIRMED AT
Ba2/BB
17
Moody’s Baa / Ba Ratings Review
Source: Moody’s releases on 02/11/2016 and 02/18/2016.
Note: Issuers are sorted based on rating following review. Appalachia companies in orange.
 Amidst the sector wide re-rating of the Energy Sector, Antero recently received affirmed ratings of Ba2 / BB from Moody’s and S&P
 Of the 21 public US Baa/Ba E&P issuers reviewed by Moody’s and highlighted below, 15 received downgrades of two or more notches, including
five companies that received downgrades of 4 or more notches, and one received a one notch downgrade
 S&P reviewed 45 High Yield issuers with 25 downgrades ranging from 1-3 notches
Of the 21 public U.S. Baa and Ba
rated E&P operators, Antero was one
of only five companies that received
an “affirmed” rating from Moody’s
AR
Rating Affirmed
Baa1
Baa2
Baa3
Ba1
Ba2
Ba3
B1
B2
B3
Caa1
Caa2
Caa3
Gray – Previous Rating
Red – New Rating
Appalachian Company

Region
4Q 2015
% Sales
Average
NYMEX Price
Average
Differential
Average
BTU Upgrade
Hedge
Effect
Average 4Q 2015
Realized Gas Price
NYMEX
Premium/
Discount
TCO 42% $2.27 $(0.32) $0.15 $0.25 $2.35 $0.08
Dom South/TETCO 26% $2.27 $(0.76) $0.10 $0.87 $2.48 $0.21
Gulf Coast(1) 5% $2.27 $(0.17) $0.17 $1.15 $3.42 $1.15
Chicago/Michigan 27% $2.27 $0.12 $0.26 $0.00 $2.65 $0.38
Total Wtd. Avg. 100% $2.27 $(0.31) $0.17 $2.27 $4.40 $2.13
$2.03
$1.88
$1.59
$1.35 $1.14
$1.11
$0.58
$0.73
$0.88
$0.75 $0.85
$0.72
$4.34
$3.22
$3.06
$2.75
$2.21 $2.20
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
$4.50
$5.00
AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5
$/Mcfe
Noncontrolling Interest of Midstream MLP EBITDA LOE
Production Taxes GPT
G&A EBITDAX
4-year Avg. All-in F&D
$4.40
$3.08 $3.00
$2.78
$2.07
$1.94
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
$4.50
$5.00
AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5
$/Mcf
1. Includes natural gas hedges.
2. Source: Public data from 4Q 2015 10-Qs. Peers include Cabot Oil & Gas, CONSOL Energy, EQT Corp., Range Resources and Southwestern.
3. 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 $0.06 of midstream revenues; EBITDAX excludes AR’s midstream EBITDA not attributable to AR’s ownership.
18
REALIZATIONS – A LEADER IN REALIZATIONS & MARGINS
AMONG LARGE-CAP APPALACHIAN PEERS
4Q 2015 Natural Gas Realizations(1)(2) 4Q 2015 Price Realization & EBITDAX Margin vs F&D(2)(3)
($/Mcfe)
 Antero continues to be a leader in its peer group in price realizations and EBITDAX unit margins
4Q 2015 NYMEX
= $2.27/Mcf
4Q 2015 Natural Gas Realizations ($/Mcf)

DOM S
23%
DOM S, 3%
TETCO M2
7%
TETCO M2
1%
TCO
40%
TCO
33% TCO, 21%
NYMEX
10%
NYMEX
10%
NYMEX
10%
Gulf Coast
2%
Gulf Coast
28%
Gulf Coast
49%
Chicago
18% Chicago
28%
Chicago
17%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
($/Mcf) 2015A 2016E
NYMEX Strip Price(1) $2.66 $2.47
Basis Differential to NYMEX(1) $(0.53) $(0.12)
BTU Upgrade(5) $0.24 $0.24
Estimated Realized Hedge Gains $1.44 $1.50
Realized Gas Price with Hedges $3.81 $4.10
Premium to NYMEX +$1.15 +$1.63
Liquids Impact +$0.29 +$0.10
Premium to NYMEX w/ Liquids +$1.44 +$1.73
Realized Gas-Equivalent Price $4.10 $4.16
REALIZATIONS – REALIZED PRICE “ROAD MAP”
Note: Hedge volumes as of 12/31/2015.
1. Based on 12/31/2015 strip pricing and 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. Based on BTU content of residue sales gas.
2015
Basis(1)
2016
Basis(1)
2017
Basis(1)
2015
Hedges
2016
Hedges
2017
Hedges
Marketed%ofTargetResidueGasProduction
+$0.02/MMBtu
$(0.12)/MMBtu(2)
$(1.30)/MMBtu
$(0.28)/MMBtu
$0.01/MMBtu
$(0.43)/MMBtu(2)
$(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)
99% exposure to favorable price indices69% exposure to favorable price indices 97% 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 >99% in 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 $(0.12)
1,160,000 MMBtu/d
@ $4.34/MMBtu
Wtd. Avg.
Basis $(0.15)
1,612,500 MMBtu/d
@ $3.92/MMBtu
420,000 MMBtu/d
@ $4.27/MMBtu
2015A 2016E 2017E
19
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
@ $3.63/MMBtu
$(0.10)/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
$17.15
$25.05
$15.17
$21.89
$98.01 $93.03
$48.63
$41.00
$0.00
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
AR NGL Pricing Mont Belvieu AR NGL Pricing Mont Belvieu AR NGL Pricing Mont Belvieu AR NGL Pricing Mont Belvieu
2013 2014 2015 2016E
Realized NGL C3+ Price WTI
REALIZATIONS – NGL REALIZATIONS AND PROPANE HEDGES
201. Based on 2016 NGL and WTI strip prices as of 12/31/2015.
2. As of 12/31/2015.
Realized NGL Prices as % of WTI(1)
54% 50%
35% 37%
($/Bbl)
NGL Marketing Propane Hedges
 Realized NGL (C3+) price was 50% of WTI in 2014 and
35% of WTI for 2015
− Including propane hedges, 2015 realizations were 42%
of WTI
 Antero has guided to realized C3+ NGL prices of 35% to
40% of WTI for 2016 (before hedging)
− Antero has hedged 30,000 Bbl/d of propane in 2016 at
$0.59 per gallon
 By 2017, 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(2)
Target 2016 C3+ NGL pricing
of 37% of WTI based on
12/31/15 strip pricing

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 2
61,500 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
Export
15%
Gulf
Coast
13%
Mid-
Atlantic
6%
Sarnia
3%
Northeast
43%
Midwest
10%
Edmonton
10%
2015 NGL Marketing by Region
21

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)
22
Shell
Beaver County Cracker
(Pending FID 1H 2016)
Mariner East 2
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
$/Gallon
Baltic Exchange LPG Freight Futures
Baltic LPG Rate ($/gal) Marcus Hook to Europe ($/gal)
Marcus Hook to Far East ($/gal)
U.S. EXPORTS ARE SUPPORTED BY EXCESS
DOCK CAPACITY AND FLEET GROWTH
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
MBbl/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 168
New builds +85
23

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)
MMBbl/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 Korea
Haiwei (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
24
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/d
1.3
1.0
0.7
0.3
-0.3

Downstream LNG
and NGL Sales
Production and
Cash Flow Growth
25
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
Guiding to 15% production growth in 2016 and targeting 20% in 2017
with ~100% hedged at $3.94/MMBtu and $3.57/MMBtu, respectively;
capital budget flexibility to adapt 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 66% 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
4
Utica Dry Gas
Activity

0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
AR EQT RRC COG CNX CHK SWN
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
EQT CHK COG AR SWN RRC CNX
-
100
200
300
400
500
600
AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6
Core Net Acres - Dry Core Net Acres - Liquids Rich
LEADERSHIP IN APPALACHIAN BASIN
Top Producers in Appalachia (Net MMcfe/d) – 4Q 2015(1)(2)
Top 12 U.S. Natural Gas Producers (Net MMcf/d) – 4Q 2015(1)
Appalachian Producers by Proved Reserves (Bcfe) – YE 2015(1)(2) Appalachian Producers by Core Net Acres (000’s) – December 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, CHK.
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)
26
4th Largest
Appalachian
Producer
 Antero has the largest proved reserve base, 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 Largest Liquids-
Rich Core Position
in Appalachia
(5)
0
500
1,000
1,500
2,000
2,500
3,000
3,500

626 971
553
755
63% 47%
24%
28%34%
22%
9% 11%
0
400
800
1,200
0%
15%
30%
45%
60%
75%
Highly-Rich
Gas/
Condensate
Highly-Rich Gas Rich Gas Dry Gas
Total3PLocations
ROR
Total 3P Locations ROR @ 12/31/2015 Strip Pricing - After Hedges ROR @ 12/31/2015 Strip Pricing - Before Hedges
184
98
108
161
263
16%
57%
83%
71%
80%
10%
27%
29%
23% 26%
0
100
200
300
0%
20%
40%
60%
80%
100%
Condensate Highly-Rich
Gas/
Condensate
Highly-Rich
Gas
Rich Gas Dry Gas
Total3PLocations
ROR
MARCELLUS WELL ECONOMICS(1)(2)
WELL COST REDUCTIONS SUPPORT
SUSTAINABLE 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. Current spot well costs based on $9.1 million for a 9,000’ lateral Marcellus well and $10.2 million for a 9,000’ lateral Utica well.
28
UTICA WELL ECONOMICS(1)(2)
 74% of Marcellus locations are processable (1100-plus Btu)  68% of Utica locations are processable (1100-plus Btu)
2016
Drilling
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 a 20% rate of return (excluding hedges)
– Including hedges, these locations generate rates of return of approximately 50% to 80%
Utica Well Cost Improvement(3)
$1.36
$1.14
$1.01
$0.000
$0.500
$1.000
$1.500
$2.000
2014 2015 Current Spot
$MM/1,000’Lateral
Well Cost ($MM/1,000' of Lateral)
16%
Decrease
vs. 2014
$1.57
$1.29
$1.13
$0.000
$0.500
$1.000
$1.500
$2.000
2014 2015 Current Spot
$MM/1,000’Lateral
Well Cost ($MM/1,000' of Lateral)
18%
Decrease
vs. 2014
12%
Decrease
vs. 2015
11%
Decrease
vs. 2015

WORLD CLASS MARCELLUS SHALE
DEVELOPMENT PROJECT
100% operated
Operating 7 drilling rigs including
1 intermediate rig
422,000 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+ years
433 horizontal wells completed
and online
– Laterals average 7,500’
– 100% drilling success rate
6 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 currently
Net 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 Gas
138,000 Net Acres
971 Gross Locations
Rich Gas
91,000 Net Acres
553 Gross Locations
Dry Gas
107,000 Net Acres
755 Gross Locations
Highly-Rich/Condensate
86,000 Net Acres
626 Gross Locations
HEFLIN UNIT
30-Day Rate
2H: 21.4 MMcfe/d
(21% liquids)
CONSTABLE UNIT
30-Day Rate
1H: 14.3 MMcfe/d
(25% liquids)
Sherwood
Processing
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 UNIT
30-Day Rate
1H: 18.2 MMcfe/d
(27% liquids)
BEE LEWIS PAD
30-Day Rate
4-well combined
30-Day Rate of
67 MMcfe/d
(26% liquids)
RJ SMITH PAD
30-Day Rate
4-well combined
30-Day Rate of
56 MMcfe/d
(21% liquids)
29
HENDERSHOT UNIT
30-Day Rate
1H: 16.3 MMcfe/d
2H: 18.1 MMcfe/d
(29% liquids)
HORNET UNIT
30-Day Rate
1H: 21.5 MMcfe/d
2H: 17.2 MMcfe/d
(26% liquids)
CARR UNIT
30-Day Rate
2H: 20.6 MMcfe/d
(20% liquids)
WAGNER PAD
30-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 ENTIRE
MARCELLUS POSITION
30
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 BTU
2.2 Bcfe/1,000’ Lateral
10 SSL Wells
1200-1275 BTU
116 SSL Wells
1100-1200 BTU
104 SSL Wells
Average Antero Marcellus Well
2014
Actual
2015
Actual Target
30-Day Rate (MMcfe/d): 13.1 15.0 16.1
Gross EUR (Bcfe): 15.3 16.8 19.2
Gross Well Cost ($MM): $11.8 $11.1 $9.1
Lateral Length (Feet): 8,052 8,508 9,000
Net F&D ($/Mcfe): $0.89 $0.78 $0.56
Btu: 1195 1228 1250

0
5
10
15
20
25
30
35
40
45
50
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
WellCount
Bcfe/1,000' of Lateral
0
5
10
15
20
25
30
MMcfe/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 VARIANCE
IN 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)
31
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: 1.6x
StdDev: 0.3x
P90
P10
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
$1.20
0.00
0.50
1.00
1.50
2.00
2.50
2010 2011 2012 2013 2014 2015
DevelopmentCost($/Mcfe)
EUR/1,000'Lateral
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
AverageFracStagesperWell
AverageStageLength(Feet)
Increasing Frac Stages per Well
Average Stage Length (Feet) Average Frac Stages per Well
32
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
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
TotalMeasuredDepth
Spud-to-RigReleaseDays
Increasing Drilling Efficiency
Avg Spud-to-RR Days Total Measured Depth (Feet)
5,732
6,717
7,345 7,308
8,052 8,508
9,033
19
38
59
103
136
74
80
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 2016E
WellsonFirstSales
LateralLength(Feet)
Increasing Lateral Lengths
Average Lateral Length (Feet) Wells on First Sales

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
 109 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 SHALE
DEVELOPMENT PROJECT
33
Cadiz
Processing
Plant
NORMAN UNIT
30-Day Rate
2 wells average
16.8 MMcfe/d
(15% liquids)
RUBEL UNIT
30-Day Rate
3 wells average
17.2 MMcfe/d
(20% liquids)
Utica
Core
Area
GARY UNIT
30-Day Rate
3 wells average
24.2 MMcfe/d
(21% liquids)
Highly-Rich/Cond
29,000 Net Acres
98 Gross Locations
Highly-Rich Gas
11,000 Net Acres
108 Gross Locations
Rich Gas
30,000 Net Acres
161 Gross Locations
Dry Gas
41,000 Net Acres
263 Gross Locations
NEUHART UNIT 3H
30-Day Rate
16.2 MMcfe/d
(57% liquids)
Condensate
36,000 Net Acres
184 Gross Locations
DOLLISON UNIT 1H
30-Day Rate
19.8 MMcfe/d
(40% liquids)
MYRON UNIT 1H
30-Day Rate
26.8 MMcfe/d
(52% liquids)
Seneca
Processing
Complex
LAW UNIT
30-Day Rate
2 wells average
16.1 MMcfe/d
(50% liquids)
SCHAFER UNIT
30-Day Rate(1)
2 wells average
14.2 MMcfe/d
(49% liquids)
URBAN PAD
30-Day Rate
4 wells average
18.8 MMcfe/d
(15% liquids)
GRAVES UNIT
500’ Density Pilot
30-Day Rate
4 wells average
15.5 MMcfe/d
(24% liquids)
FRANKLIN UNIT
30-Day Rate
3 wells average
17.6 MMcfe/d
(16% liquids)
FRAKES UNIT
30-Day Rate
2 wells average
18.6 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
$1.80
0.00
0.50
1.00
1.50
2.00
2013 2014 2015
DevelopmentCost($/Mcfe)
EUR/1,000'Lateral
EUR vs. Development Cost Per Unit
EUR/1,000' Lateral (Bcfe) Development Cost ($/Mcfe)
34
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
289
183 175
26
47
49
-
10
20
30
40
50
60
-
50
100
150
200
250
300
350
2013 2014 2015
AverageFracStagesperWell
AverageStageLength(Feet)
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
TotalMeasuredDepth(Feet)
Spud-to-RigReleaseDays
Increasing Drilling Efficiency
Spud-to-RR Days Total Measured Depth (Feet)
6,431
8,021
8,662 8,792
11
41
57
30
0
10
20
30
40
50
60
70
0
2,000
4,000
6,000
8,000
10,000
2013 2014 2015 2016E
WellsonFirstSales
LateralLength(Feet)
Increasing Lateral Lengths
Average Lateral Length (Feet) Wells on First Sales

LARGE UTICA SHALE DRY GAS POSITION
35
 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:
Chesapeake
Hubbard BRK #3H
3,550’ Lateral
IP 11.1 MMcf/d
Hess
Porterfield 1H-17
5,000’ Lateral
IP 17.2 MMcf/d
Gulfport
Irons #1-4H
5,714’ Lateral
IP 30.3 MMcf/d
Eclipse
Tippens #6H
5,858’ Lateral
IP 23.2 MMcf/d
Magnum Hunter
Stalder #3UH
5,050’ Lateral
IP 32.5 MMcf/d
Well Operator
24-hr IP
(MMcf/d)
Lateral
Length
(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. The Rymer 4HD has been flowing into the sales line for 60 days with an average choke-restricted flow rate of 20 MMcf/d.
Magnum Hunter
Stewart Winland 1300U
5,289’ Lateral
IP 46.5 MMcf/d
Range
Claysville SC #11H
5,420’ Lateral
IP 59.0 MMcf/d
Chevron
Conner 6H
6,451’ Lateral
IP 25.0 MMcf/d
Gastar
Simms U-5H
4,447’ Lateral
IP 29.4 MMcf/d
Utica Shale Dry Gas Acreage in OH/WV/PA(1)
Rice
Bigfoot 9H
6,957’ Lateral
IP 41.7 MMcf/d
AR Utica Shale Dry Gas
WV/PA
Net Resource
12.5 to 16 Tcf
1,889 Gross Locations
188,000 Net Acres
Ohio
3P Reserves
2.3 Tcf
263 Gross Locations
41,000 Net Acres
Total OH/WV/PA
Net Resource
14.8 to 18.3 Tcf
2,152 Gross Locations
229,000 Net Acres
Stone Energy
Pribble 6HU
3,605’ Lateral
IP 30.0 MMcf/d
Southwestern
Messenger 3H
5,889’ Lateral
IP 25.0 MMcf/d
Rice
Blue Thunder
10H, 12H
≈9,000’ Lateral
Gastar
Blake U-7H
6,617’ Lateral
IP 36.8 MMcf/d
EQT
Scotts Run
3,221’ Lateral
IP 72.9 MMcf/d
CNX
Gaut 4IH
5,840’ Lateral
IP 61.0 MMcf/d
Antero
Rymer 4HD
6,620’ Lateral
IP 20.0 MMcf/d
(2)

ANTERO’S FIRST UTICA DRY GAS WELL
36
 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 for first 60 days
 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
Gulfport
Irons #1-4H
5,714’ Lateral
IP/1,000’: 5.3 MMcf/d
Range
Claysville SC #11H
5,420’ Lateral
IP/1,000’: 10.9 MMcf/d
CNX
Gaut 4IH
5,840’ Lateral
IP/1,000’: 10.4 MMcf/d
EQT
Scotts Run
3,221’ Lateral
IP/1,000’: 22.6 MMcf/d
Gastar
Blake U-7H
6,617’ Lateral
IP/1,000’: 5.6 MMcf/d
Gastar
Sims U-5H
4,447’ Lateral
IP/1,000’: 6.6 MMcf/d
Stone Energy
Pribble 6HU
3,605’ Lateral
IP/1,000’: 8.3 MMcf/d
Magnum Hunter
Stalder #3UH
5,050’ Lateral
IP/1,000’: 6.4 MMcf/d
Magnum Hunter
Stewart Winland 1300U
5,280’ Lateral
IP/1,000’: 8.8 MMcf/d
Utica Dry Gas Fairway
Antero
Rymer 4HD
6,620’ Lateral
IP 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 SALES PORTFOLIO
37
MMBtu/d
Columbia
7/26/2009 – 9/30/2025
Firm Sales #1
10/1/2011– 10/31/2019
Firm Sales #2
10/1/2011 – 11/30/2015
Firm Sales #3
1/1/2013 – 5/31/2022
Momentum III
9/1/2012 – 12/31/2023
EQT
8/1/2012 – 6/30/2025
REX/MGT/ANR
7/1/2014 – 12/31/2034
Tennessee
11/1/2015– 9/30/2030
(Stonewall/WB) Mid-Atlantic/NYMEX
(Stonewall/TGP) Gulf Coast
(TCO) Appalachia or Gulf Coast
Appalachia
Appalachia
ANR
3/1/2015– 2/28/2045
(REX/ANR/NGPL/MGT) Midwest
Local Distribution
11/1/2015 – 9/30/2037
(ANR/Rover) Gulf Coast
Antero Transportation Portfolio
1,280 BBtu/d
590 BBtu/d
375 BBtu/d
250 BBtu/d
800 BBtu/d
600 BBtu/d
630 BBtu/d
40 BBtu/d
Gross Gas Production (Actuals) Illustrative Gross Gas Production(1)
1. Assumes production growth guidance of 15% in 2016 and targeted 20% annual production growth in 2017.
2. Based on 2016 production guidance of 1.715 Bcfe/d.
3. Assumes 25% to 50% mitigation on excess capacity and current spreads based on strip pricing as of 12/31/2015.
Lowest cost, local
unfavorable FT projected to
not be used through 2017
2016E Net Marketing Expenses:
$15 Million
$20 Million
$30 to $35 million (3)
$30 to $55 Million (3)
2016E Total Net Marketing Expenses:
$95 to $125 Million
($0.15 to $0.20 per Mcfe)(2)
2017E Net Marketing
Expenses:
$ Amounts in line with 2016
 While Antero has excess FT in place through 2017, the expected cost of unutilized FT is estimated to be manageable at <10% of EBITDA
through 2017
Projected cost after
mitigation due to positive
futures spreads

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 2015
requirements)
LEED Gold Headquarters
Building
 Corporate headquarters in Denver, Colorado LEED Gold Certified
HEALTH, SAFETY, ENVIRONMENT & COMMUNITY
Antero Core Values: Protect Our People, Communities And The Environment
Strong West Virginia
Presence
 79% of all Antero Marcellus
employees and contract
workers are West Virginia
residents
 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
38

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
39

40
Antero Midstream (NYSE: AM)
Asset Overview

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.
End
Users
End
Users
Gas Processing
Y-Grade Pipeline
Long-Haul Interstate
Pipeline
Inter
Connect
NGL Product
Pipelines
Fractionation
Compression
Low Pressure Gathering
Well Pad
Terminals
and
Storage
(Miles) YE 2015 YE 2016E
Marcellus 106 114
Utica 55 56
Total 161 170
AM has option to participate
in processing, fractionation,
terminaling and storage
projects offered to AR
Marcellus 76 98
Utica 36 36
Total 112 134
(MMcf/d) YE 2015 YE 2016E
Marcellus 700 940
Utica 120 120
Total 820 1,060
AM Owned Assets
Condensate Gathering
Stabilization
Utica 19 19
End
Users
AM Option Assets
(Ethane, Propane,
Butane, etc.)
AM’S FULL VALUE CHAIN BUSINESS MODEL
41

1. Represents inception to date actuals as of 12/31/2015 and 2016 midpoint guidance.
2. Includes both expansion capital and maintenance capital.
42
Utica
Shale
Marcellus
Shale
Projected Gathering and Compression Infrastructure(1)
Marcellus
Shale
Utica
Shale Total
YE 2015 Cumulative Gathering/
Compression Capex ($MM) $981 $462 $1,443
Gathering Pipelines
(Miles) 182 91 273
Compression Capacity
(MMcf/d) 700 120 820
Condensate Gathering Pipelines
(Miles) - 19 19
2016E Gathering/Compression
Capex Budget ($MM)(2) $235 $20 $255
Gathering Pipelines
(Miles) 30 1 31
Compression Capacity
(MMcf/d) 240 0 240
Condensate Gathering Pipelines
(Miles) - - -
Gathering and Compression Assets
ANTERO MIDSTREAM GATHERING AND COMPRESSION
ASSET OVERVIEW
• Gathering and compression assets in core of rapidly
growing Marcellus and Utica Shale plays
– Acreage dedication of ~438,000 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 66% of AM units (NYSE: AM)

ANTERO MIDSTREAM WATER BUSINESS OVERVIEW
43
Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.
1. Represents inception to date actuals as of 12/31/2015 and 2016 midpoint guidance.
2. All Antero water withdrawal sites are fully permitted under long-term state regulatory permits both in WV and OH.
3. Includes both expansion capital and maintenance capital.
4. Marcellus 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. Utica 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.
 AM acquired AR’s integrated water business for $1.05 billion plus earn out payments of $125 million at year-end in each of 2019 and 2020
− The acquired business includes Antero’s Marcellus and Utica freshwater delivery business, the fully-contracted future advanced wastewater
treatment complex and all fluid handling and disposal services for Antero
Antero advanced wastewater treatment facility
to be constructed – connects to Antero
freshwater delivery system
Projected Water Business Infrastructure(1)
Marcellus
Shale
Utica
Shale Total
YE 2015 Cumulative Fresh Water
Delivery Capex ($MM) $469 $62 $531
Water Pipelines
(Miles) 184 75 259
Fresh Water Storage
Impoundments 22 13 35
2016E Fresh Water Delivery Capex
Budget ($MM)(3) $40 $10 $50
Water Pipelines
(Miles) 20 9 29
Fresh Water Storage
Impoundments 1 - 1
Cash Operating
Margin per Well(4) $700k - $750k
$775k -
$825k
2016E Advanced Waste Water
Treatment Budget ($MM) $130
2016E Total Water Business Budget
($MM) $180
Water Business Assets
• Fresh water delivery assets provide fresh water to support
Marcellus and Utica well completions
– Year-round water supply sources: Clearwater facility, Ohio River,
local rivers & reservoirs(2)
– 100% fixed fee long term contracts
● Advanced wastewater capex of $130 million budgeted in 2016

0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
Antero Clearwater Advanced Wastewater Treatment Capacity (Bbl/d)
Produced/Flowback Volumes (Bbl/d)
Illustrative Produced & Flowback Water VolumesAdvanced Wastewater Treatment
Antero Produced Water Services and Freshwater Delivery Business
Antero Advanced
Wastewater Treatment
3rd Party Recycling
and Well Disposal
(Bbl/d)
Advanced Wastewater Treatment Complex
Estimated capital expenditures ($ million)(1) ~$275
Standalone EBITDA at 100% utilization(2) ~$55 – $65
Implied investment to standalone EBITDA build-out multiple ~4x – 5x
Estimated per well savings to Antero Resources ~$150,000
Estimated in-service date Late 2017
Operating capacity (Bbl/d) 60,000
Operating 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
44Integrated Water Business
Antero Advanced
Wastewater Treatment
Freshwater delivery system
Flowback and
produced
Water
Well Pad
Well Pad
Completion
Operations
Producing
Freshwater
Salt
Calcium Chloride
Marketable byproduct
Marketable byproduct used in oil
and gas operations
Freshwater delivery system
ANTERO MIDSTREAM ADVANCED WASTEWATER
TREATMENT ASSET OVERVIEW

$1
$5 $7 $8
$11
$19
$28
$36
$41
$55
$83
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
26 31 40 36 41
116
222
358
454 435
478
0
100
200
300
400
500
600
700
800 Utica Marcellus
10 38 80 126
266
531
908
1,134 1,197 1,216 1,195
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800 Utica Marcellus
108
216
281 331 386
531
738
935 965
1,038
1,124
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800 Utica Marcellus
Low Pressure Gathering (MMcf/d)
Compression (MMcf/d)
High Pressure Gathering (MMcf/d)
EBITDA ($MM)
45
$313
HIGH GROWTH MIDSTREAM THROUGHPUT
Note: Y-O-Y growth based on 4Q’14 to 4Q’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
TotalDebt/LQAEBITDA
• $1.5 billion revolver in place to fund future growth capital
(5x Debt/EBITDA Cap)
• Liquidity of $887 million at 12/31/2015
• Sponsor (NYSE: AR) has Ba2/BB corporate ratings
AM Liquidity (12/31/2015)
AM Peer Leverage Comparison(1)
($ in millions)
Revolver Capacity $1,500
Less: Borrowings 620
Plus: Cash 7
Liquidity $887
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
46
(2)

($ in millions) 12/31/2015
Cash $23
Senior Secured Revolving Credit Facility 707
Midstream Bank Credit Facility 620
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
Net Unamortized Premium 7
Total Debt $4,709
Net Debt $4,686
Financial & Operating Statistics
LTM EBITDAX(1)
$1,221
LTM Interest Expense(2) $237
Proved Reserves (Bcfe) (12/31/2015) 13,215
Proved Developed Reserves (Bcfe) (12/31/2015) 5,838
Credit Statistics
Net Debt / LTM EBITDAX 3.8x
Net Debt / Net Book Capitalization 39%
Net Debt / Proved Developed Reserves ($/Mcfe) $0.80
Net Debt / Proved Reserves ($/Mcfe) $0.35
Liquidity
Credit Facility Commitments(3) $5,500
Less: Borrowings (1,327)
Less: Letters of Credit (702)
Plus: Cash 23
Liquidity (Credit Facility + Cash) $3,494
ANTERO CAPITALIZATION – CONSOLIDATED
1. LTM and 12/31/2015 EBITDAX reconciliation provided on page 69.
2. LTM interest expense adjusted for all capital market transactions since 1/1/2015.
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.
48

ANTERO RESOURCES – 2016 GUIDANCE
Key Variable 2016 Guidance
Net Daily Production (MMcfe/d) 1,715
Net Residue Natural Gas Production (MMcf/d) 1,355
Net C3+ NGL Production (Bbl/d) 46,500
Net Ethane Production (Bbl/d) 10,000
Net Oil Production (Bbl/d) 3,500
Net Liquids Production (Bbl/d) 60,000
Natural Gas Realized Price Premium to NYMEX Henry Hub Before Hedging ($/Mcf)(1)(2) +$0.00 to $0.10
Oil Realized Price Differential to NYMEX WTI Oil Before Hedging ($/Bbl) $(10.00) - $(11.00)
C3+ NGL Realized Price (% of NYMEX WTI)(1) 35% - 40%
Ethane Realized Price (Differential to Mont Belvieu) ($/Gal) $0.00
Operating:
Cash Production Expense ($/Mcfe)(3) $1.50 - $1.60
Marketing Expense, Net of Marketing Revenue ($/Mcfe) $0.15 - $0.20
G&A Expense ($/Mcfe) $0.20 - $0.25
Operated Wells Completed 110
Drilled Uncompleted Wells 70
Average Operated Drilling Rigs ≈ 7
Capital Expenditures ($MM):
Drilling & Completion $1,300
Land $100
Total Capital Expenditures ($MM) $1,400
1. Based on current strip pricing as of December 31, 2015.
2. Includes Btu upgrade as Antero’s processed tailgate and unprocessed dry gas production is greater than 1000 Btu on average.
3. Includes lease operating expenses, gathering, compression and transportation expenses and production taxes.
Key Operating & Financial Assumptions
49

ANTERO MIDSTREAM – 2016 GUIDANCE
Key Variable 2016 Guidance
Financial:
Adjusted EBITDA ($MM) $300 - $325
Distributable Cash Flow ($MM) $250 - $275
Year-over-Year Distribution Growth(1) 28% - 30%
Operating:
Low Pressure Pipeline Added (Miles) 9
High Pressure Pipeline Added (Miles) 22
Compression Capacity Added (MMcf/d) 240
Fresh Water Pipeline Added (Miles) 30
Capital Expenditures ($MM):
Gathering and Compression Infrastructure $240
Fresh Water Infrastructure $40
Advanced Wastewater Treatment $130
Maintenance Capital $25
Total Capital Expenditures ($MM) $435
1. Reflects the expected distribution growth percentage associated with the fourth quarter 2016 over the fourth quarter 2015.
Key Operating & Financial Assumptions
50

$1,300
$100
Drilling & Completion Land
2016 CAPITAL BUDGET
By Area
51
$1.8 Billion – 2015(1)
By Segment ($MM)
$1,650
$160
Drilling & Completion Land
56%
44%
Marcellus Utica
By Area
$1.4 Billion – 2016
By Segment ($MM)
 Antero’s 2016 initial capital budget is $1.4 billion, a 23% decrease from 2015 capital expenditures of $1.8 billion and a 58%
decline from 2014 capital expenditures
23%
131 Completions
 50 DUCs
1. Excludes $39 million for leasehold acquisitions in 2015. DUCs are drilled but uncompleted wells at year-end.
110 Completions
 70 DUCs
75%
25%
Marcellus Utica

0.1
0.4
0.9
1.8
3.5
5.6
TBD
$0.0
$0.5
$1.0
$1.5
$2.0
$2.5
$3.0
$3.5
$4.0
$4.5
$5.0
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
2010 2011 2012 2013 2014 2015
Utica Marcellus Borrowing Base
$4.5 Bn
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.
52
3P RESERVES BY VOLUME – 2015(1)NET PDP RESERVES (Tcfe)(1)
NET PROVED RESERVES (Tcfe)(1) 2015 RESERVE ADDITIONS
• Proved reserves increased 4% to 13.2 Tcfe at 12/31/2015 with a pre-tax
PV-10 of $6.7 billion at SEC pricing, including $3.1 billion of hedges
− Proved PV-10 at strip pricing of $8.2 billion, including $2.5 billion of
hedges
• 3P reserves were 37.1 Tcfe at 12/31/2015 with a pre-tax PV-10 of $6.8
billion at SEC pricing, including $3.1 billion of hedges
− 3P PV-10 at strip pricing of $13.7 billion, including $2.5 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
2.8
4.3
7.6
12.7
(Tcfe)
13.2
13.2 Tcfe
Proved
21.4 Tcfe
Probable
2.5 Tcfe
Possible
Proved
Probable
Possible
37.1 Tcfe 3P
93% 2P
Reserves
(Tcfe) $Bn
$550 MM

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)
53
Marcellus – 29.6 Tcfe
Utica – 7.5 Tcfe
Upper Devonian – 0.0 Tcfe
37.1
Tcfe
Marcellus – 34.0 Tcfe
Utica – 8.4 Tcfe
Upper Devonian – 0.0 Tcfe
42.4
Tcfe
20%
Liquids
35%
Liquids

626
971
553
755
63%
47%
24% 28%
34%
22%
9% 11% 0
200
400
600
800
1,000
1,200
0%
20%
40%
60%
80%
Highly-Rich Gas/
Condensate
Total3PLocations
ROR
Total 3P Locations
ROR @ 12/31/2015 Strip Pricing - After Hedges
ROR @ 12/31/2015 Strip Pricing - Before Hedges
MARCELLUS SINGLE WELL ECONOMICS
– IN ETHANE REJECTION
54
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-$28
Marcellus Well Economics and Total Gross Locations(1)
Classification
Highly-Rich Gas/
Condensate
Highly-Rich
Gas Rich Gas Dry Gas
Modeled BTU 1313 1250 1150 1050
EUR (Bcfe): 20.8 18.8 16.8 15.3
EUR (MMBoe): 3.5 3.1 2.8 2.6
% Liquids: 33% 24% 12% 0%
Lateral Length (ft): 9,000 9,000 9,000 9,000
Well Cost ($MM): $9.1 $9.1 $9.1 $9.1
Bcfe/1,000’: 2.3 2.1 1.9 1.7
Net F&D ($/Mcfe): $0.52 $0.57 $0.64 $0.70
Direct Operating Expense ($/well/month): $1,498 $1,498 $1,498 $1,498
Direct Operating Expense ($/Mcf): $0.92 $0.92 $1.17 $0.70
Transportation Expense ($/Mcf): $0.28 $0.28 $0.28 $0.28
Pre-Tax NPV10 ($MM): $8.9 $5.1 ($0.7) $0.2
Pre-Tax ROR: 34% 22% 9% 11%
Payout (Years): 2.0 2.8 6.5 5.5
Gross 3P Locations(3): 626 971 553 755
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, 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.
2016
Drilling
Plan

184
98
108
161 263
16%
57%
83%
71%
80%
10%
27% 29%
23% 26%
0
50
100
150
200
250
300
0%
20%
40%
60%
80%
100%
Condensate Highly-Rich Gas/
Condensate
Total3PLocations
ROR
Total 3P Locations
ROR @ 12/31/2015 Strip Pricing - After Hedges
ROR @ 12/31/2015 Strip Pricing - Before Hedges
UTICA SINGLE WELL ECONOMICS
– IN ETHANE REJECTION
55
DRY GAS LOCATIONS RICH GAS LOCATIONS
HIGHLY
RICH GAS
LOCATIONS
Utica Well Economics and Gross Locations(1)
Classification Condensate
Highly-Rich Gas/
Condensate
Highly-Rich
Gas Rich Gas Dry Gas
Modeled BTU 1275 1235 1215 1175 1050
EUR (Bcfe): 9.4 17.0 25.3 23.8 21.4
EUR (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 9,000
Well Cost ($MM): $10.2 $10.2 $10.2 $10.2 $10.2
Bcfe/1,000’: 1.0 1.9 2.8 2.7 2.4
Net F&D ($/Mcfe): $1.34 $0.74 $0.50 $0.53 $0.59
Fixed Operating Expense ($/well/month): $2,788 $2,788 $2,788 $2,788 $1,498
Direct Operating Expense ($/Mcf): $0.99 $0.99 $0.99 $0.99 $0.50
Direct Operating Expense ($/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 $6.4
Pre-Tax ROR: 10% 27% 29% 23% 26%
Payout (Years): 7.8 3.1 2.9 3.7 3.2
Gross 3P Locations(3): 184 98 108 161 263
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 $1.2 million for road, pad and production facilities, assume
Antero will begin to realize lower well costs in 2016 as the company utilizes incremental completion crews for deferred completions beginning at year end 2015 and as existing drilling rig contracts
begin to roll off during 2016.
2. Pricing for a 1225 BTU y-grade ethane rejection barrel. NGLs at 37.5% of WTI for 2016 and 50% of WTI for 2017 and thereafter. NGL prices are forecast to increase in 2017 relative to WTI due to
projected in-service date of Mariner East 2 project allowing for a significant increase in AR NGL exports via ship.
3. Undeveloped well locations as of 12/31/2015. 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content.
2016
Drilling
Plan
Assumptions
 Natural Gas – 12/31/2015 strip
 Oil – 12/31/2015 strip
 NGLs – 37% of Oil Price 2016; 50% of
Oil Price 2017+
NYMEX
($/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
$274
($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
$280.0
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
56
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
Guidance Hedged
561. Weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio; excludes impact of TCO basis hedges. 30,000 Bbl/d of propane hedged in 2016, 35,500 Bbl/d hedged in 2017
and 2,000 Bbl/d hedged in 2018.
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
~ 100% of 2017
Target Hedged

$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
$0.70
2013A 2014A 2015E 2016E
($/MMBtu)
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 Firm
Transportation(1)(2)
2013 Firm Transportation – 647 MMcf/d
Average All-in FT Cost $0.25/MMBtu
2016 Firm Transportation – 3.5 Bcf/d
Average 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
57
Appalachia
35%
Midwest
20%
Gulf Coast
45%

$525
$1,000
$1,100
$750
$0
$300
$600
$900
$1,200
$1,500
2015 2016 2017 2018 2019 2020 2021 2022 2023
($inMillions)
$1,500
$887
($620)
$0 $7
$0
$250
$500
$750
$1,000
$1,250
$1,500
Credit Facility
12/31/2015
Bank Debt
12/31/2015
L/Cs Outstanding
12/31/2015
Cash
12/31/2015
Liquidity
12/31/2015
58
STRONG FINANCIAL LIQUIDITY AND DEBT TERM
STRUCTURE
58
$4,000
$2,607
($707)
($702) $16
$0
$1,000
$2,000
$3,000
$4,000
Credit Facility
12/31/2015
Bank Debt
12/31/2015
L/Cs Outstanding
12/31/2015
Cash
12/31/2015
Liquidity
12/31/2015
AR LIQUIDITY POSITION ($MM) AM LIQUIDITY POSITION ($MM)
 Approximately $3.5 billion of combined AR and AM financial liquidity as of 12/31/2015
 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 4.3% and significantly enhance liquidity
while the average debt maturity is February 2021
AM Credit Facility

Moody's S&P
POSITIVE RATINGS MOMENTUM
Moody’s / S&P Historical Corporate Credit Ratings
“Outlook Stable. The affirmation reflects our view that Antero will
maintain funds from operations (FFO)/Debt above 20% in 2016, as it
continues to invest and grow production in the Marcellus Shale. The
company has very good hedges in place, which will limit exposure to
commodity prices.”
- S&P Credit Research, February 2016
“Moody’s confirmed Antero Resources’ rating, which reflects its strong
hedge book through 2018 and good liquidity. Antero has $3.1 billion in
unrealized hedge gains, $3 billion of availability under its $4 billion
committed revolving credit facility and a 67% interest in Antero
Midstream Partners LP.
- Moody’s Credit Research, February 2016
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 Rating Rationale S&P Rating Rationale
59
3/31/2015
Ba2/BB
2/12/20169/1/2010
Ratings Affirmed
February 2016
 Antero’s corporate credit ratings were recently affirmed at Ba2/BB by Moody’s and S&P, respectively, despite the severe
commodity price down cycle

LNG Exports
48%
Mexico/Canada
Exports
18%
Power
Generation
17%
Transportation
1%
Industrial
16%
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
60
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 2020
Mexico/Canada Exports Power Generation
Transportation Petrochem
LNG 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 Total
Sabine 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 1.7
LNG 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
61
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

2015 GLOBAL LPG DEMAND
 Global LPG demand is 8.5 MMBbl/d and growing
62

GLOBAL LPG DEMAND DRIVEN BY
PETCHEM AND RES/COMM
 Largest 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
631. PIRA NGL Study, September 2015.
MMBbl/d
14.7
13.0
11.4
9.8
8.2
6.5
4.9
3.3
1.6

GLOBAL LPG TRADE DRIVEN BY U.S. SHALE
 The U.S. is the largest single driver of the rapid expansion in LPG trade accounting for over 90% in trade growth
MMBbl/d
5.2
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
• 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. petrochem
demand 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
MMBb/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
MBbl/d
Ship Pipeline
250
200
150
100
50
MBbl/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
MBbl/d
Williston PADD 4 PADD 1 (East Coast) PADD 2 PADD 3
No Northeast
rejection after 2017
66
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)
Pricing
Propane: $0.39/Gal
N-Butane: $0.56/Gal
Pricing
Propane: $0.56/Gal
N-Butane: $0.76/Gal
Mariner East II
61,500 Bbl/d AR
Commitment
(see table below) (3)
4Q 2016 In-Service
Shipping
Propane: $0.07/Gal
N-Butane: $0.08/Gal
AR Mariner East II Commitment (Bbl/d)
Product Base Option (3)
Total
Ethane (C2) 11,500 - 11,500
Propane (C3) 35,000 35,000 70,000
Butane (C4) 15,000 15,000 30,000
Total 61,500 50,000 111,500
67
Mont Belvieu Propane Netback ($/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 $0.49
Upside to Appalachia Netback: $0.16 $0.18

ANTERO RESOURCES DECEMBER 31, 2015 RESERVES
68
Reserves Detail – 12/31/2015
Marcellus Shale
Gas
(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 $8,647
% Liquids(3) 21%
Ohio Utica Shale
Gas
(Bcf)
Liquids
(MMBbl)
Total
(Bcfe)
PV-10 ($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 $2,535
% Liquids(3) 15%
Combined Reserves
Gas
(Bcf)
Liquids
(MMBbl)
Total
(Bcfe)
PV-10 ($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
69
EBITDAX Reconciliation
($ in millions) Quarter Ended LTM Ended
12/31/2015 12/31/2015
EBITDAX:
Net income including noncontrolling interest $175.6 $980.0
Commodity derivative fair value (gains) (545.1) (2,381.5)
Net cash receipts on settled derivatives instruments 269.9 856.6
Interest expense 60.5 234.4
Income tax expense (benefit) 77.2 575.9
Depreciation, depletion, amortization and accretion 162.2 711.4
Impairment of unproved properties 60.7 104.3
Exploration expense 0.8 3.8
Equity-based compensation expense 18.6 97.9
State franchise taxes (0.1) 0.1
Contract termination and rig stacking 27.6 38.5
Consolidated Adjusted EBITDAX $307.8 $1,221.4

ANTERO MIDSTREAM EBITDA RECONCILIATION
70
EBITDA and DCF Reconciliation
$ in thousands
Three months ended
December 31,
2014 2015
Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow:
Net income $55,898 $49,008
Add:
Interest expense 2.062 2,892
Depreciation expense 17,290 23,152
Contingent acquisition consideration accretion - 3,333
Equity-based compensation 4,226 4,810
Adjusted EBITDA $79,476 $83,195
Less:
Pre-water acquisition net income attributed to parent (22,234) -
Pre-water acquisition depreciation expense attributed to parent (3,086) -
Pre-water acquisition equity-based compensation expense attributed to parent (654) -
Pre-water acquisition interest expense attributed to parent (359) -
Pre-IPO EBITDA (36,464) -
Adjusted EBITDA $16,679 83,195
Less:
Cash interest paid - attributable to Partnership (331) (2,934)
Income tax witholding upon vesting of Antero Midstream LP equity-based compensation awards - (4,806)
Maintenance capital expenditures attributable to Partnership (1,157) (3,096)
Distributable Cash Flow $15,191 $72,359

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, 2015 included in
this presentation have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates as of December 31, 2015
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, 2015. 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
71

Company website presentation march 2016

Recommended

Recommended

More Related Content

What's hot

What's hot (20)

Viewers also liked

Viewers also liked (20)

Similar to Company website presentation march 2016

Similar to Company website presentation march 2016 (20)

More from AnteroResources

More from AnteroResources (11)

Recently uploaded

Recently uploaded (20)

Company website presentation march 2016