This document is the first quarter 2016 earnings call presentation for Antero Resources Corporation. It contains forward-looking statements and discusses Antero's hedge strategy, which has resulted in $2.1 billion in realized hedge gains since 2009. It also summarizes Antero's projected incremental EBITDA of $125.6 million from its Stonewall project. Additional sections compare Antero's EBITDAX and margins to Appalachian peers, show Antero's continued measured growth, and demonstrate Antero's flexibility and upside in various commodity price scenarios.

1. First Quarter 2016 Earnings Call Presentation
April 28, 2016

2. FORWARD-LOOKING STATEMENTS
This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities,
events or developments that Antero Resources Corporation and its subsidiaries (collectively, the “Company” or “Antero”) expects, believes or
anticipates will or may occur in the future are forward-looking statements. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “estimate,”
“project,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements. However, the
absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-
looking statements contained in this presentation specifically include estimates of the Company’s reserves, expectations of plans, strategies,
objectives and anticipated financial and operating results of the Company, including as to the Company’s drilling program, production, hedging
activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made
by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and
other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are
beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking
statements. These include the factors discussed or referenced under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for
the year ended December 31, 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.

3. $0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$0
$50
$100
$150
$200
$250
$300
$350
$MM
2
 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 the amount of time for well payouts, thereby
enhancing liquidity
 Antero has realized $2.1 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 3/31/2016, the unrealized commodity derivative value is $3.1 billion
● Significant additional hedge capacity remains under the credit facility hedging covenant for 2020 – 2022 period
Quarterly Realized Hedge Gains / (Losses)
Realized Hedge Gains
Projected Hedge Gains
NYMEX Natural Gas
Historical Spot Prices
($/MMBtu)
NYMEX Natural Gas
Futures Prices 03/31/16
3.6 Tcfe Hedged at
average price of
$3.71/Mcfe through
2022
Average Hedge Prices
($/MMBtu)
$3.36
$3.91
$3.57
$3.91
$3.70 $3.66
$3.24
$3.1 Billion in
Projected Hedge
Gains Through 2022Realized $2.1 Billion
in Hedge Gains
Since 2009
HEDGE STRATEGY PRODUCES CONSISTENT RESULTS
AND STABILITY
(1)
1. Represents average hedge price for nine months ending 12/31/2016.

4. Pre Post
In-Service In-Service
Projected 2016 Average Volume (BBtu/d)
DOMS Priced Sales 329 0
TETCO M2 Priced Sales 321 0
TCO Priced Sales 0 54
Firm Sales (TCO / Nymex) 0 595
Total 650 650
2016 Strip Pricing ($/MMBtu)
DOMS (1)
$1.31 N/A
TETCO M2 (1)
$1.29 N/A
TCO (1)
N/A $2.04
Firm Sales (TCO / Nymex) (2)
N/A $1.94
Annual Revenue ($MM)
DOMS $157.1 $0.0
TETCO M2 151.7 0.0
TCO Pool Sales (1)
0.0 40.6
Firm Sales (TCO / Nymex) (2)
0.0 422.5
$308.7 $463.1
Incremental Revenue $154.3
Less: Incremental Firm Transport Costs: (28.7)
Projected Incremental EBITDA $125.6
PROJECTED INCREMENTAL EBITDA FROM STONEWALL
1. 2016 Strip pricing as of March 31, 2016.
2. Blended price based on contracted firm sales volumes with third parties.
Existing TCO capacity of 582 MMcf/d with additional
1.1 Bcf/d of Stonewall transportation and sales has
eliminated all Marcellus swing gas sales to
Dominion South and TETCO M2 thus far in 2016 and
is expected for the full year of 2016
3
2016 DOMS Strip: $1.31
Variance to Nymex ($0.87)
Variance to TCO ($0.73)
2016 TETCO M2 Strip: $1.29
Variance to Nymex ($0.88)
Variance to TCO ($0.75)

5. $2.03
AR P1 P5 P3 P2 P4
$355
AR P5 P1 P3 P2 P4
3Q 2015
$1.97
AR P3 P5 P4 P2 P1
$2.03
AR P3 P2 P1 P5 P4
$2.56
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
P2 AR P5 P3 P4 P1
$308
AR P5 P3 P2 P4 P1
$1.90
AR P3 P4 P2 P5 P1
$291
P5 AR P3 P2 P4 P1
$269
P5 AR P2 P3 P4 P1
$355
$0
$100
$200
$300
$400
$500
P5 P2 AR P4 P3 P1
HIGHEST EBITDAX & MARGINS AMONG PEERS
Quarterly Appalachian Peer Group EBITDAX Margin ($/Mcfe)(1)
Quarterly Appalachian Peer Group EBITDAX ($MM)(1)
1Q 2015 2Q 2015
Note: AR and EQT EBITDAX margin excludes EBITDA from midstream MLP associated with noncontrolling interest. AR consolidated EBITDAX margin for 1Q 2016 was $2.22/Mcfe. CNX excludes EBITDAX
contribution from coal operations.
1. Source: Public data from form 10-Qs and 10-Ks. Peers include COG, CNX, EQT , RRC and SWN.
4Q 2015 1Q 20161Q 2015 2Q 2015
AR Peer Group Ranking – Top Tier
#2 #1 #1 #1 #1
AR Peer Group Ranking – Improving Over Time
#3 #2 #2 #1 #1
Y-O-Y AR: ↔ $0MM
Peer Avg:  $170MM
NYMEX Gas: 30%
NYMEX Oil:  32%
Y-O-Y AR:  21%
Peer Avg:  46%
NYMEX Gas:  30%
NYMEX Oil:  32%
4
3Q 2015
AR has ranked first for both the highest EBITDAX and EBITDAX margin
among Appalachian peers for the second straight quarter
4Q 2015 1Q 2016
TBA
TBA
TBA
TBA
TBA
TBA

6. 3.7x
4.9x
0.6x
1.5x
3.0x
3.4x
3.8x
4.6x
1.3x
2.4x
5.6x
0.0x
1.0x
2.0x
3.0x
4.0x
5.0x
6.0x
AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5
YE 2015 Leverage YE 2016E Leverage
17% 15%
19%
3% 2%
(11%)
12%
(6%)
(5%)
(27%) (44%)-50%
-40%
-30%
-20%
-10%
0%
10%
20%
AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5
2016E Production Growth
2016E EBITDAX Growth
CONTINUED MEASURED GROWTH
5
2015 vs. 2016E Year-End Net Debt / LTM EBITDAX(1),(2)
NOTE: Peers include CNX, COG, EQT, RRC and SWN.
1. 2015 and 2016E production and EBITDAX per Bloomberg Street Consensus estimates. Peer 5 2016E production and EBITDAX per company issued press release.
2. 2016E Debt to EBITDAX assumes year-end 2016E debt divided by 2016E EBITDAX. 2016E debt calculated as 2015 YE debt, less free cash flow. Free cash flow is equal to 2016E EBITDAX, less 2016E
interest expense per Bloomberg consensus estimates, less 2016 capital spending guidance per company press releases.
3. AR pro forma for secondary offering of 8.0 million AM units on 3/24/2016 for net proceeds of $178 million.
9.8x
Antero continues to grow its production and cash flow through the commodity price downturn while also maintaining
prudent leverage metrics
2016E EBITDAX and Production Growth(1)
Antero is the
only one of its
Appalachian
peers that is
growing cash
flow in line with
production
growth
(66%)
(3)

7. 6
1. Revenues represent annual mark-to-market value based on 3/31/2016 strip pricing, including 1Q 2016 actual hedge gain of $324 million.
2. Consensus EBITDAX as of 3/31/2016.
3. Includes targeted drilling and completion cost improvements.
 Antero can achieve 17% year-over-year net production growth for 2016 by spending only $675 million, or approximately $500
million less than the $1.2 billion of expected hedge revenues for the year(1)
 Incremental growth capital of $625 million in 2016 positions Antero to achieve its 20% year-over-year targeted net production
growth in 2017, while only having to spend $875 million in 2017
LOW MAINTENANCE CAPITAL PROVIDES
FLEXIBILITY AND UPSIDE
Maintenance Capital
$275
Maintenance Capital
$500
2016 Growth Capital
$400
2017 Growth Capital
$375
2017 Growth Capital
$625
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
$1,600
2016 2017
$1.3 Bn D&C Budget
0% Y-O-Y
Growth of
1,493 MMcfe/d
17% Y-O-Y
Growth
Contributes to 20%
Y-O-Y Growth
Target for 2017
0% Y-O-Y
Growth of
1,750 MMcfe/d
20% Y-O-Y
Growth Target
for $875 MM
Capex in 2017
Hedge
Revenues
$1,156MM(1)
Hedge
Revenues
$572MM(1)
$MM
2016 2017
Prior year DUCs completed 16 70
D&C Capital – DUCs ($MM) $125 $425
Driven by the DUC inventory, continued capital efficiency
and volumes sold forward at attractive prices, Antero is
positioned to achieve its 2016 guidance and 2017
production target with modest outspend
2018 Growth
Capital
TBD
(3)
Consensus
EBITDAX(2)
Consensus
EBITDAX(2)

8. $3.7
$11.2 $13.9
$20.4
$26.7
$3.1
$2.5
$0.9
($0.3) ($1.6)
$2.4
$2.4 $2.4
$2.4
$2.4
$9.2
$16.1
$17.3
$22.5
$27.6
($5.0)
$0.0
$5.0
$10.0
$15.0
$20.0
$25.0
$30.0
$35.0
$40.0
$45.0
SEC Pricing 12/31/2015 Strip $60 Oil $67.50 Oil $75 Oil
$3.50 Gas $4.00 Gas $4.50 Gas
AR Ownership in AM shares ($B)
Hedge Value Pre-Tax PV-10 ($B)
3P Reserves Pre-Tax PV-10 ($B)
FLEXIBILITY & UPSIDE
7
 As the most active operator in Appalachia, Antero has kept its workforce intact while also preserving the ability to accelerate efficiently when commodity prices
recover
 Accelerated development is further enhanced by Antero’s ability to flow incremental production to the most favorable price indices using Antero’s firm transport
portfolio
 Despite its large hedge position, Antero has tremendous leverage to natural gas and NGL prices due to scale of its 3P reserves and development infrastructure
Net 3P Reserve/Hedge pre-tax PV-10 plus
AM ownership less net debt, Per Share(3)
$45
$64
$83
Increase in pre-tax
PV10 value does not
include the addition of
locations; represents
upside in prices only
on 12/31/15 locations
Note: Assumes NGL prices equal to 37.5% of WTI for 2016 and 50% of WTI thereafter. All PV-10 values are on a pre-tax basis.
1. Total 3P locations of 3,719 less 110 planned completions in 2016.
2. Strip pricing as of December 31, 2015 for each of the first ten years and flat thereafter.
$54 Oil; $3.23 Gas
Increase in reserve pre-tax
PV-10 is well in excess of
hedge PV-10 lost at higher
prices
3P Reserve/Hedge Pre-Tax PV-10 Upside Value(3)
Substantial InventoryOptionality to Accelerate Development
$41
Remaining
Undeveloped
3P Locations(1)
3,609
85%
Producing Wells
at YE 2015
540 wells producing
1.5 Bcfe/d net (13%)
2016E Well
Completions
110 (2%)
3. PV-10 of 3P reserves and hedges less $4.7 billion of net debt as of 3/31/2016, plus market value of 108.9
million AM units owned by AR (as of 3/31/2016).
(2)
0
500
1,000
1,500
2,000
2,500
0
5
10
15
20
25
2013 2014 2015 2016E 2017E
Average Rigs
Ability to triple rig count
from 2016 levels, as
demonstrated by
historical rig utilization
# of Antero Rigs MMcfe/d
AR Net
Production
2016 Guidance
2017 Target
($Bn)

9. Old Borrowing Base $4,500 $4,000 $3,400 $3,250 $3,000 $4,000 $2,000 $2,000 $1,525 $2,600 $1,400 $1,750 $1,000
New Borrowing Base $4,500 $4,000 $3,200 $2,800 $3,000 $2,750 $2,000 $1,250 $1,150 $1,050 $1,050 $1,025 $1,000
Result -- -- ($200) ($450) -- ($1,250) -- ($750) ($375) ($1,550) ($350) ($725) -- Average
% change -- -- (6%) (14%) -- (31%) -- (38%) (25%) (60%) (25%) (41%)
--
(30%)
SPRING 2016 BORROWING BASE REAFFIRMED
Borrowing Base Actions
(1) Note: Represents Spring 2016 borrowing base actions for all public companies with a borrowing base greater than $1 billion prior to the redetermination.
 Antero’s $4.5 Billion borrowing base was reaffirmed by its lender group, representing one of only five public E&P companies that
did not receive a reduction in its borrowing base thus far in the redetermination season (1)
– Driven by significant PDP reserve growth and increase in value of hedge position
8
$2,800
$3,000
$2,000
$1,150 $1,050 $1,050 $1,025
$4,000
$4,500
$4,000
$3,200
$3,250
$2,000
$1,525
$2,600
$1,400
$1,000
AR CHK COG CXO RRC WLL CNX SM OAS DNR EGN WPX MRD
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
$4,000
$4,500
BorrowingBaseAmount($mm)
$3,400
$1,250Antero was one of only five public
E&P companies (one of three
Appalachia operators) that did not
receive a reduction in their
borrowing base from March’s
redetermination process
Red New Borrowing Base
Borrowing Base Affirmed
$450
$1,250
$350
$ Amount of Reduction
$725
$1,550$375
$750
$200
$2,750
$1,750
Appalachian Company

10. PROVEN TRACK RECORD OF WELL COST REDUCTIONS
9
Marcellus Well Cost Reductions for a 9,000’ Lateral ($MM)(1)
NOTE: Based on statistics for drilled wells within each respective period.
1. Based on 200 ft. stage spacing.
2. Based on 175 ft. stage spacing.
$5.3 $4.6 $5.3 $4.7 $4.7 $4.7
$8.7
$7.8
$7.6 $7.1 $7.1
$5.6
$-
$2
$4
$6
$8
$10
$12
$14
$16
2014 Q4 2015 Q1 2015 Q2 2015 Q3 2015 Q4 2016 Q1
$MM
DRILLING AFE COMPLETION AFE
$14.0
$12.4 $12.9
$11.8 $11.8
29% Reduction in
Utica well costs since
Q4 2014
Utica Well Cost Reductions for a 9,000’ Lateral ($MM)(2)
$4.0 $3.8 $3.4 $3.2 $3.2 $3.1
$8.3
$7.3 $7.4 $7.0 $7.0
$5.4
$-
$2
$4
$6
$8
$10
$12
$14
2014 Q4 2015 Q1 2015 Q2 2015 Q3 2015 Q4 2016 Q1
$MM
DRILLING AFE COMPLETION AFE
$12.3
$11.1 $10.8
$10.2 $10.2
$0.95 / 1,000’
32% Reduction in
Marcellus well costs
since Q4 2014
17% Reduction vs. well
costs assumed in YE
2015 reserves
13% Reduction vs. well
costs assumed in YE
2015 reserves
$1.14 / 1,000’
Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016
Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016
COST COST
$8.5
$10.3

11. Marcellus ShaleUtica Shale Ohio
10
Operating Highlights
 Top 10 best drilling footage days in
Marcellus since 2009 have all occurred in
2016, including 5,291’ drilled in 24 hours in
West Virginia on the Charleston 3H
 Recently drilled and cased longest lateral
in company history at 14,024 feet
 Increased sand placement during
completions to 98% in Q1 2016
 Stayed within targeted zone for 98% of
lateral length drilled in Q1 2016
 Utilizing new floating casing procedure,
reducing casing run time by over 12 hours
 Increased proppant loading and shorter
stages in certain areas of the Marcellus
1. Based on statistics for wells completed within each respective period.
2. Year end 2016 forecast.
CONTINUOUS OPERATING IMPROVEMENT
(2)
Utica Marcellus
2014 2015 Q1 2016 Q1 2016 vs. 2014 2014 2015 Q1 2016 Q1 2016 vs. 2014
Activity Levels
Average Rigs Running 4 5 1 (75%) 14 9 7 (50%)
Average Completion Crews 2.0 3.0 1.5 (25%) 5.5 2.0 4.0 (27%)
Operational Improvements
Drilling Days 29 31 24 17% 29 24 21 28%
Average Lateral Length (Ft) 8,543 8,575 9,000 5% 8,052 8,910 9,000 12%
Stages per Well 47 49 51 9% 40 45 45 12%
Stage Length 183 175 175 4% 200 200 200 0%
Stages per Day 3.2 3.7 4.4 38% 3.2 3.5 3.8 19%
Well Cost & Performance Improvements
D&C per 1,000' $1.55 $1.36 $1.14 (26%) $1.34 $1.18 $0.95 (29%)
EUR per 1,000' (Bcf) (1)
1.4 1.6 1.6 14% 1.5 1.7 2.0 33%
EUR per 1,000' (Bcfe) (1)
1.5 1.8 1.8 20% 1.8 1.9 2.3 28%
(2)

12. 1,194
1,128 1,117
990
1,031
1,016
958 956
1,084
1,126
1,274
1,304
1,337
1,418
1,480
1,500
800
900
1,000
1,100
1,200
1,300
1,400
1,500
1,600
Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 Feb-16 Mar-16 2016
Plan
ProppantPlaced(lbs/ft)MARCELLUS PROPPANT PLACEMENT
11
Increased Proppant Load by 25% While Increasing Proppant Placement to 98%
Pilot testing demonstrated
improved recoveries while
maintaining well density

13. 0
5
10
15
20
25
30
35
4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000
EUR(Bcfe)
Lateral Length (Feet)
All Wells Q1 2016 Wells
12
MARCELLUS IMPROVEMENTS DRIVING VALUE CREATION
Antero Marcellus EUR vs. Lateral Length(1)(2)
33 wells > 10,000’ lateral
length and 43 wells waiting
on completion ranging from
10,000’ to 14,000’
1. All 251 wells completed since 2014 when Antero transitioned to shorter stage length completions (SSL).
2. EUR’s include NGL processing (C3+) but assume ethane rejection.
Longer Laterals Better Well Economics
TBD
Current
completions
using 1,500 lbs/ft
of sand and 39
Bbls/ft of water
2016 wells
average 2.3
Bcfe/1,000’
98% sand placement for
1,200 lbs/ft drove
outperformance in 1Q
2016 compared to type
curve
39 wells > 20 Bcfe
High correlation of EURs
to lateral length

14.  While we have not changed our 1.7 Bcf/1,000' Marcellus project-wide type curve, we are seeing stronger EURs per 1,000' in a
significant portion of our Marcellus rich gas acreage as exhibited in our 2.0 Bcf/1,000' average for wells completed in the first quarter
with at least 30 days of production history
$8.7
$11.7
$5.2
$7.7
35%
45%
24%
30%
0%
10%
20%
30%
40%
50%
$0.0
$3.0
$6.0
$9.0
$12.0
$15.0
1.7 Bcf/1,000'
2.3 Bcfe/1,000'
2.0 Bcf/1,000'
2.7 Bcfe/1,000'
1.7 Bcf/1,000'
2.1 Bcfe/1,000'
2.0 Bcf/1,000'
2.5 Bcfe/1,000'
Pre-TaxROR
Pre-TaxPV-10
Pre-Tax PV-10 Pre-Tax ROR
Classification(1) Highly-Rich Gas/Condensate Highly-Rich Gas
BTU Regime 1275-1350 1275-1350 1200-1275 1200-1275
EUR (Bcfe): 20.8 24.4 18.8 22.1
EUR (MMBoe): 3.5 4.1 3.1 3.7
% Liquids: 33% 33% 24% 24%
Lateral Length (ft): 9,000 9,000 9,000 9,000
Well Cost ($MM): $8.5 $8.5 $8.5 $8.5
Bcf/1,000’ 1.7 2.0 1.7 2.0
Bcfe/1,000’: 2.3 2.7 2.1 2.5
Net F&D ($/Mcfe): $0.48 $0.41 $0.53 $0.45
Pre-Tax NPV10 ($MM): $8.7 $11.7 $5.3 $7.7
Pre-Tax ROR: 35% 45% 24% 30%
Payout (Years): 2.5 2.0 3.7 2.9
Breakeven NYMEX Gas Price ($/MMBtu)(5) $1.67 $1.40 $2.31 $2.05
Gross 3P Locations(3): 626 971
13
NYMEX
($/MMBtu)
WTI
($/Bbl)
C3+ NGL(2)
($/Bbl)
2016 $2.26 $41 $16
2017 $2.77 $45 $21
2018 $2.87 $47 $24
2019 $2.93 $49 $25
2020 $3.03 $50 $26
2021-25 $3.49 $51-$53 $27
Assumptions
 Natural Gas – 3/31/2016 strip
 Oil – 3/31/2016 strip
 NGLs – 37.5% of Oil Price
2016; 50% of Oil Price 2017+
4535
2016 Development Plan: Completions
1. 3/31/2016 pre-tax well economics based on a 9,000’ lateral, 3/31/2016 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 include $1.2 million for road, pad and production facilities.
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.
4. Represents actual results for 1Q 2016.
5. Breakeven price for 15% pre-tax rate of return.
MARCELLUS UPSIDE POTENTIAL
Highly-Rich Gas/Condensate Highly-Rich Gas
(4) (4)

15. 14
APPENDIX
14

16. ANTERO RESOURCES EBITDAX RECONCILIATION
15
EBITDAX Reconciliation
($ in millions) Quarter Ended LTM Ended
3/31/2016 3/31/2016
EBITDAX:
Net income including noncontrolling interest $10.7 $591.5
Commodity derivative fair value (gains) (279.9) (1,901.9)
Net cash receipts on settled derivatives instruments 324.3 996.1
Interest expense 63.3 244.4
Income tax expense (benefit) 4.8 333.3
Depreciation, depletion, amortization and accretion 192.2 720.9
Impairment of unproved properties 15.5 111.3
Exploration expense 1.0 3.5
Equity-based compensation expense 23.5 93.6
State franchise taxes 0.0 (0.1)
Contract termination and rig stacking 0.0 29.6
Consolidated Adjusted EBITDAX $355.4 $1,222.2