company overview september 2013

September 2013Company Overview

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 thispresentation that address activities, events or developments that Antero Resources LLC and its subsidiaries (collectively, the “Company”) expects, believes or anticipates will or may occur in the future are forward-looking statements. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. 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 in the Company’s filings with the SEC.

We caution 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, theuncertainty 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 “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012.

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.

Forward-Looking Statements

1

Antero Resources Snapshot• Private E&P company headquartered in Denver, Colorado – extensive shale experience

− Drilled and operated over 450 horizontal shale wells in Barnett, Woodford, Marcellus and Utica Shales

• Appalachian Shale-Focused – a “pure play” company with upstream and midstream assets− Marcellus Shale: 328,000 net acres all located in the Southwestern Core area, 195 horizontal wells completed− Utica Shale: 101,000 net acres all located in the Core of the play, 11 horizontal wells completed− Upper Devonian Shale: 170,000 net acres (overlying Marcellus Shale), 2 horizontal wells completed

• High production growth – Appalachian production has increased 115% year-over-year to 458 MMcfe/d net for 2Q 2013, including 3,300 Bbl/d of liquids

− Estimated August 2013 net production averaged 590 MMcfe/d including 9,000 Bbl/d of liquids− Current net production is 680 MMcfe/d including 13,500 Bbl/d of liquids, with an additional 115 MMcfe/d of net

production including 4,300 Bbl/d of liquids constrained/shut-in waiting on pipeline, compression or processing

• Large, low risk drilling inventory – Over 4,500 horizontal drilling locations will continue to feed high growth in existing 6.3 Tcfe(1) proved reserve base as of June 30, 2013 (assuming ethane rejection)

• Low cost leader – $1.03/Mcfe 3-year pro forma development cost calculated using 2012 J.P. Morgan methodology(2)

− $0.90/Mcfe estimated net future development cost in 6/30/2013 3P reserve base (assuming ethane rejection)

• Rapidly growing liquids exposure – 12% by production volume today, forecast to grow to ~20% by 2014 assuming ethane rejection (~40% liquids exposure if assume ethane recovery in 2014 and beyond)

• Large long-term hedge position – 1,024 Bcfe hedged at $5.11/MMBtu NYMEX-equivalent(3) through 2019

• Infrastructure emphasis – Gathering, compression and processing infrastructure either in place or committed and underway – well positioned in southern portion of Marcellus and Utica Shale plays for access to gas takeaway

• Strong liquidity to fuel low cost growth – ~$1.0 billion(4) of undrawn borrowing base capacity as of June 30, 2013

2

___________________________1. 6/30/2013 SEC reserves assuming ethane rejection using a price deck of $3.43/MMBtu for Appalachia. WTI SEC price averaged $91.65/Bbl. Reserves audited by independent third-party engineers DeGolyger & MacNaughton using

SEC reserve methodology and pricing. 2. Source: Proved developed F&D research report prepared by J.P. Morgan dated 7/22/2013. Includes total drilling and completion costs but excludes land and acquisition costs for all companies. Defined as total drilling and

completion capital expenditures for the period divided by PDP and PDNP volumes added after adding back production for the period. Calculated by Antero using J.P. Morgan methodology; Marcellus and Utica only. 3. In order to compare hedges across basins and commodities, hedged basin prices are converted by Antero to NYMEX-equivalent prices using current basis differentials in the over-the-counter futures market and 6:1 gas to oil ratio. 4. Lender commitments under the facility are $1.75 billion which can be expanded to the full $2.0 billion borrowing base. Undrawn capacity as of 6/30/2013.

Appalachia

Total – SEC Reserves

___________________________1. 6/30/2013 SEC reserves assuming ethane rejection and using a price deck of $3.43/MMBtu for Appalachia. WTI SEC price averaged $91.65/Bbl. Reserves prepared internally using SEC reserve methodology and pricing

and audited by independent third-party engineers DeGolyer & MacNaughton. 2. See note on page 38 for 3P definition. 3. Includes hedge PV-10 value of $944 million.4. All net acres allocated to the Upper Devonian Shale are included among the net acres allocated to the Marcellus Shale as formations attributable to the same leases.

Marcellus Shale

Low Cost Liquids-Rich Reserve Base

SEC Proved Reserves(1) 5,959 BcfeNet 3P Gas Equivalent(1,2) 18,714 BcfeNet 3P Liquids(1,2) 465 MMBbls% Liquids – Net 3P 15%2Q 2013 Net Production 453 MMcfe/dNet Acreage 328,000Undrilled Locations 2,941

SEC Proved Reserves(1) 6.3 TcfeNet 3P Gas Equivalent(1,2) 27.7 TcfeNet 3P Liquids(1,2) 667 MMBbls% Liquids – Net 3P 14%

Proved Developed PV-10(3) $3.0 Billion

Proved PV-10(3) $5.4 Billion

2Q 2013 Net Production 458 MMcfe/d

Net Acreage(4) 429,000

Utica Shale

SEC Proved Reserves(1) 279 BcfeNet 3P Gas Equivalent(1,2) 5,254 BcfeNet 3P Liquids(1,2) 164 MMBbls% Liquids – Net 3P 19%2Q 2013 Net Production 1 MMcfe/dNet Acreage 101,000Undrilled Locations 720

Upper Devonian Shale

SEC Proved Reserves(1) 44 BcfeNet 3P Gas Equivalent(1,2) 3,780 BcfeNet 3P Liquids(1,2) 38 MMBbls% Liquids – Net 3P 6%2Q 2013 Net Production 4 MMcfe/dNet Acreage(4) 170,000Undrilled Locations 915

3

● Antero increased Appalachian proved reserves by 44% at mid-year 2013, assuming ethane recovery, and 47% assuming ethane rejection, from year-end 2012

Marcellus, 18.7 Tcfe

Utica, 5.3 Tcfe

Upper Devonian, 3.8 Tcfe

• Antero’s liquids-rich position provides significant upside to improving NGL pricing– 3P reserves of over 1.6 BBbls of NGLs and condensate assuming ethane recovery mode – 31% liquids

Significant Ethane Optionality

Ethane Rejection(1) Ethane Recovery(1)

Gas, 23.8 Tcf

Oil, 71 MMBbls NGLs, 595

MMBbls

Gas, 22.2 Tcf

Oil, 71 MMBbls

NGLs, 1,580

MMBbls

27.7 Tcfe 32.1 Tcfe

14% Liquids 31% Liquids___________________________1. Ethane rejection occurs when ethane is left in the wellhead gas stream when 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.

4

Marcellus, 21.8 Tcfe

Utica, 6.1 Tcfe

Upper Devonian, 4.2 Tcfe

Strong Track Record of Growth

___________________________1. Proved reserves for 2006, 2007 and 2008 represent previously effective SEC methodology. 2009, 2010, 2011, 2012 and 6/30/2013 proved reserves based on current SEC reserve methodology and

pricing and audited by independent third-party engineers. 2012 excludes Arkoma Basin reserves which were sold on June 29, 2012 and Piceance Basin reserves which were sold on December 21, 2012. Marcellus includes Upper Devonian Shale proved reserves.

2. CAGR = Compound Annual Growth Rate.

Average Net Daily Production

Net Proved SEC Reserves (1)

Appalachia Production

Operated Wells Spud

6 3187 105 133

244

87 235 6801,141

3,231

5,017

8596

126

18

6691Economic

Crisis

119

5

334

4,929156

21

458

2Q 2013

6,282

30

124

239

458

1Q 2013

383383

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

Rang

e

Cabo

t

EQT

SM E

nerg

y

Nob

le

Cim

arex

Sout

hwes

tern

Pion

eer

Conc

ho

Dev

on

Ches

apea

ke

EOG

New

field

0%

20%

40%

60%

80%

100%

Industry Leading Finding Costs

Industry 3-Year All-in Finding Costs Through 2012(1)(2)

3‐Year Comp Median = $2.75/Mcfe(3)

• Based on the Howard Weil 2012 F&D Cost Study, Antero had the lowest three-year average all-in finding cost through 2012 of $0.48/Mcfe

$/Mcfe

Ant

ero

___________________________1. Source: Howard Weil 2012 Finding & Development Cost Study.2. Antero finding costs calculated over 3 years using 12/31/2012 SEC reserves, including Arkoma, Fayetteville and Piceance. Reserves were audited by DeGolyer & MacNaughton (Appalachia, Arkoma and

Fayetteville) and Ryder Scott (Piceance). Antero % Gas Reserves reflects MY 2013 proved reserves assuming ethane rejection. 3. Median calculated for comparable company set used in this graph; excludes Antero.

● Includes all drilling, land and acquisition expenditures

- Most direct Antero comparables

6

% Gas ProvedReserves

$0.48

Marcellus Producers

$0.84 $1.02 $1.31

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

Cabo

t

Rang

e

Sout

hwes

tern

EQT

Ultr

a

Ches

apea

ke

Dev

on

Conc

ho

New

field

Pion

eer

Cim

arex

EOG

SM E

nerg

y

Nob

le

0%

20%

40%

60%

80%

100%

$1.03 $1.14$1.41 $1.57 $1.71

Most-direct Antero comparables___________________________1. Source: Proved developed F&D research report prepared by J.P. Morgan Research dated 7/22/2013. Includes all total drilling and completion costs but excludes land and acquisition costs for all companies. Defined as

total drilling and completion capital expenditures for the period divided by PDP and PDNP volumes after adding back production for the period. Antero % Gas Reserves calculated from 6/30/2013 proved reserves. 2. Median calculated for comparable company set used in this graph; excludes Antero.3. Calculated by Antero using J.P. Morgan methodology – pro forma for divestiture of Arkoma and Piceance properties.4. Calculated by Antero using J.P. Morgan methodology.

Industry 3-Year Development Costs Through 2012(1)

Ant

ero

PF

(3)

$/Mcfe

● Per Mcfe development cost excluding land is a better measure of capital efficiency than finding costs− Antero was the leader in 3-year development costs through 2012

Industry Leading Development Costs

7

Ant

ero

(4)

3‐Year Comp Median = $3.04(2)

% Gas ProvedReserves

• Based on the J.P. Morgan proved developed F&D methodology, Antero ranks as the lowest cost developer with a three-year average pro forma development cost of $1.03/Mcfe

● Antero expects to realize approximately $771 million(1) of hedge gains over the next seven years from its current 1,024 Bcfe hedge book which averages $5.11/MMBtu NYMEX-equivalent, assuming current strip prices− Protects future cash flow thereby supporting drilling plans and production growth

Current Antero Hedge Position – July 1, 2013 through 2019(2)Current Antero Hedge Position – July 1, 2013 through 2019(2)

Natural Gas SwapsHedged Volume

(MMBtu/d)NYMEX-Equivalent Price

($/MMBtu)(2)

2013 470,270 $5.252014 398,000 $5.932015 390,000 $5.692016 522,500 $5.232017 640,000 $4.412018 530,000 $4.732019 87,500 $4.75

___________________________1. Undiscounted value based on STRIP natural gas prices as of August 30, 2013.2. Virtually all hedges are fixed price swaps, hedged to the basin. Basin prices are converted by Antero to NYMEX-equivalent prices using current basis differentials in the over-the-counter futures market and a gas to oil

conversion ration of 6:1.

Strong Hedge Position

8

$91

$206 $217 $182

$24 $52 $-

$62

$(50)

$-

$50

$100

$150

$200

$250

2013 2014 2015 2016 2017 2018 2019

$MM Projected Annual Hedging Gains (1)(2)

Realized Gains Unrealized Gains

$154

9

Asset Overview

9

Appalachian Basin – Overview

10

Antero Marcellus SW PA25,000 Net Acres

2 horizontal wells completed

Antero Marcellus NW WV303,000 Net Acres

193 horizontal wells completed15 rigs running

Southwestern andNortheastern Core Areas

Marcellus Rich Gas Window in Southwestern Core

Upper Devonian Shale Resource Overlies Antero Marcellus Acreage

Antero Utica OH101,000 Net Acres

11 horizontal wells completed4 rigs running

Utica Liquids Rich Fairway

Source: Company presentations and press releases.

Utica Core Area

● 328,000 net acres of leasehold in Southwestern Core of the Marcellus play– 52% HBP with additional 26% not expiring for 5-plus years– Over 80% of acreage has rich gas processing potential

● 100% operated by Antero

● 6.0 Tcfe of proved reserves; 18.7 Tcfe of 3P reserves

● 534 MMcfe/d net operated production estimated for August 2013 including 6,900 Bbl/d of liquids– 585 MMcfe/d of estimated current net production including

8,500 Bbl/d of liquids (including Upper Devonian Shale)

● Operating 15 drilling rigs currently and two frac crews 24/7

● Antero has completed 195 consistently strong horizontal wells, 193 of which are online– Demonstrated ability to drill wells with long laterals

7,000 ft + in less than 30 days– 100% drilling success rate

Fully Integrated● Sherwood I (running at full capacity) and Sherwood II

processing plants currently on line – 400 MMcf/d capacity fully dedicated to Antero– 200 MMcf/d Sherwood III processing plant expected to go

on line in 4Q 2013 with 200 MMcf/d Sherwood IV expected in 2Q 2014

● 1,300,000 MMBtu/d of long-haul firm transportation or firm sales secured – well positioned in southern portion of play− 530,000 MMBtu/d of back-haul firm transportation to Gulf

Coast

● Committed to 20,000 Bbl/d ethane takeaway capacity on Enterprise ATEX pipeline to Mont Belvieu expected to be in service 1Q 2014

Antero Marcellus Shale SummarySummary

11

Large Scale Position in Marcellus Core ● Antero has delineated and de-risked a large scale acreage position in the Southwestern Core of the Marcellus

Shale in northern West Virginia – currently building more infrastructure to process highly rich gas

Sherwood Processing

Plant

Webley Fork 1H:13.3 MMcfe/d 30-day rate

Little Tom 1H:16.0 MMcfe/d 30-day rate

Valentine Unit1H: 5,232 Boe/d IP

(50% Liquids)2H: 3,726 Boe/d IP

(50% Liquids)

Moore Unit1H: 21.5 MMcfe/d 30-day rate2H: 20.5 MMcfe/d 30-day rate

Dry Gas65,000 Net Acres

588 Gross Locations

Rich Gas157,000 Net Acres

1,430 Gross Locations

Highly Rich Gas106,000 Net Acres

923 Gross Locations

Dotson Unit1H: 3,780 Boe/d IP

(50% Liquids)2H:4,547 Boe/d IP

(50% Liquids)

Constable Unit1H: 5,257 Boe/d IP

(51% Liquids)

Source: Company presentations and press releases. Note: All IPs are 24-hour peak rate; Boe/d IPs assume processing and full ethane recovery.

12

Cleta Unit1H: 15.9 MMcfe/d

30-day rate2H: 17.0 MMcfe/d

30-day rate

Triad Spencer Unit4 wells averaged

1,550 Boe/d 30-day rate(54% Liquids)

CHK Hadley Unit1,884 Boe/d IP(58% Liquids)

EQT PEN 15 Unit5 wells averaged

1,553 Boe/d 30-day rate (51% Liquids)

141 Horizontals Completed10.1 Bcfe average EUR

8.3 MMcfe/d average 30-day rate 6,917’ avg lateral length

Prunty Unit1H: 3,205 Boe/d IP

(50% Liquids)

Blanche Unit2H:3,019 Boe/d IP

(52% Liquids)

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

Dec

-09

Feb-

10

Apr

-10

Jun-

10

Aug

-10

Oct

-10

Dec

-10

Feb-

11

Apr

-11

Jun-

11

Aug

-11

Oct

-11

Dec

-11

Feb-

12

Apr

-12

Jun-

12

Aug

-12

Oct

-12

Dec

-12

Feb-

13

Apr

-13

Jun-

13

Aug

-13

Mcf

/d

Gross Mcfd NET MCFD

Strong Marcellus Production Growth

Antero Gross Operated Marcellus Production

13

Bobcat Lateral onlineSeptember 2010

Jarvisville Lateral onlineJune 2011

Tichenal Lateral onlineSeptember 2011

Shift to pad development drilling

Tichenal Compressorrepairs Dec 2012

Infrastructure Delays

14

● Antero has over 3-½ years of production history to support its 1.5 Bcf/1,000’ of lateral recovery assumption as demonstrated by the graph and table below− DeGolyer & MacNaughton (D&M), Antero’s third party reserve auditor, supports this type curve

● Antero’s average 24-hour peak rate is 13.9 MMcf/d in the Marcellus

24-hour peak(3)

30-dayavg. rate

90-dayavg. rate

180-dayavg. rate

One-yearavg. rate

Two-yearavg. rate

Three-yearavg. rate

MMcf/d 13.9 7.9 6.2 5.3 4.0 2.9 2.3# of wells 193 177 171 134 95 49 15

Antero Marcellus Type Curve Support

___________________________Note: Type curve reflects pre-processed wellhead production.1. Wells normalized to time-zero; production for each well normalized to 7,000’ lateral length.2. Actual wellhead IPs, not normalized.3. Excludes two wells that are shut-in and waiting on infrastructure.

0.01.02.03.04.05.06.07.08.09.010.011.012.013.014.015.0

0.01.02.03.04.05.06.07.08.09.0

10.011.012.013.014.015.0

0 1 2 3 4 5 6 7 8 9 10

Cum

ulat

ive

Bcf

MM

cf/d

Production Year

Area 1 Type Curve (7,000' Lateral)Area 1 Actual Production (Normalized to 7,000' Lateral)Area 1 Type Curve Cumulative Production (7,000' Lateral)

Antero Marcellus 1.5 Bcf/1,000’ Type Curve(1)Antero Marcellus 1.5 Bcf/1,000’ Type Curve(1) Antero Marcellus 24-hr Wellhead IPs(2)Antero Marcellus 24-hr Wellhead IPs(2)

0

5

10

15

20

25

30

35

MM

cf/d

1st Production From All Wells 2009 - 2013

Average IP13.9 MMcf/d

-

100

200

300

400

500

600

700

800

0%

50%

100%

150%

200%

250%

300%

950 1000 1050 1100 1150 1200 1250 1300 1350

RO

R

DRY BTU

Marcellus Processing Economics

___________________________1. Assumes 85% NRI and NGL price of 40% of WTI for 1200 BTU y-grade barrel. NGL WTI correlation changes to reflect y-grade barrel composition for different BTU regimes.2. No ethane takeaway available until Enterprise ethane pipeline is online (expected 1Q 2014). Well economics include fixed fee cost tariff on ATEX ethane pipeline.

• Dramatic improvement in returns by processing higher BTU gas – Antero’s Marcellus rich gas leasehold spans the 1050 to 1350 BTU spectrum

• Antero has 2,353 gross processable horizontal locations (>1050 BTU)

Representative of single well examples used for Marcellus rich gas in Appendix

- CurrentAntero rigs

15

No Processing

128% ROR

Dry Gas Locations Rich Gas Locations Highly Rich Gas Locations

57% ROR C2 RejectionC2 Recovery

Single well economics example(1)(2):– 10.0 Bcf well– $8.0 million well cost ($0.94/Mcf net F&D cost)– Assumes $4.25/MMBtu NYMEX 3-year STRIP, $90.00/Bbl oil

and NGL pricing at 40% of WTI for 1200 BTU y-grade barrel

1250 BTU – NGL MarginC2 Rejection: $2.12/McfC2 Recovery: $2.17/Mcf

1150 BTU – NGL MarginC2 Rejection: $0.73/McfC2 Recovery: $0.76/Mcf

Gas$4.38

Gas$4.07

Gas$4.04 Gas

$3.55 Gas

$3.36

Condensate $0.45

Condensate $0.45

NGLs (C3+)$0.96

NGLs (C3+)$2.26

NGLs (C2+)$1.22

NGLs (C2+)$2.62

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

1050 BTU 1150 BTU 1250 BTU 1150 BTU 1250 BTU

Dry Gas Rich Gas Rich Gas

+$2.04Upgrade

___________________________1. Assumes $4.25/MMBtu NYMEX, $90.00/Bbl WTI and current NGL spot prices. 1.054 and 2.070 (ethane rejection) and 3.332 and 5.145 (ethane recovery) GPM s used, all processing costs, shrink and fuel included. No

ethane takeaway available until Enterprise ethane pipeline is online (expected 1Q 2014). Ethane recovery well economics include fixed fee cost tariff on ATEX ethane pipeline.

Marcellus Rich Gas – Liquids and Processing Upgrade

Current – Ethane Rejection Projected – Ethane Recovery

(1085 BTU)4% shrink

(1100 BTU)6% shrink

(1006 BTU)14% shrink


$4.38

$5.03

$6.75

$4.77

$6.42

$/Wellhead Mcf(1)

• Marcellus rich gas and highly rich gas acreage provides a significant advantage in well economics – assuming $4.25/MMBtu NYMEX, $90.00/Bbl WTI and current spot NGL pricing correlation

• Upgrade analysis demonstrates that ethane recovery is not economic at current ethane price

16


($/Mcf)

+$2.37Upgrade

+$0.65Upgrade

+$0.39Upgrade

Fresh Water Management SystemWater Management System MapSummary

17

December 2013 Expected Completion

Date

158-mile Marcellus water sourcing and distribution system to improve operational efficiency and reduce water truck traffic– $375 million total project costs– $200 million in 2013E capital costs– 150-miles of temporary and reusable pipeline,

40 centralized water storage facilities equipped with transfer pumps and 4 pumping stations optimize water delivery

56-mile Utica water sourcing and distribution system to improve operational efficiency and reduce water truck traffic– $150 million total project costs– $50 million in 2013E capital costs– 45-miles of temporary and reusable pipeline

and 22 centralized water storage facilities and equipped with transfer pumps

Reduces frac water costs from $6.00/Bbl to $2.00/Bbl– Cost savings of up to $600,000 per well

Reliable year-round water supply

Over 30% of wells drilled in 2013 and up to 90% of wells drilled in 2014 to utilize new water infrastructure

CNX/HessNoble 16A

8.8 MMcf/d + 1,556 Bbl/d NGL + 768 Bbl/d oil

● Based on geologic analysis and announced drilling results, the core area is in the southern portion of the play

● Antero has 101,000 net acres of leasehold in Core of the Utica play– 20% HBP and remaining 77% not expiring for

5-plus years– Over 90% of acreage has rich gas processing

potential● 100% operated by Antero● Operating four drilling rigs currently; fifth rig to be

added in 4Q 2013● 279 Bcfe of proved reserves; 5.3 Tcfe of 3P

reserves● 56 MMcfe/d net operated production estimated for

August 2013 including 2,100 Bbl/d of liquids– 95 MMcfe/d of estimated current net

production including 5,000 Bbl/d of liquids● 11 wells on line – 30 MMcfe/d of estimated

constrained production● 100% drilling success rateFully Integrated● 80 MMcf/d of priority processing capacity until 4Q

when Seneca I is expected on line● 200 MMcf/d Seneca I cryogenic processing plant

on line in early 4Q 2013 and 200 MMcf/d Seneca II expected on line late 4Q 2013

● Access to 20,000 Bbl/d of ethane takeaway capacity on Enterprise ATEX pipeline to Mont Belvieu expected to be in service 1Q 2014

Antero Utica ShaleSummarySummary

18

Gulfport Energy Wagner #1-28H


Chesapeake Bailey #3H

5.7 MMcf/d + 270 Bbl/d NGL + 205 Bbl/d oil

Chesapeake Brown #10H1,445 Boe/d

(Including 8.7 MMcf/d gas)

ChesapeakeConiglio #6H

1,125 Boe/d with 290 Bbl/d Oil

ChesapeakeMangun #8H

3.1 MMcf/d + 1,015 Bbl/d liquids

ChesapeakeNeider #3H

3.8 MMcf/d + 980 Bbl/d liquids

ChesapeakeShaw #5H

1,435 Boe/d with770 Bbl/d Oil + 180 Bbl/d NGL

ChesapeakeBurgett #8H

1,210 Boe/d with 70% Liquids

ChesapeakeSnoddy #6H


ChesapeakeBuell #8H


Gulfport EnergyShugert #1-12H

26 MMcf/d + 2,907 Bbl/d NGL + 300 Bbl/d oil

Gulfport EnergyShugert #1-1H

20 MMcf/d + 2,022 Bbl/d NGL + 144 Bbl/d oil

Gulfport EnergyBK Stephens #1-16H

6.9 MMcf/d + 759 Bbl/d NGL + 1,224 Bbl/d oil

CNX/HessNoble 1A


Gulfport EnergyBoy Scout #1-33H

7.1 MMcf/d + 1,008 Bbl/d NGL + 1,560 Bbl/d oil

Gulfport EnergyRyser #1-25H


Gulfport EnergyGroh #1-12H


Enervest Cairns #5H


Antero Miley Unit 2H and 5HA

Utica Shale Industry Activity(1)Utica Shale Industry Activity(1)

Hess/CNXAthens A 1H-24

10.2 MMcf/d + 1,803 Bbl/d NGL + 1,056 Bbl/d oil

Utica Core Area

Gulfport EnergyStutzman #1-14H

Peak rate 21 MMcf/d

___________________________Source: Company presentations and press releases. Peak rates are 24-hour rates except where noted.1. In some cases, Antero has converted rich gas rates where BTU has been disclosed to NGLs, assuming ethane recovery. Where BTU has not been disclosed, Antero has estimated BTU and gas composition.

RexxGuernsey 1H


RexxNoble 1H


RexxGuernsey 2H


Antero Wayne Unit 2H, 3HA and 4H

Antero Rubel Unit1H, 2H and 3H

Antero Norman Unit 1HAntero Yontz Unit 1H

Gulfport EnergyMcCort 1-28H


Gulfport EnergyMcCort 2-28H

10 MMcf/d + 1009 Bbl/d NGL

Antero Sanford Unit1H

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

Antero Has Many of the Top Utica IPs Announced

● Antero has achieved 7 of the top 8, and 10 of the top 17, announced Utica IPs to-date

● Some of the best 24-hour peak rates of any shale play in North America– 3,000 to 8,900 Boe/d per

well in the core area● Liquids content from 40% -

70% (assumes ethane recovery)

● Utica Core defined as Noble, Monroe, Guernsey, Belmont and Harrison Counties, Ohio– Actual core is a subset of

these counties and ties to Antero’s geologic model

___________________________Source: Antero, press releases and company presentations. 1. All rates converted to oil equivalent based on press release, assumed BTU and Antero processing model. Not normalized for lateral length.2. Based on 6 and 4 hour tests, respectively.3. Production data based on 7-day IPs.

19

Utica IPs (1)Summary

Core 2,000 to 8,900 Boe/d IPs

Antero Utica Wells 3rd Party Core Utica Wells 3rd Party Non-Core Utica Wells

Tier 11,000 to 2,000 Boe/d IPs

Boe

/d

(2)(2) (3) (3)

Strong Utica Production Growth

Antero Gross Operated Utica Production

20

• Antero brought on 10 Utica wells in August after gaining access to third-party processing

0

2,000

4,000

6,000

8,000

10,000

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

8/1/2013 8/8/2013 8/15/2013 8/22/2013 8/29/2013 9/5/2013

Bo/

d

Mcf

/d

Gross Gas Net Gas Gross Oil Net Oil

Antero Marcellus PA25,000 net acres

21

Integrated Marcellus and Utica Midstream Infrastructure

Own and operate:• 77 miles of gathering pipelines in the Marcellus Shale• 1 mile of gathering pipelines in the Utica Shale• Four compressor stations in the Marcellus Shale• 2013 midstream capex of $500 million for gathering,

compression and water systemThird party access to:• 94 miles of third party gathering in the Marcellus Shale• Nine compressor stations in the Marcellus Shale and three

in the Utica• Total compression capacity of 766 MMcf/d increasing to

2.3 Bcf/d by YE2014• 1 Bcf/d of firm processing capacity (482 MMcf/d in service)• 1.3 Bcf/d of long-haul firm transportation or firm sales• 20,000 Bbl/d of committed ethane takeaway capacityFresh Water Pipeline:• 158-mile proprietary water pipeline system in Marcellus

Shale and 56-mile system in the Utica Shale• Total cost of $525 million, $250 million expected to be

spent in 2013• Reduces well completion costs by up to $600,000 per well

Third PartyPlant Processing

Capacity (MMcf/d)

Contracted Firm Processing Capacity

(MMcf/d)(1)Anticipated Date

of Completion

Marcellus ShaleSherwood I 200 200 In service

Sherwood II 200 200 In service

Sherwood III 200 150 Fourth Quarter 2013

Sherwood IV 200 200 Second Quarter 2014

Marcellus Shale Total 800 750

Third PartyPlant Processing

Capacity (MMcf/d)

Contracted Firm Processing Capacity

(MMcf/d) (1)Anticipated Date

of Completion

Utica Shale

Cadiz (2) 185 - In service

Seneca I (3) 200 200 Fourth Quarter 2013

Seneca II (3) 200 - Fourth Quarter 2013Seneca III (4) 200 100 First Quarter 2014

Utica Shale Total 785 300

1. Contracted firm capacity at the Sherwood and Seneca facilities as of the start-up date of each identified unit.2. Firm interim capacity of 80 MMcf/d at Cadiz will be fixed at 50 MMcf/d capacity upon start-up of the Seneca I processing complex and will terminate upon start-up of the Seneca II processing complex.3. Antero has an option on Seneca I firm capacity that, if exercised by a certain date, would result in an additional 50 MMcf/d of temporary interim capacity at the Seneca II processing facility.4. Remaining 100 MMcf/d of capacity at the Seneca III processing complex is available for commitment at our option.

$0.00 $0.00 $0.00 $0.29

$0.62

$1.35

$2.47 $2.50 $2.94 $3.02 $3.26 $3.27 $3.34

$3.65 $3.66 $3.70 $3.75 $3.81 $4.13 $4.25

$5.05 $5.37 $5.49

$6.75

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

Low Break Even Gas Price Portfolio

Gross Location and Returns Data(1)

Gross Horizontal Drilling Locations • 4,576 gross horizontal drilling locations − Supports significant production growth potential

• Portfolio of rich gas locations provides significant flexibility to achieve reserve and production growth with less sensitivity to commodity price environment

• Over 80% of 4,576 identified horizontal drilling locations target liquids-rich processable gas and many also have condensate

___________________________1. Source: Credit Suisse report dated 06/18/2013 – break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI.

1250 BTU 1050 BTU

22- Antero Projects

3 Yr Strip ~$4.25/MMBtu

923

Wel

l Loc

atio

ns

1,43

0 W

ell L

ocat

ions

208

Wel

l Loc

atio

ns 588

Wel

l Loc

atio

ns

512

Wel

l Loc

atio

ns

$ /

MM

Btu

NYM

EX

Highly Rich Rich Dry TotalMarcellus 923 1,430 588 2,941Utica 208 512 0 720Upper Devonian 6 659 250 915

Total 1,137 2,601 838 4,576

Processable 1,137 2,601 3,738% Processable 82%

Utica21

Marcellus135

2012 Capex Budget by Type 2012 Capex Budget by Project

Total: $1,690MM Total: $1,690MM

2013E Capex Budget by Type 2013E Capex Budget by Project

Total: $1,950MM Total: $1,950MM

2012 and 2013E Capital Budget

23

Land41%

2012 Wells Spud by Project

Total: 119

2013E Wells Planned by Project

Total: 156

Piceance/Arkoma33

Utica3

Marcellus83

Drilling41%Midstream

8%

Piceance/Arkoma6%

Utica41%

Marcellus53%

Utica15%

Marcellus85%

Land13%

Midstream26%

Drilling62%

12 mos. 12 mos. 12 mos. 12 mos. LTM$ millions 12/31/2009 12/31/2010 12/31/2011 12/31/2012 6/30/2013Summary Operating ResultsProduction (Bcfe) (1) 38 49 89 122 138Net Daily Production (MMcfe/d) (1) 105 133 244 334 378EBITDAX (1) $201 $198 $341 $434 $457 Cash interest expense (1) $36 $56 $68 $90 $105 Proved reserves (Bcfe) (2) 1,141 3,231 5,017 4,929 6,282Proved developed reserves (Bcfe) (2) 245 457 844 1,047 1,445Pre-tax Proved PV 10 (2)(3) $625 $1,858 $4,103 $3,223 $5,412

Summary CapitalizationCash and cash equivalents $11 $9 $3 $19 $11

Bank credit facility 142 100 365 217 960 2nd lien credit facility 375 0 0 0 0Subordinated debt 0 25 25 25 25Senior notes 0 528 927 1,227 1,458 Total debt $517 $653 $1,317 $1,469 $2,443 Members' equity 1,393 1,490 1,461 1,461 1,461Non-controlling interest 30 0 0 0 0 Total book capitalization $1,940 $2,143 $2,778 $2,930 $3,904

Net debt $506 $644 $1,314 $1,450 $2,432

Credit StatisticsNet debt / net book capitalization 26.2% 30.2% 47.4% 49.8% 62.5%Net debt / EBITDAX 2.5x 3.3x 3.9x 3.3x 5.3xEBITDAX / interest expense 5.6x 3.5x 5.0x 4.8x 4.4xNet debt / proved reserves ($/Mcfe) $0.44 $0.20 $0.26 $0.29 $0.39 Net debt / proved developed reserves ($/Mcfe) $2.07 $1.41 $1.56 $1.38 $1.68 Net debt / production ($/Mcfed) $4,860 $4,794 $5,381 $4,338 $6,433 Pre-tax Proved PV 10 / net debt 1.2x 2.9x 3.1x 2.2x 2.2x

Includes Discontinued Operations

Financial Summary

24

Current Financial Summary

___________________________1. Production, EBITDAX and cash interest expense are non-GAAP as they include discontinued operations until transaction closing per 2009 - 2012 10-Ks and 6/30/2013 10-Q. Transactions include the Arkoma

Woodford and Fayetteville Shale asset sale for $445 million on June 29, 2012, and the Piceance Basin upstream and midstream asset sale for $325 million on December 21, 2012. 2. LTM proved developed and proved reserves as at 6/30/2013.3. Pre-tax PV-10 value includes hedge value for each year; 2012 includes hedge value of $1.3 billion and 2Q 2013 hedge value is $0.9 billion.

Key Credit Strengths

World class asset base with scale

Liquids-rich Marcellus and Utica shale plays are two of the premier U.S. shale plays Antero has scale in both of these plays – 328,000 net acres in the Marcellus Shale

and 101,000 net acres in the Utica Shale

Large, low risk drilling inventory

$1.03/Mcfe 3-year development cost leader through 2012 per J.P. Morgan equity research methodology

$0.90/Mcfe average net development cost for 6/30/2013 3P reserves – assuming ethane rejection

Low cost leader

115% average Marcellus production growth from 2Q 2012 to 2Q 2013 12% liquids by production volume today forecast to grow to ~20% by 2014 assuming

ethane rejection (~40% assuming ethane recovery)

Large long-term hedge position

1,024 Bcfe hedged at $5.11/MMBtu NYMEX-equivalent(1) through 2019

Rapid production growth with liquids

exposure

100% drilling success rate in the 208 horizontal wells in Marcellus, Utica and Upper Devonian Shales to date

Over 3,600 horizontal drilling locations in the Marcellus and Utica; an additional 900 horizontal drilling locations have been identified in the Upper Devonian

___________________________1. Assumes 1000 Btu average heat content. Excluding Rockies hedges. 2. Lender commitments under the facility are $1.75 billion which can be expanded to the full $2.0 billion borrowing base. Undrawn borrowing base capacity as of 6/30/2013.

25

Strong liquidity ~$1.0 billion of undrawn borrowing base capacity as of June 30, 2013(2)

2626

Appendix

Firm Transportation/Sales Commitments –Appalachia

27

Firm Sales #110/1/2011 – 10/31/2019

Firm Sales #210/1/2011 – 5/31/2017

EQT8/1/2012 – 8/31/2021

Momentum III9/1/2012 – 12/31/2021

Firm Sales #31/1/2013 – 5/31/2022

Columbia7/26/2009 – 9/30/2025

Chicago Direct4/1/2013 – 9/30/2021

MMBtu/d

-

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

Aug-

13

Nov

-13

Feb-

14

May

-14

Aug-

14

Nov

-14

Feb-

15

May

-15

Aug-

15

Nov

-15

Feb-

16

May

-16

Aug-

16

Nov

-16

Feb-

17

May

-17

Aug-

17

Nov

-17

Feb-

18

May

-18

Aug-

18

Nov

-18

Feb-

19

May

-19

Aug-

19

Nov

-19

Feb-

20

May

-20

Aug-

20

Nov

-20

$3.6

-$7.6

$4.7

$25.3$33.6

$29.0$27.9$26.1

$12.3$16.2$17.4

$27.8$29.2

$19.3$25.2

$42.8

$80.0$82.5

$58.7

$49.4$48.1

$14.1

($1.50)

($1.00)

($0.50)

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

($20.0)

$0.0

$20.0

$40.0

$60.0

$80.0

$100.0

Q12008

Q22008

Q32008

Q42008

Q12009

Q22009

Q32009

Q42009

Q12010

Q22010

Q32010

Q42010

Q12011

Q22011

Q32011

Q42011

Q12012

Q22012

Q32012

Q42012

Q12013

Q22013

Quarterly Realized Gains/(Losses)1Q '08 - 2Q '13

• Antero has realized over $665 million of gains on commodity hedges over the past 5-½ years

– Gains realized in 21 of last 22 quarters

Historical Antero Hedging Results

28

$MMs $/Mcfe

Utica Shale Wells – Antero Initial Results

● Antero has drilled and completed 11 Utica Shale wells in the Core of the play to-date

___________________________1. 24-hour peak rates assume full ethane recovery however Antero is currently rejecting ethane due to current market prices. 2. Rubel 2H and 3H peak rates based on 6-hour and 4-hour flow tests, respectively.3. Average of Antero’s first 11 wells, assuming ethane rejection.

29

Antero Utica Well Initial Production Data

LateralWell Oil Eq. Rate Wellhead Gas Condensate Shrunk Gas NGL % Total LengthName County (Boe/d)(1) (MMcf/d) (Bbl/d) (MMcf/d) (Bbl/d) Liquids BTU (Feet)

Yontz 1H Monroe 8,879 38.9 52 33.9 3,177 36% 1161 5,115Rubel 1H Monroe 7,917 31.1 214 25.9 3,391 46% 1231 6,554Rubel 2H(2) Monroe 7,816 30.9 232 25.8 3,284 45% 1217 6,571Rubel 3H(2) Monroe 7,097 28.4 142 23.7 3,003 44% 1220 6,424Norman 1H Monroe 6,181 26.1 45 22.3 2,419 40% 1186 5,498Wayne 3HA Noble 5,852 14.7 1,905 11.6 2,018 67% 1272 6,712Wayne 4H Noble 5,698 14.2 1,922 11.2 1,907 67% 1265 6,493Wayne 2H Noble 4,257 10.9 1,331 8.5 1,503 67% 1281 6,094Miley 2H Noble 3,740 8.6 1,450 6.7 1,172 70% 1278 6,153Miley 5HA Noble 3,369 7.7 1,285 6.0 1,090 70% 1291 6,296Sanford 1H Noble 1,148 1.8 653 1.4 256 79% 1316 7,159

5,632 19.4 839 16.1 2,111 57% 1247 6,2794,682 19.4 839 18.2 805 42% 1247 6,279

Average ‐ Ethane RecoveryAverage ‐ Ethane Rejection(3)

24‐hr Peak Rate

0%

20%

40%

60%

80%

100%

120%

140%

160%

180%

200%

$3.00 $4.00 $5.00 $6.00 $7.00

BTA

X R

OR

NYMEX $/MMbtu$8.0 MM / 9.0 Bcf $8.0 MM / 10.0 Bcf $8.0 MM / 11.0 Bcf

Lateral Length

Well Cost($MM) EUR (Bcf) Net F&D ($/Mcf)

7,000 $8.7 9.8 $1.03

___________________________1. Fixed NYMEX gas prices with appropriate basis adjustment to the Marcellus area. 85% NRI assumed.2. Defined as 10% before tax rate-of-return.

• Assumes 1050 BTU gas – no processing, dry gas• Estimated 588 gross horizontal drilling locations in the dry gas category (950 to 1050 BTU)

Antero Average for First 195 Horizontal Wells

30

Marcellus Shale Well Economics Horizontal Dry Gas

(1)(1) (1) (1) (1)

Well Cost($MMs) EUR (Bcf) F&D ($/Mcf)

NYMEX Breakeven(2)

$8.00 9.0 $1.05 $3.03$8.00 10.0 $0.94 $2.78$8.00 11.0 $0.86 $2.59

3 Yr Strip$4.25/MMBtu25-40% ROR

Long-term$5.50/MMBtu45-70% ROR

NaturalGas,

100%

• Assumes 1150 BTU gas and includes processing margin at $90.00/Bbl oil and 36% WTI NGLs(1)

• Estimated 1,430 gross horizontal drilling locations in the 1050 to 1250 BTU category(2)

NGLs, 36%Natural

Gas, 64%

769 MBbls NGLs

0%

20%

40%

60%

80%

100%

120%

140%

160%

180%

200%

$3.00 $4.00 $5.00 $6.00 $7.00

BTA

X R

OR

NYMEX $/MMbtu$8.0 MM / 9.0 Bcf $8.0 MM / 10.0 Bcf $8.0 MM / 11.0 Bcf $8.0 MM / 10.0 Bcf - Spot NGL Pricing 4/1/13

~57% ROR


Marcellus Shale Well Economics Horizontal Rich Gas

___________________________1. No ethane takeaway available until Enterprise ethane pipeline is online (expected 1Q 2014). Well economics include fixed fee cost tariff on ATEX ethane pipeline.2. Economics will vary considerably depending on Btu and other factors.3. Volumes assume ethane recovery. NGL and oil volumes based on 10 Bcf well.4. Defined as 10% before tax rate-of-return.5. Fixed NYMEX gas prices with appropriate basis adjustment to the Marcellus area. 85% NRI assumed. NGL price of 36% WTI assumed except for SPOT NGL pricing case which assumes C2 rejection.

31

(5) (5) (5) (5) (5)

3 Yr Strip$4.25/MMBtu45-70% ROR


NYMEX Breakeven(4)

$8.00 9.0 $1.05 $1.26$8.00 10.0 $0.94 $0.97$8.00 11.0 $0.86 $0.73 Long-term

$5.50/MMBtu65-105% ROR

Lateral Length

Well Cost($MM) EUR (Bcf) Net F&D ($/Mcf)

7,000 $8.7 9.8 $1.03

(3)

0%

50%

100%

150%

200%

250%

300%

$3.00 $4.00 $5.00 $6.00 $7.00

BTA

X R

OR

NYMEX $/MMbtu$8.0 MM / 9.0 Bcf $8.0 MM / 10.0 Bcf $8.0 MM / 11.0 Bcf $8.0 MM / 10.0 Bcf - Spot NGL Pricing 4/1/13

• Assumes 1250 BTU gas and includes processing margin at $90.00/Bbl oil and 44% WTI NGLs(1)

• Estimated 923 gross horizontal drilling locations in the 1250 to 1350 BTU category(2)


Marcellus Shale Well Economics Horizontal Highly-Rich Gas

32

(5) (5) (5) (5) (5)


NYMEX Breakeven(4)

$8.00 9.0 $1.05 $0 $8.00 10.0 $0.94 $0$8.00 11.0 $0.86 $0

3 Yr Strip$4.25/MMBtu

100-155% ROR

Long-term$5.50/MMBtu

130-200% ROR

~128% ROR

% Oil, 2%

NGLs, 47%

NaturalGas, 51%

(3)Lateral Length

Well Cost($ MM) EUR (Bcf) Net F&D ($/Mcf)

7,000 $8.7 9.8 $1.03

___________________________1. No ethane takeaway available until Enterprise ethane pipeline is online (expected 1Q 2014). Well economics include fixed fee cost tariff on ATEX ethane pipeline.2. Economics will vary considerably depending on Btu and other factors.3. Volumes assume ethane recovery. NGL and oil volumes based on 10 Bcf well.4. Defined as 10% before tax rate-of-return.5. Fixed NYMEX gas prices with appropriate basis adjustment to the Marcellus area. 85% NRI assumed. NGL price of 44% WTI assumed except for SPOT NGL pricing case which assumes C2 rejection.

1,194 MBbls NGLs; 24 MBbls/Oil

Marcellus Processing Barrels – 1150 BTU

NGL Barrel - VolumeNGL Barrel - Volume

Current NGL Value - $17.27/Bbl(1)Current NGL Value - $44.48/Bbl(1)

C2 Recovery

C2 Recovery

C2 Rejection

C2 Rejection

___________________________1. Assumes $90.00/Bbl WTI pricing and current spot NGL prices.

33

Propane, 57%

Pentanes+, 16%

Normal Butane,

13%

Iso Butane, 9% Ethane, 5%

Propane, $18.64

Pentanes+, $13.31

Normal Butane, $6.83

Iso Butane, $5.44

Ethane, $0.27

Ethane, 70%

Propane, 18%

Pentanes+, 5%

Normal Butane, 4%

Iso Butane, 3%

Propane, $6.06

Ethane, $3.44

Pentanes+, $4.04


Iso Butane, $1.66

Marcellus Processing Barrels – 1250 BTU

NGL Barrel - VolumeNGL Barrel - Volume

Current NGL Value - $23.44/Bbl(1)Current NGL Value - $48.44/Bbl(1)

C2 Recovery

C2 Recovery

C2 Rejection

C2 Rejection

___________________________1. Assumes $90.00/Bbl WTI pricing and current spot NGL prices.

34

Propane, 51%Pentanes+,

21%

Normal Butane,

16%

Iso Butane, 8% Ethane, 3%

Pentanes+, $18.26

Propane, $16.80


Iso Butane, $5.02

Ethane, $0.16

Ethane, 58%

Propane, 23%

Pentanes+, 9%

Normal Butane, 7%

Iso Butane, 4%

Propane, $7.52

Pentanes+, $7.55

Ethane, $2.86


Iso Butane, $2.11

Gas$4.38

Gas$4.07

Gas$4.04 Gas

$3.55 Gas

$3.36

Condensate $0.45

Condensate $0.45

NGLs (C3+)$1.11

NGLs (C3+)$2.91

NGLs (C2+)$1.68

NGLs (C2+)$3.68

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

$10.00

1050 BTU 1150 BTU 1250 BTU 1150 BTU 1250 BTU


Marcellus Rich Gas Provides Liquids and Processing Upgrade

$4.38

$5.18

$7.40

$5.24

$7.49

• Marcellus rich gas and highly rich gas acreage provides a significant advantage in well economics – assuming $4.25/MMBtu NYMEX, $90.00/Bbl WTI and 40% WTI NGL pricing

• Upgrade analysis demonstrates that ethane recovery is economic at higher ethane prices

35Current – Ethane Rejection Projected – Ethane Recovery

$/Mcf on Wellhead Gas Volumes (1)($/Mcf)

___________________________1. Assumes $4.25/MMBtu NYMEX, $90.00/Bbl WTI and 40% WTI NGL pricing for 1200 BTU y-grade barrel for ethane recovery, C3+ spot prices for ethane rejection. 1.054 and 2.070 (ethane rejection)

and 3.332 and 5.145 (ethane recovery) GPMs used, all processing costs, shrink and fuel included. No ethane takeaway available until Enterprise ethane pipeline is online (expected 1Q 2014). Ethane recovery well economics include fixed fee cost tariff on ATEX ethane pipeline.

+$0.80Upgrade

+$3.02Upgrade


+$0.86Upgrade

+$3.11Upgrade

(1085 BTU)4% shrink

(1100 BTU)6% shrink



Antero EBITDAX Reconciliation

EBITDAX

36

($ thousands) 6 Months EndedAntero Resources LLC 6/30/2012 6/30/2013EBITDAX:Net income (loss) $254,318 $83,196Unrealized loss (gain) on commodity derivative contracts (114,498) (61,265)Interest expense and other 48,593 63,396 Provision (benefit) for income taxes 183,969 53,325Depreciation, depletion, amortization and accretion 38,477 93,484 Impairment of unproved properties 1,581 6,359 Exploration expense 4,756 11,662 (Gain) Loss on sale of assets (291,305) --Other 1,996 1,200EBITDAX from Continuing Operations $127,887 $251,357EBITDAX from Discontinued Operations 100,692 --EBITDAX $228,579 $251,357

The U.S. Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserve estimates (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 reserves included in this presentation have been audited by Antero’s third-party engineers. Antero’s estimate of probable and possible reserves was prepared by Antero’s internal reserve engineers, has not been reviewed by third-party engineers, and is provided in this presentation because management believes it is useful information that is widely used by the investment community in the valuation, comparison and analysis of companies. Antero does not plan to include probable and possible reserve estimates in its filings with the SEC.

We use certain other terms in this presentation relating to estimates of hydrocarbon volumes that the SEC’s guidelines prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, possible or probable reserves as defined by SEC regulations and accordingly are substantially less certain and no discount or other adjustment is included in the presentation of such numbers. 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 our 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 June 30, 2013. The SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.

“Unrisked Resource” refers to Antero’s internal estimates of hydrocarbon quantities that Antero’s management believes may be potentially discovered through exploratory drilling or recovered with additional drilling. Unrisked resource may not constitute 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. Actual quantities that may be ultimately recovered from Antero’s interests will differ substantially. Factors affecting ultimate recovery include the scope of our 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. Estimates of unrisked resource may change significantly as development of Antero's resource plays provides additional data.

“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.

Cautionary Note Regarding Hydrocarbon Quantities

37

Antero Resources

1625 17th Street

Denver CO 80202

www.anteroresources.com

company overview september 2013

Investor Relations