Howard Weil 42 nd Annual Energy Conference March 24, 2014 - - PowerPoint PPT Presentation

Howard Weil 42nd Annual Energy Conference March 24, 2014

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,

• bjectives 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

• ther 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, 2013 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 the Registration Statement 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

• r update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

1

WORLD CLASS POSITION IN THE CORE OF THE MARCELLUS AND UTICA LIQUIDS-RICH FAIRWAYS

Source: Company presentations and press releases.

Utica Shale Core Area Marcellus Shale Southwestern & Northeastern Core Areas Upper Devonian Shale Resource Overlies Marcellus Acreage

2

ANTERO LIQUIDS-RICH UTICA SHALE

107,000 Net Acres 18 Horizontals Completed 5 Rigs Currently Running

ANTERO MARCELLUS SHALE SW PA

25,000 Net Acres 2 Horizontals Completed Strong Results

ANTERO MARCELLUS SHALE NW WV

327,000 Net Acres (Primarily Liquids-Rich Fairway) 234 Horizontals Completed 15 Rigs Currently Running Utica Shale Liquids-Rich Fairway Utica Shale Dry Gas Resource Underlies Marcellus Acreage Marcellus Shale Liquids-Rich Fairway

1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000

2006 2007 2008 2009 2010 2011 2012 2013

Woodford Piceance Marcellus Utica

(3)

87 235 680 1,141 3,231 5,017 4,283 7,632

(5) (5) Sold Woodford and Piceance

3

200 400 600 800 1,000

2006 2007 2008 2009 2010 2011 2012 2013 2014E

Woodford Piceance Marcellus Utica

6 31 87 105 133 244 334 522

(4)

950

AVERAGE NET DAILY PRODUCTION (MMcfe/d) NET PROVED SEC RESERVES (Bcfe)(2)

193 25 50 75 100 125 150 175 200

2006 2007 2008 2009 2010 2011 2012 2013 2014E

Woodford Piceance Marcellus Utica

85 96 126 18 66 91 119 162

(4)

• 1. CAGR = Compound Annual Growth Rate.
• 2. Proved reserves for 2006, 2007, and 2008 represent previously effective SEC methodology. 2009, 2010, 2011, 2012 and 2013 proved reserves based on current SEC reserve methodology and SEC pricing and

are audited by independent third-party engineers.

• 3. Includes Upper Devonian Shale proved reserves (10 Bcfe in 2012 and 44 Bcfe in 2013).
• 4. Per Company press release dated January 29, 2014; production mid-point of 925-975 MMcfe/d guidance.
• 5. 2012 and 2013 proved reserves are both in ethane rejection mode.
• 6. Per First Call estimate as at 3/20/2014.

Financial Crisis

STRONG TRACK RECORD OF GROWTH

OPERATED GROSS WELLS SPUD

Sold Woodford and Piceance

EBITDAX ($MM)

$0 $200 $400 $600 $800 $1,000 $1,200 $1,400

2006 2007 2008 2009 2010 2011 2012 2013 2014E

Discontinued Operations Continuing Operations $0 $60 $209 $201 $198 $341 $434 $649 $1,272

(6)

UPPER DEVONIAN SHALE Net Proved Reserves(1) 44 Bcfe Net 3P Reserves (1) 4.2 Tcfe Pre-Tax 3P PV-10(1) NM % Liquids – Net 3P 7% 4Q 2013 Net Production 3 MMcfe/d Undrilled 3P Locations 951

C

PREMIER UNCONVENTIONAL RESOURCE PLATFORM

1. Proved, probable, and possible reserves as of December 31, 2013, assuming ethane rejection using SEC methodology and SEC pricing. Evaluations prepared by our internal reserve engineers and audited by DeGolyer & MacNaughton (D&M). Pre-Tax 3P PV-10 is a non-GAAP financial measure. 2. All net acres allocated to the Dry Gas Utica 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 leases. 3. RigData as of 3/18/2014.

TOTAL – 12/31/13 RESERVES(1) Assumes Ethane Rejection

Net Proved Reserves(1) 7.6 Tcfe Net 3P Reserves(1) 35.0 Tcfe Pre-Tax 3P PV-10(1) $20,362 MM Net 3P Liquids 902 MMBbls % Liquids – Net 3P 15% 4Q 2013 Net Production 678 MMcfe/d

• 4Q 2013 Net Liquids

11,190 Bbl/d Net Acres(2) 459,000 Undrilled 3P Locations 4,778 MARCELLUS SHALE Net Proved Reserves(1) 7.2 Tcfe Net 3P Reserves (1) 25.0 Tcfe Pre-Tax 3P PV-10(1) $15,729 MM % Liquids – Net 3P 17% 4Q 2013 Net Production 621 MMcfe/d Undrilled 3P Locations 3,068

• 100% operated
• Stable acreage base

− Marcellus Shale: 51% HBP, with additional 21% not expiring for 5+ years − Utica Shale: 20% HBP, with additional 79% not expiring for 5+ years

• Portfolio flexibility across dry gas to liquids-rich and

condensate windows

• Significant investment in midstream infrastructure and

secured takeaway capacity

• Financial flexibility to pursue planned 2014 and 2015

development drilling activities − $1.2 billion available liquidity with current $1.5 billion bank commitment

• Full scale development underway

− 20 rigs currently operating

A

UTICA SHALE – LIQUIDS-RICH Net Proved Reserves(1) 362 Bcfe Net 3P Reserves (1) 5.8 Tcfe Pre-Tax 3P PV-10(1) $4,666 MM % Liquids – Net 3P 15% 4Q 2013 Net Production 54 MMcfe/d Undrilled 3P Locations 759

B

4

A C B

“Pure-Play” Appalachian-Focused Shale Company

UTICA SHALE – DRY GAS Net Acres(2) 128,000 Net Resource 7-11 Tcf Undrilled Locations 1,080

D

D

Appalachia Rig Count vs. Peers(3) 15 11 10 8 6 4 5 5 10 15 20 25 Antero EQT RRC CNX COG RICE

Rigs

Marcellus Shale Utica Shale 20

OUTSTANDING RESERVE GROWTH

• 1. 2012 and 2013 reserves assume ethane rejection.

5

PROVED RESERVE GROWTH(1) 3P RESERVE GROWTH(1)

• Proved PV-10 increased 133% to $7.0 billion (including

hedges)

• 3P PV-10 increased 82% to $21.4 billion (including hedges)
• Replaced 1,857% of 2013 production
• All-in finding cost of $0.58/Mcfe
• 2013 “top-down” development cost of $1.25/Mcfe
• 2013 “bottoms-up” development cost of $1.10/Mcfe
• Only 14% of 1P and 58% of 3P locations booked as SSL

(1.73 Bcf/1,000’ type curve)

• No Utica Shale WV/PA dry gas reserves booked

4.2 7.2 0.1 0.4 2 4 6 8 10 2012 2013 (Tcfe)

Marcellus Utica

7.6 17.6 25.0 4.0 5.8

4.2

10 20 30 40 50 2012 2013 (Tcfe)

Marcellus Utica Upper Devonian

Drivers

POTENTIAL RESERVE GROWTH DRIVERS 2013 RESERVE UPDATE

• Marcellus SSL completions
• Full scale Utica program
• Utica increased density drilling
• Utica dry gas drilling
• Core acreage acquisitions

Driver 2014 Action

Complete transition to SSL type curve

4.3 21.6 35.0

• Successful

drilling

• Expanded

proved footprint

• 79,000 net

acres added in 2013

• SSL results
• Utica results

41 wells to be completed; only 21 PUD locations booked as proved at YE 2013 $200 million leasehold budget Drilling 2 increased density pilots in Utica Drilling first Utica dry gas well in WV (128,000 net acres WV/PA)

Drivers

LARGE UNBOOKED ANTERO UTICA DRY GAS POSITION

6

 128,000 Utica dry gas net acres − 1,080 locations underlying current Marcellus Shale leasehold in West Virginia and Pennsylvania  7 to 11 Tcf of total resource − Not included in 35 Tcfe of 3P reserves  Expect to drill and complete a Utica Shale dry gas well in the second half of 2014  Other operators have reported strong Utica Shale dry gas results including the following wells:

Dry gas resource position underlies Antero’s Marcellus leasehold in WV / PA

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 30.0 MMcf/d Triad Hunter Stalder #3UH 5,050’ Lateral IP 32.5 MMcf/d Antero Planned Utica Well 2H 2014

Well Operator IP (MMcf/d) Lateral Length (Ft) Hubbard BRK #3H Chesapeake 11.1 3,550 Porterfield 1H-17 Hess 17.2 5,000 Irons #1-4H Gulfport 30.3 5,714 Tippens #6H Eclipse 30.0 5,858 Stalder #3UH Triad Hunter 32.5 5,050

Source: Antero acreage position reflects tax districts in which greater than 3,000 net acres are held.

INTEGRATED MIDSTREAM PROCESSING AND TAKEAWAY

Infrastructure and commitments in place to handle strong natural gas, NGL and oil production growth – Portfolio of firm transportation and sales and West Virginia location minimizes basis risk

7

• 1. Antero firm transportation as of 3/18/2014.

200 400 600 800 1,000 1,200 1,400 1,600 (MMcf/d) Sherwood I Sherwood II Sherwood III Sherwood IV Sherwood V Seneca I Seneca II Seneca III Seneca IV

Total Capacity 1,550 Marcellus Utica

Sherwood I Sherwood II Sherwood III Seneca I Seneca II Seneca III

Growing Processing Capacity

Sherwood V Seneca IV

Appalachian Firm Transportation/Sales Commitment by Operator

Sherwood IV Source: Company presentations, press releases.

500,000 1,000,000 1,500,000 2,000,000 2,500,000

RRC EQT COG CNX CHK TLM STO SWN WPX RDS APC NFG

Mcf/d Firm Sales Firm Transportation

(1)

AR

• $2.50
• $2.00
• $1.50
• $1.00
• $0.50

$0.00 $0.50 2014 2015 2016 2017 2018 2019 Appalachian Basis to NYMEX(2)

LONG HAUL PIPELINE AND TRANSPORTATION NETWORK

8

 Antero has a leading firm transportation capacity position and is well-positioned in the southern portion of the Marcellus and Utica Shale from a gas takeaway perspective

Note: Antero firm transportation and firm sales positions listed by pipeline in color-coded boxes.

• 1. Firm transport as of year-end 2014. See Page 30 for timing of firm transportation graph.
• 2. Basis data from Wells Fargo daily indications and various private quotes as of 3/18/2014.

(1) TCO Basis to NYMEX Current 2015

• $0.01
• $0.46

Dom South Basis to NYMEX Current 2015

• $0.31
• $0.89

Leidy Basis to NYMEX Current 2015

• $1.45
• $2.16

CGTLA Basis to NYMEX Current 2015

• $0.03
• $0.08

Chicago Basis to NYMEX Current 2015 +$0.22

• $0.04

TCO Dom South TETCO M2 Leidy Chicago

2013 % of Production Sold TCO 67% Dom South 22% TETCO M2 5% NYMEX 6%

+

All-in Firm Transportation Costs $0.37 $0.42 $0.43

$0.25 $0.30 $0.35 $0.40 $0.45 $0.50 2013A 2014E 2015E ($/Mcf)

• Wtd. Avg. FT Expense ($/Mcf)

Appalachia 39% Gulf Coast 33% Chicago 28% 2015 Firm Transportation(1)

FIRM TRANSPORTATION REDUCES APPALACHIAN BASIS EXPOSURE

Appalachia 49% Gulf Coast 51% 2013 Firm Transportation(1) 2013 Firm Transportation – 647 MMcf/d Average All-in FT Cost $0.37/Mcf 2015 Firm Transportation – 2.1 Bcf/d Average All-in FT Cost $0.43/Mcf

+ $0.06/Mcf

9

 Antero’s future firm transportation portfolio introduces more exposure to Gulf Coast and Chicago pricing, with little incremental cost

Included in cash production expense

• 1. Represents accessible firm transportation and sales agreements.

2014E REALIZATIONS

Ethane Propane Iso Butane Normal Butane Natural Gasoline

Total $53.84 per Bbl 55% of WTI Strip(3)

2014E NGL Y-GRADE (C3+) REALIZATIONS

ESTIMATED 2014 NATURAL GAS REALIZATIONS ($/MCF)

$24.04 $6.42 $7.73 $14.91 $0.74 10

• 1. NYMEX differential represents contractual deduct to NYMEX-based sales and current basis differentials in the over-the-counter futures market.
• 2. Includes firm sales.
• 3. Based on current strip pricing.
• 4. Includes natural gas hedges.

2014 Hedged Volumes 729 MMcfe/d

Region 2014E % Sales Average NYMEX Price(3) Average Differential(2),(3) Average BTU Upgrade Estimated Hedge Gain(3) Average 2014E Realized Gas Price(4) Average Premium / (Discount) Appalachia 82% $4.49 $(0.36) $0.40 $0.21 $4.74 $0.25 Gulf Coast(1) 11% $4.49 $(0.25) $0.40 $0.03 $4.67 $0.18 Chicago 8% $4.49 $0.12 $0.40 $0.06 $5.08 $0.59 Total Wtd. Avg. 100% $4.49 $(0.31) $0.40 $0.30 $4.87 $0.38

Tetco M2 28% Chicago 20% DOM S 9% NYMEX 9% TCO 34% 2014 HEDGED VOLUMES – BY INDEX

$0.09 – premium to NYMEX (high end of current guidance)

% of C3+ Bbl Ethane 2% Propane 50% Iso Butane 10% Normal Butane 16% Natural Gasoline 22%

+

$0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 AR 2013 AR 2014E RRC 2013 EQT 2013 COG 2013 RICE 2013 $/Mcfe

LOE Production Taxes GPT G&A Hedge Gain E&P EBITDAX before Hedge Gain 4-year Avg. All-in F&D ($/Mcfe)

$5.17 $4.11

EBITDAX $3.39/Mcfe EBITDAX $2.92/Mcfe

$4.38

EBITDAX $2.98/Mcfe

$4.91 $5.69

F&D $0.58/Mcfe F&D $0.58/Mcfe F&D $0.95/Mcfe EBITDAX $3.25/Mcfe EBITDAX $3.79/Mcfe F&D $0.81/Mcfe EBITDAX $2.59/Mcfe F&D $1.13/Mcfe

$4.01

F&D $0.74/Mcfe

11

• 1. Includes realized hedge gains only; unrealized hedge gains excluded.
• 2. Operating costs include lease operating expenses, production taxes, gathering processing and firm transport costs and general and administrative costs.
• 3. 4-year proved reserve average all-in F&D from 2010-2013. Calculation = (Development costs + exploration costs + unproved properties and land capital costs) / Total reserves added (2013 ending reserves –

2010 beginning reserves + 4–year reserve sales – 4-year reserve purchases + 4-year accumulated production).

BIGGEST “BANG FOR THE BUCK” IN APPALACHIAN BASIN

 Antero has the highest price realizations and operating cash flow per Mcfe combined with the lowest all-in F&D cost among its Appalachian peers − Results in highest recycle ratio, or ability to grow production and reserves with cash flow − Increase in realizations and EBITDAX/Mcfe for 2014E driven by a 4x increase in liquids production to ≈ 25,000 Bbl/d

Antero 2013 Price Realization(1) & EBITDAX Per Unit(2) vs F&D(3) Including Realized Hedge Gains Peer 1 Peer 2 Peer 3 Peer 4

0.0x 2.0x 4.0x 6.0x 8.0x 5.4x 2.7x 2.9x 2.3x $0.00 $1.00 $2.00 $3.00 $4.00 $1.03 $1.14 $1.41 $1.57 $1.71

Other Peers

LOW DEVELOPMENT COST DRIVES BEST-IN-CLASS RECYCLE RATIOS

12

Source: Proved developed F&D research prepared by JP Morgan Research report dated 07/22/2013. 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. Includes all drilling and completion costs but excludes land and acquisition costs for all companies.

• 1. Antero internal estimate using JP Morgan development cost methodology; excludes Arkoma and Piceance operations.
• 2. Antero estimate based on public information; includes Arkoma and Piceance operations.

3-Year All-in Development Costs ($/Mcfe) through 2012

Antero Appalachia-Focused Peers

Source: Wall Street research. Defined as 2011-2013 average (Cash Operating Netback / PD F&D costs) x (1 + 2013-2015 consensus production CAGR). PD F&D Costs 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 per JP Morgan analysis. Includes all drilling and completion costs but excludes land and acquisition costs for all companies.

• 1. Antero data pro forma for Woodford and Piceance divestitures.

Antero Appalachia-Focused Peers

3-Year Average Growth – Adjusted Recycle Ratio through 2013

$/Mcfe Other Peers

Needed to make up for base declines in conventional and GOM production

? ? ?

Over 2,700 Antero Drilling Locations Permian Niobrara Granite Wash Barnett Haynesville

U.S. INCREMENTAL GAS SUPPLY BREAK-EVEN PRICE CURVE(1)

13

 Low cost, liquids-rich Utica and Marcellus Shales will remain attractive in most commodity price environments Utica Shale SW (Rich) Marcellus Shale

• 1. Source: Credit Suisse report dated January 2014 – Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI

NE (Dry) Marcellus Shale Eagle Ford Shale

MARCELLUS & UTICA – ADVANTAGED ECONOMICS

729 650 643 780 710 468

$4.92 $4.80 $4.71 $4.33 $4.60 $4.41 $4.49 $4.23 $4.16 $4.15 $4.29 $4.38

$0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 200 400 600 800 2014 2015 2016 2017 2018 2019 BBtu/d 11% 17% 16% 54% 2% NYMEX CGTLA Dom South TCO Chicago

SIGNIFICANT LONG-TERM COMMODITY HEDGE POSITION

14

% HEDGE VOLUMES BY INDEX – 3/18/2014

Average Index Hedge Price ($/MMBtu)(1) Hedged Volume NYMEX Strip (3/18/2014) ($/MMBtu)

NATURAL GAS HEDGES – 3/18/2014

• 1. Reflects weighted average index price per annum based on volumes hedged and 6:1 gas to oil ratio. Antero has hedged ~3,000 Bbl/d for 2014, WTI hedges comprise ~1% of overall hedge book.

 ~$750 million mark-to-market unrealized gain as of March 18, 2014  1.5 Tcfe hedged from January 1, 2014 through year-end 2019

LARGE MIDSTREAM FOOTPRINT

15

Ohio River Withdrawal System Completed

Antero Midstream estimated cumulative YE 2014 total capital investment in midstream ~ $1.5 billion – Includes gathering lines, compressor stations and water distribution infrastructure Proprietary water sourcing and distribution system − Improves operational efficiency and reduces water truck traffic − Cost savings of $600,000 to $800,000 per well − One of the benefits of a consolidated acreage position Utica Shale Marcellus Shale

Projected Midstream Infrastructure(1) Marcellus Shale Utica Shale Total YE 2014E Cumulative Gathering / Compression Capex ($MM) $750 $350 $1,100 Gathering Pipelines (Miles) 192 92 284 Compression Capacity (MMcf/d) 410 120 530 YE 2014 Cumulative Water System Capex ($MM) $300 $100 $400 Water Pipeline (Miles) 122 48 170 Water Storage Facilities 31 16 47 YE 2014E Total Midstream ($MM) $1,050 $450 $1,500

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 12/31/2013 and 2014 guidance.

APPALACHIAN FRESH WATER DISTRIBUTION SYSTEM

16

West Virginia

• 70+ miles of buried trunk line currently in operation
• 47 miles of buried trunk line is budgeted to be installed and operational in 2014
• 1.8 MM barrels of storage currently available
• 2.4 MM barrels storage budgeted for 2014
• System designed to deliver 80 barrels per minute from multiple freshwater sources, simultaneously

Utica Marcellus

Ohio System West Virginia System Antero leasehold

West Virginia System

2014+ 2014+ Existing pipeline

Harrison County Doddridge County Tyler County Ritchie County Pleasants County

Ohio

• 20+ miles of buried trunk line currently in operation
• 25 miles of buried trunk line is budgeted to be installed and operational in 2014
• 1.0 MM barrels of storage currently available
• 2.5 MM barrels storage budgeted for 2014
• System designed to deliver 80 barrels per minute from multiple freshwater sources, simultaneously

withdrawal point withdrawal point Sherwood Plant

Ohio System

Existing pipeline 2014+

Antero leasehold

withdrawal point Seneca Plant

Belmont County Monroe County Noble County Guernsey County

withdrawal point

ASSET OVERVIEW

17

WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECT

Antero Has Delineated And De-Risked Its Large Scale Acreage Position

 100% operated  352,000 net acres in Southwestern Core – 51% HBP with additional 21% not expiring for 5+ years  236 horizontal wells completed and online – Laterals average 7,000’ – 100% drilling success rate  Net production of 621 MMcfe/d in 4Q 2013, including 8,900 Bbl/d of liquids  3,068 future drilling locations in the Marcellus (71% are processable)  Operating 15 drilling rigs including 4 shallow rigs  25.0 Tcfe of net 3P (17% liquids), includes 7.2 Tcfe of proved reserves (assuming ethane rejection)

18

Highly-Rich Gas 101,000 Net Acres 834 Gross Locations Rich Gas 86,000 Net Acres 707 Gross Locations Dry Gas 104,000 Net Acres 890 Gross Locations Highly-Rich/Condensate 61,000 Net Acres 637 Gross Locations MOORE UNIT 30-Day Rate 1H: 10.3 MMcfe/d 2H: 10.3 MMcfe/d (20% liquids) MHR WEESE UNIT 30-Day Rate 4-well average 9.3 MMcfe/d (31% liquids) CHK HADLEY UNIT 24-Hour IP 9.1 MMcfe/d (32% liquids) EQT PENN 15 UNIT 30-Day Rate 5-well average 9.3 MMcfe/d (26% liquids) CONSTABLE UNIT 30-Day Rate 1H: 15.3 MMcfe/d (26% liquids) 142 Horizontals Completed 30-Day Rate 10.3 Bcf average EUR 8.1 MMcf/d 6,915’ average lateral length PRUNTY UNIT 30-Day Rate 1H: 12.2 MMcfe/d (27% liquids) HINTERER UNIT 30-Day Rate 1H: 12.9 MMcfe/d (20% liquids) RUTH UNIT 30-Day Rate 1H: 19.2 MMcfe/d (14% liquids)

Sherwood Processing Plant

EQT 30-Day Rate 12 Recent Wells 9.2 MMcfe/d (20% Liquids) Source: Company presentations and press releases. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held. Note: Rates assume ethane rejection. BLANCHE UNIT 30-Day Rate 2H: 10.2 MMcfe/d (30% liquids) DOTSON UNIT 30-Day Rate 1H: 12.4 MMcfe/d 2H: 11.8 MMcfe/d (26% liquids)

MARCELLUS – SIMPLE STRUCTURE

19

 Several regional anticlines in core area − Predictable “layer cake” geology − No faults at Marcellus level

• Over 1.7 million feet (315 miles)

drilled horizontally without crossing a fault − 3-D seismic not required to guide horizontal wells  Regional East-West seismic line shows gentle structure at Marcellus level  Allegheny Front and complex structure located many miles east of core area  Favorable geology allows for longer laterals Average Marcellus Lateral Lengths

7,300 4,800 4,500 4,100 2,000 4,000 6,000 8,000 Antero EQT RRC COG Feet

Source: Company presentations.

Wolf Summit Arches Fork Big Moses

Marcellus Onondaga Benson Rhinestreet

Profile along regional seismic line (time)

W E

Regional Seismic Line

No Data

Tully 100’ Contours Top Marcellus

1,000 10,000 30 60 90 120 150 180 210 240 Gas Production (Mcfe/d) Days From Peak Gas Antero Type Curve SSL Average Wellhead SSL Average Processed

Enhancing Recoveries

 Shorter stage length (SSL) summary: – 36 SSL wells completed – 32 SSL wells have at least 30 days

• f production history

– 150’ to 225’ (SSL) vs. 350’ stages previously  28% higher 30-day wellhead rate for first 32 SSL wells vs. the Antero type curve – 29% higher 180-day rate vs. the Antero type curve – Other Marcellus operators have indicated 20% to 30% improvement in IPs and EURs  The 30-day processed rate for Antero’s first 32 SSL wells has averaged 38% higher than the Antero type curve  Estimated 12% to 15% increase in well costs for SSL completions as compared to non-SSL

20

SHORTER STAGE LENGTHS (“SSL”) – ENHANCING MARCELLUS RECOVERIES

1.5 Bcf/1,000’ Type Curve

Normalized production increase for 36 SSL wells vs. 1.5 Bcf/1,000' Type Curve

SSL vs Non-SSL Wellhead Average Rate Comparison 30-day Rate 90-day Rate 120-day Rate 180-day Rate SSL Well Count 32 19 18 10 SSL Avg. Wellhead Rate – MMcf/d(1) 9.8 8.0 7.7 7.3 Wellhead Type Curve – MMcf/d(2) 7.6 6.6 6.2 5.7 SSL % Rate Improvement 28% 22% 24% 29% SSL Avg. Processed Rate – MMcfe/d(1) 11.2 9.2 8.7 8.3 Processed Type Curve – MMcfe/d(3) 8.1 7.0 6.6 6.0 SSL % Rate Improvement 38% 31% 33% 38%

(1) Wellhead condensate production is converted on a 6:1 basis (2) 1.5 Bcf/1,000’ Type Curve (3) 1.5 Bcf/1,000’ Type Curve processed assuming 1225 BTU

4 8 12 16 20 MMcf/d 30-Day Average Production Rates

0.0 3.0 6.0 9.0 12.0 15.0 0.0 3.0 6.0 9.0 12.0 15.0 1 2 3 4 5 6 7 8 9 10 Cumulative Bcf MMcf/d Production Year

Antero Non-SSL Type Curve Actual Non-SSL Production Non-SSL Type Curve Cumulative Production 1.7 Bcf/1,000' SSL Type Curve SSL Actual Production

 Antero has over four years of production history to support its 1.5 Bcf/1,000’ type curve (non-SSL)  Antero’s SSL type curve has been increased to 1.73 Bcf/1,000’ with only 12% to 15% higher well costs  Lack of faulting and contiguous acreage position allows for drilling of long laterals ~ 7,300’ − Drives down costs per 1,000’ of lateral resulting in best in class development costs

ANTERO’S MARCELLUS SHALE TYPE CURVE SUPPORT

• 1. 236 Antero Marcellus wells normalized to time zero, production for each well normalized to 7,000’ lateral length.
• 2. 32 Antero Marcellus SSL wells normalized to time zero, production for each well normalized to 7,000’ lateral length.

Marcellus Type Curve – Normalized to 7,000’ Lateral

(1)

21

24-Hour Peak Rate 30-Day

• Avg. Rate

90-Day

• Avg. Rate

180-Day

• Avg. Rate

One-Year

• Avg. Rate

Two-Year

• Avg. Rate

Three-Year

• Avg. Rate

Wellhead (MMcf/d) 14.3 8.1 6.3 5.3 4.2 3.1 2.3 # of wells 236 224 221 193 131 65 26

EURs Increase With Lateral Length Well Cost / 1,000’ Decreases with Lateral Length Wellhead 30-day Rates - 224 Wells

Average 30-Day Rate – 8.1 MMcf/d

(2)

4 8 12 16 20 2,000 4,000 6,000 8,000 10,000 EUR, BCF Lateral Length, ft $0.6 $0.8 $1.0 $1.2 $1.4 $1.6 $1.8 2,000 4,000 6,000 8,000 10,000 $MM / 1,000' Lateral length, ft

MARCELLUS SINGLE WELL ECONOMICS – ASSUMES ETHANE REJECTION

22

DRY GAS LOCATIONS RICH GAS LOCATIONS HIGHLY RICH GAS LOCATIONS

Assumptions

 12/31/2013 Strip Pricing & SEC Reserves

NYMEX ($/MMBtu) WTI ($/Bbl) C3+ NGL(2) ($/Bbl) 2014 $4.24 $95 $54 2015 $4.16 $88 $50 2016 $4.09 $83 $50 2017 $4.09 $80 $50 2018+ $4.14 $79 $50

Marcellus SSL Well Economics and Total Locations(1)

Classification Highly-Rich/ Condensate Highly-Rich Gas Rich Gas Dry Gas BTU Range 1275-1350 1200-1275 1100-1200 <1100 Modeled BTU 1313 1250 1150 1050 EUR (Bcfe): 16.5 14.9 13.3 12.1 EUR (MMBoe): 2.8 2.5 2.2 2.0 % Liquids: 34% 24% 12% 0% Lateral Length (ft): 7,000 7,000 7,000 7,000 Stage Length (ft): 225 225 225 225 Well Cost ($MM): $9.5 $9.5 $9.5 $9.5 Bcf/1,000’: 1.7 1.7 1.7 1.7 Bcfe/1,000’: 2.4 2.1 1.9 1.7 Pre-Tax NPV10 ($MM): $20.5 $13.7 $6.6 $3.7 Pre-Tax ROR: 117% 65% 32% 21% Net F&D ($/Mcfe): $0.68 $0.75 $0.84 $0.92 Payout (Years): 0.9 1.3 2.4 3.6 Gross 3P Locations: 637 834 707 890

• 1. Well economics are based on 12/31/2013 proved SSL reserves (P90) and strip pricing. Includes gathering, compression and processing fees.
• 2. Pricing for a 1225 BTU y-grade rejection barrel.

637 834 707 890 117% 65% 32% 21% 200 400 600 800 1,000 0% 50% 100% 150%

Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Total 3P Locations ROR Locations ROR

Source: Company presentations and press releases. Note: Antero acreage position reflects townships in which greater than 3,000 net acres are held. Note: Third party peak rates assume ethane recovery; Antero 24-hour peak rates assume ethane recovery; Antero 30-day rates assume ethane rejection.

• 1. For non-Antero wells, 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.

 100% operated  107,000 net acres in the core rich gas / condensate window – 20% HBP with additional 79% not expiring for 5+ years – 75% of acreage has rich gas processing potential  18 Antero-operated horizontal wells completed and online − 100% drilling success rate  Net production of 54 MMcfe/d in 4Q 2013 including 2,200 Bbl/d of liquids − First production in early August 2013 had access to Cadiz pipeline and processing − Seneca I processing plant came online in November 2013 and Seneca II came online in January 2014 − First 120 MMcf/d compressor station went into service in late January with an additional 120 MMcf/d compressor station expected by late 1Q 2014  759 future drilling locations – Approximately 15% of EUR is liquids assuming ethane rejection  Operating 5 rigs including 1 shallow rig  5.8 Tcfe of net 3P (15% liquids), includes 362 Bcfe of proved reserves (assuming ethane rejection)

EXCITING CORE UTICA SHALE POSITION DELIVERS CONDENSATE AND NGLS

23

Utica Shale Industry Activity(1)

Seneca Processing Plant Cadiz Processing Plant CHESAPEAKE 24-Hour IP Buell #8H 9.5 MMcf/d + 1,425 Bbl/d liquids GULFPORT 24-Hour IP Boy Scout 1-33H, Ryser 1-25H, Groh 1-12H Average 5.3 MMcf/d + 675 Bbl/d NGL + 1,411 Bbl/d Oil REXX 24-Hour IP Guernsey 1H, 2H, Noble 1H Average 7.9 MMcf/d + 1,192 Bbl/d NGL + 502 Bbl/d Oil MILEY UNIT 30-Day Rate 2 wells average 7.5 MMcfe/d (60% liquids) NORMAN UNIT 1H 30-Day Rate 16.4 MMcfe/d (17% liquids) YONTZ UNIT 1H 30-Day Rate 17.0 MMcfe/d (14% liquids) RUBEL UNIT 30-Day Rate 3 wells average 17.3 MMcfe/d (22% liquids) GULFPORT 24-Hour IP McCort1-28H, 2-28H, Stutzman 1-14H Average 13.1 MMcf/d + 922 Bbl/d NGL + 21 Bbl/d Oil GULFPORT 24-Hour IP Wagner 1-28H, Shugert 1-1H, 1-12H Average 21.0 MMcf/d + 2,270 Bbl/d NGL + 292 Bbl/d Oil Utica Core Area WAYNE UNIT 30-Day Rate 3 wells average 10.8 MMcfe/d (49% liquids) GARY UNIT 1H 30-Day Rate 29.7 MMcfe/d (22% liquids) Highly-Rich/Cond 30,000 Net Acres 205 Locations Highly-Rich Gas 26,000 Net Acres 161 Locations Rich Gas 24,000 Net Acres 182 Locations Dry Gas 27,000 Net Acres 211 Locations

UTICA CORE – GEOLOGICALLY DEFINED

Utica Geologic Map

24

VENHAM 1-A

WASHINGTON

ET RUBEL 1 PILOT

MONROE

BUELL 8H PILOT

HARRISON

WALL 3H PILOT

BEAVER

<39.10MI> <38.70MI> <47.15MI> 6500 7900 8000 8400 8500 8800

A A’

Point Pleasant Formation Utica Shale Point Pleasant Shale Utica Shale

Core Utica Shale Liquids-Rich Fairway

Emerging Downdip High Pressure, High Rate Utica Shale Dry Gas Play SEM: Highly Porous Amorphous Kerogen - Miley 5H Core

0.0 10.0 20.0 30.0 40.0 50.0 60.0 MMcfe/d

Source: Antero, press releases and company presentations. Note: Assumes ethane recovery.

ANTERO HAS MOST OF THE TOP UTICA 24-HOUR IPS – STRONG SUPPORT FOR CORE POSITION

 Antero has 12 of the top 13 Utica 24-hour peak rates (IPs) announced to date  Represent some of the best 24- hour peak rates of any shale play in North America – 20 to 53 MMcfe/d per well 24- hour peak rate in the core area – Excellent reservoir pressure with gradients in the 0.7 psi/ft range  Liquids content ranges from 40%-70% (assumes ethane recovery) in the liquids-rich window  Antero recently announced 30- day rates on some of these wells (see page 36)

25

UTICA 24-HOUR IPs

Core

12 to 53

MMcfe/d IPs Tier 1

6 to 12

MMcfe/d IPs

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

UTICA SINGLE WELL ECONOMICS – ASSUMES ETHANE REJECTION

26

DRY GAS LOCATIONS RICH GAS LOCATIONS HIGHLY RICH GAS LOCATIONS

Assumptions

 12/31/2013 Strip Pricing & SEC Reserves

Utica Well Economics and Locations(1)

Classification Highly-Rich/ Condensate Highly-Rich Gas Rich Gas Dry Gas BTU Range 1250-1300 1200-1250 1100-1200 <1100 Modeled BTU 1275 1225 1175 EUR (Bcfe): 11.3 20.5 18.8 16.6 EUR (MMBoe): 1.9 3.4 3.1 2.8 % Liquids 32% 23% 15% 0% Lateral Length (ft): 7,000 7,000 7,000 7,000 Stage Length (ft): 240 240 240 240 Well Cost ($MM): $11.0 $11.0 $11.0 $11.0 Bcf/1,000’: 1.2 2.4 2.4 2.4 Bcfe/1,000’: 1.6 2.9 2.7 2.4 Pre-Tax NPV10 ($MM): $15.7 $26.6 $18.4 $11.7 Pre-Tax ROR: 137% 169% 95% 56% Net F&D ($/Mcfe): $1.21 $0.66 $0.72 $0.82 Payout (Years): 0.5 0.5 0.8 1.3 Gross 3P Locations(3): 205 161 182 211

• 1. Well economics are based on 12/31/2013 proved (P90) reserves and strip pricing. Includes gathering, compression and processing fees.
• 2. Pricing for a 1225 BTU y-grade rejection barrel.
• 3. Gross 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content.

NYMEX ($/MMBtu) WTI ($/Bbl) C3+ NGL(2) ($/Bbl) 2014 $4.24 $95 $54 2015 $4.16 $88 $50 2016 $4.09 $83 $49 2017 $4.09 $80 $49 2018+ $4.14 $79 $49

205 161 182 211 137% 169% 95% 56% 50 100 150 200 250 0% 50% 100% 150% 200%

Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Total 3P Locations ROR Locations ROR

ANTERO KEY ATTRIBUTES

27 Critical Mass In Two World Class Shale Plays Market Leading Growth Industry Leading Capital Efficiency and Recycle Ratio Significant Emphasis on Takeaway and Liquids Processing Liquidity and Hedge Position Support High Growth Story “Forward Thinking” Management Team with a History of Success

28

APPENDIX

28

Keys to Execution

Pad Impact Mitigation

• Closed loop mud system – no mud pits
• Protective liners or mats on all well pads in addition to berms

Green Completion Units

• All Antero well completions use green completion units for completion flowback,

essentially eliminating methane emissions (full compliance with EPA 2015 requirements) Central Fresh Water System & Water Recycling

• Numerous sources of water – building central water system to source water for

completion

• Antero recycles over 95% of its flowback water with the remainder injected into

disposal wells – no discharge to water treatment plants in West Virginia Natural Gas Powered Drilling Rigs

• Nine of Antero’s contracted drilling rigs are currently running on natural gas

Natural Gas Vehicles (NGV)

• Antero supported the first natural gas fueling station in West Virginia which

recently opened

• Antero has a dozen NGV trucks and plans to continue to convert its truck fleet to

NGV Safety & Environmental

• Five company safety representatives and 45 safety consultants cover all material

field operations 24/7 including drilling, completion, construction and pipelining

• 23-person company environmental staff plus outside consultants monitor all
• perations and perform baseline water well testing

Local Presence

• Land office in Ellenboro, WV
• Recently moved into new 50,000 square foot district office in Bridgeport, WV
• 109 of Antero’s 264 employees are located in West Virginia and Ohio

LEED Gold Headquarters Building

• Antero’s new corporate headquarters in Denver has been LEED Gold Certified
• Completion expected by spring of 2014

HEALTH, SAFETY, ENVIRONMENT & COMMUNITY

Antero Core Values: Protect Our People and the Environment

Strong West Virginia Presence

• Over 75% of Antero Marcellus

employees and contract workers are West Virginia residents

• Antero named Business of

the Year for 2013 in Harrison County, West Virginia “For

• utstanding 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

29

ANTERO FIRM TRANSPORTATION AND FIRM SALES

30

MMBtu/d

Columbia 7/26/2009 – 9/30/2025 Firm Sales #1 10/1/2011– 10/31/2019 Firm Sales #2 10/1/2011 – 5/31/2017 Firm Sales #3 1/1/2013 – 5/31/2022 Momentum III 9/1/2012 – 12/31/2023 EQT 8/1/2012 – 12/31/2023 REX/MGT/ANR 4/1/2013 – 9/30/2025

• 500,000

1,000,000 1,500,000 2,000,000 2,500,000

Gas $4.46 Gas $4.19 Gas $4.15 Gas $4.08 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 1050 BTU $5.15 $6.55 $7.68 $4.46 1150 BTU 1250 BTU 1300 BTU

MARCELLUS SHALE RICH GAS – LIQUIDS AND PROCESSING UPGRADE

• 1. NGL prices as of 3/18/2014 from IntercontinentalExchange.
• 2. Assumes $4.25/MMBtu NYMEX, $90.00/Bbl WTI and current NGL spot prices. 0.886, 1.972 and 2.632 (ethane rejection) GPMs used, all processing costs, shrink and fuel included. No NYMEX basis

differential assumed.

Current – Ethane Rejection

(1076 BTU)

8% shrink

(1109 BTU)

12% shrink

(1119 BTU)

14% shrink

$/Wellhead Mcf(1)(2)

($/Mcf)  Marcellus Shale 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(1)

31

+$0.69

Upgrade

+$2.08

Upgrade

+$3.22

Upgrade

Highly-Rich Gas Dry Gas

NGLs (C3+) $0.96 NGLs (C3+) $2.24 NGLs (C3+) $3.03 Condensate $0.16 Condensate $0.56

Highly-Rich/ Condensate Dry Gas

2013 REALIZATIONS

Ethane (C2) Propane (C3) Iso Butane (C4) Normal Butane Natural Gasoline

Total $52.61 per Bbl 54% of WTI(4)

2013 NGL Y-GRADE (C3+) REALIZATIONS 2013 NATURAL GAS REALIZATIONS ($/MCF)

55% 2% 11% 15% 17% $23.49 $6.27 $7.55 $14.57 $0.72 32

• 1. NYMEX differential represents contractual deduct to NYMEX-based sales.
• 2. Includes firm sales.
• 3. Price excludes hedges.
• 4. Based on monthly prices through 12/31/2013 WTI.

Antero Barrel 2013 % Sales Average NYMEX Price Average Differential(2) Average BTU Upgrade Average 2013 Realized Price(3) Average Premium / (Discount) TCO 67% $3.65 $(0.06) $0.42 $4.02 $0.37 Dominion South 22% $3.65 $(0.41) $0.39 $3.64 $(0.01) NYMEX(1) 6% $3.65 $(0.40) $0.39 $3.65 − TETCO 5% $3.65 $(0.26) $0.41 $3.80 $0.15 Total 100% $3.65 $(0.16) $0.42 $3.90 $0.25

$0.00 $0.00 $0.00 $0.00 $0.89 $1.15 $2.47 $2.50 $2.60 $2.94 $3.20 $3.27 $3.51 $3.65 $3.66 $3.70 $3.75 $3.80 $3.81 $4.13 $4.25 $4.66 $5.05 $5.37 $5.49 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00

637 834 707 890 117% 65% 32% 21% 200 400 600 800 1000 0% 50% 100% 150%

Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Total 3P Locations ROR Locations ROR

MULTI-YEAR DRILLING INVENTORY SUPPORTS LOW-RISK, HIGH-RETURN GROWTH PROFILE

Large Inventory of Low Breakeven Projects(3)

• 1. Well economics based on 12/31/2013 3P SSL reserves and strip pricing as of 12/31/2013.
• 2. A portion of these locations do not assume SSL completions.
• 3. Source: Credit Suisse report dated January 2014 – Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI.
• 4. 3-year NYMEX STRIP as of 3/18/2014.

3 Yr Strip - $4.29/MMBtu(4)

637

Locations

1,541

Locations

366

Locations

890

Locations $ / MMBtu NYMEX (Gas)

182

Locations

33

MARCELLUS SSL WELL ECONOMICS(1)(2) UTICA WELL ECONOMICS(1)

205 161 182 211 137% 169% 95% 56% 50 100 150 200 250 0% 50% 100% 150% 200%

Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Total 3P Locations ROR Locations ROR

1,000  71% of Marcellus locations are processable (1100-plus Btu)  72% of Utica locations are processable (1100-plus Btu) `

>2,700 Antero Liquids-Rich Locations

Well 24-Hour Peak Rate % Total Estimated EUR Well Cost F&D IRR PV-10 Payout Undrilled Name County (MMcfe/d) Liquids BTU (Bcfe) ($MM) ($/Mcfe) % ($MM) (Years) Locations Highly-Rich Gas/Condensate (1250 - 1300 BTU) Highly-Rich Gas/Condensate (1250 - 1300 BTU) Milligan 2H Noble 40.2 66% 1276 Coal 3H Noble 35.3 67% 1278 Wayne 3HA Noble 35.1 67% 1272 Wayne 4H Noble 34.2 67% 1265 Milligan 3H Noble 32.1 62% 1276

11.3 $11.0 $1.21 137% $15.7 0.5 205

Milligan 1H Noble 25.8 68% 1276 Wayne 2H Noble 25.5 67% 1281 Miley 2H Noble 22.4 70% 1278 Miley 5HA Noble 20.2 70% 1291

Average 30.1 67% 1277

Highly-Rich Gas (1200 - 1250 BTU) Highly-Rich Gas (1200 - 1250 BTU) Rubel 1H Monroe 47.5 46% 1231 Gary 2H Monroe 43.5 44% 1224 Rubel 3H Monroe 42.6 44% 1220

20.5 $11.0 $0.66 169% $26.6 0.5 161

Rubel 2H Monroe 37.4 45% 1217 Dollison 1H Noble 27.5 63% 1238

Average 39.7 48% 1226

Rich Gas (1100 - 1200 BTU) Rich Gas (1100 - 1200 BTU) Yontz 1H Monroe 53.3 36% 1161 Norman 1H Monroe 37.1 40% 1186

18.8 $11.0 $0.72 95% $18.4 0.8 182 Average 45.2 38% 1174

Dry Gas (< 1100 BTU) Dry Gas (<1100 BTU) No Antero Dry Gas Drilling To-Date

Average NM NM NM 16.6 $11.0 $0.82 56% $11.7 1.3 211

Antero Type Curve Regime - 12/31/2013 Strip Pricing - 7,000' Lateral

Ethane Recovery

Antero Utica Well Results

Ethane Rejection

34

OUTSTANDING UTICA WELL RESULTS − DRIVE STRONG PROVED RESERVE BOOKING

1. 24-hour peak rates assume full ethane recovery (assuming typical ethane plant product recoveries of 85% to 90%) however Antero is currently rejecting ethane due to current market prices. 2. Average of Antero’s first 15 core area wells, assuming ethane rejection.

ANTERO UTICA SHALE WELLS – 24 HOUR IPS

35

Lateral Well Gas Equivalent Rate Wellhead Gas Shrunk Gas NGL Condensate % Total Length Name County (MMcfe/d) (MMcf/d) (MMcf/d) (Bbl/d) (Bbl/d) Liquids BTU (Feet) Yontz 1H Monroe 53.3 38.9 33.9 3,177 52 36% 1161 5,115 Rubel 1H Monroe 47.5 31.1 25.9 3,391 214 46% 1231 6,554 Gary 2H Monroe 43.5 28.9 24.2 3,053 162 44% 1224 8,882 Rubel 3H Monroe 42.6 28.4 23.7 3,003 142 44% 1220 6,424 Milligan 2H Noble 40.2 17.2 13.5 2,361 2,087 68% 1276 5,989 Rubel 2H Monroe 37.4 24.8 20.7 2,635 156 45% 1217 6,571 Norman 1H Monroe 37.1 26.1 22.3 2,419 45 40% 1186 5,498 Coal 3H Noble 35.3 15.1 11.8 2,063 1,850 67% 1278 7,768 Wayne 3HA Noble 35.1 14.7 11.6 2,018 1,905 67% 1272 6,712 Wayne 4H Noble 34.2 14.2 11.2 1,907 1,922 67% 1265 6,493 Milligan 3H Noble 32.1 15.4 12.1 2,111 1,228 62% 1276 5,267 Milligan 1H Noble 25.8 10.6 8.3 1,461 1,442 68% 1276 6,436 Wayne 2H Noble 25.5 10.9 8.5 1,503 1,331 67% 1281 6,094 Miley 2H Noble 22.4 8.6 6.7 1,172 1,450 70% 1278 6,153 Miley 5HA Noble 20.2 7.7 6.0 1,090 1,285 70% 1291 6,296

35.5 19.5 16.0 2,224 1,018 57% 1249 6,417 28.7 18.8 17.6 844 1,018 42% 1251 6,518 Average ‐ Ethane Recovery(1) Average ‐ Ethane Rejection

(2)

24‐hr Peak Rate

1. Average of Antero’s first 11 core area wells, assuming ethane rejection.

ANTERO UTICA SHALE WELLS – 30-DAY RATES

36

Antero’s wells produced against 1,100 psi line pressure until late January 2014 due to lack of compression facilities − First 120 MMcf/d compressor station started up in late January 2014

Lateral Well Gas Eq. Rate Wellhead Gas Shrunk Gas NGL Condensate % Total Estimated Length Name County (MMcfe/d) (MMcf/d) (MMcf/d) (Bbl/d) (Bbl/d) Liquids BTU (Feet) Gary 2H Monroe 29.7 24.6 23.1 1,023 65 22% 1224 8,882 Rubel 2H Monroe 19.2 15.9 15.0 625 64 22% 1217 6,571 Rubel 3H Monroe 18.7 15.6 14.7 623 43 21% 1220 6,424 Yontz 1H Monroe 17.0 15.2 14.6 392 1 14% 1161 5,115 Norman 1H Monroe 16.4 14.3 13.6 461 2 17% 1186 5,498 Rubel 1H Monroe 14.0 11.5 10.8 501 28 23% 1231 6,554 Wayne 2H Noble 12.1 6.5 6.0 367 653 51% 1281 6,094 Wayne 3HA Noble 11.0 6.1 5.6 354 540 49% 1272 6,712 Wayne 4H Noble 9.2 5.2 4.7 284 452 48% 1265 6,493 Miley 2H Noble 9.0 3.8 3.5 213 700 61% 1278 6,153 Miley 5HA Noble 5.9 2.7 2.5 161 418 59% 1291 6,296

14.7 11.0 10.4 455 270 35% 1239 6,436 17.9 11.0 9.2 1,189 270 53% 1239 6,436

30‐Day Rates ‐ Antero Core Area

Average ‐ Ethane Rejection Average ‐ Ethane Recovery(1)

CONSIDERABLE RESERVE BASE WITH ETHANE OPTIONALITY

 40 year proved reserve life based on 2013E production  Reserve base provides significant exposure to liquids-rich projects – 3P reserves of over 2.2 BBbl of NGLs and condensate in ethane recovery mode; 33% 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.

ETHANE REJECTION(1) ETHANE RECOVERY(1)

37

Marcellus – 25.0 Tcfe Utica – 5.8 Tcfe Upper Devonian – 4.2 Tcfe

35.0 Tcfe

Gas – 29.6 Tcf Oil – 91 MMBbls NGLs – 811 MMBbls Marcellus – 29.5 Tcfe Utica – 6.7 Tcfe Upper Devonian – 4.7 Tcfe

40.8 Tcfe

Gas – 27.4 Tcf Oil – 91 MMBbls NGLs – 2,151 MMBbls

15% Liquids 33% Liquids

POSITIVE RATINGS MOMENTUM

Moody’s / S&P Historical Credit Ratings

“We would consider a positive rating action if the company continued to convert its PUD reserves to proved developed reserves and improved profitability, while maintaining leverage below 3x.”

• S&P Credit Research, October 2013

“An upgrade could be considered if debt / average daily production is sustained below $20,000 per boe and debt / proved-developed reserves is sustained below $8.00 per boe. An upgrade would also be contingent on Antero maintaining unleveraged cash margins greater than $25.00 per boe and retained cash flow to debt over 40% as it builds out infrastructure needs to support production growth.”

• Moody’s Credit Research, October 2013

Moody's S&P Credit Rating (Moody’s / S&P) Ba3 / BB- B1 / B+ B2 / B B3 / B- 9/1/2010 2/24/2011 5/31/2012 10/21/2013 2/18//2014 2/28/2012 11/28/2011 8/27/2011 5/27/2011 Ba2 / BB Ba1 / BB+ Caa1 / CCC+

(1)

___________________________ 1. Represents corporate credit rating of Antero Resources Corporation / Antero Resources LLC.

Baa3 / BBB-

Moody’s Upgrade Criteria S&P Upgrade Criteria

38

ANTERO – 2014 GUIDANCE

39

Key Variable Guidance Range

Natural Gas Realized Price Premium to NYMEX ($/Mcf)(2) $0.00 - $0.10 NGL Realized Price (% of WTI) ($/Bbl) 53% - 57% Oil Realized Price Differential to NYMEX ($/Bbl) $(10.00) - $(12.00) Net Production (MMcfe/d) 925 - 975 Net Natural Gas Production (MMcf/d) 780 - 820 Net Liquids Production (Bbl/d) 24,000 – 26,000 Cash Production Expense ($/Mcfe)(3) $1.50 - $1.60 G&A Expense ($/Mcfe) $0.25 - $0.30 Average Marcellus Rig Count 14 Average Utica Rig Count 4 Total Wells Spud 193 Total Wells Completed 181

1. Rig and well counts based on Antero guidance per press release dated January 29, 2014. Financial assumptions per press release dated February 26,2014. 2. 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 2014 Operating & Financial Assumptions(1)

$1,550 $650 $450

Drilling & Completion Midstream Land

82% 18%

Marcellus Utica

$1,800 $600 $200

Drilling & Completion Midstream Land

73% 27%

Marcellus Utica

ANTERO 2014 CAPITAL BUDGET

2014E

40

$2.60 Billion $ 2.65 Billion

2014E 2013E 2013E

CAPITALIZATION

• 1. Equity valuation based on 262.0 million shares outstanding and a share price of $63.95 as of 3/20/2014. Enterprise value includes net debt.
• 2. Pro forma interest expense adjusted for $1,578 million net proceeds from IPO priced on 10/14/2013 and $1,000 million 5.375% Senior Notes priced on 10/24/2013 net of fees; assumes $525 million

9.375% Senior Notes, $25 million 9.00% Senior Note and $140 million 7.25% Senior Notes repaid at beginning of year along with residual cash used to repay bank debt.

• 3. Lender commitments under the facility reduced to $1.5 billion from $1.75 billion on 10/21/2013; commitments can be expanded to the full $2.0 billion borrowing base upon bank approval.

PRO FORMA CAPITALIZATION

($ in millions) 12/31/2013 (PF Financing) 12/31/2013 (2) Cash $17 $17 Senior Secured Revolving Credit Facility 288 288 7.25% Senior Notes Due 2019 260 260 6.00% Senior Notes Due 2020 525 525 5.375% Senior Notes Due 2021 1,000 1,000 Net Unamortized Premium 6 6 Total Debt $2,079 $2,079 Net Debt $2,062 $2,062 Shareholders' Equity $3,599 $3,599 Net Book Capitalization $5,660 $5,660 Net Market Capitalization(1) $18,816 $18,816 Financial & Operating Statistics LTM EBITDAX $649 $649 LTM Interest Expense(2) $137 $106 Proved Reserves (Bcfe) (12/31/2013) 7,632 7,632 Proved Developed Reserves (Bcfe) (12/31/2013) 2,023 2,023 Credit Statistics Net Debt / LTM EBITDAX 3.2x 3.2x LTM EBITDAX / Interest Expense 4.8x 6.1x Net Debt / Net Book Capitalization 36.4% 36.4% Net Debt / Net Market Capitalization 11.0% 11.0% Net Debt / Proved Developed Reserves ($/Mcfe) $1.02 $1.02 Net Debt / Proved Reserves ($/Mcfe) $0.27 $0.27 Liquidity Credit Facility Commitments(3) $1,500 $1,500 Less: Borrowings (288) (288) Less: Letters of Credit (32) (32) Plus: Cash 17 17 Liquidity (Credit Facility + Cash) $1,197 $1,197

41

ANTERO EBITDAX RECONCILIATION

42

EBITDAX Reconciliation

($ in millions) (12 Months Ended) Antero Resources LLC 12/31/2012 12/31/2013 EBITDAX: Net income (loss) from continuing operations $225.3 $(24.2) Commodity derivative fair value (gains) losses (179.5) (491.7) Net cash receipts on settled commodity derivatives instruments 178.5 163.6 (Gain) loss on sale of assets (291.2)

• Interest expense and other

97.5 136.6 Loss on early extinguishment of debt

• 42.6

Provision (benefit) for income taxes 121.2 186.2 Depreciation, depletion, amortization and accretion 102.1 234.9 Impairment of unproved properties 12.1 10.9 Exploration expense 14.7 22.3 Stock compensation expense

• 365.3

Other 4.1 2.9 EBITDAX from continuing operations $284.7 $649.4 EBITDAX: Net income (loss) from discontinued operations ($510.3) 5.3 Commodity derivative fair value (gains) losses (46.4)

• Net cash receipts on settled commodity derivatives instruments

92.2

• (Gain) loss on sale of assets

795.9 (8.5) Provision (benefit) for income taxes (272.6) 3.2 Depreciation, depletion, amortization and accretion 89.1

• Impairment of unproved properties

1.0

• Exploration expense

1.0

• EBITDAX from discontinued operations

$149.6

• EBITDAX

$434.3 $649.4

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, 2013 included in this presentation have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates are as of December 31, 2013, assuming 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, 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.  “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.  “Highly-rich/condensate” refers to gas having a heat content between 1275 BTU and 1350 BTU in the Marcellus Shale and 1250 BTU and 1300 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 1250 BTU in the Utica Shale.  “Rich gas” refers to gas having a heat content of between 1100 BTU to 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

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