company website presentation january 2016

Company OverviewJanuary 2016

FORWARD-LOOKING STATEMENTS

This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Antero Resources Corporation and its subsidiaries (collectively, the “Company” or “Antero”) expects, believes or anticipates will or may occur in the future are forward-looking statements. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “estimate,” “project,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include estimates of the Company’s reserves, expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company’s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include the factors discussed or referenced under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014 and in the Company’s subsequent filings with the SEC.

The Company cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014 and in the Company’s subsequent filings with the SEC.

Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

1

Antero Resources Corporation is denoted as “AR” and Antero Midstream Partners LP is denoted as “AM” in the presentation, which are their respective New York Stock Exchange ticker symbols.

2

CHANGES SINCE DECEMBER 2015 PRESENTATION

Slide 12, 53

Updated AR “bridge” slide for hedges and 2015E F&D cost as of 12/31/2015 Slide 3

Updated 9/30/2015 AR and AM standalone leverage and liquidity slides for 12/31/2015 pricing Slide 13

Updated hedge and mark-to-market graphs for AR as of 12/31/2015

Slide 9, 24, 51, 52 Updated AR slides highlighting Marcellus and Utica single well economics as of 12/31/2015

Updated AR slides showing net acres and rig position as of 12/31/2015 Slide 5, 25, 29

Slide 15, 16Updated gas, propane and NGL realizations and hedges for AR as of 12/31/2015

ANTERO – “THE BRIDGE” TO BETTER OIL & GAS PRICES

2015E 2016E 2017E

Large and Growing Production Base

Declining Development Costs

Production Sold Forward

Strong Liquidity

Firm Transport to Favorable Markets

40%+ growth1.4 Bcfe/d+

25% - 30% growth targetmidpoint 1.785 Bcfe/d

Continue to target peer-leading production growth

~$0.88/Mcfe YTD down 10% from 2014

• 2,450 “high grade” horizontal locations with similar economics

• Target 12% cost reduction

Continue to target peer-leading development costs

1,316 BBtu/d hedged at $4.43/MMBtu(94% of guidance)

1,793 BBtu/d hedged at $3.94/MMBtu(≈100% of target)

2,073 BBtu/d hedged at $3.57/MMBtu

• $3.0 billion at 9/30/2015• Additional $2.7 billion of

AM units

Continue to target growth in PDP reserves, midstream assets and hedge portfolio

Continue to target growth in PDP reserves, midstream assets and hedge portfolio

• 2.3 Bcf/d of FT• Expect 71% of sales volumes

priced at favorable markets


priced at favorable markets


priced at favorable markets• 61,500 Bbl/d of FT on

Mariner East 2 for export

Highly Sustainable Business Model - Antero holds a leading position within the lowest cost U.S. basin, a large and growing production base, a substantial long-term hedge position, over $5.0 billion of direct and indirect liquidity, and an increasing percentage of volumes sold to favorable markets

3

4

Most Active Operatorin Appalachia

Largest Firm Transport and Processing

Portfolio in Appalachia

Largest Gas Hedge Position in U.S. E&P +

Strong Financial Liquidity

Highest Growth Large Cap E&P

Largest Core Liquids-Rich Position in

Appalachia

Highest Realizations and Margins Among

Large Cap Appalachian Peers

Growth Liquids-Rich

Hedging &Liquidity

Midstream

Drilling

LEADING UNCONVENTIONAL BUSINESS MODEL

MLP (NYSE: AM)Highlights

Substantial Value in Midstream Business

Realizations

Takeaway

WellEconomics

1

2 3

4

5

67

8

Premier AppalachianE&P Company

Run by Co-Founders

High ReturnLocations

Note: 2014 SEC prices were $4.07/MMBtu for natural gas and $81.48/Bbl for oil on a weighted average Appalachian index basis. 2015 SEC prices expected to be lower. 1. All net acres allocated to the WV/PA Utica Shale Dry Gas and Upper Devonian Shale are included among the net acres allocated to the Marcellus Shale as they are stacked pay formations attributable to

the same leasehold. 2. Antero and industry rig locations as of 1/1/2016, and average rig count for 4Q 2015, per RigData.

DRILLING – MOST ACTIVE OPERATOR IN APPALACHIA

5

COMBINED TOTAL – 12/31/14 RESERVESAssumes Ethane RejectionNet Proved Reserves 12.7 TcfeNet 3P Reserves 40.7 TcfePre-Tax 3P PV-10 $22.8 BnNet 3P Reserves & Resource 53 to 57 TcfeNet 3P Liquids 1,026 MMBbls% Liquids – Net 3P 15%3Q 2015 Net Production 1,506 MMcfe/d- 3Q 2015 Net Liquids 52,250 Bbl/dNet Acres(1) 569,000Undrilled 3P Locations 5,331

UTICA SHALE CORE

Net Proved Reserves 758 BcfeNet 3P Reserves 7.6 TcfePre-Tax 3P PV-10 $6.1 BnNet Acres 147,000Undrilled 3P Locations 1,024

MARCELLUS SHALE CORE

Net Proved Reserves 11.9 TcfeNet 3P Reserves 28.4 TcfePre-Tax 3P PV-10 $16.8 BnNet Acres 422,000Undrilled 3P Locations 3,191

UPPER DEVONIAN SHALE

Net Proved Reserves 8 BcfeNet 3P Reserves 4.6 TcfePre-Tax 3P PV-10 NMUndrilled 3P Locations 1,116

WV/PA UTICA SHALE DRY GASNet Resource 12.5 to 16 TcfNet Acres 188,000Undrilled Locations 1,889

02468

1012

Rig

Cou

nt

Operators

4Q Average SW Marcellus & Utica

0.25

0.50

0.75

1.00

1.25

1.50

4Q'13 Annualized 2014A 2015E

29%

22%19%

17%

10%

(4%)

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

35%

AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5

GROWTH – DEBT-ADJUSTED PER SHARE PRODUCTION

6

Based on the strength of its drilling program, and focus on the highly prolific Marcellus and Utica Shale core areas, Antero has delivered 29% compounded annual growth in net debt-adjusted production per share since its IPO in October 2013

Antero’s net debt-adjusted production per share growth rate is seven percentage points higher than the next closest Appalachian peer

NOTE: Production/Net Debt-Adjusted Share = total production divided by net debt-adjusted shares outstanding each period. 1. Net debt-adjusted shares = net debt at end of each period/stock price average for each respective period, plus average common shares outstanding each respective period.2. Peers include CNX, COG, EQT, RRC, SWN.

AR Annualized Production / Net Debt-Adjusted Share(1)

Mcf

e/Sh

are

Net Debt-Adjusted Production per Share Growth vs. Peers (2)

(Since AR IPO)

0

10,000

20,000

30,000

40,000

2010 2011 2012 2013 2014 2015E

NGLs (C3+) Oil

5 246

6,436

23,051

37,000+

61%+ GrowthGuidance1. Assumes ethane rejection.

2. Reflects midpoint of 2016 production growth target of 25%-30%.

1,400

1,785

0

600

1,200

1,800

2010 2011 2012 2013 2014 2015E 2016E

Marcellus Utica Guidance

30124

239

522

1,007

7

AVERAGE NET DAILY PRODUCTION (MMcfe/d)

0

50

100

150

200

2010 2011 2012 2013 2014 2015E

Marcellus Utica Deferred Completions

1938

60

114

177 180

130

GROWTH – STRONG TRACK RECORD

OPERATED GROSS WELLS COMPLETED

40%+ GrowthGuidance

0

3,000

6,000

9,000

12,000

15,000

2010 2011 2012 2013 2014

Marcellus Utica

677

2,8444,283

7,632

(1) (1)

12,683

(1)

NET PROVED RESERVES (Bcfe)

AVERAGE NET DAILY LIQUIDS PRODUCTION (Bbl/d)

+

25%-30% GrowthTarget

(2)

8

LIQUIDS-RICH – LARGEST CORE POSITION

Source: Core outlines and peer net acreage positions based on investor presentations, news releases and 10-K/10-Qs. Rig information per RigData as of 1/1/2016.1. Based on company filings and presentations. Peer group includes Ascent, CHK, CNX, CVX, ECR, EQT, GPOR, NBL, RRC, STO, SWN.

• Antero controls an estimated 37% of the NGLs in the liquids-rich core of the two plays

• Antero has the largest core liquids-rich position in Appalachia with ≈371,000 net acres (> 1100 Btu)

• Represents over 21% of core liquids-rich acreage in Marcellus and Utica plays combined

Antero has over 3,000 undeveloped rich gas locations with an average lateral length of 6,800’ in its 3P reserves as of 12/31/2014

0

100

200

300

400

(000

s)

Core Liquids-Rich Net Acres(1)

94 289 254 664 139 1,010 889 628 248

29%26% 23%

34%27%

22%

11% 9% 10%

83% 80%

71%

63%57%

47%

28%24%

16%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Utica Highly-Rich Gas

Utica Dry Gas - Ohio

Utica Rich Gas MarcellusHighly-Rich

Gas/Condensate

Utica Highly-Rich Gas/

Condensate

MarcellusHighly-Rich

Gas

Marcellus DryGas

Marcellus RichGas

UticaCondensate

RO

R

ROR @ 12/31/2015 Strip Pricing - Before Hedges ROR @ 12/31/2015 Strip Pricing - After Hedges

2016 Antero Drilling Plan

1. 12/31/2015 pre-tax well economics based on a 9,000’ lateral, 12/31/2015 natural gas and WTI strip pricing for 2016-2024, flat thereafter, NGLs at 37.5% of WTI for 2016 and 50% of WTI thereafter, and applicable firm transportation and operating costs including 50% of Antero Midstream fees. Well cost estimates, which include $1.2 million for road, pad and production facilities, assume Antero will begin to realize lower well costs in 2016 as the company utilizes incremental completion crews for deferred completions beginning at year end 2015 and as existing drilling rig contracts begin to roll off during 2016.

2. ROR @ 12/31/2015 Strip Pricing – After Hedges reflects 12/31/2015 well cost ROR methodology with the 12/31/2015 hedge value allocated based on 2016-2021 projected production volumes resulting in blend of strip and hedge prices.

9

At 12/31/2015 strip pricing, Antero has 2,450 locations with well economics that exceed 20% rate of return (excluding hedges)– Including hedges, these locations generate rates of return of approximately 47% to 83%

Rates of return include pad, facilities, cash production expenses (including midstream and FT costs)– See assumptions pages in appendix for further detail

ANTERO MARCELLUS & UTICA WELL ECONOMICS(1)(2)

2,450 “High Grade” Drilling

Locations

NYMEX($/MMBtu)

WTI($/Bbl)

C3+ NGL($/Bbl)

2016 $2.50 $41 $152017 $2.79 $46 $232018 $2.91 $49 $252019 $3.03 $52 $262020 $3.18 $54 $272021-25 $3.31-$3.88 $55-$56 $27-$28

12/31/15 Strip Pricing 12/31/15 Hedge PricingNYMEX

($/MMBtu)C3+ NGL

($/Bbl)

$4.19 $18$3.72 $22$3.70 $25$3.60 $26$3.38 $27

$3.31 - $3.88 $27-$28

$2.50 $2.79 $2.91 $3.03 $3.18

$4.19$3.72 $3.70 $3.60 $3.38

$0.00$1.00$2.00$3.00$4.00$5.00

2016 2017 2018 2019 2020

12/31/15 NYMEX Strip Pricing - Before Hedges12/31/15 Strip Pricing - After Hedges

Locations

WELL ECONOMICS – WELL COST REDUCTIONS SUPPORTSUSTAINABLE BUSINESS MODEL

Antero ResourcesCorporation (NYSE: AR)

$9.9 Billion Enterprise Value(1)

Ba2/BB Corporate Rating

Antero MidstreamPartners LP (NYSE: AM)

$4.5 Billion Enterprise Value(1)

67% LP Interest$2.7 Billion MV(1)

E&P Assets

Gathering/Compression Assets

MIDSTREAM – MLP (NYSE: AM) HIGHLIGHTSSUBSTANTIAL VALUE IN MIDSTREAM BUSINESS

1. AR enterprise value excludes AM debt, minority interest and cash. Market values (MV) as of 12/31/2015 and includes subordinated units; balance sheet data as of 9/30/2015. 2. Based on 277.0 million AR shares outstanding and 175.8 million AM units outstanding.3. 3.5 Tcfe hedged at $3.81/Mcfe average price through 2022 with mark-to-market (MTM) value of $3.1 billion as of 12/31/2015. 10

Corporate Structure Overview(1)

Market Valuation of AR Ownership in AM:• AR ownership: 67% LP Interest = 116.9 million units

AM Priceper Unit

AM UnitsOwnedby AR(MM)

AR Value in AM LP Units

($MMs)Value Per

AR Share(2)

$20 117 $2,338 $8$21 117 $2,455 $9$22 117 $2,572 $9$23 117 $2,689 $10$24 117 $2,806 $10$25 117 $2,923 $11

Water Infrastructure Assets

MLP Benefits:- Funding vehicle to expand midstream business- Highlights value of Antero Midstream- Liquid asset for Antero Resources

Public

33% LP Interest$1.3 Billion MV(1)

$3.1 Bn MTM Hedge Position(3)

As of 3Q 2015: 1,506 MMcfe/d Net 40.7 Tcfe 3P Reserves 5,331 Undrilled Locations

TAKEAWAY – LARGEST FIRM TRANSPORTATION AND PROCESSING PORTFOLIO IN APPALACHIA

Antero Long Term Firm Processing & Takeaway Position (YE 2018) – Accessing Favorable MarketsMariner East 2

62 MBbl/d CommitmentMarcus Hook Export

Shell20 MBbl/d Commitment

Beaver County Cracker (2)

Sabine Pass (Trains 1-4)50 MMcf/d per Train

Lake Charles LNG(3)

150 MMcf/d

Freeport LNG70 MMcf/d

1. February 2016 and full year 2016 futures basis, respectively, provided by Intercontinental Exchange dated 12/31/2015. Favorable markets shaded in green.2. Subject to Shell FID expected mid-year 2016.3. Lake Charles LNG 150 MMcf/d commitment subject to BG FID expected in 2016.

Chicago(1)

$0.25 / $0.02

CGTLA(1)

$(0.07) / $(0.06)

TCO(1)

$(0.16) / $(0.18)

11

Cove Point LNG4.85 Bcf/dFirm GasTakeaway

By YE 2018

Antero’s natural gas firm transportation (FT) portfolio builds to 4.85 Bcf/d by YE 2018 with 87% serving favorable markets, with an average demand fee of $0.40/MMBtu and positive weighted average basis differential to NYMEX after assumed Btu uplift for gas

YE 2018 Gas Market MixAR 4.85 Bcf/d FT

44%Gulf Coast

17%Midwest

13%Atlantic

Seaboard

13%Dom S/TETCO

(PA)

13%TCO

Positive weighted

average basis differential

Antero Commitments

(3)

(2)

12

HEDGING – INTEGRAL TO BUSINESS MODEL Hedging is a key component of Antero’s business model which includes development of a large, repeatable drilling inventory

– Locks in higher returns in a low commodity price environment and reduces well payout thereby enhancing liquidity

Antero has realized $1.7 billion of gains on commodity hedges since 2009– Gains realized in 28 of last 29 quarters, or 97% of the quarters since 2009

● Based on Antero’s hedge position and strip pricing as of 12/31/2015, the unrealized commodity derivative value is $3.1 billion

● Significant additional hedge capacity remains under the credit facility hedging covenant for 2018 – 2022 period

Quarterly Realized Hedge Gains / (Losses)

Realized Hedge GainsProjected Hedge Gains

NYMEX Natural Gas Historical Spot Prices

($/Mcf)

NYMEX Natural Gas Futures Prices

3.5 Tcfe Hedged at average price of

$3.81/Mcfethrough 2022

Average Hedge Prices ($/Mcfe)

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$0

$50

$100

$150

$200

$250

$300

$MM

$3.50

$4.51

$3.94

$3.57$3.88 $3.89

$3.73$3.30

$3.1 Billion on Balance Sheet in

Hedge Gains Through 2022Realized $1.7 Billion

in Hedge Gains Since 2009

Liquid “non-E&P assets” of $5.8 Bnsignificantly exceeds total debt of $3.9 Bn

Liquidity

LIQUIDITY – STRONG BALANCE SHEET AND FLEXIBILITY Antero Resources (NYSE:AR) Antero Midstream (NYSE:AM)

9/30/2015 Debt Liquid Non-E&P Assets 9/30/2015 Debt Liquid Assets

Debt Type $MMCredit facility $500

6.00% senior notes due 2020 525

5.375% senior notes due 2021 1,000

5.125% senior notes due 2022 1,100

5.625% senior notes due 2023 750

Total $3,875

Asset Type $MMCommodity derivatives(1) $3,117

AM equity ownership(2) 2,668

Cash 10

Total $5,795

Asset Type $MMCash $10

Credit facility – commitments(3) 4,000

Credit facility – drawn (500)

Credit facility – letters of credit (535)

Total $2,975

Debt Type $MMCredit facility $525

Total $525


Total $18

Liquidity


Credit facility – capacity 1,500

Credit facility – drawn (525)

Credit facility – letters of credit -

Total $993

Approximately $3.0 billion of liquidity at AR plus an additional $2.7 billion of AM units

Approximately $1 billion of liquidityat AM

13

Only 35% of AM credit facility capacity drawn

Note: All balance sheet data as of 9/30/2015, inclusive of water drop down and associated financing. 1. Mark-to-market as of 12/31/2015.2. Based on AR ownership of AM units (116.9 million common and subordinated units) and AM’s closing price as of 12/31/2015.3. AR credit facility commitments of $4.0 billion, borrowing base of $4.5 billion.

$1.97 $1.62

$1.30 $1.18 $1.17 $0.66

$0.58 $0.73 $0.85 $0.72 $0.88$0.75

$3.86

$2.93

$2.33 $2.34 $2.55

$2.35

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50


$/M

cfe

Noncontrolling Interest of Midstream MLP EBITDA LOEProduction Taxes GPTG&A EBITDAX4-year Avg. All-in F&D

$3.99

$2.77 $2.63 $2.46 $2.21 $2.02

$0.00$0.50$1.00$1.50$2.00$2.50$3.00$3.50$4.00$4.50


Region3Q 2015 % Sales

Average NYMEX Price

AverageDifferential(2)

AverageBTU Upgrade

Hedge Effect

Average 3Q 2015Realized Gas Price(3)

NYMEX Premium/Discount

TCO 41% $2.77 $(0.30) $0.22 $0.14 $2.83 $0.06Dom South/TETCO 32% $2.77 $(1.63) $0.10 $0.77 $2.01 $(0.76)Gulf Coast(1) 7% $2.77 $(0.27) $0.22 $0.68 $3.40 $0.63Chicago/Michigan 20% $2.77 $0.20 $0.18 $0.04 $3.19 $0.42Total Wtd. Avg. 100% $2.77 $(0.62) $0.17 $1.67 $3.99 $1.22

1. Gulf Coast differential includes contractual deduct to NYMEX-based sales.2. Includes firm sales. 3. Includes natural gas hedges.4. Source: Public data from 3Q 2015 10-Qs. Peers include Cabot Oil & Gas, CONSOL Energy, EQT Corp. and Southwestern. 5. Includes realized hedge gains and losses. Operating costs include lease operating expenses, production taxes, gathering, processing and firm transport costs and general and administrative costs. 4-year proved

reserve average all-in F&D from 2011-2014. Calculation = (Development costs + exploration costs + leasehold costs) / Total reserves added (2014 ending reserves – 2011 beginning reserves + 4-year reserve sales – 4-year reserve purchases + 4-year accumulated production). AR price realization includes $0.03 of midstream revenues; EBITDAX excludes AR’s midstream EBITDA not attributable to AR’s ownership.

14

REALIZATIONS – A LEADER IN REALIZATIONS & MARGINSAMONG LARGE-CAP APPALACHIAN PEERS

3Q 2015 Natural Gas Realizations(3)(4) 3Q 2015 Price Realization & EBITDAX Margin vs F&D(4)(5)

($/Mcfe)

Antero continues to be a leader in its peer group in price realizations and EBITDAX unit margins

3Q 2015 Natural Gas Realizations ($/Mcf)

3Q 2015 NYMEX = $2.77/Mcf

DOM S 23%

DOM S, 4% DOM S, 4%

TETCO M27%

TETCO M21%

TETCO M21%

TCO 40%

TCO 32%

TCO, 21%

NYMEX10%

NYMEX14%

NYMEX10%

Gulf Coast2%

Gulf Coast21% Gulf Coast

39%

Chicago18% Chicago

28%Chicago

25%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

($/Mcf) 2015E 2016ENYMEX Strip Price(1) $2.66 $2.49Basis Differential to NYMEX(1) $(0.53) $(0.17)BTU Upgrade(5) $0.25 $0.24Estimated Realized Hedge Gains $1.47 $1.49 Realized Gas Price with Hedges $3.86 $4.05 Premium to NYMEX +$1.29 +$1.56Liquids Impact +$0.25 +$0.11Premium to NYMEX w/ Liquids +$1.45 +$1.67Realized Gas-Equivalent Price $4.11 $4.16

REALIZATIONS – REALIZED PRICE “ROAD MAP”

Note: Hedge volumes as of 12/31/2015.1. Based on 12/31/2015 strip pricing and YTD actuals for 2015. 2. Differential represents contractual deduct to NYMEX-based firm sales contract.3. Represents 120,000 MMBtu/d of TCO index hedges and 390,000 MMBtu/d of

TCO basis hedges that are matched with NYMEX hedges for presentation purposes.

4. Represents 60,000 MMBtu/d of TCO index hedges and 120,000 MMBtu/d of TCO basis hedges that are matched with NYMEX hedges for presentation purposes.

5. Assumes ethane rejection resulting in 1100 BTU residue sales gas.

2015Basis(1)

2016 Basis(1)

2017 Basis(1)

2015Hedges

2016Hedges

2017Hedges

Mar

kete

d %

of T

arge

t Res

idue

Gas

Pro

duct

ion

+$0.02/MMBtu

$(0.12)/MMBtu(2)

$(1.30)/MMBtu

$(0.28)/MMBtu

$0.02/MMBtu

$(0.43)/MMBtu(2)

$(0.95)/MMBtu

$(0.18)/MMBtu

$(0.04)/MMBtu

$(0.43)/MMBtu(2)

$(0.78)/MMBtu

$(0.25)/MMBtu

$(0.05)/MMBtu

$(0.06)/MMBtu

1,370,000 MMBtu/d

@ $3.40/MMBtu

40,000 MMBtu/d

@ $4.00/MMBtu

230,000 MMBtu/d

@ $5.74/MMBtu

510,000 MMBtu/d

@ $3.87/MMBtu(3)

170,000 MMBtu/d

@ $4.09/MMBtu

272,500 MMBtu/d

@ $5.35/MMBtu

180,000 MMBtu/d

@ $3.54/MMBtu(4)

95% exposure to favorable price indices71% exposure to favorable price indices 95% exposure to favorable price indices

Antero’s exposure to favorable gas price indices like Chicago, Gulf Coast, NYMEX and TCO is expected to increase to 95% by 2016 Improved 2016 realizations driven by Stonewall gathering pipeline which was placed in-service in early December 2015 and will eliminate

virtually all swing sales at Dominion South and Tetco in 2016

$(1.00)/MMBtu

$(0.93)/MMBtu

Wtd. Avg.Basis ($0.53)

Wtd. Avg.Basis $(0.17)

1,160,000 MMBtu/d@ $4.34/MMBtu

Wtd. Avg.Basis $(0.17)

1,612,500 MMBtu/d@ $3.92/MMBtu

420,000 MMBtu/d

@ $4.27/MMBtu

2015E 2016E 2017E

15

380,000 MMBtu/d

@ $3.88/MMBtu

990,000 MMBtu/d

@ $3.49/MMBtu

70,000 MMBtu/d

@ $4.57/MMBtu

1,860,000 MMBtu/d@ $3.64/MMBtu

$(0.10)/MMBtu

$(0.75)/MMBtu

Current markets indicate positive

differential in 2016

$0.59

$0.43 $0.40

$0.41

$0.10

$0.20

$0.30

$0.40

$0.50

$0.60

$0.70

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

2016 2017

Hedged Volume Average Hedge Price Strip (12/31/2015)

$52.61 $53.71 $46.23 $51.98

$16.53$25.23

$15.17$21.89

$98.01 $93.03

$48.63 $41.00

$0.00

$20.00

$40.00

$60.00

$80.00

$100.00

$120.00

AR NGL Pricing Mont Belvieu AR NGL Pricing Mont Belvieu AR NGL Pricing Mont Belvieu AR NGL Pricing Mont Belvieu

2013 2014 2015 YTD 2016E

Realized NGL C3+ Price WTI

REALIZATIONS – NGL REALIZATIONS AND PROPANE HEDGES

161. Based on 2016 NGL and WTI strip prices as of 12/31/2015. 2. YTD as of 10/31/2015. 3. As of 12/31/2015.

Realized NGL Prices as % of WTI(1)

54% 50%

34% 37%

($/Bbl)

NGL Marketing Propane Hedges Realized NGL (C3+) price was 50% of WTI in 2014 and

Antero is forecasting 30% to 35% of WTI for 2015−YTD 2015(2) NGL realizations were 34% of WTI− Including propane hedges, first ten months of 2015

realizations were 40% of WTI

By year-end 2016, Antero will market a significant portion of its NGL volumes out of Marcus Hook to export markets once Mariner East 2 is in service – 61,500 Bbl/d firm commitment with expansion rights

(Bbl/d)

$82 MM $7 MM

($/Gal)

Mark-to-Market Value(3)

Target 2016 NGL pricing of 37% of WTI based on 12/31/15 strip pricing

(2)

NORTHEAST NGLS ARE TRANSPORTATION CHALLENGED

1. As an anchor shipper on Mariner East 2, Antero has the right to expand its NGL commitment with notice to operator. 2. 2015 NGL production assumes ethane rejection.

Mariner East 261,500 Bbl/d AR Commitment(1)

4Q 2016 In-Service

Not so much a supply problem but more of a logistics problem for NGLs in the northeast today− The majority of northeast NGL production is being transported by expensive rail and trucking− NGLs that are transported “to the water” are also faced with high shipping rates

Export15%

Gulf Coast13%

Mid-Atlantic

6%Sarnia

3%

Northeast43%

Midwest10%

Edmonton10%

2015 NGL Marketing by Region

17

NORTHEAST NGL GROWTH IS SUPPORTED BY INCREASING TAKEAWAY OPTIONS

1. Chart 10 per BAML research dated 6/5/2015. Pipeline volumes are capacity estimates.

Industry NGL Pipelines – Actual (2015) and Projected(1)

18

ShellBeaver County Cracker(Pending FID 1H 2016)

Mariner East 262 MBbl/d Commitment

Marcus Hook Export

Gulf Coast Critical to

NGL Pricing

Appalachia

NGL transportation rates are expected to decline $0.12 to $0.15 per gallon by 2017 as pipeline options to domestic markets and export terminals go in-service (Mariner East 1 and 2, for example)

(MMBbl/d)

$0.00

$0.10

$0.20

$0.30

$0.40

$0.50

$/G

allo

n

Baltic Exchange LPG Freight Futures

Baltic LPG Rate ($/gal) Marcus Hook to Europe ($/gal)

Marcus Hook to Far East ($/gal)

U.S. EXPORTS ARE SUPPORTED BY EXCESSDOCK CAPACITY AND FLEET GROWTH

0200400600800

1,0001,2001,4001,6001,800

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

MB

bl/d

Butane Exports Propane Exports Total Export Capacity

Excess LPG Export Terminal Capacity vs. Expected Export Volumes(1)

Excess dock capacity supports growing LPG export volumes

through 2025

Fleet Growth Supports U.S. LPG Export Growth(2) LPG Freight Futures Show Declining Freight Costs(3)

Baltic LPG shipping cost to NWE declines from $0.14/gal to $0.09-$0.10/gal in early

2017 on fleet supply growth numbers

Projected growth in VLGC fleet supports increasing LPG export volumes and

lower shipping costs

1. Source: Bentek.2. Source: Poten & Partners, August 2015.3. Baltic Rate based on 9/30/2015 Baltic Futures converted to cost per gallon of LPGs, assuming 75/25 propane/butane.

LPG transportation rates from northeast fractionation to Europe and Asia should improve by $0.05 to $0.15 per gallon by YE 2016,driven both by pipelines replacing rail and by lower shipping costs

Excess Dock Capacity

Current Fleet 168New builds +85

19

POSITIVE OUTLOOK FOR LONG-TERM NGL MARKETS

Steady Global LPG Demand Growth Through 2035(1)

1. Source: PIRA NGL Study, September 2015.2. Source: IHS, Waterborne, SK Gas Analysis; Wood Mackenzie; Wood Mackenzie; PDH C3 capacity based on 25 MBbl/d = 650 Mt/y.

Multiple Factors Driving Global LPG Demand Growth Through 2020(2)

MM

Bbl

/d

0.0

0.33

0.67

Forecast global LPG demand growth of 800 MBbl/d to 1 MMBbl/d by 2020 to be driven by petrochem projects in Asia and Middle East as well as residential/commercial, alkylate and power generation demand− Naphtha cracker conversion to LPG another potential demand driver that has not yet been factored into analyst estimates ≈1 MMBbl/d

China KoreaHaiwei (2016) - 21 MBbl/d C3

SK Advanced (2016) - 27 MBbl/d C3

Ningbo Fuji (2016) - 29 MBbl/d C3

Fujian Meide (2016) - 29 MBbl/d C3

Tianjin Bohua 2 (2018) - 29 MBbl/d C3 United States

Fujian Meide 2 (2018) - 29 MBbl/d C3

Enterprise (3Q 2016)- 29 MBbl/d C3

Oriental Tangshan (2019) - 25 MBbl/d C3

Formosa (2017)- 25 MBbl/d C3

Firm and Likely PDH Underway (By 2020)

Total - 243 MBbl/d C3

Million Tons, Global PDH Capacity

1990 2000 2010 2020

20

10

0

20

14.7

13.0

11.4

9.8

8.2

6.5

4.9

3.3

1.7

U.S. Driven Global LPG Supply Through 2035(1)

MMBbl/d MMBbl/d1.3

1.0

0.7

0.3

-0.3

Downstream LNGand NGL Sales

Production andCash Flow Growth

21

Antero has completed its first Utica dry gas well with encouraging early results; has 229,000 net acres in OH, WV and PA highly prospective for Utica dry gas

KEY CATALYSTS

Targeting 25% to 30% production growth in 2016 with ~100% hedged at $3.94/MMBtu; capital budget flexibility to commodity price changes

Large, low unit cost core Marcellus and Utica natural gas drilling inventory with associated liquids generates attractive returns supported by long-term natural gas hedges, takeaway portfolio and downstream LNG and NGL sales agreements

Pursuing additional value enhancing long-term LNG and NGL sales agreements, as well as additional NGL firm takeaway

Antero owns 67% of Antero Midstream Partners and thereby participates directly in its growth and value creation; acquisition of integrated water business from Antero expected to result in distributable cash flow per unit accretion in 2016

Midstream MLP Growth

Sustainability of Antero’s Integrated

Business Model

1

2

3

5

4Utica Dry Gas

Activity

-

100

200

300

400

500

600


Core Net Acres - Dry Core Net Acres - Liquids Rich

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

AR EQT RRC COG CNX SWN

0200400600800

1,0001,2001,4001,6001,800

EQT COG AR SWN RRC CNX

LEADERSHIP IN APPALACHIAN BASIN

Top Producers in Appalachia (Net MMcfe/d) – 3Q 2015(1)(2) Top 12 U.S. Natural Gas Producers (Net MMcf/d) – 3Q 2015(1)

Appalachian Producers by Proved Reserves (Bcfe) – YE 2014(1)(2) Appalachian Producers by Core Net Acres (000’s) – August 2015(3)(4)

1. Based on company filings and presentations.2. Appalachian only production and reserves where available. Excludes companies that do not break out Appalachian production including CVX, HES and XOM. 3. Based on Antero geologic interpretation supported by state well data, company presentations and public land data. Peer group includes CNX, COG, EQT, RRC, SWN.4. Southwestern leasehold and reserves include the impact from STO and WPX property acquisitions closed in January 2015. 5. Includes proved reserves categorized in “Northern Division” consisting of Utica Shale, Marcellus Shale and Powder River Basin.

(4)

22

3rd Largest Appalachian

Producer

Antero has the largest proved reserve base, the largest core liquids-rich acreage position and is one of the largest producers in the Appalachian Basin

Appalachian Peers

11th Largest U.S. Gas Producer

Largest Proved Reserve Base In

Appalachia

0

500

1,000

1,500

2,000

2,500

3,000

3,500

Largest Liquids-Rich Core Position

in Appalachia

ASSET OVERVIEW

23

248

139 94

254289

16%

57%

83%

71% 80%

10%

27% 29% 23% 26%

0

100

200

300

0%20%40%60%80%

100%

Condensate Highly-RichGas/

Condensate

Highly-RichGas

Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

R

664 1,010

62888963% 47%

24% 28%34%22%

9% 11%

0

400

800

1,200

0%15%30%45%60%75%

Highly-RichGas/

Condensate

Highly-Rich Gas Rich Gas Dry Gas

Tota

l 3P

Loca

tions

RO

R

Total 3P Locations ROR @ 12/31/2015 Strip Pricing - After Hedges ROR @ 12/31/2015 Strip Pricing - Before Hedges

MARCELLUS WELL ECONOMICS(1)(2)

WELL COST REDUCTIONS SUPPORTSUSTAINABLE BUSINESS MODEL

Marcellus Well Cost Improvement(3)

1. 12/31/2015 pre-tax well economics based on a 9,000’ lateral, 12/31/2015 natural gas and WTI strip pricing for 2016-2025, flat thereafter, NGLs at 37.5% of WTI for 2016 and 50% of WTI thereafter, and applicable firm transportation and operating costs including 50% of Antero Midstream fees. Well cost estimates, which include $1.2 million for road, pad and production facilities.

2. ROR @ 12/31/2015 Strip-With Hedges reflects 12/31/2015 well cost ROR methodology, with the 12/31/2015 hedge value allocated based on 2016-2021 projected production volumes resulting in blend of strip and hedge prices.

3. 2015E well costs based on $10.3 million for a 9,000’ lateral Marcellus well and $11.6 million for a 9,000’ lateral Utica well.

24

UTICA WELL ECONOMICS(1)(2)

72% of Marcellus locations are processable (1100-plus Btu) 72% of Utica locations are processable (1100-plus Btu)

2016Drilling

Plan

Antero has reduced average well costs for a 9,000’ lateral by 16% in the Marcellus and 18% in the Utica as compared to 2014 well costs At 12/31/2015 strip pricing, Antero has 2,450 locations that exceed 20% rate of return (excluding hedges)

– Including hedges, these locations generate rates of return of approximately 50% to 90%

Utica Well Cost Improvement(3)

$1.357 $1.144

$0.000

$0.500

$1.000

$1.500

$2.000

2014 2015E

$MM

/1,0

00’ L

ater

al

Well Cost ($MM/1,000')

16% Decrease vs. 2014 $1.571

$1.289

$0.000

$0.500

$1.000

$1.500

$2.000

2014 2015E

$MM

/1,0

00’ L

ater

al

Well Cost ($MM/1,000')

18% Decrease vs. 2014

WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECT

100% operatedOperating 7 drilling rigs including

1 intermediate rig422,000 net acres in

southwestern Marcellus core (75% includes processable rich gas assuming an 1100 Btu cutoff)– 52% HBP with additional 25%

not expiring for 5+ years419 horizontal wells completed

and online– Laterals average 7,500’– 100% drilling success rate6 plants in-service at Sherwood

Processing Complex capable of processing in excess of 1.2 Bcf/d of rich gas−Over 900 MMcf/d of Antero gas

being processed currentlyNet production of 1,140 MMcfe/d

in 3Q 2015, including 33,000 Bbl/d of liquids 3,191 future drilling locations in

the Marcellus (2,302 or 72% are processable rich gas)28.4 Tcfe of net 3P (17% liquids),

includes 11.9 Tcfe of proved reserves (assuming ethane rejection)

Highly-Rich Gas138,000 Net Acres

1,010 Gross Locations

Rich Gas91,000 Net Acres

628 Gross Locations

Dry Gas107,000 Net Acres

889 Gross Locations

Highly-Rich/Condensate86,000 Net Acres

664 Gross Locations

HEFLIN UNIT30-Day Rate

2H: 21.4 MMcfe/d (21% liquids)

CONSTABLE UNIT30-Day Rate

1H: 14.3 MMcfe/d (25% liquids)

SherwoodProcessing

Complex

Source: Company presentations and press releases. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held. Note: Rates in ethane rejection.

NERO UNIT30-Day Rate

1H: 18.2 MMcfe/d(27% liquids)

BEE LEWIS PAD30-Day Rate

4-well combined 30-Day Rate of

67 MMcfe/d (26% liquids)

RJ SMITH PAD30-Day Rate



25

HENDERSHOT UNIT30-Day Rate

1H: 16.3 MMcfe/d2H: 18.1 MMcfe/d

(29% liquids)

HORNET UNIT30-Day Rate

1H: 21.5 MMcfe/d2H: 17.2 MMcfe/d

(26% liquids)CARR UNIT30-Day Rate

2H: 20.6 MMcfe/d(20% liquids)

WAGNER PAD30-Day Rate



Antero’s Marcellus well performance has continued to improve over time with a tight statistical range of results across its entire acreage position

PROLIFIC PREDICTABLE RESULTS ACROSS ENTIREMARCELLUS POSITION

26

Marcellus PDP Locations (As of 9/30/2015)

(1)

1. Source: IHS; 3rd party producing wells include Consol, EQT, Exxon/XTO, Noble, Ascent, PDC, Magnum Hunter, Statoil, Chesapeake / SWN.

>1275 BTU2.2 Bcfe/1,000’ Lateral

7 SSL Wells

1200-1275 BTU2.0 Bcfe/1,000’ Lateral

106 SSL Wells

1100-1200 BTU1.8 Bcfe/1,000’ Lateral

110 SSL Wells

Average Antero Marcellus Well

2014 Actual

2H 2015Budget Current

30-Day Rate (MMcfe/d): 13.1 16.1 16.1

Gross EUR (Bcfe): 15.3 19.2 19.2

Gross Well Cost ($MM): $11.8 $10.3 $9.1

Lateral Length (Feet): 8,052 9,000 9,000

Net F&D ($/Mcfe): $0.89 $0.63 $0.56

Btu: 1195 1250 1250

0

5

10

15

20

25

30

1.3 1.4 1.5 1.6 1.7 1.8 1.9 2 2.1 2.2 2.3 2.4 2.5 2.6 2.7 More

Wel

l Cou

nt

Bcfe/1,000' of Lateral

0

5

10

15

20

25

30

MM

cfe/

d

Antero’s Marcellus average 30-day rates have increased by 67% over the past two years as the Company increased per well lateral lengths by 12% and shortened stage lengths by 45% compared to 1H 2013

INCREASING RECOVERIES AND LOW VARIANCEIN MARCELLUS

1. Processed rates converting C3+ NGLs and condensate at 6:1. Ethane rejected and sold in gas stream.

Antero 30-Day Rates – 415 Marcellus Wells(1)

27

Antero SSL Reserves per 1,000’ of Lateral – 223 Marcellus SSL Wells

2014 – 13.0 MMcfe/d

2013 – 9.4 MMcfe/d

2009–2012 – 8.0 MMcfe/d

The Marcellus is a reliable, low risk play as demonstrated by the tight distribution of EURs per 1,000’ and the P10/P90 ratio of only 1.7x for 223 SSL wells

P10: 2.35 Bcfe/1,000’P90: 1.42 Bcfe/1,000’

P10/P90: 1.7x

P90

P10

2015 YTD – 14.4 MMcfe/d

411 420

361

283

200 200

14 16

21

27

40 45

- 5 10 15 20 25 30 35 40 45 50

- 50

100 150 200 250 300 350 400 450

2010 2011 2012 2013 2014 2015E

Ave

rage

Fra

c St

ages

per

Wel

l

Ave

rage

Sta

ge L

engt

h (F

eet)

Increasing Frac Stages per Well

Average Stage Length (Feet) Average Frac Stages per Well

(1)

1.5 1.61.5

1.6

2.0

$0.97 $0.89

$0.98 $1.13

$0.89

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

0.00

0.50

1.00

1.50

2.00

2.50

2010 2011 2012 2013 2014

Dev

elop

men

t Cos

t ($/

Mcf

e)

EUR

/1,0

00' L

ater

al (B

cfe)

EUR vs. Development Cost per Unit

EUR/1,000' Lateral (Bcfe) Development Cost ($/Mcfe) 28

MARCELLUS WELL PERFORMANCE IMPROVEMENTS Increasing recoveries and efficiencies, through longer laterals, shorter stage lengths and faster drilling SSL completions drove a 21% decline in development costs in 2014 while lower service costs and efficiencies are driving further

development cost reductions in 2015

1. 2015 reflects Antero guidance per 1/20/2015 press release. 2. Based on 2015 data as of 11/30/2015.

5,732 6,717

7,345 7,308

8,052 9,000

19

38

59

103

136

80

0

20

40

60

80

100

120

140

160

0

2,000

4,000

6,000

8,000

10,000

2010 2011 2012 2013 2014 2015E

Wel

ls o

n Fi

rst S

ales

Late

ral L

engt

h (F

eet)

Increasing Lateral Lengths

Average Lateral Length (Feet) Wells on First Sales

(1)

37 36 34 32 29 24

13,181 14,067 14,658 14,607 15,355 15,830

-

4,000

8,000

12,000

16,000

20,000

0

10

20

30

40

50

2010 2011 2012 2013 2014 2015YTD

Tota

l Mea

sure

d D

epth

Spud

-to-R

ig R

elea

se D

ays

Increasing Drilling Efficiency

Avg Spud-to-RR Days Total Measured Depth (Feet)

(2)

Note: Antero acreage position reflects townships in which greater than 3,000 net acres are held. Antero 30-day rates in ethane rejection.1. 30-day rate reflects restricted choke regime.

100% operated Operating 3 drilling rigs 147,000 net acres in the core rich gas/

condensate window (73% includes processable rich gas assuming an 1100 Btu cutoff)– 28% HBP with additional 61% not expiring

for 5+ years 93 operated horizontal wells completed and

online in Antero core areas− 100% drilling success rate

4 plants in-service at Seneca Processing Complex capable of processing 800 MMcf/d of rich gas− Over 500 MMcf/d being processed currently,

including third party production Net production of 366 MMcfe/d in 3Q 2015

including 19,250 Bbl/d of liquids Fifth third-party compressor station went in-

service September 2015 with a capacity of 120 MMcf/d

First AM compressor station went in-service November 2015

1,024 future gross drilling locations (735 or 72% are processable gas)

7.6 Tcfe of net 3P (15% liquids), includes 758 Bcfe of proved reserves (assuming ethane rejection)

WORLD CLASS OHIO UTICA SHALEDEVELOPMENT PROJECT

29

CadizProcessing

Plant

NORMAN UNIT30-Day Rate

2 wells average16.8 MMcfe/d (15% liquids)

RUBEL UNIT30-Day Rate

3 wells average17.2 MMcfe/d(20% liquids)

Utica Core Area

GARY UNIT30-Day Rate


Highly-Rich/Cond29,000 Net Acres

139 Gross Locations

Highly-Rich Gas11,000 Net Acres

94 Gross Locations

Rich Gas30,000 Net Acres

254 Gross Locations

Dry Gas41,000 Net Acres

289 Gross Locations

NEUHART UNIT 3H30-Day Rate16.2 MMcfe/d(57% liquids)

Condensate36,000 Net Acres

248 Gross Locations

DOLLISON UNIT 1H30-Day Rate19.8 MMcfe/d(40% liquids)

MYRON UNIT 1H30-Day Rate26.8 MMcfe/d(52% liquids)

SenecaProcessingComplex

LAW UNIT30-Day Rate


SCHAFER UNIT30-Day Rate(1)


URBAN PAD30-Day Rate

4 wells average 18.8 MMcfe/d (15% liquids)

GRAVES UNIT500’ Density Pilot

30-Day Rate4 wells average15.5 MMcfe/d(24% liquids)

FRANKLIN UNIT30-Day Rate


FRAKES UNIT30-Day Rate


1.4 1.6

$1.64

$1.24

$0.00

$0.30

$0.60

$0.90

$1.20

$1.50

$1.80

0.000.200.400.600.801.001.201.401.60

2013 2014

Dev

elop

men

t Cos

t ($/

Mcf

e)

EUR

/1,0

00' L

ater

al (B

cfe)

EUR vs. Development Cost per Unit

EUR/1,000' Lateral (Bcfe) Development Cost ($/Mcfe) 30

OHIO UTICA WELL PERFORMANCE IMPROVEMENTS Increasing recoveries and efficiencies through longer laterals, shorter stage lengths and faster drilling Lower service costs and efficiencies, and focus on liquids-rich locations, driving development cost reductions in 2015

1. 2015 reflects Antero guidance per 1/20/2015 press release.2. Based on 2015 data as of 11/27/2015.

6,431

8,021 9,000

11

41

50

0

10

20

30

40

50

60

0

2,000

4,000

6,000

8,000

10,000

2013 2014 2015E

Wel

ls o

n Fi

rst S

ales

Late

ral L

engt

h (F

eet)

Increasing Lateral Lengths

Average Lateral Length Wells on First Sales

(1)

289

183 175

26

47 51

-

10

20

30

40

50

60

-

50

100

150

200

250

300

350

2013 2014 2015E

Ave

rage

Fra

c St

ages

per

Wel

l

Ave

rage

Sta

ge L

engt

h (F

eet)

Increasing Frac Stages per Well

Average Stage Length (Feet) Average Frac Stages per Well

(1)

32 29 31

14,643 16,321 17,227

-

3,000

6,000

9,000

12,000

15,000

18,000

0

10

20

30

40

2013 2014 2015 YTD Tota

l Mea

sure

d D

epth

(Fee

t)

Spud

-to-R

ig R

elea

se D

ays

Increasing Drilling Efficiency

Spud-to-RR Days Total Measured Depth (Feet)

(2)

LARGE UTICA SHALE DRY GAS POSITION

31

Antero has completed its first dry gas Utica well – a 6,619’ lateral in Tyler County, WV

Antero has 229,000 net acres of exposure to Utica dry gas play in OH, WV and PA

Other operators have reported strong Utica Shale dry gas results including the following wells:

ChesapeakeHubbard BRK #3H

3,550’ LateralIP 11.1 MMcf/d

HessPorterfield 1H-17


GulfportIrons #1-4H5,714’ Lateral

IP 30.3 MMcf/d

EclipseTippens #6H5,858’ Lateral

IP 23.2 MMcf/d

Magnum HunterStalder #3UH5,050’ Lateral

IP 32.5 MMcf/d

AnteroUtica Well Completing

Well Operator24-hr IP(MMcf/d)

LateralLength

(Ft)

24-hr IP/1,000’Lateral

(MMcf/d)

Scotts Run EQT 72.9 3,221 22.633

Gaut 4IH CNX 61.0 5,840 11.131

CSC #11H RRC 59.0 5,420 10.886

Stewart-Win 1300U MHR 46.5 5,289 8.792

Bigfoot 9H RICE 41.7 6,957 5.994

Blank U-7H GST 36.8 6,617 5.561

Stalder #3UH MHR 32.5 5,050 6.436

Irons #1-4H GPOR 30.3 5,714 5.303

Pribble 6HU SGY 30.0 3,605 8.322

Simms U-5H GST 29.4 4,447 6.611

Conner 6H CVX 25.0 6,451 3.875

Messenger 3H SWN 25.0 5,889 4.245

Tippens #6H ECR 23.2 5,858 3.960

Porterfield 1H-17 HESS 17.2 5,000 3.440

1. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held in OH, WV and PA.2. Stewart-Winland well is most proximate Utica test to Antero’s Tyler County, WV well which is currently being completed.

Magnum HunterStewart Winland 1300U


RangeClaysville SC #11H


ChevronConner 6H

6,451’ LateralIP 25.0 MMcf/dGastar

Simms U-5H4,447’ Lateral

IP 29.4 MMcf/d

Utica Shale Dry Gas Acreage in OH/WV/PA(1)

RiceBigfoot 9H


AR Utica Shale Dry GasWV/PA

Net Resource12.5 to 16 Tcf

1,889 Gross Locations188,000 Net Acres

AR Utica Shale Dry GasOhio

3P Reserves2.4 Tcf

289 Gross Locations41,000 Net Acres

AR Utica Shale Dry GasTotal OH/WV/PA

Net Resource14.9 to 18.4 Tcf

2,178 Gross Locations229,000 Net Acres

Stone EnergyPribble 6HU


SouthwesternMessenger 3H5,889’ Lateral

IP 25.0 MMcf/d

RiceBlue Thunder

10H, 12H≈9,000’ Lateral

GastarBlake U-7H


EQTScotts Run


CNXGaut 4IH


(2)

ANTERO’S FIRST UTICA DRY GAS WELL

32

Antero recently drilled and completed its first dry gas Utica well in Tyler County, WV (Rymer 4HD)− 11,409 Total Vertical Depth (TVD)− 6,619’ lateral length− 100% working interest

Dry gas fairway extends from the Antero Utica acreage in eastern Ohio to the Antero Marcellus play acreage in northern West Virginia

188,000 net acres in West Virginia and Pennsylvania with net resource of 12.5 to 16 Tcf as of 9/30/2015 (not included in 40.7 Tcfe of net 3P reserves)− 1,889 locations underlying current Marcellus Shale leasehold in

West Virginia and Pennsylvania

41,000 net acres in Ohio with net 3P reserves of 2.4 Tcf as of 12/31/2014− 289 locations in Ohio

In total, Antero has 229,000 net acres and 2,178 potential locations in the Point Pleasant high pressure, high porosity dry gas fairway in OH, WV and PA− 10,000’ to 14,500’ TVD−Density log porosity values average > 8.5% − 120’ to 130’ total thickness− 25 MMcf/d to 73 MMcf/d industry 24-hr IP flow rates− 1000 to 1040 BTU expected

NOTE: Wellbore diagram for illustrative purposes only.

Targeted Pay Zone

IP / 1,000’ Lateral (MMcf/d)

5.0 – 10.0

10.0 – 15.0

15.0 – 25.0

GulfportIrons #1-4H

5,714’ LateralIP/1,000’: 5.3 MMcf/d

RangeClaysville SC #11H

5,420’ LateralIP/1,000’: 10.9 MMcf/d

CNXGaut 4IH

5,840’ LateralIP/1,000’: 10.4 MMcf/d

EQTScotts Run

3,221’ LateralIP/1,000’: 22.6 MMcf/d

GastarBlake U-7H


GastarSims U-5H


Stone EnergyPribble 6HU


Magnum HunterStalder #3UH5,050’ Lateral

IP/1,000’: 6.4 MMcf/d

Magnum HunterStewart Winland 1300U


AnteroUtica Well Completed

Rymer 4HD

Utica Dry Gas Fairway

-

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

4,500,000

5,000,000

5,500,000

FIRM TRANSPORTATION AND FIRM SALES PORTFOLIO

33

MMBtu/d

Columbia7/26/2009 – 9/30/2025

Firm Sales #110/1/2011– 10/31/2019

Firm Sales #210/1/2011 – 11/30/2015

Firm Sales #31/1/2013 – 5/31/2022

Momentum III9/1/2012 – 12/31/2023

EQT8/1/2012 – 6/30/2025

REX/MGT/ANR7/1/2014 – 12/31/2034

Tennessee11/1/2015– 9/30/2030

(Stonewall/WB) Mid-Atlantic/NYMEX

(Stonewall/TGP) Gulf Coast

(TCO) Appalachia or Gulf Coast

AppalachiaAppalachia

ANR3/1/2015– 2/28/2045

(REX/ANR/NGPL/MGT) Midwest

Local Distribution11/1/2015 – 9/30/2037

(ANR/Rover) Gulf Coast

Antero Transportation Portfolio

1,280 BBtu/d

790 BBtu/d

375 BBtu/d

250 BBtu/d

800 BBtu/d

600 BBtu/d

630 BBtu/d

40 BBtu/d

Gross gas production would fill Antero’s market leading firm transportation / sales portfolio by 2019 (excluding unfavorable

Appalachia based firm transport) (1)

Gross Gas Production (Actuals) Illustrative Gross Gas Production (25% Annual Growth CAGR Assumed) (1)

1. Assumes midpoint of preliminary production growth target of 25% to 30% in 2016 and targeted 25% annual production growth CAGR through 2020.

Keys to Execution

Local Presence

Antero has more than 3,500 employees and contract personnel working full-time for Antero in West Virginia. 79% of these personnel are West Virginia residents.

District office in Marietta, OH District office in Bridgeport, WV 227 (48%) of Antero’s 473 employees are located in West Virginia and Ohio

Safety & Environmental

Five company safety representatives and 57 safety consultants cover all material field operations 24/7 including drilling, completion, construction and pipelining

37 person environmental staff plus outside consultants monitor all operations and perform baseline water well testing

Central Fresh Water System & Water Recycling

Numerous sources of water – built central water system to source fresh water for completions

Antero recycled over 74% of its flowback and produced water through 2014 Building state of the art wastewater treatment facility in WV (60,000 Bbl/d)

Natural Gas Vehicles (NGV)

Antero supported the first natural gas fueling station in West Virginia Antero has 30 NGV trucks and plans to continue to convert its truck fleet to NGV

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

Natural Gas Powered Drilling Rigs & Frac Equipment

8 of Antero’s contracted drilling rigs are currently running on natural gas First natural gas powered clean fleet frac crew began operations summer 2014

Green Completion Units All Antero well completions use green completion units for completion flowback,

essentially eliminating methane emissions (full compliance with EPA 2015requirements)

LEED Gold Headquarters Building Corporate headquarters in Denver, Colorado LEED Gold Certified

HEALTH, SAFETY, ENVIRONMENT & COMMUNITYAntero Core Values: Protect Our People, Communities And The Environment

Strong West Virginia Presence 79% of all Antero Marcellus

employees and contract workers are West Virginia residents

Antero named Business of the Year for 2013 in Harrison County, West Virginia “For outstanding corporate citizenship and community involvement”

Antero representatives recently participated in a ribbon cutting with the Governor of West Virginia for the grand opening of the first natural gas fueling station in the state; Antero supported the station with volume commitments for its NGV truck fleet

34

CLEAN FLEET & CNG TECHNOLOGY LEADER

● Antero has contracted for two clean completion fleets to enhance the economics of its completion operations and reduce the environmental impact

● Replaces diesel engines (for pressure pumping) with electric motors powered by natural gas-fired electric generators

● A clean fleet allows Antero to fuel part of its completion operations from field gas instead of more expensive diesel fuel. Benefits of using a clean fleet include:− Reduce fuel costs by up to 80%

representing cost savings of up to $40,000/day

− Reduces NOx and CO emissions by 99%− Eliminates 25 diesel truckloads from the

roads for an average well completion− Reduces silica dust to levels 90% below

OSHA permissible exposure limits resulting in a safer and cleaner work environment

− Significantly reduces noise pollution from a well site

− Is the most environmentally responsible completion solution in the oil and gas industry

• Additionally, Antero utilizes compressed natural gas (CNG) to fuel its truck fleet in Appalachia− Antero supported the first natural gas fueling

station in West Virginia− Antero has 30 NGV trucks and plans to

continue to convert its truck fleet to NGV

35

36

Antero Midstream (NYSE: AM)Asset Overview

Regional Gas Pipelines

Miles Capacity In-Service

Stonewall Gathering Pipeline(2)

50 1.4 Bcf/d Yes

1. Acquired by AM from AR for a $1.05 billion upfront payment and a $125 million earn out in each of 2019 and 2020. 2. AM holds option to purchase 15% of Stonewall pipeline at cost plus cost of carry.

EndUsers

EndUsers

Gas Processing

Y-Grade Pipeline

Long-Haul Interstate

Pipeline

InterConnect

NGL Product Pipelines

Fractionation

Compression

Low Pressure Gathering

Well Pad

Terminalsand

Storage

(Miles) YE 2014 YE 2015E

Marcellus 91 108

Utica 45 56

Total 136 164

AM has option to participate in processing, fractionation,

terminaling and storage projects offered to AR


Marcellus 62 76

Utica 35 36

Total 97 112

(MMcf/d) YE 2014 YE 2015E

Marcellus 375 800

Utica 0 120

Total 375 920

AM Owned Assets

Condensate GatheringStabilization


Utica 16 19

EndUsers

AM Option Assets

(Ethane, Propane, Butane, etc.)

AM’S FULL VALUE CHAIN BUSINESS MODEL

Water Drop Down

37

1. Represents inception to date actuals as of 12/31/2014 and 2015 midpoint guidance.2. Includes water drop down and $15.0 million of maintenance capex at 2015 midpoint guidance.

38

UticaShale

MarcellusShale

Projected Midstream Infrastructure(1)

Marcellus Shale

Utica Shale Total

YE 2014 Cumulative Gathering/ Compression Capex ($MM) $836 $345 $1,181

Gathering Pipelines(Miles) 153 80 233

Compression Capacity(MMcf/d) 375 - 375

Condensate Gathering Pipelines (Miles) - 16 16

2015E Capex Budget ($MM)(2) $256 $182 $438Gathering Pipelines

(Miles) 31 12 43

Compression Capacity(MMcf/d) 425 120 545

Condensate Gathering Pipelines (Miles) - 3 3

Midstream Assets

ANTERO MIDSTREAM ASSET OVERVIEW

• Gathering and compression assets in core of rapidly growing Marcellus and Utica Shale plays

– Acreage dedication of ~434,000 net leasehold acres for gathering and compression services

– Additional stacked pay potential with dedication on ~147,000 acres of Utica deep rights underlying the Marcellus in WV and PA

– 100% fixed fee long term contracts

• AR owns 67% of AM units (NYSE: AM)

ANTERO INTEGRATED WATER BUSINESS

39

Marcellus Fresh Water System(2)

• Provides fresh water to support Marcellus well completions • Year-round water supply sources: Ohio River and local rivers• Ozone Water treatment facility expected in-service January 2016• Significant asset growth in 2015 as summarized below:

Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.1. Represents inception to date actuals as of 9/30/2015 and 2015 guidance.2. All Antero water withdrawal sites are fully permitted under long-term state regulatory permits both in WV and OH. 3. Assumes fee of $3.685 per barrel subject to annual inflation and 250,000 barrels of water per well that utilize the fresh water delivery system based on 9,000 foot lateral. Operating margin excludes G&A.4. Assumes fee of $3.635 per barrel subject to annual inflation and 275,000 barrels of water per well that utilize the fresh water delivery system based on 9,000 foot lateral. Operating margin excludes G&A.

Utica Fresh Water System(2)

• Provides fresh water to support Utica well completions • Year-round water supply sources: local reservoirs and rivers• Significant asset growth in 2015 as summarized below:

Marcellus Water System YE 2014 YE 2015E

Water Pipeline (Miles) 177 226

Fresh Water Storage Impoundments 22 24

Cash Operating Margin per Well ($)(3) $700K -$750K

Utica Water System YE 2014 YE 2015E

Water Pipeline (Miles) 61 90

Fresh Water Storage Impoundments 8 14

Cash Operating Margin per Well ($)(4) $775K -$825K

Projected Fresh Water Delivery Infrastructure(1)

Marcellus Shale

Utica Shale Total

YE 2015E Cumulative Water System Capex ($MM) $340 $113 $453Water Pipelines (Miles) 226 90 316Water Storage Facilities 24 14 38

AM acquired AR’s integrated water business for $1.05 billion plus earn out payments of $125 million at year-end in each of 2019 and 2020− The acquired business includes Antero’s Marcellus and Utica freshwater delivery business, the fully-contracted future advanced wastewater

treatment complex and all fluid handling and disposal services for Antero

Antero advanced wastewater treatment facility to be constructed – connects to Antero

freshwater delivery system

010,00020,00030,00040,00050,00060,00070,00080,000

Antero Clearwater Advanced Wastewater Treatment Capacity (Bbl/d)

Produced/Flowback Volumes (Bbl/d)

ADVANCED WASTEWATER TREATMENT

Illustrative Produced & Flowback Water VolumesAdvanced Wastewater Treatment

Antero Produced Water Services and Freshwater Delivery Business

Antero AdvancedWastewater Treatment

3rd Party Recyclingand Well Disposal

(Bbl/d)

Advanced Wastewater Treatment ComplexEstimated capital expenditures ($ million)(1) ~$275Standalone EBITDA at 100% utilization(2) ~$55 – $65Implied investment to standalone EBITDA build-out multiple ~4x – 5xEstimated per well savings to Antero Resources ~$150,000Estimated in-service date Late 2017Operating capacity (Bbl/d) 60,000Operating agreement

• Antero has contracted with Veolia to integrate an advanced wastewater treatment complex into its water business

• Veolia will build and operate, and Antero will own largest advanced wastewater treatment complex in Appalachia− Will treat and recycle AR produced and flowback water− Creates additional year-round water source for completions− Will have capacity for third party business over first two years

1. Includes capital to construct pipeline to connect facility to freshwater delivery system. Includes $10 million that AR agreed to fund in the drop down transaction. 2. Standalone EBITDA projection assumes inter-company fixed fee for recycling of $4.00 per barrel and 60,000 barrels per day of capacity. Does not include potential sales of marketable byproducts.

20 Years, Extendable

40Integrated Water Business

Antero Advanced Wastewater Treatment

Freshwater delivery system

Flowback and produced

Water

Well Pad

Well Pad

CompletionOperations

Producing

Freshwater

Salt

Calcium Chloride

Marketable byproduct

Marketable byproduct used in oil and gas operations

Freshwater delivery system

$1$5 $7 $8 $11

$19

$28

$36$41

$55

$0

$10

$20

$30

$40

$50

$60

26 31 40 36 41 116

222

358

454 435

0

100

200

300

400

500

600

700 Marcellus

10 38 80 126 266

531

908

1,134 1,197 1,216

0

200

400

600

800

1,000

1,200

1,400

1,600 Utica Marcellus

108 216

281 331 386 531

738

935 965 1,038

0

200

400

600

800

1,000

1,200

1,400 Utica Marcellus

Low Pressure Gathering (MMcf/d)

Compression (MMcf/d)

High Pressure Gathering (MMcf/d)

EBITDA ($MM)(1)

41

$185

HIGH GROWTH MIDSTREAM THROUGHPUT

1. 2015E EBITDA guidance updated per 10/13/2015 Partnership press release based on 10/1/2015 effective date for water drop down. Y-O-Y growth based on 3Q’14 to 3Q’15.

0.0x

1.0x

2.0x

3.0x

4.0x

5.0x

6.0x

Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8

Tota

l Deb

t / L

QA

EB

ITD

A

• $1.5 billion revolver in place to fund future growth capital (5x Debt/EBITDA Cap)

• Liquidity of $993 million at 9/30/2015

• Sponsor (NYSE: AR) has Ba2/BB corporate ratings

AM Liquidity (9/30/2015)

AM Peer Leverage Comparison(1)

($ in millions)

Revolver Capacity $1,500

Less: Borrowings 525

Plus: Cash 18

Liquidity $993

1. As of 9/30/2015. Peers include TEP, EQM, MWE, WES, RMP, SHLX, DM, and CNNX.2. AM pro forma for water drop down; LQA EBITDA for water based on 2016E midpoint of 8.5x – 9.0x purchase price multiple announced.

Financial Flexibility

SIGNIFICANT FINANCIAL FLEXIBILITY

42

(2)

43

APPENDIX

43

($ in millions) 9/30/2015 Cash $27

Senior Secured Revolving Credit Facility 500Midstream Bank Credit Facility 5256.00% Senior Notes Due 2020 5255.375% Senior Notes Due 2021 1,0005.125% Senior Notes Due 2022 1,1005.625% Senior Notes Due 2023 750Net Unamortized Premium 7Total Debt $4,407Net Debt $4,380

Financial & Operating StatisticsLTM EBITDAX(1) $1,246LTM Interest Expense(2) $219Proved Reserves (Bcfe) (12/31/2014) 12,683

Proved Developed Reserves (Bcfe) (12/31/2014) 3,803

Credit Statistics

Net Debt / LTM EBITDAX 3.5xNet Debt / Net Book Capitalization 38%Net Debt / Proved Developed Reserves ($/Mcfe) $1.15Net Debt / Proved Reserves ($/Mcfe) $0.35

LiquidityCredit Facility Commitments(3) $5,500Less: Borrowings (1,025)Less: Letters of Credit (535)Plus: Cash 27

Liquidity (Credit Facility + Cash) $3,968

ANTERO CAPITALIZATION – CONSOLIDATED

1. LTM and 9/30/2015 EBITDAX reconciliation provided on page 65.2. LTM interest expense adjusted for all capital market transactions since 1/1/2014.3. AR lender commitments under the facility increased to $4.0 billion from $3.0 billion on 2/17/2015; borrowing base capacity increased to $4.5 billion from $4.0 billion on 10/26/2015. AM credit facility

increased to $1.5 billion concurrent with water drop down on 9/23/2015.44

ANTERO RESOURCES – UPDATED 2015 GUIDANCE

Key Variable 2015 GuidanceNet Daily Production (MMcfe/d) 1,400

Net Residue Natural Gas Production (MMcf/d) 1,175

Net Liquids Production (Bbl/d) 33,000

Net Oil Production (Bbl/d) 4,000

Natural Gas Realized Price Differential to NYMEX Henry Hub Before Hedging ($/Mcf) $(0.20) - $(0.30)

Oil Realized Price Differential to NYMEX WTI Before Hedging ($/Bbl) $(12.00) - $(14.00)

NGL Realized Price (% of WTI) 30% - 35%

Cash Production Expense ($/Mcfe)(1) $1.50 - $1.60

Marketing Expense, Net of Marketing Revenue ($/Mcfe) $0.20 - $0.30

G&A Expense ($/Mcfe) $0.23 - $0.27

Net Income Attributable to Non-Controlling Interest ($MM) $23 - $27

Operated Wells Completed 130

Average Operated Drilling Rigs 14

Capital Expenditures ($MM)

Drilling & Completion $1,600

Water Infrastructure $50

Land $150

Total Capital Expenditures ($MM) $1,800

1. Includes lease operating expenses, gathering, compression and transportation expenses and production taxes. Excludes net marketing expense.

Key Operating & Financial Assumptions

45

ANTERO MIDSTREAM – 2015 GUIDANCE

Key Variable Initial Guidance(1) Updated Guidance(2)

Adjusted EBITDA ($MM) $150 - $160 $180 - $190

Distributable Cash Flow ($MM) $135 - $145 $160 - $170

Year-over-Year Distribution Growth(3) 28% - 30% 28% - 30%

Low Pressure Pipelines Added (Miles) 44 27

High Pressure Pipelines Added (Miles) 20 15

Compression Capacity Added (MMcf/d) 545 545

Capital Expenditures ($MM)

Low Pressure Gathering $165 - $170 $90 - $95

High Pressure Gathering $85 - $90 $70 - $75

Compression $160 - $165 $165 - $170

Condensate Gathering $5 - $10 $5

Water Infrastructure(4) - $80 - $90

Maintenance Capital $10 - $15 $15

Total Capital Expenditures ($MM) $425 - $450 $425 - $4501. Financial guidance per Partnership press release dated 1/20/2015.2. Updated financial guidance per Partnership press release dated 10/13/2015. 3. Reflects the expected distribution growth associated with the fourth quarter 2015 over the fourth quarter 2014.4. Includes fresh water delivery system plus waste water treatment capital expenditures.

Key Operating & Financial Assumptions

46

$2,477$197

$841

Drilling & Completion Water Infrastructure Land

65%

35%

Marcellus Utica

2015 CAPITAL BUDGET

By Area

47

$3.5 Billion - 2014By Segment ($MM)

$1,600

$50 $150

Drilling & Completion Water Infrastructure Land

59%41%

Marcellus Utica

By Area

$1.8 Billion – 2015By Segment ($MM)

Antero’s 2015 capital budget is $1.8 billion, a 49% decrease from 2014 capital expenditures of $3.5 billion

49%

177 Completions 130 Completions

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

2015 2015 2016 2016 2017

Gas

Pric

e $/

MM

Btu

Completion Deferral Impact on Realized Gas Price

TETCO CGTLA

TETCO Cal 2015:$1.88/MMBtu

CGTLA Cal 2016: $3.27/MMBtu

BTAX IRR:57%

48

Plan to defer 50 Marcellus well completions into 2016 to achieve higher gas price realizations− Stonewall gathering pipeline placed on line 12/1/2015 connects incremental Marcellus production to CGTLA (Gulf Coast) and

TCO pricing− Results in estimated pre-tax IRR of 57% vs. 39% from 2015 TETCO pricing in first year, excluding sunk drilling costs

COMPLETION DEFERRALS – OPTIMIZING PRICING

0

50

100

150

200

250

300

350

400

450

500

Jan-16 Mar-16 May-16

Gro

ss W

ellh

ead

Prod

uctio

n (M

Mcf

/d)

Completion Deferral Impact on 2016 Production

Production From 50 Deferred

Completions

+$1.39/MMBtu Pickupin Price =

18% BTAX IRR Increase

BTAX IRR:39%

12.7 TcfeProved

21.8 TcfeProbable

6.3 TcfePossible

Proved

Probable

Possible

40.7 Tcfe 3P

85% 2P Reserves

OUTSTANDING RESERVE GROWTH

1. 2012, 2013 and 2014 reserves assuming ethane rejection. 2014 SEC prices were $4.07/MMBtu for natural gas and $81.48/Bbl for oil on a weighted average Appalachian index basis.49

3P RESERVES BY VOLUME – 2014(1)3P RESERVE GROWTH(1)

25.0 28.4

5.87.64.24.6

05

1015202530354045

2013 2014

(Tcfe)

Marcellus Utica Upper Devonian

Key Drivers

4.2

NET PROVED RESERVES (Tcfe)(1) 2014 RESERVE ADDITIONS

35.040.7

• 93,000 net acres added in 2014

• SSL results

• Utica results

• 3P reserves increased 16% to 40.7 Tcfe at 12/31/14 with a PV-10 of $22.8 billion

− Estimated 10% well cost reduction since YE 2014 results in $2.0 billion increase in 3P PV-10

• All-in finding and development cost of $0.61/Mcfe for 2014 (includes land)

• “Bottoms-up” development cost of $0.98/Mcfe for 2014

• Only 66% of 3P Marcellus locations booked as SSL (1.7 Bcf/1,000’ type curve) at 12/31/2014

• No Utica Shale WV/PA dry gas reserves booked –estimated net resource of 11.1 Tcf

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

2010 2011 2012 2013 2014

Marcellus Utica

0.7

2.84.3

7.6

12.7

(Tcfe)

CONSIDERABLE RESERVE BASE WITH ETHANE OPTIONALITY 35 year proved reserve life based on 2014 production annualized Reserve base provides significant exposure to liquids-rich projects

– 3P reserves of over 2.5 BBbl of NGLs and condensate in ethane recovery mode; 32% 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)

50

Marcellus – 28.4 Tcfe

Utica – 7.6 Tcfe

Upper Devonian – 4.6 Tcfe

40.7Tcfe

Gas – 34.5 Tcf

Oil – 102 MMBbls

NGLs – 924 MMBbls

Marcellus – 33.7 Tcfe

Utica – 8.6 Tcfe

Upper Devonian – 5.1 Tcfe

47.4Tcfe

Gas – 32.0 Tcf

Oil – 102 MMBbls

NGLs – 2,459 MMBbls

15%Liquids

32%Liquids

664

1,010

628

88963%

47%

24% 28%34%

22%9% 11% 0

2004006008001,0001,200

0%

20%

40%

60%

80%

Highly-Rich Gas/Condensate


Tota

l 3P

Loca

tions

RO

RTotal 3P LocationsROR @ 12/31/2015 Strip Pricing - After HedgesROR @ 12/31/2015 Strip Pricing - Before Hedges

MARCELLUS SINGLE WELL ECONOMICS – IN ETHANE REJECTION

51

DRY GAS LOCATIONS RICH GAS LOCATIONS

HIGHLY RICH GAS

LOCATIONS

Assumptions Natural Gas – 12/31/2015 strip Oil – 12/31/2015 strip NGLs – 37% of Oil Price 2016; 50% of

Oil Price 2017+

NYMEX($/MMBtu)

WTI($/Bbl)

C3+ NGL(2)

($/Bbl)

2016 $2.50 $41 $15

2017 $2.79 $46 $23

2018 $2.91 $49 $25

2019 $3.03 $52 $26

2020 $3.18 $54 $27

2021-25 $3.31-$3.88 $55-$56 $27-$28

Marcellus Well Economics and Total Gross Locations(1)

ClassificationHighly-Rich Gas/

CondensateHighly-Rich

Gas Rich Gas Dry GasModeled BTU 1313 1250 1150 1050EUR (Bcfe): 20.8 18.8 16.8 15.3EUR (MMBoe): 3.5 3.1 2.8 2.6% Liquids: 33% 24% 12% 0%Lateral Length (ft): 9,000 9,000 9,000 9,000Well Cost ($MM): $9.1 $9.1 $9.1 $9.1Bcfe/1,000’: 2.3 2.1 1.9 1.7Net F&D ($/Mcfe): $0.44 $0.48 $0.54 $0.59Direct Operating Expense ($/well/month): $1,498 $1,498 $1,498 $1,498Direct Operating Expense ($/Mcf): $0.92 $0.92 $1.17 $0.71Transportation Expense ($/Mcf): $0.28 $0.28 $0.28 $0.28

Pre-Tax NPV10 ($MM): $8.9 $5.1 ($0.7) $0.2Pre-Tax ROR: 34% 22% 9% 11%Payout (Years): 2.0 2.8 6.5 5.5

Gross 3P Locations(3): 664 1,010 628 8891. 12/31/2015 pre-tax well economics based on a 9,000’ lateral, 12/31/2015 natural gas and WTI strip pricing for 2016-2025, flat thereafter, NGLs at 37.5% of WTI for 2016 and 50% of WTI thereafter,

and applicable firm transportation and operating costs including 50% of Antero Midstream fees. Well cost estimates, which include $1.2 million for road, pad and production facilities, assume Antero will begin to realize lower well costs in 2016 as the company utilizes incremental completion crews for deferred completions beginning at year end 2015 and as existing drilling rig contracts begin to roll off during 2016.

2. Pricing for a 1225 BTU y-grade ethane rejection barrel. NGLs at 37.5% of WTI for 2016 and 50% of WTI for 2017 and thereafter. NGL prices are forecast to increase in 2017 relative to WTI due to projected in-service date of Mariner East 2 project allowing for a significant increase in AR NGL exports via ship.

3. Undeveloped well locations as of 12/31/2014.

2016Drilling

Plan

248

13994

254 289

16%

57%

83%71%

80%

10%

27% 29%23% 26%

050100150200250300

0%

20%

40%

60%

80%

100%

Condensate Highly-Rich Gas/Condensate


Tota

l 3P

Loca

tions

RO

R

Total 3P LocationsROR @ 12/31/2015 Strip Pricing - After HedgesROR @ 12/31/2015 Strip Pricing - Before Hedges

UTICA SINGLE WELL ECONOMICS – IN ETHANE REJECTION

52

DRY GAS LOCATIONS RICH GAS LOCATIONS

HIGHLY RICH GAS

LOCATIONS

Utica Well Economics and Gross Locations(1)

Classification CondensateHighly-Rich Gas/

CondensateHighly-Rich

Gas Rich Gas Dry GasModeled BTU 1275 1235 1215 1175 1050EUR (Bcfe): 9.4 17.0 25.3 23.8 21.4EUR (MMBoe): 1.6 2.8 4.2 4.0 3.6% Liquids 35% 26% 21% 14% 0%Lateral Length (ft): 9,000 9,000 9,000 9,000 9,000Well Cost ($MM): $10.2 $10.2 $10.2 $10.2 $10.2Bcfe/1,000’: 1.0 1.9 2.8 2.7 2.4Net F&D ($/Mcfe): $1.08 $0.60 $0.40 $0.43 $0.48Fixed Operating Expense ($/well/month): $2,788 $2,788 $2,788 $2,788 $1,498Direct Operating Expense ($/Mcf): $0.99 $0.99 $0.99 $0.99 $0.50Direct Operating Expense ($/Bbl): $2.73 $2.73 $2.73 - -Transportation Expense ($/Mcf): $0.55 $0.55 $0.55 $0.55 $0.55

Pre-Tax NPV10 ($MM): $0.0 $5.8 $7.6 $5.6 $6.4Pre-Tax ROR: 10% 27% 29% 23% 26%Payout (Years): 7.8 3.1 2.9 3.7 3.2

Gross 3P Locations(3): 248 139 94 254 2891. 12/31/2015 pre-tax well economics based on a 9,000’ lateral, 12/31/2015 natural gas and WTI strip pricing for 2016-2025, flat thereafter, NGLs at 37.5% of WTI for 2016 and 50% of WTI thereafter,

and applicable firm transportation and operating costs including 50% of Antero Midstream fees. Well cost estimates, which include $1.2 million for road, pad and production facilities, assume Antero will begin to realize lower well costs in 2016 as the company utilizes incremental completion crews for deferred completions beginning at year end 2015 and as existing drilling rig contracts begin to roll off during 2016.

2. Pricing for a 1225 BTU y-grade ethane rejection barrel. NGLs at 37.5% of WTI for 2016 and 50% of WTI for 2017 and thereafter. NGL prices are forecast to increase in 2017 relative to WTI due to projected in-service date of Mariner East 2 project allowing for a significant increase in AR NGL exports via ship.

3. Undeveloped well locations as of 12/31/2014. 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content.

2016Drilling

Plan

Assumptions Natural Gas – 12/31/2015 strip Oil – 12/31/2015 strip NGLs – 37% of Oil Price 2016; 50% of

Oil Price 2017+NYMEX

($/MMBtu)WTI

($/Bbl)C3+ NGL(2)

($/Bbl)

2016 $2.50 $41 $15

2017 $2.79 $46 $23

2018 $2.91 $49 $25

2019 $3.03 $52 $26

2020 $3.18 $54 $27

2021-25 $3.31-$3.88 $55-$56 $27-$28

$4

$8

$5$25 $34 $29 $28 $26 $12 $16 $17 $28 $29 $19 $25

$43

$80 $83$59 $49 $48

$14

$47 $54

$1

$1

$58$78

$185$196$206

($2.00)

($1.00)

$0.00

$1.00

$2.00

$3.00

$4.00

($20.0)

$30.0

$80.0

$130.0

$180.0

$230.0

Quarterly Realized Gains/(Losses)1Q '08 - 4Q '15

1,793 2,073 2,015 1,960 1,288 480 10

$3.94$3.57

$3.88 $3.89 $3.73 $3.50

$3.30$2.50 $2.79 $2.91 $3.03 $3.18 $3.31

$3.46

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

-

500

1,000

1,500

2,000

2,500

2016 2017 2018 2019 2020 2021 2022

53

Average Index Hedge Price(1)Hedged Volume Current NYMEX Strip(2)

COMMODITY HEDGE POSITION

~$3.1 billion mark-to-market unrealized gain based on 12/31/2015 prices 3.5 Tcfe hedged from January 1, 2016 through year-end 2022

$1,009 MM $572 MM $711 MM $567 MM $232 MM $26 MM

Mark-to-Market Value(2)

LARGEST GAS HEDGE POSITION IN U.S. E&P

~ 100% of 2016 Target Hedged

531. Weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio; excludes impact of TCO basis hedges. 3,000 Bbl/d of oil and 23,000 Bbl/d of propane hedged for 2015. 2. As of 12/31/2015.

Hedging is a key component of Antero’s business model due to the large, repeatable drilling inventory Antero has realized $1.7 billion of gains on commodity hedges since 2008

– Gains realized in 30 of last 32 quarters$MM

$/Mcfe

$0 MM

$0.14 $0.17 $0.23$0.33$0.11 $0.11

$0.12

$0.13

$0.00

$0.10

$0.20

$0.30

$0.40

$0.50

$0.60

$0.70

2013A 2014A 2015E 2016E

($/M

MB

tu)

Wtd. Avg. FT Demand ($/MMBtu) Wtd. Avg. FT Commodity/Fuel ($/MMBtu)

All-in Firm Transportation Costs(1)

FIRM TRANSPORTATION REDUCES APPALACHIAN BASIS EXPOSURE

Appalachia 49%Gulf Coast

51%

2013 FirmTransportation(1)(2)

2013 Firm Transportation – 647 MMcf/dAverage All-in FT Cost $0.25/MMBtu

2016 Firm Transportation – 3.5 Bcf/dAverage All-in FT Cost $0.46/MMBtu

+ $0.18/MMBtu

Antero’s firm transportation (FT) portfolio increases visibility on production growth and increases exposure to Gulf Coast and Midwest pricing, with little incremental cost per Mcf

Reduces weighted average basis by $0.35 per MMBtu compared to 2014 basis – while significantly reducing Appalachian basis exposure

Utilized portion included in cash production

expense(fixed cost)

1. Assumes full utilization of firm transportation capacity. 2. Represents accessible firm transportation and sales agreements.3. Based on current strip pricing as at 12/3012015.

Included in cash production expense

(variable cost)$0.25 $0.28 $0.35

$0.46

2016 Basis(3)

TCO – $(0.18)/MMBtu DOM S – $(0.94)/MMBtu

2016 Basis(3)

Chicago – $0.02/MMBtu

2016 Basis(3)

CGTLA – $(0.06)/MMBtu

54

Appalachia35%

Midwest20%

Gulf Coast45%

$525

$1,000 $1,100

$750

$0

$200

$400

$600

$800

$1,000

$1,200

2015 2016 2017 2018 2019 2020 2021 2022 2023

($ in

Mill

ions

)

$1,500

$993

($525)

$0 $18

$0

$250

$500

$750

$1,000

$1,250

$1,500

Credit Facility9/30/2015

Bank Debt9/30/2015

L/Cs Outstanding9/30/2015

Cash9/30/2015

Liquidity 9/30/2015

55

STRONG FINANCIAL LIQUIDITY AND DEBT TERM STRUCTURE

55

$4,000$2,975

($500)($535) $10

$0

$1,000

$2,000

$3,000

$4,000

Credit Facility9/30/2015

Bank Debt9/30/2015

L/Cs Outstanding9/30/2015

Cash9/30/2015

Liquidity9/30/2015

AR LIQUIDITY POSITION ($MM) AM LIQUIDITY POSITION ($MM)

Over $3.9 billion of combined AR and AM financial liquidity as of 9/30/2015 No leverage covenant in AR bank facility, only interest coverage and working capital covenants

AR Credit Facility AR Senior Notes

DEBT MATURITY PROFILE

Recent credit facility increases and equity offerings have allowed Antero to reduce its cost of debt to 4.4% and significantly enhance liquidity while the average debt maturity is April 2021

AM Credit Facility

Moody's S&P

POSITIVE RATINGS MOMENTUMMoody’s / S&P Historical Corporate Credit Ratings

“We could raise the ratings due to our assessment of an improvement inthe company's financial profile. An improvement in the financial profilewould include maintaining FFO to debt of greater than 45% andnarrowing the amount that the company outspends its cash flows by.”

- S&P Credit Research, September 2014

"The upgrade reflects Moody's expectation that Antero will continue toreport strong production growth and increasing reserves despitechallenging market conditions and without a significant increase inleverage. Antero's low finding and development costs and significantcommodity hedge position should allow the company to continue toprosper despite today's low commodity price environment.“

- Moody’s Credit Research, February 2015

Corporate Credit Rating (Moody’s / S&P)

Ba3 / BB-

B1 / B+

B2 / B

B3 / B-

2/24/2011 10/21/2013 9/4/20145/31/13

Ba2 / BB

Ba1 / BB+

Caa1 / CCC+

(1)

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

Baa3 / BBB-

Moody’s Upgrade Rationale S&P Upgrade Criteria

56

3/31/2015

Ba2/BB

9/30/20159/1/2010

LNG Exports48%

Mexico/Canada Exports

18%

Power Generation

17%

Transportation1%

Industrial16%

20 BCF/D OF INCREMENTAL GAS DEMAND BY 2020 Significant demand growth expected for U.S.

natural gas

More than 65% of the 20 Bcf/d in incremental gas demand forecast by 2020 is expected to be generated from exports:− LNG: 9.5 Bcf/d (~48%)− Mexico/Canada: 3.5 Bcf/d (~18%)

Of the 9.5 Bcf/d of expected incremental demand from LNG export projects, 6.7 Bcf/d (or 70%) of the projects have secured the necessary DOE and FERC permits

57

Incremental Demand Growth Through 2020 by Category

Projected Incremental Natural Gas Demand Through 2020

Source: Simmons & Company International, “2015 US Natural Gas Outlook and Updated Long Term Demand Forecast,” September 2014.

Sherwood 7 2

5

9

13

17

20

0

4

8

12

16

20

2015 2016 2017 2018 2019 2020Mexico/Canada Exports Power GenerationTransportation PetrochemLNG Exports

9.5 Bcf/d of the 20 Bcf/d of incremental demand is expected to come from

LNG exports

(Bcf/d)

LNG

Exports

Power Gen

Petrochem

LNG Exports by Project(in Bcf/d)

2015 2016 2017 2018 2019 2020 TotalSabine Pass 1 - 0.6 - - - - Sabine Pass 2 - 0.6 - - - - Sabine Pass 3 - - 0.6 - - - Sabine Pass 4 - - 0.6 - - - Sabine Pass 5 - - - - 0.6 - 3.0 Cove Point 1 - - 0.4 - - - Cove Point 2 - - - 0.4 - - 0.8 Cameron 1 - - - 0.6 - - Cameron 2 - - - 0.6 - - Cameron 3 - - - - 0.6 - 1.8 Freeport 1 - - - 0.5 - - Freeport 2 - - - - 0.5 - Freeport 3 - - - - 0.5 - Freeport 4 - - - - - 0.4 2.1 Corpus Christi 1 - - - - 0.6 - Corpus Christi 2 - - - - - 0.6 1.2 Lake Charles 1 - - - - - 0.6 0.6

LNG Incremental Exports - 1.2 1.6 2.2 2.9 1.7LNG Cumulative Exports - 1.2 2.8 5.0 7.9 9.5

LNG EXPORTS BY PROJECT – EXPECTED START UP

Assuming 9.5 Bcf/d of LNG exports by 2020, the U.S. will be the world’s 3rd largest LNG exporter behind Qatar and Australia− 7.7 Bcf/d (81%) of the 9.5 Bcf/d of expected LNG

exports have secured US DOE non-FTA (Free Trade Agreement) permit approval

− 6.7 Bcf/d (four projects, 70%) have been awarded FERC construction permits

The first LNG export project, Sabine Pass LNG Train 1, is expected to commence operations in early 2016− Antero has committed to 200 MMcf/d on Sabine

Pass Trains 1-4

The second LNG export project, Cove Point LNG, is expected to commence operations in mid-2017− Antero has committed to 330 MMcf/d on Cove

Point 1 & 2

58

LNG Exports by Project Through 2020

Antero Supply Agreements for Portion of Capacity

Source: Simmons & Company International, “2015 US Natural Gas Outlook and Updated Long Term Demand Forecast,” September 2014. Note: Data updated for recent announcements subsequent to Simmons report.

Antero Supplied

2015 GLOBAL LPG DEMANDGlobal LPG demand is 8.5 MMBbl/d and growing

59

GLOBAL LPG DEMAND DRIVEN BYPETCHEM AND RES/COMMLargest end-use sectors for LPG are residential/commercial, which tends to grow with population and improvement in

living standards in the emerging markets− PIRA forecasting >1.0 MMBbl/d over next 5 years and >4.5 MMBbl/d of global LPG demand growth over next 20 years

601. PIRA NGL Study, September 2015.

MMBbl/d14.7

13.0

11.4

9.8

8.2

6.5

4.9

3.3

1.6

GLOBAL LPG TRADE DRIVEN BY U.S. SHALEThe U.S. is the largest single driver of the rapid expansion in LPG trade accounting for over 90% in trade growth


MMBbl/d5.2

4.6

3.9

3.3

2.6

2.0

1.3

0.7

United States

U.S. SHALE NGL EURS SUPPORT LPG TRADE GROWTH


• U.S. shale play NGL reserves are 50.8 billion barrels

• Eagle Ford, Marcellus, Utica, Bakken and Permian are the work horses of U.S. shale production growth

• Marcellus/Utica NGL resource estimate by PIRA is 9.7 billion barrels, in line with Antero estimate of ≈ 11.1 billion barrels

• The growth curve of each basin will ultimately be a function of downstream solutions and investment

(1)

(1)(1)

POSITIVE OUTLOOK FOR LONG-TERM ETHANE MARKETS AS WELL

U.S. Ethane Supply/Demand Balance Through 2020(1)

1. Source: Bentek, August 2015.2. Source: Citi research dated 7/15/2015.

U.S. Ethane Exports Through 2020(2)

U.S. ethane demand is projected to increase at an annual 3.5% CAGR through 2020, primarily based on an ≈8% CAGR for U.S. petrochemdemand and a 30% growth in exports primarily to Europe− The growth in shipping exports in 2016 and 2017 is driven by Enterprise Products’ 200 MBbl/d export facility on the Gulf Coast

-

0.5

1.0

1.5

2.0

2.5

2012 2013 2014 2015 2016 2017 2018 2019 2020

MM

Bb/

d

Petchem Exports Rejection Total Supply (Net Stock Change)

U.S. Seaborne Ethane Exports Through 2020(2)

-

50

100

150

200

250

300

350

2013 2014 2015 2016 2017 2018 2019 2020

MB

bl/d

Ship Pipeline

250

200

150

100

50

MB

bl/d

U.S. exports increase significantly into 2016

and 2017 as EPD’s Morgan Point Facility

comes in-service

U.S. Ethane Rejection by Region Through 2020(1)

Access to both Marcus Hook and the Gulf Coast is

critical to optimizing ethane

netbacks

Rejection declines significantly into 2018

Unlike LPG, 80% of ethane will be

consumed in the U.S.

Petrochem demand increases at ≈8% CAGR through 2020

-

100

200

300

400

500

600

2012 2013 2014 2015 2016 2017 2018 2019 2020

MB

bl/d

Williston PADD 4 PADD 1 (East Coast) PADD 2 PADD 3

No Northeast rejection after 2017

63

Northeast Ethane

Rejection

Exports

U.S. PetChem

Europe

Mariner East II

Shipping $0.25/Gal

NGL EXPORTS AND NETBACKS STEP-UP BY 4Q 2016

1. Source: Intercontinental exchange as of 12/31/2015.2. Source of graphic: Tudor Pickering Holt & Co. research presentation dated June 16, 2015.3. As an anchor shipper on Mariner East II, Antero has the right to expand its NGL commitment with

notice to operator.

4. Shipping rates based on benchmark Baltic shipping rate of $59.57/ton as of 12/31/15, adjusted for number of shipping days to NWE.

5. Pipeline fee equal to $0.0725/gal, per Mariner East I tariff. Terminal fee equal to $0.12/gal, per TPH report dated June 16, 2015.

Upon in-service of Mariner East II, Antero will have the ability to market its propane and n-butane to international buyers, which we expect will provide uplifts of $0.16/Gal and $0.18/Gal, respectively, to the current netbacks received from propane and n-butane volumes shipped to Mont Belvieu today− In the meantime, Antero has 30,000 Bbl/d of propane hedged at $0.59/Bbl in 2016

Commitment to Mariner East II results in approximately $127 million in combined incremental annualized cash flow from propane and n-butane sales (~$86 MM from propane and ~$41 MM from n-butane)

PricingPropane: $0.39/GalN-Butane: $0.56/Gal

PricingPropane: $0.56/GalN-Butane: $0.76/Gal

Mariner East II61,500 Bbl/d AR

Commitment (see table below) (3)

4Q 2016 In-Service

ShippingPropane: $0.07/GalN-Butane: $0.08/Gal

AR Mariner East II Commitment (Bbl/d)Product Base Option (3) TotalEthane (C2) 11,500 - 11,500 Propane (C3) 35,000 35,000 70,000 Butane (C4) 15,000 15,000 30,000

Total 61,500 50,000 111,500

64

Mont Belvieu Propane Netback ($/Gal)Propane N-Butane

January Mont Belvieu Price (1): $0.39 $0.56

Less: Shipping Costs to Mont Belvieu (2): (0.25) (0.25)

Appalachia Propane Netback to AR: $0.14 $0.31

NWE Netback ($/Gal)Propane N-Butane

January NWE Price (1): $0.56 $0.76

Less: Spot Freight (4): ($0.07) ($0.08)

FOB Margin at Marcus Hook: $0.49 $0.68

Less: Pipeline & Terminal Fee (5): (0.19) (0.19)

Appalachia Netback to AR: $0.30 $0.49Upside to Appalachia Netback: $0.16 $0.18

ANTERO RESOURCES EBITDAX RECONCILIATION

65

EBITDAX Reconciliation

($ in millions) Quarter Ended LTM Ended9/30/2015 9/30/2015

EBITDAX:Net income (loss) including noncontrolling interest $544.7 $1,413.4Commodity derivative fair value (gains) (1,079.1) (2,768.3)Net cash receipts (payments) on settled derivatives instruments 205.9 665.1(Gain) loss on sale of assets - (40.0)Interest expense 60.9 222.9Loss on early extinguishment of debt - -Income tax expense (benefit) 335.5 868.5Depreciation, depletion, amortization and accretion 189.1 706.5Impairment of unproved properties 8.8 51.0Exploration expense 1.1 9.8Equity-based compensation expense 23.9 105.6State franchise taxes - 0.6Contract termination and rig stacking - 10.9Consolidated Adjusted EBITDAX $290.8 $1,245.9

EBITDAX:Net income from discontinued operations - -(Gain) on sale of assets - -Provision for income taxes - -Adjusted EBITDAX from discontinued operations - -

Total Adjusted EBITDAX $290.8 $1,245.9

ANTERO MIDSTREAM EBITDA RECONCILIATION

66

EBITDA Reconciliation

Three months ended September 30,

2014 2015Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow: Net income $ 34,290 $ 42,648Add:

Interest expense 2,455 2,044Less:

Pre-water acquisition net income attributed to parent (29,211) (7,841)

Pre-water acquisition interest expense attributed to parent (522) (770)Pre-water acquisition operating income attributed to parent (29,733) (8,611)

Operating income - attributable to Partnership $ 7,012 $ 36,081Add:

Depreciation expense - attributable to Partnership 10,227 15,076

Equity-based compensation expense - attributable to Partnership 1,562 4,205 Adjusted EBITDA $ 18,801 $ 55,362

Less:Cash interest paid - attributable to Partnership (1,038)Maintenance capital expenditures attributable to Partnership (4,214)

Distributable cash flow $ 50,110

Reconciliation of Adjusted EBITDA to Net Cash Provided by Operating Activities:Adjusted EBITDA $ 18,801 $ 55,362 Add:

Pre-water acquisition net income attributed to parent 29,211 7,841

Pre-water acquisition depreciation expense attributed to parent 4,390 6,485

Pre-water acquisition equity based compensation expense attributed to parent 549 1,079Pre-water acquisition interest expense attributed to parent 522 770

Amortization of deferred financing costs attributed to parent — 285Less:

Interest expense (2,455) (2,044)Changes in operating assets and liabilities (8,258) (15,311)

Net cash provided by operating activities $ 42,760 $ 54,467

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, 2014 included in this presentation have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates as of December 31, 2014 assume ethane rejection and strip pricing.

Actual quantities that may be ultimately recovered from Antero’s interests may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery include the scope of Antero’s ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates.

In this presentation:

“3P reserves” refer to Antero’s estimated aggregate proved, probable and possible reserves as of December 31, 2014. The SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.

“EUR,” or “Estimated Ultimate Recovery,” refers to Antero’s internal estimates of per well hydrocarbon quantities that may be potentially recovered from a hypothetical future well completed as a producer in the area. These quantities do not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules.

“Condensate” refers to gas having a heat content between 1250 BTU and 1300 BTU in the Utica Shale.

“Highly-Rich Gas/Condensate” refers to gas having a heat content between 1275 BTU and 1350 BTU in the Marcellus Shale and 1225 BTU and 1250 BTU in the Utica Shale.

“Highly-Rich Gas” refers to gas having a heat content between 1200 BTU and 1275 BTU in the Marcellus Shale and 1200 BTU and 1225 BTU in the Utica Shale.

“Rich Gas” refers to gas having a heat content of between 1100 BTU and 1200 BTU.

“Dry Gas” refers to gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.

Regarding Hydrocarbon Quantities

67

company website presentation january 2016

Investor Relations