3Q 2015 Earnings Call Presentation October 29, 2015

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.

ANTERO OUTPERFORMANCE – HIGHEST EBITDAX & EBITDAX MARGINS AMONG PEERS

Quarterly Appalachian Peer Group EBITDAX Margin ($/Mcfe)(1)

Quarterly Appalachian Peer Group EBITDAX ($MM)(1)

3Q 2014 4Q 2014 1Q 2015 2Q 2015

Note: AR and EQT EBITDAX margin excludes EBITDA from midstream MLP associated with noncontrolling interest. CNX excludes EBITDAX contribution from coal operations.

1) Source: Public data from form 10-Qs and 10-Ks. Peers include COG, CNX, EQT and RRC.

3Q 2014 4Q 2014 1Q 2015 2Q 2015

AR Peer Group Ranking – Top Tier

#1 #1 #2 #1 #1

AR Peer Group Ranking – Improving Over Time

#2 #3 #2 #1 #1

Y-O-Y AR: $1MM

Peer Avg: $103MM

NYMEX Gas: 32%

NYMEX Oil: 53%

Y-O-Y AR: 33%

Peer Avg: 51%

NYMEX Gas: 32%

NYMEX Oil: 53%

2

$292

$0

$50

$100

$150

$200

$250

$300

$350

$400

P2 AR P3 P4 P1

$330

P2 P4 AR P3 P1

$355

P2 AR P4 P3 P1

$269

AR P2 P3 P4 P1

$291

AR P3 P2 P4 P1

3Q 2015

$2.93

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

AR P3 P2 P1 P4

$2.84

AR P2 P3 P4 P1

$2.56

P2 AR P3 P4 P1

$1.90

AR P3 P4 P2 P1

$1.97

AR P3 P4 P2 P1(2) 3Q 2015

For the second straight quarter AR has the highest EBITDAX

margin and EBITDAX among Appalachian peers

$2.32

$1.95 $1.94 $1.86 $1.77 $1.68

$3.99

$2.63 $2.77

$2.46 $2.21

$2.02 $2.46

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

AR P2 P3 P1 P5 P4

Natural Gas Price Realization - Before Hedges Natural Gas Price Realization - After Hedges Median - After Hedges

$12.08

$8.10

$6.23

$4.75 $4.72

$16.47

$8.10 $9.45

$4.75 $4.72 $6.43

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

$16.00

$18.00

AR P2 P3 P1 P5 P4

NGL Realization - Before Hedges NGL Realization - After Hedges Median - After Hedges

3Q 2015 NATURAL GAS AND NGL REALIZATIONS

Note: Excludes peer that does not report a standalone NGL price.

1) Public data from form 10-Qs and 10-Ks. Peers include COG, CNX, EQT, RRC and SWN.

NATURAL GAS PRICE REALIZATIONS(1) 3Q 2015 NYMEX: $2.77/MMbtu

NGL PRICE REALIZATIONS(1) 3Q15 NYMEX WTI: $46.42/Bbl

($/Mcf)

($/Bbl)

68% of sales to favorable markets, expected to increase to 85% in 2016 (TCO, Chicago, Nymex)

26%

of

WTI 17% of WTI 10% of WTI 10% of WTI

3

• Antero’s realized NGL price, including hedges, was approximately 3x greater than

the peer group average during the quarter.

• Outperformance expected to continue as AR has 30,000 Bbl/d of propane hedged

in 2016 with Mariner East II capacity in 2017 expected to improve realizations

35%

of

WTI

87% hedged in 3Q15, expected to increase to ~100% in 2016

13%

of

WTI

21%

of

WTI N/A

4

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 $1.5 billion of gains on commodity hedges since 2009

– Gains realized in 26 of last 27 quarters, or 96% of the quarters since 2009

● Based on Antero’s hedge position and strip pricing as of 9/30/2015, the unrealized commodity derivative value is $2.8 billion

● Significant additional hedge capacity remains under the credit facility hedging covenant for 2017 – 2021 period

Quarterly Realized Hedge Gains / (Losses)

Realized Hedge Gains

Projected Hedge Gains NYMEX Natural Gas

Historical Spot Prices

($/M

cf)

NYMEX Natural Gas

Futures Prices

3.1 Tcfe Hedged at average price of

$3.93/Mcfe through 2021

$2.8 Billion on

Balance Sheet in

Hedge Gains

Through 2021

Average Hedge Prices

($/Mcfe)

$3.67

Realized $1.5 Billion

in Hedge Gains

Since 2009

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$0

$50

$100

$150

$200

$250

$M

M

$4.51

$3.94 $3.83

$4.06 $3.94

$3.75

0%

20%

40%

60%

80%

100%

Strip(9/30/15)

$40 Oil /$2.50 Nymex Gas

$30 Oil /$2.00 Nymex Gas

$20 Oil /$1.50 Nymex Gas

$10 Oil /$1.00 Nymex Gas

INSULATED FROM 2016 COMMODITY PRICE VOLATILITY

5 (1) 2016 total production based on 2016 preliminary targeted production growth of 25% to 30% over 2015 production guidance of 1.4 Bcfe/d.

(2) 2016 Strip as of 9/30/2015: NYMEX Gas - $2.80/MMBtu; WTI Oil - $48.70/Bbl.

Antero is hedged ~100% (1.75 Bcfe/d to 1.82 Bcfe/d)

on its targeted 2016 production growth of 25% to

30% off of 2015 guidance

2016 Hedges

– 1.613 Bcf/d of gas hedged at $3.92/Mcf

– 30,000 Bbl/d of propane hedged at $0.59/Gal

As the chart below demonstrates, Antero’s 2016

projected EBITDAX at 9/30/2015 strip prices would

only decline by 3% at flat $30 WTI and $2.00

NYMEX natural gas prices

Hedge Impact on 2016 Projected EBITDAX

(% o

f 2016 P

roje

cte

d E

BIT

DA

X

at

Str

ip) 98% of

Projected

EBITDAX

97% of

Projected

EBITDAX

95% of

Projected

EBITDAX

94% of

Projected

EBITDAX

(2)

2016 Volume Hedged (BBtu/d)

(BB

tu/d

)

EBITDAX at

Strip Pricing

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

2016

1,793

(98% to 102% of

Targeted 2016

Production Range

at a price of

$3.94/MMBtu)

1,750

1,820 2016

Production

Target(1)

Liquidity

STRONG BALANCE SHEET AND FINANCIAL FLEXIBILITY

Antero Resources (NYSE:AR) Antero Midstream (NYSE:AM)

9/30/15 Debt Liquid Non-E&P Assets 9/30/15 Debt Liquid Assets

Debt Type $MM

Credit 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 $MM

Commodity derivatives(1) $2,842

AM equity ownership(2) 2,694

Cash 10

Total $5,546

Liquid non-E&P assets of $5.5 Bn significantly exceeds

total debt of $3.9 Bn

Asset Type $MM

Cash $10

Credit facility – commitments(3) 4,000

Credit facility – drawn (500)

Credit facility – letters of credit (535)

Total $2,975

Debt Type $MM

Credit facility $525

Total $525

Asset Type $MM

Cash $18

Total $18

Liquidity

Asset Type $MM

Cash $18

Credit facility – capacity(4) 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 liquidity at AM

Note: All balance sheet data as of 9/30/2015, inclusive of water drop down and associated financing.

1. Mark-to-market as of 9/30/2015.

2. Based on AR ownership of AM units (116.9 million common and subordinated units) and AM’s closing price as of 10/23/15.

3. AR credit facility commitments of $4.0 billion, borrowing base of $4.5 billion.

4. Credit facility increased to $1.5 billion upon water drop down – 3 new banks added to existing bank group of 17 banks.

6

Only 35% of AM credit facility capacity drawn

ANTERO’S FIRST UTICA DRY GAS WELL

7

Antero recently drilled and cased its first dry gas Utica well in Tyler

County, WV with results expected in 4Q 2015 (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

186,000 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

40,000 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 226,000 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

Gulfport

Irons #1-4H

5,714’ Lateral

IP/1,000’: 5.3 MMcf/d

Range

Claysville SC #11H

5,420’ Lateral

IP/1,000’: 10.9 MMcf/d

CNX

Gaut 4IH

5,840’ Lateral

IP/1,000’: 10.4 MMcf/d

EQT

Scotts Run

3,221’ Lateral

IP/1,000’: 22.6 MMcf/d

Gastar

Blake U-7H

6,617’ Lateral

IP/1,000’: 5.6 MMcf/d

Gastar

Sims U-5H

4,447’ Lateral

IP/1,000’: 6.6 MMcf/d

Stone Energy

Pribble 6HU

3,605’ Lateral

IP/1,000’: 8.3 MMcf/d

Magnum Hunter

Stalder #3UH

5,050’ Lateral

IP/1,000’: 6.4 MMcf/d

Magnum Hunter

Stewart Winland 1300U

5,280’ Lateral

IP/1,000’: 8.8 MMcf/d

Antero

Utica Well Drilling

Rymer 4HD

Utica Dry Gas Fairway

47% 45%

40%

38% 35%

31%

16% 15% 14%

38% 38%

32% 29% 28%

26%

13% 11% 10%

0%

10%

20%

30%

40%

50%

Utica Highly-Rich Gas

MarcellusHighly-Rich

Gas/Condensate

Utica Dry Gas - Ohio

Utica Highly-Rich Gas/

Condensate

Utica Rich Gas MarcellusHighly-Rich

Gas

Marcellus DryGas

UticaCondensate

Marcellus RichGas

RO

R

ROR @ 6/30/2015 Strip - Spot Well Costs ROR @ 6/30/2015 Strip - Current Well Costs

AR WACC ≈ 8.5%

Antero

Drilling Plan

Locations 94 664 289 139 254 1,010 889 248 628

1. 6/30/2015 pre-tax well economics based on a 9,000’ lateral, 6/30/2015 natural gas and WTI strip pricing for 2015-2024, flat thereafter, NGLs at 32.5% of WTI for 2015–2016 and 50% of WTI thereafter,

and applicable firm transportation and operating costs . Well cost estimates include $1.2 million assumed for road, pad and production facilities. Current well costs include existing contracts. Spot

well costs are adjusted for current market drilling and completion rates resulting in a $1.2 million cost saving vs. current well costs. Antero will begin to realize spot well costs as the company utilizes

incremental completion crews for deferred completions beginning at the beginning of 2016 and as existing drilling rig contracts begin to roll off during 2016.

2. Market data for WACC calculation as of 8/25/2015.

HIGH RETURN LOCATIONS DRIVE VALUE CREATION

8

Using the 6/30/2015 strip, 100% of Antero’s 4,200+ fully-engineered undrilled Marcellus/Utica 3P locations exceed Antero’s underlying weighted

average cost of capital (WACC) of 8.5%

−Well economics on some wells expected to improve further starting in early 2016 as the Company utilizes incremental market based contracts

for drilling and completion operations which is expected to reduce well costs by another 10 to 12% over time

−These returns are based on all-in well costs which include $1.2 million of road, pad and production facilities costs

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

2,450 “High

Grade” Drilling

Locations

Pre Post

In-Service In-Service

Projected 2016 Average Volume (BBtu/d)

DOMS Priced Sales 329 0

TETCO M2 Priced Sales 321 0

TCO Priced Sales 0 80

Firm Sales (TCO / Nymex) 0 570

Total 650 650

2016 Strip Pricing ($/MMBtu)

DOMS (1)

$1.79 N/A

TETCO M2 (1)

$1.87 N/A

TCO (1)

N/A $2.61

Firm Sales (TCO / Nymex) (2)

N/A $2.49

Annual Revenue ($MM)

DOMS $215.3 $0.0

TETCO M2 219.5 0.0

TCO Pool Sales (1)

0.0 75.8

Firm Sales (TCO / Nymex) (2)

0.0 520.4

$434.8 $596.2

Incremental Revenue $161.4

Less: Incremental Firm Transport Costs: (35.3)

Projected Incremental EBITDA $126.1

PROJECTED INCREMENTAL EBITDA FROM REGIONAL GATHERING PIPELINE IN SERVICE

1. 2016 Strip pricing as of September 30, 2015.

2. Blended price based on contracted firm sales volumes with third parties.

Existing TCO capacity of 582 MMcf/d with additional

1.1 Bcf/d of Regional Gathering firm transportation

and sales should eliminate all Marcellus swing gas

sales to Dominion South and TETCO M2 in

December 2015

9

Pre- Stonewall

Stonewall In-Service

Volume (BBtu/d)

DOMS Priced Sales (1) 199 0

TETCO Priced Sales 322 0

Stonewall -> Firm Sales 0 520

Total 520 520

Pricing ($/MMBtu)

DOMS (2) $1.89 N/A

TETCO M2 (2) $1.94 N/A

Nymex / TCO WGL Contracts (3) N/A $2.67

Revenue ($MM)

DOMS $137.4 $0.0

TETCO M2 228.6 0.0

Nymex / TCO WGL Contracts 0.0 507.8

$366.0 $507.8

Incremental Revenue $141.8

FT Variable Costs ($/MMBtu)

DOMS (No FT) $0.00 N/A

EQT / M3 to TETCO M2 $0.17 N/A

Stonewall $0.00 $0.07

Total FT Variable Costs ($MM)

DOMS (No FT) $0.0 $0.0

EQT / M3 to TETCO M2 (20.5) 0.0

Stonewall 0.0 (14.3)

Total ($20.5) ($14.3)

Change in Costs $6.2

Incremental Impact to EBITDA (4) $148.0

2016 DOMS Strip: $1.79

Variance to Nymex ($1.04)

Variance to TCO ($0.82)

2016 TETCO M2 Strip: $1.87

Variance to Nymex ($0.96)

Variance to TCO ($0.74)

10

APPENDIX

10

ANTERO EBITDAX RECONCILIATION

11

EBITDAX Reconciliation

($ in millions) Quarter Ended LTM Ended

9/30/2015 9/30/2015

EBITDAX:

Net income (loss) including noncontrolling interest $544.7 $1,413.4

Commodity 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 60.9 222.9

Loss on early extinguishment of debt - -

Income tax expense (benefit) 335.5 868.5

Depreciation, depletion, amortization and accretion 189.1 706.5

Impairment of unproved properties 8.8 51.0

Exploration expense 1.1 9.8

Equity-based compensation expense 23.9 105.6

State franchise taxes - 0.6

Contract termination and rig stacking - 10.9

Consolidated 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