Goldman conference presentation v f-01.06.16

Goldman Sachs Global Energy ConferenceJanuary 7, 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.

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

2

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.

HIGH RETURN LOCATIONS DRIVE VALUE CREATION

3

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

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 $1.7 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

2.1x

0.0x1.0x2.0x3.0x4.0x5.0x6.0x7.0x

Peer 5 AR Peer 1 Peer 6 Peer 2 Peer 3 Peer 4

E&P Debt (net of Cash and M-T-M Hedge Value)(1) / LTM EBITDA (excl. Realized Hedging Revenue)

5

HEDGE BOOK SUPPORTS FINANCIAL PROFILE

Note: Data presented as filed for the quarter ended September 30, 2015 ($ in millions), prepared by Antero management. Peer group comprised primarily of gas weighted E&P names with comparable credit profiles, including NFX, QEP, RRC, SM, SWN, WPX.1. Represents total E&P debt less cash and mark-to-market hedge value.

Antero exceeds closest credit peer by $2.3 billion

AR net leverage maps with strong BB credit peers

Only credit peer with less than $1.5 billion of E&P debt

$2,842(9/30/15)

$0$500

$1,000$1,500$2,000$2,500$3,000$3,500

AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6

Mark-to-Market Hedge Value (9/30/15) for BB / BBB E&P Credits ($MM)$3,117

(12/31/15)

$0

$1,000

$2,000

$3,000

$4,000

$5,000

AR Peer 5 Peer 2 Peer 1 Peer 3 Peer 4 Peer 6

E&P Debt (net of Cash and M-T-M Hedge Value)

BB Credit Peer

BBB Credit Peer

Pre PostIn-Service In-Service

Projected 2016 Average Volume (BBtu/d)DOMS Priced Sales 329 0TETCO M2 Priced Sales 321 0TCO Priced Sales 0 80Firm Sales (TCO / Nymex) 0 570

Total 650 650

2016 Strip Pricing ($/MMBtu)DOMS (1) $1.54 N/ATETCO M2 (1) $1.56 N/ATCO (1) N/A $2.31Firm Sales (TCO / Nymex) (2) N/A $2.21

Annual Revenue ($MM)DOMS $185.1 $0.0TETCO M2 183.0 0.0TCO Pool Sales (1) 0.0 67.1Firm Sales (TCO / Nymex) (2) 0.0 461.2

$368.1 $528.3

Incremental Revenue $160.2Less: Incremental Firm Transport Costs: (25.2)

Projected Incremental EBITDA $135.0

STONEWALL PIPELINE IN SERVICE – EBITDA IMPACT

1. 2016 Strip pricing as of 12/31/2015.2. 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 Stonewall Gathering firm transportation

and sales should eliminate virtually all Marcellus swing gas sales to Dominion South and TETCO M2

in 2016

6

2016 DOMS Strip: $1.54Variance to Nymex ($0.95)Variance to TCO ($0.77)

2016 TETCO M2 Strip: $1.56Variance to Nymex ($0.93)Variance to TCO ($0.75)

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

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

7

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

NGL REALIZATIONS AND PROPANE HEDGES

81. 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)

2016 FT Portfolio and Projected Gas Sales

Net Production Target (MMcfe/d) (1) 1,785Net Gas Production Target (MMcf/d) (80% of Net Production) 1,430Net Revenue Interest Gross-up 80%Gross Gas Production Target (MMcf/d) 1,785BTU Upgrade (2) x1.100 Gross Gas Production Target (BBtu/d) 1,975

Firm Transportation / Firm Sales (BBtu/d) 3,525Estimated % Utilization of FT/FS 56%

Excess Firm Transportation 1,550Marketable Firm Transport (BBtu/d) (3) 1075Unmarketable Firm Transportation 475

Estimated % Utilization of FT/FS Portfolio (Including Marketable FT) 87%

ANTERO FIRM TRANSPORTATION APPROPRIATELY DESIGNED TO ACCOMMODATE GROWTH

91. Represents midpoint of 2016 preliminary targeted net daily production growth of 25% to 30%.2. Assumes 1100 BTU residue sales gas.3. Represents excess firm transportation that is deemed marketable to 3rd parties based on a positive differential between the receipt and delivery points of the FT capacity, less variable transport cost.

• Antero projects firm transportation in excess of equity gas production of approximately 1,550 BBtu/d in 2016

• Expects to market or mitigate the cost of approximately 1,075 Bbtu/d of the excess FT with 3rd party gas

• Expect to fully utilize FT portfolio by 2019, assuming 2016 targeted production growth is maintained long-term (excludes Appalachia based FT directed to unfavorable indices)

0

600

1,200

1,800

2,400

3,000

3,600

(BBtu/d)

2016 Targeted Gross Gas

Production(1)

1,975 BBtu/d

Unmarketable Unutilized Firm Transport

~475 BBtu/d ($0.15 / MMBtu)

Marketable Unutilized Firm Transport ~1,075 BBtu/d

($0.39 / MMBtu)

Utilized Firm Transport / Firm Sales

~1,975 BBtu/d($0.45 / MMBtu)

Total Firm Transport (4)

3,525 BBtu/d

Excess Capacity Marketable /

FT Segment (Location) (BBtu/d) Unmarketable

Columbia / TGP (Marcellus) 625 MarketableANR North / ANR South (Utica) 450 MarketableEQT / M3 (Marcellus) 475 Unmarketable

Total Excess Firm Transport 1,550

2016 Firm Transport

Dec

reas

ing

Cos

t of F

T

2016EMarketing 2016E Marketing Revenue

Spread Assuming % Volume Mitigated($ / MMBtu) (2) 25% 50%

"Marketable" Firm Transport Capacity625 BBtu/d of Columbia / TGP $0.72 $41 $82450 BBtu/d of ANR North / ANR South $0.12 4 10

Sub-Total $45 $92$ / Mcfe - 2016E Targeted Production (1) $0.07 $0.14

Unmarketable (EQT / M3) ($/MMBtu)2016 TETCO M2 Pricing (Sold Gas) $1.562016 TETCO M2 Pricing (Bought Gas) (1.56)

Total Spread $0.00

Marketable (TCO / TGP) ($/MMBtu)2016 TGP-500 Pricing (Sold Gas) $2.432016 TETCO M2 Pricing (Bought Gas) (1.56)Less: Variable FT Costs (0.15)

Total Spread ("In the Money") $0.72

FIRM TRANSPORTATION PORTFOLIO PRESENTS MARKETING OPPORTUNITIES

10NOTE: Analysis based on current strip pricing as of 12/31/15. 1. Represents midpoint of 2016 preliminary targeted net daily production growth of 25% to 30%.2. Spread for each respective “marketable” firm transport represents the difference between the gas price Antero

would receive at the delivery point of each pipeline versus the price Antero would pay to buy gas at the receipt point of each piece of capacity, less the variable costs to transport on each segment of firm transportation.

2016 Projected Marketing Expenses:

0

600

1,200

1,800

2,400

3,000

3,600

(BBt

u/d)

2016 Targeted Gross Gas Production (2)

1,975 BBtu/d

$0.06 / Mcfe of 2016E Production (2)

$0.10 to $0.17 / Mcfe of 2016E Production (2)

Utilized FT$0.45 / Mcfe of 2016E

Production (2)

Illustrative Marketing Example:

2016 FT and Marketing Expenses per Unit:

2016 Marketing Revenue Projection:

Based on the midpoint of 2016 preliminary targeted net daily production growth of 25% to

30%, Antero projects net marketing expenses of ~$0.13 to $0.20 per Mcfe in 2016

Gathering& Transportation

Costs

MarketableNet Marketing

Expense

UnmarketableNet Marketing

Expense

Positive Spread

No Spread

($ in millions, except per unit amounts) 2016E 2016E 2016EDemand Marketing Marketing Marketing

Cost Expenses Revenue Expenses, Net"Unmarketable" Firm Transport

475 BBtu/d of EQT / M3 Appalachia FT $0.15 / MMBtu $26 - $26

"Marketable" Firm Transport Capacity625 BBtu/d of Columbia / TGP $0.49 / MMBtu $112 $41 - $82 $30 - $71450 BBtu/d of ANR North / ANR South $0.24 / MMBtu 40 $4 - $10 $30 - $36

Sub-Total $152 $45 - $92 $60 - $107

Grand Total - 2016 Marketing Expenses, Net $177 $45 - $92 ~$85 to $132 MM

$ / Mcfe - 2016 Targeted Production (1) $0.27 $0.07 - $0.14 $0.13 - $0.20

$1.97

AR P3 P4 P2 P1

“THE BRIDGE” RESULTS IN OUTPERFORMANCE VS. 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 2015AR 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: $1MMPeer Avg: $103MMNYMEX Gas: 32%NYMEX Oil: 53%

Y-O-Y AR: 33%Peer Avg: 51%NYMEX Gas: 32%NYMEX Oil: 53%

11

$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 P13Q 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(2)3Q 2015

For the second straight quarter, Antero has both the highest EBITDAX and EBITDAX margin among Appalachian peers

12

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

13

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

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

14

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)

15

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)

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 ECONOMICS – 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.

16

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

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. 17

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)

18

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)

$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

19

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)

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

~ 100% of 2016 Target Hedged

191. 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

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

20

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.

$2.32 $2.32

$1.94 $1.95 $1.86 $1.77

$3.99

$3.18 $2.77 $2.63

$2.46 $2.21

$2.55/Mcf Midpoint

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

AR RICE RRC EQT CNX SWN

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/Bbl Midpoint

$0.00$2.00$4.00$6.00$8.00

$10.00$12.00$14.00$16.00$18.00

AR EQT RRC CNX SWN COG

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

REALIZATIONS – 3Q 2015 LEADING 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 95% in 2016 (TCO, Chicago, Nymex)

26% of

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

21

• Antero’s realized NGL price, including hedges, was approximately 3x greater than the peer group average during the quarter.

• Outperformance expected to continue into 2016 as AR has 30,000 Bbl/d of propane hedged along with contracted C4+ pricing – expect NGL price realizations to be 37% of WTI

• Further improvement expected beyond 2016 when Mariner East 2 is placed into service35% of

WTI

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

13% of

WTI

21% of

WTI N/A

-

100

200

300

400

500

600

AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5

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

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



24

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

25

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

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

26

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


LARGE UTICA SHALE DRY GAS POSITION

27

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

28

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

29

Antero Midstream (NYSE: AM)Asset Overview

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.

30

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

31

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

32Integrated 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)

33

$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.

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

34

Downstream LNGand NGL Sales

Production andCash Flow Growth

35

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

36

APPENDIX

36

($ 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 43.2. 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 9/23/2015.37

-

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

38

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

Illustrative gross gas production fills 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.

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

39

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

40

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

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 2, 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

41

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

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-

9/1/2010 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

42

3/31/2015

Ba2/BB

ANTERO RESOURCES EBITDAX RECONCILIATION

43

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

44

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

Investor Relations

Goldman conference presentation v f-01.06.16