Credit Suisse 21 st Annual Energy Summit February 2016 - - PDF document

Credit Suisse 21st Annual Energy Summit February 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,

• bjectives and anticipated financial and operating results of the Company, including as to the Company’s drilling program, production, hedging

activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and

• ther factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are

beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking

• statements. These include the factors discussed or referenced under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for

the year ended December 31, 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

• r 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

2015A 2016E 2017E

Large and Growing Production Base Declining Development Costs Production Sold Forward at Attractive Prices Strong Liquidity Firm Transport to Favorable Markets

48% growth to 1.493 Bcfe/d 15% growth guidance to 1.715 Bcfe/d 20% growth target on 2016E guidance ~$0.88/Mcfe in 2015 down 10% from 2014

• 2,227 “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 guidance) 2,073 BBtu/d hedged at $3.57/MMBtu (≈100% of target)

• $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
• 69% of sales volumes priced

at favorable markets

• 3.5 Bcf/d of FT
• Expect 99% of sales volumes

priced at favorable markets

• 3.6 Bcf/d of FT
• Expect 97% of sales volumes

priced at favorable markets

• 61,500 Bbl/d of FT on

Mariner East 2 for NGL 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 virtually all of its production volumes sold to favorable markets

2

$1,300 $100 Drilling & Completion Land

2016 CAPITAL BUDGET DRIVES MOMENTUM

By Area 3

$1.8 Billion – 2015(1)

By Segment ($MM)

$1,650 $160 Drilling & Completion Land 56% 44%

Marcellus Utica Marcellus

By Area

$1.4 Billion – 2016

By Segment ($MM)

 Antero’s 2016 initial capital budget is $1.4 billion, a 23% decrease from 2015 capital expenditures of $1.8 billion and a 58% decline from 2014 capital expenditures

23%

131 Completions  50 DUCs at YE

• 1. Excludes $39 million for leasehold acquisitions in 2015. DUCs are drilled but uncompleted wells at year-end.

110 Completions  70 DUCs at YE 75% 25%

Marcellus Utica Marcellus

Baa3 Ba1 Ba1 Ba1 Ba3 Ba3 Ba3 Ba3 B1 B1 B1 B2 B2 B2 B3 Caa1 Caa2 Baa2 Baa3 Baa3 Baa3 Baa2 Baa2 Ba2 Baa3 Baa3 Ba1 Ba1 Baa3 Ba1 Ba1 Ba1 Ba1 Ba3 Ba3 Ba2 Ba3

• Baa3

Baa3 Baa3 Baa3 Baa3 Baa3 Baa3 Baa3 Baa3 Baa3 Baa3 Baa3

NBL XEC EQT PXD APC HES CXO AR CLR MUR NFX RRC SWN EGN QEP SM WPX UNT EPE WLL DNR

ANTERO CREDIT QUALITY AFFIRMED AT Ba2/BB

4 Moody’s Baa / Ba Ratings Review

Source: Moody’s releases on 02/11/16 and 02/18/16. Note: Issuers are sorted based on rating following review. Appalachia companies in orange.

 Amidst the sector wide re-rating of the Energy Sector, Antero recently received affirmed ratings of Ba2 / BB from Moody’s and S&P  Of the 21 public US Baa/Ba E&P issuers reviewed by Moody’s and highlighted below, 15 received downgrades of two or more notches, including five companies that received downgrades of 4 or more notches, and one received a one notch downgrade  S&P reviewed 45 High Yield issuers with 25 downgrades ranging from 1-3 notches

Of the 21 public U.S. Baa and Ba rated E&P operators, Antero was one

• f only five companies that received

an “affirmed” rating from Moody’s

AR Rating Affirmed Baa1 Baa2 Baa3 Ba1 Ba2 Ba3 B1 B2 B3 Caa1 Caa2 Caa3 Gray – Previous Rating Red – New Rating Appalachian Company

5

Most Active Operator in Appalachia Largest Firm Transport and Processing Portfolio in Appalachia Largest Gas Hedge Position in U.S. E&P + Strong Financial Liquidity Growing Through the Down Cycle 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 Well Economics

1 2 3 4 5 6 7 8

Premier Appalachian E&P Company Run by Co-Founders

Sustainable Business Model

Note: 2015 SEC prices were $2.56/MMBtu for natural gas and $50.13/Bbl for oil on a weighted average Appalachian index basis.

• 1. 3P reserve pre-tax PV-10 based on annual strip pricing for first 10-years and flat thereafter as of December 31, 2015. NGL pricing assumes 39%, 46% and 48% of WTI strip prices for 2016, 2017 and

2018 and thereafter, respectively.

• 2. 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.

• 3. Antero and industry rig locations as of 1/29/2016, and average rig count for January 2016, per RigData.

DRILLING – MOST ACTIVE OPERATOR IN APPALACHIA

6

COMBINED TOTAL – 12/31/15 RESERVES Assumes Ethane Rejection

Net Proved Reserves 13.2 Tcfe Net 3P Reserves 37.1 Tcfe Strip Pre-Tax 3P PV-10(1) $11.2 Bn Net 3P Reserves & Resource 50 to 53 Tcfe Net 3P Liquids 1,237 MMBbls % Liquids – Net 3P 20% 4Q 2015 Net Production 1,497 MMcfe/d

• 4Q 2015 Net Liquids

54,750 Bbl/d Net Acres(2) 569,000 Undrilled 3P Locations 3,719 OHIO UTICA SHALE CORE Net Proved Reserves 1.8 Tcfe Net 3P Reserves 7.5 Tcfe Strip Pre-Tax 3P PV-10(1) $2.5 Bn Net Acres 147,000 Undrilled 3P Locations 814 MARCELLUS SHALE CORE Net Proved Reserves 11.4 Tcfe Net 3P Reserves 29.6 Tcfe Strip Pre-Tax 3P PV-10(1) $8.7 Bn Net Acres 422,000 Undrilled 3P Locations 2,905 WV/PA UTICA SHALE DRY GAS Net Resource 12.5 to 16 Tcf Net Acres 188,000 Undrilled Locations 1,889

2 4 6 8 10 12 Rig Count Operators January 2016 SW Marcellus & Utica(3)

$198 $341 $434 $649 $1,164 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 2010 2011 2012 2013 2014 2015E 2016E 10,000 20,000 30,000 40,000 50,000 60,000 2010 2011 2012 2013 2014 2015 2016E NGLs (C3+) Oil 5 246 6,436 23,051 48,298 60,000

24% Growth Guidance

• 1. Assumes ethane rejection. 2015 proved reserves include 1.1 Tcfe of ethane due to de-ethanizer being placed online at Sherwood facility and commencement of ethane delivery contracts in 2017.
• 2. Represents Bloomberg street consensus estimates as of 02/19/16.

1,715 600 1,200 1,800 2,400 2010 2011 2012 2013 2014 2015 2016E 2017E

Marcellus Utica Guidance

30 124 239 522 1,007 1,493

7

AVERAGE NET DAILY PRODUCTION (MMcfe/d)

50 100 150 200 2010 2011 2012 2013 2014 2015 2016E

Marcellus Utica Deferred Completions

19 38 60 114 177 181 131 110 180

GROWTH – GROWING THROUGH THE DOWN CYCLE

OPERATED GROSS WELLS COMPLETED AVERAGE NET DAILY LIQUIDS PRODUCTION (Bbl/d)

15% Growth Guidance 20% Growth Target

 Antero is in the unique position of being able to sustain growth and value creation through the price down cycle

CONSOLIDATED EBITDAX ($MM)

Street Consensus(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 2,700 undeveloped rich gas locations with an average lateral length of 7,580’ in its 3P reserves as of 12/31/2015

100 200 300 400

(000s)

Core Liquids-Rich Net Acres(1)

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 Marcellus Highly-Rich Gas/ Condensate Utica Highly- Rich Gas/ Condensate Marcellus Highly-Rich Gas Marcellus Dry Gas Marcellus Rich Gas Utica Condensate ROR ROR @ 12/31/2015 Strip Pricing - Before Hedges ROR @ 12/31/2015 Strip Pricing - After Hedges

2016 Antero Drilling Plan

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

108 263 161 626 98 971 755 553 184

• 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 2,227 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 2,227 “High Grade” Drilling Locations

NYMEX ($/MMBtu) WTI ($/Bbl) C3+ NGL ($/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

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

NYMEX ($/MMBtu) C3+ NGL ($/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 Hedges 12/31/15 Strip Pricing - After Hedges

Locations

WELL ECONOMICS – SUSTAINABLE BUSINESS MODEL

500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 Proved Developed Production (BBtu/d) Undeveloped Production (BBtu/d) Hedged Volume (BBtu/d)

WELL ECONOMICS – HEDGING UNDEVELOPED PRODUCTION

10

(1) Represents illustrative Antero production forecast, adjusted for residue gas BTU content of 1100 BTU.

Antero has hedged a significant portion of its forecasted undeveloped production stream from wells yet to be drilled at prices well above current strip pricing, including virtually all of its undeveloped production forecast through the end of 2017 Natural Gas Hedged Volume vs. Production

(BBtu/d)

(1) (1)

Antero has hedged virtually all of its undeveloped production through the end of 2017

Developed (Illustrative) Undeveloped (Illustrative)

$3.94/Mcfe $3.57/Mcfe $3.91/Mcfe $3.87/Mcfe $3.72/Mcfe

No Production Guidance

• r Targets Disclosed

Beyond 2017

Antero Resources Corporation (NYSE: AR) $11.4 Billion Enterprise Value(1) Ba2/BB Corporate Rating Antero Midstream Partners LP (NYSE: AM) $4.0 Billion Enterprise Value(1) 67% LP Interest $2.3 Billion MV(1)

$11.2 Bn 3P PV-10(4) E&P Assets

Gathering/Compression Assets

MIDSTREAM – MLP (NYSE: AM) HIGHLIGHTS SUBSTANTIAL VALUE IN MIDSTREAM BUSINESS

• 1. AR enterprise value excludes AM debt, minority interest and cash. Market values (MV) as of 1/31/2015 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.
• 4. 3P pre-tax PV-10 based on annual strip pricing for first 10-years and flat thereafter as of December 31, 2015. NGL pricing assumes 39%, 46% and 48% of WTI strip prices for 2016, 2017 and 2018 and

thereafter, respectively.

11

Corporate Structure Overview(1) Market Valuation of AR Ownership in AM:

• AR ownership: 67% LP Interest = 116.9 million units

AM Price per Unit AM Units Owned by 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 $1.2 Billion MV(1)

$3.1 Bn MTM Hedge Position(3)

TAKEAWAY – LARGEST FT AND PROCESSING PORTFOLIO IN APPALACHIA

Antero Long Term Firm Processing & Takeaway Position (YE 2018) – Accessing Favorable Markets

Mariner East 2 62 MBbl/d Commitment Marcus Hook Export Shell 20 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 LNG 70 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)

12

Cove Point LNG

4.85 Bcf/d Firm Gas Takeaway 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 Mix Antero 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)

• 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

TAKEAWAY – FIRM TRANSPORTATION AND SALES PORTFOLIO

13

MMBtu/d

Columbia 7/26/2009 – 9/30/2025 Firm Sales #1 10/1/2011– 10/31/2019 Firm Sales #2 10/1/2011 – 11/30/2015 Firm Sales #3 1/1/2013 – 5/31/2022 Momentum III 9/1/2012 – 12/31/2023 EQT 8/1/2012 – 6/30/2025 REX/MGT/ANR 7/1/2014 – 12/31/2034 Tennessee 11/1/2015– 9/30/2030

(Stonewall/WB) Mid-Atlantic/NYMEX (Stonewall/TGP) Gulf Coast (TCO) Appalachia or Gulf Coast Appalachia Appalachia

ANR 3/1/2015– 2/28/2045

(REX/ANR/NGPL/MGT) Midwest

Local Distribution 11/1/2015 – 9/30/2037

(ANR/Rover) Gulf Coast

Antero Transportation Portfolio

1,280 BBtu/d 590 BBtu/d 375 BBtu/d 250 BBtu/d 800 BBtu/d 600 BBtu/d 630 BBtu/d 40 BBtu/d

Gross Gas Production (Actuals) Illustrative Gross Gas Production(1)

• 1. Assumes production growth guidance of 15% in 2016 and targeted 20% annual production growth in 2017.
• 2. Based on 2016 production guidance of 1.715 Bcfe/d.
• 3. Assumes 25% to 50% mitigation on excess capacity and current spreads based on strip pricing as of 12/31/2015.

Lowest cost, local unfavorable FT projected to not be used through 2017

2016E Net Marketing Expenses: $15 Million 2016E Net Marketing Expenses: $20 Million 2016E Net Marketing Expenses: $30 to $35 million (3) 2016E Net Marketing Expenses: $30 to $55 Million (3)

2016E Total Net Marketing Expenses: $95 to $125 Million ($0.15 to $0.20 per Mcfe)(2)

2017E Net Marketing Expenses: $ Amounts in line with 2016

 While Antero has excess FT in place through 2017, the expected cost of unutilized FT is estimated to be manageable at <10% of EBITDA through 2017

Projected cost after mitigation due to positive futures spreads

$0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $0 $50 $100 $150 $200 $250 $300 $MM

14

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 Gains Projected Hedge Gains NYMEX Natural Gas Historical Spot Prices ($/MMBtu) NYMEX Natural Gas Futures Prices 3.5 Tcfe Hedged at average price of $3.79/ Mcfe through 2022 Average Hedge Prices ($/Mcfe)

$3.48 $3.94 $3.57 $3.91 $3.87 $3.72 $3.30

$3.1 Billion on Balance Sheet in Hedge Gains Through 2022 Realized $1.7 Billion in Hedge Gains Since 2009

90% 83% 80% 74% 69% 51% 46% 45% 39% 25% 15% 14% 11% 39% 22% 13% 44% 53% 2% 23% 22% 19% 1% 6% 80% 31% 14% 8% 5% 0.0% 10.0% 20.0% 30.0% 40.0% 50.0% 60.0% 70.0% 80.0% 90.0% 100.0% AR Peer 1 Peer2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 12 Peer 13 Peer 14 Peer 15 2016 2017 2018

HEDGING – HIGHEST PROPORTION HEDGED AMONG E&P OPERATORS

15 Antero has substantially de-risked its cash flow profile and differentiated itself versus its peer group through its extensive hedge portfolio, with 100% of forecasted production hedged in 2016 and 2017 and 80% of consensus estimated production hedged in 2018

Source: Public filings. Projected production for peers based on consensus estimates. Projected production for AR based on 2016 guidance of 15% growth, 2017 target of 20% growth, and 2018 consensus estimates. Note: Operators include APC, CHK, CLR, COG, CXO, EOG, EQT, GPOR, NBL, NFX, PXD, RICE, RRC, SWN, WPX (1) As of December 31, 2015.

0% - > 0% - > 100%+ 2016 Average Peer Production Hedged: 43% 2017 Average Peer Production Hedged: 16% 2018 Average Peer Production Hedged: 4%

Total Production Hedged (% of Forecasted / Consensus Production)

• Antero has 3.5 Tcfe hedged at average price of

$3.79/MMBtu and $3.1 Billion mark-to-market(1)

• 94% hedged through 2018 at $3.81/MMBtu

0% - > 0% - >

Peer Group Average Production Hedged Through 2018: 20% Antero Production Hedged Through 2018: 94%

Liquid “non-E&P assets” of $5.8 Bn significantly 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 $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) $3,117 AM equity ownership(2) 2,668 Cash 10

Total $5,795 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 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

16

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.

Average NYMEX Price ($/Mcf) Average Differential ($/Mcf) Average BTU Upgrade ($/Mcf) Discount to NYMEX ($/Mcf) Gas Hedge Effect ($/Mcf) Average Realized Gas Price ($/Mcf) Average Realized Gas Premium to NYMEX ($/Mcf) Liquids Upgrade ($/Mcfe) Realized Equivalent Price ($/Mcfe) Gas Equivalent Premium to NYMEX ($/Mcfe) 3Q 2015 $2.77 $(0.62) $0.17 $(0.45) $1.67 $3.99 $1.22 ($0.16) $3.83 $1.06 4Q 2015 $2.27 $(0.31) $0.17 $(0.14) $2.27 $4.40 $2.13 ($0.12) $4.28 $2.01

$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 AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 $/Mcfe

Noncontrolling Interest of Midstream MLP EBITDA LOE Production Taxes GPT G&A EBITDAX 4-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 AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5

• 1. Includes natural gas hedges.
• 2. Source: Public data from 3Q 2015 10-Qs. Peers include Cabot Oil & Gas, CONSOL Energy, EQT Corp., RICE Energy and Southwestern.
• 3. 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.

17

REALIZATIONS – A LEADER IN REALIZATIONS & MARGINS AMONG LARGE-CAP APPALACHIAN PEERS

3Q 2015 Natural Gas Realizations(1)(2) 3Q 2015 Price Realization & EBITDAX Margin vs F&D(2)(3)

($/Mcfe)

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

3Q 2015 NYMEX = $2.77/Mcf

3Q and 4Q 2015 Natural Gas Realizations ($/Mcf)

DOM S 23% DOM S, 3% TETCO M2 7% TETCO M2 1% TCO 40% TCO 33% TCO, 21% NYMEX 10% NYMEX 10% NYMEX 10% Gulf Coast 2% Gulf Coast 28% Gulf Coast 49% Chicago 18% Chicago 28% Chicago 17% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

($/Mcf) 2015A 2016E NYMEX Strip Price(1) $2.66 $2.47 Basis Differential to NYMEX(1) $(0.53) $(0.12) BTU Upgrade(5) $0.24 $0.24 Estimated Realized Hedge Gains $1.44 $1.50 Realized Gas Price with Hedges $3.81 $4.10 Premium to NYMEX +$1.15 +$1.63 Liquids Impact +$0.29 +$0.10 Premium to NYMEX w/ Liquids +$1.44 +$1.73 Realized Gas-Equivalent Price $4.10 $4.16

REALIZATIONS – FAVORABLE PRICE INDICES

Note: Hedge volumes as of 12/31/2015.

• 1. Based on 12/31/2015 strip pricing and 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. Based on BTU content of residue sales gas.

2015 Basis(1) 2016 Basis(1) 2017 Basis(1) 2015 Hedges 2016 Hedges 2017 Hedges

Marketed % of Target Residue Gas Production +$0.02/MMBtu $(0.12)/MMBtu(2) $(1.30)/MMBtu $(0.28)/MMBtu $0.01/MMBtu $(0.43)/MMBtu(2) $(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)

99% exposure to favorable price indices 69% exposure to favorable price indices 97% 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 >99% in 2016  Improved 2016 realizations driven by Stonewall gathering pipeline which was placed in-service December 1, 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 $(0.12) 1,160,000 MMBtu/d @ $4.34/MMBtu

• Wtd. Avg.

Basis $(0.15) 1,612,500 MMBtu/d @ $3.92/MMBtu

420,000 MMBtu/d @ $4.27/MMBtu

2015A 2016E 2017E

18

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 @ $3.63/MMBtu

$(0.10)/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 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 $17.15 $25.05 $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 2016E Realized NGL C3+ Price WTI

REALIZATIONS – NGL REALIZATIONS AND PROPANE HEDGES

19

• 1. Based on 2016 NGL and WTI strip prices as of 12/31/2015.
• 2. As of 12/31/2015.

Realized NGL Prices as % of WTI(1)

54% 50% 35% 37%

($/Bbl)

NGL Marketing Propane Hedges

 Realized NGL (C3+) price was 50% of WTI in 2014 and 35% of WTI for 2015 − Including propane hedges, 2015 realizations were 42%

• f WTI

 Antero has guided to realized C3+ NGL prices of 35% to 40% of WTI for 2016 (before hedging) − Antero has hedged 30,000 Bbl/d of propane in 2016 at $0.59 per gallon  By 2017, 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(2)

Target 2016 C3+ NGL pricing

• f 37% of WTI based on

12/31/15 strip pricing

ANTERO’S FIRST WEST VIRGINIA UTICA DRY GAS WELL

20

 Antero recently drilled and completed its first dry gas Utica well in Tyler County, WV (Rymer 4HD) − 11,409 Total Vertical Depth (TVD) − 6,620’ lateral length − 100% working interest − 20 MMcf/d restricted flow rate for ~60 days  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 37.1 Tcfe of net 3P reserves as of 12/31/2015) − 1,889 locations underlying current Marcellus Shale leasehold in West Virginia and Pennsylvania  41,000 net acres in Ohio with net 3P reserves of 2.3 Tcf as of 12/31/2015 − 263 locations in Ohio  In total, Antero has 229,000 net acres and 2,152 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 Utica Dry Gas Fairway

Antero Rymer 4HD 6,620’ Lateral IP 20.0 MMcf/d

• 100

200 300 400 500 600 AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Core Net Acres - Dry Core Net Acres - Liquids Rich 200 400 600 800 1,000 1,200 1,400 1,600 1,800 EQT AR CHK COG SWN RRC CNX 2,000 4,000 6,000 8,000 10,000 12,000 14,000 AR EQT RRC COG CNX SWN CHK

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) – December 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, CHK.
• 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)

21

2nd Largest Appalachian Producer  Antero has the largest proved reserve base, 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 Largest Liquids- Rich Core Position in Appalachia 500 1,000 1,500 2,000 2,500 3,000 3,500

(5)

22

Antero Midstream (NYSE: AM) Asset Overview

• 1. Represents inception to date actuals as of 12/31/2015 and 2016 midpoint guidance.
• 2. Includes both expansion capital and maintenance capital.

23

Utica Shale Marcellus Shale

Projected Gathering and Compression Infrastructure(1)

Marcellus Shale Utica Shale Total YE 2015 Cumulative Gathering/ Compression Capex ($MM) $981 $462 $1,443 Gathering Pipelines (Miles) 182 91 273 Compression Capacity (MMcf/d) 700 120 820 Condensate Gathering Pipelines (Miles)

• 19

19 2016E Gathering/Compression Capex Budget ($MM)(2) $235 $20 $255 Gathering Pipelines (Miles) 30 1 31 Compression Capacity (MMcf/d) 240 240 Condensate Gathering Pipelines (Miles)

• Gathering and Compression Assets

ANTERO MIDSTREAM GATHERING AND COMPRESSION ASSET OVERVIEW

• Gathering and compression assets in core of rapidly

growing Marcellus and Utica Shale plays – Acreage dedication of ~438,000 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 MIDSTREAM WATER BUSINESS OVERVIEW

24

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

• 1. Represents inception to date actuals as of 12/31/2015 and 2016 midpoint guidance.
• 2. All Antero water withdrawal sites are fully permitted under long-term state regulatory permits both in WV and OH.
• 3. Includes both expansion capital and maintenance capital.
• 4. Marcellus 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. Utica 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.

 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 Projected Water Business Infrastructure(1) Marcellus Shale Utica Shale Total YE 2015 Cumulative Fresh Water Delivery Capex ($MM) $469 $62 $531 Water Pipelines (Miles) 184 75 259 Fresh Water Storage Impoundments 22 13 35 2016E Fresh Water Delivery Capex Budget ($MM)(3) $40 $10 $50 Water Pipelines (Miles) 20 9 29 Fresh Water Storage Impoundments 1

• 1

Cash Operating Margin per Well(4) $700k – $750k $775k - $825k 2016E Advanced Waste Water Treatment Budget ($MM) $130 2016E Total Water Business Budget ($MM) $180

Water Business Assets

• Fresh water delivery assets provide fresh water to support

Marcellus and Utica well completions – Year-round water supply sources: Clearwater facility, Ohio River, local rivers & reservoirs(2) – 100% fixed fee long term contracts

• Advanced wastewater capex of $130 million budgeted in 2016

10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 Antero Clearwater Advanced Wastewater Treatment Capacity (Bbl/d) Produced/Flowback Volumes (Bbl/d)

Illustrative Produced & Flowback Water Volumes Advanced Wastewater Treatment Antero Produced Water Services and Freshwater Delivery Business

Antero Advanced Wastewater Treatment

3rd Party Recycling and Well Disposal

(Bbl/d)

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

25

Integrated Water Business Antero Advanced Wastewater Treatment Freshwater delivery system Flowback and produced Water Well Pad Well Pad Completion Operations Producing

Freshwater Salt Calcium Chloride

Marketable byproduct Marketable byproduct used in oil and gas operations Freshwater delivery system

ANTERO MIDSTREAM ADVANCED WASTEWATER TREATMENT ASSET OVERVIEW

$1 $5 $7 $8 $11 $19 $28 $36 $41 $55 $0 $10 $20 $30 $40 $50 $60 26 31 40 36 41 116 222 358 454 435 478 100 200 300 400 500 600 700 800 Utica Marcellus 10 38 80 126 266 531 908 1,134 1,197 1,216 1,195 200 400 600 800 1,000 1,200 1,400 1,600 1,800 Utica Marcellus 108 216 281 331 386 531 738 935 965 1,038 1,124 200 400 600 800 1,000 1,200 1,400 1,600 1,800 Utica Marcellus

Low Pressure Gathering (MMcf/d) Compression (MMcf/d) High Pressure Gathering (MMcf/d) EBITDA ($MM)(1)

26

$313

HIGH GROWTH MIDSTREAM THROUGHPUT

Note: Y-O-Y growth based on 4Q’14 to 4Q’15.

• 1. 2016E EBITDA guidance updated per 2/17/2016 Partnership press release. Y-O-Y growth based on 3Q’14 to 3Q’15.

Downstream LNG and NGL Sales Production and Cash Flow Growth 27 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 FOR ANTERO

Guiding to 15% production growth in 2016 and targeting 20% in 2017 with ~100% hedged at $3.94/MMBtu and $3.57/MMBtu, respectively; capital budget flexibility to adapt 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 4 Utica Dry Gas Activity

28

APPENDIX

28

ANTERO RESOURCES – 2016 GUIDANCE

Key Variable 2016 Guidance

Net Daily Production (MMcfe/d) 1,715 Net Residue Natural Gas Production (MMcf/d) 1,355 Net C3+ NGL Production (Bbl/d) 46,500 Net Ethane Production (Bbl/d) 10,000 Net Oil Production (Bbl/d) 3,500 Net Liquids Production (Bbl/d) 60,000 Natural Gas Realized Price Premium to NYMEX Henry Hub Before Hedging ($/Mcf)(1)(2) +$0.00 to $0.10 Oil Realized Price Differential to NYMEX WTI Oil Before Hedging ($/Bbl) $(10.00) - $(11.00) C3+ NGL Realized Price (% of NYMEX WTI)(1) 35% - 40% Ethane Realized Price (Differential to Mont Belvieu) ($/Gal) $0.00

Operating:

Cash Production Expense ($/Mcfe)(3) $1.50 - $1.60 Marketing Expense, Net of Marketing Revenue ($/Mcfe) $0.15 - $0.20 G&A Expense ($/Mcfe) $0.20 - $0.25 Operated Wells Completed 110 Drilled Uncompleted Wells 70 Average Operated Drilling Rigs ≈ 7

Capital Expenditures ($MM):

Drilling & Completion $1,300 Land $100 Total Capital Expenditures ($MM) $1,400

• 1. Based on current strip pricing as of December 31, 2015.
• 2. Includes Btu upgrade as Antero’s processed tailgate and unprocessed dry gas production is greater than 1000 Btu on average.
• 3. Includes lease operating expenses, gathering, compression and transportation expenses and production taxes.

Key Operating & Financial Assumptions

29

ANTERO MIDSTREAM – 2016 GUIDANCE

Key Variable 2016 Guidance Financial:

Adjusted EBITDA ($MM) $300 - $325 Distributable Cash Flow ($MM) $250 - $275 Year-over-Year Distribution Growth(1) 28% - 30%

Operating:

Low Pressure Pipeline Added (Miles) 9 High Pressure Pipeline Added (Miles) 22 Compression Capacity Added (MMcf/d) 240 Fresh Water Pipeline Added (Miles) 30

Capital Expenditures ($MM):

Gathering and Compression Infrastructure $240 Fresh Water Infrastructure $40 Advanced Wastewater Treatment $130 Maintenance Capital $25 Total Capital Expenditures ($MM) $435

• 1. Reflects the expected distribution growth percentage associated with the fourth quarter 2016 over the fourth quarter 2015.

Key Operating & Financial Assumptions

30

500 1,000 1,500 2,000 2,500 3,000 3,500 4,000

2016 FT Portfolio and Projected Gas Sales Net Production Target (MMcfe/d) (1) 1,715 Net Gas Production Target (MMcf/d) (80% of Net Production) 1,372 Net Revenue Interest Gross-up 80% Gross Gas Production Target (MMcf/d) 1,715 BTU Upgrade (2) x1.100 Gross Gas Production Target (BBtu/d) 1,885 Firm Transportation / Firm Sales (BBtu/d) 3,525 Estimated % Utilization of FT/FS 53% Excess Firm Transportation 1,640 Marketable Firm Transport (BBtu/d) (3) 1,015 Unmarketable Firm Transportation 625 Estimated % Utilization of FT/FS Portfolio (Including Marketable FT) 82%

ANTERO FT PORTFOLIO APPROPRIATELY DESIGNED TO ACCOMMODATE GROWTH

31

• 1. Represents 2016 forecasted net daily production.
• 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 1,640 BBtu/d in 2016

• Expects to market or mitigate the cost of

approximately 1,015 BBtu/d of the excess FT with 3rd party gas

• Expect to fully utilize FT portfolio by 2019, based on

five year development plan (excludes Appalachia based FT directed to unfavorable indices)

(BBtu/d) 2016 Targeted Gross Gas Production(1) 1,885 BBtu/d Unmarketable Unutilized Firm Transport ~625 BBtu/d ($0.15 / MMBtu) Marketable Unutilized Firm Transport ~1,015 BBtu/d ($0.39 / MMBtu) Utilized Firm Transport / Firm Sales ~1,885 BBtu/d ($0.45 / MMBtu) Total Firm Transport 3,525 BBtu/d

Excess Capacity Marketable / FT Segment (Location) (BBtu/d) Unmarketable Columbia / TGP (Marcellus) 550 Marketable ANR North / ANR South (Utica) 465 Marketable EQT / M3 (Marcellus) 625 Unmarketable Total Excess Firm Transport 1,640

2016 Firm Transport

Decreasing Cost of FT

($ in millions, except per unit amounts)

Demand 2016E 2016E 2016E Fee Marketing Marketing Marketing ($ / MMBtu) Expenses Revenue Expenses, Net "Unmarketable" Firm Transport 625 BBtu/d of EQT / M3 Appalachia FT $0.15 $35

• $35

"Marketable" Firm Transport Capacity 550 BBtu/d of Columbia / TGP $0.49 $99 $43 - $72 $27 - $56 465 BBtu/d of ANR North / ANR South $0.24 42 $6 - $11 $31 - $36 Sub-Total $141 $49 - $83 $58 - $92 Grand Total - 2016 Marketing Expenses, Net $176 $49 - $83 ~$95 to $125 MM $ / Mcfe - 2016 Targeted Production (1) $0.28 $0.08 - $0.13 $0.15 - $0.20

FT PORTFOLIO UPDATE

32

NOTE: Analysis based on strip pricing as of 12/31/15. 1. Represents 2016 production growth guidance of 15% to 1,715 MMcfe/d. 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:

600 1,200 1,800 2,400 3,000 3,600 (BBtu/d) 2016 Targeted Gross Gas Production 1,885 BBtu/d $0.06 / Mcfe of 2016E Production (2) $0.09 to $0.14 / Mcfe of 2016E Production (2) Utilized FT $0.45 / Mcfe of 2016E Production (2)

2016 FT and Marketing Expenses per Unit: 2016 Marketing Revenue Projection:

Based on the 2016 guidance of 15% annual production growth, Antero projects net marketing expenses of $0.15 to $0.20 per Mcfe in 2016

Gathering & Transportation Costs Marketable Net Marketing Expense Unmarketable Net Marketing Expense

Unmarketable (EQT / M3) ($/MMBtu) 2016 TETCO M2 Pricing (Sold Gas) $1.56 2016 TETCO M2 Pricing (Bought Gas) (1.56) Total Spread $0.00 Marketable (TCO / TGP) ($/MMBtu) 2016 TGP-500 Pricing (Sold Gas) $2.43 2016 TETCO M2 Pricing (Bought Gas) (1.56) Less: Variable FT Costs (0.15) Total Spread ("In the Money") $0.72

Illustrative Marketing Example:

Positive Spread No Spread

2016E Marketing 2016E Marketing Revenue Spread Assuming % Volume Mitigated ($ / MMBtu) (2) 30% 50% "Marketable" Firm Transport Capacity 550 BBtu/d of Columbia / TGP $0.72 $43 $72 465 BBtu/d of ANR North / ANR South $0.12 6 11 Sub-Total $49 $83 $ / Mcfe - 2016E Targeted Production (1) $0.08 $0.13

($ in millions) 9/30/2015 Cash $27 Senior Secured Revolving Credit Facility 500 Midstream Bank Credit Facility 525 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 Net Unamortized Premium 7 Total Debt $4,407 Net Debt $4,380 Financial & Operating Statistics LTM EBITDAX(1) $1,246 LTM Interest Expense(2) $219 Proved Reserves (Bcfe) (12/31/2015) 13,215 Proved Developed Reserves (Bcfe) (12/31/2015) 5,838 Credit Statistics Net Debt / LTM EBITDAX 3.5x Net Debt / Net Book Capitalization 38% Net Debt / Proved Developed Reserves ($/Mcfe) $0.75 Net Debt / Proved Reserves ($/Mcfe) $0.33 Liquidity Credit Facility Commitments(3) $5,500 Less: 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.

33

626 971 553 755

63% 47% 24% 28%

34% 22% 9% 11% 200 400 600 800 1,000 1,200 0% 20% 40% 60% 80%

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

ROR

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

MARCELLUS SINGLE WELL ECONOMICS – IN ETHANE REJECTION

34

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)

Classification Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Modeled BTU 1313 1250 1150 1050 EUR (Bcfe): 20.8 18.8 16.8 15.3 EUR (MMBoe): 3.5 3.1 2.8 2.6 % Liquids: 33% 24% 12% 0% Lateral Length (ft): 9,000 9,000 9,000 9,000 Well Cost ($MM): $9.1 $9.1 $9.1 $9.1 Bcfe/1,000’: 2.3 2.1 1.9 1.7 Net F&D ($/Mcfe): $0.52 $0.57 $0.64 $0.70 Direct Operating Expense ($/well/month): $1,498 $1,498 $1,498 $1,498 Direct Operating Expense ($/Mcf): $0.92 $0.92 $1.17 $0.70 Transportation Expense ($/Mcf): $0.28 $0.28 $0.28 $0.28 Pre-Tax NPV10 ($MM): $8.9 $5.1 ($0.7) $0.2 Pre-Tax ROR: 34% 22% 9% 11% Payout (Years): 2.0 2.8 6.5 5.5 Gross 3P Locations(3): 626 971 553 755

• 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, 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 12/31/2015.

2016 Drilling Plan

184 98 108 161 263

16% 57% 83% 71% 80%

10% 27% 29% 23% 26% 50 100 150 200 250 300 0% 20% 40% 60% 80% 100%

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

ROR

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

UTICA SINGLE WELL ECONOMICS – IN ETHANE REJECTION

35

DRY GAS LOCATIONS RICH GAS LOCATIONS HIGHLY RICH GAS LOCATIONS

Utica Well Economics and Gross Locations(1)

Classification Condensate Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Modeled BTU 1275 1235 1215 1175 1050 EUR (Bcfe): 9.4 17.0 25.3 23.8 21.4 EUR (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 9,000 Well Cost ($MM): $10.2 $10.2 $10.2 $10.2 $10.2 Bcfe/1,000’: 1.0 1.9 2.8 2.7 2.4 Net F&D ($/Mcfe): $1.34 $0.74 $0.50 $0.53 $0.59 Fixed Operating Expense ($/well/month): $2,788 $2,788 $2,788 $2,788 $1,498 Direct Operating Expense ($/Mcf): $0.99 $0.99 $0.99 $0.99 $0.50 Direct Operating Expense ($/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 $6.4 Pre-Tax ROR: 10% 27% 29% 23% 26% Payout (Years): 7.8 3.1 2.9 3.7 3.2 Gross 3P Locations(3): 184 98 108 161 263

• 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, 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 12/31/2015. 3P locations representative of BTU regime; EUR and economics within regime will vary based on BTU content.

2016 Drilling 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

OUTSTANDING RESERVE GROWTH

• 1. 2012, 2013, 2014 and 2015 reserves assuming ethane rejection. 2015 SEC prices were $2.56/MMBtu for natural gas and $50.13/Bbl for oil on a weighted average Appalachian index basis.

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3P RESERVES BY VOLUME – 2015(1) 3P RESERVE GROWTH(1)

25.0 28.4 29.6 5.8 7.6 7.5

4.2 4.6

5 10 15 20 25 30 35 40 45 2013 2014 2015 (Tcfe)

Marcellus Utica Upper Devonian

NET PROVED RESERVES (Tcfe)(1) 2015 RESERVE ADDITIONS

35.0 40.7

• Proved reserves increased 4% to 13.2 Tcfe at 12/31/2015 with a pre-tax

PV-10 of $6.7 billion at SEC pricing, including $3.1 billion of hedges − Proved PV-10 at strip pricing of $8.2 billion, including $2.5 billion of hedges

• 3P reserves were 37.1 Tcfe at 12/31/2015 with a pre-tax PV-10 of $6.8

billion at SEC pricing, including $3.1 billion of hedges − 3P PV-10 at strip pricing of $13.7 billion, including $2.5 billion of hedges

• All-in finding and development cost of $0.80/Mcfe for 2015 (includes land

and all price and performance revisions)

• Drill bit only development cost of $0.71/Mcfe for 2015
• Only 69% of 3P Marcellus locations booked as SSL (1.7 Bcf/1,000’ type

curve) at 12/31/2015

• Negligible Utica Shale WV/PA dry gas reserves booked – estimated

net resource of 12.5 – 16 Tcf

0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0 2010 2011 2012 2013 2014 2015

Marcellus Utica

0.7 2.8 4.3 7.6 12.7 (Tcfe) 13.2 37.1 13.2 Tcfe Proved 21.4 Tcfe Probable 2.5 Tcfe Possible Proved Probable Possible

37.1 Tcfe 3P 93% 2P Reserves

Gas – 27.6 Tcf Oil – 92 MMBbls NGLs – 2,382 MMBbls Gas – 29.7 Tcf Oil – 92 MMBbls NGLs – 1,145 MMBbls

CONSIDERABLE RESERVE BASE WITH ETHANE OPTIONALITY

 27 year proved reserve life based on 2015 production annualized  Reserve base provides significant exposure to liquids-rich projects – 3P reserves of over 2.4 BBbl of NGLs and condensate in ethane recovery mode; 35% 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.

• 2. 1.1 Tcfe of ethane reserves (182 million barrels) was included in 12/31/2015 reserves from the Marcellus Shale as the first de-ethanizer was placed online at the MarkWest Sherwood facility in December

2015 and Antero’s first ethane sales contract is expected to commence in 2017 upon the completion of Mariner East 2.

ETHANE REJECTION(1)(2) ETHANE RECOVERY(1)

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Marcellus – 29.6 Tcfe Utica – 7.5 Tcfe Upper Devonian – 0.0 Tcfe

37.1 Tcfe

Marcellus – 34.0 Tcfe Utica – 8.4 Tcfe Upper Devonian – 0.0 Tcfe

42.4 Tcfe 20% Liquids 35% Liquids

Moody's S&P

POSITIVE RATINGS MOMENTUM

Moody’s / S&P Historical Corporate Credit Ratings

“Outlook Stable. The affirmation reflects our view that Antero will maintain funds from operations (FFO)/Debt above 20% in 2016, as it continues to invest and grow production in the Marcellus Shale. The company has very good hedges in place, which will limit exposure to commodity prices.”

• S&P Credit Research, February 2016

“Moody’s confirmed Antero Resources’ rating, which reflects its strong hedge book through 2018 and good liquidity. Antero has $3.1 billion in unrealized hedge gains, $3 billion of availability under its $4 billion committed revolving credit facility and a 67% interest in Antero Midstream Partners LP.

• Moody’s Credit Research, February 2016

Corporate Credit Rating (Moody’s / S&P) Ba3 / BB- B1 / B+ B2 / B B3 / B- 2/24/2011 10/21/2013 9/4/2014 5/31/13 Ba2 / BB Ba1 / BB+ Caa1 / CCC+

(1)

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

Baa3 / BBB-

Moody’s Rating Rationale S&P Rating Rationale

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3/31/2015

Ba2/BB

2/12/2016 9/1/2010

Ratings Affirmed February 2016

 Antero’s corporate credit ratings were recently affirmed at Ba2/BB by Moody’s and S&P, respectively, despite the severe commodity price down cycle

Europe

Mariner East I I

Shipping $0.25/ Gal

NGL EXPORTS AND NETBACKS STEP-UP BY 2017

• 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) based

• n current product pricing

Pricing Propane: $0.39/Gal N-Butane: $0.56/Gal

Pricing Propane: $0.56/Gal N-Butane: $0.76/Gal

Mariner East II 61,500 Bbl/d AR Commitment (see table below) (3) 4Q 2016 In-Service

Shipping Propane: $0.07/Gal N-Butane: $0.08/Gal AR Mariner East II Commitment (Bbl/d) Product Base Option (3) Total Ethane (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

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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 $0.49 Upside to Appalachia Netback: $0.16 $0.18

$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 $274 ($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 $280.0

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

40

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 Guidance Hedged

40

• 1. Weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio; excludes impact of TCO basis hedges. 30,000 Bbl/d of propane hedged in 2016, 35,500 Bbl/d hedged in 2017

and 2,000 Bbl/d hedged in 2018.

• 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

~ 100% of 2017 Target Hedged

$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 Millions) $1,500 $993 ($525) $0 $18 $0 $250 $500 $750 $1,000 $1,250 $1,500

Credit Facility 9/30/2015 Bank Debt 9/30/2015 L/Cs Outstanding 9/30/2015 Cash 9/30/2015 Liquidity 9/30/2015

41

STRONG FINANCIAL LIQUIDITY AND DEBT TERM STRUCTURE

41

$4,000 $2,975 ($500) ($535) $10 $0 $1,000 $2,000 $3,000 $4,000

Credit Facility 9/30/2015 Bank Debt 9/30/2015 L/Cs Outstanding 9/30/2015 Cash 9/30/2015 Liquidity 9/30/2015

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

ANTERO RESOURCES EBITDAX RECONCILIATION

42

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

ANTERO MIDSTREAM EBITDA RECONCILIATION

43

EBITDA Reconciliation

Three months ended September 30, 2014 2015 Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow: Net income $ 34,290 $ 42,648 Add: Interest expense 2,455 2,044 Less: 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 $ 36,081 Add: 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 1,079 Pre-water acquisition interest expense attributed to parent 522 770 Amortization of deferred financing costs attributed to parent — 285 Less: 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, 2015 included in this presentation have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates as of December 31, 2015 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, 2015. 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

44