Howard Weil 47 th Annual Energy Conference MARCH 25, 2019 Legal - - PowerPoint PPT Presentation

Howard Weil 47th Annual Energy Conference

MARCH 25, 2019

Legal Disclaimer

This presentation includes “forward-looking statements.” Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond AR’s control. All statements, except for statements of historical fact, made in this presentation regarding activities, events or developments AR expects, believes or anticipates will or may occur in the future, such as 2019 and long-term financial and operational outlook, impacts of hedge monetizations, impacts of natural gas price realizations, AR’s expected ability to return capital to investors and targeted leverage metrics, AR’s estimated unhedged EBITDAX multiples, future plans for processing plants and fractionators and AR’s estimated production, are 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 forward-looking statements speak only as of the date of this presentation. Although AR believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. AR 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 AR’s control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability

• f 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 "Item 1A. Risk Factors" in AR’s Annual Report on Form 10-K for the year ended December 31, 2018. This presentation includes certain financial measures that are not calculated in accordance with U.S. generally accepted accounting principles (“GAAP”). These measures include (i) Adjusted EBITDAX, (ii) Free Cash Flow, (iii) Net Debt, (iv) Distributable Cash Flow, (v) Adjusted EBITDA and (vi) E&P Adjusted EBITDAX Margins. Please see “Antero Non-GAAP Measures” for the definition of each of these measures as well as certain additional information regarding these measures, including the most comparable financial measures calculated in accordance with GAAP.

Antero Resources Corporation is denoted as “AR” in the presentation and Antero Midstream Corporation is denoted as “AM” or “New AM”

2

The Size and Scale to Capitalize on the Resource

3 Market Cap……….……........... Enterprise Value(1)….………… Corporate Debt Ratings……… Leverage(2) ….......................... 2019 Net Production Guidance Liquids................................ Proved Reserves…..…........... % Liquids(3)......................... Net Acres………….…...……… Core Drilling Locations……….. AR Midstream Ownership (31%) $2.9B $6.4B Ba2 / BB+ / BBB- 2.1x 3.15 - 3.25 Bcfe/d 154 -164 MBbl/d 18.0 Tcfe 37% 612,000 3,013 $2.2B

Note: Equity market data as of 3/19/19. Reserves as of 12/31/2018. See 2019 Guidance page for production guidance details. (1) Includes ownership of $2.2 billion of Antero Midstream units. (2) Leverage is pro forma net debt (pro forma for cash received in midstream simplification) divided by LTM Adjusted EBITDAX as of 12/31/18. See appendix for details. (3) Proved reserves contain 46 MMBbls of condensate, 498 MMBbls of C3+ NGLs and 554 MMBbls of ethane. Assumes approximately 415 MMBbls of additional ethane are rejected and left in the natural gas stream.

Antero Resources Profile

Antero Acreage SW Marcellus Core Ohio Utica Core

Key Investment Points

These materials are not to be printed, downloaded or distributed. These materials are only available to QIBs and non-US persons.

4

Closed Midstream Simplification Highly economic liquids-rich drilling inventory Realizing premium natural gas and NGL pricing Appalachia-leading EBITDAX margins for 6 years straight Investing within cash flow in 2019 (1) Run by Co-founders – 9% management

• wnership

Deconsolidated Antero Midstream and converted to C-corp Shareholders aligned Upstream transparency & independent board at AM Result of integrated midstream, FT, hedging and liquids-rich development strategy Entire FT portfolio for gas and ME2 for NGLs now in service Strong balance sheet with scale: 2.1x leverage on $1.7 B of LTM EBITDAX Recent Company buybacks and insider share purchase activity Top 20 midstream vehicle with highest DCF growth and lowest leverage A Catalyst for Multiple Expansion

Note: See appendix for Non-GAAP items and reconciliation. Leverage is net debt/LTM Adjusted EBITDAX and is pro forma for midstream simplification transaction. See appendix. 1) AR’s total capital expenditures expected to be at or less than Cash Flow From Operations.

1 2 3 4 5 6 8

Retained 31% interest in Antero Midstream C-corp

7 ~1,300 locations with 25% ROR breakeven prices <$2.05 NYMEX

Repositioned With Simplified Structure

Simplified Structure

9% 82% 31%

Midstream simplification transaction results in ownership of one publicly traded midstream entity with all midstream investors owning the same security

Public Management

5

508 MM shares

NYSE: AR NYSE: AM

Original Private Equity Investors 9% Management 10%

309 MM shares

Original Private Equity Investors 14% Public 45%

Simplification Transaction Closed

• No IDRs
• No MLP
• C-corp governance
• Majority of independent directors at AM
• AR retains significant stake in midstream

Shareholder-Friendly Initiatives Improve Transparency

• Announced deconsolidation of Antero Midstream from Antero Resources financial

statements going forward

• New AM is independently funded with its own $2 billion credit facility and ready access to

capital markets: AM 2027 Senior Notes yielding 5.45% (Ba2/BB+/BBB-) YE 2018 Pro Forma Net Debt / LTM EBITDAX 2019 Cash Flow Enterprise Value / 2019E EBITDAX

Benefits From Financial Statement Deconsolidation

6

Note: See appendix for Non-GAAP items and reconciliation. Peers include CNX, COG, EQT, RRC & SWN. Peer data and AR 2019E EBITDAX represents Bloomberg consensus estimates. Enterprise value as of 3/19/2019. 1) Total capital expenditures expected to be at or less than cash flow from operations.

Previous View of Antero Consolidated… New View of Antero Deconsolidated… $5.8 Bn $3.5 Bn $2,037 MM $1,717 MM 2.8x 2.1x Cash Flow Deficit Due to Midstream Capital Needs Investing within Cash Flow (1) 4.2x (Peers: 4.5x) 2.9x YE 2018 Net Debt LTM EBITDAX

Leading NGL Position & Integrated Strategy Drive Peer-Leading Margins

Prolific Underlying Resource Underpins Growth

8

Antero Resources holds 40% of the core undrilled liquids-rich locations in Appalachia with attractive economics and low breakeven prices

Peers include Ascent, CNX, COG, CVX, Encino, EQT, GPOR, HG, RRC and SWN. Based on Antero analysis of undeveloped acreage in the core of the Marcellus and Ohio Utica Shales. Rigs as of 3/8/19. Locations as of 12/31/18.

Core Liquids-Rich Appalachian Undrilled Locations(1) AR ~40%

A 15% C 13% K 7% D 3% I 8% B 5% H 5% F 3% J 2% 2,043 Locations

Largest NGL Producer and the 4th Largest Gas Producer

Top U.S. Natural Gas Producers – 4Q18 Top U.S. C2+ NGL Producers - 2019E(1)

Antero is the largest NGL producer in the U.S. and has the most exposure to NGL prices among the top producers

150 29% 13% 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 50 70 90 110 130 150

Most exposure to NGL prices

1) Antero C2+ NGL production represents the midpoint of 2019 guidance. Peer C2+ NGL production represents consensus as of 3/12/2019. Percentage of pre-hedge commodity revenues based on 4Q 2018 actuals.

9

Peer Avg. Pre-Hedge NGL % of Product Revenue (MBbls/d) 2,240 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 (MMcf/d)

4th largest gas producer

in the U.S.

4,562 2,901 5,169

• 1,000

2,000 3,000 4,000 5,000 6,000

2014 2015 2016 2017 2018 RECORD

Lateral Feet Marcellus Utica 10,107 15,075 11,412 17,445

• 2,000

4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000

2014 2015 2016 2017 2018 RECORD

Lateral Feet Marcellus Utica 4.6 5.2 9.0 3.6 4.9 10.0

• 1.0

2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0

2014 2015 2016 2017 2018 RECORD

Stages per Day Marcellus Utica

10

Drilling and Completion Efficiencies Continue

Average Lateral Feet Drilled per Day Drilling Days Average Lateral Length per Well Completion Stages per Day

8,206

Note: Percentage increase and decrease arrows represent change in Marcellus data from 2014 to 2018.

12 8 18 10 5 10 15 20 25 30 35

2014 2015 2016 2017 2018 RECORD

Drilling Days Marcellus Utica

$1.15 $2.03 $2.05 $2.27 $2.43 $2.58 $2.64 $2.72 $2.84 $2.93 $3.07 $3.18 $3.32 $3.40 $3.96 $3.98 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50

Marcellus Highly-Rich Gas/Cond. (1313 Btu) Marcellus Highly Rich- Gas (1250 Btu) Utica Highly- Rich Gas/Cond. (1235 Btu) Utica Condensate (1275 Btu) Marcellus Shale - NE PA - Dry Utica Dry Gas (1050 Btu) Utica Highly- Rich Gas (1215 Btu) Utica Rich Gas (1175 Btu) Marcellus Rich Gas (1150 Btu) Marcellus Dry Gas (1050 Btu) Marcellus Shale - SW PA - Dry Haynesville - N LA Core - Long Laterals Marcellus Shale - WV Dry Utica Shale - Dry Gas Ohio Eagle Ford - Dry Gas Haynesville - N LA Core - Standard Laterals

Many Years of Capital Efficient Development

11

JP Morgan Equity Research breakeven analysis for best industry dry gas drilling locations. Excludes associated gas inventory with >50% liquids. Breakeven analysis for AR prepared by management based on same parameters as J.P. Morgan Equity Research calculation with the exception of the WTI oil price, Antero used strip WTI. Antero drilling inventory as of 12/31/18. 1) Breakeven price is defined as half cycle pre-tax ROR of 25%. Assumes average strip WTI oil price of $55.25/Bbl as of 3/1/2019. 2) Antero half cycle well economics assume 12,000’ lateral lengths and 69% of AM fees paid by AR to AM to account for AR’s midstream dividend stream from AM (based on 31% pro forma ownership of New AM). 3) 2020-2023 average NYMEX Henry Hub price as of 3/1/19.

• Low breakeven gas price drilling inventory and integrated marketing strategy

yields resilient development plan

• Much of AR’s drilling inventory is in effect, “associated gas”

Industry Dry Gas Locations

$2.69 (2020-2023 Strip) (3)

Antero and Industry Best Gas Drilling Locations – 25% ROR Half Cycle Breakeven Prices(1)(2)

59 1,175 59 281 38 67 43 360 1,017 Undrilled Locations

1,679 premium drilling locations: 25% ROR breakeven < $2.69/MMBtu

Antero Locations AR AR AR AR AR AR AR AR AR

(Susquehanna County)

Antero Drilling Rigs

Resilient and Flexible Development Plan

12

Lower Prices Higher Prices Lower Prices: $50 Oil / $2.85 Gas

• 10% Production CAGR (2019-2023)
• <2x leverage by 2022
• Free Cash Flow neutral
• 100% hedged on 2019 production

guidance and 55%-60% hedged on 2020 outlook

Antero’s flexible development program through 2023 will be responsive to commodity prices to grow production and maximize free cash flow

Higher Prices: $65 Oil / $3.15 Gas

• 15% Production CAGR (2019-2023)
• <1x leverage by 2021
• $2.5 - $3.0 Bn of Free Cash Flow (1)
• Appropriate mix of return of capital

and balance sheet deleveraging Maintain balance sheet strength Disciplined growth with expanding margins Likely outcome is somewhere in between

1) Free cash flow is defined as cash flow from operations after working capital changes less total capital spending including land. See appendix for additional Non-GAAP information.

10% Production CAGR

13

Long-Term Outlook

1,000 2,000 3,000 4,000 5,000 6,000 2019 Guidance 2020E 2021E 2022E 2023E Production (MMcfe/d) <2x Leverage by 2022

• r Sooner

Free Cash Flow Neutral

$50 / $2.85

15% Production CAGR <1x Leverage by 2021 $2.5 - $3.0 Bn Free Cash Flow $65 / $3.15

Note: Production CAGR ranges apply to midpoint of 2019 production guidance. 1) Free cash flow is defined as cash flow from operations after working capital changes less total capital spending including land. See appendix for additional Non-GAAP information.

Antero is poised to prudently grow production to maximize free cash flow, ultimately resulting in an appropriate mix of further delevering and return of capital

Production Growth Scenarios (2020 – 2023)

$2.5 - $3.0 Bn Free Cash Flow Generation (1) Oil and Gas Price Assumptions

Attractive NGL Marketing and Pricing

31

Mont Belvieu Conway

International Markets Domestic Markets

Note: 2020 blend of 65% international / 35% domestic assumes ME2 is fully in service with 275,000 Bbl/d of capacity. 1) Strip prices as of 12/31/18, reflecting 2019 guidance assumptions. Antero C3+ NGL component barrel consists of 56% C3 (propane), 10% isobutane (Ic4), 17% normal butane (Nc4) and 17% natural gasoline (C5+).

Antero has diversified NGL pricing exposure in 2019 via ME2 to international markets and rail and truck to domestic markets

Diversified exposure results in Antero realizing a C3+ NGL sales price effectively in line with Mont Belvieu pricing 14

Sold Internationally at a $0.05/gal to $0.10/gal premium to Mont Belvieu Sold Domestically at a $0.10/gal to $0.15/gal discount to Mont Belvieu

Antero 2019 C3+ NGL Pricing Guidance (1)

Domestic International Combined Sales Point Hopedale Marcus Hook Blended % of AR 2019 C3+ Volume 50% 50% 100% Expected Premium / (Discount) to Mont Belvieu ($/Gal) ($0.10) – ($0.15) $0.05 - $0.10 ($0.05) - $0.00 Realized C3+ Price ($/Gallon) $0.56 – $0.61 $0.76 – $0.81 $0.66 – $0.71 Realized C3+ NGL Price ($/Bbl) ~$28 – $30 NYMEX WTI Price ($/Bbl) $47 % of WTI ~60% to 65%

2019

• f

Firm Transportation Portfolio is a Strategic Advantage

15

1,000 2,000 3,000 4,000 5,000 1/1/16 1/1/17 1/1/18 1/1/19 1/1/20 1/1/21 1/1/22 1/1/23

Appalachia (M2/Dom S.): 625 MMBtu/d

Premium Markets Regional markets and lowest transport cost ($32 MM/year)

AR’s Firm Transport expected to be filled by 2022 (excluding regional)

Note: 2019 expected premium to NYMEX and net marketing expense based on previously disclosed guidance. 1) Realized hedge gain per produced Mcfe ranges (where applicable) for 2019-2021 are based on $2.85/MMBtu NYMEX price assumption. Production assumes 10% to 15% annual production growth outlook. 2) Unutilized firm transport cost, including historical mitigation, divided into estimated average net production. No mitigation assumed for 2019 and beyond.

Total 4.7 Bcf/d

(MMBtu/d)

3) 2019 natural gas volume assumes midpoint of 2019 guidance and has been grossed up for 84% average net revenue interest and an 1100 BTU factor. 2020 and beyond assume 10% or 15% year-over-year growth thereafter. 4) Premium unutilized capacity excludes regional capacity. 2019 range based on 2019 gas production guidance range.

Net Marketing Expense ($/Mcfe):(2)

($0.175) – ($0.225) ($0.13) – ($0.18)

2019E 2020E 2021E

($0.05) – ($0.10)

2016A 2017A 2018A

($0.13) ($0.16) ($0.16)

Premium Unutilized Capacity (BBtu/d)(4)

450 730 800 1,075 – 1,125 650 – 800 150 – 475 Premium gas pricing plus realized hedge profits more than offset the cost of carrying excess transportation capacity until production fills

Realized Hedge Gains ($/Mcfe):(1)

$0.24 $0.06 $0.02 - $0.03 $1.48 $0.26 $0.25

All of AR’s contracted firm transport (FT) projects are now in service

• Antero’s FT portfolio has delivered Appalachia-

leading realized pricing quarter after quarter

• Unutilized transport cost is manageable, can be

reconfigured and is virtually eliminated by 2022

2016 2017 2018 2019 2020 2021 2022 2023

Hedge Position Supports Operating Plan Including FT

16 Antero Hedge Profile

In order to support its FT commitments, AR has consistently executed the most comprehensive commodity hedging program in the industry

30% Swap s 30% Swap s 30% Swap s

1,149 2,330 1,418 710 850 90 $3.48 $3.00 $3.00 $3.00 $2.91 $3.00 $2.76 $2.63 $2.64 $2.71 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 500 1,000 1,500 2,000 2,500 2019 2020 2021 2022 2023 NYMEX Collar Volume NYMEX Swap Volume NYMEX Swap Price NYMEX Strip Price

1) Based on 3/1/2019 strip pricing. 2) Mark-to-market as of 12/31/18.

$2.50 Floor (MMcf/d) ($/MMBtu) $3.38 Ceiling

Swap at $3.48/ MMbtu Swap at $3.00/ MMbtu Swap at $3.00/ MMbtu Swap at $3.00/ MMbtu Collar

(1)

$607 MM mark-to-market (2)

Hedges Strip

Firm commitment fees are expected to be offset by gas and liquids price uplift enabled by the FT plus proceeds from hedges put in place to support the FT

2019 FT Benefits Outweigh Costs

17

$211 MM $624 MM $240 MM $1,075 $0 $200 $400 $600 $800 $1,000 $1,200 2019 Total Cost Liquids Utilized Gas Unutilized

Note: Firm transportation expenses and benefits are gross for working interest and royalty interest owners. 1) Based on strip pricing as of 3/1/19. Hedges were primarily entered into at the time the firm transportation portfolio was constructed in order to protect the long-term commitment associated with firm transportation. 2) Represents midpoint of Antero’s 2019 realized natural gas pricing guidance ($0.175/Mcf premium to NYMEX) compared to the average Tetco M2 and Dominion South Indices through 2023 ($0.50/Mcf negative differential). 3) Represents $0.07/ gal benefit on the 50 MBbl/d of propane and butane shipped on ME2 and expected to be sold at Marcus Hook at a premium to Mont Belvieu. The benefit is the difference between the realized price relative to Mont Belvieu expected in 2019 (net of ME2 costs) compared to the realized price relative to Mont Belvieu in 2018 (without ME2 in-service).

Midpoint of 2019 Guidance

Liquids GP&T Gas GP&T Net Marketing Expense

Excerpt from 2018 10-K (Page F-31)

Natural gas and NGL firm transportation commitment fees

($MMs)

2019 Firm Transportation Benefits (Gross)

$265 MM $660 MM $200 MM 2019 Total Benefits $1,125 $0.68/Mcf uplift on Antero gas sales versus regional pricing (2) $0.07/Gal Uplift on ME2 Volume (3) Expected 2019 Hedge Realizations (1)

Net Benefit of $50 MM

Fully Utilized Transport Unutilized Transport

2019 Firm Transportation Costs (Gross)

Peer-leading EBITDAX Margins for Six Years

18

Forward-thinking business strategy including liquids-rich focus, transportation capacity to premium markets and forward sales (hedging) has resulted in peer- leading realized prices and margins for 6 straight years – “multiple ways to win”

All-in Pricing Realizations ($/Mcfe) E&P Adjusted EBITDAX Margins ($/Mcfe)

$5.17 $5.10 $4.09 $4.08 $3.61 $3.94 $2.90 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 2013 2014 2015 2016 2017 2018 AR Peer Average NYMEX Henry Hub Gas $3.36 $2.96 $2.07 $2.06 $1.61 $1.74 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 2013 2014 2015 2016 2017 2018 AR Peer Average

Source: SEC filings and press releases. Peers include: CNX, COG, EQT, RRC & SWN. E&P Adjusted EBITDAX margin is a non-GAAP measure. See appendix for detailed definitions and reconciliations.

+36% vs. Peer Avg. from 2013 - 2018 +27% vs. Peer Avg. from 2013 - 2018

EBITDAX burdened with both utilized and unutilized transportation expense

1.0x 1.8x 2.1x 2.3x 2.3x 3.1x 0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x 3.5x

COG SWN AR CNX EQT RRC

Strong Balance Sheet and Scale

19

Antero has the balance sheet and cash flow scale to actively develop its low cost, liquids-rich inventory while delevering and returning capital to shareholders

Note: Adjusted EBITDAX and net debt are non-GAAP measures. See appendix for definitions and reconciliations. Year-end net debt from company filings and press releases. Moody’s, S&P and Fitch ratings are sourced from Bloomberg. Year-end net debt from company filings and press releases. AR historical leverage and EBITDAX reconciliations included in respective reporting period earnings releases. Senior notes yield as of 3/22/19. 1) Pro forma for $297 million in proceeds from Midstream simplification transaction which closed on 3/12/2019. 2) 2018 EBITDAX via company press releases and filings. SWN EBITDAX excludes contribution from Fayetteville assets.

Year-end 2018 Net Debt / LTM Adj. EBITDAX

Appalachian Peers

NR Ba2/ BB/ BB B1/ BB-/ NR Baa3/ BBB-/ BBB- Ba2/ BB+/ NR Ba2/ BB+/ BBB-

Bond market values financial strength: AR 2025 Senior Notes trading at 5.30% yield

Appalachian Peer 2018 EBITDAX ($MM) (2)

$1,717 $0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 EQT AR COG RRC SWN CNX

(1)

20

Premier Integrated Appalachian Midstream Assets Premier Northeast Infrastructure Platform

Antero Clearwater Facility

Midstream Driving Value for AR Since Inception

21

Takeaway assurance and reliable project execution

AM Infrastructure Buildout Midstream Ownership Benefits

Never missed a completion date with fresh water delivery system Unparalleled downstream visibility Attractive return on investment (4.3x ROI for AR to date)(1) Just-in-time capital investment

Antero Clearwater Facility Processing Facility Current Infrastructure Future Infrastructure

Owning and controlling the infrastructure has been critical to sustainable development; Antero Midstream provides a customized midstream solution

3rd Party Area

• f Dedication

1) Assuming 3/19/19 share price for AR’s 31% stake in AM.

Long Track Record Of Success

22

Distributable Cash Flow(1): $53 MM $680 MM - $730 MM $67 MM $870 MM - $920 MM Adjusted EBITDA(1): +1,201% +1,235%

$0.37 $0.43 $0.56 $0.72 $0.94 $1.24 0.4x 0.6x 0.8x 1.0x 1.2x 1.4x 1.6x 1.8x 2.0x $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $1.20 $1.40 4Q' 14 Annualized 2015A 2016A 2017A 2018A 2019 Guidance (Midpoint) Dividends Per Share DCF Coverage

AM Dividend Per Share and DCF Coverage Since IPO IPO Year - 2014 2019 Guidance

1) Adjusted EBITDA and Distributable Cash Flow are non-GAAP measures. For additional information regarding these measures, please see “Antero Midstream Non-GAAP Measures” in the Appendix. 2) Historical dividends adjusted for recently closed simplification transaction. 3) Based on share price as of 03/22/2019.

Antero Midstream has delivered a 27% dividend CAGR through the downturn and exceeded DCF coverage targets by 22% on average since its IPO

IPO DCF Coverage Midpoint Target 1.15x

(2)

IPO

9.3% Yield(3)

Long-Term Outlook

23

18% Distributable Cash Flow CAGR Declining Leverage Profile to low to mid 2x Excess DCF and

• ptionality for AM

$50 / $2.85 25% Distributable Cash Flow CAGR Declining Leverage Profile to low to mid 2x Excess DCF and

• ptionality for AM

$65 / $3.15

(1)

Based on AR’s flexible long-term outlook, AM is targeting an 18% - 25% distributable cash flow (DCF) CAGR from 2020 to 2022

Note: Distributable cash flow is a non-GAAP metric – see appendix for details. 1) Based on the midpoint of 2019 distributable cash flow guidance.

AM Distributable Cash Flow Growth Scenarios (2020 – 2022)

$0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 2019 Guidance 2020E 2021E 2022E Millions Oil and Gas Price Assumptions

DCF Profile Supports Capital Retention

24

Distributable Cash Flow vs. Growth Capex ($MM)

Antero Midstream’s cash flow growth, self-funding business model, and declining capex profile drives optionality for New AM

25% DCF CAGR Target

Note: Distributable Cash Flow is a Non-GAAP measures. For additional information regarding these measures, please see appendix. Dividends and DCF targets pro forma for simplification transaction expected to close in March 2019. 1) Growth capex based on FactSet consensus estimates as of 3/19/2019.

Excess DCF available for:

• Deleveraging and capital

retention

• Organic growth capex
• Dividend growth
• Share repurchases

18% DCF CAGR Target Growth Capex(1) 1.1x-1.2x DCF Coverage Guidance in 2019 $2.0 B Organic Project Backlog $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 2019 2020 2021 2022 2019 Dividends (Midpoint) ($MM)

0.0x 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x 7.0x 8.0x 9.0x 10.0x Kinder Morgan Enterprise Products Enable Midstream Plains All American Pipeline DCP Midstream Magellan Midstream Energy Transfer TransCanada ONEOK Cheniere Energy Andeavor Logistics EnLink Midstream Phillips 66 Partners MPLX Williams Enbridge Western Gas EQM Midstream Targa Resources Antero Midstream 0.0% 5.0% 10.0% 15.0% 20.0% 25.0% 30.0% Debt / LTM Adjusted EBITDA 3-Year Distributable Cash Flow CAGR (2019-2022)

Highest DCF Growth Among Top 20 Midstream

25

Antero Midstream is a unique midstream vehicle with scale, low leverage and high distributable cash flow growth all in a C-Corp structure

C-Corp Leverage MLP ENBRIDGE KINDER MORGAN TRANSCANADA WILLIAMS ANTERO MIDSTREAM*

*

TARGA RESOURCES* PLAINS ALL AMERICAN Eliminated IDRs (Simplified)

*

Source: FactSet. Top 20 midstream companies by market capitalization as of 3/19/2019. Peer leverage as of 12/31/18. 1) Includes entities with both a publicly traded C-Corp and partnership, designated in striped blue/gray.

14 of 20 entities have simplified and 9 of 20 are C-Corps(1)

AM

Highest DCF Growth at

midpoint of target range and one of the Lowest Leverage profiles

*

ENLINK MIDSTREAM

18%

*

ONEOK*

* * * * * * *

25%

*

Summary Comments

Diversified Commodity Mix Enhances Value Proposition

9.1 MM shares repurchased in 4Q 2018 Mitigated Commodity Risk Controlled Resource Development 100% hedged on natural gas in 2019 @ $3.00/MMBtu floor on average Just-in-time midstream investment by AM Liquids-Rich Resource and Scale Pro forma leverage of 2.1x at 12/31/18 Peer Leading Margins Disciplined Focus on Returns Attractive Long-Term Outlook Top NGL producer in the U.S. Ability to grow and generate free cash flow 22% debt-adjusted growth per share in 2019 Appalachian leader for 6 straight years

Shareholder Value

Low Cost Liquids-Rich Resource Base Maintain Strong Balance Sheet 26

See appendix for Non-GAAP items and reconciliation.

Return of Capital

Appendix

2019 Capital Plan and Guidance

2019 Guidance Ranges

Net Production (Bcfe/d) 3.15 – 3.25 Net Natural Gas Production (Bcf/d) 2.225 – 2.275 Net Liquids Production (Bbl/d) 154,000 – 164,000 Net Oil, C3+ and Ethane Production (Bbl/d) Oil: 8,500 – 9,500 | C3+: 97,500 – 102,500 | C2: 48,000 – 52,000 Natural Gas Realized Price Differential to NYMEX ($/Mcf) $0.15 to $0.20 Premium C3+ NGL Realized Price (% of NYMEX WTI) 60% – 65% Cash Production Expense ($/Mcfe)(1) $2.15 – $2.25 Marketing Expense ($/Mcfe) $0.175 – $0.225 G&A Expense ($/Mcfe) (before equity-based compensation) $0.10 – $0.14 D&C Capital Expenditures ($MM) $1,300 - $1,450 Land Capital Expenditures ($MM) $75 – $100 Average Operated Rigs, Average Completion Crews & Operated Wells Completed Rigs: 5 | Completion Crews: 4 | Wells Completed: 115 – 125

Note: 2019 average NYMEX and WTI pricing was $3.00/MMBtu and $50.00/Bbl, respectively. 1) Includes lease operating expense, gathering, compression, processing and transportation expense and production and ad valorem taxes.

28

Consistent with guidance previously categorized as “Stand-alone” (released January 8, 2019)

As of December 31, 2018 ($MM) Antero Midstream Antero Resources (Stand-alone) Antero Resources (Consolidated) Cash $0 $0 $0 Debt Revolving Credit Facility $348 $405 $753 5.375% Senior Notes Due 2021 $1,000 $1,000 5.125% Senior Notes Due 2022 $1,100 $1,100 5.625% Senior Notes Due 2023 $750 $750 5.375% Senior Notes Due 2024 $650 $650 5.000% Senior Notes Due 2025 $600 $600 5.75% Senior Notes Due 2027(1) $650 $650 Net unamortized debt issuance costs ($8) ($25) ($33) Total Debt $1,640 $3,830 $5,470 Net Debt (Total Debt - Cash) $1,640 $3,830 $5,470 LTM Adjusted EBITDA $717 $1,717 $2,037 Debt / LTM Adjusted EBITDA 2.3x 2.2x 2.8x Credit Facility Capacity $1,500 $2,500 Liquidity $1,152 $2,095 Publicly Announced Pro Forma Adjustments to Net Debt Since December 31, 2018 ($MM) Antero Midstream Antero Resources (Stand-alone) Antero Resources (Consolidated) Cash Consideration for Simplification Transaction $598 ($297) $301 Total Adjustments to Net Debt: Increase / (Decrease) $598 ($297) $301 Pro Forma Net Debt $2,238 $3,533 $5,771 Pro Forma Debt / LTM Adjusted EBITDA 3.1x 2.1x 2.8x Credit Facility Capacity $2,000 $2,500 Liquidity (2) $1,054 $1,707

Antero Capitalization – Pro forma as of 12/31/18

Pro Forma Status Quo for AM Senior Notes Offering Pro Forma for Midstream Simplification 29

1) AM senior secured notes issued on 3/12/2019. 2) Includes $685 million in letters of credit outstanding at AR.

10 20 30 40 50 60 70 80 90 100 Bcf/d

U.S. Gas Supply and Base Decline

30

Source: S&P Global Platts. Note: Platts supply forecast through 2023 is within a 2% tolerance of EIA’s supply forecast over the same period. 1) Current 2018 year-end volumes represent historical and forecasted volumes from Platts Analytics. 2) Top five basins/plays that are included in the Rest of U.S. 3) Base decline calculated using 4Q over 4Q forecast production rates for all wells producing as of year-end 2018 based on Platts bottoms up well by well analysis.

Includes: Gulf Coast/GOM, SCOOP/STACK, Green River, Barnett, Anadarko(2)

Permian Appalachia Greater Haynesville DJ Bakken Eagle Ford

Base Decline

Significant U.S. base decline requires substantial new supply just to maintain flat production

32% 9% 36% 13% 6%

% Contribution to Current Supply

Rest of U.S. 27% 18% 13% 11% 9%

Gas supply grew 12% in the U.S. in 2018 Most current gas production in the U.S. is shale production

12%

Current(1): 85 Bcf/d

Appalachian Gas Supply and Base Decline

• 5

10 15 20 25 30 35

Bcf/d

31

Annual Base Decline Base Dry Gas Production Volumes

Source: S&P Global Platts 1) Current marketed dry gas production represent Platts modeled 4Q 2018 average volumes and differs from pipeline scrape data. 2) Base decline calculated using 4Q over 4Q forecast production rates for all wells producing as of year-end 2018 based on Platts bottoms up well by well analysis.

Base Rich Gas Sourced Volumes

Appalachian base decline at 33% is a bit steeper than U.S. base decline as 2018 supply growth in Appalachia was higher than the U.S. as a whole Appalachia Base Decline – Gross Wellhead Production (Bcf/d) (1)(2)

33% 20% 14% 11% 8%

Appalachian gas supply grew 22% in 2018

22%

Current: 31 Bcf/d(1)

Antero Production and Base Decline

32

• Antero’s base decline rate is almost identical to the base decline rate estimated for

Appalachia with Platt’s data

• Type curve shape is very similar across all operators in the Marcellus
• Base decline rates are primarily a function of production growth in the prior 12 months

AR Base Decline – Net Equivalent Production (Bcfe/d) (1)

1 2 3 4

Note: Decline rates represent fourth quarter average vs. prior year fourth quarter average. 1) Assuming no more wells are completed after 4Q 2018. 2) Current production represent AR 4Q average volumes. 3) Represents growth from 4Q 2017 average to 4Q 2018 average.

33% 20% 14% 11% 9%

Antero equivalent production grew 37% in 2018 (3)

37% Antero Annual Base Decline Antero Production Volumes Appalachia Annual Base Decline 33% 20% 14% 11% 8%

Current: 3.2 Bcfe/d(2) Appalachian base decline rate for comparison purposes

500 1,000 1,500 2,000 2,500 3,000 3,500 2019 2020 2021 2022 2023

Maintenance Capital

33

500 1,000 1,500 2,000 2,500 3,000 3,500 2019 2020 2021 2022 2023

2.7 Bcfe/d – 2018 Full Year Production 3.2 Bcfe/d – AR’s 4Q 2018 Production

(33%) (30%) First Year Decline Rate (1) Annual Maintenance Capital ($MM) (1)

Note: Based on Antero reservoir engineering team analysis. 1) Represents capital required each year to maintain production at the respective target levels (3.2 Bcfe/d and 2.7 Bcfe/d). Decline rate represents Q4 over Q4 change in production.\

MMcfe/d

4Q18 production: 3.2 Bcfe/d

MMcfe/d

Full Year 2018 Production: 2.7 Bcfe/d $840 $820 $720 $680 $640

2019 2020 2021 2022 2023

Average Annual Maintenance Capital: $600 MM (27%) (25%) (24%)

2019 2020 2021 2022 2023

(30%) (28%) $690 $610 $600 $550 $530 (27%) (25%) (24%) Average Annual Maintenance Capital: $740 MM First Year Decline Rate (1) Annual Maintenance Capital ($MM) (1) Antero’s average F&D cost on its 5 year PUD inventory in reserve base is $0.44/Mcfe

• Capital required to maintain flat production is a function of the base decline rate, which is a function
• f growth over the prior 12 months, as well as the beginning production level and capital efficiency
• Maintenance capital declines each year if the objective is to keep production flat (zero growth)

Maintenance Capex Sensitivities

Maintenance Capex ($MM) Maintenance Capex Wells Completed

Antero’s annual maintenance capital declines each year and averages $600 MM (2.7 Bcfe/d) to $740 MM (3.2 Bcfe/d) over the next five years for flat production

84 63 68 53 10 20 30 40 50 60 70 80 90 2019 2020 2021 2022 2023 3.2 Bcfe/d 2.7 Bcfe/d

Number of wells completed to hold production flat for 5 years for the following production rates:

$840 $640 $690 $530 $0 $100 $200 $300 $400 $500 $600 $700 $800 $900 2019 2020 2021 2022 2023 3.2 Bcfe/d 2.7 Bcfe/d

$MM in drilling and completion capex to hold production flat for 5 years for the following production rates:

5 year Average for 2.7 Bcfe/d: $600 MM 5 year Average for 3.2 Bcfe/d: ~$740 MM

Note: Based on Antero internal analysis from reservoir engineering team.

$MM # of Wells

34

35

Summary Decline Rate & Maintenance Capex Comments

Source: Antero reservoir engineering team analysis. 1) Source: Platts. 2019 decline rate represents Q4 over Q4 change in production.

• In general, the higher the supply or production growth in the prior 12 months,

the higher the base decline, which assumes no more wells are completed

2019 2020 2021 2022 2023 Maintenance Capital ($MM) $840 $820 $720 $680 $640

• Antero’s drilling and completion budget for 2019 has two components:
• The 2019 budget sets Antero up for growth in 2020 over 2019
• Antero could hold production flat at 3.2 Bcfe/d for five years and would have

declining maintenance capital assuming zero inflation and no efficiency gains

2019 Drilling & Completion Capital Breakdown Maintenance Capital (Zero Growth) $840 MM Growth Capital $460 MM Drilling & Completion Capital Budget $1,300 MM 4Q 2018 / 4Q 2017 YoY Growth 2019 Base Decline U.S. Gas Supply (1) 12% 27% Appalachian Gas Supply (1) 22% 33% Antero Equivalent Production 37% 33%

Antero grew production by ~900 MMcfe/d,

• r 37%, from 4Q

2017 to 4Q 2018

36

Competitive Gathering and Compression Fee Structure

AR Pays Competitive Gathering & Compression Fees

• AR’s gathering and compression fees paid to AM are below the Appalachian average

based on extensive internal analysis of 19 publicly disclosed and undisclosed private midstream contracts

AR has Low or No MVCs with AM

• No minimum volume commitments (“MVCs”) on any low pressure gathering with AM
• MVCs on high pressure gathering and compression assets put in-service after the AM

IPO (11/2014)

• 75% to 70% MVCs on high pressure gathering and compression, respectively,

when a project is requested by AR

• MVC levels are determined by AR’s production forecast and capacity needs; AM may

build infrastructure with capacity larger than requested for efficiency purposes that is not subject to MVCs

AR Receives Reliable and Timely Gathering and Compression from AM

• AR has complete visibility and drives AM’s planning and in-service timing for key

infrastructure projects

• AR is essentially AM’s sole customer, which results in unmatched service
• AR receives just-in-time customized and controlled midstream buildout
• Critical to AR’s ability to execute its development plan and optimize its capital efficiency

1 2 3

$0.53 $0.00 $0.10 $0.20 $0.30 $0.40 $0.50 $0.60 $0.70 $0.80 $0.90 $1.00

Appalachian Study Average: $0.60/MMBtu

37

Appalachia Gathering and Compression Fee Study

Note: All gathering & compression fees normalized to 1,250 Btu gas and two stage compression. Analysis based on public and private company disclosures for Appalachia midstream contracts.

AR Fees Paid to AM Converted to MMBtu AR Contracted Gathering/Compression Fees to AM ($/Mcf) $0.66 Typical BTU Conversion (Average BTU of 1250) for 2018/2019 Programs 1.25 AR Gathering/Compression Fees (Converted to $/MMBtu) $0.53

NOTE: Most midstream fees are disclosed on a $/MMBtu basis. AR’s fees are disclosed on a $/Mcf basis and must be converted to a $/MMBtu basis to appropriately compare to others Private Gathering & Compression Agreements

P

Publicly Disclosed Agreements

Competitive Fresh Water Fee Structure

38

AR Pays Highly Competitive Fresh Water Fees

• AR pays a fixed-fee per barrel to AM for fresh water pipeline service at the well pad that is firm

and is $0.39/Bbl lower cost than variable sourcing and trucking costs Peer Challenges:

• Exposure to trucking cost inflation currently observed in Appalachia, driven by continued

production growth and larger completions requiring more water

AR Receives Reliable and Timely Fresh Water Service From AM

• AR has never missed a scheduled completion date due to the inability to source and transport

fresh water for completions through AM Peer Challenges:

• Unavailability of local water sources during dry season or drought
• Logistical challenges accessing pads and rural roads by truck, particularly during inclement

weather

Sustainable Clean Water via Pipeline

• Fresh water pipeline system eliminated ~1.4 million truck trips and ~92,000 tons of CO2

emissions for AR in 2017 and 2018

• Full-cycle water system integrated with Antero Clearwater facility to reuse the fresh water by-

product of the advanced wastewaster treatment Peer Challenges:

• Utilizing produced and flowback water in completions rather than fresh water increases chemical

costs during completions and increases risk of negative impact on reservoir productivity

AR has Water MVCs with AM only through 2019

• AR has very manageable MVCs on fresh water of 120 Mbbl/d in 2019

1 2 3 4

AR Saved ~$0.39/Bbl on Fresh Water in 2018

39

Stonefly Pad – 12 Wells Round Trip Miles Minutes $/Bbl Pad Avg 74 112 $4.44 AR Costs Per Barrel $0.65 Stanley Pad – 3 Wells Round Trip Miles Minutes $/Bbl Pad Avg 22 58 $3.56 AR Savings Per Barrel $(0.23) Alexander Pad – 10 Wells Round Trip Miles Minutes $/Bbl Pad Avg 44 74 $3.82 AR Savings Per Barrel $0.03 Crestone Pad – 6 Wells Round Trip Miles Minutes $/Bbl Pad Avg. 58 136 $4.83 AR Savings Per Barrel $1.04

Antero 2018 Average Loading Time (Minutes) 60 Staging Time (Minutes) 100 Trucking Cost per Hour $95 Barrels Per Truck (Bbls) 97 Avoided Cost to Truck to All Pads ($/Bbl) $4.18 Firm Delivery Fee paid to AM ($/Bbl) $3.79 AR Fresh Water Savings ($/Bbl) $0.39

Schultz Pad – 3 Wells Round Trip Miles Minutes $/Bbl Pad Avg. 32 62 $3.62 AR Savings Per Barrel ($0.17)

Antero analyzed its 2018 completions and the “avoided cost” of utilizing AM’s fresh water pipeline system vs. trucking water for completions

• Antero utilized mapping and routing expertise to find optimized routes to each pad (i.e. “best case” travel routes)
• Costs on a per barrel basis can vary dramatically due to hourly trucking costs (typical delays due to: staging and loading

times, traffic congestion, completion shut-downs, bad weather, and challenging topography)

• AR realized savings in 2018 alone totaled $0.39/Bbl or $27 million

Note: Select 2018 pads shown above are illustrative of the company wide development plan across AR’s acreage position.

Antero Resources D&C Capital

40

$0.95 $0.97 $0.93 $0.93 $0.06 $0.03 $0.01 $0.01 $0.02 $0.01 $0.80 $0.85 $0.90 $0.95 $1.00 $1.05 $1.10 2018 Marcellus Well Cost Inflationary Costs New Sand / Completion Contracts Increased Stages per Day 2019 Budgeted Marcellus Well Cost Increased Sand Self Sourcing Optimized Water Logistics Further Increase in Stages per Day 2019 Target Marcellus Well Cost

Antero Resources Marcellus Well Cost ($MM/1,000’ assuming 12,000’ Lateral)

Through negotiating contracts and self sourcing sand, Antero was able to mitigate a majority of inflationary pressures on D&C capital for 2019

Drilling, water hauling, and production facility inflation Re- negotiated completion contracts and self sand sourcing Improved completion efficiencies 100% of sand self sourced Lower water truck staging times and improved

• perations at

Clearwater

Note: Assumes 2,000 pound per foot completion.

41

Antero Non-GAAP Measures

Total Debt and Net Debt Net Debt is calculated as total debt less cash and cash equivalents. Management uses Net Debt to evaluate its financial position, including its ability to service its debt obligations. Adjusted EBITDAX Adjusted EBITDAX as defined by the Company represents income or loss as reported in the Parent column of Antero's guarantor footnote (for historical periods) to its financial statements before interest expense, interest income, gains or losses from commodity derivatives and marketing derivatives, but including net cash receipts or payments on derivative instruments included in derivative gains or losses, income taxes, impairments, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, equity in earnings or loss of Antero Midstream and gain or loss on changes in the fair value of contingent acquisition consideration. Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units. The GAAP financial measure nearest to Adjusted EBITDAX is net income or loss that will be reported in Antero's condensed financial statements going forward and reported in the Parent column of Antero's guarantor footnote to its financial statements for historical financials. While there are limitations associated with the use of Adjusted EBITDAX described below, management believes that these measures are useful to an investor in evaluating the company's financial performance because these measures:

• are widely used by investors in the oil and gas industry to measure a company's operating performance without regard to items excluded from the calculation of such

term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors;

• helps investors to more meaningfully evaluate and compare the results of Antero's operations from period to period by removing the effect of its capital structure from its
• perating structure; and
• is used by management for various purposes, including as a measure of Antero's operating performance, in presentations to the company's board of directors, and as a

basis for strategic planning and forecasting. Adjusted EBITDAX is also used by the board of directors as a performance measure in determining executive compensation. Adjusted EBITDAX, as defined by our credit facility, is used by our lenders pursuant to covenants under our revolving credit facility and the indentures governing the company's senior notes.

There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non- recurring items that materially affect the company's net income, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. In addition, Adjusted EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Free Cash Flow Free Cash Flow as presented in this release and defined by the Company represents Cash Flow from Operations, less Drilling and Completion capital and leasehold capital. Free Cash Flow is a useful indicator of the company’s ability to internally fund its activities and to service or incur additional debt. There are significant limitations to using Free Cash Flow as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company’s net income, the lack of comparability of results of operations of different companies and the different methods of calculating Free Cash Flow reported by different companies. Free Cash Flow does not represent funds available for discretionary use because those funds may be required for debt service, land acquisitions and lease renewals, other capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations. Free Cash Flow is a measure of financial performance not calculated under GAAP and should not be considered in isolation or as a substitute for cash flow from

• perating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity.

Antero has not included a reconciliations of Free Cash Flow to its nearest GAAP financial measure because it cannot do so without unreasonable effort and any attempt to do so would be inherently imprecise.

Consolidated (Pro Forma Simplification) Deconsolidated (Pro Forma Simplification) Enterprise Value Market Capitalization $2,636 $2,636 Net Debt $5,198 $3,558 Enterprise Value $7,834 $6,194 AM Value $2,186 Adjusted Enterprise Value $4,008 2019E Consensus EBITDAX Consensus AR EBITDAX $1,876 $1,559 Less: Midstream distributions

• ($197)

2019 EBITDAX $1,876 $1,362 EV / EBITDAX Multiple EV / EBITDAX 4.2x 2.9x

EV / 2019E EBITDAX Reconciliation

Source: Bloomberg estimates and Antero pro-forma balance sheet projections. * Priced as of March 19, 2019.

Pro Forma for Simplification ($3 per AM unit only) Upstream only EBITDAX (consensus)

42

Antero Resources Adjusted EBITDAX and Net Debt Reconciliation

43

Twelve months ended (in thousands) December 31, 2018 Net (loss) and comprehensive (loss) attributable to Antero Resources Corporation $ (397,517) Commodity derivative fair value losses 87,594 Gains on settled commodity derivatives 243,112 Marketing derivative fair value gains (94,081) Gains on settled marketing derivatives 72,687 Interest expense 224,977 Income tax benefit (128,857) Depletion, depreciation, amortization, and accretion 845,136 Impairment of unproved properties 549,437 Impairment of gathering systems and facilities 4,470 Exploration expense 4,958 Gain on change in fair value of contingent acquisition consideration 93,019 Equity-based compensation expense 49,341 Equity in loss of Antero Midstream Partners LP 3,664 Distributions from Antero Midstream Partners LP 159,181 Adjusted EBITDAX $ 1,717,121 AR bank credit facility 405,000 5.375% AR senior notes due 2021 1,000,000 5.125% AR senior notes due 2022 1,100,000 5.625% AR senior notes due 2023 750,000 5.000% AR senior notes due 2025 600,000 Net unamortized premium 1,241 Net unamortized debt issuance costs (26,700) Total debt 3,829,541 Less: AR cash and cash equivalents — Debt 3,829,541 Less: Proceeds from Antero Midstream Simplification 297,000 Pro Forma Net Debt 3,532,541

Antero Resources Adjusted EBITDAX Per Mcfe

44 Adjusted EBITDAX per Mcfe Reconciliation (Annual)

2013 2014 2015 2016 2017 1Q2018 2Q2018 3Q2018 4Q2018

($/Mcfe)

Natural Gas, Oil, Ethane and NGL sales $ 4.31 $ 4.74 $ 2.53 $ 2.60 $ 3.35 $ 3.56 $ 3.35 $ 3.70 $ 4.05 Realized commodity derivative gains (losses) $ 0.86 $ 0.37 $ 1.57 $ 1.48 $ 0.26 $ 0.47 $ 0.42 $ 0.28 $ (0.09) Distributions from Antero Midstream $ - $ - $ 0.16 $ 0.17 $ 0.16 $ 0.17 $ 0.17 $ 0.16 $ 0.15 Less: WGL + SJR Impact $ 0.10 All-In E&P Revenue $ 5.17 $ 5.10 $ 4.27 $ 4.25 $ 3.77 $ 4.21 $ 3.94 $ 4.15 $ 4.11 Gathering, compression, processing, and transportation $ 1.25 $ 1.46 $ 1.56 $ 1.70 $ 1.75 $ 1.80 $ 1.79 $ 1.77 $ 1.88 Production and ad valorem taxes 0.24 0.23 0.14 0.10 0.11 0.12 0.11 0.12 0.15 Lease operating expenses 0.05 0.08 0.07 0.07 0.11 0.15 0.14 0.14 0.15 Net Marketing Expense / (Gain)

• 0.14

0.23 0.16 0.13 (0.27) 0.30 0.31 0.22 General and administrative (before equity-based compensation) 0.26 0.23 0.20 0.16 0.15 0.15 0.15 0.14 0.11 Total E&P Cash Costs $ 1.81 $ 2.14 $ 2.20 $ 2.19 $ 2.26 $ 1.93 $ 2.48 $ 2.48 $ 2.51 E&P EBITDAX Margin (All-In) $ 3.36 $ 2.96 $ 2.07 $ 2.06 $ 1.61 $ 2.28 $ 1.46 $ 1.68 $ 1.61 Production Volumes (Bcfe) 191 368 545 676 822 214 229 250 296 $ Millions Natural Gas, Oil, Ethane and NGL sales $ 821 $ 1,741 $ 1,379 $ 1,757 $ 2,751 $ 762 $ 768 $ 925 $ 1,197 Realized commodity derivative gains (losses) 164 136 857 1,003 214 101 96 71 (25) Distributions from Antero Midstream 89 112 132 36 39 41 44 All-In E&P Revenue $ 985 $ 1,877 $ 2,324 $ 2,872 $ 3,097 $ 900 $ 903 $ 1,037 $ 1,216 Gathering, compression, processing, and transportation 239 537 853 1,146 1,441 384 410 443 556 Production and ad valorem taxes 46 86 77 69 91 25 25 29 43 Lease operating expenses 9 28 36 51 94 31 32 35 44 Net Marketing Expense / (Gain)

• 50

123 106 108 (59) 69 78 66 General and administrative (before equity-based compensation) 50 86 108 110 119 31 33 34 33 Total E&P Cash Costs $ 345 $ 786 $ 1,196 $ 1,483 $ 1,853 $ 413 $ 569 $ 619 $ 742

Antero Midstream Non-GAAP Reconciliation

45

The following reconciles net income to Adjusted EBITDA and Distributable Cash Flow: $ in Thousands 2014 G&C Only 2014 2015 2016 2017

Net income $ 16,832 $ 127,875 159,105 236,703 307,315 Interest expense, net 4,620 6,183 8,158 21,893 37,557 Impairment of property and equipment — — — 23,431 Depreciation 36,789 53,029 86,670 99,861 119,562 Accretion and change in fair value of contingent acquisition consideration — 3,333 16,489 13,476 Accretion of asset retirement obligations — — — — Equity-based compensation 8,619 11,618 22,470 26,049 27,283 Equity in earnings of unconsolidated affiliates — —

• 485
• 20,194

Distributions from unconsolidated affiliates — — 7,702 20,195 Gain on sale of assets–Antero Resources — — — — Gain on sale of assets–third-party $ $ — —

• 3,859

— Adjusted EBITDA 66,860 198,705 279,736 404,353 528,625 Pre-IPO net income attributed to parent

• 98,219

— — — Pre-IPO depreciation attributed to parent

• 43,419

— — — Pre-IPO equity-based compensation attributed to parent

• 8,697

— — — Pre-IPO interest expense attributed to parent

• 5,358

— — — Pre-Water Acquisition net income attributed to parent

• 22,234
• 40,193

— — Pre-Water Acquisition depreciation attributed to parent

• 3,086
• 18,767

— — Pre-Water Acquisition equity-based compensation attributed to parent

• 654
• 3,445

— — Pre-Water Acquisition interest expense attributed to parent

• 359
• 2,326

— — Adjusted EBITDA Attributable to the Partnership $ 66,860 $ 16,679 215,005 404,353 528,625 Interest paid

• 2981
• 331
• 5,149
• 13,494
• 46,666

Increase (decrease) in cash reserved (paid) for bond interest — — —

• 10,481

291 Income tax withholding upon vesting of Antero Midstream Partners equity- based compensation awards — —

• 4,806
• 5,636
• 5,945

Maintenance capital expenditures

• 10,423
• 1,157
• 13,097
• 21,622
• 55,159

Distributable cash flow $ 53,456 $ 15,191 191,953 353,120 421,146