Company Presentation OCTOBER 2018 Cautionary Statement This - - PowerPoint PPT Presentation

Company Presentation

OCTOBER 2018

Cautionary Statement

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 release regarding activities, events or developments AR expects, believes or anticipates will or may occur in the future, such as those regarding future commodity prices, future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, Consolidated Adjusted EBITDAX, Stand-Alone E&P Adjusted EBITDAX, Consolidated Adjusted Operating Cash Flow, Stand-Alone Adjusted Operating Cash Flow, Free Cash Flow, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas, natural gas liquids and oil prices, acreage quality, access to multiple gas markets, expected drilling and development plans (including the number, type, lateral length and location of wells to be drilled, the number and type of drilling rigs and the number of wells per pad), projected well costs, future financial position, future technical improvements and future marketing opportunities, 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 release. Although Antero 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 the 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, 2017. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no

• bligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise,

except as required by applicable law. This presentation includes certain financial measures that are not calculated in accordance with U.S. generally accepted accounting principles (“GAAP”). These measures include (i) Consolidated Adjusted EBITDAX, (ii) Stand-Alone E&P Adjusted EBITDAX, (iii) Consolidated Adjusted Operating Cash Flow, (iv) Stand-Alone E&P Adjusted Operating Cash Flow, (v) Free Cash

• Flow. Please see “Antero Definitions” and “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 | OCTOBER 2018 PRESENTATION

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

The Size and Scale to Capitalize on the Resource

3

ANTERO RESOURCES | OCTOBER 2018 PRESENTATION

Market Cap……….……........... Enterprise Value….…………… Corporate Debt Ratings……… Stand-Alone Leverage……….. Net Production (2018E)…....... Liquids................................ 3P Reserves………..…........... C2+ NGLs(1)........................... Condensate......................... Net Acres………….…...……… Core Drilling Locations………. Hedge Mark to Market……….. AR Midstream Ownership (53%) $6.3B $10.1B Ba2 / BB+ / BBB- 2.6x 2.7 Bcfe/d 130,000 Bbl/d 54.6 Tcfe 2,131 MMBbls 131 MMBbls 620,000 3,295 $1.2B $3.0B

Note: Equity market data as of 9/20/18. Balance sheet data, hedge mark to market as of 6/30/18. Reserves as of 12/31/2017. Enterprise value excludes AM net debt. See 2018 Guidance in Appendix. (1) C2+ 3P Reserves contain 1,318 MMBbls of C3+ NGLs and 812 MMBbls of ethane. Assumes approximately 31% ethane recovery leaving 1,808 MMBbls of ethane in the natural gas stream.

Antero Resources Profile

Antero Acreage SW Marcellus Core Ohio Utica Core

A $17B Integrated Natural Gas and NGL Business

Organizational Structure

4

ANTERO RESOURCES | ORGANIZATIONAL STRUCTURE

Note: Enterprise value as of 9/20/18. AR E&P enterprise value excludes $3.0 Bn of ownership value in AM and AM net debt. (1) Sponsors represent Warburg Pincus, Yorktown & senior management.

100% Incentive Distribution Rights (IDRs)

NYSE: AMGP Enterprise Value: $3.2B No Ratings NYSE: AM Enterprise Value: $7.1B Corp Ratings: Ba2 / BB+ / BBB- NYSE: AR E&P Enterprise Value: $7.1B Corp Ratings: Ba2 / BB+ / BBB-

58% 42%

Sponsors(1) Sponsors(1)

53% 27% 73% 47%

Public Public Public

Natural Gas Liquids Update: Leading Position & Strong Fundamentals

5

116 33% 10% 34% 15% 11% 11% 16% 11% 13% 13% 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 20 40 60 80 100 120 140 AR EOG RRC DVN APC COP OXY MRO NBL PXD NGL % of Pre-Hedge Product Revenues Consensus C2+ NGLs (MBbl/d) 2018 Consensus C2+ NGL Production

(1)

Leader in Leverage to NGL Prices

6

Top NGL Producers in the U.S.

Source: Bloomberg consensus, SEC filings and company press releases. Note: Volumes represent consensus as of 9/20/2018. 2Q 2018 realized prices are weighted average including ethane (C2) where applicable. Percent of 2Q 2018 total product revenues is calculated on a pre-hedge basis. (1) 2Q 2018 actual NGL revenue percentage based on unhedged revenue. * Denotes consensus inclusive of international NGL production.

NGLs Generate 33%

• f AR Revenue (1)

2Q 2018

$26.35 $27.86 $23.69 $24.10 $34.88 $26.71 $28.87 $25.62 $24.39 $28.83

Antero Delivers Highest Exposure to Rising NGL Prices

Pre-hedged Realized NGL Price ($/Bbl) Pre-Hedge NGL % of Total Product Revenues

NATURAL GAS LIQUIDS UPDATE | LEADING POSITION AND STRONG FUNDAMENTALS

* * * *

50,000 100,000 150,000 200,000 250,000 2014 2015 2016 2017 2018E Guidance 2019E Target 2020E Target 2021E Target 2022E Target Natural Gasoline (C5+) IsoButane (iC4) Normal Butane (nC4) Propane (C3) Ethane (C2) 245,000

Rapidly Growing NGL Production

7

Antero NGL Production Growth by Purity Product

Note: Excludes condensate. See Appendix for further assumptions around long-term targets. C2 Ethane volumes in 2018 reflect adjustment for timing of ME2 in-service date from 6/1/18 to 10/1/18.

Total (Bbl/d) C5+ iC4 nC4 C3 C3+ Production C2

C2 Ethane 17,476 C2 Ethane 26,500 C2 Ethane 40,000

NATURAL GAS LIQUIDS UPDATE | LEADING POSITION AND STRONG FUNDAMENTALS

Appalachia: Geographic & Infrastructure NGL Advantaged

MID-CONTINENT APPALACHIA

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PERMIAN ROCKIES BAKKEN/WILLISTON

Mariner East Cornerstone

Exports to International Markets

Mont Belvieu Conway Appalachia

• In-basin fractionation and transport marketable

purity products

• Sufficient fractionation capacity
• Fixed fractionation fees
• Producer controls product destination and captures

pricing uplift

8

Permian, Rockies, Mid-Continent & Bakken

• Transport Y-grade for out-of-basin fractionation
• Severely constrained fractionation,Y-grade

transportation and NGL storage capacity

• Rapidly rising fractionation fees
• Midstream controls product destination and captures

pricing uplift

NATURAL GAS LIQUIDS UPDATE | LEADING POSITION AND STRONG FUNDAMENTALS

500 1,000 1,500 2,000 2,500

• $0.10

$0.00 $0.10 $0.20 $0.30 $0.40 $0.50 $0.60 $0.70 Ethane Production (Mbbl/d) Fractionation Spread ($ per Gallon) U.S. Ethane Production Fractionation Spread: (MB Ethane vs Henry Hub Gas)

9

NATURAL GAS LIQUIDS UPDATE | LEADING POSITION AND STRONG FUNDAMENTALS

Ethane: Positive Frac Spread Driving Recovery

Source: EIA, Bloomberg

Ethane Production and Frac Spreads Natural Gas and Ethane Pricing ($/Gal) Ethane price improvement exceeds change in natural gas on a gallon equivalent basis Higher Ethane Prices Needed to Incentivize Recovery in Basins Farther from U.S. Gulf Coast

$0.00 $0.10 $0.20 $0.30 $0.40 $0.50 $0.60 $0.70 $0.80 $0.90 $1.00 $ per Gallon Henry Hub Gas ($/Gallon Equivalent) Mont Belvieu Ethane

2018 Gas Value:

• 7% Y/Y

Antero’s Ethane Exposure: All Upside

10 Antero’s ethane has a natural gas pricing “floor” and purity ethane “ceiling”; increases in ethane purity prices are all upside Antero’s balanced approach to ethane sales results in 50% of contracts tied to purity ethane prices vs. natural gas value Ethane Revenue Uplift ($MM)

Ethane sensitivity: +$0.10/gallon x 2019 production target x ~50% exposure to Mt. Belvieu = ~$40MM incremental 2019 ethane Revenue

$115 $90 $130 $60 $175 $265 $305 $0 $50 $100 $150 $200 $250 $300 $350 1H 2018 Actual $0.23/Gal 2H 2018E Strip Prices $0.45/Gal 2018 Actual + Strip $0.32/Gal 2019E Strip Prices $0.40/Gal 2019E +$0.10 Upside $0.50/Gal Incremental Revenue

40 MBbl/d Antero has no hedges in place for C2 volumes 44 MBbl/d 55 MBbl/d 55 MBbl/d 35 MBbl/d

Note: Ethane prices reflect realized price to Antero and assume $(0.05)/gallon discount to Mt. Belvieu prices based on 2018 Antero guidance. 2019 volumes are assumptions only, based on ME2 in-service and an increase in de-eth capacity expected to come on-line in 4Q18.

+$0.10/Gal C2 price change = $40MM incremental revenue

NATURAL GAS LIQUIDS UPDATE | LEADING POSITION AND STRONG FUNDAMENTALS

Material reduction in U.S. propane inventories relative to the 5-year average Current propane days of supply are 18% below last year and 24% below the 5-year average

Strong Propane Fundamentals

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Propane Days of Supply U.S. Propane Inventories

10 20 30 40 50 60 70 80 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Days of Supply 5-Yr Range 2018 2017 5-Yr Avg 2013-2017 20 40 60 80 100 120 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec MMBbls 5-Yr Range 2017 2018 5-Yr Avg 2013-2017

Source: EnVantage Inc. and Energy Information Administration (EIA).

MB C3 $1.03/gallon remainder of 2018 2017 2018 2017 2018

NATURAL GAS LIQUIDS UPDATE | LEADING POSITION AND STRONG FUNDAMENTALS

Strong Natural Gas Liquids (C3+) Price Improvement

Source: Intercontinental Exchange (ICE) pricing data. Assumes C3+ barrel weightings of: propane 57%, normal butane 16%, Isobutane 10%, pentanes 17%. 1) Balance 2018 represents strip pricing as of 9/17/2018.

$0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $1.20 $1.40 $1.60 $1.80 $2.00 C3+ NGLs ($/Gallon)

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30% 40% 50% 60% 70% 80% 90% 100% C3+ NGLs as a % of WTI Crude Oil

Mont Belvieu C3+ NGL Price ($/Gallon) Mont Belvieu C3+ NGL prices have increased 28% year-over-year and 145% since January 2016 lows But still remain well within historical levels on a on a relative basis compared to WTI crude oil C3+ Price as a Percent of WTI

2H18 $1.17/Gal $49.19/Bbl 67%

NATURAL GAS LIQUIDS UPDATE | LEADING POSITION AND STRONG FUNDAMENTALS

• 1. 2H18 represents strip pricing as of 9/17/2018. Volumes based on midpoint of guidance. Antero has 26 MBbl/d of propane hedged at $ $0.76 per gallon for the remainder of 2018 and no C3+

hedges beyond 2018.

Antero’s C3+ NGL Exposure: Highly Leveraged

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Pentane 17% IsoButane 10% Butane 16% Propane 57%

Antero’s NGL price directly benefits from the recent strengthening

• f NGL prices at Mont Belvieu

NGL fundamentals remain constructive and support higher prices despite illiquid and backwardated NGL futures prices Antero C3+ Barrel Composition by Product – Mont Belvieu Pricing Mont Belvieu Pricing (Pre-differential & ME2) Antero C3+ Barrel 1H18

• Avg. Price

Balance 2018 Variance 57% $0.87 $1.03 +$0.16 16% $0.86 $1.21 +$0.35 10% $1.12 $1.22 +$0.10 17% $1.46 $1.58 +$0.12 C3+ $/Gal $0.99 $1.17 +$0.18 C3+ $/Bbl $41.74 $49.19 +$7.46 Volume (Bbl/d) 67,000 88,000 +21,000 13

NATURAL GAS LIQUIDS UPDATE | LEADING POSITION AND STRONG FUNDAMENTALS

$700 $235 $405 $430 $1,130 $1,365 $1,535 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 $1,800 1H 2018 Actual $35/Bbl 2H 2018E Strip Prices $43/Bbl 2018 Actual + Strip $40/Bbl 2019E Strip Prices $38/Bbl 2019E Strip +$5/Bbl $43/Bbl Incremental Revenue

77.5 MBbl/d ME2 on 11/1 Antero has no hedges in place for C3+ volumes for 2019 and beyond

Pre-Hedge Revenue Sensitivity to C3+ NGL Pricing ($MM)

Note: Represents 9/17/2018 strip Mont Belvieu pricing. 2H18 assumes Mariner East 2 on November 1 2018. 2H18 volumes implied by full year guidance and 1H18 actual results. 2019 volumes assume 20% liquids growth vs. 2018 guidance of 77,500 Bbl/d. Assumes C3+ barrel weightings of: propane 57%, normal butane 16%, Isobutane 10%, pentanes 17% and holds 1H18 local differential of $(6.00)/Bbl flat. Initial ME2 in- service 11/1/18 moving Antero’s 50,000 Bbl/d of contracted volumes.

67 MBbl/d No ME2

Powerful C3+ NGL Pricing Upside Exposure

93 MBbl/d Full ME2 93 MBbl/d Full ME2 88 MBbl/d ME2 on 11/1

Compounded pricing leverage from increasing volumes, prices, and Mariner East 2 uplift drives cash flow growth For every $5.00/Bbl increase in NGL prices, Antero generates an incremental $170MM in Revenue

+$5/Bbl change = +$170MM in revenue

14

NATURAL GAS LIQUIDS UPDATE | LEADING POSITION AND STRONG FUNDAMENTALS

Antero’s NGL Pricing Uplift from Mariner East 2

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Mont Belvieu Conway Europe Netback 2019

NWE Price ($/Gal) $1.08 Pipeline, Terminal & Shipping Cost (1) $(0.24) NWE Netback $0.84 Blended Conway / MB Netback $0.73 Uplift vs. 1Q18 Average Differential +$0.11

Asia Netback 2019

FEI Price ($/Gal) $1.17 Pipeline, Terminal & Shipping Cost (1) $(0.33) Asia Netback $0.84 Blended Conway / MB Netback $0.73 Uplift vs. 1Q18 Average Differential +$0.11

International Markets Domestic Markets

Marcus Hook

Antero Blended Netback 2019

Conway/Mt. Belvieu Price ($/Gal) $0.89 Average 1H 2018 Differential $(0.16) Blended Conway/MB Netback $0.73

Source: Poten Partners. Prices reflect blended price of propane and butane based on Antero’s ME2 volume commitment. Note: Based on Baltic forward shipping rates and propane strip prices as of 09/17/18. Includes associated port and canal fees and charges. (1) Based on Wall Street research. Antero cost may be lower.

Mariner East 2 (“ME2”) Initial Capacity (4Q18): Committed volumes Full Capacity (3Q19): 275 MBbl/d AR Commitments: 35 Mbbl/d C3 15 MBbl/d C4 AR Expansion Rights: 50 Mbbl/d C3/C4

Mariner East 2 will allow AR to access international LPG markets and realize a ~$4.50/Bbl uplift on its exported barrels

50,000 Bbl/d Mariner East 2 commitment equates to over $82 MM of incremental annual cash flow

4Q 2018

15

NATURAL GAS LIQUIDS UPDATE | LEADING POSITION AND STRONG FUNDAMENTALS

A Cash Flow Inflection Point

16 Step Change in Capital Efficiency Reduces 5-Year D&C Capex by $2.9B The Size & Scale to Capitalize on Resource Announced Longer Lateral Development Plan Averaging 11,500’ per Well Highest Leverage to NGL Prices Among Top NGL Producers

Sustainable Cash Flow Growth

Generating 5-Year Free Cash Flow of $1.6B at YE Strip & $2.8B at $60 Oil

Joining an Elite E&P Group With: Scale Double Digit Growth Free Cash Flow Low Leverage

Disciplined Returns Focus

→33% - 37% Full Cycle Returns →23% 5-Year Debt-Adjusted Production CAGR per share →22% 5-Year Cash Flow CAGR per share

Note: See definitions for free cash flow and assumptions behind long-term targets in Appendix; free cash flow definition includes maintenance land spending, but excludes discretionary land spending.

VALUE PROPOSITION | CAPITAL DISCIPLINE AND DELEVERAGING

Long Lateral Development Plan

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SCALE & GROWTH | COST EFFICIENCY DRIVERS: LONGER LATERALS

59% of Inventory Now ≥ 10,000’ Lateral Length 5-Year Plan Averages 11,500’

Average Lateral Length per Completed Well Core Drilling Inventory by Lateral Length

10,800’

Average Inventory Lateral Length 12,700 2,000 4,000 6,000 8,000 10,000 12,000 14,000 2018 2019 2020 2021 2022 145 155 160 165 165 Wells Completed(1) 498 1,450 200 400 600 800 1,000 1,200 1,400 1,600 <6,000' 6,000' - 8,000' 8,000' - 10,000' 10,000' - 12,000' ≥12,000' Feet Feet (Number of locations)

1) Wells completed reflects midpoint of targeted completions per year.

Step Change in Capital Efficiency

Consolidated Drilling & Completion Capital Expenditures Production Targets

2.7 3.3 4.0 4.6 5.2 2.7 3.3 3.9 4.5 5.2 0.0 1.0 2.0 3.0 4.0 5.0 6.0 2018 2019 2020 2021 2022 Bcfe/d As of December 2016 As of December 2017

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VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | SIGNIFICANT CAPITAL REDUCTION

$2.9B Capex Reduction Over 5 Years

Cumulative Reduction in Drilling & Completion Capital

Same Production Targets

20% Production CAGR 2018-2020 15% Production CAGR 2021-2022

Same Production Growth With Much Less Capital Spending

$1.6 $1.7 $2.0 $2.2 $2.4 $1.3 $1.3 $1.3 $1.4 $1.7 $0.0 $0.5 $1.0 $1.5 $2.0 $2.5 2018 2019 2020 2021 2022 $ Billions As of December 2016 As of December 2017

Breakdown of D&C Capex Savings

19

$2.9B

Capital Efficiencies Captured Within D&C Capex From New Development Program

$0.9B

Lateral Lengths

$0.5B

Improved Cycle Times

$1.1B

Optimizing Capital Allocation

$0.09MM/1,000’ savings from 9,000’ to 12,000’ Reduced drilling days, increase in stages per day and concurrent operations Continued shift to high- graded Marcellus

$0.4B

Well Cost Savings

Related to reduced AFEs including lower flowback water handling cost due to Clearwater Facility and begin self-sourcing sand

D&C Capex Savings

Lateral Lengths Cycle Times Well Cost Savings Capital Allocation & Enhanced Recoveries

VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | COST EFFICIENCY DRIVERS

Note: See appendix for further detail on D&C capital.

3,872 2,575 5,169

• 1,000

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

2014 2015 2016 2017 2Q 2018 RECORD

Feet Marcellus Utica 9,611 15,075 12,886 17,445

• 2,000

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

2014 2015 2016 2017 2Q 2018 RECORD

Feet Marcellus Utica 4.6 5.0 9.0 3.6 5.4 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 2Q 2018 RECORD

Stages per Day Marcellus Utica

20

Drilling and Completion Efficiencies

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

VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | COST EFFICIENCY DRIVERS

8,206

Note: Percentage increase and decrease arrows represent change in Marcellus data from 2014 to 2Q 2018.

12 8 20 10 5 10 15 20 25 30 35

2014 2015 2016 2017 2Q 2018 RECORD

Drilling Days Marcellus Utica

Compelling Full Cycle Well Economics

21

Single Well Economics Bridge to Corporate Level Returns Fully Burdened Corporate Level Well Economics are Outstanding

Note: See company presentation on Antero Resources investor relations website for further detail behind full cycle and half cycle single well economics; WACC calculated using CAPM. (1) ROR (D&C only) burdened with 60% of AM fees to give credit for AM ownership/distributions and variable firm transportation fees only (i.e. excluding sunk demand costs). (2) Incremental 40% of AM fees represent the full midstream fees AR pays to AM on complete stand-alone basis (i.e. no credit for midstream ownership). Includes increase in D&C capital to account for full water fees paid to AM. (3) 2.4 bcfe/1,000’ EUR assumes ethane rejection.

111% 102% 82% 61% 49% 37% 9% 20% 20% 13% 12% 0% 20% 40% 60% 80% 100% 120%

ROR (D&C only) Pad cost & facilities Half cycle ROR Fixed FT fees ROR with full FT fees Full AM fees ROR-fully burdened fees G&A ROR post- G&A Land costs Full cycle (corporate) ROR

AR WACC ≈ 8%

VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | ATTRACTIVE WELL ECONOMICS DRIVE GROWTH

Fully burdened well economics support investment Corporate ROR well in excess of cost of capital

(1) (2)

Half cycle ROR Full cycle ROR Well Assumptions

12,000’ Lateral 1250 BTU Wellhead Gas 2.4 Bcfe/1,000’ EUR(3) 6/30/2018 Strip Pricing

5 10 15 20 25 $0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 2014 2015 2016 2017 2018E 2019E 2020E 2021E 2022E Number of Drilling Rigs In Millions Stand-Alone Adjusted Cash Flow From Operations D&C Capital Antero Rig Count

Capital Discipline Leads to Free Cash Flow

22

Stand-Alone Adjusted Cash Flow Alongside D&C Capital Expenditures D&C Capital Investment Fully Funded with Cash Flow

Note: Stand-alone adjusted cash flow from operations represents net cash provided by operating activities as reported in the Parent column of AR’s guarantor footnote to its financial statements before changes in current assets and liabilities, plus the AM cash distributions payable to AR, plus the earn out payments expected from Antero Midstream associated with the 2015 water drop down transaction. Estimates assume strip pricing as of 12/31/2017. (1) D&C maintenance capital represents $590MM per year to hold production flat at 2.3 Bcfe/d which was year-end 2017 exit rate. (2) Free cash flow definition includes $175MM of maintenance land spending, but excludes $175MM discretionary land spending.

48% reduction in D&C capital budget and 15 rig reduction since 2014 Future D&C capital budgets that are measured and within cash flow

Free Cash Flow(2)

VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | SUSTAINABLE CASH FLOW GROWTH

D&C Maintenance Capital(1)

Near Term Free Cash Flow Inflection Point

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Stand-Alone Cash Flow(1) Antero Is Approaching a Free Cash Flow Inflection Point

Note: Stand-Alone Adjusted Operating Cash Flow represents net cash provided by operating activities as reported in the Parent column of AR’s guarantor footnote to its financial statements before changes in current assets and liabilities, plus the AM cash distributions payable to AR, plus the earn out payments expected from Antero Midstream associated with the 2015 water drop down transaction. (1) Based on 12/31/2017 strip pricing.

Capital discipline to reduce completion crews and D&C capex in 2H18 Production growth and strong liquids prices drives free cash flow in 4Q18 and beyond

ANTERO RESOURCES | DISCIPLINED FOCUS ON RETURNS & CAPITAL EFFICIENCY

Cash Outspend Free Cash Flow Generation Q4 2018 represents a free cash flow inflection point 2019E – 2022E Q3 2018 Q4 2018 Delevering & Return of Capital Potential

3.9x 3.6x 2.8x 2.9x 0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x 3.5x 4.0x 4.5x 5.0x 2014A 2015A 2016A 2017A 2018 Guidance 2019 Target 2020 Target 2021 Target 2022 Target Stand-Alone Financial Leverage 12/31/17 Strip Pricing (Base Case) $60 Oil / $2.85 Gas $50 Oil / $2.85 Gas

Cash Flow Growth → Deleveraging Profile

23% Debt-Adjusted Production CAGR Generates Free Cash Flow Balance Sheet Deleveraging & Optionality

Note: See Appendix for key definitions and assumptions. Stand-alone financial leverage is calculated by dividing year-end stand-alone debt by last twelve months stand-alone EBITDAX. Note all free cash flow after land spending is assumed to be used for debt reduction.

Leverage targets inclusive of $500 MM of maintenance and discretionary land capex from 2018 - 2022

Deleveraging Supported By:

• 2.4 Tcfe Hedge Position
• 4.7 Bcf/d FT Portfolio
• $1.4B of Targeted AM

Distributions

CAPITAL DISCIPLINE AND DELEVERAGING | CASH FLOW DRIVES LOW LEVERAGE

S&P Upgrade to BB+

Moody’s Ba2 Outlook “Positive” BBB- Rating

Fitch Recently Rated AR Investment Grade

2Q 2018 Leverage: 2.6x

24

25

Antero Profile Should Drive Multiple Expansion

Approaching an Elite Group of E&Ps With Scale, Double Digit Growth, Low Leverage & Free Cash Flow Generation

Source: Bloomberg & Antero Estimates as of 9/20/18. (1) Adjusted EBITDAX and Adjusted Operating Cash Flow are non-GAAP measures. AR EV/EBITDAX multiple also reflects an enterprise value that excludes AR ownership of AM, and EBITDAX excludes AM distributions received by AR, for comparative purposes with peer E&P multiples. For additional information regarding these measures, please see “Antero Definitions” and “Antero Non-GAAP Measures” in the Appendix.

VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | ATTRACTIVE VALUATION

U.S. Publicly Traded E&Ps Leverage < 3.0x Enterprise Value > $10B Production Growth >15% Leverage <2.0x Free Cash Flow

# of Companies Median Debt/ Adjusted EBITDAX Median EV/ 2019 Adj. EBITDAX 52 2.1x 5.5x 37 1.5x 5.6x 17 1.5x 6.2x 9 1.5x 6.2x 6 1.0x 6.9x 5 0.8x 7.2x

EOG CXO PXD

AR 2019E unhedged EBITDAX Multiple: 3.9x

Scale Growth Low Leverage

Permian & Appalachia

FCF Generation

  

COG CLR

 

in 2019 in 2018

Premium for:

0% 1% 2% 3% 4% 5% 6% 7% 8% 9% 2018 2019 2020 FCF Yield

26

VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | 5-YEAR OUTLOOK

Attractive Free Cash Flow Yield

Note: See definitions for free cash flow and assumptions behind long-term targets in Appendix. “Elite” group of peers includes COG, CXO, CLR, EOG, PXD; “Integrated” group includes XOM & CVX. Source: Bloomberg. Represents free cash flow yield for the base case at 12/31/17 strip pricing. (1) Represents free cash flow divided by current market capitalization as of 9/20/18.

Free Cash Flow Yields Exceed Both Best-In-Class Peers & Integrated Oil & Gas Companies

AR 7% FCF Yield(1)

Surpasses Industry Leading Peers, While Maintaining Strong Production Growth

Assuming current stock prices, Antero should deliver free cash flow yield well in excess of both the integrateds and the “best in class” E&P peers

Scale & Growth: Liquids-Rich Resource Meets Capital Efficiency

Antero is Very Well Positioned in the Core of the Core

28

Positioned in the Core of the Core

Northern Rich

High-Graded Core 2.24 Bcfe/1,000’ Avg. EUR 61% Undeveloped

Southern Rich

High-Graded Core 2.24 Bcfe/1,000’ Avg. EUR 66% Undeveloped AR Holds 62% of Undeveloped

Southwest Marcellus Core

~2.9 Million Acres ~76% Undeveloped

Antero Acreage Antero Marcellus Wells Industry Marcellus Wells Antero Marcellus Rig Industry Marcellus Rig

Dry Gas

High-Graded Core 2.30 Bcfe/1,000’ Avg. EUR 74% Undeveloped AR Holds 13% of Undeveloped

> 1,300 lb/ft Completions High- Graded Core Areas Most Active Operators Percent Undeveloped Advanced Completions (>1,300 lbs/ft) Bcfe / 1,000’ Wells Northern Rich RRC, CNX, HG 67% 2.24 474 Southern Rich AR, EQT, SWN 70% 2.24 517 Dry Gas EQT, CVX, RRC, CNX 78% 2.30 747

Note: Excludes 600,000 urban acres. EURs assume full ethane rejection. Based on Antero reserve engineering of most recent state and internal production data.

ANTERO RESOURCES | SUSTAINABLE DEVELOPMENT OF WORLD CLASS LIQUIDS-RICH RESOURCE BASE

3,295 2,333 1,605 1,259 720 714 663 588 583 556 500 1000 1500 2000 2500 3000 3500 4000 AR A B C D E F G H I Undrilled Locations

Largest Undrilled Core Liquids Drilling Inventory

29

10,848’ 9,563’ 6,775’ 7,723’ 6,040’ 9,583’ 8,905’ 8,396’ 7,731’ 8,639’

Antero Holds 40% of Core Undrilled Liquids-Rich Locations

Largest Inventory in Appalachia

(1) Peers include Ascent, CHK, CNX, COG, CVX, EQT, GPOR, HG, RRC and SWN. Based on Antero analysis of undeveloped acreage in the core of the Marcellus and Ohio Utica plays. Excludes deep Utica resource in West Virginia & Pennsylvania.

Who Can Consistently Drill Long Laterals? Who Has the Running Room?

Core Marcellus & Utica Undrilled Locations(1)

Lateral Length:

SCALE & GROWTH | CORE OF THE CORE

Rich Gas Locations NE PA Dry Gas Dry Gas Locations

A Pioneer in Longer Lateral Development in Appalachia

30

(1) All laterals rounded to the nearest thousand. (2) Represents wells placed to sales.

Antero Historical & Future Lateral Length Program

113 85 22 12 10 4 12 13 57 103 93 107 76 81 78 77 93 50 100 150 200 250 300 ≤ 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 > 15,000 Well Count Lateral Length(1)

Antero

# of Wells

• Avg. Lateral

Length Total Drilling Program to Date 945 8,275 2018-2022 Program(2) 790 11,425 Wells to Date ≥10,000’ 245 10,700

SCALE & GROWTH | COST EFFICIENCY DRIVERS: LONGER LATERALS

5 10 15 20 25 30 35 40 45 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 16,000 EUR (Bcfe) Lateral Length (ft) EUR in Bcfe/1,000' 2.3 Bcfe/1,000'

Longer Laterals Scale the Resource

31

SCALE & GROWTH | COST EFFICIENCY DRIVERS: LONGER LATERALS

EURs by Marcellus Lateral Lengths

A 1:1 Proportional Increase in EURs with Longer Laterals

Antero well results show no evidence of degradation in recovery per foot of completed lateral out to over 14,000’

R2 = .73

Note: Assumes ethane rejection.

The Longer, the Better…

32

SCALE & GROWTH | COST EFFICIENCY DRIVERS: LONGER LATERALS

Note: Represents half cycle economics at 6/30/2018 strip pricing for a 1250 Btu Marcellus well. See Appendix for further assumptions on single well economics.

Single Well Economics by Lateral Lengths

$7.1 $11.9 $16.6 $21.0 58% 77% 89% 90% 0% 20% 40% 60% 80% 100% $- $5.0 $10.0 $15.0 $20.0 $25.0 6,000' Lateral 9,000' Lateral 12,000' Lateral 15,000' Lateral PV-10 ($MM) ROR (%)

~60% Improvement in ROR from a 6,000’ Lateral to a 15,000’ Lateral

$0.60 $0.80 $1.00 $1.20 $1.40 $1.60 $1.80 $2.00 $2.20 3,000 6,000 9,000 12,00015,000 $MM/1,000 ft of lateral Lateral Length (ft)

Marcellus

2014 2017

Declining Well Costs → Longer Laterals the Next Step

33

SCALE & GROWTH | COST EFFICIENCY DRIVERS: LONGER LATERALS

Note: Well costs reflect 2,000 pound per foot completions. See Appendix for further assumptions.

Historical Well Costs

41% | 43% Lower Costs

Marcellus | Utica reduction in well costs from 2014 to 2017 for a 9,000’ lateral

• 54% from efficiencies
• 45% from service costs

9% | 10% Cost Benefit

Marcellus | Utica reduction in well cost per 1,000’ lateral going from 9,000’ to 12,000’ laterals 41% Reduction

$0.60 $0.80 $1.00 $1.20 $1.40 $1.60 $1.80 $2.00 $2.20 $2.40 $2.60 3,000 6,000 9,000 12,000 15,000 $MM/1,000 ft of lateral Lateral Length (ft)

Utica

2014 2017

43% Reduction 9% Reduction 10% Reduction

Operating Evolution Continues

34

(1) Based on Marcellus 11,000 foot lateral and 2,000 pounds per foot AFE. Assumes nine wells per pad.

Drilling Efficiency (25%)

42%

Decline in well costs since 2014

54%

Permanent cost efficiencies

46%

Vendor-related cost reductions

Efficiencies Expected to Offset Service Cost Inflation

Facilities, Pad & Road Allocation 9% Tubulars 4% Sand 12% Flowback Water 5% Completion Spreads 25% Drilling Rigs & Services 21% Completion Services 24%

Drilling Rigs/Services

→Fit-for-purpose rigs with dual operation capabilities to improve cycle times →Improved drillout efficiency →Penetration rates still increasing with new downhole motors

Completion Spreads/Services

→ Concurrent operations with larger pads allowing simultaneous drilling and completion and easier access → More wells per pad → Automated completion equipment to increase stages per day

Sand

→ 100 mesh sand for easier pumping & fewer screenouts → Self-sourcing sand to reduce supply cost → Regional sand mines in the Permian expected to reduce demand for Northern White sand

• → increase stages per day
• → higher potential recoveries
• → easier pumping with fewer
• → reduce supply cost
• 100% of Completion

Spreads Under Contract Through 2019 Antero has 100% of 2018 Rigs and 50% of 2019 Rigs Under Fixed Rate Contracts with Average Rig Rates Declining Towards $17,500/day in 2018 as Higher Rig Rate Contracts Roll Off

Achievements to Date 2018 Marcellus Well Cost(1) Next Steps in Efficiency Evolution

SCALE & GROWTH | OPERATING TECHNOLOGIES EVOLVE

$0.88 $0.73 $0.51 $0.42 $1.28 $0.94 $0.73 $0.74 $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $1.20 $1.40 2014 2015 2016 2017 Marcellus Utica

35

SCALE & GROWTH | COST EFFICIENCY DRIVERS: WELL COST REDUCTION

Dramatically Lower F&D Cost

F&D Cost per Mcfe(1)(2)

(1) Ethane rejection assumed. (2) F&D cost is defined as current D&C cost per 1,000’ lateral divided by net EUR per 1,000’ lateral assuming 85% NRI in Marcellus and 81% NRI in Utica. Please see “Antero Definitions” and “Antero Non-GAAP Measures” in the Appendix.

Dramatic Improvement in Operating Efficiencies, Lower Service Costs and Higher Well Recoveries Have Driven F&D Costs Materially Lower

52% | 42% Lower F&D

in Marcellus | Utica

Rover Pipeline Uplift and Optionality

36 Unlocks development optionality between Marcellus and Utica and provides further Chicago & Gulf Coast exposure Rover Sherwood Lateral expected to be placed into service in September Rover Pipeline Map

Chicago via Rover ($/MMBtu) 2019

Chicago Price ($/MMbtu)(1) $2.54 Approximate Variable Cost $(0.06) Netback Price $2.48 TETCO M2 Price $(2.10) Uplift vs. TETCO M2(1) $0.38

Gulf Coast via ANR ($/MMbtu) 2019

Gulf Coast Price ($/MMbtu)(1) $2.63 Approximate Variable Cost $(0.04) Netback Price $2.59 TETCO M2 Price $(2.10) Uplift vs. TETCO M2(2) $0.49

Ability to utilize 800 MMcf/d Rover capacity with both Marcellus production (Sherwood Processing Plant) and Utica production (Seneca Processing Plant)

Rover Phase 1A (in-service) Rover Phase 1B (in-service) Rover Laterals (3Q18-4Q18) Natural Gas Pricing Hub

1. Futures prices as of 9/17/18. 2. Based on 2019 Tetco M2 futures prices and includes $0.14 of variable cost

ANTERO RESOURCES | CONTROL DEVELOPMENT & MITIGATE INDUSTRY RISKS

Well Hedged at High Prices Relative to Strip

TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PRODUCTIVITY DRIVERS

2,195 2,330 1,418 710 850 90 $3.70 $3.50 $3.25 $3.00 $3.00 $2.91 $2.92 $2.78 $2.66 $2.61 $2.64 $2.70 $- $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00

• 100

400 900 1,400 1,900 2,400 2018 2019 2020 2021 2022 2023 MMcfe/day

Average Index Hedge Price(1) Hedged Volume Current NYMEX Strip(2) Mark-to-Market Value(2)

(1) Weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio. Includes 26,000 Bbl/d of propane hedged at $0.76/gallon and 6,000 Bbl/d of oil hedged at $56.99/Bbl for 2018 only. (2) As of 6/30/18.

Commodity Hedge Position ~$1.2B Mark-To-Market Unrealized Gains Based On 6/30/2018 Prices

2.4 Tcfe hedged through

2023 at $3.35/MMBtu

~26 MBbl/d of propane

hedged in 2018 at $0.76/Gal

$3.9B of realized gains

• n hedges since 2008

37

~100% of 2018 and 2019 Target Gas Production Hedged at $3.50/MMBtu

($/MMBtu)

$0.10/ Mcfe $0.15/ Mcfe < $0.10/ Mcfe $0 $0 $0.125/Mcfe $0.20/Mcfe $469 $0.45/Mcfe $585 $0.48/Mcfe $224 $0.15/Mcfe $37 $35 $0 $100 $200 $300 $400 $500 $600 2018 Guidance 2019 Target 2020 Target 2021 Target 2022 Target $ Millions Net Marketing Expense (High End) Net Marketing Expense (Low End) Hedge Gains

38

TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | FIRM TRANSPORTATION & HEDGE BOOK

A Paired Trade – Hedges Support Firm Commitments

Hedge Gains More than Offset Marketing Expense – Hedges Support FT Commitments Firm Transportation Portfolio

Allows Antero to achieve:

Effectively Hedge NYMEX Index

A key advantage as

• ur product is

delivered to NYMEX- related markets

Premium Price Certainty

Less volatility and greater surety in realized prices 5-Year Cumulative: Hedge Gains: $1,350 Marketing Expense: ($461) Net Uplift: $889

Hedge Portfolio Supports Firm Commitments

$1,150 $2,830 $6,061 $795 $179 $311 $395 $250 $2,980

$0 $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000

AM IPO (2014) Sale of Water Business (2015) Sale of AM Units (2016) Sale of AM Units (9/6/17) AM Distributions Received as of 6/30/18 Total Proceeds to Date Expected Earnout Payments (2019E-2020E) Pre-tax Value

• f AM Units

Held by AR @ $30.41 (09/20/18) Pre-tax Cumulative Value of Antero Midstream

Cash Proceeds (SMM)

Midstream Driving Value for AR Since Inception

Antero Midstream Return on Investment for AR (Pre-tax)(1) 4.7x ROI

Takeaway Assurance Return on Investment Downstream Visibility

(1) Midstream proceeds received by AR to date plus market value of AR’s 53% ownership of AM at 6/30/18 divided by the approximate $1.3B of AR capital invested at time of AM IPO.

39

TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | MIDSTREAM DRIVING VALUE

Consistent results through the price cycles Antero’s integrated strategy has resulted in peer-leading all-in realized prices amongst the peer group

$5.17 $5.10 $4.09 $4.08 $3.60 $3.90

$- $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 2013 2014 2015 2016 2017 1H 2018

AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5

Source: Public data from company 10-Ks. Peers include CNX, COG, EQT, RRC and SWN. All-in realized natural gas equivalent pricing includes liquids and hedge realizations for the period. Hedge realizations is the stippled top portion of each bar.

The Leader in All-In Realized Pricing in Appalachia…

40

TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PROFITABILITY DRIVERS

Antero Has Been the Leader in Natural Gas Equivalent Prices For Over Five Years

($/Mcfe) Nymex Henry Hub

All-In Realized Pricing ($/Mcfe) – Appalachian Peers (Includes Liquids and Hedge Realizations)

$3.36 $2.97 $2.07 $2.06 $1.61 $1.86 $- $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 2013 2014 2015 2016 2017 1H 2018 AR Peer 1 Peer 2 Peer 4 Peer 5 Peer 3 EBITDAX Margin ($/Mcfe)

41

Consistent Leader in EBITDAX Margin

On a Stand-Alone EBITDAX Margin Basis, Antero has Consistently Outperformed its Appalachian Peers Through Up and Down Commodity Cycles

Source: SEC filings and company press releases. AR 2017 margins exclude $0.10/Mcfe negative impact from WGL and SJR natural gas contract disputes. Peers include CNX, COG, EQT, RRC & SWN. (1) AR and EQT EBITDAX include distributions from midstream ownership. Cash costs for AR and EQT represent stand-alone GPT, production taxes, LOE and cash G&A. Post-hedge and post net marketing expense where applicable.

WTI Price ($/Bbl) WTI Oil Price ($/Bbl) $0 $20 $40 $60 $80 $100 $120

Stand-Alone EBITDAX Margin vs WTI Oil Price

TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | EBITDAX MARGINS

Sustainable margins through the price cycles Antero’s integrated strategy has resulted in peer-leading EBITDAX margins for over 5 years

Disciplined Capital Efficient Midstream Model

Antero Midstream At A Glance

43

Market Cap………………....... Enterprise Value….........……. LTM Adjusted EBITDA(1)…….. % Gathering/Compression… % Water…..…..…..…..…….. Net Debt/LTM EBITDA…….... Corporate Debt Rating………. $5.7B $7.1B $619 MM 65% 35% 2.3x Ba2 / BB+ /BBB-

Note: Equity market data as of 9/20/2018. Balance sheet data as of 6/30/2018.

• 1. LTM Adjusted EBITDA as of 6/30/18. Adjusted EBITDA is a non-GAAP measure. For additional information regarding this measure, please see “Antero Midstream Non-GAAP Measures” in the Appendix.

ANTERO MIDSTREAM │DISCIPLINED CAPITAL EFFICIENT MIDSTREAM MODEL

AM Highlights AMGP Highlights

Market Cap………………....... Net Debt/LTM EBITDA...……. $3.2B –

Antero Midstream Utica Assets Antero Midstream Marcellus Assets

Compressor Station: In Service Antero Clearwater Facility Processing Facility Compressor Station: 2018 Gathering Pipeline Fresh Water Pipeline Stonewall Pipeline

Sherwood Processing Facility – 1.8 Bcf/d Existing Capacity Antero Clearwater Treatment Facility 60,000 Bbl/d Capacity Stonewall JV Pipeline New Smithburg JV Processing Facility – Civil Work Under Way

$280 $404 $529 $730 2.2x 2.1x 2.3x

0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 $1,800 2015A 2016A 2017A 2018E Guidance 2019E 2020E 2021E 2022E

EBITDA Leverage

Disciplined EBITDA Growth

44

AM EBITDA and Leverage

2014 IPO Leverage Target: Low 2x

ANTERO MIDSTREAM │DISCIPLINED CAPITAL EFFICIENT MIDSTREAM MODEL

2Q 2018 Leverage: 2.3x

Capital Efficiency Drives Free Cash Flow Generation

DISCIPLINED CAPITAL EFFICIENT BUSINESS MODEL

45

AM Throughput Growth

Over $2.4 billion of Free Cash Flow from 2018 – 2022 Before Distributions

($800) ($600) ($400) ($200) $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 2014A 2015A 2016A 2017A 2018 Guidance 2019 Target 2020 Target 2021 Target 2022 Target AM Cash Flow Outspend Before Distributions

With No Change to Throughput Volumes ~$500MM in Capital Efficiencies

Earn-out Payments from Water Drop Down

Leverage existing asset base and realization of “full build-out EBITDA multiples”

Note: Includes water earnings and capital invested on a recast basis prior to drop down and excludes drop down purchase price

We Are Here AM Free Cash Flow Before Distributions

Free Cash Flow is a non-GAAP measure. For additional information regarding this measure, please see “Antero Midstream Non-GAAP Measures” in the Appendix..

Antero Midstream Project Economics

46

AM Project Economics by Investment

30% 18% 15% 30% 15% 15% 40% 28% 25% 40% 25% 18% 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% LP Gathering HP Gathering Compression Fresh Water Delivery Advanced Wastewater Treatment Processing/ Fractionation Internal Rate of Return

“Just-in-time” capital investment philosophy drives attractive project IRR’s 17% 12% 29% 12%

• 30%

% of 5-year Organic Project Backlog Weighted Avg: 25% IRR

ORGANIC PROJECT BACKLOG WITH PEER-LEADING RETURNS

Antero Midstream Return on Invested Capital

47

AM Return on Invested Capital (ROIC)

2017 ROIC of 15% in

• nly fourth year of AM
• perations

Future organic growth capital leverages existing trunklines and major gathering arteries

12% 9% 13% 15% 0% 5% 10% 15% 20% 25% 2014A 2015A 2016A 2017A 2018E 2019E 2020E

Actual Consensus

Source: Factset consensus estimates. See appendix for ROIC calculation

Fewer pads to service reduces capital with same throughput

DISCIPLINED CAPITAL EFFICIENT BUSINESS MODEL

Return on invested capital is a non-GAAP measure. For additional information regarding this measure, please see “Antero Midstream Non-GAAP Measures” in the Appendix.

AM Long-Term Distribution and Coverage Targets

48

$1.03 $1.33 $1.72 $2.21 $2.85 $3.42 $4.10 1.8x 1.4x 1.3x 0.0x 0.2x 0.4x 0.6x 0.8x 1.0x 1.2x 1.4x 1.6x 1.8x 2.0x $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 2016A 2017A 2018 Guidance 2019 Target 2020 Target 2021 Target 2022 Target DCF Coverage Ratio Distribution Per Unit Distribution Guidance (Mid-point)

Long-Term Distribution Targets and DCF Coverage Unchanged capital investment philosophy with disciplined financial policies result in ability to target peer-leading distribution growth through 2022

Distribution Target (Mid-point) DCF Coverage Targets

Note: Implied yield based on AM unit price as of 9/20/18.

Implied Yield 9.4% 5.7% ANTERO MIDSTREAM │DISCIPLINED CAPITAL EFFICIENT MIDSTREAM MODEL

Antero Midstream’s Premier Asset Footprint

Gathering and Compression Fresh Water Delivery Wastewater Handling and Treatment Processing and Fractionation

Antero Midstream provides a customized full value chain midstream solution in the lowest cost natural gas and liquids basins: the Marcellus and Utica Shale

• Integrated system in the core of the Marcellus

and Utica Shales delivering wellhead gas directly to key processing plants and long haul pipelines

• Joint Venture with MPLX (NYSE: MPLX) aligns

the largest liquids-rich resource base with the dominant processing and fractionation footprint in Appalachia

• Largest freshwater delivery system in

Appalachia that has a 100% track record of timely fresh water deliveries to AR’s completions

• Largest wastewater treatment facility in the

world for shale oil and gas operations

PREMIER INTEGRATED APPALACHIAN MIDSTREAM ASSETS

49

Northeast Value Chain Opportunity

50

~$1.9B Organic Project Backlog ~$800MM JV Project Backlog

WELL PAD

LOW PRESSURE GATHERING HIGH PRESSURE GATHERING

COMPRESSION GAS PROCESSING (50% INTEREST) REGIONAL GATHERING PIPELINE (15% INTEREST) FRACTIONATION TERMINALS & STORAGE

Y-GRADE PIPELINE (ETHANE, PROPANE, BUTANE) NGL PRODUCT PIPELINES

LONG HAUL PIPELINE

INTERCONNECT

END USERS

PDH PLANT

>$1.0B Downstream Investment Opportunity Set

Note: Third party logos denote company operator of respective asset.

AM Assets AM/MPLX JV Assets Potential AM Opportunities

Upstream Downstream

5-year identified project inventory of $2.7B plus an additional $1.0B of potential downstream opportunities

OUTLOOK: ORGANIC PROJECT BACKLOG WITH PEER-LEADING RETURNS

Most Integrated Natural Gas & NGL Business in the U.S.

51

World Class E&P Operator in Appalachia

Contiguous Core Acreage Position Allows for Long Lateral Drilling and Significant Capital Efficiencies Largest NGL Producer in the U.S. Leads to Peer Leading Cash Flow Margins Optimized 5-Year Plan Results in High Return Drilling & Free Cash Flow Midstream Ownership & Integration Delivers Value and Just-in-Time Infrastructure Buildout

53% Ownership

ANTERO RESOURCES | SUMMARY

A Leading Northeast Infrastructure Platform Levered Exposure to Northeast Infrastructure Buildout

Appendix

APPENDIX | 2018 GUIDANCE

Updated 2018 Guidance

Stand-Alone Consolidated

Net Daily Production (Bcfe/d) ~2.7 Net Liquids Production (BBl/d) ~130,000 Natural Gas Realized Price Differential to Nymex $0.05 to $0.10 Premium C3+ NGL Realized Price (% of Nymex WTI) 57.5% – 62.5% Cash Production Expense ($/Mcfe) $2.05 – $2.15 $1.60 – $1.70 Marketing Expense ($/Mcfe) (10% Mitigation Assumed) $0.10 – $0.125 G&A Expense ($/Mcfe) (before equity-based compensation) $0.125 – $0.175 $0.15 - $0.20 Adjusted EBITDAX $1,700 – $1,800 $2,050 – $2,150 Adjusted Operating Cash Flow $1,480 – $1,600 $1,750 – $1,900 Net Debt / LTM Adjusted EBITDAX Low 2x Mid 2x D&C Capital Expenditures ($MM) $1,500 $1,300 Land Capital Expenditures ($MM) $150 ($25MM Maintenance) $150 ($25MM Maintenance)

Note: See Appendix for key definitions. Cash flow and EBITDAX guidance based on 12/31/2017 strip pricing . 2018 average NYMEX and WTI pricing was $2.83/MMBtu and $59.57/Bbl, respectively. (1) Includes lease operating expense, gathering, compression, processing and transportation expense and production and ad valorem taxes.

53

APPENDIX | 5-YEAR ASSUMPTIONS

Antero Guidance and Long-Term Target Assumptions

Stand-Alone Consolidated

Net Daily Production (MMcfe/d) 20% CAGR through 2020 and 15% Growth in each of 2021 and 2022 Natural Gas Realized Price Differential to Nymex $0.05 to $0.10 Premium (2018) $0.00 to $0.10 Premium (2019 – 2022) C3+ NGL Realized Price (% of Nymex WTI) 57.5% – 62.5% (2018) 69% (2019+) – ME2 Fees Booked to Transport Costs Realized Oil Price Differential to WTI ($5.00) – ($6.00) Cash Production Expense ($/Mcfe)(1) $2.05 - $2.15 (2018) $2.10 – $2.25 (2019 – 2022) $1.60 - $1.70 (2018) $1.65 – $1.75 (2019 – 2022) Marketing Expense ($/Mcfe) $0.10 - $0.125 (2018) $0.15 – $0.20 (2019) <$0.10 (2020) $0.00 (2021 – 2022) G&A Expense ($/Mcfe) (before equity-based compensation) $0.125 – $0.175 (2018 – 2019) $0.10 – $0.15 (2020 – 2022) $0.15 - $0.20 (2018 – 2019) $0.10 – $0.15 (2020 – 2022) Cash Interest Expense ($/Mcfe) $0.175 – $0.225 (2018 – 2019) $0.10 – $0.15 (2020 – 2021) <$0.10 (2022) $0.25 – $0.30 (2018 – 2019) $0.20 – $0.25 (2020 – 2022) Well Costs ($MM / 1,000’) (Assumes 12,000’ completions at 2,000 lbs. per foot of proppant) Marcellus: $0.95 MM Utica: $1.07 MM Marcellus: $0.80 MM Utica: $0.95 MM

(1) Includes lease operating expense, gathering, compression, processing and transportation expense and production and ad valorem taxes.

54

55

APPENDIX | 5-YEAR ASSUMPTIONS

Antero Guidance and Long-Term Target Assumptions (Cont.)

Stand-Alone E&P Consolidated

Adjusted Operating Cash Flow(1) $10.4B (Cumulative 2018 – 2022) N/A Annual D&C Capital Expenditures ($MM) $1,500 – $1,600 (2018 – 2020) $1,700 – $2,000 (2021 – 2022) $1,300 – $1,400 (2018 – 2021) $1,600 – $1,700 (2022) Land Maintenance Expenditures ($MM)(2) ~$200 (Cumulative 2018 – 2022) Free Cash Flow(1) $1.6B (Cumulative 2018 – 2022) N/A Leasehold Growth Capital Expenditures ($MM) ~$300 (Cumulative 2018 – 2022) Number of Well Completions 790 well completions Marcellus EUR per 1,000’ of Lateral 2.0 Bcf/1,000’; 2.5 Bcfe/1,000’ (25% ethane recovery) Utica EUR per 1,000’ of Lateral 2.0 Bcfe/1,000’ (ethane rejection)

Note: See Appendix for key definitions. Cash flow guidance is based on 12/31/2017 strip pricing. Average NYMEX pricing was $2.83/MMBtu, $2.81/MMBtu, $2.82/MMBtu, $2.85/MMBtu and $2.89/MMBtu in 2018, 2019, 2020, 2021 and 2022. Average WTI pricing was $59.57/Bbl, $56.19/Bbl, $53.76/Bbl, $52.29/Bbl and $51.67/Bbl for 2018, 2019, 2020, 2021 and 2022. (1) Adjusted Operating Cash Flow and Free Cash Flow are non-GAAP financial measures. For additional information regarding these measures, please see the following pages (“Antero Definitions” and “Antero Non-GAAP Measures”). (2) Includes leasehold capital expenditures required to achieve targeted working interest percentage.

56

APPENDIX | PROJECT ASSUMPTIONS

Antero Long-Term Target Project Assumptions

In-Service Date

Rover Phase 2 2H 2018 Mariner East 2 2H 2018 WB Xpress West 4Q 2018 WB Xpress East 4Q 2018 Mountaineer Xpress / Gulf Xpress YE 2018

Note: Based on publicly available information.

6/30/2018 Debt Maturity Profile

$1,000 $1,100 $750 $650 $600 $455 $770 $0 $500 $1,000 $1,500 $2,000 $2,500 2018 2019 2020 2021 2022 2023 2024 2025

Liquidity & Debt Term Structure

AR Credit Facility AM Credit Facility AR Senior Notes AM Senior Notes

New credit facilities for AR and AM have allowed Antero to extend its average debt maturity out to 2022

57

ANTERO RESOURCES | CONSOLIDATED LIQUIDITY AND BALANCE SHEET

No maturities until 2021

Deleveraging is Driving Ratings Momentum

58

ANTERO RESOURCES | TRENDING TOWARDS INVESTMENT GRADE

Moody's S&P Fitch

Corporate Credit Ratings History

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

Ba3 / BB- B1 / B+ B2 / B B3 / B- Ba2 / BB Ba1 / BB+ Caa1 / CCC+ / CCC Baa3 / BBB- 2010

Investment Grade Rating: BBB- Fitch Jan. 2018 Stable through commodity price crash

Credit Markets Have a Strong Appreciation for Antero Momentum

Investment Grade Rating from Fitch (BBB-) & Recent Upgrade from S&P (BB+) Stable Credit Ratings with Consistent Upgrades from the Beginning of the Decade Through the Downturn

2011 2012 2013 2014 2015 2016 2017 2018

Upgrade to BB+ S&P Feb. 2018

Investment Grade

Outlook to Positive Moody’s Feb. 2018

59

APPENDIX | ASSUMPTIONS

D&C Capital Transparency

D&C Capital

(1)

(1) Based on Marcellus AFE, which assumes inflation on consumable products (i.e. sand/chemicals).

($MM) 2018 2019 2020 Total Well Completions (I.e. First Sales) 145 155 160 Average Lateral 9,700 10,500 11,600 Adjusted Well Count (I.e. Based on Capital Timing) 155 157 150 Average Lateral 9,700 10,500 11,600 Total Adjusted Lateral Feet 1,503,500 1,648,500 1,740,000 Cost per Lateral Foot ($MM/1,000) - Lateral Savings ONLY $0.86 $0.83 $0.81 Implied D&C $1,293 $1,368 $1,409 Savings from Concurrent Ops. / Increasing Stages per Day ($24) ($79) Adjusted Capital Cost $1,293 $1,344 $1,330 Implied Cost per Lateral Foot ($MM/1,000)

$0.86 $0.82 $0.76

60

APPENDIX | PRICING ASSUMPTIONS

Antero Long-Term Target Pricing Assumptions

Commodity prices: All forecasts reflect the following commodity price cases:

• Base case: Strip commodity pricing at 12/31/17 ($54.71 WTI crude oil & $2.84 Nymex Henry Hub) for 2018 - 2022
• Upside case: 12/31/17 Strip for 2018 and $60 WTI crude oil & $2.85 Nymex Henry Hub gas prices for 2019 - 2022
• Downside case: 12/31/17 Strip for 2018 $50 WTI crude oil & $2.85 Nymex Henry Hub gas prices for 2019 - 2022

Current Hedging Arrangements

• 80% Hedged on natural gas production through 2020 at $3.44/MMBtu and 52% hedged on natural gas production

through 2022 at $3.34/MMBtu

• 23% hedged on C3+ NGL production in 2018 at $0.75/gallon (Propane volume only)

Oil and Gas Strip Commodity Prices (12/31/17)

$59.62 $56.19 $53.76 $52.29 $51.67 $2.82 $2.81 $2.82 $2.85 $2.89 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $35.00 $40.00 $45.00 $50.00 $55.00 $60.00 $65.00 2018 2019 2020 2021 2022 WTI Nymex ($/Bbl) ($/MMBtu)

17.3 Tcfe Proved 35.1 Tcfe Probable 2.3 Tcfe Possible Proved Probable Possible

54.6 Tcfe 3P 96% 2P Reserves

• 1. 2012, 2013, 2014 and 2015 reserves assuming ethane rejection. In 2016, 554 MMBbls of ethane assumed recovered to meet ethane contract. In 2017, 656 MMBbls of ethane assumed recovered to meet ethane
• contract. 2017 SEC prices were $2.91/MMBtu for natural gas and $45.35/Bbl for oil on a weighted average Appalachian index basis. 2017 10-year average SEC prices are NYMEX $3.11/Mcf and WTI $51.03/Bbl.

2017 realized C3+ and C2+ prices including regional market differentials were $0.77/gal and $0.49/gal, respectively.

3P RESERVES BY VOLUME – 2017(1) NET PROVED RESERVES (Tcfe)(1)

• −

− − /1,000’ of

• −

− /1,000’ of

• 0.0

2.0 4.0 6.0 8.0 10.0 12.0 14.0 16.0 18.0 2010 2011 2012 2013 2014 2015 2016 2017 Marcellus Utica 0.7 2.8 4.3 7.6 12.7

(Tcfe)

13.2 15.4 17.3

Substantial Reserve Growth

61

APPENDIX | RESERVE GROWTH

$10.8B Proved PV-10

2017 Year-End proved pre-tax PV-10 at SEC pricing, including $0.6B of hedge value

$18.4B 3P PV-10

2017 Year-End 3P pre-tax PV-10 at SEC pricing, including $0.6B of hedge value

62

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

APPENDIX | GATHERING AND COMPRESSION FEES

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

63

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

APPENDIX | GATHERING AND COMPRESSION FEES

Private Gathering & Compression Agreements

P

Publicly Disclosed Agreements

Competitive Fresh Water Fee Structure

64

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 $0.50/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 >620,000 truck trips and 42,000 tons of CO2 emissions for

AR in 2017 alone

• 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 both 2018 and 2019

1 2 3 4

APPENDIX | FRESH WATER DELIVERY FEES

AR Saved ~$0.50/Bbl on Fresh Water in 2017

65

James Webb Pad – 9 Wells Round Trip Miles Minutes $/Bbl Pad Avg 15 36 $3.60 AR Costs Per Barrel $(0.09) Stewart Pad – 4 Wells Round Trip Miles Minutes $/Bbl Pad Avg 51 83 $4.38 AR Savings Per Barrel $0.69 Edna Monroe Pad – 10 Wells Round Trip Miles Minutes $/Bbl Pad Avg 36 77 $4.28 AR Savings Per Barrel $0.59 Bettinger Pad – 1 Wells Round Trip Miles Minutes $/Bbl Pad Avg. 56 99 $4.64 AR Savings Per Barrel $0.99

Antero 2017 Average Loading Time (Minutes) 60 Staging Time (Minutes) 120 Trucking Cost per Hour $90 Barrels Per Truck (Bbls) 90 Avoided Cost to Truck to All Pads ($/Bbl) $4.19 Firm Delivery Fee paid to AM ($/Bbl) $3.69 AR Fresh Water Savings ($/Bbl) $0.50

Nicki Pad – 6 Wells Round Trip Miles Minutes $/Bbl Pad Avg. 41 74 $4.23 AR Savings Per Barrel $0.58

Antero analyzed its 2017 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 2017 alone totaled $0.50/Bbl or $28 million

Note: Select 2017 pads shown above are illustrative of the company wide development plan across AR’s acreage position.

APPENDIX | FRESH WATER DELIVERY FEES

Note: 2H 2018 based on 2018 balance strip pricing as of 7/25/2018. Local index represents a blend of Dominion South and TETCO M2 pricing. Midwest index represents a blend of Chicago and MichCon pricing. Gulf Coast index represents a blend of Gulf and Nymex-based pricing.

Antero 2018 Firm Transport Index Breakdown

Expected Natural Gas Price Realization Improvement

TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PROFITABILITY DRIVERS

~97% of Antero Gas Is Expected to be Sold in Favorably Priced Markets in the Balance of 2018

66

59% 60% 17% 14% 16% 23% 8% 3% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 1H 2018 2H 2018

Index Differential % of Gas Sold Differential % of Gas Sold

Local Markets(1) $(0.55) 8% $(0.43) 3% Midwest $0.07 16% $(0.07) 23% TCO $(0.20) 17% $(0.22) 14% Gulf Coast $(0.14) 59% $(0.11) 60% Wtd.Avg. Differential: $(0.15) 100% $(0.13) 100% BTU Uplift $0.24 $0.24

All-in vs. NYMEX +$0.09

+$0.11

+$0.05 - $0.10

Updated forecast premium to NYMEX after BTU uplift

5% decrease to Local Markets Local Midwest TCO Gulf Coast 8% increase in exposure to Midwest & Gulf Cost Markets

Fresh Water MVC’s and Earn-Outs

67

• Minimum volume commitments (MVC’s) on fresh water delivery volumes were put in

place to support revenues and rates of return for AM’s acquisition of the water business in September 2015

• Earn-outs at year-end 2019 and 2020 provided incentives for AR to perform long term

Fresh Water Delivery MVC’s and Earn Out Payments (MBbl/d)

90 100 120 120 161 MBbl/d 200 MBbl/d 123 153 221(1) 50 100 150 200 250 2016A 2017A 2018 2019 2020 MBbl/d MVCs Earnout #1 Earnout #2 Actual Volumes

APPENDIX | FRESH WATER DELIVERY MVCS

(1) Represents 1Q 2018 fresh water delivery volumes.

Guidance Summary - 2018

68

Guidance 2017 Guidance 2018 Guidance Change

Net Income ($MM) $305 - $345 $435 - $480 +41% Adjusted EBITDA ($MM) $520 - $560 $705 - $755 +35% DCF ($MM) $405 - $445 $575 - $625 +41% Distribution Growth 28 – 30% 28 – 30%

• DCF Coverage

1.30x – 1.45x 1.25x - 1.35x

• 7%

Maintenance Capex ($MM) $65 $65 0% Growth Capex ($MM) $735 $585

• 20%

Total Capex ($MM) $800 $650

• 19%

APPENDIX: GUIDANCE

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.

Core of the Core Development Programs

69

SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | UNDERSTANDING THE RESOURCE

EUR Regime BTU Range 2018 Well Completions 2019 Well Completions Half Cycle Well Economics (Strip Price) Total Undrilled Locations Average Lateral Length Marcellus

Highly-Rich Gas Condensate 1275-1350 14 30 200% 447 12,500’ Highly-Rich Gas 1200-1275 106 101 89% 935 11,500’ Rich Gas 1100-1200 4 32% 495 11,150’

Ohio Utica

Condensate 1250-1300 19 2 59% 206 9,950’ Rich Gas 1100-1200 3 9 39% 102 11,550’ Dry Gas 1050 3 9 36% 187 10,450’ Total(1) 145 155 Program Stats: 93% | 98% Strip | $70 Oil ROR 1,253 BTU Average Program Stats: 102% | 106% Strip | $70 Oil ROR 1,248 BTU Average High-Grade Inventory Totals: 2,372 High-Grade Inventory Averages: 11,400’

1) Wells completed reflects midpoint of targeted completions per year.

Hedged Multiple 2019E EBITDAX ($MM): $2,094 Excludes AM Distributions EV / 2019E EBITDAX: 3.4x Unhedged Multiple 2019E EBITDAX ($MM): $1,520 Excludes AM Distributions & Hedge Revenues EV / 2019E EBITDAX: 3.9x

$6,275 $5,949 $5,274 $1,420 $3,006 ~$1,175 $11,550 $7,124

$0 $2,000 $4,000 $6,000 $8,000 $10,000 $12,000 $14,000 Consolidated Enterprise Value Antero Midstream Net Debt After Tax Value of AM Owned Units AR Stand-alone E&P Value

70

APPENDIX | VALUE CREATION

Antero Consolidated and Stand-Alone Enterprise Value

Note: Balance sheet data as of 6/30/18, except AR and AM unit price as of 9/20/18 and hedge mark-to-market as of 6/30/18. Hedged and unhedged 2019E EBITDAX multiples represent consensus less 75% of consensus AM EBITDA (water contribution).

99MM units

• wned and AM

market price of $30.41/unit

Market Value Net Debt Hedge MTM E&P Assets

21% tax on value of AM units (net of NOLs)

($MM)

Antero Assumptions: Single Well Economics

71

APPENDIX | SINGLE WELL ECONOMICS

SWE Cost Type Description of Cost Half Cycle Full Cycle

Well Costs

• Drilling and completion costs
• Assumes well costs for a 12,000’ lateral,

2,000 lbs of proppant per lateral foot and both fresh and flowback water

• Utica Condensate regime assumes 1,500

lbs or proppant per lateral foot Marcellus: $10.6MM Utica South/Dry: $12.2MM Utica Beaver: $11.5MM (60% AM water fees) Marcellus: $11.4MM Utica South/Dry: $12.8MM Utica Beaver: $12.2MM (100% AM water fees) Working Interest / Net Royalty Interest

• Reflects Antero’s average WI/NRI in the

respective plays Marcellus: 100% / 85% Utica: 100% / 81% Midstream Gathering Fees

• Midstream low pressure, high pressure

and compression fees 60% of AM gathering fees 100% of AM gathering fees Firm Transportation(1)

• FT costs may include both demand and

variable fees associated with expected production Variable FT costs only of $0.06/Mcf (variable fees associated with expected production) Fully utilized FT costs of $0.54/Mcf (including both demand and variable fees) General & Administrative Costs

• General and administrative costs

associated with Antero None $750,000 per well Land

• Assumes 12,000’ well with 660’/1,000’

spacing for Marcellus/Utica respectively and $3,600 per acre None Marcellus - $655,000 per well Utica - $1,087,000 per well Spud to FP Timing

• Provides a timeframe for initial spud to

first production 184 days spud to FP (Economics based on first production at 7/1/2018) Realized Pricing

• Commodity price assumptions

06/30/2018 strip pricing (weighted)

(1) SWEs exclude marketing expenses and related commodity hedge contracts that support Antero’s firm transportation portfolio

Single Well Economics: Marcellus – In Ethane Rejection

72

APPENDIX | SINGLE WELL ECONOMICS

Classification Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas

Modeled BTU 1313 1250 1150 1050 EUR (Bcfe): 32 29 26 24 EUR (MMBoe): 5.3 4.9 4.3 3.9 % Liquids: 33% 24% 11% 0% Well Cost ($MM): $10.6 $10.6 $10.6 $10.6 Bcfe/1,000’: 2.7 2.5 2.2 2.0 Net F&D ($/Mcfe)(1): $0.40 $0.43 $0.49 $0.53 Net Direct Operating Expense ($/Mcfe): $1.26 $1.33 $1.39 $1.05 Transportation Expense ($/Mcfe): $0.04 $0.05 $0.06 $0.06 Pre-Tax NPV10 ($MM): $27.0 $16.5 $6.6 $3.9 Pre-Tax Half Cycle ROR: 200% 89% 32% 21% Payout (Years): 0.5 1.5 2.8 4.1 Gross Core Locations in BTU Regime: 447 935 495 874

Cumulative Volumes Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas Gas (MMcf) Oil (Mbbl) Gas (MMcf) Oil (Mbbl) Gas (MMcf) Oil (Mbbl) Gas (MMcf) Oil (Mbbl)

Year 1 4,300 116 4,300 24 4,300 4,300 Year 2 6,500 143 6,500 31 6,500 6,500 Year 3 7,900 152 7,900 36 7,900 7,900 Year 4 9,100 157 9,100 40 9,100 9,100 Year 5 10,200 161 10,200 44 10,200 10,200 Year 10 13,900 176 13,900 57 13,900 13,900 Year 20 18,500 194 18,500 73 18,500 18,500

Note: SWE cost assumptions reflect average costs per Mcfe on the first five years of the life of a well. F&D cost is defined as current D&C cost per 1,000’ lateral divided by net EUR per 1,000’ lateral assuming 85% NRI in Marcellus. Please see “Antero Definitions” and “Antero Non-GAAP Measures” in the Appendix.

Single Well Economics: Utica – In Ethane Rejection

73

APPENDIX | SINGLE WELL ECONOMICS

Note: SWE cost assumptions reflect average costs per Mcfe on the first five years of the life of a well. F&D cost is defined as current D&C cost per 1,000’ lateral divided by net EUR per 1,000’ lateral assuming 81% NRI in Utica. Please see “Antero Definitions” and “Antero Non-GAAP Measures” in the Appendix.

Classification Condensate Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas

Modeled BTU 1275 1235 1215 1175 1050 EUR (Bcfe): 13 25 29 28 26 EUR (MMBoe): 2.2 4.2 4.8 4.6 4.4 % Liquids 40% 30% 21% 16% 0% Well Cost ($MM): $10.8 $11.5 $12.2 $12.2 $12.2 Bcfe/1,000’: 1.1 2.1 2.4 2.3 2.2 Net F&D ($/Mcfe)(1): $1.03 $0.57 $0.53 $0.55 $0.57 Net Direct Operating Expense ($/Mcfe): $1.18 $1.32 $1.44 $1.47 $0.85 Transportation Expense ($/Mcfe): $0.04 $0.05 $0.05 $0.06 $0.07 Pre-Tax NPV10 ($MM): $8.8 $17.9 $12.1 $8.4 $8.6 Pre-Tax Half Cycle ROR: 59% 139% 58% 39% 36% Payout (Years): 1.7 0.4 1.8 2.1 2.6 Gross Core Locations in BTU Regime: 206 27 22 102 187

Cumulative Volumes Condensate Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas

Gas (Mmcf) Oil (Bbl) Gas (Mmcf) Oil (Bbl) Gas (Mmcf) Oil (Bbl) Gas (Mmcf) Oil (Bbl) Gas (Mmcf) Oil (Bbl) Year 1 1,600 129 4,300 110 5,600 6 5,400 5,500 Year 2 2,300 153 5,800 127 7,700 8 7,500 8,200 Year 3 2,800 166 6,900 138 9,100 9 8,800 10,000 Year 4 3,300 176 7,700 146 10,200 10 9,900 11,400 Year 5 3,600 186 8,400 152 11,100 11 10,800 12,500 Year 10 5,000 219 10,900 175 14,500 14 14,100 16,500 Year 20 6,700 258 14,000 202 18,700 19 18,200 21,200

74

APPENDIX | DISCLOSURES & RECONCILIATIONS

Antero Non-GAAP Measures

Consolidated Adjusted EBITDAX, Stand-alone E&P Adjusted EBITDAX, Consolidated Adjusted Operating Cash Flow, Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow are financial measures that are not calculated in accordance with U.S. generally accepted accounting principles (“GAAP”). The non-GAAP financial measures used by the company may not be comparable to similarly titled measures utilized by other companies. These measures should not be considered in isolation or as substitutes for their nearest GAAP measures. The Stand-alone measures are presented to isolate the results of the operations of Antero apart from the performance

• f Antero Midstream, which is otherwise consolidated into the results of Antero.

Consolidated Adjusted EBITDAX and Stand-alone E&P Adjusted EBITDAX The GAAP financial measure nearest to Consolidated Adjusted EBITDAX is net income or loss including noncontrolling interest that will be reported in Antero’s consolidated financial statements. The GAAP financial measure nearest to Stand-alone E&P Adjusted EBITDAX is Stand-alone net income or loss that will be reported in the Parent column of Antero’s guarantor footnote to its financial

• statements. While there are limitations associated with the use of Consolidated Adjusted EBITDAX and Stand-alone E&P 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

• ther factors;
• helps investors to more meaningfully evaluate and compare the results of Antero’s operations (both on a consolidated and

Stand-alone basis) from period to period by removing the effect of its capital structure from its operating structure; and

• is used by management for various purposes, including as a measure of Antero’s operating performance (both on a

consolidated and Stand-alone basis), in presentations to the company’s board of directors, and as a basis for strategic planning and forecasting. Consolidated Adjusted EBITDAX is also used by the board of directors as a performance measure in determining executive compensation. Consolidated 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 Consolidated Adjusted EBITDAX and Stand-alone E&P Adjusted EBITDAX as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company’s net income on a consolidated and Stand-alone basis, 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, Consolidated Adjusted EBITDAX and Stand-alone E&P Adjusted EBITDAX provide no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.

75

APPENDIX | DISCLOSURES & RECONCILIATIONS

Antero Non-GAAP Measures

Antero has not included a reconciliation of Consolidated Adjusted EBITDAX or Stand-alone E&P Adjusted EBITDAX to their nearest GAAP financial measures for 2018 because it cannot do so without unreasonable effort and any attempt to do so would be inherently

• imprecise. Antero is able to forecast the following reconciling items between Consolidated Adjusted EBITDAX and Stand-alone E&P

Adjusted EBITDAX to net income from continuing operations including noncontrolling interest: Antero has a significant portfolio of commodity derivative contracts that it does not account for using hedge accounting, and forecasting unrealized gains or losses on this portfolio is impracticable and imprecise due to the price volatility of the underlying commodities. Antero is also forecasting no impact from franchise taxes, gain or loss on early extinguishment of debt, or gain or loss on sale of assets, for 2018. For income tax expense (benefit), Antero is forecasting a 2018 effective tax rate of 18% to 19%.

(in thousands) Consolidated Stand-alone E&P Low High Low High Interest expense $250,000 $300,000 $200,000 $220,000 Depreciation, depletion, amortization, and accretion expense 950,000 1,050,000 800,000 900,000 Impairment expense 100,000 125,000 100,000 125,000 Exploration expense 5,000 15,000 5,000 15,000 Equity-based compensation expense 95,000 115,000 70,000 90,000 Equity in earnings of unconsolidated affiliate 30,000 40,000 N/A N/A Distributions from unconsolidated affiliates 40,000 50,000 N/A N/A Distributions from limited partner interest in Antero Midstream N/A N/A 166,000 170,000

76

APPENDIX | DISCLOSURES & RECONCILIATIONS

Antero Non-GAAP Measures

Consolidated Adjusted Operating Cash Flow, Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow The GAAP financial measure nearest to Consolidated Adjusted Operating Cash Flow is cash flow from operating activities as reported in Antero’s consolidated financial statements. The GAAP financial measure nearest to Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow is Stand-alone cash flow from operating activities that will be reported in the Parent column of Antero’s guarantor footnote to its financial statements. Management believes that Consolidated Adjusted Operating Cash Flow and Stand-alone E&P Adjusted Operating Cash Flow are useful indicators of the company’s ability to internally fund its activities and to service or incur additional debt on a consolidated and Stand-alone basis. Management believes that changes in current assets and liabilities, which are excluded from the calculation of these measures, relate to the timing of cash receipts and disbursements and therefore may not relate to the period in which the operating activities occurred and generally do not have a material impact on the ability of the company to fund its

• perations. Management believes that Free Cash Flow is a useful measure for assessing the company’s financial performance and

measuring its ability to generate excess cash from its operations. There are significant limitations to using Consolidated Adjusted Operating Cash Flow, Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company’s net income on a consolidated and Stand-alone E&P basis, the lack of comparability of results

• f operations of different companies and the different methods of calculating Consolidated Adjusted Operating Cash Flow and Stand-

alone E&P Adjusted Operating Cash Flow reported by different companies. Consolidated Adjusted Operating Cash Flow and Stand- alone E&P Adjusted Operating Cash Flow do not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and

• bligations.

Antero has not included reconciliations of Consolidated Adjusted Operating Cash Flow, Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow to their nearest GAAP financial measures for 2018 because it would be impractical to forecast changes in current assets and liabilities. However, Antero is able to forecast the earn out payments expected from Antero Midstream associated with the water drop down transaction that occurred in 2015, each of which is a reconciling item between Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow, as applicable, and cash flow from operating activities as reported in the Parent column of Antero’s guarantor footnote to its financial statements. Antero forecasts these items to be $125 million in each of 2019 and 2020. Additionally, Antero is able to forecast lease maintenance expenditures and Stand-alone drilling and completion capital, each of which is a reconciling item between Free Cash Flow and its most comparable GAAP financial measure. For the 2018 to 2022 period, Antero forecasts cumulative lease maintenance expenditures of $200 million and cumulative Stand-alone E&P drilling and completion capital of $8.6 billion.

Antero Resources Stand-Alone Adjusted EBITDAX Reconciliation

APPENDIX | DISCLOSURES & RECONCILIATIONS

AR Stand-Alone Adjusted EBITDAX Reconciliation

($ in millions) Three Months Ended LTM Ended 6/30/2018 6/30/2018

Net income (loss) including noncontrolling interest $(136,385) $230,254 Commodity derivative gains (55,336) (211,640) Gains on settled commodity derivatives 95,884 335,252 Marketing derivative (gains) losses 110 (72,730) Gains (losses) on settled marketing derivatives (15,884) 94,158 Interest expense 54,388 222,479 Loss on early extinguishment of debt — 1,205 Income tax expense (25,573) (461,669) Depreciation, depletion, amortization, and accretion 202,283 759,260 Impairment of unproved properties 134,437 302,473 Impairment of gathering systems and facilities 4,470 4,470 Exploration expense 1,471 7,983 Gain on change in fair value of contingent acquisition consideration (3,947) (14,181) Equity-based compensation expense 13,204 65,070 Distributions from Antero Midstream 38,559 143,100 Equity in net income of Antero Midstream 26,926 74,056 Total Adjusted EBITDAX $334,607 $1,479,540

77

Antero Resources Consolidated Adjusted EBITDAX Reconciliation

Consolidated Adjusted EBITDAX Reconciliation

($ in millions) Three Months Ended LTM Ended 6/30/2018 6/30/2018

Net income (loss) including noncontrolling interest $(67,275) $453,149 Commodity derivative gains (55,336) (211,640) Gains on settled commodity derivatives 95,884 335,252 Marketing derivative (gains) losses 110 (72,730) Gains (losses) on settled marketing derivatives (15,884) 94,158 Interest expense 69,349 267,224 Loss on early extinguishment of debt — 1,500 Income tax benefit (25,573) (461,669) Depreciation, depletion, amortization, and accretion 238,750 889,707 Impairment of unproved properties 134,437 302,473 Impairment of gathering systems and facilities 8,501 31,932 Exploration expense 1,471 7,983 Equity-based compensation expense 19,071 91,194 Equity in earnings of unconsolidated affiliate (9,264) (31,466) Distributions from unconsolidated affiliate 10,810 32,270 Total Adjusted EBITDAX $405,051 $1,729,337 APPENDIX | DISCLOSURES & RECONCILIATIONS

78

Antero Midstream Non-GAAP Measures

APPENDIX

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Non-GAAP Financial Measures and Definitions Antero Midstream views Adjusted EBITDA as an important indicator of the Partnership’s performance. Antero Midstream defines Adjusted EBITDA as Net Income before interest expense, depreciation expense, impairment expense, accretion of contingent acquisition consideration, equity-based compensation expense, excluding equity in earnings of unconsolidated affiliates and including cash distributions from unconsolidated affiliates. Antero Midstream uses Adjusted EBITDA to assess:

• the financial performance of the Partnership’s assets, without regard to financing methods in the case of Adjusted EBITDA, capital

structure or historical cost basis;

• its operating performance and return on capital as compared to other publicly traded partnerships in the midstream energy sector,

without regard to financing or capital structure; and

• the viability of acquisitions and other capital expenditure projects.

The Partnership defines Distributable Cash Flow as Adjusted EBITDA less interest paid, income tax withholding payments and cash reserved for payments of income tax withholding upon vesting of equity-based compensation awards, cash reserved for bond interest and ongoing maintenance capital expenditures paid. Antero Midstream uses Distributable Cash Flow as a performance metric to compare the cash generating performance of the Partnership from period to period and to compare the cash generating performance for specific periods to the cash distributions (if any) that are expected to be paid to unitholders. Distributable Cash Flow does not reflect changes in working capital balances. The Partnership defines Free Cash Flow as cash flow from operating activities before changes in working capital less capital

• expenditures. Management believes that Free Cash Flow is a useful indicator of the Partnership’s ability to internally fund infrastructure

investments, service or incur additional debt, and assess the company’s financial performance and its ability to generate excess cash from its operations. Management believes that changes in operating assets and liabilities relate to the timing of cash receipts and disbursements and therefore may not relate to the period in which the operating activities occurred. The Partnership defines Return on Invested Capital as net income plus interest expense divided by average total liabilities and partners’ capital, excluding current liabilities. Management believes that Return on Invested Capital is a useful indicator of the Partnership’s return on its infrastructure investments. The Partnership defines Adjusted Operating Cash Flow as net cash provided by operating activities before changes in current assets and liabilities. See “Non-GAAP Measures” for additional detail.

Antero Midstream Non-GAAP Measures

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The GAAP financial measure nearest to Adjusted Operating Cash Flow is cash flow from operating activities as reported in Antero Midstream’s consolidated financial statements. Management believes that Adjusted Operating Cash Flow is a useful indicator of the company’s ability to internally fund its activities and to service or incur additional debt. Management believes that changes in current assets and liabilities, which are excluded from the calculation of these measures, relate to the timing of cash receipts and disbursements and therefore may not relate to the period in which the operating activities occurred and generally do not have a material impact on the ability of the company to fund its operations. Management believes that Free Cash Flow is a useful measure for assessing the company’s financial performance and measuring its ability to generate excess cash from its operations. There are significant limitations to using Adjusted Operating Cash Flow and Free Cash Flow as measures 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 Operating Cash Flow reported by different companies. Adjusted Operating Cash Flow does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, and other commitments and obligations. Antero Midstream has not included reconciliations of Adjusted Operating Cash Flow and Free Cash Flow to their nearest GAAP financial measures for 2018 because it would be impractical to forecast changes in current assets and liabilities. Antero Midstream is able to forecast capital expenditures, which is a reconciling item between Free Cash Flow and its most comparable GAAP financial measure. For the 2018 to 2022 period, Antero forecasts cumulative capital expenditures of $2.7 billion. Antero Resources non-GAAP measures and definitions are included in the Antero Resources analyst day presentation, which can be found on www.anteroresources.com.

Antero Midstream Non-GAAP Measures

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Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures. The GAAP measure most directly comparable to Adjusted EBITDA and Distributable Cash Flow is Net Income. The non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow should not be considered as alternatives to the GAAP measure of Net Income. Adjusted EBITDA and Distributable Cash Flow are not presentations made in accordance with GAAP and have important limitations as an analytical tool because they include some, but not all, items that affect Net Income and Adjusted EBITDA. You should not consider Adjusted EBITDA and Distributable Cash Flow in isolation or as a substitute for analyses of results as reported under GAAP. Antero Midstream’s definition of Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other partnerships . Antero Midstream has not included a reconciliation of Adjusted EBITDA to the nearest GAAP financial measure for 2018 because it cannot do so without unreasonable effort and any attempt to do so would be inherently imprecise. Antero Midstream is able to forecast the following reconciling items between Adjusted EBITDA and net income (in thousands): The Partnership cannot forecast interest expense due to the timing and uncertainty of debt issuances and associated interest rates. Additionally, Antero Midstream cannot reasonably forecast impairment expense as the impairment is driven by a number of factors that will be determined in the future and are beyond Antero Midstream’s control currently. Twelve months ended December 31, 2018 Low High Depreciation expense ........................................................................................... $ 160,000 — $ 170,000 Equity based compensation expense ................................................................... 25,000 — 35,000 Accretion of contingent acquisition consideration .............................................. 15,000 — 20,000 Equity in earnings of unconsolidated affiliates .................................................... 30,000 — 40,000 Distributions from unconsolidated affiliates........................................................ 40,000 — 50,000

Adjusted EBITDA and DCF Reconciliation

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Adjusted EBITDA and DCF Reconciliation ($ in thousands)

Three months ended June 30, 2017 2018 Net income $ 87,175 $ 109,466 Interest expense 9,015 14,628 Impairment of property and equipment expense — 4,614 Depreciation expense 30,512 36,433 Accretion of contingent acquisition consideration 3,590 3,947 Accretion of asset retirement obligations — 34 Equity-based compensation 6,951 5,867 Equity in earnings of unconsolidated affiliates (3,623) (9,264) Distributions from unconsolidated affiliates 5,820 10,810 Gain on sale of assets- Antero Resources — (583) Adjusted EBITDA 139,440 175,952 Interest paid (2,308) 372 Decrease in cash reserved for bond interest (1) (8,734) (8,734) Income tax withholding upon vesting of Antero Midstream Partners LP equity-based compensation awards(2) (2,431) (1,500) Maintenance capital expenditures(3) (16,422) (16,000) Distributable Cash Flow $ 109,545 $ 150,090 Distributions Declared to Antero Midstream Holders Limited Partners 59,695 72,943 Incentive distribution rights 15,328 28,461 Total Aggregate Distributions $ 75,023 $ 101,404 DCF coverage ratio 1.5x 1.3x

1) Cash reserved for bond interest expense on Antero Midstream’s 5.375% senior notes outstanding during the period that is paid on a semi-annual basis on March 15th and September 15th of each year. 2) Estimate of current period portion of expected cash payment for income tax withholding attributable to vesting of Midstream LTIP equity-based compensation awards to be paid in the fourth quarter. 3) Maintenance capital expenditures represent the portion of our estimated capital expenditures associated with (i) the connection of new wells to our gathering and processing systems that we believe will be necessary to

• ffset the natural production declines Antero Resources will experience on all of its wells over time, and (ii) water delivery to new wells necessary to maintain the average throughput volume on our systems.

Cautionary Note

Regarding Hydrocarbon Quantities

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, 2017 included in this presentation have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates as of December 31, 2017 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,
• 2016. 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.

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APPENDIX | DISCLOSURES & RECONCILIATIONS