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 of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "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 obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. 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 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.
ANTERO RESOURCES | OCTOBER 2018 PRESENTATION The Size and Scale to Capitalize on the Resource
Antero Resources Profile Antero Acreage SW Marcellus Core Ohio Utica Core Market Cap……….……...... $6.3B Enterprise Value….…………… $10.1B Corporate Debt Ratings……… Ba2 / BB+ / BBB- Stand-Alone Leverage……….. 2.6x Net Production (2018E)…...... 2.7 Bcfe/d Liquids...... 130,000 Bbl/d 3P Reserves………..…...... 54.6 Tcfe C2+ NGLs(1)...... 2,131 MMBbls Condensate...... 131 MMBbls Net Acres………….…...……… 620,000 Core Drilling Locations………. 3,295 Hedge Mark to Market……….. $1.2B AR Midstream Ownership (53%) $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 | OCTOBER 2018 PRESENTATION 3 Organizational Structure
A $17B Integrated Natural Gas and NGL Business
Sponsors(1) Public Sponsors(1) Public
27% 73% 58% 42%
NYSE: AR 100% Incentive NYSE: AMGP E&P Enterprise Value: $7.1B Distribution Rights Enterprise Value: $3.2B (IDRs) Corp Ratings: Ba2 / BB+ / BBB- No Ratings
53%
Public 47%
NYSE: AM Enterprise Value: $7.1B Corp Ratings: Ba2 / BB+ / BBB-
Note: Enterprise value as of 9/20/18. AR E&P enterprise value excludes $3.0 Bn of ownership value in AM and AM net debt. (1) Sponsors represent Warburg Pincus, Yorktown & senior management. ANTERO RESOURCES | ORGANIZATIONAL STRUCTURE 4 Natural Gas Liquids Update: Leading Position & Strong Fundamentals
5 Leader in Leverage to NGL Prices
Top NGL Producers in the U.S.
2018 Consensus C2+ NGL Production Pre-hedged Realized NGL Price ($/Bbl) 140 45% Pre-Hedge NGL % of Total Product Revenues (1) NGLs Generate 33% 40% 120 116 of AR Revenue (1)
2Q 2018 35% 34% /d) 33% 100
30% MBbl
80 25% ProductRevenues
60 20%
Hedge - 16% 15% 15%
40 13% 13% ofPre 11% Consensus C2+ NGLs C2+ ( Consensus 11% 11% 10% 10%
20 % NGL 5%
$26.35 $27.86 $23.69 $24.10 $34.88 $26.71 $28.87 $25.62 $24.39 $28.83 0 0% AR EOG RRC DVN APC* COP* OXY* MRO* NBL PXD Antero Delivers Highest Exposure to Rising NGL Prices 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. NATURAL GAS LIQUIDS UPDATE | LEADING POSITION AND STRONG FUNDAMENTALS 6 Rapidly Growing NGL Production
Antero NGL Production Growth by Purity Product
Natural Gasoline (C5+) IsoButane (iC4) 250,000 245,000 Normal Butane (nC4) Propane (C3) Ethane (C2) C3+ Production
200,000 C2
/d)
150,000 Bbl
Total ( Total C2 Ethane 40,000 C3 100,000 C2 Ethane 26,500
C2 Ethane 17,476 nC4 50,000 iC4
C5+ 0 2014 2015 2016 2017 2018E 2019E 2020E 2021E 2022E Guidance Target Target Target Target
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. NATURAL GAS LIQUIDS UPDATE | LEADING POSITION AND STRONG FUNDAMENTALS 7 Appalachia: Geographic & Infrastructure NGL Advantaged Permian, Rockies, Mid-Continent & Bakken Appalachia . Transport Y-grade for out-of-basin fractionation . In-basin fractionation and transport marketable . Severely constrained fractionation,Y-grade purity products transportation and NGL storage capacity . Sufficient fractionation capacity . Rapidly rising fractionation fees . Fixed fractionation fees . Midstream controls product destination and captures . Producer controls product destination and captures pricing uplift pricing uplift
31 BAKKEN/WILLISTON
APPALACHIA Exports to Cornerstone Mariner East International MID-CONTINENT Markets ROCKIES Conway
PERMIAN Mont Belvieu
NATURAL GAS LIQUIDS UPDATE | LEADING POSITION AND STRONG FUNDAMENTALS 8 Ethane: Positive Frac Spread Driving Recovery
Higher Ethane Prices Needed to Ethane price improvement exceeds change Incentivize Recovery in Basins Farther in natural gas on a gallon equivalent basis from U.S. Gulf Coast
Natural Gas and Ethane Pricing ($/Gal) Ethane Production and Frac Spreads
$1.00 $0.70 2,500
$0.90 $0.60 $0.80 2,000 $0.50 /d)
$0.70
Mbbl $0.60 $0.40 1,500 $0.50 $0.30 $0.40 $ per$Gallon $0.20 1,000 $0.30 $0.20 $0.10
500 ( ProductionEthane
$0.10 2018 Gas Value: $0.00 Fractionation Spread ($ per Gallon)per ($ Spread Fractionation -7% Y/Y $0.00 -$0.10 0
Henry Hub Gas ($/Gallon Equivalent) U.S. Ethane Production Mont Belvieu Ethane Fractionation Spread: (MB Ethane vs Henry Hub Gas)
Source: EIA, Bloomberg NATURAL GAS LIQUIDS UPDATE | LEADING POSITION AND STRONG FUNDAMENTALS 9 Antero’s Ethane Exposure: All Upside
Antero’s ethane has a natural gas pricing Antero’s balanced approach to ethane “floor” and purity ethane “ceiling”; increases sales results in 50% of contracts tied in ethane purity prices are all upside to purity ethane prices vs. natural gas value
Ethane Revenue Uplift ($MM)
Incremental Revenue +$0.10/Gal C2 price change = $40MM incremental revenue $350 Antero has no hedges in $305 $300 place for C2 volumes $265
$250 $130 $90 $200 $175
$150 $115
$100 $60 44 MBbl/d
$50 55 MBbl/d 55 MBbl/d 35 MBbl/d 40 MBbl/d $0 1H 2018 2H 2018E 2018 2019E 2019E Actual Strip Prices Actual + Strip Strip Prices +$0.10 Upside $0.23/Gal $0.45/Gal $0.32/Gal $0.40/Gal $0.50/Gal Ethane sensitivity: +$0.10/gallon x 2019 production target x ~50% exposure to Mt. Belvieu = ~$40MM incremental 2019 ethane Revenue 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. NATURAL GAS LIQUIDS UPDATE | LEADING POSITION AND STRONG FUNDAMENTALS 10 Strong Propane Fundamentals
Current propane days of supply are Material reduction in U.S. propane 18% below last year and 24% inventories relative to the 5-year average below the 5-year average
Propane Days of Supply U.S. Propane Inventories
80 MB C3 $1.03/gallon 120 remainder of 2018 70 100
60
80
50
40 60 MMBbls
Days Days ofSupply 30 2017 40 2017 20 2018
2018 20 10
0 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
5-Yr Range 2018 2017 5-Yr Avg 2013-2017 5-Yr Range 2017 2018 5-Yr Avg 2013-2017
Source: EnVantage Inc. and Energy Information Administration (EIA). NATURAL GAS LIQUIDS UPDATE | LEADING POSITION AND STRONG FUNDAMENTALS 11 Strong Natural Gas Liquids (C3+) Price Improvement
Mont Belvieu C3+ NGL prices have But still remain well within historical increased 28% year-over-year and 145% levels on a on a relative basis since January 2016 lows compared to WTI crude oil
Mont Belvieu C3+ NGL Price ($/Gallon) C3+ Price as a Percent of WTI
$2.00 100%
$1.80 90% $1.60
$1.40 2H18 80% $1.17/Gal $1.20 $49.19/Bbl 67% 70% $1.00 60% $0.80
C3+ NGLs ($/Gallon) NGLs C3+ $0.60 50% $0.40
C3+ NGLs as a % of WTI Crude Oil CrudeWTI % asofa NGLs C3+ 40% $0.20
$0.00 30%
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. NATURAL GAS LIQUIDS UPDATE | LEADING POSITION AND STRONG FUNDAMENTALS 12 Antero’s C3+ NGL Exposure: Highly Leveraged
Antero’s NGL price directly benefits NGL fundamentals remain constructive and from the recent strengthening support higher prices despite illiquid and of NGL prices at Mont Belvieu backwardated NGL futures prices
Antero C3+ Barrel Composition by Product – Mont Belvieu Pricing
Mont Belvieu Pricing (Pre-differential & ME2) 100% Antero 1H18 Balance 90% C3+ Barrel Avg. Price 2018 Variance
80% 57% $0.87 $1.03 +$0.16 Propane 70% 57% 16% $0.86 $1.21 +$0.35 60% 10% $1.12 $1.22 +$0.10 50% 17% $1.46 $1.58 +$0.12 40% Butane C3+ $/Gal $0.99 $1.17 +$0.18 16% 30% IsoButane C3+ $/Bbl $41.74 $49.19 +$7.46 20% 10% Pentane 10% 17% Volume (Bbl/d) 67,000 88,000 +21,000 0%
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. NATURAL GAS LIQUIDS UPDATE | LEADING POSITION AND STRONG FUNDAMENTALS 13 Powerful C3+ NGL Pricing Upside Exposure
Compounded pricing leverage from For every $5.00/Bbl increase in NGL increasing volumes, prices, and Mariner prices, Antero generates an East 2 uplift drives cash flow growth incremental $170MM in Revenue
Pre-Hedge Revenue Sensitivity to C3+ NGL Pricing ($MM)
Antero has no hedges in Incremental Revenue +$5/Bbl change = place for C3+ volumes +$170MM in revenue for 2019 and beyond $1,800 $1,535 $1,600 $1,365 $1,400 $1,130 $405 $1,200 $235 $1,000 $700 $800 88 MBbl/d $600 $430 ME2 on 11/1 $400 67 MBbl/d 77.5 MBbl/d 93 MBbl/d 93 MBbl/d $200 No ME2 ME2 on 11/1 Full ME2 Full ME2 $0 1H 2018 2H 2018E 2018 2019E 2019E Actual Strip Prices Actual + Strip Strip Prices Strip +$5/Bbl $35/Bbl $43/Bbl $40/Bbl $38/Bbl $43/Bbl
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.
NATURAL GAS LIQUIDS UPDATE | LEADING POSITION AND STRONG FUNDAMENTALS 14 Antero’s NGL Pricing Uplift from Mariner East 2
Mariner East 2 will allow AR to access 50,000 Bbl/d Mariner East 2 commitment international LPG markets and realize a equates to over $82 MM of ~$4.50/Bbl uplift on its exported barrels incremental annual cash flow
Domestic Markets International Markets 31 Mariner East 2 (“ME2”) Initial Capacity (4Q18): Committed volumes Europe Netback 2019 Full Capacity (3Q19): 275 MBbl/d AR Commitments: 35 Mbbl/d C3 Marcus NWE Price ($/Gal) $1.08 15 MBbl/d C4 Hook Pipeline, Terminal & AR Expansion Rights: 50 Mbbl/d C3/C4 $(0.24) Shipping Cost (1) NWE Netback $0.84 Blended Conway / MB $0.73 Netback Conway 4Q 2018 Uplift vs. 1Q18 Average +$0.11 Differential Antero Blended Netback 2019
Conway/Mt. Belvieu Price ($/Gal) $0.89 Asia Netback 2019 FEI Price ($/Gal) $1.17 Average 1H 2018 Differential $(0.16) Pipeline, Terminal & Blended Conway/MB Netback $0.73 $(0.33) Shipping Cost (1)
Mont Asia Netback $0.84 Belvieu Blended Conway / MB $0.73 Netback Uplift vs. 1Q18 Average +$0.11 Differential 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. NATURAL GAS LIQUIDS UPDATE | LEADING POSITION AND STRONG FUNDAMENTALS 15 A Cash Flow Inflection Point Joining an Announced Longer Lateral Elite E&P Development Plan Group With: Averaging 11,500’ per Well Sustainable Cash Flow Growth Scale
Step Change in Capital Generating 5-Year Free Cash Efficiency Reduces 5-Year Flow of $1.6B at YE Strip & D&C Capex by $2.9B $2.8B at $60 Oil Double Digit Growth
Highest Leverage to NGL Low Prices Among Top Disciplined Returns Focus Leverage NGL Producers → 33% - 37% Full Cycle Returns → 23% 5-Year Debt-Adjusted Free Cash Production CAGR per share → 22% 5-Year Cash Flow Flow The Size & Scale to CAGR per share Capitalize on Resource
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 16 Long Lateral Development Plan
59% of Inventory Now 5-Year Plan Averages 11,500’ ≥ 10,000’ Lateral Length
Average Lateral Length Core Drilling Inventory by Lateral Length per Completed Well
14,000 1,600 12,700 1,450 1,400 12,000 10,800’ 1,200 Average Inventory 10,000 Lateral Length
1,000
8,000 locations)of Feet 800 6,000
Number 600 ( 498 4,000 400
2,000 200
0 0 2018 2019 2020 2021 2022 <6,000' 6,000' - 8,000' - 10,000' - ≥12,000' Wells 8,000' 10,000' 12,000' 145 155 160 165 165 Completed(1) Feet 1) Wells completed reflects midpoint of targeted completions per year. SCALE & GROWTH | COST EFFICIENCY DRIVERS: LONGER LATERALS 17 Step Change in Capital Efficiency
Consolidated Drilling & Completion Capital Production Targets Expenditures
As of December 2016 As of December 2017 As of December 2016 As of December 2017 $2.5 $2.4 $2.9B Capex Reduction 6.0 $2.2 Over 5 Years 5.2 5.2 $2.0 $2.0 Cumulative Reduction in Drilling & 5.0 4.6 4.5 $1.7 $1.7 Completion Capital $1.6 4.0 3.9 4.0 $1.5 $1.4 $1.3 3.3 3.3 $1.3 $1.3 3.0 2.7 2.7
$Billions Bcfe/d $1.0 Same Production 2.0 Targets $0.5 20% Production CAGR 2018-2020 1.0 15% Production CAGR 2021-2022
$0.0 0.0 2018 2019 2020 2021 2022 2018 2019 2020 2021 2022
Same Production Growth With Much Less Capital Spending
VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | SIGNIFICANT CAPITAL REDUCTION 18 Breakdown of D&C Capex Savings
D&C Capex Capital Allocation Lateral Lengths Cycle Times & Enhanced Well Cost Savings Savings Recoveries $0.4B Well Cost Savings
Related to reduced AFEs including lower flowback $1.1B water handling cost due Optimizing Capital to Clearwater Facility and $2.9B Allocation begin self-sourcing sand Capital Efficiencies Captured Within Continued shift to high- D&C Capex From $0.5B graded Marcellus New Development Improved Cycle Program Times
Reduced drilling days, increase in stages per day and $0.9B concurrent operations Lateral Lengths
$0.09MM/1,000’ savings from 9,000’ to 12,000’
Note: See appendix for further detail on D&C capital. VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | COST EFFICIENCY DRIVERS 19 Drilling and Completion Efficiencies Drilling Days Completion Stages per Day
35 10.0 10.0 9.0 30 9.0
8.0
25 20 7.0 20 5.4 6.0 5.0 5.0 4.6 15 12 10 4.0 3.6 Drilling Drilling Days 8
10 3.0 Stages Stages per Day 5 2.0 1.0 0 - 2014 2015 2016 2017 2Q 2018 RECORD 2014 2015 2016 2017 2Q 2018 RECORD Marcellus Utica Marcellus Utica Average Lateral Length per Well Average Lateral Feet per Day
17,445 8,206 18,000 6,000 16,000 15,075 5,169 5,000 14,000 12,886 3,872
12,000 4,000
9,611 10,000
3,000 2,575 Feet 8,000 Feet 6,000 2,000 4,000 1,000 2,000 - - 2014 2015 2016 2017 2Q 2018 RECORD 2014 2015 2016 2017 2Q 2018 RECORD Marcellus Utica Marcellus Utica
Note: Percentage increase and decrease arrows represent change in Marcellus data from 2014 to 2Q 2018. VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | COST EFFICIENCY DRIVERS 20 Compelling Full Cycle Well Economics
Fully burdened well economics Corporate ROR support investment well in excess of cost of capital
Single Well Economics Bridge to Corporate Level Returns
120% Well Assumptions 12,000’ Lateral 111% 9% 100% 1250 BTU Wellhead Gas 102% 20% 2.4 Bcfe/1,000’ EUR(3) 80% 6/30/2018 Strip Pricing 82% 20%
60% 61% 13%
49% 40% 12% 37%
20% AR WACC ≈ 8% 0% ROR (1) Pad cost HalfHalf cyclecycle Fixed FT ROR with Full AM ROR-fully G&A ROR post- Land costs FullFull cycle (2) (D&C only) & facilities RORROR fees full FT fees fees burdened G&A (corporate)ROR fees ROR 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. VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | ATTRACTIVE WELL ECONOMICS DRIVE GROWTH 21 Capital Discipline Leads to Free Cash Flow
48% reduction in D&C capital budget Future D&C capital budgets that are and 15 rig reduction since 2014 measured and within cash flow
Stand-Alone Adjusted Cash Flow Alongside D&C Capital Expenditures Stand-Alone Adjusted Cash Flow From Operations D&C Capital Antero Rig Count $3,000 D&C Maintenance Capital(1) 25
$2,500 Free Cash Flow(2) 20
$2,000 15 $1,500
In Millions In 10 $1,000
5 Rigs Drilling of Number $500
$0 0 2014 2015 2016 2017 2018E 2019E 2020E 2021E 2022E 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. VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | SUSTAINABLE CASH FLOW GROWTH 22 Near Term Free Cash Flow Inflection Point
Production growth and strong liquids Capital discipline to reduce completion prices drives free cash flow crews and D&C capex in 2H18 in 4Q18 and beyond
Stand-Alone Cash Flow(1)
Q4 2018 represents a free cash flow
inflection point Free Cash Flow Generation Flow Cash Free
Delevering & Return of Capital Potential
Q3 2018 Q4 2018 2019E – 2022E
Cash Cash Outspend 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. ANTERO RESOURCES | DISCIPLINED FOCUS ON RETURNS & CAPITAL EFFICIENCY 23 Cash Flow Growth → Deleveraging Profile
12/31/17 Strip Pricing (Base Case) $60 Oil / $2.85 Gas 5.0x $50 Oil / $2.85 Gas S&P Upgrade to BB+ 23% Debt-Adjusted 4.5x Moody’s Ba2 Outlook “Positive” Production CAGR
3.9x 4.0x 3.6x BBB- Rating Fitch Recently Rated AR Investment 3.5x Grade 2.9x 3.0x 2.8x 2Q 2018 Generates Free 2.5x Cash Flow Leverage: 2.6x 2.0x
Alone Financial Leverage Financial Alone - Deleveraging Supported By: 1.5x
• 2.4 Tcfe Hedge Position Stand 1.0x • 4.7 Bcf/d FT Portfolio • $1.4B of Targeted AM Balance Sheet Deleveraging & 0.5x Distributions Optionality 0.0x 2014A 2015A 2016A 2017A 2018 2019 2020 2021 2022 Guidance Target Target Target Target
Leverage targets inclusive of $500 MM of maintenance and discretionary land capex from 2018 - 2022
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. CAPITAL DISCIPLINE AND DELEVERAGING | CASH FLOW DRIVES LOW LEVERAGE 24 Antero Profile Should Drive Multiple Expansion
Median Debt/ Median EV/ # of Adjusted 2019 Adj. AR 2019E Companies EBITDAX EBITDAX unhedged U.S. Publicly Traded E&Ps EBITDAX Multiple: 3.9x 52 2.1x 5.5x
Leverage < 3.0x 37 1.5x 5.6x Premium for: Enterprise Value Scale > $10B 17 1.5x 6.2x
Production Growth Growth >15% 9 1.5x 6.2x
Leverage Low Leverage <2.0x in 2019 6 1.0x 6.9x Free EOG COG CXO CLR FCF Generation Cash in 2018 Flow PXD 5 0.8x 7.2x Permian & Appalachia 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 25 Attractive Free Cash Flow Yield
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 AR 7% FCF Yield(1) 9% Surpasses Industry Leading Peers, While Maintaining Strong Production 8% Growth
7%
6%
5%
4% FCF Yield FCF 3%
2%
1%
0% 2018 2019 2020 Free Cash Flow Yields Exceed Both Best-In-Class Peers & Integrated Oil & Gas Companies
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. VALUE PROPOSITION: HIGH RETURN PORTFOLIO & FREE CASH FLOW | 5-YEAR OUTLOOK 26 Scale & Growth: Liquids-Rich Resource Meets Capital Efficiency Positioned in the Core of the Core
Antero Acreage Antero Marcellus Wells Industry Marcellus Wells Northern Rich High-Graded Core Antero Marcellus Rig 2.24 Bcfe/1,000’ Avg. EUR Industry Marcellus Rig 61% Undeveloped > 1,300 lb/ft Completions
Dry Gas Southern Rich High-Graded Core High-Graded Core 2.30 Bcfe/1,000’ Avg. EUR 2.24 Bcfe/1,000’ Avg. EUR 74% Undeveloped 66% Undeveloped AR Holds 13% of Undeveloped AR Holds 62% of Undeveloped
Advanced Completions High- Graded Most Active Percent (>1,300 lbs/ft) Core Areas Operators Undeveloped Southwest Marcellus Core Bcfe / Wells ~2.9 Million Acres 1,000’ ~76% Undeveloped Northern Rich RRC, CNX, HG 67% 2.24 474
Southern Rich AR, EQT, SWN 70% 2.24 517
EQT, CVX, Dry Gas 78% 2.30 747 RRC, CNX Antero is Very Well Positioned in the Core of the Core
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 28 Largest Undrilled Core Liquids Drilling Inventory
Core Marcellus & Utica Undrilled Locations(1)
4000 Who Can Consistently Drill Long Laterals? Who Has the 3500 3,295 Running Room? Antero Holds 40% of Core 3000 Undrilled Liquids-Rich Locations
Dry Gas Locations Largest Inventory in Appalachia
2500 2,333
2000 1,605 1500
Undrilled LocationsUndrilled 1,259 Rich Gas Locations 1000 NE PA Dry Gas 720 714 663 588 583 556 500
0 AR A B C D E F G H I Lateral Length: 10,848’ 9,563’ 6,775’ 7,731’ 7,723’ 8,639’ 6,040’ 9,583’ 8,905’ 8,396’ (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. SCALE & GROWTH | CORE OF THE CORE 29 A Pioneer in Longer Lateral Development in Appalachia
Antero Historical & Future Lateral Length Program
300 # of Avg. Lateral Antero Wells Length
Total Drilling Program 250 945 8,275 to Date 103 2018-2022 Program(2) 790 11,425
57
200 Wells to Date 245 10,700 13 ≥10,000’
12 93 Well Count Well 150 107
100
113 76 50 81 78 93 85 77
22 12 10 0 4 ≤ 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 > 15,000 Lateral Length(1) (1) All laterals rounded to the nearest thousand. (2) Represents wells placed to sales. SCALE & GROWTH | COST EFFICIENCY DRIVERS: LONGER LATERALS 30 Longer Laterals Scale the Resource
EURs by Marcellus Lateral Lengths
EUR in Bcfe/1,000' 2.3 Bcfe/1,000' R2 = .73 45
A 1:1 Proportional 40 Increase in EURs with
35 Longer Laterals Antero well results show no evidence of degradation in recovery per foot of 30 completed lateral out to over 14,000’
25
20 EUR (Bcfe) EUR
15
10
5
0 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 Lateral Length (ft) Note: Assumes ethane rejection. SCALE & GROWTH | COST EFFICIENCY DRIVERS: LONGER LATERALS 31 The Longer, the Better…
Single Well Economics by Lateral Lengths
PV-10 ($MM) ROR (%)
$25.0 100% 89% 90%
77% $20.0 80%
$21.0 58% $15.0 60% $16.6
$10.0 40% $11.9
$5.0 $7.1 20%
$- 0% 6,000' Lateral 9,000' Lateral 12,000' Lateral 15,000' Lateral
~60% Improvement in ROR from a 6,000’ Lateral to a 15,000’ Lateral
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. SCALE & GROWTH | COST EFFICIENCY DRIVERS: LONGER LATERALS 32 Declining Well Costs → Longer Laterals the Next Step
Historical Well Costs
Marcellus Utica
41% | 43% 2014 2017 2014 2017 Lower Costs $2.20 $2.60 Marcellus | Utica reduction in well costs $2.40 from 2014 to 2017 for a 9,000’ lateral $2.00 - 54% from efficiencies $2.20 - 45% from service costs $1.80
$2.00
$1.60 $1.80
$1.40 $1.60 9% | 10% $1.40
$1.20 43% 43%
Cost Benefit 41%
$MM/1,000 $MM/1,000 ftof lateral $MM/1,000 $MM/1,000 ftof lateral
$1.20 Reduction
Marcellus | Utica reduction in well cost Reduction per 1,000’ lateral going from $1.00 9,000’ to 12,000’ laterals $1.00 $0.80 $0.80 9% 10% $0.60 Reduction $0.60 Reduction 3,000 6,000 9,000 12,00015,000 3,000 6,000 9,000 12,000 15,000 Lateral Length (ft) Lateral Length (ft)
Note: Well costs reflect 2,000 pound per foot completions. See Appendix for further assumptions. SCALE & GROWTH | COST EFFICIENCY DRIVERS: LONGER LATERALS 33 Operating Evolution Continues Achievements Next Steps in 2018 Marcellus Well Cost(1) to Date Efficiency Evolution
Facilities, Pad Flowback & Road Drilling Rigs/Services • Fit-for-purpose rigs improves Water Allocation 42% 5% 9% → Fit-for-purpose rigs with dual operation cycle times Decline in well costs Tubulars capabilities to improve cycle times • Enhanced walking and dual operation 4% since 2014 → Improved drillout efficiency capabilities Sand → Penetration rates still increasing with 12% new downhole motors • Concurrent operations Drilling • Larger pads allowing for production at Efficiency (25%) Completion Spreads/Services one end and drilling at the other Completion Spreads Completion Services → Concurrent operations with larger • More wells per pad 25% 24% pads allowing simultaneous drilling 46% and completion and easier access • Automated completion equipment Vendor-related cost → More wells per pad → increase stages per day reductions Drilling Rigs & Services → Automated completion equipment to 21% increase stages per day • Reduced cluster spacing → higher potential recoveries Sand 54% → 100 mesh sand for easier pumping & • 100 Mesh Sand Antero has 100% of 2018 Rigs and fewer screenouts → easier pumping with fewer Permanent cost 50% of 2019 Rigs Under Fixed 100% of Completion → Self-sourcing sand to reduce Rate Contracts with Average Rig screenouts and less cost efficiencies Spreads Under Contract Rates Declining Towards supply cost Through 2019 $17,500/day in 2018 as Higher Rig → Regional sand mines in the Permian • Self-Sourcing Sand Rate Contracts Roll Off expected to reduce demand for → reduce supply cost Northern White sand Efficiencies Expected to Offset Service Cost Inflation • Improved Drillout Efficiency
(1) Based on Marcellus 11,000 foot lateral and 2,000 pounds per foot AFE. Assumes nine wells per pad.
SCALE & GROWTH | OPERATING TECHNOLOGIES EVOLVE 34 Dramatically Lower F&D Cost
F&D Cost per Mcfe(1)(2)
Marcellus Utica $1.40 52% | 42% $1.28
$1.20 Lower F&D in Marcellus | Utica
$1.00 $0.94 $0.88
$0.80 $0.73 $0.73 $0.74
$0.60 $0.51 $0.42 $0.40
$0.20
$0.00 2014 2015 2016 2017 Dramatic Improvement in Operating Efficiencies, Lower Service Costs and Higher
(1) Ethane rejection assumed. Well Recoveries Have Driven F&D Costs Materially Lower (2) F&D cost is defined as current D&C cost per 1,000’ lateral divided by net EUR per 1,000’ lateral assuming 85% NRI in Marcellus and 81% NRI in Utica. Please see “Antero Definitions” and “Antero Non-GAAP Measures” in the Appendix. SCALE & GROWTH | COST EFFICIENCY DRIVERS: WELL COST REDUCTION 35 Rover Pipeline Uplift and Optionality
Unlocks development optionality between Rover Sherwood Lateral expected to be Marcellus and Utica and provides further placed into service in September Chicago & Gulf Coast exposure
Rover Pipeline Map
Chicago via Rover Rover Phase 1A (in-service) ($/MMBtu) 2019 Rover Phase 1B (in-service) Rover Laterals (3Q18-4Q18) (1) Chicago Price ($/MMbtu) $2.54 Natural Gas Pricing Hub 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 Ability to utilize 800 MMcf/d Rover Approximate Variable Cost $(0.04) capacity with both Marcellus Netback Price $2.59 production (Sherwood Processing Plant) and Utica production TETCO M2 Price $(2.10) (Seneca Processing Plant) Uplift vs. TETCO M2(2) $0.49
1. Futures prices as of 9/17/18. 2. Based on 2019 Tetco M2 futures prices and includes $0.14 of variable cost ANTERO RESOURCES | CONTROL DEVELOPMENT & MITIGATE INDUSTRY RISKS 36 Well Hedged at High Prices Relative to Strip
Commodity Hedge Position
Hedged Volume Average Index Hedge Price(1) Current NYMEX Strip(2) Mark-to-Market Value(2) ~100% of 2018 and 2019 Target Gas Production Hedged ($/MMBtu) at $3.50/MMBtu 2,400 2,330 2.4 Tcfe hedged through $5.00 2,195 2023 at $3.35/MMBtu $3.9B of realized gains $4.50 on hedges since 2008 ~26 MBbl/d of propane 1,900 $3.70 hedged in 2018 at $0.76/Gal $4.00 $3.50 $3.25 $3.50 $3.00 $3.00 $2.91 1,400 $3.00
/day $2.92 $2.78 $2.66 $2.50 $2.61 $2.64 $2.70 1,418 MMcfe 900 850 $2.00 710 $1.50
400 $1.00
90 $0.50
-100 2018 2019 2020 2021 2022 2023 $- ~$1.2B Mark-To-Market Unrealized Gains Based On 6/30/2018 Prices (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. TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PRODUCTIVITY DRIVERS 37 A Paired Trade – Hedges Support Firm Commitments
Hedge Portfolio Supports Net Marketing Expense (High End) Net Marketing Expense (Low End) Firm Commitments Hedge Gains $585 $0.48/Mcfe $600
$469 $0.45/Mcfe 5-Year Cumulative: $500 Firm Transportation Portfolio Hedge Gains: $1,350 Allows Antero to achieve: Marketing Expense: ($461)
$400 Net Uplift: $889
$300 $224
$ Millions $ $0.20/Mcfe $0.15/Mcfe Effectively $200 Premium Price Hedge NYMEX $0.125/Mcfe Certainty Index $100 $0.15/ Less volatility and Mcfe < $0.10/ $37 $35 A key advantage as $0.10/ Mcfe greater surety in Mcfe realized prices our product is $0 $0 $0 delivered to NYMEX- 2018 2019 Target 2020 Target 2021 Target 2022 Target related markets Guidance
Hedge Gains More than Offset Marketing Expense – Hedges Support FT Commitments
TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | FIRM TRANSPORTATION & HEDGE BOOK 38 Midstream Driving Value for AR Since Inception
Antero Midstream Return on Investment for AR (Pre-tax)(1)
$7,000 $2,980 $6,061 $6,000
4.7x
$5,000 ROI
$4,000 $395 $2,830 $250 $3,000 $311 $795 $179 $2,000 Cash ProceedsCash(SMM) $1,150 $1,000
$0 AM IPO (2014) Sale of Water Sale of AM Sale of AM AM Total Proceeds Expected Pre-tax Value Pre-tax Business Units (2016) Units (9/6/17) Distributions to Date Earnout of AM Units Cumulative (2015) Received as of Payments Held by AR @ Value of Antero 6/30/18 (2019E-2020E) $30.41 Midstream (09/20/18)
Takeaway Downstream Return on Assurance Visibility Investment
(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 $1.3B of AR capital invested at time of AM IPO.
TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | MIDSTREAM DRIVING VALUE 39 The Leader in All-In Realized Pricing in Appalachia… Antero’s integrated strategy has resulted in peer-leading all-in realized prices Consistent results through the price cycles amongst the peer group All-In Realized Pricing ($/Mcfe) – Appalachian Peers (Includes Liquids and Hedge Realizations)
$6.00 AR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Nymex Henry Hub
$5.17 $5.10 $5.00
$4.09 $4.08 $3.90
$4.00 $3.60
) Mcfe
$3.00 ($/
$2.00
$1.00
$- 2013 2014 2015 2016 2017 1H 2018 Antero Has Been the Leader in Natural Gas Equivalent Prices For Over Five Years
Source: Public data from company 10-Ks. Peers include CNX, COG, EQT, RRC and SWN. All-in realized natural gas equivalent pricing includes liquids and hedge realizations for the period. Hedge realizations is the stippled top portion of each bar. TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PROFITABILITY DRIVERS 40 Consistent Leader in EBITDAX Margin
Antero’s integrated strategy has resulted in Sustainable margins through the price cycles peer-leading EBITDAX margins for over 5 years
Stand-Alone EBITDAX Margin vs WTI Oil Price EBITDAX Margin WTI Price ($/Mcfe) ($/Bbl) AR Peer 1 Peer 2 Peer 4 Peer 5 Peer 3 WTI Oil Price ($/Bbl) $4.00 $120
$3.36 $3.50 $100 $2.97 $3.00 $80 $2.50 $2.07 $2.06 $1.86 $60 $2.00 $1.61
$1.50 $40
$1.00 $20 $0.50 $0 $- 2013 2014 2015 2016 2017 1H 2018 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. TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | EBITDAX MARGINS 41 Disciplined Capital Efficient Midstream Model Antero Midstream At A Glance AM Highlights Antero Midstream Marcellus Assets Market Cap………………...... $5.7B Enterprise Value…...... ……. $7.1B LTM Adjusted EBITDA(1)…….. $619 MM % Gathering/Compression… 65% New Smithburg JV % Water…..…..…..…..…….. 35% Processing Facility – Civil Work Under Way
Net Debt/LTM EBITDA…….... 2.3x Sherwood Processing Facility – 1.8 Bcf/d Corporate Debt Rating………. Ba2 / BB+ /BBB- Existing Capacity AMGP Highlights Market Cap………………...... $3.2B Net Debt/LTM EBITDA...……. – Antero Midstream Utica Assets
Antero Clearwater Treatment Facility 60,000 Bbl/d Capacity Stonewall JV Pipeline
Compressor Station: In Service Processing Facility
Compressor Station: 2018 Antero Clearwater Facility
Gathering Pipeline Fresh Water Pipeline Stonewall Pipeline
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 43 Disciplined EBITDA Growth
AM EBITDA and Leverage
EBITDA Leverage 2014 IPO Leverage $1,800 3.0x Target: Low 2x $1,600 2.3x 2.5x 2.2x $1,400 2.1x
$1,200 2.0x
$1,000 2Q 2018 Leverage: 2.3x 1.5x $800 $730
$600 $529 1.0x $404 $400 $280 0.5x $200
$0 0.0x 2015A 2016A 2017A 2018E 2019E 2020E 2021E 2022E Guidance
ANTERO MIDSTREAM │DISCIPLINED CAPITAL EFFICIENT MIDSTREAM MODEL 44 Capital Efficiency Drives Free Cash Flow Generation
With No Change Leverage existing asset base ~$500MM in Capital and realization of “full build-out Efficiencies to Throughput Volumes EBITDA multiples”
Over $2.4 billion of Free Cash Flow from 2018 – 2022 Before Distributions $1,400 AM Cash Flow Outspend Before Distributions $1,200 Earn-out Payments from Water Drop Down AM Throughput Growth $1,000 AM Free Cash Flow Before Distributions $800 $600 $400 We Are Here $200 $0 ($200) ($400) ($600) ($800) 2014A 2015A 2016A 2017A 2018 2019 2020 2021 2022 Guidance Target Target Target Target Note: Includes water earnings and capital invested on a recast basis prior to drop down and excludes drop down purchase price Free Cash Flow is a non-GAAP measure. For additional information regarding this measure, please see “Antero Midstream Non-GAAP Measures” in the Appendix.. DISCIPLINED CAPITAL EFFICIENT BUSINESS MODEL 45 Antero Midstream Project Economics
“Just-in-time” capital investment philosophy drives attractive project IRR’s
AM Project Economics by Investment
45% 40% 40% 40% Weighted 35% Avg: 25% IRR 30% 28% 30% 30% 25% 25% 25% 20% 18% 15% 18% 15% 15%
Internal Rate of Return Return of Rate Internal 10% 15% 5% 0% LP HP Compression Fresh Advanced Processing/ % of Gathering Gathering Water Wastewater Fractionation 5-year Organic Delivery Treatment Project 17% 12% 29% 12% - 30% Backlog
ORGANIC PROJECT BACKLOG WITH PEER-LEADING RETURNS 46 Antero Midstream Return on Invested Capital
AM Return on Invested Capital (ROIC)
2017 ROIC of 15% in 25% only fourth year of AM operations 20%
Future organic growth 15% 15% capital leverages 13% existing trunklines and 12% major gathering 10% 9% arteries
5% Fewer pads to service reduces capital with Actual Consensus same throughput 0% 2014A 2015A 2016A 2017A 2018E 2019E 2020E Source: Factset consensus estimates. See appendix for ROIC calculation
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. DISCIPLINED CAPITAL EFFICIENT BUSINESS MODEL 47 AM Long-Term Distribution and Coverage Targets
Unchanged capital investment philosophy with disciplined financial policies result in ability to target peer-leading distribution growth through 2022
Long-Term Distribution Targets and DCF Coverage
Distribution Guidance Distribution Target DCF Coverage Targets (Mid-point) (Mid-point) Implied Yield $4.50 2.0x 1.8x $4.10 $4.00 1.8x
9.4%
$3.42 $3.50 1.4x 1.6x 1.3x 1.4x $3.00 $2.85 1.2x $2.50 5.7% $2.21 1.0x $2.00 $1.72 0.8x $1.50 $1.33
$1.03 0.6x DCF Coverage Ratio Coverage DCF Distribution Per Unit Per Distribution $1.00 0.4x $0.50 0.2x $0.00 0.0x 2016A 2017A 2018 2019 2020 2021 2022 Guidance Target Target Target Target
Note: Implied yield based on AM unit price as of 9/20/18. ANTERO MIDSTREAM │DISCIPLINED CAPITAL EFFICIENT MIDSTREAM MODEL 48 Antero Midstream’s Premier Asset Footprint 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 Gathering and and Utica Shales delivering wellhead gas Compression directly to key processing plants and long haul pipelines
• Joint Venture with MPLX (NYSE: MPLX) aligns Processing and the largest liquids-rich resource base with the Fractionation dominant processing and fractionation footprint in Appalachia
• Largest freshwater delivery system in Fresh Water Appalachia that has a 100% track record of Delivery timely fresh water deliveries to AR’s completions
Wastewater • Largest wastewater treatment facility in the Handling and world for shale oil and gas operations Treatment
PREMIER INTEGRATED APPALACHIAN MIDSTREAM ASSETS 49 Northeast Value Chain Opportunity 5-year identified project inventory of $2.7B plus an additional $1.0B of potential downstream opportunities Upstream Downstream
AM Assets AM/MPLX JV Assets Potential AM Opportunities
~$800MM JV Project Backlog FRACTIONATION TERMINALS NGL & STORAGE PRODUCT PIPELINES
(ETHANE, PROPANE, BUTANE)
WELL GAS >$1.0B PAD COMPRESSION PROCESSING Y-GRADE PIPELINE Downstream LOW HIGH Investment PRESSURE PRESSURE GATHERING GATHERING Opportunity Set END USERS (50% INTEREST) PDH PLANT
~$1.9B Organic Project Backlog LONG HAUL REGIONAL PIPELINE GATHERING PIPELINE (15% INTEREST)
Note: Third party logos denote company operator of respective asset. INTERCONNECT OUTLOOK: ORGANIC PROJECT BACKLOG WITH PEER-LEADING RETURNS 50 Most Integrated Natural Gas & NGL Business in the U.S.
53% Ownership
World Class E&P A Leading Northeast Levered Exposure to Northeast Operator in Appalachia Infrastructure Platform Infrastructure Buildout
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
ANTERO RESOURCES | SUMMARY 51 Appendix 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 $0.05 to $0.10 Premium Nymex C3+ NGL Realized Price 57.5% – 62.5% (% of Nymex WTI)
Cash Production Expense ($/Mcfe) $2.05 – $2.15 $1.60 – $1.70
Marketing Expense ($/Mcfe) $0.10 – $0.125 (10% Mitigation Assumed) G&A Expense ($/Mcfe) $0.125 – $0.175 $0.15 - $0.20 (before equity-based compensation)
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
$150 $150 Land Capital Expenditures ($MM) ($25MM Maintenance) ($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. APPENDIX | 2018 GUIDANCE 53 Antero Guidance and Long-Term Target Assumptions
Stand-Alone Consolidated
20% CAGR through 2020 and 15% Growth in each of Net Daily Production (MMcfe/d) 2021 and 2022 Natural Gas Realized Price Differential $0.05 to $0.10 Premium (2018) to Nymex $0.00 to $0.10 Premium (2019 – 2022) C3+ NGL Realized Price 57.5% – 62.5% (2018) (% of Nymex WTI) 69% (2019+) – ME2 Fees Booked to Transport Costs
Realized Oil Price Differential to WTI ($5.00) – ($6.00)
$2.05 - $2.15 (2018) $1.60 - $1.70 (2018) Cash Production Expense ($/Mcfe)(1) $2.10 – $2.25 (2019 – 2022) $1.65 – $1.75 (2019 – 2022) $0.10 - $0.125 (2018) $0.15 – $0.20 (2019) Marketing Expense ($/Mcfe) <$0.10 (2020) $0.00 (2021 – 2022) G&A Expense ($/Mcfe) $0.125 – $0.175 (2018 – 2019) $0.15 - $0.20 (2018 – 2019) (before equity-based compensation) $0.10 – $0.15 (2020 – 2022) $0.10 – $0.15 (2020 – 2022) $0.175 – $0.225 (2018 – 2019) $0.25 – $0.30 (2018 – 2019) Cash Interest Expense ($/Mcfe) $0.10 – $0.15 (2020 – 2021) $0.20 – $0.25 (2020 – 2022) <$0.10 (2022) Well Costs ($MM / 1,000’) Marcellus: $0.95 MM Marcellus: $0.80 MM (Assumes 12,000’ completions at Utica: $1.07 MM Utica: $0.95 MM 2,000 lbs. per foot of proppant)
(1) Includes lease operating expense, gathering, compression, processing and transportation expense and production and ad valorem taxes. APPENDIX | 5-YEAR ASSUMPTIONS 54 Antero Guidance and Long-Term Target Assumptions (Cont.)
Stand-Alone E&P Consolidated
$10.4B Adjusted Operating Cash Flow(1) N/A (Cumulative 2018 – 2022)
$1,500 – $1,600 (2018 – 2020) $1,300 – $1,400 (2018 – 2021) Annual D&C Capital Expenditures ($MM) $1,700 – $2,000 (2021 – 2022) $1,600 – $1,700 (2022)
Land Maintenance Expenditures ($MM)(2) ~$200 (Cumulative 2018 – 2022)
$1.6B Free Cash Flow(1) N/A (Cumulative 2018 – 2022)
Leasehold Growth Capital Expenditures ($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. APPENDIX | 5-YEAR ASSUMPTIONS 55 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. APPENDIX | PROJECT ASSUMPTIONS 56 Liquidity & Debt Term Structure
6/30/2018 Debt Maturity Profile
AR Credit Facility AM Credit Facility AR Senior Notes AM Senior Notes $2,500
$2,000 New credit facilities for AR $770 and AM have allowed Antero to extend its average $1,500 debt maturity out to 2022 $455 $1,000 $1,000 $1,100 $750 $650 No maturities $600 $500 until 2021
$0 2018 2019 2020 2021 2022 2023 2024 2025
ANTERO RESOURCES | CONSOLIDATED LIQUIDITY AND BALANCE SHEET 57 Deleveraging is Driving Ratings Momentum
Corporate Credit Ratings History
Stable Credit Ratings with Consistent Investment Grade Rating from Upgrades from the Beginning of the Fitch (BBB-) & Recent Decade Through the Downturn Upgrade from S&P (BB+)
Corporate Credit Rating Investment Grade Upgrade to BB+ (Moody’s / S&P / Fitch) Rating: BBB- S&P Feb. 2018 Fitch Jan. 2018 Baa3 / BBB- Investment Grade Ba1 / BB+ Ba2 / BB
Ba3 / BB- B1 / B+ B2 / B Outlook to Positive Moody’s Feb. 2018 B3 / B- Stable through commodity price crash Caa1 / CCC+ / CCC 2010 2011 2012 2013 2014 2015 2016 2017 2018
Moody's S&P Fitch
Credit Markets Have a Strong Appreciation for Antero Momentum
ANTERO RESOURCES | TRENDING TOWARDS INVESTMENT GRADE 58 D&C Capital Transparency
D&C Capital
($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
(1) 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
(1) Based on Marcellus AFE, which assumes inflation on consumable products (i.e. sand/chemicals).
APPENDIX | ASSUMPTIONS 59 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 & $2.85 Nymex Henry Hub gas prices for 2019 - 2022
Oil and Gas Strip Commodity Prices (12/31/17)
($/Bbl) ($/MMBtu) $65.00 $2.82 $2.82 $2.85 $2.89 $3.00 $2.81 $60.00 $59.62 $2.50 $56.19
$55.00 $53.76 $2.00 $52.29 $51.67 $50.00 $1.50
$45.00 $1.00
$40.00 $0.50
$35.00 $0.00 2018 2019 2020 2021 2022 WTI Nymex
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)
APPENDIX | PRICING ASSUMPTIONS 60 Substantial Reserve Growth NET PROVED RESERVES (Tcfe)(1) (Tcfe) Marcellus Utica 18.0 17.3 16.0 15.4 6/30/2017 RESERVE ADDITIONS Proved PV-10 14.0 12.7 13.2 $10.8B • Proved reserves increased 7% to 16.5 Tcfe 12.0 2017 Year-End proved pre-tax PV-10 − Proved pre-tax PV-10 at SEC pricing of $9.3 billion, including 10.0 at SEC pricing, including $1.3 billion of hedge value 7.6 $0.6B of hedge value − Proved pre-tax PV-10 at strip pricing of $10.1 billion, including 8.0 $1.7 billion of hedge value 6.0 4.3 − Increased Marcellus wellhead type curve to 2.0 Bcf/1,000’ of 4.0 2.8 lateral for additional 199 PUD locations 2.0 0.7 • 3P reserves increased 14% to 53.0 Tcfe 0.0 − 3P PV-10 at strip pricing of $17.0 billion, including $1.7 billion of (1) 2010 2011 2012 2013 2014 2015 2016 2017 3P RESERVES BY VOLUME – 2017 hedge value − Increased Marcellus wellhead type curve to 2.0 Bcf/1,000’ of lateral for additional 398 Probable locations 2.3 Tcfe Possible • All-in F&D cost of $0.48/Mcfe for proved reserve additions during six months ended 6/30/2017
17.3 Tcfe Proved $18.4B 3P PV-10 Proved Probable 35.1 Tcfe 2017 Year-End 3P pre-tax PV-10 at SEC Probable pricing, including $0.6B of hedge value Possible
96% 2P Reserves 54.6 Tcfe 3P
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 $0.49/gal, respectively. APPENDIX | RESERVE GROWTH 61 Competitive Gathering and Compression Fee Structure 1 AR Pays Competitive Gathering & Compression Fees - AR’s gathering and compression fees paid to AM are below the Appalachian average based on extensive internal analysis of 19 publicly disclosed and undisclosed private midstream contracts
2 AR has Low or No MVCs with AM - No minimum volume commitments (“MVCs”) on any low pressure gathering with AM - MVCs on high pressure gathering and compression assets put in-service after the AM IPO (11/2014) - 75% to 70% MVCs on high pressure gathering and compression, respectively, when a project is requested by AR - MVC levels are determined by AR’s production forecast and capacity needs; AM may build infrastructure with capacity larger than requested for efficiency purposes that is not subject to MVCs
3 AR Receives Reliable and Timely Gathering and Compression from AM - AR has complete visibility and drives AM’s planning and in-service timing for key infrastructure projects - AR is essentially AM’s sole customer, which results in unmatched service - AR receives just-in-time customized and controlled midstream buildout - Critical to AR’s ability to execute its development plan and optimize its capital efficiency
APPENDIX | GATHERING AND COMPRESSION FEES 62 Appalachia Gathering and Compression Fee Study
AR Fees Paid to AM Converted to MMBtu AR Contracted Gathering/Compression Fees to AM ($/Mcf) $0.66 Typical BTU Conversion (Average BTU of 1250) for 2018/2019 Programs 1.25 $1.00 AR Gathering/Compression Fees (Converted to $/MMBtu) $0.53 $0.90 NOTE: Most midstream fees are disclosed on a $0.80 $/MMBtu basis. AR’s fees are disclosed on a $/Mcf basis and must be converted to a $/MMBtu $0.70 basis to appropriately compare to others Appalachian Study Average: $0.60/MMBtu $0.60 $0.53 $0.50
$0.40
$0.30
$0.20
$0.10
$0.00
P Publicly Disclosed Agreements Private Gathering & Compression Agreements
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. APPENDIX | GATHERING AND COMPRESSION FEES 63 Competitive Fresh Water Fee Structure 1 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 2 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 3 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 4 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
APPENDIX | FRESH WATER DELIVERY FEES 64 AR Saved ~$0.50/Bbl on Fresh Water in 2017 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 Antero 2017 Average Loading Time (Minutes) 60 Staging Time (Minutes) 120 Nicki Pad – 6 Wells Trucking Cost per Hour $90 Round Miles Minutes $/Bbl Barrels Per Truck (Bbls) 90 Trip
Pad Avoided Cost to Truck to All Pads ($/Bbl) $4.19 41 74 $4.23 Avg. Firm Delivery Fee paid to AM ($/Bbl) $3.69 AR Savings Per Barrel $0.58 AR Fresh Water Savings ($/Bbl) $0.50
Bettinger Pad – 1 Wells Edna Monroe Pad – 10 Wells
Round Round Miles Minutes $/Bbl Miles Minutes $/Bbl Trip Trip
Pad Pad 56 99 $4.64 36 77 $4.28 Avg. Avg
AR Savings Per Barrel $0.99 AR Savings Per Barrel $0.59
Stewart Pad – 4 Wells James Webb Pad – 9 Wells Round Round Miles Minutes $/Bbl Miles Minutes $/Bbl Trip Trip Pad 51 83 $4.38 Pad Avg 15 36 $3.60 Avg
AR Costs Per Barrel $(0.09) AR Savings Per Barrel $0.69
Note: Select 2017 pads shown above are illustrative of the company wide development plan across AR’s acreage position.
APPENDIX | FRESH WATER DELIVERY FEES 65 Expected Natural Gas Price Realization Improvement
Antero 2018 Firm Transport Index Breakdown
100% 8% 5% decrease to 3% Local 90% Local Markets 16% 80% 23% Midwest +$0.05 - $0.10 70% 8% increase in 17% 14% TCO Updated forecast 60% exposure to Midwest & Gulf Cost Markets premium to NYMEX 50% Gulf Coast after BTU uplift 40% 30% 59% 60% 20% 10% 0% 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 +$0.11
~97% of Antero Gas Is Expected to be Sold in Favorably Priced Markets in the Balance of 2018 Note: 2H 2018 based on 2018 balance strip pricing as of 7/25/2018. Local index represents a blend of Dominion South and TETCO M2 pricing. Midwest index represents a blend of Chicago and MichCon pricing. Gulf Coast index represents a blend of Gulf and Nymex-based pricing.
TRANSITION TO FREE CASH FLOW & LOW LEVERAGE | PROFITABILITY DRIVERS 66 Fresh Water MVC’s and Earn-Outs • Minimum volume commitments (MVC’s) on fresh water delivery volumes were put in place to support revenues and rates of return for AM’s acquisition of the water business in September 2015 • Earn-outs at year-end 2019 and 2020 provided incentives for AR to perform long term Fresh Water Delivery MVC’s and Earn Out Payments (MBbl/d)
MVCs Earnout #1 Earnout #2 Actual Volumes 250 221(1) 200 MBbl/d 200 153 161 MBbl/d
150 123
MBbl/d 100
120 120 50 90 100
0 2016A 2017A 2018 2019 2020 (1) Represents 1Q 2018 fresh water delivery volumes.
APPENDIX | FRESH WATER DELIVERY MVCS 67 Guidance Summary - 2018
2017 2018 Guidance Guidance Guidance Change
Net Income ($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%
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.
APPENDIX: GUIDANCE 68 Core of the Core Development Programs
Half Cycle Total Average BTU 2018 Well 2019 Well Well EUR Regime Undrilled Lateral Range Completions Completions Economics Locations Length (Strip Price) Marcellus Highly-Rich Gas 1275-1350 14 30 200% 447 12,500’ Condensate Highly-Rich Gas 1200-1275 106 101 89% 935 11,500’
Rich Gas 1100-1200 0 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: Program Stats: High-Grade High-Grade
Inventory Inventory 93% | 98% 102% | 106% Totals: Averages: Strip | $70 Oil ROR Strip | $70 Oil ROR
2,372 11,400’ 1,253 BTU Average 1,248 BTU Average
1) Wells completed reflects midpoint of targeted completions per year. SCALE & GROWTH: LIQUIDS-RICH RESOURCE MEETS CAPITAL EFFICIENCY | UNDERSTANDING THE RESOURCE 69 Antero Consolidated and Stand-Alone Enterprise Value
Hedged Multiple 2019E EBITDAX ($MM): $2,094 Excludes AM Distributions EV / 2019E EBITDAX: 3.4x
($MM) Unhedged Multiple 2019E EBITDAX ($MM): $1,520 Excludes AM Distributions & Hedge Revenues $14,000 EV / 2019E EBITDAX: 3.9x
$12,000 $11,550 Net Debt $1,420 $10,000
$3,006 $8,000 $5,274 $7,124 ~$1,175 21% tax on Hedge MTM $6,000 value of Market AM units (net of Value NOLs) E&P $4,000 Assets 99MM units $6,275 owned and AM $5,949 $2,000 market price of $30.41/unit
$0 Consolidated Antero Midstream After Tax Value of AM AR Stand-alone Enterprise Value Net Debt Owned Units E&P 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). APPENDIX | VALUE CREATION 70 Antero Assumptions: Single Well Economics
SWE Cost Type Description of Cost Half Cycle Full Cycle
• Drilling and completion costs • Assumes well costs for a 12,000’ lateral, Marcellus: $10.6MM Marcellus: $11.4MM 2,000 lbs of proppant per lateral foot and Utica South/Dry: $12.2MM Utica South/Dry: $12.8MM Well Costs both fresh and flowback water Utica Beaver: $11.5MM Utica Beaver: $12.2MM • Utica Condensate regime assumes 1,500 (60% AM water fees) (100% AM water fees) lbs or proppant per lateral foot
Working Interest / • Reflects Antero’s average WI/NRI in the Marcellus: 100% / 85% Net Royalty Interest respective plays Utica: 100% / 81%
Midstream Gathering • Midstream low pressure, high pressure 60% of AM gathering fees 100% of AM gathering fees Fees and compression fees
Variable FT costs only of • FT costs may include both demand and Fully utilized FT costs of $0.06/Mcf (variable fees Firm Transportation(1) variable fees associated with expected $0.54/Mcf (including both associated with expected production demand and variable fees) production)
General & Administrative • General and administrative costs None $750,000 per well Costs associated with Antero
• Assumes 12,000’ well with 660’/1,000’ Marcellus - $655,000 per well Land spacing for Marcellus/Utica respectively None Utica - $1,087,000 per well and $3,600 per acre
• Provides a timeframe for initial spud to 184 days spud to FP Spud to FP Timing first production (Economics based on first production at 7/1/2018)
Realized Pricing • Commodity price assumptions 06/30/2018 strip pricing (weighted)
(1) SWEs exclude marketing expenses and related commodity hedge contracts that support Antero’s firm transportation portfolio APPENDIX | SINGLE WELL ECONOMICS 71 Single Well Economics: Marcellus – In Ethane Rejection
Highly-Rich Classification Highly-Rich Gas Rich Gas Dry Gas Gas/Condensate
Modeled BTU 1313 1250 1150 1050 EUR (Bcfe): 32 29 26 24 EUR (MMBoe): 5.3 4.9 4.3 3.9 % Liquids: 33% 24% 11% 0% Well Cost ($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 $3.9 Pre-Tax Half Cycle ROR: 200% 89% 32% 21% Payout (Years): 0.5 1.5 2.8 4.1 Gross Core Locations in BTU Regime: 447 935 495 874
Highly-Rich Highly-Rich Gas Rich Gas Dry Gas Cumulative Gas/Condensate Volumes Gas (MMcf) Oil (Mbbl) Gas (MMcf) Oil (Mbbl) Gas (MMcf) Oil (Mbbl) Gas (MMcf) Oil (Mbbl) Year 1 4,300 116 4,300 24 4,300 0 4,300 0 Year 2 6,500 143 6,500 31 6,500 0 6,500 0 Year 3 7,900 152 7,900 36 7,900 0 7,900 0 Year 4 9,100 157 9,100 40 9,100 0 9,100 0 Year 5 10,200 161 10,200 44 10,200 0 10,200 0 Year 10 13,900 176 13,900 57 13,900 0 13,900 0 Year 20 18,500 194 18,500 73 18,500 0 18,500 0 Note: SWE cost assumptions reflect average costs per Mcfe on the first five years of the life of a well. F&D cost is defined as current D&C cost per 1,000’ lateral divided by net EUR per 1,000’ lateral assuming 85% NRI in Marcellus. Please see “Antero Definitions” and “Antero Non-GAAP Measures” in the Appendix. APPENDIX | SINGLE WELL ECONOMICS 72 Single Well Economics: Utica – In Ethane Rejection
Highly-Rich Highly-Rich Classification Condensate Gas/ Rich Gas Dry Gas Gas Condensate Modeled BTU 1275 1235 1215 1175 1050 EUR (Bcfe): 13 25 29 28 26 : EUR (MMBoe) 2.2 4.2 4.8 4.6 4.4 % Liquids 40% 30% 21% 16% 0% Well Cost ($MM): $10.8 $11.5 $12.2 $12.2 $12.2 Bcfe/1,000’: 1.1 2.1 2.4 2.3 2.2 (1) Net F&D ($/Mcfe) : $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
Highly-Rich Gas/ Condensate Highly-Rich Gas Rich Gas Dry Gas Cumulative Condensate Volumes 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 0 5,500 0 Year 2 2,300 153 5,800 127 7,700 8 7,500 0 8,200 0 Year 3 2,800 166 6,900 138 9,100 9 8,800 0 10,000 0 Year 4 3,300 176 7,700 146 10,200 10 9,900 0 11,400 0 Year 5 3,600 186 8,400 152 11,100 11 10,800 0 12,500 0 Year 10 5,000 219 10,900 175 14,500 14 14,100 0 16,500 0 Year 20 6,700 258 14,000 202 18,700 19 18,200 0 21,200 0 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. APPENDIX | SINGLE WELL ECONOMICS 73 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 of 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 other 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.
APPENDIX | DISCLOSURES & RECONCILIATIONS 74 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:
(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
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%.
APPENDIX | DISCLOSURES & RECONCILIATIONS 75 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 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 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 of 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 obligations. 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 $8.6 billion.
APPENDIX | DISCLOSURES & RECONCILIATIONS 76 Antero Resources Stand-Alone Adjusted EBITDAX Reconciliation
AR Stand-Alone Adjusted EBITDAX Reconciliation
($ 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 $1,479,540
APPENDIX | DISCLOSURES & RECONCILIATIONS 77 Antero Resources Consolidated Adjusted EBITDAX Reconciliation
Consolidated Adjusted EBITDAX Reconciliation
Three Months ($ in millions) 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
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.
APPENDIX 79 Antero Midstream Non-GAAP Measures
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.
APPENDIX 80 Antero Midstream Non-GAAP Measures
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):
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
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.
APPENDIX 81 Adjusted EBITDA and DCF Reconciliation
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 offset 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.
APPENDIX 82 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.
APPENDIX | DISCLOSURES & RECONCILIATIONS 83