Company Presentation december 2018
Legal Disclaimer NO OFFER OR SOLICITATION This presentation includes a discussion of a proposed business combination transaction (the “Transaction”) between AM and AMGP. This presentation is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the Transaction or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended. IMPORTANT ADDITIONAL INFORMATION In connection with the Transaction, AMGP has filed with the U.S. Securities and Exchange Commission (“SEC”) a registration statement on Form S-4, that includes a joint proxy statement of AM and AMGP and a prospectus of AMGP. The Transaction will be submitted to AM’s unitholders and AMGP’s shareholders for their consideration. AM and AMGP may also file other documents with the SEC regarding the Transaction. The registration statement on Form S-4 has not been declared effective by the SEC, and the definitive joint proxy statement/prospectus has not yet been delivered to the shareholders of AMGP and unitholders of AM. This document is not a substitute for the registration statement and joint proxy statement/prospectus that has been filed with the SEC or any other documents that AMGP or AM may file with the SEC or send to shareholders of AMGP or unitholders of AM in connection with the Transaction. INVESTORS AND SECURITY HOLDERS OF ANTERO MIDSTREAM AND AMGP ARE URGED TO READ THE REGISTRATION STATEMENT AND THE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION AND ALL OTHER RELEVANT DOCUMENTS THAT ARE FILED OR WILL BE FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THESE DOCUMENTS, CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION AND RELATED MATTERS. Investors and security holders will be able to obtain free copies of the registration statement and the joint proxy statement/prospectus (when available) and all other documents filed or that will be filed with the SEC by AMGP or AM through the website maintained by the SEC at http://www.sec.gov. Copies of documents filed with the SEC by AM will be made available free of charge on AM’s website at http://investors.anteromidstream.com/investor-relations/AM, under the heading “SEC Filings,” or by directing a request to Investor Relations, Antero Midstream Partners LP, 1615 Wynkoop Street, Denver, Colorado 75219, Tel. No. (303) 357-7310. Copies of documents filed with the SEC by AMGP will be made available free of charge on AMGP’s website at http://investors.anteromidstreamgp.com/Investor-Relations/AMGP or by directing a request to Investor Relations, Antero Midstream GP LP, 1615 Wynkoop Street, Denver, Colorado 75219, Tel. No. (303) 357-7310. PARTICIPANTS IN THE SOLICITATION AMGP, AM, AR and the directors and executive officers of AMGP and AM’s respective general partners and of AR may be deemed to be participants in the solicitation of proxies in respect to the Transaction. Information regarding the directors and executive officers of AM’s general partner is contained in AM’s 2018 Annual Report on Form 10-K filed with the SEC on February 13, 2018, and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC’s website at http://www.sec.gov or by accessing AM’s website at http://www.anteromidstream.com. Information regarding the executive officers and directors of AMGP’s general partner is contained in AMGP’s 2018 Annual Report on Form 10-K filed with the SEC on February 13, 2018 and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC’s website at www.sec.gov or by accessing the AMGP’s website at http://www.anteromidstream.com. Information regarding the executive officers and directors of AR is contained in AR’s 2018 Annual Report on Form 10-K filed with the SEC on February 13, 2018 and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC’s website at www.sec.gov or by accessing the AMGP’s website at http:// www.anteroresources.com. Investors may obtain additional information regarding the interests of those persons and other persons who may be deemed participants in the Transaction by reading the joint proxy statement/prospectus regarding the Transaction when it becomes available. You may obtain free copies of this document as described above. 2 Antero Resources december 2018 Presentation
Legal Disclaimer This presentation includes “forward-looking statements.” Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond AR’s control. All statements, except for statements of historical fact, made in this presentation regarding activities, events or developments AR expects, believes or anticipates will or may occur in the future, such as the expected sources of funding and timing for completion of the share repurchase program if at all, impacts of hedge monetizations, the expected consideration to be received in connection with the closing of the Transaction, the timing of the consummation of the Transaction, if at all, impacts of natural gas price realizations, financial and operational guidance, AR’s expected ability to return capital to investors and targeted leverage metrics, AR’s estimated unhedged EBITDAX multiples, future plans for processing plants and fractionators, AR’s estimated production and the expected impact of Mariner East 2 on AR’s NGL pricing, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this presentation. Although AR believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. AR cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond 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. 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 Adjusted EBITDAX, (iii) Consolidated Adjusted Operating Cash Flow, (iv) Stand-Alone 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. 3 Antero Resources december 2018 Presentation
The Size and Scale to Capitalize on the Resource 4 Antero Resources december 2018 presentation Market Cap . ........... Enterprise Value(1) . Corporate Debt Ratings Stand-Alone Leverage(2) Net Production (2018E) ....... Liquids................................ 3P Reserves .. ........... C2+ NGLs(3)........................... Condensate......................... Net Acres . ... Core Drilling Locations . AR Midstream Ownership (53%) $3.4B $7.4B Ba2 / BB+ / BBB- <2.2x 2.7 Bcfe/d 130,000 Bbl/d 54.6 Tcfe 2,131 MMBbls 131 MMBbls 620,000 3,295 $2.5B Note: Equity market data as of 12/17/18. Balance sheet data, hedge mark to market as of 9/30/18. Reserves as of 12/31/2017. Enterprise value excludes AM net debt. See 2018 Guidance in Appendix. Includes ownership of $2.5 billion of Antero Midstream units. Stand-alone leverage is stand-alone debt divided by LTM Adjusted EBITDAX and is forecast for year-end 2018. 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 additional ethane in the natural gas stream. Antero Resources Profile Antero Acreage SW Marcellus Core Ohio Utica Core
Recent Developments/ Near-Term Catalysts Hedge Monetizations and Restructuring (December 2018) Generated Proceeds of $357 million to repay debt Monetized 68% of Apr-Dec 2019 natural gas fixed price swaps Replaced with collars ($2.50/MMBtu floor and an average $3.38/MMBtu ceiling) Reset 70% of 2020 fixed price swaps from $3.25/MMBtu to $3.00/MMBtu Resulting hedge portfolio protects 100% of 2019 and greater than 50% of 2020 expected natural gas production with a $3.00/MMBtu NYMEX price floor on average Share Repurchases (November/December 2018) Repurchased 9.1 million shares (3% of outstanding shares) at an average price of $14.10/share Approximately $470 million remaining in current $600 million share repurchase program Rover Sherwood Lateral In-service (November 2018) Enabled AR to shift approximately 550 MMcf/d of gas sales from Appalachian Basin pricing to Midwest pricing with only $0.06/MMBtu variable cost Mariner East 2 (early 1Q 2019) Cleared remaining legal and regulatory hurdles; one horizontal drill (HDD) remaining Expected initial phase in-service early 1Q 2019 (capacity to move AR’s 50, 000 Bbl/d commitment) AR’s 11,500 Bbl/d ethane sales contract with Borealis was in-service 11/1/2018 with first shipment out of Marcus Hook, PA Midstream Simplification (October 2018) Expected to close in 1Q 2019 (subject to the approval of Antero Midstream unitholders and AMGP shareholders), providing AR with at least $300 million in cash 5 Antero Resources December 2018 presentation
2019 Hedge Restructuring 6 Antero 2019 Natural Gas Hedge Profile Total hedged volume remains unchanged at 100% of expected natural gas production for 2019 Antero monetized 1.575 Bcf/d of swaps generating approximately $235 MM in proceeds April – December 2019 swaps monetized at attractive NYMEX levels and replaced with collars Puts protect downside at $2.50/MMBtu and calls offset “put” costs while opening up the upside between current strip and call ceiling ranging from $3.31/MMBtu to $3.54/MMBtu 2019 hedge position anchored with 2.33 Bcf/d hedged at $3.62/MMBtu in 1Q 2019 Proceeds utilized for accelerated delevering Sculpted collars for upside and capped downside flat with $2.50/MMbtu puts NYMEX strip as of 12/17/2018. (1) Antero Resources december 2018 presentation 2,330 755 755 755 1,575 1,575 1,575 2,330 2,330 2,330 2,330 $3.43 $2.76 $2.78 $2.87 $3.31 $3.31 $3.54 $2.50 $2.50 $2.50 $3.62 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 - 500 1,000 1,500 2,000 2,500 1Q19 2Q19 3Q19 4Q19 Collar Volume Swap Volume NYMEX Strip Price NYMEX Call Price NYMEX Put Price NYMEX Swap Price ( MMcf /d) ($/ MMbtu )
2020 Hedge Restructuring 7 Antero 2020 Natural Gas Hedge Profile Total hedged volume remains unchanged Antero reset 2020 swaps at slightly lower prices generating approximately $122 MM in proceeds NYMEX swap price reduced from $3.25/MMBtu to $3.00/MMBtu in 2020 No change to overall hedged volumes Proceeds utilized for accelerated delevering Monetize + maintain upside to call price Lower strike price = $120 MM proceeds NYMEX strip as of 12/17/2018. (1) Antero Resources december 2018 presentation (MMcf/d) ($/MMBtu) 1,418 1,418 1,418 1,418 $3.00 $2.52 $2.56 $2.66 $3.00 $3.00 $3.00 $3.00 $3.25 $3.25 $3.25 $3.25 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 - 200 400 600 800 1,000 1,200 1,400 1,600 1Q20 2Q20 3Q20 4Q20 Swap Volume NYMEX Strip Reset NYMEX Swap Price Previous NYMEX Swap Price
Natural Gas Price Realizations Provide 4Q18 Uplift 8 AR’s 400 MMcf/d of unhedged natural gas production in 4Q18 provides exposure to recent natural gas price surge Rover Sherwood Lateral was placed into service in November unlocking 550 MMcf/d exposure to Midwest & Gulf Coast markets Rover Pipeline & Unhedged Volume Exposure Uplift Midwest via Rover ($/MMBtu) – Since 11/3/18 Nov/Dec 2018 Midwest Price ($/MMbtu)(1) $4.17 Approximate Variable Cost $(0.06) Netback Price $4.11 TETCO M2 Price $(3.41) Uplift vs. TETCO M2(1) $0.70 Estimated 4Q18 Adjusted EBITDAX Impact $23MM Unhedged Volume Impact 4Q 2018 Volume (MMcf/d) 400 Nymex HH Forecast (10/31/18) $3.16 Nymex HH Forecast (11/30/18)(2) $3.64 Unhedged Price Exposure +$0.58 Estimated 4Q18 Adjusted EBITDAX Impact $21MM 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 Represents a blend of October/November and December front month pricing. Uplift includes $0.14/MMBtu variable cost to TETCO M2. Based on a blend of October/November actuals and first of month Henry Hub price for December. Antero Resources december 2018 presentation AR 800 MMcf/d FT AR 600 MMcf/d FT Gulf Coast AR 200 MMcf/d FT Chicago
Note: Q4 2018 based on October and November actuals and a combination of first of month and gas daily pricing for December 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. 1) Implied premium to Nymex for 4Q 2018 includes a ~$0.30/MMBtu Btu upgrade. Antero 2018 Firm Transport Index Breakdown Expected Natural Gas Price Realization Improvement ~100% of Antero Gas Is Expected to be Sold in Favorably Priced Markets Beginning December 2018 9 Implied Premium to Nymex(1) +$0.07 + $0.25 - +$0.30 Local Midwest TCO Gulf Coast 5% increase to Gulf Coast Markets 8% increase to Midwest Markets 6% decrease to Local Markets Antero Resources december 2018 presentation 7% decrease to Local Markets (TCO) 56% 61% 17% 10% 16% 24% 11% 5% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% YTD 2018 4Q 2018
Simplification Transaction – A Near Term Catalyst Achieves a “Win-Win-Win” Transaction Across the Antero Family Simplifies the Structure and Unlocks Shareholder Value Maintains Antero’s Integrated Strategy & Long-Term Outlook Further Aligns the Interest of All Antero Equity Holders and Management Midstream Simplification expected to close in 1Q19 Provides AR with at least $300 million of cash proceeds 10 Antero Resources December 2018 presentation
Status Quo Structure Antero Simplified Pro Forma Structure Simplified Pro Forma Structure 53% 100% Incentive Distribution Rights (IDRs) Sponsors/ Management Public Public 23% 77% Sponsors/ Management Public 57% 43% 47% 23% 77% 31% Midstream simplification transaction results in one publicly traded midstream entity and better aligns the interests of PE sponsors and management with AR shareholders Eliminates IDRs and the Series B profits interests related to the IDRs AR shareholders and PE sponsors / management will all own the same type of interest in the midstream entity (common stock) Public Public Sponsors/ Management Sponsors/ Management 24% 11 Series B Profits Interest (1) 45% 1) Series B profits interest held by Antero management. New AM 508 MM shares 188 MM units 186 MM shares Antero Resources December 2018 presentation
Diversified Business Reduces Commodity Risk 12 Positive Variance: NYMEX HH Price 16% 400 MMcf/d unhedged exposure AR realized premium to NYMEX HH 45% +550 MMcf/d to premium priced Chicago market via Rover Negative Variance: WTI Oil Price 10% Net Loss on hedging contracts due to natural gas spike Natural Gas Spike Offsets NGL Weakness Antero Resources december 2018 presentation The increase in natural gas prices and sales point improvement have effectively offset the cash flow impact from lower oil and NGL prices 4Q 2018 Estimated EBITDAX Waterfall $0 $100 $200 $300 $400 $500 $600 $700 4Q 2018E EBITDAX (3Q Earnings Release) Liquids Realized Pricing Impact Natural Gas Realized Premium Uplift Net Hedge Gain / Loss Impact 4Q 2018E EBITDAX (Unchanged) $MM
Antero Resources December 2018 Presentation 13 The Value Proposition Future Liquids and Natural Gas Prices: Up 5-10% (2) Q4 Free Cash Flow Generation & Simplified Corporate Structure (3) Adj. EBITDAX, Production and Reserves: Up ~20%(1) Total Net Debt: Down 18%(1) Yet Trading Multiples & Market Cap: Down ~50% (2) A Substantially Better Outlook From the Last Hedge Monetization to Today From June 30, 2017 to September 30, 2018 From June 30, 2017 to December 14, 2018 Near-term targets
Natural Gas Liquids Update: Leading Position
Largest NGL Producer Undrilled Core Liquids-rich Inventory(1) Top U.S. C2+ NGL Producers - 2018E(2) Antero is the largest NGL producer in the U.S. and controls 40% of the core undrilled liquids-rich locations in Appalachia Over 2.5x inventory of closest Appalachian competitor Most exposure to NGL prices Based on Antero analysis of undeveloped acreage in the core of the Marcellus and Utica plays. Peers include Ascent, CHK, CNX, CVX, EQT, GPOR, HG, RRC and SWN. Consensus as of 11/30/2018. Percentage of pre-hedge commodity revenues based on 3Q 2018 actuals. 15 Peer Avg. Pre-Hedge NGL % of Product Revenue Natural Gas Liquids Update leading position 2,234 - 500 1,000 1,500 2,000 2,500 Undrilled Liquids - Rich Locations 115 37% 16% 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 50 60 70 80 90 100 110 120 130 MBbl/d
A Leader in Realized Pricing and Adj. EBITDAX Margins Antero’s integrated strategy has resulted in peer-leading realized prices and margins for 6 straight years and consistent results through price cycles All-in Pricing Realizations ($/Mcfe) Standalone E&P Adj. EBITDAX Margins ($/Mcfe) Source: SEC filings and press releases. Peers include: CNX, COG, EQT, RRC & SWN. +36% vs. Peer Avg. from 2013 - 2018 +28% vs. Peer Avg. from 2013 - 2018 16 Integrated business strategy drives peer leading margins peer leading margins $5.17 $5.10 $4.09 $4.08 $3.61 $3.98 $2.83 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 2013 2014 2015 2016 2017 3Q 18 AR Peer Average NYMEX Henry Hub Gas $3.36 $2.97 $2.07 $2.06 $1.61 $1.68 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 2013 2014 2015 2016 2017 3Q 18 AR Peer Average
Antero’s Ethane Exposure: All Upside 17 Antero’s balanced approach to ethane sales results in 50% of contracts tied to purity ethane prices vs. natural gas value +$0.10/gal ethane price change equates to $40 MM in incremental revenue Ethane Revenue Uplift ($MM) Ethane sensitivity: +$0.10/gallon x 2019 production target x ~50% exposure to Mt. Belvieu = ~$40MM incremental 2019 ethane revenue 50 MBbl/d 50 MBbl/d Note: Forward prices use strip as of 11/30/2018. 2018 ethane prices and revenue are based on actuals plus 4Q strip. 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 +$43 - $81 MM Natural Gas Liquids Update leading position $43 $81 $173 $254 $0 $50 $100 $150 $200 $250 $300 2018 Actual + Strip $0.33/Gal 2019E Strip Prices $0.33/Gal 2019E +$0.10 Upside $0.43/Gal Incremental Revenue 39 MBbl /d
Antero’s First Ethane Export – November 2018 18 Natural Gas Liquids Update leading position Antero’s 11,500 Bpd C2 sales contract with Borealis commenced on November 1, 2018 First ship departed Marcus Hook on November 26 with 337,040 barrels of ethane bound for Borealis’ steam cracker in Stenungsund, Sweden Expect to load ~1 ship per month for duration of 10-year contract
Pre-Hedge Revenue Sensitivity to C3+ NGL Pricing ($MM) Note: Represents 11/30/2018 strip Mont Belvieu pricing. 2019 volumes assume 20% liquids growth vs. 2018 C3+ guidance of 77,500 Bbl/d. Assumes C3+ barrel weightings of: propane 57%, normal butane 16%, isobutane 10%, pentanes 17% and reflects differential of $(6.00)/Bbl. Initial ME2 in-service 1/1/19 moving Antero’s fully contracted “Full ME2” 50,000 Bbl/d of contracted volumes. Powerful C3+ NGL Pricing Upside Exposure 93 MBbl/d Full ME2 93 MBbl/d Full ME2 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 +$0 - $170MM 19 Natural Gas Liquids Update leading position $2 $172 $973 $1,145 $850 $900 $950 $1,000 $1,050 $1,100 $1,150 $1,200 2018 Actual + Strip $36/Bbl 2019E Strip Prices $31/Bbl 2019E Strip +$5/Bbl $36/Bbl Incremental Revenue 77.5 MBbl /d ME2 on 11/1/18 Antero has no hedges in place for C3+ volumes for 2019 and beyond
Antero’s NGL Pricing Uplift from Mariner East 2 31 Mont Belvieu Conway Europe Netback 2019 NWE Price ($/Gal) $0.78 Pipeline, Terminal & Shipping Cost (1) $(0.24) NWE Netback $0.54 Blended Conway / MB Netback $0.46 Uplift vs. YTD 2018 Average Differential +$0.08 Asia Netback 2019 FEI Price ($/Gal) $0.87 Pipeline, Terminal & Shipping Cost (1) $(0.33) Asia Netback $0.54 Blended Conway / MB Netback $0.46 Uplift vs. YTD 2018 Average Differential +$0.08 ME2 Rail To Europe NWE Index Rail To Asia FEI Index International Markets Domestic Markets Marcus Hook Antero Blended Netback 2019 Conway/Mt. Belvieu Price ($/Gal) $0.64 Average YTD 2018 Differential $(0.18) Blended Conway/MB Netback $0.46 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 11/30/18. Includes associated port and canal fees and charges. 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 Local Mariner East 2 will allow AR to access international LPG markets and realize a ~$3.36/Bbl uplift on its exported barrels 50,000 Bbl/d Mariner East 2 commitment equates to over $61 MM of incremental annual cash flow 4Q 2018 20 Today Natural Gas Liquids Update leading position
Liquids-Rich Resource + Capital Efficiency = Free Cash Flow
22 Drilling and Completion Efficiencies Average Lateral Feet per Day Drilling Days Average Lateral Length per Well Completion Stages per Day Liquids resource + capital efficiency = free cash flow cost efficiency drivers 8,206 72% Increase 28% Increase 228% Increase Note: Utica 3Q 2018 results reflect YTD results, as Antero is not operating any rigs in the Utica during 2H18. Note: Percentage increase and decrease arrows represent change in Marcellus data from 2014 to 3Q 2018. Marcellus Down 59% 4,321 2,983 5,169 - 1,000 2,000 3,000 4,000 5,000 6,000 2014 2015 2016 2017 3Q 2018 RECORD Lateral Feet Marcellus Utica 10,407 15,075 11,044 17,445 - 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 2014 2015 2016 2017 3Q 2018 RECORD Lateral Feet Marcellus Utica 4.6 5.5 9.0 3.6 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 3Q 2018 RECORD Stages per Day Marcellus Utica 12 8 20 10 0 5 10 15 20 25 30 35 2014 2015 2016 2017 3Q 2018 RECORD Drilling Days Marcellus Utica
Integrated Business Strategy Drives Peer Leading Margins
Midstream Driving Value for AR Since Inception 24 Takeaway assurance and reliable project execution AM Midstream Buildout Midstream Ownership Benefits Never missed a completion date with fresh water delivery system Unparalleled downstream visibility Attractive return on investment (4.7x ROI for AR) Just-in-time capital investment Antero Clearwater Facility Processing Facility Current Infrastructure Future Infrastructure Future buildout Owning and controlling the infrastructure is critical to sustainable development; Antero Midstream provides a customized midstream solution Integrated business strategy drives peer leading margins midstream driving value
Antero Midstream At A Glance – Status Quo 25 Market Cap ....... Enterprise Value ......... . LTM Adjusted EBITDA(1) .. % Gathering/Compression % Water .. .. .. .. .. Net Debt/LTM Adj. EBITDA . Corporate Debt Rating . $4.7B $6.3B $665 MM 65% 35% 2.3x Ba2 / BB+ /BBB- Note: Equity market data as of 12/17/2018. Balance sheet data as of 9/30/2018. LTM Adjusted EBITDA as of 9/30/18. 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 december 2018 Presentation AM Highlights AMGP Highlights Market Cap ....... Net Debt/LTM Adj. EBITDA.... $2.5B – 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 – 2.0 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
Antero: Not Just a Natural Gas Producer Liquids-Rich Resource and Scale Diversified Commodity Mix Enhances Shareholder Value Top NGL producer in the U.S. Control Resource Development Mitigate Commodity Risk Just-in-time midstream investment 100% hedged on natural gas in 2019 @ $3.00/MMbtu floor on average Disciplined Focus on Returns $600MM share repurchase program Maintain Strong Balance Sheet Attractive Free Cash Flow Growth Peer Leading Margins 23% debt-adjusted growth per share Appalachian leader for 6 straight years Expected in 4Q 2018 <2.2x by YE 2018 Shareholder Value Low Cost Liquids-Rich Resource Base Return of Capital 26 See appendix for Non-GAAP items and reconciliation Antero Resources december 2018 presentation
Appendix
Antero Pro Forma Hedge Position 28 Antero Hedge Profile Total proceeds from hedge restructuring of $357 MM in proceeds Monetize + maintain upside to call price 30% Swaps 30% Swaps 30% Swaps 1) Based on 12/17/2018 strip pricing . $2.50 $3.44 appendix pro forma hedge position (MMcf/d) ($/MMBtu) 1,149 1,418 710 850 90 2,330 1,418 710 850 90 $3.48 $3.00 $3.00 $3.00 $2.91 $2.96 $2.69 $2.63 $2.65 $2.69 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 0 500 1,000 1,500 2,000 2,500 2019 2020 2021 2022 2023 NYMEX Collar Volume NYMEX Swap Volume NYMEX Swap Price NYMEX Strip Price
Compelling Full Cycle Well Economics 29 Single Well Economics Bridge to Corporate Level Returns Fully Burdened Corporate Level Well Economics are Outstanding Note: See slide #33 for further detail behind full cycle and half cycle single well economics; WACC calculated using CAPM. 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). 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. AR WACC 8% appendix Attractive Well Economics Drive Growth Fully burdened pre-hedge 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 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
9/30/2018 Debt Maturity Profile 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 30 Appendix consolidated liquidity and balance sheet No maturities until 2021 $1,000 $1,100 $750 $650 $600 $547 $875 $0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 2018 2019 2020 2021 2022 2023 2024 2025
Delevering is Driving Ratings Momentum 31 Appendix Trending towards investment grade 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 Moody's S&P Fitch
32 Appendix Cost Efficiency Drivers: Well cost Reduction Dramatically Lower F&D Cost F&D Cost per Mcfe(1)(2) Ethane rejection assumed. 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 (2014 – 2017) $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
Antero Assumptions: Single Well Economics 33 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) SWEs exclude marketing expenses and related commodity hedge contracts that support Antero’s firm transportation portfolio
34 Appendix disclosures & reconciliations Antero Definitions Consolidated Adjusted EBITDAX: Represents net income or loss from continuing operations, including noncontrolling interests, before interest expense, interest income, derivative fair value gains or losses (excluding net cash receipts or payments on derivative instruments included in derivative fair value gains or losses), taxes, impairment, depletion, depreciation, amortization, and accretion, exploration expense, franchise taxes, equity-based compensation, gain or loss on early extinguishment of debt, and gain or loss on sale of assets. Consolidated Adjusted EBITDAX also includes distributions from unconsolidated affiliates and excludes equity in earnings or losses of unconsolidated affiliates. See “Antero Non-GAAP Measures” for additional detail. Consolidated Adjusted Operating Cash Flow: Represents net cash provided by operating activities before changes in current assets and liabilities. See “Antero Non-GAAP Measures” for additional detail. Consolidated Drilling & Completion Capital: Represents drilling and completion capital as reported in AR’s consolidated cash flow statements (i.e., fees paid to AM for water handling and treatment are eliminated upon consolidation and only operating costs associated with water handling and treatment are capitalized). F&D Cost: Represents 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. There is no directly comparable financial measure presented in accordance with GAAP for F&D Cost and therefore, a reconciliation to GAAP is not practicable. Free Cash Flow: Represents Stand-alone Adjusted operating cash flow, less Stand-alone E&P Drilling and Completion capital, less Land Maintenance capital. See “Antero Non-GAAP Measures” for additional detail. Land Maintenance Capital: Represents leasehold capital expenditures required to achieve targeted working interest percentage of 95% for 5-year development plan (i.e. historical average working interest), plus renewals associated with 5-year development plan. Stand-Alone Adjusted EBITDAX: Represents income or loss from continuing operations as reported in the Parent column of AR’s guarantor footnote to its financial statements before interest expense, interest income, derivative fair value gains or losses from exploration and production and marketing (excluding net cash receipts or payments on derivative instruments included in derivative fair value gains or losses), impairment, depletion, depreciation, amortization, and accretion, exploration expense, franchise taxes, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, and gain or loss on changes in the fair value of contingent acquisition consideration. Stand-alone E&P Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units. See “Antero Non-GAAP Measures” for additional detail. 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 water drop down transaction that occurred in 2015. See “Antero Non-GAAP Measures” on slide 35 for additional detail. Stand-Alone Drilling & Completion Capital: Represents drilling and completion capital as reported in the Parent column of AR’s guarantor footnote to its financial statements and includes 100% of fees paid to AM for water handling and treatment and excludes operating costs associated with AM’s Water Handling and Treatment segment).
35 Antero Non-GAAP Measures Consolidated Adjusted EBITDAX, Stand-Alone Adjusted EBITDAX, Consolidated Adjusted Operating Cash Flow, Stand-Alone 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 Adjusted EBITDAX The GAAP financial measure nearest to Consolidated Adjusted EBITDAX is net income or loss including non-controlling interest that will be reported in Antero’s consolidated financial statements. The GAAP financial measure nearest to Stand-Alone 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 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 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 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
Appendix 2018 guidance 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) $1,550 - $1,600 $1,350 - $1,400 Land Capital Expenditures ($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. Reflects most recent guidance update on 10/31/2017. Includes lease operating expense, gathering, compression, processing and transportation expense and production and ad valorem taxes. 36
Antero Resources Stand-Alone Adjusted 4Q18 EBITDAX Reconciliation Appendix disclosures & reconciliations 37 Antero has not included a reconciliation of fourth quarter 2018 Stand-Alone Adjusted EBITDAX to their nearest GAAP financial measures for the fourth quarter of 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 for the fourth quarter of 2018 between Stand-alone 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 the fourth quarter of 2018. Antero has not included reconciliations of Stand-alone Adjusted Operating Cash Flow and Free Cash Flow to their nearest GAAP financial measures for the fourth quarter of 2018 because it would be impractical to forecast changes in current assets and liabilities. (in thousands) Stand-alone Low High Interest expense $50,000 $60,000 Gains (losses) on settled commodity derivatives (25,000) (35,000) Depreciation, depletion, amortization, and accretion expense 210,000 230,000 Exploration expense 500 1,000 Equity-based compensation expense 11,000 13,000 Distributions from limited partner interest in Antero Midstream 40,000 45,000
38 Appendix II 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 Gains on settled commodity derivatives 230,000 250,000 230,000 250,000 Depreciation, depletion, amortization, and accretion expense 950,000 1,050,000 800,000 900,000 Impairment expense 400,000 450,000 400,000 450,000 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 Resources Standalone Adjusted EBITDAX Reconciliation Standalone LTM Adjusted EBITDAX Reconciliation Appendix disclosures & reconciliations 39 Stand-Alone Twelve months ended September 30, (in thousands) 2018 Net income attributable to Antero Resources Corporation $ 210,898 Commodity derivative fair value gains (334,617) Gains on settled commodity derivatives 344,917 Marketing derivative fair value gains (72,687) Gains on settled marketing derivatives 78,098 Interest expense 219,206 Loss on early extinguishment of debt 1,205 Income tax benefit (397,638) Depletion, depreciation, amortization, and accretion 787,598 Impairment of unproved properties 482,568 Impairment of gathering systems and facilities 4,470 Exploration expense 7,050 Gain on change in fair value of contingent acquisition consideration (15,645) Equity-based compensation expense 57,496 Equity in (earnings) loss of Antero Midstream 92,545 Distributions from Antero Midstream 149,292 Adjusted EBITDAX $ 1,614,756
Antero Resources Stand-alone Adjusted EBITDAX Per Mcfe Appendix disclosures & reconciliations 40 Standalone Adjusted EBITDAX per Mcfe Reconciliation (Annual) 2013 2014 2015 2016 2017 1Q2018 2Q2018 3Q2018 ($/Mcfe) Natural Gas, Oil, Ethane and NGL sales 4.31 $ 4.74 $ 2.53 $ 2.60 $ 3.35 $ 3.56 $ 3.35 $ 3.70 $ Realized commodity derivative gains (losses) 0.86 $ 0.37 $ 1.57 $ 1.48 $ 0.26 $ 0.47 $ 0.42 $ 0.28 $ Distributions from Antero Midstream - $ - $ 0.16 $ 0.17 $ 0.16 $ 0.17 $ 0.17 $ 0.16 $ All-In E&P Revenue 5.17 $ 5.10 $ 4.27 $ 4.25 $ 3.77 $ 4.21 $ 3.94 $ 4.15 $ Gathering, compression, processing, and transportation 1.25 $ 1.46 $ 1.56 $ 1.70 $ 1.75 $ 1.80 $ 1.79 $ 1.77 $ Production and ad valorem taxes 0.24 0.23 0.14 0.10 0.11 0.12 0.11 0.12 Lease operating expenses 0.05 0.08 0.07 0.07 0.11 0.15 0.14 0.14 Net Marketing Expense / (Gain) - 0.14 0.23 0.16 0.13 (0.27) 0.30 0.31 General and administrative (before equity-based compensation) 0.26 0.23 0.20 0.16 0.15 0.15 0.15 0.14 Total E&P Cash Costs 1.81 $ 2.14 $ 2.20 $ 2.19 $ 2.26 $ 1.93 $ 2.48 $ 2.48 $ E&P EBITDAX Margin (All-In) 3.36 $ 2.96 $ 2.07 $ 2.06 $ 1.61 $ 2.28 $ 1.46 $ 1.68 $ Production Volumes (Bcfe) 191 368 545 676 822 214 229 250 $ Millions Natural Gas, Oil, Ethane and NGL sales 821 $ 1,741 $ 1,379 $ 1,757 $ 2,751 $ 762 $ 768 $ 925 $ Realized commodity derivative gains (losses) 164 136 857 1,003 214 101 96 71 Distributions from Antero Midstream 89 112 132 36 39 41 All-In E&P Revenue 985 $ 1,877 $ 2,324 $ 2,872 $ 3,097 $ 900 $ 903 $ 1,037 $ Gathering, compression, processing, and transportation 239 537 853 1,146 1,441 384 410 443 Production and ad valorem taxes 46 86 77 69 91 25 25 29 Lease operating expenses 9 28 36 51 94 31 32 35 Net Marketing Expense / (Gain) - 50 123 106 108 (59) 69 78 General and administrative (before equity-based compensation) 50 86 108 110 119 31 33 34 Total E&P Cash Costs 345 $ 786 $ 1,196 $ 1,483 $ 1,853 $ 413 $ 569 $ 619 $
Antero Midstream Non-GAAP Measures 41 The following table reconciles net income to Adjusted EBITDA for the twelve months ended September 30, 2018 as used in this presentation (in thousands): The following table reconciles consolidated total debt to consolidated net debt (“Net Debt”) as used in this presentation (in thousands): September 30, 2018 Bank credit facility $ 875,000 5.375% AM senior notes due 2024 650,000 Net unamortized debt issuance costs (8,146) Consolidated total debt $ 1,516,854 Cash and cash equivalents — Consolidated net debt $ 1,516,854 Twelve Months Ended September 30, 2018 Net income $ 401,491 Interest expense 53,307 Impairment of property and equipment expense 29,202 Depreciation expense 138,279 Accretion of contingent acquisition consideration 15,644 Accretion of asset retirement obligations 101 Equity-based compensation 23,453 Equity in earnings of unconsolidated affiliate (35,139) Distributions from unconsolidated affiliates 39,735 Gain on sale of asset – Antero Resources (583) Adjusted EBITDA $ 665,490
