2Q NYSE Stock Symbol: Common Dividend: $0.67 Common Shares Outstanding: 577 Million. Internet Address:

2Q 2017 NYSE Stock Symbol: EOG Common Dividend: $0.67 Common Shares Outstanding: 577 Million Internet Address: http://www.eogresources.com Investor Relations Contacts David J. Streit, Vice President IR/PR (713) 571-4902, dstreit@eogresources.com Kimberly M. Ehmer, Director IR/PR (713) 571-4676, kehmer@eogresources.com W. John Wagner, Engineer IR (713) 571-4404, wjwagner@eogresources.com

Copyright; Assumption of Risk: Copyright 2017. This presentation and the contents of this presentation have been copyrighted by EOG Resources, Inc. (EOG). All rights reserved. Copying of the presentation is forbidden without the prior written consent of EOG. Information in this presentation is provided as is without warranty of any kind, either express or implied, including but not limited to the implied warranties of merchantability, fitness for a particular purpose and the timeliness of the information. You assume all risk in using the information. In no event shall EOG or its representatives be liable for any special, indirect or consequential damages resulting from the use of the information. Cautionary Notice Regarding Forward-Looking Statements: This presentation includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others: the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities; the extent to which EOG is successful in its efforts to acquire or discover additional reserves; the extent to which EOG is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects; the extent to which EOG is successful in its efforts to market its crude oil and condensate, natural gas liquids, natural gas and related commodity production; the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, transportation and refining facilities; the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG s ability to retain mineral licenses and leases; the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations; environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities; EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties; the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically; competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services; the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) and services; the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise; weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression and transportation facilities; the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG; EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements; the extent to which EOG is successful in its completion of planned asset dispositions; the extent and effect of any hedging activities engaged in by EOG; the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions; political conditions and developments around the world (such as political instability and armed conflict), including in the areas in which EOG operates; the use of competing energy sources and the development of alternative energy sources; the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage; acts of war and terrorism and responses to these acts; physical, electronic and cyber security breaches; and the other factors described under ITEM 1A, Risk Factors, on pages 13 through 22 of EOG s Annual Report on Form 10-K for the fiscal year ended December 31, 2016 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K. In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration and extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. Oil and Gas Reserves; Non-GAAP Financial Measures: The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only proved reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also probable reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as possible reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this presentation that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC s latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG s Annual Report on Form 10-K for the fiscal year ended December 31, 2016, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-gaap financial measures can be found on the EOG website at www.eogresources.com.

2Q 2017 Exceeded High End of All U.S. Production Targets Delivered Per Unit LOE, Transportation and DD&A Rates Below Target Reduced CWC* in Delaware, Powder River and DJ Basins Achieved YTD Asset Sale Proceeds of $175 Million FY 2017 Increased U.S. Crude Oil Growth Forecast to 20% from 18%** Maintained Capex Guidance of $3.7-$4.1 Billion*** Balance Capex + Dividend with Discretionary Cash Flow - Complete 480 Net Wells - Average 26 Rigs in 2017 * CWC = Drilling, Completion, Well-Site Facilities and Flowback. ** Based on midpoint of 2017 guidance, as of August 1, 2017. *** Based on full-year estimates, as of August 1, 2017. EOG _0817-3

U.S. Leader in Return on Capital Employed U.S. Oil Growth Leader Among Lowest Cost Producers in Global Oil Market Commitment to Safety and the Environment Create Significant Long-Term Shareholder Value EOG _0817-4

Culture Rate-of-Return Driven Decentralized / Non-Bureaucratic Multi-Disciplined Teamwork Innovative / Entrepreneurial Every Employee is a Business Person Exploration Operations Information Technology Internal Prospect Generation First Mover Advantage Best Rock / Best Plays Low Cost Acreage Most Prolific U.S. Horizontal Wells Fastest U.S. Horizontal Driller Industry Leading Completion Technology Self-Sourcing Materials / Services Low Infrastructure & Production Cost Proven Track Record of Execution Large Proprietary Data Marts Real-Time Data Capture Predictive Algorithms 65+ In-House Desktop / Mobile Apps Fast / Continuous Tech Advancement High Return Oil Growth EOG _0817-5

WTI Oil: HHub Gas: $17 $2.20 $28 $4.10 $26 $3.40 $61 $7.20 $71 $4.20 $95 $3.70 $46 $2.50 28% 30% 26% 26% 22% 19% 15% 18% 16% 12% 14% 1998-2016 Average 13.2% 4% 5% 5% 2% 8% 4% 1% -4% 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 * ROCE in 2013 and prior years calculated using reported net income (GAAP) and 2014 2016 using adjusted net income (Non-GAAP). See Reconciliation Schedules. EOG _0817-6

Premium Non-Premium Direct ATROR* > 100% 20% First Year Gross Oil (Bbl/ well) Direct Finding Cost ($/BOE) 200,000 $7 100,000 $13 U.S. Production MBOD DD&A $/BOE Drives Higher ROCE 278.3 335.0 17.34 15.75 2016 2017E** 2016 2017E** * Data from 2016 completed wells. Calculated using futures strip prices in February 2017. See reconciliation schedule. ** Based on midpoint of 2017 guidance, as of August 1, 2017. EOG _0817-7

Shifting to Premium Locations (% Completed Premium Wells*) Premium Drilling Direct ATROR* (Minimum Return for Premium) 80% 90+% 100%+ 60% 50% 30% 14% 23% 10% 2014 2015 2016 2017 Est 2018+ Est Oil: $30 $40 $50 $60 * Percent of domestic gross completed wells which are premium. * See reconciliation schedules. 6.5 BnBoe* 7,200 Net Undrilled Locations >10 Years of Drilling * Estimated potential reserves net to EOG, not proved reserves. EOG _0817-8

7,200 6,000 4,300 3,200 Feb 2016 Aug 2016 Sep 2016 May 2017 Resource Potential** 2.0 BnBoe 3.5 BnBoe 5.1 BnBoe 6.5 BnBoe Per Well 625 MBoe 815 MBoe 850 MBoe 900 MBoe * Premium locations are shown on a net basis and are all undrilled. ** Estimated potential reserves net to EOG, not proved reserves. EOG _0817-9

7,000 Lateral Boed 1,400 Delaware Basin Oil Midland Basin Oil 1,200 1,000 800 Solid Colors: Oil Gray Bar: Natural Gas 600 400 200 0 Well Count EOGA B C D E F G H I J K L M N O P Q R S T U V W X Y Z AA 52 9 24 4 18 13 22 20 9 3 24 61 5 3 3 23 61 20 163 8 18 26 34 28 26 49 17 51 Average daily six-month production, normalized to 7,000 lateral. All horizontal wells from original operator, January 2016 June 2017. Gas production converted at 20:1. Wolfcamp formation, Wolfcamp reservoir designation, all counties. Delaware Basin peer companies: APA, APC, BHP, CDEV, COP, CXO, EGN, JAG, MTDR, OXY, PE, RDS, REN, XEC and XOM. Midland Basin peer companies: APA, CVX, CXO, ECA, EGN, FANG, OXY, PE, PXD, RSPP, SM and XOM. Source: IHS Performance Evaluator, supplied by IHS Global Inc.; Copyright (2017). EOG _0817-10

4,000 3,000 2,000 1,000 0 EOG _0817-11 Whirling Wind 11 Federal Com 704H Whirling Wind 11 Federal Com 703H Whirling Wind 11 Federal Com 702H Neptune 10 State Com 503H Neptune 10 State Com 504H Rattlesnake 21 Federal Com 702H Audacious Btl Federal Com 002H Rattlesnake 21 Federal Com 701H Orion A 701H Whirling Wind 14 Federal Com 701H Carpenter University Lands 7-20 Unit 4LS Cabra Nino 11 B3NC State Com 1H Orrtanna 20 Fed 701H Rattlesnake 28 Federal Com 704H Endurance 36 State Com 701H Skull Cap Federal Com 022H State Galileo 7 15H Thor 21 702H Lomas Rojas 26 State Com 708H Drainage 34-136 1H Bopd * Horizontal oil wells. Source: IHS, company reports and state regulatory filings. EOG Well Industry Well

12-Month Cumulative MBO 300,000 250,000 200,000 EOG Initiates: Precision Targeting Advanced Completions 2016 EOG Delaware Basin Delaware Basin Peers Midland Basin Peers Bubble Area Denotes 30-Day IP 2015 150,000 2016 100,000 2013 2013 2014 2014 2015 2014 2015 2016 50,000 2013 Longer Laterals are Driving Industry Well Productivity Improvements - 3,500 4,500 5,500 6,500 7,500 8,500 Lateral Length (Feet) Cumulative 12-month oil production. All horizontal wells from original operator. Wolfcamp formation, Wolfcamp reservoir, all counties. Delaware Basin peer companies: APA, APC, BHP, COP, CXO, MTDR, OXY, RDS, REN and XEC. Midland Basin peer companies: APA, CVX, CXO, ECA, EGN, FANG, OXY, PE, PXD, RSPP and XOM. Source: IHS Performance Evaluator, supplied by IHS Global Inc.; Copyright (2017). EOG _0817-12

Direct ATROR* Net Present Value per Well* ($MM) 151% $5.9 104% $4.8 $1.8 29% 15% $0.5 EOG Premium Wells EOG All Wells Industry Delaware Basin Industry Midland Basin EOG Premium Wells EOG All Wells Industry Delaware Basin Industry Midland Basin * ATROR and NPV calculated using $50 WTI and $3.00 NYMEX fixed for life of well. Assumes industry capital and operating costs equal to EOG. See reconciliation schedules. All horizontal wells from original operator. Wolfcamp formation, Wolfcamp reservoir, all counties. Delaware Basin peer companies: APA, APC, BHP, COP, CXO, MTDR, OXY, RDS, REN and XEC. Midland Basin peer companies: APA, CVX, CXO, ECA, EGN, FANG, OXY, PE, PXD, RSPP and XOM. Source: IHS EOG _0817-13

Delaware Basin Wolfcamp Oil Play South Texas Eagle Ford Bakken 9.8 8.5 1H17-11% 7.6 7.6 5.7 4.7 1H17-4% 4.5 4.3 7.2 5.1 1H17-6% 4.8 4.6 2015 2016 1H17 Target 2015 2016 1H17 Target 2015 2016 1H17 Target * Normalized to 7,000 lateral. * Normalized to 5,300 lateral. * Normalized to 8,400 lateral. * CWC = Drilling, Completion, Well-Site Facilities and Flowback. EOG _0817-14

$13.53 $12.09* $10.55* $10.46** G&P G&A Transportation LOE 2014 2015 2016 2017E * Excludes one-time expenses of $19.4 million in 2015 related to early leasehold termination and $47.0 million in 2016 related to voluntary retirements and acquisition costs. Includes stock compensation expense and other non-cash items. ** Based on midpoint of 2017 guidance, as of August 1, 2017. Excludes one-time expenses of $13.3 million for early lease termination and joint venture transaction costs. See reconciliation schedules. EOG _0817-15

LOE/Boe $14 $12 Low-Cost Oil Producer $10 $8 EOG LOE Peers 2016 LOE $6 2015 $4 2016 2017E $2 $0 0% 10% 20% 30% 40% 50% 60% 70% Oil Production Mix Source: Company filings. Peers: APA, APC, CHK, CLR, COG, CXO, DVN, ECA, MRO, MUR, NBL, NFX, PXD, RRC, SWN and XEC. EOG _0817-16

$MM 1,000 750 500 1,948 2017 Consensus Cash Flow After Capex & Dividend Based on $50 WTI 250 0 (250) EOG (500) (750) (1,000) Source: FactSet consensus, U.S E&P Companies >$500MM market cap, as of 7/24/17. Consensus 2017 WTI oil price $50. * Discretionary cash flow less capex and dividends. EOG _0817-17

MBopd 800 700 600 500 400 300 200 100 0 15%-25% CAGR 2016* 2017 2018 2019 2020 $60 $50 * Pro forma for full year of production from Yates in 2016. ** Discretionary Cash Flow Capex + Current Dividend. EOG _0817-18

EOG _0817-19

Real-Time Data Streams from Every Asset EOG Proprietary Data Marts Optimized for Big Data Processing Frac Fleets Rigs Wells on Production 65+ EOG Proprietary Applications In-House Developed: Algorithms Data Science Software EOG Proprietary Data Logs Cores 3-D Seismic Micro Seismic Reservoir Models Desktop Mobile Predictive Analytics Decentralized Decision Making: Comprehensive: Covers All Aspects of EOG Business Completions: Optimize Advanced Designs to Geologic Setting A Control Room in Your Pocket Precision Lateral Targeting: Petrophysical Modeling of Best Target Geosteering: Integrated with Petrophysical Models EOG _0817-20

* Sample 1-foot core extracted from Lower Eagle Ford. Enlarged to show detail of the rock. 1. Grade Rock Characteristics High to Low Quality 2. Overall Grade 3. Drill Lower Eagle Ford EOG _0817-21

Enhance Complexity to Contact More Surface Area Contain Events Closer to Wellbore Note: Microseismic dots represent well stimulation events during completions. EOG _0817-22

Play Net Acres Total Locations* Resource Potential** (MMBoe) Premium Locations*** Eagle Ford 528,000 7,200 3,200 2,425 Bakken/Three Forks -Core - Non-Core 120,000 110,000 975 1,125 620 400 330 - Delaware Basin - Wolfcamp 346,000 2,660 2,900 1,700 - Second Bone Spring 289,000 1,870 1,400 1,350 - Leonard 160,000 1,800 1,700 1,100 Rockies - DJ Basin - Powder River Basin 81,000 460 210 200 400,000 _ 315 _ 190 _ 120 _ 2,100,000 16,000 10,600 7,200 Inventory Growing in Quality and Size * Number of producing and undrilled remaining net wells as of January 1, 2017. Assumes no further downspacing, acreage additions or enhanced recovery. ** Estimated potential reserves (MMBoe) net to EOG, not proved reserves. Includes proved reserves and prior production from existing wells. *** Premium locations are shown on a net basis and are all undrilled. EOG _0817-23

EOG Employees Are Incentivized to Deliver Returns Returns Production and Reserve Growth/ Replacement EOG 6% 30% A 10% 20% B 40% C 20% 10% D E 25% 10% 30% F 25% G 10% H 30% Source: Company Reports. Percentages represent approximate weightings applied in determining 2016 executive officer short-term incentive compensation. Peer companies: APA, APC, COP, DVN, HES, MRO, NBL and PXD. EOG _0817-24

Low Financial Leverage Net Debt to Total Capitalization* Committed to the Dividend 16 Increases in 17 Years 70% $0.70 60% Peers $0.60 50% $0.50 40% $0.40 30% $0.30 20% $0.20 10% $0.10 0% Peer Average EOG $0.00 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Note: Dividends adjusted for 2-for-1 stock splits effective March 1, 2005 and March 31, 2014. * Source: Company reports as of 3/31/17. See reconciliation schedule. Peer Companies: APA, APC, CLR, COG, COP, CXO, DVN, HES, MRO, NBL, NFX, OXY, PXD, RRC and XEC. EOG _0817-25

EOG Competitive Globally Brent ($/BBL) $100 $90 $80 New Marginal Cost of Oil $70 $60 $50 $40 $30 $20 Middle East ( $65 - $75) Far East Mexico Nigeria Venezuela U.S. Tight Oil Russia EOG ($30) * North Sea GOM Angola Brazil US L48 Conv US L48 Conv Oil Sands Russia $10 $0 Middle East/Russia Medium Cost Conventional US Tight Oil Deep Water High Cost Non-OPEC Arctic / Russian Unconventional % World Supply 49% 28% 5% 13% 5% - * Brent equivalent price required to achieve 10% Direct ATROR (see reconciliation schedules). Source: PIRA. EOG _0817-26

Brushy Canyon City Hall Leonard A Leonard B Wall Street 4,800 1 st Bone Spring 2 nd Bone Spring 3 rd Bone Spring Upper Wolfcamp Battery Park Middle Wolfcamp Lower Wolfcamp 40 150 Battery Park to Wall Street to City Hall 4,800 One World Trade Center 1,792 Middle Bakken Lower Eagle Ford EOG _0817-27

Net Resource Potential 6.0 BnBoe* Roosevelt 6,330 Net Locations; 7,200 Laterals Average 13 Rigs Operating in 2017 Northwest Shelf 143,000 Net Acres Chaves Significant Infrastructure Installed - Water Sourcing, Gathering and Recycling - Sand Rail-Car Unloading Facilities - Oil and Gas Gathering and Takeaway Eddy Lea Delaware Basin 416,000 Net Acres Low LOE Per-Unit Rate Test Permian Northwest Shelf in 2017 Culberson EOG 559,000 Net Acres Loving Winkler Ward Reeves * Estimated potential reserves net to EOG, not proved reserves. Includes 462 MMBoe of proved reserves booked at December 31, 2016 and prior production from existing wells. EOG _0817-28

346,000 Net Acres Prospective with Multiple Target Zones - 2,660 Net Wells - Complete 110 Net Wells in 2017 vs. 71 in 2016 Estimated Resource Potential 2.9 BnBoe,* Net to EOG Oil Play - 226,000 Net Acres, 1,585 Net Wells; 660 Spacing - Upper and Middle Zones - EUR 1,330 MBoe, Gross; 1,050 MBoe, NAR - CWC** Target $7.6 MM for 7,000 Lateral Combo Play - 120,000 Net Acres, 1,075 Net Wells; 880 Spacing - Upper and Middle Zones - EUR 1,550 MBoe, Gross; 1,200 MBoe, NAR - CWC** Target $7.5 MM for 8,300 Lateral Testing 500 Spacing and Additional Targets Wolfcamp Oil and Combo Plays Bopd Boed Lateral - 2Q 2017 25 Gross Wells 30-Day IP 1,945 3,010 6,500 NGLs 20% Gas 27% NGLs 32% Gas 42% Oil 53% Typical Wolfcamp Oil Well Oil 26% Typical Wolfcamp Combo Well * Estimated potential reserves net to EOG, not proved reserves. Includes 330 MMBoe of proved reserves booked at December 31, 2016 and prior production from existing wells. ** CWC = Drilling, Completion, Well-Site Facilities and Flowback EOG _0817-29

Second Bone Spring 289,000 Net Acres Prospective in Northern Delaware Basin - 1,870 Net Wells; 850 Spacing - Complete 25 Net Wells in 2017 vs. 13 in 2016 Estimated Resource Potential 1.4 BnBoe,* Net to EOG Gas 22% NGLs 16% Oil 62% Typical Well - EUR 950 MBoe, Gross; 780 MBoe, NAR - CWC** Target $7.3 MM for 7,000 Lateral Typical Second Bone Spring Well Leonard Shale 160,000 Net Acres Prospective; 1,800 Net Wells - 660 Spacing in A and B Zones - Complete 5 Net Wells in 2017 vs. 8 in 2016 Estimated Resource Potential 1.7 BnBoe,* Net to EOG Typical Well - EUR 1,175 MBoe, Gross; 940 MBoe, NAR - CWC** Target $6.3 MM for 6,800 Lateral NGLs 28% Gas 41% Oil 31% Typical Red Hills Leonard Shale Well * Estimated potential reserves net to EOG, not proved reserves. Includes 67 MMBoe of proved reserves in Second Bone Spring and 66 MMBoe in Leonard Shale booked at December 31, 2016 and prior production from existing wells. ** CWC = Drilling, Completion, Well-Site Facilities and Flowback. EOG _0817-30

Delaware Basin Wolfcamp Oil Wells Average Cumulative Production* Delaware Basin Second Bone Spring Wells Average Cumulative Production* (MBoe) 350 300 250 2016 2015 (MBoe) 240 190 2016 2015 200 140 150 100 90 50 40 0 0 90 180 270 360-10 0 90 180 270 360 Producing Days Producing Days * Normalized to 4,500-foot lateral. * Normalized to 4,500-foot lateral. EOG _0817-31

Largest Oil Producer and Acreage Holder in the Eagle Ford - Average 8 Rigs Operating in 2017 - Complete 195 Net Wells in 2017 vs. 236 in 2016 San Antonio BEXAR GUADALUPE GONZALES FAYETTE LAVACA Estimated Resource Potential 3.2 BnBoe;* 7,200 Net Wells KINNEY UVALDE MEDINA WILSON DE WITT Typical Well - 5,300 Lateral; 40-Acre Spacing - EUR 580 MBoe, Gross; 450 MBoe, NAR - CWC** $4.7MM in 2016; Target $4.3MM Precision Targeting - Lateral Drilling Window 20 vs. Prior 150 ZAVALA MAVERICK DIMMIT Laredo WEBB FRIO Crude Oil Window LA SALLE Wet Gas Window Dry Gas Window ATASCOSA MCMULLEN LIVE OAK KARNES BEE Corpus Christi 0 25 Miles Implementing Enhanced Oil Recovery Program - Incremental Reserves 30%-70% - Direct ATROR*** >30% and PVI**** >2.0 Bopd Boed Lateral 2Q 2017 51 Gross Wells 30-Day IP 1,520 1,960 6,500 - Lynch Unit 2H-4H 2,555 3,245 5,800 - Olympic A 1H-D 4H 2,160 2,910 6,600 - Dio Unit 11H-15H 2,135 2,840 5,100 * Estimated potential reserves net to EOG, not proved reserves. Includes 1,003 MMBoe proved reserves booked at December 31, 2016 and prior production from existing wells. ** CWC = Drilling, Completion, Well-Site Facilities and Flowback *** See reconciliation schedules. Assumes oil price $40 per barrel WTI and natural gas price $2.50 per MMBtu Henry Hub. **** Net present value divided by capital investment. EOG 590,000 Net Acres 528,000 Net Acres in Oil Window NGLs 14% Gas 15% Oil 71% Typical Eagle Ford Well EOG _0817-32

Eagle Ford West Wells Average Cumulative Oil Production* Eagle Ford East Wells Average Cumulative Oil Production* (Mbo) (Mbo) 175 150 125 100 2016 2015 2014 2013 175 150 125 100 2016 2015 2014 2013 2012 75 2012 75 50 50 25 25 0 0 90 180 270 360 0 0 90 180 270 360 Producing Days Producing Days * Normalized to 6,600-foot lateral. * Normalized to 4,600-foot lateral. EOG _0817-33

Canada Complete 35 Net Wells in 2017 vs. 48 in 2016 State Line Stanley, ND Estimated Resource Potential 1.0 BnBoe* - 8,400 Lateral - $5.1 MM CWC** in 2016; Target $4.6 MM - 650 Spacing Elm Coulee Bakken Lite Bakken Core Antelope Extension Focus on Premium Locations - Bakken Core and Antelope Extension Areas - 120,000 Net Acres 20 Miles Core Non-Core EOG Acreage Bakken/Three Forks Bakken Oil Saturated LOE per BOE Reduced 43% Last Two Years - Installed Water Handling and Other Infrastructure Bopd Boed Lateral 2Q 2017 22 Gross Wells 30-Day IP 1,175 1,450 8,400 - Clarks Creek 73-75, 110-0719H 2,075 2,965 9,800 Gas 15% NGL 15% Oil 70% Williston Basin Remaining Wells * Estimated potential reserves net to EOG, not proved reserves. Includes 208 MMBoe proved reserves in Bakken/Three Forks booked at December 31, 2016. Includes prior production from existing wells. ** CWC = Drilling, Completion, Well-Site Facilities and Flowback. EOG _0817-34

Average 2 Rigs in Rockies in 2017 Powder River Basin PRB Turner Sand Identified as Premium Play - Testing 4,800 Column of Stacked Pay Complete 30 Net Wells in 2017 vs. 20 in 2016 CWC* Target $5.0MM for 8,000 Lateral - 2Q Wells at Target Powder River Basin Sheridan Johnson Natrona PRB Core Exploration Area Campbell Converse Crook Weston MT WY Niobrara 8 Gross Turner Wells 2Q 2017 Bopd Boed Lateral - 30-Day IP 910 1,745 8,700 DJ Basin DJ Basin Codell Identified as Premium Play Complete 15 Net Wells in 2017 vs. 30 in 2016 CWC* Target $4.5MM for 9,000 Lateral - 2Q Wells at Target 10 Gross Codell Wells 2Q 2017 Bopd Boed Lateral 770 885 9,000 EOG 400,000 Net Acres DJ Basin WY CO Weld EOG 81,000 Net Acres Laramie * CWC = Drilling, Completion, Well-Site Facilities and Flowback. EOG _0817-35

Trinidad Trinidad and Tobago Sercan Joint Development Project - Completed 5 Gross / 3 Net Well Program Completed One Additional Net Well in July - Drill and Complete Three Additional Net Wells in 2H 2017 Entered Into New Gas Supply Contract - Enables Additional Premium Drilling United Kingdom East Irish Sea (Conwy) - Production Commenced March 2016 - Optimum Production Rate 10,000 Bopd - Undergoing Facility Improvements TRINIDAD VENEZUELA United Kingdom East Irish Sea ATLANTIC OCEAN SECC U(b) 4(a) U(a) NORTH SEA EOG _0817-36