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eogresources Q3 2015 Earnings Report

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NYSE Stock Symbol: Common Dividend: Basic Shares Outstanding: Internet Address: http://www.eogresources.com EOG $0.67 550 Million Investor Relations Contacts Cedric W. Burgher, SVP Investor and Public Relations (713) 571-4658, cburgher@eogresources.com David J. Streit, Director IR (713) 571-4902, dstreit@eogresources.com Kimberly M. Ehmer, Manager IR (713) 571-4676, kehmer@eogresources.com


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Copyright; Assumption of Risk: Copyright 2015. 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 and costs, 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, 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, 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 optimize 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, 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 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 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 20 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014, 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 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, 2014, 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.


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3Q 2015 Increased Delaware Basin Resource Estimate by 1.0 BnBoe* - Increased Wolfcamp Shale Resource Estimate by 500 MMBoe* - Introduced Second Bone Spring Sand Resource Estimate of 500 MMBoe* - Total Resource Estimate 2.35 BnBoe* Acquired 26,000 Net Acres in Delaware Basin for $368MM - Including 750 Boepd Net Production Exceeded 3Q 2015 Oil Production Forecast Due to Advanced Completions Lowered 2015 LOE, Transportation and G&A Expense Guidance - Achieved Primarily Through Sustainable Efficiency Improvements 2015 Plan Focus on Top Plays: Eagle Ford, Bakken and Delaware Basin - Generating Greater Than 35% Direct ATROR** at $50 Oil - Decline Rates Moderating Produce Flat YOY U.S. Oil Production Reduce Capex 42% YOY Defer Completions: Drill 570 Net Wells and Complete 450 Net Wells - Year-End DUCs*** 320 vs. Normal ≈ Low 100s * Estimated potential reserves net to EOG, not proved reserves. Includes proved reserves and prior production from existing wells. ** See reconciliation schedules. *** Drilled uncompleted well. EOG_1115-1


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Uniquely Positioned for Strong 2016 Performance Balanced Capex and Discretionary Cash Flow Increased Capital Flexibility - Fewer Rigs on Long-Term Contracts - Limited Retention Drilling Obligations - Few International Commitments Large, High-Quality DUC Inventory in Place - Highest Rate of Return Increased Organic Growth Potential Large Inventory of High Rate-of-Return Crude Oil Assets EOG_1115-2


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High-Quality Assets With Scale - Large Eagle Ford, Bakken and Delaware Basin Footprints - Scale Drives Cost Savings and Leverages Technology Gains - Most Productive, Lowest-Cost, Horizontal Oil Wells in the U.S. Innovation and Technology Focus - In-House Completion Design - 10+ Years of Continuous Well Performance Improvements - Maximize Field Recoveries and NPV Low-Cost Operator - 10+ Years of Continuous Efficiency Gains - Low Operating Costs and Highest Production Per Employee in Peer Group - Vertically Integrated: Self-Sourced Sand, Chemicals and Drilling Fluids Organic Exploration Growth - Internal Prospect Generation First-Mover Advantage - Inventory Creation Outpacing Drilling by 2X and Quality Rising Organization and Culture Bottom-Up Value Creation - Decentralized Structure Promotes Accountability - Returns-Driven Culture – Significant Employee Compensation Criteria Sustainable Competitive Advantage EOG_1115-3


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40% Eagle Ford Bakken/Three Forks – Core Delaware Basin Wolfcamp - Oil and Combo Delaware Basin 2nd Bone Spring Sand Delaware Basin Leonard 70% Powder River Basin Wyoming DJ Basin 20% 10% $60 Oil $50 Oil Direct ATROR* at Flat Oil Prices Bakken/Three Forks – Non-Core Midland Basin Wolfcamp Direct ATROR* Based on cash flow and time value of money: - Estimated Future Commodity Prices and Operating Costs - Costs Incurred to Drill, Complete and Equip a Well Excludes Indirect Capital: - Gathering, Processing and Other Midstream - Land, Seismic, Geological and Geophysical * See reconciliation schedule. Oil price is at the wellhead, natural gas price is futures strip. EOG_1115-4


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Economics Today vs. $95 Oil Three Years Ago 100% ATROR* 80% 60% 75% 60% 60% 45% 40% 35% 35% 20% 0% Western Eagle Ford 2012 @ $95 Oil Delaware Basin Leonard Today @ $60 Oil Today @ $50 Oil * See reconciliation schedule. EOG_1115-5


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8.8% 7.0% 6.6% 6.3% 4.8% 4.7% 4.1% 4.1% 2.8% EOG Co. 1 Co. 2 Co. 3 Peer Avg Co. 4 Co. 5 Co. 6 Co. 7 2.5% Co. 8 * Source: FactSet, adjusted earnings. Peer companies: APC, APA, CHK, DVN, HES, MRO, NBL and PXD. EOG_1115-6


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Net Acres Remaining Locations* Drilling Years** Resource Potential (MMBoe)*** Eagle Ford 561,000 5,500 13 3,200 Bakken/Three Forks – Core 120,000 590 14 620 Bakken/Three Forks – Non-Core 110,000 950 Delaware Basin Wolfcamp 156,000 2,050 75 1,300 Delaware Basin 2nd Bone Spring Sand 109,000 1,250 70 500 Delaware Basin Leonard 91,000 1,600 115 550 DJ Basin 85,000 460 30 210 Powder River Basin 63,000 275 13 190 ≈ 1,300,000 ≈ 12,500 Play 400 ≈ 7,000 >20 Years of Drilling * Number of remaining net wells as of January 1, 2015 (Bakken/Three Forks as of July 1, 2015, Delaware Basin as of November 5, 2015). Assumes no further downspacing, acreage additions or enhanced recovery. ** Based on average of 2014 and 2015 number of well completions held flat. *** Estimated potential reserves net to EOG, not proved reserves. Includes proved reserves and prior production from existing wells. EOG_1115-7


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2010 Completions 540 Events /1,000 ft 2015 Completions 4,030 Events /1,000 ft Enhance Complexity to Contact More Surface Area Contain Events Closer to Wellbore EOG_1115-8


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1. Scale Rock Characteristics High to Low Quality 2. Summarize and Identify Best Target 3. Drill Eagle Ford EOG_1115-9


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Gathering, Processing and Other $8.3 Bn Exploration and Development Facilities $0.7 Exploration and Development $1.0 $4.7-$4.9 Bn $0.3 $0.8 $6.6 $3.7 2014 2015* * Based on full-year estimates as of November 5, 2015, excluding acquisitions. EOG_1115-10


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$14 EOG Maintains Stable LOE While Increasing Liquids Mix $12 LOE/Boe $10 EOG Peers’ 2014 LOE $8 2011 $6 2014 2012 2015E 2013 2010 $4 $2 $0 0% 10% 20% 30% 40% 50% 60% 70% 80% Liquids Production Source: Company filings. Peers: APA, APC, CHK, CLR, CXO, DVN, MRO, NBL, NFX, PXD, RRC and XEC. EOG_1115-11


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Committed to the Dividend $0.70 $0.67 Increased Dividend Twice in 2014 16 Dividend Increases in 16 Years $0.60 $0.59 $0.50 $0.40 $0.38 $0.29 $0.30 $0.31 $0.32 2010 2011 $0.34 $0.26 $0.18 $0.20 $0.12 $0.10 $0.03 $0.04 $0.04 $0.04 $0.05 1999 2000 2001 2002 2003 $0.06 2004 $0.08 $0.00 2005 2006 2007 2008 2009 2012 2013 2014 2015 Note: Dividends adjusted for 2-for-1 stock splits effective March 1, 2005 and March 31, 2014. EOG_1115-12


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Leonard A 550 MMBoe Net to EOG* Oil and Combo Play Leonard B Texas Red Hills New Mexico Brushy Canyon - 300’- 500’ Spacing 4,800’ 1st Bone Spring 2nd Bone Spring 500 MMBoe Net to EOG* Over-Pressured Oil Play - Testing 550’ Spacing 3rd Bone Spring Upper Wolfcamp Middle Wolfcamp 8 Rigs 2015 1,300 MMBoe Net to EOG* Over-Pressured Oil and Combo Play - Testing 500’ Spacing Lower Wolfcamp * Estimated potential reserves net to EOG, not proved reserves. Includes proved reserves booked at December 31, 2014 and prior production from existing wells. EOG_1115-13


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156,000 Net Acres Prospective with Multiple Target Zones - 4,500’ Average Lateral; ≈700’ Spacing - 2,050 Net Drilling Locations; Plan ≈35 Net Well Completions in 2015 NGLs 24% Gas 26% Estimated Reserve Potential* 1.3 BnBoe, Net to EOG Oil Play; 106,000 Net Acres, 1,375 Locations - Oil Well EUR 750 MBoe, Gross; 600 MBoe, NAR - CWC** $6.9MM Typical Northern Wolfcamp Oil Well Combo Play; 50,000 Net Acres, 675 Locations - Combo Well EUR 900 MBoe, Gross; 675 MBoe, NAR - CWC** $6.5MM NGLs 33% Testing 500’ Spacing and Additional Targets - First High-Density Completion in 3Q Lea County Wells – Delaware Basin Wolfcamp 30-Day Record* IP Rate 30-Day Lateral Bopd Boepd Boepd Thor 21 #701H 4,100’ 3,175 4,270 2,800 Thor 21 #702H* 4,600’ 3,335 4,465 3,490 Brown Bear 36 State #702H 4,600’ 3,085 3,725 2,035 Brown Bear 36 State #703H 4,600’ 3,025 3,905 2,405 Oil 50% Oil 31% Gas 36% Typical Reeves County Wolfcamp Combo Well * Estimated potential reserves net to EOG, not proved reserves. Includes 40 MMBoe of proved reserves booked at December 31, 2014 and prior production from existing wells. ** CWC = Drilling, Completion, Well-Site Facilities and Flowback. EOG_1115-14


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109,000 Net Acres Prospective in Northern Delaware Basin 1,250 Net Drilling Locations; Complete ≈35 Net Wells in 2015 - ≈ 850’ Spacing Estimated Reserve Potential* 500 MMBoe, Net to EOG Typical Well - 4,500’ Lateral - EUR 500 MBoe, Gross; 400 MBoe, NAR - $6.6 MM CWC** - API 43°- 48° NGLs 17% Gas 23% Oil 60% Typical 2nd Bone Spring Sand Well Testing 550’ Spacing and Additional Targets Implemented High-Density Completions in 2Q 2015 Neptune 10 State Com #501H Neptune 10 State Com #502H Lateral 4,500’ 4,500’ County Lea Lea IP Rate Bopd Boepd 2,380 2,865 2,030 2,430 30-Day Boepd 2,095 1,785 * Estimated potential reserves net to EOG, not proved reserves. Includes 38 MMBoe of proved reserves booked at December 31, 2014 and prior production from existing wells. ** CWC = Drilling, Completion, Well-Site Facilities and Flowback. EOG_1115-15


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Completed Well Cost* ($MM) Average Drilling Days* (Spud-to-TD) 7.8 14.4 6.9 6.6 13.2 11.4 9.6 5.7 2014 2015 Plan Current Target 2014 2015 YTD 3Q15 Record * Normalized to 4,500’ lateral. CWC = Drilling, Completion, Well-Site Facilities and Flowback. EOG_1115-16


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91,000 Net Acres Prospective >1,600 Net Drilling Locations; ≈10 Net Completions 2015 Estimated Reserve Potential* 550 MMBoe, Net to EOG Cumulative Crude Oil Production* (Mbo) 70 2015 2014 2013 2012 2011 60 50 40 30 Typical Well - EUR 500 MBoe, Gross; 400 MBoe, NAR - $5.5 MM CWC** - 4,500’ Lateral Identify Targets and Refine Completion Designs - Developing on 300’ to 500’ Spacing in 2015 Implemented High-Density Completions Beginning 2015 - Higher Production with Closer Spacing 20 10 0 0 30 60 90 120 150 Producing Days * Normalized to 4,500-foot lateral. Average Well Spacing (Feet) 1,030 910 835 560 Evaluating Oil Mix; Highly Variable Across the Play 390 Four-Well Pad - Hawk 35 Fed #7-10H: IP Rates 1,130-1,985 Bopd 2011 2012 2013 2014 2015 * Estimated potential reserves net to EOG, not proved reserves. Includes 110 MMBoe of proved reserves booked at December 31, 2014 and prior production from existing wells. ** CWC = Drilling, Completion and Well-Site Facilities and Flowback. EOG_1115-17


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Largest Oil Producer and Acreage Holder in the Eagle Ford - Average 15 Rigs Operating in 2015 - Complete ≈300 Net Wells in 2015 San Antonio Estimated Potential Reserves* 3.2 BnBoe; 7,200 Net Wells - EUR 450 MBoe/Well, NAR at ≈ 40-Acre Spacing Crude Oil Window Multi-Well Pad Development - Improved Capital Efficiency - 88% of 3Q 2015 Completions Acreage 91% Held by Production Phoenix Unit #4-5H: IP Rates 3,935 and 3,695 Bopd Naylor Jones Unit 26 #1-2H: IP Rates 2,665 and 2,640 Bopd Korth Unit #8H: Fastest EOG Well to 500 MBbl Oil – 274 Days Wet Gas Window Dry Gas Window Laredo 0 Gas 12% Fewer Lease Retention Obligations NGLs 10% Oil 78% Targeting Lateral Placement as Narrow as 20’ Window Testing Stacked-Staggered “W” Patterns in Lower Eagle Ford 25 Miles EOG 624,000 Net Acres 561,000 Net Acres in Oil Window 2015 Operations Expanding High-Density Completions to ≈95% of 2015 Wells Corpus Christi Current Production Mix * Estimated potential reserves net to EOG, not proved reserves. Includes 1,008 MMBoe proved reserves booked at December 31, 2014 and prior production from existing wells. EOG_1115-18


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Eagle Ford West Wells Average Cumulative Crude Oil Production* Eagle Ford West Completion Design 47 High-Density Wells* vs. 41 Low-Density Wells* 2014 Vintage Wells (Mbo) (Mbo) 2015 2014 2013 70 60 50 2012 40 30 20 10 140 Cumulative Crude Oil Production 80 Shallower Decline 120 +33% 100 High-Density Wells 80 +30% 60 Low-Density Wells 40 20 0 0 0 20 40 60 80 100 120 140 160 180 Producing Days * Normalized to 5,300-foot lateral. 0 30 60 90 120 150 180 210 240 270 Producing Days * Normalized to 5,300-foot lateral. EOG_1115-19


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Completed Well Cost* ($MM) Average Drilling Days* (Spud-to-TD) 6.1 5.7 14.2 5.5 5.3 10.9 8.9 7.7 4.2 2014 2015 Plan Current Target 2012 2013 2014 Current Record * Normalized to 5,300’ lateral. CWC = Drilling, Completion, Well-Site Facilities and Flowback. EOG_1115-20


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Estimated Reserve Potential 1.0 BnBoe* - 1,540 Net Remaining Locations** - 8,400’ Lateral - $7.0 MM CWC** - 650’ Spacing Core – Highest Rate-of-Return Drilling - 120,000 Net Acres - Bakken Core and Antelope Extension Canada Bakken Lite Elm Coulee Bakken Core Bakken Subcrop Non-Core – Economic With Upside - 110,000 Net Acres - Bakken Lite, State Line and Elm Coulee Antelope Extension 20 Miles Additional Upside Potential - High-Density Completions - Targeting - Downspacing Area Core Non-Core Existing Wells Total Reserve Potential* MMBoe, Net 360 400 260 1,020 Stanley, ND State Line Core Non-Core Gross/Net EUR (MBoe/Well) 745/610 510/420 580/470 EOG Acreage – Bakken/Three Forks Bakken Oil Saturated Net Locations** 590 950 560 2,100 * Estimated potential reserves net to EOG, not proved reserves. Includes 219 MMBoe proved reserves in Bakken/Three Forks booked at December 31, 2014. Includes prior production from existing wells. ** As of July 1, 2015 *** CWC = Drilling, Completion, Well-Site Facilities and Flowback. NGL 15% Gas 15% Oil 70% Remaining Wells EOG_1115-21


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Improving Operating Efficiencies Focus on Bakken Core; 2 Rigs Complete ≈25 Net Wells in 2015 vs. 59 Net Wells in 2014 2015 Operations - Add Infrastructure to Reduce Future Operating and Capital Costs - Zipper-Style Completion Process on Multi-Well Pads - Less Than 6-Month Payout on Infrastructure Projects - Installing Water Handling Systems for Completions and Production Reduced CWC* 20% from 2014 - Primarily from Sustainable Efficiencies 3-Well Pad: Parshall #23-3029H, #26-3029H and #88-3029H - 1,830 Bopd (Average IP) - Average Lateral 5,925’ Riverview #102-32H: 200 MBO in First 91 Days * CWC = Drilling, Completion, Well-Site Facilities and Flowback. EOG_1115-22


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Completed Well Cost* ($MM) Average Drilling Days* (Spud-to-TD) 8.8 20.8 7.8 7.0 14.7 6.5 12.4 7.6 5.6 2014 2015 Plan Current Target 2012 2013 2014 3Q15 Record * Normalized to 8,400’ lateral. CWC = Drilling, Completion, Well-Site Facilities and Flowback. EOG_1115-23


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Play Marcellus / Utica Net Acres 71,000 Haynesville 143,000 Eagle Ford 63,000 Barnett Type Gas Gas and Combo Gas 298,000 Gas and Combo 94,000 Gas and Combo S. Texas Frio/Vicksburg 195,000 Gas and Combo Horn River 127,000 Gas Uinta Option Value for Natural Gas Price Recovery EOG_1115-24


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Trinidad and Tobago Trinidad ATLANTIC OCEAN Stable Production in 2015 TRINIDAD 4(a) Drill 4 Net Wells to Maintain Deliverability U(a) U(b) SECC VENEZUELA United Kingdom East Irish Sea (Conwy) - First Production YE 2015 - Estimated Peak Production – 20 MBopd, Net United Kingdom East Irish Sea NORTH SEA EOG_1115-25


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Maintain Low Net Debt-to-Total Cap Ratio - Credit Ratings – Moody’s A3 / S&P ASuccessful Efforts Accounting Zero Goodwill $2.7 Billion in Available Liquidity - $0.7 Billion Cash at September 30, 2015 - $2.0 Billion Credit Facility – Undrawn at September 30, 2015 EOG Reserves Within 5% of Independent Engineering Analysis - Prepared by DeGolyer and MacNaughton - 27 Consecutive Years - Reviewed 76% of 2014 Proved Reserves EOG_1115-26


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4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0 Co. 1 Co. 2 Co. 3 Co. 4 Co. 5 Peer Avg Co. 6 Co. 7 Co. 8 Co. 9 Co. 10 Co. 11 Co. 12 Co. 13 Co. 14 EOG Co. 15 Source: UBS Investment Research, as of October 19, 2015. Based on $49/Bbl WTI and $2.85/MMBtu. Peer Group: APA, APC, CLR, COG, COP, CXO, DVN, HES, MRO, NBL, NFX, OXY, PXD, RRC and SWN. EOG_1115-27


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On Track to Achieve 2015 Objectives Improve Well Performance Through Technology and Innovation - Targeting - High-Density Completions Lower Capital and Operating Costs - Identify Efficiency Improvements - Improve Infrastructure - Capture Service Cost Reductions Extend Our Lead - Add High-Quality Acreage – Leasing, Farm-Ins, Acquisitions - Organic Exploration Growth Maintain a Strong Balance Sheet - Balanced Capex to Cash Flow - Flexibility to Make Opportunistic Investments Generate High Returns at Low Oil Prices EOG_1115-28


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Copyright; Assumption of Risk: Copyright 2015. 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 and costs, 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, 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, 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 optimize 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, 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 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 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 20 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014, 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 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, 2014, 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.


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