NYSE Stock Symbol: EOG Common Dividend: $0.67 Basic Shares Outstanding: 550 Million Internet Address: http://www.eogresources.com 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
Focus on Returns Shifting to Premium Locations - Generate at Least 30% Direct ATROR* at $40 Oil - Sustainable Improvement >10 Years of Inventory and Growing Grow Premium Inventory At Rapid Pace - Improve Existing Plays With Technology and Innovation Precision Lateral Targeting & Advanced Completions - Organic Exploration and Tactical Acquisitions Increase Capital Productivity - Oil Production Declines Just 5% YOY With 47% Less Capital - Drill 200 Net Wells and Complete 270 Net Wells - 300 Drilled Uncompleted Net Wells At YE 2015 - Average 11 Rigs in 2016; 9 Rigs on Contract At YE 2016 Maintain Strong Balance Sheet Low-Cost Global Oil Producer * See reconciliation schedules. EOG_0216-1
A Record Year For Improvements Identified 2 BnBoe* and >3,200 Premium Net Well Locations Increased Capital Efficiency - Reduced Capital Spending 44% YOY and Maintained Flat U.S. Oil Production Identified >6x New Net Well Locations as Drilled in 2015-2,200 in Delaware Basin and 960 in Bakken/Three Forks - Added 1.6 BnBoe Net Resource Potential* Generated Sustainable Efficiency Improvements - Reduced 2015 Cash Operating Costs** by 17% - Lowered Well Costs In Top Plays 2015 Results Achieved 192% Proved Reserve Replacement*** at $11.91/BOE All-In Finding Cost*** Exceeded Oil Production Forecast Delivered Capital Spending Below Forecast Acquired 34,000 Net Acres In Sweet Spot of Delaware Basin * Estimated potential reserves net to EOG, not proved reserves. Includes proved reserves and prior production from existing wells. ** LOE, transportation, G&A, Taxes other than income and gathering and processing, on a per-unit basis. Exclude one-time expense of $18.7 million related to early leasehold termination. Includes stock compensation and other non-cash expense. See reconciliation schedules. *** Reserve replacement ratio and finding costs before revisions due to price. See reconciliation schedules. EOG_0216-2
High-Quality Assets With Scale - Large Eagle Ford, Bakken and Delaware Basin Footprints - Scale Drives Cost Savings and Leverages Technology Gains Innovation and Technology Focus - In-House Completion Design - Merging Data Science and Geoscience Low-Cost Operator - 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 - Replacing Inventory At 2x Drilling Pace Organization and Culture - Decentralized Structure Bottom-Up Value Creation - Returns-Driven Culture Significant Employee Compensation Criteria Sustainable Competitive Advantage EOG_0216-3
>3,200 Premium Net Well Locations With 2 BnBoe* >10 Years of High Rate-of-Return Drilling 100%+ 60% 30% 10% $30 $40 $50 $60 * Estimated potential reserves net to EOG, not proved reserves. See reconciliation schedules. EOG_0216-4
$40 Oil Premium Inventory 30% 60% 15% Eagle Ford Delaware Basin Wolfcamp - Oil and Combo Delaware Basin 2 nd Bone Spring Sand Delaware Basin Leonard Bakken/Three Forks Core Powder River Basin 40% Wyoming DJ Basin 5% 10% Bakken/Three Forks Non-Core $50 Oil 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 * Direct ATROR at Flat Oil Prices. See reconciliation schedules. Oil price at the wellhead, natural gas price $2.50 per MMBtu. EOG_0216-5
Play Net Acres Remaining Locations* Total Premium Resource Potential (MMBoe)** Eagle Ford 549,000 5,200 1,535 3,200 Bakken/Three Forks Core 120,000 590 330 620 Bakken/Three Forks Non-Core 110,000 950 400 Delaware Basin Wolfcamp 168,000 2,130 695 1,300 Delaware Basin 2 nd Bone Spring Sand 111,000 1,250 255 500 Delaware Basin Leonard 93,000 1,600 280 550 DJ Basin 85,000 460 210 Powder River Basin 63,000 275 80 190 1,300,000 12,500 3,200 7,000 Inventory Growing in Quality and Size * Number of remaining net wells as of January 1, 2016. Assumes no further downspacing, acreage additions or enhanced recovery. ** Estimated potential reserves net to EOG, not proved reserves. Includes proved reserves and prior production from existing wells. EOG_0216-6
Shift to Premium Locations Higher Well Productivity 120-Day Cumulative Oil Production* (Bbl per Foot Treated Lateral) 20.9 Lower Costs 10.7 13.6 2014 2015 2016 Est * Domestic completions, gross oil production. EOG_0216-7
10 9 8 7 6 5 4 288.9 $8.3 Bn $0.7 $1.4-44% 284.4 $4.7 Bn $0.3 $0.8 300.00 270.0 250.00 Oil Production (MBopd) Gathering, Processing and Other 200.00 Exploration and Development Facilities Exploration and Development 150.00 3 2 $6.2 $3.6-47% $2.4 - $2.6 Bn $0.1 $0.4 100.00 50.00 1 $2.0 0 2014 2015 2016* 0.00 * Based on full-year estimates as of February 25, 2016, excluding acquisitions. EOG_0216-8
1st 3 Months Bopd/Boed 113 900 800 700 600 500 400 300 200 100 Wolfcamp Delaware Wolfcamp Midland Natural Gas Well Count Number of Wells 40 35 30 25 20 15 10 5 0 EOG A B C D E F G H I J K 0 Average three-month production, normalized to 5,000 lateral. All horizontal wells from original operator January October 2015. Gas production converted at 20:1. Delaware Basin: Culberson, Eddy, Lea, Loving, Reeves and Ward counties. Peer Companies: APA, APC, CXO, XEC. Midland Basin: Martin, Midland and Upton counties. Peer Companies: APA, CXO, FANG, PE, PXD, RSPP, QEP. Source: IHS Performance Evaluator, supplied by IHS Global Inc.; Copyright (2016). EOG_0216-9
Eagle Ford West Wells Average Cumulative Crude Oil Production* Eagle Ford East Wells Average Cumulative Oil Production* (Mbo) (Mbo) 140 120 100 80 2015 2014 2013 140 120 100 80 2015 2014 2013 2012 60 2012 60 40 40 20 20 0 0 30 60 90 120 150 180 210 0 0 30 60 90 120 150 180 210 Producing Days Producing Days * Normalized to 6,600-foot lateral. * Normalized to 4,600-foot lateral. EOG_0216-10
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 Note: Microseismic dots represent well stimulation events during completions. EOG_0216-11
1. Measure Rock Characteristics and Grade High to Low Quality 2. Overall Grade 3. Drill Lower Eagle Ford EOG_0216-12
Delaware Basin Wolfcamp Oil Play South Texas Eagle Ford Bakken 11.5 8.8 7.5 6.8 6.1 5.7 5.3 7.2 6.5 2014 2015 Target 2014 2015 Target 2014 2015 Target * Normalized to 4,500 lateral. * Normalized to 5,300 lateral. * Normalized to 8,400 lateral. * CWC = Drilling, Completion, Well-Site Facilities and Flowback. EOG_0216-13
$17.02 $15.39 $14.49 $13.72 $12.84* 2014 1Q15 2Q15 3Q15 4Q15 G&P G&A Taxes Other Than Income Transportation LOE * Excludes one-time expense of $18.7 million related to early leasehold termination. Includes stock compensation expense and other non-cash items. See reconciliation schedules. EOG_0216-14
EOG Competitive Globally Brent ($/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 Oil Sands US L48 Conv Russia $10 $0 Middle East/Russia Medium Cost Conventional US Tight Oil Deep Water High Cost Non-OPEC Arctic / Russian Unconventional % World Supply 50% 22% 5% 16% 7% - * Price required to achieve 10% Direct ATROR (see reconciliation schedules). Source: PIRA. EOG_0216-15
4 Rigs 2016 Brushy Canyon Red Hills New Mexico Texas Leonard A Leonard B 1 st Bone Spring 550 MMBoe Net to EOG* Oil and Combo Play - 300-500 Spacing 4,800 2 nd Bone Spring 3 rd Bone Spring 500 MMBoe Net to EOG* Over-Pressured Oil Play - Testing 550 Spacing Upper Wolfcamp Middle Wolfcamp 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, 2015 and prior production from existing wells. EOG_0216-16
168,000 Net Acres Prospective with Multiple Target Zones - 4,500 Average Lateral; 700 Spacing - 2,130 Net Drilling Locations - Complete 60 Net Wells in 2016 vs. 28 in 2015 Estimated Resource Potential 1.3 BnBoe,* Net to EOG Oil Play - 110,000 Net Acres, 1,375 Locations - EUR 750 MBoe, Gross; 600 MBoe, NAR - CWC** $7.5MM in 2015; Target $6.8MM Combo Play - 58,000 Net Acres, 755 Locations - EUR 900 MBoe, Gross; 675 MBoe, NAR - CWC** $6.6MM in 2015 - Acquired 8,000 Net Acres in 4Q 2015 Testing 500 Spacing and Additional Targets - First High-Density Completion in 3Q 2015 Average 30-Day IP in 4Q 2015: 1,495 Bopd and 2,215 Boed - 12 Wells in Wolfcamp Oil and Combo Windows NGLs 24% Gas 26% NGLs 33% Gas 36% Oil 50% Typical Northern Wolfcamp Oil Well Oil 31% Typical Reeves County Wolfcamp Combo Well * Estimated potential reserves net to EOG, not proved reserves. Includes 211 MMBoe of proved reserves booked at December 31, 2015 and prior production from existing wells. ** CWC = Drilling, Completion, Well-Site Facilities and Flowback. EOG_0216-17
Second Bone Spring Sand 111,000 Net Acres Prospective in Northern Delaware Basin - 1,250 Net Drilling Locations; 850 Spacing - Complete 10 Net Wells in 2016 vs. 27 in 2015 Estimated Resource Potential 500 MMBoe,* Net to EOG Typical Well - 4,500 Lateral - EUR 500 MBoe, Gross; 400 MBoe, NAR - $6.6 MM CWC** in 2015 - API 43-48 NGLs 17% Gas 23% Oil 60% Leonard Shale 93,000 Net Acres Prospective - >1,600 Net Drilling Locations; 12 Net Wells Completed in 2015 Estimated Resource Potential 550 MMBoe,* Net to EOG - Evaluating Oil Mix; Highly Variable Across the Play Typical Well - 4,500 Lateral - EUR 500 MBoe, Gross; 400 MBoe, NAR - $5.8 MM CWC** in 2015 Typical 2 nd Bone Spring Sand Well * Estimated potential reserves net to EOG, not proved reserves. Includes 64 MMBoe of proved reserves in Second Bone Spring Sand and 72 MMBoe in Leonard Shale booked at December 31, 2015 and prior production from existing wells. ** CWC = Drilling, Completion, Well-Site Facilities and Flowback. EOG_0216-18
Largest Oil Producer and Acreage Holder in the Eagle Ford - Average 5 Rigs Operating in 2016 - Complete 150 Net Wells in 2016 vs. 329 in 2015 San Antonio BEXAR GUADALUPE GONZALES FAYETTE LAVACA KINNEY UVALDE MEDINA Estimated Resource Potential 3.2 BnBoe;* 7,200 Net Wells - EUR 450 MBoe/Well, NAR at 40-Acre Spacing Precision Targeting - Lateral Drilling Window 20 vs. Prior 150 Acreage 91% Held by Production at YE 2015 30-Day IP (Bopd) Lepori Unit 4H 2,915 Lightfoot Unit 5H-8H 2,425 Naylor Jones Unit 31 1H 1,780 MAVERICK Laredo ZAVALA DIMMIT WEBB FRIO Crude Oil Window LA SALLE Wet Gas Window Dry Gas Window ATASCOSA MCMULLEN WILSON LIVE OAK KARNES BEE Corpus Christi EOG 608,000 Net Acres 549,000 Net Acres in Oil Window DE WITT 0 25 Miles 2016 Operations Focused on Premium Locations Few Lease Retention Obligations Testing Stacked-Staggered W Patterns 200 to 250 Apart Reducing Operating Costs Through Sustainable Efficiencies NGLs 11% Gas 13% Oil 76% Current Production Mix * Estimated potential reserves net to EOG, not proved reserves. Includes 1,032 MMBoe proved reserves booked at December 31, 2015 and prior production from existing wells. EOG_0216-19
Focus on Premium Locations in Bakken Core Canada Complete 10 Net Wells in 2016 vs. 25 in 2015 Estimated Resource Potential 1.0 BnBoe* - 1,540 Net Remaining Locations - 8,400 Lateral - $7.2 MM CWC** in 2015-650 Spacing Core Highest Rate-of-Return Drilling - 120,000 Net Acres - Bakken Core and Antelope Extension Non-Core Future Upside - 110,000 Net Acres - Bakken Lite, State Line and Elm Coulee Elm Coulee Bakken Subcrop 20 Miles State Line Core Non-Core Bakken Lite Bakken Core Antelope Extension EOG Acreage Bakken/Three Forks Bakken Oil Saturated Stanley, ND Reserve Potential* Gross/Net Net Area MMBoe, Net EUR (MBoe/Well) Locations Core 360 745/610 590 Non-Core 400 510/420 950 Existing Wells 260 580/470 560 Total 1,020 2,100 * Estimated potential reserves net to EOG, not proved reserves. Includes 165 MMBoe proved reserves in Bakken/Three Forks booked at December 31, 2015. Includes prior production from existing wells. ** CWC = Drilling, Completion, Well-Site Facilities and Flowback. Gas 15% NGL 15% Oil 70% Remaining Wells EOG_0216-20
Reset Company to Be Successful At Low Prices Improve Well Productivity with Technology and Innovation - Precision Lateral Targeting - High-Density Completions Lower Costs - Identify Further Efficiency Improvements - Enhance Infrastructure Extend Our Lead - Add Premium-Quality Drilling Potential Thru Organic Exploration - Develop Only Premium Locations Going Forward Maintain a Strong Balance Sheet - Balance Capex to Cash Flow - Recycle Inventory Through Asset Sales Resume High-Return Growth When Prices Improve EOG_0216-21
EOG_0216-22
(MBod) 2014 +1,252 2015 +721 2016-732 2017-233 9,653 9,694 9,428 9,456 9,479 9,433 9,449 8,959 9,201 9,129 9,345 9,407 9,318 9,370 9,315 9,197 9,125 9,041 8,987 8,926 8,754 8,835 8,815 8,577 8,678 8,568 8,611 8,687 8,404 8,509 8,492 8,498 8,504 8,414 8,476 8,425 8,603 8,568 8,420 8,244 8,309 8,310 8,247 7,998 8,087 Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov * EIA STEO Model Released 2/9/2016. EOG_0216-23
What Are The Drivers? Production Increased 2 MMBod January 2013 to May 2015-11% Longer Laterals - 14% Enhanced Completion Technology - 75% Number of Wells Put to Sales Each Month Conclusion - Number of New Wells Put to Sales Most Significant Driver - Completion Technology Continues to Improve - Lateral Length Plateauing Production Will Decline When Operators Stop Outspending Cash Flow EOG_0216-24
Asset Quality - Highly Variable - Small Sweet Spots All Operators Are Not Equal Sustainable Productivity Improvements - Driven by Operators with the Best Technology Cost Reductions - Cyclical for Many Operators Not Sustainable Very Few Operators Earn a 10% ATROR at $40 Oil Only Operators With the Best Assets and Technology Will Be Successful At Lower Oil Prices EOG_0216-25
EOG > 2X Industry Average Bopd 800 758 700 600 500 400 368 300 200 100 0 EOG Industry * Eagle Ford, Bakken, Permian, DJ and PRB. Source: IHS Performance Evaluator, supplied by IHS Global Inc.; Copyright (2016). 1/1/13 through 6/30/15. EOG_0216-26
Well Count 300 Percent Oil 100% 250 Well Count Percent Oil 80% 200 60% 150 100 40% 50 20% 0 EOG A B C D E F G H I J K L M N O P Q R S 0% * Source: Sanford C. Bernstein & Co. Thousand Club includes wells with 30-day rate over 1,000 Boepd in 2015. Gas converted 20:1. Represents 3,600 wells out of 40,000 drilled. Peer Group: APA, BHP, CLR, COP, CXO, DVN, ECA, EPE, FANG, HES, MRO, NFX, OXY, PXD, QEP, SD, WLL, XEC, XOM. EOG_0216-27
359 EOG is Industry Leader 250 214 213 212 188 158 155 153 137 EOG A B C D E F G H I Source: IHS Performance Evaluator, supplied by IHS Global Inc.; Copyright (2016). Data as of Sept. 2015. Peer companies: APC, CHK, CLR, COP, CXO, DVN, MRO, PXD and WLL. EOG_0216-28
9.0% 7.6% 7.3% 6.5% 4.9% 4.3% 4.2% 4.2% 2.8% 2.5% EOG A B C Peer Avg D E F G H * Source: FactSet, adjusted earnings. Peer companies: APC, APA, CHK, DVN, HES, MRO, NBL and PXD. EOG_0216-29
$0.70 Committed to the Dividend 16 Dividend Increases in 17 Years $0.67 $0.67 $0.60 $0.59 $0.50 $0.40 $0.30 $0.26 $0.29 $0.31 $0.32 $0.34 $0.38 $0.20 $0.18 $0.12 $0.10 $0.03 $0.04 $0.04 $0.04 $0.05 $0.06 $0.08 $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. * Indicated annual rate. EOG_0216-30
Trinidad and Tobago Trinidad Complete One Net Well Late 2016 Limited Capital Spending in 2016 Active Exploration Program United Kingdom East Irish Sea (Conwy) - First Production March 2016 - Estimated Peak Production 20 MBopd, Net TRINIDAD VENEZUELA United Kingdom East Irish Sea ATLANTIC OCEAN SECC U(b) 4(a) U(a) NORTH SEA EOG_0216-31
Maintain Strong Balance Sheet - Investment Grade Credit Ratings Successful Efforts Accounting Zero Goodwill $2.7 Billion in Available Liquidity - $0.7 Billion Cash at December 31, 2015 - $2.0 Billion Credit Facility Undrawn at December 31, 2015 Increased Dividend 16 Times in 17 Years - Current Indicated Annual Rate $0.67 per Share EOG Reserves Within 5% of Independent Engineering Analysis - Prepared by DeGolyer and MacNaughton - 28 Consecutive Years - Reviewed 86% of 2015 Proved Reserves EOG_0216-32
9 8 7 6 5 4 3 2 1 0 A B C D E F G Peer Avg H I J K L M EOG N O Source: UBS Investment Research. Net debt as of 9/30/15 and 2016E EBITDAX as of January 22, 2016. Based on $40/Bbl WTI and $2.45/MMBtu. Peer Group: APA, APC, CLR, COG, COP, CXO, DVN, HES, MRO, NBL, NFX, OXY, PXD, RRC and SWN. EOG_0216-33
Copyright; Assumption of Risk: Copyright 2016. 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, reduce or otherwise control operating and capital costs, generate income or cash flows or pay dividends are forward-looking statements. Forwardlooking 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 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 21 of EOG s Annual Report on Form 10-K for the fiscal year ended December 31, 2015 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, 2015, 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.