NYSE Stock Symbol: Common Dividend: Basic Shares Outstanding: Internet Address: http://www.eogresources.com EOG $0.67 547.5 Million Investor Relations Contacts Maire A. Baldwin, Vice President IR (713) 651-6364, Fax (713) 651-6473 [email protected] David J. Streit, Director IR (713) 571-4902, [email protected] Kimberly A. Matthews, Manager IR (713) 571-4676, [email protected] Copyright; Assumption of Risk: Copyright 2014. 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 and extent 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 17 through 26 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013 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). As noted above, 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, 2013, 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 2014 Delivered 33% YOY U.S. Crude Oil Growth and 17% Total Production Growth Raised Common Stock Dividend 34%; Second Increase in 2014 Added Delaware Basin Oil Play, 2nd Bone Spring Sand to Drilling Inventory Strong Spacing and Productivity Results from Leonard Shale Grew Non-GAAP EPS 38%, EBITDAX 19% and Discretionary Cash Flow 18%* Net Debt-to-Total Cap Ratio 22% at June 30, 2014* YTD 2014 Added ≈ 10 Years of High-Return Drilling Inventory in DJ and Powder River Basins Increased Eagle Ford Reserves** by 45% - 2.2 BnBoe - Added ≈ 1,600 High ROR Net Drilling Locations - Expect Continued Production Growth Next 10+ Years 3.2 BnBoe, Net to EOG * Certain financial metrics reflected are ‘as Adjusted.’ See reconciliation schedules. ** Estimated potential reserves, not proved reserves. EOG_0914 v3-1 Best Horizontal Crude Oil Assets in North America Peer-Leading Organic Crude Oil Production Growth - 2011 +52% - 2012 +39% 40% 4-Year CAGR - 2013 +40% - 2014E* +29% 2014E ROE/ROCE > Average of Majors, Integrateds and Independent E&Ps Exploration and Technology Focus Increases Drilling Inventory - Identify New Plays - Expand and Improve Existing Plays - Completion Technology Leader Efficient and Innovative Operator - EOG Self-Sourced Sand Reduces Completion Costs - EOG Crude-by-Rail Infrastructure Provides Market Flexibility Disciplined, Return-Focused Capital Allocation Rate-of-Return Focus Drives Shareholder Value and Growth * Based on mid-point of full-year 2014 production estimates as of August 5, 2014. EOG_0914 v3-2 Exploration and Technology Focus Exploration - Identify Additional Targets in Existing Plays - Generate New Plays Internally - Capture Premier Acreage - Early-Mover Strategy Drives Low Leasing Costs Technology Application - EOG Completion Innovation - Increase Drilling Density/Down-Spacing to Maximize NPV - Reduce Per-Unit Operating Costs Inventory Growing in Both Size and Quality - Added 2,300 Net Drilling Locations 1H 2014 2x 2014 Drilling Program - New Inventory Return >60% Direct ATROR* - New Resource Plays Still Growing in North America Core Competency and Sustainable Competitive Advantage * See reconciliation schedules. EOG_0914 v3-3 Direct After-Tax Rate of Return* 100% Eagle Ford Bakken/Three Forks Delaware Basin Leonard Powder River Basin Parkman Wyoming DJ Basin Codell Powder River Basin Turner Delaware Basin 2nd Bone Spring Sand Delaware Basin Wolfcamp 60% 30% Wyoming DJ Basin Niobrara Midland Basin Wolfcamp Barnett Combo Dry Gas * See reconciliation schedules. EOG_0914 v3-4 2014* Gathering, Processing and Other 10% Majority of Capex Increase Going to Top Plays: Eagle Ford, Bakken, Permian and Rockies 10 Exploration and Development Facilities 11% 9 8 $8.1 to $8.3 Bn $7.1 Bn 7 6 5 Exploration & Development E&P Facilities Exploration & Development Gathering, Processing and Other 4 3 Exploration and Development 79% 2 1 0 2013 2013 Exploration and Development E&D Facilities Gathering, Processing & Other 2014E* 2014E* 2014E Capex ≈ $8.1 to $8.3 Bn* Including Facilities and Midstream * Based on full-year estimates as of August 5, 2014, excluding acquisitions. EOG_0914 v3-5 Tactical - 2014 High Return Oil Growth Increased Dividend Twice - February +33% - August +34% Strategic - 2015+ High Rate-of-Return Capital Expansion - Increase E&P Activity in Highest ATROR Plays - Increase High-Return Drilling Inventory through Exploration Consider Further Dividend Increases Maintain Strong Balance Sheet EOG_0914 v3-6 Extending Our Lead 400 350 EOG 300 OXY 250 CVX 200 150 100 50 0 Jan May 2010 Sep Jan May Sep Jan 2011 May Sep 2012 Jan May Sep 2013 Jan 2014 * Source: IHS data through April 2014. Gross operated oil production. EOG_0914 v3-7 70 60 50 40 30 20 10 Co. 12 Co. 13 Chesapeake Energy Marathon Oil Average Co. 8 Co. 9 Co. 10 Co. 11 Denbury Resources Apache Corp Co. 7 Cimarex Energy Peer Avg. Noble Energy Co. 6 Newfield Exploration Co. 5 Concho Resources Co. 4 Pioneer Resources Co. 3 Continental Resources Co. 2 Devon Energy Co. 1 Anadarko Petroleum -10 EOG Resources EOG Hess Corporation 0 Sources: Company filings, First Call. Production adjusted for Acquisitions/Dispositions to reflect ‘Organic’ production only. Peers include: APA, APC, CHK, CLR, CXO, DNR, DVN, HES, MRO, NBL, NFX, PXD, XEC. EOG_0914 v3-8 300 ≈ 285 250 65 Actual 220 200 62 158 150 113 100 75 50 55 20 2009 2010 45 38 0 2011 2012 2013 2014E* * Based on mid-point of full-year 2014 production estimates as of August 5, 2014. EOG_0914 v3-9 2014 Net Wells 520 Oil Eagle Ford Drilling Years* 12 Bakken/Three Forks 80 8 Delaware Basin Leonard/Bone Spring 40 40+ DJ Basin 39 12 Powder River Basin 34 8 Delaware Basin Wolfcamp 14 75+ Midland Basin Wolfcamp 10 50+ Combo >15 Years of Drilling * Based on current technology and 2014 drilling program. Assumes no further downspacing or enhanced recovery. EOG_0914 v3-10 2011 2012 2013 2014E* 2015E - 2017E Crude Oil and Condensate 52% 39% 40% 29% NGLs 39% 32% 17% 18% 48% 37% 34% 27% Continued Best-in-Class Double-Digit Growth North American Gas -7% -9% -13% -3% Flat Other Gas** --% 9% -6% 3% Flat 9.4% 10.3% 9.4% 14% Total Company Liquids Total Company Highest Annual Organic Crude Oil Growth of Large Cap E&P Peer Group Over Last Four Years * Based on the mid-point of full-year 2014 production estimates as of August 5, 2014. Liquids converted at 6:1 ratio. ** Contingent on Trinidad market conditions. EOG_0914 v3-11 79% 76% ≈ 89% 88% 86% NGLs 72% 71% 59% 53% Oil 47% 41% 29% 21% 28% 24% 14% 2006 2007 2008 2009 2010 2011 Liquids (Crude Oil and NGLs) 2012 12% 2013 ≈ 11% 2014E* Natural Gas * Based on NYMEX 2014 Current Oil to Gas Prices as of July 11, 2014 and mid-point of full-year 2014 production estimates as of August 5, 2014. EOG_0914 v3-12 $43.31 $40.14 $34.11 $29.29 $20.04 2010 2011 2012 2013 2Q YTD * Wellhead Revenues for Crude Oil and Condensate, Natural Gas Liquids and Natural Gas less Lease and Well Costs, Transportation Costs, Exploration Costs, Dry Hole Costs, General and Administrative, Taxes Other than Income and Net Interest Expense plus any Net Cash Receipts from (Payments on) Settlement of Commodity Derivative Contracts, calculated on a per unit basis. EOG_0914 v3-13 ROCE ROE 18.1% 14.5% 15.6% 12.4% 11.8% 9.4% 2012* 2013* 2014E** 2012* 2013* 2014E** * See reconciliation schedule. ** Goldman Sachs estimates July 25, 2014, $96.50 WTI and $4.25 Henry Hub in 2014. EOG_0914 v3-14 ROCE* ROE* 18.1% 15.6% 14.5% 13.7% 14.1% 12.7% 12.4% 10.0% 13.6% 11.7% 11.2% 9.5% 8.9% 1 2013 2 2014E 1 2013 E&P Integrateds Majors EOG 3.7% E&P Integrateds Majors EOG E&P Integrateds Majors EOG 3.4% E&P Integrateds Majors EOG 6.6% 2 2014E * Source: Goldman Sachs, May/July 2014 estimates. Majors: BP, CVX, RDS, TOT, XOM. Integrateds: COP, HES, MRO, MUR, OXY. E&Ps: APC, APA, CHK, DVN, NBL, NFX, PXD. Also see EOG reconciliation schedules. EOG_0914 v3-15 Committed to the Dividend $0.70 $0.67 Increased Dividend Twice in 2014 16 Dividend Increases in 15 Years $0.60 $0.50 $0.50 $0.40 $0.375 $0.29 $0.30 $0.31 $0.32 2010 2011 $0.34 $0.255 $0.18 $0.20 $0.12 $0.10 $0.03 $0.035 $0.04 $0.04 $0.05 $0.06 1999 2002 2003 2004 $0.08 $0.00 2000 2001 2005 2006 2007 2008 2009 2012 2013 2014* 2014** Note: Dividends adjusted for 2-for-1 stock split effective March 1, 2005 and March 31, 2014. * Indicated annual rate effective April 2014. ** Indicated annual rate effective October 2014. EOG_0914 v3-16 140 API Gravity 120 50 to 100 48° to 50° 100 45° to 48° 35° to 45° 80 0 to 35° 60 40 20 0 EOG EOG 1 Conoco Phillips 2 3 Devon 4 5 Anadarko 6 7 EP Energy 8 9 BHP 10 * IHS data January 2011 through April 2014. Cumulative gross crude oil and condensate production for producers with ≥20 MMbo. Producers 1 -10 include: APC, BHP, CHK, COP, DVN, EPE, FCX (ECA), MRO, MUR, PXD. EOG_0914 v3-17 Largest Oil Producer and Acreage Holder in the Eagle Ford - 2Q 2014 Oil Production Up 46% YOY Continued Outstanding Well Results Across Acreage IP Rate County Well Bopd Gonzales Boothe Unit 11H 4,570 DeWitt Justiss Unit 13H 4,130 Karnes McCoy Unit 2H 5,415 Atascosa Pacheco Unit 1H 1,840 McMullen Naylor Jones Unit 43 W2H 2,030 La Salle Naylor Jones Unit 127 2H 2,500 Window Crude Oil Wet Gas Dry Gas Total Net Acres 564,000 22,000 46,000 632,000 San Antonio Crude Oil Window Wet Gas Window Dry Gas Window Corpus Christi Laredo 0 25 Miles EOG 632,000 Net Acres Gas 12% NGLs 10% Oil 78% Current Production Mix EOG_0914 v3-18 Big Fields Get Bigger Increased Estimated Potential Reserves* by 45% Increased Total Well Count to 7,200, Net Locations - ≈ 12-Year Inventory of >60% ATROR** Drilling Locations - Average 40-Acre Spacing Across Acreage Reserve Potential* Since Discovery (BnBoe) 3.2 Increased EUR to 450 MBoe/Well, NAR 2.2 Third Reserve Increase in Four Years 1.6 2014 Operations 0.9 Well Economics >100% Direct ATROR** Continue to Improve Wells with Completion Techniques Plan to Drill ≈ 520 Net Wells, 26-Rig Program Apr 2010 Feb 2012 Feb 2013 Feb 2014 EOG Self-Sourced Sand Continues to Increase Efficiencies and Lower Well Costs Targeting $5.7 MM CWC with Larger Fracs and Longer Laterals * Estimated potential reserves, not proved reserves. Includes 765 MMBoe proved reserves booked at December 31, 2013. ** See reconciliation schedule. EOG_0914 v3-19 April 2010 Wells/Section (Unit) 5 Feb 2012 10 Feb 2013 Feb 2014 10 - 16 16 Per Well Spacing (Acres) 130 Acres 65 Acres 40-65 Acres ≈40 Acres Est. Reserves, NAR 320 MBoe 450 MBoe 400 MBoe 450 MBoe $5.25 MM $6 MM $6 MM $5.7 MM 80% 130% 100% 100%+ CWC Direct ATROR* Per Section (640 Acres) Est. Reserves NPV10 1.6 MMBoe $23 MM Total Net Potential Reserves 0.9 BnBoe 4.5 MMBoe $69 MM 1.6 BnBoe 6.4 MMBoe $98 MM 2.2 BnBoe 7.2 MMBoe $114 MM 3.2 BnBoe** * See reconciliation schedule. ** Estimated potential reserves, not proved reserves. Includes 765 MMBoe proved reserves booked at December 31, 2013. EOG_0914 v3-20 Average Cumulative Crude Oil Production* for Eagle Ford West Wells (Mbo) 45 2014 YTD 40 2013 35 30 2012 2011 25 20 15 10 5 0 0 10 20 30 40 50 60 Producing Days * Normalized to 5,300’-foot lateral. EOG_0914 v3-21 Atascosa County Pacheco Unit 1H 1,840 Bopd Dicke A Unit 4H 1,810 Bopd Gonzales County Zimmerman Unit 14H 3,800 Bopd Boothe Unit 11H, 16H 4,570 and 3,245 Bopd San Antonio DeWitt County Justiss Unit 11H – 13H 3,900 – 4,130 Bopd Karnes County Wolf Unit 6H - 9H 3,160 - 3,600 Bopd McCoy Unit 2H, 1H 5,415 and 5,290 Bopd La Salle County Laurette Unit 1H 2,040 Bopd Naylor Jones Unit 127 1H – 3H 2,200 – 2,500 Bopd McMullen County Naylor Jones Unit 43 West 2H 2,030 Bopd 0 25 Miles EOG 564,000 Net Acres in Crude Oil Window EOG_0914 v3-22 Transformed into High ROR Crude Oil Growth Play Canada New Frac Technology Improves Recovery and Returns Stanley, ND State Line Delivering 100% Direct ATROR* from Core and Antelope Bakken Lite - Bakken Core ≈ 90,000 Net Acres - Antelope Extension ≈ 20,000 Net Acres Elm Coulee 86 MBoed Gross Production YE 2013, 38% Increase YOY Bakken Subcrop Strong Core Wells - Wayzetta 43-0311H - Wayzetta 44-0311H - Wayzetta 45-0311H Bakken Core Parshall 1-36H Discovery Well 1,505 Bopd 2,410 Bopd 2,690 Bopd 20 Miles EOG Acreage – Bakken/Three Forks Bakken Oil Saturated Operations 2014 Focus on Core and Antelope; 6 Rigs 80 Net Wells Planned for 2014, Target $9.0 MM CWC Continued Success with 1,300’ Spacing - Testing Further Downspacing to Maximize NPV EOG Self-Sourced Sand Now Fully Integrated Testing Three Forks Intervals in 2H 2014 * See reconciliation schedules. Note: 221 MMBoe proved reserves in Bakken/Three Forks booked at December 31, 2013. Antelope Extension Gas 2% NGLs 6% Gas 11% Oil 92% Core Well NGLs 11% Oil 78% Antelope Well EOG_0914 v3-23 Leonard A Texas New Mexico Brushy Canyon Leonard B Net to EOG* MMboe High ROR Oil Play - Spacing Tests Underway 550 MMboe Over Pressured Oil Play - Strong Initial Tests Evaluating High ROR Combo Play - Spacing Tests Underway 800 MMboe 4,800’ 1st Bone Spring Leonard/ Bone Spring 2nd Bone Spring 3rd Bone Spring Wolfcamp Upper Wolfcamp Middle Wolfcamp Lower Wolfcamp * Estimated potential reserves, not proved reserves. EOG_0914 v3-24 Drilled and Participated in 16 Wells Since 2013 - Wells Producing from 500 - 1,400 Bopd - API = 45° Target Well Economics for 4,500’ Lateral - EUR ≈ 500 MBoe/Well, Gross - $6 MM CWC and 100% Direct ATROR* - Plan to Drill 9 Wells in 2014 Beneath 73,000 Net-Acre Leonard Position - Evaluating and Delineating Acreage NGLs 14% Gas 16% Oil 70% Typical Red Hills 2nd Bone Spring Sand Well Integrating Self-Sourced Sand Applying EOG Advanced Completion Technology First EOG Wells Delivering Very Good Results and Economics IP Rates Lea County Bopd + NGLs Bpd + MMcfd Mars 3 State #1H 1,270 150 1.1 Jolly Roger 16 State #1H 1,450 210 1.5 Lateral 3,300’ 4,500’ * See reconciliation schedule EOG_0914 v3-25 73,000 Net Acres EOG’s 3rd Best ROR Play NGLs 26% Both a Development and Exploration Area Estimated Reserve Potential* 550 MMBoe, Net to EOG Gas 24% Target Well Economics for 4,400’ Lateral - 500 MBoe EUR/Well, Gross; 400 MBoe, NAR Oil 50% Typical Leonard Well - $5.0 MM CWC and ≈ 100% Direct ATROR** 1,600+ Net Drilling Locations - 2-Rig Drilling Program - Testing Multiple Zones and Spacing Patterns Recent ‘A’ Zone Downspacing and ‘B’ Zone Well Results – Peak Rates Dragon 36 State (4 Wells) Gemini (3 Wells) Mercury State #1H Mercury State #2H Falcon 25 Fed #2H Zone A A A B B Bopd + 1,100 - 1,500 1,120 - 1,530 1,700 1,630 920 NGLs Bpd 195 - 235 185 - 220 360 230 120 + MMcfd 1.1 - 1.3 1.0 - 1.2 2.0 1.3 0.7 * Estimated potential reserves, not proved reserves. Includes 63 MMBoe of proved reserves booked at December 31, 2013. ** See reconciliation schedule. EOG_0914 v3-26 Completed Well Costs* ($MM) Average Oil IP Rates* (Bopd) $6.9 $6.4 1,263 $5.3 $5.0 691 2011 2012 2013 2014 YTD 2011 737 2012 783 2013 2014 YTD * Normalized to ≈ 4,400-foot lateral. EOG_0914 v3-27 Better Wells on Tighter Spacing (Mbo) (Feet) 45 40 1,200 1,032’ 15% 911’ 35 1,000 17% 14% 30 800 836’ 25 600 20 554’ 400 15 10 200 5 0 0 2011 2012 2013 Average 80-Day Cumulative Oil* 2014 YTD Well-Spacing * Normalized to 4,400-foot lateral. EOG_0914 v3-28 134,000 Net Acres Multiple Pay Targets Estimated Reserve Potential* 800 MMBoe, Net to EOG Target Well Economics for 4,500’ Lateral, Reeves County - 900 Mboe EUR/Well, Gross; 700 MBoe, NAR - $6.5 MM CWC and 70% Direct ATROR** 1,100+ Net Drilling Locations - Plan to Drill 14 Net Wells in 2014 - 1 Rig Testing 750’ Spacing Pattern in Same Zone - Good Initial Results Recent Well Results – Peak Rates (Reeves County) State Apache 57 (3 Wells) State Harrison Ranch 56 (2 Wells) State Apache 57 #1107H Zone Upper Upper Upper Oil 31% NGLs 33% Gas 36% Typical Delaware Wolfcamp Well Bopd + NGLs Bpd + MMcfd 590 - 865 200 - 265 1.3 - 1.7 660, 665 275, 450 1.8, 2.9 1,600 460 3.0 * Estimated potential reserves, not proved reserves. Assumes estimated 2% - 3% recovery factor and includes 21 MMBoe of proved reserves booked at December 31, 2013. ** See reconciliation schedules. EOG_0914 v3-29 10 Years of High-Return Drilling Inventory in the Rockies Basin DJ Powder River Play Net Acres Net Locations Net to EOG* MMboe % Crude Oil API Direct ATROR** Codell 85,000 225 125 78% 36 >100% Niobrara 50,000 235 85 71% 35 ≈45% Parkman 30,000 115 75 69% 41 >100% Turner 63,000 160 115 34% 44- 56 ≈100% 735 400 Total * Estimated potential reserves, not proved reserves. ** See reconciliation schedules. EOG_0914 v3-30 Targeting Codell and Niobrara, 39 Net Wells Target Economics for 9,000 Foot Laterals Codell Niobrara EUR/Well (Mboe) Gross 695 430 NAR 560 355 CWC ($MM) $7.3 $8.0 Direct ATROR* >100% ≈45% Spacing (Feet) Current 1,300’ 880’ Testing 710’ 710’ Codell – Recent Well IPs (9,000’ Laterals) Bopd Jubilee 103-0433H 1,400 Windy 504-1806H 1,400 Jubilee 513-0820H 1,325 Jubilee 584-1705H 1,180 Pole Creek 525-2413H 1,165 Jubilee 586-1705H 1,145 Niobrara – Initial Well IPs (3,600’ Laterals) Bopd Windy 01-18H 700 Jubilee 30-07H 670 Jubilee 69-04H 700 Jubilee 513-0820H Pole Creek 525-2413H Jubilee 69-04H Jubilee 30-07H Jubilee 103-0433H Jubilee 584-1705H 586-1705H Windy 01-18H Windy 504-1806H Gas 7% NGLs 15% Oil 78% Codell Well NGLs 19% Gas 10% Oil 71% Niobrara Well * See reconciliation schedules. EOG_0914 v3-31 Wyoming Targeting Parkman and Turner, 34 Net Wells Lateral Length EUR/Well (Mboe) Gross NAR CWC ($MM) Direct ATROR* Spacing (Feet) Current Parkman 7,300’ Turner 8,200’ 850 680 $5.0 >100% 860 705 $7.5 ≈100% Mary’s Draw 419-16H 1,300’ 1,655’ Mary’s Draw 404-21H Bolt 404-05H Bolt 429-05H Bolt 22-05H Blade 01-2116H Mary’s Draw 468-34H Parkman – Recent Well IPs (4,000’ Laterals) Mary’s Draw 404-21H Mary’s Draw 468-34H Bopd + Rich Gas 1,045 305 Mcfd 980 330 Mcfd NGLs 11% Turner – Recent Well IPs Blade 01-2116H Bolt 22-05H Bopd 746 686 NGLs + Bpd + 112 132 GasGas 43%43% Gas 20% Mcfd 1,046 1,230 Lateral 6,500’ 4,200’ Oil 69% Parkman Well Oil Oil 34% 34% NGLs 23% NGLs 23% Turner Well * See reconciliation schedules. EOG_0914 v3-32 Play Haynesville Marcellus, Bradford County S. Texas Frio/Vicksburg Eagle Ford Barnett Uinta Horn River Net Acres Type 143,000 Gas and Combo 46,000 195,000 68,000 Gas Gas and Combo Gas 298,000 Gas and Combo 94,000 Gas and Combo 127,000 Gas Acreage Holds Option Value for Natural Gas Price Recovery EOG_0914 v3-33 Trinidad Trinidad and Tobago ATLANTIC OCEAN Expect Full Contract Deliverability in 2014 TRINIDAD 2H 2014 Drilling Program to Maintain Future Deliverability - Plan to Drill 3 Net Wells 4(a) U(a) U(b) SECC VENEZUELA United Kingdom United Kingdom Central Graben East Irish Sea (Conwy) - First Production Early 2015 - Estimated Peak Production – 20 MBopd, Net East Irish Sea NORTH SEA Southern Gas Basin EOG_0914 v3-34 Maintain Low Net Debt-to-Total Cap Ratio - Credit Ratings – Moody’s A3 / S&P ASuccessful Efforts Accounting Zero Goodwill Two Dividend Increases in 2014 - 16 Increases in 15 Years EOG Reserves Within 5% of Independent Engineering Analysis Prepared by DeGolyer and MacNaughton - 26 Straight Years - Reviewed 82% of Proved Reserves for 2013 EOG_0914 v3-35 Crude Oil* 2014 August 1 to December 31 Bbld $/Bbl 194,000 $96.19 MMBtud $/MMBtu 330,000 $4.55 175,000 $4.51 Natural Gas* 2014 September 1 to December 31 2015 January 1 to December 31 * As of August 5, 2014. Does not reflect options held by certain counterparties to extend current crude oil derivative contracts or to enter into additional natural gas derivative contracts. See reconciliation schedules for details. EOG_0914 v3-36 Rate-of-Return Focused Investments Drive Shareholder Value and Growth Peer-Leading Organic Crude Oil Production Growth 2014E ROE/ROCE > Average of Majors, Integrateds and Independent E&Ps Exploration Focus - Premier Acreage Positions - Early-Mover Strategy Drives Low Leasing Costs Completions Designed In-House Using Self-Sourced Materials - Highest Productivity Wells in Industry - Lowest Completed Well Costs - Still Making Advancements Peer-Leading Discretionary Cash Flow Growth - 15 Years of Dividend Growth - Strengthening Balance Sheet EOG_0914 v3-37 Copyright; Assumption of Risk: Copyright 2014. 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 and extent 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 17 through 26 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013 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). As noted above, 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, 2013, 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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