Houston CFA Society March 2016
100% 90% Forecast 6% 7% 7% 7% 8% 9% 10% 12% 13% 14% 6% 6% 6% 6% 5% 5% 5% 5% 5% 5% 80% 70% 27% 26% 25% 27% 29% 29% 29% 28% 27% 26% 60% 50% 40% 22% 22% 23% 23% 24% 24% 25% 25% 26% 26% 30% 20% 39% 38% 38% 37% 34% 32% 31% 30% 30% 29% 10% 0% 1990 1995 2000 2005 2010 2015 2020 2025 2030 2035 Oil Natural Gas Coal Nuclear Renewables Source: BP Energy Outlook 2035 Dated Feb 2015. EOG _0216-1
Forecast 63.8 66.0 72.7 79.3 79.9 85.2 89.2 93.4 96.4 98.1 1990 1995 2000 2005 2010 2015 2020 2025 2030 2035 Source: BP Energy Outlook 2035 Dated Feb 2015. EOG _0216-2
Five-Year Average Annual Growth (MMBOD) 2010 2011 2012 2013 2014 2015 OPEC NGL / Condensate / Other Supply Non-OPEC Non-Shale Liquids Supply OPEC Crude Supply Shale Liquids Supply Source: PIRA Energy Group. EOG _0216-3
History Bakken Play Williston Basin North Dakota - First Major Horizontal Oil Play - Started 2005-2006 Eagle Ford Play South Texas - Most Prolific Horizontal Oil Play - First Horizontal Shale Oil Play - Discovered 2009 Permian Basin West Texas & S.E. New Mexico - Largest Horizontal Oil Play - Activity Ramped Up 2010-2011 Mid Continent Scoop Stack Play - New Emerging Large Play - Activity Ramped Up 2014-2015 EOG _0216-4
Bakken/ Three Forks 1,120 (28%) Powder River Basin 87 (2%) DJ Basin 275 (7%) 6 Plays Produce 87% of All Horizontal Tight Oil Production 4 MMBOD Mid Continent 225 (6%) Permian 980 (24%) Eagle Ford 1,380 (34%) Source: IHS Gross Crude and Condensate Production as of Sept. 2015. EOG _0216-5
12,000 10,000 8,000 6,000 4,000 2,000 U.S. Crude Oil Data (MMBOD) 2011 2012 2013 2014 2015 Production 5.6 (39%) 6.5 (44%) 7.5 (50%) 8.7 (55%) 9.4 (58%) Net Imports 8.9 (61%) 8.5 (56%) 7.6 (50%) 7.0 (45%) 6.9 (42%) 0 1970 1972 1974 1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 Source: EIA Data through December 2015. EOG _0216-6
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 _0216-7
Well Count 300 Percent Oil 100% 250 Well Count Percent Oil 80% 200 60% 150 100 40% 50 20% 0 EOG DVN CHK PXD MRO COG HES COP BHP CXO TOU EPE XEC EQT NBL SWN CLR RRC RICE SM 0% * Source: Sanford C. Bernstein & Co. Thousand Club includes wells with 30-day rate over 1,000 Boed in 2015. Represents 3,600 wells out of 40,000 drilled. EOG _0216-8
EOG Employees Are Incentivized to Deliver Returns Returns Production and Reserve Growth EOG 8% 30% Co. 1 15% 30% Co. 2 50% Co. 3 40% Co. 4 15% Co. 5 10% 36% Co. 6 33% Co. 7 15% Co. 8 25% Source: Company Reports. Percentages represent weightings applied in determining executive officer short-term incentive compensation. Peer Group: APA, APC, CHK, DVN, HES, MRO, NBL and PXD. EOG _0216-9
1,800 1,600 1,609 1,400 1,200 1,000 800 600 400 372 200 0 2011 2012 2013 2014 2015 2016 Source: Baker Hughes. EOG _0216-10
(MBod) 2014 +1,252 8,959 9,201 9,428 9,129 9,648 9,451 9,341 9,694 2015 +725 2016-764 9,479 9,433 9,452 9,377 9,407 9,305 9,315 9,262 9,196 9,112 9,057 8,990 2017-479 8,754 8,835 8,577 8,678 8,568 8,244 7,998 8,087 8,860 8,698 8,587 8,338 8,337 8,335 8,273 8,275 8,208 8,280 8,302 8,213 8,275 8,146 8,152 8,288 8,247 8,011 7,951 8,112 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 3/8/2016 EOG _0216-11
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 _0216-12
359 EOG is Industry Leader 250 214 213 212 188 158 155 153 137 EOG DVN APC COP CHK MRO WLL CLR PXD CXO Source: IHS Performance Evaluator, supplied by IHS Global Inc.; Copyright (2016). Data as of Sept. 2015. EOG _0216-13
9.0% 8.1% 7.3% 6.5% 5.2% 5.1% 4.9% 4.4% 2.9% 2.6% EOG DVN NBL PXD Peer Avg MRO APC APA HES CHK Source: FactSet, adjusted earnings. EOG _0216-14
9 8 7 6 5 4 3 2 1 0 SWN RRC DVN CLR MRO COG APC Peer Avg APA COP NBL NFX HES CXO EOG OXY PXD 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. EOG _0216-15
Five Sustainable Advantages 1. High-Quality Assets With Scale 2. Innovation and Technology Focus 3. Low-Cost Operator 4. Organic Exploration Growth 5. Organization and Culture Uniquely Positioned to Improve Returns Year After Year EOG _0216-16
San Antonio Eagle Ford Reserve Potential* Since Discovery (BnBoe) 3.2 Crude Oil Window 2.2 Wet Gas Window 1.6 Laredo Dry Gas Window Corpus Christi 0.9 0 25 Miles EOG 624,000 Net Acres 561,000 Net Acres in Oil Window Apr 2010 Feb 2012 Feb 2013 Feb 2014 * Estimated Potential Reserves, Not Proved Reserves. Includes 1,008 MMBOE Proved Reserves Booked at December 31, 2014. EOG _0216-17
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 $2.0 0 2014 2015 2016* 0.00 * Based on full-year estimates as of February 25, 2016, excluding acquisitions. EOG _0216-18
Completed Well Cost* ($MM) Average Drilling Days* (Spud-to-TD) 8.8 20.8 7.8 7.0 6.5 14.7 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 _0216-19
$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 _0216-20
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 _0216-21
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 _0216-22
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 _0216-23
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) 80 70 60 50 40 30 20 10 2015 2014 2013 2012 Cumulative Crude Oil Production (Mbo) 140 120 100 80 60 40 20 High-Density Wells Shallower Decline +30% Low-Density Wells +33% 0 0 20 40 60 80 100 120 140 160 180 0 0 30 60 90 120 150 180 210 240 270 Producing Days Producing Days * Normalized to 5,300-foot lateral. * Normalized to 5,300-foot lateral. EOG _0216-24
1. Measure Rock Characteristics and Grade High to Low Quality 2. Overall Grade 3. Drill Lower Eagle Ford EOG _0216-25
$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 _0216-26
Economics Today vs. $95 Oil Three Years Ago 100% 80% 75% ATROR* 60% 40% 60% 60% 35% 35% 45% 20% 0% Western Eagle Ford Delaware Basin Leonard 2012 @ $95 Oil Today @ $60 Oil Today @ $50 Oil EOG _0216-27
>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 _0216-28
Global Liquids Supply (MMBOD) Forecast 24.7 2.6 28.3 3.1 30.1 3.9 39.1 38.6 37.4 34.6 31.5 30.3 9.79 9.1 8.2 6.6 7.4 6.9 10.2 14.2 17.4 20.2 5.4 5.8 7.2 8.1 9.4 10.1 10.66 OPEC U.S. Shale 40.0 43.0 46.7 46.2 44.1 41.9 39.7 38.9 38.8 1995 2000 2005 2010 2015 2020 2025 2030 2035 Non-OPEC Conventional Non-OPEC Unconventional Shale Liquids OPEC Other OPEC Crude Source: PIRA Energy Group. EOG _0216-29
Conclusions Global Conventional Discoveries of New Oil Are Declining U.S. Horizontal Oil Has Become a Major Source of New Oil Supply - Lowered Marginal Cost of Oil to $70 - $80 / BBL U.S. Horizontal Oil Growth is Critical to Satisfy Global Demand Growth Strong Growth in U.S. Horizontal Oil Requires $60+ / BBL Prices - 12+ Month Response Time to Achieve 500 MMBOD Growth U.S. Industry Leaders Will Continue to Improve Economics and Be Competitive in World Market U.S. and Arab Gulf States Will Supply Future Oil Demand Growth There is No Longer an Effective Swing Producer - OPEC Refuses to Act - U.S. Cannot Respond Quickly EOG _0216-30
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. EOG _0216-31