Eog Resources, Inc. · NYSE:EOG
Eog Resources — Investor Presentation (November 2014)
39 slides from Eog Resources's investor presentation, November 2014
Slide 1: Investor Relations Contacts
NYSE Stock Symbol: EOG Investor Relations Contacts Common Dividend: $0.67 Maire A. Baldwin, Vice President IR Basic Shares Outstanding: 548 Million (713) 651-6364, Fax (713) 651-6473 mbaldwin@eogresources.com David J. Streit, Director IR (713) 571-4902, dstreit@eogresources.com Internet Address: Kim
Slide 2: Copyright; Assumption of Risk; Forward-Looking Statements
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 provi
Slide 3: Increased FY 2014E Production Growth Targets Again
Increased FY 2014E* Production Growth Targets Again - Crude Oil 27% 29% 31% - Total Company 12% 14% 16.5% Confirmed Crude Oil Window of Delaware Basin Wolfcamp – 90,000 Net Acres Eagle Ford Completion Enhancements and Drilling Efficiencies Increase ATROR Successful Antelope Extension Three Forks Wel
Slide 4: Maximize Rate of Return on Investment of Capital
Maximize the Rate of Return on Investment of Capital by Controlling Operating and Capital Costs and Maximizing Reserve Recoveries* Best Horizontal Crude Oil Assets in North America Peer-Leading Organic Crude Oil Production Growth - 2014E** +31% - 2014E 3-Year CAGR** +36% 2014E ROE/ROCE > Average of
Slide 5: Exploration and Technology Focus
Exploration and Technology Focus Core Competency and Sustainable Competitive Advantage Exploration - Generate New Plays Internally • Capture Premier Acreage • Early-Mover Strategy Drives Low Leasing Costs - Identify Additional Targets in Existing Plays Technology Application - “EOG Completions” In-H
Slide 6: Oil Price Required for 10% Direct ATROR
Eagle Ford Bakken/Three Forks Delaware Basin Leonard Oil Price Required for 10% Direct ATROR* Delaware Basin Wolfcamp Oil Direct ATROR* at Flat $80 Oil Price Delaware Basin 2nd Bone Spring Sand 100% $40 Powder River Basin Parkman Wyoming DJ Basin Codell Delaware Basin Wolfcamp Combo Powder River Bas
Slide 7: Play Minimum Locations
Minimum Drilling Play Locations* Years** Eagle Ford 6,000 12 Bakken/Three Forks 640 8 Delaware Basin Leonard 1,600 40 Delaware Basin 2nd Bone Spring Sand Evaluating Delaware Basin Wolfcamp 1,100 75 DJ Basin 460 12 Powder River Basin 275 8 Midland Basin Wolfcamp 500 50 ≈ 10,600 >15 Years of Drilling
Slide 8: 2014E Capex ≈ $8.1 to $8.3 Bn Including Facilities and Midstream
Majority of Capex Increase Going to Top Plays: 2014* Eagle Ford, Bakken, Permian and Rockies 10 Gathering, Exploration and 9 $8.1 to $8.3 Bn Processing Development 8 and Other Facilities $7.1 Bn Gathering, 7 Exploration & 10% 11% Development Processing E&P Facilities and Other 6 Exploration & Develo
Slide 9: Tactical 2014 and Strategic 2015+ Priorities
Tactical - 2014 High-Return Oil Growth Increased Dividend Twice - February +33% - August +34% Strategic - 2015+ Consider Further Dividend Increases High Rate-of-Return Capital Investment - Prioritize E&P Activity to Highest ATROR Plays - Increase High-Return Drilling Inventory through Exploration Ma
Slide 10: Extending Our Lead
400 Extending Our Lead 350 EOG 300 OXY 250 CVX 200 150 100 50 0 Jan May Sep Jan May Sep Jan May Sep Jan May Sep Jan May 2010 2011 2012 2013 2014 * Source: IHS data through June 2014. Gross operated oil production. EOG_1114 v2-8
Slide 11: Crude Oil and Condensate Production Growth
2011 2012 2013 2014E* 2015E - 2017E Crude Oil and Condensate 52% 39% 40% 31% Continued Best-in-Class NGLs 39% 32% 17% 23% Double-Digit Growth Total Company Liquids 48% 37% 34% 29% North American Gas -7% -9% -13% ≈0% Flat Other Gas** --% 9% -6% 4% Flat Total Company 9.4% 10.3% 9.4% 16.5% Highest Annu
Slide 12: Organic Crude Oil Growth vs. Peers
70 60 50 40 30 20 10 Co. 13 0 EOG Co. 1 Co. 2 Co. 3 Co. 4 Peer Co. 5 Co. 6 Co. 7 Co. 8 Co. 9 Co. 10 Co. 11 Co. 12 Avg -10 Sources: Company filings, First Call. Production adjusted for Acquisitions/Dispositions to reflect ‘Organic’ production only. Peers: APA, APC, CHK, CLR, CXO, DNR, DVN, HES, MRO,
Slide 13: Crude Oil Production History and 2014E
300 ≈ 288 250 68 Actual 220 200 62 158 150 45 113 100 38 75 55 20 50 0 2009 2010 2011 2012 2013 2014E* * Based on mid-point of full-year 2014 production estimates as of November 4, 2014. EOG_1114 v2-11
Slide 14: Peer Comparison
80 70 60 50 40 30 20 10 0 EOG Co. 1 Co. 2 Co. 3 Co. 4 Co. 5 Co. 6 Co. 7 Co. 8 Co. 9 Peer Co. 10 Co. 11 Co. 12 Co. 13 Co. 14 Avg Source: First Call, Company Reports. Peer Group: APA, APC, CHK, CLR, CXO, DNR, DVN, ECA, MRO, NBL, NFX, PXD, WLL, XEC EOG_1114 v2-12
Slide 15: 2013 Lease Operating Expense vs. Liquids Production Mix
2013 Lease Operating Expense (LOE) vs. Liquids Production Mix $14.00 $12.00 $10.00 $8.00 LOE/Boe 2011 EOG LOE Below YTD Peer Average and $6.00 2014 2010 Stable Despite Rising 2012 2013 Liquids Production Mix $4.00 $2.00 EOG Peers $0.00 0% 10% 20% 30% 40% 50% 60% 70% 80% % Liquids Production Source:
Slide 16: ROCE and ROE
ROCE ROE 17.0% 15.6% 13.4% 12.4% 11.8% 9.4% 2012* 2013* 2014E** 2012* 2013* 2014E** * See reconciliation schedule. ** Goldman Sachs estimates October 29, 2014, $94.83 WTI and $4.38 Henry Hub in 2014. EOG_1114 v2-14
Slide 17: ROCE and ROE vs. Majors and Integrateds
ROCE* ROE* 13.7% 13.4% 17.0% 12.4% 12.7% 15.6% 14.1% 13.6% 10.0% 9.5% 11.7% 11.2% 6.2% 8.0% Integrateds Integrateds Integrateds Integrateds 3.4% 3.7% Majors Majors Majors Majors EOG EOG EOG EOG E&P E&P E&P E&P 1 2 1 2 2013 2014E 2013 2014E * Source: Goldman Sachs, May/October 2014 estimates. Majors:
Slide 18: Committed to the Dividend
$0.70 Committed to the Dividend $0.67 Increased Dividend Twice in 2014 $0.60 16 Dividend Increases in 15 Years $0.50 $0.50 $0.40 $0.375 $0.34 $0.31 $0.32 $0.29 $0.30 $0.255 $0.20 $0.18 $0.12 $0.10 $0.08 $0.05 $0.06 $0.03 $0.035 $0.04 $0.04 $0.00 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
Slide 19: New Mexico Delaware Basin
Brushy Canyon Net to EOG* MMboe Leonard A New Mexico High ROR Oil Play 550 MMboe Texas - Spacing Tests Underway Leonard B Red Hills Leonard/ Bone Spring 4,800’ 1st Bone Spring 2nd Bone Spring Over Pressured Oil Play Evaluating - Strong Initial Tests 3rd Bone Spring Wolfcamp Upper Wolfcamp Over Press
Slide 20: Decades of High-Return Drilling Inventory
Decades of High-Return Drilling Inventory Net Net Net to EOG % Direct ATROR** Play Acres Locations MMboe* Crude Oil 2013 2014 Delaware Basin Leonard 80,000 >1,600 550 50% 100% ≈100% 2nd Bone Spring Sand 90,000 70% n/a 100% Wolfcamp Oil Window 90,000 50% n/a 100% Combo Window 50,000 31% 60% 70% Total
Slide 21: Confirmed Highly Over-Pressured Oil Window in Northern Delaware Basin
Confirmed Highly Over-Pressured Oil Window in Northern Delaware Basin NGLs - Oil Mix Rises to 50% 24% Oil - Economics Competitive with Other EOG Oil Plays Gas 50% 26% Focused on Best 140,000 Net Acres with Multiple Pay Zones Gas - 90,000 Net Acres in Oil Play 36% Typical Northern - 50,000 Net Acres
Slide 22: 90,000 Net Acres Prospective in Northern Delaware Basin
90,000 Net Acres Prospective in Northern Delaware Basin - Further Evaluating and Delineating Acreage - 20-Mile Step Out Well in 3Q 2014 Confirms Prospectivity NGLs Drilled and Participated in 21 Gross Wells Since 2013 14% - Plan to Drill 13 Gross Wells in 2014 Gas 16% - Wells Producing from 500 - 1,
Slide 23: Completion Technology Driving Higher Production from Tighter Spaced Wells
Completion Technology Driving Higher Production from Tighter Spaced Wells 80,000 Net Acres Estimated Reserve Potential* 550 MMBoe, Net to EOG NGLs Target Well Economics for 4,400-Foot Lateral 26% Oil - 500 MBoe EUR/Well, Gross; 400 MBoe, NAR Gas 50% 24% - $5.0 MM CWC and ≈ 100% Direct ATROR** >1,600
Slide 24: Tighter Spacing and Enhanced Completions Improve Well Productivity
Tighter Spacing and Enhanced Completions (Bbl) Improve Well Productivity 60,000 50,000 26% Increase Cumulative Oil Production 40,000 Average of 2014 300’ Spaced Pattern Wells 30,000 Average of 2013 20,000 Single Wells 10,000 0 0 30 60 90 120 150 Producing Days * Normalized to 4,500-foot lateral. EOG
Slide 25: Largest Oil Producer and Acreage Holder in the Eagle Ford
Largest Oil Producer and Acreage Holder in the Eagle Ford - 23 Rigs Operating San Antonio - Drilled 392 Net Wells YTD, Plan ≈540 Net Wells in 2014 Multi-Well Pad Development - Higher Capital Productivity Crude Oil Window - Non-Linear Production Profile Wet Gas Continued Outstanding Well Results Acro
Slide 26: Big Fields Get Bigger
Big Fields Get Bigger Third Reserve Increase in Four Years Increased Estimated Potential Reserves* by 45% in 2014 Reserve Potential* Since Discovery At Least Ten Years of Future Production Growth (BnBoe) Increased Total Well Count to 7,200, Net Locations 3.2 - ≈ 12-Year Inventory of >60% ATROR** Dri
Slide 27: Footage Per Day and Spud to TD
Footage Per Day Spud to TD (Average Days) 1,756' 22.3 1,561' 1,205' 16.1 14.2 935' 884' 10.9 8.9 4.3 2010 2011 2012 2013 2014 2010 2011 2012 2013 2014 Record YTD YTD EOG_1114 v2-25
Slide 28: Eagle Ford West Wells Improving Well Productivity
Eagle Ford West Wells Improving Well Productivity* Average Cumulative Crude Oil Production* (Mbo) (Mbo) 70 70 60 60 Cumulative Oil Production Cumulative Oil Production High Density Frac 2014 YTD 39% 50 50 Increase 2013 40 40 2012 30 2011 30 20 20 Early 2014 Frac 10 10 0 0 0 10 20 30 40 50 60 70 80 9
Slide 29: Wells per Section and Spacing Economics
April 2010 Feb 2012 Feb 2013 Feb 2014 Wells/Section (Unit) 5 10 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 CWC $5.25 MM $6 MM $6 MM $5.7 MM Direct ATROR* 80% 130% 100% 100%+ Per Section (640 Acres) Est. Reserves
Slide 30: Eagle Ford 564,000 Net Acres in Crude Oil Window
Gonzales County Neuse Unit 1H 4,170 Bopd Boothe Unit 12H, 13H Atascosa County 2,945 and 2,640 Bopd Stockhorst Unit 1H 2,105 Bopd DeWitt County San Antonio Boothe Unit 14H, 15H 3,310 and 3,445 Bopd Karnes County Lake Unit 4H, 6H, 8H 2,070, 1,990, 2,400 Bopd Colleen Unit 1H 3,660 Bopd Hickok Unit 1H 3
Slide 31: Bakken Transformed into High ROR Crude Oil Growth Play
Transformed into High ROR Crude Oil Growth Play Through Improved Completions Canada Delivering 100% Direct ATROR* from Core and Antelope State Line Stanley, ND - Bakken Core ≈ 90,000 Net Acres Bakken - Antelope Extension ≈ 20,000 Net Acres Lite Elm Encouraging Results on 700’ Spacing in the Core Cou
Slide 32: Spud-to-TD and Average Completed Well Cost
Spud-to-TD* Average Completed Well Cost* (Days) ($MM) 22.7 10.5 10.4 9.3 8.7 16.1 13.5 12.5 2012 2013 2014 Current 2012 2013 2014 Current YTD YTD * Normalized to 10,000’ lateral. EOG_1114 v2-30
Slide 33: 10 Years of High-Return Drilling Inventory
10 Years of High-Return Drilling Inventory Net Net Net to EOG % Direct Basin Play Acres Locations MMboe* Crude Oil API ATROR** DJ Codell 85,000 225 125 78% 36 >100% Niobrara 50,000 235 85 71% 35 >45% Powder River Parkman 30,000 115 75 69% 41 >100% Turner 63,000 160 115 34% 44- 56 ≈100% Total 73
Slide 34: DJ Basin: Targeting Codell and Niobrara
Targeting Codell and Niobrara, 39 Net Wells in 2014 Experimenting with Larger Frac Design Niobrara Target Economics for 9,400-Foot Laterals Codell Jubilee Jubilee 151-1034H Codell Niobrara 555-1034H 152-1034H 553-1034H 153-1034H EUR/Well (Mboe) 554-1034H 154-1034H Gross 695 430 NAR 560 355 CWC ($MM)
Slide 35: Powder River Basin: Targeting Parkman and Turner
Targeting Parkman and Turner, 34 Net Wells in 2014 Wyoming Experimenting with Larger Frac Design Parkman Turner Lateral Length 7,300’ 8,200’ EUR/Well (Mboe) Gross 850 860 NAR 680 705 CWC ($MM) $7.0 $7.5 Direct ATROR* >100% ≈100% Parkman Turner Spacing (Feet) Mary’s Draw Mary’s Draw 412-1527H Current
Slide 36: Trinidad and United Kingdom
Trinidad and Tobago Trinidad ATLANTIC Expect Full Contract Deliverability in 2014 OCEAN TRINIDAD 4(a) 2H 2014 Drilling Program to Maintain Future U(b) U(a) Deliverability SECC - Plan to Drill 3 Net Wells VENEZUELA United Kingdom United Kingdom Central Graben East Irish Sea (Conwy) East Irish NORTH -
Slide 37: Crude Oil and Natural Gas Derivative Contracts
Crude Oil* 2014 Bbld $/Bbl November 1 to December 31 192,000 $96.15 2015 January 1 to June 30 47,000 $91.22 July 1 to December 31 10,000 $89.98 Natural Gas* 2014 MMBtud $/MMBtu December 1 to December 31 330,000 $4.55 2015 January 1 to December 31 175,000 $4.51 * As of November 4, 2014. Does not refl
Slide 38: Rate-of-Return Focused Investments Drive Shareholder Value and Growth
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 Design
Slide 39: Copyright; Assumption of Risk; Forward-Looking Statements
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 provi
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