Eog Resources, Inc. · NYSE:EOG
Eog Resources — Investor Presentation (November 2014)
40 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: 547.5 Million (713) 651-6364, Fax (713) 651-6473 [email protected] David J. Streit, Director IR (713) 571-4902, [email protected] Internet Address: K
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: 2Q 2014 and YTD 2014 Highlights
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%, EBITDA
Slide 4: Best Horizontal Crude Oil Assets in North America
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 - Id
Slide 5: Exploration and Technology Focus
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 Maximi
Slide 6: Direct After-Tax Rate of Return
Eagle Ford Bakken/Three Forks Delaware Basin Leonard Direct After-Tax Rate of Return* Powder River Basin Parkman Wyoming DJ Basin Codell Powder River Basin Turner Delaware Basin 2nd Bone Spring Sand 100% Delaware Basin Wolfcamp 60% Wyoming DJ Basin Niobrara Midland Basin Wolfcamp Barnett Combo 30% D
Slide 7: 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 6 Facilities and Other Exploration & Develo
Slide 8: Tactical 2014 and Strategic 2015+ Plans
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 Maint
Slide 9: 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 2010 2011 2012 2013 2014 * Source: IHS data through April 2014. Gross operated oil production. EOG_0914 v3-7
Slide 10: Organic production growth versus peers
70 60 50 40 30 20 10 Co. 12 Co. 13 0 EOG Co. 1 Co. 2 Co. 3 Co. 4 Co. 5 Co. 6 Peer Co. 7 Co. 8 Co. 9 Co. 10 Co. 11 Avg. -10 Apache Corp Anadarko Petroleum EOG Resources Devon Energy Continental Resources Pioneer Resources Average Concho Resources Noble Energy Cimarex Energy Hess Corporation Denbury R
Slide 11: Actual and 2014E production
300 ≈ 285 250 65 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 August 5, 2014. EOG_0914 v3-9
Slide 12: Net Wells and Drilling Years
2014 Drilling Oil Net Wells Years* Eagle Ford 520 12 Bakken/Three Forks 80 8 Delaware Basin Leonard/Bone Spring 40 40+ DJ Basin 39 12 Powder River Basin 34 8 Combo Delaware Basin Wolfcamp 14 75+ Midland Basin Wolfcamp 10 50+ >15 Years of Drilling * Based on current technology and 2014 drilling progr
Slide 13: Production growth by product, 2011-2017E
2011 2012 2013 2014E* 2015E - 2017E Crude Oil and Condensate 52% 39% 40% 29% Continued Best-in-Class NGLs 39% 32% 17% 18% Double-Digit Growth Total Company Liquids 48% 37% 34% 27% North American Gas -7% -9% -13% -3% Flat Other Gas** --% 9% -6% 3% Flat Total Company 9.4% 10.3% 9.4% 14% Highest Annual
Slide 14: Liquids vs Natural Gas production mix
88% ≈ 89% 86% NGLs 79% 76% 71% 72% 59% 53% Oil 47% 41% 29% 28% 24% 21% 14% 12% ≈ 11% 2006 2007 2008 2009 2010 2011 2012 2013 2014E* Liquids (Crude Oil and NGLs) 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
Slide 15: Cash margin per unit, 2010-2Q YTD 2014
$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
Slide 16: ROCE and ROE
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
Slide 17: ROCE and ROE versus Majors, Integrateds and E&Ps
ROCE* ROE* 18.1% 15.6% 14.5% 14.1% 13.7% 13.6% 12.4% 12.7% 11.7% 11.2% 10.0% 9.5% 8.9% 6.6% 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/July 2014 estimates. Majors: BP
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: Crude oil API gravity versus peers
140 API Gravity 120 50 to 100 48° to 50° 100 45° to 48° 80 35° to 45° 0 to 35° 60 40 20 0 EOG Conoco Phillips Devon Anadarko EP Energy BHP EOG 1 2 3 4 5 6 7 8 9 10 * IHS data January 2011 through April 2014. Cumulative gross crude oil and condensate production for producers with ≥20 MMbo. Producers
Slide 20: Largest Oil Producer and Acreage Holder in the Eagle Ford
Largest Oil Producer and Acreage Holder in the San Antonio Eagle Ford - 2Q 2014 Oil Production Up 46% YOY Continued Outstanding Well Results Across Acreage Crude Oil Window IP Rate County Well Bopd Wet Gas Window Gonzales Boothe Unit 11H 4,570 Dry Gas Window Corpus Christi DeWitt Justiss Unit 13H 4,
Slide 21: Big Fields Get Bigger
Big Fields Get Bigger Increased Estimated Potential Reserves* by 45% Reserve Potential* Since Discovery Increased Total Well Count to 7,200, Net Locations (BnBoe) - ≈ 12-Year Inventory of >60% ATROR** Drilling Locations 3.2 - Average 40-Acre Spacing Across Acreage Increased EUR to 450 MBoe/Well, NAR
Slide 22: Eagle Ford well spacing, reserves and returns over time
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 23: Average Cumulative Crude Oil Production for Eagle Ford West Wells
(Mbo) Average Cumulative Crude Oil Production* 45 for Eagle Ford West Wells 40 2014 YTD 2013 35 30 2012 25 2011 20 15 10 5 0 0 10 20 30 40 50 60 Producing Days * Normalized to 5,300’-foot lateral. EOG_0914 v3-21
Slide 24: Eagle Ford well results map
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 San Antonio 4,570 and 3,245 Bopd 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
Slide 25: Bakken: Transformed into High ROR Crude Oil Growth Play
Transformed into High ROR Crude Oil Growth Play Canada New Frac Technology Improves Recovery and Returns State Line Stanley, ND Delivering 100% Direct ATROR* from Core and Antelope Bakken Lite - Bakken Core ≈ 90,000 Net Acres Elm Coulee - Antelope Extension ≈ 20,000 Net Acres Bakken Core 86 MBoed Gr
Slide 26: Delaware Basin Leonard/Bone Spring
Brushy Canyon Net to EOG* MMboe Leonard A New Mexico High ROR Oil Play 550 MMboe Texas - Spacing Tests Underway Leonard B 4,800’ 1st Bone Spring Leonard/ Bone Spring 2nd Bone Spring Over Pressured Oil Play Evaluating - Strong Initial Tests 3rd Bone Spring Wolfcamp Upper Wolfcamp High ROR Combo Play
Slide 27: Second Bone Spring Sand wells
Drilled and Participated in 16 Wells Since 2013 - Wells Producing from 500 - 1,400 Bopd NGLs - API = 45° 14% Gas Target Well Economics for 4,500’ Lateral 16% - EUR ≈ 500 MBoe/Well, Gross Oil - $6 MM CWC and 100% Direct ATROR* 70% - Plan to Drill 9 Wells in 2014 Beneath 73,000 Net-Acre Leonard Positi
Slide 28: Delaware Basin Leonard play
73,000 Net Acres EOG’s 3rd Best ROR Play NGLs 26% Both a Development and Exploration Area Oil 50% 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 Typical Leonard - $5.0 MM CWC and ≈ 100% Direct ATROR** Well
Slide 29: Completed Well Costs and Average Oil IP Rates
Completed Well Costs* Average Oil IP Rates* ($MM) (Bopd) $6.9 $6.4 1,263 $5.3 $5.0 783 737 691 2011 2012 2013 2014 2011 2012 2013 2014 YTD YTD * Normalized to ≈ 4,400-foot lateral. EOG_0914 v3-27
Slide 30: Better Wells on Tighter Spacing
(Mbo) Better Wells on Tighter Spacing (Feet) 45 1,200 1,032’ 15% 40 911’ 1,000 35 17% 30 14% 800 836’ 25 600 20 554’ 15 400 10 200 5 0 0 2011 2012 2013 2014 YTD Average 80-Day Cumulative Oil* Well-Spacing * Normalized to 4,400-foot lateral. EOG_0914 v3-28
Slide 31: Delaware Basin Wolfcamp
134,000 Net Acres Multiple Pay Targets Estimated Reserve Potential* 800 MMBoe, Net to EOG NGLs Oil 33% 31% Target Well Economics for 4,500’ Lateral, Reeves County - 900 Mboe EUR/Well, Gross; 700 MBoe, NAR Gas 36% - $6.5 MM CWC and 70% Direct ATROR** 1,100+ Net Drilling Locations Typical Delaware - P
Slide 32: 10 Years of High-Return Drilling Inventory in the Rockies
10 Years of High-Return Drilling Inventory in the Rockies Net Net Net to EOG* % Direct Basin Play Acres Locations MMboe Crude Oil API ATROR** DJ Codell 85,000 225 125 78% 36 >100% Niobrara 50,000 235 85 71% 35 ≈45% Powder River Parkman 30,000 115 75 69% 41 >100% Turner 63,000 160 115 34% 44- 56
Slide 33: DJ Basin: Targeting Codell and Niobrara
Targeting Codell and Niobrara, 39 Net Wells Target Economics for 9,000 Foot Laterals Codell Niobrara Jubilee Pole Creek 513-0820H 525-2413H EUR/Well (Mboe) Gross 695 430 Jubilee Jubilee 69-04H NAR 560 355 30-07H CWC ($MM) $7.3 $8.0 Jubilee 103-0433H Direct ATROR* >100% ≈45% Jubilee 584-1705H Spacing
Slide 34: Powder River Basin: Targeting Parkman and Turner
Wyoming Targeting Parkman and Turner, 34 Net Wells Parkman Turner Bolt Bolt Lateral Length 7,300’ 8,200’ 429-05H 404-05H EUR/Well (Mboe) Bolt Gross 850 860 22-05H NAR 680 705 CWC ($MM) $5.0 $7.5 Mary’s Draw Direct ATROR* >100% ≈100% 419-16H Spacing (Feet) Mary’s Draw Blade Current 1,300’ 1,655’ 404-
Slide 35: Natural gas acreage by play
Play Net Type Acres Haynesville 143,000 Gas and Combo Marcellus, Bradford County 46,000 Gas S. Texas Frio/Vicksburg 195,000 Gas and Combo Eagle Ford 68,000 Gas Barnett 298,000 Gas and Combo Uinta 94,000 Gas and Combo Horn River 127,000 Gas Acreage Holds Option Value for Natural Gas Price Recovery EO
Slide 36: Trinidad and United Kingdom operations
Trinidad and Tobago Trinidad ATLANTIC Expect Full Contract Deliverability in 2014 OCEAN TRINIDAD 2H 2014 Drilling Program to Maintain Future 4(a) U(a) Deliverability U(b) SECC - Plan to Drill 3 Net Wells VENEZUELA United Kingdom United Kingdom Central Graben East Irish Sea (Conwy) East Irish NORTH -
Slide 37: Maintain Low Net Debt-to-Total Cap Ratio
Maintain Low Net Debt-to-Total Cap Ratio - Credit Ratings – Moody’s A3 / S&P A- Successful 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 -
Slide 38: Crude oil and natural gas derivative contracts
Crude Oil* 2014 Bbld $/Bbl August 1 to December 31 194,000 $96.19 Natural Gas* 2014 MMBtud $/MMBtu September 1 to December 31 330,000 $4.55 2015 January 1 to December 31 175,000 $4.51 * As of August 5, 2014. Does not reflect options held by certain counterparties to extend current crude oil derivati
Slide 39: 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 40: 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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