Eog Resources, Inc. · NYSE:EOG
Eog Resources — Investor Presentation (February 2015)
34 slides from Eog Resources's investor presentation, February 2015
Slide 1: EOG Resources Investor Relations Contacts
NYSE Stock Symbol: EOG Investor Relations Contacts Common Dividend: $0.67 Cedric W. Burgher, SVP Investor and Public Relations Basic Shares Outstanding: 548 Million (713) 571-4658, [email protected] David J. Streit, Director IR (713) 571-4902, [email protected] Internet Address: Kimbe
Slide 2: Copyright and Forward-Looking Statements
Copyright; Assumption of Risk: Copyright 2015. 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: Focus on Returns
Focus on Returns Maximize Return on Capital Invested in 2015 - Drill Best Plays: Eagle Ford, Delaware Basin and Bakken - Defer Well Completions Focus on Reducing Costs, Improving Well Productivity Maintain Strong Balance Sheet Take Advantage of Opportunities to Add Drilling Inventory - Leasehold, Fa
Slide 4: 2014 Operational and Financial Highlights
Operations 31% YOY Crude Oil Production Growth and 17% Total Company Production Growth - Three-Year CAGR 37% Crude Oil Growth Increased Total Company Net Proved Reserves 18% Achieved 249% Total Proved Reserve Replacement* at $13.25/Boe Finding Cost* Identified >2x as Many New Well Locations as Drill
Slide 5: Organic Growth Leader
Organic Growth Leader 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
Slide 6: Direct ATROR by Play
Eagle Ford Direct ATROR* at Flat $55 Oil Bakken/Three Forks Direct ATROR* at Flat $65 Oil Delaware Basin Leonard Delaware Basin Wolfcamp Oil and Combo Delaware Basin 2nd Bone Spring Sand 35% 60% Powder River Basin Midland Basin Wolfcamp 15% 25% Wyoming DJ Basin * Direct ATROR Based on cash flow and
Slide 7: Minimum Drilling Locations by Play
Minimum Drilling Play Locations* Years** Eagle Ford 5,500 11 Bakken/Three Forks 580 7 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 ≈ 10,000 >15 Years of Drilling
Slide 8: ROCE and ROE vs Peers
ROCE** ROE** 13.7% 13.7% 16.4% 12.4% 12.4% 15.6% 14.1% 10.5% 13.3% 12.4% 7.9% 9.1% 4.3% 5.5% 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 * EOG actuals. Also see EOG reconciliation schedules. *
Slide 9: 2015 Capex Going to Top Plays
Gathering, Processing and Other $8.3 Bn Exploration and Development Facilities $0.7 Exploration and Development $1.0 $4.9-$5.1 Bn $0.4 $0.6 $6.6 $4.0 2014 2015* ≈80% of 2015* Capex Going to Top Plays: Eagle Ford, Delaware Basin and Bakken * Based on full-year estimates as of February 18, 2015, exclu
Slide 10: Benefit of Delaying Well Completion Six Months
ATROR** +30% Benefit of Delaying Well Completion Six Months at Various Prices +25% +20% +15% +10% +5% +0% -5% $50 $55 $60 $65 $70 $75 Oil Price After Six Months* * $45 oil price first six months. Based on Eagle Ford West Type Well ** See reconciliation schedule. EOG_0215-8
Slide 11: Increase in Rate of Return by Deferring Completion
ATROR** Increase in Rate of Return by Deferring Completion Even if Oil Price Does Not Recover for 24+ Months 15% 10% 5% 0% 6 9 12 15 18 21 24 Months of Deferred Completion* * $45 oil price until completion, then $65 thereafter. Note: Based on Eagle Ford West Type Well. ** See reconciliation schedule
Slide 12: Thousand Club Well Contributors
Peak 30-Day Rate of Top 20 2014 Well Count of Top 20 “Thousand Club*” Contributors “Thousand Club*” Contributors Boed 2,500 250 2,000 200 1,500 150 1,000 100 500 50 0 0 1 5 2 3 4 5 6 7 8 9 1 2 3 4 6 7 8 9 10 11 12 13 14 15 16 17 18 19 10 11 12 13 14 15 16 17 18 19 EOG Peak Oil Peak Gas EOG Total Wel
Slide 13: Higher Rate of Return at $65 Oil Than $95 in 2012
ATROR* 100% Higher Rate of Return at $65 Oil Than at $95 Oil in 2012 75% 2015 50% 2012 25% 0% $45 $55 $65 $75 $85 $95 Oil Price * See reconciliation schedule. EOG_0215-11
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. Employee count YE 2013. Peer Group: APA, APC, CHK, CLR, CXO, DNR, DVN, ECA, MRO, NBL, NFX, PXD, WLL and XEC. EOG_0215-12
Slide 15: EOG Maintains Stable LOE
$14 EOG Maintains Stable LOE Despite Rising Liquids Mix $12 $10 EOG Peers’ 2013 LOE LOE/Boe $8 2011 2014 $6 2010 2012 2013 $4 $2 $0 0% 10% 20% 30% 40% 50% 60% 70% 80% Liquids Production Source: Company filings. Peers: APA, APC, CHK, CLR, CXO, DVN, MRO, NBL, NFX, PXD, RRC and XEC. EOG_0215-13
Slide 16: 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 $0.38 $0.34 $0.31 $0.32 $0.29 $0.30 $0.26 $0.20 $0.18 $0.12 $0.10 $0.08 $0.05 $0.06 $0.03 $0.04 $0.04 $0.04 $0.00 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 20
Slide 17: Net Proved Reserves Increased 18%
Total Company Net Proved Reserves Increased 18% to 2.5 BnBoe Total Company Net Proved Liquids Reserves Increased 26% to 1.6 BnBbls - Liquid Reserves 64% of Total Reserves Reserve Replacement Ratio* Before Revisions Due to Price 249% at Cost of $13.25 per Boe Total Company Liquids Reserve Replacement
Slide 18: Eagle Ford
Largest Oil Producer and Acreage Holder in the Eagle Ford - 15 Rigs Operating for 2015 San Antonio - Completed 534 Net Wells in 2014; Plan ≈345 in 2015 Multi-Well Pad Development - Higher Capital Productivity Crude Oil - Lumpy Production Profile Window Continue to Enhance Completion Techniques in We
Slide 19: Eagle Ford Well Productivity
Eagle Ford West Wells Average Cumulative Crude Oil Production* Improving Well Productivity* (Mbo) (Mbo) 70 70 60 60 Cumulative Oil Production Cumulative Oil Production High-Density Completion 50 2014 50 39% 2013 Increase 40 40 2012 30 2011 30 20 20 Early 2014 Completion 10 10 0 0 0 10 20 30 40 50 60
Slide 20: Completed Well Cost and Drilling Days
Completed Well Cost* Average Drilling Days ($MM) (Spud-to-TD) 7.2 14.2 6.2 6.1** 5.7 10.9 8.9 4.3 2012 2013 2014 2015 Plan 2012 2013 2014 Record * Normalized to 5,300’ lateral. CWC = Drilling, Completion and Well-Site Facilities. ** Initiated High-Density Completions. EOG_0215-18
Slide 21: Delaware Basin
Brushy Canyon Net to EOG* 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-Pressured H
Slide 22: Delaware Basin Wolfcamp Oil and Combo
Confirmed Highly Over-Pressured Oil Window in Northern Delaware Basin NGLs - Oil Mix Rises to 50% 24% - Economics Competitive with Other EOG Oil Plays Oil Gas 50% 26% Focused on Best 140,000 Net Acres with Multiple Pay Zones - 90,000 Net Acres in Oil Play; 50,000 Net Acres in Combo Play Gas - >1,100
Slide 23: Delaware Basin 2nd Bone Spring Sand
90,000 Net Acres Prospective in Northern Delaware Basin - Moving Into Full Development in 2015 - Largest Relative Increase in Capital in 2015 Completed 3 Operated Net Wells in 2014 NGLs - Plan to Complete 37 Net Wells in 2015 14% Gas - Wells Producing from 1,270 - 1,825 Bopd 16% - API ≈ 44° Oil 70%
Slide 24: Delaware Basin Leonard
Advanced Completions Driving Higher Production from Tighter Spaced Wells - 90-Day Cumulative Production Up 17% in 2014 80,000 Net Acres Estimated Reserve Potential* 550 MMBoe, Net to EOG NGLs 26% Oil Typical Well Gas 50% 24% - 500 MBoe EUR/Well, Gross; 400 MBoe, NAR - $5.5 MM CWC** - 4,400’ Lateral
Slide 25: Cumulative Oil Production and Well Spacing
Cumulative Crude Oil Production* Average Well Spacing (Feet) (Mbo) 60 50 1,030 Cumulative Oil Production 2014 910 40 2013 835 2012 30 2011 560 20 10 0 0 10 20 30 40 50 60 70 80 90 2011 2012 2013 2014 Producing Days * Normalized to 4,500-foot lateral. EOG_0215-23
Slide 26: Bakken/Three Forks
Optimizing Completion Formula Across Field and Within Canada Laterals of Single Wells Stanley, ND State Line Bakken Core ≈ 90,000 Net Acres - Antelope Extension ≈ 20,000 Net Acres Bakken Lite Elm Coulee Bakken Core Encouraging Results on 700’ Spacing in the Core - Testing 500’ and 300’ Spacing Bakke
Slide 27: Bakken Well Cost and Drilling Days
Average Completed Well Cost* Average Drilling Days ($MM) (Spud-to-TD*) 22.7 10.5 10.4 9.3 8.2 16.1 12.0 10.4 7.1 2012 2013 2014 2015 Plan 2012 2013 2014 4Q14 Record * Normalized to 10,000’ lateral. CWC = Drilling, Completion and Well-Site Facilities. EOG_0215-25
Slide 28: Natural Gas Acreage Holds Option Value
Play Net Type Acres Marcellus, Bradford County 46,000 Gas Haynesville 143,000 Gas and Combo Eagle Ford 63,000 Gas Barnett 298,000 Gas and Combo Uinta 94,000 Gas and Combo S. Texas Frio/Vicksburg 195,000 Gas and Combo Horn River 127,000 Gas Acreage Holds Option Value for Natural Gas Price Recovery EO
Slide 29: Trinidad and Tobago and United Kingdom
Trinidad and Tobago Trinidad ATLANTIC Expect Stable Production in 2015 OCEAN TRINIDAD 4(a) Drill 2 Net Wells to Maintain Deliverability U(b) U(a) SECC VENEZUELA United Kingdom United Kingdom East Irish Sea (Conwy) East Irish NORTH SEA - First Production 3Q 2015 Sea - Estimated Peak Production – 20 M
Slide 30: 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 $4.1 Billion in Available Liquidity - $2.1 Billion Cash at December 31, 2014 - $2.0 Billion Credit Facility – Undrawn at December 31, 2014 EOG Reserves Within 5% of Independent
Slide 31: Peer Valuation Comparison
4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0 Co. 2 Co. 1 Co. 8 Co. 3 Co. 5 Co. 4 Co. 9 Peer Co. 11 Co. 6 Co. 12 Co. 14 Co. 13 Co. 7 Co. 10 Co. 15 EOG Co. 16 Avg Source: UBS Investment Research. Based on $49/Bbl WTI and $3.25/MMBtu Peer Group: APA, APC, CHK, CLR, COG, COP, CXO, DVN, HES, MRO, NBL, NFX, OX
Slide 32: Crude Oil and Natural Gas Derivative Contracts
Crude Oil* 2015 Bbld $/Bbl February 1 to June 30 47,000 $91.22 July 1 to December 31 10,000 $89.98 Natural Gas* 2015 MMBtud $/MMBtu March 1 to March 31 225,000 $4.48 April 1 to April 30 195,000 $4.49 May 1 to December 31 175,000 $4.51 * As of February 16, 2015. Does not reflect options held by certa
Slide 33: Rate-of-Return Focused Investments Drive Shareholder Value
Rate-of-Return Focused Investments Drive Shareholder Value Creation 2014 ROE/ROCE > Average of Majors, Integrateds and Independent E&Ps Ready to Grow When Prices Improve - Uncompleted Wells - High-Return Drilling – Eagle Ford, Delaware Basin and Bakken - Strong Oil Growth 2016+ If Oil Prices Suffici
Slide 34: Copyright and Forward-Looking Statements
Copyright; Assumption of Risk: Copyright 2015. 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
EOG Resources — Investor Presentation (February 2015) on 6ix