Credit Suisse Energy Summit. David Stover, President and COO February 2014

Transcription

1 Credit Suisse Energy Summit David Stover, President and COO February 2014

2 Noble Energy Execution delivering a unique future Outstanding Growth Agenda Production expected to more than double by 2018 Cash flow to increase $1 B per year Returns to reach record levels Diversified Portfolio Provides Exceptional Optionality Inventory of ultra-high return opportunities U.S. unconventional, global deepwater and exploration all play material roles 7.5 BBoe Proved Reserves and Discovered Unbooked Resources Fueling Growth Industry-leading Exploration Capability Potential to add materially to discovered resources Financial and Organizational Capacity in Place to Deliver 2

3 Five-Year Growth Outlook 2013 to 2018 Superior long-term performance Debt-Adjusted Growth per Share* (CAGR) 19% 22% Visible Growth Profile from Discovered Resources Contributions from All Operating Areas Superior Operational and Financial Outcomes by 2018 Production 629 MBoe/d Reserves 2.9 BBoe ROACE* 17% Production Cash Flow $8.3 B discretionary cash flow** 18% net debt-to-cap ratio * Term defined in appendix ** See appendix for referenced price case 3

4 Cash Flow Outlook Growing cash flows support investment program Grows $1 B per Year with 5-year CAGR of 19% Exceeds Cash Capital Beginning in 2016 $1 B Cumulative Excess through 2018 $ B 10 Discretionary Cash Flow* 2014 West Africa Eastern Med. Other DJ Basin DW GOM Eastern Med. Marcellus 2018 Other 2 West Africa DW GOM DJ Basin Discretionary Cash Flow* Organic Cash Organic Capital Cash Capital* Marcellus 4 * Term defined in appendix

5 2013 Accomplishments Continuing to build on success Sales Volume Up 20 Percent, Excluding Divestitures Record Reserves of 1.4 BBoe, Up 19 Percent Reserve replacement of 369% with all-in F&D cost of $12/Boe Delivered Three Major Projects Tamar producing 2.5 years from sanction First production from Alen, 6 months ahead of plan First Integrated Development Plan (IDP) at Wells Ranch in DJ Basin Six New Major Projects Sanctioned Exploration Discoveries Continue Building the Future Troubadour, Dantzler, Karish and Tamar SW Discovered Unbooked Resources Up Over 25% Enhanced Portfolio with Acquisitions and Exchanges Industry-leading Safety Performance 5

6 YE 2013 Reserve Roll Forward Nearly 20 percent increase driven by all core areas MMBoe By Core Area 1,600 1, Reserve Replacement of 369% 1,406 Eastern Med. West Africa Other DJ Basin Marcellus 1,200 1,184 DW GOM By Commodity 1,000 U.S. Natural Gas Liquids 800 YE 2012 Production Sales and Purchases Extensions Performance Price YE 2013 Int. Natural Gas 6

7 A Closer Look at 2014 Substantial growth in core areas Production Outlook MBoe/d 18% Year Over Year Increase, Adjusting for Sales and Exchange Led by DJ Basin, Marcellus Shale and Israel Preparing and Investing for Future Growth Accelerating U.S. onshore developments Developing our next phase of major projects Increasing Optionality of Eastern Mediterranean Gas Growing Israel domestic market Executing contracts Scoping LNG floating and onshore Maintaining High-impact, Strategic Exploration Program NE Nevada play, Cameroon and deepwater GOM Maturing other frontier areas for new drilling Eastern Med West Africa DW GOM New Ventures $4.8 B Capital* Other Marcellus DJ Basin *Assume no joint venture carry in the Marcellus Shale program - maximum potential impact $225 MM 7

8 DJ Basin Creating and accelerating value again! Contiguous High-value Acreage Position 609,000 net acres with 87% in oil window Supports acceleration and optimization from IDP s Net Risked Resources of 2.6 BBoe 9,500 normal length equivalent locations Drilling Activity Doubles to Nearly 700 Equivalent Wells per Year by 2018 Five-Year Production CAGR of 23% Technical and Operation Excellence in All Phases ERLs generating 3X the NPV of normal laterals Integrated Development Plans (IDPs) enhancing NPV by 30-50% 8

9 9 DJ Basin 2014 Operations Premier acreage position Accelerating Pace of Development 320 operated horizontal wells, which includes 55 ERLs Production Up 28%, Adjusting for the Asset Exchange Performing Basin Wide Downspacing (24-32 wells per section) 30-40% of 2014 well count Located in 5 IDP areas Strong Well Performance and Lower Well Costs IDPs Maximizing Value While Reducing Impacts Wells Ranch and East Pony in progress Investing $2 B or 40% of Total Capital Program Northern Colorado Wells Ranch East Pony Greater Wattenberg Area (GWA) NBL Acreage Gas Window Oil Window* * Liquids above 50%

10 DJ Basin Downspacing Maximizing value through testing of optimal spacing Confirmed Minimum 16 Wells per Section in Oil Window 30 to 40 Percent of 2014 Wells at Higher Density Spacing Five IDPs represent over 50% of total acreage Determining Optimal Spacing for each IDP considering Reservoir characterization Greeley Crescent IDP 6-12 downspace wells A, B, C, and Codell benches East Pony IDP downspace wells A, B, and C benches Legacy vertical wellbores Surface constraints Wells Ranch IDP downspace wells A and C benches Core IDP 4-8 downspace wells A, C, and Codell benches Mustang IDP 6-12 downspace wells B, C, and Codell benches 24 wells/sec wells/sec

11 Multiple IDP Areas Delivering Superior Results Strong performance of standard length and ERLs East Pony IDP Timbro 1 st East Pony ERL 9,040 lateral Producing 600 Bo/d and 800 Mcf/d after 90 days Wells Ranch IDP Jenkins 1 st Codell ERL 6,985 lateral Producing 300 Bo/d and 1,400 Mcf/d after 60 days East Pony IDP 3 Rohn State ERLs 8,700 lateral average Combined volume of 2,300 Bo/d and 800 Mcf/d after 20 days Core IDP 5 well Loeffler Pad 4,400 lateral average Producing 3,200 Boe/d after 30 days Wells Ranch IDP Recent batch of 10 wells 4,500 lateral average 8 of 10 performing in line with 400 MBoe EUR Remaining 2 performing at 305 MBoe average 11

12 Integrated Development Plan Impact Decreasing footprint and increasing economics in all phases of the asset life-cycle Reduced Development Costs $0.4 to $0.8 MM per well ($ per Boe*) No need for tanks on each well Less water trucking due to distribution lines Pad drilling & ERL efficiencies Reduced Operating Costs $0.1 to $0.3 MM per well ($ per Boe*) Eliminates oil hauling Eliminates water hauling More efficient use of pumpers Reduced emissions Drives $2B in Incremental Value for Two Currently Sanctioned IDPs Accounts for only 18% of acreage $ MM East Pony IDP Incremental Value Uplift per Well $1.2 $1.0 $0.8 $0.6 $0.4 $0.2 $0.0 Operational Efficiencies Infrastructure Longer Laterals Infrastructure Trucking Operational Efficiencies Future Current 12 * Based on 345 MBoe EUR type curve for East Pony

13 Marcellus Shale Maximizing value from a premier resource play Net Risked Resources of 15 Tcfe, Doubled Over Two Years 350,000 net acres in southwest fairway 88% NRI enhances returns Five Year Production CAGR Over 45% Efficiencies and Learnings Driving Well Costs Down On track to deliver 20% reduction over 2 year period ending 2014 Well Performance - EURs and IPs Continue to Improve Multiple Upside Opportunities Downspacing, delineation, completions and new intervals 13

14 Marcellus 2014 Activity Delivering value with upside opportunities Accelerating Development 100 operated wet gas and 70 dry gas wells Lateral lengths on operated wells to average over 7,000 ft. Production up Over 90% Further Improvement in Well Cost and Performance Continue to Implement IDP Concept Conduct 500 Ft. Downspacing Tests in Multiple Areas No interference on 750 ft. spacing Delineate New Areas Oxford / Pennsboro / Shirley Drill several Burkett tests Majorsville Allegheny Airport Oxford / Pennsboro / Shirley SW PA Dry Wet Gas Acreage Dry Gas Acreage Focus Areas 14

15 Marcellus Operational Excellence Tremendous value added in short period of time BT NPV10 $ MM 8 Returns Doubled Through Efficiencies and Performance Improvement Value Impact of Improvements (Wet Gas) Historical* EUR Uplift Cost Reductions EURs up 60% from acquisition Realized 10% cost improvement Focus on long laterals Longer Laterals Today Wet Gas Area Historical* Today Future Laterals 5,000 7,000 7,000-10,000 Well Cost $7.2 MM $8.0 MM $7.1 - $8.3 MM $ M Per Lateral Foot $1.44 $1.14 $ $0.83 Zones Marcellus Marcellus Multiple Targets Spacing 1, Stages EURs 4.3 Bcfe 0.86 Bcfe/1,000 $1.67 F&D 9.6 Bcfe 1.37 Bcfe/1,000 $0.83 F&D BT NPV10 $1.5 MM $7.4 MM 15 *EUR estimates from JV initiation in Cost estimates from 2012 Analyst Conference

16 Marcellus Performance Upside Potential to materially increase resources and type curves Positive Results from Reduced Stage and Cluster Spacing (RSCS) Average initial rate up to 40% higher Mcf/Lateral Ft Cum. Production (Normalized) on RSCS Wells and Offsets Designing more tests across the JV 60 Optimized Flowback and Production Potential EUR uplift of 5-15% Potential to increase condensate production Testing Refrac Potential Days RSCS Wells Offset Wells 16

17 Deepwater Gulf of Mexico Sustained value creation with visibility for significant growth Proven Track Record of Exploration Success Leading-edge technology with disciplined processes Production and Cash Flow to More than Double in Next Five Years Oil-dominated production delivers strong margins Existing Infrastructure Contributing to Significant Value Creation Four Recent Discoveries to Add More than $1.3 B BT NPV10 with Upside Big Bend and Gunflint startups in Dantzler, Troubadour tie-ins to existing infrastructure Existing Portfolio with 3.8 BBoe Gross Unrisked Resources 4-5 prospects planned for drilling in next 2 years 17

18 Big Bend Development Substantial upside to initial base development NBL Operated with 54% WI Gross Resources of MMBoe Single Well Subsea Tie-back Development 18 First oil expected late 2015 Peak rate 22,000 Boe/d gross, 90% oil Additional Potential Resources of MMBoe Gross Additional producer wells Water injection considered for secondary recovery Strong Point Forward Economics (50 MMBoe case) Net capital $385 MM (gross $710 MM) Payout within 2 years of startup BT NPV10 $390 MM BT ROR 42% 18 mile subsea tie-back 6,050-7,200 ft. water depth Accommodate additional developments

19 Dantzler Development Leveraging Big Bend infrastructure for exceptional returns Dantzler Troubadour Big Bend NBL Operated with 45% WI Multi-zone Discover MMBoe gross resources Over 85% oil Planned Tie-in to Big Bend Development Allows acceleration of first production to 1H16 Peak rate 36 MBoe/d gross Strong Point Forward Economics (55 MMBoe) Net capital $245 MM (gross $540 MM) Payout less than 1 year from startup BT NPV10 $695 MM BT ROR 98% 19

20 West Africa Leveraging expertise and experience in Africa Unique Approach to Creating Value Liquids and gas monetization with LPG, LNG and Methanol Two Major Projects Brought Online in Last Two Years Leveraging Infrastructure for Future Developments Diega sanction targeted in 2014 Expanding Regional Position into Highly Prospective Areas Progressing Regional Gas Monetization Plans Exploration Well Planned for Cameroon in

21 Alen, Another Major Project Success Unique design leverages Aseng FPSO Project Sanction to Startup in 30 Months First production in May 2013, 6 months early On budget for $1.3 B gross Designed to Maximize Value Offshore gas plant for condensate separation Gas reinjection for enhanced condensate recovery and future monetization Condensate storage and offloading at Aseng FPSO Field Expected to Reach MBbl/d Gross in 2014 Currently producing 28 MBbl/d Best-in-class Safety Performance Over 11 million man hours worked since sanction with only one lost-time incident 21

22 Greater Diega Area Leveraging existing infrastructure Aseng Alen Diega Diega, Carla and Carmen Operated with 45% WI MMBoe gross resources 75% liquids Diega Oil Development Positive results from 2013 appraisal Successful flow test confirmed reservoir continuity and quality Initial development phase MMBoe gross Moving Forward with Sanction Finalize development plans by mid 2014 Expect first oil late 2016 at 10 MBbl/d per well Evaluate regional development scenarios, including Carmen and Carla discoveries 22

23 Eastern Mediterranean World-class discoveries with world-class opportunities Approximately 40 Tcf Gross Resources Discovered Over 19 Tcf available for export markets Outstanding Operational Performance from Tamar Averaging 750 MMcf/d since startup Growing Domestic and Regional Markets Israel demand growth expectation increased to 17% Multiple regional markets emerging Leviathan Development Options Progressing Continuing Exploration and Appraisal Program 3 BBbl and 4 Tcf of remaining potential Generating Strong Cash Flow to Support Future Projects 23

24 Tamar Field Supplying a growing domestic market Outstanding Operational Performance Near 100% facility uptime Current deliverability capacity of 1 Bcf/d Averaged 750 MMcf/d since startup Quality Investment $0.90/Mcf F&D, $0.40/Mcf LOE Average price realization $5.75/Mcf 200 MMcf/d Onshore Compression Expansion Project Underway $220 MM gross investment with mid 2015 startup Tamar SW provides added flexibilty Underpinned by IEC gas purchase option Additional Expansion to 1.5 Bcf/d Planned for 2016 Supported by identified / executed contracts Bcf/d Capacity and Sale Projection AOT Compression +22% Capacity Planned Further Expansion +25% Expected Annual Avg. Sales 24

25 Leviathan Development Monetizing 19 Tcf of natural gas resources Phased Development Approach Diversifies supply to Israel New regional and LNG markets Focus on Partnering with Government and Customers Leviathan FPSO Leviathan FLNG Fixed Platform Initial Development Targeting Domestic and Regional Markets Sanction driven by market and regulatory maturity Targeting first sales in 2017 LNG, FLNG Options Progressing Finalizing the Sell Down to Woodside 25

26 Leviathan Memorandum of Understanding Bring in a strategic partner with LNG expertise NBL Selling 9.66% Interest to Woodside Continue as upstream operator with 30% working interest Cash Payments Totaling $525 MM $390 MM at closing, which is expected in 2014 $135 MM at FID of LNG project or as regional exports contracts are signed Revenue Sharing Up to $502 MM 2.9% of WPL s export revenues, once gross export volumes exceeds 2 Tcf Other Payments $19 MM should Leviathan resources be determined to exceed 20 Tcf 1.0% royalty on WPL s oil revenues related to deep Mesozoic oil development Woodside to Operate LNG field development Subject to Execution of Definitive Agreements and Customary Regulatory Approvals 26

27 Robust Exploration Prospect Inventory Testing 850 MMBoe net risked resources in the next 24 months NE Nevada Drilling additional wells Conduct production tests Deepwater GOM Test 4 5 Miocene prospects Sierra Leone 3D seismic acquisition Eastern Mediterranean Deep Mesozoic oil test in Israel Drill next Cyprus gas prospect Cameroon Exploration well planned Falkland Islands Complete 3D seismic evaluation Spud first operated well 27

28 Noble Energy Delivering a unique future 28

29 Forward-looking Statements and Other Matters This presentation contains certain forward-looking statements within the meaning of the federal securities law. Words such as anticipates, believes, expects, intends, will, should, may, and similar expressions may be used to identify forward-looking statements. Forward-looking statements are not statements of historical fact and reflect Noble Energy s current views about future events. They include estimates of oil and natural gas reserves and resources, estimates of future production, assumptions regarding future oil and natural gas pricing, planned drilling activity, future results of operations, projected cash flow and liquidity, business strategy and other plans and objectives for future operations. No assurances can be given that the forward-looking statements contained in this presentation will occur as projected, and actual results may differ materially from those projected. Forward-looking statements are based on current expectations, estimates and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those projected. These risks include, without limitation, the volatility in commodity prices for crude oil and natural gas, the presence or recoverability of estimated reserves, the ability to replace reserves, environmental risks, drilling and operating risks, exploration and development risks, competition, government regulation or other actions, the ability of management to execute its plans to meet its goals and other risks inherent in Noble Energy s business that are discussed in its most recent Form 10-K and in other reports on file with the Securities and Exchange Commission. These reports are also available from Noble Energy s offices or website, Forward-looking statements are based on the estimates and opinions of management at the time the statements are made. Noble Energy does not assume any obligation to update forward-looking statements should circumstances or management's estimates or opinions change. This presentation also contains certain historical and forward-looking non-gaap measures of financial performance that management believes are good tools for internal use and the investment community in evaluating Noble Energy s overall financial performance. These non-gaap measures are broadly used to value and compare companies in the crude oil and natural gas industry. Please also see Noble Energy s website at under Investors for reconciliations of the differences between any historical non-gaap measures used in this presentation and the most directly comparable GAAP financial measures. The GAAP measures most comparable to the forward-looking non-gaap financial measures are not accessible on a forward-looking basis and reconciling information is not available without unreasonable effort. The Securities and Exchange Commission requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. The SEC permits the optional disclosure of probable and possible reserves, however, we have not disclosed our probable and possible reserves in our filings with the SEC. We use certain terms in this presentation, such as discovered unbooked resources, resources, risked resources, recoverable resources, unrisked resources, unrisked exploration prospectivity and estimated ultimate recovery (EUR). These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. The SEC guidelines strictly prohibit us from including these estimates in filings with the SEC. Investors are urged to consider closely the disclosures and risk factors in our most recent Form 10-K and in other reports on file with the SEC, available from Noble Energy s offices or website, 29

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