Bank of America Merrill Lynch 2018 Global Energy Conference. November 2018

Transcription

1 Bank of America Merrill Lynch 2018 Global Energy Conference November 2018

2 Strategy to Enhance Value Blueprint to deliver leading total shareholder returns Peer-leading Cash Flow Per Debt-adjusted Share Growth High-margin EMed and U.S. Onshore delivers leading cash flow profile vs. peers and across investment sectors Prioritizing shareholder returns including $750 MM buyback Relentless Focus on Capital Efficiency & Corporate Returns On track to deliver double digit ROACE (1) in 2020E Incentive Plans Aligned with Shareholder Interests Financial Strength Low Leverage and High Flexibility Committed to Stakeholders and the Environment 2018 plans enhanced to incorporate ROACE (1), CROCI (1) and cash flow per debt-adjusted share metrics Achieved $600 MM 3-year debt reduction target Increased dividend 10%; continue to grow with cash flows Decreased direct greenhouse gas emissions in 2017 Increasing use of recycled water in Delaware completions, Achieved ~30% YE18 target in early 4Q18 (1) Term defined in appendix. 2

3 Portfolio Combination Provides Competitive Advantage Advancing developments for sustained value creation U.S. Onshore: Extensive High-margin, High-return Inventory in Liquids-rich, Low-cost Basins Progressing Mustang IDP development in DJ Basin, gas processing diversification supporting volume growth Transitioned to row development in Delaware Basin, driving operating efficiencies Strong cash flow contribution from the Eagle Ford Eastern Mediterranean: World-class Assets in Undersupplied Regional Market ~1 Bcfe/d record sales volumes in 3Q18 from Israel demand Leviathan ~67% complete, on track for first gas sales by YE19 Egypt pipeline agreements solidify robust cash flow outlook West Africa: Cash Flow Generation and New Opportunities Brent-linked oil and strong global methanol pricing driving substantial cash flow Progressing high-return Alen gas monetization towards sanction early 2019, first gas in 2021 DJ Basin Delaware Eagle Ford U.S. Onshore 485,000 net acres; high WI 3Q18 Sales Volumes: 249 MBoe/d 3Q18 Realized Oil Price (1) : $65.54/Bbl Eastern Mediterranean Gross Discovered Reserves: ~40 Tcfe 3Q18 Sales Volumes: 242 MMcfe/d 3Q18 Realized Gas Price (1) : $5.49/Mcf Israel Equatorial Guinea West Africa Gross Undeveloped Resources: 3 Tcf 3Q18 Sales Volumes: 55 MBoe/d 3Q18 Realized Oil Price (1) : $73.70/Bbl (1) Average realized prices do not include impacts of hedges 3

4 DJ Basin Strong performance and future outlook CO Decisive Victory in Defeating Proposition 112 Broad support for oil and gas industry in Colorado Continued Volume Growth, up 7% vs 3Q17 (1) Operated 2 rigs and 3 frac crews in 3Q Substantial volume ramp through 3Q18 from Mustang IDP Anticipate Growth in 4Q18 Despite Non-core Acreage Divestment (4 Mboe/d) Mustang/Wells Ranch to drive 4Q growth Material Gas Processing Expansion Ongoing NBL benefits by gas processing diversification and protected through compression Williams (Discovery) plant expected online in 4Q18 DJ Basin Activity 3Q18 Oil (MBbl/d) 61 NGL (MBbl/d) 26 Gas (MMcf/d) 235 Total Sales (MBoe/d) 126 Operated Rigs 2 Wells Drilled (2) 28 Wells Completed (2) 24 Wells Brought Online (2) Avg. Lateral Length (ft) 10, Weld Mustang Wells Ranch MBoe/d DJ Basin Net Production (1) Volumes up 7% 3Q18 vs. 3Q17 3Q16 3Q17 3Q18 Total Oil East Pony NBL Acreage Municipalities GOR: Low Mid High MBbl/d (1) Pro-forma for divestitures and reflects the current presentation of sales volumes, post-implementation of ASC 606 accounting standard. (2) Represents NBL operated activity. 4

5 DJ Basin Mustang IDP Robust new well performance Strong Results from Mustang Row Development Producing 27 MBoe/d (+60% oil) from initial 31 wells Significant growth throughout 3Q after moderated initial ramp in July Implementing row development concept with modular infrastructure design Mustang Infrastructure Maximizing Gas Processing Flexibility Diversified processing capacity across 3 providers with multiple offload points Well positioned to benefit from near-term processing expansions, totaling more than 700 MMcf/d from 4Q18 to YE19 Strong volume growth driving retained Midstream EBITDA (1) growth; NBL owns 75% gathering infrastructure, NBLX owns 25% MBoe/d Substantial Volume Growth from Initial Row in Mustang 10 cum. wells online 20 cum. wells online 30 cum. wells online 0 7/1 7/16 7/31 8/15 8/30 9/14 9/29 10/14 Gross 3-Stream Production NBL Acreage DCP New or Upcoming 300 MMcf/d Processing 2Q19 DCP 200 MMcf/d Online Mustang WES +200 MMcf/d 2019 WMB 200 MMcf/d 4Q18 (1) Term defined in Appendix. 5

6 DJ Basin Mustang Area Comprehensive drilling plan (CDP) setting NBL apart Primary Operatorship Established Designates NBL as operator on acreage and sole authority to permit new wells; further allows NBL the opportunity to control the pace of activity Supports row development by preventing offset interruption from well communication or downtime due to shut-in wells Increasing Capital Efficiency across Position First large-scale CDP approved in State of Colorado, requires contiguous acreage footprint Allows for shared facility and infrastructure; reduces trucking and surface access needs Permitting Process Streamlined Permits carry a six-year expiration versus the standard two-years CDP provides for accelerated permitting Spans a CDP Key Statistics position over Consists of nearly potential locations Square Mile net acres ~ wells approved to date under the CDP Currently in permitting for more than additional wells Permits carry a year expiration timeline 6

7 DJ Basin Consolidating NBL s acreage position Recent Trade Adds to NBL s Contiguous Acreage in Wells Ranch and Mustang NBL received ~12,900 net acres from PDCE in exchange for 12,300 net acres in an all undeveloped acreage transaction Acreage trade increases working interest in core areas of Mustang and Wells Ranch; also adds to Cummins IDP Further allows NBL to control pace of development and capital spend Creating Additional Value through Long Lateral Development and Utilizing Existing Infrastructure Increases capital efficiency with inventory in Mustang and Wells Ranch averaging over 9,500 ft. Generates $100 MM in additional value by swapping out longer-dated inventory for near-term drilling All acreage traded was primarily non-operated Incremental value added to NBLX due to development timing Pre-Trade Acreage Trade Details NBL Acreage Acreage Traded: ~12,300 Acreage Gained: ~12,900 Post-Trade Wells Ranch Wells Ranch Mustang Mustang 7

8 Delaware Basin 115% production growth year-over-year TX Solid Operations in 3Q with Sales Volumes of 58 MBoe/d Continued strong volume growth, up 11 MBoe/d from 2Q18 Oil volumes up 15% 3Q18 vs. 2Q Transitioned to Row Development Currently operating 6 rigs and 1 frac crew, anticipate wells to come online in 4Q Focusing row development around CGFs, primarily in Wolfcamp A and Third Bone Spring zones Anticipate adding completion activity early in Early Crude Service from EPIC NGL Pipeline Anticipated in 3Q19; Providing Access to Gulf Coast Markets Timing coincides with row development 100 MBbl/d capacity on EPIC Oil Pipeline in January 2020 Delaware Activity 3Q18 Oil (MBbl/d) 38 NGL (MBbl/d) 11 Gas (MMcf/d) 52 Total Sales (MBoe/d) 58 Operated Rigs 6 Wells Drilled (1) 21 Wells Completed (1) 22 Wells Brought Online (1) 20 Avg. Lateral Length (ft) 7,420 MBoe/d Delaware Basin Net Production Volumes more than doubled 3Q18 vs. 3Q17 (2) 3Q16 3Q17 3Q18 Total Reeves Oil (MBbl/d) Ward Pecos NBL Acreage (1) Represents NBL operated activity. 8

9 Delaware Basin Activity Transitioning to optimal multi-zone row development Leveraging Learnings from Delaware Drilling and across U.S. Onshore Successfully executing row development in DJ and Eagle Ford Appraisal of multi-zone developments throughout position Implementing Systematic Row Development Program around CGFs Sequencing operations across row mitigates potential completion interference from traditional single-pad development NBL competitively advantaged with contiguous acreage position and key gathering infrastructure in-place Significant Operating Efficiencies from Proximity and Scale Streamlining rig and crew mobilization to reduce cycle time in section Accelerating learnings through predictable and repeatable operations Efficient use of surface infrastructure and synergies Water recycling, flowline connections, deployment of auxiliary services, etc. Producing Wells Reeves Buffer Zone Completed Wells Frac NBL Acreage CGF Illustration of Wolfcamp A (1) Development Only Row Development Across 2 Miles Buffer Zone DUC Inventory Drill (1) Illustration assumes 6 Wolfcamp A Upper wells and 6 Wolfcamp A Lower wells. Development may include other zones. 9

10 Eastern Mediterranean Growing natural gas demand and increasing cash flows Record 3Q18 Gross Sales Volumes 1,090 MMcfe/d; Net 242 MMcfe/d Driven by strong electricity demand and coal displacement Leviathan 67% Complete, Remains on Budget and On Schedule for First Gas Sales by YE19 Recent milestones: Finished 2 well completions, flow tests confirm deliverability Completed installation of subsea trees and completed floating of the main deck Upcoming key milestones before YE18: Finish all well completions and flowline installation Complete jacket fabrication and sail-away Completed Required Tamar Sell-down, $10.3 B Valuation (1) Working interest of 39.66% in Leviathan and 25% in Tamar. Assumes ~$50 WTI price deck. $MM 1,500 1, (500) (1,000) 7.5% Tamar Sale ATAX Aphrodite 35% WI Tamar SW 25% WI Egypt Tamar 25% WI Leviathan 39.7% WI Dor NBL Interests Producing Discovery Field Development Existing Pipeline New Pipeline Tel Aviv Ashdod Israel Long-term Net Cash Flow Profile from Tamar and Leviathan (1) 2018: Divested TMRP Shares ~$170 MM BTAX 2019E: Purchase of EMG ~$200 MM 2018E 2019E 2020E 2021E 2022E 2023E 2024E 2025E Capex Corporate Tax Profit Tax BTAX Operating Cash Flow 10

11 EMed Regional Update Multiple pathways to deliver Tamar and Leviathan natural gas exports to Egypt EMG Pipeline Agreements Low Cost Access to Growing Regional Demand Via Existing Infrastructure 90-km 26 offshore pipeline with ~700 MMcf/d capacity, assessing expansion capability Technical evaluation and flow reversal underway NBL and partners secure operatorship and full capacity at closing ~$200 MM net acquisition costs (10% indirect NBL interest) including pipeline reversal work, payable at closing anticipated early Anticipate Closing EMG Transaction in 1H19 Closing contingent upon confirmed Tamar gas flow At least 350 MMcf/d firm when Leviathan commences in late Aqaba-El Arish Agreement Provides for Additional Pipeline Route Within Egypt LOI to transport gas will provide incremental capacity to sell gas INGL Pipelines Under Construction INGL Arab Gas Pipeline Under Construction Arab Gas Pipeline EGAS Pipelines EMG Pipeline Aqaba-El Arish Pipeline EMG Pipeline Egypt Aqaba-El Arish Pipeline Israel Jordan 11

12 Bcf/d EMED Huge Natural Gas Demand Region Agreements secured in Israel, Jordan, and Egypt with ample running room Primary Source of Power for Israel Supplying nearly 70% of domestic power through record Tamar sales Government mandating coal conversions and incentivizing new uses of natural gas (industrial and CNG for transport) Significant Jordan Agreement for Leviathan 15 year, 1.6 Tcf, ~$10 Bn NEPCO contract Premium, Brent-linked price displacing LNG Substantial and Growing Demand in Egypt 10 year, 2.3 Tcf, ~$15 Bn Dolphinus contracts Premium Egypt domestic and LNG re-export prices More than 3 Bcf/d of unmet Egypt demand by Over 900 MMcf/d Total Volume Under Contract for Leviathan Total of all Leviathan contracts now estimated to be > $20 B in gross revenues or > 5x expected capital invested Over 200 MMcf/d Israel, 350 MMcf/d Egypt, 350 MMcf/d Jordan Continue negotiations to fill up Leviathan phase 1 to 1 Bcf/d Footnotes: 1) Based on BDO and Noble Energy internal estimates 2) Based on NEPCO and Noble Energy internal estimates 3) Assumes Probable Developments ) Nameplate capacity of 7.2 MMTPA at Idku, 5 MMTPA at Damietta (~2 Bcf/d, including feed gas) 5) Tamar I (1.1 Bcf/d) and Leviathan I (1.2 Bcf/d) EMED Market Demand & NBL Supply Capacity

13 West Africa Entering the next phase of development Strong Existing Cash Flows from Brent-linked Production at Alba, Aseng and Alen Heads of Agreement Established High-level Commercial Terms for Alen Gas Monetization Alba field declines resulting in open capacity at LNG plant Capital-efficient development utilizing existing Alen field and LNG infrastructure to monetize 600 Bcfe gross resources Pricing linked to global LNG markets Project Sanction Anticipated Early 2019 and First Gas in 2021 Currently progressing FEED and marketing activities Project scope includes minor Alen platform modifications and construction of 40-mile pipeline Potential for Alen to become regional gas hub 3 Tcf total gross resources from multiple discoveries in area Equatorial Guinea Methanol Plant 45% WI LPG Plant 28% WI Bioko Island Alba Field 33% WI Aseng 40% WI Yolanda Cameroon Alen 45% WI Yoyo Alen Platform, Equatorial Guinea NBL Interests Producing Discoveries Proposed Pipeline 13

14 Exploration Program Materially enhanced, high-quality portfolio with 1-2 drilling prospects anticipated per year Eastern Mediterranean ~470 K gross acres 25-40% WI, NBL operated Deep oil potential BBoe 4 3 Exploration Resource Portfolio New Ventures Captured >100 K acres with substantial resource potential in U.S. onshore (low cost entry / high liquids prospectivity) Signed agreement for operatorship of >2 MM gross acres in new country offshore Newfoundland ~2.3 MM gross acres 25% WI, non-operated Interpretation / maturation of prospects Gabon ~670 K gross acres 60% WI, NBL operated Processing 3D seismic Net Unrisked Resources Net Risked Resources Potential Tested in

15 Noble Energy Catalysts driving differential value creation Near-term Catalysts Additional Catalysts U.S. Onshore Operational Execution Delivering 20-25% oil growth (1) FY18 vs. FY17 Progressing row development in Delaware and DJ Basins Mustang IDP delivering top-tier results with gas processing diversification High-margin EMed Gas Sales Closing EMG transaction, targeting interruptible gas sales from Tamar early in 2019 Under negotiations to fill up Leviathan Phase 1 Leviathan first gas sales by year-end 2019 Sanction Gas Monetization in West Africa Capital efficient project with access to global LNG markets Sustainable Free Cash Flow Profile; Returning Cash to Shareholders Leading cash flow growth into 2020 and beyond driven by EMed and U.S. Onshore Competitive across E&P peers and all investment sectors Expansion Opportunities in EMed Additional phases at Tamar and Leviathan with potential to double gas deliverability to ~4 Bcf/d, driven by market demand Exploration Success Enhanced portfolio with potential to establish new core area post 2020 (1) Pro-forma for acquisitions and divestitures. 15

16 Appendix 16

17 Fourth Quarter 2018 Guidance 4Q 2018 Sales Volume Crude Oil and Condensate (MBbl/d) Natural Gas Liquids (MBbl/d) Natural Gas (MMcf/d) Total Equivalent (MBoe/d) Low High Low High Low High Low High United States Onshore (1) Israel Equatorial Guinea Equatorial Guinea - Equity method investment Total Company Capital & Cost Metrics Capital Expenditures (2) ($MM) Total Company Organic Capital $625 - $700 Cost Metrics LOW HIGH Lease Operating Expense (3) ($/BOE) Gathering, Transportation & Processing ($/BOE) Production Taxes (% Oil, Gas, NGL Revenues) Marketing ($MM) 8 12 DD&A (3) ($/BOE) Exploration ($MM) G&A ($MM) Interest, net ($MM) Other Guidance Items ($MM) Equity Investment Income Midstream Services Revenue Third Party Non-Controlling Interest NBLX Public Unitholders (1) Reflects 4 MBoe/d reduction from Greeley Crescent divestiture in the DJ Basin, closed in September of (2) Includes only NBL-funded portion of midstream capital expenditures. (3) Reflects lifting schedule in Equatorial Guinea. 17

18 Forward-Looking Statements and Other Matters This presentation contains certain "forward-looking statements" within the meaning of federal securities laws. Words such as "anticipates", "plans", "estimates", "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. Such forward-looking statements may include, but are not limited to, future financial and operating results, and other statements that are not historical facts, including 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 forwardlooking 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 and uncertainties 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 businesses that are discussed in Noble Energy's most recent annual report on Form 10-K, quarterly report on Form 10-Q, and in other Noble Energy reports on file with the Securities and Exchange Commission (the "SEC"). These reports are also available from the sources described above. 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 any forward-looking statements should circumstances or management s estimates or opinions change. The SEC 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 may use certain terms in this presentation, such as gross discovered resources, which by their nature are 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, Terms EBITDA ROACE CROCI Definition GAAP earnings before interest, taxes, depreciation, depletion, and amortization. Return on average capital employed. GAAP earnings before interest and taxes divided by (shareholders equity plus long-term debt plus long-term capital leases). Cash return on capital invested. GAAP operating cash flow, before working capital, divided by (shareholders equity plus long-term debt plus long-term capital leases). 18

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