2017 UBS GLOBAL OIL & GAS CONFERENCE. May 2017

Transcription

1 2017 UBS GLOBAL OIL & GAS CONFERENCE May 2017

2 NOBLE ENERGY INVESTMENT THESIS Best assets, best execution, best results Industry-leading Well Performance in Premier U.S. Onshore Basins 4.5 BBoe net unrisked resources, 7,500 liquids-rich drilling locations ~30% U.S. Onshore oil CAGR to 2020 High-Margin EMED Business Doubling Gross Gas Deliverability by 2020 World-class Leviathan project online late 2019 in substantially undersupplied region Value Creating Portfolio Management Focusing portfolio on highest-margin and fastestgrowing assets Accelerating value of assets not attracting capital Robust Financial Capacity and Disciplined Capital Allocation Maintained Investment Grade credit rating 2

3 PORTFOLIO TRANSFORMATION Ongoing process focusing portfolio on high-margin assets THEN Diversified portfolio focusing on both oil and natural gas, onshore and offshore globally 2014 Capital Allocation U.S. Onshore Liquids Eastern Med. Other ACTIONS Entered liquids-rich Eagle Ford Shale and Delaware Basin through ROSE Merger Expanded Delaware Position to 2 BBoe Net Unrisked Resources with CWEI Acquisition Exited Marcellus Upstream and Midstream, Accelerating Value of Assets Not Attracting Capital Established Noble Midstream Business and Launched X IPO Optimized DJ Basin Position through Acreage Exchanges Divested EMED Assets Enabling Leviathan Development Funding Sanctioned Initial Phase of Leviathan Development, First Gas by YE 2019 NOW Focus on fastestgrowing and highest-margin U.S. onshore liquids plays and Eastern Mediterranean 2017 Capital Allocation U.S. Onshore Liquids Eastern Med. Other 3

4 PORTFOLIO POSITIONED FOR HIGH MARGIN GROWTH Accelerating robust oil and EMED growth Combined DJ, Delaware and EMED Grow More Than 200 MBoe/d to 2020 Vast Majority of Capital Allocated to Delaware, DJ and EMED E EMED Cash Margins Competitive with Best U.S. Unconventional Oil Basins Employee Incentives Focused on Value Creation Returns, free cash flow and safety Operating Cash Flow Accelerating Much Faster Than Total Company Production E operating cash flow CAGR proforma 33-45%* * Ranges used throughout the presentation represent base to upside plan outcomes, adjusted for 2016 divestitures. See base and upside plan pricing in appendix. 160 MBoe/d (1) 2016 Divestment Adjusted E CAGR*: 23-31% DJ, Delaware and EMED Volume Growth EMED Delaware DJ 370 MBoe/d 2020E Base Plan 465 MBoe/d 2020E Upside Plan (1) 2016 Tamar production volumes adjusted to reflect a reduction in working interest to 25%, anticipated to be accomplished during plan period. Base plan for 2020 assumes Leviathan volumes at startup of a minimum 600 MMcf/d, gross. Upside plan assumes 1 Bcf/d at startup. 4

5 2017 KEY GOALS AND OBJECTIVES Substantial progress on outcomes for the year Goals Accelerate Onshore Activities and Drive Capital Efficiencies Status Currently operating 8 USO drilling rigs (2 DJ Basin, 5 Delaware, 1 Eagle Ford) Record drill times in DJ Basin, Delaware & Eagle Ford Well performance above expectations in all basins Successful Integration of CWEI into Commence Leviathan Development Grow Value of Midstream to Target Over $1 Billion in Portfolio Proceeds Focus Exploration on Long-term Value Well performance above 1 MMBoe type curve Exiting 2017 with 6 total rigs in Delaware Basin Sanctioned initial phase in February, ~$2 B gross capital under contract Drilling underway for 2 development wells in 2017 Progressing 5 central gathering facilities for Drop-down potential in 2017 Already generated $2 Bn YTD Focusing portfolio on high-margin, high-growth assets; More proceeds potential Preparing Araku (Suriname) prospect for 4Q drilling Capturing low capital, long-term opportunities 5

6 SIGNIFICANT POSITIONS IN PREMIER, LOW-COST BASINS 4.5 BBoe net unrisked resource potential, 7,500 liquids-rich locations Over 70% Inventory with Wells Below $40 Breakeven 352,000 net acres 3,220 gross locations 8,400 average lateral length 2 BBoe net unrisked resources DJ Basin 118,000 net acres 4,225 gross locations 7,800 average lateral length 2 BBoe net unrisked resources 35,000 net acres 360 gross locations Delaware 7,600 average lateral length 460 MMBoe net unrisked resources Eagle Ford 8,000 6,000 4,000 2,000 0 MBbl/d BTAX PV10 or Greater <$40/Bbl <$2/Mcf DJ 30% Base Plan Pricing Delaware 2017 USO Oil Growth Gross Identified Locations Eagle Ford 40% Note: Reflects Marcellus divestiture, anticipated to close in 2Q17. 0 FY 2016 FY 2017E 2H H 2017E 6

7 U.S. ONSHORE CATALYST-RICH 2017 U.S. onshore oil projected at high end of original expectations Highlights 2Q 3Q 4Q Anticipating 30% Full Year Oil Growth vs Rapidly Increasing Activity Throughout 2017 ~3X the amount of wells to be brought online in 2Q17 vs. 1Q17 Adding More Rigs in the DJ and Delaware, Exit 2017 with 6 in Delaware and 3 in DJ Installing Multiple Central Gathering Facilities to Support Upstream X Drop - Down Potential Integration of CWEI Assets 1st Multi-Zone Development Pad Online (WCA, 3BS), with 1st 10K ft. laterals in Delaware 1st Central Gathering Facility Online in Delaware DJ Basin Growth Driven by East Pony Wells Online Continued Eagle Ford Growth from Gates Ranch Row 4 wells 10+ Wells Online in Delaware Wells Ranch High Intensity Completions Online in DJ Basin 20+ Wells Online in Delaware 2nd Multi-Zone Development Pad Online in Delaware 2nd Central Gathering Facility Online in Delaware Additional Eagle Ford Growth with Upper Eagle Ford Tests 7

8 DELAWARE BASIN: TOP-TIER POSITION Superior, contiguous position with midstream advantage TX 2 nd Largest Southern Delaware Operator Creating Differential Value with Long Laterals, Midstream Advantage and High Liquids Content Strong Recoveries in Top-Tier Position 1.2 MMBoe Wolfcamp A type curve legacy and 1.0 MMBoe Wolfcamp A acquisition type curve (7,500 ft laterals) Rapidly Accelerating Activity and Applying s expertise Top 90-day oil rates in area Increasing activity on CWEI acreage to 3 operated rigs by YE17 Leveraging technical capabilities in onshore unconventionals 118,000 Net acres 4,225 Gross locations 7,800 ft Average lateral Length 2 BBoe Net unrisked resources 1,500 1, Southern Delaware Basin GOR Map Acreage CWEI Acreage Avg. 90 Day Oil IP Normalized to 7,500 ft (Bbl/d) 0 A B C D E F G H I Source: State data within 20-mile radius of position 8

9 DELAWARE BASIN: LEADING PERFORMANCE Optimizing completion design for optimum value Continued Outperformance 1Q17 Wells Trending 35% Above 1.2 MMBoe Type Curve After 60 Days Top 2 most productive industry Delaware Basin wells in 1Q17* Cum. MBoe Delaware Wolfcamp A Well Results Highest Industry 90-day Oil Rates in Southern Delaware** Early Results from 1Q17 5,000 lbs/ft Test are Encouraging Pony Deal 12 1H cumulative rate is ~30% higher than Pony Deal 12 5H after 60 days Continuing to Test Various Proppant Concentrations, Clusters per Stage and Stage Spacing for Optimal Design Activity Acceleration and Well Performance Driving 10X Growth to 2020E (145 MBoe/d) Days on Production 2016 Average (8 wells) 1Q17 Average (3 wells) Wells WCA 1.2 MMBoe Type Curve Gross 3 Stream, Normalized to 7,500 ft 1Q17 5,000 lbs/ft Test Materially Outperforming Offset 3,000 lbs/ft Completion Proppant (lbs/ft) IP-30 (Boe/d) IP-60 (Boe/d) Oil % Lateral Length (ft) Pony Deal 12 1H 5,038 1,882 1,710 73% 4,699 Pony Deal 12 5H 3,073 1,514 1,284 73% 4,532 5,000 lbs/ft outperformance 20% 30% * Source: Well test rate analysis by KLR Group, report dated 4/24/17; ** Source: State data within 20-mile radius of position 9

10 DJ BASIN: FOUNDATIONAL ASSET Large, high-quality, contiguous acreage position Creating Differential Value with Long Laterals, Midstream Advantage and High Liquids Content Recent Enhanced Completions Trending Significantly Above Type Curve in Oily Areas Wells Ranch 1.0 MMBoe type curve for 9,500 ft lateral East Pony 570 MBoe type curve for 7,500 ft lateral MBbl/ 1000ft Highest Type Curve Oil EUR/1,000 ft and Lateral Lengths Among DJ Operators Oil EUR/1,000 ft Type Curve Lateral Length Type Curve Lateral Length (ft) 10,000 9,000 8, ,000 Net acres 3,220 Gross locations 8,400 ft Average lateral Length 2 BBoe Net unrisked resources 46% 49% Weld Greeley Crescent Bronco 50% Acreage Increasing Oil Mix* Wells Ranch Mustang 52% CO East Pony IDP Areas GOR: Low Mid High 30 7, East Pony Wells Ranch A B C D 6,000 2Q16 3Q16 4Q16 1Q17 *Percentage oil of total DJ Basin sales volumes 2017 Completion Focus Areas Source: Company Filings and estimates; Peers include APC, SRCI, XOG, PDCE 10

11 DJ BASIN: LEADING PERFORMANCE Success with enhanced completions extending beyond Wells Ranch Enhanced Completions Wells Ranch High Intensity Completions Continue to Outpace Type Curve by More than 50% Over Extended Periods 1,800 lbs/ft Completions in Wells Ranch Indicating Significantly Lower Development Cost per BOE Initial Enhanced Completions in East Pony Demonstrating Similar Outperformance East Pony Position Contains Mix of Federal and Fee Acreage Combination of standard and enhanced completions in development plan Continue to Evaluate Optimal Proppant, Stage Spacing and Cluster Design for Efficiency Cum. MBoe Cum. MBoe Wells Ranch Recent Results* Days on Production 1Q17 1,800 lbs/ft (6 wells) Wells Ranch 1.0 MMBoe Type Curve (1,400 lb/ft) East Pony Enhanced Completions Well Results* Days on Production 2,800 lbs/ft Completions (4 wells) East Pony 570 MBoe Type Curve (1,400 lbs/ft) * Gross 3 Stream, Wells Ranch normalized to 9,500 ft and East Pony normalized to 7,500 ft 11

12 EAGLE FORD: PROLIFIC ASSET POTENTIAL Significant growth contributor in Activity Focused in Highly Prolific South Gates Ranch Lower Eagle Ford South Gates Ranch EUR 3.5 MMBoe for 7,000 lateral (750 lateral spacing) ~30 South Gates Ranch wells online in Focus Areas Generate Exceptional Economics Near-term Resource Upside Potential Initial operated Upper Eagle Ford well in Briscoe Ranch in line with expectations Gates and L&E Upper Eagle Ford wells planned Testing enhanced completions on Briscoe Ranch and L&E areas Cum MBoe ,000 Net acres 360 Gross locations 7,600 ft Average lateral Length 460 MMBoe Net unrisked resources Dimmit 2016 S. Gates Ranch Lower Eagle Ford Performance vs. Type Curve 3,500 MBoe Type Curve (750') Avg. 1,000' Actuals Webb Acreage TX Days on Production Gross 3 stream normalized to 7,000 lateral 12

13 EXPANDING MIDSTREAM Advantaged position in DJ and Delaware Basins DJ Basin Differentially Positioned Process own gas in East Pony IDP Optimizing field pressure with compression Access to Front Range pricing Material DCP capacity expansions underway IDPs Beneficially Located Near Multiple Crude Takeaway Options Material tightening in 2017 differential X Mustang Facility Operational by YE2017 Delaware Basin Unlocking Development Mode with First X Central Gathering Facility by Mid-2017 Facilitates pad drilling Reduced trucking Designed to incorporate produced water recycling X and Plains 50/50 JV Acquired Advantage Pipeline, Enhancing Crude Takeaway Options Access to multiple outlets including Gulf Coast, Midland & PAA s pipeline network 2 nd Facility Online YE2017, Beginning Plans for 2 Additional Central Gathering Facilities in

14 EASTERN MEDITERRANEAN World-class resources in a high-demand region Tamar 10 Tcf (Producing) and Leviathan 22 Tcf Gross Recoverable Resources Tamar currently supplying up to 60% of Israel power generation Expanding Ultimate Gross Capacity to Over 4 Bcf/d Tamar current capacity 1.2 Bcf/d Leviathan ultimate capacity of 2.1 Bcf/d through cost advantaged expansion Regional Deficit at 4 Bcf/d Currently, Growing to Over 9 Bcf/d Commenced exports to Jordan in 1Q17 High Natural Gas Demand in Israel Leading to Record Tamar Sales Volumes 1Q17 gross sales volumes of 956 MMcfe/d up 12% from 1Q16 Bcf/d Sizable Regional Gas Deficit Israel Deficit Jordan Deficit Egypt Domestic Deficit Egypt LNG Plant Deficit Turkey Contract Openers Cyprus Deficit Note: Data represents & BDO Israel estimates. Also reflects Egypt LNG imports of ~1.2 Bcf/d through

15 LEVIATHAN: PHASE ONE 1.2 BCF/D FROM 4 WELLS Steady cash flow stream, payout within 3-4 years Phase One Low-cost Development Capital $3.75 B gross, $1.5 B net LOE less than $0.40/Mcf Project Delivers Initial Annual Net Operating Cash Flow of at Least $650 MM at Startup and Exceeds $5 B Over First 10 Years Minimum volume case delivers at least $400 MM net and adds one year to payout Leviathan Project Fully Funded with Tamar Operating Cash and Planned EMED Portfolio Management $MM 1, (200) (400) (600) (800) *Government take includes royalties (12.5%), profit tax and corporate tax (23%) as percentage of project cash flows **Excludes financing; working interest 39.66% ***See appendix for definition of this Non-GAAP measure Partnership ~40% Life of Project Cash Flows* Government of Israel ~60% Phase One Net Cash Flow Profile- Target Case** 1 Bcf/d at Startup Capex Corporate Tax Profit Tax Pre-Tax Operating Cash Flow*** Free Cash Flow*** 15

16 NOBLE ENERGY INVESTMENT THESIS Best assets, best execution, best results Industry-leading Well Performance in Premier U.S. Onshore Basins 4.5 BBoe net unrisked resources, 7,500 liquids-rich drilling locations ~30% U.S. Onshore oil CAGR to 2020 High-Margin EMED Business Doubling Gross Gas Deliverability by 2020 World-class Leviathan project online late 2019 in substantially undersupplied region Value Creating Portfolio Management Focusing portfolio on highest-margin and fastestgrowing assets Accelerating value of assets not attracting capital Robust Financial Capacity and Disciplined Capital Allocation Maintained Investment Grade credit rating 16

17 Forward-Looking Statements and Other Matters This presentation contains certain "forward-looking statements" within the meaning of federal securities laws. 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. 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 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 and uncertainties include, without limitation, the risk that the cost savings and any other synergies from the recent merger with Clayton Williams Energy, Inc. may not be fully realized or may take longer to realize than expected, disruption from the merger transaction making it more difficult to maintain relationships with customers, employees or suppliers, the diversion of management time on post-merger related issues, 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 and Clayton Williams' most recent annual reports on Form 10-K, respectively, and in other Noble Energy and Clayton Williams 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 use certain terms in this presentation, such as net unrisked resources, gross recoverable resources, type curve, MBoe type curve, MMBoe type curve, or estimated ultimate recovery (EUR), which 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 and Clayton Williams most recent Form 10-K and in other reports on file with the SEC, available from Noble Energy s offices or website, This presentation also contains certain 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 see the attached schedules for reconciliations of the differences between any historical non-gaap measures used in this presentation and the most directly comparable GAAP financial measures. 17

18 Non-GAAP Reconciliations Pre-tax operating cash flow (Non-GAAP) and free cash flow (Non-GAAP) should not be considered an alternative to, or more meaningful than, operating cash flow (GAAP). Our management believes and certain investors may find that pre-tax operating cash flow and free cash flow is beneficial in evaluating and comparing companies in the crude oil and natural gas industry when discussing financial results. The following presents a reconciliation of each of these non-gaap financial measures to their nearest comparable GAAP measure. The GAAP measure most directly comparable to pre-tax operating cash flow and free cash flow is operating cash flow. Non-GAAP measures may not be directly comparable to similarly titled measures of other companies. Please see below reconciliation of each of these Non-GAAP measures on a cumulative basis from 2017 to 2029E. The annual data included in the reconciliations is included in the chart on slide 44 labeled Phase One Net Cash Flow Profile-Target Case. Cumulative E ($B) Operating cash flow (GAAP) 5.3 Profit tax 1.5 Corporate tax 1.0 Pre-tax operating cash flow (Non-GAAP) 7.8 Cumulative E ($B) Operating cash flow (GAAP) 5.3 Capital expenditures 1.5 Free cash flow (Non-GAAP)

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