JP Morgan Energy Equity Conference. June 2017

Transcription

1 JP Morgan Energy Equity Conference June 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 High-Margin EMED Business Doubling Gross Gas Deliverability by late 2019 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 Investment Grade credit rating 2

3 GUIDING PRINCIPLES Enabling success in any price environment Disciplined Capital Management Flexible investment programs for commodity environment Balance cash outflows to cash inflows Maintain strong liquidity and balance sheet Continually Enhance Capital Efficiency Advance technical competencies, learning curve and sustainable value improvements Drive Delaware economics through development mode efficiencies Leverage Benefits of Well Positioned and Diversified Portfolio Continue portfolio optimization opportunities Price-insulated EMED cash flows Capitalize on Low-Cost Environment with Quality Long-Cycle Development 3

4 PORTFOLIO TRANSFORMATION Focusing portfolio on high-margin assets THEN Diversified portfolio with access to both oil and natural gas, onshore and offshore globally 2014 Capital Allocation 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, X IPO and First Drop Down Optimized DJ Basin Position through Acreage Exchanges 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 U.S. Onshore Liquids Eastern Med. Other 4

5 FINANCIAL POSITION Strong balance sheet enabled opportunistic growth Robust Liquidity Liquidity to total assets ratio above 20% from Q17 No near-term debt maturities Generated over $4.5 B Portfolio Proceeds Monetized non-strategic assets at right time, generating good value Portfolio value acceleration strengthens balance sheet Aligned Investments Within Cash Flows Continue to Focus on Proactive Hedging Successful historical hedge program with $1.6 B net positive settlements over Q17 Investment Grade Credit Rating Optimal cost of capital and access to capital markets $ B $ B ~$5 B in Liquidity Through Time Q17 Available Revolver Cash Proceeds Bolsters Balance Sheet Onshore CNNX MLP X MLP Israel 5

6 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 Added 1 rig post CWEI acquisition close Sanctioned initial phase in February, ~$2 B gross capital under contract Field development drilling underway Progressing 5 central gathering facilities for Completed initial drop down in June Already generated over $2.2 B YTD Focusing portfolio on high-margin, high-growth assets Preparing Araku (Suriname) prospect for 4Q drilling Capturing low capital, long-term opportunities 6

7 SIGNIFICANT POSITIONS IN PREMIER, LOW-COST BASINS 4.5 BBoe net unrisked resource potential, 7,500 liquids-rich locations Over 65% Inventory with Wells Breakeven Below $40 352,000 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. * See appendix for base plan pricing 0 FY 2016 FY 2017E 2H H 2017E 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 Currently operating 2 rigs on CWEI acreage 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: TOP-TIER POSITION Large, high-quality, contiguous acreage position Creating Differential Value with Long Laterals, Midstream Advantage and High Liquids Content Recent Enhanced Completions Trending 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 7, ,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 20 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 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 ~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 35,000 Net acres 360 Gross locations 7,600 ft Average lateral Length 460 MMBoe Net unrisked resources Dimmit Webb Acreage South Gates Ranch Wells Online in MMBoe Type Curve (7,000 Lateral) TX Rest of Year 1Q17 12

13 EXPANDING MIDSTREAM Advantaged position in DJ and Delaware Basins DJ Basin Differentially Positioned Process and gather own gas in East Pony IDP area Optimizing field pressure with compression Access to Front Range pricing Material DCP capacity expansions underway IDPs Optimally Located Near Multiple Crude Takeaway Options 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 produced water recycling X and Plains 50/50 JV Acquired Advantage Oil Pipeline, Enhancing Crude Takeaway Options Access to multiple outlets including Gulf Coast, Midland & PAA s pipeline network 2 nd Facility Online YE2017, Planning for Two Additional Central Gathering Facilities in

14 MATERIAL MIDSTREAM EMBEDDED VALUE X is a growing portion of the value opportunity $556 MM received to date IPO proceeds, distributions and drop down proceeds ~2.4x Payout on invested capital contributed to X (1) $823 MM ownership of LP units (2) > $1.5 B combined retained EBITDA (3) and GP value (4) $MM Substantial Growth in Cash Flow Distributions (5) to 2017E 2018E 2019E 2020E IDR Distributions LP Distributions X Aligned to s Focus Areas in U.S. Onshore X yields in top quartile of MLP valuations maintains control and ownership with 100% of GP Initial Drop Down Generated $245 MM Cash to Sold 15% interest in Blanco River DevCo (Delaware) and remaining 20% interest in Colorado River DevCo (DJ Basin) Attractive Future Drop Down Potential Anticipate significant growth in Delaware and DJ Basin development company interest Substantial existing opportunities with sponsor retained East Pony gas gathering and processing (1) Includes distributions, IPO and drop down proceeds. Invested capital includes proportionate contribution through IPO and drop down of additional interests. (2) Represents s 50.1% ownership of X LP unit at market value as of 6/23/17 closing price. (3) Estimates average EBITDA of retained assets and development company interest. Applies potential future drop down multiple of 7.5x and 10x to EBITDA. EBITDA is a Non-GAAP metric that cannot be easily reconciled to GAAP metric at this asset level. See appendix for definition of this non-gaap measure. (4) Estimates 100% ownership of X GP IDR average cash flows at 25x to 35x multiple. (5) owns 100% of the GP Holdings of X. Assumes 20% X distribution growth and units outstanding remain flat. 14

15 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

16 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*** 16

17 NOBLE ENERGY Competitively advantaged to deliver differential performance Superior Portfolio Top-tier U.S. Onshore asset quality and inventory depth Integrated midstream business delivers financial and operational advantages Capital flexibility through diversification Operational Excellence Leading unconventional performance: longer laterals, IDPs, underground laboratories and enhanced completions Industry-leading major project execution Financial Strength Disciplined capital allocation process Prudent balance sheet and risk management 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", "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. 18

19 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)

20 Appendix Price deck assumptions and defined terms Period Base Plan Upside Plan WTI, Brent ($/Bbl) Henry Hub ($/Mcf) WTI, Brent ($/Bbl) Henry Hub ($/Mcf) 2017 $50 $3 $60 $ $55 $3 $65 $ $55 $3 $65 $ $56 $3 $66 $ Avg $54 $3 $64 $3 Term Definition EBITDA Earnings before interest, taxes, depreciation and amortization 20

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