EFTA01411427.pdf

Deutsche Bank Markets Research Industry US Integrated Oils Date 31 May 2015 North America United States Industrials Integrated Oil Ryan Todd Research Anal st Igor Grinman Min David Fernandez The "Other" 40 Million Barrels a Day and the Call on US Crude Growth The Coming Highs & Lows of Non-OPEC Production (and what it means for US) While significant attention has been dedicated to the analysis of the US supply dynamics over past 6 months, we turn our attention to the less-well understood 40 MMb/d of global crude production (ex-OPEC, ex-US onshore, ex-NGLs), and the outlook for the coming 2-5 years. Key takeaways: 1) Don't expect a major roll-over in Non-OPEC supply through 2017, 2) we still see a call on US onshore growth of 500 Mb/d in 2017 with 2H16 ramp 3) we likely need $65-$70/bbl oil to incentivize and support this growth, 4) post-2017, Non-OPEC shortages to drive rapidly escalating call on US crude and price inflation. Deutsche Bank Securities Inc. Deutsche Bank does and seeks to do business with companies covered in its research reports. Thus, investors should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision. DISCLOSURES AND ANALYST CERTIFICATIONS ARE LOCATED IN APPENDIX 1. MCI (P) 124/04/2015. EFTA01411427 EFTA01411428 Deutsche Bank Markets Research North America United States Industrials Integrated Oil Industry US Integrated Oils The "Other" 40 Million Barrels a Day and the Call on US Crude Growth The Coming Highs & Lows of Non-OPEC Production (and what it means for US) While significant attention has been dedicated to the analysis of the US supply dynamics over past 6 months, we turn our attention to the less-well understood 40 MMb/d of global crude production (ex-OPEC, ex-US onshore, ex-NGLs), and the outlook for the coming 2-5 years. Key takeaways: 1) Don't expect a major roll-over in Non-OPEC supply through 2017, 2) we still see a call on US onshore growth of 500 Mb/d in 2017 with 2H16 ramp 3) we likely need $65-$70/bbl oil to incentivize and support this growth, 4) post-2017, Non - OPEC shortages to drive rapidly escalating call on US crude and price inflation. Waiting for the Non-OPEC collapse? Don't hold your breath Despite significant capital cuts (20% across our global coverage), and fears of massive Non-OPEC declines, our analysis suggests greater than expected resilience in global Non-OPEC production through 2017, as a slug of major projects works its way through the system. Between 2015 and 2017, we estimate annual, major project-driven growth barrels of 1380 Mb/d, vs. the historical rate of 970 Mb/d between 2004-2013, supporting annual Non-OPEC supply growth of 150-200 Mb/d through 2017. But, there is a call on US onshore oil growth — the new swing producer Even with moderate growth in Non-OPEC production, solid global crude demand will still result in a call on US onshore production growth, although not likely until 2H16 (+350 Mb/d by 4Q16), rising to —500+ Mb/d in 2017. With current activity levels resulting in slightly declining US onshore production in 2H15, we see the need for increasing activity into late 2015/early 2016 to meet a rising call on US crude into 2H16. OPEC production, however, remains a looming risk, where current elevated levels of production (May 2015 estimated 31.6 MMb/d vs. our assumed 30.5 MMb/d target), a lifting of sanctions in Iran or Saudi strategy could push the US call further into 2017. $55/bbl oil isn't going to suffice Single well economics aside, corporate level cash flow suggests higher price is necessary to incentivize sufficient activity. We estimate an average oil price of $70/bbl to support moderated volume growth (ie. 35%-40% of pre-collapse peak rate) within producer cash flows. This falls to $60/bbl breakeven when EFTA01411429  spending 120% of cash flow. In other words, we will need a higher price than where we are today to make the US onshore "machine" work. Post-2017? Hold on to your hat... By late 2017, rising declines and deferred FIDs will drive a rapidly escalating call on US supply. Major oil project FIDs fell to 6 in 2014, the lowest level in 15 years, well below the average of 23/yr since 2000, with 2015 likely to be even lower. With an average of 1.2 MMb/d of capacity sanctioned a year over the past 10 years, the hole left by deferrals will be difficult to address, sending the call on US crude growth north of 1,000 Mb/d/yr by late this decade. Thriving in moderation — Stocks to own; Upgrade OXY to Buy; Cut HES to Hold Given the relatively cautious medium-term oil price outlook, our preference remains largely for names whose combination of asset quality and balance sheet allow them to support moderate, capital efficient growth within a moderate oil price environment. We upgrade OXY to BUY and downgrade HES to HOLD. Other preferred names include MRO, DVN, EOG. Date 31 May 2015 FITT Research Ryan Todd Research Analyst Igor Grinman Research Anal st David Fernandez 11111111M Key Changes Company CVX.N HES.N MRO.N MUR.N OXY.N X0M.N DVN.N APA.N APC.N PXD.N NBL.N Source: Deutsche Bank Top picks Marathon Oil (MRO.N),USD27.19 Devon Energy (DVN.N),USD65.22 EFTA01411430 Source: Deutsche Bank Companies Featured Chevron (CVX.N),USD103.00 ConocoPhillips (COP.N),USD63.68 Hess Corporation (HES.N),USD67.52 Marathon Oil (MRO.N),USD27.19 Murphy Oil (MUR.N),USD43.46 Buy Buy Hold Buy Hold Occidental Petroleum (OXY.N),USD78.19 Buy ExxonMobil (XOM.N),USD85.20 Source: Deutsche Bank Hold Target Price 120.00 to Rating 125.00(USD) 90.00 to 75.00(USD) 37.00 to 35.00(USD) 51.00 to 46.00(USD) 81.00 to 90.00(USD) 91.00 to 89.00(USD) 70.00 to 81.00(USD) 69.00 to 60.00(USD) 96.00 to 100.00(USD) 182.00 to 175.00(USD) 56.00 to 52.00(USD) Buy to Hold Hold to Buy EFTA01411431 Buy Buy Occidental Petroleum (OXY.N),USD78.19 Buy EOG Resources (E0G.N),USD88.69 Buy Deutsche Bank Securities Inc. Deutsche Bank does and seeks to do business with companies covered in its research reports. Thus, investors should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision. DISCLOSURES AND ANALYST CERTIFICATIONS ARE LOCATED IN APPENDIX 1. MCI (P) 124/04/2015. EFTA01411432 31 May 2015 Integrated Oil US Integrated Oils Table Of Contents Executive Summary 3 The Non-OPEC growth outlook to 2017 8 Looking for rapid declines? Don't hold your breath 8 Non-OPEC growth: Late to the party 8 Where is the growth coming from? 10 Capex Reductions 15 Show me the money (or lack thereof) 15 Setting the stage for the next oil price spike? 18 The North Sea: A Case Study On Spend and Decline Rates 20 Implied Call on the US 24 The new, "price driven" swing producer 24 Incentivizing the US producer 27 Updated Equities Outlook 29 Getting a Bit Defensive 29 Upgrading OXY to Buy from Hold 32 Downgrading HES to Hold from Buy 32 Risks to the Outlook 33 Iran and the Rest of OPEC 33 Other Risks to the Outlook 37 A Country by Country Outlook on Key Players 40 Angola 40 Brazil 42 Canada 44 EFTA01411433 Caspian Sea, ex Russia 47 Colombia 49 U.S. Gulf of Mexico 51 Malaysia 54 Mexico 56 North Sea 59 Russia 61 Appendix 63 Page 2 Deutsche Bank Securities Inc. EFTA01411434 31 May 2015 Integrated Oil US Integrated Oils Executive Summary Expecting a Non-OPEC collapse? Don't hold your breath Given the scale of cuts to global capex (20% across our global coverage universe), many in the market have speculated about the imminent decline of global Non-OPEC production. Although we see significant risk post-2017, our analysis suggests greater than expected resilience in global Non-OPEC production over the next couple of years, as a slug of major capital projects, the fruit of 5 years of consistently high oil prices, works its way through the system. Between 2015 and 2017, we estimate annual, major project-driven growth barrels of 1380 Mb/d, vs. the historical rate of 970 Mb/d between 20042013, supporting annual Non-OPEC supply growth of 500 Mb/d through 2017. Leading drivers: US GoM, Brazil, Canada, and slower declines on recent redevelopment projects in the North Sea. While project delays or poor performance could lead to disappointment (a hallmark of Non-OPEC supply), there is clearly a robust slate of projects on the horizon. Figure 1: Since 2004, higher contributions from major projects have driven Non-OPEC Supply growth 2000 1528 1500 1134 1000 719 500 0 <800 Mb/d -500 Avg Growth Bbl Contribution Source: Deutsche Bank, Wood Mackenzie, IEA YoY Non-OPEC Supply Growth (Avg) Source: Deutsche Bank, Wood Mackenzie, IEA Despite the large cut to headline capex, this is largely consistent with the source of the capex cuts, with the largest share of capex reductions (outside of the US onshore) concentrated in exploration budgets and deferrals of major project spend, with limited impact on near-term production levels. Norway: Exhibit A In some ways, Norway is a microcosm of the larger global picture. Largely synonymous with mature declining assets, averaging 6% YoY decline since 2002 (vs 9% for the UK), the Norwegian North Sea will actually see production flat to slightly increasing through 2017. Driving this is a significant increase in major project growth barrels, with nearly 380 Mb/d expected online between 2015-2017, vs. an average of 35 Mb/d of annual, projected driven increase from 2009-2013. EFTA01411435 800-1000 Mb/d 1000 - 1200 Mb/d >1200 Mb/d 933 Figure 2: .And over the coming 5 yr outlook, major project growth is expected to reach peak levels following recent $100/bbl oil incentivized spend 200 400 600 800 1000 1200 1400 1600 1800 0 1325 Mb/d 975 Mb/d Deutsche Bank Securities Inc. Page 3 Mb/d YoY Crude Production Growth (Mb/d) EFTA01411436 31 May 2015 Integrated Oil US Integrated Oils Figure 3: Norwegian growth barrels at recent highs 100 120 140 160 180 200 20 40 60 80 0 2009 2010 2011 2012 2013 Source: Deutsche Bank, Wood Mackenzie, IEA, includes Ekofisk II redevelopment project 2014 2015 2016 But, there is a call on US onshore oil growth — the new swing producer Although we don't expect a rapid decline in Non-OPEC production, stronger than expected global crude demand will still result in a call on US onshore production growth, although not likely until 2H 2016 culminating in a 2017 call of —500 Mb/d. We decompose the call into two parts: IIWe estimate that —260 Mb/d of incremental demand is needed beyond peak (2Q15) L48 production that is not otherwise being supplied from non-OPEC producers (assuming non-growing OPEC). IIWe anticipate a trough in US production in 1Q16 and estimate a gap of —270 Mb/d vs 2Q15 production that will need to narrowed toward an estimated call on US onshore production of —7.65 MMb/d in '17. We anticipate demand for US onshore crude production to accelerate through 2017 and for the call on YoY crude growth to nearly 700 Mb/d in 2018 and to surpass 1,000 Mb/d in 2019/2020 as Non-OPEC production growth tapers off. Figure 4: Incremental Demand for US Onshore Crude Expected To Emerge Late 2016 (vs. 2Q15 Production)... 1500 1000 500 0 100 200 300 EFTA01411437 400 500 600 -500 -1000 -300 -200 -100 0 -42 -230 1Q16 -1500 2Q16 3Q16 4Q16 1Q17 531 342 149 Figure 5:..Forward rolling 12 mo call on US onshore production growth (vs 1016 production) positive in 2H16 Source: Deutsche Bank, Wood Mackenzie, IEA Source: Deutsche Bank, Wood Mackenzie, IEA Page 4 Deutsche Bank Securities Inc. call on US Crude vs. 2015 Production (mbpd) YoY Growth 12 Mo Rolling Call on US onshore production (Mb/d) EFTA01411438 31 May 2015 Integrated Oil US Integrated Oils And $40-55/bbl oil isn't going to suffice Despite arguments about asset breakevens in the onshore at prices as low as $40/bbl, the number that matters for the resumption of drilling/completion activity is corporate level cash flow, not single well rates of return, in our view. Despite the sector being fairly well capitalized at present, partially thanks to a recent wave of equity issuance, total leverage remains quite high and companies are likely to stick relatively close to cash flow as activity picks up. Across the E&P universe, if we assume 20% decline in well costs and spend within cash flow in 2016/2017, we estimate an average oil price of $70/bbl to support 35% of pre-collapse production growth (our estimated demand for US onshore crude by late 2016). This falls to $60/bbl breakeven when spending 120% of cash flow. In other words, we will need a materially higher price than asset-breakeven prices to make the US onshore "machine" work. Figure 6: Oil Price to generate 35% of prior peak growth in 2016-17 $10 $20 $30 $40 $50 $60 $70 $80 $90 $0 CLR EOG PXD CXO APC DVN WLL HES MRO Avg CFO=Capex CFO=120% Capex Source: Deutsche Bank By late 2017, hold on to your hats By late 2017, rising declines and deferred FIDs will drive a rapidly escalating call on US supply. Major oil project FIDs fell to 6 in 2014, the lowest level in 15 years, well below the average of 23/yr since 2000, with 2015 likely to be even lower. With an average of 1.2 MMb/d of capacity sanctioned a year over the past 10 years, the hole left by deferrals will be difficult to address, sending the call on US crude growth north of 1,000 Mb/d/yr by late this decade. Figure 7: Major Oil Project Sanctions (FIDs) by year 10 15 20 25 EFTA01411439 30 35 40 0 5 Figure 8: Peak capacity of project FIDs by year (Mb/d) 500 1000 1500 2000 2500 3000 0 $72 $61 Source: Deutsche Bank, Wood Mackenzie Source: Deutsche Bank, Wood Mackenzie Deutsche Bank Securities Inc. Page 5 $/bbl (WTI) EFTA01411440 31 May 2015 Integrated Oil US Integrated Oils What does it mean for the stocks? For the equities, the debate centers on the pace of the recovery in crude price, and how soon should investors pay for it. Given what we view as a rather tepid recovery in crude over the next 18-24 months, (followed by significant longterm strength), and relatively aggressive current implied valuations (sector discounting $75/bbl+), we remain focused on names that have the asset quality and balance sheet to grow production in a capital efficient manner (ie. largely within cash flow) in a moderate oil price world. We upgrade OXY to Buy and downgrade HES to Hold on an improving outlook at OXY (Permian exceeding expectation + FCF generation and cash return to shareholders at the current strip). Other preferred names include: DVN, MRO, EOG. IIOXY: We upgrade OXY to Buy (from Hold) on its advantaged combination of growth and free cash flow in a moderate oil price environment. We see a number of key drivers for OXY, including: 1) Permian performance continues to exceed expectations, with likely upside to conservative 2016 target of 120 Mboe/d, 2) leading FCF generation in our coverage universe at $65/bbl WTI (1.8% postdividend in 2016, or 5.8% pre-dividend, vs. peer average of a 2.4% FCF deficit in 2016), led by three primary Middle East projects which generate —$1.0-$1.5 Bn/yr of FCF, 3) 2017 start-up of ethylene cracker driving —$1.0 Bn/yr of FCF from the chemical business from 2017, 4) 2nd highest dividend yield in our coverage universe (3.9%), with FCF driving further growth and share buyback, 5) solid crude leverage in the case of a rebound in oil price, and 6) relatively attractive valuation at 6.7x 2017 EV/DACF (or 6.4x adjusted for Midstream/Chemicals segments). IIHES: We downgrade HES to Hold (from Buy) primarily on account of the company's notable outspend (second to worst in the group based on 4Q15 annualized figures). We expect investors to continue to struggle (4%/3% underperformer since recent WTI trough/in May) with HES' relatively high spend on investments that are not expected to generate near-term cash flow (North Malay Basin, US midstream, Stampede, exploration, etc); not surprisingly, HES scores last on our defensive scorecard despite offering a healthy balance sheet (4th in the group on a '16 net debt/cap basis). While an attractive valuation (5.6x 2017 EV/DACF vs group at 6.4x) and impressive liquids leverage (highest in the group) sets up well for investors looking to play a crude price bounce, our defensive-tilted outlook suggests HES's mediumterm outspend/ FCF profile will remain in the spotlight. Primary Risks: global demand, supply delays, decline rate and OPEC We view the following as amongst the primary risks to our outlook: OPEC — Outside of a change in policy by Saudi, we see two primary risks to EFTA01411441 our forecast in the immediate horizon (6-12 months): Iran (a potential reduction in the call on US growth by —450 Mb/d) and Iraq (increased export volumes out of Kurdistan an incremental —400 Mb/d over 2014 levels presently) Longerterm growth in sustainable productive capacity from Iraq and the UAE pose the greatest risks to an increased need for US onshore crude during the tailend of our forecast period. As for Saudi, we sensitize our outlook to Saudi market share as a % share of global oil supply. Using a 5 year average market share of global supply, implied go-forward Saudi production results in a call on US onshore growth of —500 Mb/d through 2018 and increasing to 700 Mb/d by 2019. Assuming current Saudi market share levels (-15%) effectively renders the call on US onshore growth non-existent during our forecast period. Page 6 Deutsche Bank Securities Inc. EFTA01411442 31 May 2815 Integrated Oil US Integrated Oils Global Oil Demand and Decline Rates — Our base case assumes 1.2 MMb/d of global product demand growth in 2016 (vs. 2015), an improvement over the current 2015 growth outlook (1.1 MMb/d). Although demand in 2015 has exceeded expectations (current estimate revised higher vs. initial 1 MMb/d), with particular strength seen in US gasoline and European product demand, increasing efficiencies in global fuel consumption, or a slowing global economy, could result in lower growth, potentially eliminating the call on US crude growth. On the flip side, demand growth approaching our bull case (1.4 MMb/d) would push the call on US crude growth towards 650 Mb/d, stressing the ability of US producers to respond, and driving much higher than expected crude prices. A change in our modeled decline rates (2015+) by 25 bps could impact the call on US crude growth by —150 mbpd in 2017. Inventory Overhang: At its peak (in 2Q16) we expect accumulated crude inventories post 4Q14 to reach 500 mbbls or —17.5% of annualized 2Q15 production. While on first blush this may seemingly present a significant headwind to our outlook, we contend that a) relative to historical levels we aren't visiting new ground, and b) strong product demand and relatively low product inventories should support an inventory shift from crude to products, somewhat mitigating the risk. Deutsche Bank Securities Inc. Page 7 EFTA01411443 31 May 2015 Integrated Oil US Integrated Oils The Non-OPEC growth outlook to 2017 Looking for rapid declines? Don't hold your breath The prevailing narrative on global Non-OPEC crude production is that: 1) it always disappoints (not entirely unfair), and 2) near-term production will disappoint as decline rates accelerate from capex cuts. While there is certainly risk to the current supply outlook and decline rates may eventually tick higher, the reality is that those looking for a rapid negative response in Non-OPEC production are likely to be disappointed. The reason? 1) Despite frequent jokes to the contrary, 4+ years of —$100/bbl crude generated significant investment that is now showing up in a relatively robust queue of growth projects that, already underway, are proceeding no matter the medium-term price of crude; and 2) Capex cuts across the globe have been disproportionately driven by major project deferral (ie. FID delays, with volume impact felt 3-5 years out), rather than cuts to brownfield/maintenance spend. Non-OPEC growth: Late to the party A look back at new, project-driven "growth" barrels (ie. incremental barrels associated with project starts or significant expansions) show that ex-US onshore Non-OPEC averaged annual growth of 970 Mb/d from 2004-2013, including only 700 Mb/d in 2012 and 2013. However, beginning in 2014, after multiple years of elevated investment, incremental project-driven growth was — 1050 Mb/d, rising to an expected 1600 Mb/d in 2015, and remaining at an elevated 1275 Mb/d per year through the rest of the decade. Figure 9: Since 2004, higher contributions from major projects have driven Non-OPEC Supply growth 2000 1528 1500 1134 1000 719 500 0 <800 Mb/d -500 Avg Growth Bbl Contribution Source: Deutsche Bank YoY Non-OPEC Supply Growth (Avg) Source: Deutsche Bank 800-1000 Mb/d 1000 - 1200 Mb/d >1200 Mb/d 933 Figure 10: .And over the near-term outlook, major EFTA01411444 project growth is expected to reach peak levels following recent $100/bbl oil incentivized spend 200 400 600 800 1000 1200 1400 1600 1800 0 1325 Mb/d 975 Mb/d Page 8 Deutsche Bank Securities Inc. Mb/d YoY Crude Production Growth (Mb/d) EFTA01411445 31 May 2015 Integrated Oil US Integrated Oils Despite the current speculation on the impact of potential reductions to brownfield capital spend (infill drilling, tie-backs) or other decline maintenance efforts, the reality is that large projects remain the single largest driver of incremental volume growth, and the lag in project development timelines means that many of those "$100/bbl crude" projects will start over the coming 2-3 years. Figure 11: Non-OPEC peak spending from 2012-2014 chief driver of increase in incremental "growth" barrels anticipated on-stream between 2015-2017 100 150 200 250 300 350 400 450 500 50 0 Onshore (ex US, Canada) Source: Deutsche Bank, Wood Mackenzie There are clearly risks to this outlook, as Non-OPEC supply has historically disappointed (see figure below), but there is no avoiding the fact that the outlook for Non-OPEC supply is more robust than usual. Figure 12: However, Non-OPEC Supply has often disappointed (IEA NonOPEC supply projection revisions) (0.8) (0.6) (0.4) (0.2) 0.0 0.2 0.4 0.6 0.8 1.0 1.2 2014 2010 2012 2013 2011 2015 Shallow DW UDW Canada Offshore, Oil Sands LNG 2009 EFTA01411446 Month IEA Forecast was Made Source: IEA, Deutsche Bank Deutsche Bank Securities Inc. Page 9 Real Capital Spending ($2014 USD, Billions) Forecast non-OPEC Supply ex US (mmb/d) Feb-08 Jul-08 Dec-08 May-09 Oct-09 Mar-10 Aug-10 Jan-11 Jun-11 Nov-11 Apr-12 Sep-12 Feb-13 Jul-13 Dec-13 May-14 Oct-14 EFTA01411447 31 May 2015 Integrated Oil US Integrated Oils Where is the growth coming from? While volume growth is coming from a variety of sources, the single largest drivers outside of the US onshore are clearly Brazil and Canada. Brazil, after years of delays and disappointment, is set to contribute —155 Mb/d per year from 2014-2020. And while the combination of lower oil price and political scandal has certainly elevated the risk profile, particularly in the out years, near-term schedules remain largely intact (see Brazil focus section on page 43). Excluding Brazil, crude production from the rest (ex-OPEC, US onshore) is projected to be relatively flat through 2020. Figure 13: 2014-2017 Cumulative Growth (Mb/d) Non-OPEC Middle East Mexico North Sea Colombia Caspian Sea Alaska Other Non-OECD Asia Europe Non-OECD India Other FSU Angola Australia Other Non-OPEC Latin America Other Europe OECD Other Asia OECD Indonesia China Non-OPEC Africa Malaysia Russia Canada Brazil GoM -400 -200 0 200 400 600 800 Source: Deutsche Bank Source: Deutsche Bank Figure 14: 2014-2020 Cumulative Growth (Mb/d) Non-OPEC Middle East Mexico North Sea Colombia Non-OPEC Africa Alaska Indonesia EFTA01411448 Other Non-OECD Asia India Other Europe OECD Europe Non-OECD Other FSU Russia Other Non-OPEC Latin America Other Asia OECD Malaysia Australia China Angola Caspian Sea GoM Canada Brazil -500 0 500 1000 Page 10 Deutsche Bank Securities Inc. EFTA01411449 31 May 2015 Integrated Oil US Integrated Oils Figure 15: Brazil and Canada: Exclude them and Non-OPEC crude production is down —1500 MMb/d from 2014-2020, include them and production is up 400 Mb/d -2000 3000 8000 13000 18000 23000 28000 33000 38000 43000 GoM Non-OPEC Middle East Indonesia Caspian Sea Other India Source: Deutsche Bank, Wood Mackenzie, IEA Through 2017, the vast majority of this growth (-99%) is currently on-stream or under development, reducing the potential risk of low current oil price. Onshore projects remain the largest source of growth (36%), with deepwater projects representing an increasingly meaningful 35% of incremental barrels (vs. only 8% of current Non-OPEC production). Figure 16: 99% of Growth from 2015-2017 of "Other Bbls" are either "Onstream" or "Under Development"_ Not Yet Developed 1% Figure 17: ...With the onshore remaining single highest source of growth Unconventional, Other 11% Under Development 33% Onstream 66% Deep-Water 17% Shallow-Water 18% Ultra Deep-Water 18% Onshore 36% 2014 EFTA01411450 2015E 2016E Colombia Australia Other Non-OECD Asia Total North Sea Mexico Total Canada 2017E 2018E 2019E Non-OPEC Africa Malaysia Russia Other Non-OPEC Latin America China Brazil 2020E Source: Deutsche Bank, Wood Mackenzie, IEA, adjusts for Brazil Lula/Iracema FPSOs not currently onstream Source: Deutsche Bank, Wood Mackenzie, IEA Deutsche Bank Securities Inc. Page 11 EFTA01411451 31 May 2015 Integrated Oil US Integrated Oils Post-2017, project risk increases materially, with 25% of expected growth from 2018-2020 not yet sanctioned (and unlikely to be sanctioned anytime soon). The ultra-deepwater grows increasingly important during this time period, rising to —24% of expected growth, with another 11% from deepwater projects. Figure 18: Post 2017, growth from "Not Yet Developed" bbls is expected to increase to 25%... Onstream 22% Not Yet Developed 26% Figure 19: With Deepwater (UDW and DW) expected to be the single highest source of growth (-35%) Unconventional, Other 13% Onshore 31% Ultra Deep-Water 24% Deep-Water 11% Under Development 52% Source: Deutsche Bank, Wood Mackenzie, IEA Source: Deutsche Bank, Wood Mackenzie, IEA, Unconventional includes oil sands, bitumen Shallow-Water 21% Figure 20: Decomposition of YoY Growth from Major Projects By Development Status 200 400 600 800 1000 1200 1400 1600 1800 0 2015E Onstream 2016E 2017E Under Development 2018E EFTA01411452 2019E 2020E Not Yet Developed Source: Deutsche Bank, Wood Mackenzie, IEA, adjusts for Brazil Lula/Iracema FPSOs not currently onstream Onshore Figure 21: Decomposition of YoY Growth from Major Projects By Project Type 200 400 600 800 1000 1200 1400 1600 1800 0 2015E 2016E Shallow-Water 2017E Deep-Water 2018E Ultra Deep-Water 2019E 2020E Unconventional, Other Source: Deutsche Bank, Wood Mackenzie, IEA, 2020 pick-up in shallow water growth from Johan Sverdrup ramp In terms of the physical decomposition of the crude bbls that are to hit the global market in the coming years, the mix is weighted heavily toward heavy Canadian oil sand volumes and medium heavy Brazilian barrels (Iara and Tartaruga Verde fields) Page 12 Deutsche Bank Securities Inc. Decomposition of YoY Growth from Major Projects (Mb/d) Decomposition of YoY Growth from Major Projects (Mb/d) EFTA01411453 31 May 2015 Integrated Oil US Integrated Oils Figure 22: While the current Non-OPEC production mix is —2/3 medium Light 15% Extra Light 1% Extra Heavy 1% Heavy 17% Figure 23: 2014-2020 "growth bbls" are anticipated to be heavier on increased volumes from the Canadian oil sands and from medium-heavy Brazil volumes Extra Heavy, 14% Extra Light, 0% Light, 18% Heavy, 23% Medium 66% Medium, 46% Source: Deutsche Bank, Wood Mackenzie, IEA, Heavy barrels are classified as <28 API with extra heavy barrels <11 API. Light barrels are classified as having an API of 38+ with Extra Light > 51 Source: Deutsche Bank, Wood Mackenzie, IEA, Heavy barrels are classified as <28 API with extra heavy barrels <11 API. Light barrels are classified as having an API of 38+ with Extra Light > 51 Figure 24: Top 25 Projects (2014-2017) Incremental Oil Production Project Region Lula-Iracema Sapinhoa Kearl SeverEnergia Kizomba Satellites Phase2 Papa-Terra Surmont Project Horizon Project Edvard Grieg Srednebotuobinskoye Block 15/06 NW Hub Kashagan Contract Area EFTA01411454 Foster Creek Laggan & Tormore Area Roncador Yarudeiskoye Delta House Goliat Area Lucius (KC 875) AOSP Ekofisk Area II Tsimin-Xux Mafumeira Golden Eagle Area Sunrise Latin America Latin America North America FSU Africa Latin America North America North America Europe FSU Africa FSU North America Europe Latin America FSU North America Europe North America North America Europe Latin America Africa Europe North America Source: Deutsche Bank, Wood Mackenzie Country Brazil Brazil Canada Russia Angola Brazil Canada Canada Norway Russia Angola EFTA01411455 Kazakhstan Canada UK Brazil Russia United States Norway Canada Norway Mexico Angola UK Canada Basin Santos Santos West Canadian - Alberta West Siberia (Central) Lower Congo Campos West Canadian - Alberta West Canadian - Alberta Northern North Sea Nepa - Botuoba Lower Congo Precaspian West Canadian - Alberta West Shetland Campos West Siberia (Central) East Gulf Coast Tertiary West Barents Sea United States West Gulf Coast Tertiary West Canadian - Alberta Central Graben Salinas-Suerte Lower Congo Moray Firth West Canadian - Alberta Operator Petrobras Petrobras Imperial Oil SeverEnergia ExxonMobil Petrobras ConocoPhillips Canadian Natural Resources Lundin Petroleum Taas-Yuryakh Eni EFTA01411456 North Caspian Operating Co Cenovus Energy Total Pet rob ras Yargeo LLOG Exploration Eni Anadarko Shell ConocoPhillips Pemex Chevron Nexen Husky Energy Project Type Dev Status UDW UDW Onshore Onshore DW DW Onshore Onshore Shallow Onshore DW Shallow Onshore DW UDW Onshore UDW DW UDW Onshore Shallow Shallow Shallow Shallow Onshore Onstream Onstream Onstream Onstream Under Development Onstream Onstream Onstream Under Development Onstream EFTA01411457 Onstream Onstream Onstream Under Development Onstream Under Development Under Development Under Development Onstream Onstream Onstream Onstream Onstream Onstream Onstream API 27 30 8 43 28 14 8 34 35 32 24 45 11 40 24 42 36 37 29 34 40 38 36 38 8 Production Start Up Yr 2009 2010 2013 2012 2015 2013 2007 2008 EFTA01411458 2015 2013 2014 2013 2001 2015 1999 2015 2015 2015 2015 2003 1999 2012 2009 2014 2015 Peak Prod Yr 2022 2016 2030 2018 2020 2017 2018 2019 2016 2023 2016 2029 2029 2018 2018 2016 2017 2016 2017 2021 2002 2017 2018 2017 2025 Incremental Production 381 171 138 120 108 EFTA01411459 96 95 89 89 85 83 83 81 81 79 79 75 72 69 68 68 64 62 60 60 2014-2017 Deutsche Bank Securities Inc. Page 13 EFTA01411460 31 May 2015 Integrated Oil US Integrated Oils Figure 25: Top 25 Projects (2017-2020) Incremental Oil Production Project IEA Region Lula-Iracema Johan Sverdrup Buzios Kashagan Contract Area Block 32 Kaombo Fort Hills Mine Hebron/Ben Nevis Novoportovskoye Tengizchevroil Area Block 21 Ayatsil-Tekel Block 16 Messoyakhaneftegaz Fields Horizon Project Christina Lake Project Clair Kizomba Satellites Phase2 Appomattox (MC 392) Vladimir Filanovski Schiehallion Lapa Stampede Bream Area Iara Prirazlomnoye (TP) Latin America Europe Latin America FSU Africa North America North America FSU FSU Africa Country Brazil Norway Brazil Kazakhstan Angola Canada Canada Russia Kazakhstan EFTA01411461 Angola North America Mexico Africa FSU Angola Russia North America North America Europe Africa FSU Canada Canada UK Angola North America United States Russia UK Europe Latin America Europe Brazil North America United States Norway Latin America FSU Source: Deutsche Bank, Wood Mackenzie Brazil Russia Basin Santos Central North Sea Rio de Janeiro Offshore Ultra Deepwater Athabasca Newfoundland West Siberia Precaspian Basin Deepwater Salinas-Sureste Deepwater West Siberia Athabasca Athabasca Atlantic Margin Deepwater Central Gulf North Caucasus Atlantic Margin Sao Paulo EFTA01411462 Central Gulf Central North Sea Rio de Janeiro Timan-Pechora Operator Petrobras Statoil Petrobras North Caspian Operating Co Total Suncor Energy ExxonMobil Gazpromneft Novi Port Tengizchevroil Cobalt International Energy Pemex Maersk Oil & Gas Messoyakhaneftegaz Canadian Natural Resources ConocoPhillips BP ExxonMobil Shell LUKOIL Nizhnevolzhskneft BP Pet robras Hess Corporation Premier Petrobras Gazprom neft shelf Project Type Dev Status UDW Shallow UDW Shallow UDW Onshore Shallow Onshore Onshore UDW Offshore DW Onshore Onshore Onshore DW DW UDW Shallow EFTA01411463 DW UDW DW Shallow UDW Shallow Onstream Probable Development Under Development Onstream Under Development Under Development Under Development Onstream Onstream Under Development Probable Development Probable Development Under Development Onstream Onstream Onstream Under Development Probable Development Under Development Onstream Onstream Under Development Probable Development Under Development Onstream API 27 28 28 45 32 10 27 32 47 44 11 36 31 34 9 24 28 38 44 EFTA01411464 26 26 32 32 26 24 Production Start Up Yr 2009 2020 2016 2013 2017 2017 2017 2011 1991 2017 2017 2019 2017 2008 2002 2005 2015 2019 2016 1998 2011 2018 2020 2018 2013 Peak Prod Yr 2022 2024 2023 2029 2020 2020 2023 2022 2023 2024 2021 2021 2023 2019 2025 2021 EFTA01411465 2020 2025 2022 2003 2020 2022 2020 2026 2021 Incremental Production 397 311 300 246 174 170 120 111 91 90 88 88 86 76 75 70 69 69 67 64 57 56 54 50 47 2017-2020 Page 14 Deutsche Bank Securities Inc. EFTA01411466 31 May 2015 Integrated Oil US Integrated Oils Capex Reductions Show me the money (or lack thereof) In addition to the relatively robust queue of project starts, the production outlook is largely supported by what we have seen in global capex trends, where cuts have been disproportionately driven by major project deferral (ie. FID delays, with volume impact felt 3-5 years out), rather than cuts to brownfield/maintenance spend. In other words, the nature of the capex cuts are likely to have a significant impact on production growth in the latter part of this decade, but a far lesser impact on near-term production (2015-2016) and/or decline rates. A brief survey of capex trends across —50 global oil and gas producers shows an average cut of 20% in 2015 vs. 2014 ($300Bn to $375Bn in 2014). However, drilling down a bit reveals a number of important details. 1) Capex cuts tend to be largest in the US and amongst independent E&Ps (35%), a reflection of both relatively high financial leverage, short cycle nature of US onshore spend and concentrated business models; 2) average capex cut across global IOCs is more moderate on average (13%), with the largest portion of cuts a result of: a) FID deferrals and delays to large-project spend, b) exploration spend, or c) downstream investment, none of which have any impact on crude production in the next 2-3 years. Further, dollar strength has offset, or partially offset the fall in crude prices in many parts of the world, none more evident than in Russia, where YoY activity levels are nearly flat in Roubles, despite the fall in crude. While certainly a limited cross section of global supply, these trends are largely validated by corporate level guidance across the largest global IOCs (XOM, CVX, COP, BP, RDS, TOT, ENI, STO), where a 13% reduction to 2015 capital spend was accompanied by a negligible reduction to 2017 production forecasts. Spending by Petrobras (PBR, covered by DB analyst Alexander Burgansky) will also be closely monitored given Brazil's role in driving nonOPEC production growth. During their late April presentation, PBR noted that they would be reducing 2016 capex spend by —40% from prior guidance and with speculation that long-term spend may also be slashed, the June budget presentation will have implications on the Call on US onshore growth. While this cycle clearly has differences, the trends to capital are consistent with those seen during 2008-2009, where brownfield capex as a share of total budgets increased materially as capital budgets were reduced. Deutsche Bank Securities Inc. Page 15 EFTA01411467 31 May 2015 Integrated Oil US Integrated Oils Figure 26: Greenfield spending will undoubtedly be challenged through 2015; however, offshore short-cycle brownfield spending is expected to be curtailed far less 100 120 140 160 180 20 40 60 80 0 Greenfield CAPEX Brownfield CAPEX 2014 offshore upstream CAPEX Exploration CAPEX 153 Figure 27: While a new deeper trough in Greenfield spending is expected this time around, it's worth noting that prior cycle's SUBSEA demand fell only —7% as brownfield activity replaced greenfield 77 63 10 15 20 25 30 35 40 0 5 2006 Engineering 2007 Equipment 2008 Services 2009 2010 SURF 2011 Share of brownfield In 2009/10 subsea demand only fell —7% as the share of brownfield picked up EFTA01411468 30% 32% 34% 36% 38% 40% 42% 44% Source: Re-printed from our European Oil Service counterparts April 9 publication th Source: Re-printed from our European Oil Service counterparts April 9 publication th In our view, brownfield spend is likely to benefit from local currency devaluations. If we look at Norway as a example, our FX team forecasts a NOK to USD exchange rate of 8.2 for 2015 a drop of —25% in the value of the Krone YoY. If we assume that 20% of spend in the NCS is denominated in local currency (a rough estimate used by Wood Mackenzie for offshore fields driven chiefly by labor costs) the FX tailwinds from the devalued NOK will contribute -4% of a targeted 20% (as an example) reduction in capital spend. For illustrative purposes if the NOK comprised —80% of NCS spend then the devaluation would contribute —15% of the targeted 20% reduction. For onshore fields with material local content requirements (i.e. Russia), Wood Mackenzie places the % of spend denominated in local currency closer to 80%. Figure 28: Stronger dollar to soften spending declines — An illustrative example using the NOK (assumes target 20% $USD capex cut from 2014) Spend reduction required (excl FX effects) 20% 15% 10% 5% 5% 0% 0% 10% 20% 30% 40% % of Spend Denominated in Local Currency Source: Deutsche Bank, Wood Mackenzie, Above Analysis Assumes Target 20% YoY Capex Cut to NCS Spend 80% 20% 18% 16% 14% 13% Reduction in Spend from FX Tailwind EFTA01411469 Page 16 Deutsche Bank Securities Inc. % Change in spend YoY ($USD) $ billions EFTA01411470 31 May 2015 Integrated Oil US Integrated Oils Figure 29: Aggregate DB Global Coverage Universe Company Capital Spend YoY % Chief Operating Region US Based PDC Continental Concho Range Bonanza Creek RSP Permian Hess Freeport-McMoRan Murphy ConocoPhillips Occidental Chevron Pioneer Apache WPX Devon Magnum Hunter EOG Marathon Noble Energy Cabot Newfield SM Energy Antero Bill Barrett ExxonMobil Oasis Southwestern Anadarko Canada Encana Europe 2511 2100 The following estimates only include upstream operations 2020 Tullow Total OMV Shell BG BP Statoil EFTA01411471 Eni Latin-America 1900 26200 4680 33280 8500 23100 19200 €12600 23400 3300 32520 6500 19900 17900 €11900 The following estimates only include upstream operations 5700 Ecopetrol Petrobras Pacific Rubiales Asia, ex China Santos Woodside Oil Search BHP Billiton Russia Gazprom Lukoil Rosneft Surgutneftegaz Tatneft Bashneft West Africa Cobalt Kosmos 829 531 850 800 3% 51% 23-Feb-15 23-Feb-15 Todd Todd While headline capital budget remains roughly unchanged from 2014; appraisal and development make up a larger portion with Cameia (Angola) expected to be sanctioned by YE15 and first oil in 2018 Over 60% of 2015 spend mix toward Ghana (Jubilee, TEN) EFTA01411472 Source: Deutsche Bank, Wood Mackenzie, Total company spend unless otherwise stated, spend is expressed in $USDMM unless otherwise specified 7013 13974 14337 4474 1613 1282 5400 10900 11900 3400 1000 1000 -23% -22% -17% -24% -38% -22% Kushnir Kushnir Kushnir Kushnir Kushnir Kushnir 3067 971 1869 4000 1786 1160 620 2000 -72% 16% -201% -100% 11-Dec-14 18-Feb-15 24-Feb-15 19-Jan-15 Hirjee Hirjee Hirjee Young 2015 capex declines primarily due to up-coming start-up of flagship GLNG project (90% complete end 2014), after commissioning of PNG LNG in 2014, FID deferrals, and slower ramp-up of growth projects under development 2015 capex increase due to Wheatstone LNG capex commitments EFTA01411473 2015 capex declines following commissioning of flagship project PNG LNG in 2014 Company has guided to a reduction in US onshore spend from $3.4Bn in FY15 to $2.2Bn in FY16 While no formal announcements have yet been made with regard to capex cuts as a result of the oil price decline, DB expects that many companies will either keep spending levels unchanged in RUB terms or modestly increase them. On a USD-denominated basis, spending is anticipated to be —20-25% lower. 4700 24500 2000 22300 900 -16% 25-Feb-15 Silverstein In the Permian expecting to operate 4-6 horizontals and 4-6 verticals and 2-3 rigs in the Eagle Ford and 3 and 2.5 in the Montney and Duvernay Exploration likely falling by 20-30% with few material greenfield projects being sanctioned from this year outside of Appomatox and the recently sanctioned Johan Sverdrup. -6% -12% -42% -2% -31% -16% -7% -6% -21% -10% -122% 15-Jan-15 20-Jan-15 29-Jan-15 30-Jan-15 3-Feb-15 3-Feb-15 6-Feb-15 18-Feb-15 Robinson Capex guidance for year at $1.9Bn Herrmann Bloomfield Herrmann Herrmann Herrmann Bloomfield Bloomfield Confirmed 2015 capital spend of — $20bn with an investment decision on Mad EFTA01411474 Dog II cloe to year-end. Signed deal with Egypt to develop the West Nile Delta gas fields in March. $5-$78n of flexibility by 2017/2018 from pre-FID projects. 2015 capital guidance intact at $18Bn (inclusive of exploration) following 1Q15 results. Guidance of Capex of €12Bn Euro. Cape Three Points was sanctioned in January. Coral LNG (Mozambique) investment decision likely by year-end 15-Dec-14 28-Jan-15 14-Jan-15 Burgansky Largely exploration-driven Burgansky Upstream capex Burgansky Largely exploration and some production facilities Delaying FID on the Majnoon field in Iraq and with a 20% reduction in unconventional spend and a re-phasing of Cardmon Creek (Canadian Oil Sands) upstream spend to trend lower per 1Q15 guidance. Key investment decisions to look out for in 2015/2016 include: Appomattox, Vito, Bonga SW, and Libra. Shell is targeting a 6% reduction in organic capital spend (pro-forma BG) in 2016, from US$42-US$43 billion to below US$40 billion on pre-tax synergies. 2015 capital spend cut to $23-$24 with reductions to brownfield spend representing a material impact. 647 4050 2300 1190 667 400 5600 3200 3433 16700 8657 37115 3200 5300 1450 5200 400 6600 5536 4880 1480 2000 1707 2500 520 38537 EFTA01411475 1430 2141 8700 473 2373 1800 722 420 400 4400 2300 2300 11500 5800 31600 1600 2200 725 4250 200 4000 3521 2900 900 1200 1045 1600 260 34000 705 1889 5650 -37% -71% -28% -65% -59% 0% -27% -39% -49% -45% -49% -17% -100% -141% -100% -22% -100% -65% -57% EFTA01411476 -68% -64% -67% -63% -56% -100% -13% -103% -13% -54% 8-Dec-14 22-Dec-14 5-Jan-15 15-Jan-15 19-Jan-15 20-Jan -15 26-Jan-15 27-Jan-15 28-Jan-15 29-Jan-15 29-Jan-15 30-Jan-15 11-Feb-15 12-Feb-15 12-Feb-15 17-Feb-15 17-Feb-15 18-Feb-15 18-Feb-15 19-Feb-15 20-Feb-15 24-Feb-15 24-Feb-15 25-Feb-15 25-Feb-15 25-Feb-15 25-Feb-15 27-Feb-15 3-Mar-15 Silverstein Expects to drill 90% of wells in the Inner/Middle Core areas, up from 67% in 2014; a 6th rig will not be added to the Wattenberg program Silverstein Decreasing op rig count from 50 to 31 by 01 (31 2015 avg); taking 8 rigs out of Bakken, 10 out of SCOOP, 1 out of other Silverstein Silverstein Silverstein Silverstein Todd Beristain EFTA01411477 Todd Todd Todd Todd Todd Todd To operate avg of 26 drilling rigs in 2015 (vs. prior 39); allocating $1.3bn D&C to DE Basin, $300mm in Texas Permian, $200mm in New Mexico Shelf Lowered 2015 budget from initial Dec; Marcellus is 95% of budget vs. 87% last year and 92% prior; cut prod to 20% vs prior 2025% Plans to complete 45-50 gross op hz wells, 30 gross op vert wells; 6 operated rigs in 2014, planning for 3.5 hz rigs and 1 vert rig in 2015 Bakken production for 2015 expected between 95 and 105; plan to run 8 rigs for the remainder of year in Bakken. Annual run-rate in capex expected to be —$3.8Bn in 2H15 Plans to run only 4 rigs in the Eagle Ford for the remaining year in 2015 Rig Count in Lower 48 dropped 60% from 2014; 6 in EF, 3 in Bakken and 4 in Permian (2 unconventional) 25 horizontal rigs (4 vertical rigs) in 1Q15; 19 in 02 and 15 in 3Q and 4Q . Total Permian production expected at 100 mboe/d in 2015 and 120 mboe/d in 2016. They had 61 uncompleted wells at year-end (exp to drill 85 and place 108 on production including 63). Could accelerate at $70/WTI Pick-up in spend YoY in US onshore Reducing hz drilling in Spraberry/Wolfcamp and EF to 16 by end of Feb (50% decline from YE14) Reducing NA rig count from 91 in Q3 to 27 by end of Feb, reduced frac crews by 50%; avg 2015 NA rig count will be 17 Silverstein Aligned capital plan to spend within cash flow; Bakken rig count to decline from 5 to 1, from 3 to 2 in SJ, from 8 to 3 in Piceance Todd Silverstein Todd Todd Todd Silverstein Silverstein Silverstein Silverstein Silverstein Todd Silverstein Silverstein Todd Plan for 0 operated rigs in Wolfcamp, 11-12 rigs in EF, will participate in 20 STACK wells; expect Canadian Oil Sands prod of 100105 mbo/d Announced a preliminary budget on 3Q14 earnings call assuming Eureka Hunter EFTA01411478 go