EFTA01411427

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 goes public (source: Magnum Hunter) and MHR will no longer have to fund its capex needs Expects to complete —45% fewer wells; reducing investment in natural gas drilling, utilizing rigs under existing commitments Plans to run 10 rigs in EF from 2Q-4Q15 and 2 rigs each in the Bakken and SCOOP/STACK through 2015 Plan for 4 rigs in the DJ, 2 rigs in the Marcellus (4 non-op rigs), and $600mm inevsted in GoM; Asdod planned for 2H15 Assumes 5 op rigs in the Marcellus (Q3 6 rigs), 4 in EF; will drill 180-190 net wells, incl 95-100 in Marcellus, 80-85 in EF ($88/bbl and $2.80/mcf) Newfield operated wells drilled in Anadarko Basin expected at 94 with production of 61 mboepd. 2015 domestic oil production —20.75 mmbls Increasing well deferrals from —45 at YE14 to —95 at YE15, completion cost reduction driven. 2015e oil production (annual) is expeted at 18.6 mmbbls vs. 16.53 mmbbls in 2014. completions. In Eagle Ford, expecting to operate 4 to 5 rigs in 2015 and make 75 In Bakken, expecting to average 3.5 rigs and make 40 gross operated completions. Revised capex down from initial budget per Q3 call; operating 14 rigs in 2015 down from 21 at YE; production growth fell 5-10% on a 33% D&C cut Laid out bull scenario of 3 rigs in DJ, 1 in UOP, capital of $475mm (expect double digit PF prod growth in 2015 from 2014 exit rate prod) Running just under 40 rigs in the US onshore exiting 1Q15. Investment spend is expected to remain less than $34Bn through 2016 and 2017 on lower oil sand investments and re-sequencing of FID decisions. Expected to complete 79 gross (63.3 net) and 2.6 net non-op wells in 2015 in the Bakken; 2015 production expected at 45-49 mboepd Planning gross well count of 540-560 (net 435-460 net) vs 2014 525 (net 412) Excludes WES. Reducing onshore rig count by 40% from 2014; deferring 125 completion until costs align with commodity prices. Liquids growth at DJ, EF, and Wolfcamp expected at 154.5, 77, and 14 mbpd at 2015 guidance Company 2014 Capex (US$M)* 2015 Capex (US$M)* Date of Change Disclosure DB Analyst DB Commentary Deutsche Bank Securities Inc. Page 17 EFTA01411479 EFTA01411480 31 May 2015 Integrated Oil US Integrated Oils Setting the stage for the next oil price spike? While current reductions to budgets may have limited impact to near-term production across much of the sector, it will certainly have a dramatic impact on long-term crude supply, with a crunch likely later this decade (2018-2020) as the impact of project deferrals takes a bite out of incremental crude supply. A quick look at global project FIDs helps put the matter into perspective. Between 2002 and 2013, the industry averaged 21 oil-targeted project sanctions a year (>5 mbpd of peak production). However, this fell to only 6 such projects sanctioned in 2014, with 2015 likely to remain in single digits. In terms of productive capacity, each year of "lost" FIDs represents an average 830Mb/d of new, annual productive capacity. Figure 30: Global project FIDs by year 10 15 20 25 30 35 40 0 5 Figure 31: Total "peak" production of FIDs by year (Mb/d) 500 1000 1500 2000 2500 3000 0 Source: Deutsche Bank, Wood Mackenzie Source: Deutsche Bank, Wood Mackenzie Page 18 Deutsche Bank Securities Inc. EFTA01411481 31 May 2015 Integrated Oil US Integrated Oils Figure 32: Near-Term FID Tracker Project Country Johan Sverdrup (Phase I) Maria Vette (ex Bream) Rosebank Cameia Norway Norway Norway UK Angola Project Type Shallow DW Shallow DW UDW Operator Statoil Wintershall Premier Chevron Cobalt Participants Prod Start Yr (Statoil 40%, Lundin 22%, Norway State 18%, Det Norske 12%, Maersk Oil and Gas 8%) (Wintershall 50%, Norway State 30%, Centrica 20%) Premier 50%, KUFPEC 30%, Tullow 20%) OMV (50%, CVX 40%, DONG 10%) (Sonangola 60%, Cobalt 40%) Bonga SW Nigeria DW Shell (CVX 20%, XOM 20%, Oando 20%, Svenska 20%, NPDC 15%, Sasol 5%) OPL 245-Etan Bosi Uge Mad Dog 2 EFTA01411482 Appomatox Shenandoah Vito Kaskida Buzios V Parque das Baleias Nigeria Nigeria Nigeria US United States United States United States United States Brazil Brazil UDW DW DW DW UDW UDW DW UDW UDW DW Eni ExxonMobil ExxonMobil BP Shell Anadarko Shell BPP Petrobras Petrobras (Eni 50%, Shell 50%) (XOM 56.25%, Shell 43.75%) (CVX 20%, XOM 20%, Oando 20%, Svenska 20%, NPDC 15%, Sasol 5%) BP (60.5%, BHP Billiton 24%, CVX 15.5%) (Shell 80%, Nexen 20%) (APC 30%, COP 30%, Cobalt 20%, MRO 10%, Venari 10%) (Shell 51%, Statoil 30%, Freeport 19%) BP (100%) Petrobras (100%) Various 2020 EFTA01411483 2018 2020 2020 2018 2024 2019 2020 2022 2025 315-380 Mb/d 50 50 80 76 Peak Prod Yr Production Commentary Plan for Development and Operation (PDO) was submitted for Phase 1 (capacity of between 315-380 Mb/d) in February. Will consist of 4 bridge-linked platforms and subsea water injection templates Concept is to connect to use subsea tieback to connect to current infrastructure. Plan for Development and Operation was submitted in May 2015 Had initially expected to FID in early 2015, now postponed so as to capture lower contracting costs Likely delayed for some time. The project had been delayed previously in 2013 by Chevron because of rising costs though the company has pointed to recent changes to the project to reduce costs. Cobalt guide is for YE15 project sanction with development drilling likely to continue until early 2016 with first oil in 2018 2020 2024 170 Shell as confirmed progress toward FID in the late 2015/early 2016 timeframe for the Bongo SW/Aparo project. The project would include the construction of a new FPSO with expected peak capacity of 225 Mb/d. WM estimates —135 Mb/d in oil production by 2022 (2 years after first oil). 2019 2024 2023 2021 EFTA01411484 2019 2020 2021 2022 2021 2018+ 2028 2025+ 2025 2023 2025 2026 2023 2027 2023 2020+ 90 >60 75 75 119 60 47 66 FPSO capacity of 150 Mb/d 100 WM assumes a start-up date of 2019. Production estimate includes Etan and nearby Zabazaba. Initially conceived as a tieback to the Erha FPSO but with successful appraisal, size of the field has increased. Exxon likely to develop in phases with a dedicated FPSO. Woodmac assumes Uge to be a standalone development with a leased 100 Mb/d FPSO BP guidance is for likely sanctioning by YE15 Shell has noted that Appomattox remains the most attractive candidate for FID in 2015 4th appraisal well being planned. 3rd appraisal well expected to spud before end of 2Q. WoodMac assumes first production will be achieved in 2021 via a dry-tree TLP with capacity of 80 Mb/d of oil. WoodMac doesn't assume FID until 2017. WM assumes field will start production in 2022 with a stand-alone spar. Currently, Petrobras has not contracted for the envisioned 5th and last FPSO for the Buzios development. Includes Baleia Ana,Itaipu, Pirambu in total WoodMac estimates that — 100 Mb/- d of production capacity to be needed with production starting in 2018 with the small Baleia Ana EFTA01411485 field; however, we note risk to a near-term production production outlook as high local requirements for these projects further cloud issues around Brazilian production. Iara Brazil UDW Petrobras Petrobras (100%) 2021 2024 135 Declaration of Commerciality filed on Dec 30, 2014; however, not yet moved towards FID (originally targeted mid-2015). Petrobras targeting first oil in 2018 vs. Woodmac in 2021 on delays associated with construction of FPSO Tengiz Projects (FGP, WPMP) Kazakhstan Onshore Tengizchevroil (CVX 50%, XOM 25%, KazMunaiGas 20%, Lukoil 5%) 2021 2024 300 TCO is expected to sanction the FGP and WPMP projects by YE2015. Woodmac expects first production in 2021: FGP will consist of two main elements: drilling more wells to raise oil production and increasing sour gas injection. Expected to lift nameplate capacity by another 260 Mb/d WPMP will serve entire field and is expected to increase long-term recovery from fields by lower pressure. Expected to contribute 50 Mb/d of oil production at peak. Pearls Kazakhstan Shallow Caspi Meruerty (Shell 55%, Kaz MunaiGas 25%, Oman Oil (20%) Source: Deutsche Bank, Wood Mackenzie, IEA, Company Reports 2020 2024 70 Wood Mackenzie estimates first production in 2020 Peak Oil Deutsche Bank Securities Inc. Page 19 EFTA01411486 EFTA01411487 31 May 2015 Integrated Oil US Integrated Oils The North Sea: A Case Study On Spend and Decline Rates In some ways, the Norwegian North Sea is representative on a small scale of larger trends across the industry over the next couple of years. After steadily declining for nearly 14 years, the combination of high oil prices, a ramp in reinvestment and a string of large development projects will see the basin hold production flat to showing slight growth through 2017. The long and winding road down... The North Sea has been synonymous in recent years with mature, Non-OPEC decline, and for good reason. Since its peak production in 2000, North Sea production has steadily declined from —6 MMboe/d to current production levels of 2.5 MMboe/d, or an average decline rate of 6%/yr. This happened despite steadily increasing capex levels. Figure 33: North Sea Oil Production 7000 6000 50000 5000 40000 4000 30000 3000 20000 2000 10000 1000 0 2000 UKCS Source: Deutsche Bank, IEA 2002 NCS 2004 2006 Other 2008 2010 North Sea Capex 2012 2014 2016E 0 60000 Despite multi-year trends, two important things are driving a dramatically different outlook over the next 2-3 years: 1) elevated level of growth barrels due to start from major projects, and 2) moderation in underlying decline EFTA01411488 rate. Here come the projects After years of inconsistent development, aggressive spend on the back of 4-5 years of elevated crude price is now bearing fruit, with -650 mbpd of incremental crude expected from 2015 through 2017. This is compared to 35 mbpd of average annual "new project" production between 2009-2013. While reduced capital budgets may provide a moderate haircut to base production over the next couple of years, this is more than offset by the scale of new projects starts. Page 20 Deutsche Bank Securities Inc. Oil Production (mboe/d) - in 2014 $USD EFTA01411489 31 May 2015 Integrated Oil US Integrated Oils Figure 34: Norwegian North Sea — Incremental Project Growth Barrels 100 120 140 160 180 200 20 40 60 80 0 2009 2010 2011 Source: Deutsche Bank, Wood Mackenzie, includes Ekofisk II 2012 2013 2014 2015 2016 Taking a closer look at decline While current reductions to capital budgets will eventually show up in underlying decline of mature assets (ie. reductions to infill drilling, workovers, and other decline mitigation expenditure), significant re-development spending in 2013/2014 will soften the decline of several key fields in the nearer- term. Adjusting for growth projects (ex redevelopment activity) and after normalizing for maintenance impacts over the last few years, we estimate that decline rates on mature assets have decreased from a 5 year peak of -12% in 2011 to -6.5% in 2014. The peaking of decline rates in 2011 followed a cut of 17% in YoY dollar-adjusted investment spending in 2010 vs. 2008. However, in our view, the sudden V-shaped recovery in crude prices during the last cycle likely placed a floor on spending cuts that would have otherwise resulted in a higher decline rate in 2011. In 2014 we estimate that decline rates on producing fields (ex-Ekofisk) reached a five-year low following an increase of —50% in development spending in 2013/2014 over the prior 4-yr average (producing fields representing —60% of this spend in 2013/2014). We forecast a normalized decline rate of 12% in the period's forecast (ex redevelopment activity which is modeled separately) during out forecast period. For every change to decline rates of 1% we estimate a production impact of 3% to our 2017 oil production estimate. In EFTA01411490 our view, the impact of project delays is mostly muted as growth projects are currently either on-stream or under development. In the following analysis, we detail our assumptions and identify the key growth drivers as well as present a framework from which to think about decline rates on the base assets. Deutsche Bank Securities Inc. Page 21 YoY Growth EFTA01411491 31 May 2015 Integrated Oil US Integrated Oils North Sea Decline Rate Framework: We construct our decline rate analysis for the underlying asset base by adjusting the actual reported monthly production numbers for growth and maintenance outliers. Specifically, we extract production contributions from growth projects and normalize maintenance outages on a monthly basis over the examined time window (we use a normalized 3% of prior year adjusted production as a normal run-rate). We then calculate the resulting annual decline and find that over the last five years decline rates peaked in 2011 at 12% following the drop-off in investment in 2010. In our view, the 12% decline in 2012 is likely understated given the Vshaped recovery in the commodity. The UK Oil and Gas industry mentions a normalized decline rate of 10% in the UKCS with moderate levels of brownfield investing, though decline-rates on mature assets could be expected to reach declines of 15%+ with minimal capital influx. In our base case we assume a gradual reversion to a more normalized declinerate of 12%. We estimate that a 1% change to our base case decline rates would impact 2017 production by 3%. In our view, a further devaluation of local currencies in the near-term, alongside capital reallocation tail-winds would present upside to brown-field investments. Figure 35: Brownfield spending has kept declines (ex new growth projects) at —10% YoY over the last 5 yrs, peaking in 2011 following a drop in prior year spending and dropping to 6.5% in 2014 on increased redeveloped activities. 2000 2200 2400 2600 2800 3000 3200 3400 3600 3800 2009 Adj Base 2010 2011 Decline Source: Deutsche Bank, Bloomberg, UK Oil and Gas, Norwegian Petroleum Directorate, Wood Mackenzie From 2010-2013 we estimate that oil decline rates (adjusting for outages and growth projects) averaged —10%; however 2014 saw a reduced decline rate of —6.5% as re-developed projects in Norway began ramping 2012 2013 EFTA01411492 Actual 2014 Page 22 Deutsche Bank Securities Inc. mboe/d EFTA01411493 31 May 2015 Integrated Oil US Integrated Oils Why the UK isn't a good proxy for Norwegian (or global Non-OPEC) production While some have looked at the UK as a cautionary tale for both the North Sea and as an example for global Non-OPEC production, we see limited read through. Like its neighbor, the UK has seen steadily declining production despite a significant increase in capital spent. However, we see a few meaningful differences: 1) fiscal policy (including the most recent tax change) has done little to encourage exploration in the region (unlike Norway), resulting in far fewer meaningful growth projects in the development queue (check the data on this), 2) aging infrastructure has become increasingly problematic (and in many cases borderline non-functioning), driving rapid increases in operating expenses and decreases in production efficiency, with increasing amounts of capital used for maintenance and asset retirement. In contrast, Norway has seen relatively limited operating cost inflation (declined in 2014), with nearly 50% of spend on producing fields free to support development drilling. Figure 36: Cost inflation and poor production efficiency have remained key themes in the UKCS... £10 £12 £14 £16 £18 £20 £0 £2 £4 £6 £8 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Average Operating Cost per Bbl Source: DECC, UK Oil and Gas, Deutsche Bank Production Efficiency 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% Figure 37: ...Leading to reductions in near-term production estimates amidst the fall in crude prices EFTA01411494 100 200 300 400 500 600 700 800 900 0 2015 2016 2017 UKCS Oil (UK Oil and Gas) - March 2014 Source: DECC, UK Oil and Gas, Deutsche Bank 2018 2019 2020 UKCS Oil (UK Oil and Gas) - March 2015 Figure 38: However, in Norway Opex ($USD/boe) inflation has been modest and declined in 2014 on exchange rate tailwinds. Figure 39: And non-development spending on currently producing fields represents —50% of current field capex 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 2009 Ordinary operating costs Modifications Maint Spend as a % of Total Opex Source: Deutsche Bank, Norwegian Petroleum Directorate Source: Deutsche Bank, Norwegian Petroleum Directorate 2010 2011 2012 Maintenance (ex wells) Other operational support 2013 Well maintenance Logistics costs 2014 38% 39% EFTA01411495 40% 41% 42% 43% 44% 45% 46% Pipelines and terminals 8% Other facilities investments 23% Development wells 49% Modifications 20% Deutsche Bank Securities Inc. Page 23 $USD/boe - 2014 USD Pricing £/boe using 2014 Pricing mboe/d EFTA01411496 31 May 2015 Integrated Oil US Integrated Oils Implied Call on the US The new, "price driven" swing producer As we stated earlier, in our view, the three most important questions in the price of crude over the next two years is: 1) Do we need US Lower 48 production to grow?, 2) How much?, and 3) what is the oil price necessary to incentivize that level of growth? Despite our view that global Non-OPEC production is not on the verge of a dramatic, capex driven decline (at least through 2017), we still see insufficient growth outside of the US to fully supply global demand growth. In short, there is a call on US Lower 48 production toward late 2016. Figure 40: The Long and Winding Road: Normalizing US Onshore Crude Supply Growth 12000 The 2-Year Path To Normalized US Onshore Crude Supply Growth... 11000 ...With —Estimated Growth of -800 Mb/d Annually In Subsequent Phase 10000 9000 8000 7000 6000 5000 4000 Modeled risks include a swing of —+/- 400 Mb/d based on +/-15% revisions to YoY IEA annual product demand growth and a 1/2% adjustment to modeled non-OPEC decline rates. 3000 For 2016, modeled downside risk includes —450 Mb/d of incremental production from Iran 2000 1000 0 2014 Year 0 2014 Onshore Production Excess Global Oil Supply Source: Deutsche Bank, IEA, Wood Mackenzie Looking for a 500 Mb/d Call on US growth starting late 2016 We define the timing around the call on US onshore growth as the point at which a sustainable need/demand for US onshore production growth is visible We anticipate material production growth from onshore producers starting late 2016 toward a 2017 call on US onshore growth of —500 Mb/d rapidly escalating toward late 2017/early 2018. We estimate the YoY demand for US onshore production to increase by —700 Mb/d in 2018 prior and to average over 1MMb/d in 2019 and 2020 as non-OPEC major project growth tapers off EFTA01411497 on anticipated spending reductions over the next 2-3 years. Year 1 YoY Demand Growth Base Decline 2015E Year 2 Growth From "Other Bbls" 2016E 2017E 2018E Years 3-6 Call on US Onshore Crude Production (Base) 2019E 2020E Page 24 Deutsche Bank Securities Inc. Implied Call on US Onshore Crude Supply (mboe/d) EFTA01411498 31 May 2015 Integrated Oil US Integrated Oils Figure 41: Incremental Demand for US Onshore Crude Expected To Emerge Late 2016 (vs. 2Q15 Production)... 1500 1000 500 0 100 200 300 400 500 600 -500 -1000 -300 -200 -100 0 -42 -230 1Q16 -1500 2Q16 3Q16 4Q16 1Q17 531 342 149 Figure 42:..Forward rolling 12 mo call on US onshore production growth (vs 1Q16 production) positive in 2H16 Source: Deutsche Bank, Wood Mackenzie, IEA Source: Deutsche Bank, Wood Mackenzie, IEA The call on US crude production growth (—500 Mb/d) is decomposed as follows: 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. Figure 43: We estimate the call on annual US onshore crude growth at —500 Mb/d in 2017 and increasing to —1MMb/d by 2019/2020 200 400 600 EFTA01411499 800 1000 1200 0 2017E Source: Deutsche Bank 2018E 2019E 2020E 1045 1031 723 531 Deutsche Bank Securities Inc. Page 25 Annual Change/Growth (Mb/d) call on US Crude vs. 2Q15 Production (mbpd) 12 Mo Rolling Call on US onshore production (Mb/d) EFTA01411500 31 May 2015 Integrated Oil US Integrated Oils Methodology: Our implied call on US onshore crude growth (in the base case) builds on two critical macro assumptions: IIGlobal product demand is assumed to grow —1.15 MMb/d in 2015 and 1.2 MMb/d in 2016 with average annual growth of —1.15 MMb/d from 2017-2020. Our demand growth assumptions are based on IEA estimates and compare to —650 Mb/d of demand growth in 2014. IIOPEC production (ex Angola) is assumed flat to 2014 levels in our forecast. This assumption is admittedly 'rosier' than would otherwise be implied from recent production levels (-31.6 MMb/d or +1100 Mb/d higher than our assumed base case vs. May 2015 levels) or from a qualitative weighting of both upside and downside risks (with Iran the most visible/pronounced risk). Please see section on OPEC risks on page 33 of the note for brief commentary around OPEC. Guided by the highlighted assumptions above, our call on US onshore crude growth starts by removing non-crude growth contributions (NGLs, Biofuels, etc.) from assumed global demand growth to obtain a proxy for global crude demand that is then analyzed against our global crude supply build up. In our base case, we assume no pick-up in rig activity in the US L48 in 2016. Figure 44: Deconstructing the 500 Mb/d Call on US onshore growth in 2017 NGL Demand 2016 Supply Overhang 1200 Product Demand Growth, net of overhang 1000 967 800 24 600 175 531 400 Crude Demand Growth (in excess of Prod) 96 29 119 Biofuel, Processing Gains Global NGL Prod growth OPEC Crude Prod Growth EFTA01411501 Non-OPEC Crude Prod Growth Growth (in excess of Prod) 200 0 -200 -235 -400 Source: Deutsche Bank, Wood Mackenzie, IEA, OPEC crude production growth is from Angola which we model out separately unlike the rest of OPEC Page 26 Deutsche Bank Securities Inc. Annual Change in Mb/d (except for Supply Overhang) EFTA01411502 31 May 2015 Integrated Oil US Integrated Oils Incentivizing the US producer As mentioned previously, the 500 Mb/d call on US onshore growth in 2017 will begin to ramp in the 2H16. We estimate that as early as late 2016 —350 Mb/d of US onshore crude production will be needed vs. 1Q16 production levels. Assuming the need for an incremental 350 Mb/d of YoY growth in US Lower 48 oil production starting in the 2H of 2016 there is a clear need for WTI price to incentivize incremental activity. While US onshore production has continued to climb in the first half of 2015 as producers have decelerated from high 2014 exit rates, we expect that production will peak in 2015, with 2H15 trending slightly lower. In the absence of incremental activity, we anticipate that 2016 crude production growth in the Lower 48 would be down 200 Mb/d YoY. In order to incentivize a resumption in drilling activity sufficient to generate this level of growth, we estimate the need for WTI at $65-$70/bbl. While some have pointed to single well economics as a justification for why growth/- returns could work at $50 or $55/bbl, we believe corporate level cash flow will be the determining factor for go forward activity levels. Figure 45: 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 In order to estimate the oil price necessary to support the proper level of corporate cash flow, we made the following assumptions: 1) well costs 20% lower than late-2014 vintage cost estimates, 2) 1Q15 operating cost assumptions, 3) base case assumes capex in line with 2016 operating cash flow (CFO), 4) 2016 volume growth at 35% of pre-collapse growth rate (ie. price necessary to support —350 Mb/d in the US vs. the prior pace of —1,000 Mb/d). Within these constraints, companies in our coverage universe averaged an average need of $60 - $85/bbl to restart and maintain the onshore "growth machine". There is clearly a large degree of uncertainty surrounding this number, driven both by varied preferences of individual companies and EFTA01411503 significant uncertainty around the eventual scale and pace of efficiency and productivity gains. From a matter of timing, we see the need for a moderate increase in activity levels beginning in the third quarter of 2015. Given the general preference for Deutsche Bank Securities Inc. Page 27 $72 $61 $/bbl (WTI) EFTA01411504 31 May 2015 Integrated Oil US Integrated Oils pad drilling and the inherent lag in bringing pad-drilled wells onstream, we estimate that the initial signs of a production impact of rigs added in 3015 will most likely not show up until early 2016. In other words, if we are to generate a meaningful level of growth by 2H16, rigs need to be added in 30 or 40 2015. Amongst large producers, Pioneer Natural Resources (PXD) has been most vocal about plans to add rigs mid-2015, but various other large operators, including EOG, OXY, NBL, etc. have suggested as much by late 3Q, early 4Q. Figure 46: Breakeven oil price by play, including sensitivity to decline from late-2014 well costs 100 10 20 30 40 50 60 70 80 90 0 -25% -10% Base Case Source: Deutsche Bank, *breakeven assumes at a 10% cost of capital While the amount of rigs necessary to support this level of growth is highly dependent on the level of efficiency gains that we see across the sector, we estimate that would argue for an incremental 75 to 100 rigs, or an 20% increase from mid-2015 trough level of -450 for unconventional oil-directed horizontals. We expect that the outlook is likely to remain volatile, with prices likely to overshoot to the upside, and with the potential for producers to accelerate too soon and further oversupply the market. Page 28 Deutsche Bank Securities Inc. EFTA01411505 31 May 2015 Integrated Oil US Integrated Oils Updated Equities Outlook Getting a Bit Defensive Given the relatively cautious medium-term oil price outlook, our preference remains largely for names whose combination of asset quality and balance sheet allow them to support moderate, capital efficient growth within a moderate oil price environment. We upgrade OXY to BUY and downgrade HES to HOLD (additional color within). Other preferred names include MRO, DVN, EOG. Figure 47: Key metrics for the group 4Q15E Annualized spend APA APC COP DVN EOG HES MRO MUR NBL OXY PXD ($mm) 160 (622) (1,840) 248 (368) (958) (487) (880) (189) 114 (59) Source: Deutsche Bank We provide two scorecards (Figure 48) for the two types of investors — ones favoring a relatively defensive positioning (which we favor) and ones playing an oil price bounce. Although several key investment attributes, such as select qualitative drivers (e.g. near-term catalysts), NAV-based valuations, etc fall outside of the scope of this exercise, we use the scorecards to help frame our view on stock-specific calls. When stacking up the names by focusing mostly on key metrics for a defensive positioning — 4Q15 annualized outspend (% of market cap), net debt/total cap, div yield, FCF yield, EV/DACF multiple, CF/DAS growth, and liquids leverage (the lower the better) — we find that OXY, MRO, APA, COP and DVN round out the top five. Interestingly, we find that MRO and OXY both EFTA01411506 stack up well (1st and 5th, respectively) in the "oil bounce" scorecard, one in which four key metrics are taking into consideration — EV/DACF multiple, headline production growth CAGR (2015-2017), CF/DAS growth (2015-2017) and liquids leverage (the higher the better). 4015E Annualized spend (% of mkt cap) -0.7% 1% 2.3% -1% 1% 5.0% 2.6% 11.5% 1% -0.2% 0% Net Debt/TC 2016E 20% 50% 31% 34% 25% 23% 23% 26% 34% 7% 15% Div Yield (Curr) 1.6% 1.3% 4.5% 1.4% 0.7% 1.4% 3.0% 3.2% 1.6% 3.9% 0.1% FCF Yield 2015E -5.7% -4.4% -6.6% -1.2% -3.1% EFTA01411507 -10.9% -7.8% -11.9% -7.9% -3.3% -1.0% 2016E -0.7% -0.9% -1.3% -1.8% -1.0% -2.8% -0.6% -9.6% -3.3% 1.8% -1.5% EV/DACF 2016E 5.5x 8.1x 7.0x 6.8x 9.8x 6.6x 6.6x 5.4x 8.3x 7.1x 13.8x 2017E CF/DAS (2015-2017) Prod'n growth ('17/'15 CAGR) 19% 5.0x 6.3x 5.8x 5.5x 7.6x 5.6x 5.5x 4.8x 7.1x 6.3x 10.2x 26% 30% 26% 41% 27% 35% 21% EFTA01411508 30% 30% 45% 2% 2% 3% 3% 7% 3% 6% 2% 15% 3% 11% Liquids Leverage (Global Oil + US NGLs) 66% 52% 57% 62% 66% 73% 69% 68% 46% 73% 73% Deutsche Bank Securities Inc. Page 29 EFTA01411509 31 May 2015 Integrated Oil US Integrated Oils Figure 48: Scorecards (Defensive and Oil Bounce) Tkr Outpsend (4Q15 annualized) OXY APA MRO COP DVN EOG PXD NBL APC MUR HES MRO PXD OXY EOG HES DVN MUR COP NBL APA APC 3 2 9 8 1 5 4 6 7 11 10 Tkr Outpsend (4Q15 annualized) 9 4 3 5 10 1 11 8 6 2 7 Net Debt/TC EFTA01411510 1 3 4 8 9 6 2 10 11 7 5 Net Debt/TC 4 2 1 6 5 9 7 8 10 3 11 Div Yield FCF Yield EV/DACF 2 6 4 1 8 10 11 5 9 3 7 4 11 2 10 7 8 3 1 5 6 9 1 3 2 6 8 EFTA01411511 5 7 10 4 11 9 7 2 4 6 3 10 11 9 8 1 5 Div Yield FCF Yield EV/DACF 2 7 1 5 9 8 4 11 7 11 6 10 3 4 10 5 3 1 6 9 2 8 CF/DAS 6 11 3 4 9 2 1 5 8 10 EFTA01411512 7 CF/DAS 3 1 6 2 7 9 10 4 5 11 8 Prod'n CAGR Liquids leverage Defensive Oil Bounce 6 10 4 7 5 3 2 1 11 9 8 4 2 6 3 8 5 9 7 1 2 7 4 9 8 6 3 11 10 5 1 4 3 2 6 1 8 EFTA01411513 5 9 18 20 22 24 30 32 33 34 37 38 42 10 11 11 7 10 33 18 32 42 30 38 24 34 20 37 21 30 15 26 25 21 17 26 37 25 21 Prod'n CAGR Liquids leverage Defensive Oil Bounce 22 15 17 21 21 21 25 25 26 26 30 EFTA01411514 37 Source: Deutsche Bank. Notes: Defensive score is calculated using the summation (equal weighting) of the following ranks (Outspend, Net Debt/TC, Div Yield, FCF Yield, EV/DACF, CF/DAS) minus the Liquids Leverage ranking (the lower the ranking, the higher the leverage). Oil Bounce score calculated based on the summation (equal weighting) of the following ranks (EV/DACF, Production CAGR, Liquids Leverage,CF/DAS). Liquids leverage represent total company oil production (global) plus US NGL production divided over worldwide production. EV/DACF, FCF yield, Net debt/- TC all based on 2016E (DBe). Production CAGR based on 2015-2017 headline growth. On a 2017 EV/DACF (APC and DVN, ex-MLP value) vs CF/DAS growth (20152017, ex hedging) basis, we find that MRO and COP look particularly cheap, with most of the other names hovering in the expected relative value territories. Figure 49: CF/DAS growth (ex hedging) vs. 2016 EV/DACF multiple 10.0x 12.0x 14.0x 16.0x 2.Ox 4.Ox 6.0x 8.0x APC APA MUR DVN OXY HES NBL COP MRO 4.Ox 2.Ox 15.00% 20.00% 25.00% 30.00% 35.00% 40 00% 45.00% 50.00% CF (ex hedges)/DAS Growth ('15-'17) Source: Deutsche Bank. Note: CF calculation strips out impact from hedging 15.00% 20.00% 25.00% 30.00% 35.00% 40.00% 45.00% 50.00% CF (ex hedges)/DAS Growth ('15-'17) Source: Deutsche Bank. Note: CF calculation strips out impact from hedging We also take a look at the ratio of forecasted exit 2015 outspend (4Q15 annualized, both excluding and including dividend obligations) relative to their 2015-2017 production CAGR (with outspend/growth as the numerator/denominator, the lower the ratio, the better). While using 4Q15 outspend levels as a rough proxy for medium-term outspend has its drawbacks (also not accounting for players with high DUC counts), we believe that in a relatively defensive oil price-minded world, this may be a ratio to consider. Page 30 EFTA01411515 Deutsche Bank Securities Inc. PXD Figure 50: CF/DAS growth (ex hedging) vs. 2017 EV/DACF multiple 12.0x 10.0x 8.Ox EOG OXY 6.Ox APA MUR APC DVN HES NBL COP MRO EOG PXD 2017 EV/DACF 2017 EV/DACF EFTA01411516 31 May 2015 Integrated Oil US Integrated Oils Overall, we find the likes of MRO, COP, DVN, OXY, and APA screening relatively well. Figure 51: Outspend and Production Growth (DBe) Summary Tkr CFO (ex WC) Capex Dividend Outspend (ann) as % of mkt cap CFO (ex WC) Capex Dividend Outspend (ann) as % of mkt cap 1Q15A APA APC COP DVN EOG HES MRO MUR NBL OXY PXD 900 1,464 2,123 1,433 1,058 482 412 275 523 1,121 334 1,407 1,666 3,332 1,593 1,546 1,237 1,151 613 919 1,675 541 94 139 910 99 92 72 142 62 64 EFTA01411517 557 6 (2,404) (1,364) (8,476) (1,036) (2,317) (3,308) (3,524) (1,601) (1,840) (4,444) (852) 10.4% 3.2% 10.8% 3.8% 4.7% 17.1% 18.8% 20.9% 10.8% 7.5% 3.7% 1,176 1,083 3,025 1,201 1,000 782 726 398 648 1,591 419 1,042 1,100 2,575 1,040 1,004 950 706 556 632 1,005 428 94 139 910 99 92 EFTA01411518 72 142 62 64 557 6 4Q15E 160 (622) (1,840) 248 (385) (958) (487) (880) (189) 114 (59) -0.7% 1.5% 2.3% -0.9% 0.8% 5.0% 2.6% 11.5% 1.1% -0.2% 0.3% Prod'n (DBe) 2015 2016 2017 485 840 487 806 576 357 439 200 332 668 201 689 608 358 456 204 402 690 219 508 EFTA01411519 872 1,582 1,644 1,670 673 720 653 377 497 209 439 712 249 Prod'n (Cons) 547 517 839 825 668 677 578 614 358 362 431 445 203 198 326 386 654 682 202 222 DBe vs Cons Growth (DBe, %) 2015 2016 2017 2015 2016 2017 16/'15 17/'16 495 -11% -6% 3% 0.4% 4.4% 894 0% -2% -2% -4.0% 8.1% 1,582 1,633 1,687 0% 1% -1% 3.9% 1.6% 701 1% 2% 3% 2.3% 4.5% 671 0% -1% -3% 5.6% 7.4% 377 0% -1% 0% 0.3% 5.2% 484 2% 2% 3% 3.9% 9.0% 202 -2% 3% 4% 2.2% 2.7% 417 2% 4% 5% 21.0% 9.1% 708 2% 1% 1% 3.2% 3.2% 238 -1% -1% 5% 9.2% 13.6% Source: Deutsche Bank. Notes: APA 2015 production adjusted for Australia, NBL figures are pro-forma for ROSE acquisition, APC and DVN capex figures are ex WES/ENLK spend respectively. Figure 52: Outspend (including div)/Prod'n CAGR ratio 10.0x 12.0x 14.0x 2.0x 4.0x 6.0x 8.0x -1.0x Figure 53: Outspend (excluding div)/Prod'n CAGR ratio 10.0x 12.0x EFTA01411520 14.0x PXD EOG APADVN OXY NBL COP APC MRO HES MUR 2.Ox 4.Ox 6.Ox 8.0x 0.Ox 1.Ox 2.Ox 3.Ox 4.Ox 5.0x 4Q15 Ann Outspend (incl div)/ (% of Mkt Cap)'/15-'17 CAGR Source: Deutsche Bank 6.Ox -2.0x OXY COP APA PXD NBL DVN MRO APC EOG HES MUR -1.0x 0.Ox 1.Ox 2.Ox 3.Ox 4Q15 Ann Outspend (ex div)/ % of Mkt Cap)'/15-'17 CAGR Source: Deutsche Bank 4.Ox Figure 54: 2017 Cash Outspend By Company 225% 181% 175% 134% 125% 125% 118% 119% 112% EFTA01411521 120% 124% 116% 110% 92% 75% 108% 122% 25% -25% APA APC DVN EOG NBL Strip -$10/bbl th PXD COP HES Strip Pricing MRO MUR Strip + $10/bbl Source: Deutsche Bank, uses May 27 strip pricing of —$69/bbl Brent and $63/- bbl WTI, includes dividends (Cash outspend defined as CFO ex WC divided by the sum of capital spend and dividend payments) OXY XOM CVX Deutsche Bank Securities Inc. Page 31 2016 EV/DACF 2016 EV/DACF EFTA01411522 31 May 2015 Integrated Oil US Integrated Oils Upgrading OXY to Buy from Hold OXY: 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% post-dividend 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). Downgrading HES to Hold from Buy 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 medium-term outspend/ FCF profile will remain in the spotlight. Page 32 Deutsche Bank Securities Inc. EFTA01411523 31 May 2015 Integrated Oil US Integrated Oils Risks to the Outlook Iran and the Rest of OPEC The above analysis rests upon the premise that OPEC (led by Saudi Arabia) will largely keep production flat with current levels. In summary, outside of a change in policy by Saudi, we see two primary risks to our near-term forecast: Iran (a potential reduction in the call on US growth by —450 Mb/d) and Iraq (risks likely weighted toward a reduction in current Iraq production levels). Longer-term growth in sustainable productive capacity from Iraq and the UAE pose the greatest risks to an increased need for US onshore crude during the tail-end of our forecast period. Iran: Holding the fate of US growth: For all of the uncertainty on both sides of the Iranian debate, the stakes are potentially enormous for US producers. An increase of even 400 Mb/d by the middle of 2016 from Iran would effectively cancel out any call on US growth in 2016 (pushing it to 2017), and with it, eliminating the need for a crude price high enough to incentivize US growth. Iran remains the main wildcard as it relates to the global 2H15/2016 oil supply picture. The recently-struck (April 2) framework agreement between Iran and the P5+1 countries was the initial key milestone before any potential final deal on Iran's nuclear program. While recent rhetoric among Iranian hardliners (Khomeini has plenty to say) and select US participants/GOP congressional members remains polarizing (parties remain wide on details such as the pace of the removal of sanctions, etc) causing some doubt, the recent letter of strong support shown by US House Democrats (150 on paper/145 voting members, just enough to sustain a presidential veto of a Congress disapproval of any final deal) have certainly increased the odds of reaching a final deal by June 30 (deadline could be moved). While the risk of a final agreement (and the resultant addition of Iranian crude barrels into the global market) is real, the key question remains Figure 55: Historical Iranian crude prod'n, 2010-April 2015 Figure 56: Iranian liquids prod'n forecast, 2011-2020E Source: Deutsche Bank, IEA. Note: crude-only production shown Source: Wood Mackenzie, Deutsche Bank. Note: Wood Mackenzie's forecast includes NGl/Condensate Deutsche Bank Securities Inc. Page 33 EFTA01411524 31 May 2015 Integrated Oil US Integrated Oils The key uncertainties around the global oil supply impact of any final agreement stem from question marks around 1) the agreed upon pace of the removal of sanctions (John Kerry suggesting 4 months to one year while the Iranians are calling for an immediately removal), 2) the actual amount of floating storage holding Iranian barrels (IEA references reports suggesting —30 mmbbl's, or 180kb/d for 6 months, Wood Mackenzie offers a smaller estimate), 3) the amount of reservoir and facility degradation in the key mature oil fields (main source of Iranian crude production) post years of underinvestment and need for secondary and FOR to boost production, and 4) the pace of IOCs involvement (list of priority 49 upstream/28 oil field projects released with formal details and the new Iran Petroleum Contract (IPC) (with much better fiscal terms than its predecessor) expected in September). While Bijan Zanganeh's (Iranian oil minister) promise of output levels of 3.8 Mb/d within 6 months of the deal (implying an increase in exports of —1 Mb/d) is on the optimistic side of forecasts (Wood Mackenzie at +450kb/d in exports in mid-2016, assuming sanctions fully lifted in mid -'16, IEA suggesting sustainable production capacity at —700kb/d above April 2015's production levels), the risk of a notable amount of Iranian crude hitting the market by end of '15/mid-'16 remains the key wildcard to our outlook. A Random Walk Through The Rest of OPEC: While this publication is not meant to address OPEC production growth in great detail, we attempt to present context around current trends and the potential risks to our outlook. Below we highlight several of the key questions (in addition to the previously discussed impact from finalizing an Iran deal) we entertained in "stress-testing" our outlook from an admittedly more abstract/qualitative angle (what else is there?). What is the potential upside to OPEC production from a return of a normalized (or should we say abnormal?). Libya devoid of conflict? While many point to 2012 production of nearly —1400 Mb/d as a starting point for quantifying a potential 'blue sky' outlook for Libya production, the country has changed significantly since the conflict first erupted in 2013. Infrastructure damage and potential degradation to field reservoir quality has resulted in a cut to the IEA estimated sustainable crude production to only 500 Mb/d for 2015. The IEA anticipates a gradual capacity creep with levels expected to reach —980 Mb/d 2020 - still short of previous levels. While not as conservative, (productive capacity estimated at —800 Mb/d for 2015) Wood Mackenzie estimates are also consistent with a view of limited upside to recent production trends out of Libya (—500 Mb/d in March and April). In our outlook we assume Libya EFTA01411525 production flat to 2014 levels of —460 Mb/d. Is the recent production burst from OPEC likely to last? During the month of May, OPEC crude production is estimated to have averaged 31.6 MMb/d (vs. 31.5 MMb/d in April) averaged or 1.5 MMb/d higher than in February. Production growth from Saudi Arabia and Iraq accounts for - 75% of the increase (— 550 Mb/d in incremental production each). The original question can be translated into: how to assess from sustained production levels from both Iraq and Saudi going forward. a) Iraq Near-Term Production Outlook Risk Likely Upper Bound: Iraq production (inclusive of exports from the Kurdish Regional Government) ramped up to an estimated 3.9 MMb/d in May, —550 Mb/d higher than 2014 levels amid strong production from Northern Iraq following the December agreement with the Kurdish Regional Page 34 Deutsche Bank Securities Inc. EFTA01411526 31 May 2015 Integrated Oil US Integrated Oils Government (KRG). As a result of the damage to pipeline infrastructure in the early part of 2014 from repeated ISIS attacks, pipeline exports from Northern Iraq averaged —185 Mb/d in 2014. Increased production from the Tawke and Taq Taq fields in Kurdistan amid the proposed financing backing from Baghdad and alongside rebuilt infrastructure, the KRG has announced a targeted pipeline export capacity/volumes of 800 Mb/d. However with current Northern Iraq export levels in excess of 600 Mb/d upside to Iraq production from the North is limited while contributions from the South remain more longterm in nature (see below section). The key driver for driving sustainability in the near-term (6-12 months) will be the extent to which Baghdad can continue to fund payments to the KRG — funds needed to pay the region's crude producers, if sustained our call on US onshore crude growth would be reduced by over 400 Mb/d. b) Saudi Production Outlook? Who knows...but our outlook looks reasonable assuming Saudi market share of global supply remains consistent with 5 year averages. With much speculation around what production level is consistent with forward Saudi strategy; our aim is not to identify a specific production level but rather to sensitize our outlook around Saudi's market share of global oil supply (a reasonable driver for Saudi production going forward). Assuming a 5 year average for Saudi market share of global oil, our call on US onshore growth remains —500 Mb/d through 2017. The US call on shore crude growth dips 200 Mb/d annually if we instead assume a forward market share similar to that in the 1H of 2014 for Saudi, and is effectively non-existent if Saudi were to maintain its current share. Figure 57: YoY Call on US Crude Growth (Mb/d) Vs. Assumed Saudi Market Share of Global Crude (%) 100 200 300 400 500 600 700 800 900 1000 -100 0 2017 2018 Base (Holds Saudi Prod Flat to 2014 Levels) w/ Saudi Supply at 1H14 Global Market Share Source: Deutsche Bank, IEA 2019 w/ Saudi Supply at 5 Yr Avg Global Market Share w/ Saudi Supply at Current Global Market Share EFTA01411527 Deutsche Bank Securities Inc. Page 35 Call on US Onshore Growth (Mb/d) EFTA01411528 31 May 2015 Integrated Oil US Integrated Oils What is expected long-term from OPEC? Outside of Iran and volatility around Saudi, the longer-term environment will be dictated chiefly by anticipated production capacity increases by both the UAE and Iraq. The UAE has set a target of 3.5 MMb/d by 2020 or —600 Mb/d above current estimated capacity levels. Adnoc has mentioned in the press that it would invest —$25Bn to develop some of its offshore fields and seems driven to meet its target production goal. In Iraq, the IEA estimates that production capacity is to increase —1000 Mb/d by 2020 from currently estimated capacity levels. However, commentary from companies like Lukoil and BP suggest that there may be downside risk to the estimate as significant investment is required in Iraq's southern oil fields particularly with regard to water injection and gas infrastructure projects. While IOCs have invested heavily in the country over the last couple of years, the extent to which they will continue to sustain investment will (at least theoretically) be linked to Baghdad to re-pay producers for work done (while simultaneously maintaining the country's security against threats from ISIS and other militant groups) Figure 58: Longer-term, Iraq and UAE are expected to drive OPEC capacity increases 500 1000 1500 2000 -1000 -500 0 Iraq 2015 2016 2017 2018 2019 2020 Libya Source: Deutsche Bank, IEA UAE Other Net OPEC Growth in Production Capacity Page 36 Deutsche Bank Securities Inc. Mb/d EFTA01411529 31 May 2015 Integrated Oil US Integrated Oils Other Risks to the Outlook Global oil demand and Decline Rates Our base case assumes global product demand growth of 1.2 Mb/d in 2016 and 2017. To date in 2015, demand has generally surprised to the upside, with gasoline demand growth in the US (+2% YoY) stronger than anticipated, while Europe and Asia have also shown surprisingly robust growth. 1096+ incremental upside to YoY product demand growth results in a —+100 mbpd increase in the 2017 implied call on US onshore crude growth. On decline rates, we assume an average global decline rate of 1/4%/yr. We estimate a swing of 150 mbpd in the 2017 implied call on US onshore crude growth call for each 1/4% change in modeled decline rates (ex-US onshore and OPEC and compounded from 2015+) Figure 59: 2017 Call on US Crude Onshore Growth (YoY) 834 100 200 300 400 500 600 700 800 900 0 Bear 1/4% Rev to Modeled Decline Rates Base Bull 15% Adj to YoY Demand Growth Source: Deutsche Bank, Wood Mackenzie, IEA, EIA, YoY Growth is calculated as the implied 2017 Call on US Onshore Production — Dbe 2016 US Onshore production. Revisions to modeled decline rates only applies to those regions we have specifically modeled out in this note and excludes US onshore, and OPEC production aside from Angola. Figure 61: A +5% premium to '17 demand growth increases implied onshore crude growth by —50 mbpd 100 200 300 400 500 600 700 800 900 EFTA01411530 0 -30% -10% 10% 30% Source: Deutsche Bank, Wood Mackenzie, IEA, EIA, YoY Growth is calculated as the implied 2017 Call on US Onshore Production — Dbe 2016 US Onshore production. Revisions to modeled decline rates only applies to those regions we have specifically modeled out in this note and excludes US onshore, and OPEC production aside from Angola -1.0% -0.5% Figure 60: 2020 Call on US Crude Onshore Growth (YoY) 531 228 200 400 600 800 1000 1200 1400 1600 0 Bear 1/4% Rev to Modeled Decline Rates Base Bull 15% Adj to YoY Demand Growth Source: Deutsche Bank, Wood Mackenzie, IEA, EIA, YoY Growth is calculated as the implied 2020 Call on US Onshore Production — 2019 Call on US Onshore Production. Revisions to modeled decline rates only applies to those regions we have specifically modeled out in this note and excludes US onshore, and OPEC production aside from Angola. Figure 62: A +1/4% revision to modeled Non-OPEC decline rates increases implied onshore crude growth by —150 mbpd in 2017 over our base case 200 400 600 800 1000 1200 1400 -200 0 0.0% EFTA01411531 0.5% 1.0% Source: Deutsche Bank, Wood Mackenzie, IEA, EIA, YoY Growth is calculated as the implied 2017 Call on US Onshore Production — Dbe 2016 US Onshore production. Revisions to modeled decline rates only applies to those regions we have specifically modeled out in this note and excludes US onshore, and OPEC production aside from Angola. 1428 1031 630 Deutsche Bank Securities Inc. Page 37 Call on US Onshore CrudeGrowth (mboe/d) Implied Call on Onshore Growth (YoY, Mb/d) Call on US Onshore CrudeGrowth (mboe/d) Implied Call on Onshore Growth (YoY, Mb/d) EFTA01411532 31 May 2015 Integrated Oil US Integrated Oils Crude inventory overhang One of the lingering challenges in tightening global crude balances, and thus pricing, is the significant crude inventory overhang, with estimated OECD crude inventories currently at 1030 MMbbls (excluding gov't stocks), or 45% above the 5 year average. We anticipate crude inventory levels to increase though mid 2016 as increasing non-OPEC supply is brought on-stream and as US onshore production gradually adjusts to a new 'normal'. The pace of inventory builds is anticipated to peak in 2Q15 with inventory levels anticipated to dip modestly in 4015 prior to heading into weaker seasonal demand in the 1st half of 2016. At its peak (in 2016) 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) low commodity driven demand growth and lower product inventory levels will largely mitigate against the risk. Figure 63: Though global crude inventory levels are expected to increase during the correction, we aren't headed anywhere we haven't already been... 2000 -16000 -14000 -12000 -10000 -8000 -6000 -4000 -2000 0 Source: Deutsche Bank, IEA, Implied global crude stock builds Figure 64: OECD total products days forward metrics reveal historically low inventory levels/ability to absorb excess crude 27.5 28.0 28.5 29.0 29.5 30.0 30.5 31.0 31.5 32.0 1Q 5 Yr Range 2Q 3Q 2014 EFTA01411533 40 Source: Deutsche Bank, Wood Mackenzie, IEA While current OECD crude inventories are —45% of 5 yr averages, product inventories are essentially flattish to historicals offering some potential relief to the crude overhang. Further we would note that looking at absolute inventory levels without regard to the role of demand trends as incomplete. Looking historically at incremental QoQ global product demand growth vs. implied crude inventory builds, we find that movements in global crude stocks closely led those in product demand (by a quarter) in the data set we looked at. Further, when adjusting for demand, OECD product inventories look more poised to potentially absorb increasing crude stocks as the IEA estimates product growing annually by —1200 mbpd. Page 38 Deutsche Bank Securities Inc. Cumulative Change in Implied Global Crude Stocks since 2006 (mbpd) EFTA01411534 31 May 2015 Integrated Oil US Integrated Oils Figure 65: Correlation of QoQ Changes in Product Demand and Implied Crude Inventory Builds 1,000 1,500 2,000 2,500 500 -3,000 -2,500 -2,000 -1,500 -1,000 -500 0 Change in Demand Change in Stocks -1Qtr Lagged Source: Deutsche Bank, IEA Non-OPEC Supply Disappointment 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. The most visible risk surrounds Brazilian production. While the pre-salt basin resource is excellent, the ability to exploit it will be challenged amid the fall-out from the "Lava Jato" scandal and from significant local content requirements for key projects. With 2016 capital spend already reduced by 40% from prior guidance (and estimated delivered FPSOs in 2016 reduced to 3 from7) on the company's latest presentation there is significant risk to the growth story. Please see page 43 for more details on Brazil. Figure 66: IEA Non-OPEC supply projections (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 EFTA01411535 2015 2009 Month IEA Forecast was Made Source: IEA, Deutsche Bank Deutsche Bank Securities Inc. Page 39 mboepd 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 EFTA01411536 31 May 2015 Integrated Oil US Integrated Oils A Country by Country Outlook on Key Players Angola Recent pre-salt drilling activity withstanding, exploration spend in Angola over the last 15 years has been largely concentrated in the Lower Congo Basin. As a result, production growth in our forecast period is chiefly driven by project start-ups in the Lower Congo. However, longer-term production growth will likely shift towards the pre-salt Kwanza Basin (Cameia. Orca, Bicuar, etc). In our view, the key near-term risk to production is a delay in the start-up of complex projects (Kaombo Block 32) while the key long-term risk is a delay in project FIDs in the Kwanza Basin (-250 mbpd of '17-20 incremental growth is from unsanctioned projects) Figure 67: Angola Production Outlook, 2014-2020e (Mb/d) 500 1000 1500 2000 0 2014 2015 Base Source: Deutsche Bank, Wood Mackenzie, IEA 2016 2017 2018 2019 Growth Bbls 2020 Figure 68: Production by type (area chart of onshore vs. shallow vs deepwater (Mb/d) 500 1000 1500 2000 0 2014 2015 2016 Onshore (Cony) Deepwater (Cony) Source: Deutsche Bank, Wood Mackenzie, IEA 2017 2018 2019 EFTA01411537 2020 Shallow water (Cony) Ultra-deepwater (Cony) Figure 69: Crude volume growth outlook by project status (Mb/d) 500 1000 1500 2000 2500 0 2014 Base Under Development DB Base Case Source: Deutsche Bank, Wood Mackenzie, IEA 2015 2016 2017 2018 2019 Growth at Onstream Assets Probable Development 2020 Figure 70: 2017 Production Swing (Bear vs. Bull) of —235 Mb/d 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 1771 1641 1536 Bear Base 6mo timing shift in growth projects Source: Deutsche Bank, Wood Mackenzie, IEA 1% adj in decline rates Bull Page 40 Deutsche Bank Securities Inc. mboe/d EFTA01411538 31 May 2015 Integrated Oil US Integrated Oils Primary Growth Drivers Near-term production growth will be supported by several project start-ups. The recent (and worth noting 'on schedule') starts of the Kizomba Satellites Phase 2 and Block 15/06 West Hub Development projects in 2Q15 are the chief drivers of 300 mbpd of crude growth through 2017. The long-term production outlook will be driven by the ramp from fields in the Kaombo Block 32, and contributions from currently unsanctioned projects (Cameia). Primary Risks Geopolitical risks withstanding, the key risks to production in our forecast window include a delay to project start-ups particularly the ramp from the Block 32 fields (projected on stream in 2017), and the delayed sanctioning of several projects including the high profile Cameia project (anticipated late 2015 FID with peak oil production by 2018 of 80 mbpd). IIProject Delays: Through 2017, primary risk is in delays to the starts of two key projects: Block 15 NE Hub and the Kaombo Block 32. Although largely in process, there could be limited risk of delays associated with cost reduction efforts in the current environment. Incremental production from the Kaombo fields in Block 32 (2017 target project start) is expected to reach a peak capacity of —230 mbpd by 2020. Deep water depths, dispersion of fields, and high presence of salt imaging has the potential for increased technical risks. IISanction Delays: Including Cameia unsanctioned projects represent nearly all the incremental crude production from 2017 to 2020. Cost reduction will be a significant driver of accelerated FID activity; Cobalt is currently estimated Cameia YE15 sanction on estimated development costs of <$20/bbl and assumed $2Bn in estimated cost savings. Figure 71: Key Growth Projects, 2014-2020 Project IEA Region Kizomba Satellites Phase2 Block 15/06 NW Hub Mafumeira Block 32 Kaombo Block 15/06 NE Hub Block 21 Block 18 West Block 31 Southeast Block 32 Central NE Orca Africa Africa Africa Africa Africa EFTA01411539 Africa Africa Africa Africa Africa Sector Deepwater Deepwater Offshore Cabinda Ultra Deepwater Deepwater Deepwater Deepwater Ultra Deepwater Ultra Deepwater Deepwater Basin Lower Congo Lower Congo Lower Congo Lower Congo Lower Congo Kwanza Lower Congo Lower Congo Lower Congo Kwanza Operator ExxonMobil Eni Chevron Total Eni Cobalt International Energy BP BP Total Cobalt International Energy Project Type DW DW Shallow UDW DW UDW UDW UDW UDW DW Dev Status Under Development EFTA01411540 Onstream Onstream Under Development Under Development Under Development Probable Development Probable Development Probable Development Probable Development API 27.5 23.6 36 32 34 44 32 32.5 33 36 Prod Start Up Yr Peak Prod Yr 2014-2017 Prod 2015 2014 2009 2017 2016 2017 2019 2020 2020 2020 2020 2016 2018 2020 2018 2024 2025 2022 2022 2022 108 83 62 40 39 10 0 0 0 0 EFTA01411541 2014-2020 Prod 177 52 64 214 67 100 45 41 28 22 Source: Deutsche Bank, Wood Mackenzie Deutsche Bank Securities Inc. Page 41 EFTA01411542 31 May 2015 Integrated Oil US Integrated Oils Brazil Through 2017, no country has a greater ability to impact the outlook on NonOPEC production growth than Brazil, which after years of delays, has begun generating meaningful growth from the Pre-Salt. Although we have haircut our outlook significantly, given the upheaval caused by the combination of lower oil price and political/corporate scandal, Brazil still represents nearly 400 Mb/d of production growth by 2017 (vs. 2014). See outlook and risks below. Figure 72: Brazil Production Outlook, 2014-2020e (Mb/d) 500 1000 1500 2000 2500 3000 3500 0 2014 2015 Base Source: Deutsche Bank, Wood Mackenzie, IEA 2016 2017 2018 2019 Growth Bbls Source: Deutsche Bank, Wood Mackenzie, IEA 2020 Figure 73: Production by type (area chart of onshore vs. shallow vs deepwater (Mb/d) 500 1000 1500 2000 2500 3000 3500 0 2014 Onshore 2015 2016 Shallow 2017 2018 Deepwater 2019 EFTA01411543 2020 Ultra-deepwater Figure 74: Crude volume growth outlook by project status (Mb/d) 500 1000 1500 2000 2500 3000 3500 4000 4500 0 2014 Base Under Development DB Base Case Source: Deutsche Bank, Wood Mackenzie, IEA 2015 2016 2017 2018 2019 Growth at Onstream Assets Probable Development 2020 Figure 75: 2017 Production Swing (Bear vs. Bull) of —300 Mb/d 1500 1700 1900 2100 2300 2500 2700 2900 2830 2678 2550 Bear Base 6mo timing shift in growth projects Source: Deutsche Bank, Wood Mackenzie, IEA 1% adj in decline rates Bull Page 42 Deutsche Bank Securities Inc. mboe/d EFTA01411544 31 May 2015 Integrated Oil US Integrated Oils Primary Growth Drivers Volume growth from 2015-2020 is primarily driven by the continued development of Pre-Salt resource in the deepwater Santos and Campos Basins. In particular, near-term volume growth is expected to come from the start of FPSOs in the Buzios and Lula/Iracema development. Development at Lulalracema (the largest driver of growth through 2017) entails a total of 10 FPSOs (8 in Lula, 2 in Iracema). 3 FPSOs are currently in operation and 7 additional FPSOs will be required for development (150 Mb/d of capacity each), 4 of which are replicant FPSOs being constructed in Brazil. Primary Risks Project execution, already problematic in recent years given the combination of technical challenges and local content requirements, have become particularly acute given the collapse in oil price and corruption scandal affecting both Petrobras and the Brazilian government. We see two primary risks: 1. Weak oil price and uncertain investment environment could impact investment in the base (ie. maintenance capital), increasing the underlying decline at the 2.4 MMb/d of current production. We see this risk as slightly less acute than some basins heavily dependent on maintenance/infill capital spend (ie. UK North Sea/Norway), however every 1% increase in underlying decline above our 8%/yr base case would reduce 2017 production by 40 Mb/d. 2. Delays to FPSO start-ups. We see a high likelihood of material delays in the start-ups of future FPSOs, particularly the 4 replicant FPSOs being constructed in Brazil with targeted start-ups in 2017-2018 (Lula South, Lula North, Lula Extension, and Lula West — P-66, P-67, P-68, P-69). We have risked project starts in proportion to local content requirements (Buzios, Taratuga Verde), assuming an average 2-year delay in targeted first oil. We model an estimated —225 Mb/d of incremental production through 2017 from the arrival of 4 FPSOs through (2 in each 2016 and 2017); the modeled production contribution increases to over 900 Mb/d by 2020. Figure 76: Key Growth Projects, 2014-2020 Project IEA Region Lula-Iracema Latin America Sapinhoa Papa-Terra Roncador Frade Cachalote BS-4 Lapa Buzios Iara Latin America Latin America EFTA01411545 Latin America Latin America Latin America Latin America Latin America Latin America Latin America Country Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Source: Deutsche Bank, Wood Mackenzie Sector Santos Santos Campos Campos Campos Campos Santos Santos Santos Santos Operator Pet rob ras Pet rob ras Pet rob ras Pet rob ras Chevron Pet rob ras Queiroz Galvao Pet rob ras Pet rob ras Pet rob ras Project Type UDW UDW DW UDW DW DW UDW UDW UDW EFTA01411546 UDW Dev Status Onstream Onstream Onstream Onstream Onstream Onstream Probable Development Onstream Under Development Under Development API 27 30 14 24 20 24 14 26 28 26 Prod Start Up Yr 2009 2010 2013 1999 2009 2008 2016 2011 2016 2018 Peak Prod Yr 2014-2017 Prod 2014-2020 Prod 2022 2016 2017 2018 2017 2018 2019 2020 2023 2026 381 171 96 79 EFTA01411547 54 32 30 28 0 0 777 171 55 55 15 12 63 85 300 50 Deutsche Bank Securities Inc. Page 43 EFTA01411548 31 May 2015 Integrated Oil US Integrated Oils Canada Volume growth will be primarily driven by expansions to existing oil sands projects with a handful of projects (Kearl, Surmont, Horizon, Foster Creek, AOSP, Sunrise) accounting for -60% of the estimated 2014-2017 production growth. With falling oil prices accelerating a decline in capital spending (with some operators announcing reductions in excess of 75% to their budgets from 2014); the longer-term (2017+) production impact resulting from subsequent project delays represents in our view the primary risk. However, we would not want to underscore the risk to production that stems from a regulatory/- political environment in which efforts to resolve infrastructure bottlenecks have been challenged. We view the near-term risk to production from the commodity to be mostly contained as US production-roll off in 2H15 alongside seasonal demand uplift to support a moderately constructive view on crude prices. Figure 77: Canada Production Outlook, 2014-2020e (Mb/d) 1000 2000 3000 4000 5000 0 2014 2015 Base Source: Deutsche Bank, Wood Mackenzie, IEA 2016 2017 2018 2019 Growth Bbls 2020 Figure 78: Production by type (area chart of onshore vs. shallow vs. deepwater (Mb/d) 1000 2000 3000 4000 5000 6000 0 2014 2015 2016 2017 2018 2019 EFTA01411549 2020 Unconventional Onshore (Cony) Shallow water (Cony) Source: Deutsche Bank, Wood Mackenzie, IEA Figure 79: Crude volume growth outlook by project status (Mb/d) 1000 2000 3000 4000 5000 6000 0 2014 Base Under Development DB Base Case Source: Deutsche Bank, Wood Mackenzie, IEA 2015 2016 2017 2018 2019 Growth at Onstream Assets Probable Development 2020 Figure 80: 2017 Production Swing (Bear vs. Bull) of —190 Mb/d (Mb/d) 3000 3200 3400 3600 3800 4000 4200 4400 4319 4201 4128 Bear Base 6mo timing shift in growth projects 1% adj in decline rates Bull Source: Deutsche Bank, Wood Mackenzie, IEA Page 44 Deutsche Bank Securities Inc. mboe/d EFTA01411550 31 May 2815 Integrated Oil US Integrated Oils Primary Growth Drivers Volume growth will be primarily driven by expansions to existing oil sands projects with a handful of projects (Kearl, Surmont, Horizon, Foster Creek, AOSP, Sunrise) accounting for -68% of the estimated 2014-2017 production growth. While mining techniques account for —20% of recoverable oil sands in Alberta, the near-term production growth profile is well-represented as Kearl, Horizon, and AOSP represent 3 of the 5 largest production contributing projects through 2017. Longer-term growth (2017+) will be driven by end of decade projects like Fort Hills and Hebron/Ben Davis. Primary Risks With falling oil prices accelerating a decline in capital spending (with some operators announcing reductions in excess of 75% to their budgets from 2014); the longer-term (2017+) production impact resulting from subsequent project delays represents in our view the primary risk. However, we would not want to underscore the risk to production that stems from a regulatory/- political environment in which efforts to resolve infrastructure bottlenecks have been challenged. We view the near-term risk to production from the commodity to be mostly contained as US production-roll off in 2H15 alongside seasonal demand uplift to support a moderately constructive view on crude prices. 1. Near-term risks to production are likely contained as US production rolls-off and seasonal demand improvements are expected to support a moderately constructive view on crude prices. At current prices/differentials rail economics remain challenged to the Gulf Coast (the most visible remaining demand market for oil sands growth) affecting smaller oil sands producers that are mostly levered toward manifest rail. However, production shut-ins are unlikely. During the previous cycle the reservoir integrity at the Great Divide project was significantly damaged as a result of operator shut-in amid low crude prices. 2. Long-term risks to production delays are likely. Intuitively, the most likely candidates for a reduction are those for which not a significant amount of capital has been invested. Companies have announced expansion delays to many of such projects including CNRL's Kirby North, MEG's Christina Lake, Husky's Sunrise and Suncor's Mackay River. Of remaining potential project delays we see greatest downside risk to project expansions at Cenovus' Christina Lake, Narrows Lake and PetroChina's MacKay River. 3. Long-term, the infrastructure bottleneck needs to be addressed. As mentioned previously, the Gulf Coast represents the last remaining market (as Western Canadian crude is for the most land-locked) that is capable of absorbing heavy crude. While recent pipeline start-ups (Marketlink and Flanagan South) have increased capacity to transport WCS bbls into the Eastern Gulf Coast, the Western Gulf Coast is not readily accessible via pipeline while rail and Jones-Act compliant vessels remain expensive particularly at a lower commodity. The Western Gulf Coast contains —60% of the entire Gulf Coast coking EFTA01411551 capacity, a lucrative reward no doubt. In fact, TransCanada has recently announced plans to investigate the economic viability of building pipe from Houston to Louisiana, we can only hope that they will have more success than they've had with a certain other proposed pipeline Deutsche Bank Securities Inc. Page 45 EFTA01411552 31 May 2015 Integrated Oil US Integrated Oils Figure 81: Though the recent recovery and narrowing of WTI-WCS has increased rail netbacks for Canadian heavies to the Gulf Coast, rail economics remain 'heavily' challenged 10.0 20.0 30.0 40.0 50.0 60.0 70.0 -40.0 -30.0 -20.0 -10.0 0.0 Jun-14 Jul-14 Aug-14 Sep-14 Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 Price Diff to Implied Bitumen Price ($/bbl) Opex Sustaining Capex Source: Deutsche Bank, Wood Mackenzie, Bloomberg, assumes 20% diluents penalty, costs shown represent an average of major SAGD projects/fields Net Back to GC No 6. (3% Sulfur) Fuel Oil Figure 82: Key Growth Projects, 2014-2020 Project IEA Region Kearl Surmont Project Horizon Project Foster Creek AOSP Sunrise Christina Lake Project Hibernia S subsea PL1001 MEG Christina Lake Jackfish Source: Deutsche Bank, Wood Mackenzie North America North America North America EFTA01411553 North America North America North America North America North America North America North America Country Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Sector Operator Athabasca Athabasca Athabasca Athabasca Athabasca Athabasca Athabasca Newfoundland Athabasca Athabasca Imperial Oil ConocoPhillips Canadian Natural Resources Cenovus Energy Shell Husky Energy ConocoPhillips HMDC MEG Energy Devon Energy Project Type Dev Status Onshore Onshore Onshore Onshore Onshore Onshore Onshore Shallow Onshore EFTA01411554 Onshore Onstream API 8 Onstream N/A Onstream Onstream Onstream Onstream Onstream Onstream Onstream Onstream 34 11 34 8 9 36 9 8 Prod Start Up Yr 2013 2007 2008 2001 2003 2015 2002 2011 2008 2007 Peak Prod Yr 2030 2018 2019 2029 2021 2025 2025 2017 2026 2029 2014-2017 Prod 138 95 89 81 EFTA01411555 68 60 51 51 47 41 2014-2020 Prod 148 109 165 121 98 60 126 28 69 41 Page 46 Deutsche Bank Securities Inc. $/bbl of Bitumen EFTA01411556 31 May 2015 Integrated Oil US Integrated Oils Caspian Sea, ex Russia Production from the Caspian Sea is largely concentrated around a few mega projects in Kazakhstan and Azerbaijan (with smaller contributions from Turkmenistan and Uzbekistan). The recent reduction (25%) in the Kazakhstan oil export duty this past March was not much of a surprise as the government had announced its intention to reduce rates in response to the lower oil price environment earlier this year. With the drop in export duty rates, the government aims to sustain longer-term production by bridging the near-term incremental production (weighted toward recovery projects) with the restart of Kashagan Phase One and ultimately growth from the currently unsanctioned Tengiz and Kashagan Phase Two projects. In Azerbaijan, the focus will be on maintaining production at the ACG contract area (-75% of 2014 country production) through the recently on-stream through the Chirag Oil Project and a renewal of the underlying PSC that is set to expire in 2024. Figure 83: Caspian Production Outlook, 2014-2020e (Mb/d) 500 1000 1500 2000 2500 3000 3500 0 2014 2015 Base Source: Deutsche Bank, Wood Mackenzie, IEA 2016 2017 2018 2019 Growth Bbls Source: Deutsche Bank, Wood Mackenzie, IEA 2020 Figure 84: Production by type (area chart of onshore vs. shallow vs. deepwater (Mb/d) 500 1000 1500 2000 2500 3000 3500 0 2014 EFTA01411557 2015 2016 Onshore (Cony) 2017 2018 2019 Shallow water (Cony) 2020 Figure 85: Crude volume growth outlook by project status (Mb/d) 500 1000 1500 2000 2500 3000 3500 0 2014 Base Under Development DB Base Case Source: Deutsche Bank, Wood Mackenzie, IEA 2015 2016 2017 2018 2019 Growth at Onstream Assets Probable Development 2020 Figure 86: 2017 Production Swing (Bear vs. Bull) of —120 Mb/d 1500 1700 1900 2100 2300 2500 2700 2900 2699 2583 2641 Bear Base 6mo timing shift in growth projects Source: Deutsche Bank, Wood Mackenzie, IEA 1% adj in decline rates Bull Deutsche Bank Securities Inc. EFTA01411558 Page 47 mboe/d EFTA01411559 31 May 2815 Integrated Oil US Integrated Oils Primary Growth Drivers Near-term oil production growth will be challenged as most mega project starts and expansions (Kashagan restart expected mid 2017 with Tengiz and Pearl contributions anticipated post 2820) are anticipated later this decade. We model a 2.5% decline rate for the base assets; as recent investment in recovery methods in ACG (Chirag Oil Project) and in Tengiz (Capacity and Reliability project) are expected to partially offset declines. Primary Risks In our view, the primary risks to the 2015-2020 production outlook for the Caspian Sea include delays to unsanctioned projects amid lower crude prices as well as increased operational delays associated with the restart of the Kashagan oil field. 1. Delays to Unsanctioned Projects: The region's most capital-intensive project is Tengiz (Wood Mackenzie estimated peak production of -240 mbpd aggregate for the WPMP and FGP projects) at -$37 Billion. Local content requirements and high export taxes delayed the scheduled FID from 2814 to 1H2015 yet with only 10% of the project's required capital invested as of YE14, there is significant risk to further project slippage. Woodmac anticipates a further delay in FID to 4Q15 with first oil production at FGP not expected until 2021 vs. the initial 2017 target date. FID decisions surrounding Kashagan Phase II (est peak production of 630 mbpd in 2830) and Pearls (est peak production of 50 mbpd in 2024) do not impact our forecast window but will have an impact on production sustainability in the country. 2. Operational Delays to the Restart of Kashagan: Operational-related delays to the restart of the Kashagan oil field) would represent another material risk in the outlook (with —$50Bn in sunk costs, the project is not materially levered to lower crude prices). Following the start of Phase One in September of 2013, the field was soon shut-in following leaks in the gas pipelines that carried sour gas onshore. Following a full replacement of the oil and gas pipelines production is expected to ramp to —400 mboe/d. Completion of pipeline replacement work is targeted for 2H2016 with Wood Mackenzie anticipated first oil production by mid-2017, reaching — 300 mboe/d by 2019. Figure 87: Key Growth Projects, 2014-2020 Project IEA Region Kashagan Contract Area Cheleken Contract Area Gum Deniz-Bahar Umid Shah Deniz Tengizchevroil Area Emba Area (Post contract) FSU FSU FSU FSU EFTA01411560 FSU FSU FSU Source: Deutsche Bank, Wood Mackenzie Country Kazakhstan Turkmenistan Azerbaijan Azerbaijan Azerbaijan Kazakhstan Kazakhstan Sector Offshore South Caspian Basin Azerbaijan Offshore Azerbaijan Offshore Azerbaijan Offshore Precaspian Basin Precaspian Basin Operator Project Type North Caspian Operating Co Dragon Oil Bahar Energy Operating Company SOCAR BP Tengizchevroil Government of Kazakhstan Shallow Shallow Shallow Shallow Shallow Onshore Onshore Dev Status Onstream Onstream Onstream Onstream Onstream Onstream Onstream API 45 34 38 40 42 47 EFTA01411561 31 Prod Start Up Yr Peak Prod Yr 2013 1972 1965 2012 2006 1991 1911 2029 2021 2021 2022 2022 2023 2022 2014-2017 Prod 2014-2020 Prod 83 17 7 3 2 2 0 329 35 11 7 32 94 28 Page 48 Deutsche Bank Securities Inc. EFTA01411562 31 May 2015 Integrated Oil US Integrated Oils Colombia In our view, Colombia's upstream sector is significantly challenged amidst a backdrop of low oil prices, a low reserve life at existing fields, high field operating costs, transportation bottlenecks, security concerns, and corruption charges involving Colombia's largest oil producer. From 2004 through 2008, oil production hovered around a stable 550 mboe/d before ramping aggressively in 2009 and peaking in 2013 at over 1,000 mboe/d; chiefly driven by production from the heavy oil fields of the Llanos basin. The majority of the remaining commercial oil reserves in Colombia is in the Llanos Basin where three fields in particular (Castilla, Rubiales, and Quifa) represented -40% of 2014 oil production. However, with the fields in decline, and production growth having largely outpaced needed infrastructure re-investment, we expect Colombia oil production to decline in our forecast period. We model a long-term decline rate of —5% (assumed upside from FOR projects) resulting in a decline in production of —200 mboe/d from 2013 peak levels by 2020. Figure 88: Colombia Production Outlook, 2014-2020e (Mb/d) 200 400 600 800 1000 1200 0 2014 2015 Base Source: Deutsche Bank, Wood Mackenzie, IEA 2016 2017 2018 2019 Growth Bbls Source: Deutsche Bank, Wood Mackenzie, IEA 2020 Figure 89: Production by type (area chart of onshore vs. shallow vs deepwater (Mb/d) 200 400 600 800 1000 1200 0 2014 EFTA01411563 2015 2016 2017 2018 Onshore (Cony) 2019 2020 Figure 90: Crude volume growth outlook by project status (Mb/d) 200 400 600 800 1000 1200 0 2014 2015 Base Under Development DB Base Case Source: Deutsche Bank, Wood Mackenzie, IEA 2016 2017 2018 2019 Growth at Onstream Assets Probable Development 2020 Figure 91: 2017 Production Swing (Bear vs. Bull) of —40 Mb/d (Mb/d) 100 200 300 400 500 600 700 800 900 0 Bear Base 6mo timing shift in growth projects Source: Deutsche Bank, Wood Mackenzie, IEA Bull 1% adj in decline rates 852 875 895 Deutsche Bank Securities Inc. EFTA01411564 Page 49 mboe/d EFTA01411565 31 May 2815 Integrated Oil US Integrated Oils Primary Risks In the near-term, we anticipate accelerated declines in mature fields as the chief risk for sustained production. Gross oil production from the Rubiales Field — one of the largest producing onshore oil fields in South America - is expected be roughly halved by mid 2816 from —200 mboe/d in 2013 at which point Pacific Rubiales' contract will not be renewed. In our view, longer- term production growth will suffer from a decline in near-term exploration spend particularly in offshore/unconventional, further pushing out the timeline for the potential of frontier plays. Upside to our production estimates would likely entail a faster than anticipated adoption/execution of EOR techniques and infrastructure build-out in the Llanos Basin. a) In the near-term, accelerated declines from major plays represents the primary risk. Gross oil production from the Rubiales Field — the largest producing onshore oil field in South America - is expected be roughly halved by mid 2016 from —200 mboe/d in 2013 at which point Pacific Rubiales' contract will not be renewed. While a potential agreement is still possible between Ecopetrol and Pacific Rubiales or another third-party entity, a significant amount of capital investment is still required to build/re-build infrastructure around the play. In our view, the required levels of capital investment and broader security concerns represent headwinds to a more aggressive adoption of EOR techniques in the play. b) Long-term production growth challenged from a decline in near-term exploration spend particularly in offshore and unconventional plays. DB estimates Ecopetrol upstream capex lower —17.5% YoY in 2015 (largely exploration-driven) while Pacific Rubiales upstream spend is expected lower 55% (largely exploration and some production facilities-driven). A further delay in the addressing the county's reserve life through the drill-bit, will place the focus back on mitigating against field declines. c) Sustaining production levels longer-term will be challenged by infrastructure/logistical bottlenecks persist: The 'heaviness' of the oil fields of the Llanos Basin present significant strains on the current infrastructure build-out in Colombia. Not only is pipeline takeaway capacity necessary to transport the crude to coastal export terminals, but facilities are required to blend the crude (API of -12.5 for the Rubiales field) to a level acceptable for pipeline flow. Identification and integration of diluent and light oil sources for blending is also required. While the recent integration of light oil producing fields has provided a fairly economical solution to the blending challenge, the scalability of the solution is unclear and the alternative (importing of naptha for use as diluent) likely too expensive particularly at lower commodity prices. Further, in the Rubiales field (and exhibited at Quifa as well) delays surrounding water disposal licensing has also significantly curtailed growth (4Q14 production for Rubiales was —170 mboe/d, a 15% drop from 2013 levels) as production was capped until EFTA01411566 licensing was obtained. Page 50 Deutsche Bank Securities Inc. EFTA01411567 31 May 2015 Integrated Oil US Integrated Oils U.S. Gulf of Mexico Near-term production in the GoM is expected to be supported by the ramp of YE14 start-ups (Tubular Bells, Jack/St Malo) and the 2015/2016 (6 and 4 projects respectively) start-up of several key deepwater projects. While the projects are expected to add an incremental 350 mbpd of crude (2016 vs. 2014), the longer-term outlook (2018+) has less visibility beyond the contribution from a few (Appomattox) deep-water projects anticipated to be sanctioned this year. Sanctioning activity, lease sales, rig rates and announcements of early rig terminations will be monitored moving forward to assess incremental shifts in industry appetite for deepwater investment. In the shelf, we assume a 5% annual decline in the central gulf through 2020 with declines likely to accelerate toward the latter part of the forecast period resulting from decreased demand for acreage. Since 2006, average acreage value has declined from $300/acre to —$100/acre and declining further to $50/acre in the most recent bidding in March. Figure 92: GoM Production Outlook, 2014-2020e (Mb/d) 200 400 600 800 1000 1200 1400 1600 0 2014 2015 Base Source: Deutsche Bank, Wood Mackenzie, IEA 2016 2017 2018 2019 Growth Bbls 2020 Figure 93: Production by type (area chart of onshore vs shallow vs. deepwater (Mb/d) 500 1000 1500 2000 0 2014 2015 2016 Onshore (Cony) Deepwater (Cony) EFTA01411568 Source: Deutsche Bank, Wood Mackenzie, IEA 2017 2018 2019 2020 Shallow water (Cony) Ultra-deepwater (Cony) Figure 94: Crude volume growth outlook by project status (Mb/d) 200 400 600 800 1000 1200 1400 1600 0 0 Base Under Development DB Base Case Source: Deutsche Bank, Wood Mackenzie, IEA 0 0 0 5 14 Growth at Onstream Assets Probable Development 14 Figure 95: 2017 Production Swing (Bear vs. Bull) of —120 Mb/d 600 700 800 900 1000 1100 1200 1300 1400 1500 1384 1310 1429 Bear Base 6mo timing shift in growth projects Source: Deutsche Bank, Wood Mackenzie, IEA 1% adj in decline rates EFTA01411569 Bull Deutsche Bank Securities Inc. Page 51 mboe/d EFTA01411570 31 May 2015 Integrated Oil US Integrated Oils Primary Growth Drivers Near-term production is expected to be supported by the ramp of YE14 startups (Tubular Bells, Jack/St Malo) and the 2015/2016 (6 and 4 projects respectively) start-up of several key deepwater projects. While the projects are expected to add an incremental 350 mbpd of crude (2016 vs. 2014), the longer-term outlook (2018+) has less visibility beyond the contribution from a few (Appomattox) deep-water projects that are largely anticipated to be sanctioned this year. Primary Risks The near-term risk to production is largely synonymous with a risk to project start-ups which we regard as generally modest relative to projects with exposure to broader geopolitical turmoil and/or a dependence on cooperation with state owned national oil companies. However, the longer—term sustainability of production from the GoM will be largely dictated by the pace of improvements in the underlying economics for deepwater projects driven by a recovery in crude prices and from significant cost concessions. In our view, tracking the progress towards improvement long-term industry sentiment toward GoM Deepwater involves IIA pick-up in FID activity. Aside from Appomattox, few unsanctioned projects are considered 'locks' to proceed through to FID this year. The sanctioning (and timing of) of Shenandoah and Mad Dog Phase II will speak to progress on the lowering of the cost curve and a higher level of conviction in the sustainability of higher crude prices. IIExtension of Rig Contracts: Wood Mackenzie estimates that —28 DW GoM rig contracts are set to expire over the next 3 years. About 1/3 of the rigs to expire in 2015 have already been released/cold-stacked while the nearly 20 rigs set to expire in 2016/2017 have as of yet not been released. IIA uptick in M&A activity: Since 2012, GoM-focused deals have declined to 8% of US deal flow in 2014 from 13% in 2012. With the short-cycle nature of the US onshore offering accelerated cost corrections and a widening valuation gap between 'haves' & 'have nots' at what point do discounted offshore valuations incentivize a pick-up in M&A activity? Figure 96: Production outlook robust for sanctioned projects and for unsanctioned projects high in sunk costs 2000 4000 6000 8000 -4000 -2000 0 Pre-FID projects, negative NPV at US$60 Brent EFTA01411571 Discoverer Enterprise* DW Champion Ensco 8501* Ensco 8502* Ensco 8505 Ensco 8506 Maersk Developer Noble Amos Runner Remaining PV Remaining PV at US $60 Brent planning price Noble Danny Adkins Source: Wood Mackenzie, Base case assumes LT (2018+) Brent of $92 Atwood Condor Development Driller III Discoverer Deep Seas Ensco DS-3 Ensco DS-4 Ensco DS-5 Noble Jim Day Noble Paul Romano Atwood Advantage DW Invictus DW Nautilus Maersk Viking Noble Bob Douglas Noble Sam Croft Noble Tom Madden Pacific Santa Ana Rowan Relentless Rowan Resolute Stena IceMAX Source: Wood Mackenzie, *Already cold/ready stacked or released, By MODU name Figure 97: 28 DW GoM rig contracts set to expire over next 3 years 2015 2016 2017 Page 52 Deutsche Bank Securities Inc. US$, millions Lucius Big Foot St Malo Heidelberg Delta House Jack Appomattox North Platte Tiber Shenandoah Kaskida EFTA01411572 EFTA01411573 31 May 2015 Integrated Oil US Integrated Oils Figure 98: Deal count in the US GoM has fallen off as a share of US Totals since 2012 250 200 150 100 50 0 20052006200720082009201020112012201320142015 Rest of US Mixture Source: Wood Mackenzie D/W S/W 0% 2% 4% 6% 8% 10% 12% 14% 16% 18% 20% Offshore % Source: Wood Mackenzie Figure 99: Declining Shelf Lease Sales To Accelerate Field Declines 100 150 200 250 50 50 0 Oct-07, Sale 205 Mar-08, Sale 206 Mar-09, Sale 208 Mar-10, Sale 213 Central high bids Jun-12, Sale 216/222 EFTA01411574 Central US$/acre Mar-13, Sale 227 Mar-14, Sale 231 Mar-15, Sale 235 0 100 150 200 250 300 350 Figure 100: Key Growth Projects, 2014-2020 Project IEA Region Delta House Lucius (KC 875) Big Foot (WR 29) Heidelberg (GC 859) Jack (WR 759) Stones (WR 508) Gunflint (MC 948) Julia (WR 627) Hadrian Dantzler (MC 782) North America North America North America North America North America North America North America North America North America North America Source: Deutsche Bank, Wood Mackenzie Sector Central Gulf Central Gulf Central Gulf Central Gulf Central Gulf Central Gulf Central Gulf Central Gulf Central Gulf Central Gulf Basin East Gulf Coast Tertiary EFTA01411575 West Gulf Coast Tertiary West Gulf Coast Tertiary West Gulf Coast Tertiary West Gulf Coast Tertiary West Gulf Coast Tertiary East Gulf Coast Tertiary West Gulf Coast Tertiary West Gulf Coast Tertiary East Gulf Coast Tertiary Operator LLOG Exploration Anadarko Chevron Anadarko Chevron Shell Noble Energy ExxonMobil ExxonMobil Noble Energy Project Type UDW UDW UDW UDW UDW UDW UDW UDW UDW UDW Dev Status Under Development Onstream Under Development Under Development Onstream Under Development Under Development Under Development Under Development Under Development API 36 29 26 35 29 28.5 36 N/A EFTA01411576 N/A 26 Prod Start Up Yr 2015 2015 2015 2016 2014 2017 2016 2016 2015 2016 Peak Prod Yr 2014-2017 Prod 2014-2020 Prod 2017 2017 2021 2021 2020 2021 2017 2024 2025 2017 75 69 52 42 38 25 23 22 21 21 40 43 53 59 45 45 11 32 20 11 Deutsche Bank Securities Inc. Page 53 Deal Count Number of high bids Average acreage value (US$/acre) EFTA01411577 31 May 2015 Integrated Oil US Integrated Oils Malaysia Similar to the broader group of countries, near-term oil production growth in Malaysia will be driven by high levels of recent development activity amidst higher oil prices. Key to the near-term oil growth will be the contribution from recent deepwater discoveries off Sabah. In the longer-term we view a broadly mature exploration profile to fail to incentivize the investment level needed to sustain oil production (production from Kikeh is expected to peak in 2017). In our model, we see overall oil production in 2020 falling —50 mboe/d from 2015 levels. Figure 101: Malaysia Production Outlook, 2014-2020e (Mb/d) 100 200 300 400 500 600 700 800 0 2014 2015 2016 Base Source: Deutsche Bank, Wood Mackenzie, IEA 2017 2018 2019 Growth Bbls 2020 Figure 102: Production by type (area chart of onshore vs. shallow vs. deepwater (Mb/d) 100 200 300 400 500 600 700 800 0 2014 2015 2016 Shallow water (Cony) EFTA01411578 Source: Deutsche Bank, Wood Mackenzie, IEA 2017 2018 2019 2020 Deepwater (Cony) Figure 103: Crude volume growth outlook by project status (Mb/d) 100 200 300 400 500 600 700 800 0 2014 Base Under Development DB Base Case Source: Deutsche Bank, Wood Mackenzie, IEA 2015 2016 2017 2018 2019 Growth at Onstream Assets Probable Development 2020 0 Bear 6mo timing shift in growth projects Source: Deutsche Bank, Wood Mackenzie, IEA Base 1% adj in decline rates Bull Figure 104: 2017 Production Swing (Bear vs. Bull) of —25 Mb/d 100 200 300 400 500 600 700 800 682 656 669 Page 54 EFTA01411579 Deutsche Bank Securities Inc. mboe/d EFTA01411580 31 May 2015 Integrated Oil US Integrated Oils Primary Growth Drivers Near-term volume growth will be driven by recent discoveries off Sabah which have extended the eventual drop-off from Kikeh to 2017. In the near-term (2014-2017) we anticipate oil production to increase 9% by 2017 to 670mboe/d driven exclusively by the deepwater fields off Sabah. However, with Sabah expected to peak production in 2017 and anticipated lower levels of exploration over the next several years, growth visibility in the region post 2017+ is limited. Primary Risks In our view, the primary risk associated to the oil production outlook is a longer-term depletion of its mature asset base. From 2010-2014 exploration activity has dropped significantly with annual exploration wells completed averaging only 11 vs. 16 during the 2003-2009 time-frame with commercial wells representing 24% and 40% of the mix respectively. While total (commercial and technical) resource discovered per well has been significant (-33 mmboe/well) over the last 5 years the commerciality of the discovered resource has fallen off. From 2000-2010 commercial reserves made up —2/3 of the discovered resource; however, that figure has averaged —1/3 over the last 4 years and reached an all time low in 2014 of 8%. Figure 105: Exploration activity has dropped over the last 5 years 10 15 20 25 30 35 40 45 50 0 5 52% 38% 31% 24% 15% 5% 24% 18% 17% 13% 5% 3% -5% 5% 15% 25% EFTA01411581 35% 45% 55% 65% 75% Figure 106: Even though resource per well metrics are more constructive, only 33% of the discovered reserves over the last 4 years are considered 'commercial' 200 400 600 800 1000 1200 1400 0 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Appraisal Exploration Commercial Source: Deutsche Bank, Wood Mackenzie Exploration Technical Comm % of Total Exp Wells Exploration Technical Source: Deutsche Bank, Mackenzie Exploration Commercial Figure 107: Key Growth Projects, 2014-2020 Project IEA Region Country SB 3 SB K SB G Wakid Asia Asia Asia Asia Malaysia Malaysia Malaysia Malaysia Source: Deutsche Bank, Wood Mackenzie Sector Sabah Sabah Sabah Sabah Operator Shell Murphy Oil Shell Petronas Carigali EFTA01411582 Project Type DW DW DW DW Dev Status Onstream Onstream Onstream Good Technical API 40 37 35 35 Prod Start Up Yr 2012 2007 2014 2019 Peak Prod Yr 2015 2021 2022 2020 2014-2017 Prod 59 33 20 0 2014-2020 Prod 40 32 50 18 Deutsche Bank Securities Inc. Page 55 # of Wells Completed Disc Reserves (mmboe) EFTA01411583 31 May 2015 Integrated Oil US Integrated Oils Mexico The 2013 energy reform is aimed at reducing the decline in oil production (which has been fallen by 3% since 2003 to 2450 mboe/d in 2014) that has resulted from a lack of investment in frontier plays particularly in the GoM deepwater (only 26 wells have been drilled in the deepwater). The implications of the energy reform in Mexico on production generally sit outside of our forecast period; however, updates around the bidding process will likely serve as a barometer for the viability of assets — particular the deepwater for which bids are due later this year. While capital investment into mature fields may accelerate the use of secondary and tertiary recovery techniques; 2014 production for identified mature onshore and offshore assets included in Round 1 represent only — 12% of 2014 production. Recovery at the Samaria field (represents 60% of the available mature assets in 2014 production) has already moved past secondary techniques, limiting to recovery factors. In our view, the key risk to production in Mexico is a continued decline in the asset base particularly as exploration results over the last several years have failed to produce prospects material enough to combat the declining portfolio. Figure 108: Mexico Production Outlook, 2014-2020e (Mb/d) 500 1000 1500 2000 2500 3000 0 2014 2015 Base Source: Deutsche Bank, Wood Mackenzie, IEA 2016 2017 2018 2019 Growth Bbls Source: Deutsche Bank, Wood Mackenzie, IEA 2020 Figure 109: Production by type (area chart of onshore vs. shallow vs. deepwater (Mb/d) 500 1000 1500 2000 EFTA01411584 2500 3000 0 2014 2015 2016 Onshore (Cony) 2017 2018 2019 Shallow water (Cony) 2020 Figure 110: Crude volume growth outlook by project status (Mb/d) 500 1000 1500 2000 2500 3000 0 2014 2015 Base Under Development DB Base Case Source: Deutsche Bank, Wood Mackenzie, IEA 2016 2017 2018 2019 Growth at Onstream Assets Probable Development 2020 Figure 111: 2017 Production Swing (Bear vs. Bull) of —140 Mb/d 1500 1600 1700 1800 1900 2000 2100 2200 2300 2246 2173 2104 Bear Base 6mo timing shift in growth projects EFTA01411585 Source: Deutsche Bank, Wood Mackenzie, IEA 1% adj in decline rates Bull Page 56 Deutsche Bank Securities Inc. mboe/d EFTA01411586 31 May 2015 Integrated Oil US Integrated Oils Primary Growth Drivers Volume growth in the forecast period (2015-2020) will be scarce. Among the most material contributions to production in the near-term are the fields from the Litoral de Tabasco business unit in Mexico's Southeastern business unit. The crude from the fields is mostly light (-37 API on average). The continued production ramp of the Tsimin field is likely the biggest spotlight in the group (Woodmac estimated —50 mboe/d in production from 2014-2017). Longerterm growth will be supported mostly by the heavy crude producing KuMaloob Zaap fields (Ayatsil and Tekel) in the Northeastern business unit. Wood Mackenzie estimates a production start in 2017 with peak production of oil reaching —102 mboe/d by 2021. The fields are expected to be tendered as part of Mexico's Round 1 as part of a joint venture opportunity with Pemex. Primary Risks We view the near-term risk to production as minimal as contributions from project startups are marginal. In our view, the longer-term (2017-2020) risk to production in Mexico is significant and is underlined by continued decline in the asset base following a 5yr period of relatively underwhelming exploration results. While capital investment into mature fields may accelerate the use of secondary and tertiary recovery technique; 2014 production for identified mature onshore and offshore assets included in Round 1 represent only — 12% of 2014 crude production. Recovery at the Samaria field (represents 60% of the available mature assets in terms of 2014 production) has already moved past secondary techniques, limiting the upside to recovery factors and potentially to capital inflow. We model a 5% decline rate on the Mexico's base assets during the production period and estimate that a shift in the base decline rate to represent —60 mboe/d of production in 2017. Figure 112: Exploration activity has dipped since 2010 with only smaller onshore discoveries classified as commercial 10 12 14 16 18 20 0 2 4 6 8 0% 10% 20% EFTA01411587 30% 40% 50% 60% 70% 80% 90% 100% Figure 113: In particular, exploration in the GoM shelf has been largely disappointing with recent discoveries mostly consisting of smaller fields since 2008 100 150 200 250 300 50 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Onshore Source: Deutsche Bank Shelf DW Comm % of Total Exp Wells 0 2005 2006 2007 2008 2009 Disc Reserve per Well (mmboe) Source: Deutsche Bank, Wood Mackenzie 2010 2011 2012 2013 % of Comm Disc Reserves 2014 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Deutsche Bank Securities Inc. Page 57 # of Wells Completed EFTA01411588 Comm Tech Comm Tech Comm Tech Comm Tech Comm Tech Comm Tech Comm Tech Comm Tech Comm Tech Comm Tech EFTA01411589 31 May 2015 Integrated Oil US Integrated Oils Figure 114: Timeline for Mexico Energy Reform, Round 1 Roll-Out Date Event Dec-13 Aug-14 Nov-14 Energy Reform Launch Initial Round Zero Results Secondary legislation approved Industry feedback on assets Jan-15 Industry feedback on contracts Launch of Round 1 Commentary Allows for private investment through PSCs and licenses Round Zero determined which assets were kept by Pemex (all producing assets are kept by Pemex) Government has adjustment Round 1 terms based on industry feedback; however finanal terms yet to be determined Opportunities will including joint ventures with Pemex (10 joint ventures identified) as well as standalone opportunities 3Q15 Bids due for shallow-water DROs and exploration Shallow-water projects are decomposed into mature offshore (Bolontiku, Sinan, Ek) and extra-heavy crude oil projects in development (Ayatsil, Tekel, Utsil). Oct-Nov-15 Bids due for mature onshore Mature Onshore include the Rodador, Ogarrio, Cardenas-Mora, and Samaria fields. With the exception of Samaria (Tertiary) recovery the rest of the assets are being offered to accelerate hydrocarbon recovery starting with secondary-recovery. The Samaria field represents —60% of mature assets (onshore and offshore) 2014 production being offered in Round 1. Dec-15 Bids due for deepwater Deepwater gas offerings in Round 1 include: Kunah and Piklis. Water depth is less than 2,000 meters. Deepwater oil offerings in Round 1 include fields (Trion, Exploratus, Maximino) in the Perdido area of the deepwater GoM (water depth greater than 2,500 meters) Source: Deutsche Bank, Pemex, Wood Mackenzie Page 58 Deutsche Bank Securities Inc. EFTA01411590 31 May 2015 Integrated Oil US Integrated Oils North Sea The North Sea has been synonymous in recent years with mature, Non -OPEC decline, and for good reason. Since its peak production in 2000, North Sea production has steadily declined from —6 MMboe/d to current production levels of 2.5 MMboe/d, or an average decline rate of 6% YoY. This happened despite steadily increasing capex levels. Despite multi-year trends, we expect North Sea production to hold broadly flat through 2016 as several growth projects are brought on-stream and significant re-development spending over the last couple of years softens the decline of several key fields. The longerterm outlook is most strongly correlated with the successful (i.e. timely) development of the massive Johan Sverdrup field and the management of declines across the broader mature asset base. On our base case assumes declines of 12%, and estimate a 1% revision to the assumed decline to result in a swing of — 125 Mb/d to our 2017 outlook. Figure 115: North Sea Production Outlook, 2014-2020e (Mb/d) 500 1000 1500 2000 2500 3000 0 2014 2015 Base Source: Deutsche Bank, Wood Mackenzie, IEA 2016 2017 2018 2019 Growth Bbls 2020 Figure 116: Production by type (area chart of onshore vs. shallow vs. deepwater (Mb/d) 500 1000 1500 2000 2500 3000 0 2014 2015 2016 EFTA01411591 Shallow water (Cony) Source: Deutsche Bank, Wood Mackenzie, IEA 2017 2018 2019 Deepwater (Cony) 2020 Figure 117: Crude volume growth outlook by project status (Mb/d) 500 1000 1500 2000 2500 3000 3500 0 2014 2015 Base Under Development DB Base Case 2016 2017 2018 2019 Growth at Onstream Assets Probable Development 2020 Figure 118: 2017 Production Swing (Bear vs. Bull) of —240 Mb/d 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 2518 2435 2280 Bear Base 6mo timing shift in growth projects Source: Deutsche Bank, Wood Mackenzie, IEA Source: Deutsche Bank, Wood Mackenzie, IEA 1% adj in decline rates Bull EFTA01411592 Deutsche Bank Securities Inc. Page 59 mboe/d EFTA01411593 31 May 2015 Integrated Oil US Integrated Oils Primary Growth Drivers Volume growth over the next two years is primarily driven from re-developed mature assets (Ekofisk II) as well as from the bringing on-line of several growth projects in both the UK and Norway. However, the longer-term viability of North Sea production growth is most strongly correlated with the successful (i.e. timely) development of the massive Johan Sverdrup field which was recently sanctioned in February. We estimate North Sea crude production to hold broadly flat (-2.5 MMb/d) through 2016 before declining to 2.2 MMb/d in 2019 w/ recovery in 2020 as Johan Sverdrup is brought on-line. Primary Risks In our view, the impact of project delays is mostly muted as all growth projects are currently either on-stream or under development with growth from the currently producing Ekofisk field alone, estimated at —15% of 2014-2016 North Sea. Post 2016, we expect a decline in the North Sea until the end of the decade/ramp of the massive Johan Sverdrup field (+300 Mb/d of production growth in 2020). The chief risk to North Sea production on a go-forward basis will focus on managing declines. We note, however, that Statoil (covered by our European counterparts), alone, accounts for -20% of the oil production growth from the North Sea over the next 3 years and any announcements of a change to the company's planned activity in the region would likely have a material impact on the forecast. Managing Declines: For a more detail look at North Sea decline, please see our case study on page 20 of this publication. In summary, we assume a decline rate (ex growth rates and redevelopment projects) of —12% during our forecast period and assume a contribution of -3% from prior year production in normalized outages within the forecasted 12% forecast. We see some upside to our forecasted decline rates as operators (in the Norwegian North Sea) benefit from exchange rate tail-winds that will soften cuts to brown field spending. Assuming that —20% of a company's NCS spend is denominated in the local currency ($ Kroner), we estimate that a 25% YoY reduction in $USD denominated capex (proxy for an industry average) will likely result in an "actual" 10% YoY cut spend. Further, a reallocation of capital away from more costly frontier plays in the Barents Sea towards more immediate cash flow accretive brown-field projects can also provide upside to our current forecast. On our base case assumes declines of 12%, and estimate a 1% revision to the assumed decline to result in a swing of — 125 Mb/d to our 2017 outlook. Figure 119: Key Growth Projects, 2014-2020 Project IEA Region Edvard Grieg Laggan & Tormore Area Goliat Area Ekofisk Area II Golden Eagle Area EFTA01411594 Mariner Western Isles Project Ivar Aasen Area Knarr Area Hej re Europe Europe Europe Europe Europe Europe Europe Europe Europe Europe Source: Deutsche Bank. Wood Mackenzie Country Norway UK Norway Norway UK UK UK Norway Norway Other North Sea Sector Central North Sea Atlantic Margin Barents Sea Central North Sea Central North Sea Northern North Sea Northern North Sea Central North Sea Northern North Sea Central North Sea Operator Lundin Petroleum Total Eni ConocoPhillips Nexen Statoil Dana Petroleum Det Norske BG DONG Energy Project Type EFTA01411595 Dev Status Shallow DW DW Shallow Shallow Shallow Shallow Shallow DW Shallow Under Development Under Development Under Development Onstream Onstream Under Development Under Development Under Development Under Development Under Development API 35 40 36.5 39.6 37.5 13 34.5 37 45 43 Prod Start Up Yr Peak Prod Yr 2014-2017 Prod 2014-2020 Prod 2015 2015 2015 1999 2014 2017 2016 2016 2015 2017 2016 2018 2016 2002 2017 2019 2017 2020 EFTA01411596 2015 2017 89 81 72 68 60 52 33 32 27 27 34 91 35 37 24 58 11 62 13 27 Page 60 Deutsche Bank Securities Inc. EFTA01411597 31 May 2015 Integrated Oil US Integrated Oils Russia At 10.5 mmbpd of crude production in 2014, Russia represents —25% of NonOPEC production; recent production growth has been driven chiefly by contributions from the conventional West Siberia basin and in our view likely to continue to be the case moving forward. While growth from green field projects is modest when compared to the country's base production, declines in mature fields will be the key driver of the forward -looking production profile. DB's house view is that Russia production will be broadly flat through 2020 with a slight ramp in the near-term as companies are expected to maintain robust activity levels. DB's Russian energy team broadly expects investment spend in Russia to track broadly flat/modestly higher in 2015 vs 2014 (in RUB). We view impacts from current sanctions as minimal as there is no sense of urgency in developing the unconventional and Artic fields so far as it relates to sustaining the production base. Given the large size of base production, a shift of 1% in the forecasted decline rate for Russia results in a significant —300 Mb/d adjustment to our 2017 call on US onshore growth. Figure 120: Russia Production Outlook, 2014-2020e (Mb/d) 2000 4000 6000 8000 10000 12000 0 2014 2015 Base Source: Deutsche Bank, Wood Mackenzie, IEA 2016 2017 2018 2019 Growth Bbls Source: Deutsche Bank, Wood Mackenzie, IEA 2020 Figure 121: Production by type (area chart of onshore vs. shallow vs. deepwater (Mb/d) 9600 9800 10000 10200 10400 10600 EFTA01411598 10800 2014 2015 2016 Onshore (Cony) 2017 2018 2019 Shallow water (Cony) 2020 Figure 122: Crude volume growth outlook by project status (Mb/d) 8500 9000 9500 10000 10500 11000 2014 2015 Base Under Development DB Base Case 2016 2017 2018 2019 Growth at Onstream Assets Probable Development 2020 Figure 123: 2017 Production Swing (Bear vs. Bull) of -600 Mb/d 8500 9000 9500 10000 10500 11000 11500 10986 10688 10411 Bear Base 6mo timing shift in growth projects Source: Deutsche Bank, Wood Mackenzie, IEA Source: Deutsche Bank, Wood Mackenzie, IEA 1% adj in decline rates Bull Deutsche Bank Securities Inc. Page 61 EFTA01411599 mboe/d EFTA01411600 31 May 2015 Integrated Oil US Integrated Oils Primary Growth Drivers Volume growth will be chiefly driven by managing declines at various mature fields in West Siberia and a handful of moderately-sized project start-ups in the Timan-Pechora (Trebs and Titov), Sakhalin (Arkutun-Dagi), and North Caucasus (Vladimir Filanovski) basins. In total we estimate growth projects to grow- term near-term production of —120 Mb/d (2016 vs. 2014) Primary Risks In our view, the key risk to near-term production growth/sustainment involves mitigating against declines in West Siberia. In our view, improvements in operator execution as well as cheap funding from a weakened Ruble will broadly keep production flat through 2020. Decline Mitigation: Exiting 1Q15 development drilling was up 17.5% YoY and the well count increased by 17%, despite the bottoming of the commodity on better execution from operators and tail-winds from cheaper Rubledenominated spend. Russian oil companies have broadly spoken to flat or modestly higher capital spending in 2015 (in RUB). The Russian government recently granted a Mineral Extraction Tax (MET) break and a reduced Export Duty rate which may ultimately further costs for operators (and incentivize drilling activity). Given the large size of the production base, a shift of 1% in the forecasted decline rate for Russia results in a significant adjustment to our call on US onshore growth (-300 Mb/d in our 2017 call on US onshore growth.) Figure 124: Key Growth Projects, 2014-2020 Project IEA SeverEnergia Srednebotuobinskoye Yarudeiskoye Talakan Fields Yaregskoye (LUKOIL) Suzunskoye Trebs and Titov Prirazlomnoye (TP) Novoportovskoye Sakhalin-1 Area Region FSU FSU FSU FSU FSU FSU FSU FSU EFTA01411601 FSU FSU Source: Deutsche Bank. Wood Mackenzie Country Russia Russia Russia Russia Russia Russia Russia Russia Russia Russia Sector West Siberia East Siberia West Siberia East Siberia Timan-Pechora East Siberia Timan-Pechora Timan-Pechora West Siberia Far East Operator SeverEnergia Taas-Yuryakh Yargeo Talakanneft LUKOIL-Komi (Yareganeft) Vankorneft Bashneft-Polus Gazprom neft shelf Gazpromneft Novi Port ExxonMobil Project Type Onshore Onshore Onshore Shallow Onshore Shallow Dev Status Onstream Onstream Onshore Under Development Onshore Onstream Onstream Onshore Under Development EFTA01411602 Onshore Onstream Onstream Onstream Onstream API 43 32 42 35 21 41 26 24 32 32 Production Start Up Yr 2012 2013 2015 1989 1939 2016 2013 2013 2011 2005 Peak Prod Yr 2018 2023 2016 2017 2017 2018 2021 2021 2022 2025 2014-2017 Prod 120 85 79 40 36 30 29 28 28 28 EFTA01411603 2014-2020 Prod 122 112 63 22 36 60 64 75 139 8 Page 62 Deutsche Bank Securities Inc. EFTA01411604 31 May 2015 Integrated Oil US Integrated Oils Appendix Figure 125: Crude Supply Model 2013 North America United States L48 (2017+ replaced with "The Call") GoM DW SW Alaska Total US Total Canada Mexico Chile Total North America Total North America, ex Onshore Europe Total North Sea Other Europe OECD Europe Non-OECD Total Europe Latin America Brazil Colombia Venezuela Ecuador Other Non-OPEC Latin America Total Latin America Africa Angola Libya Nigeria Algeria Non-OPEC Africa Total Africa Middle East Saudi Arabia Iran Iraq UAE Kuwait Qatar Neutral Zone Non-OPEC Middle East Total Middle East Asia Australia Other Asia OECD EFTA01411605 China India Malaysia Indonesia Other Non-OECD Asia Total Asia Russia Caspian Sea Other FSU Total FSU "Other Bbls" ex OPEC "Other Bbls" with Angola 5895 1254 975 279 515 7664 3333 2532 7 13537 7642 2509 430 129 3068 2030 1008 2497 517 814 6866 1718 898 1953 1148 2171 7888 9487 2682 3080 2762 2549 881 520 1305 23266 335 60 4173 EFTA01411606 769 586 732 836 7491 10506 2727 105 13339 38868 40586 2014 6946 1395 1120 275 497 8838 3612 2440 7 14897 7951 2518 412 130 3059 2260 990 2462 551 808 7072 1661 460 1915 1121 2198 7355 9611 2812 3332 2759 2608 861 383 1276 23642 354 64 4216 EFTA01411607 766 612 700 818 7529 10576 2689 99 13364 39437 41098 2015E 7351 1493 1234 259 472 9316 3756 2346 6 15424 8073 2509 395 130 3034 2427 956 2462 551 800 7196 1617 460 1915 1121 2184 7297 9611 2812 3332 2759 2608 861 383 1218 23583 357 57 4216 EFTA01411608 778 691 653 800 7551 10659 2672 93 13424 39668 41285 2016E 7293 1583 1340 243 449 9325 3964 2248 5 15542 8249 2491 391 108 2990 2563 907 2462 551 800 7283 1617 460 1915 1121 2177 7289 9611 2812 3332 2759 2608 861 383 1146 23512 322 68 4216 EFTA01411609 761 674 711 795 7546 10699 2655 87 13441 39820 41437 2017E 7674 1610 1382 228 426 9710 4157 2173 5 16045 8371 2435 406 99 2940 2678 875 2462 551 800 7366 1641 460 1915 1121 2281 7418 9611 2812 3332 2759 2608 861 383 1118 23483 337 68 4216 EFTA01411610 735 669 703 795 7523 10688 2641 81 13410 538 39995 41636 2018E 8397 1551 1337 215 405 10353 4311 2076 4 16745 8348 2393 406 90 2888 2851 864 2462 551 800 7528 1717 460 1915 1121 2239 7452 9611 2812 3332 2759 2608 861 383 1091 23456 384 68 EFTA01411611 4216 709 683 678 795 7532 10650 2774 75 13498 40111 41829 2019E 9442 1507 1305 202 385 11333 4446 1981 4 17764 8322 2200 384 81 2665 3016 842 2462 551 800 7671 1770 460 1915 1121 2196 7461 9611 2812 3332 2759 2608 861 383 1086 23452 370 68 EFTA01411612 4216 682 661 636 773 7405 10579 2917 69 13564 39896 41666 2020E 10473 1447 1258 190 365 12285 4491 1870 4 18649 8177 2174 370 72 2616 3182 814 2462 551 800 7809 1820 460 1915 1121 2073 7388 9611 2812 3332 2759 2608 861 383 1067 23432 362 60 EFTA01411613 4216 674 648 603 750 7312 10566 2929 63 13557 39598 41419 14-15 405 98 114 -17 -25 144 -94 50 122 -8 -17 0 -25 167 -34 0 0 -8 124 -44 0 0 0 -14 -58 0 0 0 0 0 0 0 -59 -59 3 -7 0 12 EFTA01411614 79 -47 -18 22 83 -18 -6 60 231 187 Source: Deutsche Bank, Wood Mackenzie, IEA, EIA, L48 Crude "Implied Call on US Crude Growth" from 2017+ and DBe from 2015-2016, includes crude oil, condensate, bitumen 14-17 Growth 728 215 262 -47 -71 545 -267 278 420 -83 -6 -31 -120 417 -116 0 0 -8 294 -20 0 0 0 83 63 0 0 0 0 0 0 0 -158 -158 -17 4 EFTA01411615 0 -32 57 3 -23 -7 112 -48 -18 46 558 538 3527 52 138 -85 -132 878 -571 308 226 -343 -42 -58 -443 921 -176 0 0 -8 737 159 0 0 0 -126 34 0 0 0 0 0 0 0 -210 -210 8 -4 0 -93 36 EFTA01411616 -97 -68 -217 -10 240 -36 194 161 320 14-'20 Deutsche Bank Securities Inc. Page 63 EFTA01411617 31 May 2015 Integrated Oil US Integrated Oils Appendix 1 Important Disclosures Additional information available upon request *Prices are current as of the end of the previous trading session unless otherwise indicated and are sourced from local exchanges via Reuters, Bloomberg and other vendors . Other information is sourced from Deutsche Bank, subject companies, and other sources. For disclosures pertaining to recommendations or estimates made on securities other than the primary subject of this research, please see the most recently published company report or visit our global disclosure look-up page on our website at http://gm.db.com/- ger/disclosure/DisclosureDirectory.eqsr Analyst Certification The views expressed in this report accurately reflect the personal views of the undersigned lead analyst about the subject issuers and the securities of those issuers. In addition, the undersigned lead analyst has not and will not receive any compensation for providing a specific recommendation or view in this report. Ryan Todd Equity rating key Buy: Based on a current 12- month view of total share-holder return (TSR = percentage change in share price from current price to projected target price plus pro-jected dividend yield ) , we recommend that investors buy the stock. Sell: Based on a current 12-month view of total shareholder return, we recommend that investors sell the stock Hold: We take a neutral view on the stock 12-months out and, based on this time horizon, do not recommend either a Buy or Sell. Notes: 1. Newly issued research recommendations and target prices always supersede previously published research. 2. Ratings definitions prior to 27 January, 2007 were: Buy: Expected total return (including dividends) of 10% or more over a 12-month period Hold: Expected total return (including dividends) between -10% and 10% over a 12month period Sell: Expected total return (including dividends) of -10% or worse over a 12-month period Regulatory Disclosures 1.Important Additional Conflict Disclosures Aside from within this report, important conflict disclosures can also be found at https://gm.db com/equities under the EFTA01411618 "Disclosures Lookup" and "Legal" tabs. Investors are strongly encouraged to review this information before investing. 2.Short-Term Trade Ideas Deutsche Bank equity research analysts sometimes have shorter-term trade ideas (known as SOLAR ideas) that are consistent or inconsistent with Deutsche Bank's existing longer term ratings. These trade ideas can be found at the SOLAR link at http://gm.db.com. Page 64 Deutsche Bank Securities Inc. 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Page 67 EFTA01411626 David Folkerts-Landau Group Chief Economist Member of the Group Executive Committee Raj Hindocha Global Chief Operating Officer Research Michael Spencer Regional Head Asia Pacific Research International locations Deutsche Bank AG Deutsche Bank Place Level 16 Corner of Hunter & Phillip Streets Sydney, NSW 2000 Australia Tel: (61) 2 8258 1234 Deutsche Bank AG London 1 Great Winchester Street London EC2N 2EQ United Kingdom Tel: (44) 20 7545 8000 Deutsche Bank AG Grote Gallusstra@e 10-14 60272 Frankfurt am Main Germany Tel: (49) 69 910 00 Deutsche Bank Securities Inc 60 Wall Street New York, NY 10005 United States of America Tel: (1) 212 250 2500 Deutsche Bank AG Filiale Hongkong International Commerce Centre, 1 Austin Road West,Kowloon, Hong Kong Tel: (852) 2203 8888 Deutsche Securities Inc. 2-11-1 Nagatacho Sanno Park Tower Chiyoda-ku, Tokyo 100-6171 Japan Tel: (81) 3 5156 6770 Marcel Cassard Global Head FICC Research & Global Macro Economics Ralf Hoffmann Regional Head Deutsche Bank Research, Germany Richard Smith and Steve Pollard EFTA01411627 Co-Global Heads Equity Research Andreas Neubauer Regional Head Equity Research, Germany Steve Pollard Regional Head Americas Research GRCM2015PROD034110 EFTA01411628