Oil Prices Fall into a Lower Range

Transcription

1 Oil Prices Fall into a Lower Range Supply overhang is real get used to double digit oil prices In our central scenario, Brent prices stay down in a new range centered on $97 per barrel (b) in 215, while WTI averages $89/b next year. In 216 and 217 both would grind down toward their long run, real dollar targets of $86/b and $8/b respectively. That compares to Brent prices averaging roughly $11/b in the last three years. This year is a transition, prices fell below $1 in Q3, and should average ~$14 (Brent) and ~$98 (WTI). September 3, 214 RESEARCH TEAM Jan Stuart Global Energy Economist jan.stuart@credit-suisse.com Johannes van der Tuin Research Analyst johannes.vandertuin@creditsuisse.com Oil market fundamentals have continued to weaken. The real problem, in our view, is supply. In contrast to the consensus, we find that oil demand growth is tracking close enough to expectations, but North American production growth is overwhelming that demand. Oil inventories continue to rise. While worries about the long run growth of supply have risen, largely due to intensifying conflict in the Mideast; oil markets have resolutely focused on the short run. In July the Brent futures curve flipped into contango that contango is still widening. While WTI is not as weak, it too should face headwinds. Isolated to a degree, WTI oil futures curves remain backwardated. But the combination of seasonally lower refiner crude oil demand and relentlessly rising production, should eventually affect WTI prices, more likely in 215. As such we are less bearish than many. In our central global scenario, the self-appointed central bankers of oil, Saudi Arabia, will cut, and things settle on a gentle glide-path toward normal. But clearly downside risk has risen. What if they don t cut? In a test of the resilience of the US upstream universe to low prices, we find an economic floor of ~$8/b Brent, and $7/b WTI. CREDIT SUISSE SECURITIES RESEARCH & ANALYTICS BEYOND INFORMATION Client-Driven Solutions, Insights and Access DISCLOSURE APPENDIX AT THE BACK OF THIS REPORT CONTAINS IMPORTANT DISCLOSURES, ANALYST CERTIFICATIONS, AND THE STATUS OF NON-US ANALYSTS. US Disclosure: Credit Suisse does and seeks to do business with companies covered in its research reports. As a result, 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.

2 Table of Contents Appendix: Risk & Data Details on demand, supply, inventories and assumptions Executive Summary Why we still think that WTI can cope Global balances: falling call on Saudi What if the Saudis don t cut: Floors and stabilizers The black oil balance is looser still 1

3 Executive Summary, price deck and what markets say

4 Supply growth is finally driving down oil prices Executive Summary & Conclusion Near term: Strong US supply growth requires other supply adjustments Weakness is real. Global oil prices have retrenched below $1 (b) per barrel. Nearly all futures curves for oil have flipped into contango (bearish coincident indicator), after years of steep backwardation (indicating tight s/d balances). While speculators have played their part, the trend shift down reflects a steady deterioration of fundamentals that began early this year. Simple fundamental trends show it s about supply. Standard metrics explain much of the issue: Non-Opec supply growth is far exceeding global oil demand growth (by as much as 1 million barrels per day in Q2-214). While Opec supplies are down yoy, inventories have continued to grow, turning a large deficit into a marked surplus at end-august. Since futures structures continue to deteriorate, something fundamental needs to change. Supply needs to be curtailed, for a few years. The more so since demand growth is unlikely to right the ship barring an unlikely imminent, lasting and material upturn in global activity. And while we remain more optimistic about oil demand than most; it s clear to us too that 214 is no banner year. After an exceptionally weak Q2, with yoy oil consumption growth well below 1 Mb/d, we expect only a modest re-acceleration into year-end. The point is, however, that sluggish demand growth had largely been anticipated. Downside risk in Europe and China was well flagged, and in the event the real downside surprise came from the US and fails to explain much of today s weakness. So in a way, oil s/d balances remain manageable and in our central case we assume that the Saudis will cut so as to stabilize prices very near the happy level of $1/b that they have repeatedly argued is in everyone s best interest. Such stabilizing / managing makes sense in many ways. Q: What if the Saudis don t cut? A: The answer isn t pretty Assume the Saudis say you broke it; you fix it ; What then is the floor under oil prices. We stress-tested the balance sheets of the US upstream -- since the shale-revolution depends on high prices to sustain momentum. $7/b WTI brings about a meaningful but temporary slowdown of growth momentum next year. It s an economic floor of sorts, and only that. Where We Are Different, Assumptions, Risk US oil production growth is still accelerating. Our model anticipates a flattening of volume growth, which will still, however, reach just north of 1 million barrels per day (Mb/d) per year in 215 and 216. What s more, accelerating output growth of natural gas liquids (NGLs) accumulated to surprisingly large (>4kb/d, pa) volumes in 214. That party is not over yet either. WTI headwinds are gathering, but we think they ll be less damaging as many think more imports need rejecting in 215. That spells wider Brent WTI diffs than in 214 though nowhere near as wide as in But as refiners expand intake capacity a bit more; railroad and pipeline expansions lower transport costs a bit more; and export options continue to proliferate; we think that the industry will again avoid super-congestion like price-dislocations. And the next spot of weakness may not come till late this year, or early in 215. Further out, we expect that new refiner, splitter and cracker capacity will combine with pragmatic relaxing of export strictures to alleviate congestion and narrow the Brent/WTI differential to $6/b or roughly the cost of taking inland crude to international waters, in the long run (218 and out). Keep a close eye on refiner crude oil demand. Black oil balances explain still more of this year s weakness. And even if Opec broadly manages supply, many of the old price-dynamics and differentials are changing structurally. In general we d argue that established premia for quality or location will continue to compress which itself lowers in the ceiling on oil prices in the near-term. 215 should be less bad for Brent. Its price need not fall much further, because refiners outside North America will need to run harder next year to supply a bump up in middle distillate demand. We project that black oil demand from refiners rises by more than1 Mb/d, versus merely ~4 kb/d in 214. Supply side risks remain very real. We cannot forecast the next disruption to sovereign oil supply. But Iraq, Libya, Nigeria and to a lesser degree Venezuela unfortunately remain unstable; while elsewhere (e.g. Venezuela, Russia) the upstream investment climate remains poor as well. We assume no further disruptions; steady flows from Libya; and more oil from Iran 3

5 CS Oil Price Forecast Decks Changes to our forecasts, and how they stack up relative to futures strips and consensus We think we are witnessing a turning point that will most likely end a four year long run of extraordinarily stable, triple digit prices. Brent oil futures have been trapped in a narrow range around $11/b Brent for a record 15 quarters in a row, but they seem to be breaking out to the downside The fourth quarter of 214 will likely mark the first quarter-average Brent oil price below $1/b since Q1-211 Marking to market: Q3-214 s $13.5 was the lowest quarter average in that string of 15 $1+ Brent prices (Q1-212 was highest at $118) If in the last three years average annual Brent prices came to ~$11/b. The next three years will likely see average prices around $93/b Brent; and $85/b WTI And prices will track, we think, a declining trend toward long run or normal levels of $86/b Brent and $8/b WTI in 215, 216 and 217 The progression would go like this: After falling -2.6% in 213; Brent oil prices, in our view, will fall -3.6% in 214; -7.5% in 215; -4.1% in 216 and as a bridge to the LR target by another -5.4% in 217 However, given the degree of management required and multiple risks still present we will probably see greater volatility too CS forecast of Brent oil futures Period Actuals & CS Forecast FY11 (a) $ FY12 (a) $ Q13 (a) $ Q13 (a) $ Q13 (a) $ Q13 (a) $ FY13 (a) $ Q14 (a) $ Q14 $ Previous Fcst Futures BBG Consensus* 3Q14 $ $ 115. $ $ Q14 $ 98. $ 11. $ $ FY14E $ $ $ $ Q15 $ 95. $ 15. $ 99.9 $ 16. 2Q15 $ 99. $ 1. $ $ Q15 $ 99. $ 15. $ $ Q15 $ 95. $ 1. $ FY15E $ 97. $ 12.5 $ $ FY16E $ 93. $ 95. $ $ FY17E $ 88. $ 95. $ $ Long-Term $ 86. $ 9. We forecast oil from a global perspective, i.e. Brent oil futures at left To the right is the WTI/Brent differential and of course the WTI deck Note that the differential continued to narrow in 214 one of the non-consensus views we got right We expect further narrowing after a trickier year for WTI in 215 Also, as the benchmark nearest the source of new oil production, WTI will in our view set the economic floor under prices e.g. should sovereign oil flow liberally Period Actuals & CS Forecast FY11 (a) $ (15.8) FY12 (a) $ (17.53) 1Q13 (a) $ (18.28) 2Q13 (a) $ (9.18) 3Q13 (a) $ (3.84) 4Q13 (a) $ (11.74) FY13 (a) $ (1.65) 1Q14 (a) $ (9.31) 2Q14 $ (6.77) 3Q14 $ (6.25) 4Q14 $ (7.) FY14E $ (7.33) 1Q15 $ (1.) 2Q15 $ (7.) 3Q15 $ (7.) 4Q15 $ (8.) FY15E $ (8.) FY16E $ (8.) FY17E $ (7.) Long-Term $ (6.) CS forecast of WTI oil futures Period Actuals & CS Forecast FY11 (a) $ FY12 (a) $ Q13 (a) $ Q13 (a) $ Q13 (a) $ Q13 (a) $ FY13 (a) $ Q14 (a) $ Q14 $ Previous Fcst Futures BBG Consensus* 3Q14 $ $ 18. $ $ 1.8 4Q14 $ 91. $ 97. $ 93.2 $ FY14E $ $ $ $ Q15 $ 85. $ 92. $ $ 11. 2Q15 $ 92. $ 93. $ 9.17 $ Q15 $ 92. $ 98. $ 89.4 $ Q15 $ 87. $ 87. $ 89.7 FY15E $ 89. $ 92.5 $ 9.1 $ FY16E $ 85. $ 85. $ $ FY17E $ 81. $ 85. $ $ 97.3 Long-Term $ 8. $ 8. *Bloomberg forecasts from previous three months only Source: Credit Suisse Research, Bloomberg 4

6 Our central case in context -- Global oil prices glide toward normal Long run Brent target of $86/b builds from an economic floor price ($8 WTI) While we can quibble over the path risks in the next few years, our long run target is probably too low a target for the end of the decade as well It fails to account fully for significant oil demand growth potential across emerging markets -- where more time is required to adopt efficiencies and substitution that can more structurally erode oil consumption As importantly, we see risk of another episode of supply scarcity, given the paucity of accessible resource plays outside North America and the unstable investment climate prevailing in the Mideast, North Africa, Russia and Venezuela Evidently, an episode of lower prices would lift demand trajectories and push supply growth to the right $13 $12 $11 $1 $9 $8 Qrtr average (act) old normal range Qrtr average (fcst) old floor new floor? new normal range? $7 J-1 J-11 J-12 J-13 J-14 J-15 J-16 J-17 J-18 J-19 J-2 Source: Credit Suisse Research, Bloomberg 5

7 Markets say that this is no ordinary dip Before diving into fundamentals data, here s what markets tell us about the state of play Shifting shapes of Brent futures curves tell you things have fundamentally changed front of the curve trades short-run s/d; long end has caught a bid WTI futures curves feature some near-term strength but we think they ll align with Brent again late this year, or early in 215 $115 A deep and long contango has emerged ($/b) $15 Alignment means WTI may take a hit ($/b) $11 $15 $1 current Brent strip mid-june Sep-13 $1 $95 Current WTI futures strip Current Brent strip $95 $9 $9 p Positioning matters: real length came in in early June (IS in Iraq) and disguised the weakening of fundamentals; once the threat to short run supply lifted, Libyan exports reemerged and refiner demand dried up, non-commercials accelerated the spot price retreat in August Their record low net-length now represents upside price risk 16% 14% 12% 1% 8% MM Futures Net Length Brent Price $13 $12 $11 $85 p Brent 1-6, watch for this to retrace toward positive territory as a precursor to real fundamentals strength emerging almost as interesting, and we think relevant especially in the next few months is the same chart for the ICE Gasoil futures strip $8 $6 $4 $2 Backwardation: Bullish % 4% 2% % J-12 A-12 J-12 O-12 J-13 A-13 J-13 O-13 J-14 A-14 J-14 $1 $9 $ -$2 -$4 Contango: Bearish J F M A M J J A S O N D Source: Credit Suisse Research, Bloomberg, ICE Futures 6

8 Fundamentals: Global s/d balances and the call on Saudi + inventory

9 Global s/d balances: Or the falling call on Saudi crude oil + inventory There is too much supply, but will Saudi Arabia cut back? As recently as June, a case for increasing tightness seemed most reasonable; in the event, the H1-214 call on Saudi was revised sharply lower. Nor does it seem to have reached anywhere near as high as last year in the summer. Now looking into year-end and the early part of next year, our central scenario projects a steep decline in the call to levels last seen before the onset of the Arab Awakening in late 21. That said, the balance remains broadly manageable, this is not the beginning of a dead-end street for the world s swing producer. Why we think the Saudis will cut: The call on Saudi Arabia s crude oil and global inventories 1. It s their job in Opec as well as in the G-2 context, Saudi Arabia is proud to remain the self-appointed central banker of oil. As such it raised production materially in 211 and again in 213, when Libya and Iranian exports were cut. In our view, the required cuts add up to less than what was gained since 28-9 (see chart) 2. Saudi officials have repeatedly and explicitly stated their preference for $1/b oil. Markets tell us that those price levels require less Saudi oil. 3. Bills to pay -- though a budget breakeven pain-threshold is nowhere near 4. We assume that the royal council (in which decision making has become more cumbersome) prefers tangibly higher revenue over some abstract inflicting of pain strategy 5. Real risk of losing control of markets 6. Lastly, the Saudis did it before (212), when they cut production by ~1 Mb/d from October to November Monthly data: Looking back, data revisions for final demand (down) and other supply (up) left a large surplus with which to add to inventory earlier this year. Looking forward, in our central scenario, the call slips below 9 Mb/d in Q1-215, from 9.7 Mb/d in August and Saudi Arabia cuts output The bearish scenario involves lower demand and greater flows from Libya an Iran. In the bullish case: Libya exports fall away again; sanctions on Iran tighten; non-opec growth decelerates and demand picks up as well Multi-year context, Call on Saudi and (fcst) production (kb/d) 1,5 1, 9,5 9, 8,5 8, 7,5 7, Call on Saudi crude oil + inventories = Global oil demand less non-opec supply (all liquids), less processing gains; less other Opec oil and less Saudi NGLs (all in 3 month MA, and kb/d) Bullish Bearish Central Scenario Production 75 A-13 J-13 O-13 J-14 A-14 J-14 O-14 J-15 Source: Credit Suisse Research 8

10 Global oil supply US has come to dominate growth outside Opec And this year that growth has overwhelmed all incremental demand In the back-ground, the black oil balance problem has been compounding This is the third year that non-opec crude oil growth has overwhelmed incremental demand for crude oil from refiners Non-Opec supply has grown by ~8 kb/d pa on average since 29, and growth accelerated significantly beginning in 212. This year it s on track to overwhelm demand growth. 214 is also the third year in a row that Non-Opec supply overwhelms incremental refiner crude oil demand The US centered shale revolution drives that supply growth In this historical chart we seasonally adjusted monthly data (through Aug 214) and adjusted the base for the US (lhs) and non-opec ex-us (rhs, kb/d) 2, 1,5 Growth (yoy) of non-opec v. demand (kb/d) Non-Opec (ex-us) CAGR: =.7% E = -.31% 46, 44, 1, 1 42, 5 8 4, E 215E 6 US CAGR: = 1.77% E = 11.88% 38, (5) non-opec all oil Oil demand Refiner crude oil (+ direct use) In 212, US crude oil and NGL supplies began to grow by > 1 Mb/d (kb/d) 2 bio fuels NGLs Crude oil and condensate J-4 J-5 J-6 J-7 J-8 J-9 J-1 J-11 J-12 J-13 J-14 36, After headwinds from the rest of non-opec abated, the US + Canada supply yoy surge lifted non-opec gains above 1 Mb/d for the first time in Q The 2 Mb/d non-opec growth hurdle was cleared last quarter (kb/d) Non-Opec total Non-Opec ex-us+can US + Can E 215E -1 Q1-'12 Q3-'12 Q1-'13 Q3-'13 Q1-'14 Q3-'14E Source: Credit Suisse Research, International Energy Agency, Joint Oil Data Initiative and national data sources 9

11 At the core of that US production growth is the tight (shale) oil revolution We re keeping a very close eye on momentum of growth and expect a peak in 214 Growth (yoy) appears to be flat-lining across the Bakken formation (kb/d) 4 3 Net change (yoy, 3mma) Bakken So too in the Eagle Ford, which includes very, very light oil (condensates and NGLs), though its growth is stabilizing at a higher level (kbd/) Eagle Ford 2 1 Decline of the base (yoy) New growth (yoy, 3mma) Jan-7 Jan-8 Jan-9 Jan-1 Jan-11 Jan-12 Jan-13 Jan-14 Permian developments, however are still in take-off mode (kb/d) 4 3 Permian -2 Jan-7 Jan-8 Jan-9 Jan-1 Jan-11 Jan-12 Jan-13 Jan-14 Nor do we have a good feel for the trajectory of growth in Colorado (kb/d) 2 15 Niobrara Jan-7 Jan-8 Jan-9 Jan-1 Jan-11 Jan-12 Jan-13 Jan-14-5 Jan-7 Jan-8 Jan-9 Jan-1 Jan-11 Jan-12 Jan-13 Jan-14 Source: Credit Suisse Research, Energy Information Agency of the US Dept. of Energy 1

12 Globally the US growth trajectory is a key variable the next few years As is Opec s production growth, or rather, its ongoing contraction ( and 215E?) In terms of surprises, the monthly data (through July) for North America diverged the most from forecast Specifically, US NGL counts and Canada s Q2 growth were the biggest misses Global oil production (all liquids) by major geography, 211 through 217E (based on monthly data through Aug 214) 214 base and yoy deltas by quarter and year (kb/d) Y-o-Y Grow th by quarter (' b/d) Y-o-Y Grow th Here are some directional and/or volumetric surprises in the data for 214: 214E 1Q14 2Q14 3Q14E 4Q14E 1Q15E 2Q15E 3Q15E 4Q15E E 215E 216E 217E Global Oil 92,93 1,13 1,5 1,1 1, , , ,155 1, 1,25 1,735 Opec all oil 36, , Non Opec 54,23 1,59 2, 1,9 1,75 1,62 1,45 1, ,255 1,82 1,27 1,14 1,35 North America 2,55 1,45 2,4 1,94 2,2 1,99 1,66 1,44 1, ,295 1,36 1,87 1,56 1,695 1,43 US 12,94 1,3 1,71 1,84 1,83 1,83 1,49 1, ,8 1,15 1,675 1,38 1,385 1,135 Canada 4, Mexico 2, South America 8, Venezuela 2, Brazil 2, Columbia Argentina Europe 4, Norw ay 1, United Kingdom FSU 14, Russia 1, Kazakhstan 1, Azerbaijan Middle East 28, ,29-1, , Saudi Arabia 11, ,1-1, Iran 3, UAE 3, Kuw ait 3, Iraq 3, Qatar 2, Africa 8,3-1,29-1, , Nigeria 2, Algeria 1, Libya 42-1,16-1, ,285 1, Angola 1, Sudan Asia 8, Indonesia China 4, India Source: Credit Suisse Research, International Energy Agency, Joint Oil Data Initiative and national data sources In Mexico, greater declines, and more near-term pessimism ahead of an upturn driven by enhanced industryaccess Brazil pre-salt growth is finally visible North Sea flows have held almost flat Russia s growth has deflated Iran has managed modestly higher production (exporting more condensate) Iraq s H1 growth of ~17 kb/d has turned into a shallow decline in Q3 High expectations for Nigeria were not met And Angola was down ~17 kb/d in H1, before beginning to recover Conversely, Sudan s progress was all but wiped out again this summer In Asia the combination of India, China and Indonesia has barely held steady 11

13 Key sovereign worry spots assumptions in our central scenario While structurally growth in North America trumps nearly all else, simple assumptions about exports from Iraq and Libya can tip the 215 balance For notes on other sovereign worry spots and their respective implications/assumptions for the medium term, please see page 22 In our central scenario for 215 we assume that Iraq s production grows only marginally and that really only from the North; Uncertainty and instability, in this view, prevent a significant upturn in investments for the South where performance is already in jeopardy from stalling activity in our view Expansion plans for the south will sooner rather than later need common infrastructure, most critically for water injection Much larger growth from KRG held territories will, in this scenario, need resolution of legal issues Libya s exports we assume in our central scenario will hold steady While fighting among the roughly 17 heavily armed militias that hold sway over parts of Libya has intensified and Tripoli in some respects no longer is the capital, two or three of the larger militias have established some control over all links in several oil export chains in both the east and the west With some support from Egypt and some Gulf monarchies, militias in the eastern Libya appear to be making progress toward stabilizing territory around Benghazi and Tobruk and points south Oil exports from points west of Tripoli appear less stable Iraq s exports from the North have been disrupted, deflating yoy gains Libya could sustain exports of about half of pre-crisis capacity (Mb/d) Jan-11 Nov-11 Sep-12 Jul-13 May-14 Mar-15E Libyan civil war Rapid recovery Civil society breaks down, exports stop 2 Militias now battle, but some exports flow... Jan-11 Jan-12 Jan-13 Jan-14 Jan-15E Source: Credit Suisse Research, International Energy Agency and Petro-logistics 12

14 Inventories have risen from lean to ample, when they shouldn t have Contra-seasonal stock builds of crude oil, while the swing-producer cut back Conventionally: OECD demand cover is high (all oil stocks / demand in days) Much of the surplus is in crude oil, and built contra-seasonally 16 OECD commercial crude oil inventory, Mbs days cover, yoy (rhs) days cover -4 Days cover, 5yr avg 46-6 J-6 J-7 J-8 J-9 J-1 J-11 J-12 J-13 J-14 And above trend crude oil imports into China have left room for builds too yr max-min 5yr avg Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec All this as Saudi crude oil exports fell 1 Mb/d from last Oct through Aug Crude oil imports: Actual v required, inventory implications (kb/d) diff with actual (rhs) crude oil net imports, 3ma 4 MA trend of required ytd cumulative implied stock chg (rhs) Saudi crude oil exports since the onset of the Arab Awakening (kb/d) Jan-1 Jan-11 Jan-12 Jan-13 Jan mom, 3mma (rhs) crude exports, 3mma yoy, 3mma (rhs) 45 Jan-11 Jan-12 Jan-13 Jan Source: Credit Suisse Research, International Energy Agency, Joint Oil Data Initiative and national data sources 13

15 There is no sign of a collapse of oil demand on the contrary Q2 s unfortunately timed growth contraction is not a new trend Global demand level trends drawn through seasonally adjusted monthly data (Log scale) 11.5 OECD oil demand dipped again into H1-214, and Q2 was the low point (yoy) J-8 J-9 J-1 J-11 J-12 J-13 J J-8 J-9 J-1 J-11 J-12 J-13 J-14 EM Oil demand remains resolutely on a growth track which is steeper for EM ex China which comprises >33% of total demand J-8 J-9 J-1 J-11 J-12 J-13 J J-8 J-9 J-1 J-11 J-12 J-13 J-14 Source: Credit Suisse Research, International Energy Agency, Joint Oil Data Initiative and national data sources 14

16 Where oil demand growth really derives from Fascinating short-run oscillations worry markets but one picture should continue to emerge US demand growth by product explains this year s biggest divergence from (our) forecasts it under-delivered in Q2 by some 3 kb/d thanks to LPG 7 212/11 213/12 214E/213 Others*** China gasoline demand growth (~1-11%, pa) is not slowing this year, monthly data through August, kb/d (kb/d) 2,5 5% 5 LPGs** 2,25 4% 3 Fuel oil 2, 3% 1-1 Jet fuel 1,75 2% -3 Diesel* 1,5 1% -5 Gasoline 1,25 % This is the big history picture that will continue to dominate. The rest is fascinating and important, but most commentary is oblivious to a 5-year long dynamic of EM ex- China oil demand that s currently tracking a ~1.5Mb/d pa expansion rate of which the transport component has begun to accelerate 35 3 EM ex China Total o/w Transport 1, Jan-7 Jan-8 Jan-9 Jan-1 Jan-11 Jan-12 Jan-13 Jan-14 China s middle distillate (diesel + (jet-) kerosene) consumption won t go sideways forever. More interesting is that even its three year pause did not trash oil prices, same monthly data series through August 214 (kb/d) 4,25 8% -1% , 3,75 3,5 3,25 3, 2,75 2,5 2,25 2, Jan-7 Jan-8 Jan-9 Jan-1 Jan-11 Jan-12 Jan-13 Jan-14 7% 6% 5% 4% 3% 2% 1% % -1% Source: Credit Suisse Research, Energy Information Agency of the US Dept. of Energy, China NBS and BP Statistical Review of World Energy 15

17 Where oil demand growth comes from in We keep running micro-driven forecasts that more often miss DM not EM The bigger shock so far this year has come from the OECD in the second quarter. Oil use in North America now appears to have contracted by.7% yoy in Q2, a large 4 kb/d undershoot of the 1.1% estimate we had arrived at in June (an estimate built on April monthly data and US weekly data through early June) Note too that yoy EM growth remains close to 3%. Indeed revisions to last year s data now show 3% growth in 213 as well despite all the US dollar and rate worries that dominated the discussion a year ago. Lastly please note that China s sub 2% growth pace is not hugely detrimental to the broader story Global oil demand growth deltas by quarter and year from a 213 base by region and principal oil-economies 1, b/ d Base by quarter ( ) by year (21-16) "norm" Notes on data surprises 213 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14E 4Q14E E 215E 216E Glo bal 91,7 2.% 1.8% 1.6% 1.2% 1.1%.9%.8%.9% 1.5%.8% 1.7%.9% 1.4% 1.5% 1.7% OECD 46,13 -.6%.3% 1.1%.7% -.4% -1.7% -.5% -.5% -1.% -1.2%.4% -.8%.1% -.2% -1.7% Emerging M arkets 45,57 4.8% 3.4% 2.2% 1.8% 2.6% 3.5% 2.% 2.2% 4.3% 3.% 3.% 2.6% 2.6% 3.% 4.1% OEC D A mericas 24,15 2.1% 1.4% 2.6% 2.5%.2% -.7%.8%.3% -.7% -1.5% 2.2%.1%.6%.4% -1.8% Canada 2,42 8.6% 5.5%.6% -1.4% -1.5% -1.1% 1.7% 1.6% 1.2% 1.8% 3.1%.2% 1.8%.9%.1% M exico 2,4.7%.4% -1.1% -7.5% -4.6% -5.2% -1.5% 2.9% 1.5% -1.3% -2.% -2.1% 2.1%.8% -.8% USA 19,3 1.5%.9% 3.3% 4.4%.9%.%.9% -.3% -1.2% -2.1% 2.6%.4%.3%.2% -2.1% So uth A merica 6,57 4.4% 4.3% 5.% 4.% 3.% 1.4% 1.5% 2.2% 3.6% 3.6% 4.4% 2.% 2.2% 1.9% 4.5% Brazil 3,3 4.8% 4.1% 6.% 3.8% 5.4% 4.5% 2.2% 3.1% 3.8% 4.5% 4.7% 3.7% 2.% 1.4% 5.4% Argentina % 2.9% 2.1% 3.3% 1.3% -8.5% 1.1% 3.6% 3.3% 6.2% 3.% -.5% 3.5% 3.5% 4.1% Euro pe 14,54-4.1% -.5%.4% -1.1% -1.4% -2.7% -.6%.3% -2.8% -3.% -1.3% -1.1%.6% -.5% -2.3% France 1,77-3.1% 2.4% 1.5% -1.8% -5.2% -5.7% -1.7% -.9% -2.2% -1.2% -.3% -3.4%.2% -2.1% -2.2% Germany 2,4-1.% 5.1% 1.3% -3.1% 1.5% -7.6% -1.6% -.8% -3.% -.1%.6% -2.2% 2.3% -4.2% -.1% Italy 1,32-4.6% -6.3% -3.9% -1.3% -6.9% -6.4% -2.%.% -3.3% -8.3% -4.% -3.8% -.6%.% -4.5% UK 1,51-3.5% -1.1%.4% -1.% -1.7% -.7% -.8% -.9% -2.6% -3.2% -1.3% -1.%.7% -.8% -2.7% Oth Europe 7,54-5.3% -1.7%.7% -.3% -.3% -.2%.2% 1.2% -2.8% -3.2% -1.6%.2%.3% 1.1% -2.4% F SU 4,56.9% 2.1% 4.% 4.7% 8.7% 2.6% 2.2%.9% 8.% 3.1% 3.% 3.5% 1.% 2.% 2.2% M ideast 7,96 7.1% 2.6% 1.5% 2.3% 5.4% 6.1% 2.2% 1.7% 4.4% 2.4% 3.3% 3.8% 3.1% 4.1% 4.1% Saudi Arabia 3,5 7.1%.8% -2.3% 5.% 6.1% 13.3% 4.4% 3.3% 5.% 4.9% 2.3% 6.8% 3.% 3.% 7.1% Iran 2, 9.7% 5.7% 3.5% -2.1% 5.% 1.% 2.% 2.% 4.1% -1.1% 4.% 2.5% 3.5% 4.%.3% Iraq % 7.1% 13.4% 3.3% 7.7%.1% -7.2% -1.% 9.2% 9.6% 7.2% -2.6%.% 1.% 13.2% A frica 3,67 8.4% 7.% -3.7% 1.5%.1% 3.7% 1.6% 3.2% -1.4% 2.1% 3.2% 2.1% 3.8% 3.7% 3.7% A sia-p ac 3,25 2.6% 1.9% 1.% -.1%.5% 1.9%.5%.8% 4.% 3.3% 1.3%.9% 1.6% 2.1% 3.2% China 1,36 5.6% 4.2% 2.% -2.2% -1.4% 2.4% 1.9% 3.5% 4.9% 3.9% 2.3% 1.6% 2.7% 3.% 6.4% India 3,73 4.8% 1.1% -1.%.6% 2.8% 5.3% 2.8% 2.1% 5.1% 5.7% 1.4% 3.3% 3.3% 4.% 3.7% Indonesia 1,78 2.6% 1.9% 5.9% 5.1% 5.2% 8.7% 4.3% 2.1% 8.9% 2.8% 4.% 5.% 3.% 3.% 5.3% Japan 4,53-3.8% -4.2% -3.8% -2.2% -.7% -5.% -8.4% -7.6% 2.6% 3.4% -3.5% -5.3% -3.5% -2.1% -1.2% South Korea 2,32-1.2% 2.% -.4%.1% 1.2% 1.1% 1.1%.3% -.4% 2.8%.1%.9%.4%.3%.8% Australia 1,8 1.7% 1.4%.6% -.2%.2%.% 1.7%.8% 4.3% 2.4%.9%.7%.6% 1.% 1.7% Thailand 1,26 6.8% 2.6%.9%.8%.5% 2.8%.% 1.2% 5.2% 6.3% 2.7% 1.1% 2.2% 3.% 3.7% Source: Credit Suisse Research, International Energy Agency, Joint Oil Data Initiative and national data sources Big revisions to data collected by the IEA raised levels for EM oil demand in 213 and their growth rates as well OECD demand came in materially lower for Q2 Especially in the US And Japan (relatively speaking) Secondarily Europe Mideast growth rates remained very high in Q2, judging from Jodi submissions We revised historic data for the FSU (up), India (down), Brazil (down) and Venezuela (up) in line with estimates published in the BP statistical review Looking forward, we apply for 215 a step change up for maritime diesel demand (+15 kb/d) and a step down for fuel oil 16

18 Compounding weakness in 214: Refiners needed less black oil

19 Our black oil balance explains more of the 214 weakness This year even less crude oil demand growth emerged than sluggish final demand indicates We estimate that required refinery run growth was less than 5 kb/d, easily met by incremental runs in the US and Saudi Arabia (+~4 kb/d each) More and more does refiner crude demand lag final product consumption Essentially: better oil refiners meet more demand with less crude oil Several factors contribute to this accelerating trend New capacity and upgraded old kit adds up to higher complexity yielding more valuable product per barrel of feedstock; Feedstock too has gotten lighter (partly due to greater condensate and NGL cuts and more and more are refiners disintermediated from new demand (e.g. US NGLs into chemical crackers displacing some naphtha) Middle distillates increasingly drive refiner crude oil requirements Nearly all diesel and kerosene comes from refiners and is core to margins Early 215, middle distillate demand growth gets a lift from shipping Also, EM demand for diesel and jet should grow a little faster While last winter s base effects add a positive delta early in 215 as well We project refinery runs need to rise ~ 1.2 Mb/d in 215 (of which only ~5 kb/d comes from the US and Saudi Arabia combined) Last year 1.4 Mb/d of oil demand growth required only ~4 kb/d higher Driven by ~5 kb/d diesel demand growth and a.3% yield lift to 44.3% refiner crude runs, reports BP Statistical Review of World Energy History (198-13) of the growing gap between final oil filling the gap, thank light liquids and light end substitutions from shale (kb/d) demand and refiner crude oil runs (kb/d) LPG ex refiners 95 final demand 9 9 'Top down' excess of light ends Refiner crude throughput Bio fuels Processing gains Other uses of crude oil Refiner crude runs, history and CS projection E 215E Oil Consumption Crude oil demand Source: Credit Suisse Research, International Energy Agency and BP Statistical Review of World Energy 18

20 What if the Saudis don t cut: the answer isn t pretty or simple

21 Stress testing the US upstream A dip and then resilience Our colleagues in CS Equities Research who cover many of the companies responsible for the phenomenal growth of the US upstream ran a $7/b WTI oil price scenario through their models. We then ran the resultant capital spending implications through the rig-by-rig US oil production model: In the case of $7/WTI upstream growth momentum would quickly deflate. Next year -11% fewer wells would be completed and volume production growth would fall by a third to some 74 kb/d, from this year s record high; But the well count would recover, as residual volume growth enhances the industry s bottom line. That, plus possible consolidation would allow spending to grow again US oil production should reach a plateau early next decade, and the growth trajectory for black oil and condensate is fairly resilient to $7/WTI Mb/d) Current forecast Shock and then recovery E 215E 216E 217E 218E 219E 22E 221E 222E Momentum of growth would take a hit in 215, then recover (kb/d) 1,4 Current forecast Shock and then recovery 1,2 1, E 215E 216E 217E 218E 219E 22E 221E 222E US Oil Production E 215E 216E 217E 218E 219E 22E 221E 222E Current, kbd 7,45 8,68 9,715 1,781 11,523 12,33 12,411 12,89 12,982 13, Sensitivity, kbd 7,45 8,64 9,34 1,212 11,11 11,751 12,239 12,654 12,763 13,41 Change, kbd (75) (376) (568) (512) (282) (172) (155) (218) (249) Growth yoy oil, current (kbd) 1,23 1,36 1, Growth yoy oil, sensitivity (kbd) 1, Delta in growth (75) (31) (193) (63) (31) No. Wells, Current 16,467 16,626 17,29 17,336 18,137 No. Wells, Sensitivity 14,859 16,285 16,883 18,33 Change in Well Count, current vs sensitivity -11% -6% -3% -1% yoy well count -1% 1% 4% 7% Source: Credit Suisse Research 2

22 And there remain the long-run stabilizers Transport demand growth remains strong across EM it s accelerating in many economies History of US oil demand, driven by use of oil in transport (Mb/d, e) 25 US Total o/w Transport 2 China s oil demand on the same scale (kb/d, e) 25 China Total o/w Transport Clearly the rest of DM is in full-on decline, but that s less important if EM ex-china remains in full-on growth mode (Mb/, e) 35 3 OECD Ex US Total o/w Transport 35 3 EM ex China Total o/w Transport Source: Credit Suisse Research and BP Statistical Review of World Energy 21

23 We should not lose sight of MENA risks (aka Black Turtles) We suspect that we remain too optimistic about interruption risk for sovereign producers Aggregate disruptions to sovereign producer oil exports in North Africa and the Mideast rose from early 211 through early 214 While there has been no new significant disruption of oil exports since, there probably will be more it s just that we cannot time and forecast them Here is a rough categorizing of which sovereign oil flows we are keeping a weary eye on (see also page 12 for separate comment on Libya and Iraq): Acute risk mostly negative, except Iran: Libya intensifying violent conflict can disrupt flow at any time Iraq the war on ISIL could spark sabotage, or worse, of southern oil fields Iran while negotiations between Tehran and the P5+1 appeared moribund from late July through early September, it appears as if all parties are redoubling their efforts to arrive at a face-saving compromise by late November s deadline. For these and other reasons we are assuming moderately higher exports in the next few years. Risks run to either side. Aggregate disruptions to exports from sovereign oil producers in MENA (kb/d) Libya Iran Sudan Egypt Syria Yemen Forecast through Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14 Jan-15E Moderate to high disruption risk Nigeria has underperformed relative to capacity and looming presidential elections risk widening already wide rifts among key stake-holders Islamic fundamentalists challenge federal government authority across seemingly still growing territory in northern states And stability across oil producing southern states remains under threat from efforts to restructure the upstream industry and wealth sharing Algeria is vulnerable to the same demographic and governing trends that toppled governments in Tunisia, Egypt, Yemen and Libya Venezuela has become less stable after the death of Hugo Chavez in 213. No new significant oil development projects have come of the drawing board. Upstream spending and activity have regressed. A crisis could entail disruptions of exports Troubled investment climates elevate risk of higher MT decline rates Russia newly installed US and EU sanctions cloud the investment horizon. The crisis surrounding Ukraine, which was the catalyst to the latest sanctions, is not over South of Iraq needs multi-billion dollar investments, and foreign partners, to come close to delivering anything like the upstream capacity expansions that many medium term supply/demand balances still rests on Iran even if nuclear negotiations with the P5+1 prove successful, broader US sanctions, and possibly some EU sanctions as well, could prove quite sticky and prevent a rapid rise in Iran s capacity Source: Credit Suisse Research, International Energy Agency and Petro-logistics 22

24 Including of course the underlying decline rates of producing fields Globally, every year 4 Mb/d of new capacity has to be developed, just to stand still Average per annum decline rates in evidence in the 1 years of data from % 18% 16% 14% 12% 1% 8% 6% 4% 2% % Source: Credit Suisse Research and Woodmac 23

25 WTI will cope: We see some weakness, but no super-congestion

26 US super congestion averted again and again? A for-sure collapse of WTI prices appears avoidable in late 214 Tactically speaking we suspect that a last year s significant de-coupling of Gulf Coast crude oil markets is unlikely to repeat during this year s autumn refiner-maintenance season The first half of 215, however, should prove trickier to navigate Crude oil markets around Houston look like they may be significantly oversupplied in H1-214 which would have a direct bearing on WTI since crude oil would quickly back up at the Cushing, OK, the futures contract delivery point For a more in-depth discussion please see Independent Refiners: 4Q Crude is Tight; 2Q Earnings Look Good; 215 Maintenance Season Still Ahead. Here are two of the more relevant charts from that report: Expected total CDU maintenance (planned + unplanned) PADDs I IV (kb/d) Crude oil imports into PADD III are down (Mb/d) And look to stay low 1,8 1,6 1,4 1,2 1, J-13 J-14 J J F M A M J J A S O N D Prior 5 Year Range Prior 5 Year Average Source: Credit Suisse Research and the Energy Information Agency of the US Dept. of Energy 25

27 The broader oil calculus in North America While in 215 more imports need rejecting, after that capacity gains should do the trick We look at oil supply balances east of the Rocky Mountains (Padds I-IV) and Canada combined E 215E US Refining Capacity US Overall, kbd 17,616 17,691 17,39 17,736 17,882 17,981 PADD 1-4, kbd 14,397 14,54 14,324 14,76 14,891 15,74 PADD V 3,219 3,151 3,66 3,3 2,99 2,97 US Crude Runs US Overall, kbd 14,72 14,799 14,997 15,39 15,722 15,919 PADD 1-4, kbd 12,369 12,453 12,667 12,97 13,368 13,591 PADD V 2,351 2,345 2,331 2,338 2,353 2,328 US Overall, yoy PADD 1-4, yoy Memo : Maintenance, PADD 1-4, kbd NA NA Utilisation, PADD 1-4, % 85.9% 85.6% 88.3% 88.% 89.7% 9.2% Utilisation (Ex Maintenance) NA NA 94.7% 93.5% 95.2% 95.5% US Crude Production US Overall, kbd 5,483 5,643 6,496 7,45 8,588 9,674 PADD 1-4, kbd 4,27 4,494 5,382 6,338 7,495 8,648 PADD V 1,212 1,15 1,114 1,111 1,93 1,26 US Overall, yoy ,138 1,85 PADD 1-4, yoy ,156 1,153 US Crude Imports US Overall, kbd 9,212 8,929 8,528 7,715 7,343 6,843 PADD 1-4, kbd 8,7 7,742 7,368 6,62 6,256 5,794 PADD V 1,142 1,187 1,16 1,94 1,87 1,48 US Overall, yoy PADD 1-4, yoy Exports & InterPADD movements Total US Exports PADD 1-4, Exports (Canada+Field Condensate) PADD V InterPADD movements to PADD Yr End Crude Inventory Padd 1-4, MB Source: Credit Suisse Research and the Energy Information Agency of the US Dept. of Energy In 214 the average annual Brent WTI differential narrowed significantly, again. More of the considerable oil supply growth has been absorbed by US and Canadian refiners: US refiner crude runs, east of the Rockies, or in Padds I-IV, are on track to rise by ~4 kb/d US exports (crude oil to Canada and condensates elsewhere) have risen by ~25 kb/d Inventories associated with production and higher refiner utilization will likely rise too Consequently, it seems as if this year only half as much imports needed to be rejected vs 213 Next year, however, there should be more rejecting of imports (~5 kb/d, or 3% more than in 214), requiring, in our view, wider differentials (discounts), and therefore a wider Brent/WTI spread We expect another 1.1 Mb/d increase in black oil (and condensate) production growth Refiners can, in our view, add some 5 bpps to utilization Exports (to Canada, and of condensates) we project will rise by another ~22 kb/d And another 5 kb/d of oil can be shifted to the US West Coast 26

28 Appendix: Detailed data of supply, demand, inventories and assumptions

29 CS oil balance: Supply side Supply Q1-'13 Q2-'13 Q3-'13 Q4-' Q1-'14 Q2-'14 Q3-'14E Q4-'14E 214E Q1-'15E Q2-'15E Q3-'15E Q4-'15E 215E 216E 217E Global YoY Grow th, net mb/d YoY Growth, % 2.9% 1.1% 2.7%.3%.6% 1.4%.9%.8% 1.2% 1.1% 1.2% 1.5% 1.3%.9%.9% 1.5% 1.% 1.1% 1.3% 1.8% Non OPEC YoY Grow th, net mb/d YoY Growth, % 2.5%.3% 1.5% 1.3% 2.4% 3.4% 2.8% 2.5% 3.1% 3.8% 3.6% 3.3% 3.5% 3.% 2.7% 2.3% 1.4% 2.3% 2.1% 2.4% North America YoY Grow th, net mb/d YoY Growth, % 4.3% 3.8% 8.2% 6.6% 7.3% 1.3% 8.% 8.1% 8.1% 11.5% 1.6% 1.6% 1.2% 1.3% 8.4% 7.1% 5.5% 7.7% 7.8% 6.1% South America YoY Grow th, net mb/d YoY Growth, % 4.9% 1.7% -.8% -3.% 1.3% 3.2% 2.%.8% 3.1% 3.5% 2.2% -2.% 1.7% -.1% 2.7% 2.4% 2.1% 1.8% -1.4% 3.4% Europe YoY Grow th, net mb/d YoY Growth, % -7.% -7.8% -6.1% -9.3% -7.% -.5% 1.3% -4.1% 1.9% -1.1% -.6% -.4%.%.9% -.2%.4%.2%.3% -1.5% -2.5% FSU YoY Grow th, net mb/d YoY Growth, % 2.6% 1.8%.4% 1.5% 1.9% 2.1% 1.8% 1.8%.5% -.1% -.7%.% -.1% -.5% -.1% -.2% -.2% -.3% -.2%.7% Russia YoY Grow th, net mb/d YoY Growth, % 3.2% 2.7% 1.% 1.3% 1.9% 1.4%.9% 1.4%.6%.2% -.6%.4%.2% -.2% -.2% -.2% -.2% -.2%.8%.6% Africa YoY Grow th, net mb/d YoY Growth, %.2% -8.% -8.6% -4.1% 2.1% 1.% 2.2%.2% 2.6% -.4% -.6% -2.1% -.1% -4.8% -3.9% -1.4% -3.4% -3.4%.8% 2.6% Mideast YoY Grow th, net mb/d YoY Growth, % 2.% -3.9% -12.9% -2.2% -9.8% -1.2% -9.9% -8.1% -3.9% -.2% -1.4%.3% -1.3% -2.2% -2.4% -5.4% -7.9% -4.5% -6.% -3.8% Asia YoY Grow th, net mb/d YoY Growth, % 4.2% -1.1% 1.6%.1% 1.1% -3.1% -2.7% -1.2% -1.5% -1.5%.2% -1.2% -1.% -2.% -2.2% -2.3% -3.2% -2.4% -4.% -3.% Processing gain OPEC YoY Grow th, net mb/d YoY Growth, % 3.6% 2.% 4.2% -1.% -1.8% -1.3% -1.9% -1.5% -1.4% -2.7% -2.3% -1.2% -1.9% -2.3% -1.8%.2%.4% -.9%.2% 1.1% Opec Crude Oil YoY Grow th, net mb/d YoY Growth, % 3.% 1.4% 3.9% -2.8% -3.7% -3.2% -3.9% -3.4% -1.4% -2.8% -2.3% -.8% -1.9% -2.3% -1.6%.6%.8% -.6%.3%.7% Opec YoY Grow th, net mb/d YoY Growth, % 3.2%.3% 3.3% -4.1% -4.3% -3.1% -3.8% -3.8% -2.1% -3.8% -2.3% -.8% -2.3% -2.5% -1.8% -.7% -.7% -1.4% -.1% Opec non-crude YoY Grow th, net mb/d YoY Growth, % 6.9% 5.2% 6.% 8.% 8.5% 8.8% 8.3% 8.4% -1.2% -1.8% -1.9% -3.% -2.% -2.3% -2.6% -2.1% -1.3% -2.1% -.4% 2.7% Source: Credit Suisse Research, International Energy Agency, Joint Oil Data Initiative and national data sources 28

30 CS oil balance: Demand side and bottom line of implied and reported stks Demand Q1-'13 Q2-'13 Q3-'13 Q4-' Q1-'14 Q2-'14 Q3-'14E Q4-'14E 214E Q1-'15E Q2-'15E Q3-'15E Q4-'15E 215E 216E 217E Global YoY Grow th, net mb/d YoY Growth, % 3.5% 1.5%.8% 2.% 1.8% 1.6% 1.2% 1.7% 1.1%.9%.8%.9%.9% 1.4% 1.6% 1.2% 1.3% 1.4% 1.5% 1.7% OECD YoY Grow th, net mb/d YoY Growth, % 1.4% -1.% -1.2% -.6%.3% 1.1%.7%.4% -.4% -1.7% -.5% -.5% -.8%.3%.6% -.3% -.1%.1% -.2% -.3% Americas YoY Grow th, net mb/d YoY Growth, % 2.% -.7% -1.5% 2.1% 1.4% 2.6% 2.5% 2.2%.2% -.7%.8%.3%.1% 1.1% 1.2% -.4%.3%.6%.4%.9% Europe YoY Grow th, net mb/d YoY Growth, %.% -2.9% -3.% -4.1% -.5%.3% -1.4% -1.4% -1.5% -2.9% -.8%.2% -1.3% 1.3%.4%.3% -.1%.5% -.7% -.2% Asia Pacific YoY Grow th, net mb/d YoY Growth, % 2.1% 1.9% 3.% -2.4% -1.6% -2.1% -1.2% -1.8%.% -2.3% -4.% -4.1% -2.6% -3.6% -1.1% -1.% -.9% -1.7% -.9% -4.3% Non-OECD YoY Grow th, net mb/d YoY Growth, % 6.1% 4.3% 3.% 4.8% 3.4% 2.2% 1.8% 3.% 2.6% 3.5% 2.% 2.2% 2.6% 2.6% 2.5% 2.7% 2.7% 2.6% 3.% 3.5% Former Soviet Union YoY Grow th, net mb/d YoY Growth, % 2.3% 8.% 3.1%.9% 2.1% 4.% 4.7% 3.% 8.7% 2.6% 2.2%.9% 3.5% 1.% 1.% 1.% 1.% 1.% 2.%.7% China YoY Grow th, net mb/d YoY Growth, % 14.% 4.9% 3.9% 5.6% 4.2% 2.% -2.2% 2.3% -1.4% 2.4% 1.9% 3.5% 1.6% 2.7% 2.7% 2.7% 2.8% 2.7% 3.% 3.3% Other emerging Asia YoY Grow th, net mb/d YoY Growth, % 5.5% 4.9% 3.% 3.9% 2.2% 2.4% 2.6% 2.8% 2.7% 4.1% 2.3% 1.8% 2.7% 2.6% 2.6% 2.8% 2.8% 2.7% 3.1% 3.7% South America YoY Grow th, net mb/d YoY Growth, % 5.4% 3.6% 3.6% 4.4% 4.3% 5.% 4.% 4.4% 3.% 1.4% 1.5% 2.2% 2.% 2.2% 1.9% 2.2% 2.4% 2.2% 1.9% 4.3% Mideast YoY Grow th, net mb/d YoY Growth, % 2.4% 4.4% 2.4% 7.1% 2.6% 1.5% 2.3% 3.3% 5.4% 6.1% 2.2% 1.7% 3.8% 2.9% 3.% 3.2% 3.2% 3.1% 4.1% 4.6% Africa YoY Grow th, net mb/d YoY Growth, % 4.4% -1.4% 2.1% 8.4% 7.% -3.7% 1.5% 3.2%.1% 3.7% 1.6% 3.2% 2.1% 3.7% 3.7% 4.% 3.7% 3.8% 3.7% 4.5% Balance, stocks Q1-'13 Q2-'13 Q3-'13 Q4-' Q1-'14 Q2-'14 Q3-'14E Q4-'14E 214E Q1-'15E Q2-'15E Q3-'15E Q4-'15E 215E 216E 217E Implied inventory change Reported oil inventory: OECD stock change OECD inv entory (billion barrels) Cover, days demand 'Call on Opec & stocks" YoY Grow th, net mb/d YoY Growth, % 4.8% 2.6% -1.3% 2.1% -.6% -2.5% -2.8% -1.% -1.9% -3.7% -3.6% -2.6% -3.% -1.4%.9%.% 9.4%.3% 3.2% 2.3% Source: Credit Suisse Research, International Energy Agency, Joint Oil Data Initiative and national data sources 29

31 OECD commercial inventories with preliminary data through August Mbls Aug(e) surplus/deficit July End month July Aug Sept Oct Nov Dec Jan Feb Mar Apr May June July Aug(e) YoY 5yr YoY 5yr mbls % mbls % mbls mbls OECD Crude oil , , 996 1,16 1, , Products 1,686 1,78 1,73 1,647 1,617 1,61 1,613 1,591 1,566 1,584 1,629 1,63 1,67 1, All oil 2,665 2,667 2,69 2,653 2,599 2,558 2,561 2,56 2,566 2,581 2,645 2,641 2,663 2, N. America Crude oil Products Gasoline Mid distillate All oil 1,369 1,382 1,392 1,365 1,338 1,36 1,285 1,29 1,294 1,329 1,36 1,368 1,375 1, Europe Crude oil Products Gasoline Mid distillate All oil Asia Pacific Crude oil Products Gasoline Mid distillate All oil Source: Credit Suisse Research, International Energy Agency and national data sources 3

32 Disclosures