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COMMODITIES RESEARCH 26 September 20

PLEASE SEE ANALYST CERTIFICATIONS AND IMPORTANT DISCLOSURES STARTING AFTER PAGE 70

OIL SKETCHES

Dancing in the dark

Among all the detailed data releases we cover in this report, very few, if any at all, capturethe current mood of the oil market. Prices have lured away from fundamentals to focusingon the increasing probability for the global economy to take another lurch down and whatshape that movement away from the recovery would be. Globally, macroeconomic datahas started to come off the boil for some time now, while the final nail in the coffin wasprovided by the latest FOMC statement, which seemingly expressed far less confidence inthe US economic outlook without addressing any substantial policy measures to tackle it.Thus, much of the immediate action in oil is simply based on the same climate ofeconomic fear that is battering all other asset classes, which then creates a cascadingeffect involving technical triggers, precipitous price falls and a disregard for the underlying

fundamentals. Yet, those fundamentals are looking remarkably robust, especially whenconsidered against the current economic backdrop where political impasse and austeritymeasures have curbed growth in most of the OECD. Much of that tightness in the oilmarket has risen from a hugely disappointing supply-side performance, but even demandhas held up fairly robustly, still putting in months of near 1 mb/d of y/y growth globally,contrary to that portrayed by sentiment. Thus, there has been a major and long-liveddisconnect between data and sentiment. The question then is where now for oil prices?While it would be naive to assume that a purely macro-based view of commodities pricesmust always win out, it is also true that with equity markets still capable of putting in asuccession of 5% plus down-days, it is too early to look for the short-term floor in oil. Ifconfidence in global policy makers falters further and weaker economic outcomes persistand turn more negative, then it is very likely that an attempt to price in sharply lowerdemand perceptions and lower risk appetite will create heightened volatility and adownward lurch in prices. Yet, if the world economy manages to generate some growth,albeit at a slower pace, we would expect oil prices to remain well supported above$90-$100 (Brent equivalent), which we put as the bare minimum economic rent belowwhere key producers and the industry as a whole start to look rather uncomfortable in themedium term. The more likely status-quo, given the current health of the supply side, islikely to be one where the fast-eroding inventory buffers and spare OPEC capacity keepsthe market fundamentally tight, leading to a significant probability of a very sharpupwards move in prices once these macro fears are allayed. .

Miswin Mahesh

+44 (0)20 7773 4291

[email protected]

Amrita Sen

+44 (0)20 3134 2266

[email protected]

www.barcap.com

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Barclays Capital | Oil Sketches

26 September 2011 2

TABLE OF CONTENTS

DEMAND AND SUPPLY HIGHLIGHTS 3FOCUS: WTI AND CUSHING BALANCES MYTH VS REALITY 12MONTHLY DATA RELEASES 27OPEC production estimates................................................................................................................... 28US crude oil imports ................................................................................................................................ 31US data revisions ...................................................................................................................................... 33Japan............................................................................................................................................................ 37Europe continental big 4 ..................................................................................................................... 40South Korea ............................................................................................................................................... 41Middle East ................................................................................................................................................ 42India............................................................................................................................................................. 43China........................................................................................................................................................... 44Air traffic..................................................................................................................................................... 46US trucking data....................................................................................................................................... 47Russia.......................................................................................................................................................... 48United Kingdom........................................................................................................................................ 49Mexico ........................................................................................................................................................ 51Brazil............................................................................................................................................................ 53International rig counts........................................................................................................................... 54Norway ....................................................................................................................................................... 56US oil production...................................................................................................................................... 57Canada........................................................................................................................................................ 59MARKETS AND PRICES 61Price ranges and crude oil forward curves......................................................................................... 61Saudi Arabian crude oil pricing............................................................................................................. 62MARKET BALANCES AND FORECASTS 63TRADE RECOMMENDATIONS 67PRICE FORECASTS 69

Data in this report comes from the following sources unless otherwise noted, and from Barclays Capital calculations.Pages 28 to 30: Energy Information Administration Short Term Energy Outlook, International Energy Agency OilMarket Report, Middle East Economic Survey, OPEC Monthly Oil Market Report, Reuters, Bloomberg. Pages 31 to 32:US Energy Information Administration. Pages 49 to 50: UK Department for Business, Enterprise and RegulatoryReform. Pages 51 to 53: Petroleos Mexicanos Indicadores Petroleros. Pages 54 to 55: Baker-Hughes. Pages 38 to 39:Ministry of Economy Trade and Industry, Preliminary Report on Petroleum Statistics.Page 56: Norwegian PetroleumDirectorate. Page 44: China Customs. Page 45 to 46: Energy Information Administration Petroleum Supply Monthly.Page 63 to 69: International Energy Agency Oil Market Report, OPEC Monthly Oil Market Report, Energy InformationAdministration Short Term Energy Outlook.

Sources

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26 September 2011 3

DEMAND AND SUPPLY HIGHLIGHTS

Demand

On the demand front, the market has started prioritising fear over fundamentals whileprojecting growth. A widespread perception of demand weakness has stemmed from the

market favouring macroeconomic gyrations as a proxy to project oil demand, rather thanderiving the trajectory from the underlying trend seen in demand data. Yes there are someweak spots in demand, but the weakness seen continues to be less pronounced than thatseen during the troughs of the 2008-09 cycle. In fact, OECD demand has shown signs ofimprovement, with US demand recovering slightly from a weak Q2, while OECD Pacificdemand is rebounding with good support from resurgence in Japan and South Korea.European demand showed weakness in July but was is in line with the trend seen lately andin line with consensus expectations. Most importantly however, even if prospects for OECDdemand were to fall to the extremes of the expectation spectrum, the health of non-OECDdemand is undisputedly strong. Crucially, even though demand growth rates inheavyweights China and India have slowed from the peaks, they continue to remain strong,supported by structural factors. Further new strong points are emerging, in major oil

producing countries with Russian and Saudi demand close to or at peak levels.Prospects for US oil demand continues to be riddled with macroeconomic undercurrents;nevertheless, the latest set of data revisions and the weekly readings does show someimprovement from the rather weak Q2. In the latest Petroleum Supply Monthly (PSM), USoil demand for June was revised higher by 273 thousand b/d to 19.277mb/d (see page 33for details). This was the first upward revision in three months, and takes June up to thehighest monthly reading of the year so far, although lower y/y by 260 thousand b/d.Nonetheless, largely due to this upward revision, Q2 demand ended on an improving note,but still remained weak, decreasing y/y by 2.1%. Q3 saw the improving trend in June beingcarried forward, and although the month-to-date September data has shown renewedweakness, overall, unrevised US oil demand in Q3 is running lower y/y by 1.8%. Whilegasoline remains weak, diesel demand has remained far more robust (up y/y in the year-to-

date by 1.5%) when compared to the 2008-09 cycle, where declines of 6% and 7.9% wererecorded respectively. In fact, the latest trucking data showed a solid y/y increase of 3.6% intotal miles driven in July, with long-haul mileage making robust progression over the monthtoo. Rail freight data, in the meantime, having started the month on a softer note, haspicked up substantially to the strongest weekly reading in exactly a year.

When the market is not concerned about US demand, the other country it tends to focus onis China and the potential imminent slowdown in Chinese oil demand. While the latestAugust reading shows Chinese apparent consumption slipped just below 9mb/d for thefirst time this year, it still remained higher y/y by 7.4%. Indeed, Chinese oil demand hasplateaued at a rather high base even after slowing down, with 9 mb/d increasingly lookinglike the new status quo for demand generated by the country and should allay fears of anyhard landing for oil consumption itself. In order to fully understand the gravity of this

consumption figure, a comparison to just three years ago shows us that Chinese oil demandis now almost 3 mb/d higher and compared to two years ago, it is now some 2.5 mb/dhigher, such has been the scale of progression made. Indeed, in the year-to-date, Chineseoil demand now averages around 9.2 mb/d, running higher y/y by 734 thousand b/d(8.8%) and has not shown any material signs of a slowdown apart, beyond that in line withthe soft landing in the economy itself. With overall Chinese economic activity picking up, asis apparent from the broader macro data (Septembers China Business Sentiment Surveyhas picked up after slowing the last two months), we would expect the softer Q3 indications(by Chinese standards) to improve in Q4, especially with the trend of destocking slowingsomewhat and possible restocking as we head to the next quarter.

Prioritizing fear over

fundamentals

US oil demand: Q3 looking better

than Q2, albeit only marginally

Chinese demand is still healthy

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26 September 2011 4

The other areas of market scrutiny remain OECD Europe, given the deterioratingmacroeconomic backdrop, and Japan, post the earthquake. European demand numberscame in lower y/y for July and on the face of it look weak, but there are greater nuances tothis. Yes, the poor economic conditions have curtailed some of the growth, however, a partof the weakness in oil demand continues to come from the loss of light sweet diesel-richLibyan (and now Syrian) crude in this region. Ever since Libyan barrels went off the market

in March, diesel demand has become the Achilles heel in Europe, falling by almost 200thousand b/d in the last four out of five months as refinery runs got compressed. Relative tothe feverish pitch of negative macroeconomic sentiment surrounding the Europeaneconomy, the underlying consumption has held up fairly well.

Japanese demand, on the other hand, continues to firm on its recovery path in July, withdemand totalling 3.811 mb/d, recording the first y/y increase since the aftermath of theearthquake. Further, the latest South Korean numbers for August saw demand posting thesecond straight month of y/y growth, following a weak Q2. With this latest dataset, SouthKorean demand has crept into positive territory, with Q3 to date demand higher y/y by 4%.

Elsewhere, Indian oil demand growth momentum picked up, increasing by 3.2% y/y in Julyto 2.959 mb/d. Most importantly, the rebound is a great example of the extremely low price

and high income elasticity of oil demand in emerging markets as despite a hike in retailprices that now makes Indias petrol prices more expensive than that of the US, gasolineconsumption has recorded a y/y growth of 4.8%. Further, Brazilian and Latin Americandemand in general remains extremely strong, with US exports to those countries remaininghigh. Among the key producing nations, demand is also at peak levels; in Russia for instancethough output has increased, exports outside the FSU have fallen, signalling that a goodportion of the output is now being diverted to domestic refineries. Though Saudi Arabiandemand has come off its records seen in June, it remains at elevated levels and overallconsumption among the GCC oil producers is robust, with Kuwait recording a record high inJuly. We would expect these healthy demand levels to peak into August as well.

Figure 1: Distillate demand still holding up well, in contrast

to 08-09 cycle

Figure 2: While global oil demand has bounced back from

the lows in Q2

3.3

3.5

3.7

3.9

4.1

4.3

4.5

06 07 08 09 10 11

400

420

440

460

480

500

520

540

560

580

600Diesel demand, mb/d, LHS

Rail freight index, thousands, RHS

83

84

85

86

87

88

89

90

91

92

06 07 08 09 10 11

Global oil demand, mb/d

Source: EIA, Bloomberg, Barclays Capital Source: Barclays Capital

Europe numbers weak on face

value, however several nuances

OECD Asia Pacific rebounding

Indian demand growth

momentum picking up again

Russian and GCC demand

peaking as well

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26 September 2011 5

Supply

Non-OPEC

While oil demand has been weakening in parts, but mostly robust overall, non-OPEC supplyperformance has been extremely weak and has provided a significant buffer to any demandweakness that may have materialised. Non-OPEC output this year has disappointed to the

tune of 0.5 mb/d in Q1, 1.2 mb/d, and 0.8 mb/d in Q3 with, in our view, further significantdowngrades to come to the Q3 number on consensus estimates. Indeed, the overallconditions of the market are now so tight that should OPEC attempt to balance the marketin Q4, spare capacity would have to fall to effectively zero.

The latest full set of global data for non-OPEC supply for June pegs the y/y increase in non-OPEC supplies to just above 100 thousand b/d, following a downward revision to 230thousand b/d to Mays levels. Output in May, now, was lower y/y by 723 thousand b/d,with heavy declines in North Sea, Middle East and the Asia-Pacific. In June, although NorthSea production remained very weak, the y/y comparisons eased as changes in maintenanceschedules created a favourable base, while strong output growth continued in theAmericas, offsetting declines elsewhere. Middle Eastern and African supplies remainedadversely affected by geopolitical outages. Asia-Pacific supplies stayed in negative growthterritory for the second straight month, falling y/y by 182 thousand b/d for the first timesince October 2009, helped by slowing Chinese output growth and falling output inMalaysia, Vietnam and Indonesia. With technical problems marring output growth andrenewed weakness seen in Caspian and Brazilian output, we would expect Julys figures tobe weaker still, extending the deficit to demand.

North Sea volumes, in particular, have been plagued with technical problems, as the UKsBuzzard oil field continues to face cooling system failures, and is taking longer thanexpected according to its operator Nexen, to ramp production back up to rates of 200-220thousand b/d. Worse still, no timeframe has been given for the resumption of stable output.These technical problems, which have been ongoing since February, have resulted in the sixOctober cargoes being delayed, following a delay of 15 cargoes in September 6-7 in August

and similar large delays since May. Not surprisingly, the latest UK production numbers for June were extremely disappointing, with crude output falling to its second-lowest levelssince April 1978, at 0.97 mb/d. Total production came in at 1.075 mb/d, lower y/y byalmost 100 thousand b/d on a base that was already heavily lower due to seasonalmaintenance last year. Compared to two years ago, June total liquids production in the UKwas lower by a substantial 0.5 mb/d. In the year-to-date (through to June), UK output isnow 235 thousand b/d lower y/y. Norwegian output hardly fares any better. While thelatest data for August shows some improvement with a y/y increase of 121 thousand b/d,the bulk of the increase came in the form of NGLs and the growth was entirely attributableto an extremely weak base from last year, when maintenance was carried out in August andSeptember rather than in May and June this year. In absolute levels, Norwegian productionhardly made any progression, with total output pegged at 1.956 mb/d. Recently, productionat its Valhall platform, which pumps Ekofisk, was halted and only resumed by mid-September, later than expected. In the year-to-date, Norwegian output is lower y/y by 131thousand b/d, and we would expect little improvement ahead.

While the uber bears would dismiss North Sea declines as hardly a cause for concern giventhat these declines have been a part of the oil market for a few years now and given thatthere are plenty of new finds to offset these shortfalls, the weakness in central Asianoutput this year would have caused a stir of sorts. In July, Kazakhstans crude productiondropped back further to an average of 1.51 mb/d in July (down y/y by 8.4%), the lowest

Non-OPEC supply

underperformance gets severe

Buzzards problems continue

to prolong

Caspian sea output faces

further headwinds

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26 September 2011 6

monthly level since March 2009, due to continued strike action affecting field production,which began back in May. Azerbaijans oil production fell y/y by 12.2%, as it continues tograpple with technical issues at its ACG project. In the year-to-date, Kazakhstan output isflat y/y, while Azeri production is down by 50 thousand b/d, a significant turnaround fromthe trend witnessed over the past few years.

Figure 3: North Sea production remains weak Figure 4: Azeri and Kazakh output face technical issues

-800

-700

-600

-500

-400

-300

-200

-100

0

100

200

08 09 10 11

Norway

UK

UK and Norwegian oil output, y/y change, thousand b/d

-0.4

-0.2

0.0

0.2

0.4

0.6

0.8

Jul-07 Jul-08 Jul-09 Jul-10 Jul-11

Russia

Kazakhstan

Azerbaijan

y/y growth in FSU output, mb/d

Source: DECC, NPDS, Barclays Capital Source: EIA, EMC, Barclays Capital

China has also been a significant source of downside surprise to the profile of non-OPECsupply this year. Growth has more than halved in the year-to-date to 2.6% compared to7.5% as it continues to battle with problems at its offshore oilfields. In August, Chineseoutput fell y/y by 1.8%, the first y/y fall since November 2009. Moreover, recently,ConocoPhillips was asked to halt production at the Peng Lai 19-3 platforms in Bohai Bay aswork continues to depressurize a field that began seeping oil into the ocean in June.Production from the field averaged about 150 thousand b/d last year, and despite a few

ramp ups of existing projects on Chinas East Coast in the horizon, Chinese crude oil outputis likely to remain under pressure for the rest of the year given the shortfalls elsewhere.

Turning to the Americas, which has been the key source of strength in non-OPEC supplylately, there has been a contrasting trend emerging between the north and the south.Having flatlined for most of the year, oil shales production is on the rise again, with NorthDakotas output reaching record highs. NGL production remains buoyant too, and thus, wewould expect US oil production to continue rising through the year. While the latestCanadian data for June showed a second consecutive y/y fall, as the wildfires kept CNQsHorizon upgrader offline, we would expect output to pick up from September onwards, withCNQ restarting the upgrader at the end of August and ramping up to full production of 110thousand b/d earlier this month. That said, planned maintenance work is being undertaken

in other upgraders this month (expected to last for 1.5 months) and could temper theuptick in output somewhat. In Latin America, though, while Colombian output hit recordhighs of 953 thousand b/d (up y/y by 21% or 165 thousand b/d) despite continuing localprotests near Petrominerales oil fields, Brazilian production has disappointed significantly.Crude output, in particular, has suffered from a series of maintenance works, with year-to-date output higher by just 42 thousand b/d and NGL production by 8 thousand b/d. In factin July, Brazilian liquids production increased by just 3 thousand b/d, with biofuels outputgrowth also turning negative due to adverse weather and lack of investment.

Chinas offshore field woes set

to worsen

US and Canadian problems

easing and to support output

growth, but Brazils

problems grow

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26 September 2011 7

Figure 5: Chinese oil production has suffered lately Figure 6: Brazilian crude output growth has slowed sharply

-4%

-2%

0%

2%

4%

6%

8%

10%

12%

Aug-07 Aug-08 Aug-09 Aug-10 Aug-11

Chinese crude output, y/y change, %

-125

-50

25

100

175

250

325

05 06 07 08 09 10 11

Brazilian crude oil production, y/y change, thousand b/d

Source: China Customs Barclays Capital Source: ANP, Barclays Capital

These shortfalls in non-OPEC supply are not temporary, in our view. Indeed, increasingly,basins around the world are becoming mature and technologically challenging to drill in,while political disputes and unfavourable hydrocarbon laws have created enough friction tostymie investments, despite sharply higher oil prices. Two countries, with huge potential,Kazakhstan and Brazil, are prime examples of this.

In Kazakhstan, the development of the Kashagan field has faced several setbacks over thepast few years since 2005. With the deadline already extended to 2013, it emerged lastmonth that Shell and its partners are likely to ask the government for a further extension. Alast-ditch plan to meet the 2013 deadline involved pumping at least 50 thousand b/d of oildirectly onshore, bypassing an unfinished processing plant on an artificial island. However,in early July, the partners rejected this option, leaving the consortium no choice but to ask

for an extension. When the Caspian field was found in 2000, it was the largest oil discoveryin 30 years, with reserves of 9-13 billion barrels of oil. Since then, it has been dogged bytechnical difficulties, pushing total development costs as high as to $136bn.

In Brazil, since the 2006 discovery of the giant Tupi oil field in the countrys offshore subsaltregion, oil companies have seen the country as one of the world's most promising upstreamprospects. Yet the optimism about Tupi and other big subsalt finds is starting to fade withfears of a politicisation of the development process. Last year's government approval of anew set of oil laws, which make Petrobras the operator of all unassigned subsalt blocks andmandate a minimum 30% stake for the company in all new subsalt projects, substantiallylimited the upside for other producers. Meanwhile, this year has been marked by thegovernment's apparent relative neglect of oil policy, and two bid rounds that were

scheduled to go forward have been pushed back to next year. Officials had long held thatthe first subsalt auction under the new rules would take place this year and would includethe giant Libra field with an estimated 8 billion barrels of oil equivalent. However, a newsubsalt royalty-sharing arrangement must first be approved. Last year's energy law packagehad included a proposal to spread more oil wealth to non-producing states, but the thenPresident Lula vetoed it. Brazilian officials said the current Brazilian President Rousseffwould present her own proposal shortly after taking office, but there has been nothingmuch more solid on that proposal to date.

Long-term issues in non-OPECsupply growth

Kazakhstans Kashagan project

faces more setbacks

Brazils subsalt drilling looks

less attractive

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26 September 2011 8

To extrapolate from 2009 and 2010 for the future of non-OPEC supply would be incorrect,in our view. No doubt there has been a technological renaissance in some parts of theworld, especially the US, where horizontal drilling technology is being put to use in liquids-rich shale plays. Higher prices have indeed incentivised technological breakthroughs, whichhave resulted in breakthroughs in deepwater drilling and sub-salt areas, as is evidenced inthe Gulf of Mexico, Africa and Brazil. But these breakthroughs come with a high cost

exploration is moving to more geologically challenging locations, with huge requirementson the infrastructure front requiring massive capital expenditure and commitment. Oilexploration has had to move into deeper waters, compelled to deal with unsavoury regimes,and operate in some of the world's most environmentally sensitive and inaccessible spots,far from proper available infrastructure. Large investments in treacherous places is almostthe new norm for conventional oil output, and thus to assume smooth sailing like thegrowth in output seen in the past couple of years, would be a mistake in our view. Theevents that have hampered non-OPEC supply in 2011 are perhaps more representative ofthe issues that will plague non-OPEC supply going ahead, and thus should not be treated asa year of exceptions.

OPEC

Even with Libyan barrels out of the market, while OPECs output continues to increase andreach three-year highs, the organisation has not been problem free. Clearly, the future ofLibya is key to determining the path taken by the rest of OPEC and we remain cautiousregarding the prospects of a swift reprise in Libyan production to pre-war levels. On thepolitical front, divisions within the rebel ranks are undermining efforts to craft a coherentinterim government. Fault lines have become increasingly apparent in recent weeksbetween the acting Prime Minister and the Islamists within the rebel coalition. Securing theweapons from Gaddafis stockpiles continues to be a major security challenge for the NTCand its NATO allies too, with the disappearance of shoulder-fired missiles causing particularconcern. Beyond these political issues, damage sustained by the oil infrastructure isextremely variable, and we expect the Sirte basin (which accounts for two-thirds of Libyasproduction) to be the most problematic in resuming production. Oil terminals have alsosustained damages, particularly those of Es Sider and Marsa el Brega. The mining of oilfacilities is known to be a problem at the Brega and Ras Lanuf oil terminals as well, whilelooting by Gaddafi loyalists has resulted in the loss of essential equipment at oil fields andterminals. Worse still, mines planted by Gaddafi remain. Our greatest reason for caution,however, remains the underlying condition of the Sirte basin reservoir. While there has beenlimited news of any deterioration to oil wells on the surface, underlying damage to oil fieldsfrom the lack of protective measures taken (eg, properly conducted well shut-ins) threatensto deplete reservoir levels, especially given the waxy nature of crude. Similar pastexperiences in Iran and Iraq point to a treacherous path ahead. Thus, while the eastern andwestern fields could bring up to 0.5 mb/d online fairly swiftly, the state of confusion in therest of the region is likely to cap volume growth at those levels in the near future.

While the focus within OPEC has been on Libya, Nigeria has also started facing serioussecurity challenges. At the end of last month, UN headquarters in the countrys capital wasattacked, following a spate of violence seen in the north of the country in the past months,which has replaced the Delta region as the most dangerous security challenge in thecountry. The fact that Goodluck Jonathan hails from the Niger Delta, along with several ofhis top officials, has helped address some of the longstanding political grievances in the oilregion, together with the Amnesty programme. Yet, while there have been no large-scalemilitia attacks on oil installations, oil theft and pipeline sabotage continues to plague theindustry. Shell shut its Adibawa pipeline in the southern Bayelsa state after saboteurs cut

Non-OPEC supply will not be

smooth sailing going forward

Libya requires caution

Nigeria heating up again

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26 September 2011 9

crude lines at the end of August and declared force majeure for its Bonny light shipmentsthrough to September. Against an estimated 2.9 mb/d of nameplate capacity, Nigeriancrude oil production has averaged 2.1 mb/d so far this year and 2.07 mb/d in 2010.

Perhaps the biggest development over the past few weeks has taken place in Iraq. Kurdistanhalted oil exports from the region, apparently due to a technical problem, but the passing of

the much contentious oil law has once again created a rift between the central andKurdistani governments. However, in January this year, Maliki and Kurdish Prime MinisterBarham Salih signed an agreement to restart exports from the KRG-controlled oil fields. Itwas part of a broader political deal that allowed Maliki to secure Kurdish support for asecond term in office. This resulted in a sharp increase in exports from Kurdistan. However,problems emerged again this spring when the parliamentary Oil and Energy Committee andIraqs oil ministry produced competing oil laws. The parliamentary legislation takes a morelenient view of the Kurdish contracts, while the oil ministry bill approves the technicalservice agreements signed by Baghdad but not the PSCs concluded by the KRG. Oilproduction from Kudistan had been making significant contributions to overall Iraqi output.Output in the region has risen steadily since the start of the year, reaching 190 thousandb/d in recent months. Also, oil exports from five fields in the area have risen to 180

thousand b/d from negligible levels so far. The KRG now accounts for more than 8% of thecountry's oil exports and more than a third of the flow through the Turkey pipeline. Thus, adispute with the KRG may have detrimental effects on Iraqi production. Moreover, the rise inKurdistan output is all the more important because southern Iraq continues to facetremendous infrastructure challenges. Foreign oil companies have all announced that theyhave passed the target of a 10% increase during the first year of their long-term servicecontracts, but now have had to cut back on their production prospects, as pipelines andstorage tanks are full to bursting. In view of these constraints, the Iraqi oil minister recentlystated that Iraq may revise its production targets lower, from 12 mb/d to 8.0-8.5 mb/d,while extending the time frame to achieve that from seven to 15 years.

Inventories

Despite a perception of weak demand and excess supply having created a rather largeinventory overhang, the reality has been starkly different. It has now been nine quarters in arow that the prior estimate of the call on OPEC has been underestimated, and the averageupwards revision has been 1.2 mb/d. In other words, for nine straight quarters the balanceof supply and demand has surprised to the positive. By our numbers, demand actuallyoutran supply by about 0.75 mb/d over the first half of the year, and that deficit has nowdoubled to 1.5 mb/d in Q3. The IEA puts the first half deficit at 0.5 mb/d, and should OPECoutput in September grow at the same pace it did in August, then the IEA projections wouldimply a supply deficit of about 1.1 mb/d in Q3. Not all of the Q3 deficit has been met byreductions in global commercial inventories, as the IEA strategic stock release, averagedover the quarter, filled about 0.65 mb/d of the gap. The reduction in global commercialinventories net of the IEA release is put at about 0.8 mb/d on our projections, and seems to

be heading for around 0.5 b/d on IEA projections, despite being a quarter where historicallyone should see stock-builds.

According to the latest IEA data on OECD stocks, Julys oil inventories increased by 10.8 mbto 2687 mb (58.4 days of forward cover), far lower than the usual seasonal builds of 27 mb.While restocking in middle distillates led to all of the gains, counter-seasonal declines incrude offset large parts of that. According to the IEA, this is the first time since 2008 thattotal oil industry stocks have slipped below the five-year average (by 12.8 mb). PreliminaryAugust data indicates a small 0.6 mb build, compared to the usual 14 mb build during themonth. Thus, despite the SPR oil making its way to the market, OECD stock levels were

Iraq: rethinking targets as

infrastructure constraints bite

Inventory drawdownscontinue at a strong pace,

despite SPR release

OECD stocks are now below the

five-year average

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26 September 2011 10

some 26.3 mb below seasonal averages and 108 mb below last years levels. In fact, in theUS, even after the 30.6 mb of SPR release, crude stocks are actually 1.4 mb lower than thelevel of overhang that existed before the first SPR entered the market such has been thelevel of attrition and strength of fundamentals in the market. The strategic stock releasewas thus swallowed whole with ease, and the physical markets are still screaming tightnesswith large premia being paid to accelerate deliveries (see page 61). Thus, in our view, it

seems very credible to conclude that Q3 has seen a large supply deficit.

Figure 7: Crude inventory overhang has reduced sharply Figure 8: The SPR release was absorbed with ease

-50

-25

0

25

50

75

100

125

150

175

200

225

Feb-08 Apr-09 Jun-10 Aug-11

OECD product stocks

OECD crude stocks

Oil inventories relative to 5 year averages (mb)

310

320

330

340

350

360

370

380

Jan Feb Mar Apr May Jul Aug Sep Oct Nov Dec

2010/112009/105 Year average

US crude oil inventories, mb

SPR release of 30.6 mb

Source: IEA, Barclays Capital Source: EIA, Barclays Capital

Summary of key consensus/agency monthly reports

IEA (Monthly Oil Market Report):

The IEAs Oil Market Report revised its global oil demand growth forecast lower for 2011 by160 thousand b/d to 1.04 mb/d and that of 2012 by 200 thousand b/d to 1.41 mb/d. The IEA

attributes lower non-OECD readings and reduced economic growth expectations as the primereason for its downward revision. It is worthwhile to note that prior to the revisions, however,the IEA had the most optimistic of demand baseline numbers. Thus, the recent revisions bringthe IEA's demand numbers closer to our own forecasts. On the supply front, the IEA has alsoreduced its non-OPEC supply growth forecast for 2011 from 0.4 mb/d to 0.2 mb/d, whichagain is in line with our own estimates. However, they state that non-OPEC supply rose inAugust, with the outages in the Middle East and China being offset by increased production inLatin America and the conclusion of maintenance in Alaska and Kazakhstan. For 2012, the IEAhas revised its non-OPEC supply growth lower by 150 thousand b/d to 1 mb/d. A goodportion of the revisions stem from lower-than-expected NGL production growth in Asia, OECDEurope, and Brazil. Other soft spots for supply in 2012 from the field level are seen in Russia,

Oman, Kazakhstan, Brazil and Australia where output is seen levelling off at a number of fields.On Libya, the IEA has raised its expectations on output resumption, revising its Q4 forecast forLibya up by 100 thousand b/d to average 350 to 400 thousand b/d by end 2011 and rising to1.1 mb/d by Q4 2012. The overall fundamental picture was positive, with OECD industrystocks rising by less than seasonal averages (by 10.8 mb) to 2687 mb, which the IEA now pegas below the five-year average for the first time since the economic recession of 2008.Preliminary data indicate that OECD stocks remained tight in August, despite the SPR release,rising by a modest 0.6mb.

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EIA (Short-Term Energy Outlook):

EIAs short-term energy outlook, despite a substantial downward revision in the USeconomic growth forecast, kept overall 2011 oil demand and oil demand growth unaltered,at 88.2 mb/d and 1.37 mb/d, respectively. Though US oil consumption has been shaved offmarginally, this were offset by small upward revisions to European and Japanese demandforecasts. For 2012, the EIA has revised its demand outlook by 0.24 mb/d to 89.59 mb/d,

thereby taking the y/y growth to 1.39 mb/d. While a hefty revision no doubt, the EIA had afar higher initial expectation, and the revision now brings it in line with our expectations ofgrowth of 1.31 mb/d in 2012. On the non-OPEC supply front, despite the plethora ofshortfalls, the agency has kept its numbers broadly unchanged, expecting a growth of 0.5mb/d in 2011 and 0.78 mb/d in 2012. We would expect these numbers to be revised lowerover the coming months, especially if the supply picture fails to improve. EIA assumes thatYemen will recover most of its pre-disruption levels of production (240 thousand b/d) earlynext year, but heightened turmoil in Syria and the potential for more sanctions on thecountry's energy sector introduce yet another source of political risk to the non-OPECoutlook. Though the situation in Libya is dynamic and circumstances have changedconsiderably since last month's Outlook, the EIA is continuing to maintain its assumption with only a slightly accelerated timetable that about one-half of Libya's pre-disruptionproduction will resume by the end of 2012. The restoration of at least some Libyanproduction is expected to contribute to an overall increase in OPEC output of 510 thousandb/d in 2012. EIA projects that OPEC surplus crude oil production capacity will fall byanother 0.5 mb/d by end of 2012.

OPECSecretariat (Monthly Oil Market Report):

The OPEC monthly oil market report made a further downward revision of 150 thousandb/d to world oil demand growth in 2011, now forecast at 1.06 mb/d. Oil demand growth in2012, has also been revised but only marginally lower to stand at 1.27 mb/d. Unlike theprevious month, where the bulk of the revision to the 2011 growth rate was caused by achange of the baseline demand for 2010 being revised higher, this time round the revisions

are a result of a downward revision to baseline demand for 2011 (by 150 thousand b/d)and 2012 (by 180 thousand b/d). The revisions were concentrated in the OECD, with bothNorth America and Europe seeing a downward revision of 80 thousand b/d and 40thousand b/d respectively on the back of a weaker-than-expected driving season in the USand sluggish economic performance in OECD Europe. Further, Chinese demand growth for2011 and 2012 was also revised lower by 50 thousand b/d and 60 thousand b/drespectively as they extrapolate a weak Q3 on to the rest of the year. On the supply side, theOPEC secretariat concedes another marginal downward revision to non-OPEC supply (thirdmonth in a row). The latest revision of 80 thousand b/d is on the back of revisionsconcentrated on Argentina, the FSU and China, and brings the Secretariats outlook in linewith the EIA's estimate of 0.5 mb/d non-OPEC supply growth; however given the continuedsignals of deterioration seen in volumes from the North Sea, Brazil and China; these

forecasts remain optimistic in our view. On Libya, OPEC stands out as being the mostoptimistic projecting production reaching 1 mb/d within the next six months, and output inthe far east and west of the country expected to resume in the coming days. As a result,they also mention the need for scaling back the extra output that had been put into themarket due to the Libyan shortfall, although we think it is too premature at this stage, giventhe underlying problems in Libya.

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FOCUS

WTI and Cushing balances myth vs. realityWhile 2011 is likely to be characterised as a watershed year, redefining the geopolitical landscapeof the Middle East, it has also been punctuated by a rapid change in the relationship between

WTI and other international benchmarks. The more global crude benchmarks have risen toreflect the tightening fundamentals, the more WTI has fallen, engulfed in a bearish web ofsentiment arising from the commercialisation of liquids-rich shale plays in the US. Much like inUS natural gas, where the rapid advancement in horizontal drilling technologies resulted insystematic oversupply, the view follows a similar trajectory for oil too. Add to that rising Canadianvolumes and its greater access to Cushing from the start-up of new pipelines, together withoverall flat to falling demand in a mature US economy, there is very little light at the end of thistunnel. WTIs delivery point Cushing remains land-locked with no outlet to get crude out to theGulf Coast, which then implies that all the rising domestic production would bottle up atOklahoma. That is exactly the sentiment with which the market is currently trading WTI, and onthat basis, undoubtedly, WTI should be dislocated from the rest of the world. Yet, in this piece,we dare to disagree, and one look at the balances (or for that matter, any data) tells us why.

Supply growth in the US is rising fast, yet a sense of proportion needs to be kept. The rise is in afew hundred thousands, rather than in millions, often confused with the cumulative total E&Pcompanies put out in their annual reports they expect to achieve in the next 5-10 years. Thus,the view of marginal oversupply may be far greater in the mind than in reality. Moreover, withincreased Canadian flows to Cushing, and the concurrent dislocation of WTI, it should come asno surprise that US producers, who have access to the more lucrative Gulf Coast, have started toreduce flows towards the Midwest. At the same time, there has been a renaissance in themovement of crude by trucks, rail and barges, and though these volumes remain small incomparison, US producers are deploying every possible method to take volumes away fromCushing. Ultimately, the start-up of new proposed pipelines will be key in helping to ease thepressures at Cushing, but for the time being, a simple extrapolation of higher domestic supplies

to depress WTI would be a gross oversimplification and incorrect, in our view.

Figure 9: Cushing balance, thousand b/d

Cushing balance cumulative growth 2011 2012 2013

Increases in crude flow

PADD2 supply growth 100 230 350

PADD3 supply growth* 50 110 210

Canadian supply growth 160 350 500

Decreases in crude flow

Storage growth at Cushing 41 64 70

Rise in PADD2 runs 40 40 35

Longhorn reversal (impact through Basin) 0 0 135Keystone XL start-up 0 0 600

Other potential pipeline start-ups 0 100 300

Increase in trucking, rail etc 30 100 150

Decrease in other pipeline flows, eg, Seaway, etc 200 250 275

New takeaway capacity in PADD3 0 50 50

Balance

Net balance at Cushing -1 86 -555

Note: *PADD3 supply that comes to Cushing Source: Barclays Capital

Roxana Mohammadian Molina+44 (0)20 7773 2117

[email protected]

Amrita Sen+44 (0)20 3134 2266

[email protected]

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WTI-Brent: one year onThe start to the dislocation of WTI as a global benchmark dates back to exactly a year. Sincethen, WTI has traded at a severe discount to key benchmarks around the world, despitefundamentals at Cushing actually remaining fairly robust. As by definition during a dislocation,the WTI-Brent differential has no equilibrium value and is undefined, and we would not be

surprised to see even more severe dislocations in the short run as sentiment moves throughthe extremes of irrationality. WTI and all other benchmarks are currently trading as almostentirely unrelated benchmarks, in a situation similar to the break down in the linkagesbetween oil and US natural gas prices, with the perceived lack of substitutability between thecrudes the key driver. In other words, in an oversupplied US market, the need to import Brentis all but gone, and, hence, the WTI-Brent spread is rendered meaningless. The ultimatesolution to WTI pricing so far below the global level will be the same as the solution to ithaving once priced far above the global level. It will involve further changes to pipelineconfigurations, potentially involving reversals and new lines aimed at moving crude throughthe Midwest and into the refinery areas of the Gulf Coast. We continue to believe that thespread between WTI and Brent or, for that matter, any other benchmark is entirely unjustified,especially when considered in a context of tight WTI time spreads, signalling no marginal

excess at Cushing, something also verified by our Cushing balances (see Figure 11 and Figure26). At some point (and we believe by end-2013 again see our Cushing balances), given thesize of the current economic incentives to do so, greater flexibility in the system and anassociated higher degree of integration between the Midwest and Gulf Coast markets is likelyto remove the structural reasons for the current dislocation; however, for now, we expect themarket to continue to severely distort WTI until the logistical bottlenecks and perceptionabout Midwest balances change.

Since the adoption of formula pricing in 1986, West Texas Intermediate (WTI) has served asone of the main international benchmarks, along with Brent and Dubai, against which othertypes of crude oil are priced. In principle, the movement in WTI prices is supposed to reflectsupply-demand conditions in the US, the largest consumer and oil importer in the world.

The WTI market is characterized by a large number of independent producers who sell theircrude oil to gatherers based on posted price. The oil is then brought into Midland and thendirected either towards the Gulf Coast refining areas or towards Cushing, Oklahoma.Cushing was the centre of US exploration from nearby fields in 1915 when it producedaround 30% of higher-grade US oil. While production peaked that year, the web ofinfrastructure and storage influenced NYMEXs decision to use Cushing as the pricing pointfor WTI contracts in 1983. Cushing is a landlocked interconnect through which crudevolumes move. The Cushing pipeline interconnect is spread over nine square miles and hascrude oil storage capacity around 65 mb (50 operable). Due to pipeline logistics, once theoil flows outwards from Midland towards Cushing, WTI can only go in one direction: north,towards Chicago. Thus, if there is a shortfall in demand from refineries in the Chicago area,there are no opportunities to re-direct oil flows out of Cushing towards other refining

centres where there might be more demand for crude oil.It has long been recognized that the link of WTI prices to other international benchmarksand to oil prices in other US regions is partly dictated by infrastructure logistics. Thus, WTIexists in the closed conditions of the Midwest, governed to the greatest extent by regionalrefinery dynamics, burgeoning flows from western Canada and by the logistics of theplumbing of pipelines in the region, all seen from the viewpoint of the value of oil in storagein Cushing. The recent disconnection of WTI prices is a clear example of how pipelinelogistics can dislocate WTI not only from the rest of the world, but also from other USregions. While this is not the first time this has happened, it is the most severe and prolong

WTI has now been dislocated for

a year, despite fundamentals at

Cushing not deteriorating

Cushing, the delivery point for

WTI, but also the point of

infrastructural bottlenecks

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occurrence. In fact, in the past, the main logistical bottlenecks impaired the markets abilityto get enough oil into Cushing; this bottleneck in many instances resulted in seriousdislocations and WTI rising to very high levels compared to other benchmarks. The problemis now reversed: while the ability to get oil into Cushing has increased, the ability to shift thisoil out of the region and to provide a relief valve for Cushing has been very limited.

Figure 10: Pipelines in the US and Canada

Source: Canadian Association of Petroleum Products

The past

In 2007, in a similar occurrence, due to logistical bottlenecks, there was a large build-up ofinventories at Cushing, resulting in WTI disconnecting from the rest of the world. Similarly, due toa reinforcing contango, Cushing was flooded with inventories in the back end of 2008 and early2009. Crude inventories at Cushing increased from 14.38 mb in October 2008 to almost 35 mbby the second week of February 2009, an increase of about 20 mb, with the logisticalcompromises of the US Midwest made more explosive by the higher Canadian crude exportflows, Midwest refinery outages and effects of an ETF holding. WTI disconnected from the rest ofthe US, the rest of the world and time spreads ballooned out to record levels of over $9 at expiry,

sending the signal that there was no appetite for more crude at Cushing. The same issue saw areprisal last year when, back in May, the prompt to second month WTI time spread balloonedout to as high as $4.59 per barrel. There had been nine straight builds amounting to just over 8mb at WTIs pricing point at Cushing, Oklahoma since the middle of March. That accumulationof oil had taken Cushing inventories to a record high of just below 38 mb. While crudeinventories stood some 0.5 mb lower than their five-year average in the rest of the US, themarginal supply imbalance was all concentrated in the Midwest, where crude inventories were18.8 mb higher than the five-year average. As a result, the Cushing distortion accounted for themajor part of the downwards pressure on WTI, forcing down the front of the curve sharply evenas the back of the curve bobbed back up, while the WTI-Brent differential widened to over $5.

Past instances of disconnecting

below global benchmarks

increasing in frequency 2007,

2009, 2010 and now

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In general, the logistical constraints at Cushing can result in a short-term build-up in crudeat Cushing, which then logically creates significant downward pressure at the front of thecurve. The feedback then creates distorted sets of time spreads reflected in the largedifferential between nearby contracts and further away contracts, ie the WTI structure flipsinto a fairly steep contango. Second, WTI decouples from Brent, and other benchmarks likeLight Louisiana Crude (LLS), evident in the large differential between the prices of the two

(Figure 13). Finally, the build-up of stockpiles around the area of Cushing usually alsoresults in the sour-sweet crude oil price differential narrowing significantly. Figure 14 belowshows that, while WTI was trading at a premium of more than $15 to the heavier and sourerMars crude grade in the middle of 2008, the differential flipped to a small discount in early2009 and now to a sustained discount of over $20 per barrel. The same is true for the heavyMexican Maya Blend, which now trades at a premium to WTI.

Clearly, WTIs dislocation has had implications across the various crude oil markets in thepast too, resulting in unusual price differentials. These effects, however, did not imply thatthe market was not functioning well at the time. On the contrary, price movements wereefficiently reflecting the local supply-demand conditions in Cushing. The main problem isthat, when localised conditions become dominant, the WTI price can no longer reflect thesupply-demand balance in the US, nor act as a useful international benchmark for pricingcrude oil. Given the frequency of the recent dislocations and the duration and severity of thecurrent dislocation of WTI to other benchmarks, the question has been raised whether WTIremains a suitable global benchmark or not. While clearly WTI does not reflect the globalsupply-demand balances currently, there are some interesting dynamics at play whichhighlight systematic market failure rather than the failure of WTI itself. While the currentsituation clearly has very little relevance to the US market outside Cushing, unfortunately, itmay not even be a full reflection of actual conditions at Cushing either.

Distorted time spreads, inter

crude spreads and light-heavy

differentials all a part of

WTIs dislocation

Figure 11: LLS and Brent differential to WTI (1st month), $/bbl Figure 12: Heavy-light differentials (Mars-WTI), $/bbl

-30

-20

-10

0

10

20

30

05 07 09 11

WTI-Brent

LLS-WTI

-20

-15

-10

-5

0

5

10

15

20

25

30

05 07 09 11

Source: Bloomberg, Barclays Capital Source: Bloomberg, Barclays Capital

Conditions at Cushing have been

correlated with WTIs price

action in the past the same

cannot be said now

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Box 1: WTI-Brent: any convergence in sight?

For over 20 years, Brent has traded at an average $1.43 discount to WTI and the spread remained within a very narrow range (Figure4). In the mid-2000s, the spread started to become much more volatile, and the standard deviation increased four-fold while theaverage discount of Brent to WTI reduced to an almost irrelevant $0.12. Since the start of this year, though, the market for WTI hascompletely dislocated and, in the year-to-date, WTI has been trading at an average of $17.7 discount to Brent, while the volatility of

the spread has also increased by almost 40%. The historical spread can be approximated by a normal distribution around the mean,a range of between -1.5 and -1 for a positive differential between Brent and WTI (Figure 5), but that also has changed over the pastfew months. The skewness coefficient (a measure of the asymmetry of the probability distribution) has increased dramatically,suggesting the right tail of the distribution has become fatter and longer or, in other words, WTI has become more likely totrade below Brent in the range of $15-20. In addition, the higher kurtosis suggests more of the spread variance is the result ofinfrequent extreme deviations of the Brent-WTI price differentials from the mean. That said, it is still too early to conclude whetherthis shift in the probability distribution is a permanent one or a temporary aberration with an eventual return to the long-termdistribution (perhaps around a new mean). One implication of the historic normal distribution for the Brent-WTI spread is its mean-reversion: periods of positive deviation from the mean tended to be followed by periods of negative deviation from the mean. Since2006, an average of 5 months of negative Brent-WTI differentials (higher WTI) have tended to be followed by an average of 10months of positive Brent-WTI spreads (lower WTI) creating a largely mean-reverting profile. Indeed, our model for the Brent-WTIspread (discussed below) shows an incipient mean-reversion.

We have long sustained that the scale of the WTI-Brent spread is unjustifiable, but the underlying fundamental drivers of thedislocation look set to become entrenched. Indeed, while the spread set a new record high in August, there has been little in the wayof new fundamental catalyst to warrant the ballooning out of that spread to such extreme values. We have attempted to model thespread from a pure supply and demand perspective, and the results of our empirical exercise confirm our view that the currentspread is unjustified.

We have modelled WTI using monthly demand numbers and (lagged) supply in the US Midwest, as well as a dummy variable tocontrol for extreme price movements. In a similar fashion, we have modelled Brent using just demand and a dummy variable. Ourresults suggest that while a WTI discount to Brent of around $6 is justified from a fundamental perspective, the current value of thatspread is not. Our analysis shows a dramatic increase in the model "residuals", or the "unexplained" part of price differentials, overthe past few months. The first observation is that, while the correlation between y/y movements of WTI and Brent price has declinedvery sharply this year, the correlation between y/y changes in US Midwest demand and global demand has increased, and so far thisyear stands over 10% higher than over the past ten years. The correlation between y/y changes of WTI and Brent price is 70% sinceJanuary, down from 95% over the past ten years, while the correlation between y/y changes in WTI and Brent demand is 88% so farthis year, up from 75% over the past ten years. The idea that prices have become increasingly disconnected despite closer demandtrends indicates that, from a pure demand point of view, price action appears overdone.

Figure 13: Historical Brent differential to WTI, $/bbl Figure 14: Probability distribution of Brent-WTI differential

-15

-10

-5

0

5

10

15

20

25

30

Aug-87 Aug-91 Aug-95 Aug-99 Aug-03 Aug-07 Aug-11

Brent-WTI

Average

0%

5%

10%

15%

20%

25%

>5

4-4.5

3-3.5

2-2.5

1-1.5

0-0.5

-1-0.5

-2-1.5

-3-2.5

-4-3.5

-5-4.5

0.84

0.85

0.86

0.87

0.88Probability distribution (1986-2005)

Normal aproximation

Source: Ecowin, Barclays Capital Source: Ecowin, Barclays capital

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Our view on the WTI dislocation has been that a combination of inflexible pipeline systems, a lack of capacity for shipping crude oilout of the US Midwest and a surge in deliveries of both Canadian and US domestic crude from new shale plays means that localoversupply is likely to be a persistent theme affecting WTI prices and spreads until at least early 2013. Current forward curves forBrent and WTI suggest that market participants expect dislocations to persist above $7 for the next four years, with the one-yearforward differential currently at $18 and the two-year forward differential at $14. However, under extreme conditions of oversupply,it is quite possible that the WTI-Brent spreads could exceed these levels by a considerable margin, especially if the storage situation

at Cushing gets so bad that price signals need to be sent to encourage some of the regions crude oil suppliers to shut in theirproduction. We have attempted to quantify this by constructing the theoretical forward curve for WTI. We first calculate thefinancing cost using US fed fund rates, and then add storage costs to calculate the total carry cost for different maturities. Wesimulate the forward curve by adding the computed carry cost to the spot price for each point on the curve. Our results showthat the point at which the current WTI forward curve meets our simulation is December 2012, after which the slope of thecurrent forward curve starts to decline gradually. The maximum gap between the current forward curve and our simulation isreached in June 2012, suggesting, as mentioned above, significant risk of further blow out in spreads during H1 2012.

The key message to take away is that the probability distribution of the WTI-Brent spread has clearly changed, becoming more"extreme event-driven", but it is still too early to determine whether this will eventually go back to the long-term normaldistribution. In addition, one point at which there already appears to be a significant risk of a further blow out in spreads is earlynext year when there is a high level of refinery maintenance being scheduled for local Midwest refiners.

The present

The latest saga started in September 2010, when the prompt WTI contango started towiden once again, at the same time as the Brent contango had started to disappear. Thistime around, it was less to do with the reality of actual Cushing builds, but more to do withperceptions that they were imminent, due to expectations of heavy turnarounds. Added tothat, the potential effects of the rupture and subsequent closure of Enbridge Line 6B led tomarket expectations of a reduction on the call on Cushing crude. Enbridge Line 6Aremained full with storage building throughout the system up to and including Illinois. Whilethe overall level of prompt contango moved around a bit following a leak soon after in Line6A, the WTI contango crept back again and remained, in our view, wider than waswarranted by the incoming data. Despite eight successive drawdowns in Cushing

inventories, amounting to 3.5 mb between the end of July and the end of September, theprompt WTI contango increased from 44 cents per barrel to $1.16 per barrel. Eventually, inearly November, Cushing inventories fell to a six-month low of 31.8 mb before beginningtheir seasonal ascent at least a month later than usual. It seemed that many in the markethad justified the large prompt WTI contangos on the basis of an expectation of an imminentand severe rise in Cushing inventories. While, first, the continuing bleed down in Cushinginventories and then the later than usual commencement in the rise of stocks, should havehelped to achieve some closure on that particular debate, prompt WTI contangos remainedfairly weak and WTI starting dislocating heavily from other benchmarks. By early this year,the WTI-Brent differential widened to more than $6 per barrel; LLS traded at a premium of$7.75 to WTI, while even the sour grade crude, Mars, moved from trading at a usualdiscount to a premium of $3.10. The very prompt spread continued to remain trapped by

overextended market perceptions of large and inevitable Cushing builds.

Reasons for the start of the dislocation

The ultimate nail in the coffin for WTI, however, was the start-up of the Keystone extensionto Cushing, drawing in more Canadian crude. The Keystone Pipeline System bringsCanadian crude to the US Midwest, with Keystone Cushing (Phase II) an extension of theKeystone Pipeline from Nebraska to Cushing, Oklahoma. Phase I, connecting Alberta withIllinois, has a maximum capacity to transport 435 thousand b/d of oil sands crude toMidwest refineries. With the Cushing extension, the overall Keystone systems capacity is

Expectations of heavy refinery

maintenance and disruptions to

pipeline flow was the start of this

present dislocation

Keystone pipeline start-up was

the nail in the coffin for WTI,

creating expectations of an

imminent and permanent filling

up at Cushing through higher

Canadian volumes

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raised to 591 thousand b/d, with the extension itself being able to transport about 156thousand b/d. The ultimate aim of the Keystone pipeline is to complete the Gulf Coastexpansion by 2013, via Cushing. But with very little progress made in even starting up theextension, currently Keystone is seen as a pipeline responsible for causing a Cushing glutrather than offering any takeaway capacity. With the start-up of this pipeline on the horizonin Q1 11, the pricing structure for WTI started assuming that all storage in Cushing was

already full, or more precisely that it is inevitable that it will fill following the start-up of theKeystone pipeline connection into Cushing. It is that expectation which then dominated,together with the recalibration of expectations on domestic production, sealing the fate forWTI. With Canadian oil sands output rising strongly and conventional production declineseasing significantly, together with Canadas inability to export crude outside the US due toinfrastructural constraints, the net result would be increased flows towards Cushing.Notwithstanding technical outages, the steady stream of new projects is set to add around200 thousand b/d of capacity in 2011 and 250 thousand b/d in 2012, with the bulk of thegrowth materialising from heavy bitumen crude. Thus, an existing sensitivity to local andspecific intra-regional factors has been heightened by the start-up of the Keystone pipeline,resulting in intensified dislocations. This trend has been exacerbated by the increasingability of US refineries to process heavy crude, and with additional coking projects slated to

come online through this year and next, Canadian bitumen should continue to find a homein the US Midwest. Overall, Keystone has proved to be a massively destabilisingdevelopment for the WTI market given the tidal wave of expectations of full storage it hascreated. Across all points this year, there has actually been a lot of spare storage at Cushingavailable and there is more coming, but the market perception is that, however much isspare, there is now a structural imbalance at the margin that means all spare storage mustinevitably fill. Keystone will not destroy the WTI market, but its impact on expectations andthe creation of the enormous rift with values on the Gulf Coast seem to suggest that WTIsdays of being seen as a global marker may be drawing to close.

Furthermore, as mentioned above, the rapid commercialisation of liquids-rich shale plays inthe US provided some buoyant expectations of domestic US oil production, with the large partof that volume expected to make its way to Cushing, effectively backing out crude demandfrom that hub. Indeed, over the past two years, there has been a tangible acceleration in thediscovery and rapid development of shale and tight sands plays in North America, especiallyplays that have extensive liquids windows. In 2011, this most positive trend has shown no

Figure 15: Keystone pipeline flow into Cushing, thousand b/d Figure 16: North Dakota oil production, thousand b/d

0

20

40

60

80

100

120

Jan-11 Mar-11 May-11 Jul-11 Sep-11

100

150

200

250

300

350

400

450

07 08 09 10 11

Source: Genscape, Barclays Capital Source: North Dakota government statistics, Barclays Capital

Expectations of higher domestic

production in the US added

further to expectations of

Cushing filling up

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signs of abating. These days, the time line from discovering a promising liquids rich shale playto commercial production has become astonishingly compressed. From emergent to core intwo years has been the story for most of the American shale plays. The Bakken formation inNorth Dakota has been the poster-child of oil shales in the US, with the rise in productionphenomenal. In 2007, North Dakotas oil output stood at 124 thousand b/d, 16% of which (20thousand b/d) was accounted for by Bakken, where a total of 441 wells had been drilled.

Today, the states output had grown to 425 thousand b/d, constituting just above half of thetotal Midwest production and the number of wells in the state stands at a staggering 5,500.The success achieved in Bakken is fuelling the idea that similar results can be obtained in othershale-plays across the country, and in particular, Eagle Ford, where a large area of recoverableliquids play has been discovered. While both the lack of proper infrastructure and quality ofcrude (particularly in Eagle Ford where the bulk of volumes is likely to be in the form of NGLsrather than liquids) remain a constraint for the long-term success and viability of US onshoreproduction, these limitations are not currently on the markets radar. Moreover, precisely dueto the lack of proper long-distance pipelines, companies such as Enbridge have added short-haul capacity to tie in to existing systems from Bakken with similar arrangements likely to bemade for Eagle Ford liquids too. The net result will be to bring more crude into Cushing in theshort term, before appropriate infrastructure expansions are completed to enable shale oil to

be shipped to other parts of the US.

To digress slightly here, it is worth reiterating our views expressed above. WTIs dislocation has todo with WTI alone and nothing else, however unjustified those perceptions may be as we willdiscuss below. The WTI-Brent differential is not related to Egypt, for which benchmark is closer tothe Suez Canal or Libya or for which benchmark is most affected by US economic statistics andexpectations While some of the recent tightness in the North Sea market due to severeproduction problems and the loss of barrels from Libya for over six months has furtheraccentuated the strength in Brent, the shortfalls in North Sea production tend to get reflected indifferentials in the physical market (eg Forties diffs over Dated Brent, which incidentally is tradingat record levels) and in the structure of the Brent curve. No doubt, the Brent structure is anextremely powerful and important driver of flat prices at the front, but to attribute the strength of

the Brent-WTI spread to North Sea production shortfalls would be a mistake, in our view. This isalso apparent when considering WTIs differentials to other benchmarks, which too havewidened to record levels and this has not been limited to Brent alone. US Gulf Coast prices(reflected in LLS benchmarks) have continued to track the global picture and are in line withBrent prices. As Brent and LLS are connected and LLS and WTI are not connected, it is clear thatthe extreme discount of WTI to Brent can have nothing to do with differences between Europe inthe US, given that Louisiana and Oklahoma are not so different that they face differentgeopolitical conditions or radically different exposures to US economic policy. In short, the WTI-Brent differential tells us absolutely nothing about differences between Europe and the US. Itdoes, however, tell us everything about the difference between crude oil in the US Gulf and crudeoil in the US Midwest. The former is part of a world market, the latter is constrained by itslogistics and can (and has) dislocated away from the world market.

The reality

Back to WTI and its regional balances. For those readers who have so far believed that Brenthas been impacted by Middle Eastern geopolitics and WTI has not, and already forgottenthe two main reasons why WTI dislocated, here is a quick recap. The latest phase of the WTIdislocation is to do with the combination of easier access to Cushing from the south and anincrease in domestic US production and Canadian availabilities, with the culmination of thelatter taking place with the start-up of the Keystone pipeline. However, despite the pertinentbelief that Cushing would fill up to the brim due to the reasons described above, the realityhas been a bit different from what current differentials signal.

WTIs dislocation is to do

with WTI alone, and not to

do with geopolitics or North

Sea production

Expectations of Cushing filling up

have not materialised yet

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First, while domestic production in the US Midwest has increased, the rise has been far lessthan consensus rhetoric usually alludes to. The unconventional plays have expanded moreat a rate in line with our expectations, that of 200-250 thousand b/d. With full H1 outputdata now available, US Midwest production is higher y/y by 95 thousand b/d, while US GulfCoast output is higher y/y by 98 thousand b/d, with the rise in volumes in Texas offsettingthe shortfalls in the Gulf of Mexico output. Granted, freezing weather in the winter and the

drought in the summer impacted both North Dakota (Bakken) and Texas (Eagle Ford) shaleplays adversely, but the current shale industry does seem quite sensitive to weathervariations, with winter months, in particular, seeing a systematic drop off in North Dakotasproduction. Moreover, equipment costs have been rising and, although not near the 2008levels, they have played a part in slowing down some of the production gains. Moreover, therig market is constrained by availability of high horsepower rigs, those that are capable ofdrilling horizontally. What this means is that rigs that are able to drill horizontally might haveto be shifted more and more from drilling for gas to drilling for oil, rather than simply beingpicked up from the sidelines. The sequential growth in H2 11 is likely to be higher given theeasing in the extreme weather conditions, as evidenced by the first look at H2 data fromNorth Dakota. The number of wells drilled in the state increased by almost 200 over themonth in July, with production rising m/m by 39 thousand b/d, the strongest pace of

monthly increase ever. While undoubtedly the strongest pace of growth, the increases arelimited to tens of thousands of barrels per day, rather than in hundreds, let alone millions. Infact it will be almost impossible for the shale plays to grow at a pace that would add millionsof barrels to the Midwest on a monthly or even yearly basis as is often taken for granted bythe market. Liquids acreage, so far, seems to be more constrained than gas acreage, whichis also likely to limit the exponential growth in volumes. Further, only a part of the US GulfCoast shale oil output actually makes its way to Cushing, so it would be a mistake to equateall of the increases in domestic US production to a 1:1 increase in Cushing stocks.

This is not to say that we doubt for even one second that the rapid commercialization ofliquids-rich shale plays could deliver higher US domestic production. In the past 24 monthsthere has been a tangible acceleration in the discovery and rapid development of shale and

tight sands plays in North America, especially those that have extensive liquids windows.The shift to oil drilling has thus been steady and relentless. Given current pricingdifferentials between oil and gas, it can hardly be described as surprising. While some of theincrease in oil drilling reflects better economics in drilling for oil versus natural gas, some ofit also simply reflects strong economics in oil that are attracting more and more rigs thathad been idled previously. The gas rig count has fallen from 996 to a current count of 896rigs, a loss of 100 rigs over the past year. Over the same time period, the oil rig count hasrisen by 353 rigs, and thus a one-to-one transfer clearly has not happened. Nonetheless, asense of proportion should be kept. Even with rigs increasingly by the hundreds, domesticproduction is not rising by the millions. Yes, US domestic production is rising and, yes, thiswill ultimately reduce the needs for the US to import crude. But the impact of this will be feltthrough LLS prices as the US competes less for West African barrels, and should not impact

WTI alone, as current prices are showing. The dislocation in WTI in theory should beprimarily based on infrastructural constraints in getting crude out of Cushing, once it getsfull, not on conjecture, especially when not proven by the data, that domestic production issurging and Cushing will imminently fill.

Shale matters, but a sense of

proportion needs to be kept

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Figure 17: Pipeline flows into Cushing, year-to-date, mb/d

Average

flows Basin

Centurion

North Hawthorn Seaway Spearhead

White

Cliffs Keystone Total

Jan-Sep 2010 298.1 26.1 25.1 140.2 144.6 26.1 0.0 660.3

Jan-Sep 2011 342.4 60.2 35.9 46.5 99.6 24.9 70.5 680.0

Difference 44.3 34.1 10.8 -93.7 -45.0 -1.2 70.5 19.8Source: Genscape, Barclays Capital

Second, while Canadian volumes into Cushing remain high and are likely to remain so in theforeseeable future, other pipeline flows have eased substantially a feature that most in themarket had overlooked entirely. In particular, Seaway and Spearhead pipelines have sentover 1.4 mb/d less crude to Cushing in the year-to-date, while Capline volumes coming tothe Midwest have fallen sharply too. This should not come as a surprise given the widedifferentials between WTI and all other crude grades in the US, where producers would beinclined to receive a higher value for their crude produced. If the differentials persist at theselevels, we would expect this trend to continue.

In fact, the flow of crude from other regions in the US to the Midwest has fallen by a large 246

thousand b/d in H1 11, while the reverse has increased by 62 thousand b/d (Figure 20). Clearly,depressed WTI values have already encouraged increased shipments by truck, trains and bargesand, while these volumes remain small in relation to the growth in production, these are likely tocontinue to increase. Logistics industry sources say that a quarter of Bakken's oil productionalready moves by rail, and they put current loading capacity in the region around 130 thousandb/d. Just recently, a 100 thousand b/d crude-by-rail terminal was confirmed, which should beginoperation this month. An additional 370 thousand b/d of similar crude-by-rail loading capacity inthe Bakken region is planned for several companies before the end of 2012.

Indeed, the greater the dislocation in WTI, the greater the incentive to speed up thetakeaway capacity from the Midwest, and also greater the incentive to send lower volumesto Cushing, wherever feasible. Equally, due to this very dislocation in WTI, refinery marginsin the Midwest have been extremely attractive, reflected in fairly strong refinery runs seenover the past few months. With the latest weekly increase, runs are now 115 thousand b/dhigher y/y. Put all of the above together and Cushing inventories have actually fallensystematically, rather than filling up to the brim (Figure 21).

Swings in US Midwest crude oil

flows have resulted in increased

crude flows out of Midwest and

slower than expected flows into

the Midwest

Figure 18: Flows in and out of the US Midwest, thousand b/d

Figure 19: Crude stocks at Cushing, Oklahoma, mb

500

700

900

1100

1300

1500

1700

1900

2100

2300

05 06 07 08 09 10 11

50

100

150

200

250

300

350Flows into Midwest

Imports into MidwestFlows out of Midwest

24

28

32

36

40

44

Jan Feb Mar Apr May Jul Aug Sep Oct Nov Dec

2010/112009/102008/09

Source: EIA, Barclays Capital Source: EIA, Barclays Capital

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Finally, another argument we have heard often is that the weakness in WTI is largely to dowith the perception that Cushing will get full, rather than the current fundamentals. Weeven accepted that premise, despite its underlying slight surrealism, as we found it difficultto fathom why prompt WTI would weaken if expectations were for Cushing to fill up nextyear. Those factors are slowly fading away somewhat too. Q1 12 was expected to see arecord 45 mb of refinery turnaround in the US Midwest alone. With the postponement of

the Whiting turnaround to later in 2012 or possibly even to 2013, Q1 12 refinerymaintenance is set to total just 25 mb now. The latest available data from the EIA onnameplate capacity at Cushing pegs the total at 57.859 mb at the end of March this year(and operational capacity at 48 mb). By April next year, nameplate capacity in Cushing willhave risen to over 75 mb (Figure 22), and thus should provide ample storage capacity.

Indeed, the backdrop described above is exactly what is being reflected in the structure ofthe WTI curve, with prompt WTI time spreads narrowing steadily (granted, heavy producerselling programmes have supported spreads throughout). In the past when Cushinginventories have filled, prompt WTI spreads have blown out to levels of above $9. If thereality was that Cushing was filled to the brim or even if the expectation was for the same,then the front-of-the-curve WTI time spreads would have to send the signal that there is

little to no crude oil storage available by ballooning out. However, the signal being sent outto the market by current time spreads is hardly one of distress. Thus, against this reality, to justify a prompt differential of WTI to other benchmarks greater than $20 points to asystematic market failure ie, to a market that is not sending the correct signals at all.

The future

The key to solving the imbalance at Cushing is to add pipeline capacity from Cushing to theUSGC. There are several competing pipeline projects that would carry substantial volumes.Here, there have been some recent breakthroughs but equally, some setbacks too.

Pipelines

The 400 thousand b/d Double E project was abandoned a few weeks ago, as EnergyTransfer Partners and Enterprise Products Partners could not find sufficient interestamong potential shippers. It emerges that producers who do not have storagecommitment at Cushing were reluctant to express their interest in the event that theyfail to get their crude to Cushing.

Cushing capacity rising too, to be

able to store more crude

Time spreads reflect the correct

conditions at Cushing, despite

the $20+ arb

Figure 20: Additional storage at Cushing, mb Figure 21: 1st-2nd month WTI time spreads, $/bbl

0

500

1000

1500

2000

2500

3000

Mar-11

Apr-11

May-11

Jun-11

Jul-11

Aug-11

Sep-11

Oct-11

Nov-11

Dec-11

Jan-12

Feb-12

Mar-12

Apr-12

Total addition = 19.5 mb

-3

-1

1

3

5

7

9

Sep-06 Sep-07 Sep-08 Sep-09 Sep-10 Sep-11

Past periods of WTI dislocation/Cushing filling up

Early 09

May-10Feb-11

Source: Company reports, Barclays Capital Source: EcoWin, Barclays Capital

Pipelines to carry crude from

Cushing will be the

ultimate solution

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However, Magellan Midstream Partners announced that they would reverse the 135thousand b/d Longhorn pipeline by mid-2013 and should help alleviate some of thesoggy balances at Cushing, as the higher flows from Canada and domestic US makes itsway to Cushing.

More so than ever, the fate of Trans Canadas Keystone XL pipeline (one with the largestvolumes), which is awaiting approval by the US Department of State, since a portion of that

pipeline crosses the US/Canadian border, is now key. The fate of the 600 thousand b/dpipeline will be decided on November 1, when the Obama administration has to make a finalruling on whether to give the go ahead or not, and, if approved, would most definitely help toalleviate significant pressure from Cushing from mid-2013 onwards. Currently, the project isfacing opposition from environmental groups, as these groups believe that TransCanada, theKeystone XL's builder, is trying to win support for the project by underplaying its potentialenvironmental hazards. Key points involve the pipeline's potential susceptibility to corrosion(internally and externally), the nature of the oil sands oil it would deliver from Alberta to USrefiners and TransCanada's monitoring capabilities. Should the administration, known for itspro-green stance, bow to the pressures of the environmental lobbyists, there is a growingrisk that the pipeline is not approved. While there are some other pipelines in the horizon,they are far from being approved and they remain theoretical at best. Thus, the approval of

Keystone XL is key and will be a key driver of the WTI-Brent spread in the coming months. Other proposals seeking shipper commitments have been made by Enbridge in the US

and Kinder Morgan in Canada.

Another possibility is the reversal of the Seaway line which has historically carried crude fromthe USGC to Cushing and could add a potential 350 thousand b/d off-take from Cushing.However, Seaway is presently underutilised (around 75 thousand b/d) and thus the reversalhas smaller than theoretical impact. The pipeline runs about 500 miles from Freeport, Texasto Cushing and is jointly owned 50/50 between ConocoPhillips and Enterprise, and feedscrudes to ConocoPhillips Borger and Ponca City refineries. In the past (2007), there havebeen talks about reversing Seeway by its previous owner TEPPCO, but it never materialised.While ConocoPhillips exit from its downstream business potentially increases the chances of

Seaways reversal, it is unlikely that the buyers of those refineries will not also want theownership of the pipeline, and risk the end of using dislocated WTI as feedstock to keepstrong margins. In order to reverse the pipeline flow, Enterprise would likely have to bringadditional pump stations and off-take terminals on stream, which could take 3-6 months.

Figure 22: Pipeline projects that could alleviate oversupply at Cushing

Name Company Route Start-up

Capacity

(kb/d)

Potential

Keystone XL TransCanada Cushing-Port Arthur Late 2013 600Northern Gateway Enbridge Alberta-Pacific Coast Q4 16 525TransMountain expansion Kinder Morgan Alberta-Pacific Coast ? 400Seaway reversal Conocco/Enterprise Cushing-USGC ? 350Trailbreaker/Line 9 reversal Enbridge Sarnia-Montreal ? 240Monarch Enbridge Cushing-USGC ? 150-300Bakken Expansion Bakken-Enbridge system Late 2012 145-325Bakken Mar

26 09 11 oil sketches

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