Oil Market Report: 13 July 2010

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  • Benchmark crude prices traded in a $71-79/bbl range in June, after a volatile May, as continued negative sentiment tempered upside price moves. Financial and equity markets remained the focus of attention, and by early July Atlantic basin benchmarks touched four-week lows, before rebounding to around $75.00/bbl by the 12th of the month.
  • OECD industry stocks rose for a second consecutive month in May, across all regions and by a combined 35.0 mb, reaching 2 757 mb or 61.0 days of forward demand cover. Preliminary data point to a further 3.5 mb build in the OECD in June, while crude and products held in floating storage fell, albeit offshore volumes remain high.
  • Global oil demand for 2011 is expected to rise by 1.6% or 1.3 mb/d year-on-year to 87.8 mb/d, assuming consensus trends in the world economy, crude prices and efficiency gains. Growth will be driven entirely by non-OECD countries (+3.8% or +1.6 mb/d), while the OECD sees resumed decline (-0.5% or -0.2 mb/d). The 2010 outlook remains largely unchanged at 86.5 mb/d (+2.1% or +1.8 mb/d versus 2009).
  • OPEC crude oil supply averaged 28.9 mb/d in June, down by 65 kb/d from May. A lull in OPEC crude capacity expansion is expected between now and end-2011, although gas liquids output rises by 0.6 mb/d in both 2010 and 2011. The 'call on OPEC crude and stock change' for 2010 has been revised up by 100 kb/d, to 28.8 mb/d. It averages 29.2 mb/d in both 3Q10 and 2011.
  • Non-OPEC supply could rise by 0.4 mb/d in 2011 to 52.8 mb/d, following 0.8 mb/d growth in 2010. Consolidated annual data and recent monthly estimates boost 2008-2010 production by 0.1 mb/d. Increases from Brazil, global biofuels, Azerbaijan, Colombia, Ghana and Oman offset decline from Mexico and the North Sea during 2011.
  • Global refinery crude throughputs are estimated at 73.5 mb/d for 2Q10, 1.3 mb/d above year ago and 0.7 mb/d higher than in 1Q10. A year-on-year recovery in US runs, plus continued expansions in non-OECD Asia, drive growth. OECD Europe, Pacific and Latin American runs remained weak due to maintenance and operational problems, though a rebound is expected in 3Q10.

A Goldilocks markets in 2011?

The July Oil Market Report is traditionally the occasion to take a first detailed look at fundamentals for the following year. Here we roll-out our quarterly projections to end-2011, hard on the heels of our annual outlook through 2015 released in the Medium-Term Oil and Gas Markets 2010 in late-June. The results suggest a market balance remaining relatively comfortable through mid-2011, but with tightening market fundamentals possible from the second half of next year.

We base our oil demand projection on the IMF's April World Economic Outlook, with global GDP growth reaching +4.3% in 2011 from +4.1% in 2010 as recovery from the 2008/2009 recession continues apace (a recent interim update by the IMF, while noting downside risks, does not materially change this view). Despite economic recovery, oil demand growth slows to 1.3 mb/d next year from 1.8 mb/d in 2010, amid a continued structural shift away from oil in the OECD and the dual impact of improving end-use efficiency and gradual phase-down of economic stimulus in the non-OECD. Next year, as in 2010, the non-OECD generates all of expected demand growth, again bringing the issues of data transparency and resilient end-user price subsidies to the fore.

Of course, sustained economic recovery cannot simply be taken for granted. Were 2011 economic growth to turn out 30% lower than our working assumption, global oil demand could be around 1.0 mb/d less, at 86.8 mb/d instead of the anticipated 87.8 mb/d. This would eclipse most of the 2011 demand growth seen in the base case and leave markets prone to renewed weakening once again.

A relatively relaxed view of market fundamentals in our base case, at least until mid-2011, hinges on  continued, albeit slower, growth in non-OPEC supply and OPEC gas liquids, respectively 0.4 mb/d and 0.6 mb/d in 2011. Relatively high, stable crude prices, rising spending, and a lull in upstream cost inflation have re-invigorated growth after the lean years of 2005-2008. Brazil, Colombia and Canada give an Americas-oriented slant to 2011 non-OPEC growth, as do rising biofuels supplies. However, new output from emerging producers like Ghana also plays a part. Qatar and the UAE drive expected growth in OPEC gas liquids, augmented by Algeria, Iran and Saudi Arabia. Given prevailing oil-gas price differentials, developers are keen to preferentially monetise wetter gas supplies wherever possible.

However, we should also acknowledge the potential for supply to disappoint to the downside. Around 30 kb/d is cut from our 2010/2011 US Gulf of Mexico estimate because of delays following the Deepwater Horizon disaster. Project delays could further curb future US supply if wide-reaching drilling restrictions arise from the disaster enquiry. And we again note the seemingly ever-present geopolitical risks hanging over some OPEC producers, which could also affect supply in the months ahead.

That said, midstream bottlenecks look unlikely between now and end-2011.  Refinery additions continue apace, with 2.3 mb/d of new primary capacity (much of it in China, the Asia Pacific and Middle East) being added globally during 2010/2011, which will cap system-wide utilisation rates. Shipyards will also deliver over 70 mdwt of new tanker tonnage this year and next. Midstream and downstream markets are notoriously cyclical, and it looks like both refining margins and freight rates could underperform, despite the economic upturn foreseen in most consensus forecasts.

While the annual 'call on OPEC crude and stock change' gains around 500 kb/d year-on-year in 2011, OPEC may still have to grapple with largely static year-on-year demand for its crude until around mid-year. Before market bears get overly excited however, it is worth pointing out that installed OPEC capacity levels themselves face something of a lull, suggesting spare capacity could be anchored close to a prevailing 5.5-6.0 mb/d until well into 2011. In short, markets in 2011 may prove 'not too hot, not too cold'. Whisper it quietly, but we might, just might, be in for some market stability for a while longer.



  • Global oil demand for 2011 is expected to rise by +1.6% or +1.3 mb/d year-on-year to 87.8 mb/d. This is based on IMF economic assumptions (World Economic Outlook, April 2010), which see global economic growth reaching +4.3% in 2011, compared with +4.1% in 2010 (this report does not integrate the last IMF partial update, released at the time of writing). It also assumes that global oil prices will average $79.40/bbl in nominal terms, and that oil intensity will decline by 2.6%. Oil demand growth in 2011 is expected to be driven entirely by non-OECD countries (+3.8% or +1.6 mb/d), while the OECD is projected to resume its gentle decline (-0.5% or -0.2 mb/d). Moreover, given the prevailing structure of economic activity, with government stimuli favouring energy-intensive sectors, growth will be led by distillates, LPG/naphtha, and gasoline. The global oil demand outlook for 2010 remains largely unchanged at 86.5 mb/d (+2.1% or +1.8 mb/d versus 2009).
  • OECD oil demand for 2011 is projected at 45.3 mb/d (-0.5% or -210 kb/d over 2010). Despite expectations of relatively strong GDP growth (+2.4%), the observed aggregate income elasticity in the OECD is effectively negative, as greater efficiency, saturation and interfuel substitution more than outweigh the impact of economic growth on oil demand. North America will cease to act as an engine of demand growth in the OECD as the 2010 economic rebound, fuelled by government spending and private-sector restocking, fades. This region's oil demand decline will compound the fall expected in Europe and the Pacific. Regarding 2010, the estimate is revised down (-20 kb/d) to 45.5 mb/d (+0.1% or +60 kb/d year-on-year), with a weaker outlook for the Pacific exceeding a higher baseline in Europe following the inclusion of finalised 2009 data.

  • Non-OECD oil demand for 2011 is estimated at 42.5 mb/d (+3.8% or +1.6 mb/d year-on-year). This is commensurate with aggregate GDP growth - expected to top +6.5% - and high income elasticity. Non-OECD Asia, the Middle East and Latin America will continue to command the lion's share of oil demand growth in 2011, but at a somewhat slower pace when compared to 2010. This is mostly due to expectations that Chinese demand growth will moderate as the government gradually withdraws its fiscal and monetary stimuli. As such, China should account for about 30% of global growth next year, versus almost half this year. The outlook for 2010, meanwhile, has been adjusted up (+70 kb/d) to 41.0 mb/d (+4.3% or +1.7 mb/d year-on-year) on the back of baseline revisions following the inclusion of finalised 2008 data for all remaining countries (most notably China, Russia and Iraq).

Global Overview

This report presents our first detailed assessment of global demand prospects for 2011. Our recently released Medium-Term Oil & Gas Markets 2010 (MTOGM) provided an initial glimpse, but this was based on data frozen in May. Since then, revisions for both OECD (2009) and non-OECD countries (2008), together with two more months of actual and preliminary readings for 2010, have been included, entailing a slightly higher baseline. The 2011 outlook, however, is broadly in line with the MTOGM. Based on the IMF's spring GDP prognoses (World Economic Outlook, April 2010), which see global economic growth reaching +4.3% in 2011 (compared with +4.1% in 2010), oil demand is projected to expand by +1.6% or +1.3 mb/d year-on-year to 87.8 mb/d. This forecast also assumes that oil prices will average $79.40/bbl in nominal terms, and that oil intensity will decline by 2.6%.

Following a familiar pattern, oil demand growth in 2011 is expected to be driven entirely by non-OECD countries (+3.8% or +1.6 mb/d), while the OECD should resume its gentle decline (-0.5% or -0.2 mb/d). This is commensurate with GDP growth and income elasticity trends: output in the non-OECD - where elasticity is highly positive - is expected to top +6.5%. This is roughly three times as high as in the OECD (+2.4%), where the observed elasticity is effectively negative, as greater fuel efficiency, saturation and interfuel substitution outweigh the impact of economic growth on oil demand.

Non-OECD Asia, the Middle East and Latin America will continue to command the lion's share of oil demand growth in 2011, but at a somewhat slower pace when compared to 2010. This is mostly due to expectations that Chinese demand growth will moderate as the government gradually withdraws its fiscal and monetary stimuli. As such, China should account for about 30% of global growth next year, versus almost half this year. Meanwhile, demand in North America will cease to act as a source of growth in the OECD as the 2010 economic rebound, fuelled by government spending and private-sector restocking, fades. This region's decline will compound the demand fall/stagnation expected in Europe and the Pacific.

Given the prevailing structure of economic activity, growth in 2011 will be led essentially by distillates, LPG/naphtha, and gasoline. Indeed, government stimuli across the world, notably in non-OECD Asia and the Middle East, have targeted energy-intensive sectors (such as construction, petrochemicals, vehicle manufacturing, consumer appliances and agriculture). Fuel oil demand, by contrast, should continue to fall, as utilities and industry switch to other sources for electricity generation (natural gas, nuclear power and renewables, as well as direct crude burning and gasoil). In addition, the consolidation of 'teapot' refineries in China has resulted in a significant reduction of fuel oil as a feedstock - and hence less production of heavy products and off-spec gasoil, included in our apparent demand calculation. Bunker demand, however, should provide a floor to fuel oil use, although more stringent environmental regulations, mandated by the International Maritime Organisation (IMO), are likely to encourage further interfuel substitution towards low-sulphur gasoil in the years ahead, despite concerns over the capability of the refining sector to meet onshore gasoil growth.

In aggregate terms, this forecast appears to be consistent with recent trends. However, there is a significant risk that global economic growth may turn out to be much more subdued than currently foreseen. The recent turmoil in the Eurozone, mounting concerns over excessive OECD indebtedness and the ensuing fiscal retrenchment, lingering global financial and trade imbalances, and recent data suggesting that the recovery may be faltering could well result in a 'double-dip' recession in several large OECD countries, according to some observers. By way of illustration, our MTOGM lower GDP case suggested that global oil demand could be some 1.0 mb/d below the base case in 2011, should economic growth be a third lower than expected. On the upside, China could well delay its policy tightening in order to pre-empt an OECD slowdown, despite rising inflationary pressures, and thus keep the momentum for strong domestic - and global - oil demand growth.

Given time limitations, this report does not integrate the last IMF partial update, released at the time of writing, but will do so in August. The slightly higher GDP prognoses for 2010 may entail small upward revisions to this year's oil demand forecast, mostly in the non-OECD, but baseline adjustments may partly counteract this. The GDP assumptions for 2011, by contrast, are broadly unchanged, although several large OECD and non-OECD countries - notably in Europe and Asia - are now expected to grow at a somewhat slower pace, which may reduce overall oil demand growth. The next full IMF update, to be released in the autumn, should provide a clearer picture on the world's economic outlook, particularly for 2011.


OECD inland deliveries (oil products supplied by refineries, pipelines and terminals) surged by 3.2% year-on-year in May, according to preliminary data, on the back of strong demand in OECD North America (which includes US Territories) and OECD Pacific (+5.7% and +2.3%, respectively). Growth in both areas was largely driven by middle distillate and 'other products' demand. By contrast, oil demand in OECD Europe remained weak (-0.4%), albeit less so than in previous months, as rising naphtha and diesel demand offset the contraction in other product categories.

Note: The tables featuring total and regional OECD demand per product, based on the latest official submissions and normally published in this section, have been moved to the back of the report from this edition under a revisited Table 2a. In addition, Table 2b has also been revamped for consistency.

Upward revisions to April data in Europe (+200 kb/d) were partly offset by changes in the Pacific (-70 kb/d), while changes in North America were negligible. Europe's sizable revisions stem from baseline changes related to the incorporation of finalised 2009 data, on the one hand, and from changes in the Netherlands' reporting methodology from 2007 onwards (detailed under 'OECD Europe' below). Overall, the adjustments for 2009 were negligible (-9 kb/d), with North America (+6 kb/d) and Europe (+9 kb/d) partially offsetting the Pacific (-24 kb/d). However, if the Netherlands were excluded, Europe's revisions would have been more substantial (-85 kb/d).

The prognosis for 2010, meanwhile, is revised down (-20 kb/d) to 45.5 mb/d (+0.1% or +50 kb/d year-on-year), with weaker expectations for the Pacific exceeding a higher baseline in Europe and virtually no changes in North America. Looking forward, as much as North America's distillates strength, suggested by preliminary estimates, may help underpin total OECD oil demand this year, decline should structurally resume in 2011. Next year, demand is projected to shrink by 0.5% (-210 kb/d) to 45.3 mb/d.

North America

Preliminary data show oil product demand in North America (including US territories) rising by 5.7% year-on-year in May, following a 3.6% increase in April. Middle distillates drove growth in May, with diesel and jet fuel/kerosene posting annual rises of 13.9% and 4.9%, respectively, as regional economic activity continued to pick up. The role of petrochemicals in the recovery has ebbed, with LPG shrinking for a second straight month, though naphtha (which accounts for a much smaller share of activity) posted annual growth of 28.4%. Despite strong growth in Canada and Mexico, regional gasoline readings remained flat due to a slight decline in US consumption. More recently, indicators have pointed to a potentially moderating economic rebound. Though developments remain positive, particularly in Canada and Mexico, the US economy is struggling to create jobs.

April preliminary data were essentially unchanged as downward revisions to LPG and jet fuel/kerosene were offset by higher residual fuel and heating oil readings. North American oil demand for 2010 is seen rising to 23.6 mb/d (+1.5% or +350 kb/d year-on-year and unchanged versus our last report). Looking forward, despite regional GDP expanding by 2.8% year-on-year, oil demand should fall slightly to 23.6 mb/d in 2011 (-0.3% or -80 kb/d) with declines in motor gasoline, petrochemical feedstocks and heating/power generation fuels outweighing growth in middle distillates.

Adjusted preliminary weekly data for the continental United States indicate that inland deliveries - a proxy of oil product demand - grew by 1.9% year-on-year in June, following a 5.6% year-on-year rise in May. June data were mixed, with a 13.0% year-on-year gain in diesel demand outweighing falls in jet fuel/kerosene demand and essentially flat gasoline and LPG deliveries. Though rising road and rail freight activity appears supportive of diesel, we remain cautious over the strength of underlying demand. Strong diesel exports are likely helping to boost weekly deliveries data, and thus apparent demand, above actual domestic consumption.

Although gasoline demand rose by only 0.4% in June, the summer driving season and lower gasoline prices (off by $0.15 cents month-on-month to about $2.75/gallon) boosted consumption throughout the month after a tepid seasonal start. Weekly data through July 2 show what may have been this year's summer gasoline demand peak (it normally occurs around the 4 July Independence Day holiday). Indeed, auto industry association AAA forecast that the number of people driving during the holiday weekend jumped by 17.7% year-on-year. Nevertheless, gasoline demand is still expected to decline slightly in 2010, given increased economic uncertainty amid a languid job market and plummeting consumer confidence in June.

Looking forward, we expect US oil demand to fall by 0.5% to 18.9 mb/d in 2011 after rising by 1.0% in 2010. While expected real GDP growth in 2011 is lower than in 2010 (2.6% versus 3.1%), the forecast assumes continued economic recovery, spurring growth of 1.8% and 1.7% in diesel and jet fuel/kerosene demand, respectively. Still, declines in other categories more than offset the middle distillate gains. In gasoline, vehicle economy improvements should lead to a decline of 0.5% (see 'Evaporating US Gasoline Demand?' in MTOGM, June 2010), while fuel usage in the petrochemicals, heating and power sectors should continue to fall structurally.

Mexican oil demand surged in May, rising by 8.9% year-on-year as industrial activity has continued to improve. Demand strength was broad-based, with gasoline, middle distillates and residual fuel oil all posting gains. In 2011, Mexican oil demand is expected to grow by 1.4% to 2.2 mb/d as economic growth increases to 4.5%. Oil product demand growth will be led by the transportation sector, with jet fuel/kerosene, diesel and gasoline all expected to post annual gains (+7.0%, +3.4% and +2.5%, respectively).

Meanwhile, estimated May growth for Canada stood at 3.9%, following reported growth of 12.3% for April. Gasoline and petrochemical feedstocks posted the strongest gains, while middle distillates posted year-on-year declines. In 2011, despite a slightly stronger GDP outlook, Canadian demand should decline by 0.9% to 2.2 mb/d. Structural declines in heating oil and residual fuel oil combined with more efficient gasoline usage should outweigh growth in diesel and jet fuel/kerosene.


According to preliminary inland data, oil product demand in Europe fell by 0.4% year-on-year in May, as rising deliveries of naphtha (+9.5%) and diesel (+4.1%) failed to entirely offset losses in all other product categories. Interestingly, jet fuel/kerosene demand was flat, indicating that the sequel of volcano-related air flight disruptions that began in May were much less severe than feared, compared to the sharp drop registered in the previous month.

Meanwhile, demand for heating and residual fuel oils remained subdued, despite relatively cold temperatures (HDDs were much higher than both the ten-year average and May 2009), indicating continued displacement by relatively abundant and cheap natural gas supplies. The weakness in heating oil deliveries, however, may also be related to efficiency gains spurred by more stringent environmental standards. Since last year, the largest heating oil market in Europe - Germany - has undergone a gradual switch to low-sulphur fuel (with 0.005% of sulphur content, compared to 0.1% for more conventional heating oil). This trend has been underpinned by subsidised low-sulphur heating oil prices and government grants to encourage the installation of new household boilers, as well as relatively low diesel prices, which have reportedly fostered wholesale blending with high-sulphur heating oil. As such, some observers expect that the entire German heating oil market will have switched to the new specification by year's end. Moreover, the new boilers - which can only burn low-sulphur oil - are some 15%-20% more efficient, according to some estimates.

Revisions to April preliminary demand data were substantial (+200 kb/d). They were mostly due to the incorporation of finalised 2009 data and, more importantly, from changes in the Netherlands' reporting methodology from January 2007 onwards. The Dutch changes were indeed large (+90 kb/d on average over 2007-2009), offsetting the entire European adjustments for 2009 (and representing three-quarters of April's revisions). Under the new methodology, NGLs supplied to the petrochemical sector, which were previously excluded from demand figures, are now counted as part of 'other products' deliveries. In addition, other light oils previously counted under gasoline are now included in naphtha demand. Overall, the naphtha category accounted for the bulk of the revisions. Total Dutch oil demand is now assessed at 1.0 mb/d in 2010 (-1.0% year-on-year), with naphtha accounting for almost 20% (twice as much as previously estimated).

Looking ahead, although total oil demand in OECD Europe remains virtually unchanged at 14.3 mb/d in 2010 (-1.6% or -240 kb/d compared with the previous year and 20 kb/d more than previously forecast), downside risks remain. The region's economic recovery may suffer from the new austerity drive, particularly if Germany, France and the United Kingdom follow through on their recent announcements. If aggregated domestic consumption fades away, the threat of a faltering economic recovery or even of a 'double-dip' recession - regional, or worse, global - cannot be discounted. But even if the situation stabilises, fulfilling current expectations of relative strong GDP growth (+1.9%), oil demand will continue to decline in 2011, falling to 14.2 mb/d (-0.2% or -30 kb/d versus 2010), with modest growth in naphtha and distillate demand failing to offset a fall in other product categories.


Preliminary data show that oil product demand in the Pacific increased by 2.3% year-on-year in May, on the back of strong deliveries of LPG (+5.1%), jet fuel/kerosene (+5.0%) and 'other products' (+59.8%), which offset falls elsewhere, notably diesel (-3.3%) and residual fuel oil (-6.1%).

The increase in LPG demand, together with modestly rising naphtha deliveries (+0.1%), suggests that the petrochemical-led economic recovery remains relatively resilient, despite concerns of a forthcoming slowdown in China, the region's main recipient of petrochemical supplies. The rise in kerosene deliveries, used for heating in both Japan and Korea, was due to continued unseasonably cold temperatures (HDDs were higher than both the ten-year average and the same month in the previous year).

The surge in 'other products', driven entirely by Japan, is more difficult to interpret. An increase in direct crude burning for power generation is implausible, given cheaper natural gas and rising utilisation rates in nuclear power plants. Most likely, this figure reflects some statistical issues with preliminary data - different sources have provided widely different estimates for May - and thus may be revised.

April data revisions came to -70 kb/d, mostly centred on naphtha and jet fuel/kerosene. As such, OECD Pacific oil demand rose slightly less than anticipated in that month (+1.7% vs. +2.3% year-on-year). Together with adjustments to 2009 data (-20 kb/d), oil product demand in 2010 is revised down by 60 kb/d to 7.6 mb/d (-0.6% or -50 kb/d year-on-year). Despite accelerating GDP growth (+2.8% year-on-year), regional oil demand for 2011 is assessed at 7.5 mb/d (-1.3% or -100 kb/d compared with the previous year), with most product categories resuming their structural decline, offsetting modest growth in LPG, naphtha and diesel demand.



According to preliminary data, China's apparent demand (refinery output plus net oil product imports) rose by 9.5% year-on-year in May. Demand continues to be led by naphtha (+52.3%), jet fuel/kerosene (+15.7%), gasoil (+12.3%) and 'other products' (+11.8%). Meanwhile, gasoline demand is again featuring counter-intuitive weakness (-2.4%), since monthly sales of new vehicles remain strong (+10% year-on-year) - although admittedly growth has slowed down slightly when compared to previous months.

This brings back to the fore concerns about Chinese data (in terms of both quality and comprehensiveness, particularly regarding independent refining activity and stocks of crude and oil products). Indeed, finalised 2008 data have been submitted, lowering the baseline by 140 kb/d and indicating lower growth than suggested by monthly figures. Moreover, the calculation of the overall implied income elasticity shows that demand data for 2001, 2007 and 2008 are arguably too low, assuming that at its current stage of development China's average income elasticity should be around 0.5. Alternatively, if oil demand data are accurate, this could suggest that GDP readings may be inflated, as repeatedly argued by numerous observers.

Aside from these data puzzles, May's growth, albeit respectable, is much lower when compared to the average of the previous eight months (+17.4%). This may suggest a gentle slowdown in 2H10, as the government attempts to cool down the economy. Recent moves towards allowing a gradual appreciation of the renminbi vis-à-vis the dollar - the re-introduction of a crawling peg - have been interpreted in such a light. However, the move - announced a week before the G20 meeting in late June - was limited in extent. Had the appreciation been much larger - +10% or more, rather than the +3% expected by most observers over the next 12 months - the effects would have probably been more significant. Under a more dramatic appreciation, imports, notably of commodities, would become cheaper, and a widely called-for global economic rebalancing (mainly through rising domestic Chinese consumption and greater US savings) would have a better chance of happening. In addition, a greater revaluation would have the additional advantage of helping to curb mounting inflation and slowing down the accumulation of foreign exchange reserves (of which at least two-thirds are estimated to be in dollars). But exports, the country's main economic engine, would also probably suffer, the more so considering that China's main trading partner - Europe - has effectively become more competitive with the euro's recent slide.

In the short term, the Chinese government will continue to face the challenge of maintaining export-driven economic growth while allowing for greater currency flexibility as requested by its trading partners, which find themselves at a comparative disadvantage relative to China. However, having so far denied itself the use of the exchange-rate tool, the government may be obliged to tighten fiscal and monetary policies to a greater degree than intended in order to control inflation and prevent asset bubbles. Thus, assuming that the government gradually unwinds its stimulus programme, oil demand growth is likely to slow down from its current pace (+9.0% in 2010). In fact, the pace of growth should moderate from 2H10 (to around +4% year-on-year versus +14% in 1H10).

In 2011, with GDP expanding by 9.9% year-on-year, oil demand is projected to average 9.6 mb/d, +4.8% or +430 kb/d versus 2010. Growth will be driven predominantly by transportation fuels (gasoline, diesel and jet fuel/kerosene) and much less by government-supported categories (such as naphtha and 'other products'), which largely underpinned 2010 growth. Both LPG and fuel oil should continue to slide given rising natural gas penetration in urban areas and the ongoing consolidation of independent refiners, notably the 'teapots'.

Other Non-OECD

India's oil product sales - a proxy of demand - surged by 6.5% year-on-year in May. In addition to prevailing strong gasoline, gasoil and LPG readings (+12.6%, +11.1% and +7.0%, respectively), naphtha demand registered a spike (+33.3%) due to the gradual start-up of a 3 million metric tonnes/year naphtha cracker at Indian Oil's Panipat refinery, in the northern state of Haryana. Nonetheless, naphtha demand is set to fall further, although the pace of decline will probably slow down as the scope for further substitution gradually diminishes. The shift from naphtha to natural gas in the power sector, which began in April 2009, is now probably close to completion, while gas production from the KG basin is approaching production capacity (although LNG imports will admittedly help meet demand).

Gasoil demand, meanwhile, was underpinned by the agricultural sector amid high temperatures (boosting water irrigation with gasoil generators), industrial activity (output rose by 17.6% year-on-year, the strongest since last December) and by ever-rising commercial vehicle sales (+57%). Similarly, gasoline consumption continued to be driven by buoyant passenger vehicle sales (+30%). Both fuels, though, may have also been boosted by anticipatory purchases ahead of forthcoming end-user price hikes.

Indeed, on 25 June, the Indian government, through its Empowered Group of Ministers, finally decided to tackle the issue of fuel price controls, almost three weeks after the last - and inconclusive - attempt. As anticipated in last month's report, the changes were partial, reflecting a compromise between the status quo and full liberalisation. Only gasoline was fully liberalised, both at the refinery gate and at retail outlets, entailing an 8% rise. Prices for gasoil, LPG and kerosene, meanwhile, were hiked (+5%, +11% and +32%, respectively), but remain under government control. Subsidies for LPG and kerosene will be maintained at least until early 2014. Gasoil prices, by contrast, will be eventually freed up, a move that would arguably have a much greater impact (gasoil consumption is four times as large as gasoline demand). Some industry observers argue that gasoil deregulation will happen over the next few months, but disruptive demonstrations in several cities, spearheaded by political parties opposed to the ruling coalition, could prompt the government to delay it further.

The political effects of rising inflation - which is already hovering at around 10% - arguably concern the government, yet a short-term spike is probably unavoidable. However, India's central bank may opt to lift interest rates in order to cool down the economy or the government may seek to moderate price hikes, notably of gasoil, through taxes or other means if they reach a yet-to-be-specified threshold - but this would effectively mean re-imposing price controls. Looking ahead, the move towards partial deregulation - if maintained - could bring significant macroeconomic benefits. Both the country's fiscal deficit and the state-owned companies' financial burden should diminish, albeit gradually. Moreover, private players would likely expand their retail operations, thus encouraging competition.

In terms of demand, these price changes are unlikely to have a significant impact in the short term, as Indian oil demand growth has been related largely to rising incomes - and as such is highly price inelastic. However, in the longer term, demand will arguably become more sensitive to crude oil price rises, setting the stage for efficiency gains and more rational energy use. Looking ahead, total oil demand is expected to rise by 2.0% year-on-year to 3.3 mb/d in 2010. Although economic growth is expected to slow down slightly to 8.4% year-on-year, oil demand growth should accelerate slightly to 3.2% in 2011 (with demand reaching 3.4 mb/d), as naphtha and residual fuel oil decline at a somewhat lower pace.

Elsewhere in Asia, Thailand registered two consecutive spikes in residual fuel oil demand in both March and April (+22.2% and +7.8% year-on-year, respectively). This was reportedly due to lower natural gas imports from neighbouring Myanmar, which is diverting the fuel to meet its own domestic needs. Facing peak power demand - March and April are usually the hottest months of the year - Thailand was thus forced to use more fuel oil. As such, Thai fuel oil demand in 2010 is likely to be virtually unchanged from the previous year, stalling the steady decline observed since 2006 (currently, about a third of the country's electricity generation depends upon natural gas). Yet Thailand's oil demand is primarily driven by LPG and gasoil, which account for almost 60% of the total. Demand for both fuels is expected to remain strong, underpinning total oil use, which should reach 990 kb/d in 2011 (+2.5% over 2010), commensurate with GDP growth (+5.5%).

Recent demand readings in Latin America strengthened as regional economic output improved. Still, concerns of overheating in some countries combined with a worsening outlook in others point to slower regional oil demand growth ahead (+3.4% in 2011 versus 4.0% in 2010). In Brazil, total oil demand grew by 8.7% year-on-year in May, led by surging demand for gasoil (+14.7%), jet fuel/kerosene (+16.0%) and gasoline (+9.6%). The country's economy grew by a stronger-than-expected 9.0% in 1Q10, while unemployment fell to historically low levels (7.3% in April). However, worries over overheating and inflation have led the central bank to tighten interest rates twice thus far this year. In 2011, with GDP growth moderating to 4.1%, total oil product demand is projected to grow by 3.9% to 2.8 mb/d, led by middle distillates and gasoline.

Chile has also started to rein in economic growth. The central bank raised interest rates in the wake of surging economic activity following February's destructive earthquake. Although Chile's JODI submissions run only through March, showing a yearly 1Q10 decline in total oil product demand, March readings were abnormally low due to the earthquake. This results in expectations of an overall fall in 2010 (-1.5%), but demand should rebound in 2011 by 3.1% to almost 350 kb/d. Growth should be led by transportation fuels, with gasoil, jet fuel/kerosene and gasoline all posting strong gains (+6.4%, +3.2% and +2.9%, respectively).

Argentina posted strong economic and industrial indicators in 1Q10, with GDP growing by 6.8%. Still, there are concerns that such readings overstate activity and rely on unsustainable public spending in the face of lacklustre private investment. Moreover, the official inflation rate may understate true inflation by over 10 percentage points. Still, oil demand readings for May were strong, with 11.0% year-on-year growth. While oil demand should rise strongly in 2010 (+7.0%) to 680 kb/d, the pace should moderate in 2011, at 3.9% on the back of more moderate GDP growth. The transportation and petrochemicals sector will drive growth, with gasoil, gasoline, jet fuel/kerosene and LPG all rising (+5.8%, +4.6%, +3.2% and +3.8%, respectively).

Meanwhile, Venezuela's economy has deteriorated, with the country re-entering recession in 1Q10, dragged down by an electricity crisis and price/currency controls that have sharply eroded private investment. A downward revision to baseline oil product demand, based on 2008 annual submissions, has resulted in a slightly lower forecast for 2010 (720 kb/d, 15 kb/d lower than previously estimated). The country's JODI submissions have been erratic, complicating efforts to gauge the monthly demand picture. With marginal GDP growth - but highly subsidised end-user prices and increasing use of oil for power generation - total demand should rise to 730 kb/d in 2011. However, the downside risk to this prognosis is considerable given the precarious state of the economy.



  • Global oil supply fell by 255 kb/d to 86.1 mb/d in June, on both lower non-OPEC and OPEC crude output. Year-on-year, global supply is up by 1.8 mb/d on higher non-OPEC (1.0 mb/d), OPEC NGLs (0.6 mb/d) and OPEC crude (0.2 mb/d).
  • Non-OPEC supply estimates for 2008-2010 are revised up by 0.1 mb/d, largely due to the inclusion of new historical data for non-OECD, but also on stronger US NGL and Canadian bitumen production reported for April. This was partly offset by lower near-term production in the OECD Europe and Pacific. 2009 non-OPEC supply is estimated at 51.6 mb/d, rising to 52.4 mb/d in 2010.
  • 2011 non-OPEC supply is forecast to grow to 52.8 mb/d, with increments from Brazil, global biofuels, Azerbaijan, Colombia, Ghana and Oman partly offset by further decline in Mexico and the North Sea. This continues the resurgence in growth seen in 2009-2010, following weaker (and hurricane-affected) 2005-2008 levels. The US Gulf of Mexico is also forecast to grow in 2011, albeit less than previously forecast, as delays due to the uncertainty surrounding drilling permits begin to register.
  • Crude oil supply from OPEC averaged 28.9 mb/d in June, down by 65 kb/d compared with the previous month. Output by OPEC-11, which excludes Iraq, was up by 40 kb/d to 26.6 mb/d, with compliance with targets estimated at 59%. The 'call on OPEC crude and stock change' for 2010 has been revised up by 100 kb/d, to 28.8 mb/d. It averages 29.2 mb/d in 3Q10 and 29.2 mb/d for 2011.
  • OPEC crude capacity is set to decline to 35.4 mb/d in 2011 from a 2010 level of 35.6 mb/d, largely due to lower volumes from Iran and Venezuela. OPEC condensate and natural gas liquids (NGL) production is projected to increase by 600 kb/d on average in 2011, to 5.8 mb/d, after a similar rise in 2010. Estimates are slightly lower than those in MTOGM 2010 based on slower project start-ups primarily in Iran and Saudi Arabia.

Note: Random events present downside risk to the non-OPEC production forecast contained in this report. These events can include accidents, unplanned or unannounced maintenance, technical problems, labour strikes, political unrest, guerrilla activity, wars and weather-related supply losses. Specific allowance has been made in the forecast for scheduled maintenance in all regions and for typical seasonal supply outages (including hurricane-related stoppages) in North America. In addition, from July 2007, a nationally allocated (but not field-specific) reliability adjustment has also been applied for the non-OPEC forecast to reflect a historical tendency for unexpected events to reduce actual supply compared with the initial forecast. This totals ?410 kb/d for non-OPEC as a whole, with downward adjustments focused in the OECD.

All world oil supply figures for June discussed in this report are IEA estimates. Estimates for OPEC countries, Alaska, Indonesia and Russia are supported by preliminary June supply data.

This month the non-OPEC supply overview and OPEC NGL section focuses on the roll out of our forecast to 2011, with discussion of key changes in production. However, to avoid duplication, several of the themes underpinning this analysis are elaborated upon in the MTOGM 2010, released on 23 June 2010. Readers should consult the MTOGM for more detailed discussion of factors affecting supply in 2011 and beyond.

OPEC Crude Oil Supply

OPEC crude oil supply was down marginally in June, with lower Iraqi output partially offset by increased output by Saudi Arabia and Nigeria. Total OPEC output in June declined by 65 kb/d to 28.9 mb/d. Production by OPEC-11, which excludes Iraq, rose by 40 kb/d, to 26.6 mb/d in June, with the group pumping 1.74 mb/d above the 24.845 mb/d collective target. Relative to targeted production cuts, compliance rates were unchanged at 59% in June.

The 'call on OPEC crude and stock change' for 2010 has been raised 100 kb/d, to 28.8 mb/d due to a downward revision in OPEC NGLs, although the 'call' reaches a 2010 high point of 29.2 mb/d this quarter. For 2011, the 'call' is projected to average a higher 29.2 mb/d, up 400 kb/d over the 2010 average.

Sabotage and operational problems combined to reduce Iraqi supply in June by 105 kb/d, to 2.31 mb/d. Total exports fell to 1.78 mb/d last month versus 1.89 mb/d in May, with the decline split evenly between the northern and the southern regions of the country.

Exports of Kirkuk crude from the northern Turkish port of Ceyhan fell to 355 kb/d in June from 420 kb/d in May after sabotage and a bomb attack forced SOMO to curtail loadings. While most attacks on this pivotal pipeline are carried out by insurgents and smugglers, unusually in early July the latest bombing was claimed by separatist Kurdish rebels. The attack by the Kurdistan Workers Party (PKK) follows the end of a ceasefire agreement with Turkey, and has raised alarm bells that the pipeline could be vulnerable from 3Q10 and beyond.

In the south, Basrah exports were down 50 kb/d to 1.43 mb/d, in part due to lower output and in part due to weather disrupting loadings. State marketer SOMO cut allocations of Basrah Light by 10% to 30% to Asian term buyers in both June and July, reportedly due to production problems at the southern fields.

Saudi Arabia's production was estimated at 8.25 mb/d, up by 50 kb/d from a revised 8.20 mb/d for May. OPEC's largest producer pumped 200 kb/d above target, with compliance just over 90%, second only to the UAE at 95%.

UAE production fell by 20 kb/d to 2.29 mb/d in line with lower June contract allocations. Supplies are expected to rebound in July after state-run ADNOC eased curbs on contract allocations for Asian buyers. Supply allocations for Murban, the UAE's primary export crude, were reduced to just 3% below contract volumes in July versus a 12% discount in June. ADNOC tightened allocations again for August liftings.

Iranian crude oil production was assessed lower by 20 kb/d, at 3.7 mb/d in June. Some tanker trackers estimated Iranian crude and condensate held in floating storage declined by 4-6 mb last month but the volume of unsold barrels stored in tankers was still a considerable 44-46 mb at end-June. The build up of unsold barrels has largely been attributed to unattractive price formulas set by state-run National Iranian Oil Co. (NIOC), with many customers expecting the company to lower prices in order to move the barrels. But NIOC has in fact raised them for July.

Nigeria's June production rebounded by 40 kb/d, to 1.94 mb/d, as shut-in crude streams were brought back on line. The 100 kb/d EA offshore field operated by Royal Dutch Shell resumed production in the first week of June after a six-week closure, though the company said the force majeure remains in place. Forcados output is also slowly recovering as repairs are made to long-damaged infrastructure. Output of Qua Iboe also appears set to rise based on export allocations for the next several months. Operator ExxonMobil had earlier declared force majeure on 12 May.

Crude oil production in Angola was down by a further 10 kb/d, to 1.79 mb/d in June due to a combination of scheduled maintenance work as well as operational problems. Angolan production hit a record peak of 1.95 mb/d in February this year but has fallen each month since. July is likely to be even lower given planned two-week maintenance at the Greater Plutonio field.

Output of Nembe crude is still constrained following a fire at the Nemba South platform at the Cabinda Block 0 in early May. Field maintenance work on the Palanca field continued last month, affecting a net 25-30 kb/d in June. Greater Plutonio continues to operate below capacity at 170 kb/d due to problems with the water injection system. The complex of five fields, a joint venture between BP and China's Sinopec, has a nameplate capacity of 200 kb/d but only rarely reaches this level due to operating problems.

Venezuelan production in June declined by 20 kb/d, to 2.23 mb/d, due to lower Orinoco output. Maintenance work on the Petrocedeno heavy oil upgrader was behind the decline in Orinoco output to 460 kb/d in June versus 480 kb/d in May.

New Sanctions Target Iran's Energy Sector

Tighter sanctions were imposed on Iran in June by the United Nations, the European Union and the US, in response to its refusal to halt its nuclear fuel enrichment programme. While the fourth round of sanctions agreed at the UN is significant in that China and Russia, after months of debate, finally agreed to be signatories, in the end the resolution did not include specific measures targeting Iran's energy sector. However, in part to counter the weaker UN measures, the EU and US sanctions are considered much tougher and expected to have a material impact on the country's energy industry. In the near term, sanctions are expected to curtail much-needed imports of gasoline and other products. The new sanctions exclude crude oil sales.

Longer term, development of the country's oil and gas industry will clearly be adversely impacted. Iran's growing gas and natural gas liquids projects are expected to be hardest hit. The June MTOGM forecast Iran's production capacity of NGLs and condensates expanding from around 520 kb/d in 2009 to just over 1.0 mb/d by 2015. While most foreign partners have withdrawn from the gas projects on the drawing board, further constraints on procuring equipment and materials for active development projects now increase the downside risk to our forecast. Following are some details of the sanctions:

  • On 9 June, the UN Security Council passed a resolution that tightens the financial restrictions between Iranian banks and the international community. It also broadens the current arms embargo to include blacklist companies linked to Iran's powerful Islamic Revolutionary Guard Corps (IRGC). In addition, the UN resolution imposes stricter regulations on shipping entities, including a provision that allows third parties to inspect all ships coming from or going to Iran if there are suspicions that banned cargo is onboard. Equally, under the umbrella of new UN sanctions, Iran's traditional foreign business partners are expected to limit activity rather than risk being shut out of the US market. Authorities in the UAE, one of Iran's major trading partners, have already begun investigating businesses linked to Iran, including trading companies that supply gasoline and other refined products.
  • The EU proposed a sanctions regime on 17 June that could come into force by end July, specifically targeting Iran's transportation sector and the oil and gas industry. Proposed sanctions on the oil and gas sector will bar "new investment, technical assistance and transfers of technologies, equipment and services related to these areas, in particular related to refining, liquefaction and liquefied natural gas technology". Targets in the transport sector include shipping and air travel.
  • On 1 July, the US put in place the toughest sanctions yet, broadening the scope of existing sanctions on US companies to include stiff penalties against foreign firms supplying Iran with refined products, which have a market value exceeding $1 million or that during a 12-month period have an aggregate fair market value of $5 million or more. Foreign companies that sell refined products or invest in the country's oil and gas sector are to be barred from doing business with US companies and financial institutions, and risk having their assets in the US frozen. The new law also sanctions international banking institutions involved with Iran's Islamic Revolutionary Guard Corps, its nuclear enrichment programme or its support for terrorist activity. Earlier in June, the US Treasury Department singled out around 20 petroleum and petrochemical companies as being under Iranian government control—an action that puts them off limits to US businesses under a general trade embargo.

New US sanctions target companies that sell refined products all along the trading chain, including shipping, financing and insurance firms, and are likely to have an immediate impact. International oil companies and trading firms have been scaling back their business activities with Iran for months in anticipation of stiffer sanctions. Royal Dutch Shell, Petronas, Lukoil, Vitol, Trafigura, Reliance, and Glencore have halted gasoline exports to Iran. Total, which has reportedly been selling about 20-25 kb/d to Iran in recent months, has also said it has ceased sales. It is unclear whether some Chinese suppliers, including CNPC and Sinopec trading subsidiaries Chinaoil and Unipec, will continue to export refined products to Iran. In anticipation of sanctions, Iran has said it has built up stocks of gasoline imports but this is a short-term solution at best, especially given that the country imports around 100 - 130 kb/d of gasoline. Plans to start curtailing subsidies for gasoline in an effort to curb demand are expected to be enacted in late September.

Even without the new round of sanctions, interest in working with Iran in its oil sector has been tepid at best, given its notoriously poor contract terms and difficult operating environment. Italian ENI for example dropped out of the next phase of the Darkhovin oil field project. However, longer term, the new sanctions could severely limit the potential of the country's gas development plans. In response to the new sanctions, South Korea's GS Engineering & Construction South cancelled its massive $1.2 billion dollar contract for work on a critical gas sweetener project at South Pars Phases 6, 7 and 8. The contract delay will have a knock on effect to South Pars 9 &10 (see OPEC NGLs). Shell and Repsol also walked away from their problematic South Pars 13-14 development. In response to contract cancellations and the new sanctions, Iran announced in June that it awarded the final six phases of the massive South Pars gas development to domestic companies, especially the country's Islamic Revolutionary Guard Corps or companies affiliated to it.

OPEC Crude Capacity 2010-11

OPEC is on course to increase installed crude oil production capacity by a net 1.9 mb/d by 2015, but the outlook for 2011 is one of decline. OPEC sees strong growth in capacity in 2010 but decline sets in during 2011-2012 before posting a recovery starting in 2013.  Crude capacity additions from new projects for 2011 are eclipsed by natural declines at mature fields, especially in Iran and Venezuela. On an annual basis, total production capacity is estimated at 35.4 mb/d for 2011 versus 35.6 mb/d in 2010.

New OPEC production capacity coming on stream in 2011 period is minimal, with only Angola expected to post a significant increase with the start up of its 200 kb/d PAZFLOR project in Block 17. Capacity estimates are based on a combination of new project start-ups and assessed base load supply, net of mature field decline. The implied decline rates for the 2010-2015 period were slightly higher, at -3.9%, than last year's -3% forecast, partly reflecting a shift in OPEC's production slate to offshore production, where decline rates can range from 15-30%, compared with 1-3% at onshore fields.


OPEC condensate and natural gas liquids (NGL) production is forecast to increase by 610 kb/d on average in 2011, to 5.87 mb/d. That is a downward revision of 385 kb/d from our MTOGM 2010 estimate and is based on slower project start-ups primarily in Iran and Saudi Arabia. The 2010 forecast was lowered by a smaller 140 kb/d on average for the year, to 5.26 mb/d. The lower estimates for the current year largely reflect further delays in the start-up of Saudi Arabia's massive Khursaniyah natural gas liquids processing facilities, expected on line in early 2010 but now projected to come on sometime in 3Q10. Nameplate capacity is 210 kb/d of NGLs and 80 kb/d of condensate, but a slow ramp up is expected. Saudi Arabia's condensate and NGL production is estimated at 1.48 mb/d in 2010, rising to 1.56 mb/d in 2011, up about 80 kb/d year-on-year.

In Iran, NGL and condensate capacity estimates have been lowered by 200 kb/d for 2011 following repeated work delays on the Bid Boland gas processing plant and South Pars 9 & 10. Latest reports are that the Bid Boland facility is only around 10% complete and is not expected on line now until end-2013/2014 at the earliest. Previously, we had expected start-up in 2011. When completed, Bid Boland is slated to produce 120 kb/d of NGLs and 20 kb/d of condensate.

Iran's problematic South Pars 9 & 10 project is delayed yet again despite official forecasts that it will be fully operational in 2H10. Indeed, the facility's sweetening capacity is operational, but it is processing sour gas produced from South Pars 6-8. Gas production from South Pars 6-8 was earmarked for reinjection at the country's oldest field, Aghajari, but getting the gas to the northwest has been fraught with problems. The sour gas has reportedly led to corrosion of the pipeline due to inferior quality of pipeline materials used as a result of sanctions. Iran had awarded South Korea's GS Engineering & Construction South the contract for work on a critical gas sweetener project at South Pars Phases 6, 7 and 8 but the company withdrew from the project this month following the latest round of sanctions (see New Sanctions Target Iran's Energy Sector). Start-up of Pars 9 & 10, with capacity of 80 kb/d of condensate and 80 kb/d of NGLs, has now receded until sometime in 2011 and all indications are that this timeline could slip into 2012. Development of Iran's South Pars has been particularly hard hit by sanctions due to problems procuring needed equipment and materials. Overall, growth in Iran's natural gas liquids capacity will be a more modest 45 kb/d, from 560 kb/d to a little over 600 kb/d in 2011.

The 2011 Outlook for Non-OPEC Supply


Following estimated non-OPEC supply growth of 0.7 mb/d and 0.8 mb/d in 2009 and 2010 respectively - the strongest increments since 2003/04 - 2011 output is forecast to rise by a more modest 0.4 mb/d. This implies growth from 52.4 mb/d in 2010 to 52.8 mb/d in 2011. As reviewed extensively in our recent MTOGM, relatively high oil prices in a stable range of $65-85/bbl over the past year and lower upstream development costs have prompted companies to boost upstream investment again. Indeed, recent surveys confirm a rise in 2010 upstream investment in the 8-12% range and possibly even higher in 2011. Observed baseload decline has also been slowed.

Growth in non-OPEC supply remains concentrated in a handful of long-standing investment bright spots - notably Brazil, Azerbaijan, Colombia, Oman, and to a lesser extent, Canada. 2011 will also see the start-up of production at the large Jubilee field offshore Ghana and continued growth in what remains a key source of growth for non-OPEC liquids - biofuels. Our forecast also estimates an incremental 55 kb/d of crude oil from the US Gulf of Mexico, despite evidence of slowing growth there as the uncertainty surrounding the deepwater drilling moratorium begins to have an impact on new upstream projects. The first named storm of the season, Hurricane Alex, caused no damage to oil infrastructure, but still forced the brief precautionary shut-in of 25% and 15% respectively of regional crude oil and natural gas production from the end of June until early July. We carry forward our usual five-year average hurricane adjustment, but note that 2010 is forecast to be the stormiest hurricane season since 2005, when Katrina and Rita hit the Gulf coast with devastating effect.

Compared to last month's report, 2009 and 2010 non-OPEC supply numbers are little changed, with revisions mostly related to consolidated data through 2008 for key non-OECD countries, including Argentina, Bahrain, Brunei, China, Egypt, India, Indonesia, Malaysia, Pakistan, Turkmenistan, Ukraine, Uzbekistan and Yemen. The two most sizeable adjustments were to China (average +80 kb/d for 2008-2010) and Egypt (+65 kb/d).

As discussed in the recent MTOGM, a key feature of forecast non-OPEC growth is the net decline expected for conventional crude overall (-110 kb/d), offset by increases in other sources of supply, including global biofuels (+210 kb/d), other non-conventional production (+150 kb/d), NGLs (+75 kb/d) and refinery processing gains (+30 kb/d). In sum, and as is apparent from the graph below, the expected seasonal pattern of non-OPEC supply in 2011 is similar to 2010. Risks to the downside or upside from this profile will depend upon whether hurricane and other outages more closely resemble those of 2008 or 2009 respectively.

Change to Biofuels Reporting

Henceforward US, Brazil and related oil subtotals no longer include fuel ethanol production. This affects around 0.7 mb/d of US output and 0.4 mb/d for Brazil, based on 2009 production levels. A new global biofuels line is included in all tabulated non-OPEC supply data.


Total OECD production is forecast to decline by 350 kb/d in 2011, with a small dip in North America and stronger decline in Europe only partly offset by a small increment in the Pacific, where Australian crude output is set to grow. Oil production in North America is expected to decline by 100 kb/d, with growth in Canada offset by steep decline in Mexico, while US output holds flat.

In the US, compared to modest growth of 50 kb/d estimated in 2010, total supply is set to decline slightly in 2011. For 2010 and 2011, we retain our hurricane adjustment, based on five-year average shut-in volumes, which amount to -210 kb/d and -240 kb/d for 3Q10 and 4Q10 respectively. Precautionary shut-ins due to the recently-passed Hurricane Alex, which briefly reached as much as 420 kb/d of crude (or around 25% of regional production) curbed June output by 27 kb/d, though fields were brought back onstream rapidly. For now, the short-term impact resulting from the Macondo spill in the US Gulf is limited to around 30 kb/d worth of project delays in both 2010 and 2011. As noted in earlier analysis however, extended project delays, if they occur, could reduce regional supply by 100-300 kb/d by 2015 compared to our existing outlook.

US Gulf of Mexico: Project Delays Already Curbing Output

We estimate that delays to new projects resulting from the Macondo oil spill have already shaved 30 kb/d off both 2010 and 2011 US crude production. Until more clarity prevails over new regulatory and operating procedures and whether the deepwater drilling moratorium will stay in place, we refrain from including a broader downward adjustment to our US production forecast. But extended project delays, if they occur, could reduce our 2015 projection for US Gulf production by 100-300 kb/d.

The BP-led team has not yet managed to plug the Macondo well, which has been leaking since a well blowout led to the sinking of the Deepwater Horizon drilling rig in late April. Currently, an estimated 35-60 kb/d of crude oil continue to flow from the wellhead (in mid-June, the figure was substantially raised from a previous estimate of 20-40 kb/d). Of this, an average 25 kb/d have been siphoned off by means of two containment systems. In turn, around one-third of this has been flared (with associated gas), while the other two-thirds have been collected, cleaned and sent ashore. Large-scale efforts are ongoing to skim, burn and disperse the oil leaking into surrounding waters, with several thousand vessels and several tens of thousands of personnel involved in clean-up operations. We estimate that something in the range of 2.3-4.5 mb of crude oil have been spilled in total, excluding the volumes contained, making this the largest oil spill in US history.

At the time of writing, BP was in the process of installing further containment systems, which should bring its capacity to siphon off oil to 80 kb/d (current capacity is around 28 kb/d) and thus in theory enough to catch all the leaking oil. Installation has required the uncoupling of existing containment systems, thus causing more oil to escape freely while installation takes place. Meanwhile, the drilling of two relief wells nearby continues. The first is reportedly very close to the existing problem well, but may take until mid-August to intercept the leaking well bore. If this is successful, heavy drilling mud can be pumped in, staunching the pressure in the well, after which it can be capped, if all goes well. An additional backup plan is to connect the Macondo well to nearby platforms by pipeline, allowing a more permanent (and more hurricane-proof) means of capturing the leaking oil.

Onshore, the debate over how to deal with the challenges posed by deepwater offshore drilling continues. On 22 June, a district court judge lifted the partial deepwater drilling moratorium put in place in late May, deeming it to be too broad a measure aimed at preventing oil spills, while discriminating against companies with untainted safety records and harming the regional economy. On 8 July an appeals court backed this decision, but the Obama administration may formulate a narrower, more targeted moratorium.

In practice, new deepwater drilling remains halted, though shallow-water, workover, well completion, waterfloods and some other drilling activities on existing, as opposed to new fields, continue. In Congress, a raft of proposed legislation is making its way through committees. Key proposals include new safety measures, stricter requirements on companies active in deepwater drilling, much-enhanced liability for companies and a possible ban on drilling within 75 miles of the coastline. Elsewhere, while other countries with offshore production continue to review their own procedures and regulations, most appear to consider systems in place to be sufficient, but are waiting for the outcome of the Macondo investigation. EU Energy Commissioner Oettinger recently called for an EU deepwater drilling moratorium, although this as yet shows no sign of being implemented. Moreover, it is worth noting that North Sea regulatory and operating procedures were dramatically tightened after the 1988 Piper Alpha disaster.

Canada is forecast to see output growth of nearly 100 kb/d to over 3.3 mb/d in 2011. Steadily rising output of both raw bitumen and mined, upgraded synthetic crude, will more than offset a decline in conventional crude from other areas, as well as lower NGL production. Sustained growth in oil sands-related output will ensure Canada remains one of the key sources of non-OPEC growth.

Oil production in Mexico is forecast to continue its steady decline, falling by 175 kb/d to 2.8 mb/d in 2011. Decline at its key Cantarell field has slowed over the past year, but remains near 22% year-on-year according to newest monthly data. Nonetheless, even further slowing in decline at Cantarell seems unlikely to completely halt a drop in national output, as other potential sources of growth are limited.

OECD Europe oil production is forecast to decline by 290 kb/d to just over 4 mb/d in 2011. Output, excepting biofuels, will fall across most countries. Oil production in the UK is set to drop by 135 kb/d to 1.3 mb/d in 2011, as decline at mature fields outstrips new production from development of the Alder, Auk, Bentley and Causeway fields, among others. The new UK government's declared ambition to maintain tax incentives to develop peripheral, difficult fields in the North Sea, was welcomed by industry.

Norway's oil production is expected to fall by 125 kb/d to 2.1 mb/d in 2011, with new output from the Morvin, Oselvar, Skarv and other developments only partly serving to stem decline. Norwegian production is currently lower than usual due to shut-ins at the Gullfaks complex and some related fields. In mid-May, operator Statoil was forced to halt production and evacuate the Gullfaks C platform due to a gas leak. It remains unclear when operations will resume. As much as 100 kb/d of capacity is potentially affected.

The OECD Pacific is forecast to see a small increment of 30 kb/d in oil production, rising to 710 kb/d in 2011. Growth is centred on Australia, as production at the newly-online Pyrenees and Van Gogh, and at the Angel, Puffin and Vincent fields increases. Australian oil production is forecast to rise by around 20 kb/d and 40 kb/d in 2010 and 2011 respectively, hitting 610 kb/d in 2011, before declining again thereafter.


In contrast to the overall decline in the OECD, oil production in non-OECD countries is forecast to increase by 465 kb/d to 30.3 mb/d in 2011, with Latin America and the FSU contributing virtually all of the incremental output. Brazil is expected to see the single largest increase, of around 210 kb/d, followed by Azerbaijan, Colombia, Ghana and Oman.

Oil production in the FSU is forecast to increase by 200 kb/d to 13.8 mb/d in 2011, largely driven by Azerbaijan, but with smaller increments in Russia and Kazakhstan. In Azerbaijan, growth at the key Azeri-Chirag-Guneshli (ACG) complex in the Caspian Sea is expected to pick up again in 2011, boosting the country's output by 135 kb/d to 1.2 mb/d. ACG (and therefore total Azeri) production is then expected to stay relatively flat through 2015. Kazakhstan is forecast to see oil production rise by 35 kb/d in 2011, to 1.7 mb/d, with small increments at the Tengiz and Karachaganak fields partly offset by decline elsewhere. Kazakhstan will have to wait until 2014/15 for another surge in growth, when the super-giant Kashagan field is due to see first output.

Russia's total oil production is forecast to increase by 40 kb/d in 2011, to just below 10.5 mb/d. This follows two bumper years in 2009 and 2010, when output at key new fields, including Vankor, YK, Verkhnechonsk and the Uvat cluster boosted production, helped by an exemption to crude export duties. New greenfield output will begin to slow, and is expected to be more than offset by decline at mature assets. Moreover, the government recently announced plans to phase out the tax exemptions, prompting some companies to warn this could put new developments at risk (see FSU: Taxing Times Ahead).

FSU: Taxing Times Ahead

Following months of conflicting reports, the Russian government recently announced the introduction from 1 July of an export tariff on previously exempt East Siberian output exported through the ESPO pipeline. This had previously been a source of tension between the ministries of Energy and Finance (see Further Uncertainty Over Eastern Siberian Tax Breaks in OMR dated 11 February 2010) where the Ministry of Energy argued that introducing the full Russian export tax would curtail production. Therefore, it appears that a compromise was reached, since the new tax will be set at 45% of the price in excess of $50/bbl (in July this amounts to $9.50/bbl or 30% of the equivalent regular Russian export duty).

The tariff introduction was not unexpected given the success of the new grade since its launch in late 2009, as volumes have sold on the spot market with relative ease, and the Kozmino terminal is now shipping at its maximum 330 kb/d capacity. The blend has found favour with Pacific Basin refiners, notably in Japan, South Korea and the US West Coast, with a quality similar to Abu Dhabi's Murban but generally priced at a discount to benchmark Dubai. Looking forward, the 300 kb/d Chinese spur of the pipeline from Skovorodino to Daqing is expected to start flowing in 1Q11 with a contracted 300 kb/d to be supplied to CNPC by Rosneft. The ESPO-2 leg from Skovorodino to Kozmino, now scheduled for completion in 2012, one year ahead of the original target, will increase Kozmino ESPO export capacity to 1.3 mb/d.

Despite the likelihood that part of the new tax will be passed on to buyers, therefore narrowing the discount to Dubai, it is not expected to initially deter purchasers, with 3Q10 loadings seen steady and the number of market participants buying the crude rising. Longer term, reports suggest that with the gradual phasing in of the full Russian tax level on East Siberian fields, and with most volumes sold on the spot market, it will likely be up to producers to absorb cost increases to assure that the grade stays competitive.

Separately, Russian pipeline operator Transneft recently announced plans for a 3.5% hike in tariffs to finance the purchase and installation of new fault diagnostic equipment for its network. Outside of Russia, Kazakhstan announced in June that in response to the stable and relatively high crude oil price it was re-introducing a $20/mt tariff on crude exports. This is significant, since the Kazakh government is likely to increase this tax further in line with oil prices as it did in the past. This will likely become an important revenue stream for the administration as exports rise following the ramp up of production from the Tengiz and Kashagan fields over the medium and longer term. As with ESPO, this development is not anticipated to have an immediate impact on exports, but risks undermining the competitiveness of Kazakh grades if producers cannot absorb the rise.

Total non-OPEC Asia including China is forecast to see production decline by 80 kb/d to 7.6 mb/d in 2011, with a drop in Chinese output exceeding limited increases elsewhere. China saw the largest baseline data adjustment (+110 kb/d), following the inclusion of some previously-undercounted output from smaller producers, according to the National Bureau of Statistics (NBS). We partly carry the upward adjustment forward into 2009 and 2010. Chinese crude oil production is now forecast to increase by 135 kb/d in 2010, falling by 90 kb/d in 2011, to average 4.0 mb/d and 3.9 mb/d respectively.

Changes elsewhere in Asia in 2010 and 2011 are more limited. India is forecast to increase production by 75 kb/d in 2010 and 35 kb/d in 2011 as output at the new Mangala/Aishwariya/Bhagyama complex onshore Rajasthan ramps up. Indian 2011 production is forecast to average 900 kb/d. Vietnam's oil output is expected to grow by 15 kb/d and 12 kb/d in 2010 and 2011 respectively, to average 360 kb/d in 2011. In contrast, oil production in Malaysia is forecast to decline by 33 kb/d and 35 kb/d respectively in 2010 and 2011, averaging 670 kb/d next year.

Total oil supply in Latin America is projected to rise by 300 kb/d in 2011, to 4.4 mb/d, with growth in Brazil and Colombia only marginally offset by declining production elsewhere, notably Argentina. In Brazil, strong growth in offshore production, including first large volumes from the pre-salt, drives an increase of 210 kb/d in 2011, following an increment of 150 kb/d in 2010. State-controlled Petrobras recently released its finalised 5-year investment plan, which boosts spending to a total of $224 billion in 2010-2014, much of it to develop an estimated 50+ billion barrels of pre-salt reserves. In 2011, total Brazilian oil production (excluding fuel ethanol) will average 2.4 mb/d. Colombia is also forecast to experience strong growth of 115 kb/d in 2010 and 2011, to average 900 kb/d next year. Much of this incremental output is envisaged to come from rising output at the Rubiales, Castilla and other heavy oil fields.

Non-OPEC Middle East is forecast to see supply growth of only 20 kb/d in 2011, rising to 1.7 mb/d. Incremental production in Oman (+60 kb/d in 2010, +55 kb/d in 2011) will see the country's output average 930 kb/d in 2011. This is partly offset by declining output in Syria, Yemen and Bahrain, which see production dip to 350 kb/d, 265 kb/d and 185 kb/d respectively in 2011.

Africa's total oil production is adjusted up by an average 55 kb/d for 2008-2011 on higher historical data for Egypt. Following a marginal dip in 2010, regional production is forecast to rise by 30 kb/d in 2011 to average 2.6 mb/d. Despite a 65 kb/d higher baseline for Egypt, production here is nonetheless projected to decline marginally in 2010 and 2011, averaging 730 kb/d in 2011. Ghana will see oil production rise by a steep 85 kb/d to 90 kb/d in 2011 due to first output from the large offshore Jubilee field, expected to start production towards the end of 2010. Output in both Equatorial Guinea and Sudan is expected to decline by a combined 40 kb/d, averaging 250 kb/d and 450 kb/d respectively in 2011.

Biofuels - Matching Brazilian Crude as a Key Source of Supply Growth

After expected annual growth of 255 kb/d in 2010, global biofuels production should increase by a further 210 kb/d in 2011. Almost 30% of 2011 growth comes from Brazilian ethanol, over 20% from US ethanol, while OECD Europe biofuels account for 15%.

In the US, newly commenced weekly reporting suggests ethanol production over 840 kb/d in June. Recently, corn prices have risen sharply while ethanol demand and prices have remained constrained by an increasingly saturated domestic market. A potentially supportive US Environmental Protection Agency decision to allow a 15% ethanol blend in conventional autos has been delayed until autumn. US export opportunities may increase above the 30 kb/d level achieved in April, particularly if Brazilian supplies remain more geared towards their own domestic market. We see US ethanol production averaging 895 kb/d in 2011, up from 850 kb/d in 2010, driven by capacity additions over the next 18 months. Still, with the margin outlook less optimistic than in 1H10, risks to overall production lie to the downside.

In Brazil, robust gasoline demand growth (+5.7% year-on-year), an improved industry operating position and capacity expansions should help ethanol production to grow to 560 kb/d in 2011, after reaching 500 kb/d in 2010. With the introduction of higher domestic blends in 2010, biodiesel in Argentina and Brazil should also grow, with combined production at 65 kb/d in 2010 and 80 kb/d in 2011. Meanwhile, in OECD Europe, several large ethanol capacity additions in the Netherlands and the UK as well as Neste's biomass-to-liquids plant in Rotterdam should help total biofuels output to grow, from 225 kb/d in 2010 to almost 260 kb/d in 2011.

OECD Stocks


  • OECD industry stocks rose for a second consecutive month across all regions by a combined 35.0 mb, reaching 2 757 mb in May. However, unlike last month, the increase was in line with the five-year average build of 39.7 mb. Product stocks rose by a sharp 17.4 mb, led by seasonal middle distillate restocking, while crude oil inventories built by 5.4 mb and other oils added a further 12.3 mb.
  • Forward demand cover stood at 61.0 days in May, up from 60.3 days at end-April, and reached the previous year's level near the top of the five-year range.
  • Preliminary June data indicate total OECD industry stocks rose by 3.5 mb, in contrast to the usual five-year average draw of 8.7 mb. Crude levels fell by 1.7 mb, while products gained 5.2 mb, as a build in the US outpaced declines in Japan and Europe.
  • Short-term oil floating storage fell to 115 mb at end-June, from 127 mb in May. Large draws in Northwest Europe and the US Gulf Coast were behind the decline, partly offset by a product build off West Africa.

OECD Inventory Position at End-May and Revisions to Preliminary Data

In May, OECD inventories rose for a second consecutive month, by 35.0 mb to 2 757 mb, slightly less than the five-year average build of 39.7 mb. Crude oil stocks grew in line with seasonal norms and posted a small increase even in the US, where stocks usually draw in May. This follows an atypically large gain of 33.5 mb in April, which doubled the surplus to the five-year average to above 55 mb. The stock build was amplified by an upward revision to April crude oil holdings (+12.6 mb), mainly in Europe.

Meanwhile, seasonal post-winter stock building of middle distillates, residual fuel oil and other products, especially in Europe and the Pacific, led the increase on the product side in May. However, the level of restocking may be overstated in May, given that over the past three months middle distillates have been revised down by 10.9 mb on average. A downward April revision of 14.4 mb resulted in a monthly draw of 6.1 mb, reversing the previously reported 9.3 mb gain in that month.

Total OECD product holdings grew by 17.4 mb in May, less than the average seasonal build of 29.2 mb, as stronger gasoline draws with the onset of US driving season provided some offset. In terms of forward demand cover, gasoline stocks stood comfortably at the top of the five-year range at 25.0 days, suggesting an ample pre-summer buffer. Yet, gasoline levels have also been revised lower in the past four months, while April's revised assessment (-10.4 mb) implied a sharper stockdraw than reported last month.

Preliminary June data point to a further 3.5 mb build in OECD inventories, contrasting with the five-year average draw of 8.7 mb. In Japan, where the seasonal build is usually driven by crude, inventories fell by 2.5 mb due to a product draw offsetting a crude gain. Meanwhile in the US, product builds, mainly concentrated in middle distillates, drove the 10.8 mb gain in stocks. In Europe, industry stocks fell by 4.8 mb in June, less than the five-year average draw of 18.3 mb, on draws in both crude and products.

Crude oil held in floating storage decreased to 85 mb in June from 93 mb in May, following offloading in the US Gulf, Northwest Europe and Asia-Pacific. An offsetting increase came from Africa, where two VLCCs reportedly stored crude near Durban. Reports indicated that several tankers holding Iranian crude were moved or discharged but, according to available tanker data, the levels stored in the Middle East Gulf remained virtually unchanged, at around 50 mb at end-June. Meanwhile, product floating storage declined by 4 mb, to 30 mb, on a draw in products held off Northwest Europe. A build off West Africa partly cushioned the fall.

Analysis of Recent OECD Industry Stock Changes

OECD North America

Industry stocks in North America rose by 6.6 mb to 1 342 mb in May, driven by an increase in US other oils, including NGLs and feedstocks. Crude oil inventories stood only 0.5 mb higher, as a build in the US outpaced a draw in Mexico stemming from increased crude exports after five years of decline. Regional product stocks contracted by 3.5 mb and thus narrowed the difference to the average level from 35.2 mb in April to 12.8 mb in May. Gasoline inventories fell by 5.5 mb and dropped below 2005 highs. However, in terms of forward demand cover, gasoline stood above the range at 22.6 days at the onset of the US driving season. Fuel oil drew by 1.3 mb following a strong build in the US during the previous month, while regional builds in middle distillate and other product stocks provided some offset to the overall product draw.

US weekly data point to a fourth consecutive monthly increase in industry stocks in June, this time by +10.8 mb, with more than half coming from middle distillates. Further support came from propane, jet kerosene and other oils, while offsetting draws occurred in crude oil and fuel oil. Crude inventories fell by 3.3 mb to 359 mb, with Cushing stocks falling from 37.6 mb to 35.8 mb at end-June.

OECD Europe

Commercial oil inventories in Europe rose by 12.9 mb to 1 002 mb in May, as both crude and products built by 5.2 mb and 9.9 mb, respectively. The increase in crude oil resulted from higher Norwegian stocks at end-May, most probably held in loading terminals ready for export. The sharpest offsetting draws occurred in the Netherlands and Italy, shedding 3.0 mb and 1.5 mb, respectively. French crude oil stocks fell by 0.7 mb to 29.8 mb, albeit from a lower base, as March and April levels were revised down by 2.5 mb on average.

On the product side, the builds stemmed from seasonal post-winter restocking of middle distillates and fuel oil (+7.6 mb and +1.7 mb, respectively), evident also in the increase of German consumer heating oil stocks from 49% to 50% of capacity in May. Both middle distillates and gasoline stood at around 40.5 days of forward demand cover. In absolute terms, middle distillates hovered at the top of the range, extending their surplus to 27.1 mb. Conversely, gasoline inventories remained 6.4 mb below average levels, close to the bottom of the five-year range, despite edging higher by 0.2 mb on average.

Inventories held in Northwest European independent storage rose in June, largely supported by higher imports of fuel oil and jet kerosene. Gasoline stocks stood above prior month levels as restocking before the start of the driving season continued, but drew in the second half of the month as exports to the US picked up. European summer driving demand for diesel pushed gasoil inventories lower. Preliminary data from Euroilstock point to a 4.8 mb draw in EU-16 inventories, slightly less than a seasonal 18.3 mb decline. Crude inventories fell by 1.8 mb, while a drop in middle distillates led products lower by 3.0 mb

OECD Pacific

In May, OECD Pacific stocks increased seasonally by 15.6 mb to 412.2 mb, led by an 11.0 mb addition to products. More than half of the build came from middle distillate restocking (+6.0 mb), while gasoline and other products added a further 1.1 mb and 3.5 mb, respectively. Almost 5.0 mb came from a sharp build in NGLs and feedstocks. Meanwhile, crude oil inventories on average fell by 0.3 mb, but a seasonal increase in Japan partially balanced a larger, counter-seasonal draw in Korean inventories.

Weekly data from the Petroleum Association of Japan (PAJ) point to a 2.5 mb decline in Japanese industry inventories in June, largely driven by product draws. Gasoline stocks fell from 11-year highs back to 13.9 mb, in the upper part of the five-year range, while gasoil inventories shed 1.2 mb and kerosene fell by 0.5 mb. Crude oil stocks increased by 3.5 mb, while jet fuel inventories also rose after holding relatively stable levels during the past two months.

Recent Developments in China and Singapore Stocks

Chinese crude oil stocks fell by 1.8 mb in May, according to China Oil, Gas and Petrochemicals (China OGP). The second successive monthly draw occurred amid high refinery runs and a dip in imports. Oil product inventories increased by 0.7 mb on builds in gasoline and kerosene. Gasoil inventories dropped slightly as domestic agricultural demand grew stronger.

Oil inventories in Singapore rose by 5.6 mb to 48.2 mb in June, according to weekly data from International Enterprise. Nearly 4 mb came from middle distillates amid steady imports from China and Korea. Fuel oil inventories added a further 1.0 mb and light distillates including motor gasoline rose, despite reportedly higher exports to Indonesia ahead of Ramadan.



  • Benchmark crude oil prices in June traded in a relatively narrow range of around $71-79/bbl compared with an unusually volatile May. The negative market sentiment that emerged in May continued to temper price moves to the upside in June. By early July both Atlantic basin benchmarks touched four-week lows before rebounding to $75.00-75.50/bbl by the 12th of the month. 
  • Global financial and equity markets continued to dominate sentiment in June, with traders and analysts acutely focused on macroeconomic data. The Eurozone crisis continued to fuel concerns that new austerity measures will lead to a double-dip recession. For much of June, China's macroeconomic data and statistics showing that the US recovery was losing steam also cast a bearish shadow.
  • US summer gasoline demand, while seasonally stronger, is showing only weak year-on-year growth of 0.4% in June. NYMEX gasoline crack spreads fell in June to around $12/bbl on average, after reaching a peak near $18/bbl in May. The tepid start to the season may yet surprise and follow last year's trajectory, when preliminary data were later revised up. In Europe, gasoline cracks came under pressure from weak regional demand and reduced export opportunities to the US and Middle East.
  • The VLCC Middle East Gulf - Japan freight market was characterised by boom and bust, as early month spot rates surged from $14/mt to peak above $20/mt on 22 June. The most likely driver was China, where increased tanker traffic resulted in severe congestion at Chinese ports, inflating prices by tying up vessels. However, rates slumped to under $13/mt by month-end on waning demand.

Market Overview

Following hard on the heels of one of the most turbulent months in the past year, June oil prices traded in a relatively narrow $8/bbl range compared with the $18/bbl range evident in May. WTI futures prices were up, on average, by $1.29/bbl to $75.40/bbl last month, while Brent prices were down on average by $1.34/bbl to $75.66/bbl. Spot prices for Middle East marker Dubai crude were down, on average, by $2.79/bbl in June to $73.99/bbl.

The negative market sentiment that emerged in May continued to temper price moves to the upside in June and July, with prices trading slightly below the January-June average of $78.35/bbl for both WTI and Brent.  By early July both Atlantic basin benchmarks touched four-week lows before rebounding to $75.00-75.50/bbl by the 12th of the month.

Global financial and equity markets continued in June to be the primary drivers of market sentiment, with traders and analysts acutely focused on macroeconomic data. For much of June, China's macroeconomic data and latest statistics showing that the US recovery was losing steam cast a bearish shadow. Prices came under pressure again at end June after the US Federal Reserve Bank opted to maintain interest rates near zero and cautioned that the US economic recovery was more sluggish than previous assessments.

Moreover, the Eurozone crisis continued to fuel concerns that new austerity measures will lead to a double-dip recession. The G-20 pushed for governments to reduce deficits at its end-June meeting in Toronto. The July release of the IMF's interim World Economic Outlook Update did little to allay concerns when it cautioned that Europe's economic woes are now the major threat to the global economic recovery. However, despite the IMF's sobering outlook for Europe, overall the fund raised its forecast for global GDP growth for 2010, to 4.5% versus its previous forecast of 4.1% (this report does not integrate the latest IMF partial update since it was released after our data freeze but the latest data do not materially change our views). Global oil demand is now expected to rise by 1.8 mb/d to 86.5 mb/d in 2010, but growth will ease in 2011 to 1.3 mb/d.

Futures Markets

The contango between the front month contract and forward markets narrowed in June as prompt prices recovered from exceptionally weak levels in May. The WTI M1-M12 also narrowed, to $6.10/bbl in June from around $8.50/bbl in May. By early July, the spread was running about $4.75/bbl.

Longer dated futures contracts are also indicating more bearish market sentiment. The M1-M78 spread in early July was just under $13/bbl compared with around $15/bbl in June and around $18/bbl spread in May. Oil for delivery in December 2013 has dropped from more than $95/bbl in early May to an average $88/bbl in June. Technical traders argued that a bear market took hold once the price structure crossed a critical threshold in late June, with the 50-day moving average price dropping below the 200-day moving average. These traders argue that such price moves indicate risks are skewed to the downside.

Trading activity on the NYMEX futures exchange was fairly muted in June given the narrow price range, with open interest in the NYMEX crude oil contract hitting the lowest level in July since the beginning of the year. That compares with record trading volumes posted in late April and early May, when prices surged above $18/bbl to over $86/bbl.

Open interest in NYMEX WTI futures fell by 8.5% to 1.26 million contracts in June, as oil prices rose on average by $1.30/bbl. After a heavy sell-off in May, money managers increased their net long holdings last month by 8 400 contracts on average. On the other hand, swap dealers offloaded some of their net longs accumulated since May, bringing their net long positions down by 13 100 contracts. Meanwhile producers and other reportables trimmed net short holdings slightly over the month.

In the gasoline futures market, money managers increased their net long positions by 18 400 lots, balanced by a 21 200 net shorts added by producers. However, after a sharp fall in May, RBOB Gasoline open interest slipped lower again to 226 500 contracts in June.

Unintended Consequences of New Market Regulation

Governments are moving apace with new regulations on financial markets, including energy derivatives. In June, the G-20 made headway in debating new regulations of over-the-counter (OTC) derivative markets, while the European Commission released a working draft for public comment on the issue. US regulators led the way in June with broad reforms of Wall Street, including proposed legislation that would require swaps and other over-the-counter (OTC) trades to move to regulated exchanges or clearing houses. US regulatory proposals on Wall Street reform prepared by the House of Representatives and the Senate were reconciled into a single rule and have already been approved by the lower chamber.

Proposed US legislation will set a number of new restrictions on the oil trading community. As it stands, the bill requires OTC trades be moved onto regulated exchanges or for trades to be processed by clearing houses. Exemptions will be made for end-users, refiners, producers and transport companies who hedge their commercial risk, such as exposure to market fluctuations. However, companies such as refiners, airlines and other commercial players may be required to post collateral for uncleared swaps and thus face substantially higher costs. The International Swaps and Derivatives Association (ISDA) calculates that as much as $400 billion could be tied up as collateral to cover derivatives exposure.

A new study commissioned by the OECD investigated the impact of index funds on the market and argues that changes to regulations could have unintended negative impacts. By way of example, the study reports that limiting participation of fund investors may unintentionally deprive futures markets of liquidity and risk absorption capacity (see 'The Impact of Index and swaps Funds on Commodity Futures Markets,' http://www.oecd.org/dataoecd/16/59/45534528.pdf).

The US bill also gives the US Commodities Futures Trading Commission (CFTC) the authority to impose position limits on both cleared and non-cleared trades. While the CFTC already considered position limits for WTI, heating oil, RBOB gasoline and natural gas futures contracts earlier this year, it is unclear whether a common line will emerge among the five CFTC commissioners.

Following in the CFTC's footsteps in soliciting public comment on proposed legislation, a working document of the Internal Markets Directorate-General of the European Commission has been made available for discussion and consultation until 10 July. The paper outlines how to implement some policy actions announced in October 2009, namely:

  • Mandatory clearing of all 'standardised' OTC derivatives;
  • Mandatory reporting of all OTC derivatives to trade repositories;
  • Common rules for Central Counterparties (CCPs) and trade repositories.

The EU's final regulatory proposal is scheduled to be published in September 2010. Other measures such as a revision to the Market in Financial Instruments Directive (MiFID) and the Market Abuse Directive (MAD) will follow later. Meanwhile, ten of Europe's largest industrial companies have warned that enactment of the EU's clearing threshold proposals risks sparking a new financial crisis. (For more information on global financial regulatory overhaul see 'Financial Market Regulation' in the June MTOGM 2010.)

Spot Crude Oil Prices

Spot crude oil prices were mixed in June, with US and North Sea benchmark crudes tighter relative to amply supplied Asian markets. US WTI posted a month-on-month gain of $1.67/bbl to $75.29/bbl, Dated Brent a decline of $0.31/bbl to $74.85/bbl and Dubai was off by a steeper $2.79/bbl to $73.99/bbl. 

The spot WTI price recovered in June from depressed May levels, in tandem with the drawdown in stocks at the pivotal Cushing storage depot. As a result, WTI regained its premium over Brent in June, to $0.44/bbl versus -$1.54/bbl in May, a swing of $1.98/bbl. By early July, the crudes were trading at near parity. Cushing stocks fell by 1.8 mb from record monthly levels of 37.6 mb at end-May. The Cushing stock drawdown helped narrow the WTI contango between M1-M2 in June to just under $1/bbl versus $3/bbl in May. In Europe, the Urals-Brent differential narrowed in June, with the discount averaging just $0.50/bbl compared with $1.50/bbl in May. Reduced exports of Russian Urals again in June coupled with several cargoes being diverted to other regions, shored up prices. The loss of some medium-sour Iraqi Kirkuk crude due to another attack on the Ceyhan pipeline also helped support Urals differentials.

North Sea premiums to Brent crude rose in anticipation of reduced supplies of both UK and Norwegian supplies in August. Scheduled maintenance is expected to cut Forties output by 150 kb/d next month while Norway's crude production is forecast to decline by 105 kb/d in August. In addition to planned maintenance affecting the Statfjord and Oseberg crude streams, as much as 100 kb/d of production from the Gullfaks platform remains shut-in since end-May due to a gas leak.

In Asia, spot prices for Middle East crudes fell sharply relative to other regions on ample supply, especially of Russian ESPO crude. Moscow's decision to impose an export tax on the new ESPO crude is not expected to dent Asian refiners' appetite. Indeed, competition among Middle East producers for Chinese market share is only expected to increase following the opening of the 300 kb/d ESPO spur to China early next year (see Non-OPEC Supply, 'FSU: Taxing Times Ahead').

Asian refiners also opted for regional crudes in June, given stronger Middle East VLCC freight rates and reduced buying interest for middle distillate-rich crudes. Asia-Pacific refiners instead have been buying heavy, sweet crudes favoured for power generation.

Underscoring the weakness for some Middle East grades, the price differential for Dubai minus Brent moved to a discount of $0.86/bbl in June versus a premium of $1.62/bbl in May. In addition, unsold Iranian crude and condensate in floating storage continued to weigh on markets. At end-June Iranian oil held offshore was estimated at around 45 mb, down from 50 mb at end May. However, while three Iranian VLCCs discharged cargo in June, the same tankers are now reportedly steaming back to reload more of the country's unsold crude.

Spot Product Prices

Spot prices for refined products were mostly lower in June, with gasoil in Europe the exception. Despite the onset of the peak summer driving season in the US, gasoline crack spreads were mostly lower in June, though differentials to Light Louisiana Sweet crude on the Gulf Coast posted a modest improvement. Preliminary data show June gasoline consumption year-on-year up a small 0.4%, leading some analysts to speculate that a strong gasoline season in the US may fail to materialise. NYMEX front-month RBOB cracks also fell in June to $12/bbl on average, after reaching a peak near $18/bbl in May, with heating oil cracks contra-seasonally trading at around parity with gasoline for several days in June.

In Europe, gasoline cracks were under pressure from weak regional demand and reduced export opportunities to the US and Middle East at end month. Increased refinery runs due to the end of maintenance work also added to unwanted supplies. In Asia, gasoline crack spreads were the exception, rising versus May levels.

Naphtha markets weakened in all major regions in June, largely due to planned cutbacks at petrochemical units.  In Singapore, naphtha crack spreads deteriorated from +$0.65/bbl in May to a loss of $1.57/bbl in June. Cracks came under pressure from increased flows from the Middle East as refiners there were offering an unusually high number of spot cargoes for July and August.  Higher imports from Europe and reduced demand from China were also weighing on cracks in Singapore.

Middle distillate crack spreads were mixed but mostly hovered around a robust $12/bbl. Diesel cracks in the US posted modest increases in June, buoyed by higher exports to Latin America. In Europe the picture was mixed, with Northwest Europe diesel cracks for Brent up a few cents on the month, to $13.56/bbl, while ULSD differentials to Urals were down almost $1/bbl in the Mediterranean.

European high-sulphur fuel oil markets were down by around $0.60-1.20/bbl in June on ample supplies, with differentials to Brent in Rotterdam at $9.13/bbl versus $8.25/bbl in May and cracks to Urals in the Med at $8.90/bbl compared with $7.62/bbl the previous month. By contrast, HSFO margins in Singapore were relatively flat over the month, though they started to improve in early July on stronger bunker demand.

Refining Margins

In June, benchmark refining margins fell in NW Europe and the Mediterranean, bar Brent hydroskimming, for which the crude price decline narrowly offset a lower net product worth. A sharper fall in naphtha and gasoline crack spreads than for fuel oil favoured simple configurations.  For the rest of the benchmark crudes, wider differentials for gasoil/diesel and jet fuel/kerosene were more than offset by lower crack spreads for other products.

In the USGC, margins were mixed. All light crude cracking margins improved, supported by stronger spreads across the product slate. Even though margins for heavier crudes processed in more complex refineries fell, depreciation more than offset by lower product prices, they continued to outperform lighter crude margins.

US West Coast margins were supported by stronger crack spreads for light products, particularly gasoline. Only the Kern cracking margin fell as a weaker fuel oil crack spread and this crude's high fuel oil yield offset light product gains. In Singapore, relative changes in feedstock values allowed Dubai margins to rise while Tapis margins fell.

End-User Product Prices in June

IEA regional end-user prices continued on a downward trend in June, decreasing by an average 4.9% in US dollars, ex-tax. On this basis, declines were reported for all products and across all surveyed countries, driven by the weakening crude oil price and strengthening US dollar. The influence of the latter factor was evidenced by the strong average fall on a US dollar basis in surveyed Eurozone countries (-5.2%) which was markedly weaker (-1.5%) when examining the monthly price changes in Euros.

Transport fuel retail prices declined again in June, with the US reporting the steepest falls in gasoline (-4.9%) and diesel (-4.5%) prices. In comparison, end-user prices in Eurozone countries declined on average by -0.9% and -0.5% in gasoline and diesel, respectively. Gasoline pump prices averaged $2.79/gallon in the US, ¥138/litre in Japan and £1.18/litre in the UK. Continental European prices ranged from €1.43 in Germany to €1.17 in Spain. Automotive diesel prices averaged $2.95/gallon in the US, ¥117/litre in Japan and £1.20/litre in the UK. Eurozone diesel prices ranged from €1.24/litre in Italy to €1.08/litre in Spain. Despite the decreases, gasoline and diesel forecourt prices were still on average 8% and 14% above year ago levels, respectively.


Dirty freight rates fell on all benchmark routes over the course of June. The VLCC Middle East Gulf - Japan route was characterised by boom and bust, as early-month spot rates surged from $14/mt on 1 June to peak above $20/mt on 22 June. Increased tanker traffic resulted in severe congestion at Chinese ports, inflating prices by tying up vessels for longer than expected. However, following waning demand, rates slumped to under $13/mt by month-end. Suezmax West Africa - US Atlantic Coast rates softened from approximately $16/mt to $12/mt over the month following subdued enquiries. In contrast, rates on the Aframax North Sea - NWE route remained relatively stable, falling by approximately $1/mt over the month.

Clean freight rates had mixed fortunes in June with Atlantic basin benchmark routes faring better than those in the Pacific. Prices firmed on the UK - US Atlantic Coast route following a seasonal increase in gasoline trade and a shortage of available vessels. East of Suez rates fell over the month as sluggish demand and ample tonnage weighed heavy on the market.

Floating storage of crude and products fell by 12.3 mb to stand at 115.1 mb at end-June, comprising falls of 8.2 mb of crude and 4.1 mb of products. The drop in crude was concentrated in the US Gulf (-7.2 mb) and NW Europe (-3.9 mb) with a likely seven VLCCs returning to the Atlantic Basin fleet, so that by end-month 37 VLCCs were storing crude and three storing product worldwide. Compared to a year ago, the storage fleet has shrunk by 38 vessels but now includes 11 more VLCCS, therefore underlining the trend of more oil being stored on the largest vessels.

Iranian crude continues to be stored at sea but the picture is becoming increasingly complicated, with mid-month reports surfacing of volumes, notably condensate, heading ashore. However, these tankers were re-deployed for storage in the Arabian Gulf by end-month with Middle East volumes only falling by 0.4 mb during June. Initial early-July reports also indicate that a net one vessel has been added to the VLCC fleet storing Iranian crude.

Lost in Translation: Improved Oil Demand Not Leading to Healthier Freight Rates

With the economic recovery continuing apace, global oil demand is now approaching levels last seen in early 2008, yet the tanker market is still subdued given oversupply. In early 2008, rates on the benchmark VLCC Middle East Gulf - Japan route stood at $47/mt and Suezmax West Africa - US Atlantic Coast reached $35/mt. Rates for each route now stand at $12/mt, representing falls of 74% and 66% respectively. The main driver behind this disparity is the increase in size of the tanker fleet. During the heady days of the 2007-08 tanker market boom, expectations of sustained high demand and inflated rates motivated many tanker operators to invest and expand their fleets. Tankers ordered during this period are now being delivered. 2009 was a record year with 31.3 mdwt delivered, but this will likely be eclipsed by deliveries of 35.8 mdwt and 37.5 mdwt in 2010 and 2011, respectively. Tanker Broker Simpson Spence and Young (SSY) estimates that the fleet expanded by a net 1.8% in 2008 but by 6.7% in 2009, with expansion maintained in the near-term despite the end-2010 phase out of single hulls, conversion to dry bulk and order slippage and cancellations. There is still localised market tightness but with such abundant tonnage, rate surges are unsustainable and have generally fallen away quickly.

Although the current picture looks gloomy for tanker owners, there are a number of factors which have supported rates above break-even levels: Firstly, demand from China and India surged, with both of these countries having sharply increased their refining capacity. As highlighted in the June 2010 MTOGM these are seen as the engines of import growth until 2015, causing many tanker operators to focus their attentions on East of Suez markets. Secondly, floating storage has remained at exceptionally high levels throughout the past two years, which has tied up tonnage on medium-term charters. If storage was to recede to the levels of 2008 it is conceivable that rates would crash, especially on VLCC routes. Nonetheless, the prospect of increased global oil demand in years to come has motivated bullish owners to again increase orders for new builds to take advantage if rates finally manage to catch up with demand.



  • Global crude throughputs are estimated at 73.5 mb/d in 2Q10, an increase of 1.3 mb/d over a year ago and 0.7 mb/d higher than in 1Q10. A year-on-year recovery in US throughputs, as well as continued expansions in non-OECD Asia, drive growth. OECD Europe continues its weak trend, with preliminary data for May posting yet another record-low. Operational problems in Latin America hamper runs there, but a recovery is expected in 3Q10.
  • Global refinery runs are expected to peak in August at 75.1 mb/d, as maintenance and outages reach a seasonal low. The seasonal rise in the OECD Pacific in particular drives the increase, though year-on-year growth continues to be fuelled by the non-OECD. 3Q10 runs reach 74.6 mb/d, 1.1 mb/d above the same period a year earlier.
  • Global crude distillation capacity is on track to increase by 1.3 mb/d in 2010 and a further 1.0 mb/d in 2011. Growth is largely accounted for by China and Other Asia, augmented by smaller expansions in the Middle East. OECD capacity is seen growing overall for the two years, as Marathon's 180 kb/d Garyville expansion on the US Gulf Coast in 1Q10 offset refinery closures elsewhere. Upgrading and desulphurisation investments add 2.1 mb/d and 3.3 mb/d, respectively, by 2011.
  • April OECD refinery yields increased for gasoil/diesel, while they remained unchanged for gasoline and the 'other products' category. Total product gross output depicts an upward trend and is approaching the lower end of the five-year range, at 42.8 mb/d, 160 kb/d or 0.4% below year-ago level. Gasoil/diesel yields were close to their five-year average, with North American yields increasing strongly at the expense of gasoline.

Global Refinery Throughput

Global refinery throughputs are estimated to have averaged 73.5 mb/d in 2Q10, 0.7 mb/d higher than in 1Q10 and 1.3 mb/d above 1Q09. Quarterly growth is dominated by North America, as runs there rose by 1.0 mb/d from 1Q10 lows. Refiners exiting turnarounds were encouraged to run at higher rates by healthy distillate cracks and stronger margins. Offsetting North America's stronger runs, throughputs in OECD Europe remained weak, while the Pacific fell sharply as maintenance peaked there. Outside of the OECD, runs in China and Other Asia continued their upward trend, while the Middle East rebounded on the back of stronger runs in Saudi Arabia.

Our 2Q10 estimate is unchanged since last month's report, with lower runs in the OECD offsetting a higher non-OECD baseline. While final US data for April were higher than weekly figures, preliminary May data for the OECD Europe, and weekly data for both the US and Japan for June, came in weaker than expected. In all, OECD 2Q10 runs have been lowered by 120 kb/d since last month's report. Changes to the non-OECD are dominated by Other Asia, as a reassessment of Indian runs has raised the baseline going back to early 2009. Chinese refinery runs were stronger than expected in May, while smaller downward adjustments have been made to the FSU and Latin America.

Global crude runs are estimated to increase by a further 1.1 mb/d in 3Q10, to average 74.6 mb/d. An expected rebound in OECD Europe and the Pacific as refiners exit maintenance, continued growth in non-OECD Asia and a resumption of operations at several refineries in Latin America underpin the quarterly growth. The inclusion of a five-year average hurricane outage assumption to US Gulf Coast operations lowers North American runs in 3Q10. Amid expectations of a heavier-than-usual storm season, this remains the largest risk to the forecast.

Refinery Expansions in 2010-2011 Eclipsed by Demand Growth

Global refinery crude distillation (CDU) capacity is expected to increase by 2.3 mb/d from 2009 to 2011. The largest increases come from China (which alone accounts for 40% of growth), India, and the US. Smaller increases take place in the Middle East and Africa. The OECD Pacific, notably Japan, leads the capacity consolidation drive by shutting 190 kb/d of capacity during these two years. Investments in upgrading and desulphurisation are expected to add 2.1 mb/d and 3.3 mb/d to capacity, respectively. While the additions are significant, expected demand growth of 3.1 mb/d for the same period mean that the currently large spare capacity surplus could be reduced over the coming years, before increasing again thereafter.

OECD CDU capacity is seen increasing by 120 kb/d in total. The commissioning of Marathon's 180 kb/d Garyville refinery in 1Q10 and Pemex's 150 kb/d expansion of Minatitlan later this year offset the closure of Shell Canada's Montreal refinery at the end of 2010. In all, North American CDU capacity is lifted by 280 kb/d by the end of 2011. Although there has been much talk of refinery closures in Europe, limited capacity reductions have so far taken place. Except for UK's Teesside refinery, which closed in 2009, only France has been able to reduce surplus capacity, with the closure of Dunkirk (which we assume to remain shut despite recent legal challenges) and one CDU at its Gonfreville refinery expected next year. Two expansion projects in Spain, however, adding 105 kb/d in 2010, as well as some smaller projects in Poland and Greece, offset the closures in France. The Pacific is the only region that will see total distillation capabilities diminish by 2011, as Japan has so far committed 275 kb/d for closure. This number could increase significantly as plans are firmed up, as discussed extensively in the MTOGM and in the feature box below: New Legislation Could Speed up Refinery Restructuring in Japan.

The non-OECD provides 95% of capacity additions this year and next. Of the 2.2 mb/d capacity expected by end-2011, China accounts for almost half. Noteworthy projects include Sinopec's 200 kb/d Tianjin plant which started operation earlier this year, as did the new CDUs at the company's Qilu refinery and CNPC's 200 kb/d Qinzhou, which started test runs in June in order to start commercial operations in September. Next year, we expect the commissioning of CNPC's Fushun and Yinchuan refineries to add around 100 kb/d each, and smaller projects a further 150 kb/d.

In Other Asia, expansions are led by India, accounting for 78% of regional growth. The government's dual policy goals of ensuring growing domestic product demand is met at affordable prices over time, and establishing the country as a major global refined product exporter, drive the expansions. Tighter fuel specifications have also led existing refineries to undertake significant upgrading and expansion projects. Despite delays in several projects, Bharat Petroleum's Bina refinery expansion is now expected to be fully commissioned in September, earlier than our 1Q11 assumption underpinning the June MTOGM forecast as presented here. Elsewhere in the region, Byco Petroleum Pakistan is increasing the capacity of its Karachi refinery from 30 kb/d to 150 kb/d by mid-2011, as it is currently reassembling the ex-Chevron Milford Haven plant it bought and shipped from the UK.

Middle Eastern capacity is augmented by smaller expansions to Iraqi refinery capacity in particular. Iraqi State Oil Marketer, SOMO, is expected to add processing units to both the Basrah and Daura refineries, while a smaller refinery is being constructed by the Kurdistan Government in Erbil to improve product supplies in the North.

Other additions come from Brazil, where Petrobras is expected to add some 70 kb/d over three refineries in 2010, (the Clara Camarao, Paulina and Sao Jose dos Campos plants). In Africa, we have included Sonangol's upgrade to its Luanda refinery for 2010 and an expansion of Morocco's Mohammedia refinery in 2011. In the FSU, a series of smaller expansions are expected, adding a combined 100 kb/d by end-2011.

OECD Refinery Throughput

OECD refinery throughputs averaged 36.1 mb/d in May, a drop of 450 kb/d from the previous month, but 310 kb/d higher than the previous year. The monthly decline stemmed from the Pacific region, where runs were constrained by maintenance, while both North America and Europe saw steady throughputs. European crude runs were nevertheless weaker than expected in May, with preliminary data pointing to another record low, of only 11.9 mb/d. Weekly June data for the US and Japan were also weaker than expected, leading to a total 2Q10 downward revision of 120 kb/d for the OECD. 2Q10 OECD runs are estimated at 36.3 mb/d, 310 kb/d higher than a year earlier.

3Q10 OECD throughputs are estimated at 36.4 mb/d, up 170 kb/d from 2Q10, as European and Pacific runs are expected to rebound from recent lows. Maintenance in both these regions traditionally peaks in 2Q, with sharp fall-offs over the summer. North American runs, on the other hand, are seen falling by almost 300 kb/d, due to the inclusion of a five-year average hurricane outage assumption on the US Gulf Coast. The Atlantic hurricane season might be the most severe since 2005, according to the US top weather agency, with a first storm, Hurricane Alex, already hitting the region, albeit with no impact on regional refinery activity.

Crude throughputs in North America look to have trended sideways in 2Q10, with preliminary data showing runs steady at 18.0 mb/d from April through June. Relatively healthy refining margins in the Atlantic basin, supported by stronger demand growth coinciding with a heavy maintenance schedule, drove the 1.2 mb/d increase in runs from January's low of only 16.8 mb/d. We expect runs to remain at these levels through August, before falling off. For the US Gulf Coast, we incorporate a five-year average outage adjustment to refinery throughputs. The extent of this year's hurricane season, and its impact on regional refinery operations, remain the key uncertainty for the 3Q10 refinery forecast.

US refinery throughputs averaged 15.2 mb/d in June, relatively unchanged from recent months, but 310 kb/d higher than the same month in 2009. Runs have been particularly strong on the US Gulf Coast, with rates actually above recent historical ranges in April and part of May, though they have more recently fallen on deteriorating economics and are now trending within their five-year range.

OECD Capacity Rationalisation Faces Hurdles

Recent developments in the OECD seem to put into question assumed refinery closures, and in some cases reverse company plans. Although refinery shut-down decisions in Canada and Europe have recently been overturned by local courts, for now, we do not expect these refineries to resume operations. In the US, however, we have already seen Valero's decision to permanently close its Delaware refinery undone, as this plant was sold, and the restart of the Aruba refinery (which we had assumed permanently closed) could follow shortly.

Shell Canada was ordered on 7 July to halt any dismantling work at its 130 kb/d East Montreal refinery, which it is converting into a fuel-distribution terminal. The refinery's union claimed that the company has contravened a provincial law that requires the permission from the Ministry of Natural Resources before any dismantling work of a refinery can go ahead. The judge accepted the claim and issued a temporary order. The company has already applied for the government's authorisation and expects to get it shortly, enabling them to continue the process of closing the refinery. At the request of the Quebec government, Shell had extended the deadline for potential buyers to submit offers, and although some bids were made, no agreement on a sale was reached.

In France, a court ordered on 30 June the restart of Total's 140 kb/d Dunkirk refinery, after the main trade union, the CGT, appealed in March against the planned closure of the refinery. The court ordered the company to restart the refinery within 15 days and to pay a €100 000 fine. Total issued a statement noting the ruling, but said it was contradictory as it did not specifically reverse the approval already given to halt operations at the plant. The company said it is currently "examining as quickly as possible ways of obtaining the necessary clarification".

In the US, refinery closures such as Valero's Delaware and Aruba refineries are already in doubt. The company announced in November 2009 that it would permanently shut its Delaware 190 kb/d refinery on poor economics. The April sale to Petroplus-led PBF group, however, means the plant will likely be re-commissioned in spring 2011, after extensive refurbishment.

Valero furthermore announced in June that it is starting a 90-day maintenance programme at its 235 kb/d Aruba refinery, with the aim to restart the plant later this year. The refinery has been shut since July 2009 due to poor economics and a tax dispute between Valero and the Aruban government, although the latter has since been resolved and the company considers economic conditions to have improved to the point where a restart is possible. News reports even state that a potential buyer has emerged for the 40 kb/d Ingleside refinery in Texas, which has been shut for 24 years.

OECD Pacific throughputs averaged 6.2 mb/d in May, in line with expectations. The month-on-month decline of 400 kb/d came from Japan, where maintenance picked up, while South Korean refinery runs were steady at 2.3 mb/d. Japanese refinery runs continued to slide in June, dragging OECD Pacific runs to their seasonal low of just 5.9 mb/d. The June total is 200 kb/d lower than last month's forecast, and it is now evident that some of the maintenance scheduled for May slipped into June, rather than other refiners making up the difference. Weekly data from the Petroleum Association of Japan show Japanese runs, at 2.92 mb/d for the week ending 19 June, hitting their lowest level since at least the beginning of 2003, at only 61.5% of capacity. Scheduled maintenance information, and indeed the latest weekly data, point to a sharp rebound in runs in July and August, before a second round of work will lower runs again in September and October. 

New Legislation Could Speed up Refinery Restructuring in Japan

As discussed in detail in the MTOGM published in June 2010, Japanese refiners face the dual challenge of rapidly shrinking domestic demand and increased export competition from new capacity in China and Other Asia. Despite more than 1.1 mb/d of announced capacity reductions in the last year, refiners have been reluctant to permanently close capacity, and less than 400 kb/d of the announced closures have so far been assigned to specific refineries or units and are considered firm at this stage.

New regulation introduced on 5 July might speed up refinery consolidation and restructuring, however. The Ministry of Economy, Trade and Industry (METI) introduced a new law, requiring all refiners to increase coking or cracking capacities to process heavy crudes from 10% of distillation currently to 13% by the end of the fiscal year ending March 2014, on the expectation that heavy and unconventional crude production will increase in coming years. Refiners will have to submit plans by 31 October on how they plan to increase their upgrading ratio, with fines set for companies failing to file plans by this date. Refiners not willing to invest in expensive upgrading units in the current weak margin environment, could instead reduce crude distillation capacity, speeding up industry consolidation in the process.

European crude runs were once again reported at record lows in May, at only 11.85 mb/d, as seasonal maintenance peaked. A total of 1.5 mb/d of capacity is thought to have been offline in May (including the permanently closed refineries of Dunkirk in France and Teesside in the UK). In Germany, runs have been revised lower from May onwards, as the planned restart of ConocoPhillips' Wilhelmshaven refinery has been delayed. The 260 kb/d refinery, which had been closed since October 2009 on poor economics, was to restart in May, but was shut only days after resuming operations due to a fire at the plant. The plant had still not restarted in early July, and it appears the refinery could be down for months.

European refinery throughputs are nevertheless expected to increase in June, as maintenance activity dropped significantly and margins remained healthy. Refinery economics improved during March and April, spurred by stronger middle distillate demand on both sides of the Atlantic Basin and reduced refinery run rates. In Europe, the improved margins likely encouraged higher runs in June, although in early July refiners were talking about economic run cuts again, following apparent oversupply and sharp falls in cracking margins. 

Non-OECD Refinery Throughput

Non-OECD refinery crude throughputs have been revised higher by 130 kb/d for 2Q10, following a reassessment of Indian refinery runs for 2009 and 1H10. Higher-than-expected runs in China and in Singapore in May further lift the estimate. Total non-OECD throughputs are now thought to have averaged 37.3 mb/d in 2Q10, 1.0 mb/d higher than the same period a year earlier. Year-on-year growth continues to be centred in Asia, with China and India providing 1.0 mb/d and 0.3 mb/d of the annual increase, respectively.

According to data from the National Bureau of Statistics (NBS), Chinese refinery runs hit yet another record high in May. Throughputs were reported at 8.46 mb/d, or 90 kb/d higher than in April and 1.1 mb/d above May 2009. Preliminary trade data and estimates indicate product exports were relatively stable in the month, just shy of 800 kb/d, while product imports fell slightly. Industry surveys show that state refiners increased utilisation rates further in June. China's largest refinery, Sinopec's 460 kb/d Zhenhai refinery, reported raising run rates to 95% of capacity, from 92% in May, to meet increasing summer oil product demand.

While PetroChina reportedly started test runs at its new 200 kb/d Qinzhou refinery at the end of June, commercial runs are not expected until August or September following testing of secondary units. The plant was designed to process low-sulphur crude oil as well as acidic grades such as Dar Blend and Nile imported from Sudan, where parent company CNPC is an equity investor. Recent reports, however, indicate that the US-listed company has abandoned these plans following pressure from the US government, which is accusing the Sudanese regime of being complicit in serious human rights abuses. As a result, Qinzhou might have to source spot feedstocks from West Africa, which could raise supply costs.

Iranian Gasoline Shortage - Improvements Ahead?

Tougher US sanctions aimed at squeezing Iran's energy and banking sectors have deepened the Islamic Republic's international isolation and significantly reduced its sources of fuel (see OPEC Supply, 'New Sanctions Target Iran's Energy Sector'). As a result, French major Total has joined Shell, BP, Reliance, and Glencore in suspending sales of refined products to Iran. The void left by international companies has until now been filled by Chinese traders, Unipec and Chinaoil, and more recently by Turkish refiner Tupras. However, the limited number of traders willing to supply Iran with gasoline and jet fuel is driving up the cost of fuel, casting doubt on the republic's ability to source the full volumes required.

Iran's demand for gasoline is estimated around 400 kb/d in 2009, and it relies on imports for up to 40% of its requirements as it lacks the refining capacity to meet domestic needs. The Iranian government's plans to double the country's refinery capacity, by building seven new refineries by 2013, looks unrealistic as international sanctions also prevent technology transfers and funding needed for expansions. According to IHS CERA, in the calendar year ending 20 March 2010, Iran managed to attract only $8 billion of the required $35 billion in foreign investment into the oil and gas sector. Of the seven projects, only the Persian Gulf Star project remains active, but even there, work seems to have stalled due to funding problems, and is thus excluded from our capacity assessments. Some smaller expansion and upgrading projects could go ahead however, as listed below. Risk to these projects remain, but for now we have assumed they will be completed within the timeframe.

The implication of the expansions listed above, and the absence of any further progress on expanding capacity, is that Iran's gasoline import requirement will shrink over the medium-term but still average about 100 kb/d in 2015. This forecast does not only hinge on development of refinery expansions though; changes to the path of demand growth could have equally significant implications. Demand growth, forecast to grow by 115 kb/d from 2009 to 2015 (4.3% average per year), is stimulated by substantial government subsidies, now in question. Attempts to tackle fuel subsidies - and ultimately lower demand - do appear to be moving forward with the intention to fully eliminate subsidies by 2011, but face fierce opposition in the Iranian society. This situation has led the government to ration gasoline and to develop alternatives, such as natural gas vehicles (NGV). By establishing the Iranian Fuel Conservation Organisation (subsidiary of NIOC), the government aims (among others) to promote NGV market development. In recent years, the number of NGV and fuelling stations has expanded dramatically due to government-supported conversion. As of May 2008, Iran had over 1.8 million NGV, so far mostly paid for by the government. Official targets to have 2.4 million NGVs on the road and 2 400 CNG stations by the end of the next Iranian year (20 March 2012) and 3.5 million NGV by 2015 demonstrate that what may have started as a technology to solve a short-term problem is now part of a longer-term strategy. The question is, if attempts raise prices and lower oil demand or increased investments fail to materialise, could NGV sufficiently fill the gap in Iran's gasoline balance?

Preliminary oil ministry statistics for May show Indian refiners increased runs by 4.6% from April, and 7.7% year-on-year, to 3.25 mb/d. The data continue to exclude throughputs at Reliance's new 580 kb/d Jamnagar refinery, which started production in March 2009. Recent company statements however have led us to reassess our estimates, and it seems we had assumed too slow a ramp-up and too low utilisation rates at the new plant. Reliance's Chairman, Mukesh Ambani, told shareholders in May that the refinery's capacity has been stretched from its initial design to a capability to run at 700 kb/d in its very first year, and that these rates have been tested. The company's latest earnings report further states that the overall utilisation rates at its refineries were 98.3% in the year ending March 2010, with 1Q10 running at 108% of capacity, leading us to raise run estimates going back to early 2009. In all, total Indian throughputs are estimated at 3.8 mb/d in 2Q10.

State-run Bharat Petroleum reportedly started processing crude at its 120 kb/d Bina refinery in early July and full scale commissioning is expected by September. This is more than one quarter ahead of our assumptions, as we were only expecting the refinery to start commercial operations in 1Q11.

Elsewhere in the region, we have revised crude runs in Singapore higher in May by about 140 kb/d, as it seems we had over-estimated offline capacity. ExxonMobil shut part of its 285 kb/d Jurong refinery from 1 May for 6 weeks, and we had assumed a full shutdown instead of only partial. Runs are nevertheless estimated at 13-month lows. Singapore refining margins improved somewhat in May and June, supported by the lower runs, but remain in negative territory on a full-cost basis.

May FSU crude throughputs have been revised slightly lower from the last report's estimate, on the back of lower runs in the Ukraine. TNK-BP's Lisichansk refinery undertook its regular maintenance programme in May and first half of June, curtailing runs. Russian throughputs were flat in May, at 4.8 mb/d, and in line with previous estimates. Runs were expected to increase in June and over the summer as maintenance, in Russia and elsewhere in the region, winds down.

Refinery activity in Latin America is estimated to have averaged 5.0 mb/d in May, a slight improvement from March and April's low levels. Chilean state oil company, ENAP, released a statement in late May announcing the resumption of operations, albeit at reduced rates, at the 116 kb/d Bio Bio refinery, which had been closed since an earthquake hit the country in February this year. The smaller Aconcagua refinery, which sustained less severe damage during the quake, restarted in mid-March at reduced rates.

Although the exact state of affairs at PDVSA's 320 kb/d Isla refinery on the island of Curaçao is unclear, we are assuming that the refinery will restart operations in July, and that runs will remain at reduced rates for some months. The refinery was shut after a power outage on 1 March and several attempts to restart the refinery in May failed following problems with compressed air, steam, water and electricity. The Curaçao government owns the near-100-year-old refinery, which has been operated by PDVSA since 1985 when Shell pulled out. Capital expenditure requirements have been estimated at $1.5 billion by PDVSA, but the company has been reluctant to invest this much money in a refinery it does not own, and reliability has suffered as a result. Elsewhere in the region, Brazilian throughputs were up 100 kb/d in April, to average 1.7 mb/d, slightly higher than our expectations. Maintenance at Petrobras' Repar and Reffaf refineries in July is expected to lower runs for that month by 165 kb/d.

Middle Eastern crude runs rose sharply in May, mostly in line with our previous assessment. Saudi Arabia, in particular, saw runs increase as maintenance at the 400 kb/d Aramco/Exxon JV Yanbu refinery was completed in mid-April. Saudi runs were reported at 1.78 mb/d in the month, 235 kb/d higher than the previous month. Middle Eastern April runs were also curtailed by maintenance at Syria's 140 kb/d Banias refinery for the entire month.

OECD Refinery Yields

April OECD refinery yields increased for gasoil/diesel and remained unchanged for gasoline and the 'other products' category. Total product gross output depicts an upward trend and is approaching the lower end of the five-year range. Year-on-year, total product gross output fell by 160 kb/d or 0.4% to 42.8 mb/d. North American supply rose by 3.1% (680 kb/d) and was close to the high-end of its five-year range, European gross production fell 6.6% (-950 kb/d) while Pacific output increased by 1.5% (100 kb/d). Month-on-month, total gross product supply increased by 320 kb/d (0.8%), with North American output rising 710 kb/d and European output falling by 300 kb/d.

OECD gasoil/diesel yields were close to their five-year average level. Yields increased in all OECD regions, with North American yields increasing strongly, by 0.9 percentage points (pp), from levels well below their five-year range. Gross output increased by 240 kb/d, with North American output increasing by 360 kb/d and Europe falling by 120 kb/d. However, gross output is still 375 kb/d (2.9%) below year-ago levels, with Europe contracting by 525 kb/d (9.3%) and North America increasing by 90 kb/d.

Naphtha yields fell in accordance with seasonal patterns and were trending close to last year's level, which defines the lower end of the five-year range for April. Naphtha yields had increased from five-year lows in June 2009 to close to five-year highs in February 2010, supported by petrochemical feedstock demand. Gross output fell by 115 kb/d on a monthly basis, but was 70 kb/d higher year-on-year (+3.4%) as North American output rose by 28% (90 kb/d). 

OECD gasoline yields remained unchanged at 34.9%. Yields in North America fell by 1.0 pp, while increasing by 1.0 pp in the Pacific. Gross output rose by 110 kb/d, with North America increasing by 100 kb/d and the Pacific by 65 kb/d. On a yearly basis, European output fell by 9.1% (-280 kb/d) with North American output almost offsetting this fall with a 2.8% increase, while output increased 5.1% (80 kb/d) in the Pacific.