Oil Market Report: 15 March 2011

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  • Political unrest in the Middle East and North Africa, currently focused on Libya, has injected volatility into futures markets, with prices gyrating by an average $3/bbl daily. By mid-March benchmark crudes were trading $10-15/bbl above average February levels, with Brent last seen just shy of $114/bbl and WTI around $100/bbl.
  • Global oil product demand growth remains largely unchanged at 2.9 mb/d in 2010 and 1.4 mb/d in 2011, but high oil prices entail significant downside risks to this year's outlook. Baseline changes in non-OECD Asia and stronger Middle East levels lift absolute demand slightly to 87.9 mb/d and 89.4 mb/d, in 2010 and 2011 respectively.
  • World oil supply rose to an all-time high of 89 mb/d in February, up 0.2 mb/d from January. Non-OPEC oil supply rose 0.3 mb/d to 53.2 mb/d on re-instated Alaskan output. 2010 non-OPEC estimates are left unchanged at 52.8 mb/d, while the 2011 forecast is raised by 0.1 mb/d, to 53.6 mb/d, on stronger-than-expected Canadian output.
  • OPEC crude oil output in February fell by 95 kb/d to 30.05 mb/d. A near 200 kb/d average monthly loss of Libyan supply was partly offset by higher production from Gulf states. OPEC's 'effective' spare capacity, excluding Libya, is now near 4.08 mb/d, its lowest since end-2008. The 'call on OPEC crude and stock change', revised up for 1Q11, is cut going forward, averaging 29.9 mb/d for 2011 overall.
  • Global refinery runs are expected to drop sharply through 1Q11 to reach a seasonal low of 73.5 mb/d in March, when refinery maintenance peaks, before rebounding to 75.3 mb/d in June. 1Q11 runs are forecast to average 74.6 mb/d (+2.0 mb/d y-o-y) rising to 74.8 mb/d (+1.0 mb/d y-o-y) in 2Q11.
  • January OECD industry inventories rose by 32.0 mb to 2 695 mb and forward demand cover increased to 58.2 days. Preliminary February data point to a sharp 43.4 mb decline, while oil in short-term floating storage grew by 8 mb.

Expect the unexpected

When presenting our 2011 outlook in recent months, we have stressed that, despite price rises since September, there was no reason to view 2011 as 'just 2008 all over again'. After all, global demand growth is seen easing back to more sustainable levels (after rapid post-recessionary growth in 2010), spare capacity upstream and downstream remain abundant, and OECD stocks at 58 days of cover look ample. But the resurgent influence of geopolitical risk and natural disasters was also less prevalent back in 2008 than it is today. Unrest in the Caucasus, and Caribbean hurricanes in late-summer 2008 coincided with economic collapse, and so had only a fleeting impact on crude prices at the time.

We have noted before the tightening in 2H10 market fundamentals, as demand ran ahead of supply by a consistent 1.1 mb/d. So the price rise from $75/bbl to $95/bbl by end-2010 had a clear fundamentals underpinning. Further gains since then have fed off MENA region political unrest, despite a spare capacity cushion. Even though limited volumes of regional production are affected so far, market perception (even if misguided) that Saudi Arabian facilities, the bulwark of OPEC spare capacity, could be targeted, has brought the geopolitical risk premium back with a bang. In reality, only Libya's 1.6 mb/d of crude production is affected so far, but concerns over Shi'ite unrest in Bahrain spreading to Saudi Arabia, plus a shadow of instability over Iran, Iraq, Yemen and other regional producers, has sustained prices above $100/bbl. OPEC effective spare capacity at just over 4 mb/d remains a calming influence, but has nevertheless fallen to its lowest since late 2008. This has fed enthusiasm for oil as a longer-term store of value, and open interest in crude futures has soared. That may only have a marginal impact, but is one more factor explaining today's price levels.

Japan now begins the long road to recovery from last week's devastating earthquake and tsunami. Aside from a staggering death toll, the disaster raises questions over Japan's economic recovery, given the scale of devastation wreaked on industrial and port facilities. The situation will evolve in coming days, but at writing 9.7 GW of nuclear generation capacity (around 200 kb/d of oil input equivalent) and 1.4 mb/d of Japanese refining capacity is offline, some of it likely long-term. Yesterday's announcement that 8 mb of extra oil will be made available by relaxing industry stockholding requirements will help. A combination of oil (with plentiful spare generation capacity), gas and coal will help fill the power generation gap, notwithstanding thermal capacity and transmission infrastructure are also damaged. There is no way of knowing yet how Japanese oil demand will evolve short-term, so we refrain from adjusting our 2011 outlook. Things will become clearer as disaster relief proceeds and the pace of recovery can be better ascertained.

Turning back to Libya, importers have so far been comparatively relaxed about the loss of 1.3 mb/d of light, sweet crude supply, partly because early-year refinery maintenance is in full swing. The initial advances made by anti-Gaddafi rebels also persuaded some that this was likely to be a short fight. But harsh reality now suggests either a prolonged civil war, or a resurgent Gaddafi regime that might reinstate control over production and export facilities, but with supplies to the global and European market limited by sanctions. Market insouciance may change abruptly as April approaches, when global crude demand is expected to increase by around 1 mb/d as Atlantic Basin refinery maintenance ends. Saudi Arabia and other producers have increased supply, although gauging volumes has been difficult, and refiners have been wary of purchasing at inflated prices. And while actual threats to production elsewhere in MENA remain theoretical for now, these threats could keep market sentiment on the bullish side a while longer. The IEA maintains a watching brief in both the unfolding Libyan and Japanese situations, and can mobilise its 1.56 billion barrels of government strategic stocks in short order if market liquidity looks badly strained. But the fact that this is now being seriously considered shows how far we have come from earlier, more comforting days when a tranquil early-2011 oil market looked more likely.



  • Forecast global oil product demand for 2010 and 2011 is revised up by 90 kb/d on average on baseline changes in non-OECD Asia and stronger-than expected readings in the Middle East. Global growth, however, remains largely unchanged. Oil demand, which averaged 87.9 mb/d in 2010 (+3.4% or +2.9 mb/d year-on-year), is expected to rise to 89.4 mb/d in 2011 (+1.6% or +1.4 mb/d year-on-year). However, persistently high oil prices entail significant downside risks to this year's prognosis.
  • Projected OECD oil demand remains largely unchanged for both 2010 and 2011. Total OECD demand, which averaged 46.1 mb/d in 2010 (+1.5% or +0.7 mb/d year-on-year), is projected to fall to 46.0 mb/d in 2011 (-0.2% or -100 kb/d versus the previous year). The decline, however, could be larger if oil prices remain at high levels, although Japan's fuel oil and direct crude use for power generation may rise following the earthquake-induced outage of several nuclear plants.

  • Estimated non-OECD oil demand for 2010 and 2011 is raised by 100 kb/d on average. Upward baseline revisions to several Asian countries (Hong Kong, Chinese Taipei and Thailand, from 2008 to 2010) and stronger December readings in a handful of Middle Eastern and FSU countries (Saudi Arabia, Iran, Iraq and Azerbaijan) have lifted estimated non-OECD demand for 2010 to 41.8 mb/d (+5.6% or +2.2 mb/d year-on-year). The prognosis for 2011 is also slightly adjusted up, in order to account for the baseline changes and on a higher prognosis for Chinese apparent demand, to 43.3 mb/d (+3.7% or +1.5 mb/d versus the previous year). However, rising oil prices and the ongoing turmoil in Middle Eastern and North African countries are a source of forecast uncertainty.

Global Overview

A pressing question in the minds of most analysts and policymakers is what impact high oil prices will have on global economic growth and inflation - and ultimately on oil demand. Indeed, after a period of remarkable stability from October 2009 to September 2010 within a relatively narrow band, oil prices (Brent) have risen by approximately 50% since then - first on very strong demand growth (4Q10) and, since early 2011 on increased regional geopolitical risk in North Africa and the Middle East, embodied by Libya's supply outage.

Empirically, past oil price shocks have shown a discernible effect on GDP. Supply shocks tend to be felt just a few months thereafter, while demand shocks usually have an impact roughly a year later. This suggests that if prices remain at current levels or rise further, by September 2011 - if not before - the global economy may feature a marked slowdown - and the more so because it would coincide with expected fiscal tightening (and possibly monetary as well, if inflationary expectations become entrenched) in the world's largest economies.

Unfortunately, estimating price impacts is notoriously difficult, because many variables are at play, particularly oil intensity, consumer behaviour and the degree to which international prices are passed through to domestic consumers. Still, diverse econometric studies suggest that a 10% increase in the price of oil could cut global GDP by anywhere between 0.2 and 0.7 percentage points after one year (and possibly by twice as much in the second year). Although the range is quite large, a simple calculation illustrates potential outcomes - and the huge uncertainty - for both economic growth and oil demand.

As an example, if current $115/bbl price levels that, as noted, are 50% above the relatively stable range evident for much of 2009-2010, were to be sustained, global GDP growth in 2011 could come in at anything between 1.0-3.5 percentage points below the IMF's assumed +4.3%. A low end of this range, implying global GDP growth of 3.4%, would cut oil demand growth from 1.6% to 1.3%, or 300 kb/d less than presently expected for this year. At the high end, with GDP growth curbed to barely 0.8%, oil demand growth would be nearly wiped out altogether, averaging only +260 kb/d.

The impact of such a price-induced economic slowdown would inevitably be felt most in more oil-intensive regions. Arguably, non-OECD countries would account for the greater share of any reduction in global oil demand that would occur as a result of lower economic growth, and the more so if rising prices render end-user subsidies financially unsustainable. However, in terms of oil product demand per capita, the OECD is possibly more vulnerable than non-OECD countries, as use per head is roughly five times higher on average - and almost nine times higher in the US and Canada, which feature the highest such metric within the OECD.


According to preliminary data, OECD inland deliveries (oil products supplied by refineries, pipelines and terminals) rose by 2.1% year-on-year in January, with all regions posting gains. Demand increased by 2.6% in OECD North America (which includes US Territories), 2.2% in OECD Pacific and 1.2% in OECD Europe, mostly driven by middle distillates. Indeed, jet fuel/kerosene, diesel and heating oil accounted for roughly two-thirds of total yearly growth - which, at +950 kb/d, was a shade below the symbolic +1.0 mb/d mark. This reflects both an economic recovery relative to a very weak baseline and much colder-than-normal temperatures.

Revisions to December preliminary data were minor (-70 kb/d), showing that total OECD demand expanded by 1.9% year-on-year during that month, broadly in line with earlier estimates (+2.1%). The adjustments, however, were relatively significant in North America (-220 kb/d), as monthly US submissions proved much lower than preliminary weekly estimates, and in Europe (+120 kb/d), given stronger-than-anticipated naphtha and diesel demand.

Based on the latest submitted data, OECD oil product demand is now estimated at 46.1 mb/d in 2010 (+1.5% or +680 kb/d year-on-year) and at 46.0 mb/d in 2011 (-0.2% or -100 kb/d versus the previous year). Both prognoses are largely unchanged versus our last report.

North America

Preliminary data show oil product demand in North America (including US territories) rising by 2.6% year-on-year in January, following a 2.3% increase in December. January readings were boosted by cold temperatures, though disruptive weather may have played an offsetting role in limiting transport demand growth. Economic conditions continue to improve, buoyed by strong industrial indicators and evidence of some recovery in the US labour market. Nevertheless, the impact of sharply rising gasoline prices coupled with anticipated structural efficiency gains should keep oil demand growth rates muted for much of the year.

December data were revised down by 220 kb/d, led by lower readings for gasoline (-150 kb/d) and 'other products' (-235 kb/d), which offset higher estimates for diesel (+140 kb/d). Weekly to monthly revisions in the US led the December changes and, at -260 kb/d, were strongly negative for the first time since May 2010. As such, North American demand is now estimated at 23.9 mb/d in 2010 (+2.6% or +600 kb/d versus 2009 and 15 kb/d lower than our last report). Demand in 2011 is seen rising to 24.0 mb/d (+0.2% or +60 kb/d year-on-year and 40 kb/d lower than our last report).

Adjusted preliminary weekly data for the United States (excluding territories) indicate that inland deliveries - a proxy of oil product demand - grew by 1.8% year-on-year in February, following a 3.2% rise in January. February readings featured a sharp gain in residual fuel oil (+51.5%, albeit from a very low base) and continued moderate growth in gasoline demand (+1.7%). During the last week of February, average retail gasoline prices rose by ¢19/gallon - the second largest weekly jump since 1990. As of early March, prices stood at over $3.50/gallon (up ¢75/gallon year-on-year). Yet recent weekly estimates have pointed to strengthening, rather than weakening, gasoline demand growth; still, given the volatility of such data, any definitive assessment is premature. Moreover, the speed and magnitude of the price rise may slow the seasonal increase. Given lower-than-expected January/February readings, our 2011 gasoline demand estimate has been revised down by 25 kb/d, now rising by a modest 0.3% versus 2010.

Meanwhile, questions also persist over diesel demand, with average retail prices approaching $3.90/gallon in early March. Preliminary weekly data suggest that middle distillate growth slowed down over January and February. Similarly, the Ceridian-UCLA Pulse of Commerce Index, which measures diesel demand through its payments system, points to slowing demand growth, with February readings up by 1.8% year-on-year, down from an average +4.7% over the previous three months. Industrial indicators, by contrast, paint a more optimistic picture. For example, purchasing managers' activity rose for the seventh consecutive month in February, intermodal rail traffic increased by 10.3% versus the previous year and the American Trucking Association's road freight tonnage index soared in January on a seasonally adjusted basis to its highest level since January 2008. The discrepancy between economic indicators and more tepid preliminary demand data may be due to greater efficiency - if so, it would suggest that the economy is better able to cope with rising prices when compared to 2008.

Canadian Puzzle

Canadian monthly submissions throughout 2010 have shown a volatile pattern. Unadjusted deliveries data suggest that Canadian oil demand grew by almost 9% year-on-year, with an 8.5% rise in gasoline. Although market sources have pointed to increased mining activity in the western part of the country as supportive of demand, with the Canadian economy expanding by only 2.9% in 2010, the headline oil demand growth rate implies an income elasticity that looks implausibly high. Before the economic crisis, Canadian demand was growing on average by 1.8% annually from 2000-2007 with GDP growth of 2.5%.  While post-crisis demand may well be rebounding faster than long-term income relationships imply, the erratic nature of some products suggests deeper data series issues.

This raises the question of whether the reporting stems from categorisation issues, a series break or simply the collection challenges of Canada's vast territory. As a result, 2010 monthly demand estimates for gasoline, heating oil and 'other products' in this report have been adjusted on the basis of our own econometric model, with total oil demand growth assessed at a more reasonable 3.9% for the year. Forthcoming revisions will hopefully narrow the discrepancy between the two data series.


Preliminary inland data indicate that oil product demand in Europe rose by 1.2% year-on-year in January, largely boosted by on-road diesel. This stems mostly from a baseline effect: in January 2010, snowstorms were more disruptive to transportation activity than was the case this year. By contrast, even though temperatures were much colder than last year (with HDDs higher both versus the ten-year average and January 2010), heating oil deliveries rose by only 1.8%, equivalent to +35 kb/d. Although this weak performance may result from consumer stock draws, demand growth was similarly frail in December, suggesting that structural decline in heating oil use remains a feature of this market.

December's revisions to preliminary demand data (+120 kb/d) were largely concentrated in naphtha and diesel, indicating that demand growth was stronger than suggested by preliminary readings in that month (+2.5% versus +1.7%). Total oil product demand in OECD Europe thus averaged 14.4 mb/d in 2010 (-0.3% or -50 kb/d compared with the previous year and 10 kb/d higher than previously expected). The outlook for 2011 is broadly unchanged, with demand expected to continue declining (-0.5% or -70 kb/d versus 2010, and roughly 10 kb/d lower versus last month's report).

In terms of absolute growth, three countries clearly stand out. In Germany, oil product deliveries increased by 60 kb/d or 2.7% year-on-year in January, according to preliminary data, with strong demand for transportation fuels offsetting a decline in heating fuel deliveries.

In France, the picture was similar. Total oil demand also rose by almost 60 kb/d (+3.3%) on the back of strong diesel deliveries (and to a lesser extent, heating oil), which offset much lower readings for residual fuel oil (suggesting that natural gas and imported electricity met peak power needs). It should be noted, though, that in both countries temperatures were warmer than last year, yet broadly in line with the ten-year average.

Finally, Turkey has featured remarkable oil demand growth over the past few months (+80 kb/d or 14.9% on average since September). With gains concentrated mostly in industrial and transportation fuels (notably naphtha and diesel), this highlights the country's economic dynamism. We estimate that total demand expanded by as much as 16.4% in January to roughly 520 kb/d.

Back to Gasoline?

Over the past two years, the European vehicle fleet has seen some intriguing developments that - if sustained over the longer term - could eventually alter the structure of oil product demand on the continent. In 2009, for the first time since 2003, the share of diesel car registrations fell below 50% (46.3% for the main five markets, including France, Germany, Italy, Spain and the UK). Although registrations recovered somewhat in 2010, they were effectively flat on a yearly basis.

Does this mean that the much touted 'dieselisation' of Europe's passenger car fleet is over, as some observers have argued, thus heralding the triumphant return of gasoline-powered vehicles? As much as the surge in sales of small, cheap gasoline-powered models in 2009 was mostly due to temporary government incentives - the scrapping schemes set by various European governments to support their struggling car manufacturers as the recession hit - other factors suggest that the exponential growth of both diesel registrations and cars in use observed from 1995 to 2007 is indeed unlikely to resume.

Prosaically, this will depend upon relative prices. On the one hand, diesel cars are likely to become even more expensive than gasoline vehicles, especially as Euro 6 standards aimed at curbing nitrous oxide (NOx) emissions are implemented from 2014. According to some analysts, this could add as much as 5% to the cost of a new diesel car, also reducing its fuel efficiency, and making it uncompetitive for motorists driving less than 60,000 km over the first three years of the car's life (a metric deemed necessary to amortise the car's cost). This could be quite noticeable in the small-car segment, with price disparities likely to be significant.

On the other hand, the retail price advantage of diesel over gasoline is likely to continue shrinking (diesel is currently about 10% cheaper, down from 15% in 2009). Even though wholesale diesel prices are higher, retail prices are lower because of sales tax differentials. However, mounting fiscal woes could prompt governments across Europe to reduce such differentials (taxes account for about 40% and 50% of end-user prices, for diesel and gasoline, respectively).

At first glance, should dieselisation be drawing to an end, the European refining industry, where distillate yields account for roughly half of total production, would be affected. Refiners would face a shrinking market amid higher supply competition from other regions. However, this possibility must not be exaggerated. First, in aggregate terms, the degree of fleet dieselisation should not be overstated - about two-thirds of the overall European fleet in use is gasoline-based, with the exception of two countries (France and, to a lesser degree, Spain), where diesel cars in use are at or slightly above 50%. Second, even though the number of diesel cars in use rose in 2010 after remaining virtually flat in recession-stricken 2009, the pace of growth has sharply decelerated since 2005. Finally, lower diesel demand growth in Europe would probably contribute to ease an otherwise tightening distillate market - and perhaps help avoid further oil price spikes in future.


Preliminary data show that oil product demand in the Pacific rose by 2.2% year-on-year in January, largely on heating and power generation fuels (respectively kerosene and residual fuel oil plus direct crude). This resulted from extreme temperatures; as a result of the cold wave that hit the region in that month, HDDs were sharply above both the ten-year average and the previous year.

The revisions to preliminary December data were negligible (+30 kb/d) and essentially concentrated in Japan's heating oil and 'other products'. As such, our estimates of total OECD Pacific demand are virtually unchanged from last month's report, with demand averaging 7.8 mb/d in 2010 (+1.7% or +130 kb/d year-on-year) and falling further to 7.7 mb/d in 2011 (-1.1% or -90 kb/d year-on-year), assuming a return to normal weather conditions. At the time of writing, though, the effects of the massive earthquake that visited Japan on 11 March were still unclear and, as such, no allowance for this tragic event has yet been made in the forecast.

The weather effect was particularly noticeable in Japan, with direct crude burning rising markedly ('other products', which include direct crude, surged by 32.9% or almost 100 kb/d year-on-year in January, roughly matching the five-year average). More worryingly, perhaps, naphtha deliveries contracted by 10.3% or 90 kb/d. This is the second monthly fall in a row, and follows several months of sluggish demand growth, suggesting that the country's petrochemical industry is again lagging, probably due to vigorous competition elsewhere in Asia. Tellingly, naphtha demand in Korea jumped by 7.9% in January, reaching a new record high (a shade below 1.0 mb/d).

Japan Nuclear Outages Point to Increased Fuel Switching

The devastating earthquakes and tsunami that hit Japan on 11 March will have a profound impact on the country's power generation sector. As of 14 March, damage to the nuclear industry, which generates more than one quarter of Japan's total electricity, had forced the shutdown of 11 reactors representing 9.7 GW of capacity. An additional 8.5 GW of oil, gas and coal capacity was also shut-in, prompting the country's largest utility, TEPCO, to consider rolling blackouts.

The current situation remains fast changing and any estimate of its impact upon energy demand is premature. Nonetheless, short-term fuel switching within the power sector is likely to be significant, with oil, gas and coal all being used to make up for the loss in nuclear output, subject to regional generation capacity and transmission availability. Indeed, under normal operating conditions, the offline nuclear plants would generate some 60 TWh of electricity per year.

Nationwide, there appears to be ample spare oil-fired capacity to compensate for this 60 TWh loss, even with 3.8 GW idled by the earthquake. In 2009, only 30% of oil-fired capacity was used, producing just over 100 TWh of electricity with 360 kb/d of oil (crude oil and fuel oil) on average. Thus, if the 60 TWh shortfall were met entirely by oil, consumption would increase by roughly 200 kb/d on an annual basis. In previous episodes of nuclear power generation constraints in the mid-2000s, such as the 21-month outage of the 8.2 GW Kashiwazaki-Kariwa plant following the July 2007 earthquake, fuel oil and direct crude burning rose by around 250 kb/d versus an otherwise declining trend for both fuels.

In practice, however, this power requirement is likely to be met by LNG and coal as well, though spare generation capacity appears to be more limited in both sectors. For example, the utilisation rate of major gas-fired power stations stood at around 55% in 2009, which is already relatively high for such type of plants. The generation of an extra 60 TWh using only gas would require plants to operate at near 70% of capacity, implying an additional 12 bcm of LNG per year (32 mcm/d).


Preliminary demand data show that non-OECD oil demand growth slowed down slightly in January, (+6.4% or +2.5 mb/d year-on-year). Total January demand is estimated at 42.1 mb/d; meanwhile, December appraisals have been revised up by 240 kb/d to 43.2 mb/d (+7.7% or +3.1 mb/d year-on-year).

All product categories continued to post strong growth in January. In relative terms, gasoil (+8.1% year-on-year), jet fuel/kerosene (+7.8%), 'other products' (+7.6%) and residual fuel oil (+6.7%) recorded the highest rates. However, gasoil led once again in terms of absolute growth (+950 kb/d, equivalent to roughly 38% of total growth), followed by 'other products' (+400 kb/d), residual fuel oil (+370 kb/d) and gasoline (+340 kb/d). Similarly, Asia remained the main driver of non-OECD oil demand growth. Yearly growth, at 1.5 mb/d (+8.2%), represented 61% of the total. In what has become a familiar pattern, China was the single largest contributor, representing 86% of Asia's increase and 52% of non-OECD growth.

Given upward baseline revisions to several Asian countries (Hong Kong, Taiwan and Thailand, from 2008 to 2010) and stronger December readings in a handful of Middle Eastern and FSU countries (Saudi Arabia, Iran, Iraq and Azerbaijan), non-OECD demand is now estimated at 41.8 mb/d in 2010 (+5.6% or +2.2 mb/d year-on-year and 100 kb/d higher than previously predicted). The prognosis for 2011 is also slightly adjusted up, in order to account for the baseline changes and on a somewhat higher prognosis for Chinese apparent demand, to 43.3 mb/d (+3.7% or +1.5 mb/d versus the previous year and +90 kb/d when compared to our last report).


China's apparent oil demand growth slowed down slightly in January (+15.3% year-on-year), with all product categories bar LPG posting strong gains. This appraisal, however, must be taken with caution: official statistics tend to be sketchy in January and February, given the Lunar New Year holidays. Figures for total refinery throughput, in particular, are often contradictory. Our current monthly estimate is based on figures by the National Bureau of Statistics released in mid-March, which indicate that throughput rose by 11.2% year-on-year in January (much lower than earlier company reports suggesting another sharp rise in runs). This results in a small upward revision to our assessment of expected apparent demand in 1Q11.

More interestingly, perhaps, in late February the National Development and Reform Commission (NDRC) hiked 'guidance' prices of gasoline, gasoil and jet fuel (an increase of 4.1%, 4.5% and 5.8%, respectively, relative to the last adjustment in late December). Despite mounting inflationary concerns, the increase suggests that the government is aware that domestic refineries may again become somewhat reluctant to supply the Chinese market if margins are not adequate. The hike, however, still lags international prices (actually, according to the price mechanism, it should have occurred in January). Therefore, a re-emergence of oil product shortages, as seen periodically over the past several years, cannot be entirely discounted, notably in drought-stricken northern China and, more generally, ahead of the resumption of economic activity after the Lunar New Year holiday lull. Still, the NDRC explicitly acknowledged in its accompanying statement the key role that independent refiners play in meeting domestic needs. The NDRC also argued that the price hike is intended to rein in consumption, although the impact may be blunted by still-buoyant economic growth and the ongoing subsidies enjoyed by key industrial and transport sector users.

Other Non-OECD

According to preliminary data, last December's increase to subsidised gasoline and gasoil prices (+300% and +800%, respectively) had a lesser impact on Iranian demand than previously expected. Earlier reports reckoned that demand would contract by around 17% year-on-year in the case of gasoline and by some 10% for gasoil. In fact, demand fell by 7.0% and 5.2% year-on-year, respectively. On a monthly basis, however, gasoline demand actually rose (+7.3% from November), possibly indicating hoarding ahead of the price increase, before plummeting in January. Gasoil use, by contrast, decreased month-on-month in both December and January - but remains within the five-year average.

Aside from data issues, the relatively muted impact of the price hike is probably related to both the nature and the usage of both fuels. Indeed, gasoline is mostly used by private motorists - arguably, with the exception of taxi drivers, this segment of the population can easily absorb the new price. By contrast, gasoil is mostly used by trucks and buses - which have effectively continued to benefit from subsidised fuel. In addition, the payment of direct cash handouts probably softened the initial blow. However, despite these somewhat better readings, we still expect Iran's overall oil product demand to decline in 2011.

Libya's descent into civil war is likely to affect the country's oil product demand in the medium term, although it is very difficult to estimate by how much at this point. In the short run, though, demand - which averaged some 270 kb/d in January, according to preliminary data - may actually be boosted by military operations. The use of planes, tanks and other military vehicles could support demand for gasoil (40% of total consumption in 2010), gasoline (11%) and jet fuel/kerosene (4%). However, power blackouts and subdued maritime traffic (largely due to falling crude oil exports) may curb residual fuel oil use (27% of total demand). In addition, shortages may emerge as on domestic refinery outages and halted oil product imports. For now, given these uncertainties, we have left our estimates for Libya largely unchanged.

During previous episodes of domestic price rises in Russia, the government's Federal Antimonopoly Service (FAS) has targeted several of the five domestic majors (Surgutneftegaz, Rosneft and LUKoil, TNK-BP and Gazpromneft), which has eventually resulted in a partial reversal of such price adjustments. In early February, the FAS launched the third such investigation since 2008, this time against Surgutneftegaz, Rosneft and LUKoil on 'artificially' hiking prices since last October. Admittedly, the Russian oil product market has an oligopolistic structure - these five companies plus Bashneft reportedly account for some 85% of the country's oil product output and own about half of all service stations, as well as most storage facilities. Nonetheless, other factors are at play, including the sharp increase in international oil prices, winter seasonal peaks, the appreciation of the rouble and the extension of excise duties since the beginning of this year.

More importantly, perhaps, oil use has sharply rebounded. Russian demand surged by 8.8% (+250 kb/d) in 2010, following its recession-induced plunge in 2009 (-6.3%). The rebound was particularly strong for transportation fuels, with annual growth rates ranging from 6% to 12%. Although this is expected to moderate in 2011 (+2.6%), it will still be significant. However, if the government succeeds in capping domestic prices and eroding refining margins, shortages could emerge as refiners would arguably have greater incentives to export crude and oil products - and perhaps even curb domestic refinery runs.

In Brazil, gasoline demand (including ethanol) increased to a record high 920 kb/d (+6.1% year-on-year) in December - the seasonal high point of the year - following annual growth of 11.4% in November. Meanwhile, rising sugar prices have made hydrous ethanol less competitive versus oil-based gasoline. As such, ethanol consumption (by volume) accounted for just 51% of the total gasoline pool in December, down from 54% from May to September. With gasoline demand likely to remain strong in 2011 - we forecast growth of 5.1% - a tightened ethanol market may require sustained gasoline imports in 2011 for Brazil, which is normally a net-exporter.

The prospect of gasoline imports has also increased in Argentina. There, gasoline demand growth is expected to reach 7.0% year-on-year in 2011, following a rise of 10.9% in December. Although economic growth helps explain the rise in demand, price distortions also play a key role: Argentine motorists are shielded from increases at the pump by government-imposed price limits.

In Chile*, meanwhile, questions persist over whether the country will face electricity rationing over the coming months due to low water levels in hydropower reservoirs, notably in the central grid (which serves 90% of the population). Recent government statements have played down the prospect of shortages with the implementation of other energy-saving measures, such as reducing electricity voltage and extending daylight savings time by three weeks. Moreover, rising LNG imports have accounted for an increasing portion of electricity generation (over 25% in January versus just 5% for diesel-fuelled power). However, given rising LNG prices and import capacity constraints, diesel imports may increase in the coming months if other measures fail to moderate power demand. Still, gasoil demand growth has slowed down in recent months, rising by only 2.3% year-on-year in December, and gasoil demand is expected to average 150 kb/d in 1Q11 - far below the 190 kb/d average seen during the southern hemisphere summer of 2007-2008.

The Gorilla in the Room: Subsidy Challenges

As international oil prices moved above the $100/bbl mark, the issue of fossil-fuel subsidies, notably for gasoline and diesel, has once again become pressing in many developing countries. However, the response to rising prices has been quite diverse. In a snapshot, developing countries fit in three broad categories. Of course, this taxonomy is not exhaustive and exclusive, as some countries may fit in several groups depending on the fuel. Moreover, the current arrangements may well change if international prices rise further.

First, there is a group of countries where end-user price liberalisation is largely non-existent. Governments maintain generous subsidies in place regardless of international prices in order to keep inflation in check and cultivate political allegiance and social stability, even if this implies a rising fiscal burden, as well as a huge waste. Saudi Arabia and Venezuela are two representative examples. Venezuelan consumers enjoy the world's cheapest gasoline and diesel - both priced some 98% below US levels (which are a good proxy of 'pure' market prices given low taxes). Saudi Arabia, due to its vast hydrocarbon endowment, is able to heavily cross-subsidise transportation fuels with the proceeds of crude oil sales.

A second group of countries features partial deregulation, with some product prices following more or less market trends and others remaining capped, reflecting the uncomfortable dilemma of having to choose between mounting fiscal deficits or control unpopular inflationary pressures. This is the case of many Asian countries, including Bangladesh, India, Indonesia, Iran, Pakistan and Sri Lanka, among others. Bangladesh and Sri Lanka, for example, allow gasoline prices to adjust over time, but keep diesel heavily subsidised in order to protect their farmers. Indonesia, meanwhile, is intent on curbing consumption and reducing imports of gasoline by allocating subsidies exclusively to public transportation vehicles and motorcycles. Iran has sharply raised gasoline and diesel prices and adjusted its quota system, but both fuels are still priced well below international levels. India has liberalised gasoline prices, but continues to subsidise diesel prices - a price differential that fosters purchases of diesel-powered vehicles and machinery, further compounding the subsidy burden. In January, Pakistan increased prices, decreased them a few days later and increased them yet again in early March, before halving them once more, reflecting the tenuous political standing of the current government.

Finally, there are countries where prices have been formally liberalised, but where the government still exerts considerable influence and de facto moderates price movements. This is done either by delaying long-due adjustments to wholesale prices (as in China or to a certain extent India for gasoline) or by forcibly persuading domestic private companies to keep prices low (Argentina, Russia).



  • Global oil supply rose to an all-time high of just under 89 mb/d in February, up by 0.2 mb/d from January due to higher non-OPEC output, while OPEC crude production was lower due to curtailed supply in Libya. Year-on-year, February global oil supply is 2.2 mb/d higher, with growth split relatively evenly between non-OPEC, OPEC crude and OPEC NGLs.
  • OPEC crude oil output in February was down marginally in the wake of the turmoil in Libya, off by just under 100 kb/d to 30.05 mb/d. A near 200 kb/d loss of Libyan supply on average in February was partially offset by increased production from the group's Gulf members. OPEC's 'effective' spare capacity, which excludes Iraq, Nigeria, Venezuela and now Libya, is estimated at 4.08 mb/d, its lowest level since late-2008.
  • The outcome of the Libyan rebellion against Muammar Gaddafi's government hung in precarious balance at press time, but what is becoming clearer is that the country's oil exports of some 1.3 mb/d will remain off the market for a considerable time due to both war-inflicted damage on oil infrastructure and international sanctions.
  • Non-OPEC oil supply rose by 0.3 mb/d to 53.2 mb/d in February on re-instated Alaskan output after pipeline-related shut-ins in January and on higher estimated UK and FSU production. The 2010 production estimate is left unchanged at 52.8 mb/d, while the 2011 forecast is raised by 0.1 mb/d, to 53.6 mb/d, on stronger-than-expected Canadian output.
  • The 'call on OPEC crude and stock change' for 1Q11 is raised by 0.4 mb/d to 30.2 mb/d due to higher forecast demand and lower non-OPEC supply. However, the 'call' for 2Q11 to 4Q11 is lowered by 0.2 mb/d on higher forecast non-OPEC supply.

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

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.

OPEC Crude Oil Supply

OPEC crude oil output in February was down marginally in the wake of civil unrest in Libya and the shut-in of around two thirds of the country's oil production by early March. A number of OPEC members have already stepped in to increase production to offset Libyan output in March and April, especially Saudi Arabia. However, with Libya now effectively in a state of full-scale civil war and production down to a trickle, other OPEC countries may need to further ramp up production in the weeks and months ahead to offset lost output of 1.5-1.6 mb/d (see Libya's Uprising Sees Oil Supplies Dwindle). The task is complicated by the fact that the bulk of Libya's output comprises relatively light, sweet crude, which will be difficult for Middle East Gulf producers to match.

In February total OPEC output fell by just under 100 kb/d to 30.05 mb/d, with a near 200 kb/d loss of Libyan supply on average in February partially offset by increased production from the group's Gulf members. January OPEC supply was revised up by 290 kb/d to 30.14 mb/d, mostly on higher estimates for Saudi Arabia and the UAE. OPEC-11 February output fell by 115 kb/d to 27.37 mb/d. Saudi Arabia, Kuwait, the UAE and Iran combined raised output by 230 kb/d month-on-month. By contrast, Nigeria and Angola saw lower output on technical problems and field maintenance work, down by a combined 160 kb/d.

OPEC as a group appears unwilling to formally raise output targets ahead of the next scheduled ministerial meeting in Vienna on 2 June. That said, key Gulf producers led by Saudi Arabia with spare capacity are already ramping up output and are prepared to increase supplies further depending on market demand. Some other members, such as Iran, appear impotent to increase production given very limited spare capacity. OPEC's effective spare capacity, which excludes Iraq, Nigeria, Venezuela and now Libya, is estimated at 4.08 mb/d, with Saudi Arabia holding almost 80% at 3.2 mb/d (see OPEC Crude Oil Production Capacity Hovers Near 4 mb/d). This is the lowest effective level since late 2008.

The 'call on OPEC crude and stock change' for 1Q11 is raised by 0.4 mb/d to 30.2 mb/d due to higher forecast demand and lower non-OPEC supply. However, the 'call' for 2Q11 was lowered by 0.2 mb/d and by 0.2 mb/d for 2H11 on higher forecast non-OPEC supply. The call for 2011 on average remains unchanged at 29.9 mb/d, compared with 29.8 mb/d for 2010.

Saudi Arabia increased output in February to an average 8.90 mb/d, up by 100 kb/d following an end-month ramp-up to around 9.1 mb/d in response to the Libyan crisis. January supply estimates were revised up by 200 kb/d, to 8.8 mb/d, after more complete tanker sailings data became available. OPEC's principal holder of spare capacity quickly moved to make more crude available to the market to offset shut-in Libyan supplies, but demand for extra barrels was limited near-term given the coincidence of the Libyan crisis with the peak of seasonal refinery maintenance in Europe and North America, as well as the quality mismatch between Libyan and Saudi Arabian crude. Instead, the Kingdom has placed additional volumes in storage in Europe and Japan ahead of stronger customer demand for April and May supplies.

Libya's Uprising Sees Oil Supplies Dwindle

While the outcome of the Libyan rebellion against Muammar Gaddafi's government hung in precarious balance at press time, what is becoming clearer is that the country's oil production and exports could be off the market for many months due to both war-inflicted damage on oil infrastructure and international sanctions.

After weeks of intermittent production and tanker activity, oil exports have ground to halt in the wake of fierce fighting between the government's well-equipped forces and the more ill-equipped rebel groups. By 14 March, the out-gunned rebels had lost much ground taken over the past three weeks, with all but two of around a dozen key oil ports falling back into the hands of government forces. The government controls all the oil export terminals in the western region of the country, which account for just over 30% of total crude exports, which averaged just below 1.3 mb/d in 2010. In the eastern region of the country, where around 840 kb/d of crude exports flow from, government forces control four of the six main export terminals.

Libya's opposition was lobbying hard for the international community to impose a no-fly zone over the eastern region of the country. While the EU, US and other countries appeared divided on the issue, and indeed, concerned over the legitimacy of imposing a no-fly zone, the Arab League made a surprise formal request on 12 March to the United Nations (UN) for such a zone to be imposed. The Arab League's Secretary General Amr Moussa said that the Libyan government no longer had any legitimacy as a result of the "serious crimes and great violations" committed against its people. A no-fly zone would protect the opposition group's stronghold in the eastern flank of the country, as well the main producing and export region. Debate in the international community is ongoing. At the same time, however, government forces appear poised to move further east, and overrun the opposition group's remaining cities. However, it is likely production and exports will remain off the market for a considerable time (months rather than weeks) as international sanctions are tightened. Already many companies are unable to pay for Libyan crude given the freeze on assets directly or indirectly controlled by Gaddafi's family and government.

Libyan crude oil production levels have become progressively more opaque since the start of the revolt on 21 February, with limited information available following the mass evacuation of foreign workers, lack of communication channels and conflicting and incomplete data on port and export activity. Libyan oil supplies were down an estimated 195 kb/d on average for February, to 1.385 mb/d. While approximately half the country's output was halted in the first few weeks of the rebellion, by 11 March it appeared that production had slowed to a trickle, not least because of the fighting. Major oil companies operating in the country, including ENI, the Oasis Group, Total and Repsol, have all pulled out their staff and ratcheted down or shut-in production.

Indeed, it is understood that most oil field operations have been shut-in or sharply curtailed, with transport routes choked off. The country's main export stream, Es Sider, had to be shut-in after a critical pipeline was bombed by government forces.

Even though the government has regained a number of important oil installations, mounting international sanctions aimed at depriving the current regime of revenue to prosecute the war have prompted almost all international oil companies to stop trade with the regime. In addition, tanker insurance fees to lift volumes are now prohibitive after the insurance market added Libya to its high-risk list of ports to avoid (see Freight).

The shut-in of Libyan, light, low-sulphur crude is having the biggest impact on European refiners, who take over 85% of the country's exports. In 2010, Libya exported 1.1mb/d to IEA countries, with the biggest buyer Italy at around 370 kb/d, followed by France at 210 kb/d, Germany at 145 kb/d and Spain at about 140 kb/d. However, refiners have been comparatively relaxed about the loss of supplies so far, in part because European refinery maintenance is peaking in March, taking around 600 kb/d of primary capacity off line.

Libyan crudes are prized for their high gasoline, low-sulphur diesel and jet fuel yields. Given tightening global market for middle distillates, concerns have centred on a potential longer-term shortfall of low-sulphur middle distillates. Already the loss of Libyan crude in Europe is having a wider impact on crack spreads for diesel and gas oil.

Libya's largest export stream at an average 340 kb/d in 2010 is Es Sider with an API of 37° and sulphur content of 0.44%. The country's Amna crude exports average just under 220 kb/d last year with an API gravity of 36° and sulphur of 0.17%. Algerian, North Sea, West African and Caspian crudes, such as Azeri Light, are the closest quality replacements. Saudi Arabia has moved quickly to replace the lost Libyan supplies by ramping up production and creating two new hybrid crudes to mimic the lighter, lower-sulphur Libyan grades. One new lighter replacement crude from Yanbu has been developed from blending Arab Super Light and Arab Light to make a crude with an API of 44° and a sulphur content of 0.5%, similar to Libya's El Shahara and Mellitah crudes. North Sea and Urals are the readiest short-haul alternatives to Libyan supply in the Mediterranean but Aramco has also been able to increase it short-haul supplies to the region by ramping up throughput to Yanbu on the Red Sea with around 36-hour delivery time to Sidi Kerir at the Sumed. However, volumes are uncertain, and the key test of the impact of the Libyan crisis will be an expected 1 mb/d hike in global crude runs in April as Atlantic Basin refinery maintenance winds down.

Around 6 mb of Arab Light are being shipped to Sumed storage in the Mediterranean, at least one tanker of Arab Light/Arab Extra Light was on its way to storage facilities in Northwest Europe and additional barrels are being sent to Okinawa in Japan.

Though Saudi/Libyan crude streams are an imperfect match, Aramco appears to be making every effort possible to compensate for the quality differences. The company has developed a lighter/sweeter crude blend to mirror more closely lost Libyan barrels by removing the Berri stream from the Arab Extra Light blend. The new special Arab Extra Light now has an API gravity of 41° and sulphur content of 0.7% compared with 39° API and 1.1% sulphur previously. Libyan Es Sider, the country's largest export stream, has an API of 37° and sulphur content of 0.44%. Saudi Aramco's other new, lighter replacement crude has been developed from blending Arab Super Light and Arab Light, with an API gravity of 44° and a sulphur content of 0.5%. Aramco has reportedly already sold one cargo of the new blend and plans to also place some of the grade closer to markets for late March and April.

Iraqi production rose in February by 20 kb/d to 2.68 mb/d, largely due to the resumption of production from the northern Kurdish region of the country. Total exports were up by about 60 kb/d, to 2.21 mb/d, with shipments of Kirkuk crude oil from the Turkish Mediterranean port of Ceyhan up by 75 kb/d to 485 kb/d. However an explosion on the pipeline in early March has currently halted export flows.

After being shut-in since September 2009, an estimated 60-70 kb/d of crude from Taq Taq, Tawke and Khormala fields in the Kurdish region was blended into the Kirkuk stream for export. However, it is unclear if the new export crudes will continue to flow in the coming months. A framework agreement between Baghdad and the Kurdish Regional Government (KRG) over payment of crude oil exports from the Kurdish region was drafted last month but not finalised. Moreover, an agreement over the broader issue of legality of the production sharing contracts signed between the KRG and international oil companies is still being hammered out and it is unclear if companies will continue to export the new crudes from the Kurdish region without a final agreement inked.

Exports of Basrah crude from the southern ports were off by just under 20 kb/d, to 1.71 mb/d but still well above 2010 average levels of around 1.5 mb/d following increased output from the Rumaila and Zubair joint-venture projects. Following in the footsteps of BP-PetroChina at Rumaila and ENI at Zubair in recent months, ExxonMobil hit a milestone in early March by attaining its target to raise production at its West Qurna Phase One project by 10% above the 244 kb/d production baseline. Once the higher production has been maintained for 30 days, ExxonMobil and its partner Shell will start recovering development costs. The partnership is tasked with raising production at the West Qurna field to a massive 2.83 mb/d from the project baseline output of just over 240 kb/d.

Output from the UAE averaged 2.48 mb/d last month, up 40 kb/d over a revised January estimate of 2.44 mb/d, and the highest level since reduced output targets were implemented over two years ago. Early indications are that the Emirates plan to boost output to 2.5 mb/d for both March and April. Abu Dhabi's state oil company Adnoc last week eased cuts to contract allocations for heavier Zakum, Upper Zakum and Umm Shaif grades in the wake of the Libyan crisis but, unusually, officially left contract allocations for distillate-rich Murban crude unchanged. That said, refiners report state-owned Adnoc is offering more Murban on the spot market, with Indian refiners picking up some of the extra barrels.

Kuwait also increased output last month, up 70 kb/d to 2.38 mb/d. Kuwait appears to have only limited spare capacity to increase output further in the short term, potentially by around 200 kb/d.

Iranian output last month was up by 20 kb/d to 3.68 mb/d. Ship brokers report that Iranian crude oil supplies held in floating storage rose for the third month running, in part due to unattractive price formulas, sanction-related payment problems and weaker demand for the poorer quality Iranian crude during the seasonal refinery maintenance period. Iranian floating storage rose by 6.5 mb, to 30.1 mb at end-February.

Angola's crude production fell by 80 kb/d, to 1.6 mb/d from an upward revised 1.68 mb/d in January. Angolan output has been running well below planned levels in recent months, with technical problems last month at the Chevron-operated Blocks 0 and 14 reducing supply by a combined 50 kb/d, while a further 30 kb/d was shut-in at Blocks 15 and 17. Loading schedules for March indicate exports will recover to over 1.7 mb/d in March before falling back again in April. The Greater Plutonio complex is scheduled for a complete shut-in in April while it undergoes extensive repair to its water injection system. Field maintenance work is also scheduled at the Total-operated Dalia system in April.

Nigerian February supply was off 80 kb/d, to around 2.16 mb/d, in part due to planned field maintenance work, which includes the Qua Iboe fields. Output is forecast to fall further in March due to scheduled work at the offshore Bonga field. However, April volumes should recover by a sharp 300 kb/d, which could help alleviate the shortage of similar quality Libyan grades.

At least on paper, Nigeria holds the promise of bringing online spare capacity over the next couple of months if needed. Much will depend on the political environment surrounding the upcoming presidential elections set for 9 April and the government's continued success in maintaining the fragile ceasefire accord with former Niger Delta militants. Past experience would suggest a resurgence in violence and possible knock-on effect on crude production during the election period, but so far a relative calm has prevailed. Increased investments by companies to reinstate shut-in production may also hinge on the passing of a compromise version of the controversial Petroleum Investment Bill ('PIB'), considered equitable to both the government and international oil companies operating in the country. The current administration of President Goodluck Jonathan has said it aims to pass the 'PIB' before the elections but there have been countless pronouncements over the past year that legislators would soon vote into law the new 'PIB', with odds now it will likely be delayed until after the April elections.

OPEC Crude Oil Spare Production Capacity Hovers Near 4 mb/d

The loss of Libyan crude supplies has concentrated the market's attention on the producer group's available spare production capacity. Not unexpectedly, industry estimates of OPEC's capacity vary widely. While higher OPEC production and a hiatus in capacity expansion has reduced effective spare capacity to around 4 mb/d, available supplies are still well above the sub 2 mb/d lows seen in 2008 and at mid-decade.

The IEA assesses current installed OPEC crude production capacity at just over 35 mb/d. We define spare capacity as oil that could theoretically be produced at the wellhead within 30 days and sustained at that level for 90 days. Installed capacity takes no account of short-term constraints such as maintenance or logistical issues. However, prevailing physical limitations on gas flaring and other technical issues are accounted for, with the result that our numbers aim to represent sustainable output potential, rather than short-term surge capacity.

Capacity estimates are updated periodically throughout the year, with a more exhaustive update done on a bi-annual basis in the Medium-Term Oil & Gas Markets report (MTOGM). Our capacity estimates are based on latest reliable estimates of field capability net of assumed mature field decline. While national and international companies regularly elaborate on the technical details of flagship new field developments, many are reticent to provide field-specific data on older facilities. The lack of transparency surrounding field operational details among many producers makes assessing precise capacity levels very difficult. (This is an issue not just limited to OPEC producers; some non-OPEC countries also suffer from the same opacity).

In an effort to provide a more realistic snapshot of current upstream supply flexibility, we calculate an estimated "effective spare capacity" measure, in addition to the headline spare capacity number. This excludes notional spare capacity in countries that we deem might struggle to increase production in the short term due to uncertainty over the technical state of apparently idled nameplate capacity, security issues or unrest in key producing or export areas. While other analysts prefer to simply cite existing production as de facto capacity for some of these countries, we prefer to show a range for spare capacity, which reflects the inherent uncertainty in this particularly opaque area of oil market accounting.

OPEC's February 'effective' spare capacity, which excludes Iraq, Nigeria, Venezuela and now Libya, is estimated at 4.08 mb/d, which is about 1 mb/d below the level implied by installed nameplate capacity. Saudi Arabia holds almost 80% of available capacity at 3.2 mb/d.

Looking forward, we see OPEC crude capacity increasing by just under 340 kb/d over the course of 2011, to 35.45 mb/d. However, almost all of the capacity increase reflects planned ramp up in new production started in 2010, with only several small projects in Nigeria expected online in 2011. As noted above, a more stable political and operating climate in both Nigeria and Iraq could potentially add a further 250 kb/d to 500 kb/d capacity in the second half of the year, but this is not presently included in our estimates.

Non-OPEC Overview

Non-OPEC oil supply rose 0.3 mb/d to 53.2 mb/d in February on the reinstatement of Alaskan output after pipeline-related shut-ins in January, and on higher estimated UK and FSU production. However, even as Alaskan production increased again, production shut-ins affected February output in Australia, Azerbaijan, Canada, Colombia, Indonesia, Norway and the UK.

Following the ousting of President Mubarak in February, the situation in Egypt appears to have calmed. While gas exports to Jordan and Israel have not yet resumed, following sabotage on the pipeline, oil production and operations remain unaffected. But February saw ongoing protests in many other countries in the wider North Africa/Middle East region, including non-OPEC oil producers Bahrain, Oman and Yemen, even though no shut-ins to oil production in any of these countries have been reported. Although dwarfed by their OPEC neighbours, collective non-OPEC production by the six major producers (the four above, plus Syria and Tunisia) in North Africa/Middle East averaged 2.5 mb/d in 2010.

Looked at in the context of ongoing Libyan oil supply disruption, overall non-OPEC supply appears likely to remain broadly flat through mid-year, with seasonal field maintenance offsetting a typical mid-year increase in Brazilian ethanol supplies. Intra-year growth from non-OPEC looks likely to be loaded towards the end of 2011, when new Brazilian deepwater supply is brought online. Implicitly, we assume that non-OPEC producers hold no spare capacity, discounting volumes shut-in for technical or weather-related issues. Thus, in the case of a sustained production shut-in in Libya, there appears to be little scope for a surge in output by non-OPEC producers with similar high-quality crude grades, such as in the Caspian or North Sea. Nonetheless, 2011 will see gross additions due to new field start-ups or ongoing ramp-up at a number of key producers (see table). These add up to around 780 kb/d of mixed quality supply.

After Strong 2010, Global Biofuels Supply Growth to Slow in 2011

Despite high oil prices and a small baseline revision, the global biofuels supply outlook looks increasingly tenuous with surging food prices. Global output should expand by 160 kb/d to 2.0 mb/d in 2011, but this is a slower pace than the 250 kb/d increase estimated for 2010. Moreover, while many producers and processes remain competitive, regional policy developments, demand uncertainty and persistent overcapacity, particularly in the biodiesel sector, may limit production gains.

In the US, where corn prices have soared to over $7/bushel, producers still enjoy acceptable margins with rising ethanol values, low natural gas prices and by-product revenues supporting production at 900 kb/d for January and February. Still, weekly output declined through much of February. Moreover, Congress continues to discuss limits to the 45 cent/gallon blenders' tax credit due to expire at end-2011, clouding investment prospects. The approval of a 15% ethanol blend for post-2000 cars in January has raised demand potential, and the EPA has signalled it would finalise labelling and registration this spring. Yet, other logistical hurdles suggest that a full roll-out may occur over a matter of years rather than months.

In Germany, ethanol demand prospects have soured with the introduction of a 10% blend designed to meet a 2011 government target of 6.25% for all petrol sold. Consumers have avoided the new blend, favouring more expensive E5 or regular gasoline, largely out of perceived fears of engine damage. As such, suppliers have signalled reluctance to advance the roll-out. Yet, the government has insisted the blend introduction would continue, bolstered by an expanded information campaign to assuage consumer concerns.

In Brazil, rising sugar prices, amid seasonally low production, pushed hydrous ethanol prices above the point of competitiveness (70%) versus gasoline in many regions. Total ethanol consumption (hydrous and anhydrous) accounted for 51% of gasoline demand in December, down from an average of 54% during the prior six months. With producers likely to maximise sugar versus ethanol production in 2011, ethanol balances should remain tight as total gasoline consumption increases by 5.1% year-on-year.

Finally, Neste started shipping renewable diesel from its new 15 kb/d plant in Singapore - the world's largest. With palm oil prices near record highs and biodiesel demand weak in Asia due to relatively few mandates, such a capacity addition may further weaken regional margins. Still, demand may yet get a boost. Malaysia has signalled that it will follow through with plans to implement a 5% biodiesel mandate in June coupled with subsidies to keep biodiesel level with diesel prices at the pump.

Non-OPEC supply estimates for 2010 are left unchanged at 52.8 mb/d, while the 2011 estimate is adjusted 0.1 mb/d higher to 53.6 mb/d on robust recent Canadian production. Annual growth is thus raised to 0.8 mb/d in 2011, from 0.7 mb/d estimated in last month's report and the 1.1 mb/d growth seen in 2010. Incremental output is expected from Latin America (+305 kb/d), China (+170 kb/d), the FSU (+150 kb/d) and global biofuels (+160 kb/d), while decline is most pronounced in OECD Europe (-90 kb/d) and Other Asia (-70 kb/d).


North America

US - February Alaska actual, others estimated:  Preliminary data indicate that US total oil supply picked up by 190 kb/d in February, to just under 8 mb/d, as Alaskan output returned to normal. January had seen oil production in Alaska fall by 170 kb/d as a pipeline leak shut-in production. February also saw the start-up of the Nikaitchuq field in Alaska, operated by ENI, which will have a peak capacity of 30 kb/d.

In late February, the US offshore regulator, the Bureau for Ocean Energy Management (BOEM) issued its first new deepwater drilling permit for the Gulf of Mexico since a previous drilling moratorium was lifted on 12 October last year. This was widely welcomed by industry, as was the hint by BOEM that other, pending, permits will follow in "weeks and months to come". Industry and some politicians are clamouring for a resumption of deepwater activity, while the BOEM has been tasked with ensuring offshore activities are more closely monitored. One new requirement by those requesting drilling permits - the need to submit detailed plans in the case of an eventual oil spill - is made easier to fulfil now that there are two competing systems in place. One is based on plans put forward by Helix Energy Solutions, part of the group which supplied some of the key ships used in the Macondo relief effort. The other is the Marine Well Containment Company (MWCC), a new outfit set up by a group of major oil companies active in the Gulf and led by ExxonMobil.

We maintain our view that existing delays to projects in the US Gulf will cause 2011 production to be around 100 kb/d lower than previously assumed. A combination of high oil prices, the highlighting of oil markets' sensitivity to the supply disruption in Libya and the need to create jobs in the US mean that there is intense pressure to resume drilling activity in the US Gulf of Mexico. Thus there remains upside potential to US oil production, if permitting were to accelerate and lead to a resumption of activities. We see production in the Gulf remaining relatively flat over the course of this year, averaging 1.5 mb/d, down from 1.65 mb/d in 2010. BP announced maintenance at its huge 250 kb/d Thunder Horse complex around March, which will likely cause a brief dip in regional output.

Average total US production estimates for 2010 and 2011 are left unchanged, with production seen at 7.8 mb/d in both years. Lower Alaskan, Californian and Gulf of Mexico production levels are offset by higher Texan and other Lower-48 states' onshore production, as well as higher NGL and other liquids.

Canada - Newfoundland January actual, others December actual:  Canadian oil supply remained curtailed in January and February, averaging 3.4 mb/d, as CNRL's 110 kb/d Horizon upgrader stayed offline following a fire. Two of the four cokers in the facility are only lightly damaged and are assumed to resume production in 2Q11. The other two cokers will reportedly restart in the third quarter. In addition, Husky saw nearly half of its capacity at an 82 kb/d upgrader shut-in in early February, also due to a fire. November's total Canadian production high of 3.6 mb/d was however confirmed, and preliminary data indicate that output stayed similarly high in December. Upward revisions of 150 kb/d to December stemmed from higher-than-expected NGL, conventional crude and syncrude production. 2Q11 is expected to see production dip further, as seasonal maintenance at oil sands facilities takes place. But 3Q11 and 4Q11 output will see output gains. 2010 oil production averaged 3.37 mb/d, while 2011 output is revised up by 100 kb/d to 3.44 mb/d on stronger-than-expected recent production and evidence that new oil sands projects are proceeding apace.

Mexico - January actual:  Mexican oil production in January was reported at just under 3 mb/d, its highest since February 2010, and 35 kb/d higher than expected. Production from the large Ku-Maloob-Zaap (KMZ) and Cantarell fields was steady month-on-month in February, at 840 kb/d and 450 kb/d respectively, while NGL output picked up slightly. National oil company Pemex announced it would resume deepwater drilling near the maritime border with the US, in the Perdido Belt. This is possible now that the recently formed National Hydrocarbons Commission (CNH) has released new regulations, requiring a tightening of safety procedures and a financial plan to cover the cost of any spill.

At the same time, however, Pemex announced a dramatic planned cut-back in drilling, especially onshore at the complex Chicontepec oil field and the Burgos gas field. Pemex nonetheless expects a slight rise in crude production in 2011, to 2.63 mb/d, from 2010 average output of 2.58 mb/d. Our own estimates see a further decline, if significantly slower than in previous years, to 2.56 mb/d in 2011. NGL production averages another 380 kb/d in both years.

North Sea

Norway - December actual, January provisional:  Norwegian oil production averaged 2.24 mb/d in January and February, a rise from December's 2.16 mb/d and on average 65 kb/d higher than expected. The small 10 kb/d Trym field started production in February, adding to recently online Gjøa (50 kb/d capacity), Vega (25 kb/d) and Morvin (35 kb/d). 2011 should also see the start-up of the Oselvar (13 kb/d), Yme (40 kb/d) and Skarv (80 kb/d) fields. Estimated 2010 Norwegian oil production is left unchanged at 2.15 mb/d, expected to stay at the same level in 2011 as growth from new fields offsets decline and with some ongoing problems at older fields.

UK - December actual:  Following a dip to 1.25 mb/d in January, February production in the UK is expected to pick up again to 1.33 mb/d. December output is revised down 45 kb/d to 1.32 mb/d. The Gryphon FPSO was taken offline in February after storm damage, and will reportedly be down for several months. The Gryphon field produced an average 15 kb/d in 2010. The Schiehallion field continues to suffer problems, with production averaging only 5 kb/d in June-November 2010, compared to an average 35 kb/d in the first five months of last year and 60 kb/d in April 2010. We expect production to return to more normal levels around mid-year. 2010 UK oil production is expected to average 1.37 mb/d, while downward revisions to 1Q11 result in a net adjustment of -15 kb/d to the 2011 forecast, and output is now expected to decline to 1.30 mb/d.


Australia - December actual:  Australian production, hit successively by cyclones in recent months, fell to an estimated 415 kb/d in February. In addition, the Cossack field was shut-in for three months, while its FPSO is replaced, reportedly cutting output by 35 kb/d. From a depressed estimated average of 465 kb/d in 1H11, production is expected to recover to an average 560 kb/d in the second half of the year, as production facilities return to normal operations and output at the new Pyrenees and Van Gogh fields ramps-up. The delayed Montara field is now expected to come onstream in 3Q11, adding 35 kb/d capacity. Annual Australian oil production is expected to remain steady at 515 kb/d in 2010 and 2011.

Former Soviet Union (FSU)

Russia - January actual, February provisional:  While January production levels were unrevised at 10.54 mb/d, Russian production in February was 45 kb/d higher than expected, at 10.56 mb/d, its highest since October 2010, when output reached an all-time post-Soviet high. January saw production at Rosneft's large Vankor field rise to 280 kb/d, its first increase after very steady production at an average 265 kb/d in 2H10. The field came onstream two years ago and is around half-way towards reaching peak capacity of 500 kb/d in the course of 2014, though complaints about the high tax burden had prompted threats by Rosneft to slow development. 2010 Russian oil production averaged 10.45 mb/d, forecast to rise to an average 10.51 mb/d in 2011.

Following January's announcement of BP-Rosneft's tie-up (see BP-Rosneft Deal Opens Up Arctic and Thaws Relations with IOCs? in report dated 10 February 2011), February saw Total buying into Novatek, hoping to reach a 20% stake by 2014. Combined with its share in the Shtokman project, this makes Total the second-largest foreign investor in Russia, behind BP. The Shtokman project meanwhile, saw its final investment decision (FID) postponed yet again.

Azerbaijan - December actual:  In December, Azerbaijani production fell a sharp 125 kb/d to 905 kb/d due to problems at the Chirag field, part of the offshore Azeri-Chirag-Guneshli (ACG) complex. The field reportedly remained at least partly shut-in in January and February. Azerbaijan's 2011 oil production is expected to average 1.06 mb/d, only marginally higher than in 2010.

FSU net oil exports fell to 9.5 mb/d in January, 140 kb/d below December's downward-revised value. This fall was led by a 310 kb/d decrease in crude oil, total shipments of which amounted to 6.5 mb/d in January. Seaborne cargoes of crude oil fell by 500 kb/d, likely explained by a sharp hike in the Urals-linked Russian crude export duty to $318/tonne. Consequently Baltic loadings fell by an acute 240 kb/d, largely due to lower exports at Primorsk. Loadings there are likely to remain low throughout 1Q11 due to ice disruption. Additionally, liftings from Ceyhan (the end-point of the BTC pipeline) fell 150 kb/d on the month after production problems in Azerbaijan. These falls were partially offset by the start-up of the ESPO spur to China which pumped 310 kb/d in January. However, seaborne cargoes of ESPO from Kozmino fell to 285 kb/d (-40 kb/d m-o-m), their lowest level since February 2010. This is expected to be a short-term phenomenon, with the Kozmino loading schedule showing an uptick towards the end of 1Q11. An historical revision has been made to crude oil exported by Transneft from December 2009 onwards; monthly quantities have been raised by 280 kb/d on average. This revision amounts to a reclassification of non-Transneft volumes and does not affect total crude exports.

Exports of products to non-FSU destinations increased by 180 kb/d in January led by increases in gasoil and 'other products'. Shipments of gasoil increased seasonally by 120 kb/d whilst the rise in 'other products' was led by gasoline. Russian volumes were hiked after the Kremlin passed a new law prohibiting the domestic sale of gasoline not complying with the Euro 3 (80-octane) standard. Although most Russian refiners already produce gasoline according to this specification, it is likely that the increase results from tank emptying and that these exports headed for Africa or Asia where many countries still use inferior gasoline.

In late January the much delayed Ust-Luga terminal on the Gulf of Finland shipped its first cargo of fuel oil. This terminal is the latest step in Russia's moves to reduce reliance on transit states, and is expected to divert Russian cargoes away from ports in Latvia, Estonia and Lithuania. Additionally, at the end of the year, crude is expected to be shipped from the port upon completion of the BPS-2 pipeline.

Other Non-OPEC

Indonesia - December actual:  Indonesian oil production levels were revised down sharply in December (-35 kb/d) and in January/February (-60 kb/d each), on reports of heavy rains curbing production. Early-year oil supply is now seen around 900 kb/d. Lower 1Q11 output and reports that ramp-up at the large Banyu Urip (Cepu) field will be further delayed, result in 2011 average production being adjusted down by 20 kb/d, to 920 kb/d, a decline from 975 kb/d in 2010.

Brazil - December actual:  Brazilian oil production reached a new high of 2.27 mb/d in December, up from 2.18 mb/d in November and around 25 kb/d higher than expected. In January/February, production was curbed slightly after a fire on the offshore Cherne 2 platform, but normal operations have now resumed. The higher production is carried through the forecast, resulting in estimated 2011 oil supply of 2.32 mb/d. This is up from 2.14 mb/d in 2010, as new offshore fields come online, including Chinook/Peregrino and Marlim Sul 3, and existing ones, including Lula (ex-Tupi) increase production. Brazil remains the single-largest source of non-OPEC supply growth in 2011, with expected incremental output of 180 kb/d.

Colombia - December actual, January preliminary:  Colombian oil production continues to rise, and reached new highs of 830 kb/d in December and 840 kb/d in January. In February and early March, the Transandino and Caño Limon crude pipelines briefly halted flows after bombings. Both are key export pipelines taking crude from Colombia's oil-producing hinterland to coastal export terminals. One of the reasons Colombia has been able to boost oil production in recent years has been because of an improved security situation. Colombian production is forecast to rise from 790 kb/d in 2010 to 905 kb/d in 2011.

OECD Stocks


  • OECD industry inventories rose by 32.0 mb to 2 695 mb in January, broadly in line with the five-year average 40.2 mb stock-build. Sharp seasonal gains in gasoline and middle distillates drove the increase, while a stronger-than-average decline in 'other products' provided partial offset.
  • OECD forward demand cover rose to 58.2 days in January, 2.4 days above the five-year average, aided by seasonal restocking. Stock cover increased from 57.4 days in December, which was the lowest level since November 2008.
  • However, OECD stocks reversed the trend in February and preliminary data point to a 43.4 mb draw, driven by 'other products' and middle distillates. This monthly drop was sharper than the 25.4 mb five-year average decline observed during 2006-2010.
  • Short-term oil floating storage rose to 62 mb in February, from 55 mb in January, driven by increases in the Middle East Gulf and Northwest Europe. Crude floating storage rose by 5 mb to 40 mb, while offshore products edged 1 mb higher to 21.5 mb.

OECD Inventories at End-January and Revisions to Preliminary Data

Commercial oil inventories in the OECD countries rose by 32.0 mb to 2 695 mb in January 2011. Sharp builds in gasoline, middle distillates and 'other oils' raised inventory levels, but a stronger-than-seasonal draw in 'other products' moderated the increase. Geographically, the largest builds occurred in Europe, where distillates flourished as the contango structure in ICE gasoil futures provided better incentives for storage. Nevertheless, the overall January gain was lower than the five-year average 40.2 mb stock-build and the OECD inventory surplus to the five-year average levels narrowed from 25.0 mb in December to 16.9 mb in January. Yet, a 13.0 mb increase in distillate holdings widened the surplus for those products, especially in Europe. 'Other oils' surged by 10.4 mb from close to average levels to the highest January readings since 1998 and thus increased their surplus to the average to 11.8 mb.

January restocking and lower demand estimates for the following three months lifted OECD forward cover to 58.2 days, 2.4 days above the five-year average. Fuel oil cover gained 2.7 days as its demand is expected to decline, while a sharp drop in 'other product' inventories reduced forward demand cover by 1.2 days. Stock cover rose from 57.4 days in December, which was the lowest level in the past two years.

The January stock-build partially mitigated a sharper-than-seasonal 79.0 mb decline in OECD inventories in 4Q10, exacerbated by downward revision to December OECD stocks. Upon receipt of more complete OECD data, total oil holdings were revised 5.2 mb lower in December, thus implying a stock-draw of 61.5 mb. Nevertheless, OECD stocks contracted by 1.4 mb in 2010 as a whole, with declines in crude oil, gasoline and distillates outweighing gains in 'other oils' and 'other products'. However, our global supply and demand balance implies a 200 mb stock-draw in 2010. With a negligible portion coming from the OECD and an estimated 66 mb from offshore stocks and oil in transit, the remaining 133 mb suggest a strong unaccounted for degree of non-OECD destocking and/or statistical difference.

OECD inventories reversed their course in February as unrest in Libya, refinery maintenance and stronger demand ate into stock holdings. Preliminary data point to a precipitous 43.4 mb draw, much sharper than the 25.4 mb five-year average decline. In contrast with a 9.5 mb build seen over the past five years, crude oil stocks fell by 2.1 mb. The onset of unrest in Libya in February halted a portion of light sweet crude supplies to Europe and refiners struggled to source future supplies of similar quality crude elsewhere. Seasonal refinery maintenance certainly eased initial pressure, but drained product stocks, especially 'other products' and distillates. Yet, oil inventories in short-term floating storage grew by 8 mb as crude in the Middle East Gulf, most probably Iranian, increased. Products moved offshore in Northwest Europe and the US Gulf, but some barrels were offloaded in the Mediterranean and Africa. Overall, crude floating storage increased from 35 mb in January to 40 mb in February, while products edged 1 mb higher to 21.5 mb.

Analysis of Recent OECD Industry Stock Changes

OECD North America

Commercial oil inventories in North America rose by 9.6 mb in January to 1 333 mb, less than the five-year average 16.2 mb stock-build. Surging gasoline stocks drove this monthly gain, but additions to crude and 'other oils' (consisting of NGLs and feedstocks) also contributed. Meanwhile, a 22.5 mb draw in 'other products' provided partial offset.

In Mexico, oil stocks fell by 3.3 mb in January, driven by a further draw in crude oil. Three sharp consecutive monthly declines shaved crude oil inventories by a third, to 16.9 mb in January. Meanwhile in the US, oil stocks increased by 12.9 mb in January, in line with the five-year average levels. Continued cold January weather with strong snowstorms led to a draw in 'other products', especially propane, which fell by a sharper-than-seasonal 23.7 mb. This draw balanced a 20.1 mb gain in gasoline and small builds in middle distillates and fuel oil. A rebound in seaborne imports to the US Gulf lifted crude oil 9.3 mb higher and 'other oils' added a further 5.7 mb.

US restocking dissipated in February as weekly data from the US EIA show US inventories dropped by a sharp 29.2 mb. Commercial crude inventories in the US rose by 3.6 mb in February, as elevated imports of Canadian crude into the landlocked US Midwest continued at a time when regional refiners cut runs. Stocks at Cushing, Oklahoma, the delivery point of NYMEX WTI futures, broke one record after another and ended at 40.2 mb in the week to 4 March. Persistently high crude oil stocks in the US Midwest, and Cushing in particular, have severely pressured WTI prices, which have been trading at a discount to Brent since mid-August 2010.

Refinery maintenance, lower imports and marginally stronger demand sent products 32.5 mb lower in February, with 'other products', gasoline and middle distillates posting the largest declines. Gasoline stocks reached all time highs by mid-February, but subsequent stronger transport fuel demand around the President's Day holiday curtailed 7.3 mb of gasoline stocks by end-month. Diesel stocks drew sharply by 6.2 mb, contributing to a 9.6 mb reduction in middle distillates, while industry holdings of heating oil declined by 1.1 mb. Meanwhile, the US Department of Energy sold almost 1 mb of heating oil from the Northeast Home Heating Oil Reserve as part of its plan to convert existing stocks into ultra-low-sulphur product.

OECD Europe

Industry oil stocks in OECD Europe grew by 20.0 mb to 967 mb in January, broadly in line with the 16.9 mb seasonal increase. Crude inventories rose by 4.2 mb, following a 3.8 mb gain in 4Q10. Crude stocks stood at 327 mb or 26.9 days of forward crude runs cover in January. Meanwhile, stronger-than-seasonal build in distillates lifted total products by 15.1 mb to only 0.4 mb below their five-year average.

Gasoline inventories rose by less than the seasonal average in 4Q10 due to stronger exports, especially to the Middle East. A similarly mild January build (+1.3 mb) brought gasoline stocks out of the five-year range to their lowest January level on record. Seasonal distillate restocking brought January levels 11.8 mb higher, following a counter-seasonal winter weather-related draw in the previous month. German end-user heating oil stocks stood at 57% of capacity in December, but January data have been delayed. We estimate that relatively high heating oil prices discouraged consumer buying and they most probably continued running down their accumulated inventories.

February preliminary data from Euroilstock point to an 8.6 mb stockdraw in the EU-15 and Norway, with the sharpest declines in crude and fuel oil. Fuel oil stocks fell by 3.6 mb and stocks held in Northwest European independent storage also dropped significantly as fuel oil arbitrage provided incentives to ship the product to Asia-Pacific. Crude oil stocks fell by 4.8 mb, declining in the Netherlands, Scandinavia, Spain and the UK. Italian crude inventories rose in February, despite the uncertainty about crude supplies from Libya due to political unrest.

It is worth noting the relative import dependence on Libyan crude for key European countries, and compare this with forward stock cover based on anticipated refinery crude runs accounting for the maintenance. Greece and Austria look to have ample stocks at present to fill the gap left by shuttered Libyan supplies, whereas refiners in Switzerland, Portugal, France and Spain look rather more exposed. Yet, the quality breakdown of commercial crude oil stocks is unknown and replacing higher quality light sweet Libyan crude poses concerns, especially to refiners maximising transport fuel output.

OECD Pacific

Industry oil stocks in the Pacific rose by 2.4 mb to 395 mb in January, driven by stronger-than-seasonal increases in 'other oils' and 'other products'. Over the past five years, commercial oil stocks rose by 7.1 mb on average. This year, higher refinery runs reduced crude oil holdings by 5.8 mb, dropping below the five-year range. 'Other oils', consisting of NGLs and feedstocks, built strongly to the top of the five-year average range in January.

Oil product stocks rose by 4.0 mb on stronger builds of 'other products'. Gasoline and distillates rose month-on-month, albeit by less than the seasonal average, following 4Q10 declines due to higher product exports to neighbouring countries.

Japanese industry inventories fell by 5.6 mb in February, according to weekly data from the Petroleum Association of Japan (PAJ). Crude oil stocks edged 0.9 mb lower, while declines in all product categories bar kerosene curbed products by 3.4 mb. Kerosene, a primary heating fuel in Japan, rose counter-seasonally by 0.6 mb, buffering tumbling gasoil, gasoline and jet fuel stocks. Meanwhile, in a response to the devastating earthquake and tsunami that hit Japan on 11 March, the country's government has temporarily lowered industry stockholding obligations by 3 days for a month starting 14 March (see Japan's Refineries Hit by Earthquakes and Tsunami).

Recent Developments in China and Singapore Stocks

According to China Oil, Gas & Petrochemicals (China OGP), Chinese commercial oil inventories rose by the equivalent of 18.0 mb, to approximately 345 mb in January (data are reported in terms of percentage stock change). Soaring imports drove commercial crude oil stocks 2.5% (5.0 mb) higher. Product inventories rose by around 13.0 mb, driven by a 25% (13.6 mb) gasoil increase due to restocking as domestic diesel shortages eased at end-2010. In addition, gasoline stocks fell by 1.4% (0.8 mb) and kerosene holdings increased by 1.3% (0.2 mb). Meanwhile, Chinese strategic petroleum reserves (SPR) reportedly amount to 30 days' consumption with crude oil accounting for 75%.

Singapore onshore inventories grew by 3.1 mb in February, led by sharp builds in middle distillate stocks. Light distillate and fuel oil stocks rose by 0.3 mb and 0.5 mb, respectively. Yet, robust domestic runs and stronger imports from neighbouring countries, mainly from Korea and India, lifted middle distillate inventories by 2.2 mb.



  • Oil futures prices have tracked the escalating political unrest in the Middle East and North Africa, with benchmark crudes trading $15-20/bbl above end-2010 levels. While political risks appear to be a prominent feature of futures market for now, the shut-in of more than 1 mb/d of Libyan crude as the country teeters on the brink of civil war provides more immediate physical underpinnings. Oil prices have gyrated by an average $3/bbl on any given day, but by early March benchmark futures Brent was last trading just shy of $114/bbl while WTI was around $100/bbl at writing. 
  • Spot prices for benchmark crudes rose on average between $7.00-7.50/bbl in February, and by early March had jumped by a further $10-15/bbl in the wake of the Libyan crisis. The loss of light, low-sulphur Libyan oil supplies to the market is having the most pronounced impact on sweet/sour price spreads. However, so far, the extensive refinery maintenance schedules for February and March have muted the impact of the lost barrels.
  • With surging crude prices outstripping product price gains at end-February, refining margins were weaker for most benchmark crudes in the Atlantic basin but mixed in the Asia-Pacific region. In general, margins for complex refineries fell the most, as light and middle distillates prices lagged the crude gains. Simple refineries fell less as fuel oil cracks were supported by strong Asian demand.
  • Crude oil tanker rates experienced resurgence across all benchmark routes in February on increased demand from Asia, weather-related disruptions in Northwest Europe as well as the Libyan crisis. The VLCC Middle East Gulf - Japan route surged from $10/mt to $18/mt following a post-Chinese New Year holiday demand increase that considerably tightened available tonnage East of Suez.

Market Overview

Escalating political unrest in the Middle East and North Africa has injected a high degree of volatility in futures markets since the start of the year, with benchmark crudes trading $15-20/bbl above end-2010 levels. While political risk issues appear to be a prominent feature of futures market for now, the shut-in of more than 1 mb/d of Libyan crude as the country teeters on the brink of civil war provides a more immediate physical underpinning.

Japan's catastrophic earthquake and tsunami had the immediate impact of countering upward price pressure from Libya. The natural disaster is reverberating across the energy chain, including the shut-in of around one-third of the country's refineries. The loss of refining capacity will reduce crude needs near term and replacing lost nuclear power generation is expected to add upward pressure on low-sulphur fuel oil supplies (see Japan Nuclear Outages Point to Increased Fuel Switching).

While prices have gyrated by an average $3/bbl on any given day, by early March benchmark futures prices were trading $10-15/bbl above average February levels. Brent was last trading just shy of $114/bbl while WTI was around $100/bbl at press time.

Since the start of the Libyan revolt on 21 February, market sentiment has ebbed and flowed with the days' news cycle on unfolding events between government forces and the opposition groups. Accurate information on the country's oil production operations has been severely limited following the mass evacuation of foreign workers, lack of communication channels and conflicting and incomplete data on port and export activity. Latest information available indicates Libyan crude production appears to be running below 500 kb/d, or a loss of more than 1 mb/d from January's estimated output of 1.58 mb/d.

International efforts to isolate the current regime politically and financially have also led to new sanctions that have severely constrained crude and product flows in and out of the country. A full-blown civil war could mean a permanent production shut-in for an indefinite period (see Libya's Uprising Sees Oil Supplies Dwindle). European refiners nonetheless indicate that there is ample crude supply in the market until at least the end of March.

Large-scale seasonal maintenance at refineries in Europe and the US has limited demand for prompt crude supplies. The loss of light, low-sulphur Libyan crude oil supplies to the market is having the biggest impact on Mediterranean refiners, which process 85% of the country's crude. While the sweet-sour spreads are widening as expected, it remains to be seen whether alternative supplies can match an expected sharp run up in global crude runs in April. Led by Saudi Arabia, OPEC has informally increased production to replace Libyan crude, while making efforts to offset the quality mismatch.  Saudi Arabia has ramped up output to over 9 mb/d and has introduced two new crude blends closer in characteristics to Libyan grades than their normal export blends.

However, reflecting market uncertainty on the severity and duration of supply outages in Libya, the forward price curve for WTI M1-M12 has come in sharply, narrowing from just over $12.40/bbl in mid-February to just  $1.95/bbl in the second week of March.  The M1-M12 Brent contract moved out of contango and into backwardation again at the onset of hostilities in Libya, averaging around $1.60/bbl in the closing days of February and a stronger $2.10 in the first ten days of March.

Markets will be closely watching the international community as it weighs its options for dealing with the crisis in coming days and weeks. At the same time, focus will also be on the impact of the Japanese crisis on the economy and financial markets.

Futures Markets

Open interest in WTI futures contracts reached yet another record high level in February, fuelled by the Libyan crisis and regional unrest. Open interest increased in February in both futures-only and futures and futures-equivalent options (thereafter combined) to 1.57 million and 2.94 million contracts, respectively. Producers increased their net short position during February; they held 29.7% of the short and 13.9% of the long contracts in WTI futures-only contracts. Swap dealers, who accounted for 28.8% and 33.5% of the open interest on the long side and short side, respectively, remained net short.

Managed money traders' net long exposure increased by more than 50% in February to an all-time high of 268 622 futures contracts.  The market share of managed money traders has risen from 26.6% to 29.8% on the long side and has fallen from 15.1% to 12.7% on the short side. They were also very active in the options market especially immediately after the start of the Libyan crisis. With the expectation of higher oil prices, they increased their outright delta-adjusted gross long position by 29%. There was also some short covering by managed money traders as reflected by a decline of 63% of gross short contracts.  Other non-commercials, who accounted for 20.5% of open interest on the long side and 20.3% on the short side, reinforced a recent trend of dwindling net short by adding 19 400 gross long contracts.

Meanwhile, open interest decreased slightly in NYMEX RBOB futures while combined open interest increased by 2 900 contracts. In February, open interest in NYMEX heating oil declined by 1.9% to 300 541 contracts while open interest in natural gas markets increased by close to 18.1% to 982 208 contracts.

Index investors continued to increase their exposure in commodities in January 2010. They added another $4.8 billion to the WTI Light Sweet Crude Oil market in January 2010, which rose to an all-time high of 663 000 futures equivalent contracts, or $62.2 billion in notional value.

Volatility: Not Unique to Exchange-Traded Commodities

Fluctuations in commodity prices, particularly in crude oil prices, have been hotly debated in recent years. Some argue that underlying market fundamentals, especially the unexpectedly strong demand shock attributed to continued strong economic growth in Asia and other emerging economies, is the main reason for the resurgence of commodity prices and for the fluctuations in prices since 2004. Others argue that speculative activity in commodity derivatives markets is the main force behind surging commodity prices. They further claim that commodities have become a new asset class in investors' portfolios, and prices are now more affected by macroeconomic news rather than by commodity-specific physical market conditions.

Policy makers have responded with a slew of proposals to control futures market activity.  Aside from the questions that such measures raise in terms of market function, liquidity, price discovery and ultimately price volatility, they are premised on a view that commodities traded on futures exchanges are intrinsically more volatile than those which are not. This is problematic.

The Onion Futures Act, which has prohibited the trading of onion futures in the US ever since it was passed in 1958, is a good example illustrating why volatility cannot be reduced by merely prohibiting some traders or all futures contracts. Empirical research suggests that prices and volatility in onion markets were higher post-Act than before the Act's implementation. A more recent example can be found in India, which banned financial trading in most agricultural products - yet found out that prices continued to rise in 2008.

In order to compare price movements and volatility between non-exchange-traded commodities and crude oil prices, we constructed a weekly spot price series for an equally weighted basket of non-exchange-traded commodities. By focusing on non-exchange-traded commodities, we seek to ensure that the fluctuations of the basket's price do not stem from changes in the activities of financial institutions in commodity futures markets. Our composite basket includes seven commodities: rice, coal, manganese, rhodium, cadmium, cobalt and tungsten. Although futures exist on rough rice and Appalachian coal, the CFTC's Commitments of Traders reports show that the open interest and the number of traders in these contracts are small, therefore we also include these commodities in our index to allow a more diversified index across commodities.

A visual comparison of the non-exchange-traded commodity price index, as well as crude oil price series, supports the notion that, starting in 2003 and more strongly after 2004, a demand shock pushed upward the prices of most commodities. A large change in the growth rate of the index is visible, with sustained growth and few price decreases from 2003 to August 2008. More importantly, prices for non-exchange-traded commodities rose faster than crude oil prices between 2006 and 2008. The plot also shows that commodity prices (of both crude oil and non-exchange-traded commodities) declined sharply amid the economic contraction of autumn 2008 and stabilised after 2009. Interestingly, one could argue that the fall in crude prices to below $40/bbl in early 2009 was something of an under-shoot, and that subsequent recovery has been more in line with the strengthening evident across commodities in light of the economic recovery. Across the commodities, we see that some non-exchange-traded commodities prices have risen more than the crude oil price. While rhodium and cadmium experienced more than a 2000% change in prices when measured in percent change between the highest and lowest observed prices between 2000 and 2010, crude oil prices rose by 663% on the same basis.

In terms of volatility, measured by the one-year moving average standard deviation of prices, the plot also shows that volatility in both crude oil prices and non-exchange-traded commodities rose sharply after 2006.

Non-exchange-traded commodities' index volatility experienced a large spike in early 2007 while crude oil prices were still relatively stable. That being said, unusually high volatility in commodity markets post-2007 does not appear unique to crude oil traded on exchanges. Other commodities that are not traded in exchanges experienced similar fluctuations and price surges in the second part of the 2000s. Moreover, volatility declined for both crude and non exchange-traded commodities once again through 2010.  This is not to say that the trading of futures and derivatives contracts on exchanges has no impact on price levels and volatility. But it does suggest that a more holistic and refined set of policy responses than simply 'driving out the speculator' may be needed to achieve more stable and predictable markets.

Spot Crude Markets

Spot prices for benchmark crudes rose on average between $7.00-7.50/bbl in February but by early March had jumped by a further $10-15/bbl in the wake of the Libyan crisis. The loss of light, low-sulphur Libyan oil supplies to the market is having the most pronounced impact on sweet/sour price spreads. However, so far, the extensive refinery maintenance scheduled for February and March has muted the impact of the lost barrels, with March needs largely covered before the onset of the crisis. European refiners in the Mediterranean take 85% of Libya's crude, and the near total shut-down will alter normal trade patterns in coming weeks and months as European refiners adjust their crude slate to adapt to fewer sweet cargoes. Mediterranean refiners are looking to secure similar grades such as Nigerian Qua Iboe or Azeri Light, though exports of the latter are expected to be down almost 15% in April from March levels due to field production problems.

The price spread in the Mediterranean for Nigerian Bonny Light - Russian Urals widened to over $6/bbl by the second week of March compared to around $4.75/bbl before events hotted up in Libya. While only very limited volumes of Libyan crude head east of Suez, with China the main buyer, there was a knock-on effect for the sweet/sour spread in the Asia-Pacific region as lighter, low-sulphur barrels became dearer. The price spread for very light, low-sulphur Malaysian Tapis versus heavier, sourer Dubai jumped to around $11/bbl in the first 10 days of March compared with a pre-crisis February average of about $7.25/bbl.

While the sweet-sour spreads are widening as expected, European refiners are reporting that there is no shortage of crude on offer but are barrel picking for the most attractively priced crudes. Refiners are now buying April/May supplies and there appears to be an extra 300 kb/d available from Nigeria, which is similar in quality to the lost Libyan barrels. Nigeria had reduced volumes of Bonga and Qua Iboe crude available in February and March due to field maintenance work but output will be restored for April liftings. However, there is growing concern over the flow of Russian exports of both crude and products after dozens of vessels were trapped in ice at Russian ports this past week (see Non-OPEC, FSU Exports).

Saudi Aramco also moved quickly to increase supplies to the market for March and April in an effort to compensate for shut-in Libyan crude. The Kingdom has added an additional 8-10 mb of crude available to refiners and plans to hold unsold barrels in floating storage or leased tank facilities in the Mediterranean, Northwest Europe and Okinawa. However, so far demand from refiners has been tepid given reduced refinery throughput rates as well as a quality mismatch with lighter, sweet Libyan crude. Although European runs are expected to begin rising again from April, high crude prices and weak margins may prompt some European refiners to cap utilisation rates in the coming months.

Given that Saudi Arabian and Libyan crude streams are a poor match, Aramco is offering a lighter/sweeter crude blend to mirror more closely lost Libyan barrels. A new special Arab Extra Light blend was developed by removing the Berri stream, which raised the API gravity to 41° versus 39° and lowered the sulphur content to 0.7% compared with 1.1% previously. Another lighter, sweet replacement crude has been developed with an API gravity of 44° and a sulphur content of 0.5%. This blend compares to an API of 43.3° and sulphur content of 0.06%. for Libya's Bu Attifel crude. However, the volumes of these new grades made available are not known.

Spot prices for heavier Middle East barrels have lagged the gains in lighter crudes, given stronger demand for distillate-rich crudes as refiners maximised output of gasoil, diesel and jet kerosene. Dubai's discount to Dated Brent widened to just over $5.00/bbl in early March compared with around $3.50/bbl on average in February.

Record levels of crude oil stocks at the landlocked Cushing, Oklahoma storage depot continued to exert downward pressure on WTI. The WTI-Dated Brent price spread widened to a peak of -$18.23/bbl on 15 February. The WTI discount to dated Brent in February averaged -$14.19/bbl compared with -$7.16/bbl for January and -$2.28/bbl in December.

Spot Product Prices

Spot prices for middle distillates and fuel oil rose in all major markets in February, up by around 8-14% on the month. Reduced refinery throughput rates due to maintenance work and stronger demand were behind the increases. Albeit still negative with the exception of low-sulphur fuel oil in New York, fuel oil cracks posted the largest improvement on the month, up between 10-14%, on increased demand for bunker fuel.

By contrast, prices for gasoline and naphtha were up by only 3-5%. Crack spreads increased for gasoil, diesel and kerosene in all regions in February but weakened at end-month as crude surged ahead on developments in Libya. By the second week of March, however, concern over availability of replacement barrels for Libya's light, sweet crude saw cracks recover.

The disproportionate impact of Libyan crude production shut-ins on European refiners has amplified market attention on potential product dislocations and shortages in the region.  Middle distillates were already supported by a tightening of supply as refiners started maintenance and stronger demand but crack spreads for diesel, gas oil and jet fuel strengthened further in March on fears of potential shortages in the coming weeks and months. That said, overall middle distillate stocks in OECD Europe are hovering near the top of the five-year range after a seasonal restocking in January, ahead of refinery turnarounds.

In the Mediterranean, jet fuel cracks posted the strongest increases, up by $1.92/bbl to $18.17/bbl, the highest levels since late 2008. Crack spreads for diesel posted a $0.90/bbl gain to just under $19/bbl on average in February and gas oil rose by $1.71/bbl to $15.11/bbl. Both products improved further in early March. In Northwest Europe, gas oil crack spreads were up just over $2/bbl to $12.13/bbl while diesel rose by $1.51/bbl to $15.75/bbl.

Middle distillate cracks posted similar gains in Singapore, with jet fuel cracks up by $2.56/bbl to $19.9/bbl while gasoil firmed by $1.55/bbl to $17.22/bbl.

Refining Margins

With surging crude prices outstripping product price gains in February, refining margins were weaker for most benchmark crudes in the Atlantic basin but mixed in the Asia-Pacific region. In general, margins for complex refineries fell the most as light and middle distillates prices lagged behind crude price gains. Simple refineries did better as fuel oil cracks were supported by strong Asian demand. Refining margins in both Europe and the US improved in early March, however, on stronger product cracks as the turnaround season in the Atlantic basin further tightened supply.

In Northwest Europe (NWE), cracking margins fell on average by $1/bbl in February, whereas hydroskimming margins were off a smaller $0.30/bbl, supported by a narrowing fuel oil discount. However, volatility over the month was high, with margins improving slightly in the first week of February, before falling steeply in the second half of the month as the rise in product prices failed to keep pace with the rapid run-up in crude prices in response to the Libyan crisis.

European gasoline cracks turned weaker in February as cold weather dampened demand and there were limited export possibilities both to West Africa and the US East Coast. Middle distillates cracks fared better on strong demand and as ongoing maintenance tightened supply in both NWE and the Mediterranean.

Mediterranean refining margins followed the same pattern, although the Urals hydroskimming margin fell to a record low of -$9.10/bbl in the first week of March, pressured by a widening fuel oil discount as high Russian runs increased supplies and the arbitrage to Asia closed. However, by the second week of March, margins improved significantly, lifted by the increase in product prices.

At the US Gulf Coast, all cracking margins fell in February with average losses from $2-$5/bbl. Bonny Light and LLS-based margins posted the largest losses as the premiums for light sweet crudes increased due to the shortfall of Libyan crude. High runs at those US refineries able to take advantage of the lower priced WTI as well as high imports from Europe pressured US gasoline cracks, increasing the losses at cracking units.

On the US West Coast, the situation was completely different, with refining margins posting large gains in February. The gains were due to a combination of widening discounts for crude feedstock and product cracks being stronger in this part of the US due to tighter supply. In March however, both gasoline and fuel oil cracks fell leading to falling margins.

In Asia, margins diverged in February. Singapore refining margins fell slightly, but losses were less than in Europe and the US, due to a narrowing fuel oil discount and a firm gasoil crack as demand was high and the start-up of spring turnarounds tightened supply. But a widening fuel oil discount in March led to increased losses, with Tapis margins plummeting to -$9.10/bbl in the first week of the month, also spurred by wider differentials for light-sweet Tapis crude.

End-User Product Prices in February

End-user prices for selected IEA countries continued their three-month upward rally during February. Gasoline prices rose on average by 4% month-over-month (m-o-m) and by 26% year-on-year (y-o-y). Diesel was up 6.7% m-o-m and 36% y-o-y. With respect to the remaining surveyed products, heating oil and low-sulphur fuel oil (LSFO) experienced price hikes of 7% and 11% m-o-m, respectively. On a yearly basis, heating oil rose by 34% and LSFO by 24%.

Italy saw the strongest increases, with gasoline up by 6.1%, diesel by 6.5% and heating oil by 8.5%. In Germany, gasoline prices saw the smallest increments among the survey countries, up by 2.2%, but posted the largest diesel increase, up 10.4%. Prices for automotive diesel rose across the board for surveyed countries. Beside the German increase, Spanish diesel was up by 8.9% and Italy a smaller 6.5% rise. Outside Europe, end-user prices posted smaller increases. In Japan prices rose for gasoline by 2.8%, diesel by 3.8% and heating oil by 4.9%. Canada registered the lowest gasoline price rise at just 2.5% and the second lowest diesel price increment at 4.9%.


Crude oil tanker rates experienced a resurgence across all benchmark routes in February on increased demand from Asia, weather-related disruptions in Northwest Europe and the crisis unfolding in Libya. The VLCC Middle East Gulf - Japan route surged from $10/mt to $18/mt following a post-Chinese New Year holiday demand increase that considerably tightened available tonnage East of Suez and drew some vessels from the Atlantic into the market. However, as demand waned, the market softened and rates fell back to below $15/mt by early March.

Suezmax rates 'piggybacked' those of the VLCCs. As tonnage of the larger vessels tightened, charterers split cargos onto 1 mb Suezmaxes. In the Atlantic basin, Suezmax rates climbed to $19/mt in early-March as tonnage has remained scarce. In Northwest Europe rates also climbed in response to tightening ice-class requirements in the Baltic. At the time of writing, the Gulf of Finland was completely covered by ice, delaying vessels and tightening tonnage. Consequently the benchmark Aframax UK - NW Europe route had surged to $10/mt by early March, nearly double the normal rates.

In the Mediterranean, Aframax and Suezmax crude tanker markets surged following the onset of unrest in Libya. Rates for cross-Mediterranean Aframax voyages climbed from $5/mt to a high point of $11.5/mt in the first week of March, the highest level since May 2010, following an increase insurance premiums for vessels calling in Libya and delays caused by uncertainty surrounding the status of Libyan ports and the coincidental onset of bad weather in the Mediterranean. However, in the second week of March the situation in Libya became clearer, the weather improved and many traders shied away from Libyan crude in light of sanctions. Consequently, many of the waiting tankers were released into the tonnage pool with subsequent downward pressure on rates, resulting in the cross-Mediterranean Aframax rate plummeting to below $6/mt.

Concerns over Libya also rolled into product tanker markets where a surge in Mediterranean markets drew in vessels normally operating in Atlantic basin markets with an ensuing significant rise, in response to rapidly tightening fundamentals, in these markets. In the event of a prolonged disruption to Libyan exports, it is suggested that Aframax rates will suffer since their demand will be reduced whilst VLCC rates could be underpinned by their increased use to deliver extra Saudi supplies.

By end-February, crude and products in short-term floating storage had risen to 61.8 mb (+6.7 mb), driven by a 6.5 mb increase in Iranian crude. As such, VLCCs deployed for storage increased by 3 to 19, the highest level since end-September 2010 with the total storage fleet now standing at 47 vessels.



  • Global crude throughputs in 1Q11 are revised down by 165 kb/d to average 74.6 mb/d since last month's report, on lower estimated Chinese runs for January and weaker US runs in February. Slightly higher throughputs in Other Asia, Europe and the Pacific partly offset the downward change. 1Q11 runs nevertheless retained annual growth above 2.0 mb/d, of which the non-OECD accounted for 80%.
  • Global refinery runs are expected to drop sharply through 1Q11, to reach a seasonal low point of 73.5 mb/d in March before picking up steam again ahead of summer and reaching 75.3 mb/d in June. In all, 2Q11 throughputs, at 74.8 mb/d, are estimated at 0.2 mb/d above 1Q11, as sharply higher runs in the US are offset by seasonally lower OECD Pacific activity. Non-OECD runs are estimated to trend sideways overall, at 38.4 mb/d. 
  • OECD crude throughputs averaged 36.9 mb/d in January, 640 kb/d less than in December, but 220 kb/d above our previous assessment. Higher than anticipated runs in both Europe and the Pacific were offset by downwardly revised Mexican figures. The monthly declines came almost entirely from the US, which saw runs drop sharply. In all, January runs were still 1.2 mb/d above the same month a year earlier. Preliminary data indicate OECD runs dropped a further 810 kb/d in February as seasonal maintenance intensified.

Global Refinery Throughput

Global refinery throughputs have been revised down by 165 kb/d for 1Q11 on lower Chinese runs in January, disrupted operations in Libya and Iraq in February and March, and weaker-than-expected US runs in February. Slightly higher-than-forecast runs in Europe and the Pacific, as well as sustained high rates in India, Brazil, Russia and Saudi Arabia, provided partial offset. Globally, runs are expected to fall sharply over February and March, as maintenance lowers runs in the Atlantic Basin and cuts rates in the Middle East.

It is likely that the earthquake that hit Japan on 11 March will have a significant impact on refinery operations for months to come. It was reported that six refineries, with a combined capacity of almost 1.4 mb/d had halted operations on the morning of the quake (see Japan's Refineries Hit by Earthquakes and Tsunami). Until the damage can be assessed, however, we retain our previous forecast, noting that Japanese runs will be lower in March and possibly beyond that, should the facilities have been damaged. In all, 1Q11 global crude runs average 74.6 mb/d, 2.0 mb/d above a year earlier, and 200 kb/d below the previous quarter. From April onwards however, global crude runs are expected to rebound sharply as turnarounds are completed in the US and refiners ramp up to meet peak summer demand. Global 2Q11 runs are estimated to average 74.8 mb/d, 0.2 mb/d higher than 1Q11 and 1.0 mb/d above a year earlier.

OECD Refinery Throughput

OECD crude runs fell by 640 kb/d in January, to average 36.9 mb/d, but retained annual growth of some 1.2 mb/d. The decline was almost entirely accounted for by the US, which saw throughputs plunge from December's high 85% to only 82% utilisation. European runs fell by 80 kb/d as a maintenance shutdown of Portugal's largest refinery lowered the regional total. In the Pacific, stronger Japanese runs were mostly offset by lower runs elsewhere. Total OECD crude runs are estimated to have fallen a further 810 kb/d in February, with particularly steep drops again registered in North America. According to preliminary data from Euroilstock, European runs also fell further, to an estimated 12.3 mb/d.

The impact of the disruption to Libyan oil supplies has so far been tempered by the seasonal lull in crude oil demand and relatively healthy inventories ahead of the crisis. Refining margins indeed plummeted as the steep crude price increases far outpaced increases registered for refined products. Several refiners stated that in the short term they were more concerned over refining profitability than access to crude, and said they would have to lower throughputs unless margins improved. Runs are nevertheless expected to pick up sharply from April onwards, when both North America and Europe complete their spring turnaround schedule and start preparing for the peak summer demand season. If Libyan supplies are still shut-in, which looks increasingly likely, the competition for feedstocks, in particular light, low-sulphur crudes, might again force feedstock prices prohibitively higher. Unless accompanied by similar moves in transport fuel prices, this may force some refiners to cut runs.

North American crude runs fell by 630 kb/d in January, to average 17.2 mb/d, on lower US throughputs. Runs fell by 280 kb/d on both the Gulf Coast and the West Coast, while remaining relatively flat on average for the other regions. Gulf Coast refining margins generally improved in January, but remained negative for cracking. Several plants started their turnarounds, including among others BP's Texas City, Conoco's Borger, Valero's Houston and Petrobras' Pasadena refineries. West Coast runs dropped in part due to the supply disruptions of the ANS pipeline in Alaska, which caused a halt in operations at some plants. Maintenance at Valero's Benicia and Shell's Anacortes plants on the West Coast also contributed, compounded by deteriorating regional cracking margins.

Mexican crude runs remained weak in January, averaging a preliminary 1.1 mb/d. Throughputs lagged year-ago levels by about 250 kb/d in the fourth quarter, as the Madero and Salina Cruz refineries were undertaking some maintenance work. The extended work and low utilisation rates of the Mexican refineries are exacerbating the country's need to import petroleum products from the US. In December 2010, Mexico's net imports averaged 600 kb/d, of which 490 kb/d of gasoline.

According to weekly data from the EIA, US refinery runs plunged another 0.5 mb/d in February, a much steeper decline than expected. US Gulf Coast runs fell most sharply, not only as maintenance picked up, but also on deteriorating margins. We estimate that more than 1 mb/d of capacity was offline on the Gulf Coast in February, compared to some 400 kb/d in January. While significant capacity is expected to be brought back in March, cracking margins for Bonny, Brent, LLS and Mars all remained firmly in the red early month, suggesting the ramp-up could be slower than otherwise would have been the case.

Refiners in the Midwest were able to take advantage of WTI's weakness relative to other crudes and resulting healthy product cracks. Regional crude throughputs hit almost 3.5 mb/d in early February before sliding as planned turnarounds got underway. Products supplied from refiners on the East Coast were also constrained, supporting regional product cracks. In addition to the permanent closures, which have reduced regional capacity by 400 kb/d since 2009 (including Valero's Delaware refinery which is planned to restart in 2011), maintenance at Sunoco' 335 kb/d Philadelphia and 180 kb/d Marcus Hook refineries in Pennsylvania lowered operating rates.

European crude throughputs averaged 12.6 mb/d in January, 200 kb/d higher than our previous estimate. Italy saw the largest revision, though French, Dutch and UK runs were also higher. According to preliminary data from Euroilstock, operations slowed further in February as maintenance picked up. Runs fell by 265 kb/d in all, notably in Italy (-105 kb/d), Germany (-85 kb/d), Spain (-85 kb/d) and the UK (-65 kb/d). A recovery in Portuguese runs, as maintenance at Galp's 220 kb/d Sines refinery was completed, provided some offset. We estimate that a total of 1.0 mb/d of capacity was shut in February, up just over 200 kb/d from January.

Runs are expected to fall again in March, on still higher maintenance, weaker margins and in some cases lack of feedstocks. Regional maintenance is slightly higher than in February, but the focus shifts from the Mediterranean to Northwest Europe. The Swiss branch of Libyan oil company Tamoil was the first refiner to announce it was running lower volumes because of weak margins and because they were struggling to replace lost Libyan volumes in March. Several other refiners have indicated they were considering run cuts due to poor economics in late-February/early-March. While most refiners have been able to source enough crude to replace lost Libyan volumes, or had enough stocks to maintain operations for the time being, the competition for feedstocks has been pushing up crude prices much more sharply than product prices, causing refinery margins to plummet. However, improved diesel cracks more recently have helped lift margins.

On 10 March, the workers at Petroplus' Reichstett refinery in eastern France went on strike, blocking oil product deliveries out of the terminal, in protest against the company's plan to shut the plant from the end of March. The refinery has a capacity of 85 kb/d and is the second in France to announce closure due to unfavourable economics and market conditions, following Total's closure of its Dunkirk plant in 2010.

Pacific crude runs averaged 7.1 mb/d in January, about 100 kb/d higher than forecast and the highest since February 2009. Japanese crude throughputs hovered above 3.8 mb/d for both January and February for the first time in two years also (weekly data includes some NGLs, here estimated at 180 kb/d, and are thus reported around 4.0 mb/d). Winter heating demand and relatively robust exports have been supporting runs lately, though the impending maintenance season will normally cut runs from next month onwards to peak in June. At the time of writing, it was unclear whether Japan's refining industry sustained significant damage when an earthquake with a magnitude 8.9 on the Richter scale hit the country early on 11 March (see Japanese Refiners hit by Earthquakes and Tsunami). Until the damage can be assessed, we refrain from adjusting the forecast, yet note that runs will likely be lower than currently shown here.

South Korean runs continued to be supported by strong domestic demand (+3.9% y-o-y in January) and higher product exports (+20.1% y-o-y in January), averaging about 2.5 mb/d for the fifth consecutive month in January. SK Energy and Hyundai Oilbank are scheduled to start maintenance in March, suggesting runs could fall from current levels. Australian runs for December were higher than expected, and led the regional upward revision, suggesting that the impact of the floods there were less severe than first thought.

Japan's Refineries Hit by Earthquakes and Tsunami

The devastating earthquake and tsunami that hit Japan on 11 March is having a severe impact on the country's refinery industry. At least six of the country's 27 refineries, with a combined capacity of 1.4 mb/d or 31% of the country's total, halted operations in the aftermath of the disaster, severely curtailing domestic product supplies. As it is still too early to ascertain the damage sustained by the facilities and the likely duration of the closures, we have refrained from making an adjustment to our global throughputs forecast, but will update when the situation becomes clearer. No major damage to facilities has yet been reported, though a fire that broke out at the storage tanks at Cosmo's 220 kb/d Chiba refinery, was still not extinguished on Monday.

Japan, the fifth largest refiner in the world (ranking behind the US, China, Russia and India in terms of throughputs in 2010), is entirely dependent on imports for its refinery feedstocks. In 2010, Japan imported 3.7 mb/d of crude oil, mostly from the Middle East. The largest sources of supply were Saudi Arabia (29%), the UAE (21%), Qatar (12%), Iran (7%) and Russia (7%). Japan also imported some 1 mb/d of refined products, mostly naphtha and LPG, while product exports - largely middle distillates - stood at some 350 kb/d in 2010.

In addition to the refinery shutdowns, nearly a quarter of Japan's ethylene cracker capacity has been shut, causing Asian naphtha cracks to tumble. Reportedly, 1.71 million tonnes per year (t/y), or 23% of the overall 7.3 million t/y ethylene capacity in Japan was closed due to the disaster, creating a glut in Asian naphtha markets. Japan is a large regional buyer, importing around 465 kb/d of naphtha in 2010, or around 57% of its demand.

One of the 10 governmental oil stockpiling sites, located at Kuji, was also affected by the tsunami. This site, which has underground storage facilities, is currently out of operation. However, only some 11 mb, or 3% of total public stocks, are stored at this site. In addition to holding government stocks, Japan also places a minimum stockholding obligation on industry. As of December 2010, the country held some 590 mb of oil stocks (320 mb of government oil stocks and some 270 mb of industry stocks), equivalent to 170 days of net imports. Government stocks managed by JOGMEC (stockholding agency of Japan) are almost all crude oil.

The Japanese government has temporarily relaxed industry stockholding requirements, lowering stockholding obligations by 3 days for a month starting 14 March, making some 8 mb available to markets. Ample stock levels mean that the key problem is rather ensuring supplies can be delivered to the worst affected areas.

Non-OECD Refinery Throughput

Non-OECD refinery crude throughputs have been revised 145 kb/d lower for 1Q11, to 38.4 mb/d, on the back of sharply lower Chinese crude runs in January. While all preliminary surveys and company statements had signalled a monthly increase in Chinese runs in January, official data released on 11 March showed runs instead plummeted, leading to a significant downward adjustment (-540 kb/d). Reduced runs in the Middle East and Africa, notably Iraq and Libya, in March also drag our forecast lower. These downward adjustments are, however, partly offset by higher Indian and Russian throughputs in January, as well as continuously strong runs in Brazil.

Looking ahead, 2Q11 non-OECD runs are expected to trend sideways overall, averaging 38.4 mb/d. Lower runs in Africa, where the closure of almost the entire refining sector of Libya is expected to drag runs lower are offset by slightly stronger runs in China and Latin America. Runs in the Middle East are expected to be depressed due to heavy maintenance, while increased capacity in India will likely offset some seasonal shutdowns planned there. Annual growth for the non-OECD as a whole slows to 1.3 mb/d, from 1.6 mb/d in 1Q11, dominated by China and Latin America (which is rebounding from exceptionally low runs in early 2010), and to a lesser degree Other Asia and the FSU. 

Official data released by the National Bureau of Statistics show Chinese crude throughputs falling by 400 kb/d in January, to 8.8 mb/d, compared to a previous assessment of a 140 kb/d monthly increase. February runs were also reported in the same update, putting these at 9.2 mb/d, in line with our previous forecast. Runs are expected to fall back again in March as some refiners undertake maintenance, and also as current high crude prices cut refining margins. There have been reports that Sinopec has had to hand out subsidies to encourage additional gasoline supplies, amid market tightness due to strong domestic aromatics demand. The head of PetroChina announced in March that the company was making refining losses with crude prices above $90/bbl, suggesting incentives to keep rates high are diminishing unless product prices are raised as well. For 2010 as a whole, Chinese refiners processed 8.5 mb/d of crude oil, an impressive 1.0 mb/d higher than a year earlier. According to the National Development and Reform Commission, the industry booked Yuan 69.4 billion ($10.54 billion) of profits for the year, 3.8% lower than 2009, as domestic product prices lagged international crude markets.

In Other Asia, runs are estimated to have reached a record high in January, underpinned by strong Indian throughputs. These averaged 4.2 mb/d, including an assumed 660 kb/d level for Reliance's export refinery, which is not included in Ministry statistics. January runs were 120 kb/d higher than December's levels and 345 kb/d above a year earlier. Runs are estimated to have dropped in February, as Reliance shut a 180 kb/d FCC unit for maintenance. Indeed, preliminary product export estimates support the lower numbers, showing a 250 kb/d drop in product exports in February compared to January. Partially offsetting the maintenance, however, the 120 kb/d Bina refinery reportedly started commercial operations in mid-February. Looking ahead, runs are expected to drop again in May/June when Essar completely shuts its 280 kb/d Vadinar refinery for 35 days. The company will raise the plant's crude distillation capacity to 360 kb/d during this period.

The uprising in Libya is not only affecting the country's crude supplies and European refiners, but also domestic refinery operations. Libya has five refineries with a combined capacity of 380 kb/d. Recently, the two largest plants, accounting for 90% of the country total, have been shut. The 220 kb/d Ras Lanuf refinery halted operations in late February, and most personnel have left. On 11 March, it was reported that Gaddafi's forces bombed the plant and surrounding oil storage tanks. The extent of the damage, and likely duration of the outage is not yet clear. The 120 kb/d Zawia plant had to temporarily shut last week, after having operated at reduced rates due to lack of feedstocks for some time, as nearby bombings and heavy fighting made continued operations unsafe. The latter plant has reportedly restarted operations. Domestic fuel shortages will soon become an issue, at least if the port situation does not improve allowing product imports to resume. Libya imported some 80 kb/d of oil products in 2010, and exported around 100 kb/d of largely jet and fuel oil to OECD countries (mainly Italy).

Middle Eastern crude runs for January are estimated at 6.2 mb/d, unchanged from December, but 50 kb/d higher than our previous assessment. Runs likely dropped significantly over February and March, as several large refineries were undertaking maintenance. In Saudi Arabia, Saudi Aramco started maintenance at its 235 kb/d Yanbu plant in February and March and is planning a complete shutdown of its 305 kb/d Jubail joint venture plant from March, reducing naphtha supplies to Asia as a result. The Kingdom's 400 kb/d Rabigh refinery is planning a complete shutdown for 30 days from end-April and through most of May. Some maintenance in Bahrain, Kuwait and the UAE is expected to have further reduced regional runs in the first quarter.

Iraq's 310 kb/d Baiji refinery, the country's biggest, had to shut a 150 kb/d crude unit on 26 February after an attack on the plant. The refinery had already shut a 70 kb/d unit for maintenance. The extent of the damage is not yet confirmed, but the refinery reportedly managed to restore partial operations within a few days. We assume the plant will run at reduced rates until the unit can be repaired, estimated to take at least 45 days by one of the refinery's managers.

In Latin America, Brazilian crude runs averaged 1.9 mb/d in December, flat from a month earlier and 100 kb/d higher than the previous year (and +50 kb/d compared to previous forecast). We have lifted the forecast somewhat to reflect the recent higher run rates. Valero announced in early March that its 235 kb/d Aruba refinery was back at "planned rates" after having had to shut down on 7 February after a freshwater tank collapsed damaging some oil product pipelines. We assume planned rates at 190 kb/d, or 80% utilisation.

Russian crude runs continue to exceed expectations, and were reported at 5.1 mb/d for January, up 200 kb/d from a year earlier and 130 kb/d above our previous forecast. Production of gasoline fell by 4.6% m-o-m according to the Energy Ministry, while gasoil dropped 0.7% and fuel oil 2.8%. Rosneft reportedly ceased production of 80-octane gasoline at its Samara, Achinsk and Komsomosk refineries due to the recent introduction of tighter fuel specifications, dragging down overall gasoline production.

In Belarus, the Mozyr refinery started processing Azeri oil in early March. The Azeri oil is part of a swap agreement with Venezuela. Under the contract, Belarus will receive 4 mt (or 80 kb/d) of Azeri light oil from Socar Resources, to be transported to the refinery via the Odessa-Brody pipeline and a reversed part of the Druzhba pipeline. In return, Socar will take Venezuelan crude supposed to be processed in Belarus, in an attempt to ease its dependence of Russian crude in accordance with a deal between Minsk and Caracas. According to the head of the company, Socar will ship the Venezuelan Santa Barbara crude to the US.

OECD Refinery Yields

December OECD yields increased for all products except naphtha, gasoline and other products. December gross output increased 0.9 mb/d from the previous month, on higher gross output in OECD North America and OECD Pacific. Unusually high runs in the US lifted the North American output, as refiners profited from strong December margins due to in particular higher heating oil cracks and relatively weak US crude prices. Output from European refineries was unchanged vs. November, and still in the lower half of the five-year average.

OECD gasoline yields fell further in December, thereby continuing the shift down seen in November. Yields fell in both OECD North America and OECD Pacific, and were unchanged in OECD Europe.

The decrease in OECD Pacific was in line with seasonal patterns as Japanese and Korean refineries focus on kerosene production for heating purposes in the winter months. In OECD Europe, refiners took advantage of the high naphtha cracks, which continued to strengthen in December, and kept naphtha outputs higher at the expense of gasoline. In OECD North America, gasoline yields fell further from November, and were in line with the five year average, quite contradictory to the peak seen in December last year. As gasoline cracks were weak due to high stock levels, refiners instead increased gasoil/diesel yields, as cold weather boosted heating oil cracks and demand from Latin America remained strong.