Oil Market Report: 10 February 2011

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Highlights

  • Crude prices were propelled higher at end-January by political unrest in Egypt, with Brent crude reaching $100/bbl on fears that the turmoil might disrupt Suez canal and SUMED pipeline flows or spread in the region. Although prices have since eased, Brent futures remain around $100.50/bbl and WTI at $87.20/bbl at writing.
  • Global oil product demand for 2010 and 2011 is revised up by 120 kb/d on average on higher-than-expected submissions in non-OECD Asia and improved economic prospects for OECD North America. At 87.8 mb/d in 2010, global oil demand rose by 2.8 mb/d year-on-year, and should reach 89.3 mb/d in 2011 (+1.5 mb/d year-on-year).
  • World oil supply rose 0.5 mb/d in January, to 88.5 mb/d, on higher OPEC crude and NGL output. Non-OPEC supply was unchanged from December at 53 mb/d, as outages continued to constrain production. 2010 estimates remain at 52.8 mb/d, while the 2011 outlook is nudged up 0.1 mb/d to 53.5 mb/d on higher North American output.
  • OPEC crude supply scaled two-year highs in January at 29.85 mb/d, with Iraq underpinning the 280 kb/d monthly increase. OPEC NGLs in 1Q11 rise by 200 kb/d to 5.7 mb/d on gains from Qatar and UAE. The 2011 'call on OPEC crude and stock change' now averages 29.9 mb/d after upward revisions to demand, close to observed January OPEC output levels. OPEC effective spare capacity stands at 4.7 mb/d.
  • Global refinery crude throughputs for 4Q10 are adjusted up by 150 kb/d, to 74.7 mb/d, 2.4 mb/d above 4Q09, on higher US, Chinese and Indian data for November/December. Global runs are expected to rise to 74.8 mb/d in 1Q11 as maintenance in Europe, the FSU and Middle East partly offset higher Chinese and Latin American runs.
  • December OECD industry stocks declined by 55.6 mb to 2 668 mb, and forward demand cover fell to 57.5 days, the lowest in the past two years. Preliminary January data point to a 19.8 mb build in OECD stocks, while oil in short-term floating storage fell.

A market that tightened in 2010

This month's report incorporates the latest IMF economic outlook, showing persistently strong non-OECD growth and stronger-than-expected OECD economic recovery. Nonetheless, the post-recessionary surge of 2010 should ease in 2011. With a diminishing stimulus impact, tightening OECD government budgets and worrisome signs of commodity price inflation in the non-OECD, global economic growth is expected to ease to 4.3% this year from 4.8% in 2010. Our outlook this month also updates 2011 price assumptions (based on the futures strip), which now come in at around $90/bbl for WTI, $9/bbl higher than the assumption used in December and January.

Crude prices have indeed been rising since September. They gained impetus in late-January from political unrest in Egypt, amid fears for the security of supply through the Suez canal and SUMED pipeline, and of possible regional contagion affecting other Middle Eastern oil producers. But while geopolitical concerns remain ever-present in the region, prices nudged lower again as the immediate threat of escalation seemed to ebb. Nonetheless, a chorus of calls to clamp down on market speculation can still be heard. The premise runs that, assuming worries on Egypt recede, and since OECD stocks and both OPEC and downstream spare capacity look plentiful, how otherwise can prices still be flirting with $100/bbl? 



We hate to be predictable, but would suggest that one clue for strengthening prices since last autumn can be gleaned from latest estimates for oil market fundamentals in 2010 (acknowledging that it is still an incomplete picture, and that data lags and gaps mean we only get a good picture of market drivers well after the event). This shows an implied global tightening to the tune of 1.1 mb/d in the second half of the year, as remarkably strong oil demand (notably gasoil-diesel) ran well ahead of global supplies. Implied global stock draw for the year as a whole averaged 0.5 mb/d, the largest since 2007. And OECD inventories, while trending sideways in 2009 and 2010 in absolute terms, nonetheless were drawn down by an average 0.6 mb/d through the second half of 2010. Moreover, the OECD stock overhang versus the five-year average has narrowed from 200 mb in early 2009 to around 30 mb now. That still seems like a lot of oil until one considers it is equivalent to less than one day's forward demand cover. Moreover the overhang is highly concentrated in North American crude and in distillate. Netting out inflated levels of landlocked US PADD 2 crude, OECD inventories are pretty close to the five year average.   

Of course, no one would pretend that prompt market fundamentals are the only influence on prices.  A host of market expectations and macro and micro financial factors play a role that ebbs and flows with time, albeit it is well nigh impossible to quantify the impact from these disparate factors. But the inescapable conclusion from our market balances is that the physical market has tightened significantly in 2010.  Ceteris paribus, a cushion of stocks and spare capacity does provide some potential to constrain further price increases in 2011. That is just as well, given the potentially damaging short term economic impacts were prices to continue to rise.

Demand

Summary

  • Forecast global oil product demand for 2010 and 2011 is revised up by 120 kb/d on average on higher-than-expected submissions in non-OECD Asia and improved economic prospects for OECD North America. Global oil demand, estimated at 87.8 mb/d in 2010 (+3.3% or +2.8 mb/d year-on-year), is projected to increase to 89.3 mb/d in 2011 (+1.7% or +1.5 mb/d year-on-year). However, persistent frailties in advanced economies and inflationary pressures in emerging countries pose downside risks to the outlook.
  • Projected OECD oil demand is adjusted up by 20 kb/d for 2010 and by 90 kb/d for 2011. Despite very cold weather in all three areas, demand growth in December 2010 was to a large extent driven by industrial and transportation fuels rather than by heating fuels, which surged in only a handful of countries, notably in Europe. Total OECD demand is now assessed at 46.1 mb/d in 2010 (+1.5% or +0.7 mb/d year-on-year). For 2011, higher economic growth assumptions by the IMF - concentrated in North America - should temper the area's structural decline, with total demand averaging 46.0 mb/d (-0.2% or -100 kb/d versus the previous year).


  • Estimated non-OECD oil demand for 2010 and 2011 is raised by 60 kb/d on average. Higher readings in Asia (mostly China) were partly compensated by a lower outlook for the Middle East (Iran). Chinese demand reached yet another record high in December (10.4 mb/d), with apparent demand rising by 12.2% in full-year 2010 (+1.0 mb/d), equivalent to over a third of global demand growth. Total non-OECD demand, estimated at 41.7 mb/d in 2010 (+5.5% or +2.2 mb/d year-on-year), is now projected to reach 43.2 mb/d in 2011 (+3.7% or +1.6 mb/d versus the previous year).

Global Overview

The latest prognoses by the IMF, published in January (World Economic Outlook Update), confirm that the global economy actually grew slightly faster than anticipated last year (+4.8% year-on-year, versus +4.7% as assessed in October). More interestingly, the revisions are mostly concentrated in the OECD, notably in the Pacific, which expanded by almost a full percentage point more than estimated earlier. This tallies with recent oil demand data, which had shown somewhat stronger-than-expected resilience in OECD demand for industrial and transportation fuels, notably in 2H10 (the surge in other fuels, as flagged in this report, was largely driven by extreme weather conditions, particularly in the Pacific).

For the non-OECD, the Fund's assessment for 2010 is broadly unchanged. Upward revisions for several Latin American and Asian countries offset relatively minor downward adjustments to China and the Middle East. Emerging economies thus grew by 7.1%, more than twice as much as developed countries. On a purchasing-power parity basis, the non-OECD - 45.3% of global GDP in 2010 - is poised to overtake the OECD in just a few years, albeit per capita income will likely lag OECD levels for rather longer.

For 2011, the IMF sees the global economy cruising ahead, albeit at a slower pace (+4.3%). Significantly, the Fund now expects a sturdier OECD recovery, while anticipating continued buoyancy in the non-OECD. Most regions have been revised up, with the notable exception of the Middle East, where anticipated economic stagnation in Iran results in a downgrade for regional expectations.

Nonetheless, these notionally healthy growth rates hide a number of concerns for the global economy. On the one hand, the OECD recovery is still fragile. Although the US economy is now expected to grow by as much as 3.0% this year - 0.7 percentage point higher than in the previous IMF forecast - this is still insufficient to curb recession-induced unemployment, despite extremely loose fiscal and monetary policies. The Japanese economy, meanwhile, is seen slowing down sharply as stimulus measures are withdrawn, with only a partial offsetting from its resilient export sector. Moreover, the country's sovereign rating was recently downgraded by a notch, highlighting its mounting fiscal travails - and potentially signalling that other advanced economies may suffer a similar fate should they postpone fiscal consolidation.

In Europe, most large economies are set to see relatively anaemic growth in 2011 - including Germany, which rebounded strongly in 2010. Moreover, the Fund raises concerns about "sovereign debt sustainability and banking sector health in a broader set of euro-area countries and possibly beyond." Yet the fiscal adjustment required to stave off a debt restructuring could prove very painful. On the other hand, lax macroeconomic policies in developed countries have encouraged significant capital flows into large, fast-growing emerging markets, not only boosting economic activity but also leading to surging inflationary pressures and appreciating currencies. More worrisome, inflation is spilling over into the OECD, driven by higher food and energy prices resulting largely from non-OECD demand.

A key question is whether China will tolerate high inflation and, if not, whether it will be able to engineer a soft landing and rebalance its economy by only using blunt administrative tools, as it has attempted (so far unsuccessfully) over the past few months. Alternatively, China could let its currency appreciate substantially and put in place more aggressive tightening measures - yet that could engender a hard landing, with negative consequences for the global economy. Our forecast, however, is based on the assumption that China will be able to rein in excessive credit and hence slow down the pace of economic growth and hence of oil demand. Some observers nonetheless contend that the strong oil demand growth momentum of 2010 will continue this year as Beijing focuses on lifting incomes in interior regions, notably in central and western China.

In terms of oil demand, these new GDP prognoses, together with a nominal oil price assumption of roughly $90/bbl for WTI, based on the futures curve in late January, up almost $9/bbl from December, translate into a slightly upwardly revised forecast of 89.3 mb/d for 2011. This implies growth of +1.7% or +1.5 mb/d year-on-year, +140 kb/d higher when compared with our last report and broadly in line with historical trends relative to GDP growth, interfuel substitution and oil intensity. Meanwhile, following new data submissions for November (final) and December (preliminary), our estimates for 2010 put global oil demand at 87.8 mb/d (+3.3% or +2.8 mb/d versus 2009 and 90 kb/d higher than previously expected). As such, at this time global growth appears to be only a fraction lower than the record reached in 2004 (+3.0 mb/d).



How Much Is Too Much?

The recent surge in the prices of oil and other commodities has resurrected a lively debate - which last raged in 2008 - on both its causes and consequences. With regard to oil, some observers argue that this price increase is entirely due to 'speculation' because the market is relatively well supplied. Still others contend that the global economy is resilient enough to absorb $100/bbl oil - and, by implication, that current production levels are adequate.

However, as this report has emphasised, global oil market fundamentals began to tighten in 3Q 2010, although the ensuing price impact has been cushioned by ample spare capacity, both upstream and downstream. Meanwhile, as much as oil prices tend to follow economic growth, as seen over the past two years, overly sharp price rises resulting from strong demand amid supply lags can also contribute to slow down economic activity, under a complex cycle of iterations that sets a temporary demand/supply equilibrium, before a new cycle begins.

In the short-term, indeed, the rise in prices acts as a consumption tax, curbing purchasing power, notably in countries where such fluctuations are quickly passed through to consumers, and worsens the terms of trade of net energy importers. This is the case for most of the OECD, but also for many non-OECD countries, where energy (and food) account for a large share of household expenditures.

Since over half of global oil demand corresponds to transportation needs, demand is initially largely price inelastic due to a lack of readily switchable alternatives, but over the medium and longer term consumers modify their habits, seeking ways to increase efficiency and/or use alternative energy sources. The collapse of the US SUV market in 2008 provides an illustration of this process of adaptation; as gasoline prices surpassed $4/gallon amid the unfolding economic crisis, sales plummeted. The market for light trucks has rebounded over the past few months, but it will be interesting to observe whether such recovery will last with gasoline prices rising once again.

Even in countries with high subsidies in place, where demand should in principle be unaffected by higher international prices, the cost is ultimately borne by the government, state-owned companies and/or private players. Empirically, this can be particularly onerous for net importing countries, ranging from Bolivia to India, Iran or Morocco, to name but a few. For illustration, the IEA's 2010 World Energy Outlook estimated that global oil subsidies reached an all-time peak of $280 billion in 2008, falling back to around $130 billion in 2009 as oil prices retreated.

These effects can be broadly encapsulated by the 'oil burden' concept, defined as nominal oil expenditures (demand multiplied by the crude price) divided by nominal GDP. This is not to say that a rising oil burden will necessarily cause an economic recession (with the clear exception of the 1970s), but that it can greatly compound the effect of other economic and financial shocks. Indeed, economic activity in the OECD had already been stagnating before oil prices began their final ascent from roughly $90/bbl in late 2007 to $147/bbl by July 2008. Thus, as much as the Great Recession can be attributed to financial factors, high oil prices were a final nail in the coffin for advanced economies at that time.

At 4.1%, the 2010 global oil burden, albeit below that of 2008 (5.1%), was already the second highest following a major recession (the highest was reached in 1980, at 8.0%). Put differently, the oil burden rose by roughly a quarter in 2010. For the OECD, this was equivalent to roughly 0.8% of its collective GDP. Moreover, under current assumptions for global GDP, oil price and oil demand, the global oil burden could rise to 4.7% in 2011, getting close to levels that have coincided in the past with a marked economic slowdown. Indeed, the combination of higher prices with a fragile economic recovery, emerging inflationary pressures and instability in the Middle East is not a healthy one. A sensitivity analysis for 2011, on a ceteris paribus basis (holding GDP and oil demand constant), indicates that, at current prices of around $90/bbl (WTI), the global oil burden is rapidly approaching the 2008 'recession threshold' - and is already well above the $70-80/bbl price range described as 'preferred' or 'ideal' by some producing countries, which would entail an oil burden of 3.5-4.0%.



In the end, the fact that oil prices tend to increase because of sustained demand growth is not under question. However, the rate of growth in prices can move out of sync with economic activity. Following the price shocks of the 1970s and early 1980s, prices were arguably 'too low' for the following two decades, in the sense that they undermined efficiency efforts, encouraged waste (both symbolised by the ascent of SUVs in North America) and removed economic incentives to promote more expensive renewables and other energy sources. By contrast, oil prices rose to unsustainable levels in the mid-2000s, certainly supporting alternative sources but also contributing to trigger the Great Recession of 2009, as noted earlier. Ideally, it might be better if the growth in both prices and GDP remained relatively proportionate, letting consumers gradually adapt and producers benefit from rising revenues. That may be wishful thinking, however, as subsidies and other market distortions persist, notably in emerging countries.

OECD

According to preliminary data, OECD inland deliveries (oil products supplied by refineries, pipelines and terminals) rose by 2.1% year-on-year in December. Growth was markedly robust in OECD North America, which includes US Territories (+3.2%), relatively resilient in OECD Europe (+1.7%) and stagnant in OECD Pacific (-0.6%). Interestingly, despite very cold weather in all three areas, demand growth was to a large extent driven by industrial and transportation fuels - in line with an economic recovery somewhat more pronounced than previously thought, as noted earlier - rather than by heating fuels, which surged in only a handful of countries, notably in Europe.

Some observers have expressed surprise over the relatively feeble performance of heating fuels. However, even if severe snowfalls impeded normal deliveries in some countries, interfuel substitution - notably in favour of cheaper gas and other sources - and a growing share of electric heating are increasingly becoming the key drivers, as this report has long argued. In fact, OECD heating oil growth in 2010 was probably minimal (+60 kb/d, according to preliminary data), despite much colder temperatures in 4Q10 relative to the same period in the previous year.



Revisions to November preliminary data were relatively large (+440 kb/d), indicating that total OECD demand expanded by 3.6% year-on-year during that month (a full percentage point higher than suggested by preliminary data). The adjustments were broadly evenly split among the three regions, with distillates accounting for almost half - but concentrated in diesel, rather than heating oil and other gasoil.



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 +20 kb/d versus our last report). For 2011, though, the higher economic growth assumptions by the IMF - concentrated in North America - temper the projected decline, with total demand averaging 46.0 mb/d (-0.2% or -100 kb/d versus the previous year and 90 kb/d higher when compared to our last report). The usual caveat regarding the assumption of normal temperatures applies, even though erratic climate conditions complicate the outlook. For example, temperatures in Europe were remarkably mild in the first half of January, then very cold, and then again quite mild since early February.

North America

Preliminary data show oil product demand in North America (including US territories) rising by 3.2% year-on-year in December, following a 2.3% increase in November. December readings benefitted from cold temperatures and strong US growth (+4.2%). Economic indicators have improved recently, with the region's GDP growth for 2011 revised up to 3.1% from 2.5% previously. Still, higher expected oil demand growth stems almost entirely from the US, with lower Canadian economic expectations offsetting a slightly rosier Mexican outlook.



November data were revised up by 135 kb/d, led by higher readings for residual fuel oil (+115 kb/d) and diesel (+85 kb/d), which offset lower LPG demand (-95 kb/d). Weekly to monthly revisions in the US for November were moderately positive and, in turn, boosted December preliminary estimates. North American demand is now estimated at 23.9 mb/d in 2010 (+2.7% or +620 kb/d versus 2009 and 10 kb/d higher than our last report). With the incorporation of both higher GDP and oil price assumptions, demand is seen rising to 24.0 mb/d in 2011 (+0.4% or +85 kb/d year-on-year and 70 kb/d higher 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 3.1% in January, following a 4.2% year-on-year rise in December. January data continued to feature sharp year-on-year gains in the volatile 'other products' category (+17.6%), underscoring the uncertain nature of the overall demand strength. Still, transportation readings appeared healthy, with gasoline and jet fuel/kerosene growing by 1.9% and 4.3%, respectively, despite disruptive weather. Recent economic indicators have been strong, and the IMF has upgraded 2011 GDP growth to 3.1%, from 2.3% previously. Moreover, despite high oil prices, January light truck sales outpaced those of passenger cars for the ninth consecutive month.



However, middle distillate readings appeared suspiciously low in preliminary data. Following estimated growth of 4.8% in 4Q10, weekly data suggested a 0.1% year-on-year decline in January, despite much colder temperatures in the Northeast when compared to January 2010. While the switch to natural gas may explain some of this weakness, 'other gasoil' represents only 15-20% of middle distillate demand. By contrast, economic indicators seem to corroborate strong diesel consumption. January's ISM purchasing managers index - a manufacturing gauge - reached its highest level since 2004, while rail traffic also posted year-on-year gains. The American Trucking Association's tonnage index surged in December to its highest level since July 2008, noting that activity appeared "seasonally soft", yet "typical" for January. High exports may be distorting the picture, but their precise effect remains unknown. As such, we have raised our own estimate of diesel for January, putting annual growth at 3.4%. Still, more and better visibility into the distillate category remains a persistent analytical need.

Mexican oil demand declined 3.4% year-on-year in December, dragged down by declines in residual fuel oil and jet fuel/kerosene, with the latter still suffering from the Mexicana airline bankruptcy last summer. Diesel and gasoline also posted weak growth readings, with the former growing at just 0.5% and the latter declining by 0.9% year-on-year. Still, an improved economic picture, with 2011 GDP expected to expand by 4.2%, versus 3.9% previously, should support a return to growth, with total annual demand increasing by 1.8% over the prior year.

Europe

Preliminary inland data indicate that oil product demand growth in Europe reached 1.7% year-on-year in December. Demand was largely boosted by industrial fuels such as LPG and naphtha, transportation fuels (on-road diesel) and heating oil. Thus, growth was supported both by more resilient-than-expected

economic activity (with industrial production up by roughly 7% year-on-year in 4Q10) and, to a lesser extent, by cold weather (with HDDs sharply higher versus the ten-year average and the previous year). Even though preliminary data are likely to be revised, it is worth pointing out the relative weakness of heating oil deliveries measured against the unusually cold temperatures that prevailed in December. Admittedly, snowfalls may have complicated deliveries, but if so that would have been arguably reflected in diesel demand, as it did regarding jet fuel/kerosene demand. Most likely, however, these readings provide further evidence of the structural decline in heating oil use.





November's revisions to preliminary demand data (+190 kb/d) followed a similar pattern. They were largely concentrated in industrial and transportation fuels, with only a minor upward adjustment to heating oil deliveries. Overall, though, demand surged by 4.8% in November, rather than by 3.4% as suggested by preliminary readings. On this basis, total oil product demand in OECD Europe is estimated to have averaged 14.4 mb/d in 2010 (-0.4% or -60 kb/d compared with the previous year and 10 kb/d higher than previously expected). The outlook has marginally improved for 2011, with demand expected to decline slightly (-0.5% or -40 kb/d versus 2010, and 40 kb/d higher than our last report).

Among the largest countries, Germany continues to lead in terms of growth, with oil product deliveries rising by 5.3% year-on-year in December, following +10.0% in November, according to preliminary data. Not surprisingly, given that the country is the largest heating oil market in Europe, growth was supported by deliveries of that fuel (+33.2%), which were in line with seasonal trends. Demand trailed almost exactly its five-year average, but consumer stocks declined to 57% of capacity, from 61% in November. Meanwhile, the snowstorms that engulfed the country had a noticeable effect on air travel, with flight disruptions resulting in a marked fall in jet fuel/kerosene demand (-9.4%).

In France, by contrast, weak heating oil deliveries in December (-5.0%) contributed to curb total oil demand (-1.0%). This may have been due to logistical problems, as the country is less well equipped than its northern European neighbours to deal with heavy snow, and to consumers delaying purchases amid high prices. More interestingly, French LPG and naphtha demand readings have recently shown an intriguing pattern, with the first rising sharply and the latter plummeting markedly. This probably reflects some interfuel substitution related from the recent strikes, with LPG becoming more economically attractive vis-à-vis naphtha for petrochemical production.



Pacific

Preliminary data show that oil product demand in the Pacific fell by 0.6% year-on-year in December. Gains in naphtha, diesel and residual fuel oil failed to offset declines in other product categories, which were partly due to unusually mild weather. HDDs were indeed below both the ten-year average and the previous year, depressing kerosene demand as well as direct crude burning for power generation - but the cold wave that hit the region in January probably reversed this trend.

Meanwhile, half of the revisions to preliminary November data (+120 kb/d) were concentrated in Japan's 'other products', as colder-than-normal weather boosted power use and hence direct crude burning. Thus, total OECD Pacific demand averaged 7.8 mb/d in 2010 (+1.7% or +130 kb/d year-on-year, virtually unchanged from last month's report), interrupting an almost continuous decline for the best part of the past decade. As much as last year's growth owed to the region's export-oriented economic recovery (naphtha demand, for instance, rose by 3.9% versus 2009), it was also largely related to extreme weather conditions, notably a summer heat wave that boosted transportation fuel use and power requirements. In 3Q10, gasoline demand rose by 3.9%, while residual fuel oil deliveries increased by 12.8% and 'other products' use surged by 27.9%.



However, last year's demand performance barely compensated the sharp plunge seen over 2008-2009, which resulted from a combination of greater efficiency, higher nuclear power generation and the global economic recession. Indeed, total OECD Pacific demand has contracted by almost 900 kb/d since 2000. This pattern of decline is expected to continue in 2011, assuming normal weather conditions, with demand falling by a further 1.7% to 7.6 mb/d (-140 kb/d year-on-year, 20 kb/d less than previously assumed).

Racing Blindfolded: Distillate Data Challenges

With middle distillates spurring the recovery in global oil demand and accounting for over half of OECD oil demand growth in 2010 (+690 kb/d), the need for improved data becomes ever more obvious. Currently, OECD governments are required to provide monthly inland deliveries data for 'Transport Diesel' (defined as on-road diesel) and 'Heating and Other Gasoil' (heating oil for industrial/commercial uses, marine diesel, rail diesel and other uses, irrespective of sulphur content). However, evolving fuel quality specifications and changing sectoral consumption patterns make these two simple categories inadequate.

As governments tighten allowable levels of sulphur in diesel and heating oil, characterising gasoil consumption by use is becoming increasingly problematic. In the US, for example, the government has required refiners to produce low-sulphur diesel (i.e., 500 ppm or less) for locomotives, ships and non-road equipment since 1 June 2007. Subsequent demand volumes reported to the IEA indicate a dramatic fall-off in the use of 'Heating and Other Gasoil', with a large increase in 'Transport Diesel'.

Notwithstanding the effects of the economic crisis, the change looks too dramatic to stem from interfuel substitution from heating oil to natural gas, suggesting that the diesel category has become increasingly muddled and potentially inflated. With several states in the US Northeast planning to reduce sulphur in heating oil to at least that of low-sulphur diesel - New York (2012), Connecticut (2014) and New Jersey (2014) - the 'Heating and Other Gasoil' category may continue to shrivel due to reporting practices.



In Europe, meanwhile, since 1 January 2011 the EU's fuel quality directive limits sulphur to 10 ppm in gasoil used by non-road mobile machinery and in inland waterways (though some countries started limiting before 2011), with rail due to follow from 1 January 2012. In Turkey, the on-road diesel market has shifted from 1000 ppm to 10 ppm. Moreover, in Germany, the government has provided tax incentives for the provision of heating oil with maximum sulphur content of 50 ppm. For its part, the German government has modified its monthly oil questionnaire to account for a separate low-sulphur heating oil category. In practice, however, tightening specifications in Europe may still create classification distortions, as in the US.

Shifting consumption patterns provide a final challenge. Globally, the use of marine diesel has been rising; with sulphur specifications for bunker fuels set to tighten by 2015, demand is likely to accelerate as ships move away from residual fuel oil. Moreover, boosted by economic growth and the need to sustain complex supply chains, both rail and marine freight may expand at the expense of less efficient trucking. Meanwhile, although gas penetration is gradually curbing heating oil demand in the OECD, power-sector disruptions in the non-OECD are increasingly met by diesel-fired generators.

Given the importance of gasoil demand, particularly in the medium-term, increased sectoral granularity will be required. Some private-sector efforts have attempted to close this information gap: for example, the Ceridian-UCLA Pulse of Commerce Index attempts to isolate US monthly on-road diesel demand based on real-time payments transactions. The IEA and its member governments are also working to improve long-term reporting. A recent statistics working group convened in Paris to consider all these issues and make proposals to enhance data gathering. Sufficiently disaggregated deliveries data are indeed needed urgently if the varying dynamics of on-road, off-road and stationary uses of gasoil are to be captured accurately.

Non-OECD

Preliminary demand data show that non-OECD oil demand growth accelerated further in December (+7.2% year-on-year), with all product categories registering strong gains. Jet fuel/kerosene and naphtha posted the highest relative growth (+15.2% and 12% year-on-year, respectively), although gasoil accounted once again for the largest absolute rise (1.0 mb/d), equivalent to 35% of total growth.



On a regional basis, Asia remains the key driver of non-OECD oil demand growth. Asian growth has surged to a new record - +2.0 mb/d or +10.6% year-on-year, accounting for 70% of the total non-OECD demand increase. As in most of the previous two years, China was the single largest contributor, representing 77% of Asia's increase and 54% of non-OECD growth.



As a result of the record-breaking strength of Chinese oil demand, estimates for total non-OECD demand in 4Q10 have been revised up by 320 kb/d, with this adjustment partly carried forward into the next four quarters, thus partly offsetting a large downward reassessment of Iran's outlook. Non-OECD demand is now estimated at 41.7 mb/d in 2010 (+5.5% or +2.2 mb/d year-on-year and 80 kb/d higher than previously predicted). The prognosis for 2011, meanwhile, remains largely unchanged at 43.2 mb/d (+3.7% or +1.6 mb/d versus the previous year and +50 kb/d when compared to our last report).

China

China's preliminary data show that apparent oil demand growth gathered speed in December (+17.7% year-on-year), with all product categories bar LPG posting strong gains. The country's total oil demand averaged 10.4 mb/d - another record month. Even accounting for some 300 kb/d in reported product stocks builds in December - a number that is uncertain at best, given the poor quality of such data - 'real' December demand may have hovered around 10.1 mb/d, 14% above year-ago levels. Overall, apparent demand rose by 12.2% in 2010 (+1.0 mb/d), equivalent to over a third of global demand growth. Naphtha, gasoil and 'other products' accounted for the bulk of growth. This reflects the extraordinary macroeconomic stimuli put in place by the Chinese government, as well as other energy-related policies, such as mandated closures of coal-fired plants to meet emissions and energy efficiency targets, which led to a fourth-quarter surge of gasoil use for small-scale electricity generators.



Looking forward, the case can be made that Chinese oil demand growth will slow down noticeably in 2011. In general terms, the economy should cool down slightly, gasoil shortages ease and oil intensity fall (as the investment frenzy has involved the purchase of a large quantity of new, more energy-efficient equipment, in addition to policy directives from the new Five-Year Plan). Meanwhile, new sources of energy (such as increasing volumes of natural gas, as well as methanol, a chemical that can be blended with gasoline) should provide some degree of interfuel substitution. Since 1 January 2011, moreover, several large cities have introduced measures to limit new automobile sales and alleviate traffic congestion. In Beijing, for example, the municipal government will issue, through a lottery system, only 240,000 new license plates - equivalent to only a third of the city's car sales in 2010. The central government, meanwhile, has abolished the preferential tax rate levied on small car purchases. Finally, a more stringent oil product price may be introduced, but the timeline is unclear.



However, at the same time that policies to improve energy efficiency bring down demand, the continued push for economic development of poorer inland provinces will support higher demand for transportation, industrial and construction fuels. Moreover, coal shortages could emerge, notably in winter, thus boosting gasoil use again: some observers note that bottlenecks are becoming much more serious, while coal stockpiles are heavily depleted (although imports are growing rapidly). Yet, overall, we remain cautious so far, expecting China's oil demand to rise by a much more modest but nonetheless significant 570 kb/d in 2011 (+6.0% year-on-year).

Elastic Mystery

China's oil demand outlook has become increasingly crucial for global oil balances. Predicting Chinese trends, however, is far from being an exact science, mostly because of huge uncertainties with respect to official data. With GDP growth in 4Q10 put at 9.8% year-on-year (from 9.6% in 3Q10), bringing full-year expansion to 10.3% (from 9.2% in 2009), the implied oil demand income elasticity stood at roughly 1.2 - about 30-50% higher than most analysts had expected (typically 0.6 to 0.8 for an energy-intensive economy such as China's).

This vast discrepancy may have been due to the gasoil surge, waste or a combination of both - or to much stronger-than-reported economic activity. Indeed, official GDP figures appear too low when compared to other indicators, such as industrial production, which rose by over 15% on average. The question on the reliability of GDP data is recurrent; if actual economic growth in 2010 was higher than suggested by official statistics, the income elasticity would indeed be closer or within the range of most observers' expectations. That, of course, presupposes that oil data are themselves completely accurate, a challenging assertion for many countries.

Other Non-OECD

India's latest experiment in domestic end-user price liberalisation is facing headwinds. The cabinet was reshuffled in January, including among others the Ministry for Petroleum and Natural Gas. The new minister appears to be going along with the policy of his predecessor, namely revising domestic gasoline prices to attempt to reflect developments in the international oil market - a move introduced in June 2010. However, he has stated that at this point it is "not possible" to deregulate gasoil prices. Admittedly, the deregulation of gasoil, which accounts for over a third of total Indian oil demand, is a difficult and highly politically charged issue. Indeed, since last December the decision has been postponed indefinitely because of its inflationary consequences.

So far, domestic gasoline prices have remained unchanged since the reshuffle, despite a significant increase in international oil prices, notably in India's reference market (Singapore). Indeed, progress on the deregulation process has been patchy. Gasoline prices have de facto been largely managed by state-owned oil marketing companies, which have effectively controlled the frequency and the magnitude of price changes since last June. Despite seven hikes since then, domestic prices continue to lag international benchmarks.



Yet, while politically expedient, a suspension of the deregulation policy would put the Indian government in a bind. The combination of rising international oil prices and the threat of renewed runaway domestic demand - gasoline demand increased by almost 40% in only three years, while gasoil surged by almost 300 kb/d over the same period - would again result in a large subsidy burden. Tellingly, since partial reforms were put in place in June, gasoline demand growth slowed to +5% on an annual basis in 2H10, compared with +10% in 2H09. While the drop in absolute terms is modest (from +39 kb/d to +33 kb/d), it shows what full deregulation could achieve. According to the government's own estimates, state-owned marketing companies will lose at least $15 billion during the 2010-11 fiscal year - some $50 million per day. The departing petroleum minister had lobbied for abolition of the 5% customs duty on crude oil and a reduction of excise duty on diesel as a means to cushion rising international prices and hence limit domestic price increases. There is a financial trade-off, however, in that such a policy would entail initially lower revenues, with implications too for the fiscal deficit.

The combined effects of a stagnating economy and the removal of fuel subsidies had a deleterious effect on Iran's gasoline and gasoil demand in 2010. On the one hand, the economy has expanded by less than 1% per year on average since 2008 - compared with some 6% annually over 2000-2007. More dramatically, the IMF's January WEO Update downgraded the country's outlook for 2011 sharply - from +3% to zero. On the other hand, as we noted last month, in mid-December 2010 the government hiked subsidised oil prices of gasoline and gasoil by 300% and 800%, respectively. This resulted in a year-on-year fall in gasoline demand of around 17% in December, according to several reports, and of 6.4% for the whole of 2010, while gasoil use contracted by some 10% and 2.5%, respectively.

Looking ahead, we have substantially revised down our estimates of Iranian demand for 2011, given that the country is likely to be mired in stagflation - economic stagnation amid high inflation. Even though the government has made a few policy changes - in mid-January it raised subsidised quotas for gasoline and removed them altogether for gasoil used by trucks and buses - oil demand will arguably fall for a third year in a row, to 1.7 mb/d (-1.4% or -60 kb/d year-on-year versus 2010 and 140 kb/d less than previously forecast).



Iran's government, however, claimed a modest victory: following the fall in gasoline demand, it announced that it had stopped producing gasoline at its petrochemicals plants, an emergency measure implemented last August in response to US sanctions. Tehran's residents will undoubtedly be grateful: the poor quality of such gasoline had been widely blamed for the serious air pollution that choked the country's capital last December.

The recent upheaval in several Arab countries has not only contributed to lift oil prices on worries of growing geopolitical oil supply risks, but it has also likely affected oil demand. Demand in Tunisia, Jordan and Yemen is relatively small - estimated in 2010 at roughly 90 kb/d in the former two and 180 kb/d in the latter - but Egypt is in an altogether different league. The country's oil demand, which averaged almost 730 kb/d in 2010, is dominated by three products (LPG, gasoline and gasoil, accounting respectively for 20%, 17% and 34% of total demand), all of which have been growing briskly for most of the past decade (at around 7% year-on-year on average), fuelled by a growing economy (+5% on average since 2000) and subsidised domestic end-user prices.

In all these countries, the political turmoil is likely to curb oil demand in 1Q11 and perhaps even beyond. To what extent, however, is difficult to ascertain at this point, other than the fall in Egyptian demand will probably dwarf that occurring elsewhere, given its large industrial sector and vibrant tourism industry. Moreover, aside from the disruption of economic activity resulting from political protests, there could be indirect and additional effects upon neighbouring countries' demand: a reported attack to a natural gas pipeline flowing from Egypt to Israel and Jordan in early February has interrupted supplies, but operations are expected to resume shortly. However, should further sabotage actions take place, demand for gasoil/residual fuel oil in both countries could increase perhaps by a combined 50 kb/d in order to meet power generation requirements if gas supplies were fully disrupted. It should be noted, however, that although Jordan depends entirely upon Egyptian gas, Israel (with total oil demand hovering around 230 kb/d) only sources 40% of its needs from its western neighbour.



Chile* may face electricity rationing in 2011 due to high demand, low hydropower supplies and surging gas consumption. Over 40% of Chile's electricity comes from hydro sources, but drought has dropped water reserves to ten-year lows. The country inaugurated its second LNG terminal in 2010 and increased total LNG imports by five-fold over 2009. Yet, with declining domestic natural gas reserves due to lack of investment, Chile remains dependent on imports for more than 90% of its gas needs. In January, the government attempted to curb natural gas subsidies in southern regions, hiking prices by almost 17% from 1 February. However, in a replay of events in Bolivia, the announcement was met with violent protests and the government rolled back its planned price increase to a mere 3%.

This suggests that Chile may continue to rely on costly diesel-fired generation to meet its peak demand needs during 2011. Last year's devastating earthquake delayed the construction of several coal-fired power plants - and record-high copper prices have supported power demand for mining operations. Although gasoil demand declined by an estimated 3.6% year-on-year in 2010, partially due to the earthquake and higher LNG supplies, it should rise again in 2011 (+3.3%), with significant upside potential should power requirements surge further.

Supply

Summary

  • Global oil supply increased by 0.5 mb/d month-on-month in January, to 88.5 mb/d, on higher OPEC crude and NGL production. Year-on-year, global output levels rose 2.4 mb/d in January, with increments split among non-OPEC crude, OPEC crude and OPEC gas liquids.
  • Non-OPEC oil supply in January remained unchanged from December at 53.0 mb/d, as field outages continued to constrain production. Estimated 2010 production remains at 52.8 mb/d, while the 2011 outlook has been nudged up by 0.1 mb/d to 53.5 mb/d on higher North American estimates, offsetting downward-revised output from OECD Pacific, FSU and global biofuels.
  • Recent political upheaval in Egypt has cast a spotlight on the country's importance as a global thoroughfare for oil traffic, linking Europe to the Middle East and Asia. Flows through the Suez Canal and the SUMED pipeline are reportedly unaffected by the unrest. In the case of a disruption to the Canal, spare capacity for northbound crude is available on the SUMED pipeline, but freight times and costs would increase if vessels were forced to transit via the Cape of Good Hope.
  • OPEC crude oil supply scaled two-year highs in January, with new production from Iraq largely responsible for the 280 kb/d monthly increase to 29.85 mb/d. OPEC supply last month reached the highest level since the group implemented lower output targets in December 2008. OPEC NGLs in 1Q11 are forecast to rise by 220 kb/d, to 5.7 mb/d compared with an average 5.5 mb/d in 4Q10. The higher output reflects increased supply from Qatar and the UAE.
  • The 'call on OPEC crude and stock change' for 2011 is adjusted up by 100 kb/d to 29.9 mb/d on upward revisions to 4Q demand estimates, and stands at close to observed January OPEC output levels. The 'call' for 4Q10 rises by 0.4 mb/d to 30.6 mb/d while 1Q11 is unchanged at 29.8 mb/d.


All world oil supply data for January discussed in this report are IEA estimates. Estimates for OPEC countries, Alaska, Peru and Russia are supported by preliminary January 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 supply scaled two-year highs in January, with new production from Iraq largely behind the 280 kb/d monthly increase to 29.85 mb/d. OPEC supply last month was at the highest level since the group implemented lower output targets in December 2008.

OPEC-11 output rose by 70 kb/d to 27.2 mb/d, with increases by UAE, Angola, Libya and Venezuela partially offset by slightly lower output from Iran and Nigeria. Relative to targeted output cuts, OPEC's compliance rate was 44% in January compared with 45% in December.

The 'call on OPEC crude and stock change' for 2010 and 2011 was increased by 100 kb/d, to 29.7 mb/d and 29.9 mb/d respectively, due to upward revisions in demand, notably for 4Q in both years. The 'call' for 4Q10 was raised by 400 kb/d to 30.6 mb/d, while that for 1Q11 was unchanged at 29.8 mb/d.



In the wake of higher prices and stronger demand, market attention in January focused on whether the producer group will formally increase production ahead of the next scheduled ministerial meeting in Vienna on 2 June 2011. OPEC ministers will have an opportunity to discuss market supplies on the sidelines of the 22 February IEF Extraordinary Ministerial Meeting in Riyadh, marking the 20th anniversary of producer-consumer dialogue. However, several OPEC officials have dismissed the idea. The new OPEC President, Iranian Oil Minister Massoud Mirkazemi, ruled out any increase in output even if prices move above $120/bbl, while Secretary General Abdullah El-Badri made any increase in supply contingent upon a serious deterioration in the crisis in Egypt.

Iraqi supplies to the market in January rose to the highest level in more than two decades, up by 210 kb/d to 2.66 mb/d. Crude exports in January averaged 2.15 mb/d, up by around 220 kb/d from December levels. Basrah exports averaged 1.73 mb/d, up by 226 kb/d while Kirkuk volumes were down marginally, by 4 kb/d to 419 mb/d.

Iraqi supply was boosted by new production from the southern Rumaila and Zubair fields. The BP-PetroChina Rumaila joint venture reached a milestone late last year by increasing production above the initial level of 1.066 mb/d by the 10% specified in its contract. The JV will now start receiving $2/bbl for every extra barrel produced from the field above the estimated 1.17 mb/d production floor.

Apparent progress in negotiations in early January between Baghdad and the Kurdistan Regional Government (KRG) over production sharing agreements signed with foreign operators prompted Norwegian oil operator DNO to restart production from the Tawke field in early February. However, reports that a deal was reached now appear premature. Deputy Prime Minister Hussain al-Shahristani countered on 7 February that the existing contracts with the KRG would not be recognised by Baghdad. Al-Shahristani reiterated that the production-sharing contracts must be converted into service contracts similar to those Baghdad has signed with IOCs.

DNO International said production at the Tawke field would reach 50 kb/d by mid-February but it is unclear what the company's plans are now. The Sinopec and Genel Energi operated Taq Taq field, however, remained shut-in due to logistical problems in moving the crude to an offsite pumping station. The two fields were briefly brought online in mid-2009 but then shut-in after Baghdad said the contracts signed with the KRG were illegal and refused to pay the operating companies for the crude exported via the Ceyhan pipeline to the Mediterranean, which collects payments from the buyers.

Saudi Arabia's January production is estimated at 8.6 mb/d, unchanged from December levels. Saudi output is running about 500 kb/d above its implied target level, with some of the extra volumes now earmarked for filling commercial storage commitments in Japan. In January, approximately 60 kb/d was destined for storage in Saudi-leased tanks at Okinawa as part of a three-year agreement with the Japanese government. Saudi Arabia will use the facility to supply regional buyers closer to their market but has pledged that Japan would receive first priority for the supplies in the event of an emergency. Saudi Arabia is Japan's top supplier at around 1.1 mb/d, or just under 30% of the country's total import volumes.

The UAE increased supply in January by 50 kb/d to 2.37 mb/d, its highest level since production lower output targets were implemented two years ago. Abu Dhabi's state oil company ADNOC eased cuts to contract allocations by between 5%-7% in January. Customer allocations for Murban crude, which accounts for about 60% of Abu Dhabi's output, were raised from 15% below contract levels to 10% for January to March.



Iranian output last month declined by 20 kb/d, to 3.66 mb/d. Ship brokers report that Iranian crude oil supplies held in floating storage rose by 2.1 mb to 23.6 mb at end-January. After weeks of exploring alternative payment options for India's estimated 400 kb/d Iranian imports, a proposal is under discussion but no agreement reached yet. At the start of the year, the Reserve Bank of India (RBI) barred payments for Iranian crude through its system in order to comply with international sanctions. Yet the current proposal allowing its largest lender State Bank of India (SBI) to deal with the proscribed European-Iranian Trade Bank (EIH) would essentially see India back-tracking on its pledge to comply with international sanctions. The EIH Bank was hit by sanctions from the US and European Union for processing transactions with Iranian banks worth billions of dollars, which allegedly helped support Iran's nuclear weapon programme.

Angola's crude production rose by 30 kb/d, to 1.65 mb/d but volumes are still well below year ago levels due to chronic operational problems at the Greater Plutonio complex. Water injection problems plagued Greater Plutonio for most of 2010, with output currently cut by half to under 100 kb/d. With technical issues still unresolved, BP is reportedly preparing for a complete shutdown of the field in April so major repair work can be undertaken. BP (50%) is partnered with Sonangol Sinopec International (50%), a joint venture between the Chinese and the Angolan state oil companies. Inaugurated in October 2007, the Greater Plutonio complex comprises the Galio, Cromio, Paladio, Plutonio and Cobalto fields located in water depths varying from 1 200 to 1 450 metres, and produces a low-sulphur, medium-gravity crude oil.

As a result, Angolan production is expected to hold at the lower 1.65-1.75 mb/d range in 1H11, or 200-300 kb/d below the lofty peak of 1.95 mb/d reached just a year ago, in February 2010. The country's next two major developments are not expected online until the latter part of 2011. Both the Total-operated 220 kb/d Pazflor project in Block 17 and the BP-operated 150 kb/d PSVM ultra-deep water fields in Block 31 are forecast to start-up in 4Q11.

Nigeria's January crude supply was down by 20 kb/d, to around 2.24 mb/d and production is forecast to edge lower in February and March, largely due to planned maintenance work at the offshore Bonga field starting at end-February and technical issues elsewhere. Last month operational problems hit Qua Iboe supplies. Few details have been forthcoming but Qua Iboe exports of around 125 kb/d were delayed from January to February or March. Offsetting the loss, Chevron completed repairs to the damaged Dibi-Abiteye pipeline, which feeds the Escravos oil stream, at mid-month.

OPEC NGLs

OPEC NGL production in 1Q11 is forecast to rise by 220 kb/d, to 5.7 mb/d compared with an average 5.5 mb/d in 4Q10. The higher output reflects increased supply from Qatar and the UAE. A steady ramp up in capacity at the UAE's Habshan and Asab projects will add around 65 kb/d in 1Q11. Habshan output is expected to add 90 kb/d each of condensate and NGLs by 2Q11. The Asab project will add 80 kb/d of NGLs by 3Q11.



Qatar is on track to boost its condensate and natural gas liquids supply to a record 1.1 mb/d in 1Q11, Output will increase by 100 kb/d in 1Q11 following the commissioning of Qatargas 4, Train 7 and ramp up of output from the Qatargas 3, Train 6, which was launched in October 2010. Train 6 capacity is pegged at 70 kb/d of condensate and 10 kb/d of NGLs. Train 7 will add 100 kb/d of condensate and around 45 kb/d of NGLs. Commissioning of the Pearl 1 GTL project is also underway, which is expected to add 70 kb/d of diesel and kerosene.

Suez Canal: Tensions in Egypt Bring a Choke Point Back into Focus

The recent political upheaval in Egypt has brought the 195 km long Suez Canal and its importance to global oil trade back into focus. Following protests on 28 January, crude oil futures surged even though there was no evidence of a direct threat to shipping in the canal, thus highlighting the concern felt by markets of any potential disruption. Located in a historically volatile region, the canal has previously been closed on two occasions; the 1956-57 Suez Crisis and the 1967-75 Egyptian blockade.

During the 1950s and 1960s, approximately 10% of global crude supply transited the canal. However, the introduction of VLCCs, capable of carrying 2 mb or more of oil and too large to use the canal fully-laden, significantly reduced the volumes of crude transported through the waterway. Suezmaxes are the largest tanker class currently using the canal, typically carrying 1 mb of oil. Official data from the Suez Canal Authority indicate that 1.8 mb/d of oil transited the canal in 2009 with 992 kb/d (54%) being sent north and 846 kb/d (46%) moving south. Over this period a total of 591 kb/d of crude oil passed through the canal in both directions, which amounts to less than 1% of global crude supply. Crude flows are split relatively equally, with 317 kb/d being shipped northbound and 274 kb/d moving southbound. The canal is still significant for the transit of products since clean tankers are typically smaller than VLCCs. In 2009, 675 kb/d of clean and dirty products moved northward, mainly composed of middle distillates and gasoline while 572 kb/d (in large part fuel oil) was shipped south.

Provisional 2010 tanker tracking data from APEX indicate that Saudi Arabian and Iranian cargoes made up the bulk of crude cargoes heading northwards through the Suez with 39% and 38%, respectively. In the opposite direction, Libya, Azerbaijan and Algeria account for 42%, 22% and 20% of crude shipments, respectively. Smaller vessels carrying gas condensate are believed to account for a significant proportion of crude traffic transiting the canal. Data indicate that 53% of clean products passing northwards originate from India. In the opposite direction, product origins are more diverse with only the Netherlands clearly identifiable as supplying significant volumes (19% of clean products and 32% of fuel oil).

Destinations of crude and products are diverse, with APEX data indicating that Spain, Italy, France and Morocco received 37%, 26%, 11% and 10%, respectively, of northbound crude flows whilst China and India received 35% and 28%, respectively of southbound crude volumes. Product destinations are more diverse with the Netherlands (21%), France (13%) and the UK (11%) taking the bulk of northbound clean products. For southbound flows, Singapore received 68% of fuel oil and Korea took 23% of clean products.

In addition to the Suez Canal, the 320 km Suez - Mediterranean (SUMED) pipeline takes crude oil from Ain Sukhna on the Red Sea to Sidi Kerir on the Mediterranean. Both terminals can accept VLCCs and the line was conceived as a route for moving crude from the Middle East Gulf to the Mediterranean using these vessels. SUMED currently has a capacity of 2.4 mb/d, although APEX data put December 2010 throughput at 1.1 mb/d. In 2010 Iran and Saudi Arabia supplied 53% and 36%, respectively of SUMED flows and approximately 70% of crude shipped via the SUMED was refined in Mediterranean rim countries.

While the Canal remains an important thoroughfare for oil traffic, in the event of the situation in Egypt deteriorating and affecting the Canal, the SUMED pipeline has ample capacity to ensure continued northbound flows. However, for product shipments, as well as crude cargoes to Asia, the only solution would be to transit via the Cape of Good Hope. This would add some 15 additional days to voyage times from the Middle East Gulf to Europe and cargoes to the US would take an extra 8-10 days. Such a situation would tie up tankers for longer which would likely increase freight rates in affected regions.

Non-OPEC Overview

Non-OPEC oil supply is estimated at 53.0 mb/d in January, unchanged from December. A series of outages continued to constrain production. Australia was battered by storms; Norway, the UK, India and Brazil saw technical problems force shut-ins, while Chinese production was hit by extreme cold. Argentinean production in December was hit by unrest, while a truckers' strike affected output in Colombia.



Overall, estimated 2010 non-OPEC production was left unchanged at 52.8 mb/d, with data for most key producers now near-complete, albeit provisional in some cases. But stronger-than-expected 4Q10 production in North America was largely carried through into 2011. Recent Canadian production, in particular, is robust, with preliminary November levels at 3.6 mb/d representing a new record high (though as always, subject to revision in coming months). Preliminary US and Mexican oil production levels were also adjusted up.

Partly offsetting this was lower estimated biofuels supply in 2010 on surging feedstock prices and a dip in recent US output. Australian oil production is adjusted down on precautionary shut-ins due to cyclones, but also the delay of start-up at a new field, while recent Azerbaijani production levels disappointed. In sum, adjustments amount to a 0.1 mb/d upward revision to the 2011 estimate, now seen averaging 53.5 mb/d, with annual growth thus slightly higher at 0.7 mb/d. 2011 growth is driven by China, Brazil, Colombia, the FSU and global biofuels. Following two years of hefty increments, North American oil supply is now set to fall back, while structural decline continues in the North Sea.



Concern about political unrest in Egypt affecting domestic oil and gas production or Suez shipments has so far proved mostly unfounded, but has likely contributed to recent price rises (see Suez Canal: Tensions in Egypt Bring a Choke Point Back into Focus). Reports indicate that some oil field personnel have been withdrawn for safety reasons and drilling activity reduced, but that oil production levels are not affected. Gas output is temporarily curbed after an explosion on a pipeline that exports gas to Jordan.



New data show that upstream development costs rose by around 4-5% in 2010. Prior to that, costs had fallen by around 12-13% in 2009, following a 2008 peak which contributed to that year's record-high price levels.

OECD

North America

US - January Alaska actual, others estimated:  US total oil supply dipped by 130 kb/d to 7.8 mb/d in January as a result of lower Alaskan production. Crude oil output on the Alaskan North Slope was largely halted for around a week after a pipeline leak in early January. Elsewhere however, onshore production continues to go from strength to strength and projected Lower-48 oil production has again been revised up. In addition to higher NGLs output and 'other hydrocarbons' (mainly refinery additives), 2011 total US output is adjusted up by 55 kb/d to 7.8 mb/d, steady from 2010.

The US government outlined more details on the split-up of the former offshore regulator, the Minerals Management Service (MMS). In addition to the Office of Natural Resources Revenue, which will oversee revenue collection, the Bureau of Safety and Environmental Enforcement will oversee safety and environmental regulations. It will manage offshore inspectors and have responsibility for issuing individual permits. Lastly, the Bureau of Ocean Energy Management will be responsible for developing longer-term plans for oil and gas development, as well as conducting environmental studies. This new trio of sub-agencies of the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) should be in place by 1 October this year. In addition, the government will be advised by a new Offshore Energy Safety Advisory Committee (OESAC) on matters concerning offshore drilling and responses to oil spills.

The authorities have yet to issue any permits for new deepwater projects (though permitting for shallow-water and existing fields continues, if at a slower pace). Secretary of the Interior Salazar was reportedly expecting the first permits by the end of 2Q11. Further delays to a resumption of drilling risk a greater impact on production than the current -100 kb/d and -300 kb/d adjustments for 2011 and 2015 that are factored into our forecast. Latest reported and preliminary production data for the Gulf of Mexico were also slightly lower than expected.



Canada - Newfoundland December actual, others November actual:  Based on preliminary data, Canadian total oil supply rose to a new high of 3.6 mb/d in November, largely on higher output from oil sands projects, especially stronger-than-expected raw bitumen production. Around 110 kb/d of production capacity remains shut-in at the Horizon facility, following a fire in January, now only presumed to gradually restart output in March. In addition, a small problem at Suncor's Terra Nova field offshore Newfoundland cut around 10 kb/d in early February. Nonetheless, stronger recent output levels are partly carried through the forecast, resulting in an overall adjustment of +70 kb/d to the 2011 forecast. 2010 total oil supply is now thought to have averaged 3.35 mb/d, and will likely remain flat at this level in 2011 as growing oil sands output is offset by a decline in conventional crude.

North Sea

Norway - November actual, December provisional:  In Norway, final November and preliminary December production data were virtually unrevised, with output flat at 2.15 mb/d. But expectations for January output were adjusted down by 70 kb/d on the shutting-in of around a third of total wells at the Gullfaks complex from December/January. The fields were previously shut-in during May 2010 following a gas leak and subsequent investigation has raised concerns about well integrity. Based on company statements, we have assumed curbed production until mid-2012. In January, the Oseberg complex was also briefly shut-in due to a gas leak, leading to an assumed curbing of -30 kb/d for the month. All in all, 2010 total oil production is left unchanged at an estimated 2.15 mb/d, while the 2011 estimate is trimmed by 35 kb/d, now averaging 2.11 mb/d. Crude oil output alone is now seen dipping from 1.66 mb/d in 2010 to 1.59 mb/d in 2011, more or less in line with a mid-January estimate by the Norwegian Petroleum Directorate (NPD) that sees oil production declining by 5.8% this year.



UK - November actual:  UK oil production for October-December 2010 was steady at around 1.36 mb/d, but as in Norway, is estimated to have fallen in January. Output is seen down by 100 kb/d on various outages. Some of the Brent cluster of platforms were shut-in from mid-January, curbing 20 kb/d and are likely to be shut for several weeks. Production at the onshore Wytch Farm field has also been halted since mid-November, but was reported in February as likely to restart soon. BP, the operator, was reprimanded by the UK regulator for safety lapses at Schiehallion, Clair and ETAP last year. Despite the outages, UK total oil production is left unrevised, estimated at 1.37 mb/d in 2010, falling to 1.32 mb/d in 2011.

Pacific

Australia - November actual:  Australian offshore production continued to be battered by storms, forcing precautionary shut-ins. Nearly half of the country's crude oil production was briefly halted in late January and again in early February, following earlier shut-ins. As a result, 4Q10 and 1Q11 output levels are curbed by 20 kb/d and 35 kb/d respectively. The start-up of the Kipper & Turrum complex was delayed from mid-2011 to the first half of 2012. In sum, 2010 total oil production is left broadly unchanged at 510 kb/d. The 2011 estimate is adjusted down by 35 kb/d, and now flatlines at 2010's level. Rising output from the Van Gogh, Pyrenees and Montara fields offsets the impact of the shut-ins and decline at mature oilfields.

Former Soviet Union (FSU)

Russia - December actual, January provisional:  According to preliminary data, Russian oil production picked up again in January, to 10.5 mb/d, following a brief, possibly weather-related dip in December. Finalised December data show higher-than-reported output from the Sakhalin projects, offset by lower liquids production by Gazprom and some smaller companies. Weaker-than-expected production from Lukoil and TNK-BP was carried through the forecast, trimming the overall 2011 estimate slightly. Minnow Irkutsk Oil boosted output at its Yaraktinskoye field, after hooking it up to the ESPO pipeline. With additions from other, smaller tie-backs, this should ultimately contribute around 40 kb/d to flows. 2010 total oil production is estimated at 10.45 mb/d, rising to 10.51 mb/d in 2011, a stark slowing of growth from 2009 and 2010, when incremental annual output averaged 200 kb/d and 240 kb/d respectively.



Azerbaijan - November actual; Kazakhstan - December actual:  Lower recent production for both Azerbaijan and Kazakhstan was carried through the outlook, trimming 2011 forecasts by 25 kb/d and 15 kb/d respectively. Azerbaijan's production in 2011 is now expected to remain virtually flat from 2010, at 1.07 mb/d, on lower-than-expected output from the Azeri-Chirag-Guneshli (ACG) complex. Kazakhstan's oil supply is expected to grow from 1.63 mb/d to 1.68 mb/d in 2011. In a threat to future oil production growth, Kazakhstan's government criticised the proposed budget for Phase II of the huge Kashagan development. Phase I is long-delayed, but is expected to see first oil in 2012/13, rising ultimately to 500 kb/d. Previously, Phase II had been expected to start in 2019, taking output to 1 mb/d. This may suffer more delays as a result of the government comments.

BP-Rosneft Deal Opens Up Arctic and Thaws Relations with IOCs?

BP took markets by surprise in mid-January when it announced a tie-up with Russian state-controlled giant Rosneft. Aside from much market speculation on the motivation for the announcement at this time, and uncertainty surrounding a legal challenge from TNK-BP's Russian shareholders, the deal may mark a more realistic attitude towards foreign investment in its hydrocarbons sector by the Russian government, an intriguing new form of IOC/NOC cooperation and the first major move into Russia's Arctic.

The first part of the deal involves an equity swap. Rosneft will receive a 5% stake in BP, while BP will add an additional 9.5% to its existing 1.25% holding in Rosneft. In addition, the two will form a joint venture to explore and develop three Rosneft-held blocks in the Kara Sea northwest of the Yamal peninsula in Russia's far north (Rosneft will control two-thirds of the JV and BP one-third). BP will essentially pay for the exploration but will be allowed to share any future profits and to book reserves. Rosneft claims the blocks could hold vast amounts of oil and gas; it estimates some 35 billion barrels of oil and 10 trillion cubic metres of gas in place, though these volumes are based on geological surveys rather than drilling.

Leaving aside the merits of the deal for the two companies, its wider significance is three-fold. Firstly, it may signal the Russian government's realisation that it requires cash flow, project management experience and technology from the majors, at least when it comes to opening up challenging new frontier areas such as this one. This marks a significant change from the status quo, in which offshore areas are currently open only to state-controlled Russian companies.



Secondly, it appears that, in its willingness to attract a major foreign investor, the government is prepared to make major concessions, such as allowing BP to book its share of any reserves discovered in the Kara Sea blocks and to share profits, rather than merely receive a fee as operator. Other considerations such as Rosneft's long-held desire to gain more of an international presence likely also played a role in determining the equity swap, but it still heralds a subtle twist in evolving IOC/NOC relationships.

Thirdly, Russia's offshore remains largely unexplored (a decision whether to go ahead with the huge Shtokman gas field in the Barents Sea is pending, while Lukoil recently brought onstream its Yuri Korchagin field in the Caspian). Yet such areas will be key to maintaining Russian oil production, which faces steep decline in output at many older fields in mature basins such as Western Siberia and the Urals/Volga region. Muted Russian growth since the middle of the last decade has depended upon new fields coming onstream in Eastern Siberia, and our outlook through 2015 for Russia suggests a hiatus in growth until new investment is forthcoming.

BP and Rosneft estimate that actual drilling in the Kara Sea blocks will start around 2015, with any new oil fields to come onstream around the end of the decade. Indeed, more investment may come. BP's announcement was followed by news that ExxonMobil had also paired up with Rosneft to explore for oil in the Tuapse Trough region of the Black Sea (though in this case there is no equity swap involved). Rosneft alone holds 17 licences for Russia's offshore, hopes to receive more and has recently submitted proposals to the government on a new tax regime for such areas, seen as key to developing them profitably.

FSU net oil exports rose to 9.82 mb/d in December, a significant increase of 560 kb/d from November. Despite a rise in Russian export taxes, crude and product shipments increased by 390 kb/d and 190 kb/d, respectively, with flows through the Transneft network increasing by 260 kb/d. Crude exports hit 6.81 mb/d, their highest level since July 2010, as deliveries via Black Sea ports increased by 290 kb/d, driven primarily by greater volumes of Kazakhstani Tengiz shipped via the Ukrainian port of Pivdenne. The rise in product exports was driven by increased fuel oil volumes (+110 kb/d m-o-m) while gasoil and 'other products' rose by a combined 80 kb/d. Recent reports suggest that the dispute between Russia and Belarus over transit tariffs and pricing has been resolved and that crude flows to Belarusian refineries have resumed. In contrast with previous disputes, Russian Urals flows to Europe via the Druzhba pipeline remained unaffected at approximately 800 kb/d, but diesel exports from Belarus to Europe were significantly cut as Belarusian refiners refocused on supplying the domestic market.



Net oil exports remained stable in 2010, averaging 9.52 mb/d (+10 kb/d y-o-y), although their dynamics changed significantly with increased flows moving east, notably through the ESPO, at the expense of westward deliveries. Transneft volumes fell to 3.90 mb/d as Russian producers shunned less economic Ukrainian ports and after a reduction in Russian pipeline deliveries to China via Kazakhstan. It is believed that a large portion of these shipments was therefore exported by non-Transneft controlled routes, notably Russian rail. However, the receipt of more complete 2010 data has brought the exceptionally high 2009 Transneft level sharply into focus; this figure may yet be revised. Product exports increased by 30 kb/d on the year after increased shipments of fuel oil (+100 kb/d) offset a combined 70 kb/d fall in gasoil and 'other products'. Despite fears that ESPO would signal the reduction in flows through the Druzhba, volumes remained remarkably stable at 1.13 mb/d in 2010 (+10 kb/d y-o-y). Looking to 2011, provisional port loading data for Kozmino indicate 284 kb/d was shipped in January, slightly below the 310 kb/d 2010 average. With East Siberian production set to continue rising, it appears that sufficient volumes will be available to supply both Kozmino and the 300 kb/d Chinese spur.

Other Non-OPEC

Argentina - December actual:  Argentinean oil production in December was revised down by a sharp 110 kb/d, falling by 150 kb/d from November to 545 kb/d. An outbreak of violence in the Santa Cruz producing region had reportedly cut output by 75 kb/d, though it was unclear for how long. We have assumed that output recovers to pre-December levels around 700 kb/d by February. 2010 total oil supply averaged 700 kb/d, expected to remain steady at this level in 2011.

Brazil - November actual, December preliminary:  Preliminary data indicate that Brazil's oil production rose to 2.25 mb/d in December, a new all-time high on the back of rising output from several new fields, including the recently-renamed Lula (ex-Tupi), the first large pre-salt field to be developed. In mid-January, a fire briefly shut-in around 10 kb/d on the offshore Cherne II platform, while in early February, the 180 kb/d capacity P-50 platform on the Albacore Leste field halted operations for several hours. 2010 total oil production is estimated to have averaged 2.14 mb/d and is expected to rise to 2.29 mb/d in 2011, a key source of this year's non-OPEC growth.



Colombia:  In Colombia, December oil production rose to 825 kb/d, its highest level since 1999. In early February, crude oil truckers shipping crude from oil fields in the hinterland to coastal export terminals went on strike (against high prices of fuel), which will likely hit production (we have assumed a cautious -25 kb/d adjustment). A sharp rise in crude production has left export infrastructure lagging, though construction of additional pipeline capacity is underway. Colombian total oil production averaged 790 kb/d in 2010, and is seen rising to an estimated 910 kb/d in 2011.

OECD Stocks

Summary

  • OECD industry stocks declined by 55.6 mb to 2 668 mb in December, while forward demand cover fell to 57.5 days, the lowest in the past two years. The second consecutive monthly draw was led by large declines in North American crude oil and 'other products', but was directionally in line with the five-year average 40.1 mb draw.
  • Preliminary January data indicate OECD industry oil stocks rose by 19.8 mb, half the seasonal five-year average increase of 40.2 mb. Crude oil inventories gained 4.2 mb, as builds in the US and Europe offset a drop in Japan, while 'other oils' added a further 4.9 mb. Increases in gasoline and distillates, partly offset by falling 'other products', drove product stocks 10.7 mb higher.
  • Short-term oil floating storage fell to 55 mb in January, from 56 mb at end-December. The declines in offshore crude stocks in Asia-Pacific and Northwest Europe drove the decrease in crude oil floating storage to 35 mb, while an increase in the Middle East Gulf and near Southeast Africa provided partial offset. Product floating storage remained unchanged at 20 mb as a build off Northwest Europe balanced a draw near West Africa.


OECD Inventories at End-December and Revisions to Preliminary Data

OECD industry oil inventories declined by 55.6 mb to 2 668 mb in December and forward demand cover dropped from 58.3 days in November to 57.5 days in December, the lowest level since November 2008. Sharp declines in crude oil and 'other product' stocks drove the stronger-than-seasonal monthly OECD draw. Inventories of 'other oils' also fell sharply, while declines in middle distillates and fuel oil were more muted. A further, albeit weaker-than-seasonal, gasoline build provided partial offset. Accordingly, product stocks contracted by 28.8 mb, crude oil by 19.2 mb and 'other oils' by 7.6 mb. In comparison, a five-year average draw of 40.1 mb is normally characterised by less steep declines in crude oil and products and a sharper drop in 'other oils'.



For the year as a whole, commercial OECD stocks built by 3.8 mb in 2010 and forward demand cover was down from 58.0 days at the beginning of 2010. However, a closer look unveils a shift from products to crude and NGLs and varied performance across the regions. European stocks drew this year by a solid 26.9 mb, while North American and Pacific stocks each gained around 15 mb year-on-year. 'Other oils', consisting of NGLs and feedstocks, rose by a strong 21.4 mb from low 2009 levels and gasoline and distillates fell by 11.1 mb and 9.1 mb, respectively.



More complete data for major OECD countries indicate total oil inventories were 18.2 mb lower in November and 5.7 mb higher in October than originally thought, implying a sharper 32.2 mb stock draw, instead of the previously reported November decline of 8.3 mb. The largest downward adjustments in each region occurred to crude oil levels. Following baseline revisions and three monthly declines, stocks have dropped 125 mb from the second-highest level on record evident in August 2010.



Preliminary OECD data point to a 19.8 mb stock build in January, half the seasonal five-year average increase of 40.2 mb. Crude oil inventories gained 4.2 mb, as builds in the US and Europe more than offset a decline in Japan. Meanwhile, an increase in Europe drove product stocks 10.7 mb higher. Gasoline and distillate inventories gained 19.9 mb and 9.5 mb, respectively, while a sharp draw in US 'other products' provides partial offset. Global short-term oil floating storage fell further to 55 mb in January, from 56 mb at end-December. Crude floating storage dropped to 35 mb and product floating storage remained unchanged at 20 mb.

Analysis of Recent OECD Industry Stock Changes

OECD North America

Industry stocks in North America fell by 37.9 mb in December, to 1 324 mb. This was the fourth consecutive monthly decline, and was slightly sharper than the five-year average 27.9 mb stock draw for the month. An uptick in regional refinery throughputs and seasonally low imports caused December crude oil inventories to decline by 22.7 mb. Much of the draw occurred on the US Gulf Coast, where refiners increased runs due to more profitable margins and, at the same time, deferred tanker arrivals to reduce end-year tax liabilities.



Stock Overhang Eases But Remains Concentrated in North America

A sharp 55.6 mb December stock draw reduced the OECD inventory surplus relative the five-year average levels to 30.2 mb, from 45.7 mb in November. The overhang is concentrated in crude oil, middle distillates and 'other oils' (19.3 mb, 32.3 mb and 9.0 mb above the seasonal norms, respectively). While industry oil stocks in Europe and the Pacific stood 14.2 mb and 4.8 mb below the five-year average levels, respectively, at end-December, North American inventories were 49.2 mb above the average.



This North American overhang comprises not only the widely noted crude held in the landlocked US Midwest, but also, until recently, volumes stored on the US Gulf Coast. However, four monthly consecutive stock draws helped to reduce the North American surplus to the five-year average levels, from 101.3 mb in August to 49.2 mb at the end of December.

The stocks glut in the US Midwest arose from elevated Canadian crude flows from 2Q10 and growing PADD 2 oil supplies. Canadian non-conventional and US shale oil production is shipped southwards by pipeline to the US Midwest and around Cushing, Oklahoma, the delivery point for the light sweet crude futures contract. Many commentators see bottlenecks at Cushing remaining in place until new pipeline capacity running from Cushing to the US Gulf Coast and from Alberta to the British Columbia coast is inaugurated in two to four years time. However, rail transport of landlocked crude from PADD 2 to US Gulf may provide a partial relief.

Meanwhile, the US Gulf Coast overhang appeared in 3Q10 on a combination of higher imports and lower crude runs. However, low December imports and high crude runs supported by profitable margins drained the crude surplus and pushed gasoline and distillate stocks in the region up, indicating the crude surplus is now shifting into products. If WTI-based margins remain strong, despite muted economic recovery, this trend might continue.

A sharper-than-seasonal 19.5 mb draw in 'other products', much of it propane used for heating, drove the overall 11.5 mb drop in product stocks, while seasonal builds in motor gasoline and middle distillates provided partial offset. Higher imports and refinery output supported a 6.4 mb increase in gasoline stocks. Distillates gained 2.1 mb, but diesel stocks rose on higher imports and refinery production, while stronger heating demand due to cold weather drained heating oil inventories.



US weekly data from the US Energy Information Administration (EIA) point to an 11.1 mb build in oil stocks in January. Continued cold January weather with strong snowstorms led to a draw in 'other products', especially propane, which fell by a further 21.4 mb. However, a sharp 17.4 mb build in gasoline and small increases in middle distillates and fuel oil cushioned the decline. Overall, product stocks fell by 1.7 mb in January, while crude oil stocks rose seasonally by 8.2 mb as seaborne imports to the US Gulf rebounded. Crude stocks held in Cushing increased by 0.9 mb to a new record level of 38.3 mb, above previous July peak levels.

OECD Europe

Commercial oil inventories in Europe fell by 1.9 mb to 945 mb in December, driven by 'other oils', gasoline and fuel oil declines. The draw contrasted with a more typical 10.7 mb product-led seasonal increase. Crude inventories rose by 2.3 mb as higher imports and lower runs in Italy, the UK and elsewhere in Europe outweighed draws due to higher refinery throughputs in France and the Netherlands.



Products fell by 1.5 mb on counter-seasonal draws in fuel oil and gasoline, while distillate gains provided a partial offset. Fuel oil inventories declined by 0.7 mb and an uptick in gasoline exports, mainly in France and Germany, reduced gasoline holdings by 1.8 mb. Middle distillates rose slightly, supported by offloading from floating storage and despite draws in the Netherlands, Italy and the UK. End-user heating oil stocks in Germany fell to 57% of capacity in December, from 61% in November, as rising gasoil prices discouraged consumer buying and they ran down their accumulated inventories.



Preliminary data from Euroilstock point to a 16.3 mb gain in January inventories in the EU-15 plus Norway. Rising crude and distillate stocks drove the increase (+5.8 mb and +7.9 mb, respectively). Meanwhile, refined oil products held in independent storage in Northwest Europe rose slightly in January, as gains in gasoline and jet kerosene outweighed draws in gasoil, naphtha and fuel oil.

OECD Pacific

In December, OECD Pacific commercial oil stocks fell by 15.8 mb to 399 mb, driven by seasonal product draws and despite the highest regional crude runs since February 2009. Crude inventories edged 1.2 mb higher (compared to a more usual seasonal 6 mb draw) as a decline in Korean crude stocks failed to outweigh stock builds elsewhere in the region. A seasonal uptick in demand sharply reduced middle distillates and 'other product' stocks, while gasoline and fuel oil also declined.



Japanese industry inventories fell by 7.6 mb in January, according to weekly data from the Petroleum Association of Japan (PAJ). Higher refinery utilisation drew accumulated crude oil stocks 9.8 mb lower, resulting in product gains, especially in gasoil, naphtha and gasoline inventories. However, stronger heating fuel demand drove inventories of kerosene lower by 2.2 mb, and thus constraining the overall product build to 1.8 mb.



Recent Developments in China and Singapore Stocks

According to China Oil, Gas & Petrochemicals (China OGP), Chinese commercial oil inventories rose by the equivalent of 10.9 mb in December (data are reported in terms of percentage stock change). Rising imports drove a 1.0 mb (0.5%) build in crude oil stocks, outpacing high refinery runs. Domestic diesel shortages finally eased as China became a net diesel importer in December, for the first time since November 2008. Consequently, gasoil stocks increased by 7.5 mb (16.0%), while kerosene and gasoline stocks rose by 0.7 mb (5.6%) and 1.7 mb (3.0%), respectively.



Singapore onshore inventories fell by 3.0 mb in January, led by declines in fuel oil and middle distillates. Higher gasoil exports left for Australia, while a drop in fuel oil inventories was reportedly driven by higher demand by Chinese teapot refiners for straight-run residue, which is in line with historical trends in the weeks leading up to the Chinese New Year holidays (this year falling in early February).



Prices

Summary

  • Crude oil prices were propelled higher at end-January by the political unrest unfolding in Egypt. Benchmark North Sea Brent breached the $100/bbl threshold on fears that the political turmoil in Egypt may spread in the region, as well as potentially disrupting oil flows through the important Suez Canal or SUMED oil pipeline. While neither outcome appears to have high probability, the situation nonetheless exacerbated bullish market sentiment in early February. Futures prices for Brent were trading around $100.50/bbl and WTI at $87.20/bbl at the time of writing.
  • US marker WTI's underpinning by local, Midwest fundamentals was acutely evident in January and early February, with the discount to North Sea Brent at an unprecedented $13.50/bbl in intra-day trade at one point. The WTI-Brent spread remained firmly in negative territory throughout January as record levels of crude stocks at the landlocked Cushing storage facility added downward pressure on the US benchmark. This in turn saw PADD 2 refiners sustaining crude runs.
  • Spot prices for refined products moved higher in January, with crack spreads for middle distillates supported by weather-related heating demand and lower global refinery throughput rates. In addition, relatively steeper discounts for benchmark crudes US WTI and Dubai to Brent inflated products cracks versus these grades.
  • Crude oil tanker rates continued their downward momentum in late January but then recovered slightly by early February following localised tonnage tightness and surging bunker fuel prices. Meanwhile, the Suezmax market appears to have so far shrugged off concerns of potential disruption in the Suez Canal, with no rate surges reported for trades transiting the region.


Market Overview

Crude prices were propelled higher at end-January by the political unrest gripping Egypt. Benchmark North Sea Brent breached the $100/bbl threshold on 31 January amid concerns that the turmoil unfolding in Egypt may spread in the region as well as potentially disrupting oil flows through the critical Suez Canal or the Suez-Mediterranean (SUMED) oil pipeline. While the likelihood of either event is still deemed low, the risk augmented already prevailing bullish market sentiment.  Approximately 2 mb/d of crude and refined products head to the Mediterranean via the Canal and SUMED oil pipeline, with about 850 kb/d of crude and products heading south via the canal. As such, the facilities provide a pivotal transit route linking the Red Sea to the Mediterranean Sea.

Since the onset of the crisis in Egypt on 25 January, Brent prices jumped just over $7/bbl to close at a peak $102.34/bbl on 2 February—the highest level since September 2008. Meanwhile, trading volumes reached feverish levels, with open interest in NYMEX WTI futures contracts in January reaching the highest level since September 2007.

Oil prices were already on an upward trajectory in the first half of January, spurred on by stronger demand, especially from China, and evidence of continuing market tightening. Comments on 24 January by Saudi Oil Minister Ali al-Naimi, since repeated, to the effect that he expected prices to hold at last year's $70-80/bbl range rather than the current higher levels suggested producers do not see recent rises as sustainable. Moreover, the Minister said global oil demand will likely rise by between 1.5-1.8 mb/d this year and that "this will give OPEC the opportunity to boost supplies to the global market," implying the producer group is prepared to raise production levels to meet these higher demand levels.

Market attention continued to focus upon the producer group, with traders searching for any signal that OPEC will formally, or informally, agree to increase supplies to the market before the next scheduled ministerial meeting, which is five months away in early June. However, before then, OPEC ministers will gather on 22 February in Riyadh to attend the IEF Extraordinary Ministerial Meeting marking the 20th anniversary of producer-consumer dialogue.

Market equanimity proved fleeting, however, as the crisis in Egypt escalated at end-month. Futures prices for benchmark crudes ended the month higher, with North Sea Brent posting much sharper gains against WTI. Brent crude rose by $4.65/bbl, to an average $96.91/bbl in January and was last trading around $100.50/bbl at the time of writing. By contrast, WTI prices in January were up on average by a more modest $0.35/bbl, to $89.58/bbl, as record levels of crude stocks at the Cushing storage facility, the delivery point of the NYMEX contract, added considerable downward pressure on the US benchmark. WTI was last trading at $87.20/bbl.



WTI's underpinning by local, US Midwestern fundamentals was acutely evident in January and early February, with the discount to Brent at an unprecedented $13.50/bbl in intra-day trade at one point. The WTI-Brent price spread deteriorated throughout the month, widening from an average -$4.82/bbl in the first week of January to -$10.04/bbl in the last week.

The massive overhang of crude stocks in the US Midcontinent is also exerting enormous pressure on the front end of the WTI futures curve, with the M1-M12 contango steadily widening throughout January, from around $4.70/bbl at the start of the month to more than $9.00/bbl by the end. That compares with an average $2.39/bbl in December. By early February, the WTI M1-M12 spread had widened to the deepest levels in more than two years, averaging $9.65/bbl. With few relief valves available via new pipelines to reduce the massive stock overhang in the Midcontinent, the inversion of the more normal WTI-Brent premium and the divergence in the two crudes' forward curves may persist for months or indeed years to come, especially as US refiners reduce demand for crude ahead of the peak turnaround season. That said, in the short term Midwest refiners maintained higher than expected runs in recent weeks. Longer term, crude pipeline capacity feeding from Cushing to the Gulf Coast and that taking Canadian crudes to the Pacific Coast may ultimately redress the logistical pressure on WTI. 



Futures Markets

Open interest in WTI futures contracts in January reached its highest level since September 2007. Open interest increased last month in both 'futures-only' and 'futures and futures-equivalent' options (hereafter combined) to 1.53 million and 2.77 million contracts, respectively. Producers increased their net short position during the month of January; they held 28.8% of the short and 17.9% of the long contracts in WTI futures-only contracts. Swap dealers, who accounted for 30.2% and 32.1% of the open interest on the long side and short side, respectively, remained net short.



Managed money traders' net long exposure increased slightly in January to 176 448 futures contracts.  The market share of managed money traders has fallen from 28.3% to 26.6% on the long side and from 16.4% to 15.1% on the short side.  Other non-commercials, who accounted for 18.7% of open interest on the long side and 20.3% on the short side, remained net short in the market.

The NYMEX and the Intercontinental Exchange (ICE) issued their annual reports on trading volume in energy products. There is clear evidence that volume in energy market derivatives has gained momentum in 2010. Although NYMEX WTI is still the most liquid energy product, growth in Brent crude oil and other energy products traded on ICE is much stronger than for NYMEX energy products. The main reasons for the divergence in the growth rate of traded volumes can be attributed to: firstly, investor appetite for Brent over WTI, due to continued deep contango in WTI futures prices and the recent dislocation between Brent and WTI prices; secondly, possible strict position limits on energy products in the US offered by NYMEX; and thirdly, a diverse range of contracts offered by ICE.

A strong rally in commodity prices, particularly energy commodity prices, in December led to increasing investments from institutional as well as retail investors, on the premise that energy and commodities offer a diversification benefit and a hedge against inflation.  The influx of commodity index money in futures and over-the-counter (OTC) markets in December 2010 in the long side reached an all-time record notional value of $283.7 billion and $211.1 billion in net notional value. Index investors added $5.0 billion to the Light Sweet Crude Oil market in December 2010, which rose to 622 000 futures equivalent contracts, or $57.4 billion in notional value.



Pre-emptive Moves Against Speculation

Speculators have never been popular, and they may never have been as unpopular as they are today. Increasingly they are blamed for fluctuations in commodity prices, particularly in energy prices, even though a market lacking speculators to take the other side of price hedging transactions for physical market players would arguably be one that would be much more volatile.

Two of the most important functions of futures markets are the transfer of risk and price discovery. In a well-functioning futures market, hedgers, who are trying to reduce their exposure to price risk, will trade with someone, generally a speculator, who is willing to accept that risk by taking opposing positions. By taking the opposing positions, these traders facilitate the needs of hedgers to mitigate their price risk, while also adding to overall trading volume, which contributes to the formation of liquid and well-functioning markets.

However, the traditional speculative hypothesis stating that profitable speculation must involve buying when the price is low and selling when the price is high, has come under strong criticism. The critique originates from the observation that prices and non-commercial positions in energy commodities have been moving together since 2002.  Accordingly, it is argued that excessive speculation by institutional investors caused energy prices to diverge from their fundamental values.

In order to combat excessive speculation and prevent market manipulation, the US CFTC, under the mandate given by the Dodd Frank Act, proposed on 13 January, 2010 hard position limits on commodity futures, options and swaps positions of speculators. Critics argued that there has yet to be a credible study which links the run up in commodity prices to trading strategies of speculators. However, the Commission justified its proposed rule as follows: "The Commission is not required to find that an undue burden on interstate commerce resulting from excessive speculation exists or is likely to occur in the future in order to impose position limits. Nor is the Commission required to make an affirmative finding that position limits are necessary to prevent the sudden or unreasonable fluctuations or unwarranted changes in prices or otherwise necessary for market protection. Rather, the Commission may impose position limits prophylactically, based on its reasonable judgment that such limits are necessary for the purpose of "diminishing, eliminating, or preventing" such burdens on interstate commerce that Congress has found result from excessive speculation". 

In seeking to prohibit excessive speculation and its possible effect on price volatility in futures markets, the Commission proposed a two-stage approach for hard position limits as preventive medicine for excessive speculation. In the first stage, the Commission will take over the existing spot-month limits set by exchanges. For example, NYMEX has a 3 000 contracts hard position limit for spot month NYMEX WTI, which now becomes the federal position limit. In the second stage, the Commission will make its own determination on the spot-month limit, any single-month and all-months-combined position limits across different trading venues once it collects enough data, especially from swap markets. The proposed rules call for spot-month

position limits at 25% of deliverable supply. The rules also limit non-spot month and all-months-combined positions to 10% of open interest for the first 25 000 contracts owned by a trader and 2.5% thereafter. Bona fide hedging positions will not be counted towards the limits. Also, if a swap dealer's counter-party is a hedger or a swap dealer completes a trade on behalf of a bona fide hedger, then the swap dealer might use bona fide exemption for this specific trade and it will not be counted towards position limits.

Proponents have employed several arguments to justify the need for hard position limits on commodity derivatives markets. They argue that hard position limits on speculative activity ensure the effective functioning of the market by minimising price disruption that could be caused by excessive speculation. They further argue that a hard position limit is necessary to reduce concentration of market share in commodity markets. This will ensure that markets would be made up of a broad group of market participants with a diversity of views, thereby preventing distortion in market prices. The limit on the concentration of market share is also deemed necessary to cut systemic risk. Finally, they argue that rules-based hard position limits are preferable to position accountability levels in that they provide much more certainty as well as preventing arbitrary intervention in the market.

Market participants however have already raised concerns over some issues concerning the proposed rules. Regulators themselves express uncertainty over what the new position limits will bring to the market. As Michael Dunn, Commissioner at the US CFTC, put it "With such a lack of concrete economic evidence, my fear is that, at best, position limits are a cure for a disease that does not exist or at worst, a placebo for one that does."  Market participants' main concerns include the following:

Lack of clarity on how the Commission reached its proposed position limit formula. The Commission has yet to provide a cost-benefit analysis for its proposed rule. Specifically, the Commission provides no evidence or justification that these limits are necessary to prevent the risks it has identified. 

Hard position limits will severely constrain trading activity which would lead to increased, rather than reduced, volatility. Liquidity in futures markets, and especially in swaps markets, will, it is argued, be unnecessarily impaired. Producers and end users would have a smaller pool of counterparty firms to hedge their price risk with, which in turn increases the bid/ask spread, thereby creating more volatility. The proposed rule can also potentially constrain the size of trading entities. This will lead to market dependence on small speculators as institutional investors would be forced out of the market once they reach their respective position limit. This would lower liquidity and increase trading costs. Higher trading costs would, in turn, force some entities to establish smaller positions.

Classifying long-only index position as speculative will restrict access by many individual investors to commodity price exposure. Index funds aggregate the buying and selling decisions of small investors, who invest in commodities due to diversification benefits as well as a hedge against inflation. It is argued that denying the exemption on index funds position limits precludes small investors from a cost effective means of investing in commodities.

Position limits might drive some participants to other markets. Introducing non-universal position limits creates regulatory arbitrage opportunities as some market participants might move their trading activity to less regulated markets. For example, imposing limits on derivatives positions that Exchange Traded Funds (ETFs) can hold will lead to the creation of physical based ETFs that are not subject to position limits, which would eventually have the potential to distort prices.

Within-class position limits inefficiently constrain liquidity and hence increase the likelihood of large price fluctuations. The proposed rule imposes position limits on the individual classes as well as across different trading venues. For example, consider a market in which the position limit is 1 000 contracts. A speculator who is long in 500 futures contracts and short in 1 250 OTC contracts would have 750 net short positions. This trader would be within the all-months all-class limit; however, he/she would be in violation of the OTC class limit.

Meanwhile, on this side of the Atlantic, the European Commission and the UK's FSA convey two opposite views on hard position limits for commodities. The European Commission's consultation report, in line with the US CFTC, urges the need to consider hard position limits on spot month contracts but position management systems for all other contracts, similar to position accountability levels in US exchanges, which will authorise regulators to demand traders to reduce their positions if needed.  On the other hand, the UK's FSA opposes hard position limits for commodities for both exchanges and OTC derivatives, arguing that a position management system is an appropriate tool to maintain fair, orderly and efficient markets.

Spot Crude Oil Prices

Spot crude markets rose on average by $3-5/bbl in January, with only depressed WTI posting smaller gains. Spot prices for lighter, distillate-rich crudes outpaced heavier sour grades as refiners maximised output of gasoil, diesel and jet kerosene. Heavier, sour crudes were relatively weaker due to a worsening fuel crack spread.  Spot crude markets are likely to come under pressure near term given reduced refinery runs for scheduled turnarounds. Indeed, Saudi Arabia, Kuwait, Iran, Iraq, among others, have largely lowered official selling prices fro April liftings.

Once again, in January price trends for benchmark crudes diverged markedly, with spot prices for WTI up a marginal $0.31/bbl on the month, to an average $89.38/bbl. By contrast, Dated Brent crossed the $100/bbl marker at end-January although prices on average in January were lower at $96.54/bbl, an increase of around $5.20/bbl month-on-month.

Spot prices for Dubai crude rose by $3.47/bbl on the month, to an average $92.52/bbl in January.  Besides amplifying WTI's weakness, Brent's relative strength also distorted pricing relationships with other crudes, including Dubai.



In the US, bulging stocks at Cushing and increased flows of Canadian crude into the Midcontinent have triggered steep discounts for WTI relative to its refined value. The WTI-Brent price spread escalated throughout the month, widening to a peak close of $11.06/bbl on 27 January. This compares with an average -$7.16/bbl for the month, -$2.28/bbl in December and -$1.13/bbl in November.

WTI's price weakness has also sharply distorted price relationships with other domestic crudes. Markets have been largely self-correcting though, with differentials to other grades adjusted to compensate for the benchmark's weakness. WTI's discount to Light Louisiana Sweet (LLS) deepened to more than $12.00/bbl in early February, compared with an average $8.40/bbl in January and $5.25/bbl in December. Local refinery runs have remained resilient to try to take advantage of WTI-linked grades' price advantage.

Further underscoring the market's adaptability, producers and traders have, at the margin, turned to shipping bargain-priced crude in the midcontinent, such as new Bakken shale from North Dakota, by rail tanks to the US Gulf Coast refining centre, where higher prices more than offset the transit costs. While volumes are reportedly just 100 kb/d, there are a number of projects underway to boost the ability to make such rail shipments. The influx of new Canadian and Bakken shale into Cushing, Oklahoma is a contributing factor to the growing surplus at the pivotal terminal/storage area.

Few other relief valves are available near-term to ease the glut at Cushing, and proposed plans for a pipeline that would move crude directly from Canada to South Texas has run into permitting problems. TransCanada's Keystone XL line is designed to carry 510 kb/d of Canadian heavy crude but opposition groups argue that increasing US reliance on Canadian oil sands output can occur only at severe environmental cost. Proponents of the line counter that well to wheels emissions from oil sands output are not markedly higher than for conventional supplies.

In Asia, spot prices for regional light crudes posted the strongest gains, with Malaysian Tapis up by $4.39/bbl, to an average $100.35/bbl in January. However, by mid-month the crude's premium started to erode on weaker naphtha cracks.

Brent's lofty premium to Dubai crude has made Middle East crudes linked to Dubai more attractive in the region. The Dated Brent-Dubai premium steepened to just over $4.00/bbl last month versus $2.31/bbl in December. The Brent-Dubai EFS premium increased to an average $4.60/bbl in January compared to $3.30/bbl in December.  Despite the steep price tag for crudes pegged to Brent, Chinese refiners appear willing to pay top dollar for lighter, distillate-rich African crudes given the country's strong demand for diesel.



Spot Product Prices

Spot prices for refined products moved higher in January, with crack spreads for gasoline, gasoil and diesel, and kerosene strengthening in the US, Singapore and the Mediterranean. Crack spreads for middle distillates were supported by winter weather-related heating demand and reduced supplies due to refinery turnarounds. Global refinery throughput rates are estimated to have declined by 800 kb/d from December to January. A further 800 kb/d is expected to be shut-in for maintenance between January and February (see Refining).

In addition, relatively steeper discounts for benchmark crudes WTI and Dubai against North Sea Brent inflated crack spreads versus these grades. By contrast, pricier North Sea Brent crude oil eroded gasoline crack spreads in Northwest Europe.

Gasoil crack spreads were robust in all major markets in January, with New York and Asia posting the strongest gains. In the US, blustery cold weather and record snow falls combined with relatively weaker WTI prices to boost crack spreads in New York by about $5.50/bbbl to almost $20/bbl in January, compared with $14.47/bbl in December and $13.09/bbl in November. At the US Gulf Coast, gasoil differentials for Mars rose by around $2.90/bbl, to around $15.00/bbl, while cracks for Light Louisiana Sweet (LLS) crude were up on average by $2.58/bbl, to $9.64/bbl, in January.



In Asia, robust Chinese demand and expectations that planned refinery turnarounds would significantly reduce supplies supported gasoil cracks in the region, with differentials to Dubai crude up by around $2.10/bbl to $15.67/bbl in Singapore, by around $2.40/bbl to $18.07/bbl in Japan and by $2.15/bbl to $15.15/bbl in South Korea.

In Europe, gasoil cracks posted more modest increases, with differentials to Urals rising by $1.45/bbl to $13.41/bbl on average in January. In Northwest Europe, relatively more expensive Brent curbed gains in cracks, which were up by just $0.22/bbl to $10.07/bbl. By contrast, diesel cracks posted higher month-on-month increases on stronger demand and expectations of tight supplies due to planned refinery maintenance, with differentials to Urals in the Mediterranean up on average by around $2.37/bbl to $18.10/bbl.



Exceptionally in January, jet/kerosene fuel cracks spreads were propelled higher on reduced supplies, as refiners maximised gasoil and diesel output, and by brisk demand. In New York, jet/kerosene differentials to WTI ballooned to $22.69/bbl on average last month compared with $16.30/bbl in December and around $14.85/bbl in November. In Europe, expectations for tighter supplies due to lower refinery throughput rates and reduced supplies from the Middle East buoyed jet fuel cracks in the Mediterranean, up by $3.37/bbl to $16.24/bbl.

In Asia, increased demand from airlines coupled with a significant increase in kerosene used as a heating fuel, especially in northern China, pushed crack spreads up by almost $3.00/bbl to $17.38/bbl on average in Singapore, by around $2.70/bbl to $17.67/bbl in Korea and by $2.40/bbl to $18.96/bbl in Japan.

After steadily rising since last autumn on stronger economic growth and robust petrochemical demand, naphtha cracks spreads weakened across the board in January. Planned maintenance work at crackers, coupled with increased use of relatively cheaper LPG as a feedstock combined to pressure naphtha markets. In Europe, naphtha cracks in the Mediterranean are down a steep 70%, to just $0.94/bbl on average last month. In Northwest Europe, naphtha cracks moved into negative territory, down a sharp $3.80/bbl to -$2.08/bbl.  In Singapore, naphtha differentials to Dubai crude were off 40%, to $2.64/bbl.



Refining Margins

Crude feedstock and product prices were volatile in January, resulting in diverging trends for refining margins. US Gulf Coast margins improved month-on-month, with the exception of Brent cracking margins, which were pressured by high Brent feedstock prices. Margins were supported by higher gasoline prices in the first half of the month and increasing diesel prices throughout January, which especially benefitted coking margins.  

In Northwest Europe, refining margins all weakened month-on-month. Brent crude strengthened throughout January, putting pressure on margins, whereas refinery turnarounds in the Mediterranean region capped Urals price increases. Product cracks, especially for middle distillates, improved in the second half of the month due to turnarounds, but product prices failed to keep up with the rapidly increasing crude prices at month-end, depressing margins again. Refining margins in the Mediterranean improved on average in January, taking advantage of lower priced Urals and higher product prices, both partly the result of the upcoming refining maintenance in the region.



In Singapore and China, refining margins generally weakened in the first part of the month, before improving in the second half on higher product cracks due to stronger demand and the upcoming maintenance season.



Review of Refining Margin Model Changes for 2011

In this 2011 cycle Purvin & Gertz, Inc has incorporated its normal updating of the model series calculations to account for the Worldscale changes effective on 1 January of this year. This includes demurrage rates for the various sized vessels which are used to calculate the estimated lighterage/lightening costs for USGC deliveries primarily.

Several upgrades have been made with respect to operating costs in the models, primarily impacting upon the variable cost escalators in the models. A more representative escalator in calculating catalyst and chemical costs has been adopted. Data have shown that catalyst costs in particular have been understated to some degree in recent historical estimations and this index has been updated retroactively using the Nelson-Farrar Chemical Costs to establish this index. Previously, the models inflated these costs for margin calculations using general inflation.

There are several other minor updates in the series, one related to power cost estimations for the Singapore margin series (retroactive to 2008) based on industry data. Certain consumer price index data are updated for the European models. Most of these factors have a minor impact on the margin series.

A major change in the West Coast index model designs is underway to best reflect the complex and continuing changes in gasoline quality, related to ethanol content in particular, which alters the basis of the refinery produced blending component. West Coast margins are calculated on a refinery basis and not at the terminal where finished product is blended. These updates are expected during the first half of this year, and will be announced and described when those changes occur. Some preliminary updates of the existing models have been made in this cycle, restating historical margins.

Historical series are now available for download at www.oilmarketreport.org. For further details on margins calculation methodologies, please contact Purvin & Gertz, Inc. at kdmiller@purvingertz.com.

End-User Product Prices in January

Average IEA end-user prices in US dollars, ex-tax rose by 4.5% in January. On this basis, price rises were reported across all surveyed products and countries, with the exception of Spain, which reported a 1.7% decrease in low-sulphur fuel oil prices (LSFO). Gasoline (5.6%), diesel (5.9%) and heating oil (5.2%) observed similar average price rises, while LSFO rose by only 1.5% across surveyed countries. Gasoline and diesel prices rose during January in the UK by a significant 6.8%, while year-on-year the increase was 21.5% and 26%, respectively. Meanwhile, France observed gasoline and diesel price increases of 7.9% and 8.5% respectively during the period, while y-o-y gains were 19% and 24%.

Regarding domestic heating oil in January, Canada (6.7%) reported the highest price rise among the surveyed countries. The UK registered the lowest monthly increment of 2.7% for January; but experienced the highest y-o-y rise (30.5%).  Low-sulphur fuel oil for industry registered mild increases in France (3.3%) and Italy (2.9%).

Price changes in IEA countries measured in dollar terms are of course affected also by relative exchange rate shifts. A Comparison between January 2011 and year-ago shows the dollar stronger against the euro but weaker versus the Japanese yen and Canadian dollar. Not surprisingly therefore, dollar denominated price increases were less than in national currency for continental European countries, while the opposite held true for Japan and Canada. January y-o-y price changes in the UK measured between sterling and dollar values were more closely aligned.

Freight

Crude oil tanker rates continued their downward momentum in late-January but then recovered slightly by early-February following localised tonnage tightness and surging bunker fuel prices. The benchmark VLCC Middle East Gulf - Japan route softened to below $10/mt but then firmed to approximately $11/mt by early-February following a rush to fix cargoes before the Chinese New Year holidays.



The Suezmax market appears to have shrugged off concerns of potential disruption in the Suez Canal, with no surges in rates reported for trades transiting the region. The benchmark Suezmax West-Africa - US Atlantic Coast route bottomed out at close to $10/mt in mid-January but then firmed following tighter fundamentals. European markets remained depressed but stable with the Aframax North Sea - North West Europe route remaining range-bound in January at between $5-$5.50/mt following low demand.

Clean product tanker rates fared little better than their dirty counterparts with only the transatlantic UK - US Atlantic Coast trade gaining out of the surveyed benchmark routes. This route stood at $20.80/mt on 1 February, approximately $2.80/mt higher than a month earlier following surging US East Coast gasoline imports. Despite brisk trade in South East Asian markets, rates on the Singapore - Japan route remained soft at close to $16/mt, while rates for Middle East Gulf-Japan rose to over $24/mt before gradually falling back to approximately $22.50 by early-February.

Short-term floating storage of crude and products stood at 55.1 mb at end-January (-1.2 mb m-o-m).  Crude fell by 1.1 mb to 34.9 mb while products decreased by a slight 0.1 mb to 20.2 mb. While the absolute amount of crude has remained relatively stable, the geographical dynamics have shifted. All crude (2.2 mb) previously stored in Northwest Europe has now come ashore, while a 2.1 mb fall was reported in Asia Pacific. These declines were offset by Iranian storage which increased to 23.6 mb (+2.1 mb), while 1.2 mb is reportedly now stored off Southeast Africa. Meanwhile, a 1.5 mb build in refined products in Northwest Europe offset declines in the Mediterranean (-0.2 mb) and West Africa (-1.4 mb).

Data from Simpson, Spence & Young Shipbrokers indicate that, the dirty and clean fleets are forecast to increase by a net 64 and 42 vessels, respectively, by end-2011. With a flat contango currently reducing the economics of floating storage and the storage fleet numbering 42 at end-January, approaching a two-year low, the prospects of a respite from a bloated tonnage pool look bleak. Therefore, localised short-term tightness in fundamentals and high bunker fuel prices look the only likely supports for freight rates over the coming months.

Refining

Summary

  • Global refinery crude throughputs for 4Q10 have been adjusted higher by 150 kb/d, to 74.7 mb/d, approximately 2.4 mb/d above 4Q09. Higher Chinese and Indian crude runs in December, plus revised US November throughputs were the main contributors. Historical adjustments to some non-OECD European and Latin American countries provided a partial offset.
  • Global crude runs are estimated at 74.8 mb/d in 1Q11, 130 kb/d less previously forecast, as higher expected runs in China and Latin America will likely now be offset by lower runs in Europe, the FSU and the Middle East. Stronger expected demand growth in China, as well as continuously high runs in recent months, underpin the revised Chinese forecast. A resumption of operations at refineries in Aruba and the Netherlands Antilles in January will likely boost Latin American runs from weak 2010 levels. Maintenance in the Middle East, the Mediterranean and the FSU in 1Q11 will partly offset these increases however.
  • OECD December throughputs rose by 730 kb/d from November, to average 37.5 mb/d. The sharpest increase came in the US, which saw runs 315 kb/d higher, albeit this was only half the monthly rise indicated by preliminary weekly data. Japanese runs also saw significant gains, taking Pacific crude runs above 7.0 mb/d for the first time since February 2009. In all, December OECD runs were 1.8 mb/d higher than a year earlier.
  • November OECD yields increased for all products except gasoline and 'other products'. Naphtha and gasoline showed the largest changes, as refiners, especially in Europe, increased naphtha production at the expense of gasoline.


Global Refinery Throughput

Global 4Q10 refinery crude runs have been lifted by 150 kb/d since last month's report, given higher throughputs in China and India in December, slightly stronger-than-expected runs in Africa, as well as revised runs for the US in November. 4Q10 runs are now estimated to have averaged 74.7 mb/d, 2.4 mb/d above a year earlier. However, a historical and downward reassessment of crude runs in non-OECD Europe and Latin America partially offset the increase. Chinese refinery runs posted yet another record high in December, despite signs from state refiners that they were planning lower operations. A sharp increase in Indian throughputs also helped lift Asian runs, as Reliance completed maintenance at its 660 kb/d domestic Jamnagar plant. Monthly US data for November lifted runs by some 300 kb/d above levels indicated by preliminary weekly data, moderating the sharp monthly increase in runs to a still-substantial 315 kb/d.

Global throughputs are expected to increase only slightly in 1Q11, to 74.8 mb/d on average, 130 kb/d less than last month's forecast. Higher runs in China and Latin America are more than offset by lower estimates for other regions. Chinese projections have been lifted, not only given recent high run rates, but also due to a now stronger expected demand profile. Latin American runs have been raised given the apparently successful restart of PDVSA's 320 kb/d Curaçao refinery and Valero's Aruba plant in January. Lower expected runs in the OECD (US and Europe) and the FSU, as well as the baseline adjustments made to non-OECD Europe, limit overall increases from 4Q10.



OECD Refinery Throughput

OECD crude throughputs averaged 37.5 mb/d in December, 730 kb/d higher than November and 1.8 mb/d above a year earlier. The monthly increase was concentrated in North America, which saw runs rise by 470 kb/d month-on-month. An upward revision of some 300 kb/d to November US data moderated the sharp monthly increase earlier seen in weekly data. Japanese crude runs also rose in December, by some 270 kb/d, taking Pacific crude runs above 7.0 mb/d for the first time since February 2009.



OECD runs are expected to drop sharply from December highs in 1Q11, but remain flat on a quarterly basis, averaging 36.3 mb/d. Maintenance normally peaks in March in both Europe and North America, but somewhat later in the Pacific. Weekly data for the US already show significant declines in utilisation rates in early 2011, in particular on the Gulf and West Coasts. With increased runs expected in Latin America, US refiners will find less support from strong export markets seen in 2010. European runs, in particular in the Mediterranean, are expected to be cut by heavy maintenance.



North American crude runs were up almost 0.5 mb/d from a month earlier in December. Growth came mostly from the US, but increases were also recorded in Mexico and Canada, where maintenance had cut runs in October and November. Revisions to US November throughputs, now some 300 kb/d higher than reported by weekly data, result in a more modest monthly increase in US runs of 315 kb/d, compared to 630 kb/d as indicated by preliminary weekly data.



Weekly data for January suggest that refinery runs in the US fell back from the high levels of the end of the year, dropping by almost 600 kb/d from December (and falling by 200 kb/d more than expected). Refinery runs were 280 kb/d lower 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.

More noteworthy, perhaps, is the fall in West Coast runs, to only 73.5% utilisation on average in January, compared with 81.7% in December. Part of the decline can be attributed to the supply disruptions of the ANS pipeline in Alaska, which caused a halt in operations at Flint Hill's 220 kb/d North Pole refinery in Alaska. Maintenance at Valero's Benicia and Shell's Anacortes plants on the West Coast also contributed, compounded by deteriorating regional cracking margins.



Runs in the Midcontinent held up, by contrast, averaging 90.2% utilisation in January, the highest in the country. PADD 2 refiners are encouraged to keep runs high by steep discounts for spot crudes, as the region struggles with excess supplies and a massive stock overhang. US refiner Valero said it was maximising sweet crude runs at Midcontinent refineries to benefit from the regional supply glut. Normally refiners would wind down runs at this time of the year, but cheap WTI has apparently led several refiners to delay maintenance in order to take advantage of the improved margins. Swelling regional product stocks could undermine product cracks and runs in coming months, however, unless demand picks up from current levels.

BP announced plans on 1 February that it hopes to divest half its US refining capacity by the end of 2012, making it the smallest refiner among the integrated majors. The company plans to sell its 475 kb/d Texas City refinery, which was the site of a major accident that killed 15 and injured 170 people in 2005, and its 265 kb/d Carson, California refinery along with its marketing interests. According to a company statement, the decision to sell the refineries is the result of a two-year review into improving the company's downstream assets portfolio and has nothing to do with the need to raise cash in the wake of the Macondo oil spill.

OECD European refinery runs for December were mostly flat from a month earlier, and in line with expectations. At 12.6 mb/d, regional runs were nevertheless some 700 kb/d above end-2009 rates. Runs in the Netherlands recovered somewhat, after refiners had operated at reduced rates since September, when Shell started maintenance at the catalytic cracker of its 412 kb/d Pernis refinery, Europe's largest. According to a company official, the catalytic cracker, which produces gasoline and diesel, was still not working in early February, and would not restart until at least the end of February.

Apart from the reduced runs at Pernis, regional maintenance in the first quarter is concentrated on the Mediterranean. Some estimates put a fifth of Mediterranean capacity closed in 1Q11, significantly tightening local product supplies and boosting margins. Our own estimates of maintenance are somewhat lower than those quoted in the press, but include ERG's Isab Sud plant in Sicily, ENI's Taranto plant, Esso's Fos Sur Mer refinery in southern France, Greece's Thessalonika and Corinth refineries among the plants that are closing for maintenance or reducing rates.

Since last month's report, LyondellBasel has announced it is considering closing the 105 kb/d Berre L'Etaing refinery in Southern France. If closed, the plant would be the third announced closure in France within a year. Total already closed its 140 kb/d Dunkirk refinery in early 2010, and will permanently reduce capacity at its Gonfreville refinery, while Petroplus recently confirmed that it intends to go ahead with the closure of its 85 kb/d Reichstett refinery in Eastern France announced in October last year. If the closures mentioned above are confirmed, total French refinery capacity will reduced from close to 2 mb/d in early 2010, to 1.56 mb/d once completed.



OECD Pacific crude runs averaged 7.0 mb/d in December, the highest since February 2009. Regional runs were 280 kb/d higher than November and 330 kb/d above a year ago, with the increase from a month earlier almost entirely accounted for by Japan, where maintenance ended. On an annual comparison basis however, growth is mostly coming from South Korea, supported by more robust domestic demand compared with its neighbour. Japanese oil product demand returned to its path of structural decline in the fourth quarter, after a temporary surge due to high temperatures over the summer.

Preliminary weekly data from the Petroleum Association of Japan (PAJ) show Japanese runs in January only slightly above expectations and closely in line with the previous year. Japanese refiner Idemitsu Kosan announced it is planning to raise 1Q11 throughputs 1% from a year earlier, and 70 kb/d above 4Q10, in order to meet increased export demand. A company official said supplies to the domestic market will continue to contract in the first quarter (-2% y-o-y) but strength in overseas markets was supporting runs. Australia's Caltex restored full operations at its 109 kb/d Lytton refinery on 24 January, after having been forced to shut on 5 January due to heavy rain and floods.



Non-OECD Refinery Throughput

Non-OECD refinery crude run estimates for 4Q10 are largely unchanged from last month's report, at 38.4 mb/d, as higher Chinese and Indian throughputs in December as well as slightly stronger African runs were more than offset by revisions to historical data for non-OECD Europe and Latin America. Chinese refiners processed at another record high level in December, despite plans to slow runs, and Indian runs rebounded sharply from maintenance lows seen in October and November. A reassessment of historical data for non-OECD Europe and Latin America, however, mostly offset the higher readings.

1Q11 non-OECD crude runs, on the other hand, have been lifted by close to 200 kb/d from last month's report to 38.5 mb/d on average. A stronger demand profile for China for 2011 leads us to expect runs to be sustained at high levels, though some questions regarding profitability with crude prices around $100/bbl, remain. Higher runs in Latin America further underpin the revised run estimates, given the apparent successful restart of PDVSA's Curaçao refinery in the Netherlands Antilles in January. The restart of Valero's Aruba refinery, which reached planned rates late January after having been shut since summer 2009, further adds to lifting Latin American runs above the depressed levels seen in most of 2010. The announcement by Hess that it will permanently shut parts of its 500 kb/d St Croix refinery in the US Virgin Islands will likely have a minimal effect on throughputs as the plant has been running at reduced rates for some time.



Chinese refiners surprised yet again to the upside in December, processing a record 9.156 mb/d of crude oil. The 200 kb/d monthly increase in throughputs came despite the country's largest refiners having signalled they were planning lower runs for that month. Year-on-year, runs were 1 mb/d higher, the strongest annual increase since May 2010. Refiners have been ramping up production to cope with diesel shortages triggered by increased demand from stand-alone power generators since late last autumn. According to customs statistics, China became a net importer of gasoil for the first time in more than two years in December. Preliminary plans are for another rise in runs in January, to 9.3 mb/d, according to industry surveys.

Total Indian refinery throughput is estimated to have averaged 4.1 mb/d in December (allowing for 660 kb/d runs at Jamnagar's export refinery - excluded from Ministry statistics - as reported in RILs quarterly earnings report). The sharp increase, of some 300 kb/d, was mostly due to an increase in runs at Reliance's domestic Jamnagar plant, which rose by 200 kb/d as maintenance was completed. The company shut a 330 kb/d crude distillation unit and a coker unit for 22 days in October-November. IOC's Panipat refinery, which was expanded to 300 kb/d in November from 240 kb/d previously, also contributed to the increase. However, private refiners Reliance and Essar's product exports dropped by 13.3% to 960 kb/d in January from December's high of over 1 mb/d. 

Industry sources have reported that India's Bharat Oman Refineries Limited will start commercial operations at its new Bina refinery in mid-February. The company started commissioning its 120 kb/d crude and vacuum distillation units in June 2010 but delays in setting up a captive power plant at the facility has postponed commercial start-up. Bina will refine a mix of 65% Arab Light and 35% Arab Heavy crude. Heavy maintenance in May will drag Indian runs lower. Amongst others, Essar will shut its Vadinar refinery for 35 days starting in May to expand capacity to 360 kb/d. The company plans to further boost capacity to 400 kb/d by September 2012 by debottlenecking some units.



Taiwanese runs for November were reported at only 800 kb/d, again about 100 kb/d lower than our expectations. Taiwan's largest refinery, Formosa's 540 kb/d Mailao plant, is still struggling to recover from a fire in July last year. The petrochemical company is planning to shut one of its three 180 kb/d CDUs and the 84 kb/d RFCC from mid-March for maintenance lasting 40 days, and run only at 300 kb/d while work is being done.

Russian crude runs averaged 5.1 mb/d in December, unchanged from November but 290 kb/d higher than a year earlier. Throughputs are expected to fall during the first quarter as maintenance picks up again after winter. The energy ministry and trade sources report that several crude units will be shut for maintenance in the first quarter, with more than 300 kb/d announced offline in March. Kazakhstani crude runs rose by almost 50 kb/d in December to average 300 kb/d as maintenance at PetroKazakhstan's Shimkent plant was completed.

TNK-BP announced in January that it is considering shutting its 175 kb/d Lisichansk refinery in the Ukraine in the first quarter unless the government addresses what the company calls discriminatory market conditions. Ukrainian refineries face strong competition from oil product imports from neighbouring Belarus and Kazakhstan, who supply local markets with fuels made from cheaper foreign crude. The company has asked the government to impose import duties on oil products or give domestic refiners access to cheaper Ukrainian crude. Lukoil already closed its Odessa refinery for maintenance in 4Q10, several months earlier than planned, due to poor economics, and plans to run the refinery only in the second and third quarter when product demand is higher. The three-week long disruption of Russian crude deliveries to Belarusian refineries in January is thought to have had a limited impact on refinery operations given its relative short duration.

African crude runs continue to be supported by strong runs reported for Egypt since August 2010 (JODI data), and there are no indications that recent turmoil are affecting runs. In Nigeria, however, runs dropped sharply in December as both the Kaduna and Warri refineries had to be closed due to militant attacks on the pipeline that feeds both refineries. At 140 kb/d, November runs were the highest since July 2008, but then plummeted to only 55 kb/d in December following the attacks. Nigeria has a nameplate capacity of 445 kb/d, but the refineries only run around 30%. State-owned NNPC reportedly restored runs at the refineries at the end of January.



Middle Eastern crude runs have been revised slightly higher for December, given stronger Saudi throughputs. These averaged 1.85 mb/d in the month, the highest since August. Middle Eastern runs are expected to fall in 1Q11, as several plants shut for maintenance. In Saudi Arabia, Aramco has announced it will shut its 235 kb/d Yanbu refinery from early February for 39 days. It is also planning to shut one 150 kb/d crude unit at its Jubail refinery in late February for 45 days, as well as a full shut down of Petrorabigh (425 kb/d) from late April to end-May. Some maintenance shutdowns in Kuwait and Bahrain will further reduce regional product supplies.



1Q11 Latin American crude run estimates have been lifted following the apparent successful restart of PDVSA's Curaçao refinery in the Netherlands Antilles. The plant, which has been closed since March 2010 due to power problems, reportedly restarted its crude units in January, though is still experiencing some problems with secondary units. Heavy rains and storms across Venezuela in late November/early December caused electrical faults and forced PDVSA to halt operations at its 310 kb/d Cardon refinery in late November, according to the state company. The nearby 645 kb/d Amuray and 146 kb/d El Palito refineries were also affected, with some units down. All refineries were reportedly operating normally in early December. Valero reported at the end of January that its 235 kb/d Aruba refinery had reached planned rates (we assume these to be 180 kb/d). On 4 February, however, the refinery was forced to shut, however, as the collapse of a freshwater storage tank damaged some oil products pipelines.

After several months with reduced runs, Brazilian crude throughputs reached a record high of 1.95 mb/d in November (90 kb/d higher than expectations and 160 kb/d above October). Hovensa, which is a joint venture between US's Hess and Venezuela's PdV, announced that it will permanently shut 150 kb/d of crude capacity at its 500 kb/d St. Croix refinery in the US Virgin Islands by the end of March because of poor margins. The shutdown will not affect any of the upgrading units and will likely have a limited impact on operating rates as the refinery has been running at reduced rates for some time. According to the company's latest quarterly earnings report, the plant's crude runs averaged 384 kb/d in 4Q10.

OECD Refinery Yields

November OECD yields increased for all products except gasoline and other products. The largest changes were for naphtha and gasoline, where refiners, especially in Europe, increased naphtha production at the expense of gasoline. OECD naphtha yields increased by 0.7 percentage points (pp) to reach the upper range of the 5-year average. Yields increased in all three OECD regions, but the rise was particularly strong in OECD Europe where yields increased by 1.54 pp. High naphtha demand from the petrochemical industry as LPG prices were strong was the main reason behind the increase.



OECD gasoline yields fell by 1.1 pp in November, and again Europe posted the largest fall with a decrease of 1.18 pp, to an overall gasoline yields level below 21%. Low gasoline spreads, high stock levels and a partly closed arbitrage to the US are factors explaining the shift. The gasoil/diesel yields trended seasonally higher, with increases in OECD North America and OECD Europe, partly offset by a decrease in the Pacific. OECD fuel oil yields increased in all regions as runs in general were high in addition to an open arbitrage between the US Gulf and Asia, and high bunker fuel demand in Singapore.



OECD gross output rebounded from the low levels seen in October as French refineries came back after strike action. Gross output in OECD Europe increased by 974 kb/d from the previous month and was in November 571 kb/d higher than in November 2009, but still some 940 kb/d lower than the five-year average. However, gross output in OECD North America was 400 kb/d higher than the five-year average in November.