Oil Market Report: 10 February 2012

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Highlights

  • An uneasy balance characterised oil markets in January, with tensions surrounding Iran counteracting a weaker economic outlook. The onset of winter weather pushed prices for Brent to six-month highs in early February. Brent was last trading at $117.50/bbl. By contrast, rising stocks at the Cushing storage depot pressured WTI prices lower in early February, to $99.50/bbl.
  • Global oil demand is forecast to climb to 89.9 mb/d in 2012, a gain of 0.8 mb/d (or 0.9%) on the year. Growth has been curtailed by 0.3 mb/d versus January's OMR, as the economic growth rate that underpins the global oil demand outlook has been reduced to 3.3% from 4.0% previously.
  • Non-OPEC supply fell by 0.2 mb/d to 53.2 mb/d in January, on lower global biofuels output, an escalation of conflict in Syria and between Sudan and South Sudan, and continuing outages in the North Sea. North American light tight oil production and NGLs, as well as increasing production in Latin America, offset declines elsewhere, supporting an expected 0.9 mb/d rebound in non-OPEC supply in 2012.
  • OPEC crude oil supply in January rose to 30.9 mb/d, the highest level since October 2008, on a steady ramp-up in Libyan production and sustained output from Saudi Arabia and the UAE. The 'call on OPEC crude and stock change' is cut by 100 kb/d for 2012, to 29.9 mb/d. OPEC's 'effective' spare capacity is largely unchanged, at 2.82 mb/d.
  • Global refinery crude throughput estimates for 1Q12 are largely unchanged from last month's report, as slightly higher OECD runs are offset by a weaker outlook for Latin America, following further capacity rationalisation. At 74.9 mb/d, global 1Q12 runs are forecast 220 kb/d above year-ago levels and unchanged from the previous quarter.
  • December OECD industry oil stocks declined by 40.8 mb to 2 611 mb, and remained below the five-year average for a sixth consecutive month. Forward demand cover fell by 0.7 days to 57.2 days, but remains 1.6 days above the five-year average. January preliminary data show a shallower-than-normal 11.4 mb build in OECD industry stocks.

Don't forget the bit in the middle

It is tempting, amid economic turmoil on one hand, and a ratcheting higher of tensions over Iran on the other, to see the oil market via the polar extremes of end-user demand and crude oil production. For sure, this month's report dwells on recent economic downgrades, and resultant weaker oil products demand growth for 2012. As we noted last month, this is providing a ceiling for otherwise stubbornly-high crude prices. Equally impossible to ignore is the influence of conjecture over the potential impact of international sanctions on Iranian crude supplies. In that regard, the market in 2012 likely has sufficient supply-side flexibility (between existing OPEC spare capacity and expected 2012 capacity additions among OPEC and non-OPEC producers) to adjust to any loss in Iranian volumes. There is also, as ever, the back-stop provided by strategic stocks in the event that market mechanisms fail. Despite these assurances, perceptions of impending supply issues are clearly placing a floor under oil prices for now.

However, simply focusing on the extremes of final oil product demand and upstream production capacity neglects the ever-important influence on markets and prices of the midstream and downstream segments of the industry. Changes in the availability of pipeline capacity and marine tankers, shifts in strategic storage and fluctuations in refinery processing capacity can all play a role in influencing not just absolute prices but, more importantly, price differentials, arbitrage flows and therefore overall market dynamics. While the potential for economic meltdown or heightened geopolitical tension makes good headlines, and provides an envelope for prices in general, it cannot wholly explain price dynamics. 

The renewed widening of Brent's now entrenched premium to WTI is a case in point. There are multiple contributory factors, but a shortage of pipeline capacity to evacuate crude from the US Midwest to US Gulf refineries is central to the issue. An added twist is the deferral of the Keystone XL pipeline project, even though that decision will arguably prompt development of alternative routes to the US Gulf or, longer term, push Canadian crude towards the Pacific Coast. In a global context, strong relative Brent prices would normally confine Atlantic Basin crudes within the region. However, Japanese power sector oil demand, after nuclear capacity shutdowns, is strengthening Asian fuel oil prices, and so too heavier Middle East crude prices. An arbitrage for Brent-linked African crudes into Asia has therefore opened.

The importance of logistical infrastructure is also emphasised by the current Sudan-South Sudan stalemate. A pipeline tariff dispute is depriving Asian buyers of marginal barrels of fuel oil-rich crude, also used for direct burning. If the situation continues, it may boost the attractiveness to Asian buyers of Iranian barrels offered into the region at discounted prices, notwithstanding EU and US sanctions. 

Another overlooked element in the Iranian situation concerns confusion over the likely implementation of the US and European financial measures. This is causing marine insurers and ship owners to be doubly cautious over the cover they provide or the routes they sail. It will likely complicate crude shipments, not only those transiting the Middle East Gulf, but also on a broader global basis. Why take a risk on insuring a vessel that has regularly called at Iranian ports in recent months, if it might result in punitive economic measures from the middle of the year? That said, ample new-build tanker capacity may ease the impact of what might otherwise be a logistical barrier to trade.  

We also note this month that incremental midstream demand, for example to fill new strategic storage capacity in China, could pull upwards of 200 kb/d extra crude into Asian markets, over and above rising regional products demand and refinery runs. Finally, the apparent paradox of weakening European 2012 oil demand, but strengthening refining margins, looks less puzzling when recent refinery rationalisation is taken into account. A spate of actual and threatened closures, from Petroplus plants in Europe, through to major export-oriented units in the Caribbean, plus a late-winter freeze in Europe and Asia, have driven products cracks sharply higher, despite an increasingly gloomy economic picture. The midstream and downstream meat in the sandwich is often just as interesting as the more visible bread that surrounds it.

Demand

Summary

  • An increasingly problematic global economic backdrop - confirmed by the IMF lowering its economic projections - is seen supporting 0.8 mb/d of oil demand growth in 2012 (versus 1.1 mb/d in January's OMR). Global GDP growth is revised down to 3.3% for 2012, from the 4.0% level assumed since September. Total oil product demand will climb to 89.9 mb/d in 2012, from 89.1 mb/d in 2011.
  • A two-speed outlook prevails - with robust oil demand growth envisaged in the non-OECD, while demand continues to fall across most of the OECD. Non-OECD oil demand will rise by 1.2 mb/d (2.8%) in 2012, more than offsetting the reduction in OECD consumption of 0.4 mb/d (0.8%), mimicking the demand trends seen in 2011.
  • The most recent data suggest a global demand contraction of 5 kb/d in the fourth quarter of 2011 year-on-year, the first such drop since the global credit crunch, albeit 4Q demand in North America and non-OECD Asia came in stronger than preliminary data suggested. Europe saw the steepest year-on-year fall in 4Q11, with demand 690 kb/d lower amid weaker economic activity and mild weather. North American demand was 530 kb/d less than a year ago.


Global Overview

The world economy is now expected to expand by 3.3% in 2012, according to the IMF's January update, a sharp deterioration from its previously assumed 4.0% growth. The largest adjustments are applied to the euro area, down by 1.6 percentage points since September and leaving an absolute euro zone contraction of 0.5% in 2012. Much of Europe already saw declines in economic activity in 4Q11 and with further drops assumed for the 1Q12, this equates to the technical definition of recession. Non-OECD Europe, saw similar stark reductions, with 1.6 percentage points extracted from their growth estimates, to 1.1%.

In North America, the US outlook remained unchanged, at 1.8% GDP growth in 2012. However, both Canada and Mexico saw slight downgrades. The Mexican economy is now forecast to grow by 3.5% in 2012 (3.6% previously), while the Canadian estimate was reduced to 1.7%, from 1.9% previously.

A combination of the worsening external environment and weakening internal demand, meanwhile, curtailed the IMF's estimate for economic growth in the emerging economies, to 5.4% for 2012 (previously 6.1%). Notable reductions in expected 2012 economic growth affect China (8.2% versus a previous 9.0% estimate), India (7.0% versus 7.5%) and Brazil (3.0% versus 3.6%). Underlying the overall forecast is the IMF's assumption that European policymakers intensify efforts to address the debt crisis. Without such cohesive action, the Fund sees a worse economic outcome likely to occur.



Having grown by as much as 5.0% in 2010, the global economy decelerated sharply in 2011, to 3.8%. Global oil demand rose from 85.6 mb/d in 2009, to 88.3 mb/d in 2010 and 89.1 mb/d in 2011, implying growth of 2.8 mb/d in 2010 and 0.7 mb/d in 2011. Admittedly, the 2010 trajectory was magnified by a post-recessionary bounce, but the sheer scale of the 2011 slowdown surprised most analysts. Our own projections for 2011 were progressively scaled back, from initial 4.3% GDP growth and 1.3 mb/d of incremental oil demand.



Despite the economic backdrop darkening further in 2012 - with global growth of just 3.3% envisaged - global oil demand is forecast to average 89.9 mb/d, up 0.8 mb/d on 2011. Growth marginally accelerates as prices, based on the futures strip, are unlikely to have the same negative influence on demand as in 2011.

Middle distillates will provide the majority of global demand growth in 2012, with gasoil demand projected to rise by 1.6% supported by the still relatively strong industrial base in emerging markets.  Consumption of fuel oil and gasoline lags behind, with demand growth in these products forecast to inch just 0.4% higher in 2012. Fuel oil demand is suffering at the hands of switching to other less polluting fuels. Gasoline demand is ailing due to the continued, albeit slowing, trend in many parts of the transportation sector towards diesel and the plateau in car sales across the OECD.



OECD

Preliminary data for December imply an OECD-wide decline of around 1.2 mb/d (or 2.6%) on the corresponding period a year earlier, leading to a 4Q11 drop of 1.0 mb/d or 2.1% over 4Q10. Europe, predictably given the weak economic backdrop, led the downtrend, with year-on-year demand decline of 0.7 mb/d seen in both December and 4Q11 overall.



Gasoline, gasoil and LPG demand in the OECD weakened in December, with all three seeing respective year-on-year demand declines of 0.4 mb/d. Only residual fuel oil bucked December's falling OECD demand trend, with a 0.1 mb/d y-o-y gain seen as the Japanese power sector continued to run fuel oil after mid-March's tsunami-related closures of nuclear facilities.

OECD demand is expected to fall by 0.4 mb/d y-o-y in 2012, or 0.8%, with gasoline accounting for more than 40% of the decline. In contrast, gasoil/diesel demand in the OECD should edge down by a more modest 35 kb/d (-0.3%). It is assumed that economic slow-down is sharpest in 4Q11 and 1Q12, so that the annual oil demand contraction tapers off running through 2012.



North America

The latest preliminary statistics for December point towards sharply falling North American demand, down 4.1% on the corresponding reading a year earlier, despite numerous reports of economic resilience. Our estimates suggest a US demand contraction of more than 5% in December, with particularly sharp declines for heating oil and LPG given unseasonably mild weather. 



The US economy has recently been showing signs of recovery. Early indicators of 4Q11 GDP growth point towards a 2.8% expansion, not far off its long term trend, while robust statistics have emerged in the employment and Purchasing Managers Indices (PMI). Consumption of oil products has however failed to match the more supportive economics, a consequence we believe of cash-strapped US consumers' heightened aversion to high prices. US gasoline prices, for example, have been clearly above year earlier levels since the end of 2009. The premium over previous year prices peaked, just shy of 40%, in May 2011, coinciding with a period of 3% year-on-year contraction in gasoline demand, a trend that appears to have become entrenched.



Despite starting 2011 in growth territory, US consumption has edged lower ever since, with the pace of the decline escalating to around 3% in both 3Q11 and 4Q11, taking demand to 18.7 mb/d. US demand is expected to decline by around 2% in the first quarter of 2012 and by 1% in the second quarter. The strengthening economy, from mid-year, could then support a slowly recuperating US demand trend. Nonetheless, US consumption for the year as a whole is seen edging 0.5% lower, equivalent to a decline of around 0.1 mb/d.

Europe

In line with the weak economic outlook, European oil demand will likely post the greatest relative decline in 2012, down by 0.3 mb/d from 2011 at an average 13.9 mb/d. The LPG, fuel oil and gasoline categories are forecast to contract most sharply, down by 4.7%, 4.4% and 3.7% respectively in 2012. Indeed all of the major European product sub-categories will see demand contractions, as the weaker economic backdrop coupled with persistently high assumed prices act to suppress consumption.



Preliminary December data point towards a year-on-year slide in OECD European oil demand for 4Q11 of 0.7 mb/d, or 4.7%, reflecting both economic slow-down and mild winter weather. Markit's Composite PMI (which tracks the overall health of the economy) for the euro zone fell to 48.3 in December - clearly signalling a decline in business sentiment (whereby any reading below 50 signals a contraction) - whereas the more oil-intensive Manufacturing PMI fell even further, to 46.9.



Having led the drop in 2011 consumption, the heavily indebted economies of southern Europe are expected to continue to dominate the forecast contraction in OECD European demand in 2012. Italian demand, for example, will fall by 4.9% (or 70 kb/d in 2012), as the IMF predicts a further economic drop of around 2.2%. The Italian forecast follows on from December's stark 7.6% contraction, with the residual fuel oil (-24.8%), naphtha (-15.4%) and LPG (-13.8%) categories particularly weak. The Italian manufacturing PMI fell to 44.3 in December. Spain will also see demand drop by around 4.5% in 2012, with the IMF predicting a 1.7% fall in economic activity. The Spanish projection comes on the back of December's 7.4% year-on-year drop. The manufacturing PMI for Spain fell to 43.7 in December.

Slightly stronger demand is foreseen in the more northerly European nations. German demand, for example, is expected to fall by just 0.5% in 2012. The IMF's latest economic projection for Germany points towards a modest gain of 0.3% in 2012. The preliminary December series for Germany depicted a 0.8% year-on-year gain in demand. Mild December temperatures suppressed German heating oil demand, which fell by 14.5% on its year earlier level. Demand in the Netherlands is expected to fall by less than 1%, with GDP growth assumed at 0.2% in 2012.

French December demand more closely matched the south European trend, declining y-o-y by 10.9%. Heating oil (-39.7%) and LPG (-27.0%) led the decline, underpinned by milder than normal December temperatures. The generally ailing economic backdrop, with unemployment above 10% and broadly flat GDP foreseen for 2012, is expected to keep oil demand on a declining 2% trend.

Pacific

OECD Pacific demand in December grew by 5.5% y-o-y. Gains in diesel (+3.9%), residual fuel oil (+22.9%) and other products (+40.2%) - including direct crude oil burning - drove the rise on the back of cold weather and low nuclear capacity availability (see box, below). December heating degree-days (HDDs) in the region were above both the ten-year average and the previous year, especially in Japan.



The recent decline in South Korean demand continued with December's 1.8% year-on-year contraction. Worsening business conditions in the Korean manufacturing sector further undermined oil demand, as the PMI fell for a fifth successive month to 46.4. Korean demand will modestly expand by 15 kb/d (or 0.6%) in 2012, to 2.24 mb/d.



Japanese oil demand grew in December by 9.5% year-on-year, lifted by greater consumption of residual fuel oil (58.3%) and other products (54.9%) on the back of additional power generation demand amid nuclear capacity closures. Taking into account the current fuel mix in the power sector, total Japanese demand will edge 0.9% higher in 2012, to 4.5 mb/d. Demand growth in the OECD Pacific region in general will accelerate very slightly, to 0.8% (adding 0.1 mb/d of additional demand), to 7.9 mb/d.

Outlook for Japanese Power Sector Oil Demand

Back in August 2011, the OMR carried out an updated assessment of the impact of nuclear outages in Japan (see Nuclear Outages See Japan's Power Sector Turn to Thermal, OMR dated 10 August 2011). Only 16 nuclear reactors were operational and the distinct possibility existed that all 54 reactors could be idle until May 2012. In that report, we estimated that incremental oil demand could amount to 230 kb/d in 2011 and grow to 270 kb/d in 2012 versus an outlook of 'normal' nuclear generation (see chart; combined crude and fuel oil generation demand was about 200 kb/d in 2010).  Our latest update, based on nuclear capacity dropping to less than 0.9 TWh in April and slowly coming back online to 15 TWh by December 2012, now suggests incremental oil demand in the power sector of 280 kb/d in 2011 and 320 kb/d in 2012. This expected incremental demand implies an upward revision of 50 kb/d for both years. Should all nuclear plants remain idle after April, then incremental oil demand could reach 465 kb/d versus an outlook of normal nuclear generation.

Fossil fuel powered plants (FFPP) generated 60.4 TWh in December, a year-on-year expansion of 41.7%, backed by the nuclear outages and colder-than-normal temperature. Residual oil and crude consumption at FFPP came in at 560 kb/d in December, 470 kb/d more than would have been assumed in pre-tsunami Japan. The incremental need for oil in the power sector offset contracting demand elsewhere in the economy and led to Japanese oil demand rising overall in 2011 by 34 kb/d or 0.8%. Our latest projection envisages total 2012 Japanese oil demand growth of 42 kb/d or 0.9%, with the power sector demand averaging 320 kb/d, again offsetting weaker lighter products requirements.



Overall, the Japanese oil demand outlook remains highly uncertain, and the possibility of a 'no nuclear' capacity profile, at least for 2012, remains a real one. Demand will also be influenced by efforts put in place to improve end-use efficiency; the impact of weaker economic growth; and the potential for renewed weather extremes such as were seen in summer 2010. Nonetheless, sustained Japanese power sector oil demand will likely be one of the few growth areas for OECD oil consumption in 2012.

Non-OECD

Maintaining its relatively strong expansionary backdrop, the non-OECD region will see demand growth of 1.2 mb/d (or 2.8%) in 2012, to average 44.6 mb/d. The industrially important gasoil market will predominate, forecast to provide 0.4 mb/d of the projected 2012 gain in oil demand. The non-OECD will dominate in oil demand terms as not only are many of its economies more heavily dependent upon oil, but they are also driven by stronger underlying economic growth. Economic growth in the emerging and developing economies averages 5.4% in 2012.



Having started 2011 in a strongly expansionary phase, with oil demand up 6.1% year-on-year in January, the non-OECD demand trend has subsequently slowed, with preliminary data for December pointing towards 1.0% year-on-year expansion, its slowest pace of growth since April 2009. Putting the slowdown in perspective, the comparison is against exceptionally strong demand for late-2010 in particular.





China

The outlook for Chinese oil demand has been curtailed, on the back of weaker economic underpinnings, with growth of 0.4 mb/d (or 3.9%) now estimated for 2012. A previous GDP growth assumption of 9% for 2012 has now been curbed to 8.2%. This lower growth assumption, along with higher domestic prices, underpins the trimmed demand projection. Moreover, some analysts have been pointing to the prospects for weaker Chinese growth, amid concerns over the impact of an ailing property market and sluggish manufacturing indicators.







Preliminary estimates of apparent demand in China - net product imports plus refinery output - point towards a near stagnation in demand in December and the fourth quarter in general. However, year-on-year comparisons for China post-September have to be treated with caution given 2010's unusually high fourth quarter demand strength. The fourth quarter of 2011 was a mixed bag, with strong gains in the jet/kerosene (+16.9%) and LPG (9.6%) categories cancelling out big drops in other products (-8.6%) and residual fuel oil (-4.1%).



Other Non-OECD

The preliminary December data for India matched our forecast from a month ago, of 3.5% year-on-year growth. Strong gains in gasoline (+11.5%), gasoil (+6.0%) and LPG (+5.3%) offset declines in naphtha (-20.8%), residual fuel oil (-18.2%) and jet/kerosene (-2.4%). The 4Q11 demand estimate came in at 3.6 mb/d, 0.2 mb/d (or 5.9%) higher than 4Q10, and a rise of 50 kb/d compared with last month's estimate. This higher baseline, and an economic growth assumption of 7.0%, combined to generate oil demand growth of 120 kb/d (3.4%) in 2012.



Argentinean oil demand grew in December by 1.9% following 1.3% growth in November and continuing the rising trend evident since mid-year. Strong growth in gasoline (29.2%) and fuel oil (25.1%) outweighed the hefty declines in other products (-10.8%). Resilient economics have supported the relatively strong demand dynamic, as industrial output rose by 2.8% year-on-year in December, while car sales rose 32%. Having risen by close to 30 kb/d (4%) in 2011, demand growth will abate to a more subdued 10 kb/d (1.3%) in 2012 as the projected growth rate of the economy roughly halves to 3.7%.



Supply

Summary

  • Global oil supply rose by 0.1 mb/d to 90.2 mb/d in January, with gains in OPEC NGLs and crude production offsetting a 0.2 mb/d decline from non-OPEC countries. Compared to a year ago, global oil production stood 1.0 mb/d higher in January, 80% of which stemmed from increased output of OPEC crude and NGLs.
  • Non-OPEC supply fell by 0.2 mb/d to 53.2 mb/d in January, on lower global biofuels output, an escalation of conflict in Syria, a worsening dispute over transit revenues between Sudan and South Sudan, and continuing outages in the North Sea. North American light tight oil production and NGLs, as well as increasing production in Latin America, offset declines elsewhere and should support a strong non-OPEC supply rebound, with growth of +0.9 mb/d expected in 2012.
  • OPEC crude oil supply in January rose to 30.9 mb/d, the highest level since October 2008, largely reflecting the steady ramp-up in Libyan output, as well as sustained output from Saudi Arabia and the UAE. New international sanctions targeting Iran's oil exports do not take effect until 1 July, but several European customers have already curtailed imports of Iranian crude and Asian buyers are also moving to line-up alternative supplies.
  • The 'call on OPEC crude and stock change' is reduced by 100 kb/d for both the first half of 2012 and the year as a whole. It averages 29.8 mb/d for 1Q12 and 29.2 mb/d for 2Q12. At 29.9 mb/d, the 2012 'call' is 700 kb/d below the 2011 average, due to a combination of higher non-OPEC supply and OPEC NGLs. OPEC's 'effective' spare capacity is estimated at 2.82 mb/d, largely unchanged from last month.


All world oil supply figures for January discussed in this report are IEA estimates. Estimates for OPEC countries, Alaska, 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 ?200 kb/d for non-OPEC as a whole, with downward adjustments focused in the OECD.

OPEC Crude Oil Supply

OPEC crude oil supply in January rose to 30.9 mb/d, the highest level since October 2008, largely reflecting the steady ramp-up in Libyan production as well as sustained high levels of output from Saudi Arabia, Kuwait and the UAE. The increase in Libyan production was partially offset by small monthly declines from Iraq, Kuwait, Angola, Nigeria and Venezuela.

OPEC supply was 900 kb/d over the group's 30 mb/d collective output target agreed at its mid-December ministerial conference in Vienna. After OPEC's consensual meeting at year-end, Iranian Oil Minister Rostam Qasemi sharpened the rhetoric in recent weeks by warning Arab OPEC members not to increase production to replace any Iranian barrels shut out of the market due to tighter sanctions on the country's oil and banking sectors. As anticipated, on 23 January the EU implemented plans for an embargo on Iranian oil effective from 1 July, and a freeze on the assets of the country's central bank, largely in line with more stringent sanctions adopted by the US.

The 'call on OPEC crude and stock change' is reduced by 100 kb/d for the first half of the year, with 1Q12 now pegged at 29.8 mb/d and 2Q12 at 29.2 mb/d. The 'call' for full-year 2012 is also lowered by 100 kb/d, to 29.9 mb/d, which is 0.7 mb/d below the 2011 average of 30.6 mb/d, due to a combination of higher non-OPEC supply (+0.9 mb/d) and OPEC NGLs (+0.5 mb/d). OPEC's 'effective' spare capacity is estimated at 2.82 mb/d compared with 2.85 mb/d last month.



Saudi Arabian crude supplies in January were unchanged at 9.85 mb/d. Saudi Arabia has increased output by 400 kb/d since last October, with some of the extra volumes going to China. Saudi Aramco reduced March official selling prices for Asian customers for the second month in a row, which some market participants viewed as a signal that the Kingdom is prepared to offer competitively priced alternatives to Iranian barrels. Saudi Oil Minister Ali al-Naimi was on record as saying the country could "easily get up to 11.4-11.8 mb/d almost immediately, in a few days...all we need is to turn valves." The minister said it would take Aramco around 90 days to bring on an additional 700 kb/d of capacity.

UAE, Iranian and Qatari output were also unchanged in January, at 2.58 mb/d, 3.45 mb/d and 820 kb/d, respectively. Kuwaiti production slipped 40 kb/d, to 2.56 kb/d in January. That is 110 kb/d below the 2.67 mb/d average for November, when it is thought the country was testing its capacity limits.

Iraqi January crude oil supply fell by 40 kb/d, to 2.65 mb/d, with lower exports of both Kirkuk and Basrah crude. Total Iraqi exports were down 40 kb/d to 2.11 mb/d last month, with southern shipments off by 25 kb/d to 1.71 mb/d, and volumes from the northern export terminal of Ceyhan on the Mediterranean down 15 kb/d to 395 kb/d. Baghdad had hoped to boost Basra Light shipments to 1.9 mb/d in January, with the start-up of a new 900 kb/d single point mooring in the Gulf but technical delays have derailed completion of the export facility. As a result of continuing export constraints, we have downgraded our expectation for a 400 kb/d increase in Iraqi capacity for 2012, to around 250 kb/d.



Libyan output continued on an upward swing in January, rising by 225 kb/d to an average 975 kb/d, based largely on preliminary tanker data. At end-January the National Oil Co (NOC) reported that production hit 1.3 mb/d and the government's latest forecast is for output to reach pre-war levels of 1.6 mb/d this summer. Libya has so far consistently outperformed industry expectations, yet a number of companies operating there are sceptical that this higher level will be sustained in the short-term given planned maintenance and repair work on wells and pipelines. Marathon, a partner in the Oasis Group, cautioned that output growth will likely be constrained by planned oil-field maintenance against the backdrop of political unrest. Libya's Arabian Gulf Oil Company (AGOCO) reported that electricity problems at the Messla and Sarir fields have delayed the planned ramp up there from 300 kb/d to 425 kb/d. Completion of repairs is now expected in April.

Escalating internal strife is now seen as the biggest risk to Libya achieving its production goals. Though not unexpected, a political divide between the National Transitional Council (NTC) and the diverse tribal regions is widening, with internal criticism of the country's new leadership becoming acute. In addition, outbreaks of violence in Bani Walid, a former Gaddafi stronghold, and Tripoli are threatening the fragile political structure, according to a new UN report. The deep-rooted legacy of weak state institutions and civil organisations is making the country's transition more difficult, according to UN officials. As a result, the UN cautioned that there is an 'ever present possibility that similar outbreaks of violence could escalate and widen in scope.'

Nigerian production was down 20 kb/d to 2.04 mb/d in January, due to month-long problems with the Nembe Creek trunk line in the Niger Delta. Shell lifted the force majeure on Bonny Light crude exports in early February after repairs were completed on the pipeline, damaged after earlier incidents of sabotage and theft. The loss of Bonny crude was partially offset by the return of production from the offshore Bonga field, after pipeline repairs were completed in early January, as well as start-up of EA field output following maintenance work.

Venezuelan output slipped 20 kb/d to 2.48 mb/d, largely due to problems reactivating the Petroanzoategui heavy crude upgrader after maintenance work. Ecuador's output was estimated at 480 kb/d, unchanged from December levels.

Iranian Customers Start Lining Up Alternative Crude Supplies

International sanctions targeting Iran's existing oil exports do not come into effect until 1 July but they are already having an impact on crude trade flows in Europe, Asia and the Middle East. As anticipated, on 23 January the EU adopted plans to ban oil imports from Iran and require all member countries to halt financial transactions with the country's Central Bank. Intended to increase pressure on Tehran to halt its nuclear development programme, the EU measures follow a similar time line to new US sanctions announced at the end of 2011. The grace period for implementing the embargo is designed to allow member countries time to find alternative supplies.

Based on 2011 exports, the EU embargo could affect up to 600 kb/d of supplies, although broader US and EU economic sanctions on Iran's Central Bank could be more pervasive if they successfully block the predominant channel for oil payments to Iran. Some estimates suggest that up to 1 mb/d of Iran's 2.6 mb/d of exports may be replaced by alternative supplies once sanctions go into effect, either forcing the state oil company to place unsold barrels into floating storage or shut-in production in the second half of the year.

The market largely discounted retaliatory Iranian threats to pre-empt a European embargo by cutting off exports to EU countries immediately, though the heightened rhetoric may have contributed to recent price strength. Iranian officials have also warned fellow OPEC producers not to fill any gap created by Iran's loss of market share but commercial imperatives are expected to rule the day.

Saudi Arabia's Oil Minister said the country could easily increase production to around 11.8 mb/d in a matter of days, or about 2 mb/d above our current production estimate of 9.85 mb/d. Angola, the UAE, Libya and Iraq are all expected to bring on new production capacity over the course of 2012, potentially as much as 850 kb/d, while non-OPEC supply is expected to rebound to the tune of nearly 1 mb/d in 2012.

Although there are five months before restrictions on existing contracts take effect, European customers have already curtailed imports of Iranian crude and Asian buyers are lining up alternative sources of supply. European customers are likely to look to Russia, Iraq and Saudi Arabia for replacement barrels. China, the single largest buyer of Iranian crude (some 550 kb/d or about 20% of exports), is thought to be lifting around half of 2011 volumes during 1Q12, although this is probably more to do with a dispute over prices. Although China has strongly opposed sanctions, the state oil companies' bargaining position with the National Iranian Oil Co (NIOC) has clearly been strengthened by the international measures.

The prospect of adequately supplied crude markets through 2012 is therefore lessening concerns over European and Asian customers finding suitable alternatives. China has stepped up purchases of Saudi crude, reportedly buying an additional 200 kb/d in recent months, though some of these extra volumes may be destined for newly completed strategic storage. China is also buying more Russian ESPO crude and Angolan grades. India has also increased purchases from Saudi Arabia and reached an agreement with Iran to pay for 45% of its crude purchases in rupees. India last year bought 350 kb/d from Iran. Other Asian buyers, including Japan and South Korea, are importing record levels of crude from West Africa, especially Angolan and Nigerian grades. While these are generally lighter and sweeter than Iranian crudes, increased demand may indicate that regional refiners are having to blend-up from now-heavier base-load supply.

While there appears to be ample crude currently available in the market, the stricter sanctions are nonetheless muddying the waters for the tanker industry. On 8 December 2011, Lloyd's Joint War Committee confirmed that Iran was deemed an area of enhanced risk of war, which led a number of underwriters to charge higher premiums for vessels calling at Iranian ports or transiting within 12 miles of the Iranian coast.

Non-OPEC Overview

Non-OPEC oil production is estimated to have fallen by 0.2 mb/d to 53.2 mb/d in January, largely due to a seasonal downturn in global biofuels output, weather and mechanical-related field outages in the North Sea, and the transit dispute between Sudan and South Sudan. The latter conflict is likely to dent non-OPEC output for the remainder of the first half of 2012 by around 240 kb/d compared to 1H11 levels. The Sudan/South Sudan dispute adds to around 160 kb/d of various unplanned field outages in the North Sea and in other parts of the world (below). Oil production remains offline in China at the offshore Peng Lai field, and unrest has dented output in Yemen and Syria by around 100 kb/d each.



As the remainder of 2011 data comes in, 4Q11 supply has been revised up by 70 kb/d from last month as higher US figures were partly offset by lower-than-expected North Sea production.  With these revisions incorporated, non-OPEC oil supply is seen to have grown by 110 kb/d to 52.7 mb/d in 2011. Yet the last month has seen the non-OPEC supply picture for 1Q12 take a turn for the worse, notably for Africa and OECD Europe. These trends are again offset by higher expectations of growth from US liquids production. We now expect non-OPEC supply to show annual growth of 490 kb/d in 1Q12, or 270 kb/d less than last month's estimate, and reach 53.2 mb/d. Non-OPEC oil production in 2012 is only slightly (-30 kb/d) lower that last month's estimate and should post gains of around 940 kb/d to average 53.6 mb/d.

On the one hand, unplanned outages at facilities operating near capacity levels and continued unrest have the potential to continue to plague non-OPEC supply in 2012. On the other hand, high prices give operators an opportunity to more intensively deploy existing and new technologies, such as horizontal drilling and EOR, to increase oil production from existing wells. The latter occurs almost entirely under the radar, but it more than offsets the most pessimistic shut-in scenarios and underpins our estimate of substantial growth in non-OPEC supply of 0.9 mb/d in 2012. Provided that unplanned outages do abate from exceptional recent levels, normalised performance, even from mature assets, holds the potential to generate healthy growth from the stunted baseline of 2011.

OECD

North America

US - December preliminary, Alaska actual, other states estimated: US crude oil supply stayed at around 5.8 mb/d in December, some 300 kb/d higher than December 2010. US NGL growth also likely rebounded by 130 kb/d to 2.3 mb/d in December, and biofuels output reached record levels of around 950 kb/d before the expiration of the ethanol tax credit. The most recent state-level Petroleum Supply Monthly data for September 2011 showed increases in production in Colorado's Niobrara. Texas Eagle Ford oil production (as defined by the Texas RRC) fell by around 25 kb/d to 110 kb/d, of which around 40% was condensate. Light tight oil production has also boosted output to over 200 kb/d in New Mexico, which includes parts of the Permian and San Juan basins. The stronger showing have resulted in a slight upwards revision to the 2012 estimate. Light tight oil growth in North Dakota and Texas are the primary sources of US crude oil production growth in 2012, which is expected to increase by 250 kb/d (+4.5%) to 5.9 mb/d. Higher-than-expected production in North Dakota, Texas, New Mexico, and Colorado cause an uptick of 0.1 mb/d for the 2012 crude outlook compared to last month. Natural gas plant liquids production, which accounted for over 30% (or 100 kb/d) of US liquids growth in 2011, also reached a record high of 2.3 mb/d in November 2011, and we expect a 30 kb/d stronger performance for the 2012 outlook.

Canada—November actual: Rising output from the oil sands brought Canadian oil production to 3.7 mb/d in 4Q11, around 140 kb/d higher than 2010 levels and around 120 kb/d above 3Q11. Canadian oil production also benefited from a stronger-than-expected return to normal production at the Canadian Oil Sands' Syncrude project, higher Suncor output from the Firebag project, and the completion of routine maintenance offshore Newfoundland. In fact, Canadian syncrude production likely reached over 1.0 mb/d for the first time in December, or around 300 kb/d higher than June 2011 levels. The Canadian oil outlook for 2012 is increased by 90 kb/d from last month, to 3.7 mb/d, to take into account higher expectations for Suncor output and the fast-tracking of the 20 kb/d Southern Pacific McKay River oil sands project. This year Canadian oil production should increase by around 230 kb/d (or 6.6%) compared to last year. Late-breaking news of an unplanned shut down at the 110 kb/d Horizon oil sands project has taken the project offline for 2-3 weeks.  Although this is not explicitly incorporated in the forecast this month, the forecast assumes -120 kb/d of downtime for mining and in-situ Canadian projects in the late spring and early summer.  An even longer outage could be on the cards if CNRL chooses to undergo further maintenance now that had been deferred to 2013.



Short-term Impacts of Keystone XL Decision

The Obama administration rejected Transcanada's September 2008 request to build the 700 kb/d Keystone XL pipeline from Alberta to the US Gulf Coast due to the "arbitrary nature of a deadline" imposed by the US Congress in a December 2011 payroll tax bill. Incremental US tight oil and Canadian heavy oil destined for Keystone XL's capacity will now have to find alternative routes for export. In the US the short term impact on production will be limited, as rail and alternative pipeline takeaway capacity is rapidly increasing in North Dakota, but the decision will likely lead to a more rapid reconfiguration of the US domestic pipeline infrastructure.

In November, the US State Department decided that it had insufficient information to make a recommendation to President Obama whether or not the cross-border Keystone XL pipeline was in the national interest. The Department received many public comments from stakeholders and felt that an in-depth analysis would be required to evaluate alternative routes. The time required for that analysis exceeded the 60-day deadline that the US Congress required in its December 2011 legislation. Therefore, President Obama accepted the State Department's recommendation to deny the presidential permit and determine that the pipeline was not in the national interest. The White House stressed that the decision was not a judgement on the merits of the pipeline, and it does not preclude TransCanada from submitting a new proposal. Although the review process would have to begin again, TransCanada still hopes to have a revised version of the project up and running by 2014.

Impact on Canadian Crude: TransCanada transports roughly 150 kb/d of West Canadian crude oil to Midwestern (PADD II) and Gulf Coast (PADD III) refineries and obtained firm long-term contracts to transport 380 kb/d in additional supplies to storage at Cushing, Oklahoma and to PADD II and PADD III refineries via the proposed expansion. Refiners in PADD III were seeking to replace declining supplies of imported heavy crude with Canadian supplies. In the short term, the decision has caused Canadian producers and the government to switch their focus onto Canadian West Coast export outlets, but these too have encountered local opposition.

Growing US Rockies and Midwestern production has meant that PADD II refiners are now taking less imported crude from the US Gulf Coast via ever-emptier pipelines such as Seaway, Capline, and Spearhead. Keystone XL would initially have relieved that function by bringing crude from Cushing to the Gulf Coast. Operators are now likely to increase the flexibility in the US system so that Canadian heavy crudes can satisfy incremental PADD III demand via various reversal plans. In the absence of either Keystone XL or a pipeline to Canada's West Coast, Canadian producers will have to export incremental volumes to refiners in the Midwest and the Rockies, instead of to PADD III or to China, incurring an $8/bbl value loss in revenue according to a recent Wood Mackenzie assessment for the Alberta Dept. of Energy.

Impact on Williston Basin Light Tight Oil Production: Keystone XL was expected to provide 65-100 kb/d of new takeaway capacity for producers in the basin in light of constrained railcar availability and Enbridge's pipeline capacity.  In addition, PADD II refiners are operating at 95% utilization rates in January, compared to 85% in PADD III. Because of these constraints in PADD II, refiners in PADD III will be more likely to process  surplus Williston basin crude and to fill up stocks at Cushing with more expensive crudes, further depressing WTI prices compared to other crude oil benchmarks. Despite the project's rejection and the short-term concerns listed above, an annual accounting suggests that rail and pipeline takeaway capacity are unlikely to pose constraints to producers in the medium term. In fact, over 550 kb/d of new takeaway capacity is planned in 2012, 70% of which is rail-based. In addition, trucks are travelling to Canada to feed as much as 35 kb/d of light tight oil into the main Canada-US pipeline systems. In the absence of Keystone XL, rail-based capacity should account for over half of total takeaway capacity by 2015 according to the North Dakota Pipeline Authority.

Outlook: The Keystone XL decision has longer-term implications for Canadian producers and will result in intensified Canadian efforts to find a West Coast outlet by the middle of this decade. In the meantime, incremental Canadian and Williston Basin crude oil will still make its way to US refiners, as favourable netbacks are likely to prevent upstream project cancellations or serious bottlenecks.

North Sea

Production from the North Sea rebounded to around 3.0 mb/d in 4Q11, 200 kb/d higher than the prior quarter, yet roughly 380 kb/d lower than 4Q10. Weather-related outages in UK, Norway, and Denmark plagued production during the last quarter and into the current quarter, keeping 1Q12 production at around 3.1 mb/d. Despite news of the UK's Buzzard field returning to levels of more than 200 kb/d for short periods of time, average output for the months of December and January is likely to have remained between 160 kb/d and 190 kb/d.

In the UK, October's preliminary crude oil output data were revised downward by 60 kb/d, underpinning a 140 kb/d lower 4Q11 estimate of 1.1 mb/d. Additionally, BP reported that the 40 kb/d Foinaven field would remain shut in February after it discovered a small leak on a flow line. Gryphon, Tullich, Maclure and the Gannett group of fields are likely to remain offline until 2H12 at best. In Norway, 4Q11 maintenance and related turnarounds were especially heavy in the Statfjord area. These stoppages have constrained Norway's production to 2.0 mb/d when most analysts were expecting a post-maintenance rebound. In fact, Norway's 4Q11 oil production increased by only 35 kb/d over 3Q11 levels and 7% below last year's levels. In sum, lingering field problems and unscheduled maintenance in 1Q12 mean that Norway and the UK's output is around 160 kb/d lower than normal outage rates for this time of year. We have revised our 2012 outlook for the North Sea lower by 130 kb/d to 3.0 mb/d, preferring to be surprised to the upside.



OECD Asia

Australia—November actual: Australian oil production increased by around 20 kb/d in November to nearly 460 kb/d. We expect that production in January will fall by around 40 kb/d from December's estimate to 470 kb/d on the impact of Cyclones Heidi and Iggy, which have reduced output at the Waenea/Cossack, Stybarrow, and Vincent fields as well as at the Mutineer/Exeter FPSO. Other field additions should raise total Australian oil output by 140 kb/d y-o-y to 570 kb/d in 2012.

Non-OECD

Former Soviet Union

Russia—January actual: Recent data for January show oil production increased by 50 kb/d to 10.7 mb/d, of which 9.9 mb/d was crude oil. On an annual basis, January's figure stood around 1.5% above January 2011 levels. Almost all of the monthly gain came from a near 40-kb/d increase in Gazprom condensate output. In January, Rosneft's Vankor field increased production by 15 kb/d to average 330 kb/d, raising the company's output to 2.6 mb/d. We expect production from this new field to continue increasing during 2012 to over 400 kb/d. Gazprom is set to inaugurate a new gas and gas condensate processing facility at the Zapolyarnoye field, allowing the company to process an additional 75 kb/d of condensate and keeping annual Russian liquids output growth near 1.2%. 1Q12 expectations in Russia are tempered slightly from last month's outlook given the severity of the winter, which we expect could cut power supplies to remote oil-producing areas as it did in 2006.

FSU net oil exports stood at 8.8 mb/d in December, their lowest level since 4Q08 and a fall of 320 kb/d compared to a month earlier. Crude shipments plummeted by 270 kb/d to 6.4 mb/d as seaborne cargoes dispatched via Black Sea and Baltic ports fell by a combined 400 kb/d. Consequently, Transneft volumes fell by 260 kb/d to 4.2 mb/d. In the Black Sea, volumes of Azerbaijani and Kazakhstani crudes sent via Novorossiysk contracted by a combined 100 kb/d, while cargoes of Siberian Light shipped via Tuapse declined by another 80 kb/d. In the Baltic, Gdansk's brief resurgence ended as loadings dried up, and Primorsk exports declined by 70 kb/d. In the East, loadings of ESPO from Kozmino rebounded by 60 kb/d to 330 kb/d, and shipments of Vityaz and Sokol crudes from Sakhalin island remained low at below 250 kb/d. Outside Transneft's system, flows through the CPC and BTC pipelines were lower-than-normal at 620 kb/d and 640 kb/d, respectively. Product exports inched down by 30 kb/d after declines in fuel oil (-70 kb/d m-o-m) and gasoil (-20 kb/d m-o-m) while 'other products' (here including naphtha and gasoline) deliveries rose by 60 kb/d, despite the continued 90% Russian excise duty on light products.

Complete 2011 data indicate that FSU net exports contracted by a significant 350 kb/d compared to 2010. Crude shipments fell by 260 kb/d after lower Kazakhstani and Azerbaijani supplies offset increased Russian volumes. Flows through the Transneft network increased by 180 kb/d to 4.2 mb/d, largely as a result of the start up the ESPO pipeline spur to China which replaced railed deliveries. Loadings at Lukoil's Varandey terminal fell to 90 kb/d due to a precipitous decline at Lukoil's Yuzhno Khylchuyuskoye field, whilst exports from Sakhalin I and II remained stable at a combined 280 kb/d. The introduction of the 60:66 tax regime in Russia curbed product exports in 2011. On an average annual basis, total product shipments fell by 80 kb/d as a 30 kb/d rise in fuel oil was offset by drops in gasoil (-100 kb/d) and Other Products (-10 kb/d), the former also a consequence of tighter Russian product specifications.



Latin America

Brazil - December actual: Brazilian crude and condensate production continued to climb to record levels of around 2.2 mb/d in December 2011, following leaks at the Frade field and Marlim Sul P-40 platform in November. Output from the Lula field continued to increase by 10 kb/d to 65 kb/d in December, and output from well tests in the BM-S-9 concession in the pre-salt of the Santos basin reached around 20 kb/d at the end of last year. However, in January Petrobras found a leak in the well and shut it in. Based on government estimates, output from the pre-salt now constitutes 170 kb/d or 8% of Brazil's crude and condensate production. A year's worth of data show Brazil's crude and condensate production rose by 50 kb/d or 2.5% in 2011, to 2.1 mb/d, roughly a third of the growth expected for 2011 a year ago. Fields adding significant amounts of production this past year included Jubarte (+70 kb/d), Frade (+20 kb/d), Marlim Leste (+20 kb/d), and Cachalote (+45 kb/d). These increases were offset by declines at Marlim (-30 kb/d), Roncador (-40 kb/d), and Albacora Leste (-30 kb/d).

Colombia - December actual: Colombian oil production fell by 30 kb/d to 930 kb/d in December because of attacks on the Caño Limón pipeline, worker strikes, and transportation restrictions. Labour unrest in January dented production at EcoPetrol's 30 kb/d la Cira field, which is likely to keep Colombia's production at December levels. In 2012, Colombia's oil output growth is expected to come from increasing production at the Castilla field, which should rise by 40 kb/d to around 120 kb/d by the end of the year. The government reported that oil-related FDI in Colombia has surged to $7.1 billion in 2011, up 145% from the prior year.



Africa

Sudan and South Sudan: Over a Barrel Again

Newly independent South Sudan pledged to shut down its output completely after it failed to agree on a revenue sharing scheme with Sudan. Sudan and South Sudan produced around 450 kb/d during 1H11 before Southern Sudan declared independence on 9 July. This report for the first time carries differentiated production levels for both countries beginning in July 2011. Based on field level analysis, we assess that South Sudan was producing roughly 260 kb/d in December, while Sudan produced around 110 kb/d. In the absence of a foreseeable resolution, we have also reduced production estimates by around 200 kb/d in 1Q12 and by 100 kb/d for 2012, reflecting landlocked South Sudan's export conundrum.

Revenue-sharing agreement breaks down. Since South Sudan declared independence, a tenuous revenue sharing scheme persisted in which Southern Sudan paid Sudan in kind for the use of its transit pipeline and the use of its port. Sudan lost around 75% of its pre-independence revenues to the South. After the South's secession, the sharing agreement gave South Sudan 60% of the revenues from the Unity field's output (located in South Sudan) and around 25% of the revenues from Block 2's output (located in Sudan). Initially, Khartoum in the north was asking for a $32-$38/bbl transit fee. After a week of negotiations in Addis Ababa, Ethiopia, South Sudan had offered $1.7 billion to Sudan and transit fees of $0.63-0.69 a barrel for use of the two lines to Port Sudan. Khartoum then demanded $5.4 billion in cash and $3/bbl. The latest African Union proposal involves the South giving Sudan a direct cash transfer of $5.4 billion, plus transit fees worth up to $1.1 billion, covering the period until the end of 2014. Reports also indicated that the cash payment could be reduced in-kind by supplies of 35 kb/d to Sudan's refineries.

South Sudan's 260 kb/d could remain absent from world markets for the near future. The Unity field and other related fields in South Sudan are located within GNPOC's Block 1A and 1B. They are integrated with GNPOC's production system for the fields located in Block 2 in Sudan, which include the Grand Heglig field and its satellites. The Unity field produced around 80 kb/d during the first half of 2011, or around 60% of GNPOC's production. Cross-border gas lines for reinjection connect these fields, and GNPOC's Central Processing Facility is located near Heglig. Therefore, any sustainable restart of production in the South will have to account for these fields' joint operation.

South Sudanese officials assess that all 274 wells in Blocks 1, 2, and 4 were shut by 25 January. In addition, officials said that 600 wells in Block 3 and 7, reportedly producing around 130 kb/d, had reached a "reduced production stage." Petrodar, in which Petronas and CNPC hold the major stakes, is refusing Sudanese requests to continue to send oil to Port Sudan.

Bad timing for a disruption. China imported roughly 260 kb/d of Sudanese and South Sudanese crude oil in 2011, roughly 5.2% of total imports, and is likely to see the most acute effects of the disruption. The loss of over 200 kb/d of heavy and acidic Dar Blend and light, sweet, and waxy Nile Blend crude oils is coinciding with strong Asian demand for medium and heavy crude oil—not to mention the threat to Iranian supplies from heightened US and European sanctions. Elsewhere in Asia, Japan's direct crude oil burn to replace nuclear-fired power is 150 kb/d more than 1Q11 y-o-y, and cyclones have shut in around 60 kb/d of Australian production. ONGC reportedly sold a cargo of Nile Blend crude at a $4.50/bbl premium to Minas blend, a record $2/bbl increase from January, and Asian customers are also bidding up the prices of Australian grades. In addition, Low Sulphur Waxy Residue (LSWR) cracks have increased by $5.49/bbl since December.

Outlook. On the one hand, both Sudan and South Sudan are almost entirely dependent on oil export revenues for their economy so a quick resolution would make economic sense and would avoid the need for new transport infrastructure. Funding for an alternative pipeline to the Kenyan cities of Lamu or Mombasa (to the south) would require greater clarity on South Sudan's oil reserves and security situation. Eventually, current and new South Sudanese oil could flow via routes that are exporting new oil production from Tullow's fields in the Albert basin in Uganda , which will add around 150 kb/d post-2014.

The two governments remain at loggerheads due to a whole host of other bilateral issues which linger after the South's secession. In addition to the transit fee dispute, the sides have not agreed on the final border status of the Abyei region. Also, citizenship issues of displaced persons, ongoing ethnic conflict, and the potential for Sudan to use its military force are inflaming tensions between the two countries amidst a worsening economic situation. Therefore, the negotiations which are to restart on 10 February are no longer just about oil, but about the two states' sovereignty. While it is impossible to predict the outcome, the broader set of economic and political factors at play mean that the two countries' oil output will remain at risk at least for the remainder of the year.

OECD Stocks

Summary

  • OECD industry oil stocks fell by 40.8 mb in December, to 2 611 mb, or 57.2 days of forward demand cover. The reduction in inventories, broadly in line with a five-year average 37.4 mb draw for December, widened the deficit versus the five-year average to 29.0 mb, from 25.6 mb in November. OECD inventory levels therefore came in below the historical average for a sixth consecutive month.
  • Preliminary data indicate an 11.4 mb build in January OECD industry inventories, a weaker build than the five-year average 43.2 mb. Crude oil stocks rose by 19.7 mb, largely in North America and Europe. In the meantime, product inventories fell by 13.2 mb driven by a sharp decline in 'other products' holdings.


  • New Chinese strategic storage capacity completed between 3Q11 and 1Q12 amounts to nearly 79 mb. This is equivalent to an incremental 220 kb/d of Chinese crude demand were the sites to be filled steadily over the course of 2012. Current high crude prices and term structure may argue against such buying, but additional crude purchasing could emerge if price or geopolitical factors warrant it.

OECD Inventories at End-December and Revisions to Preliminary Data

OECD industry oil stocks fell by 40.8 mb to 2 611 mb in December. With the reduction in stocks broadly in line with a five-year average 37.4 mb draw, the deficit of inventories versus the five-year average widened to 29.0 mb, from 25.6 mb in November. As a result, inventory levels stand below the five-year average for a sixth consecutive month. Regionally, the surplus of inventories versus the five-year average in North America rose significantly, offset by a similar widening in deficit in Europe. OECD forward demand cover fell to 57.2 days from 57.9 days in November, but remained 1.6 days above the five-year average of 55.6 days.



Crude stocks declined seasonally by 21.4 mb to 913 mb, marking a sixth straight month of below average readings. Crude holdings in Europe led the decline, falling by 15.3 mb while OECD Pacific showed a marginal gain of 0.2 mb. Despite a continued increase in Libyan crude production, the backwardated price structure encouraged European refiners to run down crude oil inventories.

Moreover, product inventories fell by 10.9 mb, compared with a five-year average 1.6 mb drop, increasing the deficit against the five-year average to 14.3 mb, from 5.0 mb in November. Most of the product stock draw stemmed from OECD Pacific, showing a 14.7 mb fall, while product holdings in Europe and North America rose by 1.0 mb and 2.9 mb, respectively. Middle distillate inventories in the Pacific led the decrease there, falling by 7.7 mb as cold winter weather at the end of the month finally drew down heating kerosene stocks. On the other hand, gasoline stocks in North America rose by a significant 8.1 mb amid higher production during a seasonal trough in demand.



OECD stocks were revised 4.7 mb higher in November, upon receipt of more complete monthly submissions from member countries. This implies a 9.6 mb build in November inventory levels, compared with preliminary estimates of a 4.1 mb build. Upward adjustments were centred on OECD Pacific crude oil and North American gasoline stocks, which were revised higher by 6.3 mb and 3.5 mb, respectively. Lower-than-initially estimated fuel oil stocks provided a partial offset.



Preliminary data indicate a 11.4 mb build in January OECD industry inventories, a weaker build than the five-year average 43.2 mb. Crude oil stocks rose by 19.7 mb, most of which stemmed from North America and Europe. In the meantime, product holdings fell by 13.2 mb. North American 'other products' inventories led the decline by falling 12.5 mb. Gasoline was the only product stocks category that showed a build, rising by 9.8 mb but only to be offset by a 9.3 mb decline in middle distillate holdings.

Analysis of Recent OECD Industry Stock Changes

OECD North America

North American industry oil inventories fell by 6.8 mb to 1 326 mb in December, nonetheless representing a shallower drop than the seasonal norm of 28.4 mb. Crude oil holdings declined by 6.3 mb on lower imports into the US as refiners deferred tanker arrivals to reduce end-year tax liabilities. 'Other oils' stocks, including feedstocks, also fell by 3.4 mb. Meanwhile, product inventories rose by 2.9 mb driven by an increase in gasoline holdings. Gasoline inventories rose by 8.1 mb due to higher refinery production. The need to sustain middle distillate production kept gasoline supply higher, even in the midst of low seasonal demand. Gasoline inventories have now been above the five-year range for four successive months. Middle distillate stocks also increased by 3.3 mb, as refiners ramped up production while exports decreased. In the meantime, fuel oil and 'other products' holdings declined by 3.0 mb and 5.5 mb respectively, providing a partial offset to increases among the main products.



US weekly data point to an 11.4 mb increase in US industry stocks in January, in line with a five-year average 12.6 mb rise. Crude holdings rose by 8.1 mb, amid lower refinery runs and as US refiners re-entered the market after end-year stock minimisation. In the meantime, crude levels at Cushing, Oklahoma rose by 1.1 mb to 30.4 mb, rebounding above the five-year average after standing below it for a second consecutive month in December. A 5.4 mb increase in 'other oils' stocks added to the US stock build in January.



US product inventories fell by 2.0 mb in January, driven by a draw in 'other products' stocks. 'Other products' holdings plunged by 12.5 mb due to the increased use of propane for heating. In the meantime gasoline holdings rose by 10.1 mb, offsetting much of the 'other products' loss. Although gasoline production in January dropped significantly, the stock build followed four-week average gasoline demand declining to the lowest level since February 2001.

OECD Europe

Industry oil inventories in Europe fell by 15.6 mb in December to 896 mb, in contrast with a five-year average 11.2 mb build. This counter-seasonal monthly draw widened the deficit versus the five-year average to 66.4 mb, from 39.6 mb in November, holding stock levels below the historical range and at their lowest since February 2003. Crude stocks counter-seasonally plummeted by 15.3 mb to 288 mb, marking the lowest level since August 1997 and a tenth straight month under the five-year range. Despite a rapid increase in Libyan crude production, a backwardated price structure encouraged European refiners to run down crude oil inventories. It is worth noting, however that crude stocks look less tight when measured against forward demand, and at 21.0 days of forward cover stand only just below the five-year range. In the meantime, European refined product holdings rose by 1.0 mb on higher refinery runs. Middle distillates led the increase, rising by 4.8 mb while gasoline, fuel oil and 'other products' holdings declined by 0.9 mb, 2.5 mb and 0.4 mb, respectively. Meanwhile, German end-user heating oil stocks fell by 2 percentage points to 57% fill at end-December.



Preliminary data from Euroilstock point to a 1.5 mb stock build in the EU-15 and Norway in January. Despite a seasonal increase, they are far short of the five-year average build of 21.1 mb. Crude oil inventories led the increase, rising by 8.1 mb. Refined product holdings, however, fell by 6.7 mb due to a sharp decline in middle distillate stocks. Middle distillate holdings decreased by 7.4 mb on a seasonal increase in heating oil use. In the meantime, gasoline stocks also declined by 1.2 mb while fuel oil and 'other products' holdings rose by 0.7 mb and 1.3 mb, respectively. Refined product stocks held in independent storage in Northwest Europe rose amid expectations of a seasonal boost in heating oil demand.

OECD Pacific

Commercial oil inventories in the OECD Pacific fell seasonally by 18.4 mb to 389 mb in December, close to the five-year average drop of 20.2 mb. The deficit of inventories versus the five-year average narrowed to 13.9 mb, from 15.8 mb in November. Crude was the only stocks category that showed a build. Although crude holdings edged up counter-seasonally by 0.2 mb to 156 mb, they remained under the five-year range for a third consecutive month. In the meantime, product stocks fell seasonally by 14.7 mb, staying barely within the historical range. Middle distillate holdings led the decline, falling by 7.7 mb as cold winter weather at the end of the month finally drew on heating kerosene stocks. 'Other products', gasoline and fuel oil holdings declined by 4.8 mb, 1.6 mb and 0.6 mb, respectively.  



Weekly data from Petroleum Association of Japan (PAJ) suggest a counter-seasonal drop of 1.6 mb in Japanese industry oil inventories in January. Crude oil stocks rose by 3.5 mb, likely on higher crude oil imports. Product stocks fell by 4.6 mb driven by a further drop in kerosene holdings. A cold spell drove kerosene stocks down by 4.2 mb. Gasoline inventories increased by 0.9 mb while fuel oil stocks edged down by 0.1 mb.



Recent Developments in Singapore and China Stocks

According to China Oil, Gas and Petrochemicals (OGP), Chinese commercial oil inventories rose in December by an equivalent of 2.5 mb (data are reported in terms of percentage stock change). Crude oil stocks fell for a third consecutive month, by 2.2% (4.7 mb). Record high refinery throughput, lower imports and a sharp increase in crude exports led the decline. High refinery runs amid an overall flattening in demand growth drove product stocks higher, by 6.1% (7.3 mb). Gasoline, diesel and kerosene inventories increased by 1.4% (0.8 mb), 10.2% (6.0 mb) and 4.9% (0.5 mb), respectively.




China's SPR Expansion: Potentially Boosting 2012 Crude Demand

Owing to the absence of comprehensive end-user consumption data, the OMR makes an assessment of Chinese apparent oil demand based on refined product output and net oil products imports. This is consistent with the measure of products-based oil demand presented for other countries. However, it does not capture potential swings in Chinese crude oil demand caused by changes in strategic storage. China has been continuing the construction of the second phase of its Strategic Petroleum Reserve (SPR), the filling of which, dependent on price and buying schedule, could materially affect Chinese crude oil demand in 2012.

In 2008, China completed building of the first phase of its SPR (SPR-1) - four storage facilities with capacity of 103 mb - and filled them with crude oil by April 2009. Although the Chinese government has yet to officially announce the locations and capacities of the crude storage sites for SPR-2, unofficial news reports identify eight storage facilities with a total capacity of 169 mb. Among them, the Dushanzi and Lanzhou sites (both with 18.9 mb capacity) were reportedly completed in the second half of 2011 and Jinzhou (18.9 mb) and Tianjin (22.0 mb) are set to be completed during the early part of 2012. Again, according to unofficial reports, the remaining four SPR-2 sites are expected to become operational by early 2013.  For SPR-3, China aims to construct further capacity of nearly 230 mb to boost total SPR capacity to approximately 500 mb by 2016.



If these reports are correct, then up to 79 mb of new storage facilities would be available to receive crude in 2012. Notionally, this would imply 220 kb/d of crude demand if they were filled steadily throughout the year. However, in reality, the pace of buying will be influenced by market conditions, and there may be disincentives to fill the reserve currently, given prevailing high prices and backwardated market structure. Equally, however, purchasing could accelerate if prices weaken, if there is a perceived need to rapidly fill empty storage capacity or if distressed cargoes become available in the Asian market following tightening EU and US sanctions against Iran.

Singapore onshore inventories rose by 1.9 mb in January, driven by an increase in fuel oil holdings. Fuel oil stocks surged by 2.8 mb, rebounding from a two-and-a-half-year low in the middle of the month. A high volume of arbitrage cargoes was reported flowing into Singapore from the West. In the meantime, gasoline stocks edged down by 0.3 mb on strong demand from Indonesia and middle distillate inventories fell by 0.6 mb as surplus Indian cargoes, which might have gone to Singapore otherwise, headed to Europe, where the structural deficit is being exacerbated by lower refining capacity.



Prices

Summary

  • An uneasy balance characterised oil markets through much of January, despite a sharp escalation in international tensions surrounding Iran. Oil prices seem to have risen only marginally on the Iranian issue, but it was the onset of winter weather that fuelled prices for international benchmark Brent to six-month highs in early February. Brent was last trading around $117.50/bbl. By contrast, rising stocks at the regional Cushing storage depot pressured WTI prices lower in early February, last trading around $99.50/bbl.
  • As the Brent-WTI price differential surged to levels not seen since last September's peaks, the ratio of Brent to WTI futures open interest climbed to 57% in January. Open interest in ICE Brent contracts surpassed 1 million contracts on 26 January 2012 and it is expected to rise further.
  • Product crack spreads increased across the board in January, with differentials for gasoline and naphtha at the top of the barrel, and fuel oil at the bottom of the barrel, increasing the most. Middle distillate markets are still strong, but moved within a smaller range over the month, except for in the US, where crack spreads improved.
  • Benchmark crude tanker rates experienced a sharp downturn in late January and early February, although they still held above their 3Q11 lows. The VLCC Middle East Gulf - Japan route initially rallied to over $17/mt on brisk pre-Chinese new year holiday trading, but market activity eased again as tonnage built, notably from new builds arriving in the market, and rates plunged again.


Market Overview

Crude oil futures traded in a higher range during January as new EU sanctions on Iranian oil imports and regulations that essentially block member countries from transacting business with the country's central bank triggered retaliatory rhetoric from Tehran. In January, futures prices for Brent posted an increase of around $3.75/bbl to an average $111.45/bbl, while WTI rose by about $1.75/bbl to an average $100.32/bbl.

By early February, cold weather in Europe fuelled stronger demand and propelled North Sea Brent futures up by a further $6/bbl over January levels, last trading around $117.50/bbl. By contrast, rising stocks at the key Cushing storage depot, the delivery point for the NYMEX contract, added downward pressure on WTI, last trading around $1/bbl below January levels, at $99.50/bbl.

Despite tougher new sanctions by the international community, the market is largely still taking the situation in its stride. Although the new measures will not go into effect until 1 July 2012, refiners and traders are already lining up alternative sources of supply. Indeed, the delayed time-line was designed to allow traditional buyers of Iranian crude a grace period of around five months to secure crude replacements (see Supply, 'Iranian Customers Start Lining Up Alternative Crude Supplies').

While there appears to be ample crude on offer in the market, the new, stricter sanctions are nonetheless causing significant problems for the tanker industry, with rates for vessels calling at Iranian ports running at a premium and talk of insurers shying away altogether from providing cover for vessels that have recently called at Iranian ports. As a result, a two-tier tanker market is emerging.



Higher prices spurred on by geopolitical concerns with Iran and turmoil in Syria were tempered by persistent concerns about the worsening euro zone debt crisis and an across-the-board downgrade in global GDP forecasts by the International Monetary Fund (IMF). The IMF cut its 2012 forecast for global economic growth to 3.3% from 4% and, indeed, this report's downward demand revisions reflect the lower projections. Global oil demand for 2012 has been revised lower by 0.2 mb/d to 89.9 mb/d, with growth now expected to average 0.8 mb/d this year. Despite more encouraging economic signals from within the US, WTI prices remain under severe pressure from swelling stocks at Cushing, rising crude flows from Canada into the Midcontinent and higher output of Bakken crude from North Dakota. As a result, the Brent-WTI price differential surged to levels not seen since peaking last October.

The late arrival of winter weather is also providing unexpected support for the crude market. Fears of gas shortages in Europe have raised the prospect of increased oil burn at power plants, with Italy already putting in place some alternative plans to start up some oil-fired plants. Indeed, despite some rather grim demand data for December, refining margins rose significantly in all major regions, albeit related more to concerns over product supply than expectations of sustained demand strength.



Brent futures prices remained backwardated in January, whereby prompt prices are stronger than further out. However, Brent M1-M12 backwardation was relatively unchanged in January at $3.65/bbl, compared with $3.70/bbl in December although the differential widened again in early February on stronger prompt prices for the North Sea marker, likely driven higher by cold weather demand.

By contrast, weak prompt demand for WTI saw the WTI M1-M12 contract move deeper into contango, with the early-February differential running at around -$2.95/bbl compared with -$0.18/bbl in January and $1.13/bbl in December.



Futures Markets

Activity Levels

The ratio of Brent futures contracts traded on the London ICE to WTI contracts in New York and London combined climbed to 57% in January, more than an 18% increase since July 2011, triggered by a persistent decline in open interest in ICE WTI contracts and an increase in Brent open interest. Both volume and open interest have been consistently declining in ICE WTI contracts. However, the upward trend in the ratio of Brent to WTI open interest is also present when we exclude ICE WTI contracts from our calculation. The ratio of ICE Brent to CME WTI open interest reached more than 73% on 24 January 2012, compared to just over 50% in July 2011.

Open interest in New York CME WTI futures and options contracts increased by less than 1 000 contracts from 3 January 2012 to 31 January 2012, reaching 2.32 million contracts. Meanwhile, open interest in futures-only contracts increased by 1.96% during the same period, from 1.37 million to a three-month high of 1.4 million. Over the same period, open interest in London ICE WTI contracts dropped to 0.36 million and 0.42 million contracts in futures-only and combined contracts, respectively. As opposed to open interest in ICE WTI contracts in London, open interest in ICE Brent contracts peaked at its highest level at 1.0 and 1.12 million contracts in futures-only and combined contracts, respectively.

With relatively stable prices for New York CME WTI contracts, money managers barely increased their bets on rising WTI crude oil prices by 2 890 contracts in January, to a two-month high of 172 921 contracts. However, WTI traders in London increased their net long position by more than 66% to a six- month high of 24 294 contracts. Over the same period, money managers reduced their bets on rising Brent prices by 10.5% from 94 315 to 84 417 contracts.



Producers reduced their net futures short positions from 99 231 to 85 660 contracts in January; they held 19.78% of the short and 13.66% of the long contracts in CME WTI futures-only contracts. Swap dealers, who accounted for 27.18% and 35.46% of the open interest on the long side and short side, respectively, increased their net short position by 58.8% to hold 115 800 net short in January. Producers' trading activity in the London WTI contracts also followed a similar pattern as CME WTI contracts. Producers in the London ICE WTI contracts increased their net long positions contracts from 5 890 to 20 199 contracts over the same period. Swap dealers, on the other hand, increased their net short positions during the same period to 47 011 from 40 694 contracts.

NYMEX RBOB futures and combined open interest increased by more than 16% in January. Open interest in NYMEX heating oil futures contracts increased by 2.04% to 274 900 contracts while open interest in natural gas markets increased by 18.41% to reach an all time high of 1.2 million contracts.

Index investors' long exposure in commodities in December 2011 declined by $24.4 billion. Meanwhile, they cut their long exposure by $9.8 billion from WTI Light Sweet Crude Oil, both on and off futures contracts in December. The number of futures equivalent contracts dipped to 603 000, the lowest since June of 2009, equivalent to $59.6 billion in notional value.



Market Regulation

On 21 January 2011, the US Court of Appeals for the District of Columbia Circuit sided with the US CFTC's argument that the International Swaps and Derivatives Association (ISDA) and the Securities Industry and Financial Markets Association (SIFAM) challenge to CFTC's position limit rule must first be heard by a lower court. Industry groups had also filed a similar challenge at the district court, which could eventually go to the Supreme Court.

On 31 January 2012, the US CFTC and SEC released their joint report to the public on the regulatory framework in the US and abroad. The report provides an update on the regulatory reforms in the US and abroad and suggests that since regulatory progress in meeting the 2009 G-20 Leaders' commitments varies across jurisdictions, it is still too early to determine precisely where there is alignment internationally and where there may be gaps or inconsistencies.

On 24 January 2012, EU ministers agreed on the final draft of the European markets infrastructure regulation (EMIR). Specifically, the EU Council of Finance Ministers agreed on the treatment of third country Central Counterparty Clearing Houses (CCPs) within EMIR. The Ministers agreed that CCPs from third countries will be recognised in the European Union if the legal regime of their home country has an effective equivalent system for the authorisation of CCPs authorised under foreign legal regimes. Furthermore, the Ministers also reached an agreement on a system that limits the power of the European Securities and Markets Authority (ESMA) in the authorization process of CCPs. However, the European Parliament raised concerns over the limited role of the ESMA. Once the final text has been agreed by the European Parliament in February 2012, it will be voted on in the European Parliament and by the European Council.

Grounds for Divorce?

In a narrow 3-2 vote on 11 January 2012, CFTC Commissioners proposed their own version of the Volcker Rule, which prohibits proprietary trading activities of banks and limits their investments in private-equity and hedge funds in line with the restrictions already proposed by the Federal Deposit Insurance Corp., the Federal Reserve, the SEC and the Comptroller of the Currency in October, 2011. The intent of the Volcker Rule is to reduce risk in the US banking system by limiting the excessive risk-taking activities of banking entities, defined as any insured depository institutions and their subsidiaries.

The Dodd-Frank Act mandates the rule to be implemented by 21 July 2012. Banking entities must comply with the new requirement by 21 July 2014 for their pre-existing investments. However, the Federal Reserve Board can extend the deadline for compliance for up to three years.

Volcker Rule

The rule has basically two parts. The first part is related to restrictions on activities of banking institutions, except for non-US banking entities' transactions outside of the United States with non-US residents. The rule prohibits proprietary trading, while allowing transactions related to underwriting, market-making, risk mitigating hedging, trading in certain US government obligations, and trading on behalf of customers. The statute defines proprietary trading as engaging in the purchase or sale of certain financial assets as a principal for the trading account of a covered banking entity.

Financial assets include securities, derivatives, commodity futures and options on these instruments, but do not include positions in loans, spot foreign exchange or spot commodities. The rule also explains what constitutes an entity's trading account. The definition of trading account specifically includes positions taken principally for the purpose of short-term (less than 60 days) resale. The proposed rule calls for the establishment of internal compliance programmes and reporting requirements on banking entities. The rule further provides guidance on what banking entities must do to prove that they are not proprietary trading but engaging in permitted activities, such as market-making or trading on behalf of customers. Finally, the proposed rule provides detailed limitations on the permitted activities. For instance, if their permitted activity would endanger the safety or soundness of the banking entity or the financial stability of the United States, then it is considered proprietary trading and it is prohibited.

The second part of the proposed rule is related to banking entities' relationship with private equity funds and hedge funds. In order to prevent a bank from indirectly engaging in proprietary trading through direct investment and also to prevent a bank from possibly bailing out such funds, the rule limits banking entities' investment in such funds.

Concerns over the Volcker Rule

Market participants, including regulators themselves, argued that the proposed regulation is overly complex. Even Volcker himself said during a speech in November that the proposed rule was much more complicated than initially intended. Regulators have already admitted the difficulty in implementing the rule. The determination of what constitutes proprietary trading and what constitutes legitimate trading activity will be challenging. Although most banking entities already closed their proprietary trading desks, some argue that they are merely moving these activities to their market-making activities. Some market participants urge regulators to put more clarity on the scope of proprietary trading and on the exceptions for permissible activities. However, regulators argued that compliance with the rules will not be based on trade-by-trade enforcement but rather at policies and procedural levels. On the other hand, if the rule mistakenly identifies banks' market-making trades as proprietary trades, this will have an impact on liquidity and thereby on the overall economy.

Foreign governments also raised concerns over the prohibition of US banks trading in foreign governments bonds. Since the US banks are one of the biggest bond buyers, prohibitions imply more costly borrowing for foreign governments. The proposed rule, rather than reducing risk, most likely will drive that risk into other places. The Japanese, Canadian and British governments have said the proposal aggravates the risk for their markets. Some further argue that if the Volcker rule does result in increased borrowing costs for European governments, which are already faced with higher borrowing costs, then the economic fallout may not be contained to the Continent.

Impact on Energy Markets

In its current proposed form, the Volcker Rule does not prohibit banking institutions from holding positions in spot commodities, in which case several reports suggest that some banks may become very active physical market players. However, the rule prohibits proprietary trading by banking entities and their subsidiaries in energy derivatives markets. Banking institutions have been active players, especially since the mid-2000s in energy derivatives markets, including in over-the counter (OTC) markets. In fact, most swap dealers in energy derivatives markets are either banking institutions or their affiliates; the latest Commitments of Traders position data suggests that 27.18% and 35.46% of the open interest on the long side and short side, respectively, of the WTI futures contracts are held by swap dealers. However, there is no estimate of how much of the swap dealers' position could be considered as proprietary trading. It will depend on how narrowly regulators interpret the scope of the definition of market-making versus proprietary trading. The interpretation is much more important in the case of their trading activity in swaps markets, where they are generally counter-parties to commodity index traders, hedgers and speculators. If their trades with other parties are considered as proprietary trading, then the ban would cover almost every trade by swap dealers in the futures and swaps markets. However, we expect most trades to be considered as market-making or trading on behalf of customers, and therefore we anticipate limited impact on liquidity in energy markets.

Spot Crude Oil Prices

Spot crude oil markets strengthened in January in line with rising tensions between Iran and the West following new, more stringent sanctions adopted by the EU and US. In response, Tehran threatened to cut-off exports to some European countries it deems especially hostile. Spot prices for benchmark crudes rose in January by $1.75-$2.75/bbl, with average prices for Dated Brent around $110.60/bbl and WTI at $100.35/bbl.

Spot crude prices' moves in early February, however, were mixed. Dated Brent continued its upward climb to six-month highs as a cold blast of Siberian weather swept across Europe and pushed spot prices about $6/bbl above January levels. By contrast, spot prices for WTI were off about $1/bbl over the same period as rising stock levels at Cushing, Oklahoma added downward pressure.

By early February the price spread between the two benchmark crudes had widened to levels not seen since last September, when they averaged over $27.50/bbl. By 6 February, the WTI/Brent differential hit an intra-day trading high of over $20/bbl compared with an average $10.20/bbl in January and $9.25/bbl in December.



US crude oil stocks held in storage at Cushing moved above the five-year average in early February, to a lofty 30.4 mb, after declining for five weeks due to a combination of sharply higher crude flows from Canada, a surge in Bakken output from North Dakota and reduced refinery throughput rates in the Midcontinent region due to maintenance work.

An increase in Cushing storage capacity last year, with more planned for 2012, should theoretically provide more room to hold growing supplies in the region, taking the pressure off prompt prices (see OMR 18 January 2012, Stocks, 'Cushing Storage Expansion'). But in practice, the relatively steady increase in crude flows into Cushing, especially from the Bakken producing region that posted an increase of around 250 kb/d last year, continues to exacerbate market dynamics (see OMR 10 November 2011, Supply, 'Eagle Ford and Bakken Bonanza to Transform US Oil Production Outlook').

Ultimately, the addition of new pipeline capacity flowing out of Cushing to the US Gulf Coast refining centre will provide the only permanent relief valve for the region. The planned reversal of the Seaway pipeline, which will have a capacity of 150 kb/d, has been delayed several months and is now not expected to be operational until end-June. The fate of the controversial 700 kb/d Keystone XL pipeline, which will run from Alberta, Canada to the US Gulf Coast is still caught in a quagmire (see Supply, 'Short-Term Impacts of Keystone XL decision').

Planned and unplanned maintenance work by refiners in the US Midcontinent has also sharply curtailed demand for crude in the short-term, especially from Canadian producers. Combined with tight pipeline capacity, price discounts for Canadian crude versus WTI have also cratered. Western Canada Select (WCS) heavy crude was trading at a discount of $31.50/bbl to WTI in early February compared to around $17.50/bbl a month ago.

A blast of exceptionally cold weather across Europe triggered a jump in Dated Brent prices in early February. That said, prices are relatively cheap compared with Dubai and other Middle East grades, prompting a record level of exports to Asia in recent weeks. Middle East Dubai and Oman grades were briefly trading at a premium to dated Brent in January. However, the average Brent/Dubai differential narrowed to around -$0.80/bbl in January compared with -$1.40/bbl in December and a more normal -$5/bbl seen on average in 2011.



The relatively weaker Brent price reflects growing availabilities of light, sweet crude in Europe, especially from the North Sea as well as Libya, and reduced refiner demand in Europe. In turn, stronger demand for distillates, higher fuel oil crack spreads and reduced Russian exports boosted Urals to a premium to Dated Brent for a few days at end-January. The Urals/Brent price spread was running at around -$0.30/bbl in early February compared with around an average -$0.70/bbl in January. Urals is seen by many as a fairly close substitute in the event of curtailed Iranian supplies into Europe.

Competitively priced West African crudes from Nigeria and Angola are also moving at a steady clip to Asia, with arguably arbitrage economics playing more of a role in this trade than moves to replace Iranian crude, given the quality differentials between African and Iranian grades. China is reportedly taking in extra Saudi and Russian ESPO crude. Exceptionally strong fuel oil crack spreads are supporting stronger prices for heavier Middle East grades.



Spot Product Prices

Product crack spreads increased across-the-board in January, with differentials for gasoline and naphtha at the top of the barrel and fuel oils at the bottom of the barrel posting the largest gains. Middle distillate markets are still strong, but moved within a smaller range over the month, except in the US where cracks improved.

Gasoline prices posted healthy gains in all regions in January, with differentials increasing $5-6/bbl month-on-month. The surge was largely due to tighter supplies, stemming from refinery closures in both Europe and PADD I, and the announcement of the closure of Hovensa's 350 kb/d St.Croix refinery in the Caribbean from mid-February, an important supplier of gasoline to the US East Coast.

In the US, New York Harbour unleaded gasoline versus WTI increased by $6.11/bbl month-on-month, while the differential to Mars crude at the US Gulf increased $6.23/bbl. In addition to the announced refinery shutdowns, a number of smaller unplanned outages on the US East Coast towards the end of January also pushed crack spreads higher, even though the actual effect on supplies was limited. Although weekly US demand readings are still depressed, export demand, particularly from Latin America, has remained strong. US gasoline exports increased to record-high levels throughout 2011, based on latest available data from November 2011.

In Europe, crack spreads gained a similar $5-6/bbl on average in January. Due to the high US prices, the arbitrage to the US East Coast was open, but also exports to the Middle East and North Africa were supportive for the European market. After trade unions in Nigeria went on strike in mid-January to protest against the removal of fuel subsidies, part of the fuel subsidy was restored, also calming European gasoline markets.



Asian gasoline crack spreads followed the increases in the Atlantic basin, with crack spreads gaining $6.75/bbl to Dubai month-on-month. The most important factor driving prices apart from continuously strong regional demand was expectations of tightening supply with the upcoming refinery maintenance season.

Naphtha cracks continued to improve in January, but were still trading at a $5/bbl discount to crude in both Europe and Singapore for the month on average. Both the recent rebound in gasoline markets and stronger demand from petrochemical producers in South Korea and Taiwan were supportive, partly as recently stronger LPG prices again made naphtha the preferred feedstock for petrochemical producers. Meanwhile, supplies are to be restricted by partial closure of Algeria's Skikda and India's Jamnagar refineries due to maintenance in the coming months.

Middle distillate crack spreads in Europe stabilised at an elevated level in January, with gasoil crack spreads moving within a $15-18/bbl range. This was in spite of mild weather most of the month and independent stocks in the ARA region building in January and standing above the five-year average at end-month. Moving into February, renewed support could come from the colder weather.



Middle distillate markets in the US strengthened in January and early February, and No. 2 oil gained $5.24/bbl versus WTI month-on-month in New York Harbour, and $3.36/bbl versus Mars in the US Gulf. This was partly due to stock draws in the second half of January, but also the announced closure of the St. Croix refinery supported crack spreads on expectations of higher middle distillate exports from the US to Latin America.

In Singapore, gasoil cracks improved by $1.45/bbl to Dubai as further stock draws from already low levels continued to support prices, together with prospects of even tighter supply ahead with the upcoming refinery maintenance season.



Fuel oil markets continued to show unusual strength, and in Asia HSFO cracks were at record-highs with positive differentials to Dubai for January on average. Continued tightness in the bunker fuel market, with refiners still adjusting to the new global sulphur regulations, explains much of the strength. In addition, the refinery closures in Europe have tightened supplies of straight-run fuel oils, together with the loss of Sudanese Dar Blend exports, which has hit the Chinese market in particular (see Supply, 'Sudan and South Sudan: Over a Barrel'). Moving into February, Asian crack spreads narrowed somewhat on the back of a large stock build in Singapore as arbitrage volumes arrived, and reports of less Chinese buying of straight run fuel oil. The Asian LSWR crack continued to strengthen on strong utility demand, especially from Japan amid falling temperatures.

Freight

All benchmark crude tanker rates experienced a sharp downturn in late January and early February, although they still held above their 3Q11 lows. The VLCC Middle East Gulf - Japan route initially rallied to over $17/mt on brisk pre-Chinese new year holiday trading but as the holiday began, market activity eased again, tonnage built, notably from new builds arriving in the market, and rates plunged to below $13/mt by early February. Anecdotal reports of problems securing insurance for vessels on routes into or out of Iran, or which have recently called at Iranian ports, have yet to translate into major vessel supply problems, although some analysts have warned this could become more of an issue going forward.



In the Suezmax market, rates on the benchmark West Africa - US Atlantic Coast trade experienced a similar pattern of boom and bust, after breaching $20/mt in mid-January for the first time since March 2011, rates nose-dived back to $15/mt by early February as demand waned. In Northern Europe, unseasonably mild weather limited gains on the Aframax North Sea - Northwest Europe voyage. Indeed, in mid-winter rates would normally be getting a boost from ice-related delays at Russian ports, however, for the first time in five years, Primorsk had no ice-class restrictions in place during January although this is likely to change in mid-February.

Product tanker rates experienced a similar trend to those for dirty vessels with any gains made during early January being erased by early February. The exception to this was the notoriously volatile transatlantic UK - US Atlantic voyage coast which, after descending in late February on the back of lengthening tonnage lists, managed to claw back some lost ground following the opening of a wide gasoline arbitrage in early February. In the East, 2012 has so far been characterised by a slow and steady erosion of rates, as demand has remained generally stable but serviced by an ample tonnage pool.

On a steady downward trend since the start of 2012, the Caribbean - US Atlantic Coast product trade is likely to remain depressed for the foreseeable future following the mid-February closure of Hovensa's St. Croix refinery in the US Virgin Islands. With the refinery being a major supplier of products, notably gasoline blending components, to the US East Coast, it is anticipated that its closure is likely to translate into lower demand for product tankers in the region given that US imports from other Caribbean refineries are comparatively small to those previously sourced from St. Croix. However, this closure could buttress the UK - US Atlantic Coast market since it is likely that US product imports will need to be sourced from elsewhere.

Refining

Summary

  • Global refinery crude throughput estimates for 1Q12 are largely unchanged from last month's report, as minor upwards adjustment to OECD runs are offset by a lower outlook for the non-OECD. In particular, Latin American runs have been significantly reduced following the announced closure of Hovensa's 350 kb/d St. Croix refinery and lower run rates at Valero's Aruba plant. At 74.9 mb/d, global runs are forecast 220 kb/d above year-ago levels and unchanged from the previous quarter.
  • OECD crude runs rose by 200 kb/d in December, to 36.7 mb/d, and 240 kb/d higher than suggested by preliminary data. Stronger runs in Europe and the Pacific were partly offset by lower runs in North America, the latter falling below year-earlier levels for the first time since July. As a result, total OECD runs fell 0.9 mb/d short of end-2010 levels, due to unseasonably weak demand and poor margins.
  • Refinery margins rose significantly in all regions surveyed in January, as surplus capacity continued to be shed in mature markets. Concerns over Atlantic Basin product availability rose with the announced shutdown of Hovensa's 350 kb/d refinery in the US Virgin Islands and as European independent refiner Petroplus filed for insolvency. Margins surged by between $2.50-$7.70/bbl, but remained negative for several simple configurations surveyed.


Global Refinery Overview

Global refinery crude runs estimates for both 4Q11 and 1Q12 are largely unchanged since last month's report, at 74.9 mb/d. While changes to 4Q11 were minimal, offsetting adjustments for the OECD and non-OECD for 1Q12 mostly cancelled each other out. Our outlook for Latin American crude throughputs has been significantly curtailed since last month's report following the announced closure of Hovensa's St. Croix refinery in the US Virgin Islands and economic run cuts at Valero's Aruba plant. In contrast, a slightly higher 4Q11 baseline for the OECD has been carried forward into the early part of 2012. Global annual growth in throughputs is estimated at around 0.2 mb/d for both quarters, with the OECD contracting and the non-OECD reporting modest growth, mirroring oil demand trends.

The significant slowdown seen in global oil product demand growth since 1Q11 is expected to extend into 2012, though non-OECD growth will again provide support for global demand from 2Q12 onwards. While the shift in economic activity and oil demand to the non-OECD will naturally extend to refinery operations, OECD runs could in part be supported by product exports. Total OECD refined product exports have been on a steadily rising trend and averaged 5.5 mb/d over 2011 (January-November), of which roughly 75% went to non-OECD countries. The US Gulf Coast and Europe could become a source for higher product imports requirements from Latin America and the US East Coast following the most recent refinery shutdowns in the latter two regions.

Despite lacklustre demand overall, margins rose significantly in all regions surveyed in January, providing temporary respite to operators. Surplus refinery capacity continues to be shed in mature markets. Concerns over Atlantic Basin product availability rose with the announced shutdown of Hovensa's 350 kb/d refinery in the US Virgin Islands and as European independent refiner Petroplus filed for insolvency in January. The future of Petroplus' five plants remain uncertain, though some interest from potential buyers has been noted. A sudden cold snap in the FSU, Europe and Japan provided further support. Margins rose by between $2.50-$7.70/bbl, but remained negative for several simple configurations surveyed. It remains to be seen if the improved economics entice refiners to hike runs, which would again put downward pressure on margins and in turn operations.



Regardless, planned maintenance will cut runs in coming months. OECD spring turnarounds normally peak over March and April, with US refiners traditionally completing work first. European maintenance is expected to peak in April this year, followed by the Pacific in May. Non-OECD runs are also expected to fall from January through March, as especially Russian and 'Other Asian' runs are curtailed by maintenance, and capacity is reduced in Latin America. The start-up of new capacity in China, Russia, India and Pakistan is expected to lift non-OECD runs in 2Q12 and 3Q12.

OECD Refinery Throughput

OECD crude runs rose by 210 kb/d in December to 36.7 mb/d, or 240 kb/d higher than suggested by preliminary data. Runs nevertheless remained weak, compared to both the previous year and the five-year average. In total, OECD throughputs were 0.9 mb/d lower than a year earlier, with deficits recorded for all regions. In part, the contraction can be explained by exceptionally weak demand, due to both structural and temporary factors. OECD consumption of refined products fell by close to 1 mb/d in 4Q11, and 0.5 mb/d for the year in total. OECD demand will likely continue to decline in 1Q12, on a mild start to the winter and as several economies flirt with recession, potentially undermining the recent recovery in margins. As surplus capacity is being rationalised, the margin environment has recently improved, providing an incentive to boost throughputs in the short term. The recent cold snap recorded in Europe and the Pacific could further support February product demand and refinery runs, but the weak overall economic picture seems likely to limit gains in margins and therefore throughputs.





North American crude runs declined by some 120 kb/d in December, to average 17.6 mb/d. The steepest fall came from the US, where both the East Coast and Gulf Coast saw lower runs, though mostly offset by higher throughputs in the Midwest and the West Coast. East Coast runs fell by 160 kb/d, following the shutdown of Sunoco's 175 kb/d Marcus Hook refinery. The company, which had already announced in September last year that it would close its Philadelphia and Marcus Hook plants by July 2012 if no buyers were found, said on 1 December it was shutting its Marcus Hook plant earlier than expected due to "deteriorating market conditions". ConocoPhillips already halted operations at its 185 kb/d Trainer refinery in late September 2011, and will be followed by Sunoco's Philadelphia plant in July 2012 if no buyer is found. In contrast, refinery capacity on the Gulf Coast will increase in 2012, once Motiva's 325 kb/d Port Arthur refinery expansion is completed. The project will lift total plant capacity to 600 kb/d and is scheduled to be completed in 1Q12.



Weekly data from the EIA show US crude intake declining sharply in January, in line with our projection, to 14.6 mb/d on average. Throughputs fell in the Midwest, as Valero's 85 kb/d Ardmore refinery shut for planned maintenance, but remained above the historical range due to continued favourable economics. East Coast runs dropped to only 880 kb/d, 160 kb/d below January 2011 and 410 kb/d lower than the five-year average. Gulf Coast runs, meanwhile, fell 145 kb/d in January, despite significantly improved margins. Maintenance at Citgo's and Conoco's Lake Charles plants and BP's Texas City refinery reduced runs to 7.2 mb/d. While Gulf Coast maintenance is expected to intensify in coming weeks, some support to runs could come from improved margins and the start-up of Motiva's expanded plant. In addition, the shutdown of Hovensa's 350 kb/d St. Croix plant, and lower runs at Valero's Aruba plant could lead to extra demand for oil products from Gulf Coast refiners.



Margins saw significant improvements on both the Gulf and West Coasts in January, partly supported by the closures in Europe, the US East Coast and the Virgin Islands. US Gulf Coast margins rose sharply for all crudes and configurations surveyed, but remained negative for Brent Cracking and Maya Coking. LLS cracking margins saw the sharpest increase of $5.46/bbl on average, to reach $5.93/bbl in the week ending 3 February. Surging gasoline prices, on supply concerns, were behind the increased margins and cracks. US West Coast margins saw similar increases, with Kern margins posting the largest gains, as Kern strengthened less than other crudes.

The January announcement that Hovensa is converting its 350 kb/d St. Croix plant into a terminal augmented concerns over product availability, especially to the vulnerable East Coast market, which has been a large importer of products from the Caribbean plant. In addition, Valero recently put the future of its 235 kb/d Aruba refinery back into question, as management suggested that the plant might also be turned into a terminal. Valero further announced they were no longer in discussion with Murphy Oil to take over its UK Milford Haven refinery. Murphy's CEO said in late January that the plant could be turned into a terminal if no buyer comes forward.



European runs for December averaged 12.2 mb/d, higher by 170 kb/d than suggested by preliminary Euroilstock data and 100 kb/d up versus November. The end-year figure is still some 400 kb/d below December 2010, with Italian runs in particular running below year-earlier levels. European fuel demand contracted by 300 kb/d in 2011, with 4Q consumption particularly weak at -690 kb/d y-o-y. Looking ahead, runs are expected to decline further in 1Q12 as spring maintenance intensifies. Preliminary Euroilstock data show January runs for EU15 + Norway down by 50 kb/d. European turnarounds normally peak over March-April. Some support could come from recently higher margins in the region, however. European refining margins surged by $3.30/bbl on average in January, though hydroskimming margins remained weak and mostly negative. Cracking margins initially improved in February, supported by the recent cold snap, but later fell back on higher crude prices.



The future of Petroplus' five European refineries remains uncertain, after talks with lenders failed in late January and the company was forced to file for insolvency. Petroplus had already halted operations at its Belgian, Swiss and French plants in January due to problems financing crude purchases. Operations at the UK and German plants, currently run by administrators, have continued at reduced utilisation of 45% and 40% respectively. Swiss private equity group Goldsmith, already a shareholder in the group, has announced it is interested in buying all five plants. Swiss investment group Gary Klesch has shown its interest in buying the Coryton, Petit Couronne and Ingolstadt plants. While there is a risk that the Coryton refinery would also have to shut for some time before a sale can be finalised, as it struggles to secure crude supplies, we assume it will continue to run at reduced capacity utilisation. National authorities and administrators are making efforts to secure buyers and to re-start the refineries as soon as possible.



OECD Pacific runs surged 240 kb/d in December, to 6.8 mb/d, on stronger Japanese runs. Weekly data from the Petroleum Association of Japan (PAJ) indicate Japanese runs rose in January, to 3.5 mb/d, the highest since the devastating earthquake that hit the country in March 2011. The two refineries still closed after the disaster are expected to restart in coming months. JX Nippon started test runs at its 145 kb/d Sendai plant in January and is expected to recommence commercial operations in March. Cosmo Oil is planning to restart its Chiba refinery gradually, as soon as it secures approvals from local authorities. The plant already restarted some desulphurisation units in December. South Korean runs trended sideways, close to record highs of 2.6 mb/d in December, slightly higher than previous expectations.



Non-OECD Refinery Throughput

Non-OECD refinery crude run estimates have been reduced by close to 200 kb/d for 1Q12 since last month's report, following the announced shutdown of Hovensa's 350 kb/d refinery in the US Virgin Islands and economic run cuts at Valero's Aruba plant. Some smaller downwards adjustment to Middle Eastern and African runs due to adjusted outages schedules also contributed. At 38.8 mb/d total non-OECD runs nevertheless stood 320 kb/d above year-earlier levels. 4Q11 non-OECD throughput estimates are unchanged since last month's report, at 38.7 mb/d.



While no new data is available for China since last month's report, January crude throughput estimates have been raised slightly to a record-high of 9.3 mb/d on better refinery profitability leading up to the New Year holidays. Company surveys show both Sinopec and PetroChina were planning to hike runs in January from already record-high end-year rates. The National Development and Reform Commission (NDRC) is expected to raise retail ceiling prices of both gasoline and gasoil by CNY300/tonne from 8 February. Increased runs also derived from newly commissioned units at Sinopec and PetroChina's Yinchuan and Beihai plants, as these ramped up to full capacity in January. Overall, Chinese runs had already attained record levels for a second consecutive month in December, when total throughputs averaged 9.28 mb/d.

In 'Other Asia', refinery runs were largely in line with estimates for November and December, leaving 4Q11 estimates at 8.9 mb/d, unchanged from a year earlier. Indian runs are estimated to have averaged 4.3 mb/d in December, adjusting for Reliance's Jamnagar export refinery and BPCL's recently commissioned Bina refinery not included in Ministry data, 3.3% higher than a year earlier and essentially flat from the previous month. Refinery throughputs were also unchanged in Singapore in December, at 1.2 mb/d. Singapore refinery margins saw significant improvement over January and bounced back into positive territory for cracking configurations, with an even sharper rebound in hydroskimming margins. Dubai hydroskimming margins averaged $1.09/bbl in January, the highest monthly average since September 2008.

Pakistan's refinery run estimates have been adjusted slightly lower for November-January as Byco Oil Pakistan shut its 35 kb/d refinery outside Karachi, to prepare for the installation of a 120 kb/d crude unit. The completion of the project is now expected by the end of 2Q12, and will make the plant Pakistan's biggest. Taiwan's crude runs fell to 720 kb/d in December, from 850 kb/d a month earlier, on safety-related shutdowns at Formosa's Mailiao refinery, but were in line with our previous forecast. In Thailand, runs rebounded by 115 kb/d in December, to 910 kb/d as maintenance wound down, also in line with previous expectations.



Russian crude runs rose by close to 150 kb/d in January, according to data from CDU TEK, to 5.3 mb/d, matching 2011 peak summer levels. Official Ministry data for December were slightly lower than our previous estimates due to lower runs at Taneco's recently commissioned Nizhnekamsk refinery. The Ministry data included this refinery for the first time in January, with the latest data showing the plant processed 108 kb/d in December. In all, December runs were down 0.6%, to 5.17 mb/d as maintenance at the Ryazan and Saratov plants was partly offset by higher runs at the Afipsky and Moscow refineries. In Kazakhstan, runs rose by some 60 kb/d, to 320 kb/d in December on rebounding runs at PetroKazakhstan's 105 kb/d Shymkent refinery. The plant was shut down for a planned 30-day turnaround from 19 October. A fire at the same plant in early February was rapidly extinguished but could entail lower runs if any damage was sustained. Lithuania's Mazeikiai refinery is scheduled to shut for 30 days from mid-April. While the refineries nameplate capacity is 300 kb/d, recent throughputs average a lower 190 kb/d.



The outlook for Latin American refinery runs has been reduced significantly since last month's report, following the announced closure of Hovensa's 350 kb/d St Croix refinery from mid-February and due to lower runs at Valero's Aruba refinery. Hovensa, a joint venture between Venezuela's PDV and Hess Corporation of the US, announced on 18 January that it will permanently shut the 350 kb/d St. Croix refinery in the US Virgin Islands, after recording cumulative losses of $1.3 billion over the last three years. The plant, which will be converted to an oil product storage terminal, already cut capacity by 150 kb/d last January. The refinery processed mostly Venezuelan crudes and some West African grades, such as Gabonese Rabi light and Mandji. The implied loss of gasoline supplies, in particular, from the already tight US East Coast market pushed gasoline prices and cracks sharply higher. NYMEX RBOB futures cracks surged to almost $25/bbl in early February, up from only $10.70/bbl on average in December. Hovensa processed 270 kb/d in 4Q11. Valero, meanwhile, is looking into the viability and future of its Aruba refinery and has cut runs amid poor margins and narrow discounts for heavy/sour versus light/sweet crudes. The refinery runs heavy/sour crude and produces feedstocks primarily sold to the company's US Gulf Coast plants. The lower runs could benefit other operators on the US Gulf Coast.



In Africa, Algeria's Sonatrach will partly shut its 300 kb/d Skikda refinery from March to August as it undertakes maintenance, sharply increasing gasoil import requirements while reducing naphtha exports. Sources expect the plant to operate at 50% utilisation during the work. The country's Arzew refinery, which has been partially shut since November due to maintenance, was expected to resume normal operations by mid-February.

Chad's sole refinery closed for a second time since its inauguration last July due to a pricing dispute between the government and majority stakeholder CNPC. The refinery stopped producing fuel on 23 December, but resumed operations on 6 February after the government and CNPC reached an agreement. 

Elsewhere, Nigeria's NNPC had to temporarily shut its Kaduna refinery in December following an attack on a pipeline in the Delta state. Libya's largest refinery, the 220 kb/d Ras Lanuf plant, remains shut, but could restart as early as February if full electricity supply to the Sarir and Messla fields is restored. In Sudan, refinery operations could be impacted by lower crude shipments from South Sudan. Feedstock supplies to the 100 kb/d refinery in Khartoum are expected to be cut, as South Sudan halted crude production, also affecting Sudan's own production (see non-OPEC, 'Sudan and South Sudan: Over a Barrel Again').