- Crude oil futures hit 18-month highs in early April, with expectations for an accelerating economic recovery, spurring financial and commodity markets, and stronger oil demand ahead. Nonetheless, underlying concerns remain that oil markets are overheated with WTI and Brent both recently trading around $85/bbl.
- Global oil demand is revised down by 70 kb/d in 2009 and up by 30 kb/d in 2010 on preliminary data adjustments in the OECD and non-OECD (Asia, Africa and Middle East). With demand now seen at 84.9 mb/d in 2009 and 86.6 mb/d in 2010, year-on-year growth averages -1.3 mb/d and +1.7 mb/d, respectively.
- Global oil supply fell by 220 kb/d to 86.6 mb/d in March on lower OPEC output. Non-OPEC supply was unchanged in March at 52.5 mb/d, and up by 900 kb/d year-on-year. Non-OPEC 2010 output is revised up 220 kb/d to 52.0 mb/d, reaffirming a more optimistic supply outlook amid elevated price levels since 2Q09. Non-OPEC supply and OPEC NGLs should rise by a combined 1.3 mb/d in 2010.
- OPEC crude production posted its first significant monthly decline in over a year, falling by 190 kb/d in March to 29.0 mb/d. Yet the lower output reflected a near 10% decline in Iraqi crude rather than effort by OPEC-11 members to rein in above-target output. OPEC-11 production, which excludes Iraq, increased by 30 kb/d to 26.7 mb/d.
- Global refinery throughput is estimated at 72.5 mb/d for 1Q10, 800 kb/d above 1Q09 - the first annual increase since 2Q08, though from a low base. While China, India and Russia all posted record highs in February, European throughputs fell to their lowest level in 17 years. Global runs should seasonally rise to 72.9 mb/d in 2Q10 (+1 mb/d year-on-year).
- OECD industry stocks fell by 38.4 mb to 2 685 mb in February, 1.6% below 2009's level, with lower crude, distillates and 'other products'. End-February forward demand cover rose to 60.0 days, but stood 0.9 days below levels of a year ago. Preliminary March data point to a 8.0 mb OECD stock build amid continued decline in floating storage.
Beauty in the eye of the beholder
Much has been said on the 'ideal' nature of $60-80/bbl prices, with OPEC Ministers and industry executives singing their praises on the margins of IEF deliberations in Cancun last month (although the final communiqué wisely avoided anything so prescriptive). We also shy away from nominating any preferred price level, despite suggesting last month that price is one of the few reliable bits of real-time information with which to gauge the state of the market amid lags in supply/demand data. While rising non-OPEC investment costs may keep prices above historical norms, this does not preclude some concerns for the fragile economic recovery now that they have shifted higher.
Many have raised anew the ogre of a speculative-driven rally, and indeed recent exuberance over gasoline may have played a role. But the declining open interest for NYMEX light sweet crude during March as a whole that accompanied higher prices points to more complex market drivers than the 'it's-all-speculation' bandwagon might admit. That said, regulators justifiably seek more visibility on opaque elements in financial markets, with the EU due to propose OTC derivatives oversight measures at mid-year and the US CFTC soon closing its consultation on position limits. Ideally, new regulation will lean towards enhanced transparency, without choking off liquidity or the ability of physical players to hedge.
OPEC Ministers again decided in mid-March to leave output targets unchanged, not only because of contentment with prevailing prices, but also perhaps acknowledging re-emerging discord over allowable production levels. A number of OPEC producers seem unhappy at existing production limits, even if the current quotas exist more in theory than in practice. However, scheduling the organisation's next gathering in October suggests a certain confidence in the way the market is headed.
The recent tightening at the front of the price curve may partly reflect perceptions of renewed short-term supply risk as non-OECD demand recovers (with Nigeria, Iran, Russia and the expected autumn hurricane season making headlines), even though a sizable cushion of spare capacity and OECD stock persists. Nor does 2010's global market balance (above) look overly weak under most scenarios for the rest of the year. Moreover, some of the more hysterical supply concerns for mid-decade have receded, and the five-year time spread has narrowed from $30/bbl a year ago to nearer $5/bbl now.
Belief in a more resilient economy and broader perceptions of stronger demand help underpin OPEC's more sanguine view of the market. Our own expectations of demand growth of around 1.6 mb/d in 2010 have been in place for almost six months. It is too early to judge their accuracy, although we note that our outlook is now considered less overly optimistic than before, and indeed has been overtaken by several prognoses for growth of 2 mb/d or more, such is the resilience of non-OECD demand (even if, paradoxically, OPEC's own official demand view remains weaker). Refining margins and utilisation have picked up to a degree, at least outside Europe. While ongoing price subsidies may shield non-OECD consumers from the reality of any potential renewed surge in prices, this, plus tighter credit than two years ago, could stall OECD economic recovery or render it more 'oil-less' than we currently envisage. Ultimately, things might turn messy for producers if $80-100/bbl is merely seen as the new $60-80/bbl, stunting economic recovery while prompting resurgent non-oil and non-OPEC supply investment.
- Global oil demand has been revised by -70 kb/d in 2009 and by +30 kb/d in 2010. The former adjustment resulted from revisions to preliminary data in OECD North America, non-OECD Asia and Africa, while the latter stemmed from higher-than-expected data from OECD North America and the Pacific, as well as non-OECD Asia and the Middle East. With oil demand now estimated at 84.9 mb/d in 2009 and 86.6 mb/d in 2010, year-on-year growth averages -1.3 mb/d and +1.7 mb/d, respectively.
- OECD oil product demand has been adjusted down by 20 kb/d in 2009, but remains unchanged in 2010 as higher readings in North America and the Pacific offset inordinately weak European data. The petrochemical-led, manufacturing-based, export-oriented economic recovery appears to be ebbing in Europe. Although industrial production has risen in France, Germany and the UK, it remains well below pre-recession levels, while in Italy and Spain it has barely increased from its recessionary depths. In addition, Greece's continued fiscal predicament has introduced a further element of economic uncertainty. Overall, OECD oil demand, estimated at 45.5 mb/d in 2009 (-4.4% or -2.1 mb/d year-on-year), is projected to decline to 45.4 mb/d in 2010 (-0.2% or -0.1 mb/d versus 2009).
- Non-OECD total oil demand has been amended by -60 kb/d in 2009 and by +40 kb/d in 2010. The changes in 2009 were largely due to downward revisions to historical data in Asia (notably Thailand since 2008) and preliminary data in Africa (South Africa in 4Q09). By contrast, the adjustment to the 2010 forecast resulted from higher-than-expected demand readings in Asia, with China continuing to exceed expectations (although apparent demand estimates may reflect a degree of product stocking), and in the Middle East, as Saudi Arabia demand continues to be boosted by direct crude burning for power generation. Total oil demand, estimated at 39.5 mb/d in 2009 (+2.1% or +0.8 mb/d year-on-year), is projected to rise to 41.2 mb/d in 2010 (+4.5% or +1.8 mb/d versus 2009). It is worth noting that six large non-OECD countries - China, Saudi Arabia, Russia, Brazil, Iran and India - are expected to account for almost three-quarters of global oil demand growth in 2010.
Preliminary data indicate that OECD inland deliveries (oil products supplied by refineries, pipelines and terminals) rose year-on-year in February for the first time since April 2008, albeit by a modest 0.1%. Growth was essentially driven by OECD Pacific and OECD North America (which includes US Territories). Demand in these regions increased by 2.4% and 1.6%, respectively, on the back of strong deliveries of LPG and naphtha (mostly used by the petrochemical industry and considered as a leading indicator for economic activity), as well as strong middle distillates and residual fuel oil requirements, largely because of cold temperatures. By contrast, demand in OECD Europe shrank by 3.4% year-on-year as weak LPG and naphtha growth failed to offset heating oil and residual fuel oil, which continued to post sharp losses despite cold temperatures.
Revisions to January preliminary data were significant (-240 kb/d), mostly because of a large downward European revision, notably at the top and the bottom of the barrel. By contrast, Pacific and North American readings were largely unchanged. January OECD demand thus fell by 4.4% year-on-year, much more than last month's assessment (-3.8%). Estimated 2009 OECD oil demand is slightly lower at 45.5 mb/d (-4.4% or -2.1 mb/d versus 2008, 20 kb/d below last month's appraisal), and the 2010 forecast remains unchanged. Nonetheless, total OECD oil demand should fall for the fifth consecutive year, by -0.2% or -110 kb/d in 2010.
Preliminary data show oil product demand in North America (including US territories) rose by 1.6% in February, with all three North American countries posting yearly gains. Regional 2010 demand growth has so far stemmed from petrochemical feedstocks - LPG and naphtha - which grew on a yearly basis by 19.3% and 27.9%, respectively, in February. Transportation fuels such as gasoline and jet/kerosene, which are tied to consumer activity, showed few signs of resurgence, particularly in the US, despite improving economic indicators. Moreover, heavy snows disrupted travel patterns in the US and Canada. Nonetheless, intra-regional trade activity has picked up, suggesting potential diesel recovery ahead. In real terms, US surface trade with Canada and Mexico jumped by 16.5% year-on-year in January, with strong readings in both the truck and railway categories. Continued positive economic activity suggests transport demand should improve across the region, although with structural efficiency improvements and rising oil prices, the upside should remain limited.
Structural Change in Action: Tightening Vehicle Efficiency Standards
In early April, following through on the National Fuel Efficiency Policy launched by the Obama administration a year ago, the US National Highway Traffic Safety Administration (NHTSA) issued new efficiency rules - updated Corporate Average Fuel Economy (CAFE) standards - while the Environmental Protection Agency (EPA) established emission requirements for light-duty vehicles. North of the border, Environment Canada announced similar rules, which aim to harmonise Canadian and US fuel efficiency and emission standards.
Under the NHSTA requirements, due to start with the 2012 model year, the average fuel efficiency of the combined passenger car and light truck fleet should gradually increase from 27.6 miles per gallon (mpg) in 2011 to 34.1 mpg by 2016. Under EPA rules, new vehicles must also achieve an industry-wide average emissions standard of 250 grams of CO2 per mile by 2016. If EPA's emissions mandates are met wholly through fuel efficiency improvements, then fuel economy may reach higher levels than those prescribed by NHSTA (35.5 mpg by 2016, according to government calculations). An important difference between both standards is related to the treatment of passenger car air conditioning systems. EPA allows automakers to generate CO2-equivalent credits through air conditioner improvements (e.g. by reducing hydrofluorocarbon emissions), while NHSTA is statutorily prohibited from granting such credits to meet CAFE standards.348
The new fleet efficiency standards depend upon an 'estimate of the mix of vehicles that will be sold in that model year'. Vehicle sales projections, which underpin the estimates, foresee that the share of less efficient light trucks relative to total sales should decrease from near 50% in 2008 to 43% in 2016. However, during most of the past decade, sales of light trucks exceeded those of passenger cars. Although this trend reversed given the economic crisis and record-high fuel prices, the shift away from light trucks must continue in order to meet NHSTA/EPA's standards. Yet the new efficiency requirements still seem to privilege the production of light trucks over passenger cars. Light trucks require only a 3.4% annual improvement under NHSTA standards, while passenger car fuel efficiency must increase by 4.5% per year. Light trucks will remain under 30 mpg by 2016, 9 mpg less than passenger cars. The disparity is similar under the EPA requirements.
Nonetheless, the joint NHSTA/EPA rules portend significantly improved fuel efficiency in new cars sold in the US, for an estimated average incremental cost of less than $1,000 per vehicle. Combined with increased penetration of ethanol, more stringent fuel efficiency standards should hasten a structural decline in US gasoline demand over the medium term. Still, there is risk that such an improvement may not be as strong as envisaged, particularly if the vehicle fleet turnover proceeds at a slower pace or if oil prices turn out to be lower than currently foreseen by the regulatory agencies.
This risk could be lessened through measures that target demand, such as a recent proposal from the House Transportation and Infrastructure Committee to raise the federal gasoline tax or implementing carbon pricing. Politically, though, such demand-side methods remain more difficult to pursue, particularly as the US economy is still in its early recovery stages.
Revisions to January preliminary data were negligible, as slightly higher US readings almost offset Canadian downward adjustments. As such, North American demand declined by 2.4% in January, more steeply than reported last month (-2.3%). North American oil demand for 2009 is now estimated at 23.3 mb/d (-3.6% or -880 kb/d versus 2008 and -15 kb/d compared with last month's report). In 2010, demand is seen rising to 23.4 mb/d (+0.5% or +110 kb/d year-on-year and +20 kb/d versus our last report), with increases in petrochemical feedstocks and a modest transport fuel rise outweighing structural declines in heating oil and residual fuel oil.
Adjusted preliminary weekly data for the continental United States indicate that inland deliveries - a proxy of oil product demand - grew by 0.4% year-on-year in March, following a 0.8% rise in February and a 3.1% fall in January. March data showed a continuation of a petrochemical-led economic recovery, but also offered more positive gasoline readings. LPG/ethane and naphtha grew by 13.6% and 4.6% year-on-year, respectively, while gasoline posted a 1.3% rise. Jet/kerosene remained weak, decreasing by 4.9% versus March 2008. Distillate demand overall remained flat, in contrast to the average 6.5% drop that had characterised the previous six months. However, working out the diesel/heating oil split in the preliminary weekly data remain problematic. Our methodology, which applies historical month-on-month changes to the percentage share of these two products, indicates diesel demand fell by 4.3% in March, offset by heating oil's upward boost. More robust industrial activity and drawing diesel inventories, however, suggest this diesel estimate may be revised up.
US economic indicators have continued to improve, with positive signs on the consumption side. Payroll data showed US employment jumping by over 160,000 in March, while consumer spending increased for the fifth consecutive month in February. Yet, with spending growth outpacing income growth -which means that consumers are dipping into savings - and the unemployment rate at a high 9.7%, the sustainability of consumption-led GDP growth remains questionable. Still, Americans are buying more cars: seasonally adjusted light vehicle sales in March rose by 21.2% year-on-year, following strong February readings (+13.7%). Excluding a sales spike in August 2009 due to the cash-for-clunkers incentive programme, March sales were at their highest level since September 2008. Heavy truck sales, by contrast, fell by 7.4% and over the past six months have lagged improvements in light vehicles. This trend may partially explain persistent diesel weakness, as supply chains continue to be streamlined in the face of weak demand and rising fuel prices.
However, it is unclear to what extent this revival in vehicle sales may support gasoline demand in the months ahead, as new cars tend to replace older, more inefficient models. Our forecast sees gasoline demand rising seasonally through the end of summer - even though overall growth remains marginal, at +0.1% year-on-year for 2010. While rising pump prices the past 12 months have not discernibly dampened vehicle activity, the prospect of $3/gallon gasoline may stall increases in vehicle-miles travelled. Reduced commuter activity, due to high unemployment, and the recent implementation of improved fuel-economy rules should also cap consumption growth, though the latter will likely affect demand only over the medium term (see Structural Change in Action: Tightening Vehicle Efficiency Standards).
Preliminary Mexican oil demand has benefitted most from the region's improved economic outlook, rising by 6.6% in February. Growth stemmed mostly from stronger gasoline demand as well as higher, counter-seasonal residual fuel oil readings, possibly due to the drought conditions that reportedly impinged upon hydropower supplies in some areas. Meanwhile, estimated February growth for Canada was less pronounced, at +3.7% year-on-year, but with a stronger diesel component.
According to preliminary inland data, oil product demand in Europe shrank by 3.4% year-on-year in February. Positive readings in LPG, naphtha and diesel failed to offset losses in all other product categories. Cold temperatures - HDDs were sharply higher than both the ten-year average and February 2009 - disrupted travel across many countries, which may have compounded gasoline's structural decline, with demand contracting by -5.4%. However, the effects of restocking earlier in the previous year and an ongoing shift to natural gas continued to weigh on deliveries of heating oil (-9.4%) and residual fuel oil (-15.8%).
The revisions to January preliminary demand data were substantial (-230 kb/d). Albeit these were concentrated in both light and heavy products (with middle distillates mostly unchanged), it is worth noting that LPG and naphtha revisions accounted for almost half of the total adjustment, thus casting some doubts on the sustainability of Europe's petrochemical-led, manufacturing-based, export-oriented economic recovery. Indeed, although industrial production has risen in France, Germany and the United Kingdom, it remains well below pre-recession levels (while in Italy and Spain it has barely increased from its recessionary lows). In addition, the thorny and unsettled issue regarding Greece's potential rescue from default and eventual contagion to other southern European countries has introduced a further element of economic uncertainty in the continent.
Overall, January oil demand sank by much more than previously anticipated (-9.5% year-on-year versus -8.0%). Coupled with dismal February preliminary readings, 1Q10 demand is set to be inordinately weak (-5.1% year-on-year), especially in light of last year's depressed baseline. Although oil product demand for 2009 is unchanged at 14.5 mb/d in 2009 (-5.4% or -830 kb/d versus 2008), it is expected to decline to 14.4 mb/d in 2010 (-0.7% or -100 kb/d compared with the previous year and 60 kb/d less than previously forecast).
Preliminary data indicate that German oil product demand fell by 6.8% year-on-year in February, with weak deliveries in most categories bar LPG and naphtha. Although naphtha deliveries rose by 4.1%, the strength of the naphtha-led surge appears to be less spectacular than reported in last month's preliminary data. Indeed, January figures were sharply revised down (-70 kb/d, equivalent to almost a fifth of naphtha demand), implying year-on-year growth of +29.8%, rather than +51.1%. This large revision, coupled with relatively weak February growth (versus a very depressed 2009 baseline) raises questions on the sustainability of the country's economic recovery, which has so far been driven by export-oriented industrial production, as domestic consumption remains anaemic.
Moreover, this suggests that oil demand will remain subdued in Europe's largest economy, as other sources of oil demand growth aside from naphtha are unlikely to materialise. Indeed, rising oil prices suggest that the all-important heating oil category (-17.2% year-on-year in February) will probably follow a more seasonal restocking, with the bulk occurring in 3Q10. German consumer heating oil stocks, which stood at 52% of capacity by end-February, have so far this year almost matched exactly their five-year average. Meanwhile, transportation fuels remain in the doldrums, with gasoline down by 9.5% and diesel by 2.4% (only jet fuel/kerosene posted modest growth, at +1.0%). Finally, residual fuel oil demand continues to be displaced by natural gas and other sources, not only in Germany but also elsewhere in Europe.
Roughly similar patterns prevailed, albeit with different magnitudes, in France, Italy, Spain and the UK, where demand fell in February (by 0.9%, 10.2%, 5.0%, and 2.1%, respectively, according to preliminary data). In all four countries, residual fuel oil demand declined; in all but France, heating oil fell and transportation fuel demand remained weak or continued to fall. Moreover, in France and the UK, naphtha also contracted. Overall, these preliminary readings continue to paint a picture of very weak European demand, in contrast to modest recovery in other OECD areas.
The much-touted French carbon tax, proposed in mid-2009 but rebuffed by the country's Constitutional Court in December, has now effectively been shelved. Despite recent vows that a new version would be implemented from next July, the government now argues such a tax should be adopted at a European level in order to preserve France's industrial competitiveness - hence entailing protracted negotiations with the country's EU partners. More importantly, perhaps, the proposed tax had raised doubts since its inception on whether it would achieve its ostensible goal of curbing demand for transportation fuels. It would have entailed a marginal price increase (about 5 cents/litre of gasoline and diesel), arguably insufficient to reduce oil demand to any significant extent.
Oil product demand in the Pacific rose in February by 2.4% year-on-year, according to preliminary data, with all product categories bar residual fuel oil registering gains. Petrochemical feedstocks, in particular, were in high demand, with LPG and naphtha rising by +2.9% and +10.0%, respectively, most notably in Japan, thus providing further evidence of an export-led industrial recovery. Much colder temperatures (relative to both the ten-year average and the previous year) supported jet fuel/kerosene deliveries (kerosene is used for heating in both Japan and Korea). Meanwhile, transportation fuels also posted strong readings when compared to last year's weak baseline, with gasoline and diesel growing by 2.4% and +2.6%, respectively. By contrast, residual fuel oil continued to decline (-20.5%), indicating that electricity needs are increasingly being met by natural gas and nuclear power plants.
January revisions, meanwhile, were negligible, confirming that OECD Pacific oil demand contracted by 0.9% in that month. Revisions for 2009 were also inconsequential; oil product demand shrank by -4.8% or -0.4 mb/d versus 2008 to 7.7 mb/d. Given slightly stronger-than-expected readings in February, the decline of oil demand in 2010 should be less pronounced (-1.5% or -110 kb/d year-on-year, some 30 kb/d less than previously anticipated).
Preliminary data indicate that oil demand in Japan rose strongly in February (+5.8% year-on-year), breaking a cycle of 20 consecutive months of decline. Leaving aside that these data may still be revised, such growth must be appraised versus last year's very weak baseline. February readings were supported by export-driven, Asian-led ethylene production (with naphtha surging by 30.2%), cold weather (jet fuel/kerosene rose by +10.4%) and transportation (gasoline and diesel jumped by +2.4% and +6.5%, respectively). Meanwhile, residual fuel oil continued to decline (-17.2%), displaced by cheaper natural gas and rising nuclear power generation (the country's nuclear utilisation rate averaged 70% in both January and February, almost three percentage points higher than in the previous year).
A key question is whether Japanese demand will continue to rise strongly in the months ahead. Excluding seasonal factors (winter kerosene use), most oil product categories, particularly transportation and burning fuels, face structural decline given unfavourable demographics and changing behavioural patterns. These include an ageing, shrinking population prone to travel less, ever rising efficiency, notably in cars, and interfuel substitution in favour of natural gas, nuclear and other sources. This leaves naphtha, which largely depends upon the country's export-oriented industrial production. Here the picture is mixed: even though industrial production rose by over 18% year-on-year in February, it is still some 12% below pre-recession levels (by contrast, Korean industrial production is now about 3% higher). In addition, the country's industrial sector, which accounts for about one quarter of GDP, is highly dependent upon exports to Asia, notably China, which has become Japan's largest trading partner. Should China tighten macroeconomic policy in the years ahead, Japan's industrial exports - and hence naphtha demand - could well falter again. In the meantime, Japanese total oil demand is seen declining by 2.8% year-on-year in 2010 - much less than in 2009 (-8.8%) but largely in line with recent years.
Preliminary data indicate that China's apparent demand (refinery output plus net oil product imports) surged by +19.9% year-on-year in February, with all product categories bar LPG and residual fuel oil posting strong gains. This followed a 24.0% rise in January, only slightly lower than had been anticipated in our last report (+28.0%), since refinery indicators for that month were delayed due to the Chinese New Year holidays. As in recent months, growth was largely supported by demand for naphtha (+51.4% year-on-year in February) and 'other products' (+37.6%), but demand for transportation fuels is catching up fast (collectively rising by +20.3%).
The customary caveat - the likely distortion of apparent figures by product stocking - still applies. Data from news agency Xinhua, which started publishing last month its own assessment of the country's commercial crude and oil product stocks, indicate that combined nationwide stocks of gasoline, diesel and kerosene rose by 10% month-on-month in February. This appears to tally with trends highlighted by the China Petroleum and Chemical Industry Association (CPCIA), reported by Reuters, whereby combined stocks of gasoline, diesel and kerosene held by state-owned PetroChina and Sinopec increased by about 12% month-on-month. CPCIA has reported disaggregated growth rates since April 2009, but not absolute levels (making the comparison with Xinhua's data difficult, thus precluding an estimate of the weight of state-owned company inventories relative to the country's total stocks); however, its data suggest that this was the fourth consecutive stock build after three months of decline.
Interestingly, though, gasoline stocks reportedly fell in February (-4% month-on-month according to Xinhua, -3% according to CPCIA). This would be equivalent to some 75 kb/d; if so, gasoline demand was probably higher than the +12.4% year-on-year increase implied by our apparent demand calculation, but this is impossible to ascertain given the lack of an historical stock series. More significantly, gasoil stocks rose sharply (+21% month-on-month according to Xinhua, +23% according to CPCIA), equivalent to about 530 kb/d or one-sixth of gasoil demand. This would suggest that gasoil demand was much weaker than the +25.3% year-on-year apparent demand rise, perhaps on the order of +4%. This would be a more reasonable gasoil growth rate, considering that many factories and transportation firms were closed during the Chinese New Year holidays (with the arrival of springtime, agricultural and industrial activities should resume and gasoil demand should grow more briskly).
Stocking is not only attributable to weak holiday demand, but also arguably to speculative motives, as rumours of an impending increase to 'guideline' prices have circulated since early 2010. Most observers expected a hike in mid-March, following the conclusion of the National People's Congress. However, the price rise never materialised, perhaps because the government is still debating on whether to reform China's oil product price mechanism, as we noted last month, or because it is concerned about mounting inflationary expectations (the CPI reached +2.7% in February, uncomfortably close to the 3% target for 2010 set by the central bank). However, with international oil prices now close to $85/bbl, the pressure to adjust domestic prices - and hence the incentive to hoard products - will arguably increase.
In the end, these considerations highlight once again the considerable degree of uncertainty regarding Chinese oil demand trends. Nonetheless, we have revised up by 90 kb/d our 2010 outlook to 9.1 mb/d (+7.2% or +610 kb/d year-year, equivalent to over a third of global oil demand growth).
According to preliminary data, India's oil product sales - a proxy of demand - fell by 0.2% year-on-year in February, the first contraction in 15 months (January's preliminary figures, which had indicated a 2.0% contraction, were revised up to +0.2%). This minor contraction highlights a trend that has become apparent for the past few months, namely the continuous fall of naphtha and residual fuel oil demand, arguably related to the growing penetration of natural gas (year-on-year demand for both fuels fell by 39.1% and 15.0%, respectively, in February). Meanwhile, demand for cooking and transportation fuels continues to rise strongly, with LPG, gasoline and gasoil rising by 10.6% on average.
The rise in transportation fuels continues to be supported by car sales, which rose on a yearly basis by almost a third in February. This suggests that the Indian economy, which was little affected by the global recession, remains buoyant. For example, industrial output rose by 16.7% year-on-year in January. Nonetheless, total oil demand may record subdued growth over the next few months given the structural decline of naphtha and residual fuel oil (which are expected to account for a still significant 22% of total demand). However, total oil consumption will arguably bounce back strongly in the years ahead as the share of other fuels in the demand pool become larger.
Since 1 April, 13 Indian cities (Delhi, Mumbai, Kolkata, Chennai, Hyderabad, Bangalore, Lucknow, Camper, Agra, Surat, Ahmedabad, Pune, and Sholapur) have switched to Euro IV-equivalent transportation fuels (the so-called Bharat Stage-IV standard). The rest of the country will adopt Euro III-equivalent standards (Bharat Stage-III) between June and October, excepting the western state of Goa, where they have been in place since this month. This move to increase fuel quality and curtail emissions (notably of sulphur dioxide) entailed a minor price increase - about Rs 0.50 or 1.1% for gasoline on average (equivalent to $0.01) and Rs 0.26 or 0.6% for gasoil, although the rise was much higher in Delhi (Rs. 2.36), as the city also raised the value-added tax on gasoil. Such price adjustment should in principle help state-owned refiners to recover their upgrading investment, estimated at some Rs 330 billion (about $7.3 billion). It is unclear whether the country will eventually move a step further, to Euro V standards. Two refining complexes - Reliance's Jamnagar and Essar's Vadinar in Gujarat state - are currently able to produce Euro V fuels, exclusively for export.
Saudi Arabia has become the second-largest source of expected global oil demand growth in 2010. This is a testimony to its resilient economy, which managed to escape the global recession with little damage, particularly on the fiscal side. Saudi Arabia has ambitious plans to expand its industrial base in order to create high-value jobs, and is particularly keen on becoming a petrochemical powerhouse, recently boosting LPG and naphtha use. Yet the country's pace of oil demand growth also underlines the skewed incentives provided by very low end-user prices, with gasoline demand expanding by 6.5% year-on-year in 2009 - and by +22.4% in January, according to preliminary data, which suggest that growth this year may well reach double-digit figures.
Aside from LPG/naphtha and gasoline, a major source of recent Saudi oil demand growth has been direct crude burning, used for power generation. Direct crude is included in the 'other products' category, which surged by an astonishing 58.7% year-on-year in 2009, thus partly displacing residual fuel oil, which contracted by 23.1%. 'Other products' are expected to rise by 8.1% in 2010, but this forecast could prove too modest. Recent statements by Saudi officials made clear that the share of direct crude in power generation is set to increase sharply over the next decade, since power demand is poised to rise by some 45% over that period. For the first time, the kingdom has publicly acknowledged that direct crude burning serves several purposes, sketched in previous editions of this report: hiking lighter crude production while holding firm to its OPEC commitment to curb exports; meeting stricter environmental rules as lighter crude is much cleaner than residual fuel oil; and curbing or even eliminating altogether fuel oil imports during the peak summer period.
However, the policy of increasing direct crude burning reflects limited success in expanding the country's natural gas reserves and boosting production (most current gas output is geared to petrochemical activities and field reinjection rather than electricity production). It also reverses a previous drive undertaken in the late 1990s/early 2000s to phase out crude from power generation, and effectively reduces the country's nominal spare capacity. More importantly, perhaps, it leaves unaddressed the issue of runaway power demand, which has been largely due to highly subsidised end-user prices.
- Global oil supply in March fell by 220 kb/d from February, to 86.6 mb/d, with OPEC accounting for nearly the entire decline. Compared to levels of a year ago, global oil supply is higher by almost 2 mb/d, with non-OPEC crude providing just under half of the increase. OPEC crude production accounted for 500 kb/d of the year-on-year gain while OPEC NGLs supplied the remaining 550 kb/d.
- March OPEC production posted its first significant decline in 14 months, off by 190 kb/d, to just shy of 29.0 mb/d. However, lower output levels reflect a near 10% decline in Iraqi output rather than any effort by OPEC-11 members to rein in above-target output. Indeed, OPEC-11 production rose by 30 kb/d in March, to 26.7 mb/d.
- OPEC ministers rolled over their current output targets at their 17 March meeting in Vienna, largely on expectations that global oil demand will pick up later in the year to absorb above-target production and against a backdrop of oil prices at 18-month highs of $80-85/bbl. OPEC is scheduled to review the market at its next meeting on 14 October in Vienna.
- March non-OPEC supply was unchanged versus February at 52.5 mb/d, with year-on-year output up by 900 kb/d. While 2009 estimates were left unchanged at 51.5 mb/d, 2010 output is revised up 220 kb/d to 52.0 mb/d, reaffirming the more optimistic outlook amid higher prices evident since 2Q09.
- The 'call on OPEC crude and stock change' has been revised down for 1Q10 by 400 kb/d, to 28.8 mb/d, due to higher non-OPEC production estimates. The average 2010 'call' is forecast at 29.1 mb/d, some 400 kb/d above average 2009 OPEC output levels of 28.7 mb/d.
Note: Random events present downside risk to the non-OPEC production forecast contained in this report. These events can include accidents, unplanned or unannounced maintenance, technical problems, labour strikes, political unrest, guerrilla activity, wars and weather-related supply losses. Specific allowance has been made in the forecast for scheduled maintenance in all regions and for typical seasonal supply outages (including hurricane-related stoppages) in North America. In addition, from July 2007, a nationally allocated (but not field-specific) reliability adjustment has also been applied for the non-OPEC forecast to reflect a historical tendency for unexpected events to reduce actual supply compared with the initial forecast. This totals ?410 kb/d for non-OPEC as a whole, with downward adjustments focused in the OECD.
All world oil supply figures for March discussed in this report are IEA estimates. Estimates for OPEC countries, Alaska, Indonesia and Russia are supported by preliminary March supply data.
OPEC Crude Oil Supply
After steadily rising over the past year, OPEC crude production posted its first significant decline in March, off by 190 kb/d, to 28.98 mb/d. However, lower monthly production reflects a near 10% decline in Iraqi output rather than any effort by OPEC-11 members bound by quotas to rein in above-target output. OPEC-11 production in March, which excludes Iraq, was up by 30 kb/d to 26.73 mb/d, 1.89 mb/d above the group's 24.845 mb/d collective target level.
OPEC ministers rolled over current output targets at their 17 March meeting In Vienna against a backdrop of oil prices at 18-month highs of $85/bbl. OPEC is next scheduled to meet on 14 October in Vienna to review the market, pushing back the bi-annual ministerial meeting slightly from a more usual September date.
OPEC appeared to have sidestepped difficult discussions of stricter compliance with output quotas at its March meeting, though several OPEC ministers reportedly expressed concern informally that some members continue to flout their output targets. OPEC compliance with output targets stood at about 55% in Marchdown marginally from 56% in February and the heady levels of 83% in March 2009. The UAE, Saudi Arabia and Kuwait are adhering closest to their targets while Angola, Nigeria and Iran have all but ignored their implied output levels.
Nigeria is the latest member country to formally request OPEC officials to revisit the basis on which individual country targets were allocated in September 2008, arguing that the country is entitled to a bigger share of the overall OPEC production ceiling. Nigerian officials contend that, when quota percentages were last set, the country's output was lower than expected at the time because of debilitating militant attacks on oil infrastructure in the volatile Niger Delta. Nigeria's representatives at OPEC explained that the two historical parameters of reserves and production capacity do not justify the September 2008 allocation, adding Nigeria had a traditional percentage of around 8% of the OPEC total compared with an estimated 6.7% currently.
Nigeria would like OPEC to revisit allocations in line with growing global oil demand. Global oil demand is forecast to rise on average in 2010 by 1.7 mb/d above levels of a year ago, with the call on OPEC crude and stock change up 300 kb/d for the year at 29.1 mb/d. Allowing for ex-quota Iraq, that is almost 2 mb/d above current official output target levels. While supply and demand balances clearly leave ample room for OPEC to formally increase targets more in line with the higher call on its crude production in 2010, the prospect of difficult negotiations over reassigning individual country allocations may be unwelcome.
Nigerian crude output reached its highest level in 20 months in March as repairs to damaged infrastructure moved forward. Production rebounded by 30 kb/d to 2.01 mb/d, compared with 1.98 mb/d in February. Since the Delta ceasefire proposal was put forward last July, when production was at the lowest level in decades, Nigeria has steadily increased production. Output is up 330 kb/d from July 2009
production levels of 1.68 mb/d. The ceasefire has enabled companies to repair damaged infrastructure and assess their shut-in production and pipeline operations. Government officials and operating companies reported that militant activity has forced the shut-in of an estimated 1 mb/d out of total nameplate capacity of 3 mb/d. Approximately half of the shut-in output was widely considered capable of being brought online relatively quickly once rebel activity was halted. As a result, over the past several years Nigeria's installed capacity has been consistently assessed at around 2.6 mb/d. It now appears, however, that much of this shuttered capacity will either take much longer to restore, or may not be restored at all. As a result, we have lowered our estimate of Nigeria's spare capacity from 2.6 mb/d to 2.2 mb/d to conform with our definition of crude oil production capacity levels that can be reached within 30 days and sustained for at least 90 days.
Companies are still assessing damage to infrastructure but, once again, an escalation in militant activity in recent months is undermining the country's production outlook. While militant attacks disrupted production in February, mid-March bomb attacks outside government buildings targeted industry officials, although there were no casualties. That said, the bold move by militants to target negotiators working on the ceasefire agreement has underscored the fragile state of the agreement between rebels and the new administration of President Goodluck Jonathan. The appointment of a new cabinet, including the oil minister, and the replacement of the head of state oil company NNPC, have been viewed as positive steps, but many obstacles remain. Under the cabinet reshuffle, veteran oil minister Rilwanu Lukman was replaced by Diezani Allison-Madueke, both Nigeria's and OPEC's first female oil minister.
Topping the political agenda in the coming months will be the passage of controversial oil reforms currently before parliament. Nigeria plans to push forward new petroleum industry legislation, including contract changes that foreign operators object to, despite the prospect that a number of long-time producers may scale back their involvement or exit the country altogether. Under the Petroleum Industry Bill (PIB) the government will be allowed to renegotiate old contracts, including those for offshore acreage. Foreign oil operators argue that the proposed PIB will force them to scupper billions of dollars of planned investments.
Crude oil production in Saudi Arabia in March rose by 90 kb/d, to 8.25 mb/d, or about 200 kb/d above its implied output target. However, it appears much of the above target output is being used for direct burn at power and desalination plants within the Kingdom to meet stronger demand leading up to the peak summer season. Saudi Arabia has sharply increased its use of crude oil for direct burn since early 2009, partly to meet stricter environmental regulations on fuel quality used in electricity generation and partly to meet refinery constraints that call for cleaner burning, lighter crude oil versus heavier oil (see Demand, Non-OECD, Saudi Arabia).
In previous years, implied direct burn crude at power plants typically increased by around 150 kb/d during the peak summer demand months. However, in 2009 volumes during June-September surged by more than 85%, from an average 380 kb/d in 2008 to just over 700 kb/d in 2009. Given forecast strong electricity demand growth, direct burn crude is expected to post sharp increases again this year. As a result, Saudi crude oil production may steadily rise further as the summer season gets underway.
Iraqi output fell by 220 kb/d in March due to operational problems and weather-related export disruptions at southern export terminals. Production declined to 2.25 mb/d from a downward revised 2.47 mb/d in February. After reaching the highest level in more than two decades in February at 2.07 mb/d, total exports in March are pegged at just 1.79 mb/d. Crude oil exports from the southern Basrah terminals were down by 235 kb/d to 1.38 mb/d in March due to stormy weather, particularly later in the month. That compares with 1.62 mb/d in February. Northern exports of Kirkuk crude were off by 45 kb/d to 410 kb/d in March.
Iran was the only other country to show a significant decline in production last month. The country's March oil production fell by 60 kb/d, to 3.68 mb/d versus 3.74 mb/d in February. Weaker demand for heavier crudes and refinery throughput cuts have reduced buying interest for Iran's poorer quality crudes, with a number of cargoes reportedly sitting unsold off Kharg Island. The threat of further sanctions against the country also appears to be affecting credit terms for sales.
March non-OPEC supply was unchanged versus February at just under 52.5 mb/d, while year-on-year, output was up by 900 kb/d. A baseline revision marginally trimmed the 2009 non-OPEC total to 51.5 mb/d. In 2010, in contrast, broader upward adjustments - this time largely for OECD countries - raised the forecast by 220 kb/d to 52.0 mb/d, reaffirming the more optimistic outlook amid higher prices evident since 2Q09.
The higher 2010 forecast stems from upward adjustments of around +65 kb/d each to Canada, the UK and Russia, and smaller revisions of around 20 kb/d to the Republic of Congo, Malaysia and Colombia. These are partly offset by downward adjustments of 20-35 kb/d each for Thailand, Brazil, Azerbaijan, China and Tunisia. Russia in particular continues to show steady growth due to ramp-up at new fields (extensively discussed in recent reports), as well as increased drilling at existing fields, amid more favourable prices and key tax breaks. The UK too has seen ramp-up at new fields and relatively robust performance in general.
At current forecast growth of 565 kb/d in 2010, non-OPEC prospects are therefore looking brighter. Despite a nominal slowing of investment in 2009 and a year-on-year production decline in 2008 (exacerbated by the impact of hurricane shut-ins in the US), upstream investment decisions made before both 2008's price surge and slump are starting to bear fruit. New upstream projects are coming online and ramping-up production, while increased drilling and workover are stimulating production from mature assets. For example, UK average annual decline has slowed from 200 kb/d in 2003-2006 to an estimated 100 kb/d for 2008-2010. Mexico is also illustrative. It remains to be seen whether state oil company Pemex has stabilised production at its core Cantarell field, but year-on-year decline has certainly slowed markedly since mid-2009.
Looking ahead, Azerbaijan remains a significant source of non-OPEC growth in 2010 (+50 kb/d) despite recent downward revisions, and more so in the medium term, as underpinned by the recent sanctioning of the next stage of development of the offshore Azeri-Chirag-Guneshli (ACG) complex operated by BP. The Chirag Oil Project is scheduled to come onstream in 2013 and is expected to raise total ACG output over 1 mb/d and sustain production levels well into the second half of the decade. Another bright spot on the horizon was President Obama's recent proposal to open up large previously inaccessible swathes of the US Outer Continental Shelf to exploration (see Proposals to Open Outer Continental Shelf Could Double US Crude Reserves). The effects of the latter will only be felt several years from now, but given the recent, overwhelming success at boosting US gas production, access to reserves coupled with the right price and advances in technology could help sustain US oil production in years to come.
New data showed further declines in upstream costs, also potentially boosting longer-term supply prospects. An updated IHS/CERA index revealed that in 4Q09, upstream capital costs had fallen by 9% year-on-year and by 13% from their 3Q08 peak. By comparison, US Bureau of Labor Statistics (BLS) data had shown an average peak (November 2008) to trough (September 2009) fall of 12%. These data again confirm that a feared investment impact from lower upstream spending in 2009 (recently measured at -15%) was almost entirely offset by declining costs. Still, potential 2010 cost savings look more limited. BLS indicators from September 2009-February 2010 rose by 1% on average while the IHS/CERA index appears closer to bottoming out as investment increases again. Moreover, recent changes in contract terms by international iron ore producers potentially signal renewed upward cost pressures for equipment and new-build hardware.
US - March Alaska actual, others estimated: Total US oil production hovered around 8.3 mb/d in February and March, broadly unchanged from January. All three months saw sizeable upward data revisions, with stronger NGL and ethanol supply. In contrast, Gulf of Mexico (GoM) crude prospects have been trimmed by 40 kb/d for 2010, despite the start-up of the Perdido complex in late March, which will eventually add 100 kb/d of crude production capacity. Perdido, operated by Shell, is the first field to come onstream from the Lower Tertiary formation and has set new records in terms of drilling depth and distance from the shore. 2Q10 will see the start-up of the Telemark field, which will be a tie-back to Mirage and should add another 25 kb/d of crude. Downward-revised GoM crude production is partly offset by higher estimated crude output in Alaska and the Other Lower-48, but total crude is nonetheless revised down by 20 kb/d for 2010. Total US supply in 2010 is now forecast to dip by 15 kb/d to 8.1 mb/d, as growth in the GoM and fuel ethanol (each around +90 kb/d) is more than offset by declines in crude from other regions and NGL production.
Proposals to Open Outer Continental Shelf Could Double US Crude Reserves
In late March, President Obama set out proposals for a wide-ranging opening of US coastal waters to oil exploration, including promising acreage in Alaska, the Eastern Gulf of Mexico and large swathes of the Atlantic Coast, which had long remained off limits to oil companies. It will take years until any oil found in these waters is developed, but with a Minerals Management Service (MMS) estimate of 39-65 billion barrels of economically recoverable crude oil likely to be offered in leases in the next few years, this would be a welcome new opportunity for oil companies, as it could double the US's oil reserves of 30.5 billion barrels.
Large tracts of the US Outer Continental Shelf (OCS) have remained off limits for oil companies for years, including all of the Pacific and Atlantic Coasts, much of Alaska and the eastern half of the Gulf of Mexico (see map), largely for environmental reasons. But those areas that have been open for development - in Alaska and the western half of the Gulf of Mexico - have long overtaken older onshore areas as the sources of growth in US domestic oil production.
Obama's proposals are part of much broader draft energy legislation that includes fuel economy standards, carbon emission limits and more support for nuclear power and renewables in the US's energy mix. Political pundits see Obama's oil exploration proposals as a trade-off for support for environmental standards. But the move to widen access to largely untapped sources of US domestic reserves must also be seen in the context of the perennial debate about oil import dependency. The lingering memory of recent high oil prices as well as the current budget crisis also play a role, as both the federal government and littoral states stand to gain from any offshore development.
How soon can oil companies expect to gain access to this new acreage? For a start, Obama's proposals have yet to be passed into law. The MMS however has already started collecting data on the offshore areas, which will ultimately determine which blocks to offer in its 2012-2017 plan. Companies may then initially only be allowed to conduct seismic exploration. There will likely also be environmental reviews and, based upon the experience of other offshore lease areas - notably Alaska - litigation by environmental groups.
Another unresolved issue is how to share revenues between neighbouring states and the federal government. In addition, the Eastern Gulf of Mexico is still under a moratorium only set to expire in 2022 - Congress would have to agree to lift this. Lastly, any development of offshore oil is expensive. While the Western and Central Gulf of Mexico benefit from existing infrastructure - both onshore and offshore - this is not true of the Atlantic Coast and only partly true in Alaska. There however, the need to maintain a certain flow volume through the Trans-Alaska Pipeline System (TAPS) is another incentive to boost regional output (see Going to California: Shrinking PADD 5 Output Redirects Crude Flows in report dated 12 November 2009). Indeed, Alaska may be the first region to see new activity and new leases, after Shell received the go-head for exploratory drilling in the Chukchi Sea in early April.
Last year's annual growth in US oil production of around 550 kb/d was largely due to the absence of GoM hurricanes. For 2010, we assume GoM hurricane adjustments of -210 kb/d and -240 kb/d respectively for the third and fourth quarters, based upon the rolling five-year average. A meteorological team at Colorado State University recently forecast above-average storm activity in 2010, with a possible four hurricanes and higher-than-usual likelihood of one of the four making landfall on the US coast.
Canada - Newfoundland February actual, others January actual: Following across-the-board revisions outlined last month (see Canadian Production Data Revisions Boost Outlook in report dated 12 March 2010), early-year production data prompted an upward adjustment of 70 kb/d to the 2010 forecast, largely on the basis of higher NGL output. Recently plagued by outages and repairs at upgrading units, mined synthetic crude should rise from a January low of 570 kb/d to average 720 kb/d in 1Q10 and 870 kb/d in 2Q10 following the completion of work at one of Suncor's plants. Rising NGL production expected this year (+25 kb/d year-on-year) and growth in mined synthetic crude (+55 kb/d) are forecast to offset a decline in conventional crude production, with total Canadian oil supply now set to rise 20 kb/d to 3.2 mb/d in 2010.
Oil Sands Growth Has Canada Searching for NGLs
Rising bitumen production from Canadian oil sands coupled with falling domestic NGL supplies have created a need to import diluent into the oil sands producing areas of Alberta. Total Canadian oil sands production (including both mined/upgraded and in situ bitumen) is expected to grow by 0.9 mb/d to 2.2 mb/d from 2009 to 2014, making it an important contributor to non-OPEC oil production growth, while pentanes plus output, the natural gas liquid (NGL) fraction traditionally used for bitumen dilution, is expected to fall. Current diluent imports into Alberta are estimated at 40 kb/d and these may need to increase to 150 kb/d by 2014, depending on a number of factors, including the growth of oil sands production as a whole and the structure of the crude bitumen value chains.
Diluent imports reflect the way in which bitumen is marketed and where it is refined. Unlike raw bitumen, synthetic crude oil (SCO) does not need to be diluted to allow pipeline transportation. All mined bitumen is upgraded to SCO, while so-called in situ bitumen, produced from deeper deposits, is mostly marketed as non-upgraded diluted bitumen, largely outside Alberta. A trend of more in situ bitumen being upgraded to SCO, or more non-upgraded bitumen being refined in Alberta would reduce the need for diluent imports as intra-Alberta bitumen shipments use recycled diluent. Oil sand producers' choice of whether to upgrade in situ bitumen depends on upgrading economics, partially subject to CO2 regulation, due to upgraders' heavy carbon footprint.706
The required diluent for bitumen varies from a 17% to 32% volume share, depending on bitumen quality. When SCO is used to dilute bitumen the blend volume is 50%. Cold weather increases the need for diluent, but insulated and heated pipelines can provide an offset. Around 10% of diluent is typically added to other heavy oil as a viscosity cutter. Current imports of diluent into Alberta consist of naphtha volumes sourced from the US Midwest and condensate volumes sourced from the Pacific terminal of Kitimat in British Columbia - both transported to Alberta by rail. Kitimat volumes are sourced from, among others, the Pisco fractionation plant in Peru. Canadian NGL prices have become disconnected from US Gulf prices due to the local shortage of NGLs, and price differentials have reached levels that encourage investments in pipeline capacity for diluent imports from the US.
In spite of recent capacity building to allow more bitumen refining within the province, most of Alberta's diluted bitumen will still be transported out of the province to important refining centres in Eastern Canada and the US Midwest. New oil sands projects expected to come on stream in the near future will likely necessitate a doubling of this network. Calgary-based Enbridge has proposed the 0.5 mb/d Northern Gateway West pipeline from Edmonton to Kitimat, which represents a possible future Pacific outlet for Canadian bitumen.
Enbridge is also behind the US$2 billion Southern Lights pipeline that will enter into operation by late 2010 and add 180 kb/d of capacity to transport diluent from refineries in the Chicago area to Edmonton. The pipeline may be partly filled by reused condensate from US Midwest refineries. Enbridge has also proposed the 0.2 mb/d Northern Gateway East pipeline from Kitimat to Edmonton that could enter service by 2015.
Based on our own estimate diluent import needs, the ongoing pipeline investments appear justified in the short to medium term, and longer-term developments might require large investment in diluent import infrastructure. Other oil-producing regions in the world will also be in need of diluent or light blend stock as their production of heavy oil increases. Oman is already applying its condensate production for this purpose, and Colombia's need for diluent is expected to double as it builds up production from the heavy Rubiales field and others in the Llanos area. The interplay of heavy oil and diluent already influences trade streams, naphtha availability, pipeline investments and the economics of synthetic upgrading of bitumen. With heavy oil production growing in the Americas, while NGL production in the region is projected to remain at best stagnant, international diluent trade will increase. Rapidly expanding NGL supply, especially from large natural gas developments in the Middle East, will likely be a key source of extra condensate supplies.
Mexico - February actual: February total oil production in Mexico was steady at just under 3 mb/d. Pemex claims to have stabilised output at its Cantarell field, which produced 520 kb/d in February. Steep decline at what used to be Mexico's largest field has more than offset gains elsewhere, leading to a steady decline in national output. The past year has seen growth at the Sihil and Kutz satellites, even while output at the core Akal field has fallen. A year-on-year comparison clearly shows a pronounced slowdown in overall output decline since mid-2009. This report forecasts a dip of 60 kb/d to 2.5 mb/d for crude production in 2010 on the assumption that incremental output at Ku-Maloob-Zaap of around 50 kb/d and a small uptick at the complex Chicontepec field will partly offset a drop in Cantarell output of around 150 kb/d. Meanwhile, total Mexican liquids supply could dip by 50 kb/d to 2.9 mb/d in 2010.
Norway - January actual, February preliminary: Norwegian oil production was steady at 2.4 mb/d in January and February, unchanged from December. Production estimates for 2009 and 2010 are largely unchanged at 2.4 mb/d and 2.2 mb/d respectively. ConocoPhillips and partners announced plans to spend up to $14 billion extending the life of the aging Eldfisk and Ekofisk fields (the combined Ekofisk area produced around 250 kb/d in 2009). Final investment decisions will be made in 2011. The Norwegian authorities are pushing for greater oil recovery at existing fields, with the Norwegian Petroleum Directorate (NPD) targeting an additional 5 billion barrels to be recovered by 2015. Statoil also announced plans to boost output at the Troll oil field with more drilling and gas injection. It also listed four fast-track projects due to come onstream in 2012-13: Katla, Vigdis Northeast, Gygrid and the Pan/Pandora satellite fields.
UK - January actual: UK total oil production rose 40 kb/d in January, to 1.5 mb/d. Stronger-than-expected recent performance at several fields and higher loading schedules for February and March prompted an upward revision of 70 kb/d to the 2010 forecast, with production now expected to fall to 1.4 mb/d from 1.5 mb/d in 2009. The second quarter will see a dip of around 105 kb/d as fields enter seasonal maintenance. Around half of this volume will stem from planned work at the Buzzard field, the UK's largest, which will see output curbed for an estimated ten days in May.
Former Soviet Union (FSU)
Russia - February actual, March preliminary: Russian total oil production, including field condensate and other NGLs, rose 45 kb/d in March to a new post-Soviet high of 10.4 mb/d, largely on higher crude output. Oil supply is up by 350 kb/d compared to March 2009, as output from a handful of large new oil fields has increased and decline at mature assets slowed. Rosneft's Vankor field alone, which started up just about a year ago, contributed 250 kb/d to this growth and should reach around 300 kb/d by the end of the year. Peak production capacity of 500 kb/d is expected to be reached mid-decade. In April, Lukoil will bring its Yuri Korchagin field onstream, one of the first to be developed in Russia's section of the Caspian Sea. It is forecast to reach peak capacity of 50 kb/d in early 2011.
On the basis of consistently higher-than-expected monthly output, 2010 forecast production has been revised up by 60 kb/d. Total oil production is now forecast to rise from 10.2 mb/d in 2009 to 10.4 mb/d in 2010, thus repeating 2009's largely unanticipated growth. As discussed in previous reports, future prospects depend on the fiscal regime, including the much-debated crude export duty and exemptions from it, which currently apply to a select group of fields in Eastern Siberia, including Vankor (see Further Uncertainty Over Eastern Siberian Tax Breaks in report dated 11 February 2010). A recent proposal is for exemptions to remain in place until the end of 2010, but then to be discontinued, except for Rosneft's Vankor, Surgutneftegaz's Talakan and TNK-BP's Verkhnechnonsk fields, for which the companies would each pay 40% of the full duty. Another interesting development is the Ministry for Natural Resources' proposal that foreign oil companies should be able to gain access to offshore licences in some form of joint venture with Russian companies. Currently considered 'strategic', offshore acreage is limited to development by state-owned Rosneft or Gazprom and remains virtually untapped.
Kazakhstan - March actual: Kazakhstan's oil production was slightly lower than expected in March, at 1.6 mb/d, despite output at its large Tengiz complex reaching new output heights of 540 kb/d. Tengiz production is up by around 40 kb/d since capacity was expanded last July and around 160 kb/d higher than one year ago, boosting total Kazakh supply, which is now forecast to rise 55 kb/d to over 1.6 mb/d in 2010.
Azerbaijan - December actual, January preliminary: For Azerbaijan, the 2010 forecast was again adjusted down on lower-than-forecast recent output at the Azeri-Chirag-Guneshli (ACG) complex and on the consortium's target production profile for the coming year. 2010 total Azeri production is now expected to rise by 50 kb/d to 1.1 mb/d. Looking into the future, March saw the sanctioning of the next stage in the ACG development, at Chirag, which will involve the construction of a new West Chirag platform and should boost production capacity by 185 kb/d, starting in 2013. This increment should boost total ACG output over 1 mb/d (from an average 840 kb/d in 2009) and sustain it there well into the second half of the decade.
February FSU net oil exports fell by 360 kb/d from January to 8.8 mb/d and were down by 730 kb/d year-on-year, in both cases evenly split between crude and product shipments. Compared to January, both seaborne and Druzhba pipeline crude exports fell, the former due to maintenance at Primorsk and stormy weather in the Black Sea. Higher domestic demand, partly due to cold weather, also trimmed shipments of crude and fuel oil. Structurally, the shift from western ports to the Arctic/Far East and Other Routes continues, as crude exports from the Pacific port of Kozmino pick up (in February, they were just under 300 kb/d). Kozmino or Eastern Siberia-Pacific Ocean (ESPO) crude continues to make headway into eastern markets and has reportedly been bought by refineries in China, Southeast Asia, Hawaii and the US West Coast. News reports also indicate the first-term deals. Meanwhile, export volumes through the CPC were down in March, also suffering from the bad weather seen in the Black Sea. Other Kazakh crude shipments were being diverted to the Polish port of Gdansk as a row with the Ukraine over pipeline tariffs still simmers.
Crude oil loading schedules indicate that March and April FSU export volumes will increase again following the end of maintenance at Primorsk and as weather delays recede. Kozmino shipments are also set to increase. Russian crude exports to Belarus in March were reportedly down by nearly 50% year-on-year following the January dispute and change in the export duty regime (see Russia - Belarus Dispute on Oil Tax and Transit in report dated 15 January 2010). Russia now intends to only send around 125 kb/d of duty-free crude to Belarus for domestic refining and consumption, which has led to lower purchases (compared to around 420 kb/d previously, which was subject to substantially reduced export duties). Belarus is evidently seeking new sources of crude and has reportedly signed an agreement with Venezuela to import 80 kb/d, rising to 200 kb/d in 2011. A first 80 kt tanker is apparently en route from Venezuela.
Various Asia-Pacific: In China, frozen seas in Bohai Bay earlier this year had less impact on production than previously assumed, leading to upward revisions for January and February. However, a reappraisal of the outlook for the rest of the year has led to a downward adjustment of the 2010 forecast by 25 kb/d, on lower expected output at fields in the Xinjiang, Changqing, Dagang and offshore areas. Total oil production is nonetheless forecast to rise by 125 kb/d to 3.9 mb/d in 2010. Thailand's total oil production baseline was adjusted down by 25 kb/d in 2008 and 2009 due to a reassessment of NGL production. This is carried forward into 2010, which, added to a slightly lower crude profile, brings down the total 2010 supply forecast by 35 kb/d. Overall Thai oil production is now assessed to stay relatively steady at 330 kb/d in 2010.
In India, independent producer Cairn announced that peak output capacity at its cluster of fields in Rajasthan (comprising Mangala, Aishwariya and Bhagyama) will eventually reach 240 kb/d, rather than a previous total of 175 kb/d. Mangala came onstream in the summer of last year and could ramp up to around 125 kb/d by early 2011. The forecast for total Indian oil output was not affected, however, and is expected to see growth of 70 kb/d to 870 kb/d in 2010, almost wholly due to output from Mangala. Lastly, January production in Malaysia picked up by 20 kb/d, coming in higher than expected, resulting in an upward-revised profile for 2010, which foresees a slight decline to 730 kb/d.
Various Latin America: Latin America's 2010 profile is broadly unchanged, and with overall growth of nearly 300 kb/d is still expected to make up nearly two-thirds of total non-OPEC growth in 2010. Around 180 kb/d of this is due to come from Brazil, which despite a downward-adjusted 2010 forecast is still anticipated to see strong growth in crude (+145 kb/d) and fuel ethanol (+35 kb/d) on the year. The other main contributor to growth will be Colombia, where recent production has consistently exceeded this report's expectations, despite recent upward revisions to forecast. Incremental output from the Rubiales heavy crude field in the Llanos Basin continues, pumping 110 kb/d in February. The country's total oil production is now forecast to grow by 125 kb/d in 2010 to 800 kb/d. New production data for Bolivia led to a baseline revision of around +10 kb/d for 2008 and 2009, which is carried through the forecast, while previous years were adjusted down slightly. Total oil production is forecast to remain steady at around 55 kb/d in 2010.
Various Africa: Newly received data for Equatorial Guinea, Gabon and Tunisia prompted baseline revisions to historical estimates. For the Republic of Congo (Brazzaville), we had not been fully capturing output from the Azurite field, which came onstream in the summer of last year. This pushes up the 2010 forecast by 25 kb/d, with the country's total oil output now estimated to rise by 20 kb/d to 300 kb/d in 2010.
- OECD industry stocks decreased by 38.4 mb to 2 685 mb in February, exceeding the five-year average monthly draw of 25.5 mb. A fall in European and Pacific crude oil stocks, European and North American middle distillate inventories, as well as North American 'other products', drove the change.
- OECD stocks in terms of days of forward demand cover rose to 60.0 as of end-February, up from 59.5 at end-January, as seasonally falling three-month forward demand outpaced the drop in absolute OECD stocks. Days cover grew the most in residual fuel oil and regionally in the Pacific and North America.
- Preliminary data indicate total OECD industry oil inventories built counter-seasonally by 8.0 mb in March, in contrast to the five-year average stock draw of 12.5 mb. US and Japanese stocks increased by 4.2 mb and 6.1 mb, respectively, while, according to Euroilstock, EU-16 inventories drew by 2.3 mb.
- Short-term crude floating storage rose to 65 mb as of end-March, from 55 mb at end-February. Refined products in short-term floating storage decreased from 74 mb at end-February to 52 mb. Most of the products draw occurred in the Mediterranean and Northwest Europe.
OECD Inventory Position at End-February and Revisions to Preliminary Data
OECD commercial oil inventories stood at 2 685 mb at end-February, down 38.4 mb from January levels. Crude, middle distillates and 'other products' underpinned the fall, which was exacerbated by labour-related disruptions in France. Over the past five years, stocks drew by 25.5 mb in February on average, but this included an unusually large 61 mb decrease in both 2007 and 2008, of mostly distillates and, to a lesser extent, gasoline. By contrast, during this February distillates and gasoline only declined by 14.3 mb and 0.4 mb, respectively.
Total products stocks declined by 26.5 mb, while they usually move down by 32.6 mb. Crude oil inventories in February fell by 10.4 mb against a five-year average build of 10.8 mb. This fall in crude helped to decrease the total oil stock surplus versus the five-year average to 67 mb, from 79 mb in January.
OECD crude oil stocks, mainly in Canada and the Netherlands, were revised down by 2.7 mb in December, while a downward revision to 'other products' in Canada resulted in a fall of 1.9 mb. However, January data came out 20.3 mb higher, mostly due to positive revisions in US crude and European middle distillate, residual fuel and 'other products' stocks. German and Italian distillate stock readings came in higher than previously reported. A reclassification of some motor gasoline stocks to naphtha in the Netherlands drove the 'other products' revision, starting in January 2010.
In terms of forward demand cover, OECD stocks increased by 0.5 days to 60.0 days by the end of February, as the weakening of OECD seasonal demand during the next three months outran falling stock levels. Much of the gain in forward cover came from North America and the Pacific. Residual fuel stocks saw the largest rise in forward cover among products. Meanwhile, distillate days cover were at relatively high levels at the end of winter, while gasoline days cover hovered above five-year levels before the onset of seasonal draws.
According to preliminary data, total OECD industry oil inventories built by 8.0 mb in March. By contrast, the five-year average stock change was a draw of 12.5 mb. Crude oil stocks rose by 24.1 mb, higher than a 16.8 mb seasonal build, while product inventories decreased by 16.0 mb, in contrast to a seasonal 33.4 mb draw. Short-term crude floating storage rose to 65 mb as of end-March, from 55 mb at end-February, as a further five VLCCs entered use. However, products floating storage continued to decrease, moving from 74 mb at end-February to 52 mb, mainly due to discharges in the Mediterranean and Northwest Europe.
Analysis of Recent OECD Industry Stock Changes
OECD North America
Industry stocks in North America rose slightly in February, as a 15.1 mb build in crude oil outweighed a 14.9 draw in product stocks. Both crude and product movements were led by the US. 'Other products' inventories, mostly propane, according to EIA preliminary data, drew by 11.8 mb, while middle distillates fell by 5.2 mb. The fall in US product stocks was partly offset by a stronger-than-normal 12.2 mb build in crude stocks. In Mexico, stocks rose overall by 3.5 mb, led by crude and fuel oil.
March preliminary US data showed a 9.5 mb draw in products offset by a 13.7 mb build in crude stocks, resulting in a net build of 4.2 mb. In comparison, the five-year average stock change was a product draw of 19.4 mb and a crude build of 10.9 mb. The majority of increases in crude stocks occurred in the Midwest and Gulf Coast. Stocks in Cushing, Oklahoma, rose by 0.9 mb and stood at 31.2 mb as of 2 April.
Draws in gasoline and distillate stocks along the East Coast and Midwest drove the fall in the US product stocks in March. Distillate stocks fell by 5.3 mb, most of which came from diesel. Gasoline inventories fell by 7.9 mb on the month, but still trended in the upper part of the five-year range. Imports were well below seasonal levels, yet rose throughout March. Comfortable overall stock levels and stronger imports appear to provide an ample supply buffer before the start of US driving season.
European oil stocks plummeted by 29.8 mb in February as both crude and product inventory levels fell. A majority of the sharp 16.3 mb counter-seasonal decline in crude oil stocks came from Norway, France and Germany. Preliminary data for Norway showed a drop of 10.0 mb in crude oil stocks due to outbound tanker sailings. Labour-related disruptions at French oil ports and low imports via the Druzhba pipeline cut an additional 2.5 mb and 6.7 mb in France and Germany, respectively.
Seasonal refinery maintenance in Belgium, the Netherlands and Spain helped to draw down product stocks, mainly distillates and gasoline, by 12.2 mb. French gasoline and middle distillate inventories fell by a combined 4.6 mb following a disruption to refinery operations after a labour walkout at Total's six French refineries. Prolonged cold weather further drew down German residential heating oil stocks to 52% of capacity at end-February from 56% at end-January.
Preliminary data indicate product stocks held in Northwest Europe independent storage rose slightly in March, as falling gasoil stocks were more than offset by increases in gasoline and fuel oil. The narrowing contango in gasoil futures reduced floating storage incentives and the volumes of, predominantly gasoil, held offshore Northwest Europe and in the Mediterranean declined by 20 mb during the month.
EU-16 oil stocks fell seasonally by 2.3 mb in March, according to preliminary data from Euroilstock. By comparison, the average European stock change in March is a draw of 2.5 mb. Reduced refinery activity driven by spring maintenance across Europe and economic run cuts helped crude stocks build 5.1 mb. At the same time, products stocks fell across the board, with middle distillates decreasing 6.0 mb, while gasoline, naphtha and fuel oil stocks drew by a combined 2.5 mb.
Pacific industry stocks drew by 9.5 mb in February, led by a 11.4 mb drop in crude oil inventories in Japan and Korea. Japanese crude stocks increased their deficit to five-year average levels. Korean crude oil stocks fell following low crude imports, which were the lowest levels since May 2009. Gasoline in the Pacific rose sharply in January (+4.1 mb), and increased further in February (+1.2 mb) to end the month well above the five-year range.
According to weekly data from the Petroleum Association of Japan, commercial oil stocks there rose by 6.1 mb in March, with crude gaining 5.1 mb. Inventories built by 13 mb during the first half of the month but retracted thereafter. Additions to naphtha inventories outweighed a seasonal decline in kerosene stocks, while further draws in gasoline took inventory below the five-year range.
Recent Developments in Singapore and China Stocks
Singapore product stocks rose by 1.6 mb in March. Light distillates reached all-time highs of 12.3 mb at end-March as supply of gasoline and naphtha exceeded regional demand. Higher imports from Europe into Asia pushed fuel oil stocks up by 0.6 mb, while middle distillates declined by 1.1 mb.
Chinese crude oil inventories rose by 10 mb to 206.4 mb at end-February according to China Oil, Gas and Petrochemicals (OGP). OGP resumed publishing the country's commercial oil inventory levels two months ago. From September to December, only estimates of stock changes were made available. The stock-build followed a surge in crude oil imports, particularly from the Middle East and FSU. Imported volumes rose 19.8% month-on-month and reached their second highest recorded level after a similar sharp increase in December 2009. Product stocks grew by 14 mb to 153.9 mb in February on a 15 mb build in gasoil inventories to 86 mb. Kerosene rose by 1 mb to 13.9 mb, while gasoline stocks fell by 2 mb to 53.9 mb.
- Oil markets rebounded to 18-month highs in March and early April, as financial and commodity markets rallied on expectations for an accelerating economic recovery this year, which trumped more mundane oil supply and demand fundamental factors. After closing at a 2010 low of $71.19/bbl on 5 February, futures prices for WTI have increased by some 20%, trading around $86/bbl on average for the first 10 days of April. Brent crude futures shadowed WTI's meteoric rise, up by $15/bbl from February lows of $69.59/bbl to $85/bbl.
- Underlying concerns, in some quarters, that oil markets are overheated remain. Although a recovery in oil demand is moving apace, with 1Q10 demand up by 1.8 mb/d year-on-year, so too, however, is global supply, up by almost 2.0 mb/d. While some see recovering demand having been sufficient to support the $70-80/bbl prices evident in the last eight months, they nonetheless raise questions over the sustainability of prices markedly higher than those levels.
- However, crude oil prices, especially for lighter grades, received support in March from an unexpected strengthening in crack spreads, especially for gas oil and diesel fuel. The upcoming peak summer gasoline season is also proving supportive of higher prices, as seen in improving crack spreads. By contrast, naphtha, which had been a pillar of support since 4Q09 tumbled on weaker demand.
- After posting steady gains in the first two months of the year, refining margins were mixed in March. Complex margins strengthened relative to those of simple configurations. However, refinery turnarounds in the March-June period, combined with economic closures and run cuts, if sustained, are expected to keep a prop under margins in the near term.
- Freight rates were generally weaker in March, on seasonally lower demand and continued ample tonnage. Product tanker rates fell steadily, while crude tanker rates were more volatile. Short-term floating storage of crude oil rose from 55 mb to 65 mb in March. By contrast, products held offshore declined by 22 mb, but are still at a relatively high at 52 mb.
Oil markets continued to scale new heights in March and early April, with benchmark crudes trading at 18-month highs. After closing at a low of $71.19/bbl on 5 February, futures prices for WTI have since steadily increased, trading around $86/bbl on average for the first 10 days of April. Brent futures shadowed WTI's meteoric rise, up by $15/bbl from February lows of $69.95/bbl to $85/bbl. Oil futures continue to move higher in tandem with stronger global financial markets. Sanguine investors have led the rally in financial and commodity markets on expectations for an accelerating economic recovery this year, trumping more mundane oil supply and demand fundamental factors. Even a stronger dollar at times failed to temper the recent price rise, with the correlation between WTI versus Dollar Index, a measure of the value of the US dollar relative to a basket of foreign currencies, showing another disconnect.
Currently visible supply/demand fundamentals might not own their own account for the $86/bbl posted in early April. On the other hand, as noted last month, the benefit of both hindsight and time-lagged data might equally see these higher price levels sustained, raising anew concerns about the impact on the global economy. Crude oil prices, especially for lighter grades, also received support in March from an unexpected jump in crack spreads, especially for gas oil and diesel fuel. Gasoline cracks also improved month-on-month supported by the upcoming summer gasoline driving season. By contrast, naphtha cracks, which had largely been outpacing other products since 4Q09, tumbled on weaker demand.
Underlying concerns, in some quarters, that oil markets are overheated remain, setting the stage for a sudden reversal of fortune. For sure, a recovery in oil demand is moving apace, with 1Q10 up 1.8 mb/d year-on-year. So too, however, is global supply, up by almost 2.0 mb/d. Crude oil inventories in the key US market are at the top of the 5-year average range, with an armada of tankers storing crude off the US Gulf Coast. After drawing down during the peak winter demand period, preliminary data show OECD industry stocks rose again in March and are at 60 days forward cover.
OPEC crude oil production reversed a 14-month upward trend, with supplies edging lower in March. Total OPEC production fell 190 kb/d, to just under 29 mb/d, with compliance with output targets slipping to 55% in March compared with 83% a year ago. OPEC ministers agreed to rollover current target levels at their 17 March meeting in Vienna, though production is now running 1.89 mb/d above the group's 24.845 mb/d output target.
Renewed market confidence in global economic growth and an accompanying recovery in oil demand are supporting stronger front-end futures prices. The narrowing of the contango between front-month crude prices and forward markets continued in March but by early April had started to widen again.
A growing perception that oil supplies in the medium term should be able to satisfy demand growth has also tempered forward prices. For the third month running, the WTI M1-M12 spread narrowed in March, to $2.86/bbl from $4.33/bbl in February and $5.37/bbl in January. However, by early April the spread was starting to widen again, to an average $3.18/bbl. Rising stocks at the key US Cushing, Oklahoma delivery point for the NYMEX light, sweet oil contract weighed on prompt prices in early April. The return to normal operation of Suncor's oil sands upgrading unit, following a two-month partial shut down which affected oil flows into the US midcontinent, also pressured prompt month WTI prices. Open interest in NYMEX WTI futures fell by 1.1% in March, with most of the fall occurring in the third week of March ahead of the contract roll-over. Money managers increased their net long positions by 25 400 lots, while swap dealers decreased their net longs by 19 300 and producers' net shorts fell by 11 200 contracts last month.
But mixed expectations of an early return of the gasoline season and rising prices are driving open interest in NYMEX RBOB gasoline futures sharply higher. Open interest reached record levels in the third week of March. The rise was driven by producers increasing their net short positions to 126 700 contracts at the end of March, up 4.0% on the month and 20.1% above a year ago. Hedge funds and other investors also followed suit. Money managers increased their net long holdings to 61 200 lots, while swap dealers stand net long 43 700 contracts.
Spot Crude Oil Prices
Spot crude oil markets strengthened across all major regions in March, with prices for benchmark grades up on average by between $4-5/bbl month-on-month. Spot prices were supported by brisk buying by refiners as plants come out of turnaround. Indeed, China, India and Russia saw refinery runs hit record levels in February. Global runs are expected to increase by 400 kb/d between 1Q10 and 2Q10, to 72.9 mb/d.
Spot prices for heavier sour grades lagged the gains in lighter distillate rich crudes, in part due to ample supply on offer against a backdrop of sharply lower refinery runs and much weaker fuel oil crack spreads. Underscoring the surplus volumes of Mideast heavier crude in Asia, the Dubai-Brent spread narrowed from a premium of $0.50/bbl in January to -$0.15/bbl in February and to a sharp -1.58/bbl in March. By early April, the spread had widened further, to -$1.33/bbl.
In Europe, the Urals-Brent differential continued to widen on weaker refiner demand and swelling supplies of sour crude. The Urals-Brent spread in the Mediterranean was -$1.85/bbl in March compared with -$0.80/bbl in February and -$0.10/bbl in January.
In the US, spot prices for WTI posted smaller gains relative to North Sea Brent. An armada of unsold spot crude supplies sitting in the US Gulf of Mexico, coupled with reduced refinery runs during seasonal maintenance, capped any stronger moves to the upside. After declining for several months, stocks held at Cushing also rose again in March, further limiting gains.
Spot Product Prices
Spot prices for refined products posted a sharp recovery in March, outpacing crude oil price increases. Gasoline and middle distillates surged on tighter supplies following reduced refinery output, especially in Europe. Gasoline crack spreads increased across all regions, with US spreads particularly robust ahead of the peak driving season. European gasoline crack spreads were also supported by strong buying interest from Africa and the Middle East.
Naphtha crack spreads, however, tumbled from the lofty levels seen over the past few months on weaker demand stemming from the peak olefin cracker turnaround season, especially in Asia. While demand for naphtha is likely to remain constrained during the March-June turnaround period, increased demand for blending into the gasoline pool may temper the decline.
Middle distillate cracks were also up sharply, with both gasoil and diesel cracks largely firming on reduced supply. In Northwest Europe, gas oil crack spreads surged on tighter supplies stemming from refinery run cuts and despite continued high levels of distillates in floating storage. Indeed, more robust demand and tighter supply helped trigger a shift from contango into backwardation for the ICE gas oil contract. The counter-seasonal shift is the first time the contract has been in backwardation in 14 months.
In Singapore, reduced middle distillate supplies on the back of lower refinery throughput rates also boosted gasoil crack spreads. Singapore crack spreads for Dubai crude rose to $10.47/bbl in March compared with $8.82/bbl in February and $7.55/bbl in January. Expectations that the global economic recovery will gather steam in the months ahead are lending further support to diesel cracks.
Fuel oil remained the weak link in the chain in March due to seasonally weaker demand in the Middle East, reduced Chinese imports and surplus supplies in Europe. Spot prices for high-sulphur fuel oil (HSFO) in Singapore were up by a meagre $0.75/bbl compared with gains of more than $5/bbl for other products. Cracked LSWR was the only product to see prices decline on the month. HSFO differentials to benchmark crudes tumbled in all major markets on anaemic demand. In Asia, HSFO cracks weakened to -$4.48/bbl from -$1.40/bbl in February. HSFO cracks showed similar trends in Europe and the US.
In March, both crude oil and product prices increased, resulting in divergent trends for refinery margins. Complex margins strengthened relative to those of simple configurations.
In Europe, all benchmarks rose bar Urals hydroskimming in the Mediterranean. Despite wider gasoline price differentials to crude and a weaker residual fuel oil crack, the Urals cracking margin in NW Europe continued to outperform that of Brent, as the Urals discount to Brent widened by more than $1/bbl on average from February.
In the USGC, Maya coking margins rose in line with stronger distillate and gasoline markets, with gasoline differentials to Maya increasing by around $5.30/bbl. The increase in Mars coking margins was less than half that of Maya's, as Mars prices rose more steeply. Cracking margins fell, apart from that of LLS, as the gains in product prices were not enough to offset those of crude oil.
In Singapore, hydroskimming margins fell, while hydrocracking margins increased. The latter configuration's higher yield of high valued products, gasoline and distillates, more than offset the rise in Tapis and Dubai prices. However, all Singapore margins surveyed remained negative on a full-cost basis.
2004-2010 Refining Margins Revision
Last year in OMR dated 13 March 2009, we completed our annual refining margins update in collaboration with Purvin & Gertz. At that time, we carried out a range of updates that included operating costs, World Scale freight rate indices and crude oil yields. These, together with regular checks on data integrity, led to an updating of historical series, in some cases retroactively starting in 2005.
This year's thorough audit of our models now results in a renewed recalculation of some margin estimates going back to 2004.
In the US Gulf Coast models, some previously-missing price quotations for 2005 and part of 2006 have been reincorporated. In the US West Coast model, product price quotation linkages have been updated, affecting the gross product value calculation in the Oman and Kern cracking margin models. Regarding the Mediterranean model, offsetting adjustments have been made to /$ ratios in the fixed-cost component and to links in the credits calculation.
Historical series are now available for download at www.oilmarketreport.org. For further details on margin calculation methodologies, please contact Purvin & Gertz, Inc. at firstname.lastname@example.org.
End-User Product Prices in March
In March, end-user product prices increased on average by 4.7% from February levels, in US dollars, ex-tax. All surveyed countries experienced rises, with notable increases reported in Germany (8.1%) and France (6.1%). In the former, rises were led by gasoline, diesel and heating oil, which increased strongly by 13.6%, 12.9% and 7.3%, respectively. This trend was mirrored throughout other surveyed European countries where these fuels increased on average by over 5%. In North America, gasoline and diesel prices rose by a similar percentage. Japan was the only exception, with transport fuels increasing modestly by just over 1% and heating oil falling slightly (-0.3%).
Due to the rising crude oil price and a strengthening US dollar, all fuels experienced significant year-on-year increases of between 20 and 70 percent. In March, average gasoline pump prices were $2.77/gallon ($0.73/litre) in the US, ¥130/litre ($1.44/litre) in Japan and £1.15/litre ($1.73/litre) in the UK. In continental Europe, forecourt prices ranged from 1.15/litre ($1.56/litre) in Spain to 1.40/litre ($1.90/litre) in Germany. Low-sulphur fuel oil did not experience as strong monthly growth compared with the other surveyed fuels, increasing on average by 1.5% as the moderate increases in France, Spain and Italy more than offset the 2% decrease in Germany.
Freight rates were generally weaker in March on seasonally lower demand and continued ample tonnage. Product tanker rates fell steadily, while crude tanker rates were more volatile. On the crude side, VLCC Mideast Gulf - Japan rates rose towards $18/mt during the first half of the month, while lower eastward sailings later in the month pressed rates towards $14/mt, before rates rebounded somewhat again in early April. The trend of lower westward sailings from the Mideast Gulf has for some time placed a premium on eastward crude sailings from the Atlantic basin, as tankers have had to ballast into the region.
In March, markets rebalanced somewhat, with stronger eastbound sailings from Mideast Gulf and new tonnage delivered to the Atlantic basin. Crude in short-term floating storage in the region rose by 8 mb over the month, and the equivalent of 14 VLCCs of crude floated off the US Gulf coast at end-March, hoping for a seasonal upswing in US crude runs. A further VLCC was removed from the market as South Korean-operated vessel carrying 2 mb of Iraqi crude heading for the US was hijacked off the coast of Somali on 4 April. Suezmax West Africa - US Atlantic Coast rates fell from end-February highs of $20/mt to $13-14/mt lows, as eastbound sailings out of West Africa fell in March and April and tonnage remained ample. Aframax North Sea-North West Europe rates rose abruptly to $11/mt in mid-March, before falling back to its habitual depressed $6/mt level. Higher loadings and weather related delays coincided to create the sudden upturn.
On the product side, Aframax (75 kt) Mideast Gulf - Japan rates fell steadily over March and early April from $24/m to below $20/mt on poor demand and growing vessel availability. This was partly as 12 large product carriers previously employed for short-term floating storage offloaded their product cargoes. Rates for 25kt UK coast - US Atlantic remained low around $20/mt and Handymax (30 kt) South East Asia - Japan rates were flat around $12/mt, as healthy demand was offset by ample tonnage. All three benchmark rates are approaching the low levels of last year, barely covering operating costs, however the upcoming Asian refinery maintenance season might support rates in the coming months. Rates for Handymax Caribbean- US Atlantic coast were the best performing clean benchmark rates in March, posting their highest monthly average since late 2008 at $13/mt, as product trade into Chile increased following the earthquake that shut in its refineries in late February.
Short-term floating storage of crude oil rose from 55 mb to 65 mb in March, while products fell from 74 mb to 52 mb, a net decrease of 22 mb. Increases in crude storage took place in the US Gulf and off North West Europe, while West Africa and the Mideast Gulf shed volumes. Products in short-term floating storage decreased in North West Europe, the Mediterranean and Asia Pacific. A net 14 vessels were freed up, 12 of which were large product carriers, while two additional VLCCs were booked for floating storage.
- 1Q10 global throughputs are estimated at 72.5 mb/d, largely unchanged from last month's report but 800 kb/d higher than a year earlier, marking the first annual increase since 2Q08. China, India and Russia all posted record high runs in February, while Japan and the US reported stronger than expected runs in February and March respectively. European runs, on the other hand, fell to their lowest level in 17 years in February amid peak seasonal maintenance and economic run cuts.
- 2Q10 global throughputs are expected to rise to 72.9 mb/d, almost 1 mb/d higher than a year earlier as global oil product demand growth gathers pace. Annual growth comes from China, Other Asia and the FSU, while the OECD continues to see structural decline. Latin American runs are also expected to average below levels of a year ago due to outages and refinery closures. All regions see increases from 1Q10 to 2Q10 bar Africa and the OECD Pacific, the latter which enter peak maintenance season, severely curbing runs.
- February OECD throughputs were 215 kb/d higher than previously estimated, averaging 35.8 mb/d. Japanese runs, in particular, came in much higher than indicated by weekly statistics, raising Pacific runs by 300 kb/d. European runs were curtailed by closures and maintenance and fell to their lowest levels since March 1993. US refinery runs surprised to the upside in March, with total throughputs returning to their five-year average in the last week of March.
- January OECD refinery yields increased for naphtha, jet fuel/kerosene and fuel oil at the expense of gasoline and other products, while gasoil/diesel yields remained unchanged. Total product gross output fell 4.3% year-on-year to 41.4 mb/d, with naphtha output increasing by 16.4% and the rest of products contracting.
Global Refinery Throughput
Global refinery throughputs are estimated at 72.5 mb/d in 1Q10, 800 kb/d higher than a year earlier and the first annual increase since 2Q08. The year-on-year growth is centred in the non-OECD, with Asia accounting for the bulk of the increase. The relatively unchanged 1Q10 global figure masks larger, offsetting changes since last month's report. The OECD has been revised higher by 175 kb/d on stronger than expected US and Japanese data. Other Asian runs have also been upped by about 100 kb/d since last month's report, on account of another record Indian throughput level in February, and due to the reassessment of some historical time series. The FSU, Latin America, the Middle East and Africa, on the other hand, are all seen lower, as more details on maintenance and outages reduced estimated runs.
Global refinery shutdowns are believed to have peaked in March, with an estimated 6.8 mb/d of capacity shut down due to maintenance, economic closures or technical problems. This is 0.5 mb/d higher than in the same month last year, but a clear improvement from January and February, which saw shutdowns 1.3 mb/d and 0.7 mb/d above levels of a year ago respectively. Global shutdowns are seen declining over 2Q10, with only the OECD Pacific region severely curtailing runs.
As refiners exit maintenance, global runs are expected to increase further in 2Q10, adding close to 1 mb/d from depressed 2Q09 levels to an average 72.9 mb/d. Growth comes from China (+900 kb/d), Other Asia (+460 kb/d) and the FSU (+300 kb/d), while the OECD continues to post structural decline (-440 kb/d). Latin American runs are also weak compared to a year ago (on earthquake damage in Chile and technical problems at PDVSA's Curaçao refinery), while Valero's Aruba refinery is assumed shut for the remainder of the forecast period. The return of economic growth and hence oil demand growth is fuelling the increase. Swelling product inventories will likely go some way towards meeting increased demand in coming months, so year-on-year growth in refinery runs is not expected to match demand growth. Surplus OECD refining capacity will most likely keep margins weak, although run rates and margins depend on refiners' resolve to restrain activity in order to sustain profitability.
OECD Refinery Throughput
1Q10 OECD crude throughputs have been revised up by 175 kb/d since last month's report, to average 35.7 mb/d. While monthly data for January were largely in line with expectations, February and March saw more significant changes since last month's report. In particular, preliminary monthly Japanese runs were about 240 kb/d higher than suggested by weekly data, lifting Pacific runs for February to 7.1 mb/d, the highest monthly average in a year. March estimates were also lifted on the back of stronger than expected runs in the US and a slightly less pessimistic view on European activity. In all, 1Q10 OECD runs were 1.0 mb/d lower year-on-year, after having contracted by an average 1.8 mb/d in 2009 and 0.9 mb/d in 2008.
OECD refinery throughputs averaged 35.8 mb/d in February, largely unchanged from January, but 215 kb/d higher than our preliminary estimate. Monthly increasing runs in Japan and the US were mostly offset by lower runs elsewhere. European runs fell 250 kb/d from January, lowered by high seasonal maintenance and poor refining economics. At 11.8 mb/d, European throughputs were at their lowest level since March 1993.
The year-on-year declines in OECD runs are expected to ease further in 2Q10, with total throughputs now estimated at 35.5 mb/d, or 440 kb/d lower than 2Q09. European and North American refiners are expected to ramp up runs sharply as maintenance ends and ahead of peak-summer product demand, while Pacific runs will fall an estimated 670 kb/d from 1Q10 as Japanese refiners enter their peak maintenance season.
North American refinery runs have been adjusted higher by 80 kb/d for 1Q10, following revised January Canadian data and significantly higher than expected US runs in March. Official US January statistics were 45 kb/d lower than weekly EIA data, but more than offset by a 90 kb/d upward revision to Canadian preliminary data. While preliminary data show both Canadian and Mexican runs lower in February and March, stronger than expected US data bring up the regional total over the course of the quarter. Regional runs are estimated at 16.9 mb/d in 1Q10, with an average 1.8 mb/d of capacity offline due to maintenance, run cuts or shutdowns. As refineries exit turnarounds over the second quarter and start preparing for the peak driving season, runs are expected to add 380 kb/d from 1Q10, but, at 17.3 mb/d, remain well below year-ago and historical levels.
Weekly EIA data for February and March point to a strong recovery in US refinery activity over the two months and into early April, with total US throughputs gradually returning to their 5-year average by end-March. Refinery throughputs on the Gulf Coast saw particularly strong gains, reaching 7.6 mb/d in the week ending 2 April, 1.3 mb/d higher than the recent low seen 2 months earlier. Coking margins on the Gulf Coast improved significantly in March, averaging $3.35/bbl for Mars and $4.98/bbl for Maya, boosting crude runs. Cracking margins were less favourable, with only LLS posting positive returns, while Bonny and Brent declined further into the red.
European throughputs averaged 12.0 mb/d in 1Q10, largely unchanged from the previous quarter and our last estimate, but almost 600 kb/d lower than 1Q09. February run rates were particularly weak, reaching a 17-year low of 11.8 mb/d. Maintenance in a number of countries, including the UK, Germany, the Netherlands, Spain and Turkey (in addition to already reduced run rates in France), largely explained the record low runs, although poor economic conditions also played a part. After a brief uptick in activity in March, European runs should dip again in April, when the maintenance closure of Neste's 200 kb/d Porvoo refinery in Finland adds to total shutdowns. Over 2Q10, runs are forecast to recover slightly as the peak turnaround season ends, although the continued bleak outlook for refining margins and high product stocks are likely to keep runs well below levels of a year ago.
OECD Pacific runs were stronger than expected in February, rebounding by more than 200 kb/d from January to average 7.1 mb/d. The increase came from Japan, despite preliminary indications from weekly data having pointed to a more stable, lower monthly average. Preliminary weekly data for March show Japanese runs declined by 400 kb/d (although this estimate is equally subject to revisions as was February's). Regardless, Pacific runs will dip further over the coming months as refinery maintenance intensifies and reaches its seasonal peak in June. An estimated 1.2 mb/d of capacity is scheduled to be shut in May, followed by 1.3 mb/d in June.
Non-OECD Refinery Throughput
1Q10 non-OECD refinery throughputs averaged 36.9 mb/d, largely unchanged from 4Q09, but 1.8 mb/d higher than a year earlier. The year-on-year increases continue to be centred in Asia, where new capacity is put to use. Chinese refining runs are seen 1.6 mb/d above 1Q09 while Other Asia posted a 470 kb/d yearly gain. Stronger than expected runs in Russia are keeping FSU throughputs at historically high levels, averaging 6.2 mb/d in 1Q10, or 260 kb/d more than a year earlier. 2Q10 is expected to a see further 1.4 mb/d annual increase in the non-OECD, to an average of 37.4 mb/d.
Several large non-OECD countries reported surprisingly high throughput levels in February. China, India and Russia all posted record highs based on recent years' data, despite poor margins and apparent oversupply in product markets. However, outages and reported maintenance are thought to have brought down runs in March sharply. Latin American runs likely fell the most, as Chilean outages coincided with the shutdown of PDVSA's Curaçao refinery in the Netherlands Antilles, as well as maintenance in Brazil and Ecuador.
Chinese refinery runs posted a record high of 8.3 mb/d in February, up sharply from a downwardly revised January level, and an impressive 1.6 mb/d above levels of a year ago. The increase in runs came despite refiners complaining that increasing international crude prices and lower domestic product prices cut profit margins. (Crude prices actually fell on average in February, and in any case, refiners are guaranteed a positive margin from the government). Reports that state-controlled refiner Sinopec received subsidies to export products in February, could have contributed to the higher run rates, although preliminary trade data actually show a significant decrease in product exports overall for that month. Runs are expected to dip in March as maintenance and unplanned shutdowns reduced rates. Amongst others, Sinopec's largest refinery, the 400 kb/d Zhenhai plant, entered overhaul in March, lowering runs by about 100 kb/d. The company's second largest refinery, Guangzhou, shut down a 160 kb/d crude distillation unit (CDU) for about three weeks after a fire in mid-March.
Other Asia refinery throughputs have equally been revised higher in February on account of another record Indian throughput level. Indian throughputs averaged 3.89 mb/d, 80 kb/d higher than in January, and 225 kb/d higher than previously assumed. The extensive turnarounds expected in February and March, notably at MRPL's Mangalore and IOC's Chennai refineries, seem not to have taken place. In light of the higher-than-expected reported figures, as well as changes to our outages outlook, we have taken a slightly more optimistic view for Indian refiners in 2Q10, raising runs by 150 kb/d.
After having reportedly reached full capacity at the end of February, Vietnam's 140 kb/d Dung Quat refinery had to reduce run rates in March due to technical problems. The refinery, Vietnam's first, started test runs in February 2009 and was scheduled to be handed over to its owner, Petrovietnam, on 25 February of this year. The technical problems, however, have led contractor Technip to delay the handover until the 'pending issues have been dealt with'. A report by the State Appraisal Council states that some of the technical problems might not be resolved until November. As a result, we have lowered our forecast for Vietnam by 60 kb/d in 2Q10.
In addition to the changes mentioned above, we have incorporated some revisions to historical data, lifting 2008 and 2009 estimates for Other Asia by 25 kb/d and 150 kb/d respectively. Amongst others, we have revisited our assessment of Singapore refinery activity, as well as incorporated revised JODI data for Indonesia for 2009. Furthermore, due to quality concerns and internal inconsistencies in Malaysian JODI data, we have decided to exclude reported crude throughput levels for Malaysia for 2009. Pending completion of a more thorough data audit, Malaysian runs are now estimated based on installed capacity and recent historical outage levels.
FSU refinery run estimates are largely unchanged for 1Q10 and 2Q10 compared with last month's report, given offsetting changes to the Russian and Belarus outlooks. Official data from the Russian Energy Ministry show a 1.8% monthly increase in runs in February, as runs reached 5.0 mb/d, 90 kb/d higher than a month earlier, and the highest level since at least January 2002. In light of these higher runs, we have lifted our forecast for Russian throughputs for 2Q10 by 70 kb/d, to average 4.84 mb/d.
As the dispute between Belarus and Russia regarding export duties drags on (with Minsk most recently filing a lawsuit in a court of the Commonwealth of Independent States seeking to abolish the export duty on petrochemical feedstocks), Belarus refineries have run at reduced rates due to lower crude supplies. The country, which normally receives some 420 kb/d of Russian crude, has reduced imports by almost half in 1Q10, claiming that Russian oil has become too expensive. In an attempt to reduce dependence on Russian crude imports, Belarus will for the first time import Venezuelan crude. President Hugo Chavez has promised to supply 80 kb/d starting in May, and the first Aframax tanker is already heading for the Baltic port of Odessa. The crude is then scheduled to go by railway to the 320 kb/d Mozyr refinery, raising a question mark on the economics of the deal.
Elsewhere in the FSU, Ukraine runs fell in February, but are expected to increase in March despite Lukoil's Odessa refinery remaining closed. The Odessa refinery, which has been shut since the end of January, was due to restart in mid-March but this has been delayed until April, reportedly due to poor margins. Kazakhstan refinery runs were 289 kb/d in February, up 10 kb/d from January, while Lithuanian runs were lower in March as PKN Orlen's 190 kb/d Mazeikiu refinery was shut for part of the month for maintenance.
Latin American crude runs have been revised lower by 50 kb/d for 1Q10 to average 5.1 mb/d, due to reduced runs in the Netherlands Antilles and Brazil for March. PDVSA's 320 kb/d Curaçao refinery remained closed for the entire month (and until mid-April at best) and Petrobras' largest refinery, the 355 kb/d Paulinia (REPLAN) refinery is assumed to have run at reduced rates due to maintenance. 2Q10 estimates are largely unchanged, as lower estimates for Chile are offset by a smaller upward adjustment elsewhere.
Our outlook for Chilean refinery runs has been lowered further since last month's report following updates on the damage suffered by the country's refineries during the 28 February earthquake. According to the Chilean Mining Minister Enap's 116 kb/d Bio Bio refinery sustained heavy damage during the quake and is not expected to resume production until June (and only to reach full capacity in 3Q10). The country's Aconcagua refinery, which sustained less serious damage, came back online in mid-March and is now operating normally.
Reports emerged that Argentina was forced to import gasoline for the first time in 30 years in March. Surging gasoline demand in December and January, peak summer driving months, led to shortages at petrol stations and depleted stocks. As a result, leading Argentine refiner YPF announced it would import 315 kb of gasoline from the US in March (Argentine regularly imports diesel, but has historically exported gasoline). The government faults Shell and Petrobras for the shortage, accusing the companies of deliberately causing gasoline shortage to force rival YPF, the Argentine unit of Repsol, to raise its prices. Fuel prices are subsidised by the government and prices are running about 15% lower than the international average. Gasoline retailers such as Shell and Petrobras have called for fuel prices to be increased. The Planning Minister said the government would be taking measures to ensure oil refineries in the country run at full capacity and warned that fuel exports by the refiners would be curbed if the shortages continued. January Argentinean refinery runs were on par with December's 540 kb/d, but slightly above depressed 2009 levels. Throughputs declined by 8% year-on-year in 2009 to an average 525 kb/d.
A reassessment of historical throughput estimates for Aruba, the US Virgin Islands and the Netherlands Antilles has also led to annual changes to Latin American estimates by +50 kb/d for 2006, +140 kb/d for 2007, +120 kb/d for 2008 and +70 kb/d for 2009. Further updates to historical data will be included in coming months.
OECD Refinery Yields
January OECD refinery yields increased for naphtha, jet fuel/kerosene and fuel oil at the expense of gasoline and 'other products', while gasoil/diesel yields remained unchanged. Total product gross output was 4.3% below levels of a year ago at 41.4 mb/d, with naphtha output increasing 16.4% but the rest of the product slate contracting, bar a small increase in 'other products'.
OECD gasoline yields dropped sharply to 34.4%, with all three OECD regions posting lower readings. Yields in North America and the Pacific were above the five-year range, while in Europe they remained below the five-year average. However, gross output is 520 kb/d lower year-on-year, with European output dropping by 405 kb/d and the Pacific increasing by 55 kb/d.
Gasoil/diesel yields fell slightly month-on-month to 28.9%. However, each region depicts different dynamics. Yields in North America are well below the five-year range, 2.8 percentage points (pp) lower year-on-year. Yields in the Pacific are in line with the five-year average, while in Europe, yields increased counter seasonally by 0.6 pp to above the five-year range. In terms of gross output, gasoil/diesel shows the strongest year-on-year decline among products, with output falling by 1.2 mb/d, of which 0.7 mb/d are in North America and 0.3 mb/d in Europe.
As in last month's report, naphtha yields continued their upward trend, supported by stronger crack spreads across all regions and strong demand for petrochemical feedstock in the Pacific. Yields increased sharply, reaching 5.3% and are now in line with the five-year average. More interestingly, naphtha is the only product for which gross output is within its five-year range, bar 'other products' at the bottom of the range. Gross output in both North America and the Pacific was in line with the five-year average, while in Europe gross output was 15% below its five-year average.