- Dated Brent prices continued to rise from mid-March to average $68/bbl in early April, driven by a strong US gasoline market. Peak seasonal refinery maintenance, a string of outages and the switch to summer specifications kept gasoline supply tight. OPEC cuts, falling stocks and geopolitical tension over Iran lent further support.
- World oil output fell by 265 kb/d in March to 85.3 mb/d on OPEC supply cuts and OECD production outages. Non-OPEC growth in 2007 is unchanged at 1.1 mb/d, versus 0.4 mb/d in 2006, extending the sharp recovery evident since mid-2006. OPEC NGLs will grow by 0.25 mb/d this year to 4.9 mb/d. Seasonal factors peg non-OPEC supply below 50.3 mb/d through to 3Q, before growth resumes to 50.9 mb/d in 4Q.
- OPEC March crude supply fell by 165 kb/d to 30.1 mb/d, largely due to Nigerian and Iraqi outages. OPEC supply curbs since last autumn have coincided with two quarters of heavy OECD stock draws and output remains below the level needed to generate the usual spring crude stock build. Effective spare capacity is 3.0 mb/d, but could diminish as the 0.7 mb/d of net new capacity due onstream by end-2007 lags an expected 2 mb/d rise in the call.
- Global oil product demand has been revised down to 84.3 mb/d in 2006 and 85.8 mb/d in 2007. For 2006 this is mainly related to improved data in non-OECD countries. Demand in the OECD remained largely unchanged, as a cold snap in North America was offset by milder temperatures in Europe and the Pacific.
- Total OECD inventories fell by 80.5 mb in February on declining product stocks in all regions and a crude draw in the Pacific. Forward cover is declining counter-seasonally and preliminary March data for the US, Japan and Europe indicate an unusual 1Q stock draw of around 1.0 mb/d.
- OECD February refinery throughputs fell by 0.6 mb/d, to 38.5 mb/d, due to heavier maintenance and unplanned shutdowns. Russian and Chinese crude runs in February increased by a combined 0.5 mb/d, to a new record level of 11.3 mb/d. OECD crude runs in March fell further to around 38.2 mb/d, but are expected to recover to 38.7 mb/d in April.
The cost of sulphur
The world is moving, albeit slowly, to lower-sulphur fuels. But there are consequences, both economic and environmental, which need to be better understood. Broadly, lowering sulphur levels has the potential to reduce competition, alter the structure of refined product and crude markets, thus raising prices. Achieving lower sulphur fuels will also significantly increase CO2 emissions.
The first option for refiners to meet low-sulphur targets is to use low-sulphur crudes. This is particularly pertinent in the initial stages of the sulphur-reduction process and puts upward pressure on prices for light sweet crudes. Even with desulphurisation capacity, the need for incremental light sweet crude inputs may persist, and the process can also result in yield losses - so the price effects may linger. Another option for refiners is to forego production of the tighter fuel specifications - with the consequence of higher transport fuel prices as local fuel markets get even tighter.
There is also a CO2 cost. Sulphur reduction relies on three key factors: temperature, pressure and hydrogen - all of which require energy. The deeper the cuts in sulphur content, the more energy that is expended in its removal. At some point, the environmental trade-off between low-sulphur and higher CO2 emissions becomes blurred. Emissions changes in other areas can also have broad-reaching impacts. If emissions encourage utilities to switch to natural gas, fuel oil prices will soften, weakening refinery margins and therefore tightening the supply of transportation fuels. In other words, power sector emissions controls could translate into higher gasoline prices (and possibly higher crude prices as well).
The suggested shift away from heavy, sour marine bunkers also has the potential to affect oil prices. Squeezing sulphur levels in bunkers is far harder, costly and generates more CO2 than desulphurising middle distillates. Refiners would have no alternative market for the bottom of the barrel at a time when the long-term trend in crude quality is getting heavier and sourer. A shift to low-sulphur marine fuels would certainly cost the refining industry a great deal, but as detailed above, there could also be implications for gasoline or diesel prices. Moreover, using diesel as the solution to lower sulphur standards, would stress a refining system already struggling to meet current transportation needs.
The opportunity to increase product trade could increase as OECD countries move to sulphur-free fuels, but the shift is slow, and other barriers may develop to constrain competition. For example, biofuel blending has the potential to exacerbate regional differences in fuel standards, an area already complicated by oxygenate and volatility regulations. Without the harmonisation of product standards trade is restricted, increasing prices and price volatility.
The impacts of less-than-optimum product market competition have been demonstrated in the US, where Californians, with tight state-level environmental specifications and with the Rocky Mountains as a barrier to competition from other US refiners, regularly have the highest wholesale gasoline prices in the world. Another example stems from the temporary lifting of some US product specification restrictions post-Hurricanes Katrina and Rita - improving supply both domestically and (through higher trade), internationally and thereby lowering prices.
A better understanding of the issues and a move to universally agreed standards would carry greater economic and possibly environmental benefits than a rush towards arbitrary regional or national standards. Ultimately, three issues in the reduction of sulphur need to be considered:
1. The net cost to consumers is significantly higher than just the cost of desulphurising equipment - complex refinery economics could mean higher prices of crude and products.
2. At some point, the benefits of incremental smog and particulate reduction may be outweighed by the marginal cost to the environment in terms of higher CO2 emissions.
3. Competition could be restrained by a lack of convergence in product specifications.
All three factors need to be taken into account when deciding on sulphur targets. International-level discussions among governments and between governments and industry are essential. Some choices are difficult, but improving competition through harmonised standards is one that could significantly improve market efficiency - particularly as global trade in refined products increases in the coming years.
- Global oil product demand has been revised down to 84.3 mb/d in 2006 and 85.8 mb/d in 2007. Changes in 2006 are related to adjustments in various, mostly non-OECD, countries. For 2007, the revisions reflect continued weather-related weak OECD demand in the first quarter and lower-than-expected FSU apparent demand, only partially offset by a higher figure for Chinese consumption. As such, world demand is estimated to have grown by 0.9% in 2006, and is expected to rise by 1.8% in 2007.
- OECD oil product demand has remained largely unchanged in 2006 at 49.2 mb/d, but is revised down slightly in 2007 to 49.5 mb/d. A cold snap from late January in North America led to upward revisions in 1Q07, but these were largely offset by downward adjustments in Europe and the Pacific, where temperatures continued to be much milder than average over the past two months.
- Non-OECD oil product demand has been adjusted downwards, both on a historical basis and looking ahead. This is due to the submission of preliminary 2005 data and revisions to previous years, which were particularly marked in Asia and the Middle East. Non-OECD oil product consumption is now estimated to have increased by 3.5% in 2006, and is expected to rise by 3.4%, to 36.3 mb/d, in 2007.
As noted in the last Oil Market Report, global oil product demand has largely been driven by erratic weather conditions in 1Q07. Demand in North America, which was particularly weak in late 2006 due to a mild winter start, rebounded strongly in February following a series of very cold snaps. The winter reprise in Europe, the Pacific and the Former Soviet Union was extremely mild, leading to significantly lower demand and, in the case of the FSU, to sharply higher exports. A notable exception to this weak trend has been China, where demand surged in January and February as a result of the Lunar New Year festivities.
Overall, however, our global demand growth assessment for 2006 and 2007 remains virtually unchanged in percentage terms, with stronger non-OECD growth offsetting weaker OECD growth. In volumetric terms, the arrival of new data submissions by a number of non-OECD countries have resulted in downward revisions to both historical figures and forecasts of about 200 kb/d on average. We now estimate that global oil product demand averaged 84.3 mb/d in 2006 (+0.9% year-on-year), and we foresee it reaching 85.8 mb/d in 2007 (+1.8%).
Concerns about the US economic outlook remain, reflecting the nervousness over the country's housing market and despite an official upward revision of 4Q06 GDP growth from 2.2% to 2.5% as a result of a reappraisal of inventories. This was the third quarter in a row of below-trend growth, and slowing overall credit growth augurs lower private consumption and hence relatively weaker GDP growth in 2007. At the time of writing, the IMF is due to release its worldwide economic forecasts - which alongside OECD data underpin our econometric demand model. The Fund has reportedly lowered its US GDP forecast for 2007 to slightly above 2%, suggesting that it sees, as do many other observers, growth slowing and inflation easing over the course of the year. More interestingly, this downward adjustment is relatively small; as such, oil demand in the world's largest consumer will unlikely be dented significantly. In the next issue of the Oil Market Report we will incorporate the IMF's latest economic assumptions in order to fine-tune the prospects of US (and worldwide) oil product demand.
Indeed, it should be noted that global growth - and hence oil demand - is increasingly driven by non-OECD countries. In China, in particular, a slowdown of its major trading partner (the US buys roughly a third of Chinese exports) is unlikely to curb economic growth. Indeed, China's recent economic activity relies essentially on investment, rather than internal and external consumption, given that capital is abundant and cheap (large household savings and private profits). Although the government's goal is to reduce investment - the so-called 'rebalancing' of the economy, away from the growth-at-any-cost model and its related environmental consequences - the country is still required to grow fast enough to maintain social stability. Therefore, it remains to be seen whether investment will be capped over the next few years and what would that imply in terms of oil demand.
Total OECD demand decreased in February (-0.3% versus year-ago levels) across all regions, according to preliminary data. The fall was due to continuing mild temperatures in Europe and the Pacific, which largely offset gains in North America, where the winter reprise was particularly severe. Thus, inland deliveries fell by 4.3% in Europe and by 4.9% in the Pacific, but rose by 4.1% in North America.
In terms of products, demand weakness in the first two areas was predictably related to lower heating fuels consumption, which declined by about 15% on average (heating and fuel oil in Europe and jet/kerosene in the Pacific). By contrast, North America posted a surge in residual fuel oil (+9.5%), and more interestingly, diesel (+14.3%), predominantly in the US, which suggests that overall economic activity is still strong despite the ongoing concerns.
The very mild temperatures that have prevailed in Europe and the Pacific have led to a slight downward adjustment of our OECD demand forecast for 2007 to 49.5 mb/d (+0.6% over 2006). It should be emphasised that this forecast assumes normal temperatures throughout the rest of this year.
Preliminary data indicate that February's inland deliveries in the continental United States - a proxy of demand - rose by 4.8% versus February 2006. The annual growth of diesel and residual fuel demand was particularly strong (+16.3% and 22.0%, respectively), possibly suggesting robust economic activity alongside the effects of the cold snap that hit the country that month. However, the seemingly buoyant growth of US oil product demand must be compared with its relative weakness last year following the after-effects of the devastating hurricanes and the outage of BP's Texas City refinery in 4Q05.
Intriguingly, heating oil deliveries were down by 10.7% on an annual basis. This contraction may seem odd given the extremely cold temperatures (in OECD North America, the number of 'heating-degree days' or HDDs in February was 22% higher than the 10-year average). It could be explained by the fact that mid-Atlantic heating oil markets may be switching to low-sulphur distillates - included in the 'diesel' category - and away from high-sulphur heating oil. If this is indeed the case, diesel's demand growth has been only partially driven by road-freight consumption. Meanwhile, the strength of residual fuel oil can be traced to higher demand of electricity for household heating. In addition, the relatively more expensive natural gas (at $8.3/mmbtu versus $7.7/mmbtu for fuel oil on average in February) probably encouraged some interfuel substitution.
According to preliminary data, February's inland deliveries in Mexico shrank by 1.3% versus the same month in 2006, dragged down by a 13.5% fall in residual fuel oil demand. This fall more than offset strong deliveries of transportation fuels (on an annual basis, motor gasoline rose by 5.4%, jet/kerosene by 11.3% and diesel by 3.1%).
More interestingly, the downward trend in LPG consumption, previously highlighted in this report, continues - deliveries fell by 2.2% year-on-year in February after January's -3.1%. Natural gas substitution plays a significant role in this trend, as we have noted, but local observers suggest that two other factors are also behind the ongoing decline: on the one hand, the substitution from LPG to diesel in commercial vehicle fleets and tighter regulations pertaining to LPG-fuelled household water boilers, which have reportedly become much more efficient.
According to preliminary data, oil product demand in Europe shrank by 4.3% in February on a yearly basis, mostly given the weakness in heating and residual oil use (-16.4% and -18.6%, respectively). As in January, temperatures were mild on average despite several cold snaps across the continent, curbing heating oil demand (HDDs were some 9% lower than normal in February). By the same token, electricity demand was also weak, weighing down on fuel oil consumption. Only jet fuel and diesel posted strong gains (+6.3% and 3.7%, respectively), highlighting the relatively strong economic activity that the continent has enjoyed since last year.
Germany's preliminary data suggest that February's heating oil deliveries contracted by as much as 41.2% on an annual basis as a result of continuing mild weather. As we have previously noted, this sharp contraction is related to German households filling their tanks in late 2006 in anticipation of tax hikes early this year and confirms our anticipation of weak heating oil demand in 1Q07. An unintended consequence of the moderate temperatures, though, is that consumer stocks remain quite plentiful by historical standards, filled at approximately 57% of capacity by month-end, three percentage points less than in January. Therefore, heating oil deliveries in March are likely to have been quite weak as well; moreover, given that the current winter is almost over, heating oil is likely to be subdued for most of this year since consumers will arguably have lower-than-normal filling requirements ahead of next winter. Meanwhile, diesel deliveries jumped by an estimated +3.1%, confirming the ongoing strength of the German economy.
Heating oil deliveries in France and Italy followed Germany's pattern, falling by 28.6% and 23.4%, respectively, compared with February 2006, because of the mild winter. Similarly, residual fuel oil demand contracted in both countries (by 39.6% and 58.7%, respectively), since electricity demand remained weak. It should be noted that the sharp decline observed in Italy is also explained by comparison with last year's surge following disruptions of Russian natural gas, which forced utilities to burn significantly higher fuel oil volumes.
Regarding transportation fuels, it is as yet unclear whether last month's brief strikes by Italian retail station operators dented demand in February. January's MOS submissions suggest that Italian consumers somewhat anticipated the disruptions (which were announced late that month). Indeed, gasoline demand declined less sharply on an annual basis than in the past few months (-3.4% versus -9.8% year-on-year in December), while diesel consumption surged by 5.7%, compared with -1.7% in the previous month. In February, by contrast, preliminary data indicate that gasoline consumption resumed its structural decline (-5.8%), while diesel deliveries increased by a paltry 1.0%.
Preliminary data indicate that oil product demand in the Pacific declined by 4.9% in February on an annual basis, due to weak demand for heating fuels (kerosene in Japan and other gasoil elsewhere) as a result of unusually mild temperatures across the region (HDDs were some 17% lower than normal in February). Overall, jet/kerosene deliveries were down by 6.3% compared with the same month in the previous year, while those of other gasoil fell by 7.6%. As in Europe, the clement winter also curbed electricity demand, thus weighing down on fuel oil consumption (-21.4%).
In Japan, total oil product demand contracted sharply in February (-9.7% on an annual basis), following January's decline of 12.3% (virtually unchanged from earlier preliminary data), implying a large revision to our earlier forecast (-380 kb/d).
As noted, extraordinarily temperate winter conditions depressed inland deliveries of jet/kerosene (-8.1%), which is mostly used for heating. Electricity demand was also weak, thus reducing the need to burn residual fuel oil (-36.0%), other low-sulphur gasoil (-12.3%) and direct crude for power generation (direct crude is included in 'other products', which contracted by 36.3%).
On a more positive note, transportation fuels posted relatively strong gains (gasoline deliveries increased by 2.5% and diesel by 3.8%), probably reflecting the renewed health of the Japanese economy, although these shifts may also be related to stocking following the structural weakness seen in both products in the previous few months.
In Korea, jet/kerosene demand was weak in February (-4.2% year-on-year) given mild temperatures. However, total oil product demand was supported by naphtha, which rose by +13.1%, and by a strong rebound in gasoline (+9.9%) and non-automotive gasoil deliveries (+16.3%). Overall, the country's oil product demand increased by a healthy 4.4% on a yearly basis.
Looking ahead, even though naphtha (the feedstock used to produce ethylene and propylene, the chemical sector's basic products) is likely to remain the driving force of consumption growth, its strength could be eventually tempered by its mounting price. Strong ethylene margins have so far outweighed rising feedstock costs, but there have been reports that some petrochemical producers are turning to cheaper alternatives, such as butane, condensates and even gasoil.
Will Japan's Nuclear Problems Bolster Fuel Oil Demand?
On 30 March, ten Japanese power utilities submitted final reports on previously undisclosed problems at their nuclear, thermal and hydroelectric facilities to the Ministry of Economics, Trade and Industry (METI). Evidence of serious incidents in several nuclear plants over the past two decades emerged last November, notably on the improper handling of fuel rods, their subsequent cover up and, in some cases, data falsification. The companies affected include, among others, Tokyo Electric Power (TEPCO, which is the country's largest), Chubu Electric Power (the third largest), Tohoku Electric Power (the fourth), Kansai Electric Power (KEPCO), Electric Power Development, and Hokuriko Electric Power.
So far, only Hokuriku has been ordered to idle one of the two nuclear reactors of its sole Shika plant (the second one has been shut since last July for inspections). While it is unclear how the government will respond to these latest developments , we suspect the outcome will be significantly less severe than in 2003, when similar incidents prompted the closure of all of TEPCO's 17 nuclear power units. At that time, residual fuel oil demand jumped by 54%, while direct-crude burning shot up by 32%. However, with TEPCO currently operating only 13 out of 17 units, any incremental restrictions could have some impact on the fuel oil market - particularly ahead of peak summer air conditioning demand.
Recently released refining and trade data for the first two months of 2007 (which had been delayed due to the Lunar New Year festivities) indicate that apparent demand (defined as refinery output plus net oil product imports, adjusted for fuel oil and direct crude burning, smuggling and stock changes) has been stronger than anticipated, particularly in January. Indeed, apparent demand in that month increased by about 10.1% year-on-year. In February, as anticipated, apparent demand was quite strong, with growth reaching an astonishing 12.3% according to preliminary data. All product categories bar residual fuel oil posted gains. These upward adjustments have led to a higher prognosis for 2007; we now foresee total oil product demand rising by 6.8% to slightly more than 7.6 mb/d.
As we noted in our previous report, February's strong pace of growth is directly related to the week-long holidays (18-24 February), when a large number of Chinese citizens travel back home. Predictably, demand for transportation fuels (which represent over 50% of total oil product consumption) surged over that month, with gasoline increasing by 14.5%, jet/kerosene by 26.1% and gasoil by 17.8%. Overall, demand for transportation fuels rose by almost 10% on an annual basis, compared with only some 1.5% for all other products, but this may also represent some stock building.
According to a report from the Ministry of Finance, China intends to finally introduce a fuel tax in 2007. The measure would be counterbalanced by the cancellation of highway tolls and other administrative fees. However, it remains to be seen whether the policy will be implemented. Indeed, the fuel tax has been endlessly debated and postponed time and again over the past few years, since it would lead to a politically sensitive increase in gasoline and diesel prices. Further postponement, however, will continue to encourage the sale of large cars and impinge upon Beijing's stated goal of increasing the country's energy efficiency.
India's oil product sales - a proxy of demand - increased by 4.3% year-on-year in February, according to preliminary data. All product categories recorded gains, particularly LPG (+8.0%) and residual fuel (+8.3%). The somewhat less buoyant demand for transportation fuels (gasoline rose by 4.2%, jet/kerosene by 3.7% and gasoil by a modest 1.2%) is explained by stock drawing (given February's cut in the retail prices of gasoline and diesel).
The Changing Nature of Thailand's Demand
Thailand is a case study on the effect of sustained price hikes on oil product demand. Indeed, high oil prices are arguably having a long-lasting impact upon the country's oil demand, which has substantially dropped over the past two years despite strong economic growth. Preliminary data suggest that total oil product demand fell by 3.7% between 2004 and 2006. In particular, gasoil consumption (of which some 93% is diesel and represents about 36% of total demand) plummeted by 6.1% over that period, followed by gasoline (14% of total demand), which contracted by 5.5%.
Following the sharp rise in international oil prices that began in 2003, the government introduced transportation fuel subsidies in January 2004, with the goal of shielding the oil-import dependent Thai economy from such a major external shock. However, the subsidies quickly proved too costly (reaching approximately $2.2 billion), and they were removed over the course of the following 18 months (in October 2004 for gasoline and in July 2005 for diesel). Predictably, demand for both products fell substantially as consumers became fully exposed to market prices (gasoline retail prices surged by about a third in the few months after the subsidy removal, while diesel prices shot up by over two-thirds). Motorists were forced to change their driving habits, reducing speed, shortening trips or modifying engines, among other measures. By contrast, the consumption of LPG (15% of demand), which is the only product still subsidized, has risen by 15% per year on average since 2004.
A key question is whether this drop in transportation fuel demand is structural. Monthly estimates suggest that demand for both gasoline and diesel has stabilized over the past few months at around 130 kb/d for gasoline and 330 kb/d for gasoil. Nevertheless, it is unlikely that the rates of growth for both products will ever again reach the highs seen when subsidies were in place (gasoil consumption, for example, jumped by almost 12% in 2004). Indeed, conservation measures have arguably become ingrained and will likely be carried on as long as oil prices remain relatively high. As such, we estimate that transportation fuel demand will only increase by about 3% per year on average over the medium-term.
On a final note, the government is actively encouraging the consumption of ethanol-blended gasoline and palm oil-based biodiesel through a policy of price discounts and other incentives. Admittedly, the volume of ethanol is currently marginal; for example, the so-called 'gasohol 95' or E5, which contains 5% of ethanol, accounts for about 20% of gasoline demand, but in practice this is equivalent to only 1% of total oil-based gasoline. Nevertheless, it should be noted that gasohol use rose more than two-fold since its introduction in 2005 and is expected to double again by the end of this year. In the medium-term, biofuels could thus well become a significant alternative to oil in Thailand.
In addition, it should be noted that revised data indicate that naphtha demand, albeit vigorous, is weaker than previously estimated. Naphtha's sales rose by 7.3% year-on-year in January, and by 3.7% in February, suggesting that industrial users are burning more natural gas. There have been reports that Shell plans to double LNG imports into its 2.5-mt/y Hazira terminal this year, having secured new customers willing to pay international gas prices. As such, naphtha demand is likely to resume its slow decline.
Given these revisions, we have marginally increased our 2007 forecast. India's total oil product demand is now expected to rise by 3.4% to slightly above 2.7 mb/d.
FSU apparent demand - defined as domestic crude production minus net exports of crude and oil products - has been further revised downwards by 252 kb/d in 1Q07. Although oil production inched up by some 90 kb/d, preliminary data suggest that net exports in February reached a post-Soviet high of 9.2 mb/d, and that March's figure was also very high. The surge in exports is attributed to the return of the Druzhba pipeline to full capacity and burgeoning Caspian shipments through the BTC and CPC pipelines. Given these sharp revisions, the region's apparent demand in 2007 is expected to be 0.3% lower than in 2006.
However, we remain concerned about the extreme volatility of FSU data, particularly regarding trade flows. We are currently assessing alternative methodologies for estimating demand - within the constraints of the limited availability of data.
- World oil supply fell by 265 kb/d in March to average 85.3 mb/d, as OECD production outages augmented further curbs in OPEC crude supply. Early 2007 global supply stands 150-200 kb/d above last year. Netting out Angola, non-OPEC supply is 1.0 mb/d above 1Q06 and total OPEC supply 0.8 mb/d lower.
- Expected non-OPEC supply growth for 2007, again net of Angola, remains at 1.1 mb/d, sharply higher than 2006's growth of 0.4 mb/d. Moreover, yearly growth has been averaging nearly 1.0 mb/d for the past three quarters, placing this year's expected rise in perspective. OPEC gas liquids growth averages 220-250 kb/d in both years.
- Downward adjustments to 2006 and 2007 non-OPEC supply affect Sudan and Yemen, with more minor changes accruing in the Americas. These are partly offset by upward adjustments for the North Sea and Russia in 2007. Non-OPEC supply may level off in 2Q and 3Q 2007 at around 50.3 mb/d as seasonal outages and maintenance take effect, before rising to 50.9 mb/d in 4Q.
- Total OPEC crude supply fell by 165 kb/d in March to 30.1 mb/d, amid lower output from Nigeria, Saudi Arabia, Iran, Kuwait, Iraq and Venezuela. Security issues kept 650 kb/d of Nigerian capacity and 440 kb/d of Iraqi output offline in March. On top of voluntary production curbs, this took effective OPEC spare capacity to 3.0 mb/d. OPEC crude capacity could rise 700 kb/d, to 34.8 mb/d, by December and to 36.5 mb/d by end-2008.
- OPEC-10 (excluding Angola and Iraq) trimmed output by 195 kb/d in March to 26.5 mb/d. This is 1.2 mb/d below September 2006, the reference point for supply curbs agreed to come into force from November onwards. A 15 March OPEC meeting in Vienna made no mention of new output targets, but noted that volatility would necessitate close monitoring of markets. The next scheduled meeting will be in Vienna on 11 September, suggesting continued production restraint.
- The 'call on OPEC crude and stock change' has been revised down by 0.2 mb/d for 2007 and by 0.1 mb/d for 2006, largely due to downward adjustments to non-OECD demand. On an adjusted basis, including Angola, the 'call' rises from 30.9 mb/d in 2006 to 31.5 mb/d this year. Supply curbs since last autumn have already trimmed OPEC production to levels close to the midpoint of the 2Q call, and have been instrumental in seeing two consecutive quarters of falling inventories.
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. 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. These aside, no contingency allowance for random events is subtracted from the supply forecast. While upside variations can occur, experience in recent years indicates that the random events listed above may cause supply losses of between 300 kb/d and 400 kb/d for non-OPEC supply each year.
Including Angola, OPEC March crude supply fell to its lowest level since January 2005, 165 kb/d lower than February at 30.1 mb/d. February supply was revised up by 40 kb/d as higher estimates for Iraq offset downward revisions for Angola, UAE and Iran. Major changes in March centred on Nigeria (-100 kb/d), amid renewed pipeline outages, and Iran and Saudi Arabia, which are both estimated to have trimmed supply by 50 kb/d. In the case of Saudi Arabia, maintenance at the Jubail refinery is thought to have offset signs of increased export sales to Asian customers. Indonesia saw a modest rise in production in March, albeit output stands 80 kb/d below a year ago. Angolan production rose to 1570 kb/d from a downward revised 1535 kb/d in February, as output increased at the Dalia field. Reduced OPEC supply, plus revised OPEC capacity estimates (see below), take nominal OPEC spare capacity to 4.0 mb/d, although a more realistic measure of effective spare capacity, excluding producers facing short-term constraints on boosting supply, comes in at 3.0 mb/d.
Production for the OPEC-10 (excluding Iraq and Angola) is now some 1.2 mb/d below September (the benchmark for the originally agreed cuts) and 1.7 mb/d below an earlier summer high last July. The communiqué from the 15 March meeting of OPEC ministers made no mention of production targets, but was widely seen as signifying no change from existing policy. Reference was made to a well supplied market, healthy commercial oil stocks, a firm 2007 economic outlook but continuing oil market volatility. Ongoing market monitoring was stressed. By deferring any further meeting to 11 September, the organisation has signalled that it sees no need for any formal change in output targets before the autumn. This breaks with traditional OPEC practice of convening a meeting in June to decide on production policy ahead of the third quarter rise in demand. This report sees OPEC already producing close to the expected 2Q midpoint low for the 'call' of around 30 mb/d. With apparently sharp draws in commercial inventory seen in 4Q06 and 1Q07, and a still-tight margin of spare capacity, current OPEC production could imply a further marked tightening in stocks in months to come as the 'call' rises by over 1.0 mb/d in both the third and fourth quarters. Moreover, this is significantly higher than an expected 0.7 mb/d rise in OPEC capacity through to the end of the year.
OPEC Crude Capacity Growing in 2007/2008
OPEC producers are expected to add a net 2.6 mb/d to installed crude capacity in 2007 and 2008, taking account of new capacity investments and net decline from older fields (decline rates are assumed to range from 1-5% pa for onshore fields in the Mideast Gulf, through to 12-15% pa for deepwater fields). Capacity is expected to reach 34.8 mb/d by the end of this year, compared with 33.9 mb/d at the end of 2006. Growth could accelerate in 2008, with capacity reaching 36.5 mb/d by the end of next year. However, the rise in 2008 is partly dependent on partially resumed operations at 450 kb/d of capacity in the western Niger Delta currently shuttered due to ethnic and political violence. Moreover, we have persisted with the working assumption of flat capacity in Iraq and Venezuela due to the uncertainties surrounding investment and upstream activity in both countries. Clearly, developments in all three of these countries are surrounded with risks both on the downside and the upside. Furthermore, despite attempts to employ conservative assumptions on project timing and realistic estimates of decline, current tightness in service and drilling markets suggest ongoing potential for slippage from headline capacity targets.
Capacity growth is expected to be heavily skewed towards Angola and Saudi Arabia, together accounting for half of the net increase. There have been recent suggestions that OPEC may attempt to bring Angola into the quota system as early as September, setting a ceiling for production close to 2.0 mb/d. However, this may not unduly affect active capacity investment, since our longer-term prognosis for Angola, while seeing capacity rising sharply to 2.0 mb/d by mid-2008, then envisages a levelling-off in a 2.0-2.2 mb/d range for the period through 2011. Note that we have now netted off production of 50-100 kb/d of Sanha condensate from the Bomboco field, counting this as OPEC NGL and reducing estimated current Angolan crude capacity to 1.6 mb/d. Rising supplies from the Dalia, BBLT (both currently producing), Rosa, Greater Plutonia and, later, Kizomba C projects drive the increase, as capacity reaches 2.14 mb/d by late-2008.
Saudi Arabia is expected to underpin OPEC capacity expansion after the short-term increases from Angola in 2007/2008. Much of the Kingdom's growth comes during 2009-2012, but this year and next also see sizeable increments from the Khursaniyah, Nuayyim and Shaybah fields, overall crude capacity increasing to 11.4 mb/d by end-2008 from a current 10.8 mb/d. This report excludes a combined 250 kb/d of Abu Safah crude and spiked condensates from the capacity total, underpinning the difference between our estimate and Saudi stated capacity of 11-11.3 mb/d. Much of the new crude lies at the lighter/sweeter (low sulphur) end of the Saudi quality spectrum, although longer-term developments such as the Manifa project in 2011/2012 will entail heavy crude destined for new domestic deep processing refineries. The Kingdom has been adept at pre-ordering drilling rigs and other supplies to ensure projects attain scheduled start-up in an increasingly delay-prone upstream investment environment. We see crude capacity rising further to some 12.5 mb/d by 2012, and with many of these new developments being linked to associated gas projects, Saudi NGL & condensate supply could also increase by some 500 kb/d in the next two years.
Nigeria generates 16% of OPEC's capacity growth for 2007/2008, albeit entirely in 2008. Capacity is expected to bounce back from 2.5 mb/d at end-2006, to 2.9 mb/d by 2008. Further modest net decline is expected for 2007, with 450 kb/d from the EA and Forcados streams assumed to remain offline. This capacity is assumed to be phased back in over the course of 2008 and 2009, subject to political tensions easing after presidential and local elections in April 2007. Indeed, Shell recently announced that this production could be restarted within five to six months, security permitting. Chevron's deepwater Agbami field also contributes to growth from late-2008. Nigeria's new, lower capacity target of 3.2 mb/d by 2011 in our opinion represents a more realistic level (compared with an earlier 4.1 mb/d), assuming deepwater projects such as Bosi, Usan, Akpo and Bonga SW proceed.
Kuwait, Qatar and the UAE each add around 200 kb/d to respective capacity levels during 2007/2008. For Kuwait, the increase centres on expansion and refurbishment at the western Minagish field and at the southern workhorse, Burgan. New capacity has been sanctioned for northern fields with the GC-24 project at the Sabriyah field, although this seems unlikely to be realised until 2010. Direct foreign participation in upstream projects remains off limits, which this report envisages may place an effective ceiling for capacity closer to 3.0 mb/d than the 4.0 mb/d longer-term official target. In Qatar, crude capacity increases are likely to be modest in comparison to those for gas and NGL (the latter potentially doubling to 1.0 mb/d by 2012). Nonetheless, we see Maersk's investment at the al-Shaheen field allowing capacity to increase to 400 kb/d by late-2008 from 240 kb/d currently. Total Qatari crude capacity reaches 1.1 mb/d from a current 0.9 mb/d in the same period. Growth from the United Arab Emirates (UAE) comes from Abu Dhabi, where ongoing investment at onshore fields feeding the Murban crude stream is already bearing fruit. Murban capacity, which stood at 1.2 mb/d in 2005 and 1.3 mb/d in 2006, is expected to average 1.55 mb/d in 2007 and 1.58 mb/d in 2008. Longer-term expansion from Abu Dhabi is likely to shift offshore, to the Upper Zakum and Umm Shaif fields, albeit this is only likely to result in higher capacity in 2010/2011. In all, UAE capacity could rise to 2.9 mb/d by end-2007 from 2.7 mb/d at end-2006, stabilising at that level through 2010 before offshore increments allow a further increase to 3.4 mb/d by 2012.
Algeria, Libya and Iran until recently held substantial potential for increased upstream capacity, based on a liberalising investment regime (Algeria and Libya) and the resource base (Iran) respectively. However, there has been an apparent change in tone in the past couple of years from Algeria and Libya as regards receptiveness to capacity expansion itself, and licence terms in particular. These factors, allied to Iran's relatively unattractive investment climate and worsening political isolation, limit any capacity growth potential from these producers in the short term. Each should see net capacity growth within a 70 kb/d to 135 kb/d range for 2007/2008. Increments come from the Hassi Messaoud field in Algeria and at Elephant and El Shahara in Libya. Iran has a series of field expansions, including Darkhovin, Masjid e Suleiman, Rag e Safid, Salman, Foroozan, Doroud and Abuzar. All told, Iranian increments add 350 kb/d to capacity between 4Q06 and 4Q08 but are offset by aggressive decline rates at older fields, leaving capacity largely unchanged at 4.0 mb/d by end-2008. Any step change in Iranian capacity would require greater outside investment at fields such as Azadegan, Yadavaran and South Pars. Without that, overall capacity levels could stagnate, or more likely decline. A government target of 5.2 mb/d by 2011 seems wholly unrealistic in the current political and regulatory environment.
The quality of new crude supplies from OPEC during 2007/2008 looks to be relatively sweet. While the crude gravity of the increments (totalling nearly 4 mb/d) is fairly evenly split between light, medium and heavy grades, 56% of the new supplies are expected to have a sulphur content of less than 1%. Sour, 2% plus sulphur material makes up less than 20% of the new supplies. The importance of new North and West African output helps to explain this trend. However, while this holds some scope for supply-side sulphur quality pressures to ease in the next two years, there is likely to be no let-up in demand-side pressures as legislators continuously tighten oil product sulphur limits. Moreover, African crude supplies can bring their own shipment and processing problems in terms of wax and acid content. Newer Angolan grades like Dalia for example have an acid content of 1.6 mgKOH/g. Crude from Chad and Congo can have even higher acid levels. Generally speaking, refiners will be restricted to running only small volumes of any crude with a total acid number (TAN) in excess of 1.0 to avoid equipment corrosion.
We have adjusted Angolan crude production estimates to net out gas liquids from the Sanha-Bomboco fields, currently around 80 kb/d. These are now counted within the OPEC NGL category. After adjusting for Sanha, preliminary indications for Angolan crude output seem to be running marginally ahead of our earlier expectation, with a 35 kb/d increase to 1.57 mb/d seen in March. Production from the Dalia field was reported by operator Total to have reached peak 220 kb/d early in April, slightly ahead of our assumed schedule.
Mixed signals emerged during March on the likelihood of Angola becoming bound by OPEC production limits. There were press suggestions that Angola was being told that production should not be allowed to rise above 2.0 mb/d, with the country potentially being required to adjust its expansion programme as early as this September. Angolan representatives denied that pressure was being brought to bear by other producers. There is no certainty that a much-quoted 2.0 mb/d is indeed the benchmark against which Angolan entry to an explicit or implicit OPEC quota system is to be measured. Nor is the status of Sanha-Bomboco liquids entirely clear. Notwithstanding, our supply model does not assume Angolan crude production attaining 2.0 mb/d until well into 2008.
Contrary to earlier estimates, Iraqi domestic crude use appears to have bounced back from January lows in February. This pulls up February's supply estimate, since a combination of Iraqi local crude use and exports, net of deliveries into storage, is used as a monthly proxy for production. An earlier estimate of 370 kb/d of domestic use for February has been revised up to 450 kb/d, taking February total supply to 1.98 mb/d. In March, local crude use is reported to have dipped to 410 kb/d, offsetting an increase in crude exports from February's 1.53 mb/d to 1.56 mb/d. Total Iraqi March supply thus fell marginally to 1.97 mb/d.
For the second consecutive month, exports were almost entirely concentrated on the southern ports of Basrah and Khor al-Amaya (augmented by around 12 kb/d shipped by pipeline to Syria). The last liftings of crude by tanker from Ceyhan in Turkey were 3 mb which loaded in January, since when the northern Kirkuk to Ceyhan pipeline has been largely non-operational. Crude in storage at Ceyhan remains at or below 1 mb as a result, unchanged since the January cargoes sailed. It will be interesting to see how soon and at what rate two new fields in the Kurdish-administered north come onstream. The Taq Taq and Tawke fields, operated by Addax and DNO respectively, are reportedly nearing the production phase, with initial capacity of some 70 kb/d combined. However, delays in actual production start-up may occur unless access to the northern export pipeline, or alternative offtake arrangements, can be secured.
Supply from Saudi Arabia in March is assessed at 8.55 mb/d, off by 50 kb/d from February. Exports and local use are used as a proxy for production, so although March Asian term crude sales nudged higher compared with February, this was likely offset by lower domestic crude use, with units at the Jubail refinery taken down for maintenance and potentially curbing throughput by 250 kb/d. April supply may prove broadly stable, with more limited refinery maintenance (and higher runs) offsetting weaker Asian export liftings.
Saudi Aramco's President and CEO was quoted in March as saying end-2006 crude capacity reached 10.7 mb/d, suggesting a Saudi total of close to 11.1 mb/d if half of Partitioned Neutral Zone capacity is included. This is broadly in line with this report's estimate of 10.8 mb/d if condensate and Abu Safah volumes accruing to Bahrain are excluded. Aramco also stated its reserve replacement ratio stood at 106% in 2006, with the discovery of 3.6 billion barrels of new oil reserves.
Nigerian supply for March is assessed down by 100 kb/d following the loss of 187 kb/d of Bonny Light production during 5-22 March due to a pipeline spill at Nembe Creek. Alongside reports of maintenance at the deepwater Bonga field, Nigerian supply is seen at 2.15 mb/d for the month. A total of some 650 kb/d of Nigerian capacity is estimated to have remained offline in March, although the gap between monthly production and sustainable capacity is a lesser 350 kb/d, as we have netted off long-term shut-ins of Forcados, EA and Escravos production from the installed capacity figure. Without the disruptions to Niger Delta supply seen over the past year, Nigerian capacity could have reached 3.0 mb/d by now. Rumours abounded in March surrounding potential postponement of elections on 21 April, in turn raising the possibility that this could inflame ethnic unrest in the Niger Delta. Drilling companies are reportedly avoiding taking on new work in the area due to security concerns, suggesting that the divergence in output between a disruption-prone delta and more secure deepwater facilities will continue.
US - Alaska March actual, others estimated: The first-quarter US crude production estimate has been revised down by 45 kb/d, largely due to lower inferred Gulf of Mexico (GOM) production in January. March GOM supply has also been cut by a month-long, water cooling system outage at the 50 kb/d Mad Dog field. However, downward revisions for the area are expected to taper off through 2007, with GOM supply rising modestly this year to 1.39 mb/d compared with 1.37 mb/d in 2006. Our 2007 base case forecast assumes a five-year average level of hurricane outages for the GOM, at around 165 kb/d for 3Q and 215 kb/d for 4Q. These levels are of course heavily influenced by the exceptional storm outages of 2005. Despite early-year warnings of a stronger-than-normal hurricane season for 2007, should this year prove more akin to 2006 (when outages were minimal) than 2005, GOM production could be correspondingly higher, particularly in 4Q07.
March also saw Alaskan supply running marginally below expectation, although crude production should nonetheless show modest recovery in 2007 after the pipeline problems which plagued 2006. Alaskan crude supply is seen averaging 770 kb/d this year, up from 745 kb/d last year. Early year data for US NGL supply also pull down the 1Q total by 30 kb/d, but we have assumed gradual recovery, with NGL supply this year coming in at 1.75 mb/d, up a modest 15 kb/d from 2006. With California, Texas and other lower-48 states' production for 4Q06 having marginally exceeded expectation, the overall trend for US crude production this year is a levelling off at 5.14 mb/d, after five consecutive years of decline. Upside adjustments to supply could materialise if autumn storms again prove less intense than the norm, whereas lower production will materialise in the event that hurricanes and mechanical outages on the scale evident in 2004-2006 recur. Local ethanol production is also expected to show growth of 60 kb/d in 2007, over and above crude oil's modest increase.
Canada - January actual: Canadian supply projections for 2007 are largely unchanged in aggregate this month, with conventional crude rising by 115 kb/d to 1.94 mb/d, while a 35 kb/d increase in synthetic crude (to 690 kb/d) offsets a 20 kb/d expected reduction in NGL output (to 680 kb/d). All told, Canada sees oil supply match last year's 120 kb/d growth, attaining 3.31 mb/d in total. However, the balance of supply shifts towards the second half of the year, as mechanical problems and scheduled maintenance in the first and second quarters respectively affect both offshore east coast and synthetic crude production. Supply growth in 2007, as in 2006, derives in part from rising Albertan bitumen and syncrude supplies. Production growth offshore Newfoundland and Labrador is also expected to resume after three disappointing years, with output from the Hibernia, Terra Nova and White Rose fields expected to rise by a combined 90 kb/d to reach 390 kb/d. These increments help offset declining onshore conventional production.
Future growth from Canada will be heavily weighted towards the oilsands in Alberta, where combined bitumen and syncrude production could reach 2.0 mb/d by the end of the decade. However, the oilsands, like other producing areas, face tightening fiscal and regulatory terms in the present high oil price era. Canada's federal government will gradually phase out the accelerated capital cost allowance, which enabled project developers to recover investment outlays more quickly through larger deductions early in project life. But existing projects are protected from the tax change, and even new projects will not begin to see the allowance phased out until 2011-2015. The impact on firmly committed developments is generally assumed to be slight therefore. Further changes in the fiscal and operating regime are being examined however, including an increase of the early-life royalty rate of 1%, and new Alberta rules on curbing CO2 emissions.938
Mexico - February actual: Total Mexican oil production for February came in 35 kb/d higher than anticipated, with crude output outperforming this report's estimate by 70 kb/d but NGL lower by 35 kb/d. Crude averaged 3.15 mb/d in February and NGL 405 kb/d. Nonetheless, forecast supply for 2007 has been held largely unchanged, with crude expected to fall by over 200 kb/d to 3.0 mb/d, while NGL production is broadly flat at 435 kb/d. Field-specific data for February confirmed a much higher profile for the Ku-Maloob-Zap fields, where output averaged 460 kb/d in February. We have added around 40 kb/d to the previous forecast of 415 kb/d for KMZ in 2007. Supplies could prove higher than this, notably with the expected arrival of a new FPSO at the field in April. Offsetting higher KMZ supply, however, is a similar scale downward adjustment for the Cantarell field, where decline of 15% has now been assumed for 2007, in line with recent announcements from state company Pemex.
Non-OPEC Supply Capped by Seasonality
Non-OPEC supply growth is likely to remain around 1.0 mb/d year-on-year for the rest of 2007, emulating actual performance over the past three quarters. However, the absolute level of non-OPEC supply could now level off for some months, having risen fairly consistently, from 49.1 mb/d last September to 50.4 mb/d recently. Seasonal reductions in crude and NGL supply, allied to scheduled maintenance, may restrain non-OPEC supply within a 50.0-50.5 mb/d range over the spring and summer. Renewed growth should re-emerge in 4Q however, when the non-OPEC total rises to average 50.9 mb/d. Rising supplies in the fourth quarter centre on a post-maintenance North Sea rebound, higher Caspian production, and an expected build-up in supplies from new fields in deepwater off Brazil. Before then, although new field start-ups are distributed through the year, seasonal factors will constrain mid-year non-OPEC supply. These include:
- operating constraints due to spring thaw in areas of Alaska and Canada, which customarily remove upwards of 100 kb/d of production;
- maintenance at Canadian heavy crude upgrading units and offshore eastern Canada, which this year could remove 150-200 kb/d;
- seasonality in North American natural gas and NGL supply which can reduce output by around 70 kb/d from winter peaks;
- traditional North Sea spring and summer maintenance, typically 100-150 kb/d on average for April-September for Norway, with equivalent volumes assumed for the UK;
- early-year cyclone activity, which reduced Australian production by around 65 kb/d in March, but which is factored into our forecast each year at lesser levels of 20-30 kb/d through May;
- an assumed five-year average hurricane outage for the US Gulf of Mexico, which this year removes 160 kb/d from 3Q supply (and also 215 kb/d from 4Q);
- maintenance work affecting major Caspian Sea oilfields in the summer.
Seasonal trends in maintenance and production elsewhere in the non-OECD, outside of a winter dip in Russia, are less easy to discern and are only included in the non-OPEC forecast once the timing of specific maintenance programmes has been announced. Even excluding these, often sporadically-reported, factors it is clear that a seasonal dip in demand, so often cited by market watchers, needs to be considered alongside a similar trend in non-OPEC oil supply. With refinery runs customarily rising after spring maintenance, demand for OPEC crude looks likely to increase in the months ahead from current output levels of around 30 mb/d.
Australia - January actual: Final data for January show that the impact of cyclone Isobel on Carnarvon Basin production from Australia's offshore North West Shelf was greater than originally thought, reducing both the basin's output and that for Australia as a whole by 45 kb/d. January crude output averaged some 450 kb/d, with gas liquids adding a further 90 kb/d. March too saw precautionary storm shut-ins with the passing of cyclones George, Jacob and Kara. North West Shelf output is estimated to have lost an average of 65 kb/d in March as a result. A further downward adjustment for Australia comes with revised official data for 4Q06 from the Bonaparte Basin.
All told however, our Australian forecast remains little changed for 2007, with crude and gas liquids output increasing by 70 kb/d to 595 kb/d, reversing several years of decline and showing the strongest growth since 2000. A full year of output from the Baskar Manta and Enfield projects, allied to expected start-up at the Puffin field, and an assumption of weakening cyclone impact henceforward, underpin the increase. This report's expectations for rising Australian crude supply over 2006-2008 lie close to recently published projections from Australia's Bureau of Agricultural and Resource Economics (ABARE), which envisage crude production of 480 kb/d in 2006/2007 and 560 kb/d in 2007/2008.
Former Soviet Union (FSU)
Russia - February actual, March provisional: First-quarter 2007 Russian oil supply growth stands at 4% versus year-earlier, albeit extreme weather in early 2006 curbed production. Data for February and March show stronger-than-expected supply, leading to a 65 kb/d upward revision for 1Q Russian production. However, since this revision was largely due to the absence of an anticipated supply downturn due to power supply work at Rosneft and Surgutneftegaz facilities, the upward revisions are largely confined to the first quarter. From a higher baseline, Russian crude supply growth in 2007 is now expected to average 2.8%, an annual increment of 265 kb/d to 9.65 mb/d. Condensate supplies are expected to add 320 kb/d to the total crude supply figure this year.
Some 175 kb/d of this year's growth comes from the Sakhalin projects in Russia's Far East. Output from Exxon's Sakhalin 1 project is already approaching peak 250 kb/d levels, and there are also reports that year-round production of Vityaz crude from the Sakalin 2 project, hitherto only produced in summer months, could begin later in 2007. For now, this report employs a working assumption that year-round supply only commences in 2008, raising the possibility that the supply data may be revised up later in the year. Moreover, the imminently expected sale of remaining Yukos producing assets to state-sponsored Rosneft and Gazprom raises some possibility of renewed investment in these moribund facilities. Although this report has assumed that the slide in production from Yukos units continues through 2007, some upside potential to this conservative forecast may now become evident. However, we will allow the dust to settle after any purchase, and await the subsequent production trend, before adjusting the forecast.
Preliminary data show that net oil exports from the FSU in February were at a post-Soviet high of 9.22 mb/d. This marked a dramatic rise of 830 kb/d compared with January's figure which had been revised down by 50 kb/d to 8.39 mb/d. The monthly increase was driven by higher non-Transneft exports, recovered transits through the Druzhba pipeline and the implementation of lower export duties in Russia from 1 February.
Greater February crude flows from the Caspian prompted a 460 kb/d rise in exports bypassing the Transneft pipeline system. Among these, exports of Azeri crude via the BTC pipeline rebounded by 150 kb/d, CPC exports rose by a similar amount, while over 90 kb/d of incremental exports left from Batumi on the Black Sea. Following reduced January exports into central Europe via the Druzhba line, interrupted by a dispute between Russia and Belarus, February exports along this route recovered by 140 kb/d. Transneft-controlled Baltic shipments also increased in February. FSU product exports meanwhile gained 290 kb/d in February to reach 2.65 mb/d, bolstered by increases of 140 kb/d and 130 kb/d in exports of fuel oil and gasoil respectively. This followed similar sharp increases in Russian refinery runs.
Loading schedules suggest that March exports may have come in 50 kb/d lower than in February, as a continuation of strong exports via BTC were possibly outweighed by reduced exports via Primorsk due to pipeline maintenance. However, a further cut in Russian export duties from 1 April may subsequently push FSU exports higher once again, capacity permitting.
Azerbaijan - February actual: Forecast crude production for Azerbaijan in 2007 is largely unchanged from last month at 880 kb/d, a rise of 225 kb/d compared with 2006. Offshore production from the Azeri-Chirag-Guneshli (ACG) complex, operated by BP, reached 700 kb/d in February, and could rise towards 750 kb/d over the rest of the year. A year ago, ACG was producing around 400 kb/d. The 620 kb/d Baku-Tbilisi-Ceyhan pipeline, which feeds ACG crude to the Mediterranean, will also be expanded to 1.0 mb/d in 2Q07. However, stronger output now expected in the first half of this year is offset by news of a two-week maintenance outage scheduled for September at the Azeri field. This could curb supply by as much as 300 kb/d for the month as a whole.
In late March, the country's Industry and Energy Minister stated that Azerbaijan would double crude production to 1.3 mb/d by 2010. This is slightly higher than the forecast contained in the last Medium-Term Oil Market Report (MTOMR) of 1.15 mb/d of crude and 50 kb/d of gas liquids by 2010.
Sudan: Oil production from Sudan is now expected to average 480 kb/d in 2007, compared with 360 kb/d in 2006. Production estimates for both years have been revised down by 40-55 kb/d as the build-up in supply from new fields feeding the Dar export blend has been slower-than-expected. Production has been constrained in part because of differences in quality between the longer-established Nile Blend and the more acidic Dar Blend. Both grades are exported via the existing Bashayer export facility on the Red Sea coast. Inauguration of the Bashayer 2 terminal later in 2007 will double current 450 kb/d export capacity. The country also plans to double production capacity to 1.0 mb/d by 2012 and to increase domestic refining capacity from a current 75 kb/d. Sudan has said it is considering joining OPEC, although it seems unlikely to do so before Ecuador, whose membership was suspended back in 1993, and which has stated that it too wishes to rejoin the producer group.
Revisions to Other Non-OPEC Estimates
Non-OPEC supply estimates this month have been revised down by 60 kb/d for both 2006 and 2007, leaving growth unchanged at 1.1 mb/d this year compared with 0.4 mb/d in 2006. Aside from adjustments mentioned in the main text above, OECD Europe supply for 2007 has been increased by 35 kb/d. A 20 kb/d downward adjustment based on lower January/February data for Denmark, is countered by upward adjustments totalling 50 kb/d for Norway and the UK. A 2Q dip in northerly Haltenbanken production from Norway has been modified to take account of an expected rebound from maintenance work at a number of fields. Early indications from aggregate January data and loading schedules for succeeding months also boost baseline 1Q UK supply by some 20 kb/d.
JODI data for September-December 2006 knock 15-30 kb/d off estimated supply from Yemen. As this report was already employing aggressive decline rates for older fields such as Masila, production estimates for newer fields in Blocks 43 and 51 have been adjusted downwards. Early-year oilfield maintenance in Brazil and Peru, allied to lower late-2006 production from Trinidad, cut the 2007 supply estimate for Latin America by 20 kb/d.
- Total OECD inventories fell by 80.5 mb in February, leaving them 49.6 mb lower year-on-year. Product stocks declined in all three regions by a cumulative 72.3 mb and despite seasonal refinery maintenance in North America and Europe, a draw in the Pacific region led to a net fall in crude stocks in the OECD. Total stocks forward cover fell slightly at a time when it usually increases, though due to rounding stayed at 54 days - the same as both end-January and levels of a year ago.
- January 2007 data were revised up by 9.5 mb, shared almost equally between crude and total product stocks. Much of this stemmed from Europe, where product numbers were revised up by 10.6 mb. In contrast, North American end-January product stocks were revised down by 5.0 mb.
- Preliminary March data for the US, Japan and Europe showed a further dip in total stocks of 23.0 mb, indicating that total first-quarter OECD inventories remain on track to fall by around 1.0 mb/d (following a 0.9 mb/d fall in 4Q06). While this would be the highest rate of decline since 1Q96, it remains subject to confirmation by final data.
OECD Industry Stock Changes in February 2007
OECD North America
North American inventories fell again in February, by a total of 48.3 mb. This was essentially all in product stocks, while crude levels were unchanged. The US stock draw of 46.3 mb made up the lion's share, but total Mexican inventories were also down by 2.0 mb, again mostly in products. In the US, lower-than-average refinery utilisation was balanced by only average crude imports, leaving crude inventories flat on the month but down 17.6 mb year-on-year.
Preliminary US data for March show a crude stock build of 7.2 mb, as imports increased again and refinery utilisation only inched upwards. The distribution of crude inventories in the US remains significant. Refinery hitches in the Midwest have kept more crude landlocked. Stocks in Cushing, Oklahoma, the delivery point for NYMEX WTI, are notably high, leading to heavy spot discounts and an unusually wide discount to ICE Brent and other domestic crudes. In contrast, stocks on the West and East Coasts were until recently at the bottom of their respective five-year average ranges.
Product inventories in North America fell by 50.2 mb in February, most of which was in the US. Ongoing refinery maintenance and several unplanned outages have curbed product output, while imports of refined products were only at average levels for this time of year. Total middle distillate stocks in February fell by 13.7 mb, and gasoline by 10.9 mb, but compared with the five-year average, gasoline levels remain tighter.
Preliminary weekly March data for the US show that product stocks have fallen further, by a total of 14.1 mb. Most of this draw was in gasoline (-12.3 mb), as demand remains strong and refinery utilisation continued to be lower-than-average. Heating oil inventories also fell by 3.7 mb, while diesel stocks were down by 1.9 mb. Having started the year well above the five-year average, a steeper-than-normal decline in gasoline stocks has dragged total product stocks to the middle of that range. However, in terms of forward demand cover, gasoline inventories are at the bottom of the five-year range for this time of year.
Total inventories in OECD Europe fell by 9.3 mb in February, which again was due to a decline in product levels. Crude stocks rose by 1.3 mb, but remain 28.7 mb lower than one year ago, and also at the bottom end of their five-year range. Draws were observed in Germany (-2.2 mb), Italy and the Netherlands (both -1.5 mb), while the UK and France saw crude stock builds of 5.3 mb and 3.5 mb respectively. The latter were both undergoing substantial seasonal refinery maintenance in February. While pan-European maintenance was expected to peak in March, the ongoing tightness in Brent forward spreads suggests this did not coincide with a significant recovery in crude inventories.
Total product inventories in Europe fell by 9.7 mb in February, but overall, a mild winter has left stocks substantially above year-ago (+20 mb) and five-year average levels (+40 mb). The February decline was predominantly in residual fuel oil (-4.7 mb) but also in gasoline (-3.8 mb) and distillate (-1.3 mb). Stock draws were observed in the UK (-3.1 mb), the Netherlands (-1.9 mb), France (-1.6 mb) and Italy (-1.4 mb), while inventories increased in Germany (+2.7 mb).
The OECD Pacific also saw a considerable stock draw of 22.9 mb in February. In this case, the fall was almost equally due to decreases in crude (-10.6 mb) and product inventories (-12.3 mb). Crude stocks are now at 160.5 mb - slightly higher than one year ago, but at the bottom end of the five-year range. Crude inventories fell both in Japan and South Korea, by 6.1 mb and 4.4 mb respectively. Preliminary March data from the Petroleum Association of Japan (PAJ) show a slight crude stock build of 2.3 mb, reflecting the start of seasonal refinery maintenance in the OECD Pacific as well as some voluntary run cuts.
Pacific product stocks in February fell by 12.3 mb, most of which was due to declining middle distillate levels. Middle distillate inventories drew by 10.6 mb, while gasoline dipped by only 1.1 mb, and fuel oil stocks inched up by 0.2 mb. Most of the product stock draw took place in Japan, where distillates fell by 8.9 mb. Korean product inventories fell by 1.7 mb, again largely driven by a decline in distillates. Preliminary PAJ data for March indicated a further downward trend in product stocks of 8.3 mb in Japan, as refiners reduced throughputs for maintenance. Kerosene inventories (for domestic heating), fell from unusually high levels at the beginning of 2007 to year-ago levels by the end of March, but remain at the upper end of their four-year range. The decline was helped by higher-than-average kerosene exports throughout February and early March.
OECD Inventory Position at End-February and Revisions to Preliminary Data
Total OECD industry stocks were 2,597.1 mb at the end of February, down 80.5 mb from January, and 49.6 mb lower than a year ago. Total crude inventories stood at 921.0 mb, 9.1 mb lower than in January, and down by 43.6 mb year-on-year. Total refined product stocks fell by 72.3 mb in February to 1,391.1 mb, or 12.8 mb lower year-on-year. Despite the draw-down, weaker demand kept end-February forward cover at 54 days, unchanged from the previous month and end-February 2006. Taking preliminary (and incomplete) March data into account, the first quarter remains on track for an OECD stock draw of around 1.0 mb/d. As noted in last month's report, this would represent the steepest first-quarter decline in stocks since 1996.
Recent Developments in ARA Independent Storage
Total oil product inventories held in independent storage in the Amsterdam-Rotterdam-Antwerp (ARA) area fell by 1.2 mb in March, but remain well above their five-year average range. The decline was almost wholly due to distillate stocks falling by 1.1 mb, though gasoline and fuel oil levels were also down by 0.2 mb and 0.1 mb respectively. Naphtha and jet-kerosene inventories meanwhile increased by 0.2 mb and 0.1 mb respectively. It is worth noting that gasoil, fuel oil, jet-kerosene and naphtha stock levels all remain above their respective five-year ranges. Gasoline in contrast, at just over 7.0 mb, has been in the middle of its range in February and March. It remains to be seen whether, with European refineries gradually returning from their March maintenance peak, the usual volumes of gasoline can be sent to the structurally short, and currently tight, US market.
Recent Developments in Singapore Stocks
According to International Enterprise, total oil product stocks held in Singapore fell marginally by 0.2 mb in March, and remain slightly above their five-year average range. A 1.0 mb draw in light distillate inventories was balanced by increases in middle distillate and fuel oil levels of 0.5 mb and 0.4 mb respectively. India has raised naphtha exports in April, which has reduced market tightness, even though petrochemical demand remains strong in the region. High-sulphur fuel oil (HSFO) prices in Singapore have risen compared with Rotterdam since mid-March, and could attract more imports from Europe as refiners there ramp up production after maintenance. Three million tonnes are reportedly booked to arrive in April, but only in the latter half of the month.
Regional OECD End-of-Month Industry Stocks
(in days of forward demand and millions of barrels of total oil)
- Prices rose further from mid-March on a strong US gasoline market and rising geopolitical tension over Iran and Nigeria. Ongoing refinery maintenance and unplanned outages kept mogas supply tight, particularly on the US West Coast. Crude futures spiked in late March when (unfounded) rumours spread that Iranian and US naval forces had clashed in the Middle East Gulf in the midst of a standoff over Iran briefly seizing 15 UK naval personnel.
- Crude prices were supported by OPEC production cutbacks, strong product stock draws and a thirst for gasoline-rich grades, despite global refinery maintenance peaking in March. WTI has widened its unusual discount to Dated Brent, though this was more a reflection of temporarily weak inland US crude demand than of the wider crude market, which remains strong.
- Refining margins mostly rose in March on strong gasoline prices, particularly in the US, where they remain highest. In Europe strong gasoline resulted in a higher return for more complex refineries, with hydroskimmers also pressured by weak fuel oil cracks and stronger regional crude prices. Asia suffered from similar, but more exaggerated pressures from crude and fuel oil, leaving margins more or less flat.
- Gasoline led product prices higher, supported by tight supply and the changeover to summer-specification material. Distillate prices also rose on spring agricultural demand, while fuel oil was mainly flat as lower output due to maintenance was balanced by a seasonal downturn in demand.
- Crude freight rates in the Mediterranean hit 15-month peaks at the end of March as the Fos strike in southern France left almost 40 tankers stranded offshore. Meanwhile, US refiners seeking crude post-maintenance boosted VLCC rates from the Mideast Gulf to six-month highs.
A flare-up of geopolitical tension concerning Iran contributed to rising prices between mid-March and early April. Against the background of new, tighter UN Security Council sanctions passed in late March, and both US and Iranian naval exercises in the Gulf, the Iranian detention of 15 UK navy personnel stirred worries that a confrontation of sorts was increasingly likely. Indeed on 27 March these concerns provoked a $5 spike in thin trading conditions to nearly $70/bbl on (unfounded) rumours that Iranian and US vessels had clashed in the Middle East Gulf.
But the primary driver of higher prices was a tight US gasoline market. Although US refineries are gradually returning from seasonal maintenance, a string of unplanned outages has intensified regional tightness. This has been particularly severe on the West Coast, driving gasoline prices to heights last seen in the aftermath of Hurricanes Katrina and Rita in 2005. Transport fuel demand has been robust which, coupled with modest gasoline and crude imports (partly related to fog in the Houston ship channel), and the switch from winter to summer-specification products, has exacerbated gasoline tightness.
In Europe, crude stocks remained at the lower end of the five-year average range in February and may have fallen even further in March. A two-week strike by dock workers in southern France's main oil hub Fos created a backlog of oil tankers that were unable to unload and OPEC production was further reduced, but with the offset that refinery throughput was lower. However, the persistent backwardation in nearby Brent futures contracts would suggest a continued tightness in European crude stocks.
European gasoline inventories, pressured by the structural reduction in regional demand were likely to have been further reduced. Before the Fos strike ended on March 31, several refineries were forced to reduce throughputs as crude stocks ran low, on average cutting throughputs by 45 kb/d in March and April (the latter due to a slow ramp-up). Meanwhile other refiners indicated they were undergoing seasonal maintenance. Elsewhere in Europe, the Rhine near Cologne was blocked for several days after a shipping accident, tightening supply upstream in southern Germany and Switzerland.
The price dip on the news that the British sailors had been released on 5 April proved fleeting, and was overwhelmed within an hour by a stronger-than-expected US weekly stock report. Moreover geopolitical issues are unlikely to go away. In particular, although Shell has indicated it hopes to restore shut in Nigerian production by the end of the year, in the short term there is concern that the run-up to the 21 April presidential election will be accompanied by more violence and kidnappings of foreign oil workers. In Ecuador, protests briefly resulted in the declaration of force majeure on Oriente and Napo exports, though this has since been resolved.
Spot Crude Oil Prices
Crude markets were shaped by gasoline tightness (and corresponding refinery needs) and OPEC cuts, which combined to create some unusual regional price imbalances. WTI remains weak, leading to unusual spreads to domestic crudes, and is at an unusual discount to Brent for six months out on the forward curve (see text box).
Strong flows of Canadian pipeline crude, as well as refinery maintenance and problems in the US have created a glut of crude in the US Midwest. Stocks at the NYMEX WTI delivery point of Cushing, Oklahoma, are near capacity, but there are limited opportunities to ship it out, leading to heavy spot discounts. In contrast, Gulf Coast refiners' thirst for gasoline-rich crudes has kept seaborne domestic crudes strong. As a result there have been significant shifts in crude price relationships to WTI, with even sour US Gulf crude Mars briefly trading at a premium. However, while the weak WTI/Brent spreads appear to suggest poor economics for West African and other imports, the same is not true when compared with other (currently) more representative grades such as LLS. But many Western Hemisphere crudes are priced off WTI, and this has led to some unusual trades, including reports of an Indian refiner buying Ecuadorean crude.
In Europe, Dated Brent has been exceptionally strong, also relative to other Atlantic Basin sweets. Low European crude stocks, lower OPEC output, rising freight rates in the Mediterranean (due to the Fos strike) and the worries over Iran have lent support. Urals in the Mediterranean gained vis-à-vis Urals in the Rotterdam market, partly on the Fos strike, but also due to projected lower Black Sea exports in April. Relative to Dated Brent however, both crudes remained flat at around a $3-4/bbl discount. In terms of the arbitrage outside of the region, Urals lost ground to Mars, but rose in value versus Oman.
Distorting a Benchmark
The persistence of WTI's unusual weakness to other domestic and international crudes has raised questions about its viability as a regional benchmark. While globally, oil prices have risen, WTI, a landlocked crude, weakened in relative terms due to local factors. Prolonged outages at Valero's McKee refinery have forced the company to re-route its intake of WTI towards Cushing, where crude stocks were already high due to a steady influx of Canadian barrels. This has led to some unusual price relationships - seaborne US Gulf crudes such as LLS or, even more unusually, sour marker Mars, have been trading at premiums to WTI.
The contrast with Dated Brent, recently even in backwardation for the first two months due to tight European crude stocks, is equally dramatic. Traditionally, WTI has traded at a premium of around $1.50/bbl to Dated Brent which tends to encourage European and African crudes across the Atlantic. But the recent weakness of WTI has pushed the spot spread to a discount of $5/bbl and more, and forward spreads remain at a discount at least six months forward.
This anomaly has not prevented crude oil trading: traders are either using larger discounts to WTI, or have reportedly switched their calculations to more (currently) representative US crudes such as LLS. So why worry?
Pricing benchmarks have emerged over a period of time because they possess certain characteristics - notably location, quality, stability and liquidity. To make the next step and become an accepted futures benchmark is even harder - only two crudes have achieved that status so far - Brent and WTI. Futures market status means that traders can price a multitude of crudes at either a premium or a discount to the benchmark, and both consumers and producers can hedge their risks. But while the risk from shifts in the price of the futures contract can be hedged, the price premium or discount (the basis risk) to that crude often cannot.
Large swings in the benchmark increase hedging risk and when, as has been the case recently, the basis risk has been larger than the outright shifts in crude oil prices, the viability of the benchmark is called into question. If this is a one-off shift, then the market will quickly shrug it off. But if volatility persists, then volumes may shift to a more stable alternative. More likely, as we have seen in other benchmarks such as Brent and Oman/Dubai, changes to the contract are an option. The market may also see opportunities in the price differential, leading to the construction of more storage capacity or pipelines offering alternative routes out of the Cushing region.
Ultimately, many areas of the industry have a vested interest in maintaining a reliable benchmark and it is unlikely that one bout of volatility will change the status of WTI. But repetitions of such events could spark a search for alternatives.
The Asia-Pacific regional crude market was shaped by sustained demand for grades rich in gasoline and naphtha. This, coupled with shuttered offshore production due to cyclones near Australia, prompted regional benchmark Tapis to rise in comparison to West and North African alternatives. Supplies of Middle Eastern Oman also tightened as Omani refineries returned from maintenance.
Dated Brent's premium to Dubai approximately doubled from mid-March levels to around $4/bbl, again on strong demand for light products. However, given Brent's narrower spreads to similar light sweet grades, this did not significantly curb purchases of Atlantic Basin grades in the region.
Refining margins mostly rose in March on strong product price gains, especially for gasoline. Increases were greatest on the US West Coast, where margins also remain by far the highest, especially for coking operations. The product market there is particularly tight, due to its relative isolation from the rest of the US, its strict product quality specifications and a string of refinery outages limiting supply. In Europe, margins were more mixed, with gains for sophisticated cracking operations and decreases for already-negative hydroskimming margins. Meanwhile, on the Singapore market, gains in margins were less marked, with the exception of Tapis hydrocracking, which gained over $1/bbl.
Data for early April however show a pronounced decline in full cost refining margins in all markets - even on the US West Coast. This appears related to a tightening of crude prices on constrained OPEC supplies and refiner buying ahead of the return from maintenance.
Spot Product Prices
Product prices increased between mid-March and early April, with gasoline clearly leading the pack. US refinery utilisation has not yet picked up much from seasonal maintenance, and with a string of unplanned outages is keeping output low and pulling down stocks. The changeover from winter to summer-grade gasoline, as well as only average-level gasoline imports are adding to the pressure. Specifically, summer-grade RBOB (reformulated gasoline blendstock for oxygenate blending) is more difficult to produce, requiring more alkylate, the price of which has risen steadily since the beginning of the year. While US refineries should ramp up production steadily towards the summer driving season, their restart coincides with Asian refineries undertaking shutdowns for turnarounds during the second quarter.
European product markets were affected by the Fos strike, though in the end this only brought runs down by around 45 kb/d in both March and April (the latter due to a slow ramp-up). While gasoline stocks in Europe fell in February, they remain in line with the five-year average in terms of forward demand cover. Still, with bookings for April to the US so far only at half of March's volume, there remain concerns about the flow of exports sent there this summer. Naphtha crack spreads are declining along their normal seasonal path, but remain significantly stronger in Asia than elsewhere. Petrochemical producers have in many cases switched to alternative feedstocks, i.e. natural gas or condensate, after naphtha prices became too high. One integrated Asian refinery/petrochemical plant even reported it was using its own gasoil as a feedstock. However, while Asian demand remains strong, Indian naphtha exports in April are due to rise to their highest level this year, a 25% increase from March, squeezing out European exports to the region.
Distillate prices in absolute terms have risen as well since mid-March, but are flat in relation to crude. Diesel prices improved in the US and Asia due to agricultural demand, with the US predicting a bumper corn crop this year on the back of an ethanol boom. In Asia, Indonesia was seen importing more distillate due to prolonged refinery maintenance, and also to cope with a tightening of the sulphur limit in diesel to 3,500 ppm from 5,000 ppm. While jet cracks gained in the US due to tighter supply, spreads fell in Asia due to higher South Korean exports and lower Chinese buying. Nevertheless, the arbitrage to the US West Coast was still open, with at least 170,000 tonnes shipped there by South Korean refiners.
Fuel oil prices were mostly flat since our last report, as weak demand balanced lower output due to OPEC cuts and refinery maintenance. In Asia, the high-sulphur fuel oil (HSFO) discount to Dubai narrowed slightly (and remains above its low-sulphur variant), on lower South Korean exports and higher regional demand. Indonesia is also expected to import more fuel oil in April, while Vietnamese purchases for the second quarter are trending above last year.
End-User Product Prices in March
End-user prices increased significantly in all OECD member countries, both in local currency and in US dollars. Gasoline ex-tax prices in US dollars rose by 15.3% in the US, 9.5% on average in Europe, and 2.8% in Japan. Gasoline prices in Canada rose by 23.1%. US dollar diesel prices (ex-tax) increased by 9.1% in the US, 5.3% in Europe, and 1.4% in Japan. Heating oil price rose in all OECD member countries by 4.6% on average, although UK prices jumped by 9.5%. US dollar LSFO prices also rose by 4.1% on average in Europe and Japan, with a 2% decline in German prices being the only exception. (A detailed breakdown of prices by OECD member countries is available in Table 14 in the Tables section of this report's website.)
Million-barrel crude tanker rates in the Mediterranean hit 15-month peaks at the end of March following a strike at Fos, a key European oil import hub in France. Regional vessel availability was reduced sharply as almost 40 tankers were left stranded offshore, unable to discharge their cargo. In the Middle East Gulf, increased vessel demand pushed VLCC rates towards six-month highs in late March, as US refiners sought transportation for crude to arrive ahead of peak summer demand. Clean product tanker rates in the Atlantic rose to the top of five-year ranges in March, supported by strong regional competition for vessels.
On 14 March, port workers at Fos began a strike which lasted 17 days. This left almost 40 tankers stranded, unable to discharge oil into the Marseille refining complex or into pipelines which feed inland refineries and other European countries. The consequent erosion of regional vessel availability pushed cross-Med Suezmax rates up from under $4/tonne to almost $11/tonne on 31 March when the strike finished, a 15-month high. Slim vessel supply also raised West African Suezmax rates from under $10/tonne to nearly $18/tonne over the same period, for trades to the US Gulf. North Sea Suezmax rates were not significantly affected and remained at seasonal norms of $9/tonne for exports to the US Atlantic coast. Aframax rates in the Mediterranean were also boosted substantially by the strike but fell sharply, alongside other regional rates, at the start of April, as the action ended and vessels were offloaded.
Competition for tankers in the Middle East Gulf tightened vessel supply considerably in March, boosting VLCC charter rates. US refiners actively sought transportation to move crude for arrival after the maintenance season, as peak summer demand approaches. Further competition for vessels for late March and first half April loading came from Eastern refiners, notably Korean, despite approaching refinery turnarounds. VLCC rates to Japan rose from around $10/tonne to almost $15/tonne in the first three weeks of March. Corresponding rates to the US Gulf rose from $16/tonne to over $24/tonne during the same period. Middle East Gulf Suezmax rates were also supported in March as thin vessel availability prompted charterers to consider splitting cargoes on to smaller vessels. Tanker movement reports confirmed that, as chartering activity implied, Middle East sailings increased in late March and April. East- and westbound VLCC rates eased at the end of the month as vessel supply increased.
US refinery maintenance reduced demand for short-haul crude imports, causing dirty Aframax rates in the Caribbean to sink from $14/tonne to $10/tonne in March, continuing the downward trend seen in February. Conversely, the need for product imports was one factor which supported clean rates to the US from the Caribbean and North Europe. Charter rates for 33,000-tonne clean vessels on the latter route rose from $24/tonne to $28/tonne in March. Although US gasoline imports were actually no higher than average seasonal levels, Atlantic Basin clean rates were supported by continued competition for European gasoline from West African refiners. East of Suez clean tanker rates were flat or slightly weaker, despite firm Asian naphtha demand. Maintenance at certain Middle East Gulf product export terminals reduced available cargoes.
- OECD throughputs fell by 0.6 mb/d in February, to an estimated 38.5 mb/d, as heavier refinery maintenance in the US and Europe and a spate of unplanned shutdowns reduced crude throughput. Crude runs in the OECD are expected to have fallen further in March to around 38.2 mb/d, but should recover in April to 38.7 mb/d, before dipping again in May as maintenance work in the Pacific reaches its seasonal peak. February crude throughput in Russia and China increased by a combined 0.5 mb/d, to a new record level of 11.3 mb/d.
- Ongoing refinery problems in North America kept regional product markets tight. The disruption caused by Valero's McKee refinery boosted product cracks on the US West and Gulf Coasts, while simultaneously depressing the value of WTI at Cushing, Oklahoma.
- OECD refinery yield data for January point to declining fuel oil production, in line with the latter part of 2006, driven by refiners in the Pacific. Middle distillate yields remain strong as Pacific refiners convert an increasing amount of their crude slate into light products. In the Atlantic Basin gasoline yields remain under pressure, with stronger naphtha yields in the US indicative of the changing balance in the gasoline pool, following the increased use of ethanol.
- Global offline capacity is estimated to have peaked in March at 4.6 mb/d. Current projections suggest that idled capacity will decline towards 3.5 mb/d by June. Delays to refinery restarts in the US and the Fos port strike in France have added to our estimate of first-quarter offline capacity.
OECD refinery runs declined in February as planned work in North America and Europe, plus a spate of unplanned outages, dragged down operating rates. Refinery maintenance increased over January's level in the US and Europe, while voluntary cuts restrained runs in the Pacific. February crude throughput averaged 38.5 mb/d, a drop of 0.6 mb/d compared with January, leaving runs flat compared with February 2006 - broadly in line with last month's expectation. However, the anticipated bounce in runs during March has been deferred to April, following extensions to planned work in the US, and the impact of the port strike in southern France. Runs are expected to dip in March to 38.2 mb/d, before recovering to 38.7 mb/d in April and drop again in May as Pacific maintenance reaches its seasonal peak. Increasing runs in the US and Europe in the second quarter will more than offset the decline in the Pacific as Japan and Korea gear up for peak maintenance.
OECD North America
North American crude throughputs in February fell for the second month running to average 17.6 mb/d, a decline of 0.4 mb/d from January, as maintenance work increased and fires damaged several refineries in the US and Canada to various degrees. US crude runs in February fell as expected, as maintenance work deepened. West Coast crude runs were affected by almost 500 kb/d of capacity taken offline during the month, most notably at Chevron's Richmond and Tesoro's Golden Eagle refineries, but also problems at BP's Carson and Exxon's Torrance operations. The Gulf Coast region saw a higher level of outages than expected, with over 900 kb/d estimated to have been offline. Refineries either in turnaround, or hampered by problems, include Shell's Deer Park, Lyondell's Houston and Valero's McKee. The latter plant suffered a serious fire in mid-February, which tightened product markets in south-western states. This boosted refinery margins on the West and Gulf Coasts, while depressing WTI values at Cushing in Oklahoma, as normal crude trade flows were reversed, as some crude was shipped up to Cushing. The partial restart of the refinery in mid-April will restore crude runs to around 85 kb/d, but full production may not be resumed much before year-end.
Canadian refineries are estimated to have lowered crude runs following disruptions to Imperial Oil and Shell refineries supplying the Ontario market, leading to reports of some supply problems at some retail stations.
Weekly US data indicate that crude runs increased over the course of March, to 14.8 mb/d, driven largely by a recovery in Gulf Coast throughputs. The West Coast turned in a weaker performance, with crude throughputs falling to their lowest level in five years, following the delayed restart of Chevron's Richmond refinery to early April. On the East Coast, the turnaround of Sunoco's 200 kb/d Girard Point refinery also reduced throughputs. Crude runs should increase further over the course of April, reaching 15.2 mb/d and 15.5 mb/d during May, subject to, as always, the level of unplanned outages.
European crude throughputs averaged 13.6 mb/d in February, down slightly from January's downwardly revised (-112 kb/d) level of 13.8 mb/d. Planned maintenance work at Shell's refineries in the UK, the Netherlands and France, and ExxonMobil's Rotterdam refinery all contributed to lower runs. February maintenance was lighter than in February 2006, by around 140 kb/d, largely explaining why runs were correspondingly 120 kb/d higher than a year ago.
Maintenance work at French refineries picked up in March, with Shell's Berre l'Etaing and Reichstett plants closed for maintenance. Furthermore, a port workers strike during the second-half of March cut runs by around 45 kb/d on average over the course of the month. The industrial action affected refiners both in and around Marseille and also those supplied by the SPSE pipeline, which include refineries in southern and eastern France and Switzerland. Crude runs were reduced by around 200 kb/d, or one third of capacity, during the latter stages of the month, due to restricted crude supplies. In addition, by the time the strike was resolved, refiners were preparing for a total shutdown. Consequently, French crude runs in March should have dipped below 1.6 mb/d, as seasonal maintenance reaches a peak and as a result of the port strike.
Anecdotally, spring 2008 could see a heavier European maintenance schedule than in 2007. Europe's biggest refinery operator Total is reported to be lining up a heavy turnaround programme for its French plants. In addition, discussions with industry participants suggest that the German refining industry is also planning a heavy maintenance schedule. However, little concrete detail is available at this point.
February crude throughput in the OECD Pacific region was broadly unchanged, at 7.3 mb/d, for the third month running. The decline of 40 kb/d from January is largely attributable to voluntary run cuts as weak demand for kerosene and poor hydroskimming margins in the region curtailed runs.
Japanese crude runs of 4.1 mb/d in February are estimated to be unchanged from January's level. Voluntary run cuts remained at about 150 kb/d for the second month running before increasing to 175 kb/d in March. Consequently crude runs were 147 kb/d below February 2006's level and capacity utilisation was similarly lower than last year.
Weekly data from the Petroleum Association of Japan suggest that these voluntary run cuts increased in March, as runs eased, due to waning kerosene demand and the start of spring maintenance. April crude runs are expected to drop further as maintenance activity ratchets up to a seasonal peak in May.
Korean runs in February were also largely unchanged, rising 21 kb/d to an average of 2.5 mb/d, despite our estimate that voluntary run cuts rose by around 20 kb/d to 107 kb/d during the month. Voluntary run cuts are estimated to have increased further in March to 128 kb/d, before declining in April with the start of the spring maintenance programme.
OECD Refinery Yields
The trend towards lower fuel oil yields continued in January, driven by a substantial decline in the Pacific, where yields reached new five-year lows. The reduction reflects the progress refiners have made in reducing unprofitable fuel oil production through investment in upgrading capacity and as a response to mild weather. Strong middle distillate production during January was centred on the Pacific, and in particular Korea, which substantially boosted yields at the expense of fuel oil. Notably the trend for weaker kerosene and stronger jet fuel production continued during January in the Pacific.
Atlantic Basin refiners registered lower gasoline yields in January, reflecting the shift in transportation demand to middle distillates. Naphtha yields in the Pacific in January recovered to their highest seasonally adjusted level in five years. During 2006 Pacific refiners registered 10 out of 12 months with naphtha yields at new five-year highs, as increasing demand from newly constructed petrochemical complexes in Asia boosted naphtha cracks.
North American refiners have partly followed this trend, with increased naphtha yields during 2006 and early 2007. Although the absolute change remains small, the switch in North American production possibly reflects the changing pressures on the gasoline blending pool. Following the introduction of ethanol as a replacement for MTBE in spring 2006, refiners may now be looking to remove high volatility blend-stocks such as light naphtha to balance out the higher volatility associated with ethanol blending. The strength in naphtha cracks since the beginning of the year offers the prospect for further gains in naphtha yields, in the Pacific, albeit ultimately at the expense of gasoline production
Crude throughput in Russia and China increased by a total of 0.5 mb/d, to a new record level of 11.3 mb/d in February. Official data for Chinese refinery activity confirm last month's estimate from provisional data that crude runs fell slightly in January, to an average of 6.3 mb/d, before increasing to a new record level of 6.5 mb/d in February. Maintenance work at several of China's largest refineries is thought to have curtailed March throughputs, with several refineries working on upgrading units during the month. February data indicate that Indian crude runs averaged 3.0 mb/d, a slight increase on the previous month. For the second month running, higher crude runs at Reliance's Jamnagar refinery accounted for much of the net increase, with runs reaching an average of 735 kb/d.
Russian crude runs similarly increased to a new (post-Soviet) record of 4.7 mb/d in February, a 4% rise from January's level of 4.5 mb/d. The 40 kb/d rebound at Surgutneftegas's Kirishi facility, which reversed January's decline, was partly responsible, as was the 26 kb/d increase at the Moscow refinery. FSU products exports increased correspondingly in February. March runs will be reduced by the fire at Lukoil's Volgograd refinery which has seriously curtailed operations.
Offline Refinery Capacity
Global offline capacity is currently expected to have peaked in March at 4.6 mb/d and is forecast to decline towards 3.5 mb/d by June. Refinery maintenance in the second quarter will be concentrated in the Asia Pacific region, which in addition to capacity offline in the Middle East will account for almost half the total.
North American and European refiners have confirmed additional planned work over the first half of 2007, raising estimates of offline capacity. Consequently OECD forecasts have been revised up, and now suggest that offline capacity will oscillate between 2.5 mb/d and 3 mb/d over the second quarter, before refiners gear up for the peak Northern Hemisphere driving season. Furthermore, the port strike in southern France has also raised our estimates of offline capacity in the first and second quarters. Further details emerged on planned maintenance in France as a consequence of the strike action in Fos, with several refineries which had previously started unreported maintenance work confirming maintenance plans.
Tighter and Tighter
The European Commission's recent Fuel Quality Directive Review raises the prospect of further rapid tightening of distillate quality requirements in Europe. It comes at a time when anecdotal evidence suggests refinery reliability is deteriorating due to existing sulphur removal requirements, lowering average utilisation rates. Furthermore, continued discussion abounds about transferring marine bunker demand from fuel oil into distillate. However, although refiners have "cried wolf" before about the impact of tighter specifications on refinery operations, progress in catalyst technology is unlikely to again provide them with another easy solution. This raises the prospect of significant investment in hydrotreating, hydrocracking (both of heavy distillate and residue) and hydrogen production capacity and will entail significantly higher emissions of greenhouse gases than current specifications.
The move by the US to limit sulphur in non-road gasoil to 500 ppm from this summer has been well flagged, as has Europe's reduction of sulphur limits for non-road gasoil, to 1,000 ppm starting in January 2008. However, the recent publication of the Fuel Quality Directive Review by the European Commission proposes further significant tightening of quality standards in a relatively short timeframe.
The proposals are essentially that:
- Non road gasoil specifications adopt a 10 ppm sulphur limit by end 2009, one year later than the mandatory tightening of automotive diesel.
- Inland marine diesel would be cut to 300 ppm sulphur by end 2009 and move to 10 ppm in 2011.
- The mandated biofuels content of at least 10% in transportation fuels by 2020 would be facilitated by a new gasoline blend containing up to 10% ethanol. A volatility waiver, (of between 3.65 kilopascals (KPa) and up to 8 KPa above the current maximum of 60 KPa), would be introduced for ethanol blends.
In addition to these proposals Europe's biggest heating oil market, Germany, will introduce 50 ppm heating oil from January 2008. This will further reduce the demand for 2,000 ppm gasoil, adding more pressure on the ultra-low sulphur diesel pool. The changes to gasoil specifications in Europe would effectively increase European desulphurisation requirements by almost 50%.
If the problem were simply a question of sulphur content in the different distillate streams the solution would be sufficient investment in upgrading and hydrotreating capacity. However, atmospheric gasoil, (i.e. from the crude distillation unit) typically has lower sulphur and higher cetane values than gasoil produced from upgrading units. Consequently, to meet current diesel production refiners rely on selective blending of these various distillate streams, in order to meet the specifications.
The inferior quality gasoil, from cokers or catalytic crackers, can have very high sulphur, nitrogen and even metals contamination. Obviously these can be reduced or removed through further processing. Crucially though, some of the sulphur in these cracked gasoils requires very severe (high pressure and temperature) hydro-treating, or possibly hydrocracking. These processes involve significant amounts of hydrogen and energy; neither of which is inexpensive, or without significant GHG emissions. Essentially, the cost of removing the last 50 ppm of sulphur in distillates can be significantly higher than removing the first 50 ppm.
Furthermore, anecdotal evidence points to existing ultra low sulphur specifications causing problems for refinery reliability. Hydro-treating units with expected life cycles (the period between necessary shut-down for catalyst change etc) of two years are being taken out of service after 18 months as they are no longer capable of making on spec product. Similarly, the need to run these units harder to meet the tighter specifications is leading to a higher incidence of unit failures, posing additional problems for refiners
Previously a refiner may have had spare hydro-treating capacity, so that temporary problems with a unit could be accommodated by reprocessing product later. Now a problem with hydro-treating could potentially lead to refineries having to reduce throughputs temporarily since there is no alternative outlet for off-spec product. Similarly, refiners had become quite adept at minimising product supply outages through partial turnarounds, keeping parts of the refinery online while others were offline. However, the growing interdependence, partly driven by the hydrogen balance across the refinery, may force some refiners to revert to "all or nothing" shut downs. Consequently the proposed changes will undoubtedly result in lower sulphur levels in gasoil, but they could have far reaching and possibly unintended consequences in terms of reduced product supply and higher greenhouse gas emissions.