- Oil prices again rose to new records above $105/bbl in early March, supported by strong distillate markets, geopolitical tensions and OPEC's decision to rollover targets until the end of the summer. Persistently weak gasoline and fuel oil cracks are forcing distillate cracks higher to encourage marginal refiners to meet strong European gasoil demand.
- Projected global oil product demand in 2008 is little changed at 87.5 mb/d, with downward pressures from weaker economic growth in the OECD mostly offset by stronger FSU projections. Historical baseline revisions lift 2006 demand, but in 2007 are more than offset by a weaker-than-expected 4Q07 in the OECD and data revisions to several non-OECD countries.
- Global oil supply increased by 185 kb/d in February to 87.5 mb/d with higher January OPEC crude supplies lifting the base. Output recovery in Canada, Mexico and the Caspian republics offset reductions for Norway and OPEC in February. Seasonal limits on OECD production and steady OPEC output may flatten global supply over the next two months.
- OPEC crude supply fell by 120 kb/d to 32.1 mb/d in February. Middle East Gulf and West African output fell 300 kb/d, offset by a 150 kb/d increase in Iraqi supply. Rolling over their existing target and assuming steady Iraqi output would leave output 0.56 mb/d below underlying 1Q08 demand, but 0.96 mb/d above this for 2Q08. OPEC effective spare capacity remains near 2 mb/d.
- OECD industry stocks built by 32.6 mb in January from an upwardly revised December, to reach 2,617 mb or 52.9 days of forward cover. December OECD revisions totalled +29.5 mb, including large upward adjustments to US and Japanese crude and European distillate stocks. Preliminary data show US and Japan stocks fell 23.0 mb in February.
- Global refinery crude throughput remains under downward pressure from poor refining economics, seasonal maintenance and operational problems. Economic run cuts continue to hamper activity in Europe and the Pacific, while year-on-year growth in 1Q08 of 0.7 mb/d is driven by China, the FSU and Asia.
$100/bbl - but what does it tell us?
The rise of oil prices over $100/barrel has been rightly greeted with concern by consumer countries and has been widely cited as a speculative-led event. Headlines referring to a wall of money (prompted by US monetary policy) entering the commodity markets - seeking a safe haven from the weaker dollar and inflation - have pointed to capital flows as one of the causes of recent price rises. So too have OPEC's decision to roll over existing quotas (and not setting a planned meeting until September), surging distillate cracks, and geopolitical tensions in South America, West Africa and the Middle East.
It is fair to say that politicians have greeted most sharp rises in prices over the past eight years as a symptom of speculation. But, in hindsight, have the price moves been irrational? Ali Al Naimi, Saudi Arabian Oil Minister, said last week that oil prices would not go below $60/bbl because that is the cost of alternatives. With current marginal costs and demand trends, he may be right. Short-term prices could dip below this level, but if they did so, then investment in non-OPEC supplies could suffer, creating upward price pressures for the future. Only a protracted and severe global recession would justify a sustained dip in oil prices below these levels.
That does not mean that Gulf producers are not making large profits at current prices: with costs of production in many countries below $10/bbl the profit margin is huge. And lack of access means that traditional economics is turned on its head, with the world developing high-cost but accessible reserves before it fully exploits low-cost oil. But the point is that the price baseline has shifted.
In 2003, moves above $30/barrel were widely cited as speculative and irrational. Now they are seen to reflect the increasing cost of accessing and developing reserves. If it was a speculative push in prices, the speculators were right. Then we have to ask what base is appropriate and how fast it is rising (with continuing service-sector inflation and dollar weakness contributing to ongoing upward pressures). Some academics suggest long-term oil prices should be reflected as a multiple (roughly three to four times) of finding and development costs (F&D). Others would disagree. But we cannot deny that F&D costs have been rising: discussions with industry have put them at $10-$30/bbl, and the EIA in a recent report estimated US offshore costs at $64/bbl.
But is it even correct to use the cost of non-OPEC production as a price base? Oil has rarely traded close to its marginal cost in the past 30 years - arguably in 1986 when OPEC abandoned quotas and in 1998/99 after the Asian currency crisis. So, we are probably looking at a base price somewhere above the marginal cost of production. We are in an era of higher oil prices, and so if we look at $100/bbl oil we have to do so with an understanding that prices are unlikely to return to levels seen in the early part of this decade. But even if cost inflation and a weakening dollar put further upward pressures on the oil price, we have a duty to ensure that the impact of these is not exaggerated. This is especially important in times of economic fragility.
Producers (and some consumers) have an underlying mistrust of the current oil price as an indicator of market fundamentals. Latest data suggest OPEC's rollover should just about redress this winter's stock draws, but the market is concerned that producers are more inclined to react to price declines than price rises. Further, while the latest output decision does not totally ignore price, the decision not to meet until September increases concern that there is no room for stronger demand or delays in non-OPEC production. That by itself provides fertile ground for speculation, as does the lack of timely stock data from many countries. Further, with spare capacity expected to remain tight, part of the price message is surely that higher stocks would provide more comfort.
Producers and consumers clearly need to work together on a number of issues - to better understand current price formation and to improve market transparency. With the current precarious state of the global economy it is imperative that both do everything possible for the right market signals to get through, ensuring that supplies will be there when needed.
- Global oil product demand has been revised down by 80 kb/d to 87.5 mb/d in 2008 (+2.0% or +1.7 mb/d over the previous year), given downward revisions to OECD and non-OECD projections. In 2007, global demand has been adjusted down by 130 kb/d to 85.8 mb/d (+1.1% or +0.9 mb/d over 2006), because of weaker-than-expected 4Q07 OECD data and offsetting, higher 2006 baseline adjustments to several non-OECD countries.
- OECD oil product demand has been lowered by almost 190 kb/d to 49.3 mb/d in 2008 (+0.3%). The changes result from weaker 4Q07 figures, notably in Europe, which were carried through, as well as lower-than-expected preliminary deliveries in January 2008. As such, most of the limited OECD oil demand growth in 2008 is expected to come from transportation fuel use, itself weighed down by weaker economic activity and higher oil prices. The US economy is indeed showing further signs of slowdown, which are weighing down on gasoline demand. In 2007, OECD demand averaged an estimated 49.1 mb/d (-0.5% year-on-year).
- Non-OECD oil product demand has been revised down by roughly 60 kb/d in 2007 and up by about 120 kb/d in 2008. The revisions were related to both 2006 baseline reappraisals of several key countries, including Brazil (-50 kb/d), China (+55 kb/d), Saudi Arabia (+19 kb/d) and Thailand (+31 kb/d), and corrections of previous submissions for Brazil (where data had only been partially released for most of 2007) and Chinese Taipei (where we uncovered an issue with conversion factors that had exaggerated submitted data by about 175 kb/d since March 2007). Overall, non-OECD demand is estimated at 36.7 mb/d in 2007 (+3.2% on an annual basis), and is expected to reach 38.3 mb/d in 2008 (+4.2%), on the back of buoyant demand in both China and the Middle East.
- A higher, retroactive consumption tax on fuel oil and naphtha in China could have unintended consequences. The tax hike, ostensibly aimed at boosting energy savings and curbing the expansion of resource-intensive sectors, may give way to another spell of oil product shortages, as higher costs will further squeeze the profitability of 'teapot' refineries, which effectively act as the country's swing producers and run mostly on fuel oil. In addition, it may encourage inflationary pressures, as manufacturing plants, mills and some power generators that run on off-spec gasoil and/or fuel oil attempt to pass higher fuel prices on to their customers. The government may thus be forced to spend more on subsidies to guarantee adequate oil product supplies and curb inflation.
According to preliminary data, total OECD inland deliveries (oil products supplied by refineries, pipelines and terminals) rose by 1.4% year-on-year in January, with all three regions posting gains. Transportation fuel deliveries, notably of diesel, supported oil product demand in OECD North America (+1.0%, including US Territories). In OECD Pacific, total demand jumped by 2.9% as colder weather conditions boosted jet fuel/kerosene deliveries, together with residual fuel oil and direct crude consumption for power generation. In OECD Europe, demand growth (+1.1%) was largely supported by a rebound of heating oil as temperatures moved closer in line with historical averages.
Given lower-than-expected 4Q07 figures, OECD demand has been revised down in 2007 (-75 kb/d) to 49.1 mb/d (-0.5% year-on-year), compared with last month's report. For 2008, the forecast has also been lowered by 190 kb/d to 49.3 mb/d (+0.3%), mostly due to milder weather conditions in January and the carry-through of weaker 4Q07 demand growth. In the OECD as a whole, oil demand growth is now expected to come almost exclusively from transportation fuel - but growth in this category should be weaker than in the past as a result of slowing economic activity, notably in the US, and higher oil prices.
Preliminary data indicate that oil product demand in North America (including US Territories) rose by 1.0% year-on-year in January, mostly underpinned by strong diesel demand (+11.4% year-on-year) and resilient gasoline deliveries (+0.2%). Diesel demand is growing apace in all three North American countries, although in the case of the US this could be related to reclassification issues (low- versus high-sulphur gasoil). As for gasoline, strong growth in Canada and Mexico offset losses in the US. OECD North America demand averaged 25.54 mb/d in 2007 (+0.9% on a yearly basis) and could decline slightly to 25.45 mb/d in 2008 (-0.4%).
According to adjusted preliminary data, inland deliveries in the continental United States - a proxy of oil product demand - rose by 1.1% year-on-year in January. Overall demand growth was mostly due to higher-than-expected deliveries of distillates (diesel: +12.3% year-on-year) and residual fuel oil (+6.6%). As noted in previous reports, the resilience of diesel demand is partly attributable to the change in sulphur specifications since mid-2006 (whereby low-sulphur non-road, locomotive and marine gasoil is now counted as diesel), which also explains the weakness in high-sulphur, heating oil deliveries (-34.8%) despite slightly colder temperatures. Indeed, in January the number of heating-degree days was 4% higher than the 10-year average (and 5% higher than in the same month of 2007), explaining the rise in residual fuel oil deliveries.
More interestingly, revised figures for December indicate that gasoline deliveries weakened in that month (-0.8% year-on-year, rather than +0.2% as previously estimated). According to unadjusted preliminary weekly data, the trend continued in both January (-0.4%) and February (-0.7%), suggesting that continuing high pump prices and the ongoing economic slowdown are starting to take a toll on gasoline demand. Gasoline demand rose by only 0.7% in 2007, slightly below the average of the previous two years. Although weekly data are likely to be revised, at this point we foresee US gasoline demand marginally declining this year.
According to preliminary data, oil product demand in Mexico declined by 0.2% on a yearly basis in January. Declines in LPG and residual fuel oil demand (-3.6% and -19.0%, respectively) offset strong gains in transportation fuel demand (gasoline deliveries rose by 5.5% year-on-year, jet fuel/kerosene by 9.2% and diesel by 7.2%). Despite growing anxieties regarding the true state of the US economy - Mexico's main export market - oil product demand in Mexico continues to be supported by rising incomes and a, so far, resilient domestic market. Total demand increased by 2.5% in 2007 to slightly above 2.0 mb/d, and is expected to expand by 1.2% in 2008.
According to preliminary inland delivery data, European oil demand grew by 1.1% year-on-year in January to 15.2 mb/d, only slightly below our previous forecast. The headline number, however, masks a more substantial downward adjustment of 260 kb/d if excluding stronger-than-expected German demand. Moreover, final monthly data for December came in more than 0.5 mb/d lower than indicated by preliminary data, notably in Belgium, France, Germany, Greece and the UK. Once again, weak heating oil and residual demand led the changes - other product categories, bar naphtha, were also weaker than expected. As a result, 4Q07 demand has been lowered by 171 kb/d, an adjustment which has to a large extent been carried through to the 2008 forecast. European oil product demand in 2007 is now estimated at 15.3 mb/d (-2.2% versus 2006), about 40 kb/d lower than the previous estimate. Meanwhile, the 2008 forecast has been adjusted down by 130 kb/d to 15.4 mb/d (+0.7%).
Temperatures in January were above the 10-year average, but the weather was not as mild as last year. Indeed, European heating oil deliveries were 8.7% higher than the same month in 2007. German heating oil deliveries were particularly strong (+28.9%). Last year, however, heating oil demand had been penalised by the value-added tax increase introduced in January 2007. The hike also weighed down on German transportation fuel demand, and this year's deliveries of both gasoline and diesel posted strong gains by comparison. Residual fuel oil, by contrast, was weak in Germany and in other main consumer countries, declining by 6.4% in January in Europe as a whole.
As noted, German demand turned out to be about 200 kb/d higher than expected in January. Total oil product demand rose by 11.4% year-on-year, with increases in all products bar fuel oil. Gasoline and diesel, in particular, grew by 7.3% and 19.8%, respectively, year-on-year. This suggests that consumers boosted purchases in December 2006 in anticipation of the value-added tax hike to be implemented in January. By contrast, December 2007 demand for both products fell by 18% and 0.9%, respectively, on a yearly basis. In 2003, when excise taxes were increased, monthly data showed no indication that consumers had shifted their purchases of transportation fuels and heating oil a month ahead. This is probably due to the fact that oil prices at the time were significantly lower. German heating oil deliveries, meanwhile, were up by 28.9% in January, very much in line with expectations. End-user demand, however, might not have been as strong as these figures indicate, since consumer heating oil stock draws were lower than historical norms. Consumer stocks fell to 52% of capacity, 8% less than in January 2007 and 3% less than in December 2007. This decline represents a stock draw of 195 kb/d, compared with a five-year average of about 290 kb/d. As for residual fuel oil, demand fell by 8.7% year-on-year in January.
In January, demand in France was stronger than anticipated, increasing by 1.2% year-on-year. Gains in diesel (+2.3%) and heating oil demand (+3.9%) offset declines in gasoline (-6.6%) and fuel oil deliveries (-5.1%). January was slightly colder than the previous year, but milder than the 10-year average, while February was slightly colder and closer to historical norms. Final December data, by contrast, were weaker than expected. Whereas preliminary data had shown a 7% increase (+3% excluding fuel oil deliveries to major consumers), finalised MOS data point to a 3.5% contraction, with the largest discrepancies in heating oil, LPG (which is also used for heating) and 'other products'.
Italian demand contracted by 2.8% in January, with gasoline and fuel oil posting double-digit declines, only partly offset by gains in middle distillates. Residual fuel oil deliveries contracted despite higher electricity demand (+0.8%), as power generation needs were met by natural gas (total thermal power generation was 3.1% higher than the previous year, and natural gas use rose by 12% year-on-year in December).
Final demand figures for the UK were particularly weak in December (-8.1%), leading to a downward revision of some 120 kb/d. All products bar LPG were revised down; and the adjustments have, to a large extent, been carried through to 2008, lowering the forecast by some 30 kb/d. Preliminary inland delivery data for January was not available at the time of writing (and JODI M-1 data have historically been very unreliable), but our forecast shows continued weakness and total demand falling by 4.1% annually for the month. In 2008, total UK oil product demand is expected to decline by 0.4%, following a 3.6% contraction in 2007. The outlook assumes a partial rebound in naphtha demand (+11.6% over 2007, compared with a 40.7% fall last year) and jet fuel (expected to rebound as logistical problems following the December 2005 Buncefield explosion are solved). Jet fuel demand, which contracted by 2.4% in 2007, should also be boosted by the US/EU 'open-skies' treaty liberalising transatlantic aviation, which comes into force at the end of March, and which is expected to increase the number of transatlantic flights at the expense of short-haul domestic and European flights.
Finally, total demand in Greece was weaker than estimated in December, posting a 4.5% annual decline. Both motor gasoline demand and diesel contracted (by 5.1% and 10.0%, respectively, compared with the same month in 2007). As diesel use is discouraged for personal vehicles (it was actually prohibited in urban areas until last December), the decline in diesel consumption is arguably related to a slowdown in commercial activity. Heating oil demand, meanwhile, should have been boosted by colder-than-normal weather in Greece, Turkey and most of the eastern Mediterranean in both January and February.
According to January preliminary data, oil product demand in the Pacific rose by 2.9% year-on-year. Demand was largely supported by strong Japanese consumption of jet fuel/kerosene for heating and fuel oil and direct crude for power generation. Temperatures were distinctly colder than in December - the number of heating-degree days in January was 3% higher than the 10-year average (and 14% higher than in the same month of the previous year). At 8.3 mb/d in 2007 (-1.6% on a yearly basis) OECD Pacific oil demand is virtually unchanged compared with last month's report. In 2008, demand is expected to reach 8.4 mb/d (+1.9%).
According to preliminary data, oil product demand in Japan - which represents some two-thirds of OECD Pacific's total - rose by 4.9% year-on-year in January. Demand was supported by heating and electricity needs amid somewhat colder-than-normal temperatures, notably in northern Japan (the country's main heating fuel region) and eastern Japan (including the densely populated Tokyo area). Jet fuel/kerosene demand (used as a heating fuel) rose by a modest 0.8% year-on-year (following December's 17.0% decline), while fuel oil and direct crude for power generation (included in 'other products') soared by 31.1%. Both fuels are expected to provide most of 2008's demand growth; in fact, there are reports that Tepco's Kashiwazaki-Kariwa nuclear power plant may remain shut much longer than expected - until March 2009, rather than being restarted in the autumn of 2008. As such, Japan's oil demand should rise this year to 5.1 mb/d (+1.6%), compared with a 3.6% decline in 2007 (to 5.0 mb/d).
In Korea, preliminary data indicate that total oil product demand contracted by 1.1% year-on-year in January. Colder temperatures boosted jet fuel/kerosene demand (+13.8%), but this failed to offset losses in all other product categories bar naphtha (which account for the largest share of total Korean demand). Total demand, which rose slightly to 2.2 mb/d in 2007 (+1.5%), is expected to reach 2.3 mb/d in 2008 (+2.3%), following a 10% temporary reduction of oil product taxes by the new government of President Lee Myung-Bak. The move, effective until December 2008, is intended to soften the inflationary impact of high fuel costs (South Korea imposes several taxes on refined products, including a special tax, a traffic tax, a driving tax, an education tax and a value-added tax). According to some reports, high oil prices have already encouraged interfuel substitution in power generation in favour of relatively cheaper LNG.
Preliminary data indicate that China's apparent demand (refinery output plus net oil product imports, adjusted for fuel oil and direct crude burning and stock changes) rose by an estimated 6.1% year-on-year in January, with all product categories bar LPG, naphtha and residual fuel oil posting significant gains. Demand for gasoline (+11.9%), jet fuel/kerosene (+16.4%) and gasoil (+18.3%) remained very strong. It should be noted, however, that these growth rates are based on partial figures, since at the time of writing refining data for January had not been released.
Assuming that refinery runs were as high in January as in December (6.9 mb/d), these preliminary data estimates would suggest that higher refinery runs and product imports had effectively dealt with the gasoil and gasoline shortages of late 2007. The country, indeed, was preparing for the key Lunar New Year holiday (when millions of migrant workers from the country's southern industrial heartland return home), which normally signals a spike in oil demand - but this year the holiday was severely disrupted by a freezing winter.
Interestingly, even before the weather emergency the domestic supply picture looked tight, with runs by 'teapot' refineries - which act as the country's swing producers - essentially flat. Relative to domestic product prices, residual fuel oil - the teapot feedstock of choice - remained expensive, causing demand to contract, for the sixth month in a row, by 12.5% year-on-year in January. Predictably, given limited domestic output, net gasoil imports filled the gap and remained very high at almost 200 kb/d. Meanwhile, net fuel oil imports, at 200 kb/d, were only about 30 kb/d higher than in the previous month. As for crude, net imports rose by almost 370 kb/d in January (to 3.2 mb/d), as state-owned Sinopec and PetroChina boosted their own refinery runs and provided subsidised crude to the teapots.
Baseline revisions in 2006 (+60 kb/d, implying a rate of growth of 7.8% for that year) have lifted our Chinese forecast. Nonetheless, the prognosis remains largely unchanged in terms of growth rates, with oil demand growing by 4.6% year-on-year in 2007 to 7.5 mb/d and by 5.6% in 2008 to 8.0 mb/d. However, as noted in last month's report, the 2008 forecast may be revised as the extent and magnitude of the widespread power shortages and inclement weather that hit China over the past two months become clear.
New Directions in China's Energy Policy?
Chinese energy policy continues to be torn between market-oriented and administrative measures. Improving the coherence of energy policies and regulations is actually one of the arguments that has long been raised in favour of creating an Energy Ministry, a move that the National Peoples' Congress (which began on 5 March) may consider - although some observers reckon that this seems unlikely at this point given ongoing disagreements among the different agencies that currently deal with energy issues. Indeed, even though policy makers often reiterate the goal of eventually moving towards market-based pricing, administrative directives continue to set the prices of oil products, leading to mounting losses in the country's downstream sector given the widening differences between domestic and international prices. More significantly, the government seems increasingly reluctant to reimburse refiners, even though the country's windfall tax on domestic crude sales is intended precisely for that purpose. Sinopec - the country's largest oil refiner, which received a compensation of roughly $1.4 billion in 2005 and $700 million in 2006 for the losses incurred as a result of Beijing's retail fuel pricing policy - may be reportedly denied an expected payment of at least Rmb 20 billion ($2 billion) for 2007. The reason is probably related to the company's profitability: despite losing about $1.3 billion on domestic sales, Sinopec managed to post Rmb 70 billion ($9.6 billion) in net profits in 2007. Moreover, compensating Sinopec could encourage other state-owned companies - notably in the power sector, where retail prices are also capped - to lobby for cash handouts as well.
Furthermore, even as end-user prices remain capped, the government has opted to raise consumption taxes for some products. On 18 February, it unexpectedly tripled the consumption tax for fuel oil and naphtha, payable by anyone who produces, processes or imports both fuels into China. The tax of fuel oil thus rose to Rmb 101.50/mt (about $14), while that of naphtha went up to Rmb 0.20/litre - retroactively to 1 January. The hikes are ostensibly aimed at boosting energy savings and curbing the expansion of resource-intensive sectors. They may, however, have two unintended consequences: 1) further tighten the oil product market and potentially prompt another spell of product shortages, as higher costs will further squeeze the profitability of 'teapot' refineries, which effectively act as the country's swing producers and run mostly on fuel oil; and 2) encourage unwelcome inflationary pressures, as manufacturing plants, mills and some power generators that run on off-specification gasoil and/or fuel oil attempt to pass higher fuel prices on to their customers. Ultimately, the government may be forced to spend even more in subsidies to guarantee adequate oil product supplies.
Nevertheless, despite having de facto increased the cost of fuel oil, the government has announced other measures that support independent players. In Shandong province, four independent refiners have been allowed for the first time to enter the domestic wholesale oil market, a privilege hitherto reserved for state-owned companies. Presumably the move should make it easier for teapots to import feedstocks - usually straight-run fuel oil from Russia, Singapore and Venezuela. In addition, on 29 February the government asked PetroChina and Sinopec to sell wholesale volumes of gasoline and diesel to independent dealers with a guaranteed profit margin of 5.5-7.0%.
At the same time, there are renewed rumours that the long-debated introduction of a transportation fuel tax will finally be approved during the National Peoples' Congress. The tax, aimed at reining in both consumption and pollution, will reportedly replace the existing road maintenance fee. However, local governments currently receive a large share of the road levy and may be opposed to the move. Moreover, a fuel tax would further exacerbate inflationary pressures - and unless it led to a significant increase in retail prices, would probably do little to limit transportation fuel demand growth. Indeed, introducing a consumer tax while leaving price caps in place is unlikely to change oil demand patterns.
China's Shifting Crude Oil Imports
Since the early 2000s, China's crude oil imports have grown rapidly, by almost 20% per year on average since 2003. In the past five years, China's imports have more than doubled to 3.3 mb/d (+135% over that period, equivalent to an incremental demand of over 2 mb/d).
Although a handful of countries - Saudi Arabia, Angola, Iran, Russia, Oman, Sudan and Congo, ranked in order of importance - continue to account for roughly 70% of total imports, China has attempted to diversify its crude import sources. Various countries in Africa, Latin America, the Middle East and Central Asia are becoming significant suppliers; new sources currently account for almost 10% of the total, compared with less than 2% in 2003.
Nevertheless, in terms of geopolitical significance, Africa and the Middle East are the key regions of Chinese supply, with 33% and 42%, respectively, of crude deliveries in 2007. For example, imports from Sudan (where China has invested heavily and continues to oppose international sanctions over the Darfur crisis) have roughly doubled to over 200 kb/d over the past five years. Meanwhile, Saudi Arabia remains China's largest single supplier, with 16% (530 kb/d) of total imports in 2007. By the same token, some countries that have sought to become key Chinese suppliers - most notably Venezuela - have still some way to go. With only 83 kb/d in 2007, Venezuela's imports only represent 3% of China's needs - and are still well below the 300 kb/d that had been promised by President Chávez, suggesting that Caracas' diversification policy is much less successful than Beijing's.
According to Indian preliminary data, oil product sales - a proxy of demand - rose by 4.4% year-on-year in January. Although the overall growth rate was relatively subdued compared with previous months, demand continues to be supported by transportation fuels, with gasoline, jet fuel/kerosene and gasoil sales rising by 15.6%, 4.3% and 15.9%, respectively. By contrast, both naphtha and fuel oil contracted by 6.5% and 8.1%, respectively, as natural gas made further inroads. Total demand in 2007 is estimated at roughly 2.8 mb/d (+5.5% over 2006). Our forecast for 2008 remains largely unchanged from last month's report, at 2.9 mb/d (+4.2%).
Following months of discussion and rumours, in mid-February the Group of Ministers (GoM) finally decided to raise the retail prices of transportation fuels, which had become considerably lower than international benchmarks. Gasoline prices rose by rise by 4.6% (+2 rupees or $0.05) per litre, while diesel prices increased by 3.3% (+1 rupee). In addition, in late February the government introduced a distinction between unbranded and branded gasoline and gasoil in order to lower the excise duty on the sale of unbranded fuels.
Yet the retail price hike - about half of what had been proposed in January, and excluding household fuels such as LPG and kerosene - is too limited to reduce the losses incurred by state-owned downstream oil companies, which support about 43% of the yearly $18-billion subsidy burden (some observers contend that, in order to be effective, the increase should be around 10-12 rupees per litre for each fuel). Moreover, the price adjustment may still provoke tensions within the governing coalition. Indeed, the Communist Party, worried about the inflationary impact of higher prices upon its main constituency - the country's poor - has repeatedly threatened to bring the government down on this issue (there will be elections in a dozen states this year and national parliamentary polls in 2009).
Further investigation suggests that last month's baseline demand revisions in Chinese Taipei are related to an error regarding conversion factors used to convert Chinese Taipei's submissions to APEC and JODI. 'Other products', as submitted to JODI, had been inflated by excessive additional naphtha demand. In May 2007, Formosa Petrochemical Corporation (FPCC) brought on line a third 1.2-million tonnes/year ethylene plant, which would consume 122 kb/d of naphtha under full capacity; actual demand figures, however, had been distorted by erroneous conversion factors. As such, the 2007 demand series was revised downwards by about 170 kb/d, largely offsetting last month's adjustment. According to official submissions, total oil product demand stood at roughly 1.0 mb/d in 2007 (+3.8% year-on-year), and is expected to grow by 1.2% in 2008, in line with historical patterns.
FSU apparent demand - defined as domestic crude production minus net exports of crude and oil products - has been revised upwards in 1Q08, given adjustments to production and trade data. Apparent demand was stronger than expected, due to weaker exports in both January and February. The region's total oil product demand, estimated at 4.0 mb/d in 2007 (-4.3% year-on-year), is thus expected to rebound to 4.1 mb/d in 2008 (+3.6%).
As anticipated in last month's report, Brazil's National Petroleum Agency (ANP) published the revised series of oil demand data for 2007. Following months of erratic reporting, partial demand figures for 2007 were released last month. In addition, the final data for 2006 have also been updated (-50 kb/d). Nevertheless, the revisions were relatively marginal when compared with last month's report. Total oil demand is now estimated at 2.2 mb/d in 2006 (+1.0% year-on-year) and 2.3 mb/d in 2007 (+5.2%), and is expected to reach 2.4 mb/d in 2008 (+3.0%). In terms of drivers, demand has been pulled by transportation fuels, notably jet fuel/kerosene (+9.1% in 2007) and gasoil (+5.9%), thus reflecting the country's buoyant economic growth. More interestingly, cheaper ethanol has largely supplanted gasoline: 'other products' (which include ethanol) rose by 15.2%, while gasoline demand increased by a paltry 0.8%.
The early-March adoption of Resolution 1803 by the United Nations Security Council (UNSC), which imposes a third set of sanctions on Iran because of its refusal to halt uranium enrichment and clear up outstanding questions regarding previous nuclear work, will likely bring back to the fore the question of the country's dependence on oil product imports. In fact, over the past two months Iran has reportedly been forced to find alternative means of payments and meet its needs by buying on the Singapore spot market, after two French banks (BNP Paribas and Crédit Agricole's investment arm Calyon) stopped issuing letters of credit to Indian refiner Reliance over its Iranian sales. This follows the withdrawal of the Swiss-Dutch trader Vitol, Iran's largest supplier of refined products, on the grounds of low profitability.
The country's attempt to curb runaway domestic gasoline demand - and hence imports - by imposing a rationing scheme has been well documented. By contrast, Iran's soaring gasoil demand has been less tracked, even though it poses significant dependency problems as well. Given low prices, gasoil use has been growing by almost 9% per year on average since 2004 (in 2006, demand jumped by almost 18%), and now accounts for over a third of total demand. More significantly, gasoil imports have reached about 40 kb/d (about 6% of total gasoil demand), partly as a result of the maximisation of gasoline production. Overall, gasoil subsidies have run as high as $1.3 billion (in the fiscal year to March).
The outlook for gasoil consumption is for growth to remain very strong in the absence of any offsetting policy measures (such as rationing or higher end-user prices). On the one hand, underlying demand from the agriculture and industrial sectors is likely to remain quite vigorous. On the other, gasoil use will arguably be supported by Iran's natural gas woes amid a severe winter - demand for gasoil has reportedly surged following Turkmenistan's decision to cut off deliveries of natural gas to northern Iran in January in a dispute over prices.
- Global oil supply increased by 185 kb/d in February to 87.5 mb/d. January's total was revised up 110 kb/d, due to higher OPEC crude supply, while 4Q07 supply was raised by 55 kb/d to 86.5 mb/d on non-OPEC revisions. Output recovery in Canada, Mexico and the Caspian republics, offset reductions for Norway and OPEC in February. Seasonal factors may limit OECD production in March and April, and with OPEC likely opting for caution, global supply is likely to level off over the next two months.
- Non-OPEC production in February averaged 50.4 mb/d, 0.3 mb/d above January, as the Americas and FSU recovered from disrupted January supply. Forecast 1Q production is cut by 90 kb/d on revisions for Mexico, India, Malaysia and Brazil. Annual 2008 non-OPEC production is trimmed by 50 kb/d, with stronger late-year USA and Canada output partly offsetting now lower supplies from Asia and Latin America. Non-OPEC 2007 supply is nudged up to 49.7 mb/d, with the 2008 total now at 50.6 mb/d.
- Expected non-OPEC supply growth in 2008 is 910 kb/d, after a 2007 increment of 540 kb/d (netting out the impact of Angola and Ecuador's move into OPEC). Growth is weighted towards the second half of 2008, unlike 2007 when the first six months saw growth averaging 0.9 mb/d before subsequently slowing. Growth in 2008 is split between the FSU, Asia, Latin America, biofuels and Africa. On top of the non-OPEC totals, OPEC NGL supplies reach 5.2 mb/d in 2008, a rise of 375 kb/d from 2007.
- Assumed net decline for non-OPEC production in our forecasts remains unchanged at some 4-5% pa. However, decline rates for mature non-OPEC fields have averaged 7.7% pa this decade, net of the inflationary impact of unscheduled field outages. Decline does not seem to have accelerated markedly since 1999, but does vary widely according to depletion, geology, location, extraction rate and reservoir management. Some mature offshore OECD assets face average decline rates closer to 15%.
- OPEC crude supply in February averaged 32.1 mb/d, down by 120 kb/d from upward-revised January levels. Amid seasonal adjustments and field outages, Middle East Gulf and West African producers together supplied 0.3 mb/d less crude in February. This was offset in part by a 150 kb/d increase from Iraq, where output reached 2.4 mb/d. Producers chose to roll-over the existing 29.67 mb/d production target at their 5 March meeting, and OPEC effective spare capacity remains near 2 mb/d.
- The call on OPEC crude and stock change (including Angola and Ecuador) averages 32.8 mb/d for 1Q08, but then dips seasonally and averages 31.9 mb/d for 2008 as a whole. Downward revisions for the call arising from weaker 4Q07 demand are offset by lower non-OPEC supply through 2008.
All world oil supply figures for February discussed in this report are IEA estimates. Estimates for OPEC countries, Alaska, Russia and Vietnam are supported by preliminary February supply data.
Note: Random events present downside risk to the non-OPEC production forecast contained in this report. These events can include accidents, unplanned or unannounced maintenance, technical problems, labour strikes, political unrest, guerrilla activity, wars and weather-related supply losses. Specific allowance has been made in the forecast for scheduled maintenance in all regions and for typical seasonal supply outages (including hurricane-related stoppages) in North America. In addition, from July 2007, a nationally allocated (but not field-specific) reliability adjustment has also been applied for the non-OPEC forecast to reflect a historical tendency for unexpected events to reduce actual supply compared with the initial forecast. This totals ?410 kb/d for non-OPEC as a whole, with downward adjustments focused in the OECD.
OPEC crude supply in February averaged 32.1 mb/d, a reduction of 120 kb/d from upward-revised January levels. Estimates for January supply from Iran and Qatar were revised up by a collective 220 kb/d after indications of higher exports and domestic crude runs for Iran, and a lower-than-expected impact from offshore field maintenance for Qatar. In February, field outages and pre-OPEC meeting manoeuvring likely underpinned a 0.3 mb/d reduction from West African and Mid East Gulf producers. Nigeria saw renewed field outages in early February in the troubled Niger Delta area, with shut-ins temporarily breaching 0.7 mb/d at one point in February. However, Iraqi supply increased by 150 kb/d, and output reached 2.4 mb/d following higher northern exports and recovering refinery runs.
OPEC producers chose to roll-over the existing 29.67 mb/d output target at their 5 March meeting, citing their view of a well-supplied market and high prices deriving more from a weak dollar, inflationary pressures and fund flows into the commodity markets than fundamental factors. In the end, arguments about seasonally weakening demand and downside economic risks carried the day in the face of appeals from consumer governments for positive action to help rebuild stocks amid record high prices. The group's next ordinary meeting is scheduled for 9 September in Vienna, although post-meeting comments suggested that the option to convene an extraordinary meeting in the interim remains open.
Total February production from the twelve members bound by quotas came in close to the collective target and indeed for the past three months individual producers have generally been producing within a couple of percentage points of the targets briefly published on the OPEC website last November. The only exceptions have been Nigeria and Angola, both producing more than 5% below target, with security-related and technical outages respectively having underpinned this 'shortfall'. Moreover it has been compensated for by above-target output from Algeria, Libya, Saudi Arabia, Kuwait and Iran. From the producers' own viewpoint, the new targets seem to bear closer relationship to output capability than did previous, largely discarded individual quotas.
Breaking the Spare Capacity Logjam
Effective OPEC spare capacity stands at 2.2 mb/d (net of Indonesia, Iraq, Nigeria and Venezuela - deemed likely to struggle to increase production in the short term). Saudi Arabia and the UAE hold 2.0 mb/d of this total. Recent pipeline outages and border tensions affecting Ecuador and Colombia, weather-related disruptions in the North Sea and Australia and the ongoing susceptibility of Nigerian and Iraqi facilities to insurgent attacks illustrate market vulnerability and suggest that a more comfortable supply cushion is desirable. Delays in completing projects such as Saudi Arabia's 500 kb/d Khursaniyah, while understandable in the currently stretched market for equipment and engineering, nonetheless highlight the minimal spare capacity that has persisted for the past five years.
By accident or design, a trend towards 'just-in-time' capacity development is following on the heels of a previous move towards 'just-in-time' inventory (arguably, the two now coexist, helping explain the strength in prices, though conversely, if tight spare capacity is seen persisting, consumers may actually revert to holding higher stocks again to compensate). Bottlenecks in labour, raw materials, fabrication, drilling and service capacity contribute to slower capacity growth. So too may producer reticence about expanding capacity ahead of uncertain future demand growth in a high price/weaker economy environment. Some OPEC members are also struggling to sustain existing capacity, for security reasons or in the face of reservoir maturity. Finally, high prices are encouraging producers (not just in OPEC) to strike a harder bargain with IOCs over access, contract terms and fiscal take, undermining marginal investments.
Breaking this investment logjam may require greater clarity and consensus between producers and consumers on demand levels for the future. This report has pointed out for some time that, in our view, demand growth can remain robust even in the face of high prices and OECD economic slowdown. This is not least because the main centres of growth in the developing Asian and Middle Eastern economies are largely insulated from some of the pricing pressures affecting other markets.
Secondly however, the traditional relationship between NOCs and the international companies likely needs to evolve to reflect new industrial realities. Many IOCs already accept the inevitability of contract renegotiation, not only in the face of higher prices, but also as hitherto high-risk, prospective exploration plays become better established as producing areas. However, as regions mature further into late life, this too will require flexibility from OPEC governments and NOCs to sustain investment and maximise recovery from marginal assets. Enjoying a greater share of revenues from producing fields at a time of high prices is one thing. But sustaining, let alone increasing, capacity in future may require more innovative investment models. Iran and Kuwait spring to mind in this regard, but also perhaps Libya and Algeria, where an initial opening up now looks to have been replaced by more caution. And all eyes are on Iraq to see the eventual shape of the investment regime there and its success or otherwise in rehabilitating production in one of the world's pre-eminent resource holders.
Some producers will need to call on newer technologies to sustain recovery from depleting assets, something the international service companies may be ideally placed to provide. Others may see future oil development prospects lying in more remote or complex formations, often involving large, integrated oil/gas and upstream/downstream facilities. Contract flexibility needs to be a two way street if the integrated operation and project management skills of the IOCs are to be called upon again. Ensuring that hydrocarbon development leads to widespread, maximised local benefits, while at the same time sustaining an attractive climate for long-term foreign investment is a challenge for all host governments.
The main movers of February OPEC supply appeared to be Iraq (+150 kb/d versus January), offset by Iran (-120 kb/d), Nigeria (-50 kb/d) and Saudi Arabia (-50 kb/d). Iran's reduction came after January supply estimates were revised up from 3.93 mb/d to 4.05 mb/d. Both export and domestic refinery runs are now adjudged higher, the latter due to refinery maintenance work reportedly slipping into February. Thus, amid signs of Middle East Gulf tanker sailings falling back in February, and with weaker local crude throughput, Iranian supply is assessed to have fallen below 4.0 mb/d once again. This is despite the start-up, as noted in last month's report, of an initial 25 kb/d of new production from the Azadegan field.
As noted above, Nigerian supply was adversely affected by shut-ins affecting Bonny, Forcados and Brass River crude, sending outages to around 700 kb/d at one stage. In all, output is assessed to have slipped from 2.06 mb/d in January to 2.01 mb/d in February. However, some of this disrupted output has now restarted, with current outages assessed at below 0.5 mb/d once again. Specifically, repairs on the Nembe Creek pipeline allowed reinstatement of 130 kb/d of Bonny crude, while earlier pipeline attacks or malfunctions affecting up to 250 kb/d of Forcados and Brass River production were also resolved around mid-month. On 3 March Shell announced that earlier force majeure on Bonny and Forcados exports had been lifted. Resumed crude supplies have also enabled progress in reopening the idled Warri refinery (reactivated in February) and the Kaduna plant which is scheduled back onstream in March.
However, Nigerian supply may remain constrained in March, with maintenance at the deepwater Bonga field likely to remove around 100 kb/d of monthly supply. There have also been reports that recent technical issues have shuttered volumes of Qua Iboe production.
Middle East Gulf tanker sailings data also imply a modest downturn in Saudi Arabian crude supply, here assessed to have slipped from 9.15 mb/d in January to 9.1 mb/d in February. Some uncertainty surrounds comments from state-producer Aramco about start-up at the Khursaniyah project. The three constituent fields - Abu Hadriyah, Fadhili and Khursaniyah - were due to begin contributing up to 500 kb/d of Arab Light crude from late 2007. However, delays with the Khursaniyah gas-oil separation plant (GOSP) have pushed start-up into 2008. There were reports in February that attainment of plateau volumes from Khursaniyah have slipped into April. While our existing capacity estimates envisage 1Q08 start-up, we were already assuming full 500 kb/d output was more likely to occur in 2Q08, although Aramco has suggested that build-up in production will be rapid.
Net Iraqi supply (excluding movements of crude into storage or reinjection) rose by 150 kb/d to 2.37 mb/d in February. Partial recovery in domestic refinery runs after widespread outages affecting the Baiji, Daura
and Basrah plants in January allowed crude throughput to rise to an estimated 375 kb/d from 280 kb/d the month before. This remains however less than 50% of total Iraqi nameplate refining capacity. Total exports rose from 1.94 mb/d to 1.99 mb/d, comprising 1.57 mb/d from southern ports (unchanged from January), 10 kb/d cross-border to Syria and an estimated 410 kb/d lifted from the Turkish port of Ceyhan, a rise of 55 kb/d from January levels. Exports on the northern route have been unaffected by military engagements between Turkish troops and Kurdish PKK insurgents in the Turkey-Iraq border region.
The oil ministry has received cabinet approval to enter technical support agreements with western companies aimed at boosting production capacity by 500 kb/d at a number of fields (see page 22 of report dated 13 February 2008). However financial and contractual negotiations are seen taking until perhaps mid-2008 to conclude.
Venezuelan crude supply is estimated unchanged in February at 2.44 mb/d, despite maintenance at the Petrocedeno (formerly Sincor) heavy oil upgrader, on assumption that sales of unupgraded heavy crude have continued. The communiqué released after the OPEC conference in Vienna expressed support for Venezuela in its ongoing legal dispute with ExxonMobil, effectively condemning moves to freeze PDVSA assets overseas. Venezuelan oil minister Rafael Ramirez announced that, following ExxonMobil's rejection of 80 kb/d shipments of Cerro Negro crude for the two parties' joint venture Chalmette refinery, this crude is being diverted to China, reportedly taking total Chinese imports of Venezuelan crude to 250 kb/d.
Ecuadorean production was also assessed largely unchanged in February at 500 kb/d, despite a brief outage of the SOTE pipeline caused by a landslide. Analysts have played down the likely oil supply impact of increased tensions in the Venezuela-Ecuador-Colombia border area, following the strike by Colombian government troops against FARC rebels inside Ecuadorean territory. Both Venezuela and Ecuador condemned the attack and at one point moved troops closer to the border with Colombia.
Non-OPEC production in February averaged 50.4 mb/d, 0.3 mb/d above January as the Americas and FSU recovered from disrupted January supply. Forecast 1Q production is cut by 90 kb/d on downward revisions for Mexico, India, Malaysia and Brazil. Seasonal factors are likely to kick in from March onwards, potentially capping non-OPEC production at around 50.3 mb/d until June. Robust growth is expected to resume in 4Q08, when non-OPEC production jumps to 51.4 mb/d from 50.4 mb/d in 3Q.
Annual 2008 non-OPEC production is trimmed by 50 kb/d, with stronger late-year USA and Canada output partly offsetting now-lower supplies from Asia and Latin America. Non-OPEC 2007 supply is nudged up to 49.7 mb/d, with the 2008 total now at 50.6 mb/d. Expected non-OPEC supply growth in 2008 is therefore 910 kb/d, after a 2007 increment of 540 kb/d (netting out the impact of Angola and Ecuador's move into OPEC). As noted above, growth is heavily weighted towards the second half of 2008, unlike 2007 when the first six months saw growth averaging 0.9 mb/d, before subsequently slowing. Growth in 2008 is split between the FSU, Asia, Latin America, biofuels and Africa, with Europe, North America and non-OPEC Middle East regions seeing continued decline. In addition to the non-OPEC totals, OPEC gas liquids and condensate supplies (traditionally counted as de facto non-OPEC supply)
reach 5.2 mb/d in 2008, a rise of 375 kb/d from 2007.
While we retain a forecast of 4-5% pa for baseload decline applied to all existing non-OPEC production, the mature portion of that output looks to be declining at closer to 7.7% pa once the impact of unscheduled weather, technical and geopolitical outages is netted out. Decline does not appear to have accelerated markedly since 1999. Nonetheless, declines rates vary widely according to reservoir depletion, geology, location, extraction rate and reservoir management practices. As might be expected, mature offshore OECD fields are facing the steepest annual decline rates, at around 15%.
US - Alaska February actual, others estimated: Total US oil production is estimated some 50 kb/d lower in February than in January, at 7.4 mb/d (of which some 5.0 mb/d is crude oil). Preliminary data for December however came in around 50 kb/d higher than our earlier estimates, largely on the strength of higher NGL and ethanol production levels. Physical supply for both components has been running ahead of expectation, despite the apparent economic disincentives accruing from high natural gas and grain prices respectively. After several months of upward revisions to baseline data, a combined 30 kb/d upward adjustment for these two components has now been carried through the 2008 US forecast.
Non-OPEC Decline Rates - Stripping Out the 'Noise'
Non-OPEC supply has consistently lagged analyst expectations since 2004. Some assign this to accelerating decline rates, with a conclusion that it will preclude material future growth in supply. Our analysis suggests that, while sizeable volumes of non-OPEC crude and condensate have to be replaced due to depletion, averaging nearly 2 mb/d per annum (pa) so far this decade, raw year-on-year production data have to be treated with caution. This data can exaggerate decline due to resource depletion, by masking temporary or systematic reductions in output from other causes. These can include weather-related outages, strikes and security-related disruptions, lower investment and mechanical break-downs. Since our forecast methodology specifically includes adjustments to supply to account for field 'reliability', our projected decline rate has to be based on 'clean' historical data net of these factors.
This periodic review of non-OPEC oil field decline rates* focuses on mature crude oil and condensate fields (not NGL and non-conventional oil) showing sustained, yearly output decline over periods of at least 12-18 months. Aggregate decline rates are production weighted, and reflect managed, rather than natural, decline, according to prevailing investment levels. The results from 1999-2007 production data suggest aggregate non-OPEC decline of 7.7% pa, and that this has not accelerated markedly in the period under review (notwithstanding, boosting recovery over the short term can imply faster longer term decline).
We have previously discussed 4-5% as an appropriate forecast net decline for all current base load non-OPEC production, encompassing fields in decline and those at, or building to, plateau. This has not changed in light of our recent assessment, since the distinct, 7.7% level applies only to the mature portion of production that is in sustained decline. Moreover, the latest analysis generally accords with the decline rates previously assumed in OMR projections, resulting in only modest, and largely offsetting, alterations in the forecast decline rate. Deviation in non-OPEC outcome versus forecast in 2008 thus seems unlikely to derive primarily from decline rates, unless observed rates shift markedly this year. Put another way, we believe that sluggish non-OPEC performance is being driven by other, largely above-ground constraints, not solely by resource depletion, important though this is for the longer term.
Building from disaggregated data, we have calculated adjusted decline rates for regional and non-OPEC totals, which net out the impact of non-geological factors. Not surprisingly, decline rates vary significantly geographically and over time. However, a surge in 'raw' decline rates in 2005 and 2006 to levels at or above 10% needs to be seen in the context of the distortions from Hurricanes Katrina and Rita, extended North Sea field shut-ins, asset divestments in Russia etc. Once these factors are excluded, 'real' decline comes in closer to the decade average. We would not claim to have captured all above-ground related field outages, nor to have sufficient field-specific production data to make a definitive judgement on decline rates themselves. But for this nine year snapshot at least, oscillation around a 7.7% pa mean is more representative than widely perceived acceleration.
The mature producing areas of the OECD tend to show the sharpest decline. Depleted assets in the North Sea, Australia and offshore US all exhibit typical decline of at least 15% pa (as indeed do parts of Mexico's offshore production, included here alongside non-OECD Latin America). Newer fields in these areas - often deepwater, smaller accumulations of oil - are also prone to rapid build to plateau, followed quickly by sharp decline. Deepwater development planning and well configurations differ markedly from onshore fields, aiming to rapidly recoup high up-front expenditures.
One proviso is worth noting however, both for these and for other areas. Detailed data for 2004-2007 field outages are more extensive than for 1999-2003. This raises the possibility that:
- adjusted 1999-2003 decline would be shallower than shown above, and as a consequence, average decline for the entire period in reality is below our headline 7.7% pa level;
- consequently, some acceleration in decline rates did occur in the later years under study.
Notwithstanding this uncertainty due to variable data quality, and while some individual fields undoubtedly show signs of decline accelerating over time, there is no compelling evidence that aggregate decline is picking up speed, after non-geological factors have been accounted for.
Elsewhere in the OECD, decline from onshore US and Canadian production (excluding the Alberta mining and upgrading projects) looks fairly stable at around 5% per annum, close to the industry rule-of-thumb for onshore production. Indeed, the surprisingly static overall profile of decline in OECD basins may actually suggest the beginnings of a price response on the supply side. Renewed drilling and enhanced oil recovery (EOR) may, at the margin, be starting to help offset natural decline, although it is dangerous to be too definitive about this. Indeed there is some evidence that engineering shortages are restricting EOR effort by the IOCs at smaller assets. Nonetheless, EOR projects can be lower profile than new green field developments, and can slip below analysts' radar, being the (albeit more cost-intensive) upstream equivalent of refinery capacity creep.
Regional aggregate decline rates for the non-OECD (plus OECD Mexico) vary from 2.5% per annum for the FSU and 4% pa for China and Latin America to 6-7.5% pa for Asia, the Middle East and Africa. The preponderance of Russian onshore production in the FSU total, and an early-decade surge in Russian brown field spending, helps explain low aggregate FSU levels. However, the mix of company and field-specific production data obscures the FSU picture. Latin American decline rates are surprisingly shallow, despite the inclusion of Mexican production. However, Mexico's ageing Cantarell field only entered sustained decline in 2005, having earlier seen production sustained by the application of a nitrogen injection programme. We have for some time assumed that Cantarell decline attains steeper levels around 15% for 2008 and beyond. Decline from Brazil's deepwater Campos Basin fields is also, so far, limited, playing a minor role compared with prevailing shallower onshore declines in determining the regional average. Our longer-term forecasts assume that the pace of deepwater decline accelerates, gaining rising importance for national/regional averages.
On a trend basis, China, other Asia and the Middle East have seen mature field decline accelerate this decade. The ageing onshore Daqing and Shengli fields, plus maturing early-phase offshore developments, have seen Chinese declines gathering pace. The rising proportion of offshore production in Asia and the problems in sustaining output from older, more complex Middle Eastern carbonate reservoirs may underpin the accelerating trend for the other two regions.
- An extensive study of the impact of decline rates on longer-term oil and gas supply will also be included in the World Energy Outlook (WEO) for release in November 2008
The US crude production forecast is largely unchanged for 2008, at 4.97 mb/d, compared with 5.1 mb/d for 2007. Output levels for 4Q07 from the Gulf of Mexico (GOM) have been trimmed by 45 kb/d to 1.3 mb/d. However, the GOM is likely to prove one of the few bright spots for US crude in 2008, expected to gain a net 70 kb/d to 1.41 mb/d for the year as a whole. Chevron announced in February that its 45 kb/d capacity Blind Faith platform is being towed into position for 2Q08 start-up. BHP's Neptune project is another April start-up, although otherwise new GOM start-ups are weighted towards the end of the year, when Typhoon, Mirage
and Thunder Horse are expected online.
Alaskan production again disappointed in February, with crude output of 720 kb/d some 35 kb/d below expectation. This report sees Alaskan output decline continuing, averaging 685 kb/d for 2008 from 725 kb/d in 2007. However, longer-term prospects may improve after numerous announcements from major companies recently. Shell is hopeful of new discoveries in the remote and challenging Beaufort and Chukchi Sea areas. BP will seek financial sanction in April for the Liberty project, from which 40 kb/d is expected from early 2011. Meanwhile ExxonMobil has submitted a revised development plan for the Point Thomson gas and condensate field, now involving 10 kb/d of liquids output (down from an original 70 kb/d) and gas reinjection. The high pressure nature of the reservoir makes reinjection difficult.
Canada - December actual: After two years of 100 kb/d-plus output growth, Canadian production growth in 2008 is seen slowing to 30 kb/d, as total oil output reaches 3.35 mb/d. In fact, over 100 kb/d of growth is expected from bitumen and synthetic crude production capacity in 2008, but this is partly offset by conventional oilfield decline and by a field reliability adjustment that nets around 80 kb/d off the 2008 total. That said, we have revised forecast Albertan conventional output up by 25 kb/d for 2008, after several months of higher-than-expected output.
Mexico - January actual: Alongside Brazil, the Mexican 2008 forecast sees the biggest adjustment this month at around -50 kb/d. Weaker than expected January Cantarell field performance was partly offset once more by higher-than-expected output from Ku-Maloob-Zaap. February output from the southern onshore fields has also been adjusted downwards to account for blockades reportedly called by former presidential candidate Lopez Obrador. State oil company Pemex reported in February that it will spend $16.6 billion on the upstream in 2008. The company has reiterated plans to hold output close to 3.1 mb/d through 2010. This report takes a more cautious view, projecting crude output of 2.97 mb/d for 2008, while NGL output is held steady at some 400 kb/d.
Norway - December actual, January provisional: Baseline 2007 data for Norway remains largely unchanged with total 2007 oil output at 2.56 mb/d. Near-200 kb/d declines seen in the past three years are expected to be repeated in 2008, as liquids output slips to 2.36 mb/d, with crude (net of condensate) at 1.8 mb/d and total gas liquids at some 550 kb/d. Loading schedules suggest weaker February production, but, conversely, upward adjustment for March supply. The Volve field came onstream as anticipated in February, although we have trimmed the expected ramp-up in supplies on reports that plateau 50 kb/d will not be attained until 1Q09. Unscheduled outages affected the Nord, Ekofisk, Eldfisk, Aasgard and Kristin fields in February, while Sleipner production has been hampered in March. The impact on our forecast was minimised by the existing field reliability adjustment applied for all forecast months.
UK - December actual: UK offshore production looks to have remained fairly steady at around 1.4 mb/d during the November-February period. However, production is seen declining sharply by as much as 25% in the period through August as seasonal maintenance takes effect. Industry association Oil & Gas UK envisages total oil production averaging a stable 1.6 mb/d during 2008, including some 250 kb/d of NGL and onshore crude production. Our forecast is weaker at 1.48 mb/d but includes a 160 kb/d field reliability adjustment, without which the two forecasts would be broadly similar.
Minor adjustments this month to UK output make little change to overall production levels. A February gas processing unit outage at the Elgin/Franklin fields reduced condensate supply but was resolved within days. Market reports on progress at the Ettrick field development have caused us to push back start-up from April to August, while we have also trimmed plateau output for 2008 to 20 kb/d from an earlier-assumed 30 kb/d. New entries in our field-specific database include Duart and Saxon, although again this has no impact on forecast supply as we were previously including these developments as tie-backs to the existing Tartan and Guillemot fields.
Australia - December actual: Australian crude production came in some 100 kb/d lower than earlier estimates, with unscheduled outages in the Carnarvon Basin proving more pervasive than initial information had suggested. Field outages also affected February output, with precautionary outages during the passage of Cyclone Nicholas. A prevailing -35 kb/d cyclone adjustment in our February forecast has subsequently been revised to -50 kb/d. Forecast Bonaparte basin production has been cut by 15 kb/d compared with last month, with water encroachment affecting the recently started Puffin field. AED Oil Ltd, which was operator of the Puffin and Talbot fields, has just announced the sale of a 60% stake in the two fields to China's Sinopec. Despite recently disappointing performance, Australian crude production is nevertheless expected to increase by some 80 kb/d in 2008 to 535 kb/d, largely on the strength of production build-up from the 80 kb/d Stybarrow field.
Former Soviet Union (FSU)
Russia - January actual, February provisional: Russian total oil output has begun 2008 at a fairly stable 10.0 mb/d (including 9.52 mb/d of crude), marginally below both 4Q07 and levels of a year ago. We have trimmed the Russian 2008 forecast this month by a net 25 kb/d on the basis of latest reported plans from the country's largest producer, Rosneft, and also lower baseline January and February supply from Lukoil and Surgutneftegaz. A partially offsetting 10 kb/d upward adjustment is however applied to NGL supply, after reports of higher Gazprom expenditures on gas processing in 2008. Total Russian production growth for 2008 is now seen at 90 kb/d (+0.9%), less than half the 2007 level. Moreover, analysts see growth remaining constrained going forward unless incoming president Dmitry Medvedev pursues earlier statements about the need for fiscal reform.
Rosneft shows the largest year-on-year production increment in our forecast, although the company may struggle to exceed recent 2.27 mb/d levels in the absence of further acquisitions. A late-year increment of 50 kb/d is also expected with the start-up of year-round production at the Sakhalin 2 project (which presently only produces for six months of the year). We have previously reported on the weaker expectations for 2008 supply from the neighbouring Sakhalin 1 project, where production was supposed to fall towards 170 kb/d from last year's 225 kb/d after permission to drill new wells was refused by the Russian authorities. January/February output data actually show Sakhalin 1 still producing in excess of 200 kb/d, raising the possibility that output may be sustained at higher levels. However, for now we retain the lower planned levels in our forecast.
Net oil exports from the FSU averaged 8.69 mb/d in January, according to preliminary data. This was 190 kb/d lower than December's average but 300 kb/d higher than the previous January (due to the 2007 rise in BTC volumes plus higher product exports). January crude exports were down 250 kb/d on the month, with a notable 130 kb/d drop in Black Sea exports as poor weather impeded loadings. Baltic crude exports fell by 80 kb/d in January with fewer of the new, enlarged 135,000-tonne cargoes loading from Primorsk than expected. Far East crude loadings also fell by 40 kb/d. January FSU product exports were almost flat on December. Severe weather reportedly disrupted Black Sea product exports but higher gasoil and gasoline volumes left northern terminals.
An increase in Russian export duties is set to reduce February exports significantly. Transneft crude oil schedules suggest that both Black Sea and Baltic loadings will be lower, with planned pipeline maintenance an added constraint to exports from Primorsk. A pricing dispute also interrupted crude flows from Russia to Germany through the Druzhba pipeline in February.
Elsewhere in the non-OPEC fold, a 20 kb/d upward revision is applied for 4Q07 through end-2008 for Turkmenistan. This follows stronger than expected 3Q07 output data. Total liquids production in 2008 is seen rising by 20 kb/d to 220 kb/d, broadly in line both with government plans and attainment evident for January-October 2007.
Brazilian crude production rises by 225 kb/d in 2008 to 1.97 mb/d, growth having slowed markedly in 2007 due to unplanned field outages and delays in bringing new projects onstream. This month's 2008 forecast has been trimmed by 55 kb/d, largely with a downward revision for the Espadarte field, where enhanced recovery has reportedly achieved less than originally planned. The Brazilian adjustment is partially offset by a 35 kb/d upward revision for Colombia, where data through end-2007 shows sharply higher-than-expected output from foreign operated projects. National oil production attained 560 kb/d in 4Q07 and is seen averaging 580 kb/d in 2008. February Colombia supply was affected by a bomb attack on the 60 kb/d Trans Andes pipeline, although government sources expected this to take days, rather than weeks to repair.
Lower baseline production from India and Malaysia results in forecast 2008 supply from each being cut by 10-15 kb/d. Trends in 2008 production from the two Asian nations diverge, with Indian output expected to slip by 15 kb/d to 800 kb/d. Malaysia on the other hand sees oil output break through the 800 kb/d mark, as the Kikeh field builds towards plateau 100 kb/d output by late 2008.
- OECD industry stocks built by 32.6 mb in January from an upwardly revised December, to reach 2,617 mb. OECD crude inventories rose by 23.7 mb in January, led by a 14.3 mb build in the US alongside increases of 3-4 mb in Mexico, Japan and Korea. OECD product stocks rose by 5.6 mb in January. A 16.7 mb increase in US gasoline inventories almost offset the country's seasonal decline in 'other products' (of which propane for heating accounts for a significant proportion) while smaller builds were seen in European and Pacific distillates.
- The December total for OECD industry stocks was revised up by 29.5 mb. Japanese and US crude stocks were adjusted upwards by 10.8 mb and 5.6 mb respectively. Upward revisions of 9.9 mb to distillate stocks were seen in OECD Europe (spread across several countries), while December gasoline inventories were also 3.5 mb higher than previously reported in the US.
- Preliminary February stocks data for US and Japan suggest a combined draw of 23.0 mb, including drops of 9.5 mb and 8.0 mb in US distillates and Japanese kerosene respectively. This would leave OECD total stocks cover little changed from the 52.9 days at end-January and the revised figure of 51.7 for end-December, but of course this is highly preliminary and excludes European and other OECD countries. End-January total OECD oil stocks stand at or above the newly calibrated (2003-07) five-year averages in all regions, although this masks specific areas of particularly low cover, such as European distillates and Pacific gasoline.
OECD Inventory Position at End-January and Revisions to Preliminary Data
A 32.6 mb build in January OECD stocks on top of an upward revision of 29.5 mb to December levels left regional OECD total oil inventories almost uniformly in excess of seasonal norms. End-January OECD oil stocks at 2,617 mb were well above the newly calibrated (2003-07) five-year absolute average of 2,570 mb. In terms of forward demand, at 52.9 days, this also exceeded the 2003-07 end-January average of 51.8 days.
North American and European total stock positions at the end of January were 1.5 and 1.2 days above average forward demand cover respectively. Even OECD Pacific total oil stocks, which have been reported below seasonal ranges for several months, were back to average levels at the end of January in absolute and forward demand terms. February forward demand cover will be calculated based on demand for March, April and May - months characterised by lower product demand - and including only Japan and US data (based on preliminary February stocks data) show little change in days cover despite a decrease in absolute stock levels.
However, regional total oil stocks do not reflect product- or country-specific stock positions. While gasoline stocks increasingly bulge in OECD Europe and North America, they remain well below seasonal ranges in the Pacific, where residual fuel stocks are also unseasonably low. Distillate stock cover in Europe, at 33.8 days for end-January, was also below the five-year average of 35 days and soaring distillate cracks in February suggest increasing tightness.
Upward revisions to December OECD stock data were significant, totalling 29.5 mb. Crude stocks in Japan and the US were respectively revised up 10.8 mb and 5.6 mb. Widespread upward adjustments to December distillate stocks levels (France, Germany, Italy, UK all corrected up by between 1 and 2 mb) pushed European distillate revisions to +9.9 mb, alongside revisions of +2.7 mb to both Canadian and US distillate stocks. Gasoline stocks in North America and Europe were revised up by 3.4 mb and 3.9 mb respectively. These upward adjustments easily overshadowed the large downward revision, of 9.1 mb, to 'Other Oils' stocks in OECD North America.
OECD Industry Stock Changes in January 2008
OECD North America
Total oil stocks in OECD North America rose by 13.9 mb in January, of which 11 mb was in the US. Weekly US data reveal that crude imports rose by half a million barrels per day in January, coinciding with the arrival horizon of increased late-2007 OPEC long-haul exports (a time when Saudi Arabian formula prices to US (and Asia) were cut for December). Tanker data indicated higher arrivals of Nigerian crude into the US in January as well. In addition there was an average monthly decrease in refinery throughputs of over 1 mb/d (both for economic reasons and planned maintenance) leading January US crude stocks to rise by 14.3 mb. Preliminary weekly data indicate a further crude stock build of 6.5 mb in February. Mexican crude stocks increased by 3.7 mb in January, with exports down marginally following stormy weather in the Gulf , leaving total OECD North American crude inventories 18 mb higher.
US gasoline stocks built seasonally in January, by 16.7 mb over the month, to reach 234.3 mb, the highest monthly closing stock level since January 1994. Weekly data indicate that US gasoline stocks rose even further in February. This may be a precursor to heavy March refining maintenance but is also a symptom of lower demand growth. This large gasoline build offset much of the 19.3 mb seasonal decrease in 'other products' stocks. Lower propane stocks are responsible for a large part of the latter. January heating-degree days were higher than normal in US regions where propane is used as a heating fuel (such as the Midwest and the US Gulf) and US weekly data indicated a sharper draw than normal in this fuel. Overall, total OECD North America product stocks fell by 4.4 mb in January.
In OECD Europe, rising distillate and gasoline inventories boosted total regional oil stocks by 6.2 mb in January. Distillate stocks were up by 3.9 mb in total, with builds of up to 2 mb in each of Germany, Italy, Netherlands and the UK, easily offsetting a 1.8 mb draw in France (where demand was strong). High European diesel imports were reported in January from the US and Asia while temperatures were milder than usual, with heating-degree days below seasonal averages (except in Greece and Turkey). Gasoline stocks also rose in Germany and the Netherlands, by 1.3 mb and 0.8 mb respectively, as exports to the US became less economic. In total, OECD Europe product stocks were up 8.2 mb in January.
OECD European crude stocks fell by 1.1 mb in January, led down by a 2.2 mb monthly decrease in the UK possibly linked to North Sea outages. Preliminary February Euroilstock data were unavailable at the time of writing, but data covering independent storage in the ARA region showed February distillate stocks falling to the bottom of seasonal ranges while gasoline stocks hit historical highs. This may have reflected European trends as a whole with distillate cracks in February indicating extreme tightness and the likelihood that demand ran ahead of refinery production, following economic run cuts.
Total oil stocks in OECD Pacific countries rose by 12.5 mb in January including an 8.5 mb increase in Korea, split evenly between crude and product. Crude inventories in Korea and Japan built by 3.9 mb and 2.9 mb respectively. Preliminary Japanese data confirm that refinery throughputs fell by 90 kb/d in January, allowing crude stocks to build in conjunction with higher imports of Middle Eastern crude. A further potential fall of 130 kb/d was indicated for February throughputs, as economic run cuts continued.
OECD Pacific product stocks rose by 1.9 mb in January. Regional builds of 1.8 mb and 0.9 mb in 'other products' and gasoline offset a 1 mb draw in residual fuel oil. Higher 'other products' stocks were observed in both Japan and Korea, while a Korean distillate stockbuild offset a corresponding draw in Japan. Residual fuel oil stocks in Japan were reported at 10.0 mb at end-January, at the bottom of seasonal ranges, and still pressured by stronger demand in the wake of the TEPCO nuclear shut-downs. Japanese weekly data indicate a large product draw, of 14.2 mb, in February, driven by an 8 mb decrease in kerosene stocks as a cold snap boosted demand for the fuel used for heating purposes.
Recent Developments in Singapore Stocks
Independently held product stocks in Singapore fell back within five-year ranges in February, according to International Enterprise, before a dramatic early March leap, probably related to new storage capacity. Decreases in fuel oil stocks easily overshadowed a build in distillate inventories. Fuel oil stocks fell from 16.2 mb in late January to finish the month at 12.8 mb. This marked a return to five-year seasonal ranges in this product, possibly related to increased residual fuel import demand in Northern Asia, including healthy Japanese fuel oil imports. Singaporean middle distillate stocks ended February near seasonal averages, at around 7.3 mb, having peaked at 8.6 mb mid-month. By end-February, light distillate stocks ended up 0.4 mb on the month, just above seasonal norms at 8.8 mb. The early-March leap in stocks related to new storage capacity.
- Oil prices again rose to new records above $100/bbl, supported by strong distillate markets, rising geopolitical tensions and OPEC's apparent reluctance to reconsider official supply levels ahead of the summer. Oil tracked new highs for a range of commodities, while the US dollar sank to a low against the euro. Talk of a large flow of money into commodities is partially justified by an increase in open interest in oil contracts, but cumulative crude oil open interest remains below 2007 peaks.
- Refined product prices were mixed, with distillate crack spreads reaching new peaks in Europe on weather-related demand and tight supplies. Gasoline crack spreads took a steep downturn, sliding into negative territory in Northwest Europe on above-average US inventories and lower demand for European barrels. Fuel oil discounts to crude widened further.
- Refining margins rose on average in February, but remain relatively low in the US and Singapore. European margins picked up slightly, both for cracking and hydroskimming, tempting some refiners to reverse economic run cuts. But early-March margin calculations indicate continued weakness.
- Middle East Gulf and West African freight rates rose above normal seasonal ranges in February on an increase in dirty vessel demand. Record volumes of West African crude headed for China in February, while sailings from the Middle East Gulf, especially on westbound routes, reportedly increased. Caribbean Aframax rates were boosted by higher US Gulf Coast refinery throughputs.
Oil prices continued to defy growing concern about the US and global economy and rose to new record levels on underlying fundamental strength. OPEC's 5 March decision to leave its production unchanged was unable to calm markets that reflect the need for a higher stock buffer due to increased geopolitical tensions and a rebuild of crude stocks ahead of peak summer demand. Cold weather and previous economic run cuts tightened the distillate market, especially in Europe, sending gasoil prices to new peaks. At the same time, refining margins in key regions remained low, despite an improvement in February, raising doubts about product stock replenishment.
Recent oil price increases would appear to be part of a wider rise in commodities, with gold, platinum, tin, soy and corn all surging to record highs. At the same time, the dollar declined to a new low against the euro. A widespread argument is that the prospect of a further decline in the dollar's value, combined with accelerating inflation, is encouraging a general investment flow into commodities. But the available data on this are - broadly speaking - inconclusive. NYMEX WTI Commitment of Traders data do show an increase in non-commercials' net-long position, but only to levels already seen in January, and not to as high as those observed last summer. At the same time, total open interest in WTI has not increased substantially, again remaining lower than last year (the same is true for ICE Brent). A look at the WTI futures' forward curve shows a widening of near-month backwardation, while at the same time a rise in 2015 prices to over $100/bbl could suggest that market participants see fundamentals remaining tight for the foreseeable future.
In contrast to headlines about crude hitting new records, peaks for distillate futures received less attention, but contributed to the market's strength. A combination of low distillate stocks - at least in parts of Europe and Japan - cold weather and lower refinery runs due to weak margins tightened markets and boosted gasoil crack spreads. This was especially true in Europe, where the ICE Gasoil/Brent futures spread reached all-time highs. In the Mediterranean, unusually cold weather, lower Russian gasoil exports and to some extent the after-effects of the January change to a 0.1% maximum sulphur content all contributed to tightness. These developments were in sharp contrast to gasoline and fuel oil crack spreads, which declined.
While existing geopolitical issues have not improved - i.e. in the Middle East and Nigeria - some new hotspots made it into the headlines. Russia briefly curbed gas flows to Ukraine, again due to a payment dispute, but volumes transiting Ukraine to Central and Western Europe were not affected. Military activity on the Turkish-Iraqi border appears to have ceased for now, and in any case did not cause any disruption to oil flows. Armenia and Azerbaijan have seen a flare-up in tension, and historical differences remain unsettled. Lastly, a Colombian raid on a FARC guerrilla camp on its border to Ecuador saw strong protests from the latter and Venezuela, both of whom Colombia accuses of aiding FARC. Venezuela and Ecuador had sent additional troops to their respective borders with Colombia, but diplomacy soon defused tensions, though a 60 kb/d Colombian crude pipeline was subsequently attacked, cutting supplies. Meanwhile, a landslide in Ecuador temporarily interrupted flows through the SOTE crude pipeline to the coast in early March, while a fire at Shell's Norfolk terminal cut gas supplies to the UK market.
Spot Crude Oil Prices
Spot crude oil prices surged to new highs in February and early March, with Atlantic Basin sweets taking some strength from North Sea outages and competition for distillate-rich West African grades amid tightness in heating oil, jet fuel/kerosene and diesel markets, especially in Europe and Asia. Despite an overall crude stock build in the US, most of the increase took place on the US Gulf Coast, while stocks at Cushing, Oklahoma, fell in February. Meanwhile, spot WTI recovered to a premium over Brent from mid-February. At the same time, US Gulf Coast cracking margins for foreign crudes remained far lower than in Europe in February, despite improving, in theory discouraging crude shipments across the Atlantic.
Meanwhile, Saudi official selling prices (OSPs) for crude sent to the US in April were raised which, in combination with already-weak refining margins, could curb volumes sent west. On the other hand, reduced refinery interest in Russian Urals in Europe - due to weak hydroskimming margins - saw the grade tumble to a discount to US sour grade Mars and widen the existing discount to Brent. This could encourage a higher flow of Russian barrels to the US. Saudi OSPs to Asia meanwhile were trimmed, a boon for refineries there that have been hit hard by weak margins. The Brent-Dubai spread widened slightly, but problems with Australian crude production caused a surge in regional marker Tapis over Brent, potentially serving to attract more Atlantic Basin crude barrels on the eastward journey.
Average February refining margins rose across the board and in all regions surveyed. Cracking and even hydroskimming margins in Europe improved to the extent that some refineries heard to have previously made economic run cuts were reportedly reversing their decision. Distillate cracks were clearly the driver, as in other markets, with spreads for diesel, heating oil and jet all rising strongly. Except for fuel oil, other cracks rose too on average. However, strong crude gains in early March - and corresponding dips in gasoline cracks, in particular - may reverse this situation.
In the US, West Coast margins increased quite strongly in February, on a pronounced improvement in average February gasoline cracks. But here too, some cracking margins remained negative. Gulf Coast cracking margins also mostly remained negative. Asian refining margins all remain weak. Korean and Japanese refiners will reportedly keep crude throughputs curtailed due to the weak margin environment.
Spot Product Prices
Product prices were mixed in February and early March. As described above, a tight distillate market, especially in the Mediterranean and Asia, has arguably been a driver of crude prices. ICE Gasoil futures and physical gasoil crack spreads reached record highs in early March on a combination of cold weather and supply tightness in regional markets. Contributing to the supply shortage was the previous reduction in refinery crude runs (subsequently partly reversed), as hydroskimming plants had lowered throughputs due to weak refining margins. Europe's recent switch to a 0.1% maximum sulphur content in heating oil/gasoil may also be causing some supply difficulties, as not all markets have yet fully switched to the new specification. In addition, Russian gasoil exports to Europe and especially to the Mediterranean will mostly continue to have a sulphur content of 0.2%, requiring either further desulphurisation or blending with lower-sulphur material.
In Asia, distillate prices rose sharply in February, supported by a number of factors. Japanese kerosene stocks have fallen to the bottom of their five-year range on cold weather and higher exports. Regional demand may stem more from the jet fuel market, as China is reportedly buying 40% more fuel for April than for March. Japanese refineries are also among those who made sharp cuts in runs due to weak margins. East Asian distillates are also flowing to the US West Coast after arbitrage spreads improved since the beginning of the year. And lastly, even Iran is reportedly taking in more East Asian cargoes, as export flows from India have been curtailed due to issues with credit lines.
Gasoline cracks in contrast have fallen sharply since mid-February. US refiners in particular have been cranking out substantially more barrels than usual and domestic stocks have risen well above their five-year range. Typically, refiners build stocks ahead of the summer at this time of year, but the unusually high levels may indicate above-average seasonal maintenance ahead, together with weaker demand. In any case, high stocks and low US prices have caused a narrowing in the arbitrage spread to Europe, likely curbing flows across the Atlantic (and adding to pressure on European refiners to keep throughputs trimmed). Northwest European gasoline stocks also remain very high as a consequence, and in early March, the NWE gasoline crack dropped to below zero. Naphtha cracks plummeted too, as crackers shut for maintenance in Europe and Asia.
Fuel oil discounts to benchmark crudes widened in February and early March as stocks remained high in key markets. China has increased its buying somewhat since the end of the Lunar New Year holiday, but regionally, Singapore stocks remain at the top of their average range, and the flow of cargoes from the west (and elsewhere) shows no sign of abating. High Singapore stocks may however partly reflect the addition of new storage capacity, and demand for fuel oil is being helped by the high prices and strong regional demand for coal and LNG - with prices well above those observed in the Atlantic Basin.
End-User Product Prices in February
Compared with recent months, IEA consumers only experienced slight increases in petroleum product prices in February. Gasoline and diesel prices on average rose by 0.8% and 0.2% respectively in US dollars, ex-tax, with major gasoline price increases in Italy and Spain (4.6% and 4.4% respectively). Heating oil end-user prices in the countries surveyed were up by 1.2% on average. Low-sulphur fuel oil prices in Europe followed the regional trend and decreased on average by more than 3% in US dollars, ex-tax, with a major decrease in Spain (-8.9%). Consumers in Japan saw a slight increase of 0.7%. However, compared with February 2007, ex-tax retail prices increased on average by 55% in US dollars and by a lower 41% in national currencies due to the dollar's weakness.
An increase in dirty vessel demand led a recovery in Middle East Gulf and West African freight rates in February. Record volumes of West African crude headed for China in February, while sailings from the Middle East Gulf, especially on westbound routes, reportedly increased. Poor weather led to delays in the Black Sea and Caribbean, undermining regional tonnage availability. Clean rates were flat in February despite higher demand for product imports from China.
Benchmark VLCC rates from the Middle East Gulf to Japan rose to $17/tonne at the end of February, from $10/tonne one month before. This brought rates above seasonal norms and reflected the upturn in demand for vessels in the Middle East Gulf trading on all routes. Spot chartering activity by Vela, Saudi Aramco's tanker chartering division, significantly increased in February according to reports. Furthermore, US refinery maintenance may have peaked in February, meaning demand for February-loading vessels (arriving in March), would coincide with the seasonal rebound in refinery runs.
West African dirty tanker rates rose well above seasonal averages in February, boosted by increased vessel demand for crude exports to China. Volumes loaded in West Africa and heading for China reportedly reached record highs of over 1 mb/d in February, as Chinese refiners maintained high throughputs in an attempt to assuage domestic product demand. VLCC rates on that route rose by around $8/tonne in February, to reach $30/tonne at end-month. West African Suezmax rates were also supported by this increase in vessel demand.
Poor weather in the Black Sea and fog in the Caribbean led to vessel delays in both regions in February. However, while Aframax rates surged in the Caribbean, on higher PADD 3 refinery throughputs, Mediterranean Aframax rates drifted, possibly related to lower Russian exports after export duty hikes. Black Sea to Mediterranean rates for 80,000 tonne cargoes fell from over $15/tonne in mid-February to $10/tonne by the end of the month.
Asian clean tanker rates were relatively flat in February. Demand for product imports into China was extremely high and refinery outages in Australia increased regional competition for imports. However, additional clean vessels arriving in the region, combined with reported run cuts by some Japanese and Korean refiners, may have prevented significant upturns in clean rates. Having fallen earlier in the month, Atlantic clean rates did recover at the end of February, amid signs of improving economics for transatlantic trades to the US. UK Continent to US Atlantic 33,000 tonne rates rose by $2.50/tonne in the last week of February to finish the month near $19/tonne.
- Refinery crude throughputs remain under downward pressure from poor economics, seasonal maintenance and operational problems. First-quarter global crude throughput is forecast to average 74.0 mb/d, with annual growth concentrated in non-OECD regions, while OECD crude runs are forecast to decline by 0.3 mb/d year-on-year. Second-quarter crude runs are forecast to average 73.9 mb/d as refiners increase throughput from the April low, ahead of peak gasoline demand in the summer.
- Economic run cuts continue to hamper activity in Europe and the Pacific. Run cuts are expected to increase in March in Japan and Korea, given record weakness in fuel oil cracks and apparent weakness in Japanese kerosene demand, but ease in Europe as higher gasoil cracks encourage some hydroskimming refineries to increase crude runs.
- OECD crude throughput in January averaged 39.0 mb/d, down 0.6 mb/d from December and 0.3 mb/d lower than the January 2007 level. Weakness in the US accounts for more than half the decline as refiners made an early start to maintenance work. Non-OECD throughput increased by 1.1 mb/d year-on-year to 35.7 mb/d.
- OECD refinery yields continue to point to record high gasoil/diesel yields. Increases in North America and Europe more than offset the drop in the Pacific, where operational problems at upgrading units limited distillate production.
Global Refinery Throughput
Global refinery crude throughput remained under downward pressure in February as weak economics undermined activity levels in several OECD regions. Strong gasoil cracks were insufficient to offset heavily negative fuel oil cracks and seasonally depressed gasoline cracks. In addition to the usual incidents and accidents, economic run cuts are estimated to have reduced OECD crude runs by 0.6 mb/d during the month. Furthermore, seasonal maintenance constrained crude runs in Europe and North America. Conversely, crude throughput in the Middle East and some parts of Asia continues to run ahead of expectations, despite poor margins for less complex refineries.
First-quarter global refinery crude throughput is projected to average 74.0 mb/d, 0.2 mb/d lower than estimated in last month's report. FSU, Chinese and Asian crude runs continue to account for the majority of the 0.7 mb/d year-on-year growth. Non-OECD crude runs are forecast to increase by 1.0 mb/d during the period while OECD crude runs are expected to decline by 0.3 mb/d year-on-year, driven by run cuts and heavy US maintenance. Second-quarter global crude runs are expected to recover from the early April low-point, averaging year-on-year growth of 0.7 mb/d.
Refineries are caught between the continued strength in crude and middle distillate prices and the structural weakness in fuel oil prices. Fuel oil continues to face competition from cheaper alternative energy sources, such as coal and gas, for market share in power generation. Recent increases in the price of these other commodities may provide some relief for refiners, however the current record weakness in fuel oil cracks compared with crude will continue to weigh on those refiners who have not invested in sufficient upgrading capacity to minimise their fuel oil production. Some improvement in fuel oil cracks may result from the runs cuts reported for February and March, but this will not alter the structural discount fuel oil attracts.
In the OECD, North American crude throughput is estimated to have reached its seasonal low-point in February as operational problems in Canada and the US added to a long list of planned shutdowns. March throughputs are expected to recover, as refiners look towards the seasonal uptick in gasoline demand over the course of the second quarter. However, the build in US gasoline stocks in recent weeks (to 14-year highs in absolute terms) raises the possibility of another bout of heavy maintenance before the end of the first quarter. Weekly data have shown a recovery in runs from the mid-February, 12-month low of 14.5 mb/d, but while this low level could be seen again, the full restart of Chevron's Pascagoula and Citgo's Lake Charles refineries, plus the imminent return of a 135 kb/d crude unit at Exxon Mobil's Baytown refinery and the final crude unit at BP's Texas City refinery should underpin Gulf Coast throughput in coming months.
OECD Pacific crude throughputs are under pressure from three factors during the first quarter. Operational problems at several refineries in Australia have cut throughputs and resulted in increased product imports from Singapore and elsewhere. Poor margins for less sophisticated refineries, driven by widening fuel oil discounts to crude, have resulted in continued run cuts in Japan and Korea in February and these are forecast to increase in March. Lastly, apparent weakness in January and early February Japanese kerosene demand may have caused refiners to reduce (relatively more profitable) domestic kerosene supplies and increase (relatively less profitable) jet fuel exports to the highest level since October. Further strengthening of the US West Coast arbitrage from Asia, may encourage further increase in jet exports in coming weeks. Japanese crude runs are expected to weaken further in March from February's level of 4.0 mb/d, as the start of seasonal maintenance adds to the economic run cuts
Korean crude runs are expected to have fallen in February and, driven by the historic lows that fuel oil cracks have reached in recent weeks, are forecast to decline further in March. Reported problems with upgrading capacity at some refineries could add to the weakness in crude runs. Furthermore, exports of fuel oil and gasoil are likely to be reduced as less complex refineries seek to minimise their production for export markets.
European crude throughput is expected to have fallen in February and again in March from January's level, as economic run cuts at hydroskimming refineries curtailed activity. This drop comes despite the record price, in both absolute terms and on a crack basis, for gasoil and ultra-low-sulphur diesel, which are now trading above the levels seen last November and December. The Mediterranean market is reported to be particularly tight. Here the combination of the switch to tighter sulphur specifications, the reduction of supplies from domestic refining capacity and reports of maintenance at some Russian refiners have coincided with a spike in demand following cold weather in Greece, Turkey, Russia and much of the East Mediterranean.
Chinese crude runs are forecast to average 6.9 mb/d during the first quarter, an increase of 0.5 mb/d year-on-year. Higher gasoil/diesel imports of around 170 kb/d in March should help to relieve the product shortages reported in recent months. However, the strong demand for diesel associated with agricultural activity in March may keep the pressure on refiners to maximise crude runs through to the end of the month. Second-quarter crude throughput is expected to decline slightly, to an average of 6.6 mb/d, due to maintenance, much of which has been deferred from the fourth quarter of last year, as refiners sought to meet strong demand for distillates. Ultimately, Chinese refiners will need to undertake maintenance work before operational reliability starts to have an impact on crude throughput. However, there remains the risk that continuing product market tightness in China could result in crude runs exceeding our forecast, if the government pressures state refineries to defer maintenance and continue supplying crude to independent refineries as recently reported. Crude runs are forecast to increase again during the third quarter, ahead of the summer Olympics in Beijing and following the start-up of Sinopec's new 200 kb/d Qingdao refinery late in the second quarter.
Elsewhere in Asia, Indian crude throughput reached a new record high in January of 3.2 mb/d, as Essar continued to start its upgrading units and expand crude throughput to 210 kb/d, a process that was completed in early March. Growth also came from Chennai Petroleum's Manali refinery, following maintenance, and near-record throughput at Reliance Industries' 660 kb/d Jamnagar refinery, where crude runs reached 760 kb/d. Indian crude throughput is forecast to plateau at around January's level, ahead of the start-up of Reliance's Petroleum's new 580 kb/d refinery at Jamnagar in the second half of the year.
Middle East crude runs were above expectations in January as scheduled work at the UAE's Ruwais refinery started later than assumed. Preliminary data from Iran for January are higher than anticipated, suggesting that the work to expand a crude unit at the Bandar Abbas refinery started later than we had assumed. Furthermore, November and December data for Saudi Arabia were revised, to 1.6 and 1.8 mb/d respectively, following last month's surprisingly strong reported crude throughput of 2.1 mb/d, and November's weaker-than-expected 1.3 mb/d. January Saudi crude runs were weaker-than-forecast, suggesting that recent reports of operational problems at Ras Tanura may have started earlier in the year. Second-quarter crude runs are forecast to increase, with the completion of Iran's second crude expansion at Bandar Abbas, part of its strategy to raise domestic crude processing capacity and reduce gasoline imports.
Preliminary data for January for the US indicate that crude runs dropped by over 0.3 mb/d, to an average of 14.9 mb/d and declined further to 14.6 mb/d in February, on the back of a combination of maintenance, economic run cuts and unplanned outages. Several refineries are planning work on catalytic cracking units, which may temporarily depress crude runs but, on balance, US crude runs are forecast to rise slightly over the course of March, from the average February level. Perhaps the bigger impact will be felt on gasoline supplies, given US refiners' bias to maximise gasoline production from such units and may partly explain the record build in gasoline stocks. Furthermore, March and April are likely to see a significant amount of hydrotreating capacity undergoing maintenance (albeit only briefly for any individual unit) as catalysts are changed over having been in-situ for two years, following the move to 15 ppm sulphur in diesel in summer 2006. Over the balance of the second quarter, US runs are forecast to increase as refiners prepare for the peak in gasoline demand over the summer months.
Provisional January data for the OECD show that crude runs fell to 39.0 mb/d, down 0.6 mb/d from December and 0.3 mb/d below the January 2007 level. As highlighted in last month's report the weak margin environment and an early start to maintenance in the US undermined activity levels. Japan and Korea were both marginally weaker than December, but stronger than January 2007 when warmer-than-normal weather resulted in economic run cuts for much of the first quarter.
OECD Refinery Yields
OECD gasoil/diesel yields increased again in December to fresh highs, driven by the restoration of hydrocracking capacity in Europe and the continued rise in US gasoil/diesel yields. Pacific gasoil/diesel yields declined, following problems with Korean upgrading equipment and lower Japanese distillate yields. The increase in the US perhaps reflects the increase in hydrocracker throughputs, while coking unit throughputs continue to languish below the five-year range and catalytic cracking throughput has only recently returned to the five-year average. Overall, upgrading unit feed rates (expressed as a percentage of total crude, NGL and feedstocks processed by refineries) have only returned to above five-year average levels in the fourth quarter.