- Oil prices rose above $60/bbl on OPEC cuts, the coldest February in the US for 30 years and refinery outages. Falling US product stocks were offset partially by unusually warm weather in Europe and Northeast Asia, but further OPEC cuts in February prevented the normal seasonal crude stock build in the OECD.
- World oil output fell by 65 kb/d in February to 85.5 mb/d amid OPEC supply cuts. Non-OPEC supply additions for 2007 remain at 1.1 mb/d, extending the growth evident since mid-2006. OPEC gas liquids add a further 0.2 mb/d this year. Sizeable supply risks remain, not least those from underinvestment caused by intensifying resource nationalism.
- OPEC February crude supply averaged 30.2 mb/d, down 125 kb/d from January as a 365 kb/d cut from OPEC-10 was partly offset by increases from Iraq and Angola, and leaves OPEC supply within the possible 2Q-range for the call. OPEC cuts since September amount to 1.0 mb/d, leaving effective spare capacity at 2.8 mb/d. In addition, outages in early March brought the offline total in Nigeria to 0.8 mb/d.
- Global oil product demand remains unchanged at 84.5 mb/d in 2006 and is seen growing by 1.8% to 86.0 mb/d in 2007. Weather-related adjustments to OECD data in Europe and the Pacific were largely offset by US demand strength and upward changes to China, FSU and India.
- Total OECD inventories fell 8.6 mb in January as a crude draw in Europe outweighed a weather-induced product build, leaving forward demand cover broadly flat at 54 days. Preliminary data show the US driving a 65.7 mb fall in February stocks in key OECD countries - or an average 1.2 mb/d decline in the first two months of 2007.
- Seasonal refinery maintenance cut January OECD throughputs by 0.5 mb/d, to an estimated 39.3 mb/d. February crude runs are seen falling to 38.4 mb/d, but rise to 38.6 mb/d in March. The end of maintenance in the Atlantic Basin will be followed by seasonal work at Pacific refineries leaving crude demand relatively flat over the first and second quarters.
Heading for a large 1Q stock draw
Tighter OPEC supply and colder temperatures in the US in February served to perpetuate the recent downward trend in OECD stocks, despite the continually mild weather elsewhere. Preliminary data suggest that OECD stocks have fallen by over 1.26 mb/d over the first two months of the year, and could be heading for the largest first quarter stock draw for over ten years. Unsurprisingly, prices have risen from their mid-January low of $50/bbl, and for the past two weeks have been ranging between $60 and $63/bbl.
OPEC crude supplies fell by 125 kb/d in February as a tightening of OPEC-10 output was partly offset by increased supplies from the two countries currently exempt from targets, Iraq and Angola. The outlook for March is a little less clear. Term allocations suggest slightly higher supplies from some members, but additional outages in Nigeria and ongoing problems in Iraq could act as an offset. Nigeria is a particular source of concern, with violence expected to increase ahead of the presidential election in April. Non-OPEC supply growth continues at around 1.1 mb/d, with lower forecast supply from the Americas predominantly offset by higher output from the Russia and the Asia Pacific.
Demand trends have been disparate. US demand jumped sharply as one of the coldest Februarys for 30 years bolstered heating needs, while transport fuel deliveries remained robust. Although it turned colder in Europe in February, heating degree-days remained around 7% below the 10-year average. Temperatures remained mild in Japan and Korea.
Demand in the US transportation fuel sector has been surprisingly robust. Primary gasoline deliveries have seen 1.8% growth for the first two months of this year, while diesel offtake is even stronger. Although the strength in diesel demand looks unseasonably high, the strong growth is really a reflection of a weak January and February last year, when demand was up by just 0.4%. This compares with the 2006 average for diesel of around 6% - suggesting that current demand is broadly in line with last year's trend.
Demand always falls in the second quarter, but its market impact is often exaggerated. The weakness is primarily in Asian heating fuel use, and comes at a time when the refining industry traditionally builds crude stocks.
In other regions, the second-quarter dip in demand is limited and is becoming less significant as air-conditioning use spreads and summers start earlier. And it is worth remembering that the calming influence of milder-than-normal weather this winter may have the opposite effect if the warm trend persists through the summer months.
Crude demand also has a different seasonal pattern to that of products: there is little difference between throughputs in the first and second quarters. On a monthly basis, it is clear that refiners start to crank up crude use in May and June to meet peak summer demand. This year is no exception: our estimates show global offline capacity remaining high until May - but that means refiners will step up purchases around mid-April to ensure the crude is in place for restarts.
Data are always subject to revision, and assessing first-quarter stock movements based on provisional data for January and partial OECD data for February is far from an exact science - but it certainly shows reason to be concerned. While stock levels in key products such as gasoline and distillate are on a par with last year, and crude stocks only appear tight in Europe, these are inventory levels that were associated with higher and sharply rising prices last summer. Moreover, both the speed of the stock fall and the fact that crude inventories are drawing counter-seasonally is of greater concern.
Atlantic Basin refiners typically build crude stocks in the first quarter so they can hit the ground running to build product stocks for the driving season when maintenance has finished. This year they could end seasonal maintenance with both lower product stocks and lower crude stocks.
So far, most signals by OPEC suggest that there will be no change in output targets at its 15 March meeting in Vienna. That comes as little surprise: current output levels continue to tighten the market and prevailing targets give the producer group the flexibility to tighten supplies by another 1.0 mb/d. In reality, stock trends and prices are signalling that higher OPEC exports will be needed in the months ahead.
Clarifying the call on opec
Analysts love detail and there is no shortage of it in this report. We build our models and forecasts from the most detailed data, whether it be product-level supply and demand, oil production from individual fields or specific unit maintenance at refineries. These estimates are fed by data-flow from a homogenised 250-point questionnaire from OECD countries, non-OECD data from both the Joint Oil Data Initiative (JODI) and just plain hard digging among myriad oil company, tanker tracking, financial, consulting and trade press sources.
Still there are gaps. There is little stock data from non-OECD countries, and supply, demand, stock and trade data never perfectly add up. The resulting difference goes into our miscellaneous-to-balance. Any of these factors can cause this gap and while we may have suspicions on the underlying cause, we do not try to force the balance with such assumptions. For the sake of transparency, we feel it is better not to subjectively allocate the balancing factor to supply and demand in one country or another. When better information becomes available, it is then a simple accounting proposition to move data from the miscellaneous-to-balance category into another as appropriate.
We also have, in bold letters in each supply section, a warning that there has been an historical tendency for non-OPEC supply to be revised down on average by 350 kb/d in a year. That figure is not constant, nor is it typically steady over the course of a year and can be caused by weather, strikes, faster-than-expected decline and accidents (among others). Again, when the underlying analysis is done at field level, it would be misleading to allocate risk arbitrarily to specific fields or countries.
Those who know our data well appreciate the clarity that this methodology brings, but for those who do not, this can create some misunderstanding. As much as we flag trends in the miscellaneous-to-balance or supply-side uncertainties, it will inevitably translate into comments that the IEA underestimates demand or overstates supply - after all, it makes a juicier sound bite than 'adjusting for the known trends in supply and miscellaneous-to-balance'. It is a simple fact of life that no one reads the 'small print'
Without adjusting the data on the back of 'hunches', some clarity can be added via the call on OPEC + stock change(call). The call is simply an arithmetical balance between non-OPEC supply, OPEC NGLs and global demand - and without an adjustment for trends in the miscellaneous-to-balance or risk adjustments to non-OPEC supply, it will not truly reflect the supply gap. So, to add some clarity, we have for some time been running graphics, articles and tables in the Oil Market Report (OMR) and Medium-Term Oil Market Report (MTOM)R looking at both the call on OPEC + stock change (call) and an adjusted call.
The adjusted call takes into account trends in the miscellaneous-to-balance (an eight-quarter moving average) and also a 350 kb/d adjustment for downside risks to non-OPEC supply (for historical data, this range only includes the actual quarterly miscellaneous-to-balance). The adjusted call has now been permanently added as a line item in Table 1 at the back of this report.
So which call is most accurate? The answer is that this will depend upon the issues that are causing the miscellaneous-to-balance. In recent years there appears to have been an understatement of demand. If so, then the adjusted call will provide the best indicator (a glance at Table 1 shows that on a yearly average basis actual OPEC production is closer to the adjusted call). However, in recent months, issues such as the anecdotal reports of a 25 mb build in Chinese strategic reserves could mean that the adjusted call is perhaps an overstatement - leaving the true call somewhere between the arithmetical call and the adjusted call.
Ultimately, we would like to be able to estimate the call with pinpoint precision, but the reality is that a range provides a better perspective - one that will widen and contract as data uncertainties fluctuate. It will not eradicate the comments that we over or understate demand and supply in certain periods, but perhaps a few more knowing looks will be exchanged every time such comments are made.
- Global oil product demand has been kept virtually unchanged at 84.5 mb/d in 2006 and 86.0 mb/d in 2007. Downward revisions to 4Q06 OECD data were largely offset by upward changes in non-OECD figures. In percentage terms, world demand is estimated to have grown by 1.0% in 2006; in 2007, it is expected to increase by 1.8%.
- OECD oil product demand has been slightly lowered by 35 kb/d in 2006 and 56 kb/d in 2007. Data revisions and continuing mild temperatures, particularly in Europe and the Pacific, weighed down on heating and residual oil demand. Total OECD oil product demand is estimated to have declined by 0.9% in 2006, but is still expected to rebound by 0.8% in 2007 to 49.6 mb/d.
- Non-OECD oil product demand has been adjusted upwards slightly in 2006 and 2007, due to a rebasing of India's consumption and revisions to FSU and China apparent demand. Non-OECD oil product consumption is now estimated to have grown by 3.7% in 2006. This year, demand is expected to rise by 3.3% to 36.5 mb/d.
Over the past few months, oil product demand has largely been driven by erratic weather conditions. After a mild start to the winter, North America endured severe cold snaps from late January, which bolstered demand. And despite the cold weather, transportation fuel demand remained robust in that region. Elsewhere, however, temperatures have been milder-than-normal, leading to significant reductions in demand in Europe and Asia Pacific, and to sharply higher exports from the FSU. We have therefore kept our global demand forecast for 2006 and 2007 virtually unchanged. In volumetric terms, we estimate that global oil product demand averaged 84.5 mb/d in 2006 (+1.0% year-on-year), and we foresee it will reach 86.0 mb/d in 2007 (+1.8%).
On the macroeconomic front, the stock exchange turmoil during the last week of February, seemingly prompted by sharp selling in China's Shanghai bourse and pessimistic comments by former Federal Reserve chairman Alan Greenspan, highlighted the downside risks to the global economy. While the capitalization of the Chinese stock market is small, the reaction highlights the importance of the country's economy - which is still racing ahead despite its dependence on exports - as a barometer of global growth. The turmoil has also reminded investors that any slowing of the US economy entails risks for global economic activity. Indeed, US 4Q06 GDP growth was sharply revised downwards, from an earlier 3.5% year-on-year to 2.2% - the second quarter in a row of below-trend growth. Moreover, there is growing evidence that the stalling housing market will eventually curb private consumption. On the one hand, the rate of default of 'sub-prime' (lowest-quality) mortgages has soared over the past months; on the other, bank lending (credit card) is growing, indicating that US consumers are increasingly unable to borrow from their housing wealth, as was the case during the real estate boom. As such, if the Federal Reserve concludes that the risks of a sharp slowdown are higher than inflationary pressures, it could well ease monetary policy by the second half of the year.
Nevertheless, other economies could help limit the negative effects of a US slowdown. Europe - particularly Germany - is holding its ground, despite earlier expectations that last year's strong growth would peter out in 2007, reflecting concern that consumers had brought forward their spending ahead of the January VAT increase. The United Kingdom and Scandinavia are also growing fast, with France following, although at a slower pace. Two European countries, though, face significant risks: Spain and Italy. In both countries, productivity is stagnant, labour costs are rising faster than elsewhere in the EU and output depends essentially on their overheated housing markets. We have therefore maintained our GDP assumptions, and are unlikely to make any significant revisions until the next IMF forecasts are released in April.
Total OECD demand growth was negative in January (-1.7% versus levels of a year ago) across all regions bar North America and lower than that of December. The month-on-month change is a typical seasonal variation; the year-on-year fall was due to continuing mild temperatures, which weighed down on both heating and fuel oil demand. Thus, inland deliveries fell by 4.5% in Europe and by 3.2% in the Pacific. However, deliveries rose by 1.4% in North America. Last month's cold snap lent more support to demand in North America (it was reportedly the coldest February on record in almost three decades), and briefly in Europe and the Pacific (by the end of the month temperatures in the latter two regions rose again).
Coupled with data revisions from country submissions, we made a 35 kb/d downward adjustment of OECD demand in 2006, to 49.2 mb/d. For the year as a whole, OECD demand fell by 0.9%, compared with our previous estimate of -0.8%. For 2007, we have kept our growth forecast unchanged at +0.8%, assuming normal temperatures throughout the rest of the year.
According to preliminary data, January's inland deliveries in the continental United States - a proxy of demand - rose by 1.2% versus January 2005. Gasoline and diesel gains offset losses in other product categories. Furthermore, preliminary weekly data show a strong demand increase in February (+4.8%). These figures, however, are likely to be revised once monthly data are compiled.
This volatile demand pattern is largely due to the weather, from an unusually warm January to a very cold February. In OECD North America, the number of 'heating-degree days' (HDDs) in January was 7% lower than the 10-year average, but 9% higher than average in February. Changing temperatures had a downward effect upon heating and fuel oil demand in January, but supported it in February.
In January, oil product demand in Europe declined by 2.6% compared with the same month in 2006, dragged down mostly by heating and residual oil (-11.8% and -10.5%, respectively). Continued mild temperatures curbed heating oil demand (HDDs were some 18% lower than normal in January), while low gas prices and subdued peak electricity demand weighed down on fuel oil use. Similarly, the mild temperatures left German domestic heating oil stocks (the continent's main market) at high levels. By contrast, jet fuel and diesel demand recorded strong gains (+6.2% and +5.5%, respectively) as economic activity resumed in earnest following the end of the holiday season.
Germany's preliminary data indicate that January's heating oil deliveries contracted by 27.8% on an annual basis, with persistent mild weather throughout the month and consumer stocks still relatively plentiful (with domestic storage tanks filled at approximately 60% of capacity by month-end, four percentage points less than in December). Moreover, despite February's cold snap, heating oil deliveries are unlikely to have risen, as consumers drew on their stocks, which were built up ahead of January's VAT tax rise. On aggregate, this would point to weak heating oil demand in 1Q07, as we have suggested in previous issues of this report. Meanwhile, gasoline deliveries plummeted (-10.7% year-on-year), while those of diesel slowed down (+2.4%), confirming that the strong growth recorded in December (+9.6% and +13.1%, respectively) had also been prompted by anticipated purchases ahead of the VAT increase. Meanwhile, jet/kerosene deliveries rose by 3.3% versus year-ago levels.
As in Germany, deliveries of heating oil in France and Italy were also weak (-8.0% and -26.7%, respectively, compared with January 2006) because of continuing mild weather. Similarly, in both countries residual fuel oil demand contracted (by -18.0% and -38.0%, respectively). In addition to the weather, it should be noted that, despite a shortfall of hydro power generation given relatively scarce rainfall, the sharp fuel oil fall in Italy is due to structural substitution for other fuels, primarily natural gas. Furthermore, by contrast to this year, 1Q06 demand was supported by interruptions to Russian natural gas supplies (January 2006), which prompted Italian utilities to buy in fuel oil.
In late January, Italy's service station operators called for a total 14 days of strikes to protest against a government decree that allows shopping centres and supermarkets to sell fuel, abolishes rules establishing minimum distances between stations and extends opening hours. The stated goal is to encourage competition and bring about lower prices for transportation fuels (Italian retail prices are among the highest on the continent). Nevertheless, it is unclear whether the protest will succeed and force the government to backtrack by creating crippling shortages - and ultimately curbing transportation fuel demand in 1Q07. Indeed, the first two days of stoppage (on 7 and 8 February) were followed by only 38.5% of motorway stations, according to consumer groups (by 90%, according to the unions), while the second planned stoppage (from 27 February to 2 March) was called off, allegedly because of ongoing talks with the Industry Ministry. In any case, February data may highlight an unusual surge in gasoline and diesel demand, since consumers may have engaged in some precautionary buying as a result of the strike threat.
According to preliminary data, total oil product demand in Japan declined sharply in January (-13.7% year-on-year). This was mostly due to weak inland deliveries of jet/kerosene (-25.5%) as a result of balmy winter conditions (demand for kerosene, which is widely used for heating in Japan, normally peaks in January). Despite a colder-than-average December, January was unusually warm (HDDs in the Pacific were about 8% lower than normal), and this mildness continued well into February (HDDs were some 20% lower than average). As such, average temperatures in January contrasted sharply
with those registered during the same month of 2006, which was particularly cold. By the same token, electricity demand remained subdued and utilities required less residual fuel oil (-20.9%) and other low-sulphur gasoil (-23.9%).
There is a possibility, however, that these figures may be revised next month, since the drop in products such as gasoline or diesel (-7.4% and -7.0%, respectively), although in line with expected trends, is astonishingly large. Nevertheless, the unusually warm weather justifies a downward revision of Japanese demand of about 135 kb/d in 1Q07, implying a fall of 2.0% for 2007 as a whole when compared with 2006.
In Korea, the mild weather also weighed down on jet/kerosene demand (-16.6% year-on-year), non-automotive gasoil (-18.3%) and residual fuel oil (-7.4%). Total oil product demand, though, was supported by the continued strength of naphtha (+13.4%), which will remain the driving force behind Korea's consumption growth, as we have previously observed. Overall, the country's oil product demand fell by only 0.2% on a yearly basis.
According to preliminary data, January's apparent demand (defined as refinery output plus net oil product imports, adjusted for fuel oil and direct crude burning, smuggling and stock changes) increased by 4.1% on an annual basis. Growth was mostly driven by naphtha (+12.4%), gasoline (+3.3%), gasoil (+5.9%) and 'other' products (+27.0%). Following further revisions to last year's monthly data, particularly in 4Q06, we estimate that demand in 2006 averaged 7.2 mb/d, slightly higher than in our last report, bringing yearly growth to 6.9%. For 2007, we estimate that total oil product demand will rise by about 6.1% to 7.6 mb/d.
January's relatively modest - by Chinese standards - pace of growth is explained by the fact that oil product demand was particularly strong in January 2006, buoyed by the Lunar New Year festivities. In 2007, by contrast, these celebrations - which prompt a surge in demand, particularly of gasoil, as many Chinese citizens travel back home - took place in February. In anticipation, the government ordered refiners to cut gasoil exports during the month in order to meet a surge of domestic demand in February. In late January, the government also reduced jet fuel surcharges for domestic airlines by 17-20%, arguably to encourage air travel (the surcharges had been raised in August 2006). According to the new rules issued by China's National Development and Reform Commission (NDRC) and the General Administration of Civil Aviation, the surcharge for flights shorter than 800 km fell from Rmb 60 to Rmb 50, while those applied to flights longer than 800 km were reduced from Rmb 100 to Rmb 80.
According to recently released data from the China Electric Power News, over the next few years the country is unlikely to see a repeat of its 2004 oil demand surge - when electricity shortages were met mostly by small diesel generators, especially in the countryside. Indeed, China reportedly expanded its generating capacity by some 102 gigawatts (GW) in 2006 to a total of about 520 GW. This increase - to be replicated in 2007 - is roughly equivalent to the entire capacity of a large European country such as France or the United Kingdom.
It should be noted, however, that many analysts, who expected a rise of 'only' 75-80 GW, are questioning the official figure. But even under the lower estimate, the generating margin (the spare capacity available to meet peak demand) is likely to reach some 10 GW this summer, compared with a 40 GW shortfall in 2004. Most of the new plants (90%) are reportedly coal-fired (hydropower accounts for some 9%, while nuclear and other represent less than 1%). Coal's cost advantage over oil or even gas is arguably the main driver: for example, LNG (the main source of supply in coastal cities) should need to trade at about $3.30-3.60/mmbtu to compete with coal, instead of the current $7-9/mmbtu (including subsidies, which will be in principle gradually phased out).
According to preliminary data, India's oil product demand rose by 7.5% year-on-year in January, mostly driven by strong gains both in naphtha (+28%) and transportation fuels (gasoline sales rose by 8.5%, jet/kerosene by 2.7% and gasoil by 8.2%). Naphtha's vigorous increase is related to natural gas shortages, as we had anticipated in our last report, and to some pricing issues (discussed below). The strength of transportation fuels sales, albeit seasonal (winter is usually the peak season for tourist and business travel), was arguably also related to stock building, with retailers keeping inventories low in anticipation of government-mandated price cuts (as happened in December).
In terms of overall oil product demand, we have made minor adjustments to our 2005 baseline following the submission of new data. Coupled with a few revisions to 2006, India's demand was actually flat in 2005 (compared with a previous estimate of 0.8%), rising by 2.5% in 2006 (versus 2.7% in our last report). For 2007, we foresee that total demand will rise by 3.1% to about 2.7 mb/d (marginally above our previous forecast of 2.6%).
Text Box: India's Price Distortions
Following November's retail price cut, the government mandated a second in mid-February, thereby reducing gasoline and diesel prices by 4.5% and 3.2%, respectively. The caps on LPG and kerosene prices were also maintained. The move was ostensibly dictated by the need to curb inflation, but political motives are also at play - in late February the ruling Congress Party lost elections in the states of Punjab and Uttarakhand, and seeks to keep a majority in its fief of Uttar Pradesh, India's most populous state.
Nevertheless, this second cut will further harm the financial position of India's downstream players. As we have previously noted in this report, price controls (re-imposed in 2004 after the 2002 liberalization) have gradually eroded retailing margins, given the rise in international oil prices. As a result, the country's refiners and marketers incur losses - so much so that some private players, such as Reliance, are trying to export as much oil product as possible, manufacturing jet fuel and gasoil that meet European and Asian specifications, and in the process nurturing India's transformation into a global refining hub. Acknowledging the problem, the government's fiscal 2007-2008 budget, presented in late February, will attempt to reduce the magnitude of downstream losses by cutting import excise taxes on crude oil from 8% to 6%, but it remains to be seen whether this will have a significant offsetting impact.
The price conundrum is also a potential obstacle to the country's avowed goal of using more natural gas, both domestic and imported (LNG), for petrochemical activities and power generation. Currently, India has two gas price mechanisms. On the one hand, both gas from domestic fields developed by Indian companies with foreign partners and regasified LNG can be sold at market prices. On the other, older gas production, mostly from fields operated by state-owned Oil and Natural Gas Corporation (ONGC), is sold at much lower prices, under the government's Administered Pricing Mechanism (APM).
An unintended consequence of this dual system is that some LNG operators, such as Shell, are seeing a lack of demand for their gas despite overall country shortages, which have forced petrochemical plants and domestic utilities to use naphtha as a feedstock over the past few months. As with oil products, the government has offered a partial solution by ruling out the construction of new gas-fired power generation plants, focusing instead on large coal-fired stations, on the grounds that natural gas shortages will last several years - despite the fact that recent significant gas finds in the Krishna Godavari basin by Reliance Industries and by ONGC, Cairn and Gujarat State Petroleum Corporation in a nearby area could arguably lead to a reduction in LNG imports in as little as three to four years.
FSU apparent demand - defined as domestic crude production minus net exports of crude and oil products - has been revised downwards by 255 kb/d in 1Q07, given both lower crude production and net exports. Unlike last year, production has reportedly been hampered by the mild weather, especially in Siberia (the tundra was too wet, rendering operational activities more difficult). Higher January seaborne exports from the Black Sea were somewhat offset by reductions in deliveries from both the BTC and Druzhba pipelines (the latter because of a transit dispute between Russia and Belarus). Moreover, we have also revised upwards 4Q07 demand by 267 kb/d to account for the weak 4Q06. As such, the region's annual growth rate for 2006 remains virtually unchanged at 1.2%, reaching 4.0 mb/d on average. Nevertheless, we are pursuing our efforts to develop a more solid demand benchmark than our current 'apparent consumption' proxy.
According to preliminary data, Brazil's oil product demand grew by 2.1% in 2006, when compared with 2005, to about 2.2 mb/d. Even though minor data revisions are likely, this rate is commensurate with the country's somewhat lacklustre economic expansion, with most product categories increasing by only 1-2%. The only exception, of course, is 'other' products, which include ethanol - this category shot up by 11.8% in 2006. Regarding 2007, we expect oil product demand to grow by 1.9%.
The surge in Brazilian ethanol demand - which now represents roughly 10% of oil-based transportation fuels (gasoline and diesel) - is understandable, considering the strong sales of flex-fuel vehicles and its wide price differential with gasoline. However, ethanol's lower energy content means that if demand were measured on a gasoline equivalent basis, growth would be even lower.
- World oil supply drifted lower by 65 kb/d in February to 85.5 mb/d as a 130 kb/d reduction in total OPEC supply countered a modest rise from non-OPEC. Preliminary data suggest that the UK, Canada, Kazakhstan, Brazil, Angola and Iraq saw higher February output, offset by markedly lower production from the US, Mexico, Norway, Saudi Arabia and Venezuela.
- Non-OPEC supply growth for 2007 is held largely unchanged at 1.1 mb/d, with a further 0.2 mb/d of growth coming from OPEC gas liquids. Yearly growth of around 1 mb/d has been evident since 3Q06, initially due to weak year-earlier levels, but this has been sustained into 1Q07. Non-OPEC growth this year therefore should regain levels seen in the first half of the decade, after weak growth in 2005 and early 2006. Russia, Azerbaijan, Brazil, Sudan, Canada and Australia are the main drivers in 2007. Downward adjustments are made to 2007 supply from North and Latin America and Kazakhstan, partly offset by upward revision to China, Russia and Malaysia.
- Total OPEC crude supply averaged 30.2 mb/d in February, a fall of 125 kb/d versus January. Recovering southern exports pushed Iraqi supply up by 185 kb/d to 1.9 mb/d while rising new field output saw Angolan production breach 1.55 mb/d. Offsetting supply cuts came from all other OPEC members, led by Saudi Arabia (100 kb/d), Venezuela (65 kb/d), Kuwait, Iran and UAE (35-40 kb/d each). Nigerian production continues to struggle, with up to 800 kb/d of shuttered production in early March. Effective spare OPEC capacity was up by 320 kb/d to 2.8 mb/d in February. Sustainable production capacity could rise by some 800 kb/d to 35 mb/d by end-2007.
- OPEC-10 (excluding Angola and Iraq) output fell by 365 kb/d in February, taking reductions in overall supply to 1.0 mb/d since September and 1.5 mb/d since the previous high point in July. Comments by OPEC representatives suggest that output targets may remain unchanged at the organisation's 15 March meeting in Vienna if prices remain close to recent levels.
- The baseline 'call on OPEC crude and stock change' is revised down by 0.3 mb/d for 1Q07 reflecting weaker demand. A counteracting upward revision in 4Q07 reflects demand rebound under normal weather after an exceptionally mild 4Q06. However, the report now also presents the 'call' as a range, with an expected high-end incorporating non-OPEC supply risks and a historical average of the report's miscellaneous-to-balance item. February OPEC supply was already within range of the expected 2Q low for the call.
All world oil supply figures for February discussed in this report are IEA estimates. Estimates for OPEC countries, Alaska, Kazakhstan and Russia 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. Allowance has been made in the forecast for scheduled maintenance in all regions and for typical seasonal supply outages (including hurricane-related stoppages) in North America. These aside, no contingency allowance for random events is subtracted from the supply forecast. While upside variations can occur, experience in recent years indicates that the random events listed above may cause supply losses of between 300 kb/d and 400 kb/d for non-OPEC supply each year.
OPEC crude supply fell by an estimated 125 kb/d in February to 30.2 mb/d. This was compared with a 155 kb/d upward-revised January base of 30.3 mb/d (both Nigeria and Iraq were revised up for January). While in February Iraq boosted supply by 185 kb/d and Angola by 55 kb/d, output from all of the remaining OPEC producers fell, by a collective 365 kb/d. Saudi Arabia's production declined by 100 kb/d to 8.6 mb/d, with Venezuela, Kuwait, UAE and Iran each trimming supplies by between 35 kb/d and 65 kb/d.
February marked the seventh straight month of reduced supply from the OPEC-10 (excluding Iraq and Angola), with output of 26.8 mb/d being around 1.0 mb/d below last September and 1.5 mb/d below the previous high point in July 2006 of 28.2 mb/d. Cuts agreed last October were due to curb supply from November onwards by 1.2 mb/d versus a September baseline. Then, OPEC's December meeting flagged a cut of 500 kb/d from an unspecified base to take place from February.
OPEC Ministers will meet in Vienna on 15 March. Comments ahead of that meeting suggest that, with prices remaining above $60/bbl, there are unlikely to be calls for further production cuts over and above those already agreed. It is always dangerous to pre-judge OPEC decisions, but it would appear that even hitherto hawkish members Iran and Venezuela are stressing compliance with existing targets rather than further supply curbs. We note that February production of 30.2 mb/d stands 400 kb/d below the low of the range for the 1Q call on OPEC crude and stock change and well within the likely range for the second quarter call.
OPEC installed production capacity stands at 34.2 mb/d (including Iraq and Angola), implying spare capacity for February of around 4.0 mb/d. However, assuming that Angola is producing flat out, and that Indonesia, Iraq, Nigeria and Venezuela face impediments to raising supply in the short term, effective spare capacity is seen at 2.8 mb/d, some 300 kb/d above January levels. Essentially the increase in spare capacity since last month derives from lower actual OPEC production. However, we have raised Iranian capacity by 50 kb/d to 3.95 kb/d on signs that the Soroush/Nowruz fields are now producing close to 190 kb/d capacity. Moreover OPEC capacity could potentially rise to 35.0 mb/d by end-2007, based on net increases from Angola, UAE, Qatar, Saudi Arabia, Kuwait and Libya. This pre-supposes that currently-shuttered Nigerian capacity in the Niger Delta region remains unavailable for the duration of 2007. A more detailed look at OPEC capacity developments will be included in an upcoming OMR and the subsequent MTOMR in July.
Production from Angola is estimated at 1.57 mb/d in February, 55 kb/d above January levels. With a series of new field start-ups scheduled for the first half of 2007 (build-up from the already-producing Dalia, plus start at the BBLT, Rosa and Greater Plutonia fields), Angolan production could reach 1.9 mb/d by the end of the year. However, it is believed that ongoing development projects at the time of Angola's accession to OPEC were ruled exempt ('grandfathered') from OPEC production curbs. This suggests that Angola may have a free hand to expand production to around 2.0-2.1 mb/d (attainable sometime in the first half of 2008) before it becomes subject to any future OPEC production restraint measures.
Iraqi crude supply broke a four-month run of decline, rising by 185 kb/d from an upward-revised January to reach 1.88 mb/d. With domestic refinery runs believed to have remained suppressed, the increase came entirely from higher exports via the southern ports of Basrah and Khor al-Amayah. These reached 1.5 mb/d versus less than 1.2 mb/d in January. January levels were adversely affected by port closures for the installation of metering equipment and by weather-related loading delays. However, not all was good news on the export front and February saw scant replenishment of Ceyhan storage after the lifting of 3 mb (97 kb/d) of Kirkuk crude by Mediterranean refiners in January. The Kirkuk-Ceyhan pipeline remained out of operation for most of February, leaving stocks at Ceyhan barely above 1 mb.
A report to the US Congress has painted a less-than-optimistic picture of progress over the past year in rehabilitating the Iraqi oil sector. Significant improvements in production and exports in 2007 are deemed unlikely. Well workovers, water injection and gas-oil separator projects hold the potential to boost wellhead production in 2007, but delays, insurgency and a lack of essential maintenance are seen as potentially impeding the supply outlook. A production target of 2.7 mb/d for 2006 has been downgraded to 2.1 mb/d for 2007, in line with gross output last year. Some sources see imminent passage of a new hydrocarbon law as providing scope to boost foreign investment, but outstanding disagreements and a lack of security cloud the picture (see below).
Iraq's Draft Hydrocarbon Law
Iraq's cabinet on 26 February approved a draft upstream hydrocarbon law which will be submitted to parliament in mid-March, potentially aiming for approval by end-May. While inevitably a compromise between centralist and regionalist interests, the draft confirms a much more state-orientated hydrocarbon sector than the laissez-faire model envisaged immediately after the toppling of Saddam. The law re-establishes the Iraqi National Oil Company (INOC) and creates a Federal Oil and Gas Council (FOGC) which will control the licensing process and approve development plans submitted by the Oil Ministry. INOC meanwhile will have total operational responsibility for existing fields and for selected, partially-developed fields including Majnoon and West Qurna which had previously been allocated to foreign developers under the Saddam regime. INOC will initially control 87% of Iraq's 115 billion barrels of proven oil reserves, also operating the pipeline network.
Oil revenues are to be pooled in a central account before redistribution to the regions on the basis of population. But details of the revenue sharing mechanisms have yet to be decided. Uncertainty surrounds the form of model contracts for new field developments. Regional authorities will be empowered to enter agreements with independent producing companies, subject to compliance with the Federal Law. A clause ruling out Production Sharing Agreements (PSAs) was reportedly dropped, assuaging the Kurdistan Representative Government (KRG), which has entered into deals for new field developments with five foreign companies. However, FOGC will reportedly only require a 66% majority to veto new contracts reached between foreign/private producers and regional governments. Attempts by parliament to claw back greater central control could lead to the KRG removing its guarded approval for the current draft, embarking on a go-it-alone approach.
Most commentators therefore see the new law as far from being a 'done deal', suggesting that strong lobbying will continue by more centralist tendencies to limit regional authorities' room for manoeuvre. Service contracts may become the preferred contract model, or the terms of deals giving equity to independent producers, such as PSAs, may be heavily skewed in the state's favour. All of this may prove academic until there is fundamental improvement in Iraq's domestic security situation (to which end the government recently closed its borders with Syria and Iran). The next step will be to remove the continuing ambiguities on contract terms and demarcation of responsibility between local and central authorities. Only then will a significant influx of development capital into Iraq's under-appraised and under-exploited oil and gas resources be possible.
Nigerian supply back to mid-2006 was adjusted higher by around 50 kb/d after re-examination of output levels, notably from newer deepwater fields. The January supply estimate was also revised up on a reassessment of shuttered production at the Obagi facility in the Bonny system (now believed at 40 kb/d against an earlier 95 kb/d). The January supply figure now stands at 2.28 mb/d compared with an original estimate of 2.15 mb/d. Notwithstanding these adjustments, over 600 kb/d of capacity remained shut-in during February, the result of a year's worth of security-related incidents in the Niger Delta. Total February supply is assessed at 2.25 mb/d, 25 kb/d below January. This was despite Chevron having restarted 13 kb/d of previously shuttered Escravos supply at the Makaraba flow station. NNPC had earlier flagged 250-300 kb/d cuts versus the original February and March export programmes, ostensibly in support of OPEC supply curbs, but likely with one eye on actual supply capability bearing in mind worsening security and production problems.
Subsequently on 5 March, Shell shut the Nembe Creek pipeline and 187 kb/d of Bonny Light production after an oil spill, taking total offline capacity to some 800 kb/d. Access to the pipeline has been restricted by local community groups. As mentioned in the MTOMR, we have assumed that 500 kb/d of Delta capacity remains offline through to 2007, with only slow reactivation occurring during the course of 2008 and 2009. A potential exodus of service personnel due to a worsening security situation in the run up to April's presidential elections may make even this scenario optimistic. Moreover, actual shut-ins are now markedly higher. We will be considering these factors when producing a revised OPEC capacity update in the next couple of months.
Venezuelan supply is assessed to have fallen by 65 kb/d in February as enforced curbs on supply from the four Orinoco heavy oil upgrader projects, announced in January, took effect. Cuts of over 100 kb/d were spread across the four projects (which are also in the process of being partially renationalised, see below), while state firm PDVSA also announced that it was cutting heavy Boscan crude supply by over 30 kb/d. Total Venezuelan crude production for February is estimated at 2.43 mb/d. There were indications from Exxon in early March that production rates at its 120 kb/d Cerro Negro upgrader facility may have fallen even further, and that it was producing just enough heavy oil to keep the upgrading unit operational.
A Farewell to Apertura
Venezuelan President Hugo Chávez has decreed that the four Orinoco heavy oil projects, which produce up to 570kb/d of synthetic crude, will be under majority state control by 1 May. Announcing in February that "the privatisation of oil in Venezuela has come to an end", Chávez has forced foreign companies to cede operational control over the joint venture projects to state company PDVSA. The state company currently holds minority stakes as follows:
- 42% of Cerro Negro, alongside ExxonMobil and BP;
- 30% of Hamaca, alongside Chevron and ConocoPhillips;
- 38% of Sincor, alongside Total and Statoil;
- 50% of Petrozuata, alongside ConocoPhillips.
The past couple of weeks have seen all the major operators bow to the inevitable and commence negotiations for a transfer of 60% majority control to PDVSA by 1 May, although negotiations over compensation may carry on until 26 June. The 270 billion bbl resource base in the Orinoco dictates that no company would want to write-off entirely the reserves booked to date, with an eye also on possible increased, albeit minority, entitlements in future. The Orinoco changes follow PDVSA's 2006 claw-back of control of service contracts with 20 foreign companies and increases in tax and royalty rates for oil production. Generous early-life fiscal terms were expected to change, indeed increases from the original 1% royalty rate at the Orinoco projects were themselves hardly a surprise. Chávez also declared "we don't want the companies to leave" while reasserting PDVSA's predominance over minority partners. The Venezuelans have also argued that improved recovery rates from existing developments (presently 10% or less in the Faja) should take priority over tapping new reserves.
Chávez doubtless hopes that increasing supply from the Orinoco Belt, or Faja, can continue to sustain upstream growth in the years ahead, with an upstream capacity target of some 5.8 mb/d for 2012. Although the Faja has been one bright spot in an otherwise mediocre upstream performance in recent years, the international companies have understandably placed a moratorium on further Orinoco investment until the new rules of engagement have been settled. In the meantime, Chávez has set a group of politically sympathetic NOCs the task of evaluating Orinoco reserves, albeit some of these new partners lack experience in the technology peculiar to heavy oil exploitation.
One further question concerns funding. PDVSA has already been saddled with a host of 'extra curricular' social spending obligations. Like Pemex in Mexico, its ability to translate higher revenues into extra barrels of production is constrained. It has taken over a $2.5 billion liability to finance and manage power and telecommunication sector nationalisations, is struggling to pay out the $6 billion for last year's migration of service contracts to joint ventures and has seen its capital spending requirements balloon with a host of diplomatically-driven foreign refining and products supply ventures. Add in an estimated $30 billion required to buy-out the IOC Orinoco shares and it is clear that cash is tight. Reports suggest the Venezuelan current account barely balanced in 2005 and 2006, despite record oil prices. No surprise then that the companies are being offered crude and future tax credits instead of cash for their shares, and that, as in Russia, the spectre of hastily discovered back-tax demands on operating companies has emerged.
US - Alaska February actual, others estimated: Preliminary data through to December now suggest that US oil production averaged 7.37 mb/d in 2006 (including 5.14 mb/d of crude), increasing only modestly from 2005's hurricane-affected 7.32 mb/d. While Gulf of Mexico (GOM) liquids plus NGL and ethanol showed healthy growth, amounting to a combined 200 kb/d, weaker Alaskan and Californian output acted as a drag on total supply. Overall, 2007 crude supply could level-off close to last year's 5.14 mb/d, with ethanol and gas liquids growth boosting total supply to 7.45 mb/d.
A potential lessening of pipeline-related outages from Alaska is assumed for 2007, and together with modest 30 kb/d growth from the Gulf of Mexico, this offsets ongoing crude output decline from the other lower 48 states. Recent deferrals for the Atlantis and Thunder Horse projects push back more substantial GOM growth into 2008. NGL and other liquids (including ethanol) rise by 25 kb/d and 50 kb/d to 1.8 mb/d and 0.6 mb/d respectively in 2007. All told, the US liquids production forecast has been trimmed by 40 kb/d from last month, largely on the basis of lower NGL projections.
On a monthly basis, February was characterised by further output disruptions. Occidental's Elk Hills field in California (45 kb/d of crude, 25 kb/d of NGL and 280 mcfd of gas) was shut in following a pipeline explosion on 6 February, but had resumed operations later in the month. In Alaska, compressor problems at BP's Northstar field in the Beaufort Sea led to the field being shut-in for three weeks from 17 February. Together, the incidents trimmed a further 50 kb/d from February supply versus last month's expectations.
Canada - December actual: NGL adjustments also affect the Canadian forecast, with a 25 kb/d downward revision for 4Q06 being extended through 2007 and pushing forecast gas liquids supply down to some 680 kb/d after modest growth hitherto this decade. However, conventional crude supply is expected to rise by 120 kb/d in 2007 to average 1.9 mb/d, with growth centred on Albertan bitumen and offshore Newfoundland crude. Synthetic crude production from the three mining projects (excluded from the conventional crude category) adds a further 20 kb/d to reach 680 kb/d. In total, Canadian oil supply matches 2006's growth of 120 kb/d and averages 3.3 mb/d in 2007. This is rather lower growth than suggested by a recent National Energy Board (NEB) forecast, although the outage/maintenance assumptions in that forecast are not known.
Offshore Newfoundland production in January came in 50 kb/d higher than this report's expectation, spread across the three fields of Hibernia, Terra Nova and White Rose. Technical problems at the former two fields proved to have less of an impact than expected. However, Hibernia production is likely to have averaged 45% below normal 180 kb/d levels in February/March as maintenance there has been brought forward from September. Albertan synthetic crude supply in January was also impeded at the Syncrude and Suncor units by maintenance and a diluent unit fire respectively.
Mexico - January actual: As anticipated in last month's report, Mexican supply rebounded after a disrupted December, reaching 3.14 mb/d of crude and 0.41 mb/d of NGL, a rise of 170 kb/d from the previous month. Crude exports also increased, by 55 kb/d month on month to 1.58 mb/d, albeit standing a hefty 470 kb/d below year-ago levels.
The forecast for Mexican supply is largely unchanged from last month, with crude and NGL combined expected to fall by around 215 kb/d year on year, averaging 3.47 mb/d. However, while doubts continue to surround state company Pemex's ability to stem decline at the 1.5 mb/d Cantarell field, there were reports in February that production at Ku-Maloob-Zap (KMZ) fields stood at between 450-500 kb/d in February. This report persists for now with a rather lower assumed 415 kb/d for KMZ in 2007, although if sustained higher production is confirmed, the Mexican projection may be revised higher. However, with Pemex saying it needs to spend $15 billion on exploration and production annually just to maintain current output, cash shortfall and correspondingly steeper decline in baseload Cantarell could act as a negative offset to any KMZ revision.
UK - December actual: We have revised up estimates for UK offshore-loaded crude (based on a higher baseline from November field-specific data) and also for the Forties crude stream as Buzzard field build-up has exceeded our expectations. However, this is offset by now-lower estimates for the Brent/Ninian systems and for NGL supply. The UK production forecast remains largely unchanged at 1.66 mb/d in 2006 and 1.7 mb/d in 2007.
This year sees a levelling off in production after uninterrupted decline so far this decade. Without the impact of rising Buzzard supply and a number of smaller scale increments, UK production would otherwise be facing a repeat of the 200 kb/d annual decreases seen in each of the past four years. Over and above Buzzard, which is on course to reach mid-year capacity output of some 200 kb/d, imminent start-up is also expected at the 40 kb/d Tweedsmuir field. This will be followed through the course of the year by new liquids supplies from the Affleck, Blane, Brenda, Brodgar, Chestnut, Chiswick, Curlew, Enoch, Perth and Starling fields.
Norway - December actual, January provisional: Forecast production from Norway has been held largely unchanged at 2.3 mb/d of crude in 2006 (2.8 mb/d for total oil) and 2.15 mb/d in 2007 (2.7 mb/d total oil). Growth centred on the Sleipner-Frigg systems and from condensate and NGL helps to stem a decline of 200 kb/d evident in the past two years. Higher oil and gas sector spending is now expected for 2007, both compared with 2005/2006 levels and to earlier estimates for this year. Development and maintenance spend is seen accounting for much of the 9% yearly increase for 2007.
Resource Nationalism: Neither New Nor Irreversible
Resource nationalism has become a key oil market buzzword of late, but it is neither new, nor solely the preserve of the more rigidly centralised economies. Few would dispute the right of any government to manage its natural resources in the best interests of its citizens. Previous phases of resource nationalism have included Mexican nationalisation in the 1940s and the creation of OPEC in 1960. The latest episodes in the 1970s, and again in the 2000s, have coincided with tighter markets and higher prices. There is a degree of 'chicken and egg' about nationalism and high prices, but the potential for a self-perpetuating cycle is clear.
This month's report highlights corporate developments in Norway at the more benign end of the scale, through to a new hydrocarbon law in Iraq, the rising economic challenges facing Mexican monopoly Pemex, and on to the increasingly NOC-dominated Russia and Venezuela. Each encapsulates the wide range of national policy approaches to hydrocarbon resource management.
It would be wrong to see resource nationalism in overly simplistic terms. All governments, OECD and non-OECD alike, tend to use higher oil prices as a pretext to shift revenue flows in their favour. But an increasingly dominant national oil company, sudden and unilateral changes in the upstream operating regime and barriers to, or higher costs for, upstream entry characterise resource nationalism in its more extreme form. So too can the actions of consumer country NOCs and monopoly pipeline operators, reacting to security of supply concerns or perhaps using them to expand geopolitical influence abroad. That said, a shift in the fiscal/operating regime, by itself, does not necessarily signify overt resource nationalism: it is usual for upstream contracts to evolve as a country matures from frontier to established producer, and on to the late-production stage.
Nonetheless, a host government's aspirations for increased rents and control can perpetuate high prices in the short and medium term. These may lead to distorted flows of upstream investment capital, particularly if returns are used to directly fund social programmes which become embedded in national spending. Often political and social spending needs grow to the point where oil exploration and development investment is compromised, which can in turn reduce oil and gas exports. In the 1970s high prices also encouraged both demand-restraint and new frontier oilfield exploration (ironically spawning a new breed of national oil company (NOC) to develop the North Sea, Brazil etc).
Eventually the downswing in the cycle tends to lead to lower prices and revenue streams, encouraging host governments to re-introduce more open-access and international company-friendly policies. International expertise is sought to stem mature field decline, to exploit more difficult-to-find oil or to manage complex, integrated oil, gas and petrochemical projects - areas in which the international companies still bring much to the table.
Arguably, the nationalistic cycle may prove prolonged this time around. Banks remain happy to fund new projects, regardless of the promoter, so long as default is unlikely. Rising supply and revenue streams have further to run in key producing countries. And technical and intellectual capital is accessible via service companies that have expanded their research and development expertise (filling the void as some international oil companies have cut back).
Ultimately, what counts is sustained levels of upstream investment. Returns are likely to be optimised for all participants through a combination of careful resource management, unhindered access to intellectual and financial capital and balanced contractual arrangements. The balance is never easy to strike, but it is one the IEA seeks to encourage through:
- ongoing dialogue to persuade major non-OECD producer and consumer governments of the mutual benefits of equal and open access to upstream reserves and;
- continued efforts among its own members to encourage diversification of oil and energy supply and investments in improving energy efficiency.
A proposed merger of the oil and gas assets of Statoil and Norsk Hydro is expected to be presented in a White Paper to the Norwegian parliament by Easter. In the absence of divestments, the new entity would account for around 70% of Norwegian liquids production, with the Norwegian government holding 62.5% ownership of the merged company.
Statoil reported in January that the oil reserves at the Snohvit gas field were likely to be uneconomic to develop. However, government representations to Statoil to reconsider appear to have been successful and the company will now drill an appraisal well targeting an estimated 100 million bbls of recoverable oil reserves. Both developments signal an apparent reinforcement of state influence over hydrocarbon developments offshore Norway.
Former Soviet Union (FSU)
Russia - January actual, February provisional: February Russian production came in 200 kb/d above the level forecast in last month's report. Production (including condensate) reached 9.9 mb/d in February, some 60 kb/d above December levels and January and February production stood a clear 400 kb/d (4%) above start-year 2006. However, the apparent 'bounce' in January/February production needs to be kept in context:
- producers were reported to have restrained 4Q06 production to take advantage of favourable production tax changes at new year;
- the impediment of exceptionally cold weather to 1Q oil production seen in 2006 was absent (indeed 1Q07 supply might have been higher still had the opposite phenomenon - early tundra thaw - not constrained oilfield work);
- the Sakhalin 1 project provided a step-up for early 2007 production, with the rapid increase of production towards 225 kb/d since export restrictions were lifted towards the end of 2006.
Hence, inflated early 2007 growth rates may not be sustainable going forward. We also note that downward adjustments made last month to Rosneft and Surgutneftegaz February/March supply on news of impending power supply maintenance were not translated into materially lower supply, at least in February. We have kept supply from these two producers suppressed in March, but may ultimately revise these higher.
Although higher baseline February production from Lukoil, Tatneft and Sakhalin 1 add 25 kb/d to expected 2007 production, growth for the year has been held largely unchanged at 2.6% pa. This is in line with the prevailing view of the Ministry of Economic Development and Trade, which in the past has tended to be fairly conservative in its growth forecasts. There remain concerns outside the Russian government over the upstream operating environment, and an apparently growing appetite on the part of the government to dilute foreign company involvement (Total at Kharyaga and TNK-BP at the Kovytka gas project look likely to be forced to relinquish control in much the way Sakhalin operators were, while foreign companies are likely to step aside in favour of state-sponsored Rosneft and Gazprom in the upcoming auction of assets of the bankrupt Yukos). That said, there does appear to be the potential for sustained, if modest, growth in a 2-3% range over the next three to four years, notwithstanding a tendency by producers to over-estimate growth prospects, notably in the current tight international drilling and service sector market.
Consolidated data for December net FSU exports show a 100 kb/d downward revision from last month's preliminary estimate. Total December flows now come in at marginally below 8.2 mb/d. January saw net exports increase by a further 250 kb/d to 8.4 mb/d, with crude shipments increasing notably from Black Sea ports (+260 kb/d), from Sakhalin (+100 kb/d) and with increased rail and barge shipments outside the main Transneft system (+150 kb/d). Russia's temporary cut-off of crude supplies to central Europe via the Druzhba pipeline in January resulted in a 140 kb/d month-on-month drop by that route to 1.11 mb/d, while BTC shipments from Azerbaijan also fell by nearly 100 kb/d. Product exports remained broadly flat in January at 2.36 mb/d. Lower export duties from 1 February are likely to have seen a further rise in FSU exports last month. Although seaborne export schedules for Russian crude were off by 100 kb/d for the month, rising supplies of crude via Sakhalin and the CPC, BTC and Druzhba pipelines could have pushed total net exports higher by 100-200 kb/d. March may see a further lull in export growth before Russian export duties are cut again from start-April.
Kazakhstan - February actual: A 25 kb/d downward adjustment in 2007 supply from Kazakhstan cancels out the impact of higher Russian production. January data came in 80 kb/d below expectation, partly because of outages affecting the Orenburg gas processing facilities in Russia, destination for some of the liquids from the Karachaganak field. However, Karachaganak production rebounded in February from 245 kb/d to 295 kb/d. We anticipate a levelling off in Kazakhstan liquids supply for 2007, at around 1.34 mb/d after 50-60 kb/d growth in both 2005 and 2006. Both of the country's key producing fields, Tengiz and Karachaganak, will expand capacity in years to come but face bottlenecks in export capacity. BG and Agip announced in February plans for an interim 110 kb/d rail export route. This follows Russian-instigated delays in expanding the independent CPC pipeline to Novorossiysk.
Expansion of the 290 kb/d Tengiz field is also stalled by slow progress on CPC. Moreover, there are signs that some of the environmental-related license issues foreign operators have recently faced in Russia are finding a parallel in Kazakhstan. Chevron has been given one month to come up with a plan to dispose of sulphur by-product from Tengiz or else it will have its license suspended.
Meanwhile, operator Eni has acknowledged that start-up of the Kashagan field will be delayed to late 2010, with initial plateau output of 350 kb/d to be attained a year later. The original start-up had been 2008, although delays have been flagged well ahead of Eni's official announcement (the MTOMR anticipated this, showing significant Kashagan volumes only from 2011). Phase one development costs have risen from $10.3 billion, first to $15 billion and now to $19 billion. Total development costs have also risen from $29 billion to $31 billion, although anticipated peak production has also risen from 1.2 mb/d to 1.5 mb/d. Kashagan volumes were to have been exported via an expanded CPC line but alternative shipment options via the BTC pipeline are now planned.
China - January actual: Steady growth in Chinese production is now expected for 2007. Output is scheduled to average 3.76 mb/d this year, up 90 kb/d from last year's 3.67 mb/d and 3.62 mb/d in 2005. Offshore increases come from the Bozhong and Caofeidan fields, while rising onshore production in the west and northwest helps to offset weakening eastern onshore mature field supply. January production came in 140 kb/d higher than anticipated, with the ageing Daqing, and also the Jilin and Changqing, fields responsible for most of the upward revision. In all, the Chinese forecast has been raised by 50 kb/d for 2007. It is thought that January's surge to 275 kb/d from Changqing may prove temporary, as year-average production is estimated by operator PetroChina at only 240 kb/d. This is nonetheless some 30 kb/d higher than in 2006. One minor downside adjustment for China concerns the north-eastern Liaohe field, where 1,385 wells were shut in during early March due to heavy snowfall. The five day shut-in affected around 40 kb/d of Liaohe's total 240 kb/d production.
Revisions to Other Non-OPEC Estimates
In total, non-OPEC supply estimates are revised only marginally this month. A 25 kb/d downward adjustment for 2005 takes non-OPEC supply to 50.2 mb/d (or 49.0 mb/d excluding Angola). A similar reduction affects 2006 (taking supply to 49.4 mb/d net of Angola), with revisions concentrated in North America. The 2005 adjustment derives from revised data from Petronas and the Central Bank for Malaysia. However, Malaysian revisions move in the opposite direction from 4Q06 onwards, pushing up the 2007 production estimate by 20 kb/d to 775 kb/d. Preliminary January data for Brazil came in 75 kb/d lower than expected, although this was due to maintenance work at the P-37 platform at the Marlim field which was not captured in the forecast previously. Therefore, the downward adjustment is restricted to January. At +190 kb/d, Brazil remains one of the key contributors to 2007 non-OPEC growth. Modest downward adjustments to December 2006 supply from Colombia and Ecuador also knock around 10 kb/d off the 2007 projection.
- Total OECD inventories fell by 8.6 mb in January, largely due to a crude stock draw in Europe, and to a lesser degree in the Pacific. The two regions however both saw product stocks increase, partly on the unusually warm weather. In contrast, North America saw a crude build and a minor decline in product stocks, as refinery maintenance commenced in earnest in January, and the second half of the month turned cold.
- Following a crude inventory draw of 23.8 mb in January, OECD stock levels are now 14.5 mb lower year-on-year, but still in the upper half of their five-year average range. The most pronounced difference is again in Europe, where crude stocks are at the bottom of the five-year average range and 23.2 mb lower year-on-year.
- Total product stocks rose by 13.7 mb in January, but are now only 32.9 mb higher than at the end of January 2006, thus halving the year-on-year difference from last month's report. Nevertheless, total product stocks remain above the five-year range for all three regions.
- Revisions to December data were marginal overall at +3.0 mb, with upward revisions of 4.0 mb and 7.0 mb in crude and product stocks respectively, offset by a -8.1 mb downward revision in 'other oils'. Regionally, most of the upward revision was centred on Europe, while North America and the Pacific were revised downward.
- Total forward demand cover is broadly unchanged at the end of January at 54 days from both the previous month and one year ago. Nominally, OECD total stocks were 26.1 mb higher year-on-year at the end of January.
- Preliminary February data indicate an even greater monthly drawdown of around 66 mb in the key OECD countries, largely in products. In the US, strong demand coincided with refinery maintenance and several unplanned outages, drawing down product stocks by 45.5 mb. In Japan, refiners reduced throughputs after stocks reached high levels on low demand, while in Europe, plants were also undergoing maintenance.
OECD Industry Stock Changes in January 2007
OECD North America
North American crude oil inventories rose by 9.1 mb in January, with stock builds of 7.0 mb and 2.1 mb in the US and Mexico respectively. In the US, the increase resulted from lower-than-expected refinery runs, as the weather was unseasonably warm in the first half of January, while some unexpected refinery outages reduced utilisation in the second half of the month. Weekly data for February show US crude stocks up by 935 kb, as refinery maintenance reached a peak while crude imports fell. A crude draw of 2.6 mb in PADD 3, the Gulf Coast, was offset by increases of 2.0 mb and 1.0 mb respectively on the West and East Coasts.
North American product inventories fell by 1.6 mb in January, of which 1.0 mb was in the US and 0.6 mb in Mexico. Distillate stocks in the US were down by 0.9 mb after the swing back to cold temperatures in the latter half of the month. Meanwhile, total US gasoline stocks rose by 15.7 mb, as refiners were able (in the first half of the month) to concentrate on bolstering gasoline production ahead of the summer. This gain was however offset by 'other products', which fell by 15.2 mb. In Mexico, small increases in gasoline and residues were balanced by a dip of 1.2 mb in distillates. Total North American product stocks at the end of January stood only 2.8 mb higher year-on-year.
Weekly US data for February show that the net effect of strong demand, peak seasonal refinery maintenance, and several refinery outages has drawn down total product stocks by 46.5 mb. The return of cold weather saw heating oil inventories fall by 10.2 mb, which added to a draw in total diesel stocks of 3.6 mb. Gasoline fell by 9.0 mb and residual fuel oil by 7.1 mb. And at the end of February, total product stocks at 660 mb have now moved below their five-year average. In terms of forward demand cover, gasoline and distillate are now each slightly below their respective five-year averages of 24 and 29 days. While refinery maintenance passed its seasonal peak in February, increased runs will also be met with higher gasoline demand and the need to produce lower-yielding summer-grade material.
European crude oil stocks fell by 29.0 mb in January, and are now 23.2 mb lower year-on-year. Strong draws were reported from France (-5.4 mb), the Netherlands (-4.4 mb), Germany (-3.0 mb) and the UK (-2.6 mb). Refinery runs were more or less unchanged in January, even though European product demand was weak due to the unseasonably warm temperatures across most of the continent. It is possible that refineries were deliberately running down crude stocks ahead of seasonal maintenance starting in February. On the other hand, North Sea production was down slightly, as was OPEC output in December. Reduced volumes through the Druzhba pipeline in January could also explain some of the difference.
Product inventories in Europe rose by 7.5 mb in January as increases in gasoline (+4.4 mb), distillates (+2.7 mb) and residual fuel (+0.6 mb) offset a small drop in 'other product' stocks (-0.3 mb). Nationally, inventories increased most in the Netherlands (+3.0 mb) and Germany (+1.1 mb), on gains in middle distillate stocks. UK gasoline stocks rose by 1.5 mb, but were offset by draws of 1.0 mb and 0.7 mb in residual fuel and distillate stocks respectively. Total French product stocks were down by 1.2 mb, as a dip in middle distillate stocks (-2.4 mb) outweighed a 1.0 mb increase in residual fuel levels.
In the Pacific, inventories of crude oil also fell in January, but only by 3.9 mb. Unlike the other two OECD regions, crude inventories are still 13.8 mb higher year-on-year. The fall in stocks was evenly spread between Japan and South Korea, with each seeing a draw of around 2.0 mb. In both countries, news reports indicated economic run cuts as warm temperatures constrained demand. In Japan in particular, crude and all product stock categories remained higher than at the end of January 2006. Weekly Petroleum Association of Japan (PAJ) data show that crude stocks remained flat in February (+0.2 mb), despite lower runs.
Total product inventories in the OECD Pacific rose by 7.8 mb in January, almost solely due to strong gains in middle distillates, but also on an unusually large drop in transportation fuel demand in Japan. Japanese product stocks rose by 4.6 mb, with increases in middle distillates and gasoline of 3.2 mb and 2.4 mb respectively offsetting slight losses in residues and 'other products'. In Korea, the picture was more or less the same. Total products rose by 3.2 mb as middle distillate and gasoline inventories rose by 4.4 mb and 0.6 mb respectively. 'Other products' and residual fuel oil meanwhile fell by 1.6 mb and 0.3 mb.
Weekly PAJ data for February show that the trend of January was reversed. Total finished product stocks fell by 9.2 mb as refineries lowered throughputs, in part for economic reasons. The largest draw was in heating fuel kerosene inventories (-7.1 mb), which had previously been unusually high due to the warm winter. Accordingly, refineries tried to boost jet fuel output, stocks of which remained flat on the month, and also hiked kerosene exports in early February. Meanwhile, gasoil and gasoline inventories fell by 1.3 mb and 0.7 mb respectively, while naphtha and fuel oil levels each increased by 0.4 mb.
OECD Inventory Position at End-January and Revisions to Preliminary Data
Total OECD industry stocks stood at 2,668.1 mb at the end of January, down 8.6 mb from the end of December, but were still 26.1 mb higher than at the end of January 2006. The year-on-year difference has narrowed sharply from 78.5 mb, compared with last month's report. OECD crude inventories were at 924.5 mb, after falling by 23.8 mb in January, and have fallen below levels of a year ago for the first time since November 2005, even while they remain at the upper end of their five-year range. Total product stocks rose by 13.7 mb to 1,457.4 mb in January and now stand 32.9 mb higher year-on-year.
Revisions to December stock data show only a marginal upward revision of 3.0 mb. This was due to the crude oil (+4.0 mb) and product figures (+7.0 mb) coming in higher, though they were partly offset by a downward revision to the 'other oils' number by 8.1 mb. Regionally, a large upward revision to crude stocks in Europe (+10.3 mb) is noteworthy, contrasting with downward revisions to crude in both the Pacific (-3.7 mb) and North America (-2.5 mb). North America in turn saw products revised up by 6.1 mb, while the changes in Europe (+1.2 mb) and the Pacific (-0.3 mb) were more marginal.
Recent Developments in ARA Independent Storage
Total oil product inventories held in independent storage in the Amsterdam-Rotterdam-Antwerp (ARA) area fell by 1.4 mb. Most of this was due to fuel oil stocks dipping by 1.3 mb, as recent weeks have again seen a steady stream of exports to the Far East. Inventories of the other product categories all remained more or less unchanged. However, gasoil inventories have moved above their five-year range on the warm weather in Europe. Naphtha levels in contrast have fallen to the bottom of the range, also on exports to Asia, where cracks have been unusually wide.
Recent Developments in Singapore Stocks
According to International Enterprise, total oil product stocks held in Singapore rose by 1.1 mb, mostly on the back of rising fuel oil levels (+0.6 mb). Late February had seen an unusually strong surge of 4.3 mb in residual fuel oil, after higher volumes from Europe poured in, but this fell again a week later. Meanwhile, light and middle distillate stocks each rose by 0.2 mb.
Regional OECD End-of-Month Industry Stocks
(in days of forward demand and millions of barrels of total oil)
- Oil prices rose above $60/bbl from a mid-January low on OPEC cuts, and as the US product market was tightened by strong demand, peak seasonal refinery maintenance and several unplanned downstream outages. These factors offset unusually warm weather in Europe and Northeast Asia, while oil markets took little notice of stock market tremors emanating from China. Further OPEC cuts in February prevented the normal seasonal crude stock build and were only partially offset by refinery maintenance.
- Product markets are driving crude prices, on the back of rising gasoline cracks in all regions. However, in contrast to the strong US and European markets, Japanese and Korean refiners are reportedly making voluntary run cuts, as weak demand has left stocks unusually high. Crude demand is expected to remain broadly flat from February levels until refinery maintenance eases from May onwards.
- Refining margins rose in February and early March and are high in the US and Europe. Healthy gasoline and, to a lesser extent, jet fuel and diesel cracks, are responsible, particularly on the US West Coast. Sour cracking margins in Europe are also high, while Asian spreads mostly remain depressed.
- Gasoline's rally outpaced a strong performance by other transportation fuels. Regionally, strong demand has boosted US diesel premiums, but in contrast jet fuel premiums were higher in Europe and, until early March, in Asia. Weak demand for fuel oil offset the impact of OPEC cuts of heavy crude, leaving cracks unchanged.
- Dirty freight rates from the Middle East Gulf remain well below five-year seasonal averages, undermined by reductions to crude trade caused by OPEC cuts and refinery maintenance. Clean rates were supported by refinery turnarounds and competition from West Africa for product vessels leaving Europe.
Crude prices have inched up from early February, but have spent most of the past month hovering around the $60/bbl mark on average. The market was overwhelmingly driven by product prices in the US, where strong demand coincided with peak refinery maintenance and several downstream outages. After an unusually warm December and first half of January, the weather has subsequently turned cold in North America, boosting heating oil demand at a time when refiners had already started to increase gasoline yields ahead of the driving season. Lower product output due to maintenance was exacerbated by some unplanned refinery outages, leading to a strong increase in gasoline cracks in particular. In Europe and Asia, the weather has remained unseasonably warm, but both regions have felt the impact of rising prices in the US.
OPEC cuts have further tightened the market, though rising Iraqi and Angolan supply muted reductions from the OPEC-10. Since September, OPEC has cut output by around 1 mb/d. The group could decide to make further cuts when it meets on 15 March, though the most recent statements by ministers indicate this is unlikely. Crude outages in Alaska and Nigeria, both due to pipeline spills, contributed to further upward market pressure, and preliminary data show a downturn in February OECD inventories. Geopolitical tension remains high over Iran, though the prospect of US and Iranian officials meeting on the fringe of a regional security conference on Iraq is a development that appeared unlikely a few months ago. Lastly, in terms of upside to prices, non-commercial participants on the NYMEX WTI market switched to net-long positions in mid-February, arguably supporting the upward tendency in prices.
On the downside, Europe and Northeast Asia have continued to see an unusually warm winter, curbing heating and utility demand. A 9% dip on a Chinese equity index sent tremors through global stock markets in late February, leading to a knee-jerk dip in prices and musings on the fragile state of the world economy. In contrast to the picture of a tight US market painted above, Asian refiners have indicated voluntary run cuts in March.
Spot Crude Oil Prices
The crude market has again been shaped by the need to hike gasoline yields for the US market, while refinery maintenance there was in full swing. Benchmark grades rose more or less in line with crude futures, with Dubai gaining additional support from lower OPEC output. In the Atlantic Basin, WTI has seen its premium over Dated Brent decline, which is usually taken to indicate a less favourable transatlantic arbitrage. This can be partly explained by tight crude stocks in Europe, but it is unusual to see the forward curve perpetuating such a weak premium through to the end of the year.
On the other hand, the Brent-Dubai EFS spread has narrowed slightly again, after widening sharply to $4.50/bbl in late February. Now at half that value, Atlantic Bas in eastbound shipments will have become more viable. This is all the more true when taking into account how high Asian light sweet benchmark Tapis is relative to Atlantic Basin alternatives Dated Brent, Bonny Light or Saharan Blend. Tapis has risen on strong demand for naphtha-rich crudes in Asia, with additional support for Asia-Pacific light sweets coming from Australian crude shut-ins due to Cyclone George.
Weaker demand for distillate and fuel oil for heating and utilities has failed to offset the impact of lower OPEC sour crude production. Bar the Tapis-Dubai spread, which has widened uniquely due to Tapis' strength, other light sweet-heavy sour spreads have been narrowing since early December. Nevertheless, distillate-rich Middle Eastern grades such as medium sours from Abu Dhabi have proved less popular, as particularly Japanese buyers have shown less interest, and are lowering throughputs to bring down distillate and other stocks. In addition, Abu Dhabi is keeping term volumes to Asia in April steady from March, while Omani volumes are reported to be higher following domestic refinery maintenance. At the same time, the new Sokol crude from Sakhalin 1 is proving popular among Asian refiners, generating extra competition.
Delivered Crude Prices in December
For the first time since August, average CIF crude import prices rose in OECD countries, by $2.02/bbl to an average of $57.90/bbl. In Europe, the average crude oil delivery price increased by $3.15/bbl to $59.94/bbl in December. North American refineries paid a CIF import price of $55.10/bbl which was $1.91/bbl higher than in November. In the OECD Pacific, crude oil delivery prices were essentially unchanged, as longer shipping routes from the Middle East to the Pacific delay the impact of rising global oil prices in 4Q on the region's delivered prices.
Atlantic Basin refining margins rose steadily in February and were on average higher than in January. Margins are quite high in the US, especially on the West Coast, where the product market has been particularly tight. In Europe, sour cracking margins are also favourable, while in contrast they remain depressed on the whole in Asia - reflecting high regional product stocks.
Strong gasoline, and to some extent distillate, cracks in the US boosted refining margins in February. On the West Coast, refinery outages at BP's Carson, California, plant combined with maintenance, the region's geographical isolation and tight product specifications to substantially raise margins. Problems at McKee's Sunray, Texas refinery, tightened the Arizona market, which it feeds via pipeline.
Of the margins quoted by this report, average February Oman cracking rose by $5.75/bbl from January, and Kern coking added $7.83/bbl in February to surpass $25/bbl - and both are still rising. Such levels were last seen at the height of last summer and prior to that during the hurricane-related outages of autumn 2005. On the Gulf Coast, margins improved too, with light sweet cracking margins for both domestic and foreign crudes moving back into positive territory in February.
In Europe, sour cracking margins for both Urals and Es Sider are now quite high, benefiting from rising gasoline cracks, but also sustained strength in jet fuel and to a lesser extent diesel. In Asia, with the exception of Dubai hydrocracking (in both Singapore and China), margins mostly deteriorated and remain depressed, reflecting a generally weaker market than in the US or Europe.
Spot Product Prices
Product markets and indeed the whole oil complex are currently driven by gasoline's strength. Tightness in the US market, on a combination of refinery maintenance, unplanned outages, pipeline problems and the switch to summer grade, is reflected by sharply falling stocks and corresponding wider cracks. However, despite a sharp decline in stocks since the start of the year, inventories remain above the five-year average in absolute terms. Less support than usual has come from Europe in terms of arbitrage cargoes, as New York Harbor/Rotterdam spreads only picked up from mid-February, and gasoline stocks in Europe at the end of January were below the five-year average.
On the other hand, the arbitrage has been open from East Asia to the US West Coast, where cracks have been particularly high. The light distillate complex in Asia has also benefited from naphtha's continued strength on strong petrochemical demand and still-constrained supply, despite higher imports from Europe.
Middle distillates were more mixed, with jet fuel cracks still high in most markets, and the performance of diesel/heating oil differing in the various regions. Diesel fuel cracks were highest in the US, where year-on-year demand growth is stronger-than-expected. In contrast, mild weather and high stocks kept middle distillate cracks flat in Europe and Asia. Japanese kerosene sales were the weakest in 24 years in January according to government figures, though inventories fell over the course of February, as refiners reduced throughputs. Jet meanwhile received some support from strong Asian exports to the US West Coast.
Fuel oil's discount to crude was flat or wider in February and early March, as the impact of OPEC cuts of heavier crudes failed to offset weak demand. Low-sulphur fuel oil (LSFO) picked up a bit from mid-February on the US East Coast as utility demand grew. Meanwhile in Asia, LSFO benefited from South Korean and Taiwanese demand just as liquefied natural gas (LNG) exports from Indonesia dropped. Ongoing investigations into Japanese nuclear power plant security data continue and considering the rise in fuel oil demand that resulted from plant closures in 2002, developments will be closely watched by the fuel oil trade. In terms of West-East arbitrage, the Rotterdam-Singapore high-sulphur fuel oil (HSFO) spread has narrowed slightly, but according to market reports, some 3.4 million tonnes are due to arrive in the East in the second half of March, significantly more than in February.
End-User Product Prices in February
As the month saw no major movements in the value of OECD currencies compared with the US dollar, trends in domestic end-user prices reflected changes when valued in US dollars. The ex-tax price of gasoline in US dollars declined by 2% on average in OECD countries surveyed in February. Pre-tax gasoline prices in the US declined by 1.8% to $0.483. Notable were the drops in US dollar wholesale gasoline prices in the UK and Japan (4.0% and 5.3% respectively). The ex-tax price of diesel has dropped by 2.3% on average in the OECD. Heating oil prices moved in opposite trends in OECD countries as prices rose by 1.7% on average in France, Germany, Canada and Italy and fell by 3.5% in Spain, the UK and Japan. The ex-tax US dollar price of fuel oil climbed on average by 3.2% in France, Italy and the UK while dropping by 5.6% in Germany and 1.7% in Spain.
Higher March term volumes from OPEC exporters supported Middle East Gulf tanker rates in late February, but they remain well below seasonal averages. Arbitrage economics up until mid-February encouraged crude exports from Europe and the US and the Far East, but ample vessel supply, due to OPEC cuts and refinery maintenance, prevented rates from climbing dramatically. Clean tanker rates in the Atlantic Basin rose due to reduced product output during OECD refinery maintenance, sustaining demand for product imports, and increased competition for vessels from West Africa.
VLCC rates from the Middle East Gulf fell to $9/tonne to Japan and $15/tonne to US Gulf in the first half of February as OPEC production cuts deepened. The mid-month trough, which mirrored the lull in mid-January, is well below the seasonal five-year average of over $15/tonne and $20/tonne for Japan and the US Gulf respectively.
Interest in Middle East Gulf vessels grew later in the month following reports that Saudi Arabia and UAE would increase crude volumes available to term customers, especially in the East, in March. Japan-bound VLCC rates rose to $12/tonne by early March, by which time, rates for vessels heading to the US Gulf had reached $17/tonne. Further support came from spot chartering by Saudi Vela in early March. The double-hull premium also continues to offer upside to rates for the chartering of better quality vessels.
In the Atlantic basin, the premium of WTI over Brent widened until mid-February, encouraging shipments of North Sea crude to the US, before dropping. At the same February mid-point, eastern grades such as Tapis were very strong relative to Brent, encouraging Brent-related material in the Atlantic Basin to move east. Relatively low mid-month Suezmax rates added further impetus for arbitrage shipments from the region and tanker sailing reports confirmed that trade volumes increased. This added pressure to vessel availability causing Suezmax rates from North Sea to the US Atlantic to rebound from a mid-February trough of under $13/tonne to over $15/tonne by end-month. West Africa to East Asia VLCC rates rose from $18/tonne to over $21/tonne over a similar period.
In the Mediterranean, Suezmax and Aframax rates fell significantly as delays in the Turkish Straits eased. Black Sea to Mediterranean Aframax rates dropped from $17/tonne at the end of January to under $8/tonne at the end of February.
In the clean sector, charter rates rose in the Atlantic Basin but were flat east of Suez. Competition for clean product vessels in the Atlantic intensified as West Africa boosted imports of high-sulphur material from European refiners. In a period of refinery maintenance, US demand for products imports remained strong. Lower temperatures supported US heating oil demand, gasoline demand was firm and jet fuel imports in 2007 have been more than double the five-year average. Rates for 33,000-tonne cargoes from North Europe to US Atlantic rose from $17/tonne at the start of February to $26/tonne at the start of March. Asian clean rates were flatter despite the growing potential for product tightness during refinery turnarounds.
- OECD throughputs in January fell by 0.5 mb/d, to an estimated 39.3 mb/d. The start of refinery maintenance in the US and Europe, and unplanned shutdowns in North America, reduced OECD operating rates. Crude runs in the OECD are expected to have fallen further in February to around 38.4 mb/d, but should recover slightly in March to 38.6 mb/d.
- Refinery problems during February in North America tightened the region's product markets, leading to stronger light product cracks. In particular the fire at Valero's McKee refinery reduced supplies to south western states, boosting West and Gulf Coast product cracks. Increased product imports into the West Coast should help ease market tightness, in the absence of further refinery disruptions.
- OECD refineries boosted jet fuel/kerosene yields in December in response to stronger prices, at the expense of diesel/gasoil. The higher production of jet fuel/kerosene occurred despite warm Pacific weather undermining regional demand. Gasoline yields continued to lag historical levels although some recovery was seen in the US and recent improvements in gasoline cracks suggests further gains will be seen in subsequent data.
- Global offline capacity is expected to peak in March at 3.5 mb/d. Current forecasts show that idled capacity will remain at, or close to, this level through early May, before dipping to around 3 mb/d. Overall refinery maintenance in 2007 appears to have started earlier than in 2006, but is currently forecast to be less severe over the second quarter than last year.
The start of US refinery maintenance and unplanned shutdowns in North America lowered OECD crude throughputs in January by 0.5 mb/d, to an estimated 39.3 mb/d. The decline from December's upwardly revised (+120 kb/d) seasonal peak of 39.7 mb/d is in line with typical seasonal patterns, and leaves January OECD crude runs 82 kb/d below the January 2006 level. Weak demand and high product stocks in the OECD Pacific prompted voluntary run cuts of 250 kb/d in January but their impact was partly offset by returning refinery capacity, keeping throughputs in the region level with those of December.
Crude runs in the OECD are expected to have fallen further in February to around 38.4 mb/d, but should recover slightly in March to 38.6 mb/d. The start of maintenance in the Pacific is then expected to offset rising throughputs in the Atlantic Basin, keeping overall activity roughly unchanged through to May.
OECD North America
North American crude throughputs in January fell by 457 kb/d to an average of 18 mb/d, from December's downwardly revised (-143 kb/d) 18.5 mb/d. Unsurprisingly, the drop in throughputs occurred largely in the US, but runs were also lower in Mexico and Canada. Despite planned maintenance being higher than a year ago, crude throughputs were 112 kb/d above January 2006 when the lingering hurricane effects from 2005 kept almost 800 kb/d of capacity off-line.
US crude runs in January fell as expected, with the start of maintenance work. On the West Coast Chevron's 240 kb/d Richmond and Tesoro's 160 kb/d Golden Eagle refineries both started planned work. On the Gulf Coast Total's 230 kb/d Port Arthur and Shell's 330 kb/d Deer Park refineries also commenced maintenance. Canadian refineries hit problems with runs curtailed at Imperial Oil's Sarnia facility following a fire at the hydrocracker in December and its Edmonton facility also cut runs in early January following problems with the catalytic cracking unit in late December.
Weekly US data indicate that crude runs fell over the course of February, to a low of 14.4 mb/d in the middle of the month, the lowest level of throughput since last March when refinery maintenance work reached its spring 2006 peak. In addition to the planned increases in work on the Gulf and West Coasts, refinery problems at Valero's 170 kb/d McKee and 210 kb/d Delaware refineries, among others, also curtailed crude runs.
West Coast crude runs remained weak, as expected, although the disruptions to three LA refineries in early March caused by the untimely (concurrent) deaths of a racoon and an opossum at two separate Los Angeles electricity sub-stations, were not factored into our forecasts. Much of the stronger margin environment has been attributed to tighter products supplies as a result of the unplanned outages, particularly the McKee refinery problems. This refinery supplies a significant part of the requirements of Arizona, forcing replacement supplies to be sourced from further afield and has raised product prices, both locally and on the US West Coast.
Canadian product markets in Ontario and Montreal were also affected due to successive refinery disruptions. Imperial Oil (a subsidiary of ExxonMobil) refineries in Sarnia and Edmonton were affected by production problems in December and January. Following on from this, Shell Canada's Montreal refinery is reported to have suffered production problems although details remain sketchy. Reports indicate that supplies to some retail stations were reduced leading to selective stock-outs. Re-supply options were further reduced by industrial action at Canadian National Railways which limited some train shipments and hampered industry attempts to maintain product supply.
European crude throughputs averaged 13.9 mb/d in January, unchanged from December's upwardly revised (+249 kb/d) level. The reported start of planned maintenance work at Shell's refineries in the UK, the Netherlands and France, plus work at Eni's Gela refinery resulted in lower runs. However, Belgian runs posted a second consecutive increase as the expanded ExxonMobil Antwerp refinery completed its return from fourth-quarter maintenance, increasing Belgian throughputs by 177 kb/d. Consequently, net regional crude runs were above the level of January 2006 by 180 kb/d.
January crude throughput in the OECD Pacific region was broadly unchanged from December's at 7.3 mb/d but 304 kb/d below a year ago, as runs were restrained by high stocks, weak demand and poor hydroskimming margins in the region.
Japanese crude runs of 4.2 mb/d in January were broadly unchanged from December's level, with the return to full service of Cosmo's Chiba refinery offsetting 150 kb/d of run cuts. Japanese capacity utilisation was 89.7% in January, in line with December, but well below January 2006's level of 94.2%.
Weekly data from the Petroleum Association of Japan show that crude runs in February were essentially unchanged from January, at 4.2 mb/d. In addition to Nippon Oil's self-imposed run cuts, Showa Shell and Japan Energy were also reported to have trimmed runs during February. In total, cuts from planned crude runs of around 160 kb/d are thought to have occurred, with Nippon Oil contributing some 140 kb/d of these. The need for further runs cuts may be obviated by the pending start of the second-quarter maintenance season.
Korean runs were also largely unchanged, rising 27 kb/d to an average of 2.5 mb/d. Economic run cuts are estimated to have fallen by 10 kb/d to 86 kb/d in the month. Similarly to Japan, warm weather and weak demand for kerosene stifled the incentive for refiners to seasonally maximise runs. As a result of this slight reduction in crude run cuts, Korea's capacity utilisation rate increased to 96.8% in January. Korean refiners have also continued with run cuts in February, with our estimates suggesting a 100 kb/d reduction in runs and the possibility of 120 kb/d in March.
OECD Refinery Yields
OECD refinery yield data for December confirm that refiners responded to price signals, boosting jet fuel/kerosene yields compared with seasonal trends at the expense of diesel and gasoil - despite warm weather weakening demand in the Pacific. Gasoline yields continued to lag historical levels although some recovery was seen in the US.
Within the jet/kerosene product category, warm December weather weighed on yields for kerosene (used for domestic heating) in the Pacific, with refiners focusing more on the production of jet fuel. Regional kerosene yields were 9.2% compared with a five-year average of 10.8%. Refiners in Korea in particular appeared to curtail kerosene production to the benefit of jet fuel with kerosene accounting for only 33% of jet/kerosene production in December, compared with 48% in December 2005.
European refineries also curtailed other distillate production in favour of jet fuel and kerosene. This move by refiners is entirely consistent with the region's stronger jet/kerosene cracks during the month. This price premium continued in Northwest Europe in January, but in the Mediterranean ULSD regained a $5/bbl premium, so next month's data may be more mixed. European gasoline yields remained weak in December and January, but the recent recovery in gasoline cracks should have boosted February production.
Preliminary data for the big two national refiners suggest that Chinese crude runs fell slightly in January compared with December, averaging 6.3 mb/d (official data are unavailable at the time of writing due to the Lunar New Year holidays). Crude runs are seen increasing in February in line with stronger demand due to holiday-related travel. January data indicate that Indian crude runs averaged 3.0 mb/d, as higher crude runs at Reliance's Jamnagar refinery, where a fire the previous month disrupted production and Bharat Petroleum's Kochi refinery boosted the overall activity level.
Russian crude runs declined in January to 4.5 mb/d from December's level of 4.6 mb/d. The decline at Surgutneftegas's Kirishi facility was largely responsible, although the reason for lower runs is not apparent at the time of writing. Partly offsetting this decline were increases at Yukos's Angarsk and Achinsk plants and TNK-BP's Saratov refinery.
Offline Refinery Capacity
Further details have emerged on planned maintenance over the recent weeks allowing us to revise up our forecast for first-half 2007 by an average of 250 kb/d. Offline capacity is currently expected to peak in March at 3.5 mb/d and is forecast to remain at, or close to, this level through early May, before dipping to around 3 mb/d. Overall refinery maintenance this year appears to have started earlier than in 2006, but is currently forecast to be less severe over the second quarter than last year.
The upward revisions in OECD regions are centred in Europe in the first quarter and the Pacific in the second quarter. The latter revision is driven partly by higher anticipated run cuts in April. North American offline capacity in February is now estimated to be 1.7 mb/d, an increase of 0.4 mb/d, following disruption to several refineries, including Valero's McKee refinery, and three refineries in Canada. European first-quarter maintenance is expected to continue at above 0.5 mb/d through until the middle of the second quarter having made an earlier than normal start in January at refineries in the Netherlands, the UK and France. OECD Pacific offline capacity forecasts have been revised up due to the higher than anticipated run cuts in Japan and Korea. Furthermore, revised timings for some planned maintenance work has shifted the second-quarter peak back to June at 1.1 mb/d, although the average remains largely unchanged at 958 kb/d, slightly ahead of the second quarter last year.