Oil Market Report: 11 April 2013

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  • Oil futures prices declined in March, under the weight of renewed pessimism for the global economic outlook. Weaker crude demand, amid exceptionally deep seasonal maintenance at refineries, added to the pressure. Brent was last trading at $106/bbl and WTI around $94/bbl.
  • The forecast of global demand growth for 2013 is little changed at 795 kb/d, to 90.6 mb/d, following slightly lower-than-expected 1Q13 deliveries. A projected contraction in OECD demand of 480 kb/d, led by a 340 kb/d decline in Europe, partially offsets growth of 1.28 mb/d elsewhere.
  • Global supply fell by 120 kb/d in March on lower OPEC output. Non-OPEC supply is forecast to average 54 mb/d in 1Q13, up 650 kb/d y-o-y but down 240 kb/d from 4Q12 highs. For 2013 as a whole, non-OPEC supply is expected to grow by 1.1 mb/d to 54.4 mb/d as South Sudan resumes exports and other disruptions abate.
  • OPEC crude oil supply turned lower in March in the wake of disruptions in Nigeria, Libya and Iraq and against a backdrop of seasonally weaker second-quarter refiner demand. Crude oil output was down 140 kb/d to 30.44 mb/d.
  • Refinery crude throughput will remain subdued in April, when spring maintenance is forecast to keep as much as 6.8 mb/d of capacity offline, including 5.6 mb/d in Europe, Asia, FSU and the Middle East. February runs exceeded expectations in Europe, however, pushing global throughput estimates to 74.9 mb/d.
  • OECD industry oil stocks decline by a seasonal 32.9 mb to stand at 2 664 mb by end-February. Stocks have been at a surplus to five-year average levels for six months. Product stocks led the draw, falling by 29 mb on reduced refining output, and by end-February covered 31.1 days of demand, 0.2 day less than a month earlier.

Oil markets take a breather

The price of Brent, the world's most widely used oil benchmark, has eased since peaking at $118.90/bbl on 8 February. By early April, front-month Brent futures had tumbled to just shy of $104/bbl for the first time since mid-June, and the backwardation on the Brent curve has eased. While some of the reasons for these developments may be Brent-specific, signs that the oil market as a whole may be getting more comfortable have led many forecasters to lower their price target for 2013. But it may be too early to call a bear market, and there are signs that some of the recent easing of upward price pressures could be relatively short-lived.

The recent price drops are consistent with the outlook laid out in our 2012 Medium-Term Oil Market Report (the 2013 edition will be released next month): that of a market enjoying significantly faster growth in oil supply and refining capacity than in demand. Supply growth, after a brief setback, is on the rebound. Saudi supply seems poised to ramp up after dipping in 4Q12 and 1Q13. Outside of OPEC, growth is picking up steam. Many of the disruptions that in aggregate had taken such a toll on last year's supply - from the Sudan-South Sudan tiff to longstanding outages in the North Sea and Brazil - are finally coming to an end.

Demand, meanwhile, remains subdued. It has been exceptionally weak in the OECD, notably in Europe, where consumption in 2013 is expected to be the lowest since the 1980s. While growth elsewhere is more robust, global demand came in below expectations in 1Q13 and our forecast for 2013 has been marginally trimmed. OECD inventories are getting more comfortable. Stocks have remained in surplus versus their five-year average for six months. Even middle-distillate stocks are getting less tight: the February middle-distillate draw was a fraction of the average for that month. Remarkably, gasoil demand growth trailed that for gasoline last year, reversing earlier trends, and may do so again this year.

Yet there are clouds on the horizon. Recent softness in crude prices likely had as much to do with record spring maintenance at refineries as with anything else. Close to 7 mb/d of refining capacity may be offline this month. But US refiners are already getting back online, and global crude runs will likely increase steeply starting next month.

At the same time, crude supply risk remains elevated. After last year's crises, new set backs, from cyclones in Australia to disruptively cold weather in North Dakota, have crept up. For the first time in months, our non-OPEC supply forecast has been revised downwards, albeit marginally. The security situation in Libya is a major worry, as is the recrudescence of attacks on oil personnel and facilities in Nigeria, where security forces face both a rise in Islamist terrorism in the North and a resurgence of violence in the South. Meanwhile, geopolitical threats, from the conflict in Syria to the dispute over Iran's nuclear plans, and now sabre-rattling in North Korea, continue unabated. While fundamentals may be easing, rarely has the market faced such diffuse risks. In a resource-rich but rapidly changing world, this makes market transparency a greater priority than ever.



  • Revisions to first-quarter demand estimates have reduced the forecast of global oil demand for 2013 by 45 kb/d from last month's Report, to 90.6 mb/d. Annual demand growth is now projected at 795 kb/d (0.9%). A weak macroeconomic environment is expected to keep demand growth relatively subdued for the remainder of the year.
  • Worries about the economy and mild February weather cut the estimate of 1Q13 demand by 115 kb/d from last month's Report. Demand estimates for Russia, Japan, Spain and India account for the bulk of the revisions. Relatively reliable electricity supplies and higher prices dampened gasoil demand in India, reducing our estimate of its consumption.
  • Gasoline demand growth outpaced that for gasoil/diesel in 2012, reversing earlier trends. Weak industrial activity slowed gasoil demand growth, whereas strength in the non-OECD transport sector supported demand for gasoline in countries where it remains the fuel of choice for personal vehicles.

Global Overview

While middle distillates have generally been accounting for a fast-growing share of the global demand barrel in recent years, preliminary data increasingly suggest that trend might have come to a halt in 2012. As oil demand statistics for the year keep coming in, it is becoming apparent that gasoline, rather than middle distillates, may have led global demand growth last year. Gasoline demand grew by an estimated 255 kb/d in 2012, compared to an aggregate gain for all products of 845 kb/d. Demand for gasoil/diesel is estimated to have expanded by 225 kb/d. If confirmed, this switch would likely reflect the dampening effect of slower industrial activity worldwide on distillate demand, whereas robust non-OECD transportation fuel markets supported demand for gasoline in countries where that fuel dominates the automobile fleet.

Saudi Arabia and China, both of which posted strong gasoline demand growth in 2012, were key contributing factors to the global trend. In a recent note, the McKinsey consultancy forecast that sales of larger vehicles would outpace those of smaller cars in China through 2020, a trend expected to continue supporting gasoline demand growth in that country, over diesel. Non-OECD gasoline consumption rose by an estimated 445 kb/d in 2012, led by gains in China (up 130 kb/d) and Saudi Arabia (+35 kb/d). At the same time, the contraction in gasoline demand slowed in the OECD to 190 kb/d in 2012, from a 340 kb/d decline in 2011.

Although global gasoil demand was relatively weak on average in 2012, industrial activity did show signs of picking up momentum over the course of the year. In the OECD, gasoil demand contracted by 240 kb/d, a steeper decline than shown in both 2011 (-65 kb/d) and the five-year average (-95 kb/d). In contrast, gasoil consumption growth in the non-OECD region slowed down from the previous five-year average, to 465 kb/d in 2012 from 535 kb/d. Flat Chinese gasoil demand growth in 2012, echoing clear signs of weakness in the Chinese manufacturing sector, kept non-OECD gasoil consumption at a relatively low level.

For 2013, we are forecasting that gasoline demand growth will once again marginally outpace gasoil, but the difference will be slight with gasoline demand projected to expand by nearly 300 kb/d versus 265 kb/d for gasoil, as the industrial backdrop remains somewhat sluggish. The faster pace of gasoil demand growth, relative to gasoline, is forecast to resume in 2014.

Overall, a slightly weaker demand trend is forecast for 2013 than in last month's Report, with annual growth now forecast at 795 kb/d (0.9%), to 90.6 mb/d (45 kb/d below our previous forecast). Our revised 1Q13 consumption estimate averaged out at 89.9 mb/d, 115 kb/d less than forecast in last month's Report. A few notable revisions in February account for the bulk of the reduction, including big cuts in the estimates for Japan (-305 kb/d), India (-170 kb/d) and Spain (-140 kb/d). Near-complete January data also reduced the estimates for that month for Russia (-125 kb/d), India (-85 kb/d), Spain (-50 kb/d) and Malaysia (-50 kb/d). These downward adjustments more than offset large upward January revisions for the US (+290 kb/d), Saudi Arabia (+120 kb/d) and Brazil (+110 kb/d).

Top-10 Consumers


The US Energy Information Administration has adjusted upwards its preliminary weekly estimates of January demand for the US50. Based on revised monthly data, January oil consumption is now estimated 2% above last year, compared to an earlier forecast for a 0.3% decline and our projection of 0.4% growth in last month's Report. The latest January statistics were thus 290 kb/d above those carried in last month's Report. Gasoil/diesel led the revision, with January growth now estimated at 6.1% y-o-y, the strongest uptick since the end of 2011. In contrast, weekly data for the four-weeks to 25 January had suggested an average 6.3% y-o-y contraction. Colder winter weather likely boosted heating oil demand, while an uptick in manufacturing sentiment may also go some way towards explaining stronger distillate deliveries. The Institute for Supply Management's Manufacturing Report on Business reported sentiment rising to a ten-month high, of 53.1 in January, with particularly strong gains in 'production' and 'new manufacturing orders'.

Gasoline continues to dominate the US oil demand barrel. Estimated gasoline demand for January came out 235 kb/d below our previous forecast, perhaps in response to a counter-seasonal gasoline price spike. Nevertheless, US50 gasoline consumption remained 0.4% above its year earlier level in January. Weekly EIA statistics suggest a further gain of nearly 1% in gasoline demand for February, continuing with flat growth in March.


Chinese apparent demand fell by 110 kb/d month-on-month in February, to 9.7 mb/d, as the Lunar New Year holiday saw many factories closing, restraining the use of industrial fuels such as gasoil and naphtha. Latest Chinese oil data point to exceptionally large gasoil inventory builds in both January and February, when percentage changes reported by China Oil, Gas and Petrochemicals suggest stocks built by 350 kb/d and 455 kb/d, respectively. Such-builds are not unusual prior to the-Lunar New Year holiday, but early-2013 gains have been particularly pronounced and may reflect a steep ramp-up in refinery runs since mid-2012. It is also possible that data for early 2013 reflect unreported upward revisions to 2012 data (see Stocks section).  The new methodology for estimating Chinese apparent demand implemented by this Report since January aims to strip out inventory changes such as the build reported for January and February from demand estimates. Even so, our data suggest an uptick in Chinese annual demand growth, to 745 kb/d in 4Q12, from 365 kb/d in 3Q12 and 90 kb/d in 2Q12.

A renewed uptick in manufacturing sentiment in March (see Global Overview) looks likely to keep Chinese oil demand supported at around 9.8 mb/d in 1Q13. For the year as a whole consumption is forecast to average roughly 10 mb/d, a gain of 3.9% (or 380 kb/d) on the year earlier. Transportation fuels are forecast to lead the Chinese upside in 2013, with gasoline up by 130 kb/d and gasoil/diesel 100 kb/d higher. The government has amended its domestic product pricing policy, potentially improving refinery margins through the remainder of the year. The National Development and Reform Commission (NDRC) still ultimately decide on domestic prices, but the previous 4% price-trigger (that had to be broached over a 22 working day period) has now been dropped. The new mechanism is more flexible, whereby the NDRC can adjust prices if it deems the previous ten working day price trend to justify it. To date, less clarity is available regarding this process, but the hope for the market is that Chinese domestic product prices will in future better reflect international oil price trends.


Preliminary data confirmed earlier expectations that the demand trend would turn negative in February due to the diminishing impact from last year's fuel switching out of nuclear power generation in year-on-year comparisons. Yet the magnitude of the contraction, -5.2% y-o-y or 305 kb/d below last month's Report, fell far below earlier projections. Warmer February weather, leading to a 10.1% y-o-y contraction in jet/kerosene demand, helps explain the lower-than-expected level of February deliveries. Demand for fuel oil and 'other products', two categories of products also used in power generation, edged lower on the month too.

February's contraction was the sharpest y-o-y reversal in nearly two years, and builds on the flat demand trend seen since October. January data revealed a modest total 0.7% gain over the year earlier, but showed drops in LPG and gasoline. LPG demand suffered in January, as Tepco shut its 600 MW number 3 unit at its 3.6 GW Anegasaki thermal power plant at the start of the month, citing technical problems. The plant uses LPG, LNG and crude as feedstocks for power generation. The Japan LPG association reported a 7% y-o-y increase in LPG sales in the first half of the 2012-2013 fiscal year (i.e. April-September). Sales to the residential sector rose by nearly 20%, while power-sector use nearly doubled. The household sector failed to reflect the otherwise rising trend, down modestly on substitution to cheaper natural gas supplies, a trend that should remain entrenched if price discounts (20% in the first half of the fiscal year) persist. In a recent report, the Japanese Institute of Energy Economics forecasts LPG sales falling by 1.1% in fiscal year 2013-2014, as weak industrial and household sector demand take hold.


Indian demand contracted in February y-o-y for the first time in three and a half years. The drop spanned all big product categories, bar naphtha and motor gasoline. Deliveries of gasoil - India's mainstay fuel - declined amid signs that a recent price hike may be triggering a demand response. India removed bulk diesel subsidies in January, which together with a series of monthly retail subsidy reductions (equivalent to a price hike of one US cent per litre, per month), has raised gasoil/diesel prices to a level that is seemingly affecting consumption levels. Further dampening demand were reports of more reliable electricity supplies, which curbed emergency generator oil-use. The severity of the price-response has led us to reduce our forecast for demand growth in 2013 to 2.3% (from the 2.8% jump carried in last month's Report) with the gasoil forecast in particular suppressed as further retail price hikes are envisaged through to the end of the year.

Momentum has gone the other way in LPG, with the cap on the maximum permitted number of subsidised LPG cylinders per household raised by 50%. A subsidised 14.2 kg LPG cylinder in Delhi costs Rs 410.5, versus the unsubsidised price of Rs 895.5. Furthermore, an additional price cut, of Rs 37.5 per cylinder, is applied for purchases over the subsidised quota.


Historical estimates of Russian demand have been reduced by 65 kb/d for 2011 and 95 kb/d for 2012, since last month's Report, led by large cuts in the 'other products' category. Nevertheless, Russian consumption still shows robust growth of 7.6% in 2011 and 3.4% in 2012 (to 3.3 mb/d). More recently, demand growth appears to have slowed, with an increase of 1.4% seen in January and a decline of 1.1% in February, with particular weakness in gasoil and 'other products'. A stronger overall growth trend is forecast to take hold over the remainder of the year, however, as the underlying economic backdrop remains supportive. The Russian demand forecast has been curbed (3.6% versus 3.8%) to reflect the weak 1Q13 data.


Brazilian oil demand continues to rise at a rapid pace, helped in part by drought limitations on hydroelectricity generation. Having risen by around 4.2% in 2012, to an average of 3 mb/d, Brazilian demand growth accelerated sharply in January, up 7.6%, and 110 kb/d more than forecast in last month's Report. The majority of the additional Brazilian consumption was in industrial fuels, as additional power plant usage (to counteract lower hydro output) compounded the effect of improving manufacturing sentiment. After a prolonged period of 'contracting' sentiment, managers' opinions (as reported by HSBC/Markit) rose back into 'expansionary' territory in October 2012, and continued to accelerate into January 2013. This spike in demand growth may prove relatively short-lived. A recent increase of nearly 5% in retail prices may curb gasoline and gasoil demand growth for the remainder of the year, while a likely improvement in hydroelectricity generation would cut power-sector demand. The government recently decided to raise the ratio of anhydrous ethanol in retail gasoline, from 20% currently to 25%, starting in May.

Saudi Arabia

Saudi Arabian oil consumption bounced back strongly in January from its December lows, led by persistently robust residual fuel oil demand. Total product demand jumped by 7.3% y-o-y to 2.8 mb/d.  All product categories showed growth except 'other products' (-4.4%). The strong performance of the country's oil-intensive manufacturing sector likely helps explain the surge in oil demand. Fuel oil, heavily used in the power sector, saw demand growth of 29.9%, followed by gasoline (+13.5%) and jet/kerosene (+9.4%). At 58.5 in February and 58.1 in January, the SABB/HSBC manufacturing PMI is well above the 50 mark that separates 'expansion' from 'contraction' in manufacturing. Economic forecasts by the International Monetary Fund suggest that GDP growth will slow to 4.2% in 2013 from 6.0% in 2012, however. Reflecting these expectations of slower macroeconomic momentum, and government efforts to curb oil demand, growth is projected to slow to  4% in 2013 (to 3.1 mb/d) from 4.8% in 2012, when demand averaged an estimated 3 mb/d. Supporting fuel oil demand forecasts, from 2Q13, will be the start-up of a new 1 200 MW fuel oil fired power plant.


Unexpectedly warm winter weather, reversing the pattern of the previous three months, cut February demand by nearly 25 kb/d from last month's forecast and led to particularly sharp reversals in kerosene and gasoil deliveries. Jet/kerosene demand fell by 12.3% y-o-y, and gasoil/diesel demand by 8.9%. Tracking forward, we maintain our forecast for a flat Korean demand trend in 2013, as government efforts to curtail demand take hold.


Following some major amendments from Statistics Canada, roughly 35 kb/d of oil products were stripped from the previous 2012 estimate, to 2.3 mb/d. This leaves the year as a whole roughly unchanged on 2011. Early indicators of 2013 point towards a modest uptick in momentum, as demand garners support from the colder-than-year-earlier winter weather, with all of the major product categories bar heavy fuel oil and gasoline seeing y-o-y growth in January. LPG demand decelerated in January (+1.8%), from its 2012 trend (2.5%), as butane prices rose due to acute storage issues. The Canadian (Sarnia) butane price rose to a premium of 22 US cent/gln over the US (Mont Belvieu, Texas) price in December 2012, roughly double the year earlier premium. Excessive build-ups of brine in the Sarnia region, a chronic issue for Canada, was cited as a key justification for this premium.


Warmer February weather, coupled with indicators of struggling economic activity, resulted in a lower German gasoil demand number, 110 kb/d below the forecast carried in last month's Report and equivalent to a 9.4% less than was consumed a year earlier. Markit's Purchasing Managers' Index for the manufacturing sector barely stood above the key-50 'expansionary' threshold, at 50.3 in February and has since fallen to 49.0 in March, pointing towards further demand weakness in the months ahead.


A weak macroeconomic background, coupled with unexpectedly warm temperatures in February, resulted in a lower 1Q13 estimate of 45.8 mb/d (125 kb/d below the forecast carried in last month's Report). Korea, Japan, France, Germany, Spain and Italy all saw warmer February temperatures than the year earlier, dampening gasoil and kerosene demand in particular. The overriding trend remains one of falling OECD consumption, driven by weak economic growth, persistently high prices and continued efficiency gains.


Stronger demand trends have been seen recently in the OECD's Latin American nations. Mexican demand rose by 3.7% in January, led by fuel oil, demand for which remained supported by continued power sector requirements. The outlook for Mexican fuel oil consumption eases through the remainder of the year, as competing LNG shipments are forecast to arrive from Peru, whilst a switch in bunker fuel from fuel oil to gasoil also comes into effect. Vessels travelling near the US Gulf coast have to burn fuel with a sulphur content no more than 0.1%, encouraging a switch to gasoil bunkers. LPG demand rose (+1.9%) as relatively subdued import prices (from the US) provided an additional boost. Chilean demand posted a strong 4.4% growth rate, boosted by continued economic gains, as depicted in the government compiled IMACEC economic activity indicator showed growth of 6.7% y-o-y in January.


OECD Europe remains by far the worst affected of all the large oil consumption regions, as the ravages of the bleak macroeconomic backdrop continues to take its toll. Early indicators of 1Q13 demand point toward a further 3.8% decline, although a modest easing in the downside trajectory is forecast towards the end of the year as relative economic momentum improves.

LPG consumption in Sweden fell in 2012, reflecting difficulties in its LPG-intensive steel industry, according to the Swedish Gas Association. Further weakness is envisaged in 2013, unless the economic situation improves dramatically, a scenario we are not confident will unfold.

Asia Oceania

Warmer-than-year-earlier winter weather in OECD Asia Oceania reduced the 1Q13 demand estimate by 105 kb/d. Consumption in the region is now down on the year earlier, the first time such a reversal has occurred since 1H11, a trend that we forecast continuing through 2013. As expected, sharp declines in heavy fuel oil and 'other products'- both used in power generation in Japan - led the downward trend. Unseasonably warm temperatures caused the 1Q13 demand contraction to exceed expectations, however. Some additional softness was seen in the gasoline sector, which came out 1.8% below the year earlier led by particularly sharp 1Q13 declines in Japan (-2.9%) and Korea (-1.7%).


Emerging markets continue to provide the majority of the world's demand growth, with the 1Q13 estimate 1.4 mb/d up on the year earlier. As in 2012, gasoline led the growth. This month's Report includes a large number of revisions to the historical African data series. South African demand for 2010 has been revised upwards by 130 kb/d. Nigerian demand estimates for 2010 were also revised higher, by 55 kb/d, as previous gasoline estimates were shown to miss product privately imported into the country. The Nigerian oil minister, Diezani Alison-Madueke, reported an 8.3% contraction in LPG demand in 2012, as LPG usage lost out to wood, charcoal and still-subsidised kerosene. This situation may change, as the National Refineries Special Task Force argues for the removal of government subsidies on all domestic refined products. Outside the African continent, Venezuelan demand continues to rise, supported by social spending and low power generation output at the world's third largest hydroelectric power plant, Guri.

Taiwanese consumption estimates of roughly 1 mb/d for January reflect a 65 kb/d upward (counter seasonal) revision to the assessment in last month's Report. Recent data from the Port Authority of Singapore show bunker fuel oil demand down 13% month-on-month, to 670 kb/d in February, but up marginally on the year earlier, in line with our forecasts.

The recent strong Thai demand data continued in January, at 1.3 mb/d, a gain of nearly 11% y-o-y. This is the fourth consecutive month of plus-7% growth, as transportation fuels rose particularly steeply while consumer confidence jumped to an 18-month high. Supporting demand projections for 1H13, consumer confidence indicators for February rose to a year-and-a-half high. Thai consumption has been on a generally accelerating trend since September, when consumer confidence bottomed-out.



  • Global supplies fell by 120 kb/d in March m-o-m to 90.7 mb/d on lower OPEC output, while non-OPEC supply increased slightly. Compared to 2012, March production stood 140 kb/d higher, as growth in non-OPEC liquids and OPEC NGLs offset a 1.1 mb/d decline in OPEC crude.
  • Non-OPEC output for 1Q13 is forecast at 54 mb/d, a gain of 650 kb/d y-o-y but a 240 kb/d dip from lofty 4Q12 levels. Maintenance at Canada's oil sands facilities, cyclones in Australia, and a seasonal decline in global biofuels output are the main factors behind the quarterly decrease. Non-OPEC supplies are forecast to grow by 1.1 mb/d to 54.4 mb/d in 2013 off of a revised 2012 baseline.
  • South Sudan production restarted in early April for export via Sudan, ending a thirteen-month outage. In addition, the restart of production at the Kearl mining project in Canada, the Elgin/Franklin complex in the UK, and the Peng Lai field in China removes from the non-OPEC supply picture some of the unplanned disruptions which had so prominently featured over the last year.
  • OPEC crude oil supply fell by 140 kb/d in March m-o-m to 30.44 mb/d, against a backdrop of seasonally weaker second-quarter refiner demand. Reduced output from Iraq, Iran, Nigeria, Libya and Algeria more than offset higher supplies from Saudi Arabia and Kuwait.
  • The 'Call on OPEC crude and stock change' for 2Q13 was revised up by 100 kb/d to 29.3 mb/d on lower than forecast non-OPEC supplies. The 'Call' for the full-year was unchanged at 29.7 mb/d. OPEC NGL production is forecast to average 6.3 mb/d in 2Q13, a downward revision of 100 kb/d from last month.

All world oil supply figures for March discussed in this report are IEA estimates. Estimates for OPEC countries, Alaska, and Russia are supported by preliminary March supply data.

Note:  Random events present downside risk to the non-OPEC production forecast contained in this report. These events can include accidents, unplanned or unannounced maintenance, technical problems, labour strikes, political unrest, guerrilla activity, wars and weather-related supply losses. Specific allowance has been made in the forecast for scheduled maintenance in all regions and for typical seasonal supply outages (including hurricane-related stoppages) in North America. In addition, from July 2007, a nationally allocated (but not field-specific) reliability adjustment has also been applied for the non-OPEC forecast to reflect a historical tendency for unexpected events to reduce actual supply compared with the initial forecast. This totals ?500 kb/d for non-OPEC as a whole, with downward adjustments focused in the OECD.

OPEC Crude Oil Supply

OPEC crude oil supply turned lower in March in the wake of supply disruptions in Nigeria, Libya and Iraq and against a backdrop of seasonally weaker second-quarter refiner demand. Crude oil output was down 140 kb/d to 30.44 mb/d, as higher supplies from Saudi Arabia and Kuwait failed to offset reduced output from Iraq, Iran, Nigeria, Libya and Algeria.

The 'call on OPEC crude and stock change' for 2Q13 was revised up by 100 kb/d to 29.3 mb/d on lower forecast non-OPEC supplies and a 100 kb/d downward adjustment to the estimate of OPEC NGL supplies, now projected to average 6.3 mb/d for the quarter. The 'call' for the full-year was unchanged at 29.7 mb/d. OPEC's 'effective' spare capacity rose 130 kb/d to 3.72 mb/d versus 3.59 mb/d in February.

Saudi crude output rose to a four-month high of 9.3 mb/d in March, up 50 kb/d over February levels. Production is expected to rise steadily in coming months as Asian refiners return from scheduled maintenance turnarounds. Higher shipments to Saudi Aramco's expanded Motiva joint-venture refinery on the US Gulf Coast and the mid-year start-up of its new 400 kb/d Jubail refinery at home are also expected to support higher crude production.

Equally, domestic direct crude burn for power generation typically starts ramping up in April in line with air-conditioning demand, reaching peak levels in August. In 2012 Saudi crude burn rose around 300 kb/d to an average 675 kb/d during the seasonally stronger demand period from April to September, compared with 380 kb/d from October to March. 

Iraqi production in March tumbled to nine-month lows, down 150 kb/d to 2.96 mb/d, largely due to weather-related disruptions of Basrah supplies in the south of the country. Total exports were down by around 150 kb/d to 2.43 mb/d, with Basrah shipments off 155 kb/d to 2.09 mb/d. Exports of Kirkuk volumes via the Ceyhan terminal on the Mediterranean were largely unchanged at around 330 kb/d. In addition, another 15 kb/d of Kirkuk crude output was trucked to Jordan. For the third month running, exports from the Kurdistan region remained suspended due to a dispute between Baghdad and Erbil over payment and volume issues.

Iranian production was down 40 kb/d to 2.68 mb/d. OECD and non-OECD countries imports of Iranian crude fell to an estimated 1.1 mb/d in March from an upwardly revised 1.26 mb/d for February. February import volumes are based on data submitted by OECD countries and non-OECD data from customs agencies and news reports. Preliminary data for March have been adjusted higher by around 215 kb/d to account for underreporting of tanker movements, the primary source of information for the most current month. Tracking Iranian tankers is fraught with uncertainties, not least because Tehran instructed its tanker fleet to turn off its tracking beacons. We have therefore applied an adjustment based on a three-month rolling average of the difference between preliminary and final import data to the most recent month to provide a more accurate assessment of current levels. To date, most of the tankers that are initially unaccounted for eventually are reported by Chinese and Indian customs data.

On 13 March the US granted a further 180-day reprieve from sanctions on crude imports to Japan and 10 EU nations after determining they had made significant cuts in import volumes. As part of a wide-ranging sanctions regime against Iran, US regulations adopted last July call for countries that import Iranian crude oil to make significant reductions in volumes as determined by the US government  or face the risk that their country's banks will be cut off from the US financial system.

Meanwhile, the latest round of negotiations on 5-6 April in Kazakhstan between Iran and the UN P5 +1 nations (the US, UK, France, Russia, China plus Germany) over the former's nuclear ambitions ended without visible progress. The P5+1 were reportedly prepared to ease some sanctions on financial transactions and trade in return for Iran agreeing to suspend its most sensitive uranium-enrichment work, which includes halting work to enrich uranium to 20% grade at the Fordo site. Iran was unwilling to accept the terms on offer. European Union foreign policy chief Baroness Catherine Ashton, the lead negotiator for the P5+1, reported "that our positions remain far apart." Currently there are no new talks planned in the decade-long dispute but diplomatic efforts may resume following Iran's presidential elections in June.

Elsewhere in the Gulf, Kuwait increased supplies in March by 70 kb/d, to 2.84 mb/d. UAE production was pegged at 2.7 mb/d in March, unchanged from February's upwardly revised estimate. February's preliminary production estimate was raised by 150 kb/d, with a portion of the higher output reportedly coming from new capacity at onshore fields that feed the Murban crude stream, the country's benchmark grade.

Three out of four of OPEC's African producers have seen their production impacted by increased militant activity in recent months. Algerian production was estimated at 1.14 mb/d, down 20 kb/d from January and February levels. The deadly attack at the In Amenas complex in January affected only natural gas and gas liquids output but crude oil production appears to have also slowed within the country as a comprehensive review of security arrangements at oil fields and infrastructure takes place.

Nigerian crude supplies fell to their lowest level in four months in March, off 50 kb/d to 1.95 mb/d, and output may trend lower following a resurgence of oil theft-related damage to pipelines and renewed threats to the country's oil infrastructure by the Movement for the Emancipation of the Niger Delta (MEND). Shell plans to close the Nembe Creek pipeline this month to conduct repairs, which could affect as much as 150 kb/d of Bonny and Forcados. Sabotage and oil bunkering (theft) is also behind ENI's decision on 23 March to shut in its onshore production in the swamp areas of the Niger Delta. The company declared force majeure on an estimated 35 kb/d of output following increased criminal activity on its facilities.

In one of the most serious attacks in recent memory, 15 government security personnel were ambushed and killed on 5 April in the southern oil-producing Bayelsa state. A statement on 8 April reportedly issued by MEND, hitherto inactive since an October 2009 ceasefire agreement, claimed responsibility for the deaths.  MEND threatened on 3 April to renew attacks on oil infrastructure after their former leader, Henry Okah, was sentenced to 24 years in prison on terrorism charges in South Africa. A MEND spokesman pledged to carry out a "plague of attacks." Contrary to the public claims by MEND, however, government officials report that the latest attack was related to infighting among militant factions over payments due as part of the 2009 amnesty programme. Renewed militant activity targeting oil companies in the south comes at a time when government security forces are already overstretched trying to contain the Islamist insurgency in the north.

Libyan crude oil supplies fell by 40 kb/d to 1.36 mb/d in March following renewed attacks on oil infrastructure by warring militias, security forces and protests by disgruntled civilians. Critically, the lack of security has led to an increase in kidnappings and killings of government officials. Following the abduction and eventual release of the chief of staff to Libya's prime minister, parliament enacted a new law on 9 April that criminalises torture and kidnapping.

The deterioration in security in Libya is threatening to derail the country's production outlook. Libya set up a 15,000 strong special security force made up of former rebel fighters, the Petroleum Facilities Guard (PFG), to protect oil installations. The lack of professional training and infighting among the various groups, however, has led to fears that the PFG are becoming part of the problem, not the solution. A lack of central government authority to control the militias is a major issue.

  • Infighting between militant groups for control of security operations at the 20 kb/d Dahra oil field, operated by Waha Oil Co, a joint venture between Libya's National Oil Corporation (NOC) and Marathon, Hess and ConocoPhillips, broke out on 18 March. Waha's total production capacity is more than 350 kb/d and produces key export grade Es Sider crude.
  • Production and drilling were disrupted at the 120 kb/d Gialo field for three weeks in March due to protesters' demand that the Waha group use locally hired companies for transportation services.
  • On 2 March shooting between rebel groups, including guards belonging to the PFG, stopped production at the Mellitah gas complex. As a result, ENI and NOC were forced to partially shut-in production at the Elephant and Wafa fields, whose crude is processed at the coastal Mellitah facility.
  • Political and security uncertainties are behind PT Medco Energi Internasional's decision in late March to delay by two years development of Area 47, a project originally slated to produce 50 kb/d in 2014.
  • An explosion on a key pipeline connected to the Zueitina oil terminal cut flows of crude and condensate in early April. NOC said the crude line was repaired within a few days but the condensate section of the line suffered more damage and remained shut-in. Officials did not specify how much crude and condensate output was affected but roughly 60-70 kb/d are exported through the terminal. One report suggested the blast was likely caused while maintenance work was underway, but officials said sabotage could not be ruled out.

Angolan production, by contrast, was marginally higher in March, up by 40 kb/d to 1.77 mb/d. BP's new PSVM production is slowly ramping up, running at around 90 kb/d on average in March. The 150 kb/d PSVM fields are not expected to reach full capacity until early 2014.

Non-OPEC Overview

Unplanned outages loomed large in last year's non-OPEC supply picture removing up to 1.1 mb/d from the market. This year's situation looks more promising, as things seem to be getting back to normal in several areas where disruptions had curtailed output. Yet this is not to say that supply risks have evaporated. On the contrary, some storm clouds are gathering which are posing significant downside risk to the forecast.

One of this year's bright spots is the reported restart of some of South Sudan's production for export via Sudan. The resumption in flows from South Sudan, as well as the restart of the Elgin/Franklin complex (UK), the Peng Lai field (China), and Frade (Brazil) remove from the non-OPEC supply picture some of the major unplanned disruptions which had reduced output last year. During the remainder of 2013, new production is coming online in Canada, Brazil and the US.  Increasing volumes of Russian gas condensate are keeping Russian liquids production afloat at 10.8 mb/d in March in the face of mounting brownfield production declines. These factors are expected to take non-OPEC supply growth to more than 1 mb/d in 2Q13 and 3Q13.

However positive these developments may appear, they should not overshadow the continued presence of downside risk to forecasts. For the first time in several months, non-OPEC supplies for 2013 have been revised downwards -- albeit by a marginal 20 kb/d,-- to 54.4 mb/d, implying forecast growth of 1.1 mb/d y-o-y. Despite the restart of Elgin/Franklin, North Sea production came in about 40 kb/d below expectations in 1Q13.  And, with Brazilian output offline for maintenance, production is down by 120 kb/d in 1Q13 on an annual basis. In Australia, cyclones recently dented production. Even North America was not immune to disappointments, as winter storms slowed North Dakota Bakken output and yet another 2012 baseline adjustment trimmed the estimate of Texas production. Turmoil in Syria continues unabated, reducing production and threatening more severe supply disruptions in the future. In total, 1Q13 non-OPEC supplies totalled 54.0 mb/d, more than 0.1 mb/d lower than forecast last month. Other baseline revisions to 2012 data include downward revisions to Canadian NGLs and Azerbaijan production, which led to a 60 kb/d reduction to 53.3 mb/d for 2012.

OECD Americas

US - March preliminary, Alaska actual, other states estimated: US crude oil production is expected to maintain its upward momentum in 1Q13, rising by 80 kb/d from 4Q12 or 870 kb/d y-o-y, though data from the US Energy Information Administration's Petroleum Supply Monthly for January show a 60 kb/d dip in US crude production that month, to 7.0 mb/d. North Dakota's Bakken production slipped by 30 kb/d to 670 kb/d, though Eagle Ford volumes continue to race ahead by around 50 kb/d each month. Cold weather and storms caused the slight pause in Bakken production growth, but growth is expected to resume in the spring. US output is expected to increase by 840 kb/d to 9.98 mb/d in 2013, unchanged from last month's estimate. 

Canada - December preliminary:  Canadian oil production growth slowed to 170 kb/d year on year in 1Q13 from 230 kb/d in the prior quarter, in line with forecasts. Output growth continues, albeit at a slower pace, on the back of rebounding output in Eastern Canada at the Terra Nova and Hibernia fields, which had been offline due to maintenance, and at in situ oil sands projects. Planned maintenance is likely to dent output at Canadian surface mining projects by 200 kb/d in 2Q13, to 810 kb/d. Revisions to historical NGL production estimates reduced the assessment of Canadian production levels in 2012 by 35 kb/d from previous estimates, a baseline revision that has been carried through the forecast. On balance, Canadian oil output is expected to grow by 200 kb/d in 2013 to 3.9 mb/d.

North Sea

North Sea production stayed at the prior quarter's levels of 3.0 mb/d in 1Q13, after having risen sharply at the end of 2012. Seasonal maintenance is expected to cut supply to 2.7 mb/d in 3Q13. Production of Brent-Forties-Oseberg-Ekofisk (BFOE) has only fallen slightly to 760 kb/d in March, compared to 780 kb/d in January and February based on preliminary estimates. Loading schedules indicate a rebound to 940 kb/d in April and 890 kb/d in May though wellhead production from these streams in April and May is expected to be lower. Production declines are expected to slow to 6.9% in 2013 from declines of 9% (310 kb/d) in 2012, unchanged from the prior month's assessments.

In Norway, liquids output fell to 1.75 mb/d in February based on the latest data but is expected to have rebounded to 1.8 mb/d in March. Norway's biggest union struck an agreement with employees on 8 April, averting a strike that would have affected the Mongstad and Vestbase bases, which are key supply points for about 20 major platforms. Last June and July, production fell by 50 kb/d and 60 kb/d, respectively, due to worker strikes.


Australia - January preliminary: Output fell to a record low of 320 kb/d in January as some production went offline for planned maintenance and precautionary measures ahead of cyclones. Production is expected to rebound to 400 kb/d by 3Q13. Thai company PTTEP noted that the cyclones would also cause yet another delay to the 35 kb/d Skua and Montara project, now expected to start in 2Q13. Due to the severity of the January cyclone-related outage and the field startup delay, Australian oil production estimates have been trimmed by 10 kb/d in 2013. Production should total 450 kb/d in 2013, on par with 2012's levels.


Former Soviet Union

Production in the Former Soviet Union totalled 13.8 mb/d in March, 70 kb/d lower than February's output level.  1Q13 production is 120 kb/d higher than the prior year and 80 kb/d higher than 4Q12.

Russia - March preliminary:  March liquids output increased by 130 kb/d y-o-y or 20 kb/d m-o-m to 10.8 mb/d. Robust condensate output growth from Gazprom accounted for about half the increase. Brownfield decline rates in 1Q13 approached levels unseen since 2010. For example, though Lukoil's output in March 2013 stayed on par with March 2012, its western Siberian assets declined at an annual rate of 1.5% in March, compared with 0.1% in 2012.  

Estimates of supply in Azerbaijan have been reduced by 100 kb/d in 4Q12 leading to an overall reduction of 30 kb/d for 2012. Newly released production data for 4Q12 indicate production unexpectedly slipped by 40 kb/d y-o-y to 90 kb/d at the Deepwater Guneshli part of the ACG field complex. Overall, ACG production declined by 7% (50 kb/d) in 2012, dragging down overall liquids output to 890 kb/d. Production is expected to fall 10 kb/d further in 2013 to 880 kb/d.

In March, Kazakhstan announced that it would raise the Customs Exports Duty to $60/tonne (8.20/bbl) from $40/tonne ($5.70/bbl). Kazakhstan introduced crude export duties in 2008 at $109.9 per tonne, cancelled them in 2009 when oil prices fell and reinstated them in 2010 at $20/tonne. The government raised the duty in January 2011 to $40/tonne when prices rose again. Prices for benchmark Brent jumped by $20/bbl to $116/bbl from January 2011 to February 2013, but have since fallen back to $110 in March. This therefore brings into question the notion that the increase in duty is due to rising oil prices. Export duties affect all oil producers (except those with a tax stabilisation clause) regardless of profits, and analysts have noted that Kazakhstan's higher-cost producers would be most vulnerable to these incremental duties. Analysts estimate the range of impacts on producers between $1.40-1.75 per barrel of exported oil, but KMG EP's 120 kb/d of exports will be most affected. The export duty increase will be partially offset by lower excess profit and corporate income taxes. TengizChevroil JV, operator of the 500 kb/d Tengiz field, may pay the duty under duress as they have done in the past, but offsets these payments against its regular royalty payments to the government. The Karachaganak consortium is exempt from the export duty but the consortium pays additional capital gains tax to the government as part of the recently completed settlement that led to an increase in Kazmunaigas's stake. It remains to be seen whether the North Caspian Operating Company, which is developing the Kashagan field, would be subject to the export duty.

A New Supermajor: How the TNK-BP Acquisition Could Affect Trade Flows  

Rosneft's acquisition of TNK-BP on 21 March creates the largest publicly-listed oil producer in the world in terms of production volume, with forecast output of around 4.1 mb/d in 2013, or 37% of Russia's total and almost 5% of global oil output. Rosneft also now accounts for around a third of Russia's refining capacity, which is itself the source of around 7% of world refinery throughput. BP retains about a 20% share in the company and CEO Bob Dudley will gain a seat on Rosneft's Board. BP gains the foothold in prospective Russian arctic exploration that was the driver behind its failed deal with Rosneft in May 2011.  During Chinese president Xi Jiping's visit to Moscow on 22 March Rosneft and CNPC reportedly signed framework agreements (but not final contracts) to increase Russian oil exports to China, which would make China Russia's top crude buyer and may substantially alter the dynamics of Russian crude exports over the medium- and long-term. Logistical and supply-side challenges raised by this deal would also likely result in a re-allocation of Russian crude flows until 2018.

Show me the money. Hot on the heels of the $55 billion TNK-BP acquisition, Rosneft announced that it had agreed to a deal with CNPC to increase crude exports to China to as high as 620 kb/d over the course of 25 years. Rosneft obtained a $2 billion loan from China Development Bank Corp, reportedly getting advance payment for some of the deliveries. In addition to the Chinese loan, Rosneft's acquisition, the biggest since ExxonMobil's purchase of XTO in 2010, is also being financed by a $10 billion deal with Glencore and Vitol for prepayment of around 270 kb/d of Rosneft's volumes over the course of the next five years. The five-year deals, first reported in December 2012, involve Rosneft supplying 70% of the oil to Glencore and 30% to Vitol.  Rosneft is also seeking a $15 billion contract with Polish refiner PKN Orlen for 360 kb/d of crude over three years.

Upstream synergies. Rosneft plans to find synergies with TNK-BP's assets in East Siberia in order to reduce access costs to pipeline infrastructure. At a recent press conference, Rosneft head Igor Sechin valued those synergies at about $4 billion-$5 billion. Sechin noted that TNK-BP's Suzun, Lodochnoye, and Tagul fields would be used to set up a centralized production hub at the existing 450 kb/d-Vankor field. Rosneft now plans to link the Suzun and Tagul fields, expected online after 2016, with the Vankor-Purpe pipeline rather than via Transneft's Zapolyarnoye-Purpe line as TNK-BP had planned. These fields could add an additional 200 kb/d to flows from a Vankor hub. Also, the deal could lead to economies of scale for several undeveloped assets, such as Yurubcheno-Tokhomskoye, that are close to newly acquired TNK-BP licenses.

Shifting flows. The acquisition and the reported China/Russia agreement have sparked much speculation about how they would impact Russian crude export flows. Currently Rosneft supplies China with 300 kb/d via the Eastern Siberian Oil Pipeline's (ESPO) spur from Skovorodino, Russia to Daqing, China, which is running at its design capacity. How it plans to ship the incremental crude volumes it has reportedly pledged to China in exchange for the loan, and from which field they will flow, remain uncertain especially after 2018. Incremental volumes via ESPO are slated to increase slowly over time by 100 kb/d by end-2017 before adding a total of 300 kb/d from 2018-2037 according to the terms of the framework agreement obtained by Bloomberg.  With Rosneft crude production projected to increase only modestly over the next few years, existing volumes from TNK-BP field's are likely to be used to make up the difference.

Currently TNK-BP sells around 375 kb/d of crude under long-term contract via western outlets and sells 150 kb/d in spot volumes from Kozmino, at the Pacific end of the ESPO pipeline. It is the latter volumes that would, on the face of it, be the most likely candidate to be shifted by Rosneft to China in fulfillment of its contract.  There are four viable export routes through which Rosneft could supply Chinese refiners:

  • Via Kazakhstan on the Atasu-Alashankou pipeline. Currently running close to its capacity of up to 280 kb/d, this line could be increased to over 300 kb/d using drag reducing agents. According to Bloomberg, 140-200 kb/d of incremental volumes would flow via this route and would require an expansion. So far this prospect looks a likely but potentially complex option given Rosneft's swap arrangement with Kazakhstan's Pavlodar refinery.  Following the newly created customs union between Russia, Belarus and Kazakhstan, Rosneft's exports to Pavlodar would remain duty free, but
A New Supermajor: How the TNK-BP Acquisition Could Affect Trade Flows  (continued) 

Kazakhstan would be required to refund the Russian state for the excise duties collected on the 'swap' exports to China. Judging by past disputes between Russia and other FSU states, such an arrangement could prove problematic. China has long complained that its Western refineries do not receive enough FSU crudes, but this arrangement is unlikely to increase overall Chinese imports and thus might not be the deal which China is looking for in the long term. There would also be quality issues as Urals would be swapped for comparatively waxy, paraffinic crudes which would be of a lower quality. Finally, Transneft would likely be loathe to see significant volumes exported without using its network.

  • The Daqing ESPO spur. As a short-term option, Rosneft could increase supplies to Daqing using drag reducing agents to increase the spur's capacity, but this would be unlikely to add more than 100 kb/d. To facilitate flows of up to 600 kb/d, new infrastructures such as pumping stations and a twinned line would likely be required. Indeed China has been lobbying for the construction of a second pipeline parallel to the first, which would double capacity. This, together with the previous option, would serve the purpose of supplying China's inland refineries, which frequently face challenges sourcing feedstock.
  • By rail via Mongolia. Before the start-up of ESPO, Russia railed crude to Western China via Mongolia. This is a viable short-term route, but the high cost of rail versus pipeline shipments could prove uneconomical over the long term.

  • ESPO shipments via Kozmino. In the short term, Rosneft is likely to divert roughly 100 kb/d in shipments to the Daqing spur. This would shift formerly spot-based crude supplies to long term contractual volumes. This would be a favorable option given CNPC and Rosneft's plan to build a refinery/petrochemical plant at Tianjin.  The JV, China-Russia Western Petrochemical Company, would take around 180 kb/d of incremental Russian crude. In the medium term, with increasing East Siberian supplies, shipments via Kozmino could rebound. Although overall ESPO volumes to Asia may not change, this shift may impact ESPO-grade crude volumes marketed on a spot basis and overall Kozmino liftings. Such a shift would also likely reduce ESPO supplies to existing customers in Japan, Korea, and the US west coast.
  • The TNK-BP Rosneft deal should be seen in the broader context of closer trade ties between Russia and China such that it would result in more contractually supplied volumes to China, as opposed to predominantly spot-based supplies. Over the short term, Rosneft will likely pull incremental volumes for China from TNK-BP fields in East Siberia or even Samotlor in West Siberia. Volumes from Kozmino would thus have to be reduced even if supplies to China were sourced and routed through other channels. This would likely occur until Rosneft unwinds its long-term contracts to European customers out of Baltic and Black Sea ports, which would allow more Western Siberian crudes to head to China to the detriment of European customers.

FSU net exports surged by over 600 kb/d to 9.62 mb/d in February, their highest level since April 2012, after crude shipments rose by 350 kb/d and product outflows by 280 kb/d. Surging flows of Urals, Tengiz and CPC blend crudes via Black Sea terminals helped lift exports, more than offsetting decreases in the Baltic, where pipeline maintenance and cold weather tempered shipments. All refined product categories rose, notably gasoil which increased by 150 kb/d over January, with many cargoes of the 10 ppm specification destined for European markets.

Latin America

Brazil - February preliminary: Planned maintenance dragged down Brazilian crude output by 40 kb/d m-o-m to 2.02 mb/d in February.  Maintenance reduced output by 85 kb/d at the Marlim, Marlim Leste, and Roncador fields in February. But Santos basin production is increasing rapidly with the newly online Sapinhoa, Sapinhoa Norte, and Báuna fields. Petrobras plans four more platforms by year-end at existing fields Roncador, Parque das Baleias, and Lula as well as at the new Papa Terra field. Based on preliminary estimates for March, production in 1Q13 stands 120 kb/d down on the year. Chevron has reportedly received approval from regulator ANP to restart some of the production at the Frade field, which has been shut since March 2012.  The field produced around 60 kb/d before it was shut.  Once the field is producing again, which could take a couple months, output levels are expected to be about half of that volume. 


Sudan and South Sudan: Production is reported to have restarted at the Thar Jath field in Block 5A in South Sudan in early April, ending a 13-month outage. Media reports indicate that this oil should reach Port Sudan in the north at the end of May and that flows of 150-200 kb/d are expected by 15 April. We expect a slower ramp up to production, with the majority of the increase taking place in 3Q13. The forecast for 2H13 production remains unchanged at a conservative 110 kb/d. Clearly, there is some upside risk to this forecast since pre-shutoff production totalled 340 kb/d, but we expect technical issues with restarting production and non-technical issues related to security to keep production restrained for the remainder of the year.

OECD Stocks


  • OECD commercial total oil stocks drew by a seasonal 32.9 mb to stand at 2 664 mb by end-February, retaining a surplus to five-year average levels for a sixth consecutive month.
  • End-January data were revised upwards by 8.5 mb meaning that last month's stock build was steeper than first estimated and that inventories remained in surplus for a fifth consecutive month, rather than in deficit as presented in last month's Report.
  • After drawing by a seasonal 29 mb, total product inventories covered 31.1 days at end-February, 0.2 days lower than a month earlier. Crude dropped by a seasonally-steep 4.4 mb, driven by an exceptional 13 mb drop in Japan, the steepest monthly fall since 1997 in that country.

OECD Inventory Position at End-February and Revisions to Preliminary Data

OECD commercial total oil stocks drew by a seasonal 32.9 mb to stand at 2 664 mb by end-February. Refined product inventories led the draw, falling by 29 mb over the month. As in recent months, 'other products' accounted for the bulk of the product inventory decline as they fell by a steep 16.3 mb, centred in the US amid surging exports and cold-weather related demand. Seasonal maintenance at many OECD refineries also helped draw down product stocks. A seasonal dip in middle distillate inventories was much shallower than typical for that time of year. Consequently, their deficit to average levels narrowed to 27.9 mb from 44 mb at end-January. All told, total products covered 31.1 days at end-February, 0.2 days lower than a month earlier.

Crude oil stocks fell counter-seasonally by 4.4 mb, a surprising dip given that OECD throughputs had been dropping. This resulted from an eye-catching 13 mb draw in Japan, the steepest monthly draw since 1997 in that country, apparently explained by a combination of temporary and structural factors including weather-related import delays and inventory draws by refineries that have been slated to close down in compliance with new Japanese emission rules. Elsewhere, crude oil stocks posted builds, including gains of 10.5 mb in OECD Americas and 1.4 mb in OECD Europe.

All OECD regions reported draws in total oil inventories. Stocks in OECD Americas and OECD Asia Oceania dropped by 17.4 mb and 14.5 mb, respectively, while those in OECD Europe inched down by 1 mb. Although the position of total OECD inventories versus five-year average levels remained relatively unchanged and in surplus for a sixth consecutive month, the regional spread of that overhang changed. The deficit of OECD Europe narrowed by 14 mb to 49 mb, the surplus of OECD Americas dropped by 8 mb to 59 mb, and the steep draw in Japanese crude stocks caused the deficit of OECD Asia Oceania inventories to deepen from 1 mb at end-January to 9 mb one month later.

Upon the receipt of more complete data, the January build in OECD industry total oil inventories was revised upwards by 8.5 mb to 31.3 mb. This meant that OECD holdings remained 3.4 mb in surplus to five-year average levels, rather than the 4.4 mb deficit presented in last month's Report. A 10.3 mb upward adjustment to the estimate for OECD Europe accounted for the bulk of the revision, offsetting minor 0.9 mb downward adjustments in both OECD Americas and OECD Asia Oceania.

Preliminary data indicate that OECD industry inventories declined by a further 9.7 mb in March, steeper than the 3.2 mb draw for the month. Falling motor gasoline (-7.5 mb) and middle distillate (-7 mb) inventories drove stocks lower, more than offsetting a weaker-than-seasonal 2.9 mb build in crude oil. On a regional basis, total oil inventories in OECD Americas and OECD Europe slipped by 9.1 mb and 3.9 mb, respectively. Meanwhile, holdings in OECD Asia Oceania rose by 3.3 mb.

Analysis of Recent OECD Industry Stock Changes

OECD Americas

Total industry oil inventories in the OECD Americas region drew by a steep 17.4 mb in February, driven by yet another plunge in 'other product' stocks (mainly propane) of 12 mb. Total product stocks plummeted by 26.5 mb, more than offsetting a seasonal build in crude of 10.5 mb. The aggregate draw was considerably steeper than the 9 mb five-year-average, causing the surplus to average levels to narrow to 59 mb, from 67 mb at end-January. Following their steep draw, total product stocks swung back to a 1 mb deficit to average levels, after two months in surplus. Demand cover inched down seasonally, total products now cover 28.5 days of forward demand, 1 day less than at end-January. Middle distillate inventories decreased seasonally by 10 mb and remained 22 mb in deficit to the average, but comfortably within the five-year range. Gasoline fell by a seasonal 6.6 mb with stocks remaining lower than a year ago on an absolute basis but level based on days of forward cover.

Preliminary US weekly data from the Energy Information Administration indicate that by end-March US stocks had fallen by a further 9.1 mb as a 17 mb draw in products outweighed a 7.3 mb build in crude. The product draw was led by seasonal falls of 7.7 mb and 7.2 mb in middle distillates and gasoline, respectively. In contrast, declines in 'other products' slowed to a 1.9 mb draw. This came as something of a surprise, given that propane exports were expected to rise in March following the expansion of Enterprise Partners' Houston terminal, which nearly doubles export capacity there to 250 kb/d. The shallow March draw in 'other products' may reflect a dip in heating demand in response to warmer temperatures.

Tightness in the PADD 1 (US East Coast) gasoline market has been very much in focus lately. The latest weekly data show that low inventories in January and early-February drew in supplies from Europe and India which helped stocks to rebuild. PADD 1 gasoline stocks built by 7.5 mb from the turn of the year to early March before receding slightly as the region transitions from winter- to summer-grade gasoline. Nation-wide, US gasoline stocks have fallen steadily so far this year and now stand 12 mb below early-January.

OECD Europe

OECD European commercial total oil inventories inched down marginally by 1 mb in February after a 2.1 mb decrease in refined products outweighed a counter-seasonal 1.4 mb build in crude, while NGLs and other feedstocks slipped by 0.3 mb. The product draw was exceptionally shallow for that time of year (compared to a five-year average draw of 11.8 mb for the month) after middle distillates posted a counter-seasonal build of 1.4 mb, versus an average draw of 9.5 mb. Consequently, the deficit of middle distillate stocks to average levels narrowed to 10 mb from 21 mb in January. This continued restocking is surprising given cold weather in the region in February, which drew down German tertiary heating oil tanks to 53% of fill. This was their second consecutive monthly decline, bringing them down by 6% at end-February since end-December. Despite their build, crude oil inventories remained at a 15 mb deficit to seasonal levels at end-February, largely due to refinery rationalisation in the region.

Preliminary data from Euroilstock indicate that EU-16 inventories fell by a counter-seasonal 3.9 mb in March. Holdings of refined products slipped by 1.6 mb while crude dropped by an additional 2.3 mb. All refined product categories fell except fuel oil. Middle distillates inched lower by 0.4 mb, weaker than the 1.4 mb five-year average draw for March. Data pertaining to refined products held in independent storage in Northwest Europe indicate that stocks rose in March with all products posting increases except gasoline which inched down.

OECD Asia Oceania

Industry total oil inventories in OECD Asia Oceania plummeted by 14.5 mb in February, led by an exceptionally steep plunge of 16.3 mb in crude oil. Japan accounted for 13 mb of that draw, with preliminary data from the Ministry of Energy, Trade and Industry (METI) indicating that commercial crude oil stocks fell to 97 mb by end-month, their lowest level since the IEA started collecting data in 1984. If confirmed, this plunge would also be the steepest monthly dip since August 1997. According to METI, several factors account for the drop. Firstly, adverse weather disrupted unloading operations at many ports and cut crude imports by about 400 kb/d. Secondly, several simple refineries are being decommissioned in Japan to comply with new legislation on refinery efficiency that takes effect in 2014. Finally, refiners may have sought to reduce their crude inventories ahead of the new Japanese fiscal year in April, as there are tax benefits associated with shifting inventories from crude to products at this time of year.

Regional total products stocks inched down by 0.3 mb shallower than the 5.9 mb average draw for February. 'Other products' accounted for the bulk of the drop, falling by a seasonal 3.4 mb over the month. Middle distillates increased by 1.2 mb, in sharp contrast to the 4.7 mb average draw. Total products now cover 21 days of forward demand, a rise of 1 day compared to a month earlier.

Preliminary weekly data for Japan from the Petroleum Association of Japan (PAJ) point to a counter-seasonal 3.3 mb build in total oil inventories in March. Refined product holdings led the increase with a 5.2 mb build spanning all product categories. Crude oil stocks fell by 2.2 mb, in line with seasonal trends, after crude runs picked up and outpaced imports.

Recent Developments in Singapore and China Stocks

Weekly data from International Enterprise indicate that onshore refined product stocks in Singapore declined by 5 mb over March. Plummeting residual fuel oil (-5.2 mb) led the decline, falling to their lowest level since July 2009 on weak imports from Middle Eastern refiners undergoing turnarounds and robust demand in China, Malaysia and Australia. In contrast, middle distillates inched marginally lower by 230 kb while light distillates rose by 450 kb. In total, inventories there amount to 38 mb, comfortably above both year-ago and five-year average levels.

According to data from China, Oil, Gas and Petrochemicals (China OGP), commercial inventories in China rose by an equivalent 1.7 mb (data are reported in terms of percentage stock change) in February led by a 12.8 mb (18%) surge in gasoil inventories. Meanwhile, gasoline stocks fell by 8% (5.2 mb) while kerosene inched up by 2% (200 kb). It is unclear whether the large gasoil build reported since the beginning of the year, which now reaches 23.7 mb, can be entirely attributed to higher product output following the recent start-up of new refining capacity, or reflects in part unreported upward revisions to 2012 data.

China's commercial crude oil stocks reportedly fell by 6.1 mb, the fifth consecutive monthly decline. Inventories now stand 27 mb lower than at end-September. It is worth noting that the implied crude stock change, calculated as the sum of net crude imports and domestic production minus refinery throughputs, pointed to a build for the second consecutive month in February. Similar implied builds in the past have suggested that China had been building its strategic reserves. This time around, the implied build might reflect in part the building of minimum operating stocks at newly commissioned refineries. In 1Q13 China commissioned 500 kb/d of new refining capacity, but China OGP data have not shown any increase in crude oil stocks since 3Q12. Although decreases in commercial crude stocks may have offset recent increases in minimum operating level requirements, new refineries may not be fully captured in the data.

Quality Time: The Changing Composition of US Crude Imports

Surging light tight oil (LTO) production in the US has not only dramatically reduced US crude imports requirements but also altered the quality of the US import barrel. The US has almost halved net crude and product imports from over 12 mb/d in 2005 to 7 mb/d in 2012. Unsurprisingly, given the quality of incremental domestic supply, light and medium sweet crude imports have been the first ones to give. Data from the US Energy Information Administration shed some light on the market response to this new supply and its effecting on crude trade flows.

Light and Medium-light crude imports are declining. While total US crude imports have plummeted by 1.6 mb/d since 2005, to average 8.5 mb/d in 2012, the composition of these imports by country of origin has also changed. In 2012 alone, crude imports from Canada have surged by almost 8%, to 2.4 mb/d, reflecting rapid growth in oil sands production. In contrast, waterborne crude imports have plummeted even faster than the aggregate decline in imports, plunging by 16% (970 kb/d).  The largest annual drop in imports centred in PADD 3 (the Gulf Coast), where crude imports last year fell by 440 kb/d to 4.5 mb/d and where Canadian imports accounted for only 2% (around 100 kb/d) of total crude imports.

Light and medium-light crudes (defined as having an API gravity above 40 and between 35-40, respectively) account for 40% of the 2.2 mb/d decline in imports since 2005.  Half of the 3 mb/d decline in waterborne imports since 2005 has been concentrated in these lighter crudes.  But these trends has accelerated in just the last two years.  Thus, in 1Q12 light and medium-light imports accounted for 17% of total imports, but by January, that percentage had fallen to 13%. Also, the import decline has been concentrated in PADD 3. Between 1Q12 and this January, US imports of light and medium-light crude fell by 390 kb/d, including 330 kb/d in PADD 3.

In January 2013 imports increased. Contrary to the declining trend in imports seen over the course of 2012, US crude imports slightly increased by 360 kb/d to 7.9 mb/d in January from the previous month, though they remain 390 kb/d lower than a year ago.  Recent import data indicates that volumes from Nigeria have increased, especially into PADD 1 (the East Coast). In fact, as crude imports increased by 380 kb/d m-o-m in January, Nigerian imports rose by 210 kb/d and Canadian imports increased by 195 kb/d.

Outlook for 2013. Rising production levels of US light tight oil, Canadian oil sands growth, and shifting demand trends will affect the US crude import composition this year. In January, the US was still importing 1.06 mb/d of light and medium-light crude, centred mostly in PADD 3, followed by PADD 1 and 2 (the Midwest). Over the past year, PADD 3 imports of light and medium-light oil have already been cut in half to 360 kb/d. As a result, light and medium-light imports account for only 10% of the remaining imports in PADD 3 in January. In the coastal areas, PADD 1 and 5 (West Coast), light and medium-light sweet crudes still represent 25% of crude imports and accounted for almost half of total light and medium-light US imports in January.

With the advantage of new rail links and favourable refinery margins, some coastal refineries are using more domestic crude and are increasing throughput.  On the East Coast, the Phillips 66 Bayway refinery started to take US crude in 2012 in a five-year take or pay contract. In the coming year, import data will begin showing more substitution of light imports for light domestic crudes. Yet signs are already emerging that medium-light imports are declining possibly from increased refinery blending. For example, Phillips 66's refineries in PADD 1 decreased medium-light imports by 10% last year. For coastal refineries, net crude oil inputs declined by 170 kb/d in 2012, at the same time that imports declined by 230 kb/d.  Therefore, domestically-sourced inputs increased by 60 kb/d.

Though total crude import levels are decreasing, PADD 2 imports of Canadian oil have increased by 160 kb/d over the last year, accounting for 98% of total imports in this area. Nevertheless, some refineries are keeping Canadian imports constant and using increased domestic supplies. For example, Holly Frontier has doubled its throughput during the last three years, without increasing imports.

Company behaviour differs. Looking more closely at the EIA data on crude deliveries to individual companies reveals differing preferences. A refinery's crude slate may depend on a variety of factors, including, but not limited to, its infrastructure and logistical links, fixed-term crude supply contracts, or the upstream portfolio of its parent company. Valero, the largest independent refiner in the US with PADD 3 throughput capacity of 1.2 mb/d, and accounting for 16% of PADD 3 refiner crude input, is a case in point. Its PADD 3 refineries have shown one of the most dramatic changes in purchasing behaviour over the last year. They imported around 80% of their light sweet feedstock in 1Q11, but by 4Q12, all of this had been replaced with domestic supplies.  In contrast, CITGO's PADD 3 refineriess continued to import 40% medium-light and light sweet crudes over the course of 2011 and 2012.  Only in January did these volumes decline.

As light tight oil production continues to increase in the upcoming months, further changes to the US crude import slate are likely.  Rising production levels, the development of oil transportation infrastructure, refinery behaviour, demand and prices will all influence the pace and composition of the decline in imports to the US and North America. 



  • Oil futures posted month-on-month losses in March, under the weight of renewed pessimism for the global economy and seasonally weaker crude demand. Brent was last trading at $106/bbl and WTI around $94/bbl.
  • The forward price spreads and differentials for benchmarks Brent and WTI have shown diverging trading patterns so far this year. Improved North Sea crude supply and a steady, albeit slow, increase in pipeline and rail flows of Canadian oil and domestic grades from Cushing to the US Gulf Coast refining centre have been the main catalysts for the change. Dated Brent's premium to Dubai crude hit a nine-month low in early April on higher North Sea supplies and relatively stronger demand for fuel oil-rich Middle East grades linked to Dubai.
  • Refined product crack spreads in March weakened for the light end of the barrel while stronger demand and low inventory levels, especially in Asia, supported fuel oil differentials. Cracks were also under pressure as refineries returned from maintenance in the US and Europe.
  • Despite stronger demand for Middle Eastern crudes from Asian refiners exiting turnarounds, rates on the benchmark VLCC Middle East Gulf - Asia route remained range bound between $8/mt and $10/mt throughout March as oversupply in the tonnage pool weighed heavy.

Market Overview

Oil futures posted month-on-month losses in March, under the weight of renewed pessimism for the outlook for the global economy. Seasonally weaker oil demand against a backdrop of peak refinery maintenance turnarounds added to the downward pressure on prices.

Brent futures saw the sharpest decline, off $6.53/bbl to $109.54/bbl on average in March. WTI prices were down a much smaller $2.36/bbl to average $92.96/bbl. By early April, price trends showed a marked divergence from March levels, with Brent off a steep $3/bbl from March averages while WTI was trading about $1/bbl above the previous month, at $106/bbl and $94/bbl, respectively. Weaker-than-expected global macro-economic data, while tempering oil prices, has so far had minimal impact on robust equity markets. Oil futures prices in March turned lower even as the S&P 500 index soared to record highs. While net long positions on the ICE futures exchange are now lower than the record high contract volumes posted on 5 February, they remain at lofty levels. Market activity measured as open interest in futures contracts saw NYMEX WTI rebound to an all-time record high in March.

The world's two major oil price benchmark grades have shown diverging trading patterns in recent months. Geopolitical issues and European economic woes are exerting greater pressure on Brent. US WTI continues to reflect regional developments, including very high crude stock levels, transportation bottlenecks at the pivotal midcontinent region and record growth in Canadian and US domestic crude supply.

The structure of forward price spreads and differentials for benchmarks Brent and WTI has shifted, with a marked increase in North Sea crude loadings and a steady, albeit slow, increase in pipeline flows of crude from Cushing to the US Gulf Coast refining centre the catalysts for the change. North Sea supplies are forecast to trend higher following Total's restart of production from its Elgin-Franklin platform complex and higher and more consistent output from the UK's Buzzard field.

As a result, the price spread between WTI and Brent futures narrowed to the smallest discount since June 2012, closing at -$11.43/bbl on 5 April. That compares with average discounts of $16.58/bbl in March and $20.75/bbl in February. 

In the US, the WTI M1-12 forward spread moved into backwardation on expectations that increased pipeline and rail capacity and the end of seasonal maintenance turnarounds would reduce surplus inventories at Cushing, which are currently hovering near record levels of around 50 mb. As a result, the WTI M1-M12 contract spread strengthened, to around $2.25/bbl in early April compared with $1.65/bbl in March and -$0.05/bbl on average in February. That compares with an average WTI M1-M12 contract spread of -$1.84/bbl in 2012.

In contrast, an increase in May loading schedules for the four North Sea crude streams that physically underpin the Brent futures contract was a factor in the narrowing of the backwardation in Brent prices. The Brent M1-12 contract averaged about $4.25/bbl in the first week of April compared with near $6/bbl in March and $7.85/bbl in February. Meanwhile, Dated Brent 's premium to Dubai hit a nine-month low in early April and was actually traded at a $0.15/bbl premium on 5 April. The dramatic shift reflects higher North Sea supplies and relatively stronger demand for fuel oil rich Mideast grades linked to Dubai.

Despite the current price weakness, demand from refiners is expected to rebound sharply in coming months, from a low of 73.9 mb/d in March to 76 mb/d in June as the summer driving and cooling season gets underway.

Futures Markets

Activity Levels

Market activity in NYMEX WTI and ICE Brent futures was up year-on-year on both exchanges between 26 February and 2 April, with open interest for ICE Brent in London posting a 27.4% increase year on year versus a more modest 10.4% rise for NYMEX WTI in New York over the period. On a monthly basis Brent open interest has been gaining on NYMEX volumes but the gains stalled last month, and indeed, the gap between the two benchmark grades widened for the latest period.  Trading volumes in futures contracts have been in line with previous trends, with NYMEX WTI down 21% y-o-y while ICE Brent posted a 12.4% y-o-y growth.

As WTI regained momentum from a 2013 low of around $91.75/bbl to slightly over $97/bbl in the beginning of April, money managers in NYMEX WTI have raised their net long exposure by 20.2%, back to mid-February levels in futures only contracts. Hedgers, which includes producers, merchants, and the processors and end user category, hereinafter labelled 'producers', have instead cut in half their net exposure, still on the net long side.

Conversely, hedge funds in London reduced their net long bets in ICE Brent with respect to 26 February levels over the reported period, following a steep downturn in ICE Brent futures. A modest recovery in weak North Sea Brent prices in the last week of March led hedge funds to mitigate the reduction in their overall net long futures positions. Offsetting swap dealers and money managers, the 'producers' category took a progressively shorter net position, notwithstanding the falling price, suggesting that hedgers had been expecting the price to fall further.

Financial Regulation

Some relevant financial rules following the financial reforms on both sides of the Atlantic came into force last month. On 11 March, the US Commodity Futures Trading Commission (CFTC) adopted mandatory central clearing for interest rates and credit default swaps. Importantly, such requirement does not apply to non-financial entities hedging their risks. New regulations went into effect 10 April for the US for derivatives end-users, notably including energy companies, that call for users to comply with Dodd-Frank Act regulations for record-keeping and reporting trades to swaps-data repositories.

In the EU, on 15 March the new European Market Infrastructure Regulations (EMIR) came into force. Drafted by the European Securities and Markets Authority (ESMA) the regulations became effective after the European Parliament and European Council adopted the technical specifications. The next step is for the European Commission to endorse the EMIR. The regulations involve central clearing for certain classes of over-the-counter (OTC) derivatives and data reporting to trade repositories. Central clearing counterparties have six months to apply for authorization by ESMA, which will in turn have up to six months to give approval, suggesting that the effective phase-in of EU derivative rules could be completed in 2014. Initial notifications regarding work to prepare for the clearing obligation will be issued on 15 April. Reporting for all asset classes, including energy derivatives, will begin on 1 January 2014.

Spot Crude Oil Prices

Spot oil prices for benchmark crudes cascaded lower in March but the level of decline varied across the different grades. Increased supplies of light crudes in Europe weighed on Brent while stronger demand for heavier Mideast crudes stemmed the decline in Dubai prices. Prices for WTI posted the smallest decline on increased flows out of the landlocked US Midcontinent.

Rising supplies of North Sea crudes weighed on spot prices for Dated Brent, down by $7.86/bbl to $108.45/bbl on average in March. Spot prices for Dubai declined by around $5.60/bbl, to $105.54/bbl ahead of the peak turnaround period in Asia (April). WTI spot prices posted the smallest decline as increased pipeline and rail capacity eased the transport bottleneck in the landlocked US midcontinent, off by $2.35/bbl to an average $92.91/bbl last month.

The shift towards more transport capacity in North America is behind the steady increase in WTI over March and into early April as the glut of crude depressing prices in the Midcontinent is reduced. The end of refining maintenance is also supporting prices relative to other benchmark grades. Roughly 1.2 mb/d of pipeline capacity and 600 kb/d of rail capacity is expected to come online this year. Relatively stronger WTI prices to weaker Dated Brent saw the price differential for the two crudes narrow sharply, to around $11.65/bbl in early April compared with $15.55/bbl in March and $21.04/bbl in February.

In Europe, increased North Sea output, higher Russian exports and surplus African crudes backed out of the US market all weighed on spot prices in March. However, the price differential between Urals and Brent strengthened in Mediterranean markets on increased demand as refiners prepared to come out of turnaround. Urals was trading at a $0.65/bbl discount to Brent in early April compared with a steeper -$1.64/bbl in March and -$1.37/bbl in February.

After a volatile two years which saw persistent disruptions in North Sea supplies and hence upward price pressure on the benchmark crude, upcoming changes in the Brent contract may provide a more stable foundation. After months of discussion, an agreement was reached on the introduction of quality premiums to the underlying BFOE contract that are aimed at increasing liquidity in the Brent market, arguably the industry's global oil benchmark.

The Brent price is currently based on four different North Sea crudes of varying quality - Brent, Forties, Oseberg and Ekofisk (BFOE). Sellers normally deliver Forties as this is the usually the cheapest of the four crudes. However, production of Forties has been on the decline, leading to speculation that the increasingly shrinking market is subject to manipulation. The introduction of quality premiums aims to give sellers some price incentive to deliver Oseberg and Ekofisk which it is hoped will increase the overall number of BFOE cargoes in play and reduce price volatility. The introduction of quality premiums will be effective from June 2013.

In Asia, relatively strong fuel oil cracks have increased demand for heavier Middle East crudes, which have supported Dubai prices and helped narrow the differential to relatively weaker Brent. The Dubai-Brent discount narrowed sharply over the past six weeks, to just -$0.15/bbl in early April compared with -$2.90/bbl on average in March and -$5.18/bbl in February.

Spot Product Prices

Refined product crack spreads in March weakened for the light end of the barrel while stronger demand and low inventory levels, especially in Asia, supported fuel oil differentials. Cracks were also under pressure as refineries returned from maintenance in the US and product supplies increased.

Although gasoline crack spreads in March were generally down from the previous month, differentials were still relatively firm compared to the last few months. On the US Gulf Coast, stronger gasoline crack spreads proved to be the exception, rising by almost $2/bbl to near $9/bbl. US refiners are in the middle of switching to summer grade fuel, lending further support to crack spreads. Gasoline cracks in Europe were down about $1.50-$1.75/bbl in March, to $10.35/bbl in Rotterdam and $12.66/bbl in the Mediterranean. Albeit down from February's exceptional levels, Europe's crack spreads were, in part, supported by the open arbitrage to the US. In Asia, unplanned refinery outages and ongoing maintenance stemmed the decline, with gasoline cracks in Singapore down $3.25/bbl but still a robust $18.55/bbl.

Naphtha crack spreads were down month-on-month in Europe and Asia. In Asia, naphtha cracks fell to their lowest range in several months due to reduced demand from the petrochemical sector as many of the facilities in Asia and the Middle East started spring maintenance. Also, naphtha prices were also partly affected rising volumes of US LPG exports and associated lower cost LPG, a relatively cheaper feedstock substitution at petrochemical plants.

Gasoil crack spreads fell across all regions as seasonal winter demand for heating oil faded in the Northern Hemisphere. The magnitude of the drop in European crack spreads surprised to the downside given much colder-than-normal weather. Weaker Asian gasoil cracks were partly due to heavy flooding in East Asia and Indonesia. Fuel substitution with natural gas also pressured gasoil. However, jet/kerosene crack spreads posted the biggest declines compared to other products in March. Seasonal weakness pressured the spread, though the downward decline eased at the end of March.

Fuel oil crack spreads improved in March but were still largely in negative territory. In Singapore cracks strengthened on reduced fuel oil imports from Middle East due to heavy refinery maintenance in the region and a sharper than expected drawdown in stocks. In addition, China's demand for fuel oil has reportedly risen. The arbitrage opportunity for fuel oil export from Europe to Asia was mostly open, resulting in firm crack spread in Europe.


Despite stronger demand for Middle Eastern crudes from Asian refiners exiting turnarounds, rates on the benchmark VLCC Middle East Gulf - Asia route remained range bound between $8/mt and $10/mt throughout March as oversupply in the tonnage pool weighed heavily. Suezmax markets fared little better but sustained fixings ahead of the Easter holidays for cargoes into Europe did lift rates on trades out of West Africa as tonnage tightened. Consequently, the benchmark West Africa - US Gulf Coast trade strengthened to a high of over $15/mt on 28 March. However, as has so often been the case recently, rates were on the slide by early-April.

In Northwest European Aframax markets the picture was mixed. Trades out of Russian ports Ust Luga and Primorsk experienced ice-related firming while rates for trades out of North Sea terminals remained depressed. The benchmark Aframax Baltic - UK trade surged to a high of $12/mt at the time of writing after late-season thick sea ice in the Baltic delayed vessels. Consequently, the pool of suitable and available vessels dwindled which makes further strengthening likely. Conversely, the tonnage pool in the North Sea was swollen by vessels unsuitable to visit Baltic ports competing for North Sea cargoes.

Rates for clean product tankers experienced a mixed bag during March. Trades into Asia continued to strengthen throughout the first half of the month led by increased naphtha demand in Japan and Korea which was largely supplied by Middle Eastern refiners returning from maintenance. However, by mid-month naphtha cracks had weakened and thus demand tapered off. Accordingly, rates on the Middle East Gulf - Japan route breached $32/mt on 21 March before falling back to below $29/mt by early-April. In the Atlantic Basin the picture was more sombre. In response to falling import demand on the US Atlantic Coast, the benchmark transatlantic gasoline trade between the UK and US Atlantic Coast weakened steadily over the month so that by early April rates stood at under $24/mt.



  • Global refinery crude throughput estimates for 1Q13 have been revised slightly higher since last month's Report, mainly on higher-than-expected February crude runs in Europe, supported by stronger than usual gasoline crack spreads in the Atlantic basin for that time of year.
  • European refiners started turnarounds in March in the wake of heavy maintenance in the US in January and February. Refiners in Asia, FSU and the Middle East were expected to follow suit. Overall off-line capacity is expected to peak in April at around 6.8 mb/d.
  • The estimate of non-OECD crude runs for 1Q13 has been reduced by 160 kb/d to 38.6 mb/d, as downwards revisions for Venezuela more than offset upward adjustments across Asia. A heavy maintenance plan in Asia looks set to curtail global crude demand until the end of the first quarter. Crude demand is expected to rebound in June and July, led by increased crude runs in North Africa and Latin America and the commissioning of new capacity in China.
  • Despite seasonal plant maintenance in Europe, FSU and Asia, refining margins dropped in March in the three major regions on the back of weak product demand. Heavy refinery maintenance peaking in April is expected to restore cracks and margins to more comfortable levels in the coming months, however.

Global Refinery Overview

The assessment of global throughput for 1Q13 has been revised marginally upwards, to an average 74.9 mb/d, on higher-than-expected February crude runs in Europe, when a spike in gasoline cracks led those refineries that were not undergoing maintenance to boost throughputs. As the peak maintenance season unwinds in the US, European refiners will start turnaround operations, followed in turn by refineries in Asia and the FSU.

Overall, global refinery maintenance is projected to peak in April, when a total of 6.8 mb/d of capacity is expected to be offline, including about one-third of Asian refining capacity. Crude runs are forecast to increase steadily in the second quarter to reach 76.9 mb/d in July, thanks to rebounding utilisation rates at North African and Latin American refineries and the start-up of new capacity in China.

Refining margins weakened across the board in March, with cracking margins down by $1.23/bbl in Europe (on Brent), $1.15-2.12/bbl in the US Gulf Coast and $1.86-2.12/bbl in Singapore (hydro-cracking). A drop in product prices led the decline in margins, while a relative strengthening in US crude prices (particularly LLS) also contributed.

The unwinding of an exceptionally heavy and early refining maintenance program in PADD 1 (the East Coast) and PADD 3 (the Gulf Coast) was a leading factor behind the decline in US margins in March. Gulf Coast margins plummeted on increased refinery operating rates, including the restart of Motiva's Port Arthur refinery. Weak domestic demand and a drop in exports helped keep product crack spreads under downward pressure. Yet refining margins fell even more steeply in PADD 2 (the Midwest), despite the fact that local refineries were still undergoing maintenance. In that case, weaker margins resulted from stronger relative prices for local crude grades, as crude inventories fell at Cushing and more crude moved out of the area. Cracks for unleaded gasoline fared comparatively well, consistent with an improvement in unemployment statistics in February. In contrast, continued weakness in the industrial recovery kept diesel cracks depressed. Jet fuel cracks posted the largest drop while fuel oil cracks remained unchanged.

In Europe, despite refineries entering spring maintenance, March margins dropped on weak product prices. Gasoline cracks weakened as a narrowing arbitrage to the US reduced export demand. Despite large amounts of naphtha heading to Asia, cracks narrowed as weak petrochemical margins reduced demand and petrochemical crackers either shut down or switched to cheaper propane.

Despite colder-than-normal weather, 0.1%-sulphur gasoil cracks took a big hit, which could suggest a large pull on tertiary stocks. Diesel cracks also narrowed on the back of weak economic activity. In contrast, fuel oil cracks improved. Complex margins in Europe rebounded by the end of March, however, likely reflecting the impact of heavy refinery maintenance, which was due to peak in April, when 1.3 mb/d of capacity was expected to be off-line.

In Asia, although refineries started maintenance operations, crack spreads for the major products weakened due to warm weather, maintenance at petrochemical crackers and a narrow middle-distillate arbitrage window to the west. As in Europe, fuel cracks bucked the trend, supported by shipping delays and reduced arbitrage opportunities from the West into Singapore.

OECD Refinery Throughput

Before they dropped in March, February OECD refinery crude throughputs rose by 350 kb/d, to 36.8 mb/d. Europe led the increase, spurred by relatively strong margins, while OECD Americas runs fell by 380 kb/d on heavy maintenance in the US and Canada. OECD Asia Pacific runs increased by more than 2.3% as Japan refiners keep on maximising production to benefit as much as possible from the shutdown of nuclear capacity.

OECD crude runs are expected to dip by 845 kb/d to 35.9 mb/d in March, when most European maintenance is set to take place. Crude runs are also forecast to decline in OECD Asia Oceania, led by South Korea, which has already started reducing its crude imports in view of a heavy maintenance season peaking in April.

OECD Americas crude runs fell by 380 kb/d in February, as dips in Canada compounded the impact of persistently lower US runs. US throughputs dipped to around 14.3 mb/d in February, cutting plant utilisation rates down to 84%. Maintenance operations peaked in January with more than 2.0 mb/d of capacity offline, but 1.7 mb/d were still reported offline in February. Preliminary data for March show a progressive return of US crude throughput, mainly in PADD 1 and PADD 3. Refinery runs in PADD 5 continue to be constrained by Chevron's Richmond California refinery outage since a fire damaged a crude distillation unit last August. At the time of writing, the refinery has reportedly been cleared to resume full operations in early April.

With the end of the maintenance season, the restart of Motiva's 200 kb/d Port Arthur crude distillation and Richmond refinery, we expect 2Q13 US crude runs to average 15.1 mb/d.

OECD European crude runs surged 5% in February to 12.1 mb/d, as unseasonably high gasoline crack spreads in the Atlantic Basin encouraged higher refining activity. French, Italian and Dutch refineries that were not undergoing maintenance lifted their throughputs. In aggregate, French runs jumped by 13% on the month, while those in Italy gained 12% and 5% in the Netherlands. Crude intake is expected to fall to around 11.5 mb/d in May, following the full closure of Shell's Hamburg refinery and refinery downtime for maintenance.

In France, following Egyptian group Arabiyya Lel Istithmaraat's decision to withdraw its bid for Petroplus' Petite Couronne refinery, two new proposals were presented by Dubai-based Netoil and Libyan company Murzuk Oil and deemed valid by the plant's legal administrators.

Crude intake at OECD Asia Oceania refineries averaged 7.3 mb/d in February, close to the last record of February 2011. Crude oil processing increased by 5% in Japan and should remain above 3.0 mb/d as few turnarounds have been scheduled in the first half of this year.

After restructuring its refining industry, Japan is progressively streamlining its petrochemicals industry. Japan's basic chemical and petrochemical industry has embarked on its own set of measures, mainly centred on downsizing and optimising operations for the moment. Recently, Mitsubishi Chemical and Sumitomo Chemical have announced the permanent closure of a steam cracker at the Kashima and Chiba complexes, respectively. Further capacity closures and restructuring are expected in order for the industry to remain competitive. Crude runs in the OECD Asia Oceania region were also boosted by record high levels in Israel, following the completion of the expansion of Paz Oil's Ashod refinery at the end of 2012.

Non-OECD Refinery Throughput

The Non-OECD crude run estimate for 1Q13 has been revised down by 160 kb/d since last month's report, to 38.5 mb/d, as downwards revisions for Venezuela more than offset upward adjustments in Asia. Non-OECD refinery intake in 2Q13 is expected to remain constrained by heavy seasonal maintenance operations from March to May, peaking in most regions in April. Crude runs should recover in June with the restart of Libya's Ras Lanuf refinery, a recovery in Algerian runs and progressive improvement in Venezuela's Amuay refinery. Support will come also from new capacity coming on stream in China.

China processed about 9.87 mb/d in February, up 6% from the same period last year, a growth due in part to the commissioning of Sinopec's new Maoming refinery last November. The plant started operating at full rates earlier this year.

The Chinese maintenance season is set to peak in April with about 900 kb/d of refining capacity offline. Petrochina's Guangxi, Qinzhou and Liaoyang refineries and Sinopec's Guangzhou and Qilu refineries are among the major plants scheduled for planned maintenance during this month.

Maintenance shutdowns and weak refining margins should pressure China crude runs in 2Q13 despite new capacity coming online during this period. Petrochina has just completed a crude pipeline to supply its new 200 kb/d Pengzhou refinery, which should start trial runs in April. From 3Q13 onwards, refining activity should rebound with the gradual ramp up of new capacity. Over the third quarter, Sinopec's 240 kb/d Quanzhou refinery is expected to start operating and by the end of the year, Sinopec's 160 kb/d Yanzi refinery expansion and CNOOC's 140 kb/d Zhejiang expansion are projected to come online.

Other Asia crude runs reached 9.8 mb/d in January, on the back of strong data in India, Singapore and Indonesia. Indian crude runs reached a record high of 4.5 mb/d as planned maintenance at Reliance's refinery was postponed. Preliminary data for February show a 5% reduction in crude runs to 4.3 mb/d.

A proposal by India's Ministry of Finance to change the formula used to price petroleum products at the refinery gate is raising concern among India's private refiners. Currently, prices are calculated using a weighted average of the import parity price and export parity price in a 80:20 ratio. In an effort to cut the government's oil subsidy burden, the finance ministry has proposed a 100% export parity pricing mechanism. If adopted, this new formula would cut refining margins and make it less attractive for private refiners to sell products in the domestic market.

Regional crude runs are forecast to bottom out in April-May to 9.4 mb/d, as Taiwan's 540 kb/d Mailiao refinery, Thailand's 275 kb/d Sriracha plant and Singapore's 460 kb/d Bukom refinery will be all under planned maintenance.

Russian refinery crude intake in March was down 3.6% to 5.3 mb/d. as seasonal maintenance slashed throughputs. Maintenance operations are expected to peak in April, when as much as 800 kb/d of capacity - more than previously expected - is due to come offline. Slavneft's Yanov, Surgutneftegas' Kirishi, TNK-BP's Ryazan and Alliance's Khabarovsk refineries are among the major refineries expected to undergo maintenance this month. FSU crude runs will then recover from May onwards, reaching 6.8 mb/d in July.

Middle Eastern crude runs for January are almost unchanged from December at 5.75 mb/d. Seasonal maintenance work started in February with the Bahrain refinery shut down from mid-February for five weeks. All Gulf countries will perform maintenance work at their refineries with peak maintenance operations expected in April, when more than 800 kb/d of capacity will be offline. Kuwait's Mina Abdullah, Oman's Sohar, and Saudi Arabia's Ras Tanura and Yanbu plants are among the major refineries expected to undergo maintenance in April.

Crude runs should then increase seasonally pushed by the start-up of the first phase (200 kb/d) of the Saudi Aramco-Total joint venture Jubail refinery. The second phase (200 kb/d) is likely to be fully operational by the end of the year.

Latin American refinery throughput in January has increased by 2% m-o-m to 4.5 mb/d on higher crude runs in Brazil and Columbia. Brazil continues to operate its refineries at a very high rate, processing 2.1 mb/d of crude oil in January, an all-time high that reflects in part a 45% jump m-o-m in throughput at the REFAP refinery. Over the last quarter, bad weather had cut rates at the refinery located in Rio Grande do Sul, causing shortages of petroleum products in the state.

Overall, Latin America crude runs remain below their five-year average, dragged down by low Venezuelan throughputs. Following a major accident at the 955 kb/d Paraguana refinery complex last summer, we estimate Venezuela's January refinery crude throughput at 550 kb/d with a gradual return to prior processing levels by July at the earliest. Recent problems in restarting key units such as the flexicoker could further delay the return to normal operations.

Elsewhere in the region, continued problems at Pointe-à-Pierre refinery in Trinidad and Tobago and the shut down of La Plata, Argentina's largest refinery after a fire recently broke out at the plant, should continue to trim regional refinery throughput, impacting oil product supply in South America and the Caribbean.

Crude runs in Africa for January fell to 1.97 mb/d mainly on low Algerian and Libyan throughputs. Algeria reported a 15% drop in its throughputs as the Skikda refinery remains partially shut-down. The refinery, which has been undergoing maintenance and upgrade work since last summer, had been expected to resume full operations in early March. Based on the most recent information available, there was still one crude distillation unit under maintenance as of end-March.

Following severe disruptions in the first quarter, Libya's Ras Lanuf refinery resumed normal operation in early April. The plant, with capacity of 220 kb/d, is the country's largest. It is jointly operated by the UAE's Trasta Energy and Libya's state-owned NOC, and had been closed under force majeure following disruptions in crude supply, power cuts and an employee strike.

With the expected restart of the Skikda and Ras Lanuf refineries and the end of planned maintenance in South Africa, we expect a recovery in African crude runs by the beginning of June to 2.3 mb/d.