- Crude oil markets firmed in December on seasonally stronger winter demand in the Atlantic basin. Brent prices were supported by continued supply outages in Libya while WTI reflected a surge in domestic refinery throughputs. Prices eased in January, though, with WTI last trading at $93.70/bbl and Brent at $106.35/bbl.
- The estimate of 4Q13 global oil demand was raised by 135 kb/d on unexpectedly strong US deliveries, partly offset by curtailments in China and elsewhere. For 2013 as a whole, growth is estimated at around 1.2 mb/d, accelerating to 1.3 mb/d in 2014 as the economy continues to recover.
- Global supplies inched down by 25 kb/d month-on-month in December to 92.23 mb/d, with a seasonal fall in biofuel output cutting non-OPEC liquids supplies by 340 kb/d. Non-OPEC production grew by 1.63 mb/d year-on-year, partly offset by a 535 kb/d drop in OPEC crude oil supply.
- OPEC crude oil supply rebounded by 310 kb/d to 29.82 mb/d in December, reversing four months of decline. Saudi Arabia and the UAE led the gain, while Iraq was the only member to post a decline. Beleaguered Libya saw only a modest rise in December, amid government expectations of an imminent recovery in oil output.
- The forecast of global refinery crude runs for 1Q14 has been lifted by 110 kb/d since last month's Report, to 76.8 mb/d, on the back of surging US crude runs. Global throughput growth for 1Q14 is assessed at 1.3 mb/d, up from only 0.3 mb/d in 4Q13, as contractions in Europe ease and new Chinese and Middle Eastern capacity ramps up.
- Total OECD commercial oil inventories plummeted by 53.6 mb in November, their steepest monthly decline since December 2011, led by a plunge in crude oil and 'other products'. Preliminary data for December indicate a further 42.5 mb draw in OECD inventories.
Scaling the wall
Average oil prices remained surprisingly steady in 2013, with Brent futures dipping by just about $3/bbl from 2012 levels to $108.70/bbl, and WTI inching upwards by $3.90/bbl, to $98.05/bbl. This apparent price stability conceals, however, wider monthly price swings and a profound redrawing of the oil map, including large-scale changes in supply and demand growth and in the volume and direction of trade flows. Most prominent among those shifts was the relentless rise in US crude production, whose 990 kb/d growth, one of the largest annual gains on record for any country, helped blunt the impact of supply declines elsewhere, notably Libya and Iran. The trend in US production looks set to continue in 2014 and beyond, providing once again one of the largest changes in the market. But there were question marks last year about how the broader market would accommodate this growth, and they remain today.
A year ago, this Report examined the possibility that as surging production continues to move the US closer to becoming a net oil exporter, there may come a time when various regulations, particularly the US ban on exports of crude oil to countries other than Canada, could have an adverse impact on continued investment into LTO and thus continued growth in production. We called this point the "crude wall." With 2013 US crude oil production exceeding even the boldest of expectations by a wide margin, that "wall" now seems to be looming larger than ever, and the issue has become a matter of public debate. Yet the "wall" is also elusive. US crude output was not alone in defying expectations last year - so were US refining runs, which surged by 500 kb/d in 2H13 year-on-year and recently hit eight-year highs; product exports, larger in volume than Indian demand at 4 mb/d in October; and even US domestic demand, which swung back into growth in 2013 after years of contraction, gaining momentum as the year went by. Midstream capacity has also responded, with large-scale development of new rail and pipeline links to bring supply to market.
The US market has so far shown remarkable flexibility in absorbing new supply. New logistical links have helped narrow somewhat - though not erase - price imbalances between inland grades near new fields and coastal ones near refining centres. Remarkably, surging US supply and runs have not markedly lowered product prices for consumers. Rising global demand and supply shortfalls elsewhere - with twice as much annual growth in global demand as in world supply last year - have kept OECD stocks tight and oil prices generally high. Despite surging throughputs, rising exports mean that North American product stocks, measured in days of demand, have fallen below their five-year average by the widest margin since October 2004. Total oil stocks across the entire OECD as of end-November had fallen to nearly 100 mb below their five-year average, their largest deficit since May 2003.
While US success in accommodating new supply does not necessarily mean that there is endless room for US output to grow, challenges to growth are not imminent. Potential US growth in 2014 seems a given, even against the backdrop of resurgent non-OPEC supply growth outside of North America. If this year has any surprises in stock, they are more likely to come from the demand side, and from supply developments in the ever-volatile MENA region. Nonetheless, there is a rising tide of technical and political debate about whether - or when - the US market may run out of options to accommodate further gains without regulatory adjustments.
- Global oil demand is forecast to grow by 1.3 mb/d in 2014, to 92.5 mb/d, from the 1.2 mb/d gain now envisaged for 2013, to 91.2 mb/d, an acceleration supported by the likelihood of stronger macroeconomic momentum as the year progresses.
- For the first time since 2010, OECD demand appears to have swung back into growth in 2013. OECD growth for the year is assessed at 85 kb/d (or +0.2%), reversing a contraction of 520 kb/d (or -1.1%) in 2012. Non-OECD economies still account for the bulk of global growth for 2013 and beyond.
- The estimate of 4Q13 oil demand has been raised by 135 kb/d, to 92.1 mb/d, led by a significant upward revision of 700 kb/d to the US demand assessment pegged to industrial fuels. Estimates for Japan, Russia and Korea have also been raised, versus curtailments for Belgium, Mexico, Italy, France and some notable non-OECD reductions.
- Non-OECD demand estimates for 4Q13 have been revised downwards, partly offsetting an upwards adjustment for the OECD. Chinese demand figures for the quarter have been cut by 290 kb/d from last month's Report, to 10.2 mb/d. Chinese momentum has been slowing since July, but preliminary estimates of a 2% contraction for November look uncharacteristically soft. Chinese demand growth is now assessed at 3.0% for 2013, down from last month's projection of 3.8%, rising to 3.6% in 2014, to 10.5 mb/d. Other notable non-OECD downside adjustments include Kuwait and India.
Global oil demand growth appears to have gradually gained momentum in the last 18 months, driven by economic recovery in the developed world. Oil demand growth has been ramping up from a low point of 0.6 mb/d year-on-year (y-o-y) in 3Q12 to a recent high-water mark of 1.5 mb/d in 3Q13. Key to this change has been a trend reversal in OECD demand. Having contracted by as much as 1.0 mb/d y-o-y in 3Q12, a year later it swung back into growth of 340 kb/d y-o-y, led by the Americas and Europe. Most OECD economies have by now largely exited the restraints of recession, with strong gains in some countries in the energy-intensive manufacturing and petrochemical sectors.
Relatively robust demand growth likely continued into 4Q13. Based on still largely preliminary data, global consumption for that quarter is now assessed at around 92.1 mb/d in 4Q13, up 1.2 mb/d y-o-y. This marks a 135 kb/d upward revision from last month's Report. Large and partly offsetting revisions have been applied to estimates for the world's two largest economies. Roughly 705 kb/d has been added to the 4Q13 estimate of US demand, now assessed at 19.3 mb/d, following exceptionally strong US monthly data for October and robust weekly data since then. On the other hand, the 4Q13 Chinese demand estimate has been reduced by 290 kb/d, to 10.2 mb/d.
While October data were revised upwards by 585 kb/d for the US, to 19.3 mb/d, most of the changes for other countries were to the downside, notably China (-100 kb/d), Kuwait (-65 kb/d), Belgium (-55 kb/d) and Canada (-50 kb/d). November data were something of a mixed bag. An even larger upward revision was applied to the US (+880 kb/d), as well as Japan (+100 kb/d), South Korea (+95 kb/d) and Russia (+75 kb/d), offset by numerous cuts included China (-390 kb/d), Mexico (-130 kb/d), Italy (-65 kb/d), India (-65 kb/d) and France (-50 kb/d).
For 2013 as a whole, global oil demand is expected to average out at around 91.2 mb/d, 40 kb/d up on last month's estimate and equivalent to a gain of 1.2 mb/d (or 1.4%) on the year. Momentum is forecast to accelerate modestly, to 1.3 mb/d, in 2014 supported by the strengthening macroeconomic picture.
Top 10 Consumers
Estimates of 4Q13 US demand have been revised sharply upwards, reflecting in part steep adjustments to October data. The latest official US monthly statistics peg US demand for that month at about 19.3 mb/d, 585 kb/d above our previous estimate. Industrial fuels led the revisions, with LPG demand lifted by robust petrochemical sector activity, while bumper crops of corn and other grains also supported strong agricultural use.
Preliminary estimates of November US demand have been raised even more steeply from last month's Report, by 880 kb/d to 19.4 mb/d. November growth, now assessed at 4.8% y-o-y, marks a near-three-year high for the US. In addition to strong LPG sales to the petrochemical and agricultural sectors, gasoline and gasoil sales were also relatively robust. Even the previously flagging naphtha sector has picked up, showing strong demand growth for November. Recovering US consumer confidence may go some way to explain 4Q13 growth of 3.5% in gasoline demand amid reports of resurgent SUV sales.
For December, US deliveries are forecast to edge down month-on-month (m-o-m) to 19.2 mb/d. This still amounts to growth of 6.1% y-o-y, a rate unseen in more than 10 years, however. Strong growth was seen across the barrel, although demand from the travel and industrial sectors, and especially the petrochemical industry, seemed particularly robust.
Upwards revisions to 4Q13 lifted the US demand estimate for 2013 as a whole by 180 kb/d, to 18.9 mb/d. Growth for the year is now projected at 2.1%, a three-year high. It is also a stronger pace of growth than that seen in the US economy as a whole. We conclude that despite our long-held belief that efficiency gains would keep the pace of US demand growth below the wider economy, 2013 was an exception driven by non-trend shifts in the petrochemical sector. In view of these revisions, our forecast of US demand growth for 2014 has been raised to 0.4%, from last month's Report which showed a contraction of 0.1%. US demand is now projected to average around 19.0 mb/d in 2014.
When the Chicago Zoo confines its polar bears to indoor facilities, as it did in early-January, you know the US is experiencing some unusually cold winter weather conditions. The first two weeks of January, for example, saw the average temperature fall below 29.5 degrees Fahrenheit (minus 1.4 Celcius), well below freezing and more than a whole degree below the seasonal norm (equivalent to a premium of roughly 15 heating degree days). Such averages, however, fail to convey the full seriousness of the extremities that hit the US, with temperatures in the East North Central region averaging out at roughly four degrees Fahrenheit (-15.6 Celcius), ten degrees below the seasonal norm and cold enough to freeze a dropped cup of hot water before it hits the ground! Logic might suggest that this would raise US oil use, as space-heating requirements are heightened. Two key factors suggest otherwise: firstly, in recent years the US space heating market has increasingly moved away from oil as its preferred choice of fuel. Secondly, the severity of the recent freeze has been so harsh that many other forms of oil consumption, such as travel, have also been curtailed, hence generally reducing the overall US demand number. The product mix will likely have changed, however, with stronger gasoil demand (hence reports that refiners are shipping large quantities of gasoil to the US) at the expense of gasoline.
Potentially supporting higher oil demand, US homes and businesses alike require additional heat, or space heating, when temperatures fall. While this extra space-heating requirement would in the past have supported a strong upsurge in heating oil demand, electricity and natural gas have in recent years increasingly gained market share in this sector. The EIA's most recent Residential Energy Consumption Survey, for example, showed that oil products accounted for just over one-tenth of total US space heating requirements in 2009, down from nearly one-fifth in 1991.
Another form of cold-weather demand-support may arise at the margin from the automotive market, as severely reduced external temperatures are proven to lower engine efficiencies. Natural Resources Canada concluded, following a study by Environment Canada, that drivers use more fuel after a cold start as engines are forced to work harder to overcome increased internal friction. The air-fuel mixture in automotive engines in cold weather needs to be richer, also requiring more fuel, and large amounts of gasoline/diesel are often spent simply warming up vehicles. The additional use of emergency generators also supports oil demand in cold spikes, as power failures trigger oil-fired generators, which likely added to the January demand estimate.
Severe cold can cut both ways on demand, however. This is especially the case in the transport sector. Earlier this month, the US cold spike resulted in cancelled and/or delayed flights and likely led many consumers to put off car travel whenever possible, offsetting the impact of decreased engine efficiency. Severe cold temperatures, snow storms and/or icy road conditions can also hamper fuel deliveries and tanker truck traffic between refineries and wholesale or retail facilities, resulting in pent-up demand. The temporary closures of some businesses will have also likely dampened industrial fuel use, with gasoil, naphtha, LPG, fuel oil and 'other products' all likely being below what they would have otherwise been.
To conclude, January's severe winter weather conditions have clouded the outlook for the month, but all in all we reckon the contribution of the weather will have been net-negative. Its full effect will not be known with certainty until April's Report, when official monthly January data will be released. However, given the strength of the recent US demand trend, any negative impact on demand from the extreme cold as may have occurred is likely to remain a one-off, and may even be offset by a rebound when pent-up demand is released later on, once weather conditions improve.
Based on preliminary estimates, Chinese apparent demand averaged 10.3 mb/d in November, 390 kb/d below the forecast carried in last month's Report. A surprise contraction of 0.6% in refinery output y-o-y partly explains the difference. Despite equating to a 2.0% drop on the year earlier, Chinese apparent demand edged up on the previous month as several refineries resumed operations after maintenance.
Excluding stock changes, the November Chinese demand estimate would have been even lower. China's National Bureau of Statistics reported that product stocks drew in November for the fifth consecutive month, with the reported reductions in gasoil/diesel inventories proving particularly pronounced. Overall gasoline provided the greatest support to the apparent demand estimate in November, but failed to offset steep declines seen in gasoil and fuel oil. Relatively weak Chinese demand for industrial fuels seems consistent with reports of stuttering manufacturing sentiment. HSBC's Chinese Manufacturing Purchasing Managers' Index (PMI) edged down to 50.8 in November, barely above the key 50-threshold delineating expansion from contraction.
This leaves growth for the year as a whole at around 3.0%, with Chinese demand now thought likely to average roughly 10.1 mb/d in 2013. For 2014, demand is forecast to rise by 3.6%, as stronger growth is anticipated supported by the addition of two new refineries and relatively robust crude import figures. Chinese New Year celebrations, in early-February, will likely provide an additional 1Q13 fillip.
Unusually strong petrochemical use lifted the Japanese demand estimate to an eight-month high in November, with naphtha and LPG leading the gains. Economic recovery also supported rising demand across the domestic transportation fuel market, with both diesel and gasoline demand up y-o-y. Overall demand figures are expected to show contraction of around 3.7% for 2013 as a whole, with a similarly-sized decline forecast for 2014, led by reduced oil demand for power generation.
With the pre-Sochi Olympic demand-support proving stronger than first expected, estimates for November have been revised upwards by 75 kb/d, to 3.6 mb/d, in line with the above-5% y-o-y growth rate prevalent since mid-year. Demand growth for 2013 as a whole is estimated at 4.1%, supported by particularly strong gains in in residual fuel oil and 'other product' categories. Although a slowdown in momentum is forecast for 2014, a still robust 2.9% expansion is foreseen, to roughly 3.5 mb/d.
Weak demand for gasoil/diesel, the mainstay of India's oil market, likely capped Indian demand growth at around 0.6% for 2013. Growth in November remained below 1% y-o-y for the sixth consecutive month. India's recent economic travails, compounding the impact of recent diesel price increases as the government curbs price subsidies, have led the downside momentum. Industrial production fell by 2.1% in November, its weakest performance since May, while consumer confidence, as tracked by Nielsen, eased to its lowest level in more than three years. After the recent soft patch, Indian oil demand growth is forecast to accelerate to 2.4% in 2014 as the underlying macroeconomic picture recovers, with GDP growth of above 5% forecast by the International Monetary Fund (IMF) in 2014.
Brazilian demand expanded by roughly 80 kb/d y-o-y to 3.2 mb/d in November, a slower pace of growth than seen in recent months as the domestic economy goes through something of a soft spot. At 2.6%, November's y-o-y growth is its weakest gain since March 2013. Manufacturing sentiment remains stuck in 'contracting' territory according to data from HSBC/Markits. A refinery fire in the southern state of Parana, at the end of November, could also curb December deliveries as supplies tighten. For 2013 as a whole, growth is projected at around 4.0%, to 3.1 mb/d, unchanged on last month's Report. Demand growth is forecast to slow in 2014, to +2.9% (to 3.2 mb/d), as the sharp gains in gasoline seen in 2013 (+5%) are unlikely to be repeated in 2014.
October data came out in-line with expectations for the month, with demand contracting in both m-o-m and y-o-y terms. An expected dip in the crude oil burn, due to seasonally reduced Saudi Arabian cooling demand, explains the m-o-m contraction. The y-o-y drop, meanwhile, mirrored a general power-sector switch that has been observed away from oil to natural gas. October's 0.3% y-o-y dip in oil demand marks the third consecutive such monthly decline, hence the flatter demand trend that is now projected for 2013 as a whole (+2.0%, to 3.0 mb/d) after 2012's near-5% gain. Saudi Arabian demand momentum should, however, pick up again in 2014, supported by a stronger domestic economic backdrop, though growth is not expected to return to earlier highs.
Despite continued signs of strength in the German manufacturing sector and of improving consumer confidence, overall German oil demand remained on a downward sloping path in both October and November. Industrial production surged by 3.5% in November, its fourth consecutive gain in the pace of growth, while consumer confidence, as measured by the GfK Group, rose to +7.1 in November, compared to a long-term average of zero.
The aggregate decline in German oil demand in November concealed contrasting trends across the barrel, with gains in industrial fuels such as naphtha and fuel oil offset by declines in gasoline and jet/kerosene. Relatively warm early-winter temperatures dampened heating oil use. Although 2013 as a whole will likely see a net increase in German oil deliveries, growth looks set to flatten out in 2014 as the ongoing trend towards more efficient oil use offsets the diminishing impact of a post-recessionary bounce in demand.
South Korean demand in November averaged around 2.4 mb/d, more than 95 kb/d above month earlier expectations. Demand was buoyed by an exceptionally steep seasonal uptick in gasoil/diesel deliveries, as manufacturing sentiment indicators imply a semblance of confidence returning after a mid-year hiatus. Strong m-o-m gains were seen across most industrial fuels, including LPG, naphtha and fuel oil, in line with stronger-than-expected manufacturing activity.
Relatively mild early-winter weather kept Canadian demand relatively muted around 2.2 mb/d in October, equivalent to a contraction of 4.7%. The revised October demand assessment is 50 kb/d below last month's forecast. LPG, fuel oil and the 'other products' categories led the contraction, offsetting gains in transportation fuels. For 2013 as a whole, we now estimate Canadian growth at around 0.6% and forecast a modest acceleration in 2014 as the underlying macroeconomic backdrop improves.
Oil demand growth in the OECD departed from recent trends, swinging back into positive territory in a sustained fashion from mid-2013 for the first time since 2010, when growth was largely attributable to a one-off, post-recessionary bounce. In fact, not since 2005 has OECD demand shown genuine growth. Things seem to have changed as of mid-2013, but growth may again prove relatively short-lived. Firstly, the positive impetus from Europe's post-recessionary bounce will likely start to fade in 2014. Secondly, OECD Asia Oceania is likely to be a strongly negative net contributor in 2014 as earlier support from the Japanese electricity sector will taper and even reverse. The possibility of stronger demand growth from the OECD Americas offers some risk to the upside, although this is not something we are currently predicting on anything more than a tentative scale.
Oil demand expanded by an estimated 2.2% in OECD Americas in November, according to preliminary data, its third consecutive month with growth of more than 1% y-o-y. The region's turn to a stronger demand path reflects a mix of industrial and transportation fuel demand. For 2013 as a whole, we estimate growth at around 1.6% (or 375 kb/d), led by strong gains in petrochemical-driven US LPG demand. Total growth is forecast to slow to around 0.4% in 2014, as the majority of the possible short-term gains in petrochemical demand have already occurred, with further strong growth unlikely until the next swathe of petrochemical capacity comes on-line, post-2014.
Mexican oil demand, at roughly 2.0 mb/d in November, came out 130 kb/d below month earlier projections, due largely to lower-than-expected fuel oil deliveries. Having been as high as 300 kb/d in August, fuel oil demand slipped to 105 kb/d in November, the lowest level on record (based on data going back to the 1970s). Low power-sector requirements and an ailing industrial backdrop combined to curb fuel oil demand. Although both power demand and industrial activity may recover in 2014 amid stronger economic conditions, Mexican oil demand is likely to remain constrained as the impact from the series of monthly price hikes seen in 2013 filters through.
Having rebounded strongly in 3Q13, European oil consumption likely edged lower again in 4Q13 (down 0.5% or by 70 kb/d) as the stimulus provided by the post-recessionary bounce weakened. Europe's weak economic performance in 4Q13 is unlikely to support a rising y-o-y demand trend. The relatively shallow dip in European demand projected for 4Q13 marks a significant slowdown from the average per annum contraction of roughly 2.4% seen 2008-2012.
Preliminary November data point towards a 0.2% fall in OECD Asia Oceania demand y-o-y. Although still negative, this is the highest relative y-o-y performance since April, due to stronger demand numbers for both Japan and Korea. Petrochemical demand in both countries was robust in November. For 4Q13 as a whole, however, a decline rate of around 1.8% (or -160 kb/d) is projected, reflecting both a much weaker performance of OECD Asia Oceania demand for October (falling 2.9% y-o-y) and the expectation of another steep decline for December. For 2013 as a whole a drop of around 2.3% is forecast, followed by a further decline of 1.7% in 2014.
Despite signs of a recovery in OECD demand growth, the non-OECD region remains by far the main engine of global oil demand growth. Having expanded by 1.5 mb/d in 2012, non-OECD demand is estimated to have grown at a more modest 1.2 mb/d in 2013, to 45.2 mb/d. Growth is forecast to accelerate again in 2014, with incremental demand projected at 1.4 mb/d. The apparent slowdown of 2013 was partly attributable to currency-related issues, which not only reduced the potential income of many nations but also in some cases put additional pressure on price subsidies to be reduced. Continued efforts to diversify power demand away from oil, particularly in the Middle East, also played a role.
Middle Eastern demand has come in below expectations in recent months, as a seasonal drop in oil use was compounded by weaker-than-previously-anticipated economic activity in some countries. Weak industrial demand saw Kuwaiti demand at roughly 0.4 mb/d in October, its lowest level since February and 65 kb/d below the estimate carried in last month's Report, with demand of all of the main product categories down in y-o-y terms. The latest Iraqi demand data continues to imply a post-summer lull, with October demand falling to a four-month low and 25 kb/d below the forecast carried in last month's Report. Ongoing political turmoil in the country seems to keep demand growth somewhat more muted than would otherwise have been the case, with an average per annum gain of 5.4% forecast for 2013, below the 6.0% projection carried last month. Overall, Middle Eastern oil demand growth is forecast to remain below 3% in 2014, as still rapid transportation fuel demand growth conflicts with reductions in power sector oil needs. Confirming this forecast trend were reports from Dubai that the Dubai Electricity and Water Authority (DEWA) has increased its total budget for 2014 (roughly $5.5 billion, versus $3.7 billion in 2013), with more than 30% intended for equipment purchases and capacity expansions. In consideration are efforts to expand clean coal and solar power capacity.
Demand for oil products in the Philippines came in at roughly 330 kb/d in October, 7.8% up on the year earlier and 35 kb/d above our month earlier forecast, as relatively strong economic conditions supported additional use of gasoil and gasoline. Demand for gasoil/diesel, came in at roughly 140 kb/d in October, equivalent to a rise of 9.3% y-o-y as industrial output figures from the National Statistics Office of the Philippines showed an 18.2% y-o-y gain. The forecast for 2013 as a whole remains relatively unchanged, at 315 kb/d, as higher October demand likely offset typhoon effects in November. An additional 10 kb/d (or +3.0%) are then forecast as being added in 2014, taking total oil demand in the Philippines up to an average of around 325 kb/d, underpinned by the IMF's forecast of 6.0% GDP growth for the year.
- Global supplies fell by a marginal 25 kb/d month-on-month (m-o-m) in December to 92.23 mb/d, with a decline of 335 kb/d in non-OPEC liquids nearly offset by a 310 kb/d rise in OPEC crude output. Compared with a year ago, December production stood 1.16 mb/d higher, led by a surge in non-OPEC supply of 1.63 mb/d and a drop of 535 kb/d in OPEC crude supplies.
- For 2013 as a whole, global supplies grew by 605 mb/d to an average 91.57 mb/d, with non-OPEC growth of 1.35 mb/d more than offsetting a decline of 860 kb/d in OPEC crude. Non-OPEC total liquids supply is forecast to grow by 1.7 mb/d in 2014.
- Non-OPEC supplies in December fell by 335 kb/d m-o-m, to 55.99 mb/d, as global biofuels experienced a seasonal decline of 420 kb/d, partly offset by a 150 kb/d increase in crude oil production. NGL production was essentially flat.
- US crude oil production exceeded 8 mb/d in November for the first time since 1988. The growing volumes of light tight oil that cannot leave North America are increasingly posing a challenge to industry, putting the spotlight on the US crude oil export ban.
- OPEC crude oil supply edged higher in December, reversing four months of decline. December production increased by 310 kb/d to 29.82 mb/d, led by Saudi Arabia and the UAE. Iraq was the only member to post a monthly decline. Beleaguered Libya saw a modest rise in December, amid government expectations of an imminent recovery in oil output.
- The 'call on OPEC crude and stock change' was raised by 100 kb/d to 29.0 mb/d for 1Q14 and by 200 kb/d to 29.4 mb/d for full-year 2014 on an upward revision to global oil demand.
All world oil supply data for December discussed in this report are IEA estimates. Estimates for OPEC countries, Alaska, Mexico and Russia are supported by preliminary December 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 May 2011, 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 ?200 kb/d for non-OPEC as a whole, with downward adjustments focused in the OECD.
OPEC Crude Oil Supply
OPEC crude oil supply edged higher in December, reversing four months of declines. December production increased by 310 kb/d to 29.82 mb/d, largely due to higher output from Saudi Arabia and the UAE. Iraq was the only member to post a monthly decline. Beleaguered Libya saw a very modest rise in December, contrary to government expectations at the time of an imminent recovery in oil output. November production was adjusted lower by 215 kb/d on a downward revision to Angolan output.
The 'call on OPEC crude and stock change' was raised by 100 kb/d to 29.0 mb/d for 1Q14 and by 200 kb/d to 29.4 mb/d for full-year 2014 on an upward revision to global oil demand. OPEC's 'effective' spare capacity in December was estimated at 3.33 mb/d versus 3.37 mb/d in November.
For full-year 2013, preliminary data show OPEC crude output declined by a collective 860 kb/d to average 30.44 mb/d, with steeply lower production from embattled Libya and sanctions-hit Iran accounting for the bulk of decline. Saudi Arabia's annual crude output edged downwards by 110 kb/d year-on-year (y-o-y), albeit from elevated year-earlier levels, to an average 9.68 mb/d. Iraqi supply growth fell short of expectations at 120 kb/d, to 3.07 mb/d, due to continued operational and export constraints in the southern region of the country and a protracted dispute between Baghdad and the northern Kurdistan Regional Government (KRG) over constitutional issues related to resources and revenues. The UAE and Kuwait were the only other countries to raise output last year, up by a combined 180 kb/d (see table below).
OPEC's crude production reached a monthly peak of 31.1 mb/d in May before trending lower for the remainder of the year, in line with the steady erosion in Libyan production. The deteriorating political situation and security problems between the central government in Tripoli and various tribal factions across the country led to paralysing protests at oilfields and export terminals, especially in the eastern region of the country. Libyan oil supplies tumbled from a high of 1.42 mb/d in April to just 230 kb/d by December. On average, Libyan output declined by 490 kb/d y-o-y to 900 kb/d in 2013.
Iranian supplies continued to contract in 2013, off by 320 kb/d to 2.68 mb/d. The wide-ranging sanctions on Iran's financial, oil and shipping sectors have combined to reduce the country's output by just under 1 mb/d since 2011. The prospect of a diplomatic thaw between Iran and the international community improved in 4Q13 but any significant return of oil to world markets will likely depend on the success of current negotiations between Tehran and the so-called P5+1 , i.e. the five permanent members of the UN Security Council, Germany and the European Union.
Meanwhile, OPEC NGLs continued on an upward trend in 2013 with increased supplies from the UAE, Kuwait, Qatar and Saudi Arabia only partially offset by declines in Iran, Libya and Nigeria. OPEC NGL supplies, including non-conventionals, rose by 120 kb/d to 6.4 mb/d on average in 2013.
Saudi crude oil production rose by 75 kb/d in December, to 9.82 mb/d. Actual crude supplied to the market was up an even sharper 450 kb/d to 9.9 mb/d from November's 9.45 mb/d, according to Saudi officials. Robust customer demand was behind the increase in supplies, with above-production volumes sourced from stocks.
Indeed, Saudi Aramco is moving apace with its planned expansion of crude oil production capacity, which includes the Shaybah field. In addition to the ongoing ramp up since April 2013 of output from the 900 kb/d offshore heavy oil Manifa field, the company announced that contracts were signed for the engineering and construction of the Shaybah Arabian Extra Light Crude Increment Project, with aims to raise crude capacity by 250 kb/d to 1 mb/d by April 2016. The contract for the expansion of Shaybah's central processing facility was awarded to South Korea's Samsung Engineering while upgrading work for the project's power plant went to China's Shandong Electrical Power Construction. Remaining contracts are scheduled to be awarded by end-January. The crude increment project is part of the Shaybah NGL Recovery Program, which will produce 2.4 bcf/d of natural gas and 240 kb/d of NGL (ethane, which is included in our NGL data), and includes nine other major contracts that are scheduled for completion by the end of 2014. The front-end engineering and design (FEED) contract for the 300 kb/d expansion of the Khurais crude increment program was awarded last year to Foster Wheeler and is expected to be completed by 2Q14. The additional 300 kb/d capacity of the Khurais Central Processing is expected to be operational in 2017.
Iranian crude oil production edged higher in December, up by 40 kb/d to 2.75 mb/d, against a backdrop of diplomatic activity aimed at halting Iran's nuclear development plans. Imports of Iranian crude were only modestly higher in December, up by an estimated 50 kb/d to 1.15 mb/d, versus an upwardly revised 1.1 mb/d estimate for November, latest data show. Preliminary data for full-year 2013 show imports of Iranian crude and condensate declined by 450 kb/d year-on-year, to 1.07 mb/d compared with 1.52 mb/d on average in 2012 (when major US and EU sanctions came into effect) and 2.42 mb/d in 2011. Import estimates are based on data submitted by OECD countries, non-OECD statistics from customs agencies, tanker movements and news reports.
Negotiations between Iran and the P5 +1 (the US, UK, Russia, China, France and Germany, plus the European Union) moved forward in early January with the unveiling of a detailed "joint plan of action" (JPA) to freeze Iran's nuclear programme for six months, while a more comprehensive long-term agreement is negotiated. Initially sketched in November, the JPA was scheduled to take effect on 20 January, with the UN's nuclear monitoring arm, the International Atomic Energy Agency (IAEA), tasked with verifying that Iran adheres to its part of the interim deal, i.e. a temporary freeze on key nuclear activities. The P5+1, in return, are slated to release approximately $4.2 billion in seized assets held in Western banks in monthly instalments.
While the interim JPA also calls for an easing of sanctions affecting the insurance and reinsurance market for tankers and crude oil cargoes, the ban on crude oil exports remains in place. The relaxation in tanker insurance provisions in the current sanctions regime may lead to small increases in Iranian crude exports to existing customers in the short-term. While the six-month interim agreement has been hailed as a diplomatic breakthrough, analysts caution that the most difficult issues have yet to be addressed as part of a broader, long-term agreement, the success of which is far from assured.
Meanwhile, some recent press reports have claimed that Moscow was in the process of agreeing a barter arrangement with Tehran to swap 500 kb/d of Iranian crude for Russian goods and services. If confirmed, the deal could derail negotiations between the P5+1 and Iran, and upend relations with the EU and the US.
Kuwaiti production edged upwards by 30 kb/d to 2.81 mb/d in December, with full-year 2013 output up by 70 kb/d year-on-year, also to 2.81 mb/d. Increased drilling and continued debottlenecking at the Mina al Ahmadi oil terminal are behind the rise. Qatar output was unchanged at 720 kb/d in December and an average 730 kb/d for full-year.
Production from the UAE rebounded 100 kb/d in December, to 2.76 mb/d, following the completion of extensive field maintenance. Full-year UAE output rose by 110 kb/d to an average 2.76 mb/d on increased capacity at smaller onshore fields. The company is also currently developing several smaller onshore fields. The UAE plans to raise capacity from around 2.9 mb/d currently to 3.5 mb/d by 2017.
The UAE formally ended its 75-year old concession agreements with international oil companies BP, ExxonMobil, Shell, France's Total and Portugal's Partex as previously announced, with state-owned Abu Dhabi National Oil Company (ADNOC) becoming the sole shareholder of its onshore operating subsidiary Adco. The Abu Dhabi government-owned ADNOC had a 60% interest in Adco, with BP, ExxonMobil, Shell and Total holding 9.5% each and Partex 2%. The award of new contracts for the concessions has been a protracted process, with a decision on new partners not expected for another year. ADNOC has invited 10 companies, including former partners and Rosneft, ENI, Statoil, South Korea's KNOC and CNPC. Ultimately the final decisions on new concessions is made by the Emirates Supreme Petroleum Council, chaired by UAE President and Abu Dhabi ruler Sheikh Khalifa bin Zayed.
Iraq's Fortunes Held Hostage to North-South Divide
Iraq's crude oil production and exports were well below official targets in 2013, undermined by chronic operational and technical issues as well as a worsening security situation in the central and northern regions of the country, which looks likely to continue in to 2014. Baghdad had been aiming for a rise to 3.5 mb/d by the end of 2013 following the installation of new export facilities in the south, but the underperforming assets were in large part behind the meagre 120 kb/d increase in crude oil output to just 3.07 mb/d in 2013. Work on the southern ports continue to face delays. The installation of new metering and a manifold platform at two loading berths at the Basrah terminal was completed in the autumn but work at the other two berths is still ongoing. More extensive work is needed at two of the four single point moorings (SPMs), which includes relieving pressure problems related to the delayed installation of gas-fuelled turbine pumps, and is not expected to be completed until the end of 1Q14 at the earliest. Given the formidable scope of the technical, security and political challenges that still need to be overcome, industry analysts expect Iraq to increase production by only 200 kb/d to 300 kb/d this year.
Iraqi production in December fell by 25 kb/d to 3.07 mb/d, largely due to continued attacks on pipelines and technical maintenance disrupting supplies in the northern region. Crude oil exports fell by 40 kb/d to 2.34 mb/d. Basrah exports were up a modest 10 kb/d to 2.08 mb/d as weather-related delays at southern ports in the Gulf constrained liftings. Northern exports of Kirkuk crude declined by around 50 kb/d to 252 kb/d, with volumes constrained by repeated attacks on the northern Ceyhan-Kirkuk pipeline as well as the continued suspension of crude exports from the KRG region to the line stemming from ongoing payment and contract disputes between Irbil and Baghdad.
Much to the chagrin of the central government in Baghdad, the KRG continues to tout plans to independently export Kurdish crude oil to the Ceyhan terminal on Turkey's Mediterranean coast. KRG production was estimated at 200 kb/d in December, with roughly half exported by truck and the remaining 100 kb/d refined locally at new 'tea pot' refineries, with the products reportedly trucked to Turkey.
Despite a loud chorus of official statements by the KRG reporting the imminent export via the new 300 kb/d pipeline that ties into the Iraq-Turkey pipeline (ITP) at Fishkabur, uncertainty surrounds the outlook given significant political and logistical hurdles. Baghdad has publicly warned Irbil, Ankara and potential customers that any exports are a serious violation of the country's constitution and stated that the State Oil Marketing Organisation (SOMO) has exclusive rights to sell crude from Iraq, including Kurdistan. Caught in the middle of the dispute between Baghdad and the KRG, Turkey has said it would honour Iraq's constitution. The parties involved all have differing interpretations of the antiquated post-war constitution dealing with the oil and gas sector and the stalled new federal hydrocarbons law intended to replace existing legislation dating from the era of Saddam Hussein. Iraqi parliamentary elections in April may provide an opportunity to resolve various disputes over control of resources, exports and revenues.
The KRG also appears overly optimistic regarding the readiness of the pipeline to deliver Kurdish oil to international markets. Reports suggest that there are a number of technical issues that must be resolved before exports can commence and pipeline testing has only gone as far as the border with Turkey. State pipeline company Botas is reportedly still repairing and renovating the small 40-inch pipeline of the twin ITP system designated to carry KRG oil to Ceyhan. Kirkuk crude moves through the larger parallel 46-inch line. The KRG stated in early January that crude oil was flowing through the controversial pipeline, and exports were on track to start at the end of January but given technical issues this appears remote in the short term. The Kurdistan Oil Marketing Organisation (KOMO) has, nevertheless, invited bidders for the shipments.
Diplomatic overtures continued in January but a resolution to the long-running dispute between Baghdad and the KRG is not expected before April's parliamentary elections in Iraq. Some analysts argue that Prime Minister Nouri al-Maliki may use KRG exports as a carrot for Kurdish support in forming a new government, especially in the wake of the worsening security crisis across the country. However, others argue this is unlikely given the poisonous relation between Prime Minister Maliki and KRG president Barzani, so the latter may be holding out for a change in the country's political leadership in April.
Northern Iraq Oil and Gas Fields and Infrastructure
Libyan crude supplies hovered near record lows in December, up by a marginal 10 kb/d to 230 kb/d. The deteriorating political situation and security problems between the central government in Tripoli and various tribal factions across the country led to continued disruptions at oilfields and export terminals, with supplies tumbling from a high of 1.42 mb/d in April to a low of just 220 kb/d in November. Libyan output declined by 490 kb/d to average 900 kb/d in 2013.
The restart of production from the 350 kb/d Sharara field in the western region of the country early in 2014 pushed total output up to 600 kb/d by mid-January. Protesters, however, were once again threatening to force the closure of the field, arguing that government officials have failed to meet their promises.
Government authorities and representatives of the protesters are still negotiating. Tribal protesters at Sharara are demanding greater authority for the Tuareg minority. Operations at the Zawiya export terminal and refinery, which are fed by the Sharara field, were continuing as of 16 January.
Nigerian production in December rose by 35 kb/d to 1.92 mb/d. The return from maintenance of the offshore Bonga field offset outages at smaller onshore operations. For full year, Nigeria supply fell by 150 kb/d to 1.95 mb/d, largely reflecting continue sabotage and theft activity to oil infrastructure in the volatile Niger Delta onshore fields.
Crude oil production in Angola posted a partial recovery in December after falling to a low of more than two years in November on technical problems at several fields. Angola output rose to 1.62 mb/d in December, up 30 kb/d from a downwardly revised November level of just 1.59 mb/d. Operational and technical problems in November reduced output at Total's block 17 by 45 kb/d while output at Chevron's Block 0, Exxon's Block 15 and BP's block 18 was reduced by 25 kb/d each. Planned maintenance at the greater Plutonio field is expected to sharply reduce supplies once again at end-February and March.
Non-OPEC production declined by 340 kb/d in December month-on-month (m-o-m), to 55.99 mb/d. A seasonal fall in global biofuels supply, mainly Brazilian ethanol, accounted for most of the drop. Excluding biofuel declines, non-OPEC output edged up by 80 kb/d. In North America, total supply increased by 65 kb/d, partly offset by drops in OECD Europe and Pacific. Overall, OECD output rose by 45 kb/d on the month. Brazil (excluding biofuels) and China also saw production increases, of 60 kb/d and 35 kb/d, respectively.
The December drop only partly reversed an exceptionally high rise in November, when final data show non-OPEC production jumped by 935-kb/d m-o-m, the highest monthly increment since October 2008. Nearly 90% of that gain came from the OECD, including more than 640 kb/d from North America. Norway and the UK also contributed, with the North Sea adding 195 kb/d to the total.
Non-OPEC crude oil production accounted for 60% of global crude output in 4Q13, roughly the same level as in the rest of the year, but about two percentage points higher than in 2012. Although non-OPEC supply has grown in recent years, its share of both total crude oil and total liquids production has not changed much since 2010.
Preliminary data for November and December suggest total non-OPEC supplies grew by a robust 1.35 mb/d for 2013 as a whole. For 2014, growth is forecast even higher, at 1.7 mb/d. As in 2013, North America is expected to provide most of the growth, offsetting declines elsewhere. Unlike in 2012 and 1Q13, however, other non-OPEC regions are expected to contribute. That includes growth of roughly 200 kb/d in Africa, 185 kb/d in Latin America and 80 kb/d in the Former Soviet Union (FSU). In the latter, Russia will provide almost all the growth, with smaller gains in Kazakhstan and Turkmenistan offset by a dip in Azerbaijan. Latin America's growth, the highest since 2011, will come almost entirely from Colombia and Brazil (not including biofuels). South Sudan will lead growth in Africa, as the country's oilfields were shut in for much of last year, though some oilfields in regions of intense internal conflict are again offline, reducing the year-on-year (y-o-y) growth.
US - November preliminary; Alaska actual, others estimated: Final October data confirmed that US crude oil output fell slightly, to 7.75 mb/d. A 100 kb/d drop in the federal GOM waters outweighed small gains in Texas, North Dakota and Alaska. US crude oil production is estimated to have exceeded 8 mb/d (at 8.01 mb/d) in November for the first time since November 1988. A return of US GOM output to September levels, combined with Alaska production of nearly 560 kb/d and continued increases on Texas shale plays, drove this achievement. Crude oil production likely expanded further to 8.1 mb/d in December as the Eagle Ford play added about 100 kb/d of net output from September to December. A slight decline in crude oil production is forecast for January, however, as a cold snap cut production on the Bakken and Permian plays, trimming overall output to an estimated 7.98 mb/d.
That January dip notwithstanding, 2014 is still expected to be another year of outstanding production growth, with crude output forecast to increase by 780 kb/d y-o-y. Production in excess of 8 mb/d has triggered a large expansion of midstream and downstream capacity to handle this influx, of largely lighter grades from the midcontinent. TransCanada's 700 kb/d Gulf Coast crude pipeline from Cushing, Oklahoma, to Port Arthur, Texas, set to start commercial service on 22 January, is a case in point. Infill began in December. Meanwhile, crude exports to Canada have been increasing in the last three years, with Gulf Coast crudes sailing to the east coast of Canada on tankers that are exempt from the Jones Act. Rail transport throughout the continent continues to expand as well (please see 'Crude Wall and US Crude Exports' and 'Update on Rail Transport of Crude Oil in North America').
Total liquids production, excluding biofuels and refinery processing gain, fell slightly along with crude oil production in October, to 10.72 mb/d, as NGL production held steady. It is estimated that in November, total liquids production exceeded 11 mb/d (including non-ethanol additives) for the first time since the 1970s. November NGL production is estimated at 2.69 mb/d, with a seasonal decline to 2.65 mb/d in December. Although NGL output still dips seasonally in winter, the development of liquids-rich shale gas plays such as Utica and Marcellus, with their relentless production increases, has gone some ways to smooth out that seasonality. (Pennsylvania now has the second-largest gas production among US states.) Ethane production alone is forecast to remain above 1 mb/d throughout 2014, with 4Q14 y-o-y growth for all NGLs of 170 kb/d.
The Crude Wall and US Crude Exports
A year ago, in a detailed discussion of US light tight oil (LTO) production trends, this Report highlighted the various midstream, downstream and regulatory hurdles to continued supply growth ('Up Against the Export Wall: Hurdles to US LTO Production Growth' in January 2013 OMR). It identified several ways in which the industry could get around a looming crude 'wall,' defined as the point at which existing regulations would limit the US market's capacity to absorb further production growth. Methods for avoiding the wall included, among others, shipping reform (including a reform to the Jones Act), a change in the regulatory statutes governing crude exports, an expansion of pipeline capacity, continued increases in refinery throughput and a change of refinery crude slates. We concluded our analysis by pledging to keep monitoring developments in the North American oil patch and their impact on global markets.
Much has changed in a year. Growth in US crude oil production has exceeded even the most bullish of expectations. Our current estimate of US crude output for 2013 outstrips our projection of a year ago by about 455 kb/d and our initial, July 2012 forecast by 690 kb/d. Indeed, US crude oil supply in 2013 registered the fastest absolute annual supply growth of any country in the last two decades, rising 15% in 2013. Given such steep growth, the 'wall' arguably looms larger than ever. It may therefore not come as a surprise that
the question of whether or not crude export regulations inherited from the 1970s ought to be revisited has become a matter of increasingly heated debate. At the same time, last year's growth has also demonstrated the capacity of the US oil industry and markets to seize new opportunities and adjust on their own to changing realities. While US supply growth has defied expectations, so have refining throughputs, product exports, crude oil exports to Canada, and even domestic demand. Bringing years of contraction to a screeching halt, the latter swung back into growth last year, expanding by 390 kb/d, or 2.1%. Overcoming, for now, the challenge of having to adjust to an ever lighter crude slate, refining runs have soared, often in defiance of long-established seasonal patterns. One market reaction to the export ban on crude has been a surge in exports of refined products. Once the world's largest net product importer, the US has become its top net exporter, with gross product exports approaching 4 mb/d in October 2013, the latest month for which official monthly data are available. Whether these achievements should be seen as confirmation of the market's limitless capacity to accommodate rising production, or, on the contrary, as a warning sign that it is running out of options to make room for new supply, remains to be seen.
Although US production growth in 2013 far surpassed our projections, the industry met the challenge of extra supply in its stride. The accommodation of the additional production was possible because of refinery, pipeline and crude rail capacity expansions, allowing the Midwestern crudes to reach the Gulf Coast and East and West Coast refineries. During 2013, several new pipelines and pipeline expansions came onstream, most of which transport crude oil between the US Midwest and the Gulf Coast. The additional pipeline capacity provided extra flexibility to the system and it coincided with an increase in refinery activity. While less than 20 kb/d of additional crude distillation capacity was brought on stream in 2013, crude runs rose 320 kb/d y-o-y as the 325 kb/d Motiva expansion, completed in 2012, reached normal rates.
Because of the infrastructure expansions, domestic crude supply growth has displaced US oil imports, particularly lighter grades. Imported light oil could be almost entirely backed out of coastal US refineries by 2015.
Based on current estimates, US crude oil production growth is expected to continue at a brisk pace in the short and medium terms, with LTO accounting for the majority of the gains (there will also be production gains from the deepwater Gulf of Mexico). Crude production is expected to reach 8.26 mb/d in 2014, with an additional 3.10 mb/d of non-crude liquids. Refinery runs will likely stay elevated in 2014 and, extending last year's trend, will be supported by further capacity expansion, although there are only two projects under way in 2014 with at least seven planned for 2015. Planned additions in 2014 will total 115 kb/d, however an additional 260 kb/d are planned for 2015.
Exports of light crude oil to Canada, currently at approximately 155 kb/d, can be increased somewhat, but these exports are subject to Canadian refiners' ability to absorb them. Already, imports of crude oil from outside of North America into eastern Canada have been largely replaced by US crude, thanks in part to the fact that oil shipments to Canada are exempt from the Jones Act. Some analysts reckon that Canadian refiners have a capacity to take only about another 250 kb/d of US crude, which would be fully utilised by sometime in 2015.
Much of the LTO is produced in the form of lease condensate, which is most optimally processed in a condensate splitter. There is currently only one condensate splitter in the US, although at least five others are in various stages of planning and construction.
Although there appears to be room in the market to accommodate further supply expansion in 2014 without any immediate change in export regulations, how long this can continue is open to debate. Given these constraints, it may not come as a surprise that the regulations governing US crude exports have recently come into the public spotlight. Several US lawmakers have raised the issue and come out either in favour or against a relaxation of the current statute, and a hearing on the implications of liberalising US crude exports has been scheduled at the US Senate Committee on Energy and Natural Resources for 30 January. Bank analysts and experts at think-tanks have issued reports and studies on the issue. No legislation to lift the ban has yet been introduced, however. Oil producers have generally come out in favour of lifting the ban and some lawmakers, notably those from oil-producing US states, support lifting the ban by Executive Order, which would allow producers to export crude oil and condensate to countries other than Canada, or at least to other countries with which the US has a free-trade agreement. Many refiners and other major oil consumers, on the other hand, support keeping the ban and worry that allowing exports would result in higher feedstock costs and erode their competitive advantage, or shift value-added industry abroad.
An additional outlet to expand exports under current legislation would be to exclude lease condensate from the crude oil export restrictions. The US Department of Commerce, which enforces the export ban, includes lease condensates in the definition of crude oil. However, this definition could be changed, or the Commerce Department could simply issue lease condensate export licences at the behest of the President.
Canada - October actual: Canadian total liquids production dropped again in October, to 3.91 mb/d. Alberta bitumen production held steady at 1.0 mb/d compared to September but fell short of expectations. A small decline in Saskatchewan, combined with the Terra Nova platform being offline the entire month, made for a decline in crude and field condensate production of nearly 120 kb/d, to 2.29 mb/d. NGL production fell to 610 kb/d, the lowest level since September 2012.
Total liquids production likely recovered in November and December, to 4.28 mb/d for both months, on the back of improved bitumen and synthetics output. Nevertheless, we have adjusted downwards our forecast of bitumen production growth for 2014, to about 160 kb/d. While this growth reflects in part investments sunk years in the past, the economics of oil-sands projects appear to have worsened, as capital costs increase and new reservoirs are getting more complex. For example, the 110 kb/d Kearl project had cost overruns of C$2 billion, and Statoil has recently voiced scepticism about continued large-scale investment in the sector. Nevertheless, Cenovus Energy plans to spend C$3.1 billion on new facilities in 2014, and in December Imperial Oil filed an application with the provincial regulator for a C$7 billion investment in the 135 kb/d Aspen in situ development. Modular construction is increasingly being used on oil sand projects in order to control costs. In addition to large-scale expansion of rail transport capacity (see 'Update on Rail Transport of Crude Oil in North America'), and amid continued uncertainty about the Keystone XL Pipeline, which still awaits potential approval, another outlet for oil-sands production, the 525 kb/d Northern Gateway Pipeline, received conditional approval in December. The federal government's Joint Review Panel approved the project, which would carry crude from Alberta to a British Columbia port, subject to 209 conditions and final ratification by the federal government. The pipeline will have a reverse-flow pipeline constructed beside it in order to import as much as 193 kb/d of diluents.
Alberta ethane production, spurred in the last decade by the Alberta Ethane Gathering System, has begun to decline and will continue to do so without significant new investment. The idea behind the Alberta Ethane Gathering System had been to link spread-out ethane production in the vast province to its two main petrochemical facilities at Joffre (Nova) and Fort Saskatchewan (Dow). Given the availability of lower-cost ethane from the liquids-rich Williston Basin in the US and Saskatchewan, however, producers are unlikely to make additional investments to maintain ethane production levels in Alberta. They are likely to opt instead to invest in additional pipeline capacity, such as the planned Vantage Pipeline from Tioga, North Dakota, to bring Williston Basin ethane to the province in the medium term.
Rail Transport of Crude Oil in the Spotlight in North America
Rail has emerged as a major means of transportation in recent years to accommodate fast-rising North American oil production from Alberta, North Dakota and elsewhere. According to the Association of American Railroads, crude oil volumes railed from US production sites (not including Canada) jumped from 9 500 car loads (roughly 20 kb/d) in 2008 to 234 000 car loads (450 kb/d) in 2012 to 400 000 car loads (770 kb/d) last year (based on preliminary data). While relatively high-cost, rail offers distinct advantages over pipelines where transport infrastructure is inexistent or insufficient, including flexibility and the possibility of speedy deployment at comparatively low initial investment costs. But a string of accidents have recently put a spotlight on the safety risks associated with this means of transportation and may set the stage for regulatory changes.
Courtesy of BakkenShale.com/Plains All American Pipeline - prices as of April 2013
While the 2013 estimates suggest that rail may move more than 10% of current US crude output, that aggregate figure conceals wide regional disparities. Rail is vital for North Dakota, America's second-largest producing state: between 60% and 70% of the state's crude production of 980 kb/d (December 2013 estimate) is brought to refineries by train. Much of the state's incremental production of more than 100 kb/d since December 2012 is railed to the US East Coast. According to Bentek Energy, the amount of crude railed to East Coast refiners from all parts of North America has tripled from about 100 kb/d in early 2013 to about 300 kb/d by year-end. Some light, tight oil (LTO) is also railed to Canada. Another producing area where rail transport is vital is the Niobrara formation and Powder River Basin in Colorado and Wyoming, and surrounding smaller areas. Output was about 350 kb/d in total for both states in 2013, and is almost entirely railed to refiners. Rail has played a bridging role on Texas formations such as the Eagle Ford, which is much closer to refiners and ports, and where substantial pipeline capacity is being built. Increased rail capacity from the midcontinent to US West Coast refineries is also being planned or under construction.
In Canada, the rail crude transport boom is still in its early days. From virtually nothing in early 2012 to 60 kb/d a year later and more than 180 kb/d at end-2013, rail has become key to deliver incremental diluted bitumen volumes to refiners, as pipelines are running at capacity and new pipeline capacity, particularly cross-border, is at best years off. According to Reuters, about 1 mb/d of new rail terminal capacity construction began in 2013 or is scheduled to begin in 2014, including planned expansions of existing terminals. Some of those expansions may depend on whether or not the US Government approves TransCanada's proposed 830 kb/d Keystone XL pipeline from Alberta to Illinois. The company has suggested however that much of the pipeline could be built on both sides of the border, but linked by rail across the border, as cross-border rail is not subject to the same regulatory constraints as pipelines. Some crude, including LTO from formations across the border in North Dakota, is also being railed to refineries in eastern Canada.
Other than the relative ease of obtaining regulatory approval for regional or cross-border rail links compared to pipelines in North America, rail offers certain advantages. Chief among them are its flexibility and the relative speed at which rail infrastructure can be deployed. With "unit trains" (freight trains carrying only oil), producers can direct shipments to where they get the best netback. Large unit trains linking oil fields directly to refineries offer economies of scale and substantially lower costs than traditional freight trains carrying multiple products. Nevertheless, the fact that crudes such as Bakken are mostly delivered by rail explains in part their price discount to WTI, as the discount is needed to offset transport costs. When production outpaces rail capacity, this can drive up transport costs and prompt further discounting.
Pipelines too have their advantages. Once the initial investment has been made, they offer significantly lower operating costs than rail (about a third of rail costs on average) and a better safety record (the rate of spillage hazardous materials of railed is about 2.7 times that of piped hydrocarbons according to the Association of American Railroads, though in absolute terms incidents even for rail are rare). Pipelines are also more energy-efficient and have lower emissions than trains. For Canadian bitumen output, the need for high-cost insulated/heated railcars can play against rail, though more diluents may be needed in pipelines.
Rail safety has come to the fore following a number of high-profile accidents in recent months. A train filled with Bakken crude killed 47 people when it derailed and exploded at Lac-Mégantic, Quebec, on 7 July. Since March, there have been no less than 10 large crude spills in the US and Canada following rail accidents, five of which also resulted in large blasts. In North Dakota on 30 December, an explosion following a collision between a crude oil unit train and a freight train once again put a spotlight on rail safety at the very heart of the most important source of railed crude in North America. The most recent incident was on 7 January 2014 in rural New Brunswick, with several tanker cars of crude oil from Western Canada (possibly from Bakken formations in Saskatchewan and Manitoba) and several propane tankers (both hydrocarbons were carried on the same train) igniting in a derailment.
In addition to spillage risks, the risk to human life due to large explosions and the liabilities associated with it (the railway company that owned the train involved in the Lac-Mégantic disaster was forced into bankruptcy by the accident) have led industry, regulators and politicians to look for solutions. Regulatory agencies, including the US Pipeline and Hazardous Materials Safety Administration (PHMSA) and the Canadian Transportation Safety Board (TSB), identified the flammability categorisation of the crudes being carried as a potential issue in the Lac-Mégantic incident. Miscategorisation can cause trains to travel too fast and take less precautions than needed with regard to the volatility of their cargo. The PHMSA, in an ongoing effort called "Operation Classification", is examining whether Bakken crude is inherently more volatile and flammable than other crudes (whether due to its corrosive properties, its very light gravity, dissolved natural gas liquids, fracking chemicals mixed into the crude, or some combination of these factors).
Whether or not Bakken crude is found to warrant special regulations, the safety of the US railcar fleet for any type of crude or product (including ethanol, which is also widely railed in the US) has also come more broadly into question. In October 2011, the US Department of Transportation (DOT) had tightened its guidelines for rail tanker cars, known as DOT-111. All newly-built railcars are now required to meet those new standards designed to let cars better resist spillage, but about 80 000 tanker cars built to the old standards are still in use in the US, and another 50 000 in Canada. Many of those older-version DOT-111 cars can remain in service for another 20 or 30 years, and would be commingled with the newer-version cars in the same trains, thereby undermining the overall safety advantage of the newer cars. Regulatory action that would call for rapid retrofitting or elimination of the older-version DOT-111 could affect off-take capacity, however. There are only about 14 000 of the newer version DOT-111 currently available for use in the US, and a smaller number in Canada. Of course, railcars cross the border regularly.
Initial findings from the 7 January New Brunswick incident investigation appear to show that the newer version DOT-111 railcars fared substantially better in the accident. Canadian officials already proposed new standards on 10 January for DOT-111 tank cars to be more crash resistant, as well as new standards for classifying dangerous goods and documentation for testing crude oil for rail transport. What the regulation is aiming at seems to be much closer scrutiny of the hazardous potential of crude oil, as well as prevention of transport of crude oil that has non-crude oil substances that are particularly volatile or corrosive even in the improved DOT-111. This could require producers or shippers to create facilities to strip out volatile substances from certain crude grades before loading. Several leading US politicians from both parties, including from North Dakota, have voiced support for tighter regulations along the lines of what has been proposed in Canada. The US National Transportation Safety Board has already made a recommendation to the PHMSA that the old-model DOT-111 cars be taken out of service. Although railway companies have generally supported greater regulation of the DOT-111, most of the cars are not owned by the freight railroads, but by producers or leasing companies that are more publicly resistant to changes.
New US rail regulations appear unlikely before early 2015. In a notice issued in mid-January, the DOT cautioned that the complexity of the rule-issuing process is such that new regulations are unlikely to be finalised before then. Transport Canada has indicated that it will work with the US Federal Railroad Administration on the issue of a timeline for the replacement of old-model DOT-111 tankers, though this could not come about unless and until US regulatory changes are adopted. Given the great amount of cross-border rail traffic, it seems in both countries' interests to have a coordinated effort on the matter.
Meanwhile, representatives of industry and US government officials reached a voluntary, 30-day agreement at a 16 January meeting to implement steps that would improve safety, such as identifying safer routes for oil transport and slowing train speeds. Retrofitting or eliminating the older DOT-111 was not discussed, as this is a longer-term approach. It is possible that, post-2014, regulations could prohibit Bakken crude from being transported in old-model DOT-111 tankers after some period, and/or require that the old model DOT-111 either be retrofitted or eliminated, regardless of the crude grades or products being transported. Should such requirements be adopted, the timeline of their implementation would be of great importance, as a short timeline will inevitably reduce available transport capacity and drive up shipping costs. While Bakken is widely expected to come under downward price pressure in any event as production volumes increase, a short implementation period would likely cause the Bakken discount to widen versus WTI, let alone Brent, despite Bakken being one of the world's lightest and sweetest grades. Such a marked impact would be temporary, however. Potential new requirements for stripping Bakken and other LTO grades of
volatile substances could also affect producer netbacks. Shipper CSX has stated that although such expenses could be large, in the end the ability of companies to move freight by rail will not be greatly affected. The Bakken formation has been developed by independent producers teaming up with freight operators to build terminals so that production and transport go hand in hand. Canadian producers have now also invested heavily in rail facilities that will remain a part of the transport system even if additional pipelines are built. Rail is likely to remain an important, though not dominant, part of the mid-stream North American market for years to come.
Mexico - November actual; December preliminary: Crude oil production declined about 25 kb/d in November, to 2.51 mb/d, led by a 20 kb/d dip from the Cantarell field. NGL production held steady at 360 kb/d for November, and likely remained at that level for December. Preliminary crude oil production figures for December show output at 2.52 mb/d. Mexico's NGL production is expected to have averaged 360 kb/d for 4Q13.
Watershed Energy Reform Approved in Mexico
December 2013 marked a watershed for Mexico, as a landmark energy bill, encompassing several constitutional changes was approved by two-thirds of the country's General Congress and a majority of state legislatures. President Peña Nieto signed it into law on 20 December. This is the first significant legal reform of Mexico's energy sector in over half a century. As discussed in this Report in September when the government first unveiled it, the reform introduces a series of wide-ranging changes in the oil, gas, and electricity sectors. In terms of the upstream oil sector, key components include:
- Private and foreign oil companies will be allowed to include projected income from oil fields based on reserve estimates in their financial results. Although the Mexican state will formerly retain sub-soil rights, allowing companies to book expected income from the fields is nearly equivalent.
- Production-sharing contracts (PSAs) and even, in some circumstances, licenses will be allowed, in addition to the initially-proposed profit-sharing contracts and the already-extant service contracts. The more financially advantageous PSAs will make it possible to attract greater investment levels from foreign/private firms, though they may be restricted to the more challenging or risky projects.
- A trust fund overseen by the Central Bank will administer and distribute revenues from contracts (other than taxes).
- PEMEX will remain 100% state-owned, but will lose its regulatory and administrative functions as the sector becomes one with multiple companies. The National Hydrocarbons Commission (CNH) will take on a larger role in administering and regulating the sector, as well as the Energy Secretariat Sener.
- PEMEX's trade union will lose its five seats on the company's board of directors.
- PEMEX is required to submit a list of properties that it no longer wants to develop to the Government within 90 days of the 20 December 2013 ratification of the law (the so-called "Round Zero").
- The Government will have 180 days to review PEMEX's proposal. Subject to Government approval, areas not wanted by PEMEX and new acreage will be opened for bidding by other companies.
- A new tax and royalty regime will be instituted that will let PEMEX keep enough revenues to maintain adequate investment levels and sustainable debt levels.
The 20 December law is only the first step; a great deal of secondary legislation is now needed to flesh out the details of the reforms. A lot of capacity building will also be required to let CNH and Sener effectively administer a hydrocarbons sector that will become much more complicated - at present, the government has no experience regulating upstream oil and gas companies. Also, new licenses issued to private companies may face legal challenges if they are deemed equivalent to concessions, which remain technically illegal under the 20 December law.
Reform of the energy sector does not affect the 2014 forecast for Mexican oil production, but the medium-term forecast may see some adjustment, particularly for the tail end of the forecast period. It should also be noted that the reform also affects the mid-stream and downstream sectors, which will be opened to 100% private/foreign ownership of facilities such as pipelines and refineries.
Norway - October actual, November preliminary: Total liquids output rebounded by about 215 kb/d in October and a further 115 kb/d in November, from a September low of 1.57 mb/d that was mainly the result of planned and unplanned maintenance. Crude output for November is estimated at 1.55 mb/d. Although the Haltenbanken system's output, which includes Asgard, Draugen, Morvin and Tyrihans fields, recovered somewhat from its two-decade low reached in September, aggregate production from the system remained below 300 kb/d in both October and, based on preliminary data, November as well. Pending final data for the last two months of the year, current estimates indicate that Norway's total output for 2013 was 80 kb/d lower than in 2012. This declining trend will slow in 2014, with total production averaging 25 kb/d lower at 1.81 mb/d.
Norway's National Petroleum Directorate (NPD) released its preliminary December data as this Report was going to press, with both IEA's and NPD's total production estimates averaging 1.92 mb/d. The breakout between crude and NGL output between the two estimates differed slightly. Preliminary data for December indicate that total production rose only slightly on the month, capped by continued technical problems and repair work at Draugen, Heidrun, Norne, Skarv and Sklud. In early January, the Gullfaks B platform, one of three platforms on the Gullfaks field, went offline, cutting production at the field from the 45 kb/d output levels maintained in recent months.
UK - September actual, October preliminary: Offshore crude oil production rose 131 kb/d in September to 729 kb/d, recovering from the year's low recorded in August. However, some of those production gains were almost immediately reversed as offshore production fell in October to 702 kb/d. Overall in 2013, it is estimated that UK liquids output inched down by about 80 kb/d, a much slower pace of decline than the 246 kb/d and 170 kb/d drops recorded in 2011 and 2012, respectively. UK's total production in 2014 is forecasted at 765 kb/d, down about 95 kb/d y-o-y. Latest data indicate a decline in November production of about 85 kb/d, despite Buzzard remaining at 200 kb/d during the month. Fields that were undergoing maintenance in November, including Claire, Magnus and Eider have since resumed production. Maintenance is estimated to have cut output by about 30 kb/d during November.
In early December, a small fire occurred on the Triton Floating Production, Storage and Offloading vessel (FPSO) that produces oil and gas from the Bittern, Clapham, Pict, Saxon, Guillemot West and North West fields. Following the fire, the operator, Dana Petroleum, removed all staff and the FPSO was shut down for maintenance and incident investigation. Production at Buzzard field, the largest oil-producing field in the UK, was halted for at least three days in early January, cutting production to an estimated 170 kb/d for the month.
BFOE production increased to 930 kb/d in December, with loadings at 948 kb/d. Storms in the North Sea delayed some Ekofisk loadings, which fell to 290 kb/d in December, although the Ekofisk scheduled loading volume for January is scheduled at 329 kb/d. Total BFOE loadings for the month are scheduled at 986 kb/d. Our BFOE forecast production for January 2014 is slightly lower at 920 kb/d.
Brazil - November actual: Crude oil and total liquids output (excluding ethanol) both dipped by about 60 kb/d in November m-o-m, to 2.04 mb/d and 2.13 mb/d, respectively. After five consecutive quarters of y-o-y declines, 3Q13 indicated a rise in y-o-y output of 45 kb/d, with 4Q13 estimated to have built on that with a further 10 kb/d y-o-y increase. At 2.17 mb/d, total liquids production in 4Q13 was the highest since 1Q12. Unusual to normal seasonal patterns, Brazilian ethanol production stayed nearly as high in November as in October, at 640 kb/d, but is estimated to have declined sharply in December, to 285 kb/d, as a typical seasonal decline was seen.
For November, the Campos Basin fell by about 110 kb/d, with production mainstays such as Roncador, Marlim Sul, and Marlim all experiencing small declines. However, the Santos Basin experienced an increase of about 50 kb/d as the Cidade de Paraty FPSO on the Lula field appears to be ramping up and as the Baúna field moves toward capacity of 80 kb/d, after some difficulties in October. In November, the Papa Terra field came online and produced an average 4 kb/d in a partial month of production, but is heading toward about 70 kb/d by December 2014. The 22 kb/d P-20 platform on the Marlim field was shut in at the end of December due to a fire.
After many delays in the past couple of years, projects appear to be finally moving forward at a healthy pace for Petrobras. The 52 000-tonne P-55 platform set out for the Roncador field in October and began production on 31 December, starting at 15 kb/d, with an eventual capacity of 180 kb/d. The P-62 FPSO, also headed for Roncador and also with a capacity of 180 kb/d, had its construction completed in December and set sail for Roncador on 30 December. Production is forecast to begin by April. Also at the end of December, the P-61 platform set off for the Papa Terra field, where it will join the 140 kb/d-capacity P-63 FPSO already producing on the field. The 180 kb/d P-58 platform also set out in December for the Parque das Baleias field and is being anchored. In September, the 150 kb/d Cidade de Ilhabela FPSO, which arrived from China in January, is expected to come online, having been delayed from 2Q14. While its conversion was completed, topside modules still need to be installed. Finally, the Cidade de Margartiba FPSO, also 150 kb/d capacity, may come online before the end of 2014. It is currently scheduled for sometime in 3Q14, but will likely come online some time after Cidade de Ilhabela. With all of these projects taken into account, y-o-y crude oil growth of approximately 100 kb/d is forecast for 2014.
leo e Gás Participações, the reformed company that emerged from the bankruptcy of OGX, managed to bring online a new field, Tuburão Martelo, in December, at 13 boe/d, which is a chance for the new company to pay off creditors. OGX was once considered to have valuable offshore acreage, but failed to bring on substantial amounts of production.
China - November actual: Oil output edged down by 40 kb/d to 4.20 mb/d in November, although preliminary December data indicate a rebound to near-October levels. The December increase is mainly due to gains in Peng-Lai and Bohai Bay production that broke the 500 kb/d mark for the first time since July 2011, along with the increases in Changqinq's production, boosted by new wells that were placed into service recently.
Preliminary data released by the Chinese government show that PetroChina and Sinopec Corp. saw slight production increases in 2013 compared with the previous year. PetroChina's Daqing oilfield, China's biggest in terms of oil output, produced approximately 800 kb/d in 2013, while production at Sinopec's Shengli field, the country's second largest, averaged at 557 kb/d. The Changquiq oil field, operated by PetroChina, produced more than 470 kb/d in 2013, including 160 kb/d of tight oil. The government also reported some increases in heavy oil production for the year, most notably at the Tahe oilfield, which produced about 70 kb/d of super-heavy oil. The Tahe oilfield is located in the Tarim Basin, which has over seven billion barrels of super heavy oil reserves, 70% of which are located in the Tahe oilfield.
South Sudan: The civil war in South Sudan and the violence that has swept across the country since 15 December have so far not greatly affected oil production. Significant risk remains, however, that additional amounts of the estimated 200 kb/d still being produced could be shut-in should the conflict spread. As Government and rebel negotiators held another round of talks, fighting that has already claimed thousands of lives continues. An estimated 40 kb/d of oil production in Upper Nile and Unity State was shut-in as a result of the unrest in December. About the same production volume was projected to remain shut-in in January at the time of this writing, particularly as it has been reported that production infrastructure was destroyed in Unity State.
Former Soviet Union
Russia - November actual; December preliminary: Final data for November show that Russia's production rose to 10.99 mb/d, including 10.21 mb/d of crude oil. Overall in 2013, Russia's oil production averaged 10.87 mb/d, up 136 kb/d, or 1.2%, from the previous year. Preliminary data for December show that Russia's monthly output will exceed 11 mb/d for the first time since at least the early 1990s. The 2013 increase in production was the fifth consecutive annual increase in Russia's output, boosted by increased drilling in legacy oil provinces, expanded use of enhance oil recovery techniques, and continued strong production from already producing fields including Vankor. Russia's production is projected to increase to 10.95 mb/d in 2014. At least some of the additional supply in 2013 and 2014 is due to Lukoil's rising production. Following years of declines, the company increased its total production in 2013, and the growth in Lukoil's production is expected to continue into 2014.
Gazprom launched the Prirazlomnoye oilfield in the Pechora Sea at the end of December, marking the commencement of operation at Russia's first Arctic offshore oil project. Drilling, production and storage of the oil will be carried out at the Prirazlomnaya ice-resistant platform, specially designed to operate in Arctic conditions. According to Gazprom, there are approximately 530 million barrels of recoverable crude oil reserves in place, and peak production is expected to reach about 120 kb/d after 2020.
On 15 January, Russia's new "tax manoeuvre" was signed into law, which lowers Russia's crude oil export tax, although this tax cut will largely be offset by an increase in the mineral extraction tax (MET). Russia's government also unexpectedly froze 2014 railway transportation tariffs for crude oil and most oil products at the 2013 levels in late December.
Kazakhstan - November actual; December preliminary: Total oil production averaged 1.74 mb/d in November 2013, nearly flat m-o-m. Stable production is projected for December and January as well, before it declines slightly in 1Q14 and 2Q14. The more pessimistic outlook for Kazakhstan in this Report compared to last month is mainly the result of our reassessment of Kashagan's production restart, now expected in August 2014 at the earliest, with commercial production no sooner than September. A number of gas leaks were reported at Kashagan in September and during the field's brief restart in October. The cause and full extent of the problem remain unclear. Recent reports suggested that the gas leaks were more extensive than initially believed, which NCOC has not denied. In any case, NCOC has acknowledged that detailed gas pipeline inspections would be necessary, which may include digging up soil around at least some of the gas lines and may prove a lengthy process. Given the adjustment to expected Kashagan production in 2014, Kazakhstan's total oil output is now forecast to average 1.71 mb/d in 2014, only 35 kb/d higher than production in 2013.
FSU net exports climbed by 140 kb/d to 9.2 mb/d in November. Rising refined products shipments (+1.4 mb/d m-o-m) drove the increase, after regional refinery throughputs were hiked by 620 kb/d in the wake of seasonal maintenance winding down at Russian refineries. Exports of all product categories increased on the month, notably fuel oil (+50 kb/d) and gasoil (+10 kb/d) while 'other products' inched up by only 20 kb/d due to a combination of high demand and prohibitively high export duties on light products. Despite the month-on-month rise, product shipments stood 430 kb/d less than in November 2012 with fuel oil and gasoil 300 kb/d and 130 kb/d lower year-on-year, respectively. However, these decreases are the product of especially high product exports in November 2012. Moreover, 2013 product deliveries are still likely to post an increase over 2012 on an annual average basis underpinned by the trend of Russia refining more oil close to the wellhead to be subsequently exported.
On the flip side, the rise in domestic demand for crude curbed Russian crude exports with flows through the Transneft network falling by 80 kb/d on the month. However, total crude shipments only inched down by 100 kb/d as flows of Azeri oil through the BTC pipeline rose by 90 kb/d to 670 kb/d. BTC shipments were reportedly hiked due to a refinery outage in the country and flows being diverted from the CPC pipeline where volumes consequently fell to 710 kb/d (-70 kb/d m-o-m). The CPC was expected to carry increased flows from Kashagan in 4Q13 but as this project remains offline it appears that Russian producers have stepped into the breach with volumes in early 2014 expected to increase substantially. Moreover, a recent report indicates that CPC flows may reach their highest since 2008 at 780 kb/d in February. One reason for this may the relatively high netbacks available to producers shipping their oil via Novorossiysk compared to Primorsk and Ust Luga where costs have reportedly increased recently due to the requirement for ice class carriers to be used on Baltic voyages.
- Total OECD commercial oil inventories plummeted by 53.6 mb in November, their steepest monthly decline since December 2011. Crude oil and the 'other products' category led the plunge. At end-month, inventories lagged year-ago levels by 85.8 mb and five-year average levels by as much as 99.5 mb.
- Refined products inventories extended their recent downward slide, falling counter-seasonally by another 32.9 mb on the month, to cover 28.4 days of forward demand, 0.7 days lower than at end-October.
- Preliminary data point to a further 42.5 mb draw in OECD inventories in December, in line with seasonal trends,with crude stocks plunging in the US on exceptionally high refinery runs. Elsewhere, stocks in Asia Oceania slipped by half their normal draw while European holdings rose counter-seasonally.
OECD Inventory Position at End-November and Revisions to Preliminary Data
OECD commercial oil inventories plunged by 53.6 mb in November, their fastest monthly decline since December 2011. By end-month they had sunk to 2 607 mb, 86 mb below year-earlier levels. The unusually steep draw also took stocks 99.5 mb below their five-year average, their widest deficit since May 2003. OECD inventories have now stood in shortfall to average levels for eight consecutive months. Europe and Asia Oceania led the decline, with deficits to average levels of 93.5 mb and 22.0 mb, respectively. Even the OECD Americas has shown a declining trend lately: while inventories in that region still stand 15.9 mb above their five-year average, that surplus has narrowed by approximately 35 mb since September.
As noted in earlier editions of this Report, OECD stocks of refined products have persistently lagged seasonal levels over the past couple of years. This month, their deficit widened to 115.6 mb, its widest since February 2003. Several reasons help explain this trend: consistently backwardated product markets, which make it uneconomical to hold inventories; record-high US product exports; a continued downturn trend in OECD oil consumption, especially in OECD Europe, requiring less stocks to cover demand; and the closure of product storage capacity as refineries have been shuttered (for further details see: Trends in Global Oil Inventories in 2013 MTOMR).
Stocks of crude and 'other products' fell particularly sharply in November. A steep upswing in OECD refinery throughputs, to the tune of 2.3 mb/d, slashed crude stocks by 20.3 mb, compared to a small average build of 4.7 mb for that month in the last five years. Stocks of 'other products' drew by an even steeper 27.3 mb, nearly three times their 9.9 mb average decline. Much of that draw was concentrated in the US, where propane stocks plummeted on surging demand and high exports. As a result, over the past two months, OECD 'other products' stocks have swung from being in surplus to seasonal levels to standing at a deficit, whether in absolute terms or on a demand-cover basis.
OECD middle distillates inventories posted their third consecutive monthly draw in November. The latest decline of 10.9 mb leaves them lagging year-earlier and five-year-average levels by 73 mb and 18 mb, respectively. All in all, total OECD refined products inventories drew counter-seasonally in November by 32.9 mb. They now cover 28.4 days of forward demand, 0.7 days below end-October levels.
October data were revised steeply downwards by 23.2 mb. Crude oil accounted for most of the revisions (-14.9 mb). Smaller reductions were applied to estimates of refined product inventories (-4.3 mb) and to NGLs and other feedstocks (-3.9 mb). Middle distillates came in 8.2 mb lower after holdings in Europe and the Americas were adjusted downwards by 4.3 mb and 4.2 mb, respectively, partly offset by a 4.1 mb upward revision to motor gasoline, centred in the OECD Americas.
Preliminary data indicate that OECD inventories fell by a further 42.5 mb in December, in line with the 44.8 mb five-year average draw for that month. However, that aggregate masks sharp regional contrasts. In the OECD Americas, inventories plunged by 34.2 mb as refinery runs hovering near record highs slashed crude stocks by 25.3 mb. Stocks of 'other products' also drew down steeply. In Asia Oceania, inventories fell by a further 10.0 mb. That decline was only half of the seasonal average, though, as counter-seasonal builds in crude partly offset shallower-than-usual product draws. In contrast with those draws, European inventories inched up counter-seasonally by 1.7 mb, led by products. For the OECD as a whole, builds spanning all product categories with the exception of 'other products' failed to offset steep crude draws. Middle distillates inventories built by 5.9 mb, twice the seasonal average, while motor gasoline stocks rose by a strong 11.8 mb.
Recent OECD Industry Stock Changes
Industry inventories in OECD Americas drew by a steeper-than-usual 28.3 mb in November, led by a 22.7 mb plunge in 'other products', nearly three times the 7.7 mb seasonal draw for that category. Two factors help explain that monthly draw in 'other products': a continued boom in US propane exports, and increasing domestic propane demand for crop drying and for LPG and naphtha in the petrochemical sector. Among refined products, middle distillates also drew by a steeper-than-usual 5.6 mb, leaving inventories 8.3 mb below 2012 levels and as much as 37.8 mb below the five-year average. In contrast, motor gasoline posted a seasonal build of 4.8 mb, which leaves the region in surplus to both last year and the five-year average.
Although still 16.0 mb above average, total oil stocks now stood 16.6 mb below last year's level. Total product stocks extended earlier declines from their August highs with a further 22.5 mb draw in November, compared to a five-year average build for that month of 1.6 mb, cutting forward cover to 27.3 days, 0.8 days lower than at end-October. Crude stockpiles slipped by a steeper-than-normal 4.3 mb while NGLs and feedstocks slid by a further 1.4 mb on the back of surging refinery throughputs, spurred in part by a spike in refining margins at end-month.
Weekly data from the US EIA point to a further 34.2 mb draw in US commercial inventories during December. Crude oil led inventories lower, plunging by 25.3 mb on the month after refinery runs jumped by 0.5 mb to their highest monthly average since 2005 on surging margins. The bulk of this draw was centred in PADD 3 where stocks dropped by 21.6 mb. In contrast, PADD 2 inventories inched down by 0.4 mb.
As in November, product stocks were led by draws in 'other products' (-24.8 mb) while motor gasoline and middle distillates both built along seasonal lines, posting gains of 10.9 mb and 9.1 mb, respectively. Middle distillate inventories have stood below the five-year range since October, while those of motor gasoline stand comfortably towards the top of the seasonal range. All told, refined products slipped by 2.2 mb in December. Early indications from January data indicate crude stocks have fallen further as refinery throughputs have remained near record levels while builds in products were likely curbed by high exports, especially of gasoline, propane and distillates, and by healthy demand above year-earlier levels. In the wake of the 'polar vortex', US distillate stocks also drew further to leave them languishing below year-ago and seasonal levels. Moreover, PADD 1 distillate stocks now sit 5.7 mb and 18.8 mb below last year and seasonal levels, respectively. This has led to regional price increases reports of imports to the region from as far a field as Europe, Russia and India as the transport of Gulf Coast supplies remains hindered by the supply of available Jones Act tankers and a lack of spare capacity on the Colonial Pipeline.
European commercial inventories decreased counter-seasonally by 13.0 mb in November, in contrast to the 12.0 mb average build of the last five years for that month. The region's deficit to average levels has widened considerably, reaching 93 mb at end-month. Crude oil stocks dropped by 10.3 mb after regional runs rose by 800 kb/d, led by draws of around 3 mb each in Germany, France and Italy. Refined products stocks drew counter-seasonally by 3.0 mb, compared to a 7.9 mb average build for the month. At end-month they covered 36.7 days of forward demand, slightly down (-0.4 days ) from end-October but a significant 3.2 days lower than November 2012 levels. Stocks drew in all products bar fuel oil month-on-month. Notably, middle distillates drew by 1.7 mb contrary to the 6.3 mb seasonal build. Since middle distillates only replenished by approximately 17 mb over the summer, inventories now lag the five-year average and last year's level by 32.0 mb and 10.0 mb, respectively. In Germany, heating oil consumers began to draw down their stocks as tank fill fell to 61% of capacity in early-December, down 2% from one month earlier.
Preliminary data from Euroilstock indicate that European inventories rebounded counter-seasonally by 1.7 mb in December, led by builds in 'other products', motor gasoline and middle distillates of 1.8 mb, 1.6 mb and 1.1 mb, respectively. Crude stocks inched down by 2.2 mb as runs remained relatively stable at 11.2 mb/d (+ 100 kb/d m-o-m).
OECD Asia Oceania
Industry inventories in OECD Asia Oceania fell by 12.3 mb in November, faster than the 4.0 mb five-year average draw for the month. The bulk of the drop came from refined products, which fell by 7.4 mb with all product categories except motor gasoline destocking. Middle distillates slid by a seasonal 3.6 mb with 'other products' falling by a further 3.3 mb, likely after a pick up in the region's petrochemical sector pressured stocks of LPG and naphtha lower. At end-month, refined products covered 19.1 days, 1.1 and 1.2 days lower month-on-month and year-on-year, respectively. Meanwhile crude holdings dropped by 5.7 mb, in contrast to the five-year average 1.9 mb build, after crude runs rose by 550 kb/d, outpacing regional imports.
Preliminary weekly data from the Petroleum Association of Japan (PAJ) point to a 10.0 mb draw in Japanese commercial inventories over December, weaker than the 14.6 mb average draw for the month. All oil categories fell bar crude oil, which inched up by a counter-seasonal 1.2 mb. Refined products dropped by a weak 6.9 mb as draws in middle distillates (-4.3 mb) and fuel oil (-1.6 mb) pressured stocks lower. Data through 11 January indicate that Japanese inventories have rebounded slightly. Crude stocks rebounded on sharply higher imports from Africa and Iraq while refined products also increased as refinery throughputs remained buoyant.
Recent Developments in Singapore and China Stocks
According to China Oil, Gas and Petrochemicals (China OGP) Chinese commercial crude stocks slipped by an equivalent 6.6 mb in November (data are reported in terms of percentage stock change) after a blast on a 200 kb/d crude pipeline transporting oil from the port of Huangdao to the Qilu refinery disrupted import flows. Commercial holdings of gasoil, kerosene and gasoline dropped by 2.0 mb, 1.0 mb and 0.2 mb, respectively. Moreover, the gasoil draw was the sixth straight monthly decline, leaving stocks at their lowest level since November 2010.
Weekly data pertaining to the land-based storage of refined products in Singapore indicate that stocks slipped by 0.1 mb in December. Stocks were dragged lower by a 1.2 mb draw in residual fuel oil, after bunkering demand in the country reportedly hit a 19-month high, outpacing healthy imports from the Atlantic Basin. Despite middle distillates rebounding by 0.7 mb over the month, stocks still stood below the five-year range at end-year. However, recent data indicate that stocks replenished to once again stand at seasonal levels by early-January. Meanwhile, light distillates built steadily from late-December onwards to leave stocks at three-year highs by early January.
- Crude oil markets strengthened across the board in December against a backdrop of seasonally stronger winter demand in Northern Hemisphere markets. North Sea Brent prices were also buttressed by continued supply outages in Libya while WTI was propelled higher by a steep run-up in domestic refinery throughputs. By mid-January, however, prices were trading well below December levels as supply worries eased, with ICE Brent crude futures last trading at $106.35/bbl and NYMEX WTI at around $93.70/bbl.
- Oil prices ebbed and flowed on supply disruptions and geopolitical developments throughout the year but overall were relatively stable in 2013. Increases in US domestic crude production served to mute the impact of sharply lower Libyan output and Iranian supplies.
- Spot product prices rose in December, with the sharpest gains seen at the light end of the barrel. Asian refiners posted improved crack spreads for naphtha and gasoline on increased petrochemical demand and refinery outages. European gasoil cracks, however, remained under pressure from US and Russian distillate imports while USGC refiners experienced a volatile month.
- Rates for crude carriers surged at the end of 2013, with gains particularly strong on routes leaving the Middle East Gulf and West Africa, with the West Africa - US Gulf Coast route surging to its highest level in six years in early January.
Crude oil markets strengthened across the board in December as seasonally stronger winter demand swept through Atlantic Basin markets. North Sea Brent prices were also buttressed by continued supply outages in Libya while WTI was propelled higher by a sharp run-up in domestic refinery throughput rates. A drawdown in OECD stocks at year-end on top of a sharp decline the previous month to levels below the five-year average also supported prices. In December, ICE Brent futures rose by $2.80/bbl to an average $110.70/bbl while NYMEX WTI increased by a stronger $3.96/bbl to $97.89/bbl.
By early January, however, Brent prices traded below December levels on expectations of increased supplies from Libya and Iraq. ICE Brent crude futures were last trading at $106.35/bbl. An exceptional winter freeze across much of the US unusually weighed on prices in early January (see Demand, 'Winter Freeze'). NYMEX WTI was trading at around $93.70/bbl at writing.
A landmark interim agreement between Iran and the P5+1 nations reached in Geneva in November, but due to go into effect 21 January, may also have reduced the market's perception of supply risk. The resumption of active negotiations between the international community and Tehran has raised the prospect of an end to the long stand-off over Tehran's nuclear programme but, while the interim agreement allows for some easing of shipping restrictions, US and EU sanctions on Iranian oil exports will remain in place for at least the next six months.
The WTI-Brent spread narrowed by around $1/bbl to just under $13/bbl in December but by early January widened to around $13.50/bbl ahead of the start-up of another major pipeline moving crude from the US Midcontinent to the key Gulf Coast refining region. TransCanada's 700 kb/d Gulf Coast crude pipeline from Cushing, Oklahoma, to Port Arthur, Texas is scheduled to start commercial service on 22 January.
Oil prices ebbed and flowed on supply disruptions and geopolitical developments throughout the year but overall were relatively stable in 2013. Benchmark crude prices diverged slightly, with Brent futures averaging $108.70/bbl, $2.98/bbl below 2012 annual levels. By contrast, WTI gained an average $3.90/bbl for the year, to an average $98.05/bbl. Significant increases in US crude production served to mute the impact of sharply lower Libyan output and Iranian supplies. Libyan output swung from a high of 1.42 mb/d in April to just 230 kb/d by December. Preliminary data for full-year 2013 show imports of Iranian crude and condensate declined by 450 kb/d year-on-year, to 1.07 mb/d compared with 1.52 mb/d on average in 2012 (when major US and EU sanctions came into effect) and 2.42 mb/d in 2011 (See OPEC Supply). The higher US production backed out further imports of lighter crude imports such as Nigerian and Algeria grades, which in turn shifted supplies to Europe and Asia, helping to offset reduced volumes from Libya and Iran. A steady increase in pipeline and railroad flows within North America also eased the downward price pressure on WTI last year, with the differential with Brent narrowing on average in 2013 to $10.70/bbl compared with around $17.50/bbl in 2012.
Underscoring the relative stability of markets throughout 2013, increased pipeline outlets from Cushing, combined with a build in crude inventories to levels above the five-year average for most of the year, led to a narrowing of the price spread between the WTI front-month and second-month contracts, M1-M2. The spread averaged just -$0.08/bbl in 2013, a narrowing of around $0.30/bbl from -$0.38/bbl in 2012. The Brent M1-M2 price spread was more volatile and largely remained backwardated due to Libyan supply outages but was unchanged at around $0.65/bbl on average from 2012 levels.
ICE Brent and NYMEX WTI money managers' net-long position movements were mixed between 10 December and 14 January, tracking changes in the benchmark grades. The gyrations in Brent futures prices, which rose by $3.50/bbl in the second half of December only to fall back to under $108/bbl in early January, mirrored similar swings in money managers' long/short ratio. Likewise, NYMEX WTI hedge funds took a progressively more bullish stance throughout December on the back of steadily rising WTI prices, falling back in early January as WTI settled lower around $92/bbl.
RBOB gasoline managed-money net-long positions showed bullish signs throughout December, but retreated slightly in early January. On the gasoil/heating oil front, net longs in the ICE Gasoil market mirrored Brent's swings, while NYMEX heating oil net longs grew in tandem with WTI and mildly retreated in early 2014.
Open interest in both Brent and WTI contracts was up about 8% year-on-year, albeit seasonally down on a month-to-month basis. December trading volumes saw both Brent and WTI grow in double digits compared with a year earlier, up 23.5% and 11.2%, respectively. The two benchmarks kept alternating for the global lead in global trading volumes, extending the pattern of the last six months, with Brent being the most traded in December. Throughout 2013, a growing portion of global Brent volumes was traded in New York, amounting to a significant 8% in December, from less than 1% at the start of the year.
The final Volcker rule was approved by five US regulatory agencies on 10 December. The rule, a major pillar of the 2010 Dodd Frank Act, bars banks from trading in commodities and derivatives for their own account, and limits their ownership in private-equity and hedge funds. Exceptions are made for spot commodities, hedging and market-making activities. As a result, several major banks have been exiting the commodity trading business. Morgan Stanley recently sold its global oil merchandising business to Russian oil company Rosneft. JP Morgan put its physical trading business up for sale in October, while Deutsche Bank announced on 5 December that it would cease its commodity trading activities in the next years due to the regulatory changes. Banks' overall presence in oil trading is sizeable and has been growing in the past years. According to the latest CFTC 'Bank Participation Report', 16 banks held 25% of overall short positions in NYMEX WTI future contracts and close to 40% of WTI calendar swaps, a significant share now set to decrease.
The European Parliament and the Council of Europe reached an agreement in principle on updated rules for markets in financial instruments (MiFID II) on 14 January. The revised directive regulates position-limits, position reporting by trader category, and high-frequency trading. Unlike in the Dodd-Frank Act, the new EU rules would apply to both physical and financial commodities. The final text is yet to be finalised and will have to be approved by a plenary session in the Parliament and signed off by the Council in order for the legislation to come into force, which is expected to happen towards end-2016.
The CFTC invited 60-days of public comments on its guidance for cross-border application of the new swap rules on 3 January. This follows a jointly filed industry lawsuit on 3 December by the Securities Industry and Financial Markets Association (SIFMA), the International Swaps and Derivatives Association (ISDA) and the Institute of International Bankers (IIB). The groups argue that the CFTC had labelled a de-facto regulation as 'guidance', in order to circumvent the stricter rulemaking procedure, which would require seeking and weighing public comment and conducting a cost-benefit analysis.
Spot Crude Oil Prices
Major benchmark crude oil prices rose between 1.9%-4.2% in December before drifting lower in early January. US WTI posted the largest increase at $3.90/bbl to $97.85/bbl, in step with exceptionally strong refinery throughput rates. North Sea Dated Brent rose by a smaller $2.90/bbl to average $110.80/bbl, supported by reduced Libyan supplies. Heavier Dubai crude gained a more modest $2/bbl to $107.90/bbl as Asian buyers preferred lighter crudes such as Malaysian Tapis. The spot Dubai-Brent differential deepened to around -$3.35/bbl in the first half of January compared with an average -$2.90/bbl in December and -$2.10/bbl in November.
US crude oil markets strengthened on the back of exceptionally high domestic refinery runs in December, diverging further from global markets. Prices for lighter US crude grades rose in tandem with robust US refinery throughput rates in December. The start-up of another major pipeline moving crude from the US Midcontinent to the key Gulf Coast refining region also supported prices. TransCanada's 700 kb/d Gulf Coast crude pipeline from Cushing, Oklahoma, to Port Arthur, Texas is scheduled to start commercial service on 22 January. Higher domestic prices saw the WTI-Brent price spread narrowed to $12.95/bbl versus $14.05/bbl in November.
Freezing weather across a broad swath of the US Midcontinent and East Coast disrupted domestic crude oil production operations, and marginally reduced output. Bakken prices relative to WTI rebounded sharply from mid-November 2013 lows, with the Bakken-WTI discount narrowing to just -$2.85/bbl in first half January compared with an average -$9.10/bbl in December and -$13.05/bbl in November.
Prices for heavy Western Canadian Select (WCS) have continued on an upward trend since early November on stronger demand from both Canadian and US refiners. Several US Midcontinent refiners are taking more Canadian heavy crude following the increase in rail and pipeline capacity from Alberta to the Midwest, including BP for its 405 kb/d Whiting, Indiana refinery and Citgo for it's 175 kb/d Lemont, Illinois facility. The WCS price discount to WTI narrowed to around $19.25/bbl in the first half of January compared with $26.30/bbl in December and $34.25/bbl in November.
In Europe, the near total absence of Libyan crude supplies due to the continued shutdown of shipping terminals supported Brent prices in December. Spot prices for Brent, however, eased in early January on a partial recovery in Libyan exports and expectations of increased North Sea supplies. Urals was trading at a negligible -$0.02/bbl to Brent in the Mediterranean in December before widening to -$0.75/bbl in first-half January on increased supplies.
In Asia, spot markets for lighter grades strengthened on improved crack spreads for naphtha and gasoline as a combination of increased petrochemical demand and refinery outages tightened supplies. Chinese crude imports hit record levels in December, with demand for spot African crude strong. By contrast, demand for heavier Mideast grades such as Dubai was relatively weaker. As a result, time-spreads for the front month Dubai tumbled over the past few months, with the Dubai M1-M2 falling to around $0.40/bbl in early January compared with $0.60/bbl in December and $1.50/bbl in November.
Spot Product Prices
Product crack spread movements were mixed in December. Asian refiners benefitted from improving cracks at the light end of the barrel as increased petrochemical demand and refinery outages supported naphtha and gasoline prices. Meanwhile European gasoil cracks remained under pressure from US and Russian distillate imports while USGC refiners experienced a volatile month. USGC cracks tumbled from November peaks in early-month after refiners increased throughputs to eight-year highs, but rebounded from mid-December as increased demand and high exports pushed up product prices.
After weakening over early-December, gasoline cracks strengthened across the board from mid-month, although the scale of increases varied between markets. The USGC crack was characterised by volatility. After tumbling in early December, the crack came roaring back after gasoline prices firmed on reports of surprisingly high demand. However, cracks dropped back in early-January after US stocks rose. NWE and Mediterranean gasoline cracks remain depressed on ample regional inventories. Nonetheless, they did inch up in December as gasoline prices rose in response to an open gasoline arbitrage to move product to the US East Coast. French refinery strikes and a fatal explosion in a gasoline hydrotreater unit at Total's Antwerp refinery also supported prices. Meanwhile, cracks in Singapore strengthened over December, as Singapore light distillate stocks drew sharply in early-month. In contrast to other regions, gains were maintained into early-January, supported by an unplanned outage at Taiwan's Formosa refinery.
Asian naphtha markets strengthened in December and into early-January after high petrochemical demand from, amongst others, Japan and Taiwan pushed the Singapore crack into positive territory for the first time since March 2013.
An increase in imports from India, as refineries there underwent maintenance, helped to push up prices, which in turn drew in supplies from Europe, the Middle East and the US. Accordingly, naphtha cracks strengthened in these markets over the month. However, the momentum slipped away in mid-January after Singapore light distillate stocks climbed to eight-year highs.
USGC middle distillates crack spreads plunged in early-December as LLS strengthened against product prices. However, cracks rose again in early-January when a cold snap, the 'polar vortex', hit the US, causing a number of outages at refineries and boosting heating oil demand. An additional buttress was provided by healthy exports to Latin American and European markets.
In Europe, product price increases were capped by mild weather and plentiful imports from the US and Russia. Nonetheless, cracks remained at seasonal levels. In mid-January, cracks firmed following a fall in Russian supplies as these volumes were diverted to the US East Coast where prices rose following recent cold weather. In Singapore, middle distillate cracks have been on a steady downward trajectory since end-November, pressured by increasing crude prices and low demand for heating fuels due to mild weather.
Early-January saw the Singapore low-sulphur fuel oil crack return to positive territory as crude prices weakened after the product gained some strength from tightening fundamentals. Singapore bunkering demand reportedly hit a 19-month high in December while regional imports remained low, causing fuel inventories to draw by a steep 3 mb in the last week of December.
Outside of Singapore, fuel oil cracks remained firmly entrenched in negative territory, considerably below year-ago levels.
Rates for crude carriers surged at the end of 2013, as increased long-haul trade tightened tanker market fundamentals. Gains were particularly strong on routes leaving the Middle East Gulf and West Africa, with the West Africa - US Gulf Coast route surging to its highest level in six years in early January. Rates in the Suezmax and Aframax sectors generally remained strong from December into early-January.
Rates for VLCCs on Middle Eastern routes strengthened on robust Asian demand, especially from China, in December. Indeed, a high number of Middle Eastern cargoes entered the market in December as Chinese refiners increased their imports, to record highs, ahead of the on 31 January Chinese New Year. As such, rates on the benchmark VLCC Middle East Gulf - Asia route generally held their levels at close to $17/mt over December before plunging quickly back to close to $10/mt by the second half of January.
In contrast, rates for Suezmaxes on voyages out of West Africa have surged since early-December for a number of reasons. Firstly, demand from Asian refiners has been strong, supported by favourable economics to ship regional grades there. Most notably, Chinese refiners imported record amounts of West African crudes in 4Q13. Secondly, as the VLCC pool shrank, charters were forced to split cargoes with two Suezmaxes required to cover one VLCC voyage. Thirdly, stormy weather in early January caused delays resulting in replacement vessels being chartered for date-specific cargoes. By early January, rates on the benchmark Suezmax West Africa - US Gulf Coast trade briefly exceeded $30/mt for the first time since December 2008.
Freight rates also surged in Northwest Europe during December. Recently, there has been healthy demand for NWE fuel oil from US and Asian markets and North Sea crudes are increasingly being imported by Asian refiners, notably in Korea and China. Consequently, vessels have been tied up for longer voyages, which has tightened tonnage. Further upward momentum was generated by bad weather in Northern Europe, which delayed voyages and left charters searching for last-minute replacement carriers to cover date-specific cargoes. Consequently, rates on the benchmark Aframax cross North Sea route exceeded $11/mt at the end-of December, their highest level since summer 2008.
Movements across the product tanker market were more mixed in December, with only transatlantic product trade providing any upward momentum. Rates for trades on the benchmark UK - US Atlantic Coast route have been on a steady upward trajectory since their November nadir. Indeed, in early January they exceeded $25/mt for the first time since August 2013. Rising gasoline exports from Europe to the US East Coast has underpinned this trend, with the arbitrage recently widening to draw in European product as East Coast prices firmed. Moreover, in mid-January rates on the trade have also been buttressed by reports of tankers being booked to ship heating oil and diesel to the US East Coast where prices have risen in the aftermath of recent cold weather.
East of Suez, product tanker markets generally firmed during December but then softened in early January. North Asia has so far experienced a mild winter and thus demand for product imports has been limited, leaving the vessel pool swollen. Consequently, rates on Asian benchmark trades remain considerably below year-earlier levels.
- The forecast of global refinery crude runs for 1Q14 has been lifted by 110 kb/d since last month's Report, to 76.8 mb/d, on a stronger US outlook. US refinery crude throughputs leaped to eight-year highs in December, resulting in annual gains of more than 0.5 mb/d for the second half of the year and 0.3 mb/d for 2013 as a whole. Surging regional liquids supply is translating into higher runs. We expect US runs to maintain annual growth of around 0.5 mb/d in early 2014.
- 4Q13 global crude run estimates are largely unchanged since last month's Report, at 76.3 mb/d, as higher-than-expected US, Russian and Brazilian throughputs towards year-end were offset by weaker European and Chinese throughputs. A labour strike in France in December slashed European runs further. At 10.9 mb/d, 4Q13 European crude throughputs plummeted by 1.1 mb/d year-on-year (y-o-y), curbing growth in global crude throughputs to only 280 kb/d.
- OECD refinery crude throughputs rebounded by a steep 2.3 mb/d in November month-on-month (m-o-m), to average 36.8 mb/d. The unwinding of seasonal maintenance lifted runs in all regions, though prolonged shutdowns and poor economics kept European runs some 900 kb/d below year-earlier levels. Preliminary data for December show OECD runs rose by a further 0.8 mb/d as US throughputs hit monthly highs unseen since July 2005.
- Global refinery margins generally deteriorated over December, with the exception of Singapore. A strike at Total's French refineries failed to lift European margins, which remained firmly negative for simple configurations and weak for more complex plants, keeping regional utilisation rates low. US refinery margins faced sharper declines m-o-m as margins came off their end-November highs. Gulf coast margins slipped $3.20/bbl on average while midcontinent rates were down by $5.90/bbl. Yet returns remained attractive, leading US refiners to process their highest level of crude since July 2005.
Global Refinery Overview
Global refinery crude runs in December were 90 kb/d lower than previously expected, as strong US and Russian throughputs only partly offset lower than expected activity in Europe and China. US throughputs hit 16.1 mb/d in December, their highest since July 2005, in part due to very good margins at end-November. European activity, on the other hand, was curtailed by strike action in France in December, while Chinese refinery activity was curtailed by disrupted crude supplies to refineries following a devastating pipeline explosion in November and as the long-awaited commissioning of new capacity was again stalled. All in all, 4Q13 global runs are largely unchanged since last month's Report, at an average 76.3 mb/d, while 1Q14 runs are forecast 110 kb/d higher.
Annual growth in refinery activity is set to rebound by 1.3 mb/d in 1Q14 from only 280 kb/d in 4Q13, as contraction in Europe eases. In 4Q13, European throughputs plunged by 1.1 mb/d y-o-y. In the OECD Americas, throughputs rose by 355 kb/d. Smaller increases came from all non-OECD regions, amounting to total non-OECD gains of 1.0 mb/d. In 1Q14, the ramp up of Saudi Arabia's Jubail refinery is expected to bring additional product volumes to market. So is new capacity recently commissioned in China. Both PetroChina's 200 kb/d Pengzhou and Sinochem's 240 kb/d Quanzhou refineries finally started trial runs in January. Both plants had been delayed several times, from initial start-up dates of end-2012 and mid-2013, respectively. The two projects are the first new refineries to come on line since 2010, when PetroChina's Qinzhou plant was completed. Russian and US runs will likely continue apace, supported by favourable economics. European refiners, on the other hand, will likely continue to struggle, in the face of weak regional demand and dismal margins, but declines should abate from current levels.
Refinery margins generally weakened in December, as supply outages lifted crude prices, outstripping meagre product price increases. The only region where margins firmed on average was Singapore, as healthy product markets and relatively subdued crude price hikes there provided upward momentum. Early January saw margins rebound in Europe and extend their gains in Singapore after benchmark crude prices eased on expectations of improved supply.
US refining margins plummeted in early December, reversing their spectacular gains of the previous month. US crude prices firmed in December as throughputs surged to their highest levels since 2005. Midcontinent refiners saw margins tumble by $5.90/bbl on average although all margins, except those for WTI, remained on a par with year-ago levels. Bakken margins led the drop, plunging by over $7/bbl on average as Bakken crude prices firmed relative to WTI. In comparison, refiners on the US Gulf Coast suffered a margin drop of $3.20/bbl on average as exceptionally high throughputs caused WTI and LLS prices to rise faster than light and middle distillate prices. Despite this fall, USGC margins remain on an upward long-term trend, higher on a year-on-year basis, with Latin American and European exports markets proving profitable outlets.
Refiners in Europe continue to see margins trend below or close to break-even levels. Not even refinery strikes in France, taking an estimated 230 kb/d of capacity off-line on average in the month, could move margins higher as increases in Brent-linked crude prices outstripped small product price gains. High distillate imports from Russia and the US are helping cap product price increases, as refiners there take advantage of their access to cheap crude and, in the case of the US, low energy costs in the form of cheap natural gas. The effect of these imports was acutely felt in the Mediterranean where, despite cold weather increasing demand for distillates, product price increases were capped by plentiful imports. Refinery margins in the Mediterranean slipped by $0.30/bbl over the month. Northwest European margins generally held steady month-on-month with Urals cracking margins actually firming by $0.30/bbl after Brent strengthened relative to Urals. As has been the case recently, margins for simple refineries remain firmly in the red.
Margins in Singapore were the only bright spot in December, as healthy demand strengthened product markets, with price increases significantly steeper than those reported in Europe. Accordingly, margins rose by $0.60/bbl on average, though refiners running Tapis were at a distinct disadvantage to others since it firmed relative to Dubai. Relatively complex refiners running Tapis thus enjoyed significantly smaller margin gains (+$0.80/bbl m-o-m) than those running Dubai (+$1.50/bbl m-o-m).
OECD Refinery Throughput
OECD crude runs rebounded by a steep 2.3 mb/d in November from a month earlier, with large gains spanning all regions. At 36.8 mb/d, total OECD runs nevertheless remained below year-earlier levels, as contractions in Europe outpaced robust activity in the Pacific and the US. Heavy turnarounds and poor margins had slashed runs to just 34.5 mb/d in October, a 20-year low. According to preliminary data, OECD crude runs gained a further 0.8 mb/d in December, to 37.5 mb/d. US refinery runs hit an eight-year high in December, offsetting lower than-expected runs in Europe, where a labour strike at several French refineries further curbed throughputs.
All in all, 4Q13 OECD runs have been lowered by 35 kb/d since last month's Report, to 36.2 mb/d. Throughputs contracted by 740 kb/d overall, as a 355 kb/d increase in the OECD Americas and relatively stable runs in OECD Asia Oceania failed to offset a contraction of almost 1.1 mb/d y-o-y in Europe. For the year as a whole, OECD throughputs were 430 kb/d lower than a year earlier, with European refiners slashing runs by 630 kb/d, while refiners in the Americas raised throughputs by 270 kb/d.
These trends are expected to continue in 1Q14. US refinery runs got off to a brisk start in January, posting even stronger annual gains than those seen at end-2013. European throughputs, on the other hand, will likely remain under pressure, though their rate of contraction is expected to ease from that seen in 2H13. In Asia Oceania, Japan will permanently halt 400 kb/d of capacity at end-March, in keeping with a government ordinance to make its industry more competitive. The impact of the refinery closures is expected to be less than nameplate capacity reductions, however, as some of the units have already been mothballed, and the remaining refineries will likely lift their utilisation rates to compensate for the closures (see 'Upcoming Capacity Reductions in Japan to Have Limited Impact'). In all, OECD runs are forecast to average 36.4 mb/d in 1Q14, up 50 kb/d y-o-y, and 55 kb/d higher than in last month's Report.
With the receipt of monthly data, North American crude runs have been revised down by 60 kb/d for November compared with our earlier assessment. Most of the revision stemmed from lower runs in Mexico, where plant turnarounds seem to have been extended from October, keeping utilisation at around 70% of capacity. Regional runs of 18.7 mb/d were nevertheless up 870 kb/d from October's seasonal low. Compared with a year-earlier, regional runs stood 445 kb/d higher, as US refiners posted annual gains of an impressive 580 kb/d.
Weekly data from the US Energy Information Administration (EIA) show US refinery crude runs surging another 475 kb/d in December on average, to 16.1 mb/d, their highest monthly average since July 2005. Crude volumes processed at refineries on the Gulf Coast rose by 315 kb/d m-o-m, and reached a high of 8.6 mb/d (or 95.6% utilisation) in the week ending 20 December. US East Coast refinery throughputs rose by 100 kb/d to 1.1 mb/d after two months of maintenance-related run cuts. Midcontinent refinery runs reached a monthly high in December of 3.58 mb/d on average, following an all-time 3.7 mb/d record high in the first week of the month. For December as a whole, refinery crude intake in the midcontinent was up by 120 kb/d y-o-y, supported by healthy margins and increased runs at BP's recently upgraded Whiting, Indiana, refinery. BP started a new 250 kb/d crude distillation capacity in July 2013, returning the refinery to its 413 kb/d nameplate capacity.
The extreme cold that swept across North America in early January caused operating problems for several regional refiners. Korea National Oil Corporation's 115 kb/d Come-by-Chance refinery in Newfoundland, Canada and PBF Energy's 180 kb/d Paulsboro, New Jersey, refinery both reportedly lost power due to the weather. In the US midcontinent, Marathon Petroleum confirmed unplanned shutdowns at its 120 kb/d Detroit refinery, while CITGO reported problems at its Lemont, Illinois, refinery. Further south, freezing conditions prompted upsets at Exxon Mobil's Joliet plant in Illinois and Total's 240 kb/d Port Arthur, Texas facility.
In addition to weather-related outages, US refineries are gearing up for seasonal overhauls in the first quarter, spring turnarounds during which they prepare for the switch from winter-grade to summer-grade gasoline. Amongst others, Monroe Energy LLC's 185 kb/d Trainer, Pennsylvania refinery started maintenance on a crude unit in early January, while Valero's Corpus Christi, Texas, and Memphis, Tennessee, refineries are doing work on their crude units starting in March.
European refinery crude intake estimates for November are largely unchanged since last month's Report, at 11.2 mb/d. Despite rising some 870 kb/d from October's low, regional throughputs remained 900 kb/d below a year earlier. Preliminary data for December from Euroilstock, released 10 January, suggest that regional runs remained weak through year-end. We have lowered our December estimate by 290 kb/d since last month's Report to average 11.2 mb/d. The bulk of the downward revision stems from France, where strike action at Total's domestic plants slashed refinery activity. The company's Gonfreville, Donges, La Mede, Feyzin and Grandpuits refineries, with combined capacity of around 840 kb/d, were offline for up to 11 days in December, curbing runs by an estimated 230 kb/d. In all, 4Q13 European crude runs are now assessed at 10.9 mb/d, 1.1 mb/d below a year earlier.
While regional runs are expected to continue to contract in 1Q14, the rate of contraction is expected to ease, to an average of 250 kb/d. Refinery maintenance normally peaks in March or April, though little firm information is available yet on planned outages. Given the extensive work completed in 2013, outages in 2014 could be less severe. Tupras' Izmit refinery in Turkey shut down in January, for up to a month, to carry out work on its Residue Upgrading Project. The $2.7 billion project, which includes a coker and a hydrocracking unit, is expected to come online in November and will contribute to reducing the country's gasoil deficit.
In OECD Asia Oceania, crude intake rose by 550 kb/d from a month earlier in November, lifted by sharply higher Japanese throughputs. Japanese refiners lifted runs 490 kb/d from a month earlier, while South Korean runs rose by close to 100 kb/d. Weekly data from the Petroleum Association of Japan show Japan's refinery crude throughputs rising another 440 kb/d in December. Japan's largest refiner, JX Nippon Oil and Energy Corp., announced it planned to cut runs in January by 2% y-o-y as unseasonably warm weather undermined kerosene demand. Exports were expected to remain high, though, providing a partial offset.
Upcoming Capacity Reductions in Japan to Have Limited Impact
The 31 March 2014 deadline for Japanese refiners to comply with a 2010 governement ordinance, requiring a minimum of 13% cracking to crude distillation (CDU) ratio for the sector as a whole, is fast approching. Faced with declining domestic demand and increased competition from new refineries in neighbouring countries, refineries have mostly opted to cut distillation capacity rather than invest in expensive upgrading units, resulting in a reduction of almost 1 mb/d from 2009, when CDU capacity stood at 4.9 mb/d. While some of the consolidation has already been completed, another 0.4 mb/d is scheduled to be cut before the end of March, taking Japan's nameplate capacity to 3.94 mb/d.
Still to come, JX Nippon Oil and Energy Corporation is scheduled to shut its 180 kb/d Muroran refinery in northern Hokkaido, while Idemitsu will close its 120 kb/d Tokuyama plant at the end of March. In addition, Tonen General is set to formally decommission the 67 kb/d CDU at its Kawasaki refinery and the 38 kb/d CDU at Wakayama by March deadline, though operations were already halted some time ago.
Furthermore, the 300 kb/d of capacity still to be shed by end-March could mostly be compensated for by remaining domestic refinery capacity. In 2013, preliminary data suggest Japanese crude intake averaged less than 3.5 mb/d, or 79% utilisation, suggesting that runs could easily be lifted at other plants to offset the shutdowns. If runs were kept unchanged from 2013's level after the capacity reductions are completed, utilisation rates would rise to 88% on average. Given continuous structural demand contractions, estimated by the IEA at around 170 kb/d for both 2013 and 2014, throughputs will likely continue to trend lower in 2014 and beyond, but by less than suggested by simply looking at the latest wave of capacity reductions.
Non-OECD Refinery Throughput
Non-OECD refinery throughput estimates for 4Q13 have been revised upwards by 50 kb/d since last month's Report, to 40.1 mb/d, on stronger-than-expected Russian and Brazilian refinery activity. With the receipt of preliminary data for December, Russia looks to have increased its crude processed domestically by 150 kb/d on the year, to almost 5.5 mb/d. Russia is the third largest refiner in the world, after the US and China. Across the Atlantic, Brazilian throughputs remained robust in November, at near-record levels of more than 2.1 mb/d. While Petrobras has managed to lift domestic refinery runs by 140 kb/d year-on-year over the first 11 months of 2013, the increase is barely enough to cover domestic demand growth, and makes only a small dent in the country's product import bill.
While recent activity at the non-OECD Asian refiners might seem weak compared with earlier trends, for the year as a whole the region expanded its throughputs by 770 kb/d, of which 360 kb/d came from China. True, the 4Q13 annual growth rates look less impressive, with China lifting its runs by just 90 kb/d y-o-y and India on track to post its first annual contraction since 2005. End-2012 throughput rates were exceptionally strong, however, making y-o-y comparisons slightly misleading. Furthermore, long-delayed refinery projects in both countries are expected to be brought on line in 2014, with PetroChina's new 200 kb/d Pengzhou refinery first up, having started trial runs on 10 January after several delays. A week later, Sinochem's 240 kb/d Quanzhou also started test runs. India's new Paradip refinery will likely start commissioning by mid-year and reach full capacity six months later.
All told, our projection of 1Q14 non-OECD refinery runs has been lifted by 55 kb/d since last month's Report, at 40.4 mb/d, 1.2 mb/d higher than a year earlier. Growth is widespread, with significant gains expected from China, Saudi Arabia and Russia in particular as new capacity ramps up, but also from Africa as the region rebounds from a weak start to 2013.
For the second consecutive month, Indian refinery runs trended below year-earlier levels in November, averaging 4.3 mb/d. Refinery maintenance at Essar's Vadinar plant and Indian Oil Corp.s' Mathura refinery curbed runs by 160 kb/d compared with a year earlier. In December, Reliance shut a CDU at its 660 kb/d Jamnagar plant due to a power failure, and the refiner announced it would shut a 330 kb/d crude unit for maintenance in 1Q14. While no official announcement has been made regarding the timing and duration of the shutdown, it is expected take place at the end of January or early February and last for at least two weeks. December product exports from private refiners were stable from November, at 1.08 mb/d. We expect Indian refinery runs to contract year-on-year also in 1Q14, but from a very high base at the start of 2013. IOC's new 300 kb/d Paradip refinery, which is expected to start trial runs towards mid-year and be fully operational by the end of the year, will run 60% Kuwaiti crude and 40% Mexican Maya, according to company statements.
Russian crude throughputs surged by 430 kb/d in November from a month earlier, to 5.7 mb/d, as heavy maintenance turnarounds were completed. At its peak in September and October, more than 1 mb/d of capacity was taken offline for scheduled work. Preliminary data show Russian refiners kept processing rates high in December, practically unchanged from November's levels. Elsewhere in the FSU, Kazakhstan's throughputs also recovered in November, up 60 kb/d to 305 kb/d, as PetroKazakhstan Oil Product's Shymkent refinery operations rebounded. The company is a JV between state-run Kazmunigaz and CNPC. The Shymkent refinery has a capacity of 103.5 kb/d, but is undergoing modernisation expected to raise the capacity to 120 kb/d. Ukrainian refinery activity remained below 100 kb/d in November, despite the recent restart of the Odessa refinery in October after a three-year hiatus.
In Brazil, crude runs at Petrobras' 13 domestic refineries were 140 kb/d higher than expected in November, averaging a near-record 2.1 mb/d. Petrobras faces scrutiny for a series of recent accidents at its refineries in recent months, with at least four refinery fires since November. The biggest fire caused the 190 kb/d REPAR refinery in Parana state to shut for almost three weeks from late November, reducing the country's fuel output by more than 10%. Most recently, a fire at the REDUC refinery in Rio de Janeiro damaged a coking unit. Petrobras faces stricter environmental and safety rules from January, according to the country's oil regulator, ANP. In the first eleven months of 2013, Brazilian throughputs have averaged 2.034 mb/d, 137 kb/d higher than in the same period the previous year. The increase is barely keeping up with domestic demand growth, however, and has made little impact to reduce costly oil product imports. Due to regulated prices, Petrobras has to sell imports at a loss, resulting in 30 billion reals ($12.7 billion) in refining-and-supply unit losses at the company since the beginning of 2012.
In the Middle East, Oman's Sohar refinery was shut for about two weeks from end December for repairs. Saudi Aramco has reportedly booked its first cargo of diesel to ship from the Jubail refinery to the Mediterranean. An 80 kt tanker is to load on 23 January. We expect Saudi runs to inch higher in coming months as Jubail reaches capacity. According to UAE's oil minister, the 400 kb/d Ruwais refinery is on schedule to be completed by the end of the year. In Iraq, Baghdad awarded a $6.04 billion contract to a consortium of South Korean firms led by Hyundai Engineering and Construction in early January, to build a 140 kb/d refinery in Karbala.
African refinery runs were revised downwards for October, following weaker-than-expected throughputs in Algeria. These fell to only 455 kb/d, from more than 600 kb/d three months earlier. Algeria's largest refinery, the 335 kb/d Skikda plant, shut its 120 kb/d condensate splitter for maintenance for about one month from mid-September. In Libya, official data (reproduced in the Middle East Economic Survey) show that in the first 11 months of 2013, crude processed in Libya averaged 223 kb/d, up 80 kb/d from 2012. Both years' intake is slightly higher than what we had assumed based on reports of shutdowns and available crude supplies, prompting minor upwards adjustments to our assessments.