Oil Market Report: 11 December 2013

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  • Futures prices fell in early November but bounced back later and into December as refinery runs picked up. Oil markets took an interim deal on the Iran nuclear question in their stride. Rising US supplies helped the WTI-Brent spread widen to $17.55/bbl at end November. Brent last traded at $109.40/bbl, WTI at $98.30/bbl.
  • The estimate of global oil demand for 2013 has been revised up by 130 kb/d, to 91.2 mb/d, on stronger-than-expected 3Q13 OECD demand growth of 320 kb/d. Global demand is now seen advancing by 1.2 mb/d in both 2013 and 2014, to reach 92.4 mb/d in 2014.
  • Global oil supplies increased by 310 kb/d in November to 92.3 mb/d, as non-OPEC crude output topped 43 mb/d for the first time in decades. Year-on-year, November supplies rose by 810 kb/d, as a 1.9 mb/d surge in non-OPEC liquids and OPEC NGL more than offset a 1.1 mb/d drop in OPEC crude.
  • OPEC crude supply fell by 160 kb/d in November to 29.73 mb/d, its fourth consecutive monthly decline. Renewed disruptions in Libya and smaller drops in Nigeria, Kuwait, the UAE and Venezuela more than offset higher output in Iran, Iraq and Angola. OPEC ministers kept their group output target unchanged at 30 mb/d.
  • Global refinery crude runs plunged to 73.6 mb/d in October, down by 2 mb/d on September and by 1 mb/d on the year, on sweeping plant maintenance and weak margins. OECD Europe and the US led the decline. Throughputs are projected to rebound to 76.3 mb/d for 4Q13, up 180 kb/d on the year, and 76.7 mb/d in 1Q14 (+1.2 mb/d).
  • OECD industry stocks edged down by 12.1 mb to 2 684 mb in October, a smaller-than-normal draw for the season, as surging crude and feedstock inventories largely offset an unusually steep product draw. Middle distillate stocks fell by 22.8 mb and at the onset of winter stood nearly 50 mb below average.

Eyes on Iran

Time will tell whether the interim agreement signed by Iran and the P5+1 nations last month in Geneva will lead to a permanent resolution of the Iran nuclear question, and thus set the stage for a significant easing of international sanctions against Iran, particularly those impacting oil exports. One thing is sure: as far as oil is concerned, the Geneva deal, regardless of its political significance, has not been the watershed moment some had hoped for. The market reaction to the deal, announced during the weekend lull in trading, was muted: a brief intraday dip in futures prices on the following Monday. Far from easing at the prospect of rising Iranian supplies, oil prices have been firming in the last few weeks on stronger-than-expected OECD demand, resurgent refining activity and continued disruptions in Libyan exports. Even WTI prices, decoupled from the rest of the market and under pressure from relentlessly rising North American production, have recently risen.

Although Tehran has received a partial easing of some sanctions, notably on petrochemical exports and maritime insurance, existing US and EU restrictions on Iranian oil exports remain firmly in place. In exchange for this limited relief and a commitment from the P5+1 not to increase sanctions further, Iran agreed to a temporary freeze on many nuclear activities as well as increased co-operation with the International Atomic Energy Agency. All parties agreed to use the six-month period covered by this interim accord to push toward a more permanent arrangement. 

While Tehran will find it easier to ship its oil, notably to India, the lifting of insurance restrictions does not open the floodgates for Iran oil exports. Tanker tracking data show that Iran took as much as 15 mb out of floating storage last month, but such draws do not necessarily equate to incremental exports. Washington has made clear its determination to enforce oil sanctions as vigorously as ever. On 29 November, it renewed sanction waivers for Iran oil importers, a clear signal that imports of Iranian oil would remain under scrutiny. China, which had no hand in designing either the US or EU sanctions, came closer to implicitly endorsing them by becoming a full signatory of the Geneva deal.

While the end of Iran oil sanctions would open a new chapter for oil markets, much work remains to be done by Iran and the P5+1 before reaching a full accord, a prospect the odds of which President Obama has publicly placed at 50-50 or less. Making room for Iran - assuming it could quickly ramp up production after years of sanctions - could be a challenge for other producers, especially in the face of rising non-OPEC supplies. For now, though, other challenges loom larger. After eight consecutive quarters of contraction, OECD demand swung back to growth in 2Q13. Consumption growth has since been gaining momentum. In the US, preliminary weekly data show demand jumping back over 20 mb/d last month for the first time since the 2008 financial crisis. OECD product inventories have plummeted. Our estimate of the "call on OPEC plus stock changes" for 1Q14 has been adjusted upwards by 0.3 mb/d, even as Libyan production faces renewed headwinds. Oil markets participants have been bracing themselves for a soft patch in the first quarter. But upside risk to oil markets, from both the supply and the demand sides, is proving remarkably persistent.



  • The forecast of global oil demand growth for 2013 has been revised upwards by 145 kb/d to 1.2 mb/d (or 1.3%), to 91.2 mb/d, on the back of stronger-than-expected delivery data for Europe and the US in recent months. A further gain of 1.2 mb/d is forecast for 2014, to 92.4 mb/d.
  • The estimate of OECD oil demand for 2013 has been raised amid mounting evidence that OECD oil deliveries swung to growth in 2Q13, reversing three consecutive quarters of year-on-year (y-o-y) contraction. OECD oil demand flattened in 2Q13, with a net gain of 15 kb/d seen, before accelerating in 3Q13, up 320 kb/d y-o-y, having generally fallen from 2Q11 to 1Q13. Such upside is likely to be short-lived, as a post-recessionary bounce eases and the Asia Oceania region in particular returns to a trend of structurally falling consumption. Despite the stronger-than-expected OECD performance, non-OECD economies are still forecast to lead global oil demand growth in 2013 and beyond.
  • Projections of US demand have been revised steeply higher for both 2013 and 2014, reflecting recent upward adjustments to official delivery data and a revised estimate of economic growth for 3Q13. The US Department of Energy's Energy Information Administration (EIA) added roughly 0.6 mb/d to its September demand assessment, while the US Bureau of Economic Analysis raised its 3Q13 GDP growth estimate to 3.6% over 2Q13, from 2.8% earlier.

  • Upwardly revised expectations of winter heating demand, compounding the effect of large upward revisions to September and October data, have raised the forecast of global demand by about 0.3 mb/d for 4Q13-1Q14, to an average of 91.6 mb/d.

Global Overview

A protracted period of steep decline in European oil demand eased back earlier this year and in some instances even reversed as the euro zone emerged from the claws of recession. From the 12-month period of 2Q12-1Q13 to 3Q13, the most recent quarter for which complete data are available, average European demand growth jumped by about 0.7 mb/d, swinging from an average decline rate of 530 kb/d y-o-y to net growth of roughly 175 kb/d.

In addition to this uptick in European oil demand, US demand growth has also been revised upwards. Roughly 110 kb/d was added to the 2013 US demand estimate, following large-scale revisions in US EIA data for September.

Although, upward adjustments to US and European demand, mostly for 3Q13, have raised the estimate of global oil demand for 2013 by 130 kb/d from last month's Report. Global demand is now estimated to have posted a y-o-y gain of roughly 1.5 mb/d in 3Q13, 0.4 mb/d above the average growth rate of the previous 12-month period. Slowing non-OECD demand growth partly offset upward revisions for OECD economies.

Projections of global demand for 2H13 have been adjusted upwards by 215 kb/d since last month's Report, to 92.0 mb/d, based on revised data for September and October. The US accounted for the bulk of the September adjustment (+695 kb/d), followed by Canada (+50 kb/d) and Belgium (+35 kb/d). Saudi Arabia provided a partial offset with a downward demand adjustment of 105 kb/d, as did Germany (-80 kb/d), Egypt (-75 kb/d) and Italy (-50 kb/d).

Preliminary data for October also lead to a net upward adjustment. Notable additions include the US (+130 kb/d), Russia (+120 kb/d), France (+90 kb/d), China (+85 kb/d), Brazil (+80 kb/d) and Germany (+80 kb/d), partly offset by declines in India (-55 kb/d) and the Philippines (-25 kb/d).

This month's Report also revisits the forecast of peak winter heating demand, which despite increasing inter-fuel competition for space heating continues to cause substantial seasonal variations in global oil consumption (see The Changing Seasonality of Oil Demand). Upwardly revised expectations of heating requirements, in conjunction with the adjustments to the estimates of September and October demand, added roughly 0.3 mb/d to the forecast for this winter, with global demand now seen likely to average 91.6 mb/d in 4Q13-1Q14.

Taking these changes into account, the demand growth forecast has been raised to 1.2 mb/d (or 1.3%) for 2013, with a similar gain projected for 2014, bringing demand to an estimated 91.2 mb/d this year and 92.4 mb/d in 2014. Industrial fuels, such as gasoil, LPG and naphtha, account for the bulk of this upward revision, reflecting the impact of economic recovery in the US and Europe. The petrochemical industry has seen something of a renaissance recently, lifting demand for petrochemical feedstock, while the shale gas and light tight oil (LTO) revolution in the US has cut LPG prices and incentivised higher use. Robust gasoline demand in China and the US also played a key role in the strong gains in oil demand seen in those countries. 

The Changing Seasonality of Oil Demand

The onset of winter in the northern hemisphere brings a renewed focus on the seasonal patterns underpinning global oil demand. In the summer months, the US driving season, running from end-May to early-September, typically boosts US gasoline demand (see the Report dated 12 June 2013). Similarly, colder weather in the heavily populated temperate zones of the northern hemisphere increases heating requirements in the winter months, lifting demand for heating fuels in 4Q and 1Q of each year. In North America and Europe, gasoil is the main liquid fuel used for space heating, while in Asia kerosene is also commonly used. Recent years have, however, seen a change in the role of oil as heating fuel, as natural gas has increasingly claimed market share away from it. Natural gas is, either piped directly into homes and commercial buildings or used indirectly as boiler fuel for thermal power stations.

Looking at data for the last 13 years, it is apparent that the traditional northern hemisphere winter spike in demand has become increasingly less pronounced. In OECD Europe, for example, average oil demand rises by 1.0% in the winter months compared to the annual average, 2000-08 (i.e. the eight winters, 4Q00-1Q01 through 4Q07-1Q08, versus the corresponding years as a whole, 2000-08). For the 2008-12 period (i.e. the four winters, 4Q08-1Q09 through 4Q11-1Q12, versus their corresponding yearly averages), however, this winter "premium" in oil demand has fallen to virtually zero. In the US, the difference between winter and annual demand swung from a 0.3% premium in 2000-08 to a 0.2% "discount" in 2008-12. The trend has been even more pronounced in Canada, where winter demand swung from a "premium" of around 1.3% in 2000-08 to a contraction of 0.4% in 2008-12. Much larger winter premiums exist in OECD Asia, and continue to exist in 2008-12, although the scales of their winter-spikes have also fallen. The Japanese "premium" falling to 6.2% in 2008-12, from 7.6% in 2000-08, whereas the Korean "premium" eased to 3.2% in 2008-12 versus 6.7% in 2000-08. Caution is advised when extrapolating from such trends, however, as data for the 2008-12 period were affected by a sharp slowdown in economic activity following the 2008-09 financial crisis. Conversely, estimates for 2013 are likely to be lifted by Europe coming out of recession.

Overall, we project that the average of OECD oil demand for 4Q13 and 1Q14 is likely to exceed the average of 2013 and 2014, by around 0.4%. This relatively weak "premium", versus a 1.6% pre-recessionary level or 0.7% in 2008-12, reflects a combination of three factors. Firstly, the North American heating market is switching out of oil products and into more competitively-priced alternatives such as electricity. Secondly, years of high oil prices, compounding the effect of the economic slowdown, have encouraged more efficient space heating, including tighter insulation and other measures. Estimates, from the EIA's most recent Residential Energy Consumption Survey, show that 48% of energy consumption in US homes in 2009 was for heating and cooling, down from 58% in 1993. Despite expectations of continued economic recovery in 2014 (the International Monetary Fund (IMF) sees OECD economic growth accelerating to 2.0% in 2014 from 1.2% in 2013), heating-oil consumers are likely to remain relatively cash-strapped this winter, so that incentives to use heating fuels efficiently will stay. Thirdly, given the unusually cold winter weather last year, a return to normal seasonal temperatures would translate into a lower number of heating degree days this winter. The US National Oceanic and Atmospheric Administration, for example, depicted OECD Europe experiencing around 130 more heating degree days last winter than the ten-year average, providing plenty of potential for reduced demand if "normality" returns.

Top 10 Consumers


US demand estimates for September have been revised steeply upwards. Between the release of its latest Short Term Energy Outlook on 13 November and that of its Petroleum Supply Monthly two weeks after, the US EIA adjusted its assessment of September demand upwards by 625 kb/d. Meanwhile, the Bureau of Economic Analysis (BEA) revised its quarterly GDP growth estimate for 3Q13 to 3.6%, up from a preliminary 2.8% assessment (versus 2Q13). It is now thought that US oil demand averaged nearly 19.1 mb/d in September, up 0.9 mb/d y-o-y. This would be the fastest pace of growth experienced in nearly 10 years, and even longer if growth is measured in percentage terms (as US oil demand has been on a contracting trend in recent years).

A key contributor to the higher September demand number has been the raised gasoline estimate, itself a beneficiary of the steep drops seen in US gasoline prices, which when coupled with the reasonably robust economic recovery combined to send the vehicle miles travelled statistics up by around 1.5% on the year earlier. Average retail prices of regular gasoline in the US, at around $3.6 per gallon, were nearly 25 cents down on the year earlier, a margin that widened to approximately 50 cents in October before narrowing once again to around 25 cents in November. Vigorous growth in the US petrochemical and transport sectors supported gains in demand for naphtha/LPG and gasoline, respectively.

Preliminary weekly data for October from the EIA suggest slower y-o-y growth for that month, even when adjusted upwards ahead of likely revisions in monthly data. Nevertheless, at a projected 18.7 mb/d, US demand for October is nearly 130 kb/d above the estimate carried in last month's Report, as the demand impact of a partial government shutdown that month seems to have been milder than expected. The forecast for 2013 as a whole has been ratcheted up by around 110 kb/d, to around 18.8 mb/d. We are discounting media claims of 20 mb/d US demand in November, as the growth rates suggested by the EIA weekly numbers are likely to be missing the true level of product exports.


Chinese apparent demand averaged roughly 10 mb/d in October, based on refinery output, net product imports and reported inventory changes. This equates to a gain of roughly 2.4% on the year, with relatively strong petrochemical activity supporting naphtha sales and high vehicle sales underpinning strong gains in gasoline demand. Passenger car sales were up by around 15% in the first 10 months of the year from the same period in 2012, supporting gasoline demand growth projected at 7.3% for 2013 and 5.7% for 2014.

Despite higher-than-expected October demand, the growth forecast for the year as a whole remains roughly unchanged on last month's Report at roughly 3.8%. Regardless of the domestic economy's recent industrial strength, some signs of slower activity have since been seen in November, such as a flattening in business sentiment and a deceleration in the total level of imports into the country, thus keeping the growth forecast unchanged on last month.


Japanese demand edged lower in October, extending earlier trends. Preliminary data indicate a contraction of 4.2% y-o-y, to around 4.2 mb/d, in line with expectations. Continued drops in oil demand from the power sector lead the decline, as electric utilities turn to coal instead of oil for power generation. Naphtha demand, however, held up reasonably well in October, up 8.6% y-o-y to 750 kb/d, as the economic recovery gains momentum and helps support the petrochemical industry. A decline rate of around 3.8% is forecast for the year as a whole, to 4.5 mb/d, with a similarly sized drop forecast for 2014, to 4.4 mb/d, as power sector oil demand likely continues to fall.


Recent weakness in Indian demand continued into October, according to the preliminary data. Domestic sales rose by 1% on the year earlier to 3.3 mb/d, 55 kb/d below the forecast carried in last month's Report. Weak diesel demand remains the main factor behind the low overall growth figure, with Indian gasoil deliveries falling by around 20 kb/d y-o-y in October. Good rains have cut irrigation needs, even as subsidy reductions and general economic weakness have combined to suppress gasoil/diesel demand. The forecast for the year as a whole has been trimmed by around 10 kb/d since last month's Report, to 3.4 mb/d, equivalent to a modest growth rate of roughly 1.0% in 2013 y-o-y. Momentum is then forecast to accelerate in 2014, to 2.7% growth, as after a tricky couple of years for the Indian economy the underlying macroeconomic picture likely improves. The IMF forecasting, in its October World Economic Outlook, GDP growth of 5.1% in 2014, after gains of 3.2% in 2012 and 3.8% in 2013.


Rapid gains in industrial oil use since April have raised the estimate of Russian demand for 2013 to around 3.4 mb/d, up 120 kb/d (or 3.7%) y-o-y and 15 kb/d above last month's projection. October's 7.8% y-o-y gain is thought likely to have been led up by sharply higher demand for 'other products', fuel oil, jet/kerosene and gasoil/diesel.


Recent strength in Brazilian demand continued in October, with average deliveries of about 3.3 mb/d, up 95 kb/d (or 3.0%) y-o-y and 80 kb/d above the forecast carried in last month's Report. Gasoline demand in particular exceeded expectations. Stronger-than-expected data for recent months have raised the growth forecast for the year, although recently announced increases in product prices may limit the upside, at least for now. Infrastructure building ahead of the 2014 World Cup is also supporting demand, with growth now forecast at 4.0% for 2013, to 3.1 mb/d.

Saudi Arabia

Saudi Arabian demand extended the decline highlighted in last month's Report. September demand was estimated at 3.2 mb/d, down for the second consecutive month by 60 kb/d (or 1.8%) y-o-y. Demand for 'other products' led the decline, apparently reflecting fuel switching from crude oil to natural gas for power generation. The projection for 2013 as a whole has been trimmed by 35 kb/d since last month's Report, to 3.0 mb/d, equivalent to a gain of 2.1% on the year. Growth is still forecast to reach 3.3% in 2014, to 3.1 mb/d, in line with the International Monetary Fund's October World Economic Outlook, which projects an increase in the pace of GDP growth to 4.4% in 2014 from 3.6% in 2013. This increase in the pace of oil demand growth is slightly less than previously assumed, however (3.6% in last month's Report).


The forecast of German oil demand growth for both 2013 and 2014 is roughly unchanged from last month's Report following mutually offsetting revisions to the estimates for September (down by 80 kb/d from last month's Report) and October (up by 80 kb/d). As alluded to in recent months, the German demand trend is showing tentative signs of edging higher in 2013, supported by a rebound in industrial activity, especially in the petrochemical sector.


Strong gains in LPG, motor gasoline and jet/kerosene contributed to the higher Canadian demand estimate for September, reversing two consecutive months of y-o-y declines. September demand is estimated roughly 1.3% above year-earlier levels. Modest growth is forecast for both 2013 as a whole and 2014, as the industrial sector of the economy in particular benefits from relatively low energy costs, compared to prices outside of North America.


South Korean demand remained relatively weak in October at an estimated 2.2 mb/d, roughly unchanged on the year. All the main product categories bar LPG and 'other products' showed y-o-y declines. For the year as a whole, demand is projected at roughly 2.3 mb/d, about flat on 2012. A modest uptick is forecast for 2014, led by increased petrochemical oil use.


OECD demand edged down by roughly 1.0% in October, according to preliminary estimates, led by steep drops in OECD Asia Oceania. Declines in the OECD Americas and Europe were more subdued. Demand for the light end of the barrel outperformed that for heavier products, with gains in gasoline, jet/kerosene, petrochemical feedstock and diesel. Reduced power-sector requirements from Mexico and Japan played the opposite role for heavier products.


Following y-o-y gains in September, preliminary data imply a return to modestly falling demand in October. The decline spanned the entire region, but was especially pronounced in Mexico, where demand was estimated at 2.1 mb/d in October, down 6.5% y-o-y, but up seasonally by 180 kb/d (or 9.1%) on the month. As is usually the case in October, transportation fuels led the monthly gains in Mexican demand, with gasoil/diesel deliveries up by 55 kb/d and gasoline by 50 kb/d.


The euro zone economy officially came out of recession in 2Q13. As economic conditions improved, the previous trend of steep contraction in European oil demand eased markedly, and for several countries demand swung back into growth. Demand for industrial fuels (most notably gasoil/diesel and LPG) has proved particularly robust recently. Large North European economies such as Germany, France, Belgium, the UK and much of Scandinavia have led the upside, but even the Mediterranean region, where demand had nosedived, has enjoyed a significantly slower pace of decline. A modest decline of around 65 kb/d (or 0.5%) is foreseen for the year as a whole, to 13.7 mb/d. The forecast decline rate is then expected to ease in 2014, to 60 kb/d (or -0.4%) to 13.6 mb/d, as economic momentum likely gathers pace.

The Irish demand series for 2013 has been adjusted upwards following revisions to official statistics. For 2Q13, Irish demand estimates have been hiked by roughly 15 kb/d, or more than 13%. These figures, coupled with stronger demand readings for recent months, lift the Irish demand estimate for 2013 as a whole to around 140 kb/d, 10 kb/d more than estimated in last month's Report and 5 kb/d (or 4.6%) above the year earlier.

Turkish oil demand rose at its fastest pace in eight months, up by 55 kb/d (or 8.2%) y-o-y in September, to 740 kb/d, supported by particularly strong gains in industrial fuels, notably gasoil and LPG. News of a deal with Japan to build nuclear power plants in Turkey will likely limit longer-term demand from the power sector, especially for fuel oil. Relatively robust economic growth numbers, at least from a European perspective, are forecast to support oil demand growth of around 4.9% for the year as a whole, to 705 kb/d. A further gain of around 2.8% is then forecast for 2014, to 725 kb/d, as the economy continues to grow, albeit not, according to the IMF, at the heady pace seen in 2013.

Recent growth in UK demand continued in September, when demand rose by 2.8% y-o-y, its fourth consecutive monthly gain. Transportation fuels led the growth, with demand for jet/kerosene up 5.3% and 1.3 % for gasoil. Continued UK demand growth is foreseen over the next couple of years, supported by the economic recovery, albeit not at the heady pace experienced in recent months, when growth was inflated by the post-economic-slowdown bounce.

Asia Oceania

The OECD Asia Oceania region lagged the overall OECD in October, according to preliminary demand estimates, led as expected by steeply falling Japanese demand. Looking forward, regional demand is projected to contract by roughly 1.8% to 8.2 mb/d in 2014, from 8.4 mb/d in 2013, as sharply declining Japanese demand undermines the regional total.


Emerging and newly industrialising economies will continue to provide the majority of the world's upside demand momentum through the forecast period, although the divergence between OECD and non-OECD demand trends will likely become less pronounced over time. Having averaged roughly 45.3 mb/d in 2013, a gain of 1.2 mb/d (or 2.8%) y-o-y, non-OECD demand is forecast to expand by a further 1.4 mb/d (or 3.1%) in 2014, to 46.7 mb/d.

While still the main engine of global growth, non-OECD demand is projected to show a slower increase for 2013 that in the last five years, when annual non-OECD growth averaged 1.4 mb/d. That gain occurred amid the sharpest global economic slowdown since the Second World War. Weakening demand growth for gasoil and gasoline were the main factors behind the recent oil demand slowdown, although LPG and jet/kerosene also saw notably slower gains. There is perhaps no better symbol of the changing dynamics in non-OECD Asian jet/kerosene demand than the recent grounding of Singapore Airline's Singapore-New York flight. The closure of that flight, after nine years, can be attributed to a combination of relatively high prices, increased competition and a still relatively fragile economic recovery.

Reports that a Russian-led consortium has been selected to build Jordan's first nuclear reactor bolster our expectations of a fallback in Middle Eastern power-sector oil demand over the long term. The region, one of the last remaining bastions of power-sector oil demand, is slowly preparing to wean itself of its dependence on oil for electricity generation. Natural gas has already made inroads into regional power generation at the expense of oil, and there has been a lot of talk in recent years of long-term investment in nuclear and solar power generation capacity. Reports that Russia's Atomstroyexport has been selected as the preferred bidder for the 1 000 megawatt Amra plant, which may provide as much as 12% of Jordan's power sector needs by 2020, provide further evidence of the gradual movement away from oil in the region's power sector.

In contrast, there have been further reports of a strong uptick in Iraqi power-sector oil use, from mid-2013, which has raised the Iraqi oil demand forecast for the year as a whole. Total Iraqi oil demand is now projected to rise by 45 kb/d or 6.0% y-o-y, to 790 kb/d on average in 2013. Growth is forecast to slow to 40 kb/d (or 5.1%) in 2014. The general theme of our Middle Eastern power sector view is, however, likely to hold for Iraq over the medium-to-long-term, as cost-competitive alternatives, such as natural gas, are forecast there too to gain market share.

Egyptian demand estimates remain volatile amid the country's continued economic difficulties and social unrest. September demand was estimated at 695 kb/d, down 3.5% on the year, driven down by transportation fuels, demand for which has been hard-hit by the recent political turmoil. Despite the country's persistent financial troubles, overall demand momentum is forecast to recover marginally, 4Q13-2014, mostly due to the weak readings in the reference period.

Revisions to historical data for Romania stripped roughly 20 kb/d from the 2012 demand estimate, to 185 kb/d, with 'other product' accounting for most of the decline. Although the revision pushes the annual change into negative territory, a modest rebound is projected for 2013, gathering momentum in 2014, as the macroeconomic situation improves.



  • Global supplies posted a monthly gain of 310 kb/d in November to 92.3 mb/d, driven by an increase in non-OPEC production that was partly offset by lower OPEC output. Year-on-year (y-o-y) November supplies stood 810 kb/d higher, with a 1.8 mb/d rise in non-OPEC liquids, 65 kb/d increase in OPEC NGLs, mitigated by a 1.1 mb/d decline in OPEC crude oil output.
  • Non-OPEC supplies increased by 470 kb/d in November month-on-month (m-o-m), to 56.16 mb/d, led by growth in North America and the North Sea. Total non-OPEC production growth is forecast at 1.4 mb/d for 2013 and 1.7 mb/d for 2014.
  • OPEC crude oil supply fell in November, down for the fourth consecutive month. November crude supply declined by 160 kb/d on the month, to 29.73 mb/d, on a drop in Libya and smaller declines in Nigeria, Kuwait, the UAE and Venezuela. All of these decreases more than offset higher output in Iran, Iraq and Angola.
  • OPEC oil ministers gathered in Vienna on 4 December and kept their output target unchanged at 30 mb/d for 1H14, although Iran and Iraq have both signalled their intention to increase crude production in due course regardless of the collective target.
  • The 'call on OPEC crude and stock change' was raised by 0.1 mb/d for 4Q13, to 29.7 mb/d, and kept roughly unchanged at 30.0 mb/d for full-year 2013. The 'call' for 1Q14 has been raised by 0.3 mb/d, to 28.9 mb/d. OPEC 'effective' spare capacity was estimated at 3.37 mb/d in November versus 3.32 mb/d in October.

All world oil supply data for November discussed in this report are IEA estimates. Estimates for OPEC countries, Alaska, Mexico and Russia are supported by preliminary November 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 to -400 kb/d for non-OPEC as a whole.

OPEC Crude Oil Supply

OPEC crude oil supply decreased in November, down for the fourth consecutive month. Total crude oil output declined to 29.73 mb/d, down by 160 kb/d from October. The decrease in November crude oil output was mainly the result of a drop in Libya's production, although smaller declines occurred in Nigeria, Kuwait, UAE and Venezuela. All of these decreases more than offset higher output in Iran, Iraq, and Angola.

OPEC ministers gathered on 4 December in Vienna to discuss the market outlook for 2014 and agreed to keep the collective output level at 30 mb/d for the first six months of 2014. Iran and Iraq have, however, signalled their intention to increase crude oil production in due course regardless of the collective target. The cartel in a press release said it sees continued global economic uncertainty as the biggest challenge to the oil markets, but acknowledged that forecast non-OPEC supply was set to "more than offset" projected increases in demand and reserved the right to "swiftly respond to developments which could have an adverse impact on the maintenance of an orderly and balanced oil market."  The next ordinary meeting is scheduled for 11 June 2014. Many market commentators have speculated that fast-rising production from US light, tight oil formations and other sources could put pressure on OPEC's crude oil output in 2014.

The 'call on OPEC crude and stock change' was raised by 0.1 mb/d to 29.7 mb/d for 4Q13 and kept approximately unchanged at 30.0 mb/d for full-year 2013. The 'call' for 1Q14 has been raised by 0.3 mb/d, to 28.9 mb/d, on the back of upward revisions to the global demand forecast. OPEC's 'effective' spare capacity was estimated at 3.37 mb/d in November compared with 3.32 mb/d in October. The 2014 'call' stood at 29.3 mb/d in November.

Saudi Arabia's crude oil production averaged 9.75 mb/d in November, remaining unchanged from October. Crude oil production in Saudi Arabia may be temporarily levelling off as domestic demand for crude burn at power plants declines seasonally. Crude oil burn for power generation typically peaks in the third quarter at approximately 700 kb/d to750 kb/d, but declines in the fourth quarter to about 350 kb/d to 400 kb/d.

Iraqi crude oil production rose in November to 3.15 mb/d, from 3.03 mb/d in October, due to a recovery in northern exports and the resumption of some exports out of the southern ports following the restart of field operations that had been suspended due to poor security conditions. The BP-operated 1.4 mb/d Rumaila field operated at reduced levels for much of November due both to a lack of export capacity and to protests around the oilfield. Although protests at a nearby drilling site in Northern Rumaila that disrupted Schlumberger and Baker Hughes operations did not directly affect BP's operation at the Rumaila field, BP evacuated its personnel fearing a spill-over of unrest. BP resumed operations at the field on 26 November following the abatement in hostilities and the field likely will become operational in the coming weeks.

Total November crude exports from Iraq increased by 130 kb/d to 2.38 mb/d for the month. The higher November exports reflect a rebound in shipments from the north, which accounted for nearly the entire increase for the month. Exports from Basrah rose just 12 kb/d to 2.07 mb/d while exports of Kirkuk crude were up by around 115 kb/d to 300 kb/d. Crude oil production from the KRG region in November was estimated at 180 kb/d.

Although Turkey and the KRG appeared to have been on the verge of signing an oil and gas trade agreement in late November, Turkey's government did not approve yet the construction of a new export pipeline that is central to the proposal. The pipeline would increase KRG's exports to 1.0 mb/d by 2015. The agreement also would have included crude oil trade terms, Turkish Energy Company's (TEC) involvement in KRG's upstream, and construction of oil and gas pipelines. The decision on the approval of the new pipeline was postponed until December, when Iraq's Prime Minister Al Maliki is scheduled to visit Turkey. A new 300 kb/d KRG pipeline linking to the Kirkuk-Ceyhan line was reportedly completed, although some reports indicate that a number of connections to the mainline have not been finished yet.

Iran's crude oil production increased to an estimated 2.71 mb/d in November from 2.68 mb/d in October. Preliminary estimates indicate that receipts of Iran's crude oil and condensate exports rose by 89 kb/d on the month, to 850 kb/d. Declining exports to Japan, Korea and Turkey were more than offset by rising exports to China and Taiwan.  The latter received its first cargo from Iran since April 2013 last month. Import estimates are based on data submitted by OECD countries, non-OECD statistics from customs agencies, tanker movements and news reports.

Iran reached a preliminary agreement with the P5+1 (the US, UK, Russia, China, France and Germany) nations in Geneva on 24 November, which eased some of the US and EU trade sanctions against Tehran. Iran agreed to a temporary freeze on many nuclear activities as well as increased cooperation with the IAEA in exchange for a commitment from the P5+1 not to increase sanctions further. The six-month agreement allows Iran to repatriate approximately $4.2 billion in assets and offers at least a temporary reprieve to the automotive, petrochemical, civilian aircraft, and gold trade industries. During this six-month period, a more comprehensive agreement is to be concluded. However, even during these six months, Iran cannot trade crude oil for gold. While a permanent resolution of the Iran nuclear question could eventually lead to a significant relaxation in sanctions against Iran, in recent days President Obama has publicly stated that he places the odds of successfully reaching such an agreement at 50-50 or less.

As far as oil exports are concerned, the easing of the sanctions mainly affects the insurance and reinsurance market for tankers and crude oil cargoes, but the oil export sanctions, which prevent countries from importing Iranian oil, are set to remain fully in place until a comprehensive agreement on Iran's nuclear program is reached. The relaxed shipping insurance provisions could theoretically make it easier for Iran to ship its crude oil and draw down its volumes of oil held in floating storage, potentially resulting in a short-term increase in Iranian crude exports at the margin. The fact that the oil sanctions remain fully in place leaves on the face of it no room for any sustained increase in exports. Even if sanctions on Iranian oil were eventually relaxed, meaningful increases in production would require a longer period and additional investment in Iran's upstream, and thus would take time to materialise. Meanwhile, the volume of crude oil held in floating storage decreased from 37 million barrels at the end of October to approximately 22 million barrels at the end of November.

Kuwaiti output declined by around 20 kb/d in November, to 2.72 mb/d, due to scheduled field maintenance, which was concluded by mid-month. The UAE's output also fell by 30 kb/d in November, to 2.73 mb/d. UAE volumes declined despite the start-up of new production from the onshore Qusawirah field. According to Abu Dhabi National Oil Company (ADNOC), based in the emirate that produces over 90% of the UAE's crude oil, production at the field officially began on 6 November at the initial production rate of 30 kb/d, which will increase to 60 kb/d by 2017.

In late November, ADNOC announced that firms, which are prequalified to bid on the country's largest onshore concessions for shared operating licenses, would receive $3 per barrel of produced oil, a significant increase from the $1 per barrel that companies currently receive. Increased compensations target six deposits that together produce more than half of the emirates' output. Although the current onshore concessions expire on 10 January 2014, UAE Energy Minister Suhail al-Mazru'i acknowledged that there will be a delay in awarding the new concessions following the January expiration of the current ones.  The prequalified companies include BP, ExxonMobil, Royal Dutch Shell and Total, all of which are current participants. ADNOC has also pre-approved Occidental Petroleum Corp., China National Petroleum Corp., Inpex, Korea National Oil Corp., Statoil and Rosneft to take part in the bids.

ADNOC has reached an agreement with ExxonMobil on the commercial terms for the Upper Zakum concession, following a contractual dispute between the two parties. The new agreement outlines increased compensation for ExxonMobil and ensures the company's continued involvement in the development. Under the new contract, Upper Zakum's output is forecast to increase to 750 kb/d by 2017 from the current 585 kb/d. Upper Zakum is the country's largest oil field and is jointly operated by a consortium of ExxonMobil, Japan Oil Development Co. and ADNOC.

Libyan oil production fell to an average 220 kb/d in November from 450 kb/d in October, as strikes at oil fields and ports intensified and violence escalated during the month, resulting in dozens of deaths and casualties. The escalation of violence and the death of nearly 50 civilians since mid-November have caused a public backlash against the militias, though whether this will cause the government to gain in popular support is unclear.

Following the OPEC meeting in Vienna on 4 December, Libyan Oil Minister Abdelbari al-Arusi announced that all oil export terminals in Libya could reopen on 10 December, and that oil output would be fully restored within two weeks after that. However, as of the end of the day on 10 December, Libyan ports remain shuttered. Even if the ports had reopened on 10 December, the timeline to restore production is overly ambitious, given the militias' unwillingness to withdraw from major oil installations. In the meantime, the situation in Libya remains precarious and oil production and exports were at their lowest levels since 2011, when the civil unrest resulted in a complete shut-in of oil production. The sharp decline in export revenues may have a devastating impact on Libya's budget. There is a significant risk of the country facing serious currency and payments problems due to the lack of revenues and drawdown of cash reserves.

Nigerian output was 35 kb/d lower in November on the month, at 1.89 mb/d, as maintenance at the offshore Bonga field reduced production and exports. Angolan output rose by 60 kb/d to 1.76 mb/d in November. BP announced that its Saturno field, started in 2012, will reach plateau production of 150 kb/d by the end of this year. Meanwhile, Angola's oil ministry announced that bidding for new exploration licenses will be delayed until the 1Q 2014, from an earlier target date of 4Q2013. A total of 15 blocks will be offered in 2014 as the country plans to raise output to 2.0 mb/d by 2015. Venezuela's production decreased slightly in November to 2.46 mb/d. During the month, Venezuela's crude oil exports averaged 1.70 mb/d, falling by about 200 kb/d compared with October.

Non-OPEC Overview

Total non-OPEC production, including biofuels and refinery processing gains, increased by 470 kb/d in November to 56.16 mb/d, led by North America (up 430 kb/d) and the North Sea (up 125 kb/d). With final data now available for the first three quarters of the year for most places, and partial 4Q13 data for many, non-OPEC production now looks on track to achieve annual growth of 1.4 mb/d for 2013, an increase of 2.6%. If confirmed, this would be the highest annual production gain in percentage terms since 2002. The overall production outlook for 2014 is unchanged since last month's Report. However, given that 2013 now has a higher yearly average, y-o-y growth for next year is lowered slightly, to 1.7 mb/d.

The figures look somewhat different if non-OPEC crude oil production is disaggregated from estimates that include NGLs, biofuels, processing gain, etc. After reaching 41.91 mb/d in 4Q12, total non-OPEC crude oil production fell back for the next two quarters, averaging 41.81 mb/d and 41.88 mb/d in 1Q13 and 2Q13, respectively. Production rebounded in 3Q13, to 42.12 mb/d, but only for 4Q13, when production is projected at 43.03 mb/d, is its increase expected to be truly substantial. Total y-o-y crude oil output growth for 2013 is forecast at 950 kb/d. For 1Q14, non-OPEC crude oil production is predicted to increase further to 43.22 mb/d, in sharp contrast with the decline of the previous year.

Whether in crude oil or other hydrocarbon liquids, production gains reflect investments made years earlier. Figures from Barclays Bank and IFP Energies nouvelles (IFPEN) suggest that E&P expenditures in the oil and gas sector, after contracting in 2009, surged in 2010 by about 11% and showed even stronger growth in 2011 (21% to 23%). Even with industry costs rising, the output growth achieved in 2013 builds upon those increases. Growth in upstream expenditure then slowed in 2012 (9% to 11%) and kept about steady in 2013 (10% to 11%). Hence the question: how sustainable are 10% to 20% annual expenditure increases if production is only rising by 3% and prices stay flat or even drop? Of course, there is great variability amongst producers in terms of baseline costs per barrel and production growth rates, and one would have to disaggregate oil from natural gas as well, so the question is not so simple. Nevertheless, given that crude oil in particular has experienced slower growth than other liquids, let alone natural gas, and that the low interest rates of recent years that have facilitated capex may rise in the future, some players in the industry may face difficult decisions.


North America

US - October preliminary; Alaska actual, others estimated:  As expected, final September data indicated that US crude oil production exceeded 7.7 mb/d for the first time since May 1989, at 7.79 mb/d for the month. Alaskan production was up about 85 kb/d m-o-m and the US Gulf of Mexico (GOM) up about 120 kb/d m-o-m as summer maintenance ended. Production of light tight oil (LTO) in Texas and North Dakota extended its gains, up by 60 kb/d combined in those two states. Enhanced oil recovery (EOR) on mature conventional fields that were formerly uneconomic is also playing a role, with about 350 kb/d of output from such fields in the Lower 48.

Based in part on weekly data, US crude oil production is estimated to have fallen slightly in October, to about 7.76 mb/d, reflecting weather-related outages in the US GOM, North Dakota and Colorado. For November, Alaska data show production up about 10 kb/d on the month, and given the lack of weather-related outages in the US GOM in November, as well as preliminary weekly figures, we estimate November crude oil production to have reached 7.97 mb/d. That was likely the highest monthly output of the year, as unusually severe winter storms seem to have curtailed production in the Permian Basin in early December.

Final data show that the US increased its crude oil production by a remarkable 1.2 mb/d y-o-y in 3Q13, an amount greater than the total crude oil production in Colombia that same quarter (which was about 1 mb/d). It is estimated that y-o-y gains will not be as strong in the remaining five quarters through the end of 2014, as growth rates, while still robust, are forecast to slow a bit in the Bakken, Eagle Ford, and Permian basins (from about 50% overall to 33%, y-o-y), and Alaska will continue declining. In one of the biggest deals ever on the Eagle Ford play, Devon Energy announced in November that it will purchase $6 billion of upstream assets from GeoSouthern. Bakken output is increasingly heading to refineries on the East and West coasts of the US, as it is competitive with imported light crudes, and the falling price of Light Louisiana Sweet (LLS) on the US Gulf Coast makes it more profitable to rail the crude long distance. Nevertheless, given that over 85% of Bakken production has a breakeven price of $45/barrel according to North Dakota authorities, it would seem that it would take a steep and sustained price drop from current levels to greatly affect the production outlook. Well costs and drilling rates, however, can vary significantly on the same reservoir, so if the breakeven price were to be approached, it could be difficult to model its effects.

TransCanada's 700 kb/d-capacity Keystone South Pipeline from the Cushing, Oklahoma delivery hub to the Texas Gulf Coast is expected to begin deliveries in early January 2014. Given that the Seaway Pipeline is already taking 400 kb/d to the Gulf Coast from Cushing, and will be expanded to 850 kb/d by the middle of 2014, there is likely to be excess capacity to take crude out of Cushing, thereby making WTI-Cushing relatively more valuable as limits to its movement to the Gulf Coast will have been eliminated. However, this is likely to depress some Gulf Coast grades further, as Gulf Coast refiners will have increased access to Mid-Continent oil. In Texas, the second phase of Nustar Energy's South Texas Crude Oil Pipeline System will now move forward, allowing an additional 65 kb/d of Eagle Ford crude to be piped to a coastal terminal by 1Q15. Concerns about the great amount of water used for hydraulic fracturing in the drought-prone state have arisen, with the state environmental agency raising serious concerns in a November report, though new techniques to use recycled water or to frack without water are being developed and deployed in some parts of the US that could potentially be implemented in Texas.

Total liquids production excluding refinery processing gain and biofuels reached 10.8 mb/d in September, as NGL output increased at a somewhat higher rate than expected (to about 2.7 mb/d). Based on preliminary numbers and seasonal changes, NGL production is estimated to have declined to 2.6 mb/d in October, and likely remained below September levels in November. Strong growth of about 200 kb/d in NGL production is expected for 2014, as liquids-rich shale formations continue to attract investments. In addition, new processing infrastructure continues to come online, such as the eighth fractionator at Enterprise Products Partners' Mont Belvieu, Texas facility, which adds 85 kb/d of capacity, for a total of 655 kb/d. Oneok partners will construct a new gas processing plant (2.06 million m3/year capacity) on the Bakken by the end of 2015 that will bring on additional NGL supply. Biofuels, and in particular, ethanol, output is increasing in the US, thanks to a bumper corn harvest. Ethanol output is estimated at about 885 kb/d in October and 915 kb/d for November. However, in 2014 US biofuels may be subject to new regulation (please see Biofuels Outlook Reviewed in Light of New US Ethanol Target).

Biofuels Outlook Reviewed in Light of the New US Ethanol Target

On 15 November, the US Environmental Protection Agency (EPA) released its proposed rulemaking for the 2014 Renewable Fuels Standard 2 (RFS2), a piece of legislation that sets the minimum annual volume of renewable fuel (including ethanol and biodiesel) to be contained in transportation fuel sold in the US. The RFS was first created under the Energy Policy Act of 2005 with a target for 7.5 billion gallons of renewable fuel in 2010, and has been expanded to 2022 under the 2007 Energy Independence and Security Act. For the first time since its introduction, the new renewable fuel target is set below that of the previous year: 15.21 billion gallons (992 kb/d) for 2014, a decrease of 1.3 billion gallons (85 kb/d) from the 2013 standard. Consequently, we have cut our forecast of 2014 US ethanol supply by 25 kb/d, to 895 kb/d.

The 2014 volumes proposed by EPA are well below the so-called "RFS2" rulemaking set in March 2010, which had mandated a total volume of 18.15 billion gallons (1.18 mb/d) for 2014. While the new 2014 standard may be further revised after a two-month public comment period, the final target looks likely to be significantly less than that of 2013.

The US biofuels mandate became a matter of controversy over the last couple of years as the level of ethanol blended in the US reached roughly 10% of US gasoline consumption, a level referred to as the "blend wall". After a summer 2012 drought damaged the corn crop and caused corn markets to rally, livestock farmers called on the EPA to ease upward pressures on corn prices by waiving the RFS's corn-ethanol mandate. A coalition of gasoline retailers, auto manufacturers and others have also urged the EPA to cut the RFS's ethanol mandate, pointing out liability issues for vehicles with regards to  using gasoline blends of more than 10% ethanol. Due to lower-than-forecast US gasoline consumption, the original RFS target for 2014 would have lifted total US ethanol consumption to more than 10% of finished gasoline demand (for more detail see Medium-Term Oil Market Report 2013). In addition, critics charged that the EPA was setting targets for cellulosic fuels that exceeded production capacity and market availability.

Also, as discussed in the August 2013 Report, the limited capacity of the market to absorb biofuels despite the government requirements has meant that refiners and other obligated parties have had to purchase ever-more expensive Renewable Identification Numbers (RINs) to prove compliance when the company could not do the blending itself. In theory, reducing the required amount of ethanol to be blended to below the 10% blend-wall threshold should reduce the value of RINs going forward.

In addition to cutting the overall 2014 ethanol mandate, the EPA has significantly reduced its target for cellulosic fuel, as the advanced biofuel industry has been developing slower than was forecast some years back. Lower-than-expected US gasoline demand and lack of cellulosic ethanol production capacity have both been taken into account in the proposed 2014 standard, which targets renewable fuel volume roughly equivalent to 10% of the gasoline pool, and requires only a minor contribution of cellulosic fuels. For the first time since the introduction of the RFS, the US EPA is required to base its ethanol standard on the US Energy Information Administration (EIA)'s forecast of gasoline demand.

As shown in the table below, the target volume of "renewable fuel", i.e. principally corn ethanol (though imported sugar-cane ethanol also qualifies), is 0.7 billion gallons (51 kb/d) below 2013 volumes and 1.3 billion gallons (90 kb/d) below the original 2014 quota set in 2010. The quota of "advanced biofuel"

which is not part of biodiesel or cellulosic biofuel has been slashed by more than 50%, down to 0.9 billion gallons (60 kb/d) from 1.46 billion gallons (95 kb/d) in the 2013 mandate. This reduction will primarily impact sugarcane-ethanol imports from Brazil, which in recent years provided for the lion's share of "advanced biofuel" blended under RFS2. Cellulosic biofuel accounts for the biggest cut in 2014 volumes versus the original RFS2 quotas of 2010, although the proposed 17 million gallon (1.1 kb/d) target for cellulosic biofuel still exceeds the 2013 mandate.

Our downwardly revised projection of 2014 US ethanol production forecast of 895 kb/d is 45 kb/d more than the actual RFS2 corn ethanol quota, as we expect a slight increase in US ethanol exports, which averaged about 36 kb/d over Jan-Sep 2013. We have also adjusted our projections for US biodiesel production marginally upwards, to 90 kb/d from 84 kb/d, as biodiesel production has increased considerably in 2013, and the ongoing difficulty of blending more than 10% of ethanol in the gasoline pool will likely lead to higher consumption of biodiesel in order to meet the advanced biofuels quota.

The EPA's decision to reduce the 2014 RFS2 quota for both corn ethanol and cellulosic biofuel reflects the difficult market situation of these biofuels in the US. In light of declining or flat gasoline consumption levels, ethanol is struggling to find its way to the market, as the 10% ethanol blend wall is approached. Indeed, some have proposed that standards should be a percentage of fuel (i.e. gasoline) consumption rather than a fixed volume, as is the case in most other countries with biofuel mandates in place. The revision of the cellulosic biofuels quota, on the other hand, reflects a lack of availability, due to the slower-than-expected ramping up of capacity of these fuels.

The current challenges related to the ethanol "blend wall" and the slow pace of development of cellulosic biofuel production suggest that EPA may continue to revise RFS quotas in the coming years.

Canada - Newfoundland October actual, others September estimated:  With synthetics, bitumen, and NGLs all falling slightly in September, Canadian total liquids production dropped by about 130 kb/d m-o-m to 3.96 mb/d. Both Suncor's and Shell's upgrading facilities underwent maintenance, and the Kearl mined bitumen project was only able to maintain production levels, instead of continuing to ramp up. The announced maintenance on the offshore Terra Nova field took production offline in October and November, with production restarted on 6 December. Despite this, production is expected to show a return to August levels of 4.1 mb/d as maintenance on synthetics projects ends (although a gas outage due to a pipeline leak took production offline at most projects for about 48 hours). Total liquids production in 4Q13 is forecast at 4.25 mb/d, including 700 kb/d of pentanes plus and other NGLs.

Following the Lac-Mégantic, Quebec, disaster in July, when a crude train derailed and caused a lethal explosion and fire, journalistic reports that rail shipments of volatile crude oil are not being sufficiently well inspected and evaluated for safety have prompted Canadian and US authorities to launch a joint effort to better manage these shipments and enforce regulations. Both countries' authorities are considering stronger regulations as well. Meanwhile, given that the Keystone XL pipeline has not yet had a final decision regarding its approval from the US government, rail has become ever more important for Canadian producers to take crude to US refiners. Previous issues of this Report have discussed various projects for new rail terminals to be built in 2014, but an insufficient number of tank cars could still create export bottlenecks.

Mexico - October actual, November preliminary: Although the trend of quarterly y-o-y declines continues, in October crude oil production was up slightly m-o-m to 2.54 mb/d. November data indicates a small decline, to 2.51 mb/d. Total liquids production for 4Q13 is forecast at 2.89 mb/d, as NGL production stabilises at 360 kb/d and then is expected to grow 20 kb/d in 1Q14.

As the time of writing, a proposed reform of the country's hydrocarbon legislation had just come before committees of the General Congress of the United Mexican States [the national legislature], with some important changes to the initial government proposals discussed in September's Report. This will be discussed further in the January 2014 Report. Much speculation has surrounded whether LTO from formations similar to those in neighbouring Texas, as well as deepwater prospects similar to offshore fields of the neighbouring US GOM, could have their future oil production outlook greatly affected by potential reforms to the sector. State oil company Pemex is undertaking projects in those areas, including drilling wells just across the border from the Eagle Ford shale play. The geologically complex onshore Chicontepec trend, where Pemex has made very large investments, has shown that the company is having difficulty obtaining high returns to investment on unconventional plays. About one out of three wells drilled is uneconomic, and after increasing production by 20 kb/d on the Chicontepec expansion in 2011-12, production has declined in 2013, falling to 62 kb/d in October. Pemex is attempting to bring in service companies to increase production with a new bid round next year, but an earlier bid round in July failed to attract a single bid.

North Sea

Norway - September actual, October provisional:  Final September data show that total liquids production was about 20 kb/d lower than previous provisional data had indicated, at 1.58 mb/d. Preliminary October data show that production was much lower than expected, by about 200 kb/d, as planned maintenance cut deeper into production output, and there was significant unplanned maintenance as well. The Alve, Balder, Draugen, Fram, Heidrun, Kristin, Marulk, Norne, Skuld, Tordis, Tyrihans, Urd and Vigdis fields all experienced maintenance-related reductions in output. Hence, the Haltenbanken system, which encompasses many of these aforementioned fields, is expected to show that output remained under 300 kb/d for October, after dropping to 150 kb/d in September, the lowest production for this system since the mid-1990s. Given the loading schedule and reduced maintenance, it is expected that November will show a rebound in production, with crude up 150 kb/d to 1.55 mb/d, and total liquids at 1.9 mb/d. That being said, the total liquids production forecast for 2014 has been revised downward by about 65 kb/d, mostly on lower output on the Haltenbanken system. It now seems that repairs needed on the Njord platform are more extensive than originally thought, and the Hyme field, which feeds into Njord, will also be offline for an extended period in 2014. Due to a power outage at the Nyhamna gas processing plant in early December, Ormen Lange NGL production is forecast to be lower for the month.

The Norwegian government released the country's total upstream oil and gas investment plan for 2014, which at $36 billion, amounts to a 2% rise on 2013. This is despite the fact that Statoil, the largest operator in Norwegian waters, will not drill a single new well in the Norwegian Sea in 2014, concentrating its activity on the North and Barents Seas, with most exploration wells in the mature North Sea. In general, given that costs are expected to rise 3.5%, investment is declining slightly in real terms.

UK - August actual, September provisional:  Offshore crude oil production slipped to 600 kb/d in August, the likely low for the year. Throughput on the Forties system fell to about 230 kb/d, down 110 kb/d from August on an outage on the system's largest field, Buzzard, as well as reduced output on the Forties field itself. In September, offshore crude oil production rebounded to about 710 kb/d, likely on an end to maintenance on the Forties system, as Forties loadings show an increase from 252 kb/d in August to 360 kb/d in September and 387 kb/d in November. Total liquids output for the UK in September was 760 kb/d, despite a large drop in NGL/condensate production to just 35 kb/d for the month, after averaging 80 kb/d previously in 2013. It is estimated that October will build on September's rise, with total liquids for October at 890 kb/d. Offshore crude oil production in 4Q13 is forecast to return to nearly the same level as 2Q13, at 780 kb/d. Despite continuing declines on most fields, a few new fields such as Huntington and Jasmine (condensates; production started up 19 November) will make up for some of the lost output. Total UK output is forecast to fall about 110 kb/d in 2014, a sharper decrease than the 80 kb/d expected for this year, but still less than the 170 kb/d drop experienced in 2012. First production from the Alma/Galia field is not expected until the beginning of 3Q14, and larger projects, such as EnQuest's Kraken field in the East Shetland basin, which won government approval in November, will not be in production until 2016.

Of concern for the medium-term production outlook is that Chevron, operator of the $10-billion Rosebank deepwater project in the West of Shetlands, stated in November that the project "does not currently offer an economic value proposition that justifies proceeding with an investment of this magnitude." Although the company indicated that it will work to improve the project value before making a final investment decision with its partners, this puts the future of the endeavour in some doubt. Similar concerns have arisen on the $6-billion Statoil-operated Bressay heavy oil field. Together, the fields represent approximately 115 kb/d in potential new output.

BFOE production increased by 100 kb/d in October, m-o-m, to 875 kb/d, with loadings at 850 kb/d. Although BFOE loadings show a further increase to 1 mb/d in November, production is expected to be somewhat lower, as loadings pick up some October production. Forties has dominated North Sea Dated pricing in recent years, as it is usually the cheapest grade, given its relatively sour quality. However, the system of quality premiums that was instituted in May of this year, partly in response to declining Forties production, has resulted in the other three benchmark grades being able to set prices. In October and November, the quality premiums widened as Forties production had fallen in previous months and similar crudes, such as from Libya, were also in short supply. Hence, all four grades set the benchmark at times in recent weeks, with Oseberg setting it most often.


Latin America

Brazil - October actual:  Production of crude oil dropped only 15 kb/d in October m-o-m, at approximately 2.1 mb/d, despite a short-lived, partial Petrobras workers strike that month. Although some fields such as Baúna, Lula and Sapinhoá experienced declines, Roncador achieved the highest production level since May 2011, at 290 kb/d. This made it Brazil's largest producing field for the month, a title that Marlim Sul had held since January 2012, despite Marlim Sul showing only slightly below-average production at 285 kb/d. Total liquids production for October was 2.17 mb/d (not including biofuels). In November, the Petrobras-operated Papa Terra deepwater heavy oilfield came online via the P-63 FPSO, despite the company having previously indicated that it would be delayed for another couple of months. This field is a key component in Petrobras' aim to increase production in the next couple of years, as the field's target production after the addition of the P-61 tension leg platform next year, and the completion of all planned wells, is 140 kb/d. Because of y-o-y declines in the first two quarters of this year, 2013 is forecast to experience a decline of approximately 40 kb/d, but growth of 90 kb/d is expected for 2014. Continued subsidies for the downstream sector by Petrobras, given that recently announced increases in retail product prices were less than expected, could affect the financial outlook for the company.

Among the fields contributing toward expected declines next year is Albacora Leste, which produced nearly 170 kb/d in the first half of 2007, but has been slowly declining since then, to 50 kb/d in 3Q13. Government regulator ANP is expected to release recommendations for the revitalisation of this field in the coming months. ANP has already asked Petrobras to make additional investments, including a new platform, so as to maintain production on Marlim Sul in the medium term. In late November, Brazil had an onshore licensing round, but only 30% of the blocks on offer were awarded. Total onshore crude oil production was about 170 kb/d in October. Brazilian ethanol production fell to 660 kb/d in October, a seasonal decline but November is estimated at 520 kb/d, a shallower drop-off than normal.


China - October actual:  Oil production was up 180 kb/d m-o-m in October, to 4.24 mb/d, as wells that had been shut for floods came back online in Daqing and Shaanxi. In addition, 680 new wells are being brought online in Daqing that are expected to lead to continued production increases on the field in the coming months. Although many mature fields are in decline, CNPC drilled about 640 new horizontal wells this year, which are expected to add about 75 kb/d of production, mostly at Changqing. CNPC has also pursued other EOR techniques, such as steamflooding and reservoir stimulation to further increase production at the Changqing block. We expect this area to show a net increase in production of nearly 60 kb/d in 2014, y-o-y. Another area showing growth is the Fengcheng ultra-heavy field, which has added about 35 kb/d in the Junggar Basin in Xinjiang in 2013, and is expected to double in output by early 2015. Offshore, the third phase of development at ConocoPhillips' Penglai 19-3 field is expected by the end of 1Q14, though incremental volumes are unclear - it will, however, be 90 kb/d or less, given the 190-kb/d offloading capacity on the FPSO. The field, which is producing about 100 kb/d as China's largest single offshore field, will have its operatorship transferred to CNOOC in 2014. Production growth for 2014 for the country as a whole is forecast at 100 kb/d.

Back onshore, China's oil industry suffered a major disaster with the explosion of Sinopec's Donghuang II crude oil pipeline on 22 November, which killed at least 55 people and injured more than twice as many. The government has held the company responsible for the blast, alleging negligence, though the phenomenon of rapid urban expansion around pipelines is also problematic. The 200-kb/d pipeline is to be permanently shut in (see Refining).

Former Soviet Union (FSU)

Russia - October actual, November provisional:  Final data for October shows crude oil production of 10.19 mb/d; total liquids production of 10.97 mb/d. Oil production in Russia continued its impressive annual growth into November, reaching 11 mb/d of total liquids, of which 10.2 mb/d was crude oil. This is another monthly output record. Noteworthy in November was the nearly 320 kb/d achieved by the Sakhalin PSAs, the first time that their production has exceeded 300 kb/d this year. However, following a government audit of these projects released in November, certain problems in their operations were identified, such as with local content requirements and flaring, which could impact production in the near future. First output from Gazpromneft's Prirazlomnoye field in the Pechora Sea has been delayed from this December to February, according to the company.

Given our December forecast, yearly output for Russia for 2013 is expected to be 10.87 mb/d, a 135 kb/d y-o-y increase and the same as was achieved in 2012. Horizontal drilling and other now-basic EOR techniques on brownfields in Western Siberia have been successful at curtailing declines enough for greenfields in East Siberia to create a net increase for the country. Lukoil began increasing horizontal drilling in 2010-11, but in 2013 Rosneft, as of November, had drilled 115 new horizontal wells. Overall, horizontal drilling had increased to 18.5% of total drilling in the country by 3Q13, up from 12% in 2012.

The 2014 forecast is for a 90 kb/d increase in total liquids. The outlook is slightly less positive than that likely seen in 2013, as some areas of West Siberia have already reached a saturation point in terms of new horizontal drilling. One of the contributors to growth is Rosneft's Srednebotuobinskoye field, which came online in September, and is already producing 20 kb/d; production is forecast to average 35 kb/d for 2014. Rosneft has announced that 2013 through 2015 spending of $2.8 billion will be made via its Vankorneft subsidiary on further expansion of output from the Vankor field and satellite fields in order to bring production up to 500 kb/d in the medium term. Next year, an increase of only 10 kb/d is forecast by the company (after achieving a 65 kb/d increase in 2013), to 440 kb/d, and only an additional 50 kb/d in the four years following, despite continued large investment. This illustrates that in Russia, as in the industry in general, incremental barrels are often coming at higher costs.

Azerbaijan - September actual: Production at the ACG fields fell to 640 kb/d in September, as output has declined gradually since June, when production was just above 700 kb/d. This has brought the total liquids yield down to 840 kb/d for the month, and makes for a y-o-y decline of 30 kb/d for 3Q13. Quarterly data shows that all of the ACG fields dipped in 3Q13 except for Guneshli, where BP has drilled new wells. SOCAR crude oil production has remained flat for the year at about 135 kb/d. Although we expect increases in Guneshli production for 4Q13, as well as new production at West Chirag in mid-2014, these are not expected to be enough to compensate for an overall drop for the country of about 60 kb/d in 2014, to 820 kb/d. Into the medium term, the expected approval later this month of an expansion of the Shah Deniz offshore gas field would add another 45 kb/d of condensates in the next few years.

Kazakhstan - October actual:   Crude oil output rose to 1.4 mb/d in October; total liquids to 1.73 mb/d, as Tengiz yielded 570 kb/d, up 45 kb/d m-o-m. This is the highest monthly liquids production for the year so far. It is expected, however, to be the monthly peak for some time to come, at least until Kashagan begins to produce at significant volumes. Indeed, since last month's Report, the near-term outlook for Kashagan has grown distinctly more negative. Kashagan, which has been shut down since 9 October, the NCOC operating consortium is investigating a pipeline that leaked gas, and large sections have had to be dug up for microscopic inspection. Other pipeline sections are having certain automated devices run through looking for problems. It will be mid-January at the earliest before a report on the pipeline problems is expected. The CEO of NCOC member Total cautioned in November, however, that the problems are "…more than simply repairing pipes." Given this, we do not expect any substantial production until April, and commercial production levels seem unlikely until May or, more likely, June.

The government and the Chevron-led consortium operating Tengiz reached a preliminary agreement in November to expand production on the Tengiz field to about 760 kb/d by 2018 and increase the field's production life to beyond 2033 with investment of about $23 billion in new wells and gas injection facilities. In the short term, however, Tengiz is expected to maintain output slightly lower than October's level, as increasingly heavy maintenance is needed to sustain production levels.

FSU net exports to non-CIS destinations remained relatively stable at 9.1 mb/d in October, a slight 80 kb/d lower than September. Crude exports rose by 140 kb/d, although in contrast to previous months most of the rise came from outside Russia, especially from Kazakhstan where refinery maintenance freed up crude for export. Notably, flows through the CPC pipeline were upped by a significant 130 kb/d to hit 780 kb/d, their highest level since December 2010. Additionally, Kazakh Tengiz crude was also railed to the Ukrainian port of Odessa, rather than the Russian outlet of Taman. Consequently, exports via Odessa reached 80 kb/d, their highest since June 2012.

Shipments sent via the Transneft network slipped by 40 kb/d on the month to 4.2 mb/d, 400 kb/d above August's recent low as Russian refinery maintenance continues. The Baltic was the only region to see a rise with flows via Primorsk and Ust Luga inching up by 20 kb/d and 80 kb/d, respectively. Volumes via the Black Sea port of Novorossiysk fell by 50 kb/d to 740 kb/d. As more Russian oil heads eastwards, this outlet has been especially hard hit, current volumes are now over 100 kb/d less than one year ago. ESPO exports slipped by 40 kb/d as Kozmino seaborne shipments inched down. Flows of Rosneft-produced crude on the spur to China remained above nameplate capacity at 340 kb/d. It now appears that the long-expected closure of the Baku - Novorossiysk pipeline will take place in February 2014. This will likely lead to a sharp reduction in Azeri oil being shipped via the Transneft network to the Black Sea with Azeri exporters, notably state-owned SOCAR, expected to continue their current trend of exporting directly to the Mediterranean via the more cost effective BTC line.

Refinery maintenance continued to affect product exports in October as refiners chose to supply domestic markets rather than send product abroad. Consequently, total product shipments continued their downward trend, falling by a significant 210 kb/d on the month to 2.6 mb/d. The bulk of the decrease was seen in fuel oil exports which plunged by 120 kb/d as domestic buying reportedly picked up ahead of winter. Meanwhile, gasoil shipments fell by 80 kb/d and 'other products' slipped by 10 kb/d.

OECD Stocks


  • Commercial inventories in OECD member countries drew seasonally by a weaker-than-normal 12.1 mb in October as strong builds in crude oil and other feedstocks partly offset an exceptionally steep 50.7 mb draw in refined products.
  • Unusually sharp declines in refined product inventories took their deficit versus the five-year average to 74.4 mb from 45.8 mb at end-September. Refined product cover decreased to 29.5 days, 0.9 days lower than at end-September.
  • Middle distillates drew by a steep 22.8 mb to stand at a wide 48.9 mb deficit to seasonal levels at the onset of winter in the Northern hemisphere.
  • Preliminary data indicate that OECD industry stocks drew by a counter-seasonal 34.5 mb in November after refined products drew by a steep 32.5 mb.

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

Commercial oil inventories in OECD member countries posted an unusually weak seasonal draw of 12.1 mb in October. At 2 684 mb, inventories now stand 12.2 mb below year-ago levels and at a 19.7 mb deficit to the five-year average. As OECD refinery activity plummeted in October to a 20 year low, refined products drew by 50.7 mb, more than twice the 22.0 mb five-year average draw for the month. The draw in product stocks was their steepest monthly decline since February 2011, a month which was also characterised by high OECD refinery turnarounds. On the flip side, as refiners decreased throughputs, crude oil stocks soared by 34.5 mb, more than five times the 6.5 mb five-year average build. NGLs and other feedstocks also increased by a further 4.1 mb across the OECD. The build in crude, coming on top of a significant 18.6 mb upward revision to September data, has taken crude holdings above the seasonal range for the first time this year. Due to that unseasonably strong crude build, the deficit of OECD total oil stocks versus the five-year average actually narrowed to 19.7 mb from 23.7 mb one month earlier.

The steep draws in refined product inventories have taken their deficit versus the five-year average to a whopping 74.4 mb, from 45.8 mb at end-September. This is the widest deficit since April 2004. Furthermore, the deficit in refined product inventories now spans all OECD regions for the first time since November 2007. It would be even wider were it not for surplus ethane supplies stranded in the US (see Excess Ethane Supplies Inflate OECD Refined Product Stocks).

A 22.8 mb plunge in middle distillates stocks led the product draws. Middle distillates inventories ended October nearly 50 mb in deficit to the five-year average (see OECD Distillate Stocks Tighten as Peak Winter Demand Season Approaches). Motor gasoline inventories dropped by a steep 12.6 mb, led by the OECD Americas. 'Other products' fell by a stronger-than-usual 11.9 mb and fuel oil fell by 3.4 mb. All told, at end-month OECD refined products covered 29.5 days of forward demand, 0.9 days lower than at end-September.

End-September OECD inventories have been adjusted upwards by 19.2 mb since last month's Report with crude oil accounting for 18.6 mb. OECD Europe and OECD Americas accounted for all of the adjustments, with upward revisions of 10.4 mb and 8.8 mb, respectively. A counter-seasonal 8.6 mb stock build reported in last month's Report for September stocks now looks even steeper at 21.4 mb.

Preliminary data indicate that OECD inventories drew by a steep 34.5 mb in November, in stark contrast to the 3.0 mb five-year average build for the month. Refined products led stocks lower, falling by a counter-seasonal 32.5 mb, concentrated in OECD Americas. If these data were to be confirmed by subsequent official data, it would see the deficit of refined products stocks versus the five-year average widen to a considerable 111 mb. Overall OECD American inventories fell by 27.6 mb while European stocks fell by 11.9 mb after refiners there drew crude stocks in tandem with rising runs. Elsewhere, Japanese stocks increased by a counter-seasonal 5.0 mb on rising crude holdings.

Excess Ethane Supplies Inflate OECD Refined Product Stocks

At end-October, OECD total product stocks stood at a significant 74.4 mb deficit to the five-year average, their widest deficit since April 2004. It was also the first time since November 2007 that product inventories across all OECD regions stood in deficit to the seasonal average at the same time. In the OECD Americas, inventories flipped from a surplus to a deficit as middle distillates drew steeply. This switch would have occurred much earlier in 2013, however, had it not been for soaring regional stocks of 'other products.' Currently 'other products' stocks in OECD Americas stand 18.3 mb in surplus to seasonal levels. That overhang exceeded 30 mb in 1Q13.

Last year and through early 2013, the large surplus of 'other products' was mainly due to excess US propane inventories. However, following the launch of a number of export terminals, US propane exports recently approached 290 kb/d, while seasonal crop drying has lifted domestic demand. By end-November, US propane inventories had retreated to 6 mb below the seasonal range and 18 mb below year-ago levels.

On closer inspection, the bulk of the overhang in 'other products' inventories now stems from excess ethane, a direct result of surging US natural gas production. US ethane stocks currently stand 13 mb (50 %) above the seasonal norm. Ethane's main use is as a petrochemical feedstock. Although the US has ambitious plans to build new ethylene crackers over the medium term, as well as more ethane pipeline capacity from separation plants to petrochemical facilities, they are currently only coming on-line at a trickle. As a result, the ethane market is oversupplied and even with rejection of ethane back into the dry gas stream, stocks are soaring. An additional problem concerns the logistical issues of evacuating ethane to consumers. Due to its light and volatile nature, it cannot easily be transported, which leaves it stranded in the US. However, a number of petrochemical companies, notably Ineos have recently made plans to ship US ethane to Europe over the medium-term with specialist tankers currently on order.

If OECD Americas 'other products' stocks and demand are stripped out of OECD aggregates of forward cover, the importance of the 'other products' overhang becomes clear. The forward demand cover provided by OECD refined products falls by 0.4 days to 29.1 days at end-October, notably below the seasonal range. Furthermore, if 'other products' are stripped from stocks and demand in OECD Americas, days of forward cover drop by 1.3 days to 27.3 days at end-October, below the five-year average and towards the bottom of the seasonal range.

In summary, since ethane's use as a feedstock is limited mostly to the production of ethylene, and that US ethane processing capacity is currently saturated and exports constrained, it should not be considered as comparable to other refined products, notably transport and heating fuels. Its price relative to propane reflects this. Therefore, to a certain extent when examining OECD and especially US refined product stocks, extra care should be taken to account for 'other product' stocks in considering inventory tightness.

Recent OECD Industry Stock Changes

OECD Americas 

Industry inventories in OECD Americas slipped by 7.4 mb in October after builds in crude oil (22.8 mb) and NGLs and feedstocks (4.6 mb) largely offset a steep, 34.7 mb draw in refined products. The draw in products was over twice the average 14.3 mb five-year average stock draw for the month. Since the decrease in total oil was broadly in line with the 9.0 mb five-year average draw, the region's surplus versus average levels stayed relatively stable at 49 mb.

The monthly draw resulted from a near-800 kb/d drop in regional refinery throughputs that decreased demand for crude and drew product stocks as distributors struggled to keep pace with product demand. As crude inventories built at an unseasonably fast pace, regional crude prices were pressured lower, with WTI and WCS weakening by $6/bbl and $9/bbl, respectively, on average over October.

Distillates inventories led the refined product draw, falling by 12.6 mb. Motor gasoline stocks followed suit, plunging by 10.8 mb. Inventories of other products also drew by a stronger-than-seasonal 11.6 mb on rising US propane demand and still-strong propane exports. All told, forward cover provided by refined products holdings fell by a significant 1.4 days m-o-m to 28.6 days by end-month.

Preliminary weekly data from the US EIA indicate that US stocks fell by a further 27.6 mb in November (data include the week ending 29 November). As with October, refined products led the draw, falling by 27.3 mb. Crude stocks provided little offset, inching up by a marginal 0.6 mb. In contrast to the October fall, however, the draw was not related to refinery maintenance, since runs came roaring back by close to 700 kb/d. Rather, it was concentrated in 'other products,' which fell by a stronger-than-seasonal 21.7 mb as propane stocks dropped by 8.2 mb on rising crop-drying and heating demand and record-high exports.

OECD Europe

Total Commercial oil holdings in OECD Europe inched down by 0.2 mb in October, as an unseasonal 12.5 mb crude oil build largely offset a 13.8 draw in refined products. Since the fall was weaker than the 6.3 mb five-year draw average for the month, the deficit of total oil inventories versus average levels narrowed to 60 mb from 66 mb at end-September. Moreover, since the crude restocking was steeper than the 1.0 mb five-year average build, European crude stocks moved into surplus (+5.7 mb) versus average levels for the first time since January 2011. Middle distillates led the product draw, falling by 8.2 mb, in line with seasonal trends. Meanwhile, stocks of motor gasoline, fuel oil and other products slipped by 2.1 mb, 2.6 mb and 1.0 mb, respectively. At end-October, refined products covered 37.1 days of forward demand, 0.3 days above one month earlier.

Preliminary data from Euroilstock point to a counter-seasonal 11.9 mb fall in European inventories over November. Plummeting crude oil stocks (-9.7 mb) led stocks lower with refined products slipping by 2.2 mb. The bulk of the product draw came from motor gasoline which fell by a counter-seasonal 2.7 mb while 'other products' slipped by 0.9 mb. Middle distillates inched up by 0.4 mb, considerably weaker than the 6.3 mb five-year average build.

OECD Asia Oceania

Total oil inventories in OECD Asia Oceania fell more steeply than usual, by 4.5 mb, compared to a 0.8 mb five-year average draw for the month. As in the rest of the OECD, refined products led the draw on the back of refinery maintenance. Unlike elsewhere, crude stocks drew seasonally by 0.8 mb, with NGLs and feedstocks posting a further 1.5 mb draw. Middle distillate stocks fell by 2.1 mb and those of residual fuel oil retreated by 1 mb. In contrast, stocks of motor gasoline and 'other products' built by 0.3 mb and 0.7 mb, respectively. At end-month, refined products covered 20.4 days of forward demand, 0.9 days above end-September.

Weekly data from the Petroleum Association of Japan indicate that Japanese total oil inventories rebounded by 5.0 mb in November from October's 4.5 mb fall. The build was concentrated in crude oil which increased by a strong 7.0 mb, NGLs and other feedstocks built by a further 0.9 mb. Products drew by 3.0 mb. All product categories destocked, led by middle distillates (-2.3 mb).

Recent Developments in Singapore and China Stocks

According to latest data from China Oil Gas and Petrochemicals (China OGP), Chinese commercial crude inventories slipped by an equivalent 4.4 mb in October (Chinese stock changes are reported in percentage terms) as refinery throughputs hit 9.7 mb, their highest since February, while imports dropped from September's record level. Despite the increase in refinery activity, commercial refined product stocks dropped by 7.6 mb, including a 6.3 mb draw in gasoil. Gasoline and kerosene stocks inched down by 0.7 mb and 0.6 mb, respectively.

Weekly data from International Enterprise indicate that land-based refined product stocks in Singapore drew by a slight 0.3 mb over November. However, this masked significant volatility during the month. The draw was concentrated in middle distillates (-1.8 mb) amid rising regional heating demand. A 1.7 mb build in residual fuel oil stocks offered an offset as Asian bunker demand reportedly remained weak and the arbitrage to move product from Asia to Europe remained open.

OECD Distillate Stocks Tighten as Winter Nears

With the onset of winter in the Northern hemisphere, attention turns towards heating fuel inventories. In the OECD, middle distillates are the liquid fuel of choice for space heating. This wide product grouping includes ultra-low sulphur diesel and heating oil, which are widely used in OECD Americas and Europe as well as kerosene, the heating fuel of choice in Japan and Korea.

Latest official data indicate that OECD middle distillate holdings tightened significantly across the OECD in October to leave all regions standing in deficit to seasonal levels. On an absolute basis, total OECD levels are in line with one year ago but considerably lower than the five-year average. The picture is not much better on a days of forward demand basis, with end-October inventories covering 30.5 days of forward demand, 0.6 days and 2.6 days below last year and the five-year average, respectively. Therefore, in the event of prolonged cold weather and an associated surge in heating fuel demand, these inventories could be depleted rapidly.

In the OECD Americas, middle distillate holdings stand broadly in line with last year but lag the five-year average by 27.4 mb. However, consideration should be given to two underlying trends affecting inventories; Firstly, the Northeast heating oil reserve halved its capacity to 1 mb in 2011 when it converted from heating oil to ultra-low sulphur diesel. Secondly, although information is scarce, anecdotal reports suggest that US consumers have switched from ultra-low sulphur diesel or heating oil to cheaper alternatives for heating such as natural gas or electricity (see The Changing Seasonality of Oil Demand in Demand section). The OMR demand forecast takes account of these trends but even on this basis regional inventories appear tight covering 28.6 days of forward demand, 0.6 days less than 2012 and a significant 4.3 days below the five-year average.

In OECD Europe, middle distillate inventories appear tight on an absolute basis, lagging the five-year average by 20 mb at end-October. However, even considering that demand has contracted since 2008, on a days-of-forward demand basis, stocks do not appear much more comfortable, lagging the five-year average by 1.4 days. However, an important point to consider is that consumers in Germany, the region's largest heating market, have extensively restocked over the summer. In October tank fill stood at 63% of capacity, 14% above April's low and higher than at any point since 2009. Since these stocks are tertiary and thus have already been removed from industry stocks, they will provide a buffer to the tight industry inventories in the event of prolonged cold weather.

In OECD Asia Oceania, middle distillates lag the five-year average on both an absolute and days of forward demand basis. However, this picture is complicated somewhat by the market being small and therefore the five-year range is narrower than elsewhere. Nonetheless, at end-October, on an absolute level, middle distillates holdings stood 1.8 mb and 2.9 mb in deficit to the five-year average and 2012, respectively. Regional inventories cover 22.7 days of forward demand, 1.0 days and 0.8 days below the seasonal average and last year, respectively. Furthermore, inventories are now currently below the seasonal range.



  • Futures prices trended lower in early November but retraced their losses later in the month and into early December. Average front-month ICE Brent averaged $107.90/bbl in November, down $1.54/bbl month-on-month, but by early December had rebounded and posted four consecutive weekly gains, averaging $111.71/bbl in the first week of the month. NYMEX light, sweet crude oil fell by a steeper $6.62/bbl in November, to $93.93/bbl, but later bounced back as well, to an average $96.42/bbl in the first week of December.
  • The WTI-Brent spread widened by more than $5/bbl in November, to an average of just over $14/bbl, reaching around $17.55 in the last week of the month, only to fall back slightly to near $15.30 in early December. Continued disruptions in Libyan crude exports helped support Brent prices, while surging US LTO supply, coupled in October with steep refinery run cuts, kept WTI prices under downward pressure.
  • Middle distillate and RBOB crack spreads rallied on the NYMEX in November on the back of resurging US demand, strong US exports of refined products, deep refinery run cuts and steep product stock draws in October. In contrast, gasoil crack spreads to Brent on the ICE edged down on high crude prices amid continued disruptions in Libyan crude exports.
  • Oil markets took an interim agreement between Iran and the P5+1 nations reached in Geneva on 24 November in their stride. Despite some relaxation of shipping restrictions, the deal keeps US and EU sanctions on Iranian oil exports firmly in place for the next six months, as the two sides engage in further talks and confidence building. After a knee-jerk, intraday dip following the Geneva accord, futures prices resumed their uptrend.
  • Rates for Very Large Crude Carriers (VLCCs) enjoyed their best month in years in November, firming steadily to end the month at levels unseen since 1Q09. Asian demand for Middle Eastern crudes remained strong as Asian refiners came out of turnarounds. Rates on the benchmark Middle East Gulf - Asia route surged to more than $17/mt by early-December, from $14.40/mt a month earlier.

Market Overview

Futures prices trended lower in early November but retraced their losses later in the month and into early December. Brent prices were especially buoyant. Average front-month ICE Brent averaged $107.90/bbl in November, down $1.54/bbl month-on-month, but by early December had rebounded and posted four consecutive weekly gains, averaging $111.71/bbl in the first week of the month. In contrast, NYMEX light, sweet crude oil fell by a steeper $6.62/bbl in November, to $93.93/bbl, but later bounced back as well, to an average $96.42/bbl in the first week of December.

The WTI-Brent spread widened by more than $5/bbl in November, to an average of nearly $14/bbl, reaching around $17.55/bbl in the last week of the month, only to fall back slightly to near $15.30/bbl in early December. Continued disruptions in Libyan crude exports and lower Iraqi exports helped support Brent prices, while surging US LTO supply, coupled with steep refinery run cuts in October, kept WTI prices under downward pressure

Iran and the P5+1 nations (the US, EU, UK, Russia, China, France and Germany) and Iran reached an interim agreement on 24 November in Geneva by which Iran agreed to a temporary freeze on many nuclear activities as well as increased cooperation with the IAEA in exchange for a commitment from the P5+1 not to increase sanctions further. While Tehran also earned a partial easing of some sanctions, notably on maritime insurance, existing US and EU oil sanctions remain firmly in place. All parties agreed to use the six-month period covered by this interim deal to push toward a more permanent arrangement. While a permanent resolution of the Iran nuclear question could eventually lead to a significant relaxation in sanctions against Iran, in recent days President Obama has publicly stated that he places the odds of successfully reaching such an agreement at 50-50 or less. Oil markets took the agreement, which was announced at a time when oil markets were closed for the weekend, in their stride. After a knee-jerk, intraday dip on Monday, 25 November, futures prices resumed their uptrend.

Meanwhile, OPEC ministers gathered on 4 December in Vienna agreed to keep their output target steady at 30 mb/d for the first six months of 2014, though both Iran and Iraq have signalled their intention to increase crude oil production in due course regardless of the collective target. The group said it sees economic uncertainty as the oil market's top challenge, but acknowledged that forecast non-OPEC supply looked set to "more than offset" projected increases in demand, and reserved the right to "swiftly respond" to any sign of market imbalance. This was understood to mean that the group could reconvene before its next ordinary meeting of 11 June 2014 if warranted by market conditions. Many commentators have speculated that fast-rising production from US light, tight oil formations and other sources could put pressure on OPEC's crude oil output in 2014.

Futures Markets

Between 29 October and 3 December, hedge funds and other money managers' net long positions in ICE Brent futures sank to their lowest levels in more than a year. Their net long positions bounced back around mid-November as Brent prices reversed earlier losses, climbing above $110/bbl by end-month. Money managers' positions in NYMEX WTI futures were little changed, as the Cushing-based benchmark traded in a narrower $5 to $6/bbl range.

Money managers were moderately bearish gasoil/heating oil in early November, but progressively shifted from a net short position to a more bullish, net-long stance as prices recovered in the second half of the month. Hedge funds also gradually increased their net long positions on NYMEX RBOB over the month, in line with an upward trend in prices over the period.

NYMEX WTI open interest was seasonally down 7% on the month in future contracts only and down by 13% in futures and options, while open interest in ICE Brent increased by 6% over the period, bringing growth year-on-year (y-o-y) to 21%. After showing signs of recovery earlier this year, global WTI trading volumes appear to have lost momentum and are now alternating with Brent trading volumes month-on-month for the lead.

Financial Regulation

The Volcker rule was approved by five US federal regulators on 10 December, namely the Federal Reserve, the Federal Deposit Insurance Corporation (FDIC), the Securities and Exchange Commission (SEC), the Office of the Comptroller of the Currency (OCC) and the Commodity Futures Trading Commission (CFTC). The rule is a pillar of the 2010 Dodd Frank Act, the financial regulation reform adopted in the wake of the 2008 financial crisis. The new rule bars commercial banks from engaging in proprietary trading (i.e. trading for their own account) and limits their stake in private-equity and hedge funds.

On 15 November, the US CFTC approved a rule ensuring that treasury bills posted as collateral can easily be converted to cash, effectively requiring the bills to be covered by credit lines. Shortly thereafter, on 20 November, the CFTC published its first weekly swaps report showing aggregate data on cleared and uncleared swaps. Upcoming reports will further categorise data by type of participant and asset class.

The European Securities Markets Authority (ESMA) has granted licences to six trade repositories under the new EMIR regulation on 12 November. Market participants will start reporting on 12 February 2014 for all asset classes, 90 days after the end of the registration period during which trade repositories could apply for a license.

Spot Crude Oil Prices

Regional contrasts in crude supply continue to be mirrored in benchmark price patterns: just as North American crude supply growth keeps racing ahead of production in the rest of the world, so too are spot prices for North American crude benchmarks increasingly divorced from those for other grades. Price trends in November and early December were a case in point. At first glance, all major crude benchmarks suffered a decline in their November average spot prices versus October. But whereas most benchmarks experienced only relatively minor losses, prices for WTI (Cushing) plummeted by $6.56/bbl on the month, causing the WTI spread versus other grades to widen.

On closer examination, monthly headline average figures conceal even stronger contrasts in weekly prices. Average price declines for November were partly misleading, as for most grades they were entirely accounted for by steep declines in the first few days of the month, which themselves extended losses of the previous month. Past that initial dip, most benchmark grades staged an impressive recovery for the remainder of the month and into December. Prices rallied across the board despite the conclusion on an interim agreement between Iran and the P5+1 nations in Geneva on 24 November, which many market observers had expected - wrongly, as it turned out - to lead to a selloff in oil markets. Once again, however, North American grades played the role of outliers. WTI prices bucked the trend set by such benchmarks as North Sea Dated, Urals or Dubai, falling steadily through most of November. Only at the very end of November and in early December did WTI retrace their losses and rise above their November average.   

Steep swings in refinery throughputs across the OECD and continued unrest in Libya compounded the impact of North American supply growth in shaping pricing patterns in November and early December. In Europe, crude supply faced renewed disruptions in Libyan oil exports in November and early December amid intensifying unrest in that country. Average Libyan crude production declined to an estimated 220 kb/d in November, from 450 kb/d in October. That new shortfall has provided support for other grades in the Mediterranean market and beyond, such as North Sea Dated (a light, sweet look-alike) and Urals (another major source of Mediterranean crude supply). Although North Sea Dated prices for November edged down on average by $1.15/bbl from October, prices have been rising steadily since the week commencing 11 November. By the first week of December, they stood more than $4.50/bbl above their November average.

Similarly, Urals prices by early December had more than retraced their losses of the previous two months. Average Urals prices fell by $3.22/bbl in October from September as both European and FSU refinery runs hit seasonal lows, and by another $0.34/bbl in November. By early December, however, Urals prices had rebounded to a weekly average of $112.86/bbl, $4.81 above their November average and $1.25/bbl above September prices. Plummeting European refinery throughputs in September and October likely helped undermine support for Urals prices during those months as refining activity in the region sank to lows unseen in decades, but failed to drag Urals prices further down in November and December, when Russian and European crude throughputs likely recovered somewhat.

Dubai prices exhibited a similar trend, but fluctuated in a narrower band. Dubai spot prices edged down by $1.66/bbl in October and by $0.69/bbl in November, but rebounded from $104.01/bbl in early November to $108.32/bbl in the last week of the month. Dubai failed to extend those gains into early December, however, averaging $108.14/bbl in the week starting 2 December. Tapis fell by a more substantial $3.62/bbl in November, but bounced back in early December, surging $4.75/bbl above the November average.

In contrast, prices for WTI and other US benchmarks have been a study in weakness. Thus WTI spot prices fell by $6.56/bbl in November, extending their $5.74/bbl drop of the previous month. Unlike grades in other regions, WTI prices continued to edge down through November. Only in the week commencing 2 December did the grade bounce back, averaging at $96.11/bbl, $1.17/bbl above its November average, but still more than $10/bbl below September prices. A plunge in US refinery throughputs in October likely helped undermine prices, as did continued strong output growth and a lack of market outlets for US crude beyond domestic markets, due to the US export ban. Strong production kept crude stocks high in November despite a recovery in refinery throughputs, especially towards the end of the month.

Delays in starting up the new 700 kb/d Keystone South pipeline from the Cushing, Oklahoma storage hub to the Nederland, Texas refining centre may also have helped keep a lid on WTI prices at the margin. The pipeline is now scheduled to start up in early January, and is expected to be a bullish factor for WTI compared to Gulf Coast grades, as WTI will flow freely to the Gulf Coast. The already-operating Seaway Pipeline from Cushing will be expanded by 450 kb/d by the end of 1H14, meaning that WTI will be able to flow out of Cushing faster than it can be fed in.

As US crude prices bucked the trend in other markets, differentials between US and other grades widened in recent weeks. The spread between North Sea Dates and WTI (Cushing) has widened from $5.66/bbl in September to $14.05/bbl in November. By the last week of November, the spread had reached $18.11/bbl, but fell back somewhat to $16.45/bbl in early December. Internal spreads between WTI and other US grades have also changed. Bakken crude is now getting better netbacks on the East and West Coasts than in the Gulf Coast market, even when comparatively high rail costs to the Atlantic and Pacific coasts are factored in. Meanwhile, even as WTI increasingly heads south to the Gulf, coastal grade Light Louisiana Sweet (LLS) is being shipped north to Illinois for refining and is becoming disconnected from the Brent-WTI spread.

Saudi Aramco raised its official selling price (OSP) for January light crude to Asia, reflecting gains in prices for comparable benchmarks. At $3.75/bbl, Arab Light's premium to the Oman/Dubai average has reached its highest level in two years.

Spot Product Prices

Atlantic Basin spot product markets showed diverging trends in November. Although product prices generally weakened across the board, crude prices were split along regional lines, leading to disparities in crack spreads. In the US, crack spreads surged as crude prices weakened. WTI and LLS lost $6.60/bbl and $5.80/bbl, respectively, over the month amid ample supplies and growing inter-grade competition. But prices for North American grades did firm up in early December, bringing US cracks sharply lower. In Europe, product prices generally fell faster than crude prices, undermining cracks. In Asia, the spot market remained strong for all products except fuel oil.

Gasoline crack spreads surged to over $20/bbl in the US Gulf Coast in mid-November, as logistical glitches in Florida caused a spike in demand for Gulf Coast-produced gasoline. The boom proved short-lived, however, and, as the Florida market returned to normal, prices retreated. In contrast, European gasoline cracks weakened to below $5/bbl as gasoline prices faced steeper falls than in any other market. Europe remains awash with gasoline as regional demand remains sluggish and export demand to the US and Africa remains weak. Meanwhile, Asian crack spreads rose on the back of falling regional supply after Northeast Asian refineries entered maintenance.

Jet kerosene cracks on the US Gulf Coast also spiked in November, surging to over $28/bbl late-month, their highest since 2008, buoyed by rising domestic demand and healthy exports. However, as with the other products, the crack came crashing down as crude prices strengthened. Despite Asia reportedly being saturated with kerosene, cracks increased steadily over the month as seasonal space-heating demand picked up and the arbitrage remained wide to export jet to Europe.

Naphtha prices rose in all markets in November, albeit from admittedly low levels. In Asia, anecdotal reports suggested petrochemical demand remained firm in the first half of the month, but subsequently faded. Meanwhile, naphtha appeared to be gaining support in Europe from petrochemical users following steep gains in European propane prices in November, which took to new heights a propane price rally started in May. Regardless of price rises, naphtha cracks still remained in negative territory into early-December.


Rates for Very Large Crude Carriers (VLCCs) experienced their best month in years as they firmed steadily to end the month at levels unseen since 1Q09. Asian demand for Middle Eastern crudes remained strong as Asian refiners came out of turnarounds. Consequently, rates on the benchmark Middle East Gulf - Asia route surged to more than $17/mt by early-December. Even with bunker fuels exceeding $600/mt, ship owners are finally firmly in the black with earnings far outweighing costs. Rates for Suezmaxes operating out of West Africa also remained robust with Asian refiners looking to import more light, sweet grades. Since these are long-haul voyages, tonnage has tightened considerably as vessels are tied-up for extended periods. This has caused rates on the benchmark West Africa - US Gulf Coast to surge above $21/mt by early-December. Even the normally calm Northwest European markets have experienced some sustained strengthening over recent weeks as demand for Urals out of Baltic ports firmed.

Although product tanker markets have generally been outperforming crude tanker markets for most of 2013, they were a mixed bag in November. The transatlantic trade in gasoline picked up as the US Atlantic Coast market (PADD 1) turned to Europe to replace US Gulf supply that had been redirected to Florida. In contrast, rates on the Singapore - Japan route weakened to under $16/mt on weak import demand as refiners opted to run down their stocks. Long-haul product trade between the Middle East Gulf and Japan also remained weak with rates for that trade bottoming out at under $20/mt, their lowest level this year, in mid-November. However, rates once again firmed in early-December following an uptick in demand.



  • The forecast of global refinery crude runs for 4Q13 has been slashed by 330 kb/d since last month's Report, on the back of exceptionally low European throughputs and weaker-than-expected runs in non-OECD Asia and Latin America. Global throughputs are now projected at 76.3 mb/d, up just 180 kb/d year-on-year (y-o-y). OECD runs are set to contract by 705 kb/d in 4Q13, dragged down by plummeting European runs, while non-OECD growth slows to 885 kb/d, from 1.5 mb/d in 3Q13.
  • Global refinery throughputs are forecast to rebound to 76.7 mb/d in 1Q14, up by 1.2 mb/d y-o-y. Growth in the Middle East and China is expected to accelerate as new capacity ramps up, while declines in European runs are expected to ease. Despite continued gains forecast for US refineries, overall OECD throughputs will continue to contract, albeit at a lower rate than seen in recent months.
  • OECD refinery crude intake plummeted 1.8 mb/d in October, to 34.5 mb/d and 20-year lows. Heavy maintenance and poor margins cut runs across all regions. European runs led the decline, down 0.8 mb/d month-on-month, and 1.6 mb/d below year earlier levels. North American refiners also curbed runs sharply, though maintained annual gains. OECD runs are set to recover through year-end and into 1Q14 as refiners come out of turnarounds.
  • Refining margins were mixed in November, with US margins outperforming those in Europe and Asia on widening crude differentials. US crude prices fell in November as robust supplies lifted inventories and supported product cracks, propelling margins higher. In contrast, European refining margins suffered from deteriorating gasoline and middle distillates cracks. Meanwhile, Tapis margins in Singapore surged more than $4/bbl on average, as the grade fell sharply from October levels.

Global Refinery Overview

Global refinery crude runs plunged by 2.0 mb/d in October from September, extending earlier drops and taking the cumulative decline since July to a staggering 4.6 mb/d. As in recent months, the drop stemmed almost entirely from the OECD. European runs were, as in September, particularly hard hit, down 790 kb/d month-on-month (m-o-m). At 10.3 mb/d, a 25-year low, European throughputs stood almost 1.6 mb/d below year-earlier levels. North American runs also plummeted, falling by close to 800 kb/d on the month, albeit from elevated levels. Despite that steep drop, North American runs remained up y-o-y, but annual growth weakened considerably from recent months. Crude runs in OECD Asia Oceania also fell, to a seasonal low of 6.3 mb/d. In contrast, non-OECD throughputs edged down by only 210 kb/d overall. Steep falls in FSU runs due to heavy maintenance were offset by higher Chinese throughputs. In all, global refinery runs slipped below year-earlier levels for the first time since May. Year-on-year contraction of 1.0 mb/d in global runs was the steepest since October 2009.

Runs look set for a steep rebound from November on, and indeed preliminary data show US, Japanese and Russian runs recouping earlier losses. Preliminary Euroilstock data show that also European runs recovered from October lows. US refinery runs surged above 16 mb/d at end-November, as maintenance wound down and margins recovered. Both Japanese and Russian throughputs also shot up, by 440 kb/d and 370 kb/d, respectively, as maintenance outages came to an end. Further increases are expected in the Middle East and China as new capacity ramps up, though Chinese runs were likely temporarily constrained in November by a deadly explosion on a pipeline that supplies several refineries in Shandong province. In all, estimates of global refinery crude runs for 4Q13 have been slashed by 330 kb/d since last month's Report, to 76.3 mb/d, trimming annual growth to just 180 kb/d for the quarter. 

Growth in global crude runs is set to rebound in 1Q14, to 1.2 mb/d. Non-OECD runs are projected to increase by 1.2 mb/d, led by the Middle East and China, with smaller gains elsewhere. Runs in 'Other Asia' now look set to decline marginally, but from a high base, as the start-up of India's new Paradip refinery is delayed until 2Q14. OECD runs are expected to stabilise at 4Q13 levels, as higher US runs offset declines in Europe and the Pacific.

New Refining Capacity Squeezes Margins in 2013 and 2014 

Following a significant reduction in the global overhang in refinery capacity in 2012 and a subsequent improvement in margins, 2013 has once again seen refining profitability pressured by excess capacity. New projects and expansions were set to provide a net gain of 1.1 mb/d in global crude distillation capacity (CDU) for 2013 and a further 1.2 mb/d in 2014, compared with only 425 kb/d in 2012. While on the face of it, refinery capacity additions look in line with projected demand growth over 2013 and 2014, in practice an increasing share of demand is being met by supplies bypassing the refining system. As such, 2013 has seen simple margins plummet, and another round of refinery consolidation looks to be in the cards.

Non-OECD refining capacity additions totalled an estimated 1.5 mb/d of new capacity in 2013, offset by a net 315 kb/d reduction in the OECD. As has been the case in recent years, the majority of growth in 2013 came from non-OECD Asia which added 0.9 mb/d, led by China. Notable Chinese refinery projects included PetroChina's 200 kb/d Pengzhou refinery, Sinochem's 240 kb/d Quanzhou plant, expansions of Sinopec's Yangzi and Anquing plants and PetroChina's expansion of its Urumqi refinery. The bulk of the new units are being completed towards year-end and its impact will likely only be felt in early 2014.

There were no refinery additions in India in 2013, but the country will once again feature high on the capacity expansion list in 2014. International Oil Company's 300 kb/d Paradip refinery is expected to be commissioned in 2Q14. Nagarjuna's 120 kb/d Cuddalore refinery could also be completed before year-end, though its progress remains somewhat uncertain (the official plan is for the plant to be completed by April 2014). Included in our refinery expansion figures, a total 350 kb/d of condensate splitting capacity is planned in South Korea and Singapore for next year, to meet local demand from the petrochemical and aromatics business.

In Latin America, the first phase of Petrobras' Abreu e Lima refinery is expected to be completed by the end of next year. While Petrobras has decided to abandon its partnership with Venezuelan PdVSA to build the plant, the project is apparently 82% completed. The expansion of Colombia's Cartagena plant from 80 kb/d to 160 kb/d has been delayed until 2015, however, as workers' protests have stalled work this year.

Middle Eastern capacity was boosted more than 0.5 mb/d in 2013 by the completion of Satorp's 400 kb/d refinery in Jubail, and expansions of Iran's Arak and Lavan refineries. The full effect of the Jubail plant will only be felt in 2014, however, when output ramps up to full capacity. By end-2014, another mega-project, the 417 kb/d Ruwais refinery in the UAE, should be completed.

In all, 1.7 mb/d of new capacity is scheduled to be added in the non-OECD in 2014. Asia accounts for 59% of this, while the Middle East accounts for 26%. The OECD has so far committed to shut 0.5 mb/d of capacity, almost all of which is accounted for by Asia Oceania. Japanese refiners have until March 2014 to comply with a government ordinance to increase their upgrading ratio, which implies investing in upgrading units or shedding crude distillation capacity. By 2Q14, Japan will have reduced its primary refinery capacity by close to 1 mb/d since 2009. Also Australia will shut a second refinery in early 2014, Caltex's 124 kb/d Kurnell plant With the exception of Italy's 55 kb/d Mantova refinery, no further closures have been announced for Europe.

Looking at expected demand growth for 2014, currently forecast at 1.2 mb/d, and how supplies that will go to meet this demand are distributed, margins look set to remain under pressure next year, and more refinery closures look inevitable. In 2014, NGLs (for the most part not processed at refineries) will grow by 550 kb/d (60% of which is non-OPEC). Biofuels will add another 60 kb/d, after expanding 120 kb/d in 2013. Add in processing gains, and only 45% of projected demand will be sourced from refinery fuels.

Refining Margins

A contrasting picture prevailed across margins for refiners in US and non-US markets throughout November. After a mixed month in October, US margins experienced another surge in November spurred on by weakening domestic crude prices, which inflated cracks spreads. However, as cracks deteriorated in early-December on the back of strengthening crude prices, margins fell back. On the other hand, European refiners were hit as margins weakened after product prices fell and regional benchmark crude prices were supported by supply concerns. Elsewhere, Asian margins generally strengthened on the month following a number of regional refineries entering maintenance.

US margins improved across the board in November as cracks surged. Both refiners on the Gulf Coast and in the Midcontinent saw their margins firm by around $4/bbl on average. In the US Gulf, refiners saw a fall of the differentials of domestic crudes such as LLS, Maya and Mars against WTI as these grades participate in an ultra-competitive market. Additional support came from logistical problems in Florida, which drew in large volumes of gasoline from the Gulf Coast. In the Midcontinent, refiners taking Canadian crude and light, tight oil saw better margins than those taking other more-expensive grades.

In Europe the picture was very different as margins weakened on lower product prices. High distillate imports from the US put downward pressure on gasoil prices, outstripping falls in spot crude prices. On average, margins in Northwest Europe and the Mediterranean Basin inched down by $0.50/bbl. Furthermore, refiners running Urals were, on average, harder hit than those running Brent after the differentials of Urals versus Brent fell. Indeed, Urals in the Mediterranean moved to a rare premium over Brent on lower Russian exports.

Meanwhile in Singapore, margins improved by $2.10/bbl on average as product prices for light and middle distillates generally held up better than elsewhere amid supply issues stemming from regional refiners undergoing maintenance. However, it should also be noted that refiners running Tapis saw their margins improve over those running Dubai after the price of the former fell sharply. A further burden on regional refiners running fuel-oil-rich Dubai crude came from weakening fuel oil prices as land-based inventories in Singapore built.

OECD Refinery Throughput

OECD crude runs plunged to a 20-year low in October, averaging only 34.5 mb/d. Based on the latest data, October throughputs now look to have plummeted by almost 1.8 mb/d m-o-m, an even steeper drop than estimated in last month's Report. Refinery maintenance curbed runs in all regions and weak margins further cut into rates. Runs in OECD Americas and Europe each fell by close to 0.8 mb/d m-o-m, and by 220 kb/d in OECD Asia Oceania.

Despite continued weak margins in Europe and Asia in November, OECD runs are expected to recover from October lows through end-year as refiners conclude maintenance work and operators raise runs to meet increased winter demand and rebuild inventories. Indeed, weekly data for the US and Japan show sharply higher runs in November than in October. Euroilstock data released on 10 December suggest European runs rising by a preliminary 8.2% in November. Regional runs remained well below year-earlier levels, however, at an estimated 11.2 mb/d (down 890 kb/d y-o-y).

All in all, estimates of 4Q13 OECD runs have been lowered by 90 kb/d since last month's Report, to 36.3 mb/d. OECD throughputs now look set to contract by 705 kb/d y-o-y in the quarter, as growth in the US fails to offset a steep 1.0 mb/d decline in Europe. For 1Q14, OECD runs are forecast to edge up to 36.4 mb/d as European contractions ease, while North America continues to post year-on-year gains.

North American refinery runs plummeted by 770 kb/d in October to 17.9 mb/d. After four consecutive months of strong y-o-y gains, averaging 460 kb/d, runs in October barely surpassed year-earlier levels. Total runs for the region came in 250 kb/d lower than our previous forecast on the back of weaker-than-expected operations in Mexico, with PEMEX's Tula and Minititlán plants undergoing maintenance.

Despite its increasing import dependency for oil products, Mexico's state-run oil company Pemex has omitted the $11.6 billion Tula refinery project from its revised business plan issued on 1 November. While previous announcement had indicated the 250 kb/d grassroots refinery would be commissioned in 2017, we had excluded it from our Medium Term Oil Market Report 2013 released last May, due to lack of progress and uncertainty on completion dates. While officially the project has not been cancelled, PEMEX now is only planning to expand its existing Tula refinery by 40 kb/d by 2018. Additional downstream investments over the period will be focused on improving gasoline and diesel yields and quality. Mexican gasoline production averaged 440 kb/d so far this year (January-October), requiring imports of 345 kb/d to meet demand. PEMEX expects 53% of gasoline demand to be met by imports in 2018, up from 43% today.

US refinery runs declined by a sharp 680 kb/d on average from September to October and by more than 1.2 mb/d over a three-week period from late September to early October. Scheduled maintenance was more heavily concentrated in October this year, as opposed to previous years when refiners scaled back runs earlier in the season. A collapse in gasoline cracks and US refining margins over September and October amplified the effect of scheduled outages. US Gulf Coast gasoline cracks versus LLS fell from $22.30/bbl in early September to $9.70/bbl at the start of October and $2.75/bbl in early November.

Lower refinery output in October and continued high exports caused markets to tighten, underpinning a recovery in product cracks and margins through November. By end-November, US Gulf Coast gasoline cracks had surged to $20.98/bbl, while diesel and heating oil cracks surged to their highest level since 2008. US refiners took full advantage of the improved margins, and by end-month had reversed their run cuts, lifting throughputs by 680 kb/d on average compared with October. The week ending 29 November saw particularly strong gains: crude intake shot up 555 kb/d week-on-week, to 16.1 mb/d. The steepest monthly gains came from the US Gulf Coast which saw runs jump by 490 kb/d in November, though sharp gains also came from refiners in the Midcontinent, who raised utilisation rates to 95% on average.

US East Coast refinery runs also staged a recovery towards the end of November. Maintenance as Phillips66's 238 kb/d Bayway refinery, PBF's Philadelphia refinery and NuStar's Paulsboro plant had curbed output in October. In the Midcontinent, Citgo's Lemont refinery was still running at reduced rates after it was forced to shut a crude unit at the 174 kb/d plant in late October due to a fire. While the atmospheric section of the crude unit was restarted on 12 November, the company is reportedly running only light crude as the fire damaged a vacuum distillation unit. Lemont normally runs heavy, sour crudes. BP started a new coking unit at its Whiting, Indiana refinery in November. The 102 kb/d coker is a milestone in the $4 billion upgrade of the refinery, which will allow the plant to refine Canadian heavy oil, instead of light, sweet crudes.

As discussed in last month's Report, European refinery throughputs reached a new low in October. Final data were even weaker than anticipated, resulting in a 310 kb/d downward revision to preliminary estimates. At 10.3 mb/d, regional runs were at their lowest levels since March 1987. The exceptionally sharp decline in throughputs, totalling 1.8 mb/d from July through October, is almost unprecedented in scale (Only seen once since monthly data collection started in 1984. European throughputs decline by 1.95 mb/d from December 1988 to March 1989). While a heavy maintenance schedule helps explain the drop, it is only part of the story. Rising product imports have kept a check on both refinery margins and runs. Indian product exports to Europe surged to a record high in October, while US exports also surged to a near record. FSU distillate exports fell to 670 kb/d in October, from 750 kb/d in September, as heavy maintenance and low runs in Russia curbed product output.

Having contracted by a 1.3 mb/d in September, regional throughputs retreated further by a massive 1.6 mb/d year-on-year in October. The contraction in throughputs spanned the continent, with the steepest drops coming from Italy (-315 kb/d), Spain (-265 kb/d), Sweden (-255 kb/d), France (-210 kb/d), Belgium (-195 kb/d) and Germany (-195 kb/d).

Regional runs rebounded in November as scheduled maintenance outages eased, though poor margins continue to curb activity. Hellenic Petroleum confirmed in November that it had shut its Thessaloniki refinery in Greece due to poor economics; traders had been reported as saying that the plant had effectively been shut since September. Total's Antwerp refinery output remains affected by a deadly explosion in November, and several refiners have apparently prolonged maintenance shutdowns due to the weak margin environment. On the other hand, Spain's Cepsa temporarily restarted its 88 kb/d Tenerife refinery on 25 November to process stored crude. Unless economic conditions improves, however, the plant will only stay open for the three to four weeks it takes to process the crude before again halting operations until the situation improves.

In OECD Asia Oceania, refinery activity also hit a seasonal low in October, at 6.3 mb/d. Japanese refiners curbed runs by 290 kb/d from a month earlier, a dip partly offset by higher South Korean throughputs. In addition to planned maintenance, Japan's JX Nippon had to shut a 110 kb/d CDU at its Mizushima B plant for most of October after a fire broke out at a furnace connected to the unit. The unit was reportedly restarted at the end of the month, however.

As maintenance wound down in November, regional runs likely increased. Offline primary distillation capacity fell from an estimated 780 kb/d in October to 510 kb/d in November. Indeed, weekly data from the Petroleum Association of Japan show Japanese runs rising 400 kb/d in November. As a result, both Japanese and regional runs are set to post annual gains for November, with Japan up 260 kb/d from a low 2012 base, when Japanese activity levels were curbed by more extensive shutdowns.

Non-OECD Refinery Throughput

Non-OECD refinery throughput estimates for 4Q13 have been lowered by 240 kb/d since last month's Report, as weaker than expected rates in Other Asia over September and October were partly carried forward to the forecast months. A deadly explosion at a crude pipeline in China in November likely contributed to lower-than-expected runs in China for that month. Non-OECD refinery runs are nevertheless set to expand by 885 kb/d in 4Q13 from a year earlier, with growth dominated by Latin America and the Middle East. Latin American refinery runs were severely curtailed in the second half of 2012 due to an explosion at Venezuela's largest refinery, the 645 kb/d Amuay complex. Middle Eastern growth is largely accounted for by the ramping up of Saudi Arabia's new Jubail refinery. Growth is expected to accelerate in 1Q14, to 1.2 mb/d, as the 400 kb/d Jubail plant and new Chinese facilities ramp up to full capacity.

Chinese refineries processed 9.8 mb/d of crude in November, up 60 kb/d from October and 60 kb/d below a year earlier. Initial company plans had been to raise throughputs in November, but a pipeline explosion at the port of Hungdao in the Quindao district on 22 November likely curbed runs at plants serviced by the pipeline in Shandong province. Sinopec reportedly cut runs at its 200 kb/d Quindao refinery following the blast and utilisation rates at several other refineries were reduced as the accident forced four other pipelines to close for safety inspections. Reportedly, independent 'teapot' refiners lifted runs in the Shandong province in a bid to cover the shortfall of products. Company plans are to raise throughputs by around 400 kb/d in December.

Indian refinery runs in October slipped below year-earlier levels for the first time in 22 months, to 4.4 mb/d. The complete shutdown of IOC's Mathura refinery for maintenance and continued weak runs at HPCL's Vizag refinery since a fire in August contributed to the 100 kb/d monthly decline. A HPCL spokesperson said the Vizag refinery could return to full rates by early February. Essar shut a 360 kb/d CDU at its Vadiar refinery for 10 days in November, limiting gasoil exports. Shipping data suggest private refiners exported just over 1 mb/d of products in October, down from an all time high of 1.39 mb/d in September. India's total product exports fell 2.7% y-o-y to 1.6 mb/d in October, of which 735 kb/d was diesel. Looking ahead, MRPL is planning to shut a third of its 300 kb/d Mangalore refinery for 10 days in January as it commissions a delayed coking unit. The most recent indications are that IOCs 300 kb/d Paradip refinery will now be commissioned in April 2014. The start-up was most recently delayed by flood damage caused by a typhoon hitting the Indian coast in October.

In the FSU, Russian refinery intake rebounded sharply in November as maintenance was completed. Runs rose by 370 kb/d on average from October, to 5.6 mb/d, 20 kb/d higher than expected and just shy of year-earlier levels. Surgutneftegaz launched a 60 kb/d hydrocracker at its Kirishi refinery in October, which is expected to lift gasoil output by 50 kb/d when fully operational. The 140 kb/d Taneko refinery at Nizhnekamsk is also set to commission a 60 kb/d hydrocracker in early 2014, further boosting output of 10 ppm diesel. So far in 2013, gasoil exports have averaged 860 kb/d, up from 780 kb/d for the same period on 2012.

Expectations are that Russian export duties will change further before the end of this year. The new tax structure is expected to have implications for refinery profitability, and provide further incentives for refinery upgrades and product exports. Fuel oil export duties are set to increase from 66% of the crude oil duty to 75% in 2014 and 100% in 2015. Clean product duties will be reduced from 66% currently to 65% in 2014, 63% in 2015 and 61% in 2016. Gasoline and naphtha duties will remain at 90% of crude oil for the time being. As the fuel oil duties increase and gasoil duties decrease, complex refineries in Russia become more competitive than both their simpler counterparts in Russia and complex refineries in Europe. Some market observers note that the equalisation of fuel and crude oil duties could be delayed beyond 2015, as it would likely result in some refineries shutting down, if they have not yet upgraded.

Elsewhere in the region, Kazakh refinery intake rose 19.9% month-on-month in September, to 327 kb/d, as the Atyrau refinery raised runs following upgrading work. In the Ukraine, refinery throughputs also rose in October, to just shy of 100 kb/d, from 79 kb/d in September and 60 kb/d earlier in the year. The 80 kb/d Odessa refinery, which Ukrainian energy trader Vetek bought from Lukoil earlier in 2013,  resumed operations in late September after it was idled three years earlier on poor margins.

Latin American throughputs have come off their summer highs and are expected to average 4.7 mb/d for the remainder of 2013. Argentina processed 560 kb/d in September, down 6.6% from a year earlier. Runs have yet to recover after a storm shut the 189 kb/d La Plata plant in April. As a result of lower throughput rates and increasing demand, Argentinean diesel imports have surged by 42% in the first 10 months of this year compared with the same period in 2012. At the same time, Argentina's exports of biodiesel to the EU have plummeted after the EU raised taxes and implemented restrictions in retaliation for alleged dumping practices. Argentina has a biodiesel production capacity of 850 kt/y, of which 21% goes to the domestic market. In an attempt to reduce its diesel imports and to mitigate the effect of lower biodiesel exports to Europe, Argentina will increase its mandatory biodiesel blend in diesel to 9% on 1 January and 10% on 1 February 2014, from 8% currently.

Brazilian refinery runs fell to 1.9 mb/d in October, and a 16-month low. A fire at Petrobras' Presidente Getulio Vargas Refinery in Parana state at the end of November has also curbed our expectations for throughputs for the end of this year. The refinery, also known as Repar, has a capacity of 190 kb/d, or about 10% of total Brazilian crude distillation capacity. The fire damaged the plant's distillation unit, forcing the company to shut the refinery to repair the damage. Petrobras announced it expects output at the refinery to restart on 17 December.

In Venezuela, PDVSA is reportedly in talks with Valero to restart some units its refinery in the near-offshore Dutch island of Aruba. Valero halted operations at the Aruba plant in September 2012 on poor economics. The site is now used as an oil product terminal. PdVSA is reportedly looking to lease some units of the refinery to produce heavy naphtha to mix into its increasingly heavy crude output from the Orinoco belt, as well as some additional storage space to replace tanks lost in several fires in 2012. PdVSA is already leasing storage tanks in Aruba from Valero and paying for the space with crude sent directly to the US. Valero has imported an average of 174 kb/d of Venezuelan crude this year up until September, an increase of 60% compared with the same period in 2012.