- Oil fell for a third month straight in September with Brent breaking through $90/bbl in October, on abundant supply, slowing demand growth and a strong US dollar. Brent prices have fallen by over 20% since June, when turmoil in Iraq lifted prices to $116/bbl, and were last at a near four-year low of $88.70/bbl. NYMEX WTI was at $85.20/bbl.
- The forecast of global oil demand for 2014 has been revised 0.2 mb/d lower since last month's Report, to 92.4 mb/d, on reduced expectations of economic growth and the weak recent trend. Annual demand growth is now projected at 0.7 mb/d in 2014, rising tentatively to 1.1 mb/d in 2015, as the macroeconomic backdrop improves.
- Global supply rose by almost 910 kb/d in September to 93.8 mb/d, on higher OPEC and non-OPEC output. Compared with a year earlier, total supply stood 2.8 mb/d higher, as OPEC supply swung back to growth and amplified robust non-OPEC supply gains of 2.1 mb/d. Non-OPEC supply growth is expected to average 1.3 mb/d 2015.
- OPEC crude oil output surged to a 13-month high in September, led by Libya's continued recovery and higher Iraqi flows. Production rose 415 kb/d from August to 30.66 mb/d. A weaker demand outlook cut the 'call on OPEC crude and stock change' by 200 kb/d for 2015 to 29.3 mb/d. The 'call' declines seasonally by 1.5 mb/d from 4Q14 to 1Q15.
- Global refinery crude demand hit new highs in August, near 79 mb/d, with OECD runs leading the uptick. The onset of seasonal plant maintenance sees runs fall through October, taking global crude runs to 77.5 mb/d in 4Q14 from 78.1 mb/d in 3Q14, with year-on-year growth rising over the same period to 1.4 mb/d from 0.9 mb/d.
- OECD commercial total oil inventories built by 37.7 mb over August, to 2 698 mb, narrowing the five-year-average deficit to 38.1 mb, from 67.1 mb one month earlier. Preliminary data indicate that inventories rose counter-seasonally by 14.0 mb over September, led by a steep 11.7 mb build in middle distillates.
The oil selloff in perspective
Steep oil price drops since June - with Brent down to near four-year lows - are casting doubt on the sustainability of current high supply growth rates. A Saudi official recently suggested that the high cost of shale oil might put a floor under prices around $90/barrel. At the same time, the selloff is putting a spotlight on weaker-than-expected demand as a leading factor behind the drops. This may go some way to explain why concerns about the sustainability of non-OPEC supply growth has not kept speculators from turning bearish: non-commercial participants in the ICE futures market swung for the first time to net short Brent positions. In fact, recent price drops appear both supply and demand driven. On both counts, it may be hazardous to extrapolate from recent developments.
While the abrupt slowdown in demand growth in 2Q14 has come as a surprise, supply growth looms larger as a factor behind the recent easing of market balances and OECD stock builds. It jumped to a staggering 2.8 mb/d in September year-on-year, as OPEC output swung back to growth for the first time in about two years, compounding the impact of a 2.1-mb/d surge in non-OPEC. But September may turn out to be a high-water mark for supply, for reasons unrelated to prices. Annual growth in non-OPEC supply is forecast to slow in 4Q14 compared to 3Q14 on expected dips in the FSU and China. As to OPEC growth, it is led by Libya and Iraq, where political risk remains exceptionally high.
Nevertheless, further oil price drops would likely be needed for supply to take a hit - or for demand growth to get a lift. Close analysis of light, tight oil supply suggests that most of it remains profitable at $80/barrel Brent. While it has been noted that many producer countries face a high "fiscal breakeven" price, this is a misnomer. High budget needs might lead them to dig into reserves if oil revenues fall short without necessarily making low-cost oil production uneconomical. They might, under the right circumstances, fuel support for lower output targets, but producers, having recently ramped up, are not signalling an imminent cut. For those whose currency is not pegged to the US dollar, recent price drops have been partly offset by swings in foreign exchange rates: thus Russia's nominal export revenues in roubles inched up lately even as they plunged in dollar terms.
Demand growth, on the other hand, may have touched bottom. While economic forecasts have been trimmed, with the IMF lowering its outlook for the third time this year, the latter is sticking to its view of a continuing economic recovery - albeit a slower and more "brittle" one than anticipated. Projections of oil demand growth for 2014-15 have been reduced, but growth is still expected to gain momentum. Recent data suggest that may already have started to happen, thanks in part to narrowing OECD losses. Record-high refinery throughputs in August and improved margins worldwide suggest demand is perhaps not as dismal as it might appear.
Sweeping changes in trade flows are exacerbating perception of demand weakness. With North American refiners increasingly sourcing feedstock locally and those in Europe downsizing, exporters must compete in the same finite Asian markets. Having long paid a price 'premium', Asian importers enjoy newfound buying power. Producers that have relied on long-term contracts, pricing formulae and strict destination clauses may soon find out that this rigid pricing system no longer works in their favour. These shifting flows could be more transformative in the longer run than temporary market rebalancing.
- The forecast of global oil demand for 2014 has been revised downwards by 0.2 mb/d from last month's Report, to 92.4 mb/d. Annual demand growth for the year is now projected at 0.7 mb/d, 250 kb/d less than previously forecast, in line with reduced expectations of economic growth. For 2014 as a whole, contractions in OECD Europe and OECD Asia Oceania partly offset average growth of 1.0 mb/d for non-OECD economies.
- The demand estimate for 2Q14 has been revised down by 100 kb/d since last month's Report, to 91.5 mb/d. Annual demand growth for the quarter is now assessed at 335 kb/d, a low of more than four and a half years. Demand growth was particularly weak in OECD Europe, OECD Asia Oceania and China. The estimate for 3Q14 has also been reduced, by 350 kb/d, with particularly sharp corrections applied to the estimates of Japan, Mexico and France. Despite these downwards adjustments, global oil demand is projected to increase seasonally for 3Q14 to 93.0 mb/d, up by 480 kb/d on the year.
- Demand growth is forecast to pick up momentum in 4Q14, albeit modestly in line with the global economy. Specific economic concerns regarding Europe, China and Russia act as a drag on the forecast, removing 0.4 mb/d from the 4Q14 estimate compared to last month's Report, but year-on-year (y-o-y) growth still accelerates to 765 kb/d for 4Q14. Sharply lower oil prices, since 2Q14, provide some support to global oil demand, but overall the weak economic environment should prove dominant.
- Global oil demand is forecast to expand by 1.1 mb/d in 2015, to 93.5 mb/d, as the macroeconomic backdrop improves. Non-OECD economies lead the projected upside momentum, rising by 1.2 mb/d. OECD oil use, meanwhile, is projected to contract by 0.1 mb/d. Notable reductions to both the European and Chinese demand estimates curb the overall forecast uptick.
New data for August, coupled with reduced expectations of macroeconomic growth, have cut the estimate of 3Q14 demand to 93.0 mb/d, 350 kb/d less than forecast in last month's Report. Annual growth for the quarter is projected to inch up to 480 kb/d (or 0.5%), from 335 kb/d in 2Q14, when it sunk to a near four-and-a-half-year low. An actual contraction in global gasoil demand, coupled with sharp decelerations in LPG and naphtha, were the main factors behind 2Q14 weakness. The forecast of a modestly larger gain in 3Q14 than in 2Q14 is supported by gasoil swinging back to growth, while projected gains in LPG and the 'other products' category accelerate.
The International Monetary Fund (IMF) cut its forecast of economic growth for 2014 and 2015 for the third time this year, in its October World Economic Outlook. Global GDP growth forecasts have been reduced to 3.3% for 2014 (versus July's 3.4% estimate) and 3.8% (versus 4.0%) for 2015, led by revisions for Europe, China, Brazil and Russia. In light of this, the forecast of global oil demand for 4Q14 has been cut to 93.5 mb/d. Momentum is still expected to accelerate in 2015, both economically and in oil-demand terms, but at a reduced rate, with global oil demand growth of 1.1 mb/d now foreseen in 2015 compared to the previous +1.2 mb/d forecast.
Recent price declines have sparked speculation about their potentially supportive impact on demand. The price elasticity of oil demand tends to be asymmetric in nature: oil demand falls on high prices more easily than it expands on lower prices. Looking at the last five incidences of crude oil price declines of 15% or more over a four-month period (as occurred, at the time of going to press, June-through-October), only in one case (in 2006) was a noticeable uptick in demand seen. The immediate impact tends to be weakening demand reducing oil prices, as opposed to lower prices triggering additional deliveries, which is very much lagged. The dramatic price decline of late 2008/early 2009, for example, was not followed by a noticeable uptick in global oil demand growth until 2H09, many months after prices had started to rebound. Oil price changes will naturally affect demand differently depending on whether they are themselves supply- or demand-driven. The price drop in 2008 was overwhelmingly demand led, whereas recent declines appear to have been largely in response to rising supply. Nevertheless, recent price movements are not expected to significantly lift demand in the short term, especially since crude price drops are not fully carried through to retail product prices.
Empirical evidence suggests that macroeconomic factors (such as income gains) have a greater impact on demand than oil prices. Our demand model therefore gives macroeconomic factors a higher weighting than crude oil price assumptions, which do not directly feed-through to retail product prices, as taxes and subsidies blunt the impact of crude price changes, and are deemed to play a less significant role than economic growth in terms of influencing demand. These two exogenous variables are however, inter-related: lower prices, for most countries, reduce the cost of doing business and support economic growth, the converse being true for net oil exporters. At this point, all we can conclude with any clarity is that lower prices offer a cushion of sorts against an otherwise vulnerable macroeconomic backdrop.
The latest oil demand data show OECD deliveries contracted by 0.9% y-o-y in August, a relative improvement on July's 1.5% decline and close to the near -1% average decline rate that has taken hold this year. Demand for gasoline, non-road gasoil and residual fuel oil posted the steepest declines, as both OECD Asia Oceania and Europe saw sharp declines in gasoline deliveries while all OECD regions generally endured falling trends for non-road gasoil and residual fuel oil.
Bucking the overall OECD demand trend in August, deliveries in the OECD Americas rose by 0.9% y-o-y to 24.6 mb/d, preliminary estimates suggest. Strong, industrially driven gains in diesel and the petrochemical sector offset steep declines in Mexican deliveries of residual fuel oil on the back of additional power-sector use of natural gas.
Preliminary estimates of US demand have been revised upwards by 15 kb/d for August and 60 kb/d for September compared to last month's Report. Demand in August is estimated to have risen to around 19.5 mb/d, up 1.8% or 350 kb/d y-o-y, before falling seasonally to 19.1 mb/d in September. Uncertainty surrounding the US budget process, in the latter stages of 2013, inflated the y-o-y comparisons. Middle distillates accounted for the bulk of the revisions, compared to last month's Report, as US diesel demand has now demonstrated a clearly rising y-o-y trend for over a year.
Overall, US demand growth is expected to fall from 0.3% in 3Q14 to 0.2% in 4Q14, reflecting the effect of the unusually cold winter weather which boosted US gasoil demand in 4Q13. Roughly 35 kb/d has been trimmed from the 4Q14 outlook, since last month's Report, as the IMF cut its US growth outlook. Momentum then modestly gathers pace in 2015, supported by the predicted macroeconomic uptick.
The European oil demand forecast has been pared back sharply in recent months to reflect the now noticeably reduced macroeconomic outlook. Whereas back in July the IMF was predicting a +1.1% expansion in euro zone economic activity for 2014, accelerating to 1.5% in 2015, a more modest 0.8% increase is now envisaged in 2014, accelerating to 1.3% in 2015. The German, French and Italian economic outlooks were amongst the most heavily reduced, hence the downside bias in the adjustments made to our oil demand forecasts for those countries. European demand averaged about 13.4 mb/d in 2Q14, rising to 13.8 mb/d in 3Q14. Although both estimates are down on the year earlier, the forecast 3Q14 drop, at -1.2%, is considerably less than that seen in 2Q14, -3.0% y-o-y, as 2Q14 was likely a low-point for euro zone macroeconomic activity.
The majority of the big European economies were revised down in August, with estimates for France and Italy curbed by 50 kb/d and 45 kb/d, respectively. Much weaker gasoil demand underlies the now reduced French estimate of 1.7 mb/d in August, 3.6% down y-o-y. Compressing French gasoil demand, total industrial output fell by 1.4% y-o-y in July, a sixth consecutive month without growth. Coupled with now notably weaker expectations for the French economy in both 2014 (+0.4% according to the IMF's October report, versus the 0.7% forecast published in July) and 2015 (+1.0%, 1.4% previously), the demand outlook for 2014 as a whole has been pared back to 1.7 mb/d in 2014, down 3.9% on the year earlier (previously -2.9%). A further decline of 1.8% is then forecast for 2015, previously -1.5%. Similarly sharp declines are projected in Italian gasoil demand.
The Asian demand picture remains very much one of falling oil demand, down sharply on account of the declines seen in Japan recently. At an estimated 7.7 mb/d in 3Q14, the OECD Asia Oceania estimate is down by 3.6% on the year earlier, with big drops in the residual fuel oil and 'other products' categories leading the way, chiefly on account of additional Japanese power-sector switching out of oil and into cheaper alternatives such as coal.
Japan is forecast to see roughly 4.2 mb/d of oil products delivered in 2015, 2.8% less than in 2014, with particularly sharp declines envisaged in those fuels that are used to generate power, such as residual fuel oil and 'other products' (includes direct crude burn). Although in 2014 these categories also saw sharp declines, the downside momentum is forecast to continue in 2015 as the power sector likely sees additional substitution over to nuclear. Japan's Nuclear Regulation Authority (NRA) granted permission on 10 September for production to resume at Kyushu Electric's two nuclear reactors at its Sendai power plant. With a combined capacity of 1.78 gigawatts, the two reactors account for roughly one-twentieth of current Japanese nuclear capacity, and these two are likely to be the first of the 48 closed reactors to return to operation. A late-4Q14/early-1Q15 start date looks likely pending local and state authorisation.
Korean deliveries in August roughly matched our month earlier projections, at 2.4 mb/d. Not only was this a six-month high but it was also nearly 55 kb/d (or 2.4%) up on the year earlier. Particularly sharp gains reported in naphtha as previously alluded to cracker closures reversed and two new condensate splitters opened.
The latest global macroeconomic slowdown has noticeably curbed non-OECD oil demand, which is still growing but at a lessened trajectory. From a macroeconomic perspective, not only are potential non-OECD export flows to European countries dented by the recent economic malaise but also many non-OECD economies are themselves at the centre of the slowdown, as sluggish macroeconomic growth occurs in China, Brazil and Russia. Total non-OECD demand, at around 47.1 mb/d in 3Q14, is up 1.9% on the year earlier, a near halving on the previous five-year trend.
Looking forward, an acceleration is foreseen in 2015, up 2.6% to 47.9 mb/d, as petrochemical and transport sector demand are projected to reaccelerate once again. We do not however envisage a return to the heady earlier growth heights, as many of the economies in the region, but most notably China, now appear to have settled back onto less industrially-driven and hence, less energy intensive futures. The economies of Asia, Africa and the Middle East are forecast to lead this mildly accelerating growth momentum in 2015, more than offsetting slower growth in sanctions-hit Russia. The recent softening in oil prices, if it continues, could change the demand mix: as lower oil prices potentially dampen Middle Eastern and former Soviet Union coffers, reducing prospective oil demand, but have the opposite effect on net consuming regions such as Asia.
Latest estimates suggest that, despite the recent build-up in sanctions, Russian demand clambered up to an all-time high of 3.8 mb/d in August. Not only was this 115 kb/d (or 3.2%) up on the year earlier but it was also 55 kb/d above our prior projection. Strong gains in gasoline, jet/kerosene and residual fuel oil offset absolute declines in gasoil and naphtha. In contrast to the first eight months of the year, momentum should slow hereafter as underlying forecasts of macroeconomic momentum dim. The IMF's October outlook cites GDP growth of around 0.2% in 2014, which after the Federal State Statistical Service reported y-o-y gains of 0.9% in 1Q14 and 0.8% in 2Q14 implies a notable 2H14 slowdown. We are most pessimistic on gasoil demand going forward, as overall Russian exports are likely to be particularly harshly hit, curbing the potential industrial requirement. Overall, an expansion of around 1.6% is foreseen for total Russian oil deliveries, to 3.6 mb/d in 2014, a level that is forecast to be roughly maintained as our 2015 outlook has now been curtailed as both lower oil prices and sanctions dent Russian per capita income.
Preliminary estimates of Chinese demand, at 10.3 mb/d in August, exceeded prior expectations (+95 kb/d over the month earlier assessment), as strong y-o-y gains were seen in two of the key underlying contributors to apparent demand, i.e. refinery output and net import numbers. Gasoline and fuel oil led August's upside, as strong gains more than offset continued declines in gasoil. Rising by 345 kb/d (or 3.5%) on the year earlier, the higher than expected August estimate was still not enough to break the generally weak underlying trend and we maintain our 3Q14 demand forecast at roughly 10.3 mb/d, up 2.0% on the year earlier, making that five quarters of relatively weak demand growth.
Escalating macroeconomic worries curtail 4Q14 forecast. Having risen by an estimated 7.4% in 1Q14 and 7.5% in 2Q14, the Chinese economic outlook has since darkened. Business confidence gauges such as HSBC's Manufacturing Purchasing Managers' Index (PMI) fell back towards neutrality in August and September, having risen to a 16-month high in July. Industrial output growth meanwhile eased to a near six-year low and fixed asset investment growth tested three-year lows. Furthermore, power output, an oft-quoted barometer of underlying economic conditions fell in August, the first time such a y-o-y reversal has occurred in four years. Gasoil takes the brunt of the forecast 4Q14 hit, down 0.7% y-o-y, as projections of subdued construction activity continue to depress usage.
Providing some compensatory 2H14 support, however, government-controlled retail prices, for both diesel and gasoline, were cut in August and September, while car sales rose by 8.5% y-o-y in August. Additionally and despite growing concerns regarding the Chinese economy, it still created 9.7 million new jobs in the first 8 months of 2014, 100 000 more than the same period in 2013. Furthermore, digging into the worrisome August power numbers deeper, it becomes apparent that a y-o-y correction is no great surprise given the record heatwaves, and hence heightened power demand, that hit many Chinese cities in August 2013.
Overall, the downwardly revised 4Q14 Chinese oil demand estimate curbs the growth forecast for 2014, to 2.3% versus the previous 2.4% projection. Expectations of weaker, albeit still rising, economic growth have similarly trimmed the 2015 forecast, by 50 kb/d over last month's Report, to 10.6 mb/d. Reports that Sinopec has cancelled plans for a 40 kb/d ethylene cracker at its soon to be upgraded Yangzi refinery marginally dent the Chinese LPG demand outlook. The cracker, which was initially announced in 2011, has been cancelled as Sinopec's petrochemical unit has recently started to lose money. The move follows reports that Sinopec also put on hold plans to build another 40 kb/d ethylene cracker in Shanghai, following the closure of an old cracker at the facility in line with the government mandate to cease operations at small-scale units.
Heavy rains, which curbed the agricultural diesel use, contributed heavily to the relatively low Indian oil demand estimate for August at 3.6 mb/d. Not only was this 30 kb/d below last month's Report but it also underwrote the sharp month-on-month (m-o-m) decline in total Indian deliveries. Further downside pressure on diesel built as the near-two year policy of curbing diesel subsidies saw domestic prices in India draw closer to international prices (see Indian Diesel Pricing Reform). In light of lower-than-anticipated August demand, we have curbed the projected 2014 average to 3.9 mb/d, equivalent to a gain of 2.2% on the year. Tracking into 2015, momentum should accelerate to around 3%, taking average deliveries up to 4.0 mb/d, as the underlying macroeconomic backdrop also picks up speed. The IMF, in its October World Economic Outlook, cited that it expects Indian GDP growth in excess of 6% in 2015, well up on the 5.6% gain foreseen for 2014.
Indian Diesel Pricing Reform
In January 2013, the Indian government decided to raise diesel prices. The plan was to gradually add 0.5 Rupees (Rs) per month until domestic Indian diesel prices reached par with wholesale prices at the refinery-gate. This decision was driven by the fact that at the end of 2012, the difference between the refinery gate price for diesel and its retail price, the so-called under-recovery, stood at over 10 Rs/litre in Delhi (equivalent to 10 US cents, 31 December 2012). The total bill for these under-recoveries reached $1.6 billion in the fiscal year 2012-13, ending 31 March 2012, with diesel accounting for 57% of the total cost. Fuel prices vary throughout India due to the taxes and duties levied by the individual states, but Delhi prices are usually used when reporting changes in pricing policy.
Full liberalisation of diesel prices has long been considered politically challenging since diesel is used for a large number of economic activities beyond transport and impacts inflation. A sharp increase in diesel prices would have trickle-down effects on end-user prices, especially for food items, since diesel is used extensively for freight transport.
By May 2013, the under-recovery had come down to 3 Rs/litre, before rebounding again to over 10 Rs/litre in October 2013. This bounce was due to an unfortunate combination of a sharply depreciating exchange rate and the upward movement of international oil prices. Measured in rupees per barrel, the Indian crude oil basket price increased by almost 20% between January 2013 and September 2013, then traded at all-time highs through the rest of the year. This put the government in a difficult situation; despite regular monthly price increases, there was no visible improvement in the financial position of the oil marketing companies for their sale of diesel. Yet, consumers felt the pinch in their pocket as they were subject to 13 price raises during 2013 compared to four increases in 2012.
The Indian government has largely continued its policy of regularly increasing diesel prices, except for a brief period from 1 April to 12 May during which voting took place for the general elections. Under-recoveries then stood at 5.71 Rs/litre. In the fiscal year 2013-14, to 31 March 2014, the total cost of these under-recoveries had fallen to $1.4 billion, with diesel subsidies taking a 45% share of the bill.
The new government that was voted into power in May 2014 continued with the policy of gradually curbing diesel subsidies. On 1 July, the under-recovery stood at 3.4 Rs/litre; more or less the same as in May 2013. This year, however, the government benefited from the combination of falling international oil prices and a
more stable exchange rate vis-à-vis the US Dollar. Under-recoveries dropped to 1.33 Rs/litre on 1 August, moved back up to 1.78 Rs/litre on 15 August and almost reached parity on 1 September at 0.08 Rs/litre. On 1 October, under-recoveries on diesel were eliminated. In fact, for the first time diesel prices in Delhi are 1.9 Rs/litre higher than based on wholesale prices. The next price revision is expected for 15 October and it will be interesting to watch if retail prices for diesel will be reduced in line with wholesale prices.
By now, the Indian public has become accustomed to the regular increase in diesel and gasoline prices after they were liberalised in June 2010. Price changes have been implemented throughout the country without any protests. Adjusting retail diesel and gasoline prices regularly, either up or down, also reflects the maturation of the Indian economy/consumer and could become the guiding principle for other fuel prices.
If the government maintains its commitment to let gasoline and diesel prices fluctuate with international prices even under adverse conditions, this could potentially reawaken the interest of private companies towards entering the retail market. In the medium-term, this might even impact on the re-positioning of some of the export-oriented Indian refineries to supply the domestic market. Projections for the fiscal year 2014-15, to 31 March 2015, foresee the total under-recovery bill falling to $1.2 billion, with diesel accounting for around 31% of the total.
Total oil deliveries in Thailand fell on a y-o-y basis in July, the first dip in seven months, as a sharp contraction in industrial output suppressed demand for gasoil/diesel, residual fuel oil and 'other products', while ongoing political disruptions dampen jet/kerosene demand. Industrial production, as tracked by the Office of Industrial Economics, fell by 5.2% y-o-y in July, keeping the average 2014 demand forecast suppressed. A modest acceleration is then foreseen in 2015, up by 2.4% on the year earlier, as the worst of the recent economic slowdown is then widely expected to have passed. Having contracted in 1Q14 (-0.5% y-o-y) GDP growth returned in 2Q14 (+0.4%), with a further acceleration then foreseen in 2015.
At approximately 355 kb/d in July, Hong Kong oil demand edged down by 2.5% y-o-y, with notable weaknesses in the residual fuel oil. Lower fuel oil use reflected the subdued level of East Asian trade flows, which dent bunker fuel demand, as weaker economic conditions in China spread across the region and specifically lowered import flows into Hong Kong, which the Census and Statistics Department reported down 2.6% m-o-m in August. Forecasts for the 2H14, running into 2015, have been curbed somewhat to reflect not just this recent data weakness but also the additional downside risks to the economic outlook as political protests break out across Hong Kong.
Initial fears that Egyptian efforts to reduce energy price subsidies might struggle to hold (see OMR dated 11 July 2014), were somewhat exaggerated. Headlines such as "the hour of suffering has struck", carried in the popular Al-Masry al-Youm newspaper captured the sentiment of the day, but consumption has since remained remarkably resilient. The near-doubling of retail pump prices held firm, as it generally became accepted that some short-term pain was required to help fix Egypt's woes. The central problem is that a near-12% deficit, 2013-14, took foreign currency reserves down to critical lows, making purchases of many essential goods and services impossible. As higher retail gasoline prices coincided with relatively muted economic growth, Egyptian gasoline demand is forecast to see sub -2% growth in 2014. It will likely not be until 2015 that stronger gains ensue, and then the trajectory will be heavily dependent upon the strength of the anticipated economic recovery. On a related point, President Abdul Fattah al-Sisi has highlighted the development of nuclear power as a key aim of his administration, potentially curbing the trajectory of future oil use. The potential impact of such moves is, however, many years into the future.
The recent demand data for two of the biggest African consumers, Nigeria and South Africa, came out little changed on the year earlier as weak demand for industrial fuels restrains momentum. Weaker-than-previously foreseen April-July data curbed both 2Q14 and 3Q14 African estimates and accordingly dampened projected deliveries across 2014 as a whole. Momentum is forecast to accelerate in 2015, but the recent weakness has marginally curtailed the forecast uptick, as sentiment dims slightly. Furthermore, the IEA remains vigilant as to the possible risks that the Ebola virus might have on oil. Over four thousand people have already died from the disease, with Guinea, Sierra Leone and Liberia particularly heavily hit. The African forecast might have to be curtailed if Ebola dampens economic activity severely, particularly if trade/travel plans are reduced by restrictions on movements.
The Colombian forecast has been curtailed to reflect Venezuelan efforts to tighten its borders in an effort to stop the illegal smuggling of heavily subsidised petrol from Venezuela to Colombia. At 330 kb/d in 2014, the Colombian demand forecast has been trimmed since last month's Report, with a growth forecast of 2.2% now being carried compared to the previous 2.9% prediction. Momentum is still forecast to accelerate in 2015, up by 2.5% to 340 kb/d, but even this trend has been curbed as the previously assumed flow of incredibly cheap Venezuela products likely dries up somewhat.
Major construction plans across the Middle East continue to support the forecast for ongoing gains in Middle Eastern oil demand. For example, in Kuwait the cabinet has approved a new five-year development plan, due to commence in 2015, which includes ambitions to construct a one billion Kuwaiti Dinar (KD) metro system (equating to a capital investment of approximately $3.5 billion), some power and refinery projects, a KD8 billion ($28.2 billion) rail expansion, a new airport terminal and various other plans. Although the full extent of such plans is unlikely to materialise given recent history, with Middle East Economic Survey citing that only two-thirds of the previous budget was spent, even partial realisation of these projects would likely support robust gains in industrial fuel use, notably gasoil in the additional construction. In strong contrast, however, continued fighting in Iraq continues to dampen the Iraqi demand forecast, lowering both the 2H14 and 2015 forecasts as an end to the conflict likely sits outside our short-term forecasting horizon.
- Global supply rose by almost 910 kb/d in September to 93.8 mb/d. Compared with one year ago, total supply was 2.8 mb/d higher on the back of increased non-OPEC supply, which accounted for 2.1 mb/d of this growth.
- Total US liquids production continues to exceed Russian and Saudi Arabian oil supplies. However, the US still produces less crude oil than both of those countries. We estimate that total US total liquids output will be above 12.0 mb/d next month and will remain above that threshold through December 2015.
- Total OPEC supply in September posted the highest year-on-year increase in nearly two years - thanks mainly to Libya's comeback. OPEC crude production in September rose 600 kb/d y-o-y (year-on-year) after contracting an average 760 kb/d over the previous 12 months.
- OPEC crude output surged to a 13-month high in September, led by Libya's continued recovery and higher Iraqi flows. Production rose 415 kb/d from August to 30.66 mb/d. Downward revisions to global demand cut the 'call on OPEC crude and stock change' by 200 kb/d for 2015 to 29.3 mb/d. The latest data also indicate the 'call' on OPEC declines seasonally by 1.5 mb/d between 4Q14 and 1Q15.
- Oil's drop below $90/bbl has raised concern in OPEC, which is due to meet at the end of November. Kuwait has said a supply cut is unlikely and top exporter Saudi Arabia is signalling it may be willing to tolerate a period of lower prices. Saudi supply edged up by 50 kb/d in September to 9.73 mb/d and in early October, Riyadh cut formula prices to the Asian market for a fourth month running.
- September non-OPEC supply increased by 495 kb/d month-on-month to 56.7 mb/d as many producers ramped up following seasonal maintenance. The US and UK were the largest contributors to the rebound as both saw significant volumes return following a heavy upkeep in August.
All world oil supply data for September discussed in this report are IEA estimates. Estimates for OPEC countries, Alaska, Mexico and Russia are supported by preliminary September 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 approximately -200 kb/d to -400 kb/d for non-OPEC as a whole.
OPEC Crude Oil Supply
OPEC crude supply rose by 415 kb/d in September to 30.66 mb/d - a 13-month high - led by increases from Libya and Iraq. Libya's recovery helped boost total OPEC supply in September to the biggest y-o-y rise in nearly two years. OPEC's crude output in September rose 600 kb/d y-o-y after contracting an average 760 kb/d over the previous 12 months.
Despite growing instability, Libyan output rose for a third month, with the country's oil fields pumping 780 kb/d in September, up 250 kb/d versus the previous month. Flows were holding above 800 kb/d in early October. A rebound in Iraq's southern oil exports pushed supply towards the higher levels pumped in May before Islamist forces swept through the north of the country.
Supply from Saudi Arabia, OPEC's top producer, edged up 50 kb/d in September after a 330 kb/d drop in August. Brent's tumble below $90/bbl - its lowest level in nearly four years - has some in OPEC hinting at the need for output restraint. Kuwait has said a reduction is unlikely and Saudi Arabia is indicating it may be prepared to accept a period of lower prices. A senior Saudi adviser suggested a floor for Brent at around $90/bbl, due to the high cost of developing unconventional oil. The group is due to meet on 27 November to set policy for the first half of 2015.
Downward adjustments to our global demand forecast have cut the 'call' on OPEC by 300 kb/d in 4Q14 and for full year 2015 by 200 kb/d to 29.3 mb/d. Latest data indicate the 'call' at 28.8 mb/d in 1Q15 versus 30.3 mb/d in 4Q14. OPEC's 'effective' spare capacity was estimated at 3.05 mb/d in September compared with 3.07 mb/d in August, with Saudi Arabia holding nearly 90% of the surplus.
Output from Saudi Arabia edged up to 9.73 mb/d in September after a drop of 330 kb/d in August. Flows may ease in October due to slower seasonal demand for domestic crude burn. During July, Riyadh used 900 kb/d in power plants at home. In 4Q13, domestic crude burn dropped to an average 380 kb/d versus 720 kb/d in 3Q13.
There was no let-up in Saudi supply to global customers in September, according to tanker tracking data, with a modest pick up in shipments versus August. Riyadh appeared determined to defend its market share in the increasingly competitive Asian market - cutting its formula prices for a fourth consecutive month. State oil company Saudi Aramco reduced its benchmark Arab Light selling price for November loadings by $1.00/bbl versus October to a discount of $1.05/bbl to the Oman/Dubai average (see Prices).
Iran's crude production eased by 50 kb/d to 2.75 mb/d in September based on continuing reports of slower liftings to Asia. This suggests that the region's imports of Iranian crude during October could edge down from the slightly lower levels seen during August and September.
Preliminary figures show deliveries of Iranian crude to regular buyers in Asia fell below the nominal 1 mb/d limit set by Western powers under an interim deal to curb Iran's nuclear programme during both August and September. Total deliveries including condensate - ultra-light oil from Iran's South Pars gas project - held steady in September at roughly 1.1 mb/d versus August. But after stripping out condensate, imports of Iranian crude averaged 950 kb/d in September - up slightly on August deliveries of 890 kb/d. These figures are subject to revision.
Although purchases of Iranian crude tailed off in August and September, deliveries during the first nine months of 2014 - at 1.1 mb/d - were about 70 kb/d higher than the same period a year ago. Shipments of condensate averaged about 190 kb/d from January through September this year, up around 100 kb/d on the first nine months of 2013.
Top buyer China appears to have curbed imports again in September, according to initial data, with deliveries slipping to 290 kb/d versus 330 kb/d in August- sharply down on April's record 800 kb/d.
Iran's second biggest customer, India, took in 200 kb/d in September versus 270 kb/d in August. Japan raised its purchases by 50 kb/d to 250 kb/d, while deliveries into the UAE, which presumably are for re-export, rose by 65 kb/d to 85 kb/d. Import volumes are based on data submitted by OECD countries, non-OECD statistics from customs agencies, tanker movements and news reports.
Upon receipt of complete OECD data, it appears that Italy imported about 20 kb/d of Iranian crude in July - the first delivery since the import of 100 kb/d in June 2012.
Diplomats from the US, Iran and the European Union are meanwhile due to start talks on 14 October in Vienna that are aimed at speeding efforts to secure a deal to end a decade-long dispute over Tehran's nuclear programme by a 24 November deadline. Iranian and Western diplomats say significant gaps remain over the scope of Iran's permissible uranium enrichment activity.
Total production from Iraq, including volumes from the Kurdistan Regional Government (KRG), rose to 3.31 mb/d - close to the 3.42 mb/d pumped in May before Islamist forces began their advance through the north of the country. Much of the 205 kb/d increase in September was due to a rebound in Basra Light exports from Iraq's giant southern oil fields, which lie far from the insurgency.
Bad weather, loading glitches and scheduling delays had restricted Basra Light shipments from Iraq's southern Gulf terminal to around 2.4 mb/d throughout the summer. But at 2.53 mb/d, September Basra Light shipments were just shy of record rates of 2.58 mb/d achieved in May. In theory, Baghdad should be able to surpass that level. With the help of international oil companies, Iraq has installed production capacity of more than 3 mb/d in the south. But logistical bottlenecks ranging from storage tanks to pumps are likely to limit export potential to around 2.7 mb/d in the near term.
While the oil hub of Basra remains insulated from Islamic State militants for now, the insurgents' violent campaign has taken a toll on production in northern Iraq. The jihadists have turned the refinery at Baiji, Iraq's largest facility, into a battleground - forcing it off line and sharply reducing output by closing the major domestic outlet for crude from the giant Kirkuk field and its satellites. Additionally, exports of some 250 kb/d of northern Kirkuk crude have been shut in since early March after repeated sabotage by militants of the Baghdad-controlled Iraq-Turkey pipeline.
The launch of Western-led air strikes in August has, however, set back the Islamic State's smuggling operation for now (see Islamist Oil Operations Set Back in Iraq and Syria). And with the threat of militant attacks from neighbouring territory receding, international oil companies are sending back expatriate staff to the KRG region. Oil production had continued as normal even as the militants pushed towards the northern region in August. Output in September rose to about 380 kb/d versus around 360 kb/d in August. Shipments along the KRG's pipeline to Turkey rose to an average 180 kb/d in September versus 120 kb/d in August.
Shipments may climb higher this month as some additional oil is being pumped from Iraq's Kirkuk field and nearby Bai Hassan - now effectively controlled by the KRG and linked by a spur to the KRG pipeline. Around 20 tankers of Kurdish crude have loaded from Turkey's Mediterranean port of Ceyhan since the end of May, but the KRG is still finding it difficult to place its barrels, as Baghdad continues to contest the legality of the exports and warns off buyers. Iraq's central government says it has the sole right to market Iraqi crude.
Qatar's output eased marginally to 710 kb/d in September, while production from the UAE slipped 40 kb/d to 2.78 mb/d. A recovery in output from the Neutral Zone shared between Kuwait and Saudi Arabia helped push up Kuwaiti supply to 2.87 mb/d in September. Production in the Neutral Zone had sunk towards 350 kb/d in August, but bounced back to 400 kb/d in September.
Libya's production recovery continues apace even as the country descends further into chaos. Output climbed 250 kb/d from August to reach 780 kb/d - the highest monthly level since July 2013 - even as rival armed factions battle for control over the North African producer. Big gains have been made since the end, in early July, of a year-long oil port blockade by rebels seeking more regional autonomy. Production surged briefly to 925 kb/d in late September - an impressive level compared to June's average 240 kb/d - and was holding above 800 kb/d in early October.
With only minor disruptions to oil operations since the rebound began, buyers of Libyan crude have grown more confident in the reliability of supply. Exports rose to 600 kb/d in September - up about 100 kb/d on August - and were running at roughly 770 kb/d in early October. Expectations are that shipments to world markets will go higher, provided ports stay open, as production of 1 mb/d is within sight. Libya's National Oil Corp. had targeted output of 1 mb/d for early October. The country's oil fields were producing 1.4 mb/d in early 2013 before protests and civil unrest caused output to sink below 200 kb/d.
There are, however, nagging doubts over the sustainability of Libya's recovery because the country's political situation remains extremely unstable. Highlighting the fragility of the North African producer's comeback, output slipped back below 900 kb/d in early October due to a protest at the Sirte oil company by local residents demanding jobs. And in mid-September, the El Sharara oil field in the southwest of the country was closed for nearly a week after fierce fighting near Tripoli led NOC to close the Zawiya export terminal and refinery, which are both linked to El Sharara, Libya's biggest oil field.
In Algeria, OPEC's other North African producer, flows eased to 1.13 mb/d in September. Despite Algiers' best efforts to attract new exploration spending, international oil companies signed up for just four of 31 exploration licenses offered in its fourth licensing round at the end of September. Companies had shown scant interest in the previous three rounds.
Angolan crude output inched up 10 kb/d on August to 1.72 mb/d as flows from Total's 160 kb/d deepwater Cravo, Lirio, Orquidea and Violeta (CLOV) project closed in on peak capacity in September. Crude production from Nigeria, which had suffered from sporadic loading disruptions, bumped up 10 kb/d from August to 1.85 mb/d. Both of these countries have significant absolute amounts of offshore crude oil output that has high production costs (see A Glance at Breakeven Prices and World Oil Production).
Supply from Venezuela and Ecuador remained steady in September at a respective 2.48 mb/d and 560 kb/d.
Islamist Oil Operations Set Back in Iraq and Syria
A Western-led air campaign over Iraq and Syria has for now weakened the Islamic State's oil network and cut back a vital source of fuel and funding for its offensive. A lightning sweep across northern Iraq this summer left the radical al-Qaeda offshoot in control of nearly 70 kb/d of oil output, mostly in Iraq.
But US-led sorties over northern Iraq, which began in early August, and Syria - which started in late September - are frustrating the jihadists' ability to operate oil fields and refineries and disrupting a smuggling operation that had raked in daily revenue estimated at between $1 million and $3 million.
Sunni militants are now thought to control about 20 kb/d of production, with most of that going into black market trade, according to the latest estimates from Western and Iraqi officials. In addition to the air raids, the Kurdistan Regional Government (KRG) and Turkey are cracking down on smuggling, further constricting the militants' revenues. Smuggling from Iraqi oil fields, which may have risen to a peak of close to 30 kb/d, was at the time of writing estimated at less than 10 kb/d, say Western and Iraqi officials.
Much of that black market oil is moving into small refineries in the area, they say. The radical militants also reportedly stole as much as 3 million barrels of oil this summer by draining down pipelines, storage tanks and pumping stations in northern Iraq.
At its peak, most of the oil smuggled from Iraq was loaded from Ajeel - the Islamic State's prime asset - on tanker trucks and routed towards the northern Kurdistan region. Militants had been filling up about 120 tanker trucks a day - or close to 20 kb/d - from the field that lies 30 km from Tikrit, say Iraqi oil industry sources.
But the contraband operation was slowed to about 10 kb/d after Baghdad bombed Ajeel in early August, damaging the control room. Recent evidence suggests that only 10 trucks a day, or less than 2 kb/d have been loading.
The Islamist militants have also lost the Ain Zalah and Batma oil fields - captured during a push in August towards Kurdistan - after re-armed Kurdish Peshmerga and Iraqi forces reclaimed them. And the West's aerial bombing appears to have halted the jihadists' march towards Bai Hassan, one of the core producing fields in northern Iraq.
Despite these setbacks, Islamic State is believed to remain in control of the Iraqi oil fields of Qayara, Najma, Balad and Himreen - which between them pump about 10 kb/d. Operations, however, are being affected by continuous air strikes.
In Syria, the militants continue to control the Deir Az-Zour oil region, which includes the Omar field, Syria's largest. Latest estimates indicate that Islamic State-controlled output has fallen to less than 10 kb/d as a result of air strikes. A far more damaging loss was the destruction of dozens of "teapot" refineries by US, Saudi and Emirati airstrikes which has affected the militants' ability to fuel their vehicles and derive revenue from sales of diesel and gasoline.
With their oil assets diminished, the militants are determined to gain access to additional sources of fuel and revenue. To that end, they are intensifying attacks on Iraq's largest refinery in Baiji, where elite Iraqi forces are standing guard. The 270 kb/d facility has been offline since the militants' early June offensive. Similarly, in Syria where much of the militants' refining capacity has been destroyed, the country's two refineries near Banias and Homs that remain under the Assad government's control may be targeted in the near future.
Non-OPEC supply rose by 495 kb/d in September to 56.7 mb/d mainly due to the return of production following maintenance-related outages that spanned North America, the North Sea and the FSU. The US and UK were the largest contributors to the production rebound as both saw significant volumes return following heavy upkeep in August. In addition, the output of LTO rose apace in North Dakota and Texas. Russia also posted an increase of about 120 kb/d month-on-month (m-o-m), as Gazprom's condensate production recovered from seasonal declines in July and August and PSA operators boosted their output. Kazakhstan's oil supply also rose by about 55 kb/d during the month as the Tengiz field returned to normal operations following maintenance in August. Brazil continued its remarkable growth in supply that prevailed this summer at about 60 kb/d m-o-m following a brief respite in July.
Escalating violence in many areas continues to affect oil output, although the outages due to unrest increased only marginally. In Colombia, where two contractors who were working on the Caño Limón pipeline were killed, production was estimated at 990 kb/d, slightly lower compared with the August output. Violence in non-OPEC Middle East countries continues unabated, with new IS gains in Syria and the Houthi takeover of Sanaa.
Recent oil price declines have triggered speculation about potential shut-ins in some of the higher-cost production areas, notably US light, tight oil (LTO) plays. An analysis of production costs and breakeven prices reveals that only a small percentage of current production in the US is at risk should Brent prices drop to around $80 per barrel for an extended period of time. LTO nevertheless requires new drilling to an unparalleled degree in order to maintain production growth (see A Glance at Breakeven Prices and World Oil Production). In fact, a relatively small percentage of total global production has breakeven prices above $80 per barrel (nominal Brent), including conventional, unconventional and deep offshore. But it's not just the price that may affect drilling and production rates: cash flow constraints may trigger drilling cuts in the US, where companies are reported to have been outspending their cash flow.
US - September preliminary, Alaska actual, other states estimated: US crude oil production rose to 8.8 mb/d in September, an increase of about 215 kb/d m-o-m. Roughly half of the increase in crude oil output is due to the return of Alaska's production, which was curtailed by Prudhoe Bay maintenance the previous month. Alaska's crude oil production recovered to nearly 500 kb/d in September. LTO continues to bolster US production, rising an impressive 90 kb/d on the month. We expect that the Bakken LTO from North Dakota will average 1.1 mb/d in 4Q14, an increase of roughly 250 kb/d y-o-y. This forecast includes a winter-weather risk factor. Operational efficiencies from multi-well pad drilling are boosting Bakken output in the final quarter of the year as more than 70% of wells drilled in the formation are of the multi-well pad variety.
The Eagle Ford shale play in Texas is expected to produce 1.7 mb/d of LTO in 4Q14, nearly 500 kb/d higher than last year. This level of production will necessitate offsetting the steep natural declines at the formation by continuing to drill more wells and employing new recovery techniques. According to the US Energy Information Administration, horizontal drilling, hydraulic fracturing and the increased use of proppant (sand, ceramics or other material designed to keep a hydraulic fracture open) have increased initial production rates at the shale play, but are followed by a steeper drop in production in 2014 compared with previous years.
Gulf of Mexico (GOM) production averaged 1.3 mb/d in September, roughly unchanged m-o-m and we expect that production in the GOM will average at this level through the end of the forecast period. Natural declines are being offset by new projects, the latest of which started production in mid-September. Shell reported the start of new production at the Cardamom field offshore Louisiana, which is expected to peak at 50 kb/d. The Tubular Bells project, operated by Hess, also commenced production. Other new production expected to come online include Chevron's Jack-St. Malo project and Anadarko's Lucius among other developments.
Natural gas liquids (NGL) production, despite a slight seasonal decline to 2.9 mb/d in September, continues to grow apace and is about 230 kb/d higher than one year ago. We expect NGL production to average 2.9 mb/d in 2014 and 3.2 mb/d in 2015. NGL output has propelled the US to the top spot among the world's crude plus condensate plus NGLs producers. Total liquids output (excluding biofuels and processing gain) for September is estimated at almost 12.0 mb/d and the US continues to exceed Russia's and Saudi Arabia's production of total liquids. However, the US still produces less crude oil than both of those countries. We estimate that US total liquids production will be above 12.0 mb/d next month and remain above that threshold through December 2015.
The continued rise in production across the US and in the Lower 48 states in particular, has led to the first Alaskan crude oil export in ten years. A cargo of Alaskan North Slope crude, which is exempt from oil export restrictions, was sent to South Korea as traditional takers of this crude on the US West Coast are now supplied by Lower 48 and Canada's production. Meanwhile, the US Department of Commerce has approved 163 crude oil export licences so far in FY2014, including 74 licences for Canada. Most of these were re-export licences, allowing only crude oil of foreign origin to be shipped out. Other countries that were granted re-export licences include UK (12), South Korea (8), China (5), Germany (5) and Spain (5) among others.
Canada - September estimated: Canada's total liquids production averaged almost 4.0 mb/d in September, about 100 kb/d lower than the previous month, mainly because of lower synthetic crude output. Production of crude oil and condensate, including bitumen, averaged slightly higher during the month at 2.5 mb/d. The lower September production figure was due to maintenance that affected numerous projects during the month. The Foster Creek project was undergoing maintenance for two weeks during the month, which took out roughly 55 kb/d of production. Conoco's Surmont project is also undergoing a five-week turnaround, affecting another 30 kb/d of production during the month. Furthermore, the upgrader at the Horizon Oil Sands project in Fort McMurray in Alberta continued to undergo maintenance for most of the month while the Long Lake upgrader was also offline. Finally, the Hibernia crude oil platform (offshore Newfoundland) was offline for two days. Increases in Canada's LTO and bitumen were not enough to offset all these maintenance-related declines.
Overall production for 2014 is expected to average 4.1 mb/d in 2014 and 4.3 mb/d in 2015. The y-o-y increase will be boosted by additional in-situ capacity, including steam-assisted gravity drainage (SAGD) projects. Foster Creek Phase F was completed in September and will add roughly 30 kb/d of oil sands production by the end of the forecast period. We expect Phase F to produce 5 kb/d in 4Q14. Meanwhile Devon Canada has filed a request with the Alberta Energy Regulator to construct and operate a SAGD project in the Cold Lake oil sands area. The company's Jackfish Phase 3 has been completed and we estimate that production from this phase will average about 5 kb/d in 4Q14 but will ramp up to 35 kb/d by the end of the forecast period.
Mexico - August actual, September preliminary: Mexico's production in August posted a slight increase compared with the month prior although preliminary data show that declines during September more than offset the August gains. Final August data show that Mexico's crude oil production averaged 2.4 mb/d, rising roughly 30 kb/d on the month. The overall increase was boosted by rising m-o-m production at the Cantarell field as well as the Ku-Maloob-Zaap fields. Despite this uptick in production, these legacy fields will continue to see declining y-o-y output with even newer fields such as Ligero now in decline.
With production actuals already in for three quarters of this year, Mexico's crude oil output is expected to average 2.4 mb/d in 2014, while NGLs are expected to stay roughly flat at 350 kb/d. However, our crude oil projection is still higher than the new Pemex crude oil forecast of 2.35 mb/d. Our forecast is not adjusted for the recently revealed volume of water that may have been included in Pemex' production figures as Pemex has not yet reported revised historical data. According to CNH, the Mexican regulatory agency, water content could have been as high as 160 kb/d in the first six months of this year. The new 2014 Pemex production forecast does not seem commensurate with the first three quarters of data, unless there are revisions.
Mexico's government offered additional details on the opening of the upstream sector (see 'Mexico Energy Sector Reform Moves into Higher Gear' in the September 2014 Report) in late September, announcing that it will invite bids for 169 fields of which 60 are already producing in addition to seeking joint ventures for Pemex. The areas available for bidding include shale plays, shallow and deepwater projects and will be offered in staggered bids starting in November.
September estimates indicate that North Sea production has partly recovered from the August low as a number of maintenance projects came to a close. August production averaged 2.5 mb/d, the lowest monthly production in a year, while September rebounded to 2.7 mb/d with all of the North Sea producers indicating rising production compared with the previous month.
Norway - July actual, August preliminary: Production in August fell less than expected by about 80 kb/d to 1.8 mb/d mainly due to maintenance at Troll, Fram and Sklud fields. The Troll C platform outage lasted seven days. Norway's total liquids production is expected to average 1.9 mb/d in 2014, approximately flat compared with a year ago. Statoil began production from the Fram H-North (reserves of 10 mboe) and Svalin C (reserves of 30 mboe) fields in the North Sea in mid-September, which were developed under the company's fast-track field development program, which refers to standardised development for marginal fields.
UK - July actual, August preliminary: Oil output in August slumped to a record low of 525 kb/d due to an extended Forties outage and production problems at the Buzzard field. Estimates indicate that UK's production recovered somewhat during September, rising to about 720 kb/d. Buzzard outages continued into September but by the last week of the month the field was largely back online.
BFOE loadings are scheduled at 852 kb/d, slightly lower than the September revised loadings of 860 kb/d. Brent and Ekofisk volumes are expected to be lower than in September, with Brent loading at below 100 kb/d for the month. Although much of the production issues related to Buzzard have been resolved, we expect that BFOE production volumes will average about 910 kb/d in October, 70 kb/d higher m-o-m.
A Glance at Breakeven Prices and World Oil Production
With the recent decline of benchmark crude oil prices, the issue of high-cost production facing curtailment is again in the news. Has the outlook for prices changed of late such that new projects may not go forward, or might some current production be shut off if prices continue to decline, or reach a new equilibrium below the average of about $110/bbl for Brent in the period of 2011 through 2H14? Of course, new project decisions are made on the basis of expected rate of return over the life of the project, with oil prices but one (albeit a very important one) of many factors. Hence, producer companies must forecast, either implicitly or explicitly, oil prices in these decisions.
The IEA does not forecast short-term or medium-term oil prices, but we do look at current price levels to see whether there are any implications for production; to determine if any production types and locations would require a relatively high oil prices in order to sustain a positive rate of return. The price point at which net return turns positive (a positive net present value for the asset in question) is known as the breakeven price. Of course, for projects already in operation, considerations are more complicated. Development costs may already be paid for, such that marginal costs are the key consideration. In addition, there is the time factor: how long can a project sustain unprofitability before a decision is made to shut it off. This is also affected by expectations of future prices - in other words, whether prices are expected to rebound sufficiently within a feasible time in order to restore profitability.
Deepwater, oil sands, and oil from North American shale plays (light, tight oil) are widely considered to be those types of crude oil production most sensitive to lower prices. In other words, these projects have a higher "hurdle-rate" price. In 2008-09, when prices collapsed due to the global recession, capital expenditures on Canadian oil sands, for example, fell from $21 billion in 2008 to $14 billion in 2009, a 33% decline (Statistics Canada). With benchmark Brent at slightly below $90/bbl, and acknowledging that many crude grades receive a lower price because of quality issues and/or being stranded in North America because of infrastructure and regulatory issues, how much of these types of production needs an average price in excess $80/bbl (nominal Brent in a given time interval) in order to break even?
In utilising Rystad Energy data, one can see that in terms of production with breakevens exceeding $80/bbl, Canadian synthetics projects have the highest percentage of production of the types examined here (about 25%) that would fall into a negative net present value if there were to be an extended period of prices below that level. Canadian mined bitumen, of which there is currently only one project (Kearl 1), has a breakeven below $80/bbl. Canadian in-situ projects have an average lower than that mined bitumen, with the exception of a very small amount of current output that has a breakeven above $80/bbl. Regardless of the type of oil sands project, production costs are quite predictable, as the amount of wells on an in-situ steam-assisted gravity drainage (SAGD) project or the shovels of mined oil sands needed to generate the desired output level is quite constant. For SAGD projects, the intention is to maintain investment levels to fully take advantage of capacity of the steam plants; for synthetics projects the capacity of the upgrading units is the approximate desired plateau production level. The lack of decline over the lifetime of these projects and their predictable output has made them attractive investments despite higher costs. Still, new projects will have to make a careful forecast of oil prices, taking into account the findings of the Canadian Energy Research Institute: new mined bitumen projects will require $100/bbl to breakeven, whereas new SAGD projects will need $85/bbl. Canadian oil sands investment bank Peter & Co., however, has estimated that the breakeven on new SAGD bitumen projects is $75/bbl. Some planned projects with high costs have been cancelled or postponed of late, such as Statoil's Corner project. Producers must also be concerned about transport, as there is very limited access to markets beyond North America with current infrastructure.
Synthetics projects would presumably require an even higher price, but there are no new synthetics projects under construction or planned, and only one new mined bitumen project planned, as Canadian producers have shifted into in-situ bitumen projects. Costs on these do vary significantly, with some current projects having breakeven prices slightly below $60/bbl at the low end. Interestingly, breakeven prices on the four Venezuelan upgrading projects (which take ultra-heavy crude, not just bitumen, for upgrading into synthetics) are lower than most Canadian oil sands projects.
As discussed in Medium‐Term Oil Market Report 2014, a relatively small amount of US LTO production faces a breakeven price of higher than $80/bbl – just slightly more than 4% for this year. Technological and organisational improvements that have enabled faster drilling rates, greater drilling density, and higher new‐well production have all been important to maintaining production in the face of increasingly‐steep decline curves (such that there is almost none of the plateau period associated with conventional oil fields). These steep decline curves mean that production can fall quickly in the absence of new drilling. In other words, because LTO wells go into decline within a few months of coming online, no currently-producing wells need to be turned off in order for a decline to be observed in fairly short order. When drilling was impeded due to weather conditions on the Bakken shale play in the winter of 2013-14, oil production declined and then struggled to rise back up to the previous level for several months. Weather can halt drilling no matter the price level, of course, whereas lower price levels (or lower expected price levels) will affect new drilling more selectively. Likewise, companies' hedging strategies will affect their sensitivity to price changes. Nevertheless, little current LTO production with a breakeven above $80/bbl does not indicate future short-term production prospects the same way as for other types of crude oil production because of the need for new drilling. The producing companies will have to examine whether the new wells need higher prices to break even, and there is a range of speculation whether even $10/bbl lower prices in the future would significantly affect drilling rates, and hence, growth rates.
Deepwater production is more "conventional" than the previously-discussed items in terms of its production profile and response to price changes, though it too tends to be higher cost, and observed decline rates are faster than conventional onshore production. Higher costs come from the challenging operating environment - average exploration capex, capex, and opex costs for onshore conventional were about $20/bbl in 2013, whereas deepwater (>125 metres) had corresponding costs of about $56/bbl. Higher costs translate into higher breakeven prices on average. Operating companies tend to design projects to extract the oil from deepwater fields at higher rates because of financial factors arising from higher costs and longer lead times from discovery to the start of commercial production, such that there is a need to repay investments as quickly as possible. These higher initial production rates tend to lead to more rapid declines. This has important implications when considering the lifetime return of the project.
As noted, some 8% of deepwater crude oil production is adjudged to require a breakeven of $80/bbl or higher. For ultra-deepwater alone (>1500 metres), the results are, perhaps surprisingly, that very little of current output from those depths, less than 1%, requires such a breakeven price. Over 80% of ultra-deepwater production is offshore Brazil and in the US GOM, where greater cost discipline has occurred on these cutting- edge projects, and relatively few have reached the latter stages of decline. Places where significant production with breakevens above$80/bbl include deepwater offshore Angola, Brazil, Norway, and the UK.
Overall, about 8% of these types of production requires Brent above $80/bbl to breakeven, totalling some 1.05 mb/d. This is about 1.1% of global liquids production. It must be pointed out, however, that there is sprinkling of high-breakeven crude oil projects throughout the world, though some of these are due in part to high government take. Places as diverse as onshore China (some 135 kb/d), Indonesia (onshore and shallow-water, some 150 kb/d), offshore shallow-water Malaysia (some 85 kb/d), Nigeria (onshore and shallow offshore, some 200 kb/d), conventional onshore US (some 80 kb/d), shallow-water UK (some 75 kb/d), and onshore conventional Russia (some 160 kb/d) have significant amounts of high-breakeven production. All told, roughly 2.6 mb/d of world crude oil production comes from projects with a breakeven price in excess of $80/bbl.
Brazil - August actual: Following a brief slowdown in Brazil's production growth in July, August crude oil production rose by about 60 kb/d to above 2.3 mb/d. As was the case in recent months, production was boosted by increases in Roncador and Lula output, with newly installed facilities providing continued growth support. Eleven new wells were connected during the month and production rose as Roncador P-55 and P-58 on the Parque das Baleias complex increased output, along with an increase in output at the Cidade de Paraty FPSO. Pre-salt production averaged a record-high of 533 kb/d. These increases were enough to offset maintenance related outages during the month, which averaged roughly 30 kb/d. Brazil's crude oil production is expected to average 2.2 mb/d in 2014 and rise to 2.4 mb/d in 2015. Chevron plans on resuming its drilling operations at the Frade field near the end of our forecast period. This would be the first time that Chevron has drilled at the field since the March 2012 drilling accident that resulted in oil seepage and subsequent suspension of Chevron's activities at the field.
Brazil's National Petroleum Agency (ANP) announced that it expects to publish new rules on oil field development by the end of this year. The new rules will address royalty payments and define what constitutes an oilfield, among other issues. The oilfield definition in particular is important, as this will determine the amount of royalties and taxes a developer will have to pay. Separate oil fields that produce from the same reservoir trigger a special tax and royalty rate. ANP and Petrobras were embroiled in a dispute over the Lula, Cernambi and Parque des Baleias projects and whether these fields should be delineated into multiple areas. Petrobras, the most indebted publicly-traded company in the world, is particularly sensitive to higher taxes and royalties as the company could be liable for more than $20 billion in payments to various layers of government over the life of the development should Lula remain defined as one field.
China - August actual: China's oil output inched up by less than 35 kb/d on the month to 4.1 mb/d, with production continuing to hover at low levels. Nearly all of China's production is crude oil, though the crude oil figure includes roughly 90 kb/d of field condensate. The increase in August was not sufficient to offset a mysterious 175-kb/d decline in July. Production at China's largest oil fields, Daqing and Changqing, was roughly unchanged compared with last month, but offshore oil production saw an increase of roughly 30 kb/d since July. Meanwhile, CNOOC announced that its Wenchang 13-6 oil field became operational in late August/early September. The field is located in the South China Sea and has a total of 12 wells. Five wells have commenced production during the initial start-up. China's oil production is expected to remain flat y-o-y at 4.2 mb/d in 2014.
Former Soviet Union
Russia - August actual, September preliminary: Russia's September total liquids production averaged more than 10.9 mb/d, roughly 120 kb/d higher m-o-m and the highest since January. The rebound in production occurred amid a continuing decrease in maintenance projects. However, average 3Q14 production was roughly 20 kb/d lower than 3Q13, the first time such a y-o-y decline has occurred since 4Q08. We expect that 4Q14 will also see a fall in production compared with one year prior, although we still expect total 2014 output to be higher than 2013.
The latest round of sanctions by the US and EU, announced in mid-September, target a number of Russian companies and prohibit US and EU companies from exporting goods, services or technology in support of exploration or production of Russia's deepwater, Arctic offshore or shale projects. The Russian companies targeted by the technology sanctions include Gazprom, Lukoil and Rosneft among others, while Gazprom Neft, Rosneft, Novatek and Transneft were targeted by sanctions related to financing and equipment for deepwater, Arctic and shale oil projects. The new measures also include a ban on international financing over 30 days to Russia's energy companies. Following the implementation of new sanctions, Total announced that it is postponing its joint venture with Lukoil for tight oil development in Western Siberia due to the sanctions. ExxonMobil also suspended its participation in a joint venture with Rosneft after drilling the University well in Kara Sea and hitting first oil. ExxonMobil is also suspending joint work with Rosneft in the Bazhenov oil shale play.
Although western companies were quick to align their operations in Russia with US and EU sanctions, some oilfield service companies are finding ways to remain active in what is a very profitable and attractive environment for many of them. These "workarounds" include registering a Russia-based subsidiary or affiliate or replacing all US and EU workers with Russians. In one such manoeuvre, a service company reportedly withdrew all of its US and EU employees and replaced them with Russian nationals, continuing its work with Rosneft, Lukoil and Gazprom Neft.
Russia's short-term production is not likely to sustain an immediate impact from the latest sanctions but they may severely hamper Russia's ability to revitalise its oil sector and offset declines in legacy fields and ensure oil production growth past the forecast period. Total liquids production in 2015 is projected to average 10.9 mb/d, a decline y-o-y due to underlying trends that are made more difficult to overcome in the current environment.
FSU net exports plunged to 8.7 mb/d in August, their lowest level since November 2008. The 630 kb/d monthly drop was led by crude exports which fell to 5.9 mb/d (-390 kb/d m-o-m) after shipments from outside Russia were curtailed. The largest monthly decreases were noted on the BTC pipeline which dropped to 680 kb/d (-70 kb/d). Flows through the Kenkiyak - Alashankou pipeline dropped by 80 kb/d to 210 kb/d, although this was due to a fall in Kazakh volumes rather than Russian transit shipments which remained at close to 140 kb/d. Meanwhile, CPC volumes fell by 40 kb/d to 860 kb/d but remain comfortably above year ago levels. Russian exports remained seasonally low, as high domestic demand for crude from Russian refiners (Russian refinery throughputs breached 6.0 mb/d for the first time in August) reduced the volumes available to be delivered abroad (see Refining).
Despite record-high Russian refinery throughputs, refined product exports dropped by 240 kb/d m-o-m to 2.9 mb/d in August. Nonetheless, both gasoil and light distillates exports remained above year-earlier levels while fuel oil shipments are now below year-ago levels. This follows the commissioning of a number of new desulphurisation units at a number of Russian refineries aimed at increasing the production of high value motor fuels compliant with western environmental legislation.
Export infrastructure is currently catching up with the increased production of these fuels and consequently Baltic ports are currently undergoing a rebalancing of product shipments. Following the conversion of Primorsk to a 'ULSD only' terminal the beginning of 2014, Russian diesel exports are being exported via the terminal at the expense of other terminals. However, a number of non-Russian terminals have plans in place to respond to the extra volumes of high quality fuel and to win business back from Russian ports. Notably, the Latvian port of Ventspils, which saw gasoil shipments drop by 25% y-o-y over the summer, is converting a product pipeline supplying the port to take ULSD. Upon the project's completion in 2015, the terminal should become more competitive, especially during mid-winter when Russian Baltic ports typically ice over. Nonetheless, these terminals will face an uphill task as gasoil shipments via Primorsk are likely to maintain their impressive growth over the next couple of years. Reports suggest that one of the BPS-1 crude pipelines feeding the post could be switched to carry ULSD, which could see exports hitting 470 kb/d in 2016 from the 210 kb/d currently delivered.
- OECD commercial total oil inventories surged by 37.7 mb over August, to 2 698 mb. The deficit of inventories versus five-year-average levels narrowed to 38.1 mb at end-August from 67.1 mb one month earlier. The deficit is now at its narrowest since September 2013.
- Commercial inventories of refined products covered 30.5 days of forward demand at end-August, 0.9 days above end-July after stocks of 'other products' and middle distillates built by a combined 41.3 mb. Crude oil stocks declined by 9.7 mb, in line with seasonal trends.
- Preliminary data indicate that inventories rose counter-seasonally by 14.0 mb over September after middle distillates built by a steep 11.7 mb.
OECD Inventory Position at End-August and Revisions to Preliminary Data
OECD commercial inventories continued to rebuild in August, surging by 37.7 mb to 2 698 mb at end-month. While inventories continue to lag average levels, at end-August the deficit shrank to 38.1 mb, its narrowest since September 2013 and a significant decrease from 67.1 mb at end-July.
Surging refined products holdings (+45.2 mb) pushed total stocks higher as OECD refinery runs continued on their upward trajectory, posting a 600 kb/d month-on-month rise in August. 'Other products' and middle distillates led the build. As with July, 'other products' inventories continued to increase at a faster clip than in 2013 and by end-August stood at a record level of close to 390 mb. Despite the steep monthly rise, the restocking of middle distillates remains underwhelming with only 9 mb added since end-2013. At end-August, middle distillates remained 11.6 mb and 53.8 mb below a year-ago and the five-year average, respectively. By end-month, refined products covered 30.5 days of forward demand, 0.9 days above end-July.
The increased refinery activity saw crude oil stocks drawn down by nearly 10 mb. In Europe stocks dropped (-7.8 mb) from their previously lofty levels while in OECD Americas they retreated by 4.6 mb as, despite a minor monthly decrease, runs there remained 300 kb/d above year-ago levels. Some offset was provided by OECD Asia Oceania (+2.8 mb) where Japanese and Korean crude imports posted month-on-month gains, outpacing rising runs.
Following the receipt of more complete data, July OECD total oil stocks are now seen 10.3 mb lower than published in last month's Report. The downward revision was centred on OECD Europe after downward adjustments to Germany (-11.8 mb), the Netherlands (-7.7 mb), Italy (-3.9 mb) and the UK (-3.1 mb). Therefore the region's 14.6 mb July stock build published in last month's Report is now seen as a steep 7.8 mb draw. Some offset was provided by 11.3 mb and 6.0 mb upward adjustments to OECD Americas and OECD Asia Oceania, respectively. Taking into account the additional 4.5 mb downwards revision to June data, the July OECD inventory build has been tempered to 9.7 mb, shallower than the 15.5 mb presented in last month's Report.
Preliminary data indicate that inventories rose by 14.0 mb over September. Since this was in sharp contrast to the 8.8 mb five-year average draw, the deficit of stocks to average levels more than halved to 15.4 mb, its smallest since April 2013. Refined products (+11.9 mb) led stocks higher, with almost all of the build accounted for by middle distillates (+11.7 mb) which increased counter-seasonally. Since this continued recent builds, the deficit of middle distillates to average levels now stands at 32 mb, its slimmest in 12 months. Crude oil stocks remained stable, inching up by 0.2 mb over the month. The bulk of the build in total oil was centred on the OECD Americas (+11.7 mb) while stocks in OECD Europe and OECD Asia Oceania inched up by 1.7 mb and 0.7 mb, respectively. If these data are confirmed by subsequent, more complete data, 3Q14 OECD inventories will have risen by 61.4 mb (670 kb/d) thereby bringing the total build since the turn of the year to 145 mb.
Recent OECD Industry Stock Changes
Commercial oil inventories in OECD Americas continued their upward trajectory, adding 9.8 mb in August. Persistently high refinery activity saw crude oil, NGLs and other feedstocks draw by a combined 5.7 mb which was more than offset by a 15.5 mb build in refined products. Despite regional crude oil holdings being drawn by 23 mb since their recent May peak, they still remain 4 mb and 22 mb above last year and five-year average, respectively, amid high domestic production. Refined products covered 29.4 days at end-August, 0.7 days above end-July.
The bulk of the 15.5 mb increase in refined products came from 'other products' (+14.8 mb), the majority of which are processed at NGL processing plants which fall outside the refining system. The seasonal replenishment of LPG and ethane inventories continues to exceed the levels posted in previous years amid healthy year-on-year NGL production growth in the US. At end-August, regional 'other products' holdings stood at a record 226 mb, 23 mb above twelve months earlier.
Stripping out the 'other products' category, refined product stocks only added 0.6 mb in August. This likely reflects in part high levels of product exports. Indeed, preliminary weekly trade data from the US Energy Information Administration (EIA) suggest that exports of refined products (net of propane) hit 3.1 mb/d in August, 300 kb/d above a year-ago, the same yearly increase seen in refinery output.
Preliminary weekly data from the EIA indicate that commercial total oil inventories rose by 11.7 mb in September, nearly twice the 5.9 mb five-year average build for the month. Refined products (+10.8 mb) led total stocks higher. In contrast to previous months, the build was not concentrated in 'other products', stocks of which gained only 3.5 mb m-o-m. Middle distillates holdings climbed by 8.5 mb, considerably steeper than the 0.3 mb five-year average build. This saw US middle distillate holdings move above year-ago levels for the first time in 2014 while the deficit versus seasonal levels narrowed to 24.1 mb at end-September from 31 mb one month earlier. Crude oil stocks remained stable (-0.1 mb m-o-m) after a draw in PADD 3 was counter-balanced by builds in PADDs 2 and 5.
OECD European oil stocks posted a 10.9 mb increase in August as a steep 16.7 mb rise in refined products more-than-offset a 7.8 mb fall in crude oil. A 500 kb/d hike in refinery runs drew crude stocks as refiners took advantage of margins reaching their highest level in 18 months. All refined product categories posted builds to leave refined product cover at 36.8 days, 1.2 days above end-July.
With the contango in the ICE gasoil contract steepening over August, stockholders added to their inventories with middle distillates posting their second consecutive monthly build (+8.6 mb) to sit at 262 mb by month-end, level with a year earlier but 20 mb below the five-year average. With prompt gasoil prices sitting at their lowest levels since 2012, German residential consumers continued to restock, with tank fill reaching 63% of capacity (+4% m-o-m), its highest level for the time of year since 2009. Meanwhile, motor gasoline inventories built counter-seasonally (+4.4 mb) amid reports of low transatlantic exports while 'other products' and fuel oil increased by 3.3 mb and 0.5 mb, respectively.
Preliminary data from Euroilstocks indicate that European inventories rose counter-seasonally by 1.7 mb during September after crude stocks posted a 4.2 mb build as regional runs dropped by 260 kb/d. Refined products drew by 2.6 mb, led by fuel oil which fell by 3.6 mb amid reports of an open arbitrage to ship product to Asia. Middle distillates (+0.5 mb) edged up counter-seasonally with the contango in European gasoil markets deepening over the month. By end-September, the deficit of middle distillates to average levels had narrowed to 10.4 mb, the smallest for two years.
OECD Asia Oceania
Inventories in OECD Asia Oceania climbed by a steep 17 mb in the wake of a 13 mb surge in refined product inventories. Regional crude oil stocks posted a surprise 2.8 mb build despite increases in Japanese and Korean throughputs. On the product side, middle distillate inventories posted the most eye-catching build (+9.5 mb), steeper than the 4.5 mb five-year average build. This saw middle distillate stocks surge back into the seasonal range to stand slightly below last year and the five-year average. Both fuel oil (+1.2 mb) and 'other products' (+3.6 mb) posted builds while motor gasoline dropped seasonally by 1.3 mb. All told, refined product cover increased by 1 day on the month to 22.4 days at end-August.
According to preliminary weekly data from the Petroleum Association of Japan (PAJ), Japanese commercial oil inventories inched up by 0.7 mb during September after a 3.0 mb drop in combined stocks of crude oil, NGLs and feedstocks was more-than-offset by a 3.7 mb rise in refined products. Middle distillates continued their recent builds, adding 2.7 mb, considerably steeper than the 0.4 mb five-year average build. By end month, the deficit of Japanese middle distillate inventories versus average levels had more than halved to 1.5 mb from 3.8 mb at end-August.
Recent Developments in Singapore and China Stocks
Monthly percentage stock change data from China Oil, Gas and Petrochemicals (China OGP) suggest that commercial crude inventories rose by an equivalent 5.3 mb in August after crude supply (production plus imports) outpaced refinery throughputs for a second consecutive month. China may also have added to its strategic crude petroleum reserve over August; the reported commercial stock build is only approximately half of the 10.4 mb total build suggested by the 'gap' between crude supply and refinery runs. Commercial refined product stocks fell by 10.1 mb over the month, led lower by an 8.1 mb plunge in gasoil holdings as the country returned to being a net exporter amid lacklustre domestic demand.
According to weekly data from International Enterprise, on-land refined product inventories in Singapore grew by 1.1 mb in September to stand level with a year earlier. A 1.2 mb build in residual fuel oil stocks drove the increase after the arbitrage to draw in product from the Atlantic Basin remained wide. By end-month, residual fuel holdings sat level with the seasonal average but 2.3 mb below a year-earlier. In contrast, stocks of light distillates dropped by 0.3 mb after a number of unscheduled outages in non-OECD Asia curtailed gasoline supplies while reportedly, less naphtha was imported from Europe.
Singapore Oil Storage Bursting at the Seams
Singapore has remained at the forefront of Asian oil trading and storage for the last twenty years, utilising its location at the mouth of the Strait of Malacca, the slim channel between Indonesia and Malaysia, which serves as the main route for oil tankers voyaging between the Middle East and East Asia.
Storage capacity within the republic is now thought to be in the region of 73 mb, a vast increase on ten years ago, and there are plans to increase the terminal further in view of the demand growth expected from Asia over the medium term. Indeed, according to the Medium-Term Oil Market Report 2014, 3.6 mb/d of demand growth can be expected from non-OECD Asia over 2014-19, almost all of which will be facilitated by imports of crude or products to the region from elsewhere. However, current and future expansions in Singapore storage are beset by difficulties, notably the scarcity of land, which has seen costs soar. Additionally, recent government legislation has reportedly sought to prohibit the allocation of land to new oil terminals while prioritising the construction of high-value assets such as petrochemical facilities.
Last month, Singapore inaugurated one of its most ambitious ventures, the first phase of the Jurong Rock caverns underground storage project. Located on Jurong Island and composed of five rock caverns capable of holding approximately 9.2 mb of oil, the $700 million project sits underground which has helped to
alleviate the space shortage above ground. In the 3 mb first phase, two caverns have been completed which are being leased to petrochemicals producer Jurong Aromatics Corporation. The additional three caverns will likely be completed in 2016.
Due to constraints in Singapore, some oil storage has moved beyond the boundaries of Singapore and into neighbouring Malaysia and Indonesia. Their governments have actively encouraged the construction of oil terminals to draw business away from Singapore so that between the two they now have the capacity to store 50 mb.
Malaysia's main push to capture business from Singapore is centred on the bordering Johor region in the south of the country where the administration has offered tax incentives to encourage investment. Notably, the planned Pengerang project will include a complex of refineries, petrochemical plants and oil terminals capable of taking VLCCs. Meanwhile, it is also expanding the Tanjung Bin storage facility by 1.4 mb to 7.2 mb in 2015 while Tanjung Langsat will eventually become home to tanks capable of holding 5.1 mb.
Indonesia is pushing ahead with a number of projects in the north of the country. A 16 mb terminal is being developed on Batam Island. This has successfully encouraged Chinese investment, which the Indonesian administration hope will be a catalyst to helping to promote business in the future. Additionally, Phase 1 of the Karimun facility is due to be completed in 2H15. Current reports suggest that, when completed, the terminal will have an initial capacity of 4.8 mb with plans already in place to add a further 3.1 mb in a second phase. However, one constraint on such developments in Indonesia is the high domestic fossil fuel subsidies. Reports suggest that a number of companies have scaled back investment in the country due to the lack of profitability in supplying fuel to the inland market.
Although a number of Malaysian ports have been included under Platts' FOB Singapore refined product price assessments since 2001, the reporting agency is now planning to move to reporting prices on a FOB Straits basis beginning 1 July 2015 to 'increase market liquidity'. The methodology would be much the same as in Northern Europe where ARA (Amsterdam and Antwerp) ports are included in Rotterdam assessments. Although the new assessment will initially only include ports in Singapore and Malaysia, Indonesian ports will likely be included later.
- Oil prices fell for a third month straight in September and sank below $90/bbl in October, pressured by abundant supply, faltering demand and a strong US dollar. Brent prices have fallen by more than 20% since June, when they soared near $116/bbl after Islamist forces swept through northern Iraq. ICE Brent was last at a near four-year low of $88.70/bbl. NYMEX WTI was at $85.20/bbl.
- Higher exports from Libya and Iraq combined with booming US output to weigh on spot markets and depress global benchmarks. Growing competition in the core Asian market prompted top OPEC producer Saudi Arabia to make sharp cuts to monthly formula prices for a fourth month in a row. The UAE, Iran and Iraq followed Saudi's lead and cut official selling prices (OSPs).
- As Brent tumbled, hedge funds continued to slash net length in ICE Brent futures, with their position shifting from all-time highs to historic lows in less than four months. Hedge funds' net length on NYMEX WTI rebounded and showed signs of strength.
- Spot product prices weakened to some of the lowest levels seen in several years in September. However, a notable exception was super unleaded gasoline in the US Gulf, which strengthened in the wake of local supply outages. Cracks were mixed, with those at the top and bottom of the barrel faring better than those in the middle.
Plentiful supply and forecasts for lower economic growth that signalled weaker demand for oil knocked Brent below $90/bbl in early October. The International Monetary Fund on 7 October cut its global GDP forecast for the third time in 2014, citing weaker growth in Brazil, Japan and core euro zone countries; Germany, France and Italy. A rallying US dollar also weighed. A strong dollar makes oil more expensive for buyers using other currencies. Ongoing conflicts in the Middle East, North Africa and Ukraine have so far failed to stem oil's third straight month of losses. Exports from Libya are on the rise despite spiralling violence and shipments from Iraq's southern terminals - far from the Islamist insurgency in the north of the country - also increased. Non-OPEC supply is also rising now that summer maintenance has ended and year-on-year gains continue in the US and Brazil (see Supply).
Swelling supplies and faltering economic growth pushed ICE Brent futures down $4.83/bbl to an average $98.57/bbl in September, while NYMEX WTI lost $3.05/bbl to average $93.03/bbl. A move by top OPEC producer Saudi Arabia in early October to cut monthly OSPs for Asia appeared to signal determination to defend its market share in a weak market and pushed prices lower. Iran, Iraq and the UAE followed with their own sharp cuts. ICE Brent was last at a near four-year low of $88.40. NYMEX WTI was at $85.20/bbl.
With supply overtaking demand, European and Middle Eastern benchmarks during September remained in contango, where prompt oil is cheaper than barrels for future delivery. But by early October, Dubai flipped into backwardation, where prompt oil is more expensive than later months, after China reportedly bought big volumes of Middle East crude. The ICE Brent M1-M2 spread was steady on August at -$0.68/bbl. Farther out, the average Brent M1-M12 widened in September to -$2.50/bbl versus -$0.78/bbl in August. NYMEX WTI, however, remains in backwardation with the M1-M2 spread averaging $0.85/bbl in September. Record refinery runs and a later start to seasonal maintenance supported the US benchmark.
Steeper declines on ICE Brent narrowed the front-month spread with NYMEX WTI in September to an average $5.54/bbl versus $7.32/bbl in August. The spread shrank in early October, narrowing to less than $3.00/bbl. Brent's weakness relative to Middle East Dubai is expected to continue to pull Dated Brent-linked crudes from West Africa and the North Sea into Asia.
As Brent tumbled, hedge funds continued to slash net length in ICE Brent futures, with their position shifting from all-time highs to historic lows in less than four months. When factoring in other non-commercial traders, the combined position turned net short for the first time since reporting started in 2011. Hedge funds' net length in NYMEX WTI rebounded and showed signs of strength.
Open interest was down markedly on the year for both contracts, with NYMEX WTI contracting by 20% and ICE Brent by a more modest 4.4%. Global trading volumes were up year-on-year for both benchmarks, 12.7% for WTI and 7.2% for Brent.
On the products side, net length on RBOB gasoline futures was reduced as prices declined following the end of driving season. Hedge funds continued to sell off New York Harbour ultra-low sulphur diesel futures through September to their strongest net short stance to date as prices trended lower.
US banking regulators finalised rules on margin requirements for uncleared swaps. The rules would determine how much collateral is to be posted for swaps traded between firms as opposed to those executed through a clearinghouse.
US Commodity Futures Trading Commission (CFTC) also approved revised margin rules for uncleared swaps, largely following those of banking regulators on 17 September. The modified rules include exceptions for government-owned gas and power utilities that use swaps to hedge price risks.
The government agency is currently seeking comment on its cross-border applications to non-US banks and overseas units of US firms. The proposed rules will be phased in between 2015 and 2019.
The European Securities and Markets Authority (ESMA) published a consultation paper on future guidelines concerning the definition of derivatives its Markets in Financial Instruments Directive (MiFID) on 29 September. The regulator is aiming to address the issue of differing interpretations of the definition of derivatives across the member states.
The CFTC could finalise its rule on speculative position limits before the end of the year. The rule, one of the most controversial pieces of the Dodd-Frank financial reform, is being re-proposed after being overruled in court in September 2012, on the grounds of non-proven necessity.
Spot Crude Oil Prices
Spot crude oil prices weakened further in September, pushed lower by rising exports from OPEC members Libya and Iraq, softening demand in Europe and Asia and robust US production that has cut demand for West African barrels. North Sea Dated Brent slumped $4.27/bbl to average $97.29/bbl in September, while WTI was more resilient - shedding $3.17/bbl to average $93.21/bbl. Sour Russian Urals took the biggest hit, losing $5.78/bbl to average $95.65/bbl. Middle East Dubai posted a decline of $5.21/bbl versus August to average $96.55/bbl.
Libya's production comeback continued to stoke competition for light sweet supplies and pressure North Sea and West African grades. Output from the North African OPEC member was holding above 800 kb/d in October - versus just 240 kb/d in June - even as the country unravels. Europe's sour crude market was also amply supplied, with UK Forties seeking an outlet in Asia for the first time since early July. Russian Urals met tepid interest, with discounts to Dated Brent sinking to an average $1.64/bbl in September versus $0.14/bbl in August. Higher shipments from Iraq in September saw more Basrah Light offered into Europe, adding to already ample supply. Kuwait, meanwhile, is leasing storage at the Egyptian Mediterranean port of Sidi Kerir as it targets Europe.
The relentless rise in US oil production has meanwhile cut the country's import requirements: not a single barrel of Nigerian crude was delivered to the US in July. Much of the excess West African crude is moving into Asia and Brent's continuing decline is making for favourable trade. More than 2.0 mb/d of West African crude was scheduled to load for Asia in September versus around 1.9 mb/d in August. China reportedly took record amounts of Atlantic basin crude in September trading. It also lifted big quantities of Russia's light, sweet ESPO Blend. Russia shipped record flows of more than 600 kb/d of ESPO from Kozmino in September, with similar levels expected this month. And, as Brent skidded below $90/bbl in early October, Beijing reportedly stepped in to buy more than 8 million barrels of Middle East crude.
Well aware of the growing rivalry in Asia - which includes barrels from Colombia, Mexico, Ecuador and Alaska - Opec's top producer Saudi Arabia cut its monthly prices in early October in an apparent bid to stay competitive. The Saudi reduction followed a sharper cut in formula prices to Asia last month. Abu Dhabi, Iran and Iraq followed with their own big reductions.
In the US, declining crude stockpiles in the trading hub in Cushing, Oklahoma and robust refinery run rates, helped lock in backwardation - where prompt oil trades at a premium to future deliveries. WTI's relative strength versus North Sea Dated Brent shrank to nearly $2.00/bbl. The US west coast is saturated with crude - prompting the first US export of Alaskan crude in a decade. Rising supplies of domestic output in the lower 48 states and Canada, enabled by increased rail connections, are flooding the US West Coast, where Alaskan crude typically finds a home. Demand meanwhile increased for Western Canadian heavy crude - shrinking its discount to benchmark WTI - as Canadian midstream firm Enbridge prepared to begin filling its 600 kb/d Flanagan South pipeline system in November that will enable additional Canadian volumes to travel from Illinois to Cushing.
Spot Product Prices
Spot product prices weakened to some of the lowest levels seen in several years in September. However, a notable exception was super unleaded gasoline in the US Gulf which strengthened in the wake of a number of localised supply outages. Cracks were mixed; those at the top and bottom of the barrel were boosted by falling product prices being outpaced by crude prices declines while middle distillate prices weakened at a faster clip than crude prices. On a region by region basis, cracks in the Mediterranean and Singapore posted steeper gains than elsewhere following sharp declines in Urals and Dubai compared to other benchmark grades.
The only product which saw prompt prices increase over September was super unleaded gasoline in the US Gulf Coast. This market was hit by a number of localised outages at gasoline refining units which tightened supply. Accordingly, inventories drew and gasoline prices rose which combined with weakening crude prices to drive cracks upwards by $6.68/bbl on average over the month. Some spill over was felt in European markets where the higher US prices re-opened the transatlantic arbitrage window. Consequently, exports increased and prices at Rotterdam and in the Mediterranean softened by a comparatively weak $1.50/bbl with gasoline cracks in both markets posting steeper gains than for other products.
Middle distillate spot prices posted the sharpest losses amid ample supplies across all markets. Aviation fuels were especially hard hit. In Northern Europe, jet cracks steadily weakened as imports remained high and amid lacklustre demand while the arbitrage to send product across the Atlantic remained shut. In the Mediterranean, despite spot prices posting sharper losses than in Northern Europe, the effect of sharply declining Urals kept cracks above a month earlier. A similar picture was noted in Singapore as jet kerosene cracks gained $1.00/bbl on a monthly average basis in the wake of sharply weakening Dubai, and more-than-offsetting a decline in spot prices amid ample supply.
The oversupply in European gasoil markets pressured prompt prices to their lowest levels since late-2010 during September. This saw the contango versus later months steepen considerably. By early-October, the discount of the prompt month versus months three and twelve stood at $0.77/bbl and $6.0/bbl, respectively. These levels are sufficient to cover land-based storage costs ahead of an expected uptick in distillate demand ahead of the January 2015 introduction of more stringent environmental controls on marine bunker fuel which will result in the increased use of marine gasoil in Northern European waters.
At the bottom of the barrel, fuel oil prices weakened across surveyed markets amid low demand and ample supply. However, these losses were outstripped by benchmark crude price losses which resulted in all cracks firming. In Europe, HSFO spot prices declined by similar amounts in Northern and Southern Europe. Nonetheless, European cracks rose to their highest levels in 18 months in tandem with falling crude prices. On a monthly average basis, Mediterranean refiners saw cracks increase by a larger increment than those in Northern Europe after Russian Urals posted sharper declines than ICE Brent. In Singapore, LSFO prices were pressured lower by high stocks as bunkering demand remained underwhelming while cracks consolidated their position in positive territory.
Surveyed crude rates were generally subdued in September except for trading Suezmaxes on voyages out of West Africa. The benchmark Suezmax rate West Africa - US Gulf Coast remained on a low note throughout most of September, inching towards $12/mt and then overtaking the $15/mt mark at the end of the month as the vessel list thinned. Very Large Crude Carriers (VLCC) rates for the Middle East Gulf towards Asia gradually inched down, touching below $10/mt, towards end-September, the lowest since June, on lower eastwards spot VLCC loadings.
Despite the deepening of Brent contango and of reports suggesting otherwise, data suggests that global floating storage has not increased in significantly in the past few months, and its stored volumes keep to be led by Iranian tankers.
Aframaxes in Northern Europe had an extremely flat month, with rates stagnating around $6/mt for both the Baltic - UK route and the North Sea - UK continent route, as activity remained insufficient to lift rates. In East Asia, record high ESPO loadings of 600 kb/d in September, due mostly to higher imports into China, lifted Aframax rates from Kozmino to Singapore to the highest in more than three years.
On product tanker rates, the 75Kt Middle East Gulf - Japan route inched below the $30/mt mark in September although vessel availability remains tight. The 37Kt UK Coast - US Atlantic rate seesawed between $15/mt and 20/mt for most of the month and then settled around $22/mt in early October as a cross-Atlantic gasoline arbitrage opportunity to ship gasoline westwards opened (See 'Product Prices').
- Global refinery crude demand hit new highs in August, near 79 mb/d, with OECD runs leading the uptick. Despite the onset of seasonal plant maintenance through October, a lighter turnaround schedule than in recent years and healthy margins will likely support runs through year-end. Global crude runs are set to dip to 77.5 mb/d in 4Q14 from 78.1 mb/d in 3Q14, with year-on-year (y-o-y) growth rising over the same period to 1.4 mb/d from 0.9 mb/d.
- Refinery margins extended their upward trend in September and into October, as crude price declines outpaced those of products. US refinery outages lifted gasoline cracks not just in the Americas, but also in Europe and Singapore. Particularly strong gains in European margins, which reached their highest level since end-2012, underpinned a recovery in regional runs in August, a sharp departure from the previous months.
- OECD refinery crude runs rose another 0.6 mb/d in August, after having surged by 2 mb/d a month earlier. At 38.1 mb/d, total OECD throughputs were 430 kb/d above the previous year, with annual gains in North America, and to a lesser degree Europe, dampened by structural declines in Japan.
- New refinery capacity in the Middle East looks set to raise regional product exports by close to 1 mb/d in coming months. Satorp's 400 kb/d Jubail refinery, which started crude processing in mid-2013, reportedly reached full capacity in August. A month later, Aramco's second 400 kb/d JV refinery, in Yanbu, started trial runs, while in the UAE, Adnoc is on track to complete its 420 kb/d Ruwais expansion before year-end. Regional demand growth, estimated around 0.2 mb/d in both 2014 and 2015, will leave significant volumes of oil products looking for export markets outside the region.
Global Refining Activity Bounces Back from June Lows
Global refinery crude demand likely hit an all-time high of nearly 79 mb/d in August, led by a dramatic resurgence of refining activity in the OECD. Improved refinery profitability since June underpinned a steep rebound in OECD throughputs, after a counter seasonal decline in June, when a combination of weak margins, seasonal maintenance and permanent plant closures had undercut runs in OECD Europe and Asia, while a string of unscheduled outages had caused US refiners to miss their seasonal uptick. The resulting dip in crude demand, compounding the impact of robust supply, left the Atlantic Basin awash with crude, pushing benchmark prices sharply lower, even as product markets tightened. As a result, European refinery margins bounced back to highs unseen since 2012, triggering a strong recovery in regional throughputs. OECD refinery crude intake surged by 2.6 mb/d over July and August, as European refinery runs climbed above year-earlier levels for the first time in almost two years, while runs in the US and South Korea reached all-time highs in July and August, respectively.
Weaker-than-expected non-OECD runs partly offset the strength in OECD refining activity and may go some way towards explaining it. Preliminary data suggest non-OECD refinery throughputs fell below the year prior in July, with exceptionally weak Asian runs. A string of planned and unplanned outages in Vietnam, Thailand, India and elsewhere cut non-OECD Asian refinery runs to 9.4 mb/d in July, excluding China, almost 0.6 mb/d below a year earlier.
Steep declines in crude prices over September and early October supported refinery margins at relatively lofty levels, even as end-user demand declined after the summer driving season ended. Global crude runs are expected to hit a seasonal low point this month, at 76.4 mb/d, as autumn maintenance gathers pace. Lower crude demand is contributing to further weakness in crude prices, while reducing capacity at a time when refiners start to prepare for the winter heating season. Oil product demand rises seasonally to a quarterly high of 93.5 mb/d in 4Q14, compared with 93 mb/d in 3Q14 and only 91.5 mb/d in 1H14.
The start-up of new refinery capacity in the Middle East and China, new condensate splitters in South Korea and Singapore, and the return of non-OECD Asian refiners from scheduled and unscheduled outages is expected to support throughputs this fall. Margins and activity levels in the OECD are, on the other hand, expected to come under pressure again from increased competition for product markets. European and Asian refiners will therefore likely be forced to scale back runs again, at least as maintenance shutdowns ease through October and into November. Overall, our estimates for global refinery throughputs are largely unchanged since last month's report, averaging 78.1 mb/d in 3Q14 and 77.5 mb/d in 4Q14. Annual gains are set to rise to 1.4 mb/d in 4Q14, from 0.9 mb/d in 3Q14, led by the Middle East and non-OECD Asia (including China). OECD throughputs are also seen up year-on-year in 2H14, with growth in the US augmented by annual gains in Europe, from a low-2013 base.
OECD Refinery Throughput
After posting a sharp 2 mb/d increase in July, OECD refinery crude throughputs extended their gains in August, rising 0.6 mb/d month-on-month (m-o-m), to 38.1 mb/d. The bulk of the increase came from Europe, where an unexpected recovery in refinery margins lifted runs to their highest levels in almost two years. US runs fell back slightly, in line with seasonal norms, though sustained substantial y-o-y gains. Record high throughput rates in South Korea, following the completion of maintenance and the start-up of two new condensate splitters over July and August, offset structural declines in Japan. In all, OECD refinery crude intake stood 430 kb/d above a year earlier in August. Preliminary data show seasonal maintenance curbing OECD runs by 1.2 mb/d in September, to 37 mb/d, slightly above earlier expectations. As plant maintenance intensifies, runs are expected to be cut further in October, though improved margins should see the OECD retain strong gains over 2013, when activity was exceptionally weak.
Refinery throughputs in the OECD Americas eased slightly in August compared with July's record highs, to 19.5 mb/d. Runs remained 425 kb/d above a year earlier, on higher US throughputs, which so far this year are up nearly 600 kb/d. US throughputs fell sharply by end-September, as maintenance got underway. On a monthly basis, US crude intake fell by 375 kb/d from August, with most of the declines coming from the Gulf Coast. Planned announced shutdowns are lighter this year than last, with some refiners reportedly postponing planned works until 2015, to benefit from currently robust refinery margins. Extensive work should curb runs in Canada, however.
Thanks to greatly improved refinery margins, European runs rose above year-earlier levels for the first time in almost two years in August. From an unexpectedly low point in June, OECD European throughput rates surged 1.2 mb/d by August. Preliminary data indicate that regional runs rose to 12 mb/d, some 465 kb/d above July and 140 kb/d higher than a year earlier. German refiners processed 200 kb/d more crude than in July, while Spain and Italy increased runs by 100 kb/d and 70 kb/d, respectively. Ireland's sole refinery also returned from maintenance after completing a full shutdown in July. A sharp recovery in refinery margins, both in Northwest Europe and on the Mediterranean, underpinned the increases, as even simple refinery margins turned positive. Margins improved further into early October, suggesting that the steep declines seen last October will not be repeated this year. As non-OECD refiners ramp up throughputs again however, refiners might again be forced to cut output, in the face of lacklustre regional demand and high product inflows.
In the OECD Asia Oceania region, refinery throughputs also rose sharply through August, on higher South Korean refinery intake. Two new condensate splitters with combined capacity of 250 kb/d started up in July in South Korea, lifting the country's crude runs, which includes condensates, to a new record high of 2.7 mb/d in August. The two units are owned by a Samsung/Total joint venture and SK Incheon Petrochem Energy, respectively. SK Innovation reportedly also raised throughputs at its Ulsan refinery, after maintenance was completed. In contrast, Japanese refinery runs fell 270 kb/d versus year-earlier levels. Despite the weak runs, Japanese gasoline exports shot up to record highs as bad weather and high retail prices curbed domestic demand. South Korea's product exports also increased in July and August, as domestic demand remained near year-earlier levels.
Non-OECD Refinery Throughput
Preliminary estimates indicated that non-OECD refinery runs slipped below year-earlier levels for the first time in 15 months in July, following particularly sharp declines in Asia. Non-OECD Asian runs, excluding China, contracted by nearly 0.6 mb/d year-on-year, on extensive outages and signs of weak demand. Increased exports from Japan, Korea and the Middle East could also have contributed to lower rates. Regional throughputs are on track to decline year-on-year for the fourth quarter in 3Q14, before a recovery is expected in the last quarter of the year. Gains in China, the Middle East and Africa have offset some of the declines, however. Growth in total non-OECD runs is now estimated to have slowed to 0.6 mb/d in 3Q14, from 1.5 mb/d in 2Q14. As offline capacity returns and new capacity continue to ramp up, annual gains are expected to rise to 1.1 mb/d in 4Q14, reaching 41.1 mb/d, from 40.5 mb/d in 3Q14.
Chinese refinery intake inched slightly higher, to 9.75 mb/d, in August, from 9.67 mb/d in July and 9.4 mb/d a year earlier. Despite a slight uptick in domestic demand, exports of key products surged to 775 kb/d in August, the highest level since December 2009. Throughputs are estimated to have risen in September, to just over 10 mb/d, before falling again in October when several refiners started maintenance. Chinese refinery activity is expected to be propped up by new capacity later in the year. Sinopec commissioned a new 100 kb/d crude unit at its Shijianzhuang refinery in July, and is scheduled to start a 120 kb/d unit at its Yangzi refinery this month. The most recent additions follow almost 500 kb/d of new capacity being completed at the start of the year.
As the demand growth outlook for China continues to deteriorate, companies continue to delay expansion projects. PetroChina most recently announced that it has delayed the expansion of its Huabei refinery, by 200 kb/d, to start up in 2017, two years later than an earlier timeline. Compared with previously ambitious refinery expansions plans, only 100 kb/d of new capacity now looks likely to be brought online in 2015. A more chunky 800 kb/d of new capacity is scheduled for 2016, when Sinopec's 300 kb/d Zhenhai and PetroChina's 200 kb/d Kunming plants will be completed. PetroChina's Huabei will also add 100 kb/d of CDU capacity, while CNOOC is planning to expand its Huizou refinery by 200 kb/d.
In 'Other Non-OECD Asia', refinery crude activity fell further in July, the last month for which data are available, to 9.4 mb/d, from 9.5 mb/d in June, and 10 mb/d a year earlier. Indian throughputs averaged only 4.3 mb/d, 245 kb/d less than a year earlier. The shutdown of HPCL's 180 kb/d Bathinda refinery, after a fire in June, was partly to blame. As the refinery remained closed through September, Indian refinery runs remained weak also in August. A deregulation of domestic retail prices, coinciding with weak domestic and regional demand has led Reliance to increasingly supply the domestic market and has forced state-owned refiners to scale back runs. Indian throughputs are nevertheless expected to rebound towards year-end. The new Paradip refinery is only expected to start crude processing in December, after numerous delays. Elsewhere, Vietnam's sole refinery completed a 40-day full shutdown in August, Thailand's Bangchak and Sriracha plants were shut in June-July, while Indonesia's Cilacap refinery shut for turnarounds in September.
After hitting yet another record high in August, of more than 6 mb/d, the onset of autumn maintenance took Russian refinery runs some 335 kb/d lower in September. At 5.7 mb/d, Russian refinery runs were still 310 kb/d above the previous year, as has been the case for most of this year. While announced maintenance schedules suggest planned outages of about 600 kb/d for both September and October, we expect throughputs to decline further in October, in line with seasonal trends. Only in two of the last ten years did Russian refiners raise runs in October.
Middle East Refining Boom to Leave Products Searching for Markets
As global oil demand growth continues to show signs of slowing down, eyes are turning to the Middle East, where several large scale refinery projects are nearing completion. Not only is the steep increase in Middle Eastern refining capacity set to dramatically boost the overall volume of products available for export, but the configuration of the plants, designed to maximise diesel production, seems somewhat at odds with market trends that in recent months have shown stronger demand growth for gasoline and jet fuel than for middle distillates.
As highlighted in our latest Medium-Term Oil Market Report, the region is poised to expand its primary refinery capacity by nearly 1.5 mb/d over 2013-15, to 9.3 mb/d. The capacity additions compare with total regional oil product demand growth of 0.6 mb/d over the same period, resulting in a significant increase in the volumes of refined products from the Middle East available for export in the near-term. Our analysis shows regional net product exports could surge to almost 1 mb/d next year, from less than 0.4 mb/d on average in 2013.
Since the start-up of Satorp's 400 kb/d Jubail refinery in September 2013, Saudi Arabian product exports have already shot up. According to JODI data, exports of gasoil/diesel, for instance, averaged 195 kb/d in January-July of this year, more than 100 kb/d higher than the same period in 2013. The Aramco-Total JV plant only reached full capacity in August, according to company officials, so product exports are likely to increase further. Aramco's second JV refinery, the 400 kb/d Yanbu plant, co-owned with China's Sinopec, is currently undergoing test runs, with full rates expected by early 2015. The UAE's new 420 kb/d Ruwais refinery is also expected to reach start-up mode by the end of this year.
These three mega-projects have been long in coming, and since their inception, market conditions have taken an unexpected turn. The current economic and oil-demand picture is quite different from what was envisaged at the time when they got underway in the mid-2000s. Not only was oil demand expected to be higher, but the make-up of the demand barrel has also changed. Since the financial crisis of 2008-09, the economic slowdown has had a more marked impact on distillate demand than on that for other products, such as gasoline. Diesel demand has also been adversely affected by subsidy reductions in key non-OECD markets, such as India, and concerns over local pollution levels and a slowdown in diesel sales in key markets such as France, have also been stemming growth in the not-so-distant 'champion of fuels'.
The new mega-refineries are heavily focused on diesel production. When fully commissioned, the plants should produce almost 0.8 mb/d of ultra low sulphur diesel (ULSD) and jet fuel. According to the companies and market estimates, Jubail has the capacity to produce 235 kb/d of ULSD diesel. The Yanbu refinery will produce some 260 kb/d of ULSD and 90 kb/d of gasoline, while Ruwais will produce an additional 175 kb/d of diesel and 85 kb/d of jet fuel. Regional distillate demand growth, meanwhile, is forecast to grow by less than 0.1 mb/d per annum this year and next.