- Oil prices sank to six-year lows in August as a supply overhang grew and concern deepened over the health of the global economy, especially in China. After rebounding on a slew of economic and fundamental data, prices turned volatile in September. Brent was last trading at $48.10/bbl with NYMEX WTI at $45.20/bbl.
- Oil's latest tumble is expected to cut non-OPEC supply in 2016 by nearly 0.5 mb/d - the biggest decline in more than two decades. Lower output in the US, Russia and North Sea is expected to drop overall non-OPEC production to 57.7 mb/d. US light tight oil, the driver of US growth, is forecast to shrink by 0.4 mb/d next year.
- OPEC crude supply fell by 220 kb/d in August to 31.57 mb/d, led by losses in Saudi Arabia, Iraq and Angola. The group's output stood 1.2 mb/d higher than a year ago. The 'call' on OPEC climbs to 31.3 mb/d in 2016, up 1.6 mb/d y-o-y as lower prices dent non-OPEC supply and support above-trend demand growth.
- Global oil demand growth is expected to climb to a five-year high of 1.7 mb/d in 2015, before moderating to a still above-trend 1.4 mb/d in 2016 thanks to lower oil prices and a strengthening macroeconomic backdrop.
- OECD oil inventories swelled by a further 18 mb in July to a record 2 923 mb. Robust refinery throughput pushed crude stocks 9.9 mb lower, while refined products added 26.7 mb. At end-July, product stocks covered 31.2 days of forward demand, 0.6 days above end-June. Preliminary data suggest further builds in August.
- Global refinery throughput reached a seasonal peak of 80.9 mb/d in August before autumn turnarounds cut runs through October. Refinery margins remained robust through early September, but with support shifting from gasoline to middle distillates as refiners gear up for the heating season.
In a word: supply
The big story this month is one of tightening supply, with the spotlight firmly fixed on non-OPEC. Oil's price collapse is closing down high-cost production from Eagle Ford in Texas to Russia and the North Sea, which may result in the loss next year of half a million barrels a day - the biggest decline in 24 years. While oil's recent volatility has been unnerving - Brent crude jolted from a six-year low below $43 /bbl to above $50/bbl in the space of days - the lower price environment is forcing the market to behave as it should by shutting in output and coaxing demand.
US oil production is likely to bear the brunt of an oil price decline that has already wiped half the value off Brent. After expanding by a record 1.7 mb/d in 2014, the latest price rout could stop US growth in its tracks. A sharp decline is already underway, with annual gains shrinking from more than 1 mb/d at the start of 2015 to roughly half that level by July. Rigorous analysis of our data suggests that US light tight oil supply, the engine of US production growth, could sink by nearly 400 kb/d next year as oil's rout extends a slump in drilling and completion rates.
Producers outside of the US also continue to adjust to the lower price outlook. Marginal fields are being shut or are at risk as companies seek to stem losses from high operating costs. Spending curbs are also accelerating decline rates. The sizeable anticipated loss of overall non-OPEC output and robust demand growth suggest that unless prices recover, lower-cost OPEC producers would need to turn up the taps during the second half of 2016 to keep the market in balance. Our forecast shows the 'call' on OPEC for 2H16 leaping to an average 32 mb/d - a level last pumped seven years ago. The group produced 31.6 mb/d during August.
But until then, inventories are continuing to build with global supply - towering 2.4 mb/d above a year ago - outpacing demand. Our balances show the world only starting to siphon off record-high stocks in the second half of 2016. At that point Iran could be producing more oil, provided sanctions are lifted following implementation of the nuclear pact it secured with the P5+1 group.
As for demand, the lure of $50/bbl oil is boosting growth to a five-year high of 1.7 mb/d this year and an above-trend 1.4 mb/d in 2016. US motorists are taking to the roads, propelling domestic gasoline demand to an eight-year high. We expect China, the world's second largest oil consumer, to keep up its crude purchases despite the recent stock market collapse, currency devaluation and steady stream of negative macroeconomic news. Beijing could also buy extra crude to fill up its strategic reserves.
Of course, it is not just non-OPEC that is taking a hit from lower oil prices. High-cost projects are also at risk in OPEC nations. The 12-member group meanwhile continues to pump vigorously, with Saudi Arabia, Iraq and the UAE producing at or near record rates. On the face of it, the Saudi-led OPEC strategy to defend market share regardless of price appears to be having the intended effect of driving out costly, "inefficient" production.
- Global oil demand growth is expected to climb to a five-year high of 1.7 mb/d in 2015, before moderating to a still-above-trend 1.4 mb/d in 2016 thanks to lower oil prices and a strengthening macroeconomic backdrop. US baseline revisions, coupled with preliminary July numbers ahead of prior expectations, raised the 2015 global demand estimate by 0.2 mb/d to 94.4 mb/d.
- Higher estimates for 3Q15 demand, 0.4 mb/d higher at 95.0 mb/d, were chiefly attributable to raised July numbers for the US, China, Europe and Russia. Russian demand beat earlier expectations as industrial-stimuli provided by recent currency weaknesses offset, to a greater degree than previously forecast, the negative impact from otherwise contracting Russian macroeconomic activity.
- Chinese oil demand growth has shown persistent gains as strong growth in the petrochemical and transport sectors, outweighs any apparent weakness in industrial oil use. Until more clarity emerges as to the success of government efforts to support continued macroeconomic growth, the forecast for Chinese oil product demand growth remains relatively muted at +3% in 2016.
- Large upgrades to historical estimates of US oil product demand added 0.1 mb/d to the global demand estimate for 2014. This work, which follows the publication of comprehensive delivery data from the US Department of Energy's Energy Information Administration (EIA), particularly raised US gasoil/diesel and LPG (which includes ethane). The latest US demand data has also exceeded earlier expectations, with preliminary July estimates pointing towards deliveries of approximately 19.8 mb/d, 0.4 mb/d up on the forecast cited in last month's Report, led by above-forecast LPG, gasoline and 'other product' demand.
Half a year into a period of clearly above-trend global oil demand growth, estimates for 2015 as a whole increasingly point to growth rising to a five-year high of around 1.7 mb/d (or 1.8%). Lower crude oil prices (if not always product prices, see Retail prices stickier outside the US), a generally strengthening macroeconomic backdrop and colder-than-year-earlier 1Q15 European winter temperatures provided a potent cocktail for robust gains in oil product demand and a turn-around from the previously beleaguered state of growth. Just one year earlier, global oil demand growth bottomed-out at a five-year low of 0.8 mb/d. We envisage global oil demand growth easing back to a still above recent-trend 1.4 mb/d in 2016, as notable decelerations (compared to 2015) are forecast for Europe, the OECD Americas and non-OECD Asia - the latter chiefly consequential on weaker Chinese demand growth.
After rising sharply in 1Q15, +1.9% (or 1.8 mb/d) year on year (y-o-y), as much colder-than-year-earlier European winter weather conditions stimulated additional gasoil/diesel demand, global oil product demand growth inched higher in 2Q15 to +2.0% y-o-y supported by accelerating gains in non-OECD Asia and a decelerating decline in OECD Asia Oceania. The light-end of the barrel pushed 2Q15 growth to a new peak, with notable 2Q15 accelerations occurring in naphtha and jet/kerosene offsetting decelerating gasoil. Global growth is forecast to ease somewhat from 2H15 through 2016, but projections remain well above recent trends and rest heavily on the assumption of continued gains in global macroeconomic activity. Current demand forecasts are based upon July's World Economic Outlook from the International Monetary Fund (IMF), which cites global economic growth accelerating to 3.8% in 2016, from +3.3% in 2015. The IMF highlights the ongoing heightened risks that surround these projections, stating in July that on the upside "a greater boost from lower oil prices is still an upside risk, especially in advanced economies," while "disruptive asset price shifts and a further increase in financial market volatility remain an important downside risk". The IMF particularly notes the possibility of "greater difficulties in China's transition to a new growth model," and the potential "spillovers to economic activity from increased geopolitical tensions in Ukraine, the Middle East, or parts of Africa". Such uncertainties in the macroeconomic outlook carry across to the very demand forecasts that they are a crucial determinant of, adding a heightened level of uncertainty to demand projections.
Preliminary OECD estimates suggest that the recent strength of the OECD data likely eased in July and will continue to ebb through to the end of our forecasting horizon in 2016. Having risen by an average of 1.4 % y-o-y in 1H15, total OECD demand growth likely pulled back to around +0.8% y-o-y in July. Momentum eases still further, to around 0.3% in 2016, as modest forecast gains in the OECD Americas roughly counter-balance some very slight projected declines in OECD Europe and OECD Asia Oceania.
Up for eight consecutive months in July in y-o-y terms, OECD American oil product demand remains clearly in growth mode as continued macroeconomic gains, coupled with sharp declines in crude oil prices, support rising oil deliveries across the OECD Americas. Gains have not, however, been seen across every participant nation, with strong gains in the US and Chile offsetting generally declining demand in Canada. Mexico has also generally seen contracting oil demand, October 2014-June 2015, albeit with a modest y-o-y gain posted in July. The overall product split in the OECD Americas is also not universally a rising one, as strong gains in gasoline, LPG and jet/kerosene counteract dips in naphtha and residual fuel oil demand.
The US has led the recent demand strength in the OECD Americas, as drivers' thirst for cheaper gasoline remains far from quenched. Up by approximately 355 kb/d on the year earlier, US gasoline deliveries clambered to a near eight-year high of 9.6 mb/d in July, as many more miles are proverbially put 'on the clock' while anecdotal reports of multi-car households making less efficient vehicle choices further add to gasoline's upside. The US Department of Transport's Federal Highway Administration reported a 3.9 % y-o-y gain in US vehicle miles travelled for the latest month it has data, i.e. June, perfectly matching US gasoline demand growth in that same month and also incidentally July. Robust gasoline, along with relatively strong gains in LPG (includes ethane), supported total US deliveries of 19.6 mb/d in June, rising to 19.8 mb/d in July. This month's Report is also noteworthy for including the EIA's revised annual data series for 2014, which essentially added 70 kb/d to the historic US oil product demand numbers. An upwardly revised 19.1 mb/d 2014 US demand estimate is cast, as estimates of LPG and gasoil/diesel demand are heavily hiked. Total US gasoil demand is now thought to have accounted for 21% of the US demand-barrel in 2014, LPG 12.5%, while gasoline still dominates at around 47%.
Looking forward, to the year as a whole, total US oil product deliveries are expected to average 19.5 mb/d, 2.2% up on the year earlier, as sharply higher transport fuel demand (land and air) offset declines in residual fuel oil and naphtha. Moving into 2016, US demand momentum, although still positive, is forecast to ease back as a large part of the initial lower-price driven transport stimulus wanes once more.
Mexican oil demand edged higher (y-o-y) once again in July, ending nine successive months of declining y-o-y demand, supported by robust gains in the transport sector. Strengthening gasoline demand led the rebound, rising strongly for two consecutive months, June-July, as much lower retail prices and slowly recuperating macroeconomic activity stimulate demand. Gasoline in Mexico accounted for roughly one out of every two-and-a-half barrels delivered last year, and with the Asociacion Nacional de Transporte Privado reporting retail prices falling to a near two-year low of 0.9 US dollars a litre in July, demand returned above 800 kb/d for the first time since 2012.
Mexican power sector oil demand continues to fall, as alternative fuels increasingly dominate production of electricity in the country. The Mexican Secretaria de Energia reported natural gas use in the power sector in July up by nearly one-third on the year earlier, triggering declines in power sector use of residual fuel oil and 'other products'. Oil's falling share of Mexican generating demand was not, however, sufficient to outweigh the strong demand support provided by resurgent transport demand. Looking forward, the forecast for total Mexican oil deliveries across the year as a whole should average 2.0 mb/d, 1.8% down on the year earlier chiefly due to sharply contracting power demand. Essentially flat demand is foreseen in 2016, as the upside support from additional macroeconomic activity and persistently lower prices are forecast to offset the downside influence from slowing projected declines in the power sector.
Reflecting the recent sharp contractions that have taken hold across Canadian industrial output in general, oil deliveries fell in y-o-y terms in each month in 1H15. With sharply lower crude oil prices cutting into the extraction spend, Statistics Canada reported total industrial output down 2.8% y-o-y in May, a fourth consecutive monthly decline. Oil deliveries, having fallen by 50 kb/d (or 2%) y-o-y in 1Q15, posted a further 45 kb/d contraction in 2Q15, as average deliveries fell to approximately 2.3 mb/d. With the sharpest 2Q15 contractions occurring in residual fuel oil, gasoline and naphtha, as a combination of ailing industrial activity and enhanced efficiency gains filters across the latest demand statistics. For the year as a whole, deliveries are expected to average 2.4 mb/d, equivalent to a drop of 1.8% on the year, a further decline of around 1.2% is foreseen in 2016, as demand falls to an average of 2.3 mb/d.
Although historical estimates of European demand still point towards a heady 1Q15 gain of around 480 kb/d y-o-y, the estimate has been curbed dramatically from last month's Report (+0.6 mb/d) as official German data has been revised down. At 2.4 mb/d in 1Q15, approximately 120 kb/d have been trimmed from the 1Q15 German demand estimate, on notably lower gasoil, naphtha and gasoline. This 1Q15 reduction, not replicated in 2Q15, eases the previously forecast European 2Q15 deceleration; as we now have European growth easing from 3.7% in 1Q15 to around 1.3% in 2Q15, as opposed to 4.6% to 0.3% previously. Indeed, the 2Q15 European demand estimate has been revised up, by around 125 kb/d since last month's Report, as very strong June demand numbers were seen in Sweden (+10% y-o-y), Turkey (+11.8%), Italy (+8.8%) and Poland (+12.1%). Specifically Swedish gasoil deliveries surged as macroeconomic activity strengthened. Notably industrial output rose by 1.2% y-o-y in June, while car registrations rose to a near-15-year high of 34 415, both series reported by Statistics Sweden.
Preliminary July estimates of both French and Italian demand showed continued y-o-y growth, respectively rising by around 15 kb/d and 90 kb/d on a y-o-y basis in July. French deliveries climbed to a near two-year high, of approximately 1.8 mb/d in July, supported by very strong gains across the main transport fuels. Italy, underpinned by very strong gains in transport and industrial fuels, saw total deliveries rise to a two-and-a-half year peak of 1.4 mb/d. The forecasts for both countries, along as many others within the region, have accordingly been raised. The Italian outlook for 2015 has been revised up by 20 kb/d, compared to last month's Report to 1.3 mb/d, the French by 10 kb/d to 1.7 mb/d.
The recent evolution of the European demand picture has not seen universal gains, however, with some notable laggards existing, such as Finland, Germany, Slovenia and the Netherlands. The latest Dutch data from June showed a tenth successive y-o-y decline, pulled down by sharp reductions in petrochemical usage. Statistics Netherlands reported total industrial production across the economy as a whole down by 2.6% y-o-y in June, a third consecutive monthly y-o-y fall.
Coupled with the now much lower starting point in German oil product demand, -120 kb/d in 1Q15, preliminary estimates of July deliveries point towards four out of the five months through July enduring absolute y-o-y contractions. This relative weakness occurring, despite sharply lower crude prices, as not only have high taxation levels in Germany sheltered consumers from any significant feed-through from lower crude prices but also relatively plentiful heating oil stocks have eased the need to refill tanks while low water levels on the Rhine have disrupted some mid-year shipments. A net-demand-decline is forecast across 2015-16, albeit to a lessening degree as ongoing economic growth and persistently depressed crude oil prices curb the projected decline rates.
Retail prices stickier outside the US
Since January, oil has traded below $70/bbl, roughly two-fifths down on the previous year. Estimates of 2015 oil demand growth have nearly doubled over a comparable period - from 0.9 mb/d to 1.7 mb/d - even though price drops at petrol forecourt have been muted outside the US. A large part of the demand adjustment - 0.7 mb/d - is attributable to OECD countries, with 48% and 38% respectively attributable to the US and Europe.
The US is commonly regarded as a very price-responsive economy. In a low price environment, the impact of excise taxation, which is essentially a fixed fee added to the fuel price before applying VAT, grows. In 2015, at $0.12 per litre (tax varies by state; figure is a US average) this tax was approximately five times lower than in Germany. As a consequence of the 38% drop in US Gulf Coast gasoline prices, July 2014 to August 2015, end user prices dropped by 27%, raising US gasoline demand forecasts by 265 kb/d since January's Report.
In Europe, high taxes and a strong US dollar limited the impact of the global crude price slide. In Germany for example, in July 2014, when the retail price peaked at 1.60 €/L the implied tax rate was 57%; six months later, when the average gasoline price stood at 1.30 €/L, the implied tax rate was 66%. At the same time the euro dropped almost 17% against the dollar. So, while dollar-denominated spot prices at Rotterdam fell between July 2014 and January 2015 -- 55% and 47% for motor gasoline and diesel, respectively, the corresponding retail price declines were 30% and 29% in dollars and 19% and 17% in euros. Despite this more muted price-support, the hike in the European 2015 demand forecast neatly matches that of the US, as the European economic backdrop has improved significantly.
The situation in OECD Asia Oceania is similar to that in Europe, although the region is taxed less than in Germany (at 41 % in Japan, in 2014), the tax rate remains high compared to the US. At ¥138/L in August, the motor gasoline pump price was 15% lower than in 1H2014 but almost 30% lower in US dollars. The Japanese gasoline forecast for 2015 has accordingly been raised, by 20 kb/d since January's Report. In China, until recently the exchange rate held firm against the US dollar, knocking gasoline prices down by around 28% since the July 2014 peak. Yet the weakening economy offsets most of the low price impact and only 15 kb/d have been added to January's forecast for Chinese gasoline. China's decision to devalue its currency against the US dollar by around 2%, on 10 August, potentially trims the prospective feed-through from further dollar-denominated price slides, dimming this potential additional Chinese demand support going forward.
Having fallen heavily, 2Q14-4Q14, recent data for OECD Asia Oceania has shown a clearly moderating pace of decline. The average 3.4% y-o-y decline, 2Q14-4Q14, eased to -0.4%, January-July; as a notable deceleration took hold in residual fuel oil, alongside upticks in naphtha, gasoline and gasoil. The greatest recent upside in OECD Asia Oceania is reserved for New Zealand, Israel and Korea, while Japan and commodity-dependent Australia have struggled. Averaging 3.9 mb/d in 2Q15, Japanese oil product deliveries fell by around 35 kb/d (or 0.8%) on the year earlier, as the negative impacts from escalating efficiency gains and contracting economic activity exceeded the support garnered from lower crude prices. Economic activity in 2Q15 came in 1.6% lower than the year earlier, or 0.4% down on 1Q15, with both exports and domestic consumption seeing absolute declines. Such weak Japanese economic underpinnings particularly impacted gasoil and jet/kerosene, while the ongoing power sector migration away from oil as a means of generating electricity dampened residual fuel oil and 'other product' demand. Preliminary estimates of July demand, meanwhile, matched last month's forecast, at 3.9 mb/d. Looking forward, for the year as a whole, Japanese deliveries are forecast to average 4.3 mb/d, 2.2 % down on the year, before falling by a more muted 1.8% in 2016 to 4.2 mb/d. Although now only accounting for a very small share of Japanese power sector demand, residual fuel oil and 'other product' demand lead the projected 2015 downside, as nuclear restarts likely dampen the power sector requirements of most 'other' energy sources, including oil. In 2016, the total relative decline rate in Japanese oil product demand eases somewhat as the underlying macroeconomic backdrop itself solidifies, with the IMF's July World Economic Outlook citing economic growth of 1.2% in 2016 after a 0.8% gain of 2015.
The recent sharp deterioration in crude oil prices is a mixed bag for non-OECD oil demand; as net oil-importing economies should, all else being equal, see higher demand, while the converse is true for net oil-exporters. This adjustment is particularly apparent for the Middle East, as the 2015 Middle Eastern demand forecast, at 8.2 mb/d, is 50 kb/d below that carried in last month's Report, as lower potential crude-export revenues curtail the potential size of domestic spending budgets in many of these countries. Non-OECD Asian demand is likely to be one of the key beneficiary regions from significantly lower oil prices, as the quantity of financing required to pay for imported oil products falls as their prices contract. India in particular will likely see higher demand, which at 3.9 mb/d in 2015 is 15 kb/d more than quoted last month, and 170 kb/d up on 2014, rising to 4.1 mb/d in 2016. The latest Indian data depicts demand growth of approximately 5.5% y-o-y in July, supported by strong gains in LPG, residual fuel oil and gasoline. Gasoil demand in July contracted by around 0.5% on the year earlier as heavy rains curbed agricultural usage.
Despite recent concerns regarding the strength of the Chinese economy - highlighted for well over a year in previous editions of this Report - Chinese oil product demand remains remarkably resilient, as estimated deliveries in 1H15 averaged 11 mb/d, approximately 5.2% higher than the year earlier. Deliberate efforts to steer the economy towards additional domestic consumption, at the expense of heavy manufacturing/exports, has supported a swing towards more rapid gasoline/jet demand growth versus lagging gasoil/residual fuel oil. Tracking forwards, a likely consequence of the recent stock market correction and resultant government efforts to calm markets - such as the devaluation of the domestic currency, sub-market product prices, lower interest rates and additional infrastructural spend - could be an easing in the pace of this adjustment, to additional transport fuels as opposed to industrial oil use.
That being said the forecast for the year as a whole, at 11 mb/d, and equivalent to a gain of approximately 4.1%, incorporates the long held belief that Chinese oil product demand growth decelerates in 2H15: from 5.6% y-o-y in 2Q15, to 3.7% in 3Q15 and 2.3% in 4Q15. August's very bleak business confidence estimate (see Untangling the significance of Chinese business sentiment indicators) confirm escalating macroeconomic worries, as have the recent weak car sales data, declines in industrial activity, plummeting property prices and fragile electricity output. For example, the National Bureau of Statistics (NBS) released data showing a 2% y-o-y slide in total power production, as well as a 0.3% y-o-y contraction in total industrial activity. Dampening the potential long-term growth forecast for Chinese transport fuels, the China Association of Automobile Manufacturers reported a 6.6% y-o-y contraction in passenger car sales in July.
Looking further forward, projections of Chinese oil demand growth remain buttressed at around 3% in 2016, at least until more clarity emerges with regard to the success of government efforts to support continued macroeconomic growth.
Untangling the significance of Chinese business sentiment indicators
The month of August saw particularly sharp declines in the price of most financial assets classes - with equities, most emerging market currencies and commodities falling sharply as investor sentiment turned increasingly bearish in response to escalating concerns about the health of the Chinese economy. The results published in August's Caixin/Markit Manufacturing Purchasing Managers' Index (PMI) for China, at 47.1 in August, were commonly cited as a particular cause for concern. Not only was this widely-quoted measure of Chinese manufacturing sentiment significantly below the key 50-threshold that demonstrates the break-even point between optimism and pessimism, it had also fallen to a near six-and-a-half-year-low. We have often alluded to the usefulness of the PMIs as a means of forecasting future economic activity, but here we explicitly focus on the potential use of these metrics as an indicator of pending Chinese oil demand.
Not including this year, the past three years have endured 19 months of net-pessimism, i.e. roughly half of the months in 2012-14 were below 50. In this specific net-pessimistic time-period, Chinese y-o-y oil demand growth averaged +3.4%. The remaining months saw Chinese oil demand growth average +4.2%; thus alluding, very roughly, to an eight-tenth of a percentage point premium when the Caixin/Markit Manufacturing PMI is net-optimistic. This optimism-premium proves particularly heightened in gasoil/diesel and gasoline, respectively, carrying additional average demand gains of 1.3 and 0.9 percentage points, 2012-14, while residual fuel oil and 'other products' significantly lagged.
At 3.7 mb/d in June the latest Saudi Arabian demand estimate maintains a large premium on the year earlier, roughly 0.2 mb/d higher than last year with strong gains in the residual fuel oil and 'other products' categories. Reports of very hot early summer weather raised both the fuel oil and 'other products' demand numbers, as additional air conditioning demand raised the Saudi Arabian power sector requirement. Despite this additional mid-year demand the forecast for the year as a whole, at 3.3 mb/d and up 3.6% on the year, has been very modestly curtailed as sharply lower oil prices curb pending government revenues. Only a modest near 2% gain is then foreseen in 2016, as lower oil prices keep a lid on domestic spending possibilities.
Recent Russian oil product demand data have been remarkably resilient, given the severity of the recession that currently grips the economy. With the Federal State Statistics Service reporting an economic contraction of 4.6% y-o-y in 2Q15 and retail sales falling across the economy as a whole, down by 9.2% in July, the latest oil demand data demonstrate surprising buoyancy. Posting modest growth in July, to approximately 3.8 mb/d, not only is this is the highest level of Russian oil demand in nearly one year but it is also 0.1 mb/d above the estimate cited in last month's Report. We note that the sharp decline in the value of the Russian rouble, versus the US dollar and the euro, provided a welcome impetus to many previously beleaguered domestic industries, pulling in additional (or at least lower decline rates) of naphtha, gasoil and 'other products' compared to our previous forecasts.
Roughly flat on the year earlier, latest estimates of Brazilian demand, at 3.2 mb/d in July, near perfectly matched our month earlier-forecast. With strong gains in gasoline and 'other product' demand offsetting sharp y-o-y contractions in industrial fuel use, notably gasoil and residual fuel oil, the overall forecast for the year as a whole has been left unaffected, also at 3.2 mb/d and essentially flat on the year earlier. This status-quo should persist in 2016, as the macroeconomic backdrop is also projected to flatten, the IMF citing an economic contraction of 0.3% in 2016 in July's World Economic Outlook.
- Global oil production dropped by 0.6 mb/d in August, to 96.3 mb/d, on lower output in both OPEC and non-OPEC countries. Supplies nevertheless stood more than 2.4 mb/d above a year earlier, with non-OPEC producers accounting for 43% of the gain.
- OPEC crude oil supply fell by 220 kb/d in August to 31.57 mb/d, led by losses in Saudi Arabia, Iraq and Angola. OPEC's two largest producers, Saudi Arabia and Iraq, posted month-on-month (m-o-m) declines, but continued to pump near record rates - leaving overall OPEC crude output roughly 1.2 mb/d higher than a year ago.
- Non-OPEC production declined by 350 kb/d in August, to 58.16 mb/d. The decline was led by the US, which based on preliminary data saw accelerating declines from recent highs, and lower North Sea volumes, curbed by seasonal field maintenance. Annual gains in total non-OPEC liquids output still stood an impressive 1 mb/d above a year earlier, from an average 1.8 mb/s seen since the start of the year.
- The plunge in global crude prices is expected to cut non-OPEC oil production by nearly 0.5 mb/d next year, on a sharply weaker outlook for US supply, lower Russian output and structural declines in the North Sea. The projected drop in output would be the largest since 1992, when non-OPEC supply contracted by 1 mb/d from the previous year, with the collapse of the Former Soviet Union.
- US LTO production is forecast to contract by nearly 0.4 mb/d next year, as the latest price rout takes 2016 futures prices below the average breakeven cost for all major shale plays. As such, the current slump in drilling and completion rates is expected to extend well into next year - in contrast to a rebound expected previously.
- 'The call on OPEC crude and stock change' climbs to 31.3 mb/d in 2016, up 1.6 mb/d year-on-year (y-o-y) on an anticipated sharp slowdown in non-OPEC supply growth combined with robust demand. The 'call' in 2H16 jumps 1.3 mb/d from 1H16 to 32 mb/d, which is above the group's current production.
All world oil supply data for August discussed in this report are IEA estimates. Estimates for OPEC countries, Alaska, Mexico and Russia are supported by preliminary August supply data.
OPEC crude oil supply
OPEC crude oil production eased by 220 kb/d m-o-m in August to 31.57 mb/d due to lower flows in Saudi Arabia, Iraq and Angola - but still stood roughly 1.2 mb/d above a year ago. Despite m-o-m declines, Saudi Arabia and Iraq - the main drivers of OPEC's expansion - continued to pump vigorously. Six straight months of double-digit production has lifted Riyadh's average output to 10.16 mb/d this year - up by 410 kb/d on 2014. Output from Iraq, including the Kurdistan Regional Government (KRG), dropped to 4.13 mb/d in August as disruptions along the country's northern pipeline thwarted supply growth. Even so, the oil fields in OPEC's second biggest producer have flowed above the 4 mb/d mark for three months running. This has raised average Iraqi supply this year to 3.8 mb/d, 560 kb/d higher than 2014.
Overall OPEC output is running at 31.17 mb/d so far this year, up 1 mb/d on a year ago and well in excess of the group's official 30 mb/d production target. Supply looks set to hold above the 31 mb/d mark for some time to come, with Riyadh holding fast to its policy of defending market share, not price, and Iraq striving to sustain its impressive growth. The group's 'effective' spare capacity stood at 2.27 mb/d in August versus 2.22 mb/d in July, with Saudi Arabia accounting for 86% of the surplus.
The 'call on OPEC crude and stock change' for 2015 and 2016 has been revised up by 200 kb/d and 500 kb/d, respectively, since last month's Report due to an expected marked slowdown in non-OPEC supply growth and a more robust demand outlook. The 'call' in 2016 is estimated at 31.3 mb/d, up 1.6 mb/d y-o-y. The 'call' in 2H16 is expected to leap by 1.3 mb/d from 1H16 to reach 32 mb/d - higher than the group's current production.
Brent crude's tumble below $50/bbl is meanwhile causing budgetary discomfort throughout OPEC, prompting some members to call for an emergency meeting to discuss output curbs. But top producer Saudi Arabia is unlikely to reverse the OPEC strategy it has steered. In any case, Saudi Arabia and fellow Gulf producers Kuwait, Qatar and the UAE are better able to withstand financial stress due to their hefty foreign currency reserves. Those with little or no cash cushion such as Venezuela, Nigeria and Angola are much more vulnerable.
OPEC is scheduled to meet on 4 December, at which point its ranks are due to swell to 13 after Indonesia re-joins the group. Indonesia left OPEC seven years ago when it became a net oil importer. It now produces around 800 kb/d of crude.
Saudi oil fields continued to produce near record-rates in August, with output of 10.3 mb/d edging down 100 kb/d m-o-m. Riyadh has pushed flows beyond the 10 mb/d mark for six months in a row - suggesting it has no intention of backing down from an OPEC policy to preserve market share, rather than price. August's dip in production appeared to be due to slightly lower exports to world markets, according to tanker trackers and industry sources, although domestic requirements remained high because of heightened summer demand from power plants.
The latest figures submitted to the Joint Organisations Data Initiative (JODI) show power plants burned 890 kb/d of crude in June versus 820 kb/d in May. Riyadh's domestic power requirement usually surges during the summer when air conditioners run flat out. Saudi refineries throttled back in June, using about 2.1 mb/d of crude versus a record 2.4 mb/d in May.
As for the international market, crude oil exports rose to around 7.4 mb/d in June from 6.9 mb/d in May, with shipments during the January-June period running close to 7.5 mb/d. Product exports fell to 1 mb/d from 1.3 mb/d in May and accounted for 12% of overall oil sales. Excluding condensates and NGLs, total Saudi oil exports rose to 8.37 mb/d in June from 8.25 mb/d in May.
The Kingdom's robust production boosted economic growth during the second quarter, but analysts expect the pace to slow as lower oil prices take a deeper toll. In a bid to plug a widening budget deficit, Riyadh sold bonds worth 20 billion riyals ($5.3 billion) in August - the second sovereign bond issue since 2007. The first, placed with quasi-sovereign institutions, took place in July.
Output in neighbouring Kuwait edged up 40 kb/d m-o-m to 2.78 mb/d as enhanced oil recovery efforts began to show results, according to industry sources. But the prolonged operational dispute over the Neutral Zone that Kuwait shares with Saudi Arabia continues to prevent the country from achieving its production potential. The offshore Khafji and onshore Wafra oil fields in the Neutral Zone have all but stopped flowing. Fellow core Gulf producer the UAE posted a fresh record of 2.93 mb/d in August thanks mostly to higher output from the offshore Upper Zakum oil field. Qatari output recovered to 650 kb/d - up 30 kb/d from July, when the collapse of a rig in the offshore al-Shaheen field impacted operations.
Output in Iraq (including the KRG) declined by 90 kb/d in August to 4.13 mb/d as attacks and theft along the northern pipeline to Turkey prevented the country from scaling new heights. OPEC's second biggest producer turned in its strongest ever performance in July, when output hit 4.2 mb/d (an upward revision from last month's Report).
The cash-strapped country has every incentive to crank out as much as it can, given the twin challenge of oil's collapse and a costly battle against the Islamic State of Iraq and the Levant (ISIL). But oil revenues fell to $3.87 billion in August - down 20% versus July - due mostly to lower oil prices as well as reduced shipments to world markets.
Iraq's giant southern oil fields delivered 3.02 mb/d of Basra crude exports, down about 40 kb/d from July's record volumes. According to official data, the southern fields pumped 3.36 mb/d in July - their highest ever.
Exports of crude from the north slid 50 kb/d to around 470 kb/d in August after flows via the Kurdish pipeline that feeds into the Iraq-Turkey pipeline were disrupted. Most of the exports to the Turkish Mediterranean port of Ceyhan were from fields under the control of the KRG, with the federal government's North Oil Co (NOC) contributing about 120 kb/d from the Kirkuk field's Baba dome and the adjacent Jambour field. Apart from the KRG's Taq Taq and Tawke oil fields and the Kirkuk oil field's Khurmala dome, the Kurds are also managing Kirkuk's Avana dome and the nearby Bai Hassan oil field, formerly operated by NOC. Industry sources say the capacity of the KRG's independent pipeline to the Turkish border has risen to at least 750 kb/d.
The KRG agreed at the end of last year to ship 550 kb/d via the central government's State Oil Marketing Organisation (SOMO) in exchange for the resumption of budget payments from Baghdad. But since mid-June, the KRG has increased its independent oil sales and cut allocations to SOMO amid an escalating row over export rights and budget payments. It said it transferred roughly 50 kb/d to SOMO in August versus 70 kb/d in July. In early September, the KRG said it allocated $75 million of revenue from its direct crude sales to three international oil companies - Genel Energy, DNO and Gulf Keystone. Companies operating in the region's oil fields had not received any revenue from exports since late last year due to the dispute between Baghdad and the Kurdish capital Erbil.
Iranian output held steady at 2.87 mb/d in August, although Tehran is gearing up to boost supplies following an anticipated easing of international sanctions. Iran and the P5+1 (China, France, Russia, the UK, US and Germany) struck a landmark nuclear pact in July that paves the way for a suspension of sanctions after Tehran complies with the terms of the deal. In theory, that point could be reached by the end of this year although in practice, the agreement is more likely to be implemented in 2016.
Iranian Oil Minister Bijan Zanganeh has said Tehran will boost output immediately to reclaim the market share it has lost since rigorous financial measures were imposed in mid-2012. Since then, neighbouring Iraq has seen striking growth. Its output has soared by more than 1 mb/d, allowing it to overtake Iran to become OPEC's second biggest producer after Saudi Arabia.
Zanganeh expects the country's oil fields to ramp up by 500 kb/d as soon as sanctions are lifted and by 1 mb/d within months. Even that strong performance would still leave Iran trailing Iraq, which is pumping in excess of 4 mb/d. Our estimate is that Iranian oil fields are capable of cranking up to 3.4 to 3.6 mb/d within six months of sanctions being eased. Tehran was producing around 3.6 mb/d in 2011 before the US and European Union imposed tighter financial restrictions.
As for international oil sales, Iran's crude exports have fallen from roughly 2.2 mb/d at the start of 2012 to around 1.0 mb/d during August versus 1.16 mb/d the previous month. Lower purchases from China, India, Syria and Turkey offset higher imports from South Korea, according to preliminary data. Purchases of condensate - ultra-light oil from the South Pars gas project - rose to about 130 kb/d from 105 kb/d the previous month, still well below the 2014 average of 190 kb/d.
While there is unlikely to be a substantial boost in Iranian production before next year, oil held in floating storage could start to hit world markets before then. Tehran had a total of 44 mb stored at sea at the end of August, down from 46 mb at the end of July. Condensate accounts for some 60% of that overall volume.
Technical snags at oil fields in the east of Libya and ongoing security issues nudged supply down to 370 kb/d in August - the lowest level since February - and less than a quarter of the 1.6 mb/d pumped before the civil war that ousted Muammar Gaddafi in 2011. The country's core source of supply is for now provided by eastern oil fields run by state Arabian Gulf Oil Co (Agoco). They were pumping roughly 225 kb/d in August versus capacity of 350 kb/d as the Nafoura and Bayda fields remained closed due to protests and power outages.
Talks are meanwhile continuing with tribal elders in western Libya to reopen pipelines linking the oil fields of El Feel and El Sharara to ports in the western Mediterranean. These core fields in the southwest, which together could produce up to 480 kb/d, have been closed since December due to a strike by oil security guards and pipeline blockades.
A long-running battle between the country's two rival governments - the so-called Libya Dawn administration in Tripoli and the officially recognised government that fled to the east - has, for months, forced a halt to operations at vital oil fields and terminals. The United Nations is attempting to resolve the conflict.
Elsewhere in Africa, Angolan supplies fell 90 kb/d m-o-m to 1.71 mb/d in August due to scheduled maintenance on offshore oil fields. Luanda is feeling the pinch of lower oil prices, and the International Monetary Fund said economic growth is likely to slow to an average annual 3.5% between 2015 and 2016 from around 4% last year. The West African producer's economy had shown rapid expansion after the end of a decades-long civil war in 2002.
And in a bid to offset a sharp decline in oil revenue due to the collapse in oil prices, Algeria will cut spending by 9% in 2016. Output in the north African producer bumped up to 1.13 mb/d in August thanks to the start-up of two new oil fields - Bir Sebaa and Bir Msana.
Oil's rout is also causing budgetary distress for Nigeria - Africa's biggest economy - where output held steady in August at 1.77 mb/d. Shell lifted a force majeure on Bonny Light crude oil after it fixed pipelines that had been hit by theft.
Among OPEC producers, cash-strapped Venezuela - which pumped 2.4 mb/d in August - is one of the hardest hit by oil's collapse amid runaway inflation and acute shortages of basic goods. The South American country's president, Nicolas Maduro, said in early September Caracas has lined up $5 billion in loans from China. Since 2007, Beijing has loaned more than $50 billion to Venezuela in return for oil. In July, China's imports of Venezuelan crude climbed to around 520 kb/d - the highest in nearly a decade.
Caracas has also been lobbying for an emergency OPEC meeting and joint cooperation with Russia to help reverse oil's decline. Maduro furthermore has proposed an OPEC heads-of-state summit to bolster oil prices that are half the value of a year ago. A severe economic crisis has made oil's recovery a top priority for the Latin American producer, especially in the run-up to crucial parliamentary elections in early December. The price of Venezuelan oil, which is mostly heavy quality, is roughly $40/bbl versus an average of around $88/bbl in 2014.
The head of Venezuelan state oil company PDVSA, Eulogio Del Pino, was meanwhile appointed to run the country's oil ministry. Del Pino, who will hold onto his post as PDVSA boss, will take over leadership of the ministry from Asdrubal Chavez so that Chavez can run for parliament.
The outlook for non-OPEC oil production has been cut for this year and next on the back of downwardly revised US production estimates for the first five months of this year and further oil price declines. Global crude benchmarks extended July's losses, shedding another $10/bbl on average in August to fresh six-year lows. While evidence of slowing US output reversed some of the declines, the average future strip for 2016 Brent is more than $10/bbl lower than in early July.
As a result, producers across the world are shutting in marginal fields with high costs of production. In the US, the recovery in drilling activity and output expected for next year is starting to look elusive. The decline in the rig count, which had stalled in early July and started to show signs of an uptick in recent weeks, shed 13 rigs in the first week of September.
A revised EIA methodology for estimating US crude production - polling producers rather than relying on partial and often incomplete state level data - suggests US Lower 48 output is already seeing an accelerated decline. With a drop in new well starts of around 40% since the start of the year, it is surprising the cut in output is not steeper (see Latest price rout slashes US production outlook). With futures prices currently well below average breakeven costs for most US LTO plays, we expect the drop to accelerate through 2016 as activity levels drop further.
Elsewhere, producers are also adjusting to lower prices by extending capital expenditure curbs and targeting lower operating costs. Rig contracts are being re-negotiated or cancelled while marginal fields are being decommissioned to stem losses. We estimate that production at risk of being shut in at a realised oil price of $50/bbl totals more than 400 kb/d, of which 250 kb/d is in the US and Canada. At an oil price of $45/bbl, this number rises to 930 kb/d. While in reality only a portion of those projects are likely to be shut, in particular by national oil companies which might choose to operate even if they were losing money, the results are illustrative of the potential impact of the latest drop in prices.
In addition, so called stripper wells, those that "strip" the remaining oil out of the ground and most of which produce less than 5 barrels a day, are being shut or are at risk of shutting at current price levels. With an estimated 400,000 stripper wells in the US alone - totalling perhaps as much as 1 mb/d, a price drop from $50/bbl to $40 /bbl could have a tremendous impact. While we try to capture these marginal field shutdowns in our model through accelerated decline rates and adjustments, the very nature and small scale of the producing units makes them hard to track and quantify and the impact could be greater than assumed in this Report, should prices remain at current levels.
As a result of the lower outlook for North American supply for next year, offset in part by a higher biofuel production forecast for Brazil and the US, projected non-OPEC production for next year has been curbed by 0.3 mb/d since last month's Report. The estimate for this year however is largely unchanged. Total non-OPEC liquids production is forecast to contract by 480 kb/d next year, to 57.7 mb/d, after posting gains of 1.1 mb/d on average in 2015. If it materialises, the decline in output would be the largest since 1992 -and the collapse of the Former Soviet Union - when non-OPEC supplies contracted by 1 mb/d from the previous year.
US - August Alaska actual, others estimated: US crude and condensate production dropped by 105 kb/d in June, to 9.3 mb/d and some 620 kb/d above a year earlier. The decline in output stemmed largely from Texas, which - according to the EIA's new estimation methods - declined for the third consecutive month through June. After posting annual gains of more than 640 kb/d in 2014, output in the US' largest producing state has already lost 45 kb/d on average in the first half of this year. Output in North Dakota, where the Bakken shale play is mostly located, held steady in June, but output in this state is also lower in 1H15 compared with the same period a year earlier. Including NGLs, total US supply growth slipped to 820 kb/d in June, its lowest since August 2012.
Preliminary data suggest extended output declines in subsequent months. Weekly estimates show monthly contractions of 90 kb/d in July and nearly 200 kb/d in August. The EIA's Drilling Productivity Report meanwhile shows output declines at the seven most prolific shale plays accelerating, losing an aggregate 350 kb/d through September from a peak of 5.6 mb/d hit in April. Lower prices and drilling are clearly starting to impact on output (see Oil rout slams brakes on US LTO growth). As such, LTO production is forecast to contract by nearly 0.4 mb/d next year, offset by higher Gulf of Mexico (+165 kb/d) and NGL production (+130 kb/d), resulting in an overall decline of 190 kb/d in US liquids output, to 12.5 mb/d.
Oil rout slams brakes on US LTO growth
Oil's downward spiral to fresh six-year lows below $50/bbl has dimmed the prospects for a recovery in US drilling activity and stalled near-term growth in light tight oil (LTO) output. Unless oil prices bounce back in coming months, supply is forecast to fall by 385 kb/d next year to 3.9 mb/d versus 4.3 mb/d forecast for this year. A sharp decline has already started, with annual gains dropping from nearly 1.2 mb/d at the start of the year to around half by July.
LTO, because of its shorter investment cycle and steep decline rates, has the capacity to respond much more quickly to price movements than other sources of supply. The very steep decline rates characterizing tight oil wells means that to grow or even to sustain production levels requires continuous investment. A new EIA methodology for assessing US oil production shows accelerated declines in US supply in the most recent months, suggesting LTO output may already have peaked.
Our analysis of recent output data for the main US shale plays reveals that output per well fell by an average 72% from initial production rates within 12 months of start-up, and declined 82% in the first two years of operation due to natural decline. As such, operators have to keep on drilling new wells or increasingly focus on higher yielding wells in core acreage (high-grading) just to offset natural declines.
Given oil companies' cuts in capital spending, an expected rebound in drilling activity and output levels for next year looks elusive in the current lower price environment (see Low prices force US producers to rethink priorities in the Oil Market Report dated 12 August). Indeed, the levelling off and partial recovery in the US rig count since early July came to an abrupt halt in in early September when data showed the steepest drop in active oil rigs since May. At 662, the number of active rigs stands nearly 60% lower than a year ago.
Since early June, the average Brent futures price for 2016, which is used as input into this Report's oil supply and demand forecasts, slumped by nearly $20/bbl before recovering some losses in early September to around $55/bbl. Taking into consideration the discount of Bakken to Brent crude - which has dropped to an average of $7.50/bbl so far this year, futures prices are currently below the average cost of production for all the main shale plays: Norwegian oil consultancy Rystad Energy estimates that the average breakeven prices for most of US LTO plays' output range from $54/bbl in the Bakken and Eagle Ford, $61-68/bbl for the Permian Basin and $64/bbl for Niobrara, with marginal acreage at a much higher cost. Although operators in the best acreage see much lower break-even costs for new wells, in the current price environment, further reductions to new LTO producing wells look inevitable.
We expect drilling and completion rates to drop by a further 20%-70% next year, depending on the play's differential between cost and realised crude prices. So far this year, the number of new producing wells in
the US has already declined by nearly 50% compared with the same period a year ago, a drop largely offset by impressive increases in productivity. Current well start and output data suggest initial production rates have surged by more than 50% this year as a result of operators only leaving rigs in the most profitable acreage. Real productivity gains are most certainly also taking place, though this is yet difficult to quantify.
As operators are likely to have already completed wells in the best acreage, the potential for further improvements in production rates per well in 2016 looks doubtful in the absence of further breakthroughs in technology. We assume initial production rates will remain largely unchanged from this year's impressive levels, on the assumption producers have enough high-quality stock not having to go into more marginal areas.
Of course the key characteristics of LTO is its flexibility - and it is responsive to prices both to the upside and to the downside. As such LTO supplies will likely also be the first to respond should market conditions improve.
Canada - May actual, June preliminary: Latest consolidated data for Canada, through May, show total oil production slipping below 4 mb/d for the first time in 20 months. At 3.86 mb/d, total output was 300 kb/d down on the month, and 200 kb/d lower than the previous year. The drop was largely anticipated after outages at Albertan upgraders and wildfires shut in some bitumen sites, but it was larger than indicated in preliminary data. In particular, synthetic crude production dropped to only 700 kb/d, its lowest since May 2013, and compares with more than 1.1 mb/d as recently as February. Other Albertan oil output dropped nearly 90 kb/d to 1.8 mb/d, with bitumen output accounting for the bulk of the decline. Lower output at the Suncor operated Terra Nova field, which shut for planned maintenance mid-month, also contributed to the slump in production.
Preliminary data for June show a rebound not only in Albertan bitumen output, by 50 kb/d, but more importantly a 230 kb/d rise in synthetic crude production. The offshore Terra Nova field remained shut for the entire month however, reporting zero output.
A fire at Syncrude's Mildred Lake upgrader on 29 August cut the outlook for September and the year as a whole. Canadian Oil Sands, which holds a 36.7% interest in the plant, announced the plant's output will now likely be at the lower range of its 2015 target announced a month earlier, around 260 kb/d.
Benchmark Canadian heavy crude oil prices collapsed to 12-year lows at near $20/bbl in August, raising questions about current operations and future expansions of the country's oil sands. Canada's largest synthetic crude project, Syncrude Canada, announced last month it is not likely to shut down operations even as the plant was losing $6 for every barrel it produces. According to the company, the project has break-even costs of C$57/bbl (US$43.46/bbl), and $47.27/bbl including interest payments, administration and other costs added. Syncrude prices meanwhile briefly slipped to $35/bbl in August before recovering to nearly $48/bbl in early September.
Lower prices have already curbed growth prospects for Canada. French major Total put on hold its Joslyn North Mine oil sands project earlier this year due to the worsening fundamental outlook. Harvest Operations says that while construction of its 10 kb/d Black Gold project is completed, first steam will be delayed until WTI oil prices rebound to around $60/bbl. Sunshine Oilsands is also postponing commissioning and start-up of the first 5 kb/d phase of its West Ells SAGD project from 1Q15 to September in order to reduce costs. Shell Canada, meanwhile, has delayed start-up of its Carmon Creek project from 2017 to 2019 to take advantage of the current downturn to achieve cost reductions.
Despite the latest oil price rout, Albertan heavy oil supplies are nevertheless rising from the start-up of new projects long in the planning. In mid-June, Imperial oil announced the start-up of its 110 kb/d expansion at its Kearl oil sands mining project, which was originally targeted for end-2015. 2Q15 also saw the start-up of ConocoPhillips' Surmont 2 project, which reported first steam at the end of May. Once fully operational at end-2017, the project will add nearly 120 kb/d of capacity.
Mexico - July actual, August provisional: Total oil output rose 30 kb/d in July to 2.6 mb/d and is forecast to remain around these levels in August as an expected rebound in NGL output offsets slightly lower crude oil production. Despite the recent uptick, Mexican production continues to face extensive structural field declines. Total liquids were around 150 kb/d lower than a year earlier during the July-August period. After managing to stem field declines at its legacy Cantarell field to less than 10% in early 2014, declines have accelerated to an average of nearly 30% so far this year. Output at the massive field averaged only 270 kb/d in August, down from 365 kb/d a year earlier and 440 kb/d on average in 2013.
According to its finance ministry, Mexico has h edged 580 kb/d of its 2016 production at $49/bbl, a price 35% lower than the $76.4/bbl locked in for 625 kb/d of its 2015 production. The ministry paid $1.09 billion for the put options bought for Brent and Maya crude, nearly a 30% increase on last year's investment. Maya crude is currently trading around $40 /bbl.
Norway - June actual, July provisional: Norwegian oil production held steady in July from a month earlier at 1.95 mb/d, up 20 kb/d from a year earlier. Final data for June show production 165 kb/d above a year ago, with annual gains stemming mostly from new fields such as the Gudrun field, Knarr and Hyme. Lower maintenance outages at existing fields also contributed, while NGL output rose 35 kb/d from the previous year to 350 kb/d. While Eni recently stated it was on track to commission its Goliat project by end summer, production has yet to start. Goliat, which is Norway's first Barents Sea development, has been plagued with delays and cost overruns. Industry sources say production will likely be delayed to later in the year.
The Norwegian Ministry of Petroleum and Energy formally approved the development plans for the Johan Sverdrup oil and gas project on 21 August. The massive offshore field, which is estimated to hold recoverable resources of 1.7-3.0 billion boe, is slated to start up by late 2019. Phase 1 of the Sverdrup development consists of four bridge linked platforms and three subsea water injection templates, with a production capacity of 315-380 kboe/d. At a later stage, output will be raised to a peak of 650 kb/d. With total capital expenditures for the field development estimated at $20.7-26.8 billion, the project's breakeven cost is estimated at less than $40/bbl.
UK - June actual, July preliminary: Total UK oil output dropped by 10 kb/d in July, extending June's 120 kb/d dip. Field level data for May show offshore crude and condensate output rising 45 kb/d, with fields feeding into the Forties stream posting healthy gains. Output increases stemmed from the recently started Peregrine and Kinnoul fields. Nexen's Golden Eagle field, which started production in November 2014, also contributed to growth as the field had reached output of 44 kb/d in May. Further gains are expected from Enquest's Alma-Galia project, set to start-up in the next few weeks.
Maersk Oil announced it would shut down the Janice floating production unit, which carries output from the Janice, Affleck and James fields in the second or third quarter of next year, as the company aims to slash overall operating expenditures by 20% by the end of 2016 compared with 2014. The facility currently produces around 7 kb/d. The announcement follows similar news from Fairfield Energy, which said in May it plans to shut its Dunlin cluster of oil fields, and Itacha Energy's decision to decommission its Athena, Beatrice and Jacky fields earlier this year.
Australia - June actual, July preliminary: Australian oil production recovered in June but continued to lag year earlier levels. At 404 kb/d, total liquids output was 95 kb/d higher than a month earlier, but 60 kb/d less than June 2014. In addition to steep field decline at a number of offshore fields, Australian production was cut by outages and industrial action over the second quarter. Woodside's Enfield project for instance saw a 50% drop in output in 2Q15 from 1Q15 due to a planned one-month turnaround and cyclone activity. Daily lockouts of more than 200 maintenance workers at the ExxonMobil operated Gippsland JV, cut 2Q15 output by 40% from the start of the year. The recently commissioned Van Gogh/Coniston oil field continued to ramp up production, to an average of 14 kb/d for the quarter from only 2 kb/d in the first quarter of the year. Preliminary data for July suggest output remain around June's level.
Brazil - July actual: Brazilian crude and condensate output jumped 50 kb/d in July to 2.45 mb/d, its highest level since January. Output rose in both the Campos and Santos Basins. State producer pre-salt output hit a new daily record on 8 July of 865 kb/d (798 kb/d for July on average). Supplies were boosted by new wells coming on line at the p-58 production platform in the Parque das Baleias and the P-62 at the Roncador field - both in the Campos Basin. Pre-salt output benefitted from new wells at the Cidade de Mangaratiba FPSO in the Santos Basin. In all, output stood 180 kb/d higher than a year earlier with gains of 300 kb/d in the Santos Basin, partly offset by Campos Basin declines of around 100 kb/d. The threat of an open-ended oil workers' union strike in protest against Petrobras' latest five-year business plan, was clouding the production outlook for the short-term at the time of writing.
In Colombia, production dropped 65 kb/d in July. A near two-month shutdown of the Cano Limon pipeline after rebel attacks shut in supply at the Cano Limon and Cano Yaruma fields through most of August, when the pipeline resumed flows. Colombian oil production is set to fall next year as companies have slashed spending and drilling activity. A total of 36 exploration wells were drilled so far this year, down from a planned 63, according to the country's oil regulator.
In Argentina, meanwhile, output was also curbed by shutdowns in early September. Argentinian state-run energy company YPF said protests and roadblocks had forced it to shut in production at two of its largest fields: the Lomo la Lata and Loma Campana - where it is developing the Vaca Muerta shale resources. The two fields produce just over 30 kb/d, out of Argentina's 530 kb/d crude and condensate output in July. Shale output stood at 22 kb/d.
China - July actual: Chinese oil production slipped 145 kb/d in July, reversing the preceding month's gain. At an average 4.31 mb/d, total output stood 190 kb/d above the previous year, and in line with last month's forecast. June's gains stemmed entirely from offshore production, which was up by 220 kb/d on the year prior and 63 kb/d up on May. According to China's CNOOC, its crude and condensate production from offshore China rose 19% year-on-year to 868 kb/d in 1H15, leaving the company on track to meet its full year production targets. In response to lower prices and revenues, the company has cut its cost by 4.5% year-on-year to $41.35/boe and its total capex by 31.4%.
Former Soviet Union
Russia - July actual, August provisional: Russian oil production continued to defy low oil prices and international sanctions, posting nearly 150 kb/d annual gain in August. Crude and condensate output inched up 20 kb/d from July, to 10.68 mb/d, supported by high drilling rates. Russian producers have been benefitting from the rouble's depreciation against the US dollar, with the dollar-based returns largely compensated for by rouble-based investments. The country's flexible tax system is also sheltering producers from the price drop, with the government taking the brunt of the decline.
Output at the country's two largest crude producers, Rosneft and Lukoil, contracted year-on year, while SeverEnergia, Bashneft, Gazprom Neft and Gazprom continued to show the highest output growth rates. So far this year, output is up 1.4% (or 145 kb/d) from a year earlier. Production is expected to level off through the remainder of the year, leaving annual output growth of 95 kb/ d for the year as a whole before production slips by 95 kb/d next year.
Russia's largest producer, Rosneft, said in its latest quarterly earnings report it was confident it could meet production and debt payment targets this year, despite lower oil prices and sanctions. Rosneft reduced its net debt by $3.9 billion in the first half of 2015, to $39.9 billion. The company plans to pay off a further $10.9 billion this year and $15.1 billion in 2016. The latest report shows total hydrocarbon production continued to grow and that crude oil output declines had slowed due to a significant increase in drilling in the first half of the year. The company said its crude oil output dropped by 0.15% in the second quarter, to 4.1 mb/d. Rosneft maintains that it will start up its Suzuskoye field in 2016.
Lukoil meanwhile recently announced it is planning to redirect its investments from its refinery modernisation program to exploration and production. Russia's second largest producer aims to stabilise output levels, with new output from its West Qurna 2 in Iraq, Pyakyakhinskoye in West Siberia and Filanovsky in the Caspian Sea offsetting declines at Western Siberian oil fields. Lukoil's CEO warned that the plans were dependent on the company's access to capital however, and that without it, output would fall.
FSU net oil exports sank by 200 kb/d in July to 8.9 mb/d in July, the first time they have dipped under 9 mb/d this year and the second consecutive month they have remained below year-earlier levels. Refined product shipments account for the entirety of the monthly drop with Russian refinery runs falling by nearly 200 kb/d on a month-on-month basis. Considering that the lion's share of the decrease was in gasoil, it could be that Russian exporters decided to hold over shipments given the extremely low Atlantic Basin diesel prices during July. Fuel oil shipments continued to decline and posted their third straight monthly decline and now stand 420 kb/d lower year-on-year, largely as a result in changes to the excise tax regime which favours the export of crude over fuel oil.
In contrast to product exports, crude shipments increased by a slight 10 kb/d to 6.25 mb/d and remain on a par with both month- and year-earlier levels. The monthly increase came after a 70 kb/d rise in BTC blend shipments offset a 50 kb/d decrease in Russian exports through the Transneft network. Nonetheless, at 4.0 mb/d in July, flows through the system remained 190 kb/d higher year-on-year. One major reason for this is the sharp devaluation of the Russian Rouble versus the US Dollar over the last year. Considering that the vast majority of Russian crude traded on international markets is priced in US Dollars, the weakness of the Rouble has largely insulated producers from the sharp decline in global crude prices.
In Ghana, the Tullow-operated Jubilee field bounced back to around 65 kb/d at the end of July, after experiencing technical problems in June. Tullow announced in its latest investor update that it plans to bring on the 80 kb/d TEN project in mid-2016.
Oman's oil output topped 1 mb/d for first time in country's history in June, despite the plunge in prices. The boost was due to a drop in planned maintenance work and was designed to compensate for revenues lost to the oil price rout. Oman is heavily dependent on oil revenues, and needs an oil price of $95-96/bbl to balance its national budget according to the International Monetary Fund. Oman's oil production has higher break-even cost than many of its neighbours, as it relies on relatively expensive Enhanced Oil Recovery (EOR) for a high share its production.
The outlook for global biofuels for 2015 and 2016 has been revised up by 70 kb/d and 114 kb/d respectively, since last month's Report to average 2.4 mb/d next year. The adjustments were led by Brazil, whose ethanol production was revised upwards 50 kb/d for 2015 and 70 kb/d for 2016, following an increase in the taxation of gasoline, which has increased the competitiveness of hydrous ethanol, and the increase in the anhydrous ethanol blending mandate to 27.5%. Brazil's biodiesel industry also received a boost from an increase in the blending mandate to 7%, resulting in an upward revision of about 10 kb/d throughout the forecast period.
In the United States, the recent uptick in gasoline demand has led higher biofuel blending requirements, lifting the US ethanol supply forecast by 10 kb/d for 2015 and 20 kb/d 2016. With the exception of biodiesel, the proposed Renewable Fuel Standard (RFS2) volumes announced by the US Environmental Protection Agency (EPA) for 2014-2016 are lower than previous statutory targets for transport biofuels. However, if achieved, the volumes proposed would still represent growth in renewable transport fuel consumption. For a full update on biofuel market developments please consult the upcoming Medium Term Renewable Energy Market Report, to be released on 2 October.
- Oil markets are tightening going forwards, as stockpiling gradually slows and inventories start to draw in 2H16. Notable builds are still anticipated, but will be significantly lower than during the previous six quarters up to 2Q15 when global stocks rose by a notional 715 mb.
- OECD commercial oil inventories followed seasonal trends and rose by 18.0 mb to end July at a record 2 923 mb. As refinery throughputs hit a seasonal high, crude oil inventories drew by 9.9 mb while refined products added 26.7 mb. At end-July, refined products covered 31.2 days of forward demand, 0.6 days above end-June.
- China appears, once again, to have added to its strategic petroleum reserve. The construction of two further sites with total capacity of 37.8 mb is expected to be completed by end-2015 and a further four sites amounting to 94.5 mb will likely start up in 2016. This schedule would imply a fill rate of roughly 380 kb/d until end-2015 slowing to 260 kb/d over 2016.
- Preliminary data suggest that OECD inventories rose seasonally by a further 13.0 mb in August after a steep 16.9 mb build in the US, centred in refined products, more-than-offset counter-seasonal draws elsewhere.
With global supply and demand balances looking tighter going forward, the pace of stock builds is expected to slow gradually over the next four quarters before inventories begin drawing in 2H16. Although projected builds are still sizeable, they will be significantly less than during the previous six quarters up to 2Q15 when global stocks rose by a notional 715 mb. Each incremental barrel added to stocks obtains more significance as inventories rise, but price signals in crude and product markets do not suggest storage capacity limits are fast-approaching. Indeed, contango structures in WTI and Brent contracts remains relatively constant despite the recent price falls. Looking forward, an impressive 230 mb of new land-based storage capacity could be commissioned before end-2016 in locations as diverse as North America, the Middle East, Africa and South East Asia with new Chinese SPR capacity expected to account for more than half. Together with current spare storage capacity, these projects will help global markets absorb excess oil.
OECD inventory position at end-July and revisions to preliminary data
OECD commercial oil inventories followed seasonal trends and rose by 18.0 mb in July to end the month at a record 2 923 mb. This marked the fifth consecutive month that stocks have built, during which time they have added 162 mb and at end-July stood 200 mb above the five-year average. When taking government inventories into account, it is also apparent that national administrations have taken advantage of low prices to replenish inventories over the past year, since total inventories have posted builds for each of the last nine months, during which they have added a net 203 mb.
The July build was driven by refined products which increased by 26.7 mb as OECD refiners continued to ramp up throughput. Middle distillates accounted for the lion's share of the build as they surged by 18.9 mb. Atlantic Basin refiners were left with excess middle distillates supplies as they lifted runs to meet surging US gasoline demand. In contrast, gasoline holdings drew counter-seasonally by 2.8 mb, which - together with a downward revision to June data - saw OECD inventories slip below the five-year average for the first time since November 2014. The seasonal restocking of propane inventories continued in North America, with 'other products' rising by 10.5 mb to stand 26 mb above average at end-July. By end-month, product cover was 31.2 days of forward demand, 0.6 days above end-June.
As US refinery activity increased and supply growth eased, crude inventories dropped by 9.9 mb, shallower than the 13.0 mb average draw for the month. The draw in OECD Americas remained in line with seasonal trends. In Europe, the decline was less than half the seasonal draw. It appears that the European stocks draw was tempered by high imports and relatively high regional crude production, amid lighter than average field maintenance, which offset high refinery throughputs. In OECD Asia Oceania, crude holdings rose seasonally by 2.8 mb despite rising refinery runs.
June OECD inventories were revised 10.9 mb lower after downward adjustments were made to the Americas and Europe. The upshot of these revisions and a much smaller downward adjustment to May was that the 9.9 mb build presented in last month's Report is now tempered to a slim-but-still-counter-seasonal 0.6 mb increase with OECD inventories now seen to have added 1.0 mb/d over 2Q15. Notably, refined products in OECD Americas were revised downwards by a combined 11.7 mb as holdings of 'other products', middle distillates and gasoline were seen lower. In Europe, a 6.0 mb downward revision to gasoline weighed heavy and saw regional holdings slip to a 4.8 mb deficit versus average levels.
Preliminary data for August suggest that OECD industrial stocks rose for a sixth consecutive month as they adhered to seasonal trends and added 13.0 mb over the month. Stocks were driven upwards by refined products (+19.3 mb) which built as refinery throughputs remained seasonally high. As OECD crude demand remained high, stocks drew by 6.8 mb, less than the seasonal draw for the month as counter-seasonal builds were posted in the US and Europe. On a product-by-product basis, 'other products' (+12.9 mb) continued to seasonally restock while middle distillates (+6.1 mb) and fuel oil (+3.6 mb) also built.
Analysis of recent OECD industry stock changes
Commercial inventories in OECD Americas adhered to seasonal trends and built by 11.0 mb in July. Consequently, the region's surplus versus average levels remained at close to 170 mb. The continued seasonal replenishment of propane saw 'other product' inventories gain 11.0 mb while, as regional refinery throughputs hit a seasonal high, middle distillates holdings added a further 9.8 mb. In contrast, amid buoyant US demand, gasoline stocks inched down counter-seasonally by 0.3 mb. As a result, regional gasoline holdings slipped below the five-year average for the first time since October 2014. All told, refined products built seasonally by 20.0 mb and demand cover increased to 30.3 days, 0.8 days above end-June. Meanwhile, the increased refinery activity weighed on crude stocks which drew by 10.6 mb while NGLs and other feedstocks increased seasonally by 1.6 mb.
Weekly data from the US Energy Information Administration (EIA) suggest that US commercial inventories rose by a steep 16.9 mb in August, their tenth consecutive monthly build. Moreover, they have now posted only one monthly draw since February 2014, during which they have increased by a staggering 250 mb to stand at a 183 mb surplus to the five-year average. The monthly build was driven by refined products, which increased by 15.6 mb as 'other products' (largely propane) continued their seasonal replenishment, rising by 12.9 mb on the month. Middle distillates continued to build at a steeper-than-seasonal rate as US refiners continue to hike production in tandem with the rising refinery output of motor gasoline. Moreover, as the driving season neared its end, stocks of motor gasoline decreased by 2.6 mb, the only refined product category to post a draw.
Despite US crude demand hitting a seasonal high, crude stocks rose counter-seasonally by 1.6 mb as imports, especially shipments from Canada into PADD 2, remained higher than in previous months. Some effect also came from the two-week unexpected shutdown of a 250 kb/d crude processing unit at BP's Whiting, Indiana refinery during mid-August. Indeed, this was reflected in PADD 2 crude stocks, which remained at close to 140 mb throughout the month. Moreover, stocks at the Cushing, Oklahoma storage hub remained at 57 mb, equating to 80% of working capacity. This helped to pressure NYMEX WTI downwards over the month and contributed to WTI delivered at Cushing falling to an unusual discount to WTI delivered at Midland.
Industry inventories in OECD Europe slipped seasonally by 2.0 mb in July as a combined 3.8 mb draw in crude, NGLs and other feedstocks outweighed a 1.8 mb build in refined products. As with the Americas, the driver was increased refinery activity as throughputs hit a seasonal peak. Regardless, the decrease in crude oil was more shallow than usual for the time of year, with regional crude production remaining higher than over the past few years amid a relatively light maintenance schedule on North Sea fields.
The build in refined products was entirely in middle distillates which increased strongly by 4.1 mb. On the other hand, motor gasoline decreased counter-seasonally by 1.6 mb to leave regional inventories standing 6.5 mb below the five-year average by end-month. Considering high refinery output and sluggish European gasoline demand, it is highly likely that stocks were pressured downwards after large quantities of gasoline were exported to the US. By end-month, regional refined product holdings covered 37.9 days of forward demand, 0.1 days above one month earlier.
Data from Euroilstock for EU15 + Norway imply that stocks inched down by 0.7 mb in August after a counter-seasonal draw (-4.4 mb) in middle distillates weighed heavy while motor gasoline holdings drew by a further 0.6 mb. Crude oil inventories rose by 1.8 mb despite refinery throughputs remaining high as reports suggest that North Sea crude production and arrivals from Russia and West Africa remained healthy. Additionally, reports suggest that refined products holdings held in independent storage in Northwest Europe remain at multi-year highs as arrivals of middle distillates from the US, Russia and Middle East remain strong ahead of European refiners entering seasonal turnarounds.
OECD Asia Oceania
Commercial oil holdings in OECD Asia Oceania continued to trend above average levels in July as they built seasonally by 9.0 mb over the month. Moreover, the regional surplus continues to be concentrated in crude oil which added a further 2.8 mb over the month to stand 28.4 mb above average at end-month. In contrast, by end-July, refined product inventories stood a slim 1.3 mb below average. The build in crude oil came against the backdrop of a continued ramp-up in refinery throughputs which indicates that regional crude imports remained high. On the product side, stocks rose by 4.9 mb as all product categories except motor gasoline posted builds. Notably, middle distillates stocks surged by 5.1 mb, significantly more than the 2.9 mb average build for the month, to leave inventories at a 3.0 mb surplus to average levels by end-month. All told, total refined product stocks covered 21.9 days of forward demand at end-July, 0.6 days above one month earlier.
Preliminary weekly data from the Petroleum Association of Japan indicate that Japanese commercial holdings remained relatively stable in August as they inched down by 30 kb. As Japanese refinery runs hit a seasonal high, crude inventories dropped by 10.2 mb, significantly steeper than the average draw for the month. Meanwhile, refined products holdings rose seasonally by 6.2 mb as increases in middle distillates (5.6 mb) and fuel oil (2.1 mb) more-than-offset draws in motor gasoline (-0.3 mb) and other products (-1.5 mb).
China fills up SPR
China's finance ministry hinted heavily in early-2015 that it would allocate extra money to build up stocks of raw materials including crude oil, copper, nickel, zinc and corn. Some of the funds were used to complete a number of delayed sites for Phase 2 of the crude SPR (strategic petroleum reserve) and significant volumes appear to have been delivered into these sites this year. Still more tanks are expected to be built in the months to come, which could imply a fill rate of roughly 380 kb/d until end-2015 slowing to 260 kb/d over 2016.
Although information on the SPR is scarce, data suggest Chinese crude stocks have built over 2015 by an amount greater than reported by China OGP which covers commercial stock changes. Chinese crude net imports have hit record levels exceeding 7 mb/d, which, coupled with a slight rise in crude production, has seen crude supply (domestic production plus net imports) outstrip domestic demand for crude. When accounting for the stock changes reported by China OGP, data suggest that unreported crude stocks built by up to 116 mb over January to July.
Not all of these implied volumes have been added to the SPR, with reports suggesting that unreported commercial crude inventories have built at a number of locations including Yangpu and Dagang. Taking account of the above SPR construction schedule, up to 78 mb have been added to the SPR over the last 18 months. Moreover, two SPR sites located at Zhoushan and Jinzhou, with total capacity of 37.8 mb, are expected to be commissioned by end-2015. Additionally, a four further sites amounting to 94.5 mb are in the latter stages of construction which will likely start up in 2016. This should see total Phase 2 capacity exceed 230 mb - significantly above the original 169 mb aim of the Chinese administration.
According to reports, China purchased a number of ESPO cargoes which were put into tanks at the recently-completed Huangdao site over July and August. Assuming that total fill at this site was 10 mb at end-August and that Zhoushan and Jinzhou will be completely filled by end-2015, this would imply a fill rate of roughly 340 kb/d until the end of the year .If the remaining Phase 2 sites were completed by end-2016 this would entail filling at an average 260 kb/d over 2016. However, it should be noted that China is also constructing tanks at a number of new refineries and oil terminals which are due to be commissioned before end-2016. Locations include Zhongjie, Anning, Nanjiang and Hainan, and these could see total tank fill exceed the rates quoted above.
Information surrounding Phase 3 of the SPR is still vague. Original plans were for the SPR to contain 500 mb by 2020 which would equate to 67 days of China's projected net imports. However, much recent speculation has concerned whether the Chinese administration is aiming for a much larger SPR, perhaps holding as much as 90 days of net imports. If this were the case, this would see the SPR holding 670 mb (based on IEA projections of China's net import requirement in 2020) with Phase 3 required to contain around 320 mb.
Recent developments in Singapore and China stocks
According to data from China Oil, Gas and Petrochemicals, Chinese commercial crude inventories rose by an equivalent 2.5 mb (data are reported in terms of percentage stock change) in July as crude net-imports remained high, at above 7 mb/d which, together with healthy domestic production, outstripped crude refinery intake. Refined products also built as refinery output remained relatively robust at close to 10.5 mb/d. Gasoline stocks inched up by 0.1 mb as domestic demand remained healthy. Gasoil holdings surged by 6.0 mb, even as exports of the product remained close to June's high. This suggests that Chinese refiners may be experiencing a similar situation to their Atlantic Basin counterparts as they are left with 'unwanted' gasoil volumes resulting from increasing gasoline output.
Data from International Enterprise suggest that land-based refined product inventories in Singapore remained relatively stable during August as they inched down by 0.5 mb after draws in middle distillates (-0.5 mb) and residual fuel (-1.4 mb) oil more-than-offset a 0.4 build in light distillates. Despite the August draw, since the beginning of the year, total product inventories have broadly followed an upwards trajectory similar to OECD inventories and remain at close to July's historical high. At end-August, all products remained in surplus to average levels, with residual fuel oil's 7 mb surplus particularly startling.
- Crude oil prices plummeted to six-year lows in August on the back of a growing supply glut, escalating concerns over the health of the global economy, especially in China, and the associated devaluation of the Yuan. After rebounding on a slew of economic and fundamental data, prices turned volatile in late August. Brent was last trading at $48.10/bbl with NYMEX WTI at $45.20/bbl.
- Despite the fall in prompt prices, the contango in ICE Brent and NYMEX WTI held steady with spreads remaining below levels that encourage storage for profit. In contrast, the Dubai market was hit by a flurry of prompt trading that flipped the contract into backwardation during August.
- Spot product prices fell across the board in August. In contrast to early summer, gasoline and fuel oil prices posted the sharpest losses while falls in middle distillates were comparatively moderate. Crack spreads were mixed with those for gasoline plunging while middle distillate spreads generally firmed.
- Crude freight rates saw a dramatic turn of events in August, particularly for larger vessel classes. Rates on the MEG-Asia route for very-large-crude-carriers (VLCCs) lost as much as 70% in three weeks, just after scaling the highest year to date, ending the earnings bonanza ship owners enjoyed throughout the year.
Benchmark crude prices touched six-year lows in August on the back of a growing global supply overhang, escalating concerns over the health of the global economy, especially in China, and the associated devaluation of the Yuan. However, after sliding steadily for much of the month, prices rebounded in early September on a slew of economic and fundamental data. At the time of writing, ICE Brent was trading at $48.10/bbl with NYMEX WTI nearly $3/bbl lower at $45.20/bbl.
As prices rebounded late in August there was a noticeable increase in volatility with markets yo-yoing into early-September. Global markets were seemingly driven by sentiment and reacting to Chinese, European and US economic numbers, a revision to US EIA supply numbers and on US inventory data.
ICE Brent weakened at a faster pace than NYMEX WTI in August which saw the spread between the two grades shrink slightly to $5.32/bbl on a monthly average basis. However, the real movement was in Dubai, which strengthened relative to other benchmarks over the month. This may have encouraged traders to arbitrage flows of Atlantic Basin crudes to Asia with reports suggesting that at least one cargo of Forties has been fixed to sail eastwards in September.
Even as prompt crude prices tumbled, the futures markets remained relatively stable in a slim contango structure (where prompt oil trades at a discount to future deliveries) - thus limiting the appetite of stockholders to increase inventories for speculative purposes. Despite prompt NYMEX WTI prices being pressured lower by persistently high inventories at the Cushing, Oklahoma delivery point, by early-September the M1-M3 spread widened to $1.18/bbl from $0.98/bbl one month earlier. The M1-M12 spread narrowed by around $0.80/bbl to $4.92 at the time of writing. The changes were even smaller in the ICE Brent market where the M1-M12 spread stood at $6.58/bbl in early September, $0.14/bbl less than one month earlier, and far from the $1 per barrel per month required to cover the costs of land-based storage.
The one exception to the contango structure was the Dubai market, which flipped into backwardation following a flurry of trading activity between two Chinese state companies in the partials market causing the price for prompt barrels to soar compared to those for future delivery. Nonetheless, as buying activity cooled, the market had returned to a contango structure by early-September.
Financial markets were remarkably volatile in August, with hedge funds' exposure to ICE Brent plunging again during the middle of the month. The 'long-to-short ratio', an indicator of speculators' sentiment, approached lows which were last touched one year ago when prices first collapsed. Funds' exposure to WTI also inched down to new lows.
Trading volumes soared counter-seasonally for both ICE Brent and NYMEX WTI during August. Activity was also exceptionally strong for the United States Oil fund, the largest oil-indexed publicly traded investment vehicle aimed at retail investors. The fund saw near-record trading volumes and strong inflows from June to mid-August, suggesting cheaper prices attracted retail investors looking for a bargain. However, the trend reversed to outflows in late August, as volatility in the market appears to have discouraged investors.
The European Securities and Markets Authority (ESMA) is seeking comment on its Implementing Technical Standards under the MiFID II directive, including weekly positions reports for commodity derivatives.
ESMA has also opened a public consultation on the margin period of risk, i.e. the period that clearing houses have to cope with a potential client's default in order to guarantee its counterparty in a trade. The consultation intends to shed light on the possible harmonisation of US and EU rules and will close on 30 September.
Spot crude oil prices
Global crude benchmarks plunged in August as the global supply glut weighed heavy. This saw benchmark North Sea Dated plummet by $9.88/bbl on a monthly average basis. Moreover, during the fourth week of August it touched $42/bbl, its lowest level since 2009. By early-September, however, it had rebounded to above $52/bbl. European refiners appear well supplied, with crude inventories standing well above average. North Sea production remains above year-ago levels due to this year's relatively light field maintenance schedule, thus limiting the opportunities for imported crudes. Indeed, the discount of Russian Urals to North Sea Dated widened over the month as exports from Russia's Baltic terminals rose. Reports also suggest that African producers in August managed to place barrels in Europe, despite not cutting prices versus North Sea Dated during the month. However, the market could become more competitive over the next few months given the expected cut in crude demand as a number of refiners enter seasonal turnarounds.
During August, the consequences of an unplanned outage on a 250 kb/d heavy crude processing unit at BP's Whiting, Indiana refinery were felt across all North American crudes. The refinery completed a modernisation project in 2013 to allow it to process heavy crude oil. Consequently, the temporary shuttering of its largest crude unit had profound ramifications for Canadian crude prices. Western Canadian Select (WCS) quickly sank below $24/bbl in mid-August, its lowest level in nearly ten years and its discount to WTI widened to $20/bbl, the largest since 4Q14. Despite initial reports that the unit could be offline for several months, the unit restarted in late-August which saw WCS rebound to close to $35 /bbl at the time of writing.
US EIA weekly data suggest that, despite the outage, Canadian imports into PADD 2 ramped up during August. It is likely that a significant portion of these volumes found their way into tanks at the Cushing, Oklahoma storage hub, the delivery point of the NYMEX WTI contract. Indeed, during August, Cushing inventories remained stubbornly high at close to 80% of working capacity. This saw WTI pressured lower so that it lost $8.03/bbl to $42.86/bbl on a monthly average basis. Nonetheless, by early August, it had recovered some of the lost ground and was last trading at $46.06/bbl. As WTI delivered to Cushing weakened, in a rare move, WTI delivered to Midland, Texas shifted into a widening premium. By early September, WTI Cushing was trading approximately $2.20/bbl below Midland. This has also been helped by the recent commissioning of the 220 kb/d Permian Express II pipeline to evacuate crude to Gulf Coast markets that has seen producers shun pipelines to move oil from Midland to Cushing.
On the Gulf Coast, LLS drew support from a weaker dollar and the first hurricane of the season. Coupled with the weakness in the Brent market, this saw LLS rise to its highest premium over Brent since 4Q14. This could have enticed US market participants to increase imports of Atlantic Basin crudes which until recently had flowed to a trickle. Considering that recent US crude stock builds have been led by increases in imports rather than from domestic production, this could create further downward pressure on WTI if and when these cargoes arrive.
In Asia, sour crude markets strengthened on a flurry of trading in the benchmark spot Dubai partial-cargo market by two Chinese state companies, Chinaoil and Unipec. This saw the market flip into backwardation mid-month as prompt prices rose against prices for future months. Nonetheless, by early-September, prompt prices had once-again moved to a discount against future months. Despite the strength of Dubai, Saudi Arabia signalled its intent for its crudes to remain competitive in Asia by cutting the official formula selling prices of its light, medium and heavy grades for October delivery to customers in the region. The relative strength of sour crude markets and the comparative abundance of light crudes, also saw the discount of light, sweet Tapis versus Dubai widen to over $3.00/bbl on a monthly average basis in August from $1.00/bbl one month earlier.
African producers are reportedly struggling to place barrels after Asian buyers, which they have been increasingly targeting of late, reportedly cut back purchases. In August, China reduced imports of Angolan grades as it bought more Russian crude. That left producers with an overhang of unsold cargoes and frantically trying to place barrels in Europe and Asia. Despite low freight rates making long-haul trades more economical, the expected decrease in refinery throughputs over the next few months will likely weigh heavy and could see the differentials of African grades being trimmed against global benchmarks.
Spot product prices
Spot product prices fell across the board in August. In contrast to early summer, gasoline and fuel oil prices experienced the sharpest losses while falls in middle distillates were relatively moderate. Crack spreads were mixed with those for gasoline posting some of the steepest falls while middle distillate cracks generally firmed.
Gasoline prices in the Atlantic Basin plummeted from their mid-summer highs during August as buying interest from traders receded ahead of the traditional Labour Day weekend end to the US driving season. As concerns over market tightness dissipated, the backwardation in the M1-M3 spread of the RBOB contract flattened to $4.63/bbl in early September from $24.28/bbl one month earlier. The recent surge in gasoline prices seen in the Atlantic Basin was led by the US where refiners struggled to supply gasoline to the key demand centres and it was here that the sharpest losses were felt, with prices on the US Gulf Coast falling by an astounding $20/bbl on a monthly average basis. In contrast, European prices fell by about $13/bbl on the same basis. Nevertheless, the arbitrage window to ship gasoline from Europe to the US remained wide for much of August and only closed during early September.
Considering the scale of product price losses, falls in gasoline cracks were tempered by plummeting crude prices. On the US Gulf, cracks for super unleaded against LLS lost nearly $13/bbl while those for conventional gasoline slipped by $4/bbl. It is highly likely that while cracks for Super were hit by waning domestic demand, cracks for the latter grade were buttressed by healthy export demand for low-octane product to markets such as Latin America and West Africa. In Europe, gasoline cracks slipped by close to $3 /bbl although the fall in the Mediterranean market was tempered by the weakness of Urals relative to Brent.
Middle distillates cracks generally improved month-on-month after falls in spot prices were outstripped by plunging crude prices. The exception was in Singapore where improvements in cracks were dampened by the unusual strength in the Dubai market amid a flurry of prompt buying activity (see spot crude prices section). The strongest rises in diesel cracks were posted in the Mediterranean where they were buoyed by the weakness of Urals and healthy export demand from North Africa. Meanwhile, rises in diesel and gasoil cracks at Rotterdam were tempered by persistently high stocks amid an uptick in imports from Russia, the Middle East and the US ahead of the normal increase in regional refinery turnarounds. On the US Gulf Coast, diesel cracks firmed by $1.14/bbl as cargoes were sent to Europe and Latin America, although spot price gains were tempered by stock builds. In Singapore, middle distillate cracks turned the corner from July's exceptional lows and rebounded to more usual levels after an uptick in demand to ship product to Europe and Australia and amid tighter supplies, likely coming after Chinese refiners reduced exports.
In percentage terms, fuel oil markets experienced the sharpest losses with spot prices falling by more than 20% across surveyed markets. Asian markets were hit hard by Chinese teapot refiners reducing their intake of fuel oil as they have been given government permission to import crude oil. As Asian prices fell, the arbitrage to move fuel oil from Europe eastwards remained firmly shut for most of the month which in turn saw European prices weaken as refiners strove to offload excess volume. Eventually, European prices weakened to levels which one again made it economic to ship product to Asia. In Asia, the relative strength of Dubai saw cracks weaken steadily over the month, the Indonesian LSWR crack was particularly badly affected and by early September stood at -$10/bbl, the lowest since 2010 as reports suggest that Japanese utility demand fell as a nuclear reactor restarted.
Crude freight rates saw a dramatic turn of events in August, particularly for larger classes of vessels. Rates on the MEG-Asia route for very-large-crude-carriers (VLCCs) lost as much as 70% in three weeks, just after scaling the highest year-to-date, ending the earnings bonanza ship owners enjoyed since the start of the year. China sparked the drop in August fixtures as traders took stock of autumn refinery maintenance and the country increased its purchases of Russian ESPO crude. Spot trades represent about a third of the crude leaving the Arab Gulf as most of the volume moves on national oil companies' proprietary fleets. These rates remained stable.
Suezmaxes leaving West African traded at sharply lower rates on the month, the lowest level for the year-to-date. This came amid stable vessel demand with an oversupply in the region reportedly weighing heavy. Aframaxes saw modest activity in the North Sea and the Baltic on seasonally lower demand. Rates began to firm modestly in late August, with September loading schedules appearing to be busier.
Product tanker rates also weakened across the board, led by eastbound naphtha shipments on the MEG-Japan route. The market loosened after fixtures eased from a five-month high and a previous peak in rates attracted more tankers to the Middle East. The UK-US Atlantic 37Kt route came under pressure in August on fading gasoline demand as the driving season approached its end and limited exports from Europe. Weakness from lower gasoline demand spilled over into lower rates for vessels on the Caribbean - USAC trade. The US Gulf - Europe route came under pressure as well as there were limited opportunities to ship diesel eastwards.
- Global refinery crude runs peaked at an estimated record 80.9 mb/d in August. Seasonal maintenance in the region will now curb throughput and steeply falling freight rates for large ships East of Suez confirm lower forecast crude demand.
- Throughput for 3Q15 and 4Q15 is estimated at 80.4 mb/d and 79.9 mb/d, with yearly growth of 2.5 mb/d and 1.7 mb/d, respectively. The Middle East, China, Europe, and Other Asia led growth in 3Q15, with the FSU the only region to post a year-on-year (y-o-y) decrease.
- Margins have been unexpectedly resilient in August and explain high crude runs. Distillate cracks edged up despite persistently high global stocks, and gasoline cracks saw substantial declines. This combination weighed on margins in the US Gulf but sent European cracking margins up above $10 /bbl. Singapore margins edged higher despite the Dubai crude price shifting into backwardation due to relentless Chinese purchases of Dubai partials. Nonetheless, Chinese ex-refinery margins are getting close to zero, a possible indication of run cuts to come.
- Reported autumn maintenance schedules suggest outages at the low end of historical trends, peaking at 4.3 mb/d in October. While non-OECD maintenance is estimated at or above the historical average, announced shutdowns in the OECD remain below average, especially in Europe.
Global refinery overview
Global crude runs are expected to have peaked in August and look set to decrease due to scheduled seasonal maintenance - not because of plunging margins, as was feared last month. Y-o-y throughput growth is shifting from above 3 mb/d to below 2 mb/d.
With the driving season nearing to its end, gasoline is no longer the driver of high margins and cracks declined to more average values. Against expectations, high middle distillate stocks did not weigh on cracks. Diesel demand appeared in places like Africa and cracks started to increase seasonally. Higher scheduled maintenance levels in Russia over September and October also cast a doubt on the level of diesel exports to Europe.
We registered above 2 mb/d of newly reported shutdowns since last month's Report for September and October, which confirms our previous assumptions of a global autumn maintenance at the low end of the historic 5-year range, and peaking in October at 4.3 mb/d. Reported data now shows non-OECD maintenance levels around their historic average (2.65 mb/d in October) except for Latin America (below average) and the Middle East, above average, with outages peaking at 1.0 mb/d in October. In OECD regions, maintenance is expected to be low but still within the 5-year range in the Americas (1.1 mb/d in October) and Asia Oceania (0.55 mb/d in October). In Europe, our information shows very limited maintenance, peaking at 0.3 mb/d in September, vs. a historical average peaking in October at 1.3 mb/d. This could be missing information or because refiners deliberately chose to postpone maintenance amid good margins.
In June, global crude runs reached 79.5 mb/d, only 0.2 mb/d higher month-on-month (m-o-m) but still 3.2 mb/d higher year on year (y-o-y). Once again, it is remarkable that OECD accounts for the largest part of the y-o-y increases (1.8 mb/d, with half of it in Europe). In the non-OECD, all regions bar the FSU showed an increase, with Other Asia the largest.
In July, the most recent month for which a complete set of monthly data is available, OECD refiners posted a 1.5 mb/d m-o-m increase in crude throughput bringing it to 39.0 mb/d - 1.4 mb/d above a year earlier. OECD Europe leads both in m-o-m and y-o-y increases while OECD Americas seems to be plateauing, probably close to its maximum capacity. Preliminary figures for August show OECD runs stable before the maintenance seasons starts in earnest: throughput is then expected to plummet to 38.1 mb/d in September then 37.2 mb/d in October.
Global crude run estimates for 3Q15 have been raised by 240 kb/d since last month's Report, to 80.4 mb/d, and 4Q15 crude runs are now predicted at 79.9 mb/d. 3Q15 upward revisions turned up in OECD for 0.4 mb/d, with half in Europe. The negative -0.15 mb/d revision in the non-OECD is a result of lower-than-expected throughputs in China and a heavier maintenance schedule announced for the FSU (more September maintenance) offset by some increase in Latin America and the Middle East. All regions, bar FSU and Latin America, contribute to the 3Q15 2.5 mb/d y-o-y growth.
The strength in gasoline margins finally gave in with the tail end of the driving season. Over August, gasoline cracks lost $20/bbl in the US Gulf, $6/bbl in Singapore and $13/bbl in Europe. More unexpectedly though, despite the high level of stocks, middle distillates cracks started to increase moderately, with Singapore levels back above $10/bbl amid reports of growing exports to Africa and Europe and news of higher seasonal maintenance in Russia. The contango in diesel prices simultaneously decreased. The fuel oil cracks were stable in August, for the month as a whole, though rising during the first half of the month before falling back towards end-month. The combination of these trends - and the larger importance of gasoline in the US - weighed on US margins, but lifted them in Europe and Singapore. The NWE Brent cracking margin reached $10.05 /bbl, the highest since 2008 with the exception of September 2012. In Singapore, the Dubai hydrocracking margin firmed to $4.83/bbl - an average value. In the US Gulf Coast, the HLS/LLS cracking margin lost $1.67 /bbl to $12.04 /bbl (still $3.6/bbl higher y-o-y), and a similar situation prevails for US Gulf coking margins. The US Mid-continent margins shot up by $6-8/bbl, but only because of lower regional output during the BP Whiting refinery outage, which has since been resolved.
OECD refinery throughput
OECD refinery crude runs increased by 1.5 mb/d in July from June, to 39.0 mb/d. Japan and Europe shared most of the increase, however the US edged up from a high 16.7 mb/d to an even higher 16.9 mb/d. The sharp increase in Japanese throughputs in July comes mostly from the comparison to a low June. Still, July's relatively high level does not seem to reflect the announcements of reduced throughputs heard of from Japanese companies last month; and neither does August, with preliminary figures another 0.26 mb/d higher. July refinery utilisation rates are now high in all the OECD: 87% in Europe to 89 % in Asia Oceania and 91% in the Americas.
OECD throughput for 3Q15 was revised up by 0.4 mb/b to 38.7 mb/d, with final figures for July and provisional ones for August up by 0.5 mb/d. The largest revisions take place in Europe, the 0.2 mb/d revision was spread in a number of countries, with Spain and Netherlands the highest. In Asia Oceania, Japan led the 0.1 mb/d upward revision.
In the OECD Americas, crude throughput reached 19.7 mb/d in July, after a downward revision of 0.1 mb/d due essentially to lower intake in Mexico. Preliminary figures show August just edging up.
In the United States, unexpected shutdowns strongly affected margins in August: in PADD 2, a partial 250 kb/d shutdown of BP's Whiting refinery sent the local crude prices on a downward spiral, lifting coking margins to above $55/bbl. However, the shutdown was shorter than initially expected, and margins settled rapidly back to more usual values. The West Coast was also subject to various operational problems at Tesoro's Los Angeles and Exxon's Torrance refinery amongst others, which created tightness in gasoline markets. In the East Coast, FCCs shut down in PBF's Delaware and Phillips' Bayway refineries. However, crude runs eased end-August, with weekly throughput decreasing for four weeks successively, from a peak of 17.1 mb/d down to 16.4 mb/d. Maintenance is expected to peak in October at 1.05 mb/d, at the low end of the 5-year range.
Europe's crude processing rose to 12.4 mb/d in July, 0.75 mb/d higher m-o-m, the highest value since summer 2012, despite relatively low utilisation rates in France and Italy. Other countries compensated, for instance Germany with a 94% utilisation rate. Notwithstanding still very high middle distillates stocks, diesel cracks edged up $1.7/bbl above last month to an average $15.1/bbl. NWE Gasoline cracks fell from $27/bbl early August to below $15/bbl at the end of the month. Consequently average NWE Brent cracking margin rose by $0.50/bbl to $10/bbl. Hydroskimming margins also remain clearly positive. Announced maintenance appears to be particularly low this autumn, peaking at 0.3 mb/d in September when the 2010-14 average peaked in October at 1.3 mb/d. We expect final autumn maintenance levels to be revised significantly higher from this 0.3 mb/d figure, even if a number of planned shutdowns may have been deferred until 2016 to benefit from the good current margins. The latest example was the postponement of Repsol's Cartagena 4Q15 maintenance shutdown to 2016, announced on 8 September. Lower VLCC freight rates have incentivised exports of fuel oil to Asia, and three shipments are already reported for September, with fuel oil cracks narrowing at the end of August.
OECD Asia Oceania
In OECD Asia Oceania July crude runs increased to 6.8 mb/d, 0.6 mb/d higher m-o-m. This is mainly due to the end of a rather high June maintenance in Japan, and this value is very much in line with past years. Seasonal autumn maintenance is announced slightly below average, peaking at 0.54 mb/d.
The run cuts announced for August in Japan on account of the excess supply of middle distillates failed to materialize, with preliminary weekly figures for August showing throughput reaching 3.4 mb/d, 0.3 mb/d higher m-o-m and 0.2 mb/d higher y-o-y. In August, margins bounced back by $1-3/bbl from a dismal July, which explains the strong refinery runs. We will have to wait for next month to see if, in Korea, GS Caltex and SK Energy did implement the run cuts both companies had announced early August.
Non-OECD refinery throughput
In June non-OECD refinery throughput increased by 0.3 mb/d to 42.1 mb/d, after a minimal monthly revision of 0.1 mb/d. In contrast, July forecast edges down by -0.3 mb/d. The largest contributor to the 1.4 mb/d y-o-y growth for June is Other Asia, (1.0 mb/d), followed by China and the Middle East, and partly offset by a negative -0.4 mb/d for FSU.
Estimated quarterly figures for 3Q2015 and 4Q15 hit 41.7 mb/d and 41.8 mb/d respectively. 3Q15 has been revised down marginally by -0.2 mb/d, lower in China and the FSU and higher in Latin America and the Middle East. The y-o-y growth in the non-OECD is now estimated at 1.5 mb/d in 3Q15 and 1.0 mb/d in 4Q15.
In China, July crude runs fell by 0.3 mb/d to 10.25 mb/d, after a 0.2 mb/d increase in June to 10.55 mb/d. These high runs continued to generate large diesel exports: approximately 0.16 mb/d in June vs. an average of 0.10 mb/d over the first 7 months of 2015. A fourth batch of oil products export quotas has been allocated by the Chinese authorities, with growing gasoil volumes, and refiner's gasoil exports could keep growing in the second half. Autumn announced maintenance is above the 5-year average, peaking at 0.5 mb/d in November, with six Sinopec refineries off-line. Internal ex-refinery margins have been decreasing steadily since May, when they reached around $12/bbl. They continued to do so in August, reaching a low of $1-2/bbl, which could end up weighing on throughputs.
June throughput in Other Asia reached 10.5 mb/d, 0.3 mb/d m-o-m growth, boosted by India's record intake, but also by strong runs in Singapore and Indonesia. Announced seasonal maintenance is roughly at its average, but peaks early in September at 0.5 mb/d, with three Indian refineries - Essar's Vadinar, MRPL's Mangalore and IOC's Koyali - offline. In India, July crude throughput fell by 0.3 mb/d from its June high, to 4.4 mb/d. Singapore September crude runs might be reduced due to a fire that delayed the restart of Shell's 500 kb/d Singapore refinery at end August.
FSU June crude runs were unchanged m-o-m at 6.9 mb/d, lower by 0.4 mb/d y-o-y. Autumn maintenance has been revised upward, to 1.1 mb/d in September and 0.7 mb/d in October, close to the 5-year average. Eleven Russian and one Kazakh refineries are expected to stop at one point in September. This higher estimate curbs our previous September throughput figure to 6.5 mb/d.
Russian throughput crept higher over the summer, from 5.7 mb/d in June, to 5.9 mb/d in July and 6.0 mb/d in August. However, like in China, poor ex-refinery margins may not justify running flat out. Refinery runs for the first eight months of the year have been 1% lower y-o-y, and are expected lower for the rest of this year.
Middle East crude runs in June were revised down by 0.2 mb/d to 6.5 mb/d. Saudi Arabia accounted for more than the entirety of this revision as its crude intake decreased from 2.4 mb/d in May to 2.1 mb/d in June - but is expected to rebound to 2.5 mb/d in July. Autumn outages this year are reported above the average, peaking at 1 mb/d in October with four large refineries offline: Saudi Aramco's PetroRabigh and Sasref, KNPC's Shuaibah - which shut down for one week during August because of a fire - and Iraq's Baji refinery, still mired in local conflicts.
In Latin America, June throughputs were stable at 4.8 mb/d, after a small upward revision of 0.1 mb/d. Announced seasonal maintenance is well below the average, however we expect additional unreported maintenance especially in Venezuela.
In Africa, June crude throughput rose by 0.1 mb/d to reach 2.2 mb/d. In Nigeria, the Kaduna refinery was the last one of the four previously shuttered refineries to restart, in August, and we expect to see some increase in JODI figures in the next few months.