Asia and the Middle East continue to invest in refineries despite oil price
The majors have seen their refinery fortunes rebound this year. But the super-refineries in the Middle East and Asia and rising ethane output in the US continue to put pressure on refiners to change their ways
The Middle East and Asia are changing the face of refining, building big plants with an eye on exports as well as satisfying rising domestic demand coming from their emerging middle classes. With low feedstock prices combined with economies of scale, their ambitions could spell more bad news for operators of inefficient plant, particularly in Europe.
Undeterred by the low global oil price, Gulf officials are keen to push ahead with new projects at a time when lower commodity prices are making construction material less expensive than in the past. “Many projects around the region are being cancelled. But this is a unique opportunity for us when oil prices are down,” said Kuwait National Petroleum Company’s manager for technical services, Nadia Bader Yousef.
The mid-October signing of a $13bn package of contracts to build a 615,000 b/d-capacity oil refinery in Kuwait is part of a drive to make the emirate a major downstream industries hub in the region.
Output from the al-Zour plant, in the Neutral Zone shared with Saudi Arabia, will account for more than a third of the new 1.8m b/d refining capacity that is planned in the GCC states over the coming decade.
Commissioning is scheduled to start in November 2019, with commercial production expected to begin the following year. The project, which has been on the drawing board for many years, has been beset by political squabbles and rising costs. Further delays to the project cannot be ruled out.
The new refinery will produce low-sulphur fuel for the country’s power generation sector. Despite the current low level of global oil prices, the Kuwaiti government is stressing that the refinery project will go ahead without the need for external financing.
Construction will take place in parallel with a Clean Fuel Project (CFP) that involves a major upgrade of the Mina al-Ahmadi and Mina Abdullah refineries and their gradual integration into a single unit with capacity to produce 0.8m b/d of higher-value products like low-sulphur diesel and kerosene for export. The package will involve 67 new units and the revamping of up to 20. When the CFP is complete, the 200,000 b/d Shuaiba refinery will be closed and turned into a storage depot and distribution centre for the domestic and export markets.
Saudis set the pace
Kuwait’s strategy now is to develop its downstream sector in a way that sees a gradual merging of oil refining and petrochemicals – a process that is well under way in Saudi Arabia, the giant of Middle East refining.
Responsibility for developing the Saudi energy sector has traditionally been divided between two state companies, with Saudi Aramco handling oil production and refining, and Sabic – along with private ventures – focusing on gas-based petrochemicals.
But in recent years Aramco has been moving into the petrochemicals sector through integrated refinery/petchems projects. Petro Rabigh, a joint venture between Aramco and Japan’s Sumitomo Chemicals on the Red Sea coast, began production in 2009 and is set for a huge expansion in the form of Rabigh 2 in 2016. But the jewel in the crown is the $20bn Sadara project – a JV between Aramco and Dow, which is due to start commercial production in 2016. Sadara will produce a range of high-value petrochemicals that rely more on refined naphtha as feedstock than natural gas (ethane). When Rabigh 2 and Sadara are completed, Saudi Aramco’s production will rise by 6m mt/y to around 15m mt/y. Sabic’s annual output is around 56m mt/y.
There are several reasons for Aramco’s changing role. For a start, the kingdom has vast reserves of oil, so it makes sense to extract more value from the crude and hedge against a day when oil exports might decline. At the same time, easily accessible reserves of natural gas (ethane) are dwindling. The extremely low gas sales price in the kingdom ($0.75/m British thermal unit (Btu)) makes it uneconomic for energy companies to develop more difficult reserves when development and production costs can be in the region of $4-6/mBtu.
The petroleum ministry is unlikely to approve further gas allocations to potential new Sabic or private petrochemical ventures. Sabic’s chief executive Mohamed al-Mady said in 2014 that “the shortage of gas and many sectors competing for it have made expansion very hard.” Any extra supplies of gas are likely to be channelled to the power sector to cut back on the huge volumes of oil burnt during the peak summer months.
Output from the Saudi refining sector has increased sharply over the past two years and is set for further expansion. The 400,000 b/d Satorp plant began production in 2013 and Yasref reached the same capacity in June this year. Yet another 400,000 b/d refinery is scheduled for start-up in 2018 at Jezan in the far south of the country. But this is close to the border with Yemen so if hostilities there continue, there must be a possibility that this project will be delayed.
Expansion is also planned at the GCC’s oldest refinery – the 267,000 b/d Sitra plant in Bahrain – which was built in 1936. Most of the crude it processes comes from Saudi Arabia, and an EPC contract was signed in September for a new 350,000 b/d pipeline from the kingdom, which is scheduled for completion in 2018. The hope is that by then, work will be under way to expand production capacity to 367,000 b/d, with the focus on boosting middle distillate capacity. However, financing difficulties could hold up this much-delayed project still further.
Oman EPC bids expected soon
Elsewhere in the GCC, work is continuing at the Qatargas Laffan 2 refinery and it is expected to start processing 146,000 b/d in 2016; and engineering, procurement and construction bids are expected for Oman’s 230,000 b/d capacity Duqm refinery in the coming weeks. The latter is a joint venture between Oman Oil Company and Abu Dhabi’s International Petroleum Investment Company (Ipic). The joint venture envisages the development of an adjacent petrochemical complex to include a mixed feedstock cracker, polypropylene plant, an aromatics facility and a styrene unit.
Ipic is also a stakeholder in a 200,000 b/d refinery which is under construction at Fujairah in the UAE, which is expected to be on-line by 2020. It will “produce middle distillates primarily for the northern Emirates of the UAE, for export and for bunker fuel.” Abu Dhabi refiner Takreer, meanwhile, brought its 417,000 b/d Ruwais expansion project on line earlier this year.
Post-sanctions Iran is likely to become a major player on the Middle Eastern refining stage. For example, work is under way at the Siraf Refining Park, which, according to National Iranian Oil Refining and Distribution Company, will consist of eight condensate splitters with a total capacity of 480,000 b/d. But financing difficulties, at least in the short term, are likely to slow the project’s progress.
Away from the Gulf region, Egypt is undertaking several refinery upgrade and expansion projects to meet the growing demand for petroleum products. As part of the plans the crude oil distillation capacity of the Midor refinery in Alexandria is being increased from 100,000 b/d to 160,000 b/d – with completion scheduled for 2018.
While the overall Middle Eastern refining picture is one of expansion, the spreading instability in the region has taken its toll. Libya’s Ras Lanuf refinery – the largest in the country with 220,000 b/d capacity – has been forced to shut down, while operations at Zawiya (120,000 b/d) have been severely disrupted.
Yemen’s aging 150,000 b/d Aden refinery was shut down early in 2015 when Houthi forces and their allies took control of southern parts of the country. But the subsequent Saudi-led military operation forced the Houthis out of the city, and one of the refinery’s two 75,000 b/d CDUs resumed operation late in September.
The year ahead for Middle East refiners is by no means one of guaranteed prosperity. Low oil prices will force major producers to trim budgets, which will likely lead to some project delays or cancellations. Algeria is one of the countries likely to be hard hit. Its plans to upgrade and expand the Algiers and Hassi Messaoud plants – to bring capacity from 651,000 b/d to 676,000 b/d – are now in question. Morocco’s sole 200,000 b/d Samir refinery was forced to close in August because of financial difficulties.
Also, much of the strategic planning of the region’s refiners – aside from meeting surging domestic demand in line with rising population figures – has been guided by the prospect of the expanding appetite for diesel in Asian markets, and China in particular. Asia’s slowing diesel demand growth is one of the challenges that Middle Eastern refiners face as they seek ways of surviving in an increasingly competitive global market.
Mixed picture for Asia Pacific refiners
Despite the prospect of shutting older refineries and narrower margins, refining capacity in the Asia-Pacific region is expected to expand by 3.2m b/d between 2015 and 2020 as demand rises. That compares to an expansion of 2.2m b/d between 2010 and 2014, data from energy consultancy IHS shows.
Regional refining capacity, which runs at about 76%, stands at around 30.4m b/d or roughly one-third of the global total. South Korea, India and Singapore are home to some of the world’s largest refineries. Since 2008, China and India have been ramping up capacity to feed their fast developing economies and in terms of total crude processing capacity, they are the biggest in Asia Pacific.
But investments in the two countries are slowing down, particularly in China, which used to add around 0.7m b/d of capacity every year, Sushant Gupta, an Asian refining specialist at Wood Mackenzie tells Petroleum Economist.
“We expect China to add 250,000 b/d of capacity every year over the next four to five years. But the demand pattern is changing and they’ll maintain a surplus of middle distillates, as demand for diesel has slowed significantly, which will boost exports,” adds Gupta. India will add about 0.6m b/d of refining capacity by 2020 to meet the growth in domestic demand for gasoline and diesel.
In southeast Asia, Malaysia and Vietnam each aim to add a major refinery in the next five years. Malaysian national oil company Petronas’ 300,000 b/d Rapid project is targeted to start up in 2019, while PetroVietnam’s 200,000 b/d Nghi Son refinery is planned to start up in 2017. More refining capacity is expected in fast demand growing and large importing countries, such as Indonesia, Vietnam, Bangladesh and the Philippines after 2020 to help keep increasing import levels in check too.
But runs in key export refineries in South Korea, Taiwan and Singapore are expected to moderate as they face intense competition from new, export refining complexes in the Middle East and India. In future, ageing refining capacity will likely be shut in Japan, Australia and Taiwan, Yam Chuan Baey, a Singapore-based downstream specialist at IHS, told Petroleum Economist.
Baey expects incremental output from the Middle East to compete directly with Indian exports to the Middle East, Africa and Europe. That will in turn drive more Indian barrels to other export markets in Asia Pacific, such as southeast Asia and Oceania. “Other key Asian exporters in South Korea, Taiwan, and Singapore, will likely face more competition from Indian exporters Reliance and Essar, which are considered to have a location advantage, being nearer to the Middle East crude source,” he says.
Crudes from the Middle East remain important to feed Asian refiners. But grades from other regions, such as Russia, as well as new production from Iraq, are increasingly supplying the region. West African grades pushed back from the US market are heading to Asia too, while heavy crudes from Latin America remain the choice of Chinese and Indian refiners.
Refining margins in Asia, which have been strong since the third quarter 2014 and started to dip in the second quarter this year are expected to narrow further towards the end of 2015, pressured by increased supply. For the first half 2015, benchmark margins in Singapore averaged $5.50/b compared to $1.80/b over the same period in 2014.
Refining margins have been inflated owing to the lag between crude and products markets, as well as lower operating costs. But they remained far from peaks of $8-9/b seen in 2008. During the second half 2015 margins started to dip and will remain low until more capacity closes or demand growth picks up pace, said Gupta. Even until 2018-19, rising supplies are projected to outpace demand growth, leading to a longer downturn this time around, he adds.
In the past couple years, demand growth has expanded at an average 3-4% annually. It is expected to grow by only 1.8%/year by 2020. In particular, demand expansion in China, which has bolstered the market for over a decade, is slowing.
Rising product exports from the US, which have cut demand for surplus output from Asia in the Atlantic basin market, as well as new refining capacity in the Middle East, are squeezing Asian margins too. Still, Baey expects Asian refining margins will recover, as refinery closures coupled with rising demand, supports reinvestment by early next decade.
In terms of consumption, gasoline and diesel will make up more than half the total regional refined product demand in future. Strong growth in gasoline demand will continue as more people buy cars in developing economies. But that growth will be capped by tightening fuel economy standards, higher fuel substitution, as hybrid-electric cars gain market share, as well as cuts in government fuel subsidies, Baey adds.
Diesel demand growth will continue to be driven by the transport sector in the developing economies, while its use in industry and power generation, will be limited as it is replaced by natural gas.
While stricter emissions standards are being introduced next year in the Philippines and Vietnam, the refineries are not all fully prepared, so they will have to import cleaner fuels from overseas, warns Gupta.
China will also introduce its National Phase 5 emissions standard, roughly equivalent to the Euro 5 standard, countrywide in 2017, which means Chinese refiners will be investing in higher hydrotreating capacity to make cleaner fuels, he adds.
US refiners adopt a light touch
Until the last few years, many US refineries were geared up to handle some of the world’s thickest crude, processing heavy, sour crudes from California, Canada, Latin America and elsewhere. Now the emphasis has switched to processing domestic light, sweet crudes raising questions over the industry’s ability to handle everything the country’s shale and tight oil boom can throw at it.
But refiners have been keen to stress they do have the necessary capacity. The American Fuel & Petrochemical Manufacturers (AFPM), an industry body, said a survey of refiners it produced earlier this year showed the US can and will process a lot more light oil in the next few years.
AFPM said this would be achieved via a number of avenues: replacing imported light crude of similar quality to US light crude oils; increasing overall refinery utilization rates; replacing light high-sulphur and medium-gravity imports with US very light crude oil; and investing in new units to utilize more of the new US light crude.
The survey found respondents – from 23 companies operating around 60% of US refining capacity – were planning to process over 0.73m b/d more very light crude oil in 2016 than they did in 2014. Respondents also said that if access to the new crude oil were not an issue and economics supported increased use of this oil, they would be able to run a further 0.8m b/d in 2016, bringing the total increase to 1.5m b/d.
While neither access nor economic conditions are likely to improve enough to warrant that maximum amount of expansion, the survey still suggests that the industry is prepared to absorb rising levels of domestic production.
At the time of the survey, the Energy Information Administration (EIA) was forecasting that tight oil production across the US lower 48 states would increase by 720,000 b/d between 2014 and 2016, slightly less than the expansion already planned by those companies polled – which itself is a figure that would be bolstered by output from refineries accounting for the other 40% of domestic capacity.
The US has about $8bn of new refining projects planned or under construction. The majority of this new capacity will be geared towards processing additional light domestic crude. The total capital cost also includes secondary units, such as hydrocrackers, to produce additional middle distillates, such as jet fuel and diesel. Imports of similar grade crude from places such as Nigeria can be expected to fall as a result.
Meanwhile, Gulf coast refineries will continue to process heavy crude from Latin America and potentially increase supply from Canadian oil sands. That would be made easier if the Keystone XL pipeline plan, which is on hold because of political wrangling, is approved, providing a route from Alberta to the Gulf of Mexico.
Gasoline demand supports margins
Investment plans have been supported by high margins through the year. These were caused initially by the fall in crude feedstock prices, at a time when refined product prices remained high. Typically, the price of gasoline and other refined products would follow oil prices down after a delay of a few months, but this year, margins have been held up by high demand for gasoline, as vehicle drivers took advantage of low pump prices to get out on to the roads more in the peak US driving months of summer.
This strong demand is reflected in data for July 2015 showing operating capacity was at an all-time record and capacity utilization was at its highest since 2004.
Demand for refined products has come not just from within the US. In the early part of the year, unplanned shutdowns in Venezuela, the delayed completion of refining capacity in Brazil and the continuing low utilisation of Mexican refineries prompted Latin American customers to turn to the US and Europe to make up the shortfall in gasoline supply, Alan Gelder, Wood Mackenzie’s head of refining research said in a note in late September.
While gasoline demand traditionally eases after the summer, planned and unplanned maintenance at US refineries may help prop up margins – and there is little sign that stocks of gasoline – or other refined products – are growing significantly, despite record levels of production.
Outages and opportunities
Not all refiners have had it their own way in recent months, though their problems have provided ambitious rivals with a chance to scale up their operations.
Refiners have long lamented the business climate engendered by California’s efforts to reduce fuel consumption as part of its climate change strategy. The state recently dropped ambitious plans to halve petroleum use in vehicles by 2030, following industry lobbying, but still remains committed to reducing it.
The medium-term outlook for refiners will be heavily influenced by the direction of the oil price
In the past, some companies, such as Valero – which has 305,000 b/d of refining capacity in the state – have said they might pull out of the state, given a potentially tough regulatory environment for the fuel market. However, while larger refining companies have focused on assets elsewhere, up-and-coming competitors keen to diversify their portfolios have seized opportunities in the state.
In September, independent refiner PBF Energy agreed to buy ExxonMobil's 155,000 b/d refinery in Torrance, near Los Angeles, for $537.5m. The deal is PDF’s second refinery acquisition of the year, having bought a 189,000 b/d refinery in Chalmette, Louisiana on the Gulf coast for $322m from a JV ExxonMobil and Venezuela’s PDVSA in June.
These purchases mean PBF, led by US refining veteran Tom O'Malley, now has refineries in four of the five main refining regions in the US, putting in a stronger position to compete with leading players such as Phillips 66, Marathon Petroleum, Tesoro, HollyFrontier and Valero.
The Torrance refinery has a troubled past, having been shut down in February after an explosion on the site. Since then ExxonMobil has not been allowed to run the fluid catalytic cracking (FCC) unit, while repairs and improvements are made. Under the purchase agreement, the refinery is to be handed over to PBF in full working condition, when it assumes control in the second quarter 2016.
While the Torrance shutdown has cost ExxonMobil dearly, the loss if its output, which meets around a fifth of southern California’s gasoline demand, has benefited other Californian refiners, taking edge off their concerns over state energy policy for now at least. Profits from California’s operating refineries due to a shortage of gasoline and rising demand over the summer months.
Torrance is not the only refinery to shut down because of operational difficulties. A halt to operations at one the three crude distillation units at BP’s 413,000 b/d Whiting refinery in Indiana for more than two weeks in August triggered a fall in the WTI benchmark for lighter US oil, due to oil originally destined for Whiting being re-routed to the storage facility in Cushing, Oklahoma. It also caused a sharp rise in gasoline prices across the Midwest due to the loss of output from the refinery.
Oil export concerns
The medium-term outlook for refiners will be heavily influenced by the direction of the oil price. While that may be subject to factors beyond US borders, refiners are also watching the debate over ending the four-decade long ban on US oil exports – intended primarily to help US producers – with some trepidation.
Increased international oil sales, should they happen, are likely to narrow the spread between the Brent and the US WTI crude benchmarks, as the price of US oil rises to become more closely aligned with international crude prices. That would push up the cost of feedstock for refineries in several US regions, potentially reducing margins.
Some supporters of lifting the ban have suggested it would have minimal effect on the US refining sector, given refined products are already allowed to be exported and that the price of gasoline, for example, is consequently already influenced by international market conditions.
However, the EIA released a report in September, analysing the impact of the removal of the ban, which concluded that a resulting rise in oil prices could reduce the US refining sector’s profits by nearly $23bn/y by 2025 compared to what they would have been were the ban still in place, assuming US oil production was at the high end of the EIA’s forecasts.
That does not mean that refiners will necessarily be worse off than they are now. “With or without current crude oil export restrictions, domestic refiners are… expected to maintain a significant advantage compared with offshore refiners given the continued projected availability of low-cost domestic natural gas, which is used as both a fuel and feedstock by refiners,” the EIA said.
The refiners themselves are putting a positive spin on the prospect of the ban being lifted. When asked at a presentation in September about the possibility that it could happen as early as January 2016, Greg Garland, chief executive of Phillips 66, one of the country’s largest refiners, said he thought the added cost of moving US oil to refineries in Europe – which he estimated at $3-5/b – meant US refiners would not be put at a disadvantage to overseas competition.
“I know different people have different views on that and what it means to the refining business. But I don't think it's going to be as big a deal as some people think,” he said.
Europe’s refiners, having been the sick men of the sector for the last five years, are now experiencing the euphoria of widening crack spreads and positive margins. Demand for diesel and motor gasoline, as well as low oil prices – where the US leads the field with the relatively low WTI trading at a discount to Brent – that has widened the crack spread and brought welcome relief for Europe’s integrated companies.
The region is still finding it hard to compete with the US, the Middle East and Russia in diesel production, while it is long in gasoline. And on top of all that, uniquely, the sector sees itself as under siege from the European Commission which it says is finding more ways to stifle investment by adding costs, delegates heard at a conference in Hungary in mid October.
Volatility is expected to be an enduring feature. Today’s wide spreads do not encourage plant closures, though refiners themselves say they are necessary.
For the time being companies’ refining divisions have been recording exceptionally good profits for the second quarter but this could be seen as a coat of varnish disguising the shabby state of the industry.
According to Dorothee Arns of lobby group Petrochemicals Europe, China’s share of the growing market is forecast to shoot up over the next 15 years while the EU’s share is set to continue to decline, despite its better-motivated work force. Assets are nearing the end of their life and less efficient; and regulations are also impeding progress, she told the conference.
The power market is also distorted: while wholesale prices have fallen in the past few years, network costs have risen and so have taxes and levies in order to promote renewables.
The European Commission’s regulation on the Registration, Evaluation, Authorisation and Restriction of Chemicals, its industrial emissions directive and its emissions trading scheme may have been well-intentioned; but if nobody was following the lead set by the EU then the region would be at a competitive disadvantage.
So the belief is that a lot needs to be done to close plants and to find new ways of making money from oil. These include using naphtha-based feedstocks in higher-value petrochemicals, as opposed to the wave of ethane-based US petrochemicals products following the huge increase in oil production on that side of the Atlantic. But ethane itself is heading to Europe too, with Swiss-registered petrochemicals company Ineos on the buying side.
The plants that do survive the bloodletting must be flexible, efficient and operate with a very high level of reliability in order to ensure they capture the spreads when they are there, says MOL group’s senior vice-president for downstream, Miika Eerola. But while refiners have no impact on the oil price, he said MOL also did not hedge its costs. Options to buy crude and sell products could mitigate some of the volatility by locking in a margin, but for now the company prefers exposure to the underlying prices.
Another beneficial side-effect of the low oil price for refiners is that it makes economic nonsense of two of the EC’s big ideas that threatened traditional refining: the electrification of transport; and biofuels. These ideas might work when oil is over $120/b but not when it is as low as $50/b, said the director-general of Fuels Europe, John Cooper.
Not hedging their bets
Some refiners are diversifying and investing in more profitable petrochemicals lines, such as MOL. It is investing in a butadiene plant that will produce synthetic rubber for tyres. Slovnaft, part of the MOL group, has also invested €300m in a major new low-density polyethylene plant which is pre-commissioning now and due on stream early next year, with a nameplate capacity of 220,000 metric tons/year. It replaces three smaller plants, adding 41,000 mt/year of output, and it will rely partly on greater energy efficiency to become more competitive with its rivals which are all based outside the EU, in countries such as China, the Middle East and Russia.
Some refineries in eastern Europe also have the legacy of the Cold War to cope with: built at a time when aerial bombardment was a possibility, the different units of their plants are spaced so far apart within their territory that they cannot use energy and heat as efficiently as they would like; while cyclical maintenance work means that the units are all at different stages of their working lives, rather than facing retirement at the same time.
Traditional transport fuels will remain a big part of MOL’s business, but here too there are new offerings such as its Fresh Corner cafes, which claim to offer the best coffee in Hungary and are designed to tempt customers into spending money on other things than low-margin fuel.
Total’s refining and chemicals president Philippe Sauquet told the Oil & Money conference that 2015 was witnessing the return of the downstream, thanks to the low oil price and the closure of uncompetitive capacity – but there was still more to be done in that direction. He said Total had closed several refineries across Europe: “We are doing our share and we expect others to be doing theirs too.”
Among Total’s plans is the conversion of its La Mede refinery near Marseilles, from crude distillation to a biorefinery in order to meet demand for biofuels. Within the EU a tenth of car demand is to be met by renewables by 2020, “but we are far from 10% today,” he said. France is going further than required, aiming at a 15% mix in gasoline or diesel by 2030 up from 7.5% today.
By 2017, La Mede will be produce 500,000 mt/year of hydrotreated vegetable oil (biodiesel)/year, using new French technology developed by public research, innovation and training center IFP Energies Nouvelles and marketed by its affiliate Axens.
Sauquet said Europe had witnessed the best growth in margins but that it was still handicapped by the diesel-gasoline imbalance. He said the industry needed to take a long-term view to progress its business. There is political pressure in Europe to clean up gasoline for cars; and demand will fall further as fuel efficiency grows. Bunker fuel is also becoming cleaner with the EC-enforced push towards ultra-low sulphur (0.1%) gasoil in ships operating in the Baltic and North Seas and the English Channel, with effect from the start of this year. Later on this will extend to more regions and to rivers. This is a sector where LNG could play a part although so far the infrastructure barely exists.