Special Report: New environmental challenges to test European refiners’ flexibility, resources

June 15, 2009
European refiners have enjoyed a short period of extremely good profitability caused by a tightening of refining capacity in the Atlantic Basin.

European refiners have enjoyed a short period of extremely good profitability caused by a tightening of refining capacity in the Atlantic Basin. The current recession, however, with the consequent loss of demand, has taken pressure off capacity and margins have reduced but not collapsed.

European refiners face new challenges driven by environmental concerns of a different order of magnitude from earlier ones. These challenges will test the flexibility and resourcefulness of participants. They will make more important than ever before the necessity to work with regulators to ensure realistic solutions that meet reasonable environmental objectives with due consideration to consumer and industry needs.

This article defines Europe as those countries to the west of Belorussia, Moldova, and Ukraine. Most (27) are members of the European Union and many not currently members wish to join.

The region covers 38 countries, a number that has grown as some of the countries in the East have subdivided. The most recent addition to achieve full international recognition is Montenegro, which sits between Albania and Bosnia.

Repsol YPF SA’s 160,000-b/d Terragona refinery was one of several European refineries that in 2008 performed maintenance to units producing low-sulfur fuels to reduce carbon emissions. An EU directive on cleaner-burning diesel took effect in January 2009. Photograph from Repsol.
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The EU dominates the region, accounting for 90% of the refined products market. This has meant that all countries follow or plan to follow EU regulations for product specifications.

European refining

The European refining industry consists of 128 refineries with combined capacity of 17.3 million b/d. Fig. 1 shows the range of capacity is wide, with the largest refinery, Shell’s plant at Pernis in the Netherlands, having a capacity of 406,000 b/d. Average capacity is 135,000 b/d.

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Most very small refineries are either associated with local inland crude oil production or produce specialty products such as asphalt. Those associated with crude oil production will eventually close as their source of crude dries up.

In the late 1970s and early 1980s Europe experienced the same dramatic reduction in fuel oil demand as did the US. The level of conversion in European refineries, however, did not develop to the same extent as in the US. This period coincided with the rapid build up of North Sea crude production, and the European refiners were able to shift their slates away from heavier Middle East and West African crude to the lighter and sweeter North Sea grades.

This move, coupled with increasing demand for bunker fuel, allowed many refiners to avoid the expense of residue-destruction investment. Only those inland refineries that are away from the bunker market and have no easy access to North Sea crude have had to invest to convert fuel oil.

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As a result the average Nelson Complexity of European refineries of 7.3 is below that of US refineries (Fig. 2).

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The ownership structure of the European refining industry has evolved extensively over the last 2 decades. Historically, most of the capacity was owned by either the international majors or by national or regional companies. Fig. 3 shows there are only a small number of independents.

The years between 1995 and 2008 saw a marked reduction in capacity attributed to regional and European national companies. This was in part due to the privatization of some of the nationally based companies in Eastern Europe and also to the series of large acquisitions that resulted in Total becoming an international major rather than a national player.

Despite some initial aggressive acquisition policies the national oil companies of the oil producing countries made few inroads into Europe. Only Kuwait, Libya (through Oilinvest), and PDVSA remain, with Saudi Aramco in 2005 selling its only acquisition, a share in Motor Oil (Hellas). Ownership of investment funds controlled by the governments of oil producing countries has been excluded from consideration here.

Following are the three main challenges facing the industry:

  • Adapting to the changing demand patterns, both in Europe and in its trading partners.
  • Participating in European efforts to reduce greenhouse-gas emissions.
  • Adjusting to the effects of future product-quality legislation.

Changing demand

Through the 1980s and early 1990s, the European industry focused on configuring to meet the growing demand for motor gasoline.

By 1997 gasoline demand peaked and has been in decline since. The decline was in part due to the well-documented switch to diesel-powered cars by European drivers. Although sales of gasoline cars are beginning to recover in some markets, higher fuel prices will continue to drive consumers to diesel until such time as alternative power trains are developed.

Even without the shift to diesel cars, stringent fuel economy standards being set by the EU would lead to a decline in gasoline use. Although subject to further revision, the objective agreed with motor manufacturers is 130 g/km CO2 emissions, which is equivalent to a gasoline consumption of 38 mpg (6.12 l./100 km). This represents a 19% reduction from the 2006 level. A further decrease under discussion targets 95 g/km CO2 in 2020, equivalent to 50 mpg.

The result is an outlook that shows a continuing decline in gasoline consumption and moderate growth in middle distillates. Jet kerosine that had grown strongly up to 2008 is suffering from the present recession; future growth will be slower. Although there are growing concerns about the GHG emitted by aviation, the public desire for air travel, fuelled by low-cost airline expansion, is likely to prevail.

The forecast shows a gradual further decline in use of heating gasoil as the natural gas networks expand but continuing growth for diesel fuel in transportation. Despite a boost to consumption that is being driven by diesel cars, more than 70% of diesel use is for commercial vehicles. Fig. 4 shows the forecast changes in demand 2007-20.

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The challenge European refiners face is to manage a growing surplus of gasoline while meeting an increased demand for middle distillates. Fig. 4 compares the anticipated demand for Europe with yields from hydroskimming Brent crude and the typical yield from a catalytic cracking refinery, still the dominant configuration in Europe. The magnitude of the gasoline mismatch is immediately apparent.

The fall in gasoline demand in Europe coincided with a period of rapid growth in the US, hence the trade of gasoline and gasoline components across the Atlantic. Gasoline trade grew to more than 600,000 b/d in 2006 from around 150,000 b/d in 2000. Through this period, European demand declined by 500,000 b/d, resulting in a balance between export volume growth and domestic demand decline.

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The future looks more difficult. The 2007 US Energy Independence and Security Act will substantially increase the volumes of nonpetroleum gasoline used in the US, and more importantly it requires significant efficiency improvements from the vehicle fleet. There are indications from the administration of US President Barack Obama that emissions standards may be tightened further. This scenario couples with Purvin & Gertz’s long-term oil price outlook that is likely to promote voluntary conservation.

The result of a declining export market for gasoline and declining domestic demand will be considerable pressure on the entire European refining industry and may result in closure of some marginal capacity. All refiners will see an economic incentive to minimize gasoline production; some may consider replacing FCC units with hydrocrackers. The need to increase middle distillate imports would support such a move.

On the middle distillate side, the picture is a great deal happier for European refiners. The region continues to be very short and imports primarily from Russia and the Middle East. Historically Russian imports suppressed refinery processing in Europe because they were available at lower cost than they could be produced. Now consumption has grown to a level that Europe depends on imports.

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Considerable investment will be required in the region to supply the relatively modest growth that is forecast. Even with a continuing investment program, imports will rise further (Fig. 6).

Emissions trading system

The EU has positioned itself as a world leader in the mitigation of climate change and declared itself prepared to accept the economic consequences of GHG emissions reductions in view of the longer term cost of unmitigated global warming. One of the key planks of strategy is implementation of a cap-and-trade system for GHG emissions.

The EU established an emissions trading system in 2003 and subsequently modified it with other directives and decisions by various EU authorities. The scheme started in 2005 and has been implemented in trading periods:

  • The first trading period (Phase 1) began in January 2005 and lasted through 2007.
  • The second trading period (Phase 2) began in January 2008 and runs to yearend 2012.
  • The third trading period (Phase 3) will begin in January 2013.

In Phase 1, emission rights were allocated freely on the basis of national allocation plans developed by EU member countries. The main achievements of Phase 1 were establishment of a system to trade emissions and procedures to measure and verify emissions.

It is broadly recognized that Phase 1 did not lead to an actual reduction of GHG emissions primarily because too many allowances were issued and, by the end of Phase 1, the price of emission units was near zero due to lack of demand.

In Phase 2, emission rights were still allocated on the basis of NAPs, but member country plans were subject to more scrutiny and are expected to lead to a reduction of emissions. At the 2008 beginning of Phase 2, emission units started trading at more than €20/tonne of CO2-equivalent (CO2e) emissions, but prices have fallen to near €15/tonne of CO2e as a result of the recession.

In Phase 2, the scope of the program has expanded in several ways. Three non-EU European countries—Norway, Iceland, and Liechtenstein—have joined the program. The aviation sector will be brought under the program in 2012. And emissions of new GHG, nitrous oxides, and perfluorocarbons were added to the program.

For Phase 3, still being defined, there is some remaining uncertainty about details of the program beyond 2012. The most recent details concerning Phase 3 were adopted by the European Council in April 2009.

The objective of the Phase 3 is to reduce CO2e emissions by 20% by 2020, compared with 1990 levels. Considering that verified 2005 emissions were 1% greater than 1990 levels, the EU will need to reduce CO2e emissions by 21% between 2005 and 2020.

The EU, however, is considering modifying the 2020 emissions-reduction target to a 30% reduction (vs. 1990). It recognizes also that this could affect the competitiveness of several industries and that there are several provisions that refer to international cooperation.

But it is clear that the EU intends to move from a system of NAPs to an EU-wide system based on auctioning emission allowances. In this respect, industrial installations will be treated as follows:

  • As of Jan. 1, 2013, the electricity generation sector will be required to buy 100% of its emission offsets through auctions.
  • Other regulated industries will be put in on transitional program, whereby they will initially be given an allocation of free emissions equivalent to 80% of their average 2005-07 emissions, and will be required either to reduce emissions by 20% or buy emission credits. The free allocations would be progressively reduced by equal amounts each year, declining to 30% of 2005-07 emissions by 2020 and to zero by 2027.
  • Industries deemed to be exposed to carbon “leakage” would continue to receive free allocations but would be subject to energy efficiency benchmarks. The definitions of leakage have been set, and there is now an effort under way to determine which industry segments are deemed to be exposed to leakage.

The ETS is only one item of what is referred to as the “Climate Package.” It is generally recognized that the objectives of the EU ETS program will be very difficult to meet without significant contributions from renewables and from the commercial deployment of carbon capture and sequestration. For this reason, the package includes a renewables directive and a proposal for a directive to promote CCS.

Other items of the package concern new vehicle efficiency targets referred to previously and policies aimed at improving energy efficiency in agricultural and residential sectors.

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At the anticipated levels of carbon cost, the potential increase in operating cost for a European refinery that would have to purchase 100% of its required emissions permits would be substantial. Purvin & Gertz has analyzed the impact on its hydrocracking benchmark refinery at various levels of carbon cost (Fig. 7).

The anticipated range of carbon cost once a large proportion of credits is auctioned is expected to be €30-45/tonne. At this level, refinery operating cost would be substantially increased.

It is clear that this level of cost could not be recovered from the market. Europe already must attract middle distillate imports to balance its supply needs and must export gasoline and fuel oil. It’s possible the prices of these commodities will be set in locations that will not see the additional cost, such as the Middle East.

The magnitude of the price increase required to recover the carbon cost for the refinery is far more than the freight costs that might be incurred by an importer. Coincidently, if for example the product came from the Middle East, the carbon emissions from the shipping would be almost the same as the refinery emission to produce the incremental fuel. Thus, European refiners would be penalized for no benefit to the global climate.

This illustrates the care that regulations must take to ensure that “unintended consequences” don’t negate what is trying to be achieved.

Product quality

The final challenge facing European refiners is the continued tightening of refined-product quality.

Since the mid-1990s, successive regulations have sought to improve the quality of fuels used in the EU. The benefit to air quality, particularly in urban areas, is readily apparent. Gasoline and diesel fuel have become almost designer products containing no sulfur and low levels of aromatics and olefins.

The sulfur part of the EU’s liquid fuels directive mandates the use of low sulfur (<1%) fuel oil inland, unless the sulfur emissions are captured, and reduces the sulfur content of heating gas oil to 0.1%. A subsequent amendment imposes a lower sulfur content on the fuel used in off-road machinery (10 ppm) and domestic marine sectors (300 ppm, reducing to 10 ppm in 2012).

As hydrotreating capacity in the region is fully utilized, the increase in the volume required to be desulfurized to 10 ppm will place an additional burden on the industry. Purvin & Gertz estimates this volume to be around 20 million tonnes/year (400,000 b/d).

Probably the most fundamental change to the European refining industry is potentially the impact of the proposed changes to bunker-fuel quality. Since the 1970s, the International Maritime Organization has controlled and sought to reduce the environmental impact from international shipping.

The overall program comes under the International Convention on the Reduction of Pollution from Ships (MARPOL). That treaty has been in force for decades and has been effective in reducing waterborne pollution arising from oily-water wastes, bilge-water disposal, tank-cleaning emissions, and others.

MARPOL Annex VI governs air pollution from marine shipping. The original Annex VI introduced a global bunker-fuel sulfur limit at 4.5%. In October 2008 the IMO’s Marine Environment Protection Committee ratified Annex VI amendments that potentially have a dramatic impact on global refining.

Annex VI amendments

The key feature of the Annex VI amendments will be the substantial reduction in the allowable sulfur in bunker fuels. The amendments call for emissions control areas, which are a development of the sulfur emissions control areas (SECA) that were introduced in the earlier amendment. The ECA can apply either to SOx, NOx, or particulate matter, or all three. The current SECAs are the Baltic Sea area and the North Sea-English Channel area.

The US, a signatory of MARPOL and Annex VI, has submitted a request for an SOx ECA roughly 200 miles off the full US coastline. Separately, California recently imposed a distillate-only bunker requirement.

Currently the ECA requirement specifies that bunker fuel with maximum sulfur of 1.5% must be used. As both of the current SECAs lie within the EU, the legislation to enforce the limits is an amended version of the Sulfur in Liquid Fuels Directive. In modifying this directive, the EU added a provision that ferries traveling among EU ports should also use low-sulfur bunkers. This imposed a demand for some lower-sulfur bunker fuel in the Mediterranean. It is estimated that at present around 12 million tonnes/year of low-sulfur bunker is supplied in Europe.

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The Annex VI Amendments provide for a substantial reduction in the allowed sulfur levels both within and outside ECAs. Fig. 8 shows the proposed progression.

In 2010 the sulfur in fuel used in an ECA will drop to 1% maximum, with a further reduction in 2015 to 0.1%. Outside of the ECAs, the maximum sulfur would drop to 3.5% in 2012, with a further reduction to 0.5% in 2020. The reduction to 0.5% will be subject to a study in 2018 and, if availability appears to be an issue, the move can be delayed to 2025.

The Annex VI amendments provide for “equivalent” means of meeting sulfur emissions requirements. Effective emissions scrubbing technology on-vessel may allow shippers to use bunker fuels with higher sulfur levels.

The technology takes advantage of naturally occurring calcium carbonate dissolved in seawater to remove SOx emissions. As part of the scrubbing process, soot, unburned fuel, and other particulates such as fuel-derived metals are also recovered in a waste material that can be disposed of onshore.

Formal approval of scrubbing technology has not occurred and ultimately may depend on approval of the maritime states’ environmental and marine safety regulators.

The SOx ECA program could expand considerably. ECAs could be established in various areas around the world where ship-derived emissions contribute to onshore pollution. Such areas may include most of North America and European waters, including the Mediterranean and Straits of Malacca, and seas off Northeast Asia.

Impacts

The refining industry faces major obstacles in producing higher-quality marine fuels. The average sulfur content of intermediate fuel oil-grade marine fuels is currently more than 2.5%. Refiners may need to reduce sulfur to 0.5%. In the short term, many refiners can blend acceptable fuels for the ECAs because they currently account for only a small portion of marine fuels burned.

The longer term difficulties are greater. The reduction to 3.5% sulfur outside the ECAs is unlikely to cause widespread problems and the move to 1% in the ECAs is also likely not to be difficult as blends can be modified to redistribute the higher sulfur components.

The drop to 0.1% sulfur and 0.5%, however, is much more challenging. At this level, reblending will not be an option because there are limited volumes of crudes available that meet the lower sulfur level. Current technology is unable to reduce the sulfur of residues to 0.1% unless very low sulfur feed is used. Even if technology were to develop to achieve this, the likelihood is that the cost would be equivalent to converting the fuel oil to lighter, more valuable fuels. Refiners that could afford to invest would simply leave the bunker market.

Some bunker fuel could be produced at 0.5% sulfur by segregating the residues from very low sulfur crudes. Once again, however, desulfurization would be required to meet the limit and even at this level, the cost would be prohibitive and refiners would preferentially invest to convert rather than just remove sulfur.

In Europe the change would be exacerbated by the lack of alternative outlets for the high-sulfur components. Refiners would be faced with having either to change crude slate, export high-sulfur components to the few remaining and rather distant markets that would be able to accept them, or make a major investment.

Unlike other specification changes such as the reduction of diesel sulfur, the investment cost to desulfurize or convert residue is very large and location-specific and requires economy of scale. A typical hydrocracking plus coker complex with associated units can cost in the order of $2 billion, a sum that is beyond the financing capability of many smaller regional refineries. Purvin & Gertz has studied the proposals and calculated the range of compliance investment for European refiners lies between $20 and $25 billion.

The investment required to supply the higher quality bunker fuels would push up prices into the range of middle distillate. Consequently the most likely outcome is that refiners convert fuel oil to distillates. The fuel cost to shipowners will rise dramatically. The higher intensity of processing in refineries will cause an increase in CO2 emissions that governments struggling to meet national emissions reduction targets will find burdensome.

Lastly, the possibility that on-board scrubbers may be widely adopted adds to the uncertainty surrounding the regulation. The potential investment is huge and the lead time correspondingly long. The refining and shipping industries along with the regulators need to come to an understanding soon on future action if the IMO timetable is to be met.

The author

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Nigel Cuthbert (nrmcuthbert @purvingertz.com) is a director and senior vice-president of Purvin & Gertz Inc. in the company’s London office. Before joining Purvin & Gertz, he worked for the Esso Petroleum Co. Ltd. and Esso UK Ltd. Cuthbert holds a chemical engineering degree from the University of Exeter and is a member of the Institute of Energy and the Society of Petroleum Engineers.