Energy and Climate Change CommitteeWritten evidence submitted by KBC Advanced Technology plc

Executive Summary

The refining sector is facing difficulties as a result of the state of the market in the wake of the financial crisis and prolonged slow recovery.

European refining is being particularly hard hit by a confluence of a number of distinct issues:

Weakening European demand.

Global and regional overcapacity.

Renewable fuels (biofuels) mandates.

Duty-driven dieselisation of the transport fuel pool.

Changing specifications in the bunker fuel market.

Rising product exports from the Middle East and Russia.

UK refining has suffered in the downturn, but the market is fairly resilient.

Current UK refining capacity is a good match for domestic supply.

UK refineries are not optimally configured to meet the domestic/NW European demand barrel.


1. The oil refining industry has been under considerable pressure since the onset of the global economic crisis in 2008. Just prior to that time, the refining sector was experiencing a period of exceptional growth and strength as a result of rising oil demand and concerns over supply shortages. These included:

(a)A surge in annual oil product demand growth of 2.4 million barrels per day (bpd) in 2004, nearly double the average global demand growth.

(b)Crude oil supply shocks caused by political instability in Iran, Iraq and Nigeria.

(c)Over one million bpd of refining capacity on the US Gulf Coast being idled for an extended period by Hurricanes Katrina and Rita.

2. As a result of these shocks and resurgent strength in refining margins, a wave of new refinery construction projects was launched beginning in 2006. The first of these new refineries was the 600,000 bpd expansion of the Reliance Petroleum refinery in Western India. In total, around 15 million bpd of new refining capacity was announced between 2006–08, with around nine million bpd of that capacity being reasonably firm.

3. The global economic crisis caused a severe disruption to the pattern of rising annual oil demand. Global oil demand fell in 2008 by 800,000 bpd and in 2009 by over two million bpd. It recovered strongly in 2010 and since has returned to its long-run trend of around 1–1.2 million bpd per annum. Oil demand did not recover to its 2007 level until 2011. Hence new capacity being built in the interim period was being added to weak demand, which led to a position of overcapacity that persists to this day.

4. New refinery construction has continued at a pace exceeding the rise in refined product demand. New capacity is largely being added in the Middle East and in Asia—India and China in particular. These additions are strategic in nature and will transform the global market for refined products:

(a)Middle Eastern refineries—particularly in Saudi Arabia and Abu Dhabi in the UAE—are aimed at producing products for export. This is counter to a usual “rule of thumb” that it is better to refine products close to end-use markets because crude oil shipping rates are cheaper than refined products shipping rates.

(b)China has been adding refining capacity at a rate of around 500,000 bpd per annum to keep pace with its domestic demand. We believe that China’s central planning policies prefer to have the fuels and petrochemicals markets supplied almost entirely from domestic refineries, leaving only a small potential requirement to trade in regional markets.

(c)India’s refiners—both state-owned and private sector—have been adding capacity far in excess of growth in domestic products demand. This is part of a strategy to see India as a regional refining hub, supplying products to its neighbours who have been less willing or able to invest. India’s government has encouraged the growth of its state-owned refineries to be able to supply at least 90% of domestic requirements from state-owned refineries.

5. Since the global downturn, Europe’s refiners have been particularly hard hit by structural changes in the global refining sector.

6. European Union refined product demand has been in decline since 2006, when it peaked at a level just over 15 million bpd. In 2012, this demand had dropped back to 13 million bpd. We forecast that it continue falling in the long term, dropping back to just 12 million bpd by 2020 and to 11.2 million bpd by 2030.

7. The EU Renewable Energy Directive (“RED”) (2009/28/EC) obliges all member states to incorporate 10% (by energy content) renewable fuels into their transport fuels pool by 2020. This is effectively a biofuels mandate obliging the use of non-refinery sourced fuels to comprise 10% of the transport pool (petrol, diesel). The directive allows a very small amount of discretion in how this mandate is achieved. The UK has its own National Renewable Energy Action Plan (NREAP) and is implementing the RED under the guidance of the Renewable Transport Fuel Obligation (RTFO).

8. EU-27 transport fuel demand in 2013 is forecast as 3.67 million bpd of diesel and 1.80 million bpd of petrol. UK 2013 demand is 290,000 bpd of petrol and 430,000 bpd of diesel. These volumes should be approximately 10% renewable content by 2020 according to the RED/RTFO requirements.

9. The combination of declining overall demand and rising supply from renewables suggests a shrinkage of EU-27 demand for conventional refined fuels from pre-recession levels of 15 million bpd to a 2020 level of 11.4 million bpd.

Challenges to UK Refiners

10. Northwest European refiners have faced considerable pressure in the years since 2008, primarily in the form of low refining margins. At times since 2008, refining margins net of operating costs have been negative, meaning that at least some refiners have been losing money on every barrel of oil they refine.

11. The EU fuels market continues to “dieselise”. Each year, the market shifts increasingly to favour the use of diesel over petrol. In 2000, market demand was nearly 50–50 between diesel and petrol. Today it is 67% diesel, 33% petrol. The main driver of this long-term trend is the favourable taxation of diesel favoured by all EU countries.

12. The UK has Europe’s most harmonised taxation policy on diesel, with the duty rate being equal on a volumetric basis for petrol and diesel. The current rate of duty is 57.95 pence per litre. All other EU countries have varying rates of tax with petrol taxed higher than diesel.

13. This is important because diesel has a higher energy content than petrol and hence gives better fuel economy on a volumetric basis. Diesel gives about 20% better fuel economy per litre and thus it is attractive in its own right. When this advantage is enhanced by a lower rate of duty, the choice of diesel over petrol becomes even more obvious.

14. In 2012 the European Commission rejected a proposed directive that would have obliged all members to harmonise duty on an energetic basis. If this had been implemented, diesel duty would have risen to a point where it would have been 20% greater than petrol.

15. Continuing dieselisation is a particular burden to NW European refiners. Most refineries in Northern Europe were built at a time when petrol was the preferred fuel. Their configurations, including their main heavy oil upgrading units, were designed to maximise the output of petrol. Many Southern European refineries have upgraded only recently and thus have been able to direct their capital spending toward the production of diesel.

16. Europe’s skewed demand barrel has resulted in a rising surplus of gasoline from NW European refineries. This gasoline has historically gone into markets in North America and West Africa. As oil demand has been reduced as a result of straitened economic circumstances in many OECD countries, demand for exports from NW European refiners has been pressured.

17. NW European refiners are squeezed economically because, having invested in gasoline-skewed upgrading configurations, they cannot economically justify a transition to a distillate-skewed production. Such projects are very expensive—$1–2 billion—and cannot achieve economic hurdle rates because they are already upgrading their low-value residue products to one higher value product (petrol) and they would only be upgrading on a differential between petrol and diesel rather than low-value fuel oil and diesel. The difference per tonne might be $50 instead of $400.

18. NW European refiners also are increasingly burdened by surplus fuel oil. According to the UK Petroleum Industry Association (UKPIA), UK refineries produce around 9% residue fuel oil (RFO), the “bottom of the barrel” product left over from refining. This low-value product is usually burned for bunker fuel for ships. In the past it also was used to generate power and for industrial uses, but these markets have been declining as they are replaced by cleaner, cheaper natural gas as a substitute.

19. From 2015, the bunker fuel market in Northern Europe will no longer be able to burn as much (if any) residue fuel oil due to changes agreed and imposed by the International Maritime Organization (IMO). Under IMO’s Annex 6, the Northern European corridor comprising the English Channel/North Sea/Baltic Sea will be subject to strict emissions guidelines that will effectively eliminate the use of RFO as bunker fuel. After 2020, all EU waters will be subject to similar regulations, though imposed by the EC rather than the IMO.

20. Refiners have two choices of action on RFO: they can sell it or upgrade it. Until 2015, with a ready market in NW Europe, it has been preferable to sell it. After 2015, most of the RFO will have to be exported to the Middle East or Asia, where markets for power and bunkering will remain.

21. This situation further impacts NW European refiners: more of their product barrel will be sold for export, which is a lower-margin activity than refining for the domestic market. Because marginal product is exported, petrol, naphtha and now RFO will be priced based on export-parity rather than import parity. This means lower returns for NW European refiners. Nearly all UK refiners are in this position.

22. A further challenge to European refiners is posed by Russia, and in particular by the extension of preferential rates of export duty on refined products. The so-called “60/66 reforms” introduced in 2011 were designed to force Russian refiners to modernise and upgrade their refineries. Prior to 60/66, Russian refiners received a significant discount for every barrel of product they produced. It was more economic for them to export RFO than to upgrade product to higher quality gasoline or diesel, but it was still economic for them to refine to any product rather than to export crude oil. This older policy had the practical outcome of keeping Russia’s antiquated refining circuit running near full capacity.

23. Under the 60/66 rules, Russia’s government is making it less attractive to export RFO. After 2016, refiners will receive no incentive for exporting fuel oil and only a small incentive for exporting petrol. They will continue to receive large incentives only for the export of distillates (gasoil, diesel, jet fuel). These are the products that are the “shortest” in Europe—that is to say, Europe must import these. At present, much of Europe’s supply is coming from East of Suez—markets in India and even as far away as South Korea. As the new export-oriented refineries in the Middle East start up, they will likely target selling distillates to Europe. US refineries, filled with cheaper domestic crude oils, are shipping distillates to Europe. And when Russia modernises its refineries, it will send a flood of new clean distillates to Europe.

24. European refining margins are to some extent sustained by the distance which distillates must travel. Diesel “cracks”—the difference between the price of crude oil and diesel—provide support for European refining margins. As the distance this material must travel grows shorter, the diesel crack spread will narrow. This will pressure NW European refining in general.

25. When we look at EU refining, we see a sort of “death of a thousand cuts”. Dieselisation means that Northern European refineries in particular are not making the right “product barrel” for the home market. Bunker fuel switching to distillates means that fuel oil prices will fall. Distillate imports from the “near abroad” mean that the diesel crack—the “tallest pole in the tent”—will be shortened. All of these weigh on the gross refining margins available to NW European refiners.

26. UK refiners have struggled in the aftermath of the financial crisis. The UK has seen two refineries close in recent years—the simple Teesside refinery and the relatively large and complex Coryton refinery. The closure of Teesside was perhaps understandable, as it was smaller scale and not capable of upgrading the bottom of the barrel. But Coryton was, according to its previous owners, Petroplus, one of its most profitable refineries. That was not sufficient to attract a buyer who was willing to keep it running as a refinery, and it is subsequently being converted to an import terminal.

Terms of Reference Issues

27. Baseline refining capacity: UK total oil product demand is around 1.43 million bpd at 2013, expected to fall to around 1.36 million bpd by 2020 and to 1.3 million bpd by 2030. The UK currently has 1.27 million bpd of refining capacity. It produces a surplus of around 100,000 bpd of gasoline and imports around 200,000 bpd of distillates (jet fuel, diesel). UK refining ran at 81.6% utilisation in 2012, even after the closure of the Coryton refinery in September.

28. The UK is positioned close to the major oil and oil products trading hub at Amsterdam-Rotterdam-Antwerp (ARA) and thus can be easily supplied from refineries and terminals there through coastal terminals and a sophisticated network of products pipelines. UK refineries are for the most part large and complex, though not optimally configured for the domestic demand barrel. UK products markets are robust and are suited both to importing and exporting on the margins, so supply from imports is not necessarily a problem.

29. Determining an adequate UK baseline capacity is a complex exercise that will depend on regional balances (ARA, NW Europe and Russia), as well as the potential for trading imports from outside the EU. The UK is accessible to imports both from North America (US Gulf Coast) and East of Suez. If refineries are running only 82% full today (ca. 1.15mbpd), then the market is well served by imports and is not signalling UK refineries to run harder for domestic consumption. With demand set to decline only modestly over the next two decades, maintaining a sustainable refining capacity at an absolute minimum of 1–1.1 million bpd would seem a suitable base level, but allowing for maintenance downtime and market flexibility, it would seem sensible to support capacity at a higher level—perhaps close to the present level of 1.27 million bpd.

30. European governments have not been particularly effective at defending their refining assets in spite of headline efforts to appear supportive of installed industrial capacity. France has lost two refineries in the past year in spite of making a show of trying to find buyers and keep sites open. Italy is plagued by overcapacity and its major refiners are practicing are using a rota “temporary closures” to avoid hard decisions about permanent site closures. The UK government, by contrast, has appeared to have a fairly laissez-faire approach to its refining sector, but the market seems fairly capable of sorting out domestic requirements, as the entrance of Shell, Vopak and Greenergy planning to import into the void opened by the Coryton closure would suggest.

31. The entry of new participants to UK refining: Valero at Pembroke, Essar Energy at Stanlow and PetroChina at Grangemouth—indicates that the UK market is not an unattractive place to refine, provided the assets fit in with corporate strategy. Valero have indicated that their first foray into European refining is a good fit with their trading business in the US, and as they sold off assets on the East Coast of the US have now replaced that supply with exports from Wales. Essar have indicated that they are working to squeeze costs out of Stanlow to make it more competitive and profitable. PetroChina’s participation in PetroIneos can be seen as a part of a larger strategy for Chinese refiners to reach out beyond Asia and establish global operations that help them to integrate their business, both upstream and downstream. The participation of these parties can be seen as a vote of confidence in the UK/EU market as a good place to do business.

May 2013

Prepared 25th July 2013