The rising carbon cost for European refineries

A few weeks ago, the FT published an article entitled “UK Steelmakers face £150mn annual bill from carbon charges, industry warns” and described the proposal to wind down free emissions allowances to industry as an “earthquake moment” for producers.

This “earthquake” refers to the phasing out of the free allocation of allowances under the UK and also EU emissions trading systems, key policy tools for the UK and EU to reach their decarbonisation objectives.

This change in allocation will mark a significant shift in how carbon pricing affects heavy industry within the UK and Europe, affecting not just steelmakers, but over 10,000 installations covered by UK and EU emissions trading systems.

One sector in particular that could be amongst the most impacted in future is that of oil refineries, a key part of the hydrocarbon industry and a significant source of CO₂ emissions in Europe. In this article, we shall explain the changing carbon-regulatory landscape and the potential impacts on European oil refiners.

Background

Established in 2005, and covering the power sector and heavy industry in Europe, the EU ETS has grown to become by far the largest carbon compliance market in the world. Having survived a number of significant setbacks in the early years, including of course the 2009 financial crisis, the EU ETS has expanded and evolved to become a market that in 2024 had a value of approximately EUR 700bn.

The price of a European Union Allowance (“EUA”) has increased significantly in the past few years, from approximately €30 in December 2020, to around €70 today, representing a large direct cost increase for the European obligated entities that this scheme relates to.

Aside from this increase in the EUA price, a fundamental change is also happening to the market that will further increase carbon costs for many companies. From 2026, in parallel with the introduction of the Carbon Border Adjustment Mechanism (CBAM) in Europe, there will be the gradual phase out of freely allocated EUA permits to many sectors.

Free Allocation phase out; no more free passes

The term free allocation refers to the free distribution of EUAs (or UKAs in the case of the UK) by governments to companies covered by the ETS. Where a company receives a freely allocated EUA, they can surrender that EUA against one tonne of CO₂ emissions generated during a compliance year. This effectively means there is no cost to them for emitting that tonne of CO₂, saving them approximately €70 per tonne at today’s prices.

Going forward, the European Commission, through recent reforms to the Emissions Trading Directive, has indicated its intent to gradually phase out the free allocation of EUAs and to fully implement the process of auctioning as the default mechanism  of enabling supply to the market. Obligated companies will therefore need to purchase their full EUA requirement through such auctions, or through the secondary traded market.

This is a very significant change that will have profound implications for many sectors covered under the scheme. Since the ETS started trading in 2005, many sectors have received a free allocation equivalent to a large proportion of their verified emissions. Obligated entities, therefore, only needed to buy EUAs to cover the shortfall between their actual emissions and that free allocation. In the past this often meant companies did not need to buy any EUAs and in some cases  had a significant surplus. Any excess free allocation could be “banked” or any unused allowances carried over from one year to the next and used to reduce their carbon compliance costs in subsequent years, or sold in the market.

Going forward, therefore, as CBAM is potentially extended in scope and free allocations reduced and eventually removed, in the not-too-distant future obligated companies will have to buy an EUA for every tonne of CO₂ they emit. Compounded on top of that change, many analysts are forecasting that EUA prices may be significantly higher over the next decade, with some analysts projecting an EUA price in excess of €150/tonne by 2035.

Implications for European refiners

What, therefore, does this mean for a sector like oil refining in Europe? In recent years, refineries have received a free allocation of EUAs based on a benchmark calculation, whereby free allocation was calculated based on the most efficient installations in the sector. This rewarded the most efficient installations by providing enough allowances to cover the majority of their verified emissions, but penalising those less efficient refineries and providing an incentive for them to reduce emissions where possible. The benchmark for refineries is to be revised in 2025 and free allocation is likely to be reduced.  However, should CBAM be extended in scope to cover refinery products, oil refineries in Europe could see their free allocation reduced much more quickly.

But what does this actually mean in terms of cost and what could it mean going forward? To illustrate, let us consider an example European refinery we’ll leave anonymously named as “Refinery X”.

In 2013, at the start of the third phase of EU ETS, Refinery X received a free allocation of 650,000 EUAs. It emitted 900,000 tonnes CO₂e and therefore had a shortfall of 250,000 EUAs that it needed to purchase in the market. If we assume that they bought EUAs in December 2013 the EUA price was approximately €5/tonne, resulting in a compliance cost for the year of around €1.25mn.

Ten years later, in 2023, the same refinery received a reduced free allocation of 500,000 EUAs, but emitted 1mn tonnes of CO₂, creating a deficit of 500,000 EUAs. In 2023, if we assume that the refinery bought the EUAs rateably over the compliance year, the average EUA price would have been around €85/tonne, resulting in a compliance cost for 2023 of €42.5mn.

If we fast forward to 2035 and make the assumption, given the trajectory, that there is no longer any free allocation for the refinery sector, then the costs for Refinery X will be substantially higher. If we then apply an EUA price of €150/tonne, as has been suggested by some analysts, Refinery X with a capacity of approximately 90,000 bpd, has a total annual carbon liability of €150mn. Depending on the complexity of a specific refinery, at an EUA price of €150/tonne, ETS compliance costs could equate to between $2 per barrel for a simple refinery up to over $5 per barrel for some of the more complex refineries in Europe.

How do refineries respond?

Refineries have always had to focus on minimising costs to remain competitive. The period of exceptionally high refinery margins in 2022 and 2023 is already a fading memory as margins have reduced in 2024 and forward margins are highly uncertain. Whilst cracks are now higher than they were in January, the forward margins are highly uncertain. Rising carbon prices and the reduction of free allowances increases the cost base, meaning a higher refinery margin will be required just to cover these costs (alongside other cost pressures, notably inflation). If cracks stay high, there is less concern, and refineries can continue to cover turnaround and maintenance costs plus the additional carbon cost. However, there is no suggestion from most analysts’ forecasts that forward refinery margins will be sufficient to cover this cost hike. Therefore, action must be taken to reduce EUA costs by investing to abate carbon emissions or convert to co-process or process more biofuels. The alternative is closure.

We estimate that out of the completed or announced European refinery closures from 2020-2030, over 80% are set to be converted into biofuels facilities. One project is planned to be repurposed into an import terminal. Since 2020, 10 refineries have shut in Europe and an estimated further 11% are expected to close by 2040 and 19% by 2050. This closure rate could be accelerated if carbon prices rise further or more quickly than currently envisaged.

One alternative pathway to outright closure is to repurpose into a storage terminal, but this can be costly. Petroineos is faced with decisions to convert Finnart (linked to Grangemouth) for import to give them a deeper draft for large cargoes. But such a conversion requires significant investment and uncertain payback.  As a comparison, Coryton refinery was never successfully converted to a terminal, as existing facilities in the Thames could manage the incremental import demand. Each site is different and should be individually assessed based on an analysis of local demand and alternative sources of supply.

For those refineries that still plan to be in operation out to 2035 and beyond, refiners need to decide on alternatives such as green hydrogen, electrifying boilers, and carbon capture. A few years ago, cost projections made green hydrogen an obvious way to reduce emissions. However, rising costs, delays in start-up, and a lack of commitment from 3^rd-party offtake for the excess hydrogen, are major hurdles for most of these projects. BP has recently cancelled the Hygreen project in Teeside, but took FID on the 100MW  Lingen green hydrogen project, choosing to focus on decarbonising that site. Whilst BP’s other German refinery at Gelsenkirchen has recently been selected  to be sold. Shell Pernis will supply green hydrogen through a 200 MW electrolyser, far larger than the refineries requirements, leaving excess to be sold to other refineries and offtakers in the region. The investment priority has been towards large scale decarbonisation investments in strategically advantageous sites where excess hydrogen volumes can be more readily monetised.

Carbon capture is the more expensive step in decarbonisation. Shell Pernis is developing capture plants to supply CO₂ into the Porthos’ collective pipeline, reducing the refinery’s emissions by approximately 25%. Stanlow refinery is involved in the HyNet project in the North West, which intends to  capture carbon at site to be sequestered and stored at the old Liverpool Bay crude oil field. EET states their carbon capture plant at Stanlow will cost £360m and remove around 45% of Stanlow’s emissions.

Clearly too much time and resource has been invested in some decarbonisation projects without really being challenged on whether the project makes sense in a variety of scenarios. There have already been small fortunes spent on developing projects that have “no legs” as they are in the wrong place or will never secure offtake at the required price level, making them unbankable and so requiring large equity commitments. At Energex Partners we support our clients by modelling these projects with realistic assumptions and providing experience-based insights that supports effective decision making.

If you would like to understand more about our Refinery commercial advisory services and carbon markets, please contact Liz Martin at Energex Partners lmartin@energex.partners and Michael  Fulton mfulton@energex.partners