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Why the UK North Sea must become a low carbon leader

In the quest to achieve the North Sea Transition Deal’s target to turn the ageing petroleum province into a net zero basin by 2050, three questions are paramount. First, where does the UKCS currently sit in carbon competitiveness? Second, what impact could decarbonisation have on the competitiveness of UK North Sea crude and natural gas in a global market increasingly concerned about carbon? Finally, given that the UK is a small player in the global oil and gas market, does decarbonisation justify government support for new UK North Sea exploration and production licences?

Production carbon intensity is a measure of the amount of CO2 emitted to produce each barrel of oil equivalent. The primary sources of emissions are offshore diesel power generation and gas flaring. The intensity of UKCS oil and gas was estimated to be 19 kg CO2 per barrel of oil equivalent (boe) in 2022, according to Rystad Energy. This puts the UKCS firmly around the global average relative to its global competitors.

Overall UKCS production carbon intensity has declined by 17% since 2019, compared to a global fall of 3%. But most of this progress was achieved by decommissioning older dirtier platforms in the North Sea, as well as disruption related to the Covid-19 pandemic. Investment in decarbonisation played a lesser role. That will need to change if CO2-cutting momentum is to be sustained.

Source: North Sea Transition Authority

Age concern

Mature oil basins such as the UK North Sea struggle to contain emissions over time. As fields age more energy is required to extract dwindling reserves, making it difficult for efficiency savings to outpace the falling rate of recovery. As such, mature fields typically experience an increase in carbon intensity in their twilight years.

North Sea Transition Authority (NSTA) data indicates that large UKCS platforms over 25 years of age emit an average of 54 kg CO2 per boe, almost five times higher than similar sized facilities that are less than 10 years old. The pattern of higher carbon intensities in older facilities is less apparent in smaller and floating platforms although those less than 10 years do still have significantly lower production carbon intensity.

Source: North Sea Transition Authority

Although overall UKCS emissions are set to decline during the period to 2030, UKCS carbon intensity is likely to increase. Field operators may conclude that there isn’t enough value (economically recoverable reserves) left in the mature fields to justify the investment in decarbonisation. Rather than invest in electrification of a mature field it often makes more sense for an operator to divest or accelerate decommissioning. 

According to analysis by Westwood Global Energy Group published in mid-2022, UKCS carbon intensity could increase by around 20% by the late 2020s to around 25 kg CO2 per boe. This increase occurs even in the optimistic scenario that offshore emissions decline by two-thirds between 2018 and 2030 to 4.9 Mt CO2e, in line with the NSTA’s central assumption of zero routine flaring and venting and eight assets fully electrified by 2030.

Prolonging the life of the UKCS through new exploration and additional licensing rounds may help to reduce overall UKCS carbon intensity by bringing down the average. However, this is likely to be the case only if operators can be sure that the government remains committed to the 2021 North Sea Transition Deal (NSTD) and invest accordingly into solutions such as electrification.

Delayed decarbonisation

Rosebank is the first major new field to be approved since the UK government enshrined into law its commitment to hitting net zero by 2050. Rosebank is part of the West of Shetland electrification project that also includes BP Clair oilfield and Ithaca Energy’s Cambo development, and the Floating Production Storage and Offloading vessel (FPSO) collecting the oil will be built ‘electrification ready’. 

Electrification would make a huge difference. Without electrification Rosebank is expected to have a carbon intensity of 12 kg CO2 per boe – around 40% below the UKCS average. If electrified, the carbon intensity would decline significantly to around 3 kg CO2 per boe.

Although first oil is expected around 2026/27, electrification is unlikely to happen before 2030 at the earliest according to Equinor, the field operator. Since it takes several years for new fields such as Rosebank to be fully commissioned and begin ramping up production, there is likely to be a significant delay before new fields come onstream and contribute to a decline in the overall UKCS carbon intensity.

Prime Minister Rishi Sunak visits the Port of Cromarty Firth at Invergordon. Source: PA

The low carbon premium

Today, crude price differentials typically reflect the value that the refiner expects to achieve from processing various grades of crude oil. The density of the crude, the sulphur content, its acidity, and the cost of transportation all influence the price that a refiner is willing to pay for a particular crude.

This will change under a carbon constrained world. Suppliers of crude and natural gas that are carbon intensive to produce will be at a big disadvantage, potentially weighing on the price that buyers will be willing to pay. In contrast, those producers able to supply crude and natural gas with a lower production carbon intensity than their competitors may be able to capture a premium.

Scope 3 emissions resulting from the combustion of oil and natural gas account for 80-95% of total carbon emissions from oil and gas companies. But the most important carbon intensity differentiator between sources of crude and natural gas is how the energy is extracted and processed – so-called Scope 1 and 2 emissions.

Recognising the potential for a low carbon premium, institutional investors and private investment funds are requesting that oil and gas companies evaluate and disclose their carbon emissions and climate-related risks. North Sea industry sources tell E-FWD that companies considering mergers and acquisitions (M&A) are factoring in the carbon intensity of the assets under offer, while considering the impact it has on the wider asset portfolio. 

Carbon border taxes

Carbon markets are also beginning to influence capital allocation decisions. The EU’s Carbon Border Adjustment Mechanism (CBAM) will initially cover imports of iron and steel, cement, fertiliser, aluminium, electricity, and hydrogen. The plan is that all sectors covered by the EU ETS (including oil production and refining) will be subject to the CBAM by 2030.

The first phase of CBAM, launched on 1st October 2023, placed only reporting obligations on affected industries. The levy is set to be introduced in 2026 and will be gradually phased in at the same rate that free allocations for obligated emitters in the EU will be withdrawn. By 2034 importers will have to pay 100% of the CBAM cost. 

Based on current EU emission allowance prices, importers will need to pay in the region of €80 per tonne of covered emissions. However, as the EU ETS emissions cap continues to decline, and the marginal emission abatement cost increases, it’s likely that the CBAM cost per tonne will also rise significantly and its coverage expanded to cover all Scope 1 and 2 emissions at some point in the future.

Crucially the CBAM is only payable if the country-of-origin does not have a carbon price comparable to the EU’s. If, as is currently the case in the UK, the carbon price is closer to €40 per tonne then EU importers would need to pay for the other €40 per tonne via the CBAM. Assuming the UKCS has a production carbon intensity of 19 kg CO2 per boe, the overall carbon cost equates to €1.50 per barrel with half of this payable by the EU importer.

In comparison, the carbon cost of Norwegian North Sea oil and gas (assuming a carbon intensity of 8 kg CO2 per boe) equates to €0.64 per barrel. As a supplier of oil and natural gas to the EU, the UKCS faces a strong challenge from Norway, which is also part of the EU ETS. That challenge will be even more difficult if the UKCS fails to decarbonise, and even more so if its carbon intensity increases between now and 2030.

Consensus forecasts see the EU carbon price rising to €150 per tonne by 2030. At this price, all else being equal, the carbon cost disadvantage of UKCS exports versus Norway is almost double today’s. UK exporters of carbon intensive products to the EU already recognise that this scenario could put them at a disadvantage. Industry pressure is one factor that could lead to a future convergence between UK and EU carbon prices.

Unavoidable carbon costs

Discussions with North Sea industry sources indicate that carbon border taxes – whether the EU’s CBAM or a future UK version – could also result in higher costs for those operators seeking to invest in the UKCS. For example, much of the infrastructure used by the offshore oil and gas industry is built using steel manufactured in Asia. Developing offshore assets in the UKCS could come at a higher cost in the future once the carbon intensity of the imported infrastructure is accounted for.

The advent of the EU’s carbon border levy, and the prospect of other countries adopting similar measures, suggests that all oil and gas producers will have to begin accounting for their carbon intensity, while putting in place measures to decarbonise. The alternative is that carbon intensive producers only export to those jurisdictions without a carbon border tax in place – resulting in a bifurcation in global energy markets based on carbon. 

In practice the latter outcome seems unlikely. Even those countries that might normally be willing to buy carbon intensive crude or natural gas will need to account for those emissions when exporting their own goods abroad. Meanwhile, carbon intensive producers are likely to find their existing credit arrangements become more costly as financial institutions factor in the associated climate risks.

Buy local

Aside from the UK’s carbon competitiveness on the export market, it’s also vital that the UK meets its own energy needs at the lowest carbon intensity possible. The natural gas market is a prime example.UK domestic production met 38% of the nation’s gas requirements in 2022, while pipeline supplies from Norway accounted for 34%. Norway delivers gas to the UK at a much lower carbon intensity than domestic UK production (8 kg CO2 per boe vs 21 kg in the UK) due to a higher degree of platform electrification and greater share of renewables in the power mix. However, since the UK is a net importer, it imports liquefied natural gas (LNG) from suppliers such as the United States and Qatar for the remainder.

Unfortunately, the average carbon intensity of LNG imported into the UK is 79 kg CO2 per boe, almost four times higher than UK natural gas production. Energy-intensive liquefaction is responsible for the bulk of LNG’s high production carbon intensity, as well as transportation.

Overall, there is a compelling case for increasing UK natural gas production, even if the UK can’t compete with the Norwegian North Sea’s low carbon intensity today. By replacing carbon intensive LNG imports with lower carbon gas produced from the UKCS, the UK can reduce overall global emissions. Developing new fields with the latest emissions reduction technologies and processes also drives down overall basin CO2 intensity.

Decarbonise or die

Unless emissions savings can be achieved by reducing consumption, a carbon constrained future creates a dilemma between energy availability and achieving decarbonisation targets. Investing in the UKCS, cutting emissions, and producing oil and gas from the North Sea in the lowest carbon intensive way possible is the best way to resolve the dilemma.

Demand for oil and natural gas is likely to remain much stronger than the net zero scenarios envisioned by the International Energy Agency (IEA) and other organisations. Less developed and emerging economies are expected to grow rapidly, increasing demand for all energy sources. For developed economies, a growing recognition of the cost of transitioning to cleaner fuels means that oil and gas are likely to remain in the energy mix far longer than expected. 

Net energy importing nations point to the fallacy of closing domestic oil and gas fields prematurely, only to cover their energy requirements by importing crude and gas from producers with much higher carbon intensity. Meanwhile, low-cost oil and gas exporting countries must decide whether they should continue to compete for the ‘last barrel’ consistent with hitting net zero.

Either way there is an incentive to produce oil and gas in the lowest carbon intensive way possible. The only alternative is for UKCS production to enter managed decline and leave the task of decarbonising oil and gas to other regions. This means passing up the opportunity to lead the world into the carbon-constrained future that is fast approaching.

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