The UK emissions trading scheme (UK ETS) is one of the most important policy tools for guiding the UK onto a trajectory towards ‘net zero’ emissions by 2050. The UK ETS, combined with platform decommissioning, has delivered recent emissions reductions from UK oil and gas production. But can carbon pricing alone incentivise platform electrification, flare mitigation and other measures necessary to deliver deeper emissions reductions?

The government launched the UK carbon market in May 2021 following the country’s exit from the European Union. Obligated emitters that had previously been subject to compliance under the EU ETS were now required to pay the price of carbon allowances traded in the UK carbon market.

Over the first 18 months or so, the price of UK emission allowances (UKAs) increased sharply, mirroring the step change in prices seen in the EU, albeit trading at an average premium of ~10-15% to the EUA price. By late August 2022, the UK carbon price had surged to over €100 per tonne – that’s more than seven times higher than where the carbon price was in 2018.

However, the high price of carbon was not to last. Over the next twelve months the UKA price had slumped to less than €40 per tonne, a discount of over 50% versus the EUA price. A loss of trust in the UK government’s commitment to climate change policies contributed to the decline.

In line with the overall emission reduction target underpinning the UK ETS, the 2021 North Sea Transition Deal (NSTD) commits the North Sea to becoming a net zero basin by 2050. The five key pillars of the deal are decarbonisation, developing the region’s carbon capture, usage, and storage (CCUS) capabilities, supporting the deployment of hydrogen production capacity, transforming the supply chain, and developing skills. The NSTD requires the oil and gas industry to cut emissions by 10% by 2025, 25% by 2027, and 50% by 2030, when compared against a 2018 baseline.

Taking stock

To understand the role that carbon prices have played in helping the North Sea achieve decarbonisation (the first of those five key pillars) we first need to take a step back and see what progress has been made. The UK’s upstream oil and gas sector is estimated to have emitted 14 Mt CO2e of greenhouse gases (GHGs) in 2022, accounting for around 4% of the UK’s emissions. Overall emissions remained relatively stable during the 2010s, however since 2018 they have dropped by 23% because of investment in decarbonisation, disruption caused by the pandemic, and the closure of a number of the older (typically more carbon intensive) oil and gas fields.

You can see this more clearly when we focus on developments offshore, where the bulk of the industry’s emissions take place. Total GHG emissions from offshore facilities declined by 3.9 Mt CO2e (27%) between 2018 and 2022 to 10.6 Mt CO2e, according to the latest data from the Environmental and Emissions Monitoring System (EEMS). Around half of the emissions decline was due to installations coming to the end of their lifespan or those that were in the process of closing. Of those assets that remained online, the primary factors contributing to the drop in emissions include a decline in flaring and a reduction in the use of gas for fuel.

Carbon dioxide emissions resulting from the combustion, flaring and transport of hydrocarbons are the only activities currently obligated under the UK ETS. Carbon dioxide accounts for around 90% of GHG emissions from the North Sea, followed by methane (7%) and nitrous oxide (~3%). The UK ETS also only applies to sites where the total rated thermal input of its combustion units exceeds 20 megawatts (MW). In total, an estimated 12.2 Mt CO2 (~97%) of the industry’s total carbon dioxide emissions was obligated under the UK ETS in 2022.

Accelerated closure

A recent study published in 2022 in the journal Energy Economics and led by researchers from the University of Aberdeen and the University of Stellenbosch in South Africa analysed the impact that carbon prices have had on the UK Continental Shelf (UKCS) oil industry. The academics found that higher carbon prices resulted in an increase in upstream operating expenditure, which in turn accelerated the early cessation of production at several fields. In addition, they calculated that carbon prices eroded the economic value of a sample of 21 new fields by an average of 28%, making them less attractive as investments. Bear in mind that this analysis includes the longer-term impact of the UK’s participation in the EU ETS, and the more recent launch of the UK ETS.

Although most of the UK’s oil and gas emissions fall under the UK ETS, operators do not currently have to pay the full price for a UK emission allowance. The oil and gas sectors are considered at high risk of relocating to jurisdictions outside the UKCS. As such they receive a significant share of their emission allowance requirements for free (as they also did under the EU ETS).While this blunts the impact of the carbon price in the short term, in the longer-term oil and gas operators know that free allowances will gradually be eliminated. Coupled with the prospect of a much tighter market for emission allowances and consequently higher prices as we approach 2030, the North Sea’s oil and gas operators are likely to have incorporated significantly higher carbon price exposure in their financial models. Indeed, many operators have been doing this for some time, using a shadow price of carbon to benchmark all their investments, whether located in the North Sea or elsewhere, under a range of carbon price scenarios.

Wider scope

During the rest of this decade the impact of the UK ETS is likely to extend to a broader proportion of the UK’s oil and gas industry’s emissions. In June 2023 the long-awaited consultation response on reform of the UK ETS was published by the UK ETS Authority. Emissions associated with gas sweetening (an energy intensive process by which acidic impurities like carbon dioxide and hydrogen sulphide are removed) will be covered by the UK ETS from 2025 and are expected to add an additional 0.4 Mt CO2 per annum from the upstream oil and gas sector to the UK ETS. The Authority also issued a call for evidence regarding the inclusion of methane in the UK ETS given its high global warming potential.

Although there is evidence that the seven-fold rise in carbon prices did have an impact on North Sea decarbonisation between 2018 and 2022, the prospects for further emission declines appears more limited. First, the sharp decline in the price of UK emission allowances over the past year (down 60% to ~€40 per tonne) may have increased the breakeven threshold for further decarbonisation investments. As outlined at the beginning of this article the decline in prices reflects concerns that the government is less committed to net zero policies, at least meeting near-term targets. Second, most of the decline in emissions seen over the past four years was due to the closure of older, often more carbon intensive production. Those opportunities won’t exist this time. Instead, much more challenging routes to decarbonisation will have to be pursued.

Electrify everything

The electrification of offshore operations is the biggest single opportunity to decarbonise the North Sea. Combustion of hydrocarbons (natural gas and diesel) for offshore power generation offshore accounted for 79% (8.4 Mt CO2) of offshore emissions in 2022. Other sources of offshore emissions include flaring (16% of emissions), venting (4%), and other non-combustion processes (2%).

Electrification is a vitally important contributor to the achievement of the NSTD 2030 target, according to the latest modelling by the North Sea Transition Authority (NSTA). The authority’s central scenario is that electrification begins in 2028, although the quicker this can be rolled out the larger the potential emission reductions will be. For example, the central case estimates total cumulative abatement between 2030 and 2050 at 15 Mt CO2e.

There are significant engineering challenges involved with the electrification of the North Sea’s offshore oil and gas installations. For example, integrating offshore platforms with the onshore electricity grid will require the laying of power cables, the construction of transformers, and establishing a network for the central distribution of power to as many platforms as possible. An alternative approach, although relying on intermittent energy, is to link up with nearby offshore wind platforms.

A report published in 2022 by the energy consultancy Xodus estimates that 10-20 facilities with relatively high-power demands need to be fully electrified by 2030 to achieve a 1.5-2 Mt CO2 annual reduction in emissions. Overall capex required is estimated to be in the range of £3.5-5 billion depending on the level of electrification, the number of assets electrified, and size of offshore wind installations.

There’s a big question mark as to whether the existing UK carbon market provides the necessary incentives. First, as discussed earlier, the recent sharp decline in the carbon price will have dampened the incentive to invest. Secondly, although it’s not clear how high the carbon price needs to be to incentivise electrification, the inherent volatility in the market and the lack of a suitable hedging mechanism beyond the next couple of years harms the North Sea electrification investment case.

Bridging the investment gap

One option that the government could employ to bridge this gap is Carbon Contracts for Difference (CCfD). They work by setting an effective guaranteed price for carbon, perhaps set at a level that covers the incremental capital and operating cost of the electrification technology. For example, in the summer of 2023 the German government launched a CCfD scheme aimed at helping their heavy emitting industries bridge the decarbonisation investment gap. Under the German CCfD scheme those companies that can decarbonise at the lowest cost will be awarded a 15-year CCfD and gain access to government funding.

Note that there are multiple ways that a CCfD could be set up, including for example linking the guaranteed CCfD price level to the prevailing UK ETS carbon price. If the UKA price falls below the price set out in the CCfD the government would have to pay the difference, indirectly providing an incentive for the government to keep the price of carbon high. In the absence of a high carbon price the government will have to secure the necessary funding, something that is likely to be politically challenging, at least currently.

High carbon prices have played an important role in the recent decline in North Sea oil and gas emissions. For example, by helping make the economic case for closing some of the older, more carbon intensive fields. The UK oil and gas industry is well known for its innovative approaches, working in one of the most challenging environments on the planet. Nevertheless, the next stage in the North Sea’s energy transition could be much more turbulent. Unless there are strong carbon price signals, backed up by a supportive financial environment, then the technological investments required to achieve the 2030 targets are unlikely to stack up.

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