A draft plan to reduce oil and gas upstream GHG emissions: what’s new in UK North Sea Net Zero?

How do you regulate the greenhouse gas (GHG) emissions associated with upstream oil and gas activity? Which of those emissions should you target? In this post, we look at a consultation that touches on these questions, published by the UK’s upstream regulator, the Oil and Gas Authority (OGA) on 5 October 2023, and reflect on some issues it raises.

Background: the OGA, its Strategy and Net Zero

First, a quick recap (keen observers of UK upstream regulation may wish to skip to the next section).

The OGA (which now tends to style itself as the North Sea Transition Authority, or NSTA) was formally established by the Energy Act 2016. As we reported at the time (see here, here, here, here, and here), it has been, from the outset, a regulator with a particular mission:

• to determine what the statutory objective of “maximising the economic recovery of UK petroleum” (MER UK) means, and to articulate, in a strategy with which they must comply, how those it regulates (“relevant persons” – very broadly, licence holders and operators, and infrastructure owners) must collaborate to achieve it;

• to use the tools provided in the Petroleum Act 1998 (as amended and supplemented by later legislation and the provisions of licences granted under it) to ensure that that objective is achieved, at a basin-wide level – which is, of course, not necessarily the same as enabling each asset to maximise its individual output or revenues.

It was clear from the outset that the OGA would prefer to pursue its goals by influencing and collaborating with the industry rather than using the more coercive elements of its toolkit.

In 2020, the OGA consulted on a revised version of its Strategy, in which its Central Obligation of MER UK acquired a second limb of “tak[ing] appropriate steps to assist the Secretary of State in meeting the net zero target, including by reducing as far as reasonable in the circumstances greenhouse gas emissions from sources such as flaring and venting and power generation, and supporting carbon capture and storage projects” (the Net Zero limb).

The Net Zero limb is not simply an add-on to the original MER UK concept.

• At the same time, the Strategy’s definition of “economically recoverable” was subtly amended to make it clear that the “capital and operating costs” to be taken into account in determining economic recoverability include “carbon costs”.

• In the words of the OGA’s subsequent Field Development Plan guidance, assessing “economically recoverable” resources “requires the inclusion of societal carbon costs which are accounted for through the use of central government GHG emissions values (carbon appraisal values) applied to all production-related GHG emissions”.

• These are a monetary value that “[placed] on 1 tonne of carbon dioxide equivalent [emissions]…based on the estimated marginal abatement costs consistent with the UK’s national and international climate commitments, including net zero and a series of interim carbon budgets”.

We explored the basis for and implications of this change in a series of articles at the time (see here, here, here, here and here). The new Strategy came into force in February 2021 and in January 2022 a legal challenge to its adoption was dismissed by the High Court. More recently, we looked again at one key element of the Net Zero limb – “platform electrification” – in the context of the INTOG offshore wind seabed leasing round and the Energy Profits Levy.

2021 also saw the North Sea Transition Deal (NSTD) struck: a non-legally binding declaration of intent by the industry and government which included, among the industry commitments, “an absolute reduction in production [i.e. upstream platform GHG] emissions of 10% in 2025, 25% in 2027, and 50% in 2030 on the pathway to net-zero by 2050”. Another significant development in that year was the OGA’s publication of its expectations as to how relevant persons should implement the Net Zero limb at each stage in the life of an upstream asset.

The UK government and the OGA have consistently taken the view that, in terms of the GHG emissions associated with activity in the UK Continental Shelf (UKCS), their focus should be on the emissions that arise either directly from upstream processes (e.g. flaring and venting) or from the production (often by gas- or diesel-fired gensets) of energy required to power upstream platforms (in other words, a focus on Scope 1 and 2, rather than Scope 3 emissions in GHG Protocol terms).

The emissions from end-use of products derived from UKCS petroleum are not the UK upstream authorities’ concern.

• If they are used in the UK, they may be subject to carbon pricing under the UK Emissions Trading Scheme (UK ETS) or the climate change levy (CCL), or other fiscal and policy measures that may serve to focus the consumer’s mind on its GHG emissions.

• If they are used elsewhere, it is for other states’ authorities to decide what action to take, as GHG emissions are assessed on the basis of where they are emitted, not where the economic demand that gave rise to their production arose (at least until carbon border levies apply under the EU’s Carbon Border Adjustment Mechanism).

• The argument that increasing the supply of fossil fuels stimulates demand for them, and therefore GHG emissions, and that this should be taken into account when, for example, granting new upstream licences, has so far been rejected by the UK government and courts.

More positively, the NSTA has sought to differentiate gas produced in the UKCS from LNG imported into the UK from elsewhere in terms of its lifecycle carbon footprint (here and here), claiming that it is up to four times “cleaner”, by this measure, than imported LNG.

However, upstream emissions remain a concern. They account for some 3% of total UK GHG emissions. Almost 80% of platform emissions in 2022 came from power generation, the rest being mostly from flaring and venting. (Note that although “platform electrification” is often used as a blanket term in this context, the technological changes that the OGA wants to see are often about producing the electricity that is used to power platforms by low(er) carbon means, rather than using electricity as a substitute for other forms of energy.)

Progress has been made in some areas. However, the NSTA’s latest production projections suggest that, even as the UKCS’s output of gas (in particular) is set to fall quite sharply over the remainder of the 2020s, the proportion of gas extracted that is consumed in the production process will increase by more than 50%. That feels as if it would be potential failure on all three limbs of the energy trilemma (security of supply, affordability and sustainability).

What is in the draft plan?

Following on from the Net Zero limb, paragraphs 18 and 19 of the Strategy provide that the OGA “may produce or adopt a plan or plans which set out its view of how any of the obligations in this Strategy may be met” and that “[w]here any relevant person intends to carry out activities in a manner which is inconsistent with any [such plan] that person must first demonstrate to the satisfaction of the OGA how their alternative meets the obligations of this Strategy”. As the OGA points out, although “non-compliance with a plan is not of itself directly sanctionable, it can evidence that the Strategy is not being complied with”, and failure to act in compliance with the Strategy is sanctionable.

The draft plan sets out “principles” rather than “targets” for emissions reductions. It is only interested in actual reductions, not “offsetting” of emissions.

Investment and efficiency: Relevant persons are expected “to make investments to reduce GHG emissions across their oil and gas extraction operations”.

• For each asset, relevant persons are to produce an Emissions Reduction Action Plan (ERAP) setting out the “applicability of available emissions abatement and emissions monitoring opportunities and technologies”, as well as “planned emissions reduction initiatives, including for logistics emissions”. The ERAP should be accompanied by a Supply Chain Action Plan (SCAP).

• Based on the ERAP, relevant persons are to “select, plan and execute…initiatives…aimed at reducing the [asset’s] emissions intensity…over a reasonable timescale”. These reductions are to be “substantially consistent”. Any proposal to recover new resources is to be accompanied by a commitment to deliver an appropriate emissions reduction opportunity from the ERAP, “including, where possible, through participation in regional electrification projects”. Further detail on reporting requirements in relation to ERAPs is promised.

Platform electrification and low carbon power: All infrastructure is to be “designed considering low carbon power options”. More specifically:

• “New developments with a first oil or gas date after 1 January 2030 must be fully electrified”, or, in the case of tie-backs, tied back only to fully electrified hosts. Those with an earlier first oil or gas date should “at a minimum come electrification ready”.

• “Financial investments must be made to electrify all assets where it is reasonable to do so”, weighing “the total remaining value of reserves and resources (risked) that will or may be developed through that asset and the expected emissions reductions from electrification against the expected cost of electrification”.

• ERAPs are to set out “comprehensive technical economic assessment[s] of…full and partial electrification options”. If the NSTA thinks that electrification is appropriate and relevant persons do not, they “should have no expectation that the NSTA will approve FDPs or FDPAs, or issue any further consents on that asset”.

Inventory: This part of the draft plan takes us back to the collectivist essence of MER UK.

• It begins with the observation that “closing some low producing installations could allow more and cleaner new production to come online while still reducing overall UKCS level emissions”.

• It goes on to point out that “locking in” cessation of production (CoP) “supports orderly phasing out of installations, and minimising emissions through efficient management of the transition from late life asset, through to CoP, into decommissioning or repurposing”.

• For assets with a GHG emissions intensity that is 50% over the basin average, relevant persons must set their appropriate company CoP dates using societal carbon values.

• If an asset is within six years of its fixed company CoP date, relevant persons should not generally expect the NSTA to grant a production consent beyond that date.

• Declaring and provisioning for a company CoP date must be accompanied by early and fit-for-purpose decommissioning planning. In each case, “early CoP, company CoP and late CoP” dates must be declared to the NSTA.

Flaring and venting: The starting point is the World Bank zero routine flaring by 2030 initiative, referenced in the NSTD. This requires that operators “provide a documented method of the split of projected flaring and venting figures” into categories: A (routine), B (non-routine) and C (emergency).

• From June 2024, relevant persons must provide such a documented method with their flare and vent consent applications, and plan (and budget) for, and secure, continuous improvements in flaring and venting GHG emissions reductions at the basin level.

• Assets consented to on a zero routine flare and vent basis must operate as such. All new developments (including tie-backs to existing hosts) must be carried out on this basis, and all assets must deliver zero routine flaring and venting by 2030.

So what’s new?

The draft plan is a logical development of previous OGA policy statements.

It could be argued that it breaks relatively little new ground in substantive terms. For example:

• Although it makes some more unequivocal statements in certain areas, these tend to be either about procedural rather than substantive requirements, or (where they are substantive) to be couched in terms that appear to leave some room for argument.

• In most of the areas that it covers, it concludes by indicating either that further details will be forthcoming on particular points, or an openness to further discussion about individual assets.
On the other hand:

• It puts down what appear to be some fairly firm markers, particularly in terms of dates by which things must be done (or, after which, they should not continue to be done).

• Electrification is a case in point. The draft plan certainly builds on existing OGA publications such as its industry letter of 5 April 2023, as well as on the practical work done by the OGA itself and the Net Zero Technology Centre (NZTC) to explore a range of possible options, but those planning assets that would come onstream after 2029 are on notice: they must electrify.

•From the outset, the OGA was explicit that MER UK might mean keeping things open for the sake of others. Now it makes clear that it may also sometimes be about closing for the sake of others.

•In its characteristic way, the OGA alludes to the potential that its regulatory arsenal gives it to compel relevant persons in the direction of desired policy outcomes, while also giving the strong impression that it would very much prefer to achieve a satisfactory result more consensually.

At the end of the day, the Net Zero limb is only part of the Central Obligation. With the best of intentions, there will be tensions around, for example, electrification and MER UK. The Environmental Statement submitted in support of the recent FDP consent for Rosebank provides a case study.

Section 2.7 of the Environmental Statement shows the licence holders having given a great deal of thought to a range of electrification solutions, only to conclude that none is certainly deliverable by the proposed date of first production in 2026, and to opt instead for conventional generation and being “electrification ready” (a choice that evidently helped shape the selection of FPSO design).

If the OGA is to stick to its policy that any asset starting production after 2029 must be fully electrified, one or more of the following outcomes seem likely:

• licence holders will do their best to accelerate development of assets that can be brought onstream before 1 January 2030, and thus only have to be electrification ready;

• some assets that are not amenable to this timetable may not be developed;

• significant progress will need to have been made in relation to the expansion of UKCS offshore (or onshore Scottish islands) windpower capacity in areas near upstream assets and/or the development of commercial and regulatory models that facilitate offtake from other such capacity;

• significant progress will need to have been made in respect of other technologies that could provide or support electrification (low carbon hydrogen, ammonia or methanol – already identified by NZTC as a promising option (see also here) – or batteries, for example) to the point where the current barriers to their deployment (in terms of cost, or modifications to or development of other equipment or infrastructure) no longer hinder their deployment.

The bigger picture

The OGA’s comments about assets with perhaps relatively low productivity but (for related reasons) high levels of production emissions stepping aside to make way for those with higher productivity and lower associated emissions is obviously of potential relevance beyond the UKCS.

However, in the absence of any global upstream regulator endowed with an NSTA-like remit, and because assets that require a lot of (or only a little) energy to extract are not evenly spread around the world’s hydrocarbon basins, it is clear that there are likely to be formidable geopolitical obstacles in the way of this becoming an organising principle for the industry globally.

Then again, things may change, at least in Europe, with the adoption of the EU’s Carbon Border Adjustment Mechanism (CBAM) and its application in due course (possibly around 2030?) to crude oil and refined products. In broad terms, CBAM will impose a cost on those importing certain emissions-intensive goods into the customs territory of the EU (or its member states’ offshore installations) based on the emissions associated with their production (including electricity used to power that production). That cost will be, roughly, what would have been the carbon price per tonne of GHG emissions payable in respect of an equivalently “dirty” production process under the EU Emissions Trading System (ETS) had the goods been made in the EU, less any carbon price in fact paid for producing the goods in the exporting country. Oil and refinery products are not in the first wave of goods subject to CBAM, but they are on the “carbon leakage list” of potential future CBAM targets.

This opens up the possibility that, notwithstanding “global oil prices”, and leaving aside the effect of any broader ESG-inspired corporate targets, lower-emissions oil and oil products could be materially cheaper, at least for EU importers, than those of higher-emissions upstream assets or refineries.

Which bring us back to the UKCS. At one point in the draft plan consultation document, the OGA refers to the importance of the industry recognising “that the full societal costs of GHG emissions are markedly larger than those that they incur directly through market-based carbon prices”. The UK ETS, and the EU ETS on which it (and CBAM) are based, are such “market-based carbon prices”. However, they are prices to which the fossil-fuelled generating equipment on upstream oil platforms are not exposed. For the moment, they benefit, like other installations on the “carbon leakage list”, from “free allocations” of emissions trading allowances and so (unlike gas platforms) do not pay a carbon price.

As CBAM begins to bite, and extends across the range of products on the carbon leakage list, oil platforms will cease to benefit from free allocations. For UKCS oil producers, that means one of two things:

• moving in step with the EU ETS, the UK ETS will withdraw free allocations from those installations that currently benefit from them – causing oil platforms to pay the UK ETS carbon price;

• to the extent that the UK ETS does not follow the pattern of the EU ETS/CBAM in this respect, unless UK ETS prices are above the level of EU ETS prices, the output of UKCS oil platforms will be at a competitive disadvantage against lower-emissions producers when imported into the EU.

This may provide a further, compelling economic reason to comply with the OGA’s draft plan.

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