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This is the fourth in a series of posts on the low carbon hydrogen policy documents published by the UK Department of Business, Energy and Industrial Strategy (BEIS) on 17 August 2021, and the second of two posts on the forms of financial support proposed by BEIS for low carbon hydrogen projects. The three previous posts can be found here, here and here.

Mitigating volume risk in the hydrogen business model

In the previous post, we explained how BEIS’s proposed “business model” (i.e. revenue support scheme) for low carbon hydrogen would mitigate the price risk facing producers. It may not feel like it to readers of the Hydrogen Business Model (BM) Consultation, but dealing with price risk is the easy bit of the business model. The real existential difficulty faced by early low carbon hydrogen projects is volume risk: what happens not when you cannot get a high enough price for the hydrogen you have produced, but when you cannot find a buyer at all? While there are things that can be done to mitigate volume risk outside the hydrogen business model (like facilitating the blending of hydrogen in the grid), these options may not be available to the first projects.

So, what are BEIS’s options for mitigating volume risk within the business model?

• Payments based purely on availability to produce would cost money without necessarily resulting in decarbonisation. They are no good for methane reformation technologies (which cannot ramp up quickly). Like capacity mechanisms in the electricity sector, they could turn out to be a drug on which the market gets hooked (with some insight, BEIS doubts its ability to refuse to NOAK projects what it would have conceded to FOAK projects in this regard).

• Government could purchase part of the producer’s output at a price that allows it to cover fixed costs, maintenance, debt servicing and a “minimum economic return” (MER) on equity.  Government would be able to “take or pay” (or sell, store, flare or vent the hydrogen). This is highly interventionist, may distort the market and is less suitable for intermittent projects.

• Government could act as a buyer of last resort for volumes with no end user buyer. Rather than purchasing a set volume in each period, it would step in on a contingent basis and purchase the first volumes that cannot otherwise be sold. In any given period, this might be nothing, a bit, or a lot (subject to a cap). The price would have to be attractive enough to cover the MER, but unattractive enough to discourage reliance. The “backstop Power Purchase Agreement” for renewable electricity generators with CfDs who are unable to find commercial offtakers (included in the CfD as a confidence-building measure) is a partial model here. This approach would weaken incentives for producers to seek market demand; may undermine market formation; and would be hard for HMG to budget for.

• A government obligation to purchase could be triggered when the hydrogen offtake volume falls below the level at which the producer cannot cover MER. It would thus apply to lower volumes than the previous option, but with higher levels of support per unit. The producer would be obliged to sell the “government share” first: if it cannot achieve the guaranteed price, the government would make up the difference. If it achieves a higher price than the guaranteed price, it would pay the difference to the government. This shares some of the problems of the previous option.

• Finally, there is the sliding scale. This would allow the producer to earn higher unit prices where offtake volumes are low, with support declining per unit as they rise. It would incentivise the producer to find offtakers because it would not be paid for not producing. It would avoid the risks and complexity of government buying “in the market”. More negatively, it delivers no support if volumes fall to zero; it is likely to become a permanent feature of the market; and it would be necessary to avoid perverse incentives around plant sizing.

The sliding scale is BEIS’s current preference. It would be delivered through the mechanism of a variable premium set by the relationship between a reference price and strike price, outlined in the previous post, but the BM Consultation does not say exactly how the sliding scale would be overlaid on this.

Other aspects of the hydrogen business model contract

Important as price and volume risk are, other things matter in a support contract too.

The BM Consultation lists a number of factors relevant to fixing the duration of support contracts and notes the precedent of 15 years for renewables CfDs, but offers no firm proposal.

It raises the pertinent question of “volume scaling”. If a plant increases its capacity, should it get business model support for the increase in capacity? The options are “yes” (potentially expensive and poor VfM); “no” (could limit market development); and “up to a pre-agreed maximum at a reduced level”.

BEIS indicates a robust line on construction overrun risks, technology/decommissioning costs; and input fuel supply disruption (all would be for the producer to manage), but it is looking at ways to help producers manage specification risk where the failure to meet specification is not their fault.

Contract allocation

BEIS’s discussions on how to address price and volume risk are at pains to be even-handed, pointing out where one option or another may not work well for a certain type of project. That does not mean that all kinds of hydrogen project will have an equal chance of obtaining business model support.

The renewables CfD regime has allocated funding largely through strike price-based auctions since 2015, but it was first road-tested with a less transparent allocation process that awarded eight (fairly generous) early CfDs in 2014. For the hydrogen business model, BEIS sees auctions as the way forward in the medium term (including different “pots” for certain kinds of project, as with renewables CfDs) but, in the first instance, it envisages that contracts will be awarded through negotiations. For projects embedded in CCUS clusters, this would be part of the ongoing CCUS cluster competitions; a similar process for non-CCUS enabled projects will be announced in due course.

In either case, the key words in the BM Consultation are: “We expect to set out specific eligibility criteria each time we open an opportunity to allocate BM support”. In other words, there will be further hoops for projects to jump through. These may not detract from the technological neutrality of the business model, but they may well be designed to focus early support on those projects that appear, for example, to be least exposed to volume risk.

NZHF and projects outside the hydrogen business model

We have not said much so far about the Net Zero Hydrogen Fund (NZHF) Consultation. Compared with the BM Consultation, it describes a rather simpler policy at shorter length and in less detail. The key points are as follows.

• Although the hydrogen business model and Renewable Transport Fuel Obligation (RTFO) will provide revenue support for low carbon hydrogen projects, BEIS still sees a role for upfront capital cost support to reduce the quantum of costs and risks for such projects. There is a clear concern that projects will need a “bridge” between the innovation funding that may have supported their earliest stages and commercial financeability.

• The NZHF aims to stimulate new low carbon hydrogen production, demonstrate commercial use of the technologies and build a pipeline of projects towards the 5GW 2030 target.

• It will be based on capital grants. Equity participation and capital guarantees are ruled out as unduly complex; government loans “may not go far enough in removing risks and barriers”.

• Funding will, in principle, be available both to projects that do and to those that do not require revenue support (e.g. via the hydrogen business model) – although the expectation, or hope, would be that capital co-funding for projects should reduce the revenue support they require.

• Projects supported outside the hydrogen business model are likely to be “smaller, often electrolytic” projects supplying transport sector end users and benefiting both from the relatively high cost of the counterfactual fuel (diesel) and RTFO revenue support.

• The focus would be on capex co-funding (“offering a percentage of the initial project cost estimate, including contingency”) and on supporting development expenditure at the feasibility, pre-FEED, FEED, and post-FEED/pre-FID stages.

• Projects would be expected to “demonstrate [their] socio-economic and industrial benefits”. They must be UK-based, with core technology at Technology Readiness Level 7 or higher.

• If applying for capex funding, they must “prove they have an agreement in principle with an offtaker for some or all of their production volumes”. For devex funding, there is a vaguer requirement to “demonstrate demand for the hydrogen”.

• Private sector financial backing must be demonstrated, and an ability to take FID by 2025. RTFO approval must be obtained where RTFO funding is relied upon.

• A series of periodic competitions for funds is scheduled to start in early 2022.

Where will the money (and the legal powers) come from?

On the question of how payments to producers under business model contracts will be funded, the BM Consultation offers two thoughts. “A Call for Evidence on energy consumer funding, affordability and fairness is expected to be published soon.” “Further details of the revenue mechanism [to fund the business model] will be provided later this year.” The recent increase in domestic energy bills as a result of a rise in gas prices has come at an awkward time for new energy funding schemes, given the UK’s historic reliance on consumer levies to fund new low carbon projects (a trend of which the latest representative is the draft Green Gas Support Scheme legislation for biomethane). Watch this space.

Clearly, any levy or other funding mechanism for the hydrogen business model similar to those that have underpinned renewable electricity subsidies would require legislation. More generally, it is hard to imagine how the whole scheme of the business model would or could be implemented without new legislation, probably including primary legislation, to support it.

The same is not true of the NZHF. It is assumed that government already has the money for this, and that it can be disbursed contractually, relying on existing industry-funding powers.

However, both the NZHF and hydrogen business model will need to comply with applicable subsidy control rules (although the NZHF Consultation highlights this issue more than the BM Consultation). At present, the UK regime is in transition from being governed by EU state aid rules (which, however, still apply in respect of Northern Ireland) to a new domestic regime that is still being legislated for.

The BM Consultation notes that BEIS is keen to explore the possibilities of projects “revenue stacking”, with different elements of public financial support. The concept of “revenue stacking” has been central to the development of many new electricity generation and storage projects in recent years. However, where the layers in the stack may be classified as subsidies (which has not been the case with, for example, revenues from grid ancillary services), care needs to be taken to avoid “overcompensation” and therefore breach of the subsidy rules.

What next?

With heads of terms for the business model due to be published, alongside a response to the BM Consultation, in Q1 2022, and the first contracts to be signed in 2023, BEIS has no time to lose in putting flesh on the bones of the business model as outlined here. And, as noted above, the launch of the NZHF is scheduled for early 2022, indicating rapid movement on that front too.

In the meantime, the background will not stand still. In particular, although the BM Consultation carefully tries to examine the various options for designing the business model in isolation from other policy developments, the Hydrogen Strategy promises an announcement on the UK’s “aspirations to continue to lead the world on carbon pricing” in the run-up to COP26 in November.

Even though it does not see carbon pricing as sufficient in itself to stimulate low carbon hydrogen projects, there are plenty of things that the government could do to help mitigate both price and volume risk by extending the reach or increasing the level of UK carbon pricing. For example, it could tweak the climate change levy and its many exemptions, or mirror the EU’s proposed extension of GHG emissions trading to new sectors (heat and transport) or its proposed adoption of a border carbon adjustment – all steps which could have benefits (and costs) beyond the hydrogen sector.

These are exciting (albeit, in the short term, rather uncertain) times for UK hydrogen projects. Those hoping to benefit from the support proposed in the BM Consultation and NZHF Consultation have until 25 October 2021 to respond to BEIS with their views. If you would like to discuss how the proposals may affect your project or how to put your case most effectively to BEIS, please get in touch.

After more than a decade of various attempts, the Nigerian oil and gas industry (the Industry) will finally have a new look following the enactment of the Petroleum Industry Act 2021 (PIA).

For many years, the Federal Government of Nigeria (FGN) sought to overhaul the Industry by introducing a new legal, regulatory and fiscal regime. The first major attempt was in 2008 when the first Petroleum Industry Bill (PIB) was introduced. Since 2008, there have been other unsuccessful attempts at reforming the Industry through reworked drafts of the PIB in 2012 and 2018.

In 2020, the FGN reintroduced the PIB 2020 to the National Assembly and, after months of deliberations, both arms of the National Assembly passed the PIB 2020 in July 2021 and the President signed the PIB 2020 (now the PIA) into law in August 2021. Based on the gazetted copy of the PIA, the PIA regime commenced on 16 August 2021.

The PIA comprises five chapters that cover the following issues:

a. Chapter 1 – Governance and Institutions: Deals with the creation of efficient and effective institutions and entities with clear and separate roles for the Industry, such as the Nigerian Upstream Petroleum Regulatory Commission (Commission) for upstream matters, the Nigerian Midstream and Downstream Petroleum Regulatory Authority (Authority) to regulate midstream and downstream operations and the Nigerian National Petroleum Company Limited – a limited liability company and commercial entity to succeed the current Nigerian National Petroleum Corporation. Chapter 1 also sets out the powers of the Minister of Petroleum Resources (Minister), which are significantly reduced vis-à-vis the regulatory framework pursuant to the Petroleum Act that confers significant powers on the office of the Minister.

b. Chapter 2 – Administration: Focuses on transparent and efficient administration/management of the upstream, midstream and downstream sectors of the Industry. While the Commission will regulate the upstream sector, the midstream and downstream sectors are within the regulatory ambit of the Authority.

c. Chapter 3 – Host Community Development: Deals with the provision of social and economic benefits to host communities. The aim is to support the development of host communities.

d. Chapter 4 – Petroleum Industry Fiscal Framework: Aimed at encouraging investment in the Industry, balancing rewards with risks and enhancing revenues to the FGN. Chapter 4 of the PIA completely overhauls the existing fiscal regime.

e. Chapter 5 – Miscellaneous Provisions: Contains provisions such as those dealing with legal proceedings, amendments, repeals, savings, transfer of assets and liabilities, transfer of employees condition of service, and interpretations.

It is indeed a new chapter for the Industry and Dentons ACAS-Law will walk through this new dawn with its clients and potential investors seeking to take advantage of the new-look Industry. Please look out for our subsequent publications where we will be providing more detailed analyses of the PIA and its impact on the Industry.

Introduction

One of the key changes introduced to the Nigerian petroleum industry (the “Industry”) by the Petroleum Industry Act, 2021 (the “PIA” or “Act”) is the complete overhaul of the administration of marginal fields. Importantly, the PIA has categorized existing marginal fields under 2 transitional structures based on whether the marginal field is a producing field or a non-producing field. The new framework introduced by the PIA raises pertinent issues that require clarity. In this edition of our Newsletter, we discuss the new transitional framework and its impact on existing farm-out arrangements.

Transitional Framework for Marginal Fields under the PIA

The PIA seeks to create a more direct relationship between the marginal field holder (“Farmee”) and the Nigerian government (“Government”) by the mandatory conversion of the marginal field¹ to either a petroleum prospecting license (“PPL”) or a petroleum mining lease (“PML”), depending on whether the marginal field is producing or not. The PIA also provides that no new marginal fields will be declared under the Act² and that existing marginal fields will be transitioned under 2 main categories namely: (a) producing marginal fields; and (b) non-producing marginal fields – which have been further classified into non-producing marginal fields declared before 1 January 2021 which have been transferred to the Government, and non–producing marginal fields which have not been transferred to the Government by the holder of an oil mining lease (“OML”) within 3 years of the effective date of the PIA³ (“Effective Date”). 

A. Producing Marginal Fields

Under this category, a holder of a producing marginal field is permitted to continue operations based on the original royalty rates and terms of the existing farm-out agreements (“FOA”) entered with the farmor of the marginal field (“Farmor”) but is mandatorily required to convert to a PML⁴ (“Conversion”) within 18 months of the Effective Date (“Conversion Period”) to benefit from the new fiscal regime⁵.

A Farmee may, therefore, elect to convert to a PML at any time within the Conversion Period. However, in the absence of such election to convert during the Conversion Period, the marginal field will automatically be converted to a PML upon the expiration of the Conversion Period. Interestingly, the early Conversion to a PML is likely to be driven by the more favourable economics introduced under the new fiscal regime, as the reduced headline tax rates from 85%⁶ to around 47.5%⁷. 

Essentially, a producing marginal field that is converted to a PML appears to have been given special status as it stands to benefit from a lower hydrocarbon tax rate (i.e.,15%) compared to the 30% applicable to OMLs converted to PMLs. Nevertheless, while the tax changes seem clear, the applicable royalty rates require further scrutiny as the PIA allows producing marginal fields to retain the existing royalty rates.⁸

Furthermore, it is pertinent to note that the PIA has not provided a clear direction in relation to the cut-off period for which the terms of the FOA will cease to apply upon Conversion to a PML. It, therefore, seems that the operations of marginal fields under this category (i.e., marginal fields converted to PMLs) may be governed by a dual regime under the existing terms of the FOA and the provisions of the PML Model Lease⁹ embodying the relevant terms and conditions pursuant to the PIA¹⁰. Should this be the case, it will give rise to several regulatory and commercial issues and would beg the question of how any conflict between the terms of the FOA and the PIA will be resolved and, where applicable, to what extent the PIA provisions will supersede the commercial arrangements of the parties which had been agreed prior to the enactment of the Act.

B. Non-Producing Marginal Fields

i. Non-Producing Marginal Fields declared before 1 January 2021

The PIA provides that non-producing marginal fields declared as such prior to 1 January 2021 shall be converted to a PPL and shall benefit from the fiscal terms for new acreage under the Act. Effectively, the recent 2020 Marginal Filed Bid Round (“MFBR”) awardees will fall under this category and the Nigerian Upstream Petroleum Regulatory Commission (the “Commission“) has the authority to issue a PPL to such awardees (“PPL Awardees”)¹¹.

Amongst other constitutional documentation requirements, the Guidelines for Farm Out and Operations of Marginal Fields – 2020 (“Guidelines”) and the award letter¹², require an awardee to execute a FOA with the Farmor. While this has been the usual practice, the validity or relevance of the FOA to marginal fields under this category (i.e., non-producing marginal fields declared before 1 January 2021) has generated ongoing conversations among stakeholders. At this stage, it is important to examine the implication of the provisions of the PIA in relation to FOAs executed pursuant to the Guidelines and the award letter, particularly in relation to obligations that have been captured under the PIA.

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In August 2021, the UK government published its Hydrogen Strategy and a number of consultations on policies to encourage the development of a UK low carbon hydrogen sector (see posts (1) to (4) in this series here). In a sector where countries are competing keenly to be among the first to capitalise significantly on the coming low carbon hydrogen revolution, momentum is crucial, and April 2022 saw the publication of a further batch of UK hydrogen policy documents, including the government’s responses to the earlier consultations. This is the first in a series of posts on the April 2022 documents. We start with the Hydrogen Investor Roadmap, because it gives a convenient overview.

The roadmap summarises policies designed to attract investment into the UK low carbon hydrogen economy. It contains important information about the timings for the launch of public funding rounds and other steps the government is taking to boost the investment case for UK hydrogen projects.

UK investment case

The government makes the case to investors for being one of the world’s most attractive business environments for hydrogen. They reference, amongst other things, the 130% capital allowances super-deduction on plant and machinery equipment, generous R&D and patent tax reliefs, lower labour costs and business-friendly employment laws.

Hydrogen investment case

The government also highlights the opportunities in an advanced and growing sector. These include:

• revenue support: projects may apply for revenue support through the Hydrogen Business Model, which will focus initially on electrolytic and CCUS-enabled hydrogen production;
• allocation rounds: there is a commitment to allocate support to projects in 2023 and 2024, with an annual allocation round;
• regulatory environment: a UK Low Carbon Hydrogen Standard is being developed to provide a yardstick for public funding of projects and to help build market confidence;
• existing assets: the UK has salt caverns and depleted oil and gas fields that are suitable for hydrogen storage as well as existing (and in some cases currently redundant) gas pipeline infrastructure that can be redeployed to transport hydrogen;
• expertise: the UK’s deep resources of both renewables and oil and gas sector expertise mean that there is no shortage of the skills or creative thinking needed to make projects happen – the UK is consistently in the top ten countries globally for hydrogen technology patent rates;
• pipeline of projects: over a dozen large-scale low carbon hydrogen projects are ongoing or under development, as well as two or three times as many smaller-scale ones. As the illustration below makes clear, these cover a range of technologies and applications.

The government tells the market how they are providing certainty to the market through:

• supporting a variety of production methods, as well as research and innovation in hydrogen infrastructure;
• stimulating demand through grants to potential end users of hydrogen, delivering pilot trials and completing innovation work;
• enabling infrastructure for the hydrogen value chain through hydrogen production projects supported by the Net Zero H2 Fund and the ongoing replacement of iron gas distribution networks with plastic;
• stimulating investment by consulting on fund design, delivering CAPEX grant funding and targeted Development Expenditure (DEVEX) support to stimulate the project pipeline;
• establishing a supportive regulatory framework through developing a greenhouse gas emissions threshold for “low carbon” hydrogen and working to implement changes to the existing non-economic regulatory framework to support hydrogen.

The paper also highlights the government’s 2035 Delivery Plan for critical activities and milestones for developing the UK hydrogen economy, as summarised in the picture below:

There is always more that can be done to support this new industry (as the recent report by RenewableUK, for example, points out). However, the UK is making a strong case to attract investors in a UK low carbon hydrogen economy, and this should provide a springboard for hydrogen projects in the UK. We have advised on low carbon hydrogen projects both in the UK and internationally and are ready to help you seize opportunities, assess risks and comply with the latest legal requirements in this exciting, but challenging, new sector.

In August 2021, the UK government published its Hydrogen Strategy and a number of consultations on policies to encourage the development of a UK low carbon hydrogen sector (see posts (1) to (4) in this series here). In a sector where countries are competing keenly to be among the first to capitalise significantly on the coming low carbon hydrogen revolution, momentum is crucial, and April 2022 saw the publication of a further batch of hydrogen policy documents, including the government’s responses to the earlier consultations.

This is the second in a series of posts on the April 2022 documents (see here for the others): it focuses on the outcome of the consultation on a Low Carbon Hydrogen Business Model (Consultation), in which the Department for Business, Energy & Industrial Strategy (BEIS) sets out its proposed policy and current thinking in light of the Consultation responses, and is accompanied by indicative heads of terms for the Business Model. As outlined in two of our earlier blog posts (see here and here), the Business Model is intended to provide financial support to the low carbon hydrogen sector by incentivising production and the use of low carbon hydrogen by overcoming the cost gap between low carbon hydrogen and cheaper higher carbon alternative fuels.

Scope of support

The Business Model will support newly constructed hydrogen facilities built for the specific purpose of producing hydrogen that can meet the requirements of the UK Low Carbon Hydrogen Standard which is being developed. Existing producers of hydrogen looking to retrofit CCUS technology so as to produce “blue” rather than “grey” hydrogen will not be eligible for support through the Business Model (but may be eligible to apply for support through BEIS’s separate Industrial Carbon Capture Business Model).  Projects that produce hydrogen as a by-product will also not be eligible.

BEIS has not yet determined whether to enable blending of up to 20% hydrogen (by volume) into the GB gas grid and is targeting a policy decision in 2023. BEIS currently views blending as a transitional option only and not a required step for the use of hydrogen in heating. BEIS is keen to ensure that the supply of pure hydrogen is prioritised for those end users who require it to decarbonise.

While projects that export hydrogen will be eligible, the specific volumes exported will not be eligible for support payments.

Support mechanism

The Consultation highlights two main risks for the production of low carbon hydrogen:

• price risk – the price the producer receives from the sale of hydrogen may not cover production costs and returns on equity (especially where the market price for competitive fuels such as natural gas is lower); and

• volume risk – the producer cannot sell enough hydrogen to cover costs with reasonable confidence.

BEIS is proposing to provide support to overcome these risks under a Low Carbon Hydrogen Agreement (LCHA). The LCHA will have many features of the existing Contract for Difference (CfD) that supports low carbon electricity generators and will be designed to provide a revenue stabilisation mechanism and ultimately encourage hydrogen production.

Price risk

As under the existing electricity CfD, the LCHA will provide for payments to be made representing the difference between a reference price for the producer’s output and an agreed strike price for that output. 

Reference price

Under the electricity CfD, the reference price is the wholesale market price for electricity established by reference to indices. In the absence of indices recording an observable market price for hydrogen (the hydrogen market is as yet not developed enough for this), BEIS’s proposal is that the LCHA will use the actual sales price for hydrogen achieved by the producer (the Achieved Sales Price).

Recognising, however, that using the Achieved Sales Price as reference price does not encourage the producer to achieve a higher selling price, and might distort other energy markets, BEIS is also proposing that the reference price will be floored at the price of natural gas. To the extent there is a shortfall of the Achieved Sales Price beneath the gas price, it will not be topped up by the LCHA.

As a further incentive for producers to seek higher priced sales and to aid price discovery, a contractual mechanism will be included that allows the producer to share in the benefit of sales values above the natural gas price floor. Options being discussed include an amount linked to the increment by which the reference price exceeds the natural gas price floor for each unit of hydrogen sold and a constraint on sale prices above a certain level. The contractual mechanism may result in the subsidy actually received being greater than the difference between the reference price and the strike price.

Strike price

BEIS states that the strike price will reflect the cost of low carbon hydrogen production as well as an allowed return on investment for the relevant project on a project-by-project basis (although BEIS is still considering this position). The level of cost components and the strike price are likely to vary for different low carbon hydrogen technology types. The intention is to move to a competitive allocation process (e.g. an auction) in the medium term. The UK government’s recent Energy Security Strategy sets out the ambition to move to price competitive allocation by 2025. BEIS is minded to include different allocation rounds/pots for future competitive allocation.

BEIS is considering the constitution of the strike price but has indicated the following non-exhaustive list:

• capex and opex associated with the construction and operation of the facility (excluding any capex funded by grant funding (for example, under the Net Zero Hydrogen Fund);

• capex, but not opex, associated with small-scale hydrogen transport infrastructure. The exclusion of opex is designed to encourage efficiencies in transportation infrastructure;

• capex and/or opex associated with a small-scale hydrogen storage infrastructure. Opex is to be taken into account as it is a key requirement in safely maintaining storage facilities; and

• an allowed return on investment.

BEIS is considering the indexation of the strike price to protect: (i) producers against unmanageable and uncontrollable changes to input costs; (ii) government from oversubsidy and (iii) end users with security of supply. BEIS has yet to determine the preferred indexation option.

Calculation of difference payments

As with the electricity CfD, payments are two-way: if the reference price exceeds the strike price, payments of the difference between the reference price and the strike price will flow from the hydrogen producer to the LCHA counterparty. However, in this scenario, the reference price floor will be the lower of the gas price and the strike price. That ensures that if the Achieved Sales Price is higher than the strike price and lower than the gas price, the producer will only pay the difference between the Achieved Sales Price and the strike price.

Under the electricity CfD, difference payments are made per MWh of electricity output. Under the LCHA, the multiplier will be sold units of hydrogen. But in what units can the strike price, the gas price floor and the Achieved Sales Price Payments be expressed on a like-for-like basis?  BEIS states that payments will be calculated on a £ per MWh higher heating value (HHV) basis. HHV has been chosen because the gas price is reported in HHV in the UK, and it reflects the full energy potential of the relevant fuel.

Volume risk

To mitigate volume risk, BEIS is minded to provide volume support to the producer through a sliding scale mechanism. The producer earns higher unit prices where offtake volumes decrease to help recover fixed and marginal costs. The support will decrease as the offtake volumes that the producer secures increase (with the last volumes only recovering the equity returns and marginal costs).

Volume support will only be available if sales are made. If actual sales fall to zero, there is no volume support to be provided. This was flagged as a major concern during the consultation process (especially where a project has a sole offtaker that falls away) but BEIS indicated that value for money was important for the Business Model.

As for the treatment of higher than expected volumes, BEIS states that any increase in the volume of hydrogen produced relative to that agreed in the hydrogen support contract between the producer and the contract counterparty will not be subsidised. However, no detail is given as to whether the producer, if it sells the additional volume, can retain the additional revenue from such sale. Timing the calculation of any volume support (such that it is only calculated once production levels for a certain period are known) may go some way to reduce any overcompensation risk.

Other considerations

BEIS intends to allow projects where the producer and consumer of hydrogen are the same entity (or closely affiliated) to be eligible. However, BEIS is currently considering options to accommodate this arrangement where there may be little or no commercial incentive for the producer to increase the price that the producer receives from the sale of its hydrogen and facilitate price discovery.

The use of intermediaries in the supply chain and reporting requirements is being considered (especially where the intermediaries take ownership of the hydrogen) to ensure that subsidised hydrogen is sold to qualifying end users and to avoid oversubsidisation if intermediaries are used.

BEIS also intends to allow hydrogen producers to receive subsidies for sales to feedstock users but notes the potential for overcompensation and causing potential market distortions and so is considering if additional measures are required (e.g. relying on the price discovery mechanism to incentivise sales at a higher price to feedstock users or using an alternative reference price).

Funding

The Low Carbon Hydrogen Agreement will initially be funded by the taxpayer, but BEIS is expecting to transition to a levy funding taking place no later than 2025, subject to legislation being in place.  Meanwhile, the government has announced an initial £100 million will be provided as part of the Industrial Decarbonisation and Hydrogen Revenue Support (IDHRS) scheme. This is also to cover the ICC business model. Further, up to £100 million of funding was announced as part of the Net Zero Strategy to award contracts of up to 250MW of electrolytic hydrogen production capacity in 2023.

In August 2021, the UK government published its Hydrogen Strategy and a number of consultations on policies to encourage the development of a UK low carbon hydrogen sector (see posts (1) to (4) in this series here). In a sector where countries are competing keenly to be among the first to capitalise significantly on the coming low carbon hydrogen revolution, momentum is crucial, and April 2022 saw the publication of a further batch of hydrogen policy documents, including the government’s responses to the earlier consultations. This is the third in a series of posts on the April 2022 documents (for other posts on these documents, see here).

One of the great unresolved questions of hydrogen policy concerns its potential role in space heating (either as a substitute for methane or blended in the gas grid). In this post, we look at the UK government’s response to its August 2021 consultation on a “grid conversion” hydrogen heating trial.

Trial and trial again

The possibility of replacing natural gas with hydrogen in the gas grid is still at the nascent stage of research, development and testing, as information needed to assess its feasibility, cost and benefits is gathered. As part of this, the UK government has spent £25 million on the Hy4Heat programme which looked into the innovation work on the potential of domestic hydrogen use, and plans a neighbourhood trial by 2023, a village scale trial by 2025 and a potential hydrogen-heated town before the end of the decade. The outcomes of all this research will feed into the decisions which will be made in 2026 on the role of hydrogen for heat decarbonisation and whether to proceed with a hydrogen-heated town. The focus on heat in particular stems from the Department for Business, Energy and Industrial Strategy’s (BEIS) analysis for the UK’s Heat and Buildings Strategy (2021). Heating in buildings currently accounts for around 23% of national carbon emissions, with the vast majority of this fuelled by natural gas.

The possibility of replacing natural gas in the grid is far-reaching – it will affect the existing gas networks down to the appliances in people’s homes which will need to be able to take hydrogen instead of natural gas. This will all need to be offered to the consumer at an attractive rate. There will also need to be infrastructure in place for people who do not want to participate in the trial, raising the question of how the natural gas and hydrogen networks will be separated. The recent Goldman Sachs “Carbonomics” report on hydrogen published in February 2022 estimates that, while hydrogen boilers have high greenhouse gas abatement potential (in comparison to other hydrogen abatement technologies) at circa 46 Gt CO₂eq, the cost is also comparatively high at circa 650 US$/tnCO₂eq. Further technology advancements will be needed in order to drive this price down.

Despite the challenges, the hope is that the trials will deliver essential evidence on the feasibility, costs, convenience and consumer acceptability of transporting 100% hydrogen safely and securely in the grid and using it in buildings for day-to-day activities. The illustration below, from the UK government’s Hydrogen Investor Roadmap (April 2022) shows how the heat strand fits into wider UK policy on low carbon hydrogen.

Hydrogen-ho

The August 2021 consultation sought views on the proposal that legislation is needed to enable the gas networks to successfully deliver a grid conversion trial, building on the “neighbourhood trial” due to take place in Levenmouth, Fife in 2023. The consultation also asked stakeholders whether additional consumer protections are required and how these should be implemented.

To convert from natural gas to hydrogen for a trial, the Gas Distribution Network company (GDN) and its delivery partners will need to carry out works within homes and businesses. There are currently limited grounds on which GDNs have the right to enter private property, and it is expected that GDNs will always aim to reach agreement with occupiers before entering premises unless it is an emergency (as they do currently with homes heated with natural gas). Nevertheless:

• to make premises suitable for heating with hydrogen, it is possible that GDNs will need to carry out some additional alterations which are not needed for natural gas; and
• for any consumers who do not wish to participate in the trial, it will be necessary to move their connection away from natural gas supplies safely.

In the context of consumer protection, consumers in a grid conversion trial area will no longer have the option of using natural gas during the period of the trial. Those consumers will need to either switch to hydrogen supplied through the gas distribution network or to an alternative heating solution offered by the GDN. In these circumstances, additional rights and protections may be required to ensure that consumers have a clear choice and are treated fairly.

Having completed the consultation, the government now intends to proceed with:

• the proposed legislative amendments required to facilitate hydrogen heating grid conversion trials; and
• measures to strengthen consumer protection for those in the trial area.

Primary legislation (to apply only for the purposes of a hydrogen grid conversion trial) is proposed in order to:

• extend the GDNs’ existing powers of entry – anticipated to only ever be used as a last resort to ensure consumer safety;
• make regulations requiring the GDNs to follow specific processes to engage and inform consumers in an appropriate way about the trial; and
• make secondary legislation for the purposes of ensuring that consumers are protected before, during and after the trial – so that, as well as continuing to enjoy the same protections that they have as natural gas consumers (e.g. the ability to switch supplier), they will not be “financially disadvantaged as a result of the…trial…including with respect to the installation and maintenance of either hydrogen heating or an alternative solution”.

The village trial may deliver critical real-world evidence on the practicalities of converting the gas grid and individual properties to hydrogen and using hydrogen for heating and cooking.

Rolling out the blue/green carpet

Of course, the idea of a hydrogen trial is not completely novel and there are some existing projects which have already helped to pave the way.

HyDeploy, run by Cadent and Northern Gas Networks, was the first project in the UK to blend hydrogen into a natural gas network. This was a project with 100 homes and 30 university buildings on a private gas network at Keele University. Up to 20% hydrogen was blended into natural gas networks for a period of 18 months which ended in spring 2021. This blending allowed the customers to keep their existing appliances. Backed by Ofgem’s Network Innovation Competition, the £7 million project was led by Cadent in partnership with Northern Gas Networks and Keele University.

SGN’s H100 Fife project is for a green hydrogen-to-homes heating network on the Fife coast. Taking electricity generated by wind turbines for the production of green hydrogen, this project will then operate through a newly built gas network to 300 opted-in homes. Customers’ appliances will need to be replaced with hydrogen-ready ones, and the project is due to have a four-and-a-half-year duration.

To blend or not to blend

The possibility of hydrogen in the gas network raises a rich range of legal and structural issues. Customer choice, keeping down costs and providing gas blends as requested by customers are all questions to consider, first at the smaller trial scale and then at the national scale. There is also the issue of blending hydrogen into the gas network, to then deblend at the exit point at the different hydrogen-to-natural-gas content that individual customers may require. HyDeploy claims that if hydrogen were blended with natural gas across the UK at a similar level to its project (up to 20%), it could save around 6 million tonnes of carbon dioxide emissions every year – the equivalent of taking 2.5 million cars off the road.

Dentons’ UK Energy team was among the first to highlight some of the commercial and regulatory aspects of a gas grid functioning on a mixture of gases in two earlier articles (here and here). We have advised on low carbon hydrogen projects both in the UK and internationally. If you would like help with evaluating potential opportunities and risks in this exciting, but challenging, new sector, please get in touch.

On 6 July, the UK government introduced an Energy Bill into Parliament. Also known as the Energy Security Bill (see the government press release and related webpage), it is packed with provisions on an unprecedentedly wide variety of subjects. Some of these have featured in consultations or statements of legislative intent over a number of years; some may come as more of a surprise to many readers; some appear as the subject of legislation here for the first time.

Given the intense policy, political and public interest in the energy sector at present, it is not surprising that the first multi-topic piece of primary legislation on the energy sector since 2016 is more than 300 pages long. The Bill’s 243 clauses and 19 Schedules include measures that will significantly affect almost all aspects of energy sector activity, including upstream oil and gas, electricity networks, nuclear power, carbon capture and storage, heat networks, hydrogen, energy efficiency, fuel sector resilience and energy system governance. Moreover, in a sense the Bill does more than its length alone might suggest, as it contains substantial powers to make new, often sector-shaping regulations.

This is, of course, only the starting point: no doubt much of the Bill will be subject to vigorous debate, and at least some amendment, in Parliament over the coming months. In future posts, we will report on its progress and look in more detail at some of its provisions; here we present a brief and broad overview of the Bill as a whole, summarising at a high level the contents of each of its 13 Parts.

CO₂ transport and storage

Part 1 sets up a new system of licensing for, and economic regulation of, the transport and storage of carbon dioxide (CCUS T&S). The provisions draw on precedents in the Electricity Act 1989 (EA89) and Gas Act 1986 (GA86), but the new licences will be granted under the new Act, rather than under amended provisions of EA89 or GA86.

• Readers of the earlier Acts will be familiar with the structure of the provisions, even if some of the content is less familiar. For example, like the EA89 and GA86, Part 1 begins by setting out the “principal objectives and general duties” of the Secretary of State and Ofgem, which are to act as their guiding lights as they carry out their functions under the new legislation. Ofgem is referred to in Part 1 as the “economic regulator” of CCUS T&S. (Elsewhere in the Bill it appears as GEMA, an acronym of its official title, the Gas and Electricity Markets Authority.)
• Similarly, there are rules about licensing of CCUS T&S operators (initially by the Secretary of State, and later by the economic regulator), including the usual provision for exemptions, modifications, appeals about modifications, provision of information to the economic regulator and the Secretary of State, enforcement of regulatory provisions, competition, reporting obligations and inter-regulator cooperation. There is also provision for a special administration regime to deal with licence holder insolvency situations, and a transfer scheme mechanism to deal with situations where a termination event arises in relation to a CCUS T&S licence.

The principles of the new regime have been discussed in previous government consultations (see, for example, here). The economic regulator’s work is not to be confused with the regulation of the physical aspects of offshore CCUS by the Oil and Gas Authority (OGA, now rebranded as the North Sea Transition Authority, but still known in legislation by its original name), which the OGA will retain.

Supporting CCUS and low-carbon hydrogen production

Part 2 is mostly concerned with revenue support contracts for carbon capture, CCUS T&S and low-carbon hydrogen production. It envisages structures that will be recognisable to those familiar with the GB renewables Contracts for Difference (CfD) regime.

• It makes provision for a “revenue support counterparty” to be “designated” in relation to each of these three sectors. The counterparties would have functions similar to those of the Low Carbon Contracts Company under the CfD regime.
• There is also a broad power for Ministers to grant financial assistance (which could include capital grants) for CCUS or low-carbon hydrogen production / transportation / storage.
• There will also be a “hydrogen levy administrator” and “allocation bodies”, which would be responsible for allocating the revenue support contracts (a function perhaps similar to that of National Grid ESO as delivery body in the CfD context).
• As with the Energy Act 2013 provisions that laid the foundations for CfDs, a large proportion of the provisions about revenue support contracts is devoted to saying what details of the new regimes can be spelt out in secondary legislation (answer: most of them).
• Part 2 also deals with the decommissioning of CO₂ storage installations, through a combination of further powers to make regulations about the arrangements for financing decommissioning and some amendments to existing legislation such as the Petroleum Act 1998 and (on change of use relief) the Energy Act 2008.
• There is provision for Ministers to designate a Strategy and Policy Statement (SPS) about strategic priorities in CCUS policy, to which Ofgem, as economic regulator, must have regard (mirroring the energy SPS provided for in the 2013 Act, but which has yet to be designated).
• Other provisions amend existing legislation, or enable the making of new regulations, relating to CO₂ storage licences and access to CCUS infrastructure. Ministers are also given power to spend taxpayers’ money on supporting CCUS and hydrogen production facilities.  

The Bill here puts in place a legislative framework for a number of policies on CCUS and hydrogen that have been consulted on in recent years (see, for example, here, here and here).

“New technology”

Part 3 covers a number of different areas.

• Building on a consultation in 2021 about “a market-based mechanism for low-carbon heat”, it enables Ministers to set up schemes to encourage the supply or installation of low-carbon heating equipment (such as heat pumps) by setting targets for “scheme participants” in terms of, for example, the energy efficiency or carbon intensity of the equipment they supply.
• It fills some legislative gaps identified in relation to the proposed “hydrogen for heat” trials in a domestic context as regards powers of entry, safety and consumer protection.
• Consistent with other recent policy announcements, it exempts nuclear fusion facilities from the requirement to apply for a nuclear site licence – a liberalising move that recognises the radical differences in safety implications of nuclear reactor (fission) technology and fusion.
• It amends the Climate Change Act 2008 to enable a range of technologies, possibly including direct air carbon capture and storage (i.e. not just those relating to land use, land-use change or forestry) to count as removals of greenhouse gases from the atmosphere for the purposes of calculating UK greenhouse gas emissions under the 2008 Act. (See, in this connection, the 5 July 2022 consultation on a business model for “engineered” removals.)

A new entity at the heart of the energy system

Part 4 is about the Independent System Operator and Planner (ISOP).

• This is the entity referred to in previous government consultation documents as the Future System Operator (FSO). It will take on a range of functions, beginning with those of the current electricity system operator, and longer-term gas network and market planning. It will hold new “electricity system operation” and “gas system planning” licences (issued, or treated as issued, under amended provisions of EA89 and GA86 respectively).
• Its role is likely to expand over time, but it will have a focus, from the outset, on certain strategic objectives (such as net zero) and a mandate to look across the whole energy value chain, not just at the parts of the energy sector regulated by EA89 and GA86.
• The establishment of the ISOP will involve both corporate (via a transfer scheme) and regulatory elements (granting of new licences and consequential modification of existing licences and industry code provisions).

Reforming industry governance

Part 5 reforms the governance arrangements for the voluminous industry codes that regulate so many aspects of the day-to-day running of the electricity and gas systems. As with the ISOP provisions, the principles underlying this Part were the subject of consultation in 2021.

• It establishes “code management” as a licensed activity under EA89 and GA86, and allows regulations to be made under which code managers for particular codes would be selected on a competitive basis.
• The overall aim is to make it easier to set strategic directions for the development of codes, with a view to ensuring that changes that are necessary to facilitate key policy priorities are pursued in a more streamlined and coordinated way. Ofgem, advised by the ISOP, would be required to publish an annual strategic direction statement to facilitate this.
• Ofgem would also be given more power to modify codes, more easily, on its own initiative (in a variety of circumstances) than it has previously had.

“Market reform and consumer protection”

Part 6 reforms existing regulatory provisions relating to a number of aspects of the energy sector.

• In the middle of the last decade, government and Ofgem published a series of documents about opening onshore electricity network provision up to competition. Although there was consultation on some draft legislation in 2016 and the notion of breaking down network monopolies received some support from Dieter Helm’s 2017 Cost of Energy Review, the proposals did not make it into legislation at that time. However, in the meantime, the notion that, for example, storage technology can sometimes provide a more effective solution to network constraints than the construction of “more wires” has gained currency.
• Last year, a government consultation formally indicated that competition in onshore networks was back on the agenda. At the same time, BEIS and Ofgem have been reviewing the arrangements for offshore transmission in the light of the government’s plans for massive expansion of UK offshore wind generation (the Offshore Transmission Network Review, or OTNR process). They have been looking to a future where offshore generators connect, like those onshore, to a coordinated network, rather than each being served by a dedicated link (typically built by itself) to the onshore transmission network (see here, here and here).
• In this context, the Bill substantially amends the provisions of EA89 that currently provide for Ofgem to hold tenders for offshore transmission owner (OFTO) licences and to make “property schemes” for transferring transmission infrastructure that has been developed by offshore generation project developers to the winning OFTO.
• The amended EA89 provisions allow for tenders to take place in relation to the award of a “relevant contract” or the granting of a “relevant licence”. Relevant contracts are contracts entered into with a licensed transmission owner or system operator, or a distribution licence holder, to carry out a project that “relates to” the GB electricity network as a whole (or an interconnector or multi-purpose interconnector – on which, see below). A relevant licence could be a licence for transmission, generation, distribution or interconnection (regular or “multi-purpose”; see below). These tenders will be organised by one or more “delivery bodies” (designated by Ministers). Regulations made by Ministers will further specify what types of project can be tendered for; Ofgem (after approval by Ministers) would make regulations about the procedures to be followed.
• For more than 20 years (see, for example, here), concerns have been raised about transactions that result in the holders of two or more network gas or electricity network licences being in common ownership – primarily on the grounds that this could result in Ofgem having fewer comparators for price control and other regulatory purposes. The Bill amends the Enterprise Act 2002 to apply to such transactions rules similar to those that have long applied to mergers between water companies. The Competition and Markets Authority (CMA) will be obliged to refer for further investigation – and may ultimately block – a merger between two energy network licence holders of the same kind if (having consulted Ofgem) it believes that it may be expected to cause substantial prejudice to Ofgem’s ability to make comparisons between such energy companies for regulatory purposes.
• Multi-purpose interconnectors (MPIs) would combine the interconnection of GB’s and another country’s electricity systems with the export of power generated offshore. Consistent with a recent government response to consultation on MPIs and wider OTNR policy, the Bill provides for a new EA89 licensable activity of operating an MPI.
• At present, the domestic gas and electricity tariff cap regime will expire at the end of 2023. The Bill permits it to be extended to carry on as far as the end of 2025 if the Secretary of State determines, after considering a report from Ofgem in 2023, that conditions for effective competition for domestic supply contracts have yet to be achieved.
• Also due to expire in 2023 are certain powers of the Secretary of State in relation to EA89 licences relating to smart meters. These are to be extended to 2028.
• A small amendment to EA89 gives primary legislative backing to the assumption on which industry has been working for years now, that – within the statutory typology of electricity sector activities set out in EA89 – electricity storage counts as generation.
• A very long clause amends legislation relating to the energy company obligation (ECO) regime by making provision for a buy-out mechanism. This is one of the outcomes of a recent government consultation on the ECO regime.

Heat networks

Part 7 establishes a UK regulatory framework for heat networks (both single-building “communal” networks and multi-building “district” networks). The use of networks can make the heating of buildings more efficient and reduce the greenhouse gas emissions associated with it, but as a technology, it remains under-exploited in the UK. This Part of the Bill has its roots in a 2020 government consultation on heat networks and, before that, a 2017 CMA market study on the same subject. The CMA’s key conclusion (following industry and other feedback) was that subjecting heat networks to the kind of regulation that applies to the supply of gas and electricity should cause the industry to grow. (This insight has already prompted the passing of the Heat Networks (Scotland) Act 2021 – aspects of heat policy, unlike gas and electricity, being a devolved matter.)

• Ofgem is appointed as the Regulator for GB, and its counterpart NIAUR for Northern Ireland, but with the proviso that either body can be replaced in its role by secondary legislation.
• Schedule 15 to the Bill essentially provides a blueprint for economic regulation of the heat networks sector along the lines of how the electricity and downstream gas sectors are regulated under EA89 and GA86 respectively, but all done through secondary legislation.
• Regulations can provide for the Regulator’s objectives and duties and general organisation, and for defining what activities in relation to heat networks it will, after a prescribed “initial period”, only be lawful for those who hold a heat network authorisation (authorisation) to carry on.
• Authorisations will in many ways resemble EA89 or GA86 licences. They may contain conditions about a range of topics, including consumer protection (e.g. pricing, customer communications, service and technical standards) and limitations on greenhouse gas emissions associated with heat networks (in England and Northern Ireland).
• It is envisaged that industry codes will sit alongside the authorisations, just as they supplement the provisions of GA86 and EA89 licences. Schedule 15 follows Part 5 in introducing a governance framework for codes with licensed code managers and so on.
• There will also be “installation and maintenance licences”, whose holders will be entitled to exercise the rights specified in the licence for purposes relating to the installation or maintenance of relevant heat networks in England, Wales or Northern Ireland.
• These licences will be a vehicle for conferring the kinds of statutory rights that are enjoyed by many utility operators in relation to the physical aspects of their businesses, such as compulsory acquisition of rights over land.
• In relation to both authorisations and licences, there will be the usual mechanisms for revocation, modification of conditions, enforcing compliance with conditions (including by the making of consumer redress orders) and application of competition law by the Regulator.
• Provision is also made for regulations to empower the Regulator to conduct pricing investigations; to replace a heat network operator (with associated powers to make a transfer scheme in respect of property, rights and liabilities); and for a special administration regime. It is also envisaged that some areas, such as metering, will continue to be regulated simply by regulations, rather than through authorisations or licences.
• Separately, there is a series of provisions about areas designated as appropriate for heat networks (heat network zones) and the regulations that can be made about them.
• At a national level, there is to be a Heat Network Zones Authority (which may or may not be the Secretary of State). At a more local level, one or more local authorities will be able to appoint a “zone coordinator” for their area(s) (or part(s) of it / them). The Authority and zone coordinators will between them identify areas appropriate for the construction and operation of district heat networks, using a specified methodology.
• Once a heat network zone has been designated, regulations may require buildings of specified types in the zone to be connected to district heat networks or installed with communal heat networks within a specified timetable (with some provision for exemptions). Zone coordinators may be given powers to grant exclusive rights to design, construct, operate or maintain district heat networks within a given zone or part of a zone.
• The regulation-making powers in Part 7 are designed to enable heat networks to be required to meet specific technical and environmental performance criteria.

Energy smart appliances and load control

It has long been apparent that a combination of smart metering, other new technologies and market-wide half hourly settlement could enable electricity to be used in ways that are more efficient at a system level and more cost-effective for consumers. This – along with the associated cyber-security concerns – is the background to Part 8 of the Bill.

• A familiar example of a “smart” appliance is the home electric vehicle charging point that waits until wholesale electricity prices are cheapest (or somebody in the market will even pay it to consume) before drawing power from the grid to charge the vehicle. Another is the fridge that may accept an offer to turn off for a few minutes in order to facilitate grid operation.
• The Bill provides statutory definitions of “energy smart appliances” and the “load control” signals (whether from the appliance’s owner or a third party) to which they are designed to respond. It then enables Ministers to make regulations about energy smart appliances that are either EV charging points or are capable of being used for refrigeration, cleaning, battery storage, electrical heating, air conditioning or ventilation.
• The aim appears to be to use product-specific regulations about functionality, performance, protection of the electricity system and a range of technical standards to build confidence in these new technologies and enable them to contribute to outcomes that are positive from decarbonisation, security of supply and affordability points of view.
• Provision is also made to create, by secondary legislation, one or more new categories of activities licensable under EA89, comprising activities relating to load control. Ministers would have powers to make consequential modifications to existing licences if this is done.
• Alongside the Bill, the government has published a consultation on this area.

Energy efficiency of buildings

One of the themes of the British Energy Security Strategy published in April 2022 was the need for more action on energy efficiency, particularly in relation to buildings. In this context, Part 9 gives Ministers a power to make energy performance regulations.

• The regulations could enable or require assessment, certification or publicising of the energy usage or efficiency of premises; or improvements to their energy usage or efficiency.
• The regulations could also restrict or prohibit the marketing of premises whose energy usage or efficiency is not assessed, certified or publicised as required, and include provision for both civil penalties and the creation of criminal offences to enforce compliance with them.

“Core fuel sector resilience”

In 2021, the government published a draft Bill on Downstream Oil Resilience. The House of Commons Committee that gave it pre-legislative scrutiny expressed some reservations about the draft Bill in its report, and the government accepted at least some of these in its response.

Against this background, Part 10 makes provision about the supply of “core fuels” (i.e. crude oil based fuels and renewable transport fuels).

• Ministers are given functions that they must exercise with a view to ensuring that UK economic activity does not suffer as a result of disruptions in the core fuel supply chain and to reduce the risk of emergencies affecting fuel supplies.
• Ministers may, in various specified circumstances, issue directions, or make regulations that apply, to “core fuel sector participants” – that is, owners of core fuel infrastructure and those carrying on activities in relation to core fuels. The common thread between the distinct but linked powers conferred on Ministers is the objectives of maintaining or improving core fuel sector resilience and mitigating or counteracting actual / potential disruption to, or failure of continuity of, core fuel supply.
• The direction-making powers would apply in relation to infrastructure owners with a capacity of more than 20,000 tonnes, and those carrying on core fuel activities with a capacity in excess of 500,000 tonnes. The regulation-making powers, and a related power to require information, apply at much lower thresholds (with a threshold of 1,000 tonnes in each case). There are powers to adjust these thresholds by secondary legislation.
• Finally, Ministers are given a power to grant financial assistance to core fuel sector participants for the purpose of maintaining or improving core fuel sector resilience or securing or maintaining continuity of core fuel supply.

Oil and gas

Part 11 makes some changes to regulation of the oil and gas sector.

• There is a change to the standard conditions (“model clauses”) of UK upstream oil and gas licences. For many years, these have included a provision allowing the OGA (and, before it was created, Ministers) to revoke (or partially revoke) the licence on a change of control of the licence holder (or one of them). However, there was no requirement to seek consent to such a change in control: instead, the common practice was to seek a “comfort letter” from the OGA to the effect that it is “not minded” to exercise its power of revocation in response to a particular transaction (a process on which the OGA has issued guidance).
• That is all set to change, with the relevant licence conditions being amended to require licensees to seek OGA consent for any change in control “at least three months” before it is proposed to occur. Such consent, if given, may come with conditions attached (applicable to the licensee or the acquirer). These changes will apply to both new and existing licences. They are supported by an amendment to the Petroleum Act 1998 requiring licence holders to provide information required by the OGA in relation to potential changes in control. Revocation remains a potential sanction for failure to comply with conditions of consent to a change in control or to provide “full and accurate” information in response to such an OGA request – or, indeed, for carrying through a change of control without consent.
• This increases the OGA’s powers over the UK upstream industry. At the same time, the consent process offers a more certain result than an (effectively) non-binding comfort letter. It also means that the OGA now exercises much the same degree of control, in much the same way, over share-based upstream acquisitions as it has previously had in respect of asset-based upstream transactions (for which its consent was already required) where an interest in a licence, rather than shares in the interest-holding companies, is acquired.
• The other provisions in this Part all have an environmental flavour, relating as they do to emergency planning for dealing with oil pollution, reducing oil and gas activities’ impacts on protected habitats and new charges for government functions in relation to decommissioning (see here and here for the consultation relating to this last provision.)

Civil nuclear sector

Part 12 makes regulatory and administrative changes in relation to the civil nuclear sector.

Some pointers on implementation

Part 13 contains the “general” provisions commonly found at the end of Bills.

• As usual, there is a power for Ministers to reflect the impact of provisions in the Bill by amending other legislative provisions using regulations. The Bill itself makes a number of such “consequential” amendments, and others may be added to it (e.g. in Schedules 8 and 11), but more will follow in regulations. The consequential amendments power is widely drafted. It includes the ability to amend primary legislation passed before or in the same session as the Bill (subject to following the “affirmative” procedure, where regulations require Parliamentary approval before they are made) and retained direct EU legislation.
• Commencement: Much of the Bill will be commenced by regulations, but the Bill provides for most of the CCUS and hydrogen provisions and the onshore electricity network competition reforms (amongst others) to come into force automatically two months after the final stage in the passing of a Bill (Royal Assent). A few high-priority provisions (including those on network mergers and heat networks) are flagged to commence immediately on Royal Assent.
• Extent: The clause setting out which provisions extend to which parts of the UK is a little more complex than is often the case in energy legislation. Westminster does not typically legislate for energy matters in Northern Ireland, but there are a number of exceptions to that here (again, including much of the CCUS and hydrogen provision). Most of the rest of the Bill extends to England, Wales and Scotland, but with carve-outs for Scotland in relation to the provisions on heat network zones and energy performance of buildings.

Further information on the Bill, including topic-by-topic factsheets, is accessible from this webpage.

The 54 signatories to the Energy Charter Treaty (ECT) have reached agreement upon the principal terms of its modernisation.  In a communication on 24 June 2022 following the fifteenth round of negotiations (a process launched in 2017), the Energy Charter Conference approved a summary explanation of the main changes.  These changes seek to rebalance and modernise the ECT, and are widely considered necessary to secure the treaty’s ongoing relevance, making it more apt to support the global energy transition by allowing states greater policy and regulatory space to fulfil their commitments under the Paris Agreement and other international environmental instruments.  

The treaty text is in the process of editorial and legal review, and will be shared with the contracting parties by 22 August 2022, with a view to its adoption at the Energy Charter Conference session on 22 November 2022.  Unanimity is required to amend the ECT and this will be established by a so-called “silence procedure”, whereby if no party voices its objection before that November session, the text can be adopted.  The new treaty will then enter into force 90 days after it is ratified by 75% of the contracting parties.  As such, the timing of the modernised ECT actually replacing the existing version is uncertain, but could conceivably even take a number of years.   

Further precision regarding the changes – both their substance and how practically they are intended to take effect – will no doubt be available in the coming months but, in the meantime, the revisions (like the ECT itself) continue to attract an equal measure of support and criticism: from both critics who wish to maintain the scope of particular protections that are being reduced, and those who consider the changes do not go far enough to redress the balance between investors’ interests and environmental policy goals.

Background

The ECT was signed in 1994 and entered into force in 1998.  Its signatories include the EU and Euratom.  It created, in the aftermath of the cold war, a multilateral framework for cooperation in the energy sector, including provisions protecting foreign investments in the sector in the territories of signatory states, providing for investor-state dispute settlement (ISDS), and promoting energy security and efficiency. 

Since its inception, more than 150 ISDS cases have been brought under the treaty, with 117 of these being in the past 10 years.  Approximately 52% of those cases that have resulted in an award have been decided in the investor’s favour.  Notably, 60% of claims have been brought by investors in renewables and there have been 13 and 51 claims against Italy and Spain respectively, most regarding their roll-back of previous incentives for investments in renewables.  This has led Italy to withdraw from the ECT (although it continues to face claims based upon ongoing protection under the ECT’s 20-year sunset clause). 

However, the treaty has faced criticism due to claims being brought against states targeting measures aimed at promoting the energy transition (such as the Netherlands’ phasing out of coal power), and the fear of a chilling effect on states wishing to change their sectoral policy in furtherance of environmental commitments.  Indeed, notwithstanding that only 33% of claims were brought by fossil fuel investors, damages awarded in those cases have accounted for 97% of all damages awarded under the ECT.  The broad definition of “investor” also attracts negative commentary in that it enables claims to be brought by “mailbox” companies domiciled in signatory states, thus potentially extending ECT protections to parent companies and shareholders that are not ECT signatory state nationals.

The modernisation discussions were premised on three “pillars”: updating the list of energy materials and products covered (to include hydrogen, for example); creating a “flexibility” mechanism enabling states to exclude or limit protections for fossil fuels; and a more regular (five-yearly) review process enabling the parties to react to technological and political developments more rapidly going forward.      

An important aspect of the negotiations has been the position of the EU, which has been a leading advocate for reform, submitting two draft proposals for revised text.  Indeed, a large number of claims have been brought by EU-domiciled investors against EU member states, clearly demonstrating the conflict between the ECT’s ISDS provision and the Commission’s position that intra-EU investment arbitration agreements contravene EU law.  The Commission’s view was confirmed by the CJEU in its 2018 decision in Slovak Republic v. Achmea B.V. (Case C-284/16)) and, in September 2021, the CJEU held in Komstroy v. Moldova (Case C-741-19) that intra-EU investment arbitration proceedings under the ECT are similarly contrary to EU law.  We therefore do not foresee EU investors bringing future ECT claims against EU member states under the existing ECT (since the courts of member states may set aside or refuse to enforce the relevant award), save potentially under ICSID Rules, which give rise to an award that is automatically enforceable and cannot be set aside by domestic courts.  It is intended that the revised ECT will contain a provision specifying that the dispute settlement provisions will not apply to members of a Regional Economic Integration Organisation such as the EU, thus expressly ruling out intra-EU claims going forward.

Indeed, the Commission has considered withdrawal from the ECT altogether, but acknowledges this would trigger the sunset clause.  That could mean existing investments would continue to enjoy protection for 20 years, and it is not settled under international law whether sunset clauses can be mutually dis-applied by state parties to an investment treaty (for instance, by the EU and its member states).  The EU has therefore instead remained committed to the modernisation process. 

“Greening” the treaty: shift in energy products covered

The ECT applies to “Economic Activity in the Energy Sector”, which is defined by reference to a list of “Energy Materials and Products”.  A number of new such materials and products, largely renewables and other sources considered important to the energy transition, are to be expressly covered by the modernised ECT and its investment protection provisions (removing current uncertainty regarding some of these solutions).  These include:

• hydrogen (notably the agreement in principle does not distinguish between fossil-based and renewable hydrogen);
• anhydrous ammonia;
• biomass;
• biogas; and
• synthetic fuels.

We would therefore expect to continue to see a high proportion of ECT claims being brought by investors in renewable solutions.  One can see these arising based on states either removing or changing specific incentives (as in the cases against Spain and Italy which, given the various pressures on public finances, appears very possible) and possibly even on states failing to implement certain aspects of their Paris commitments in a timely way.  

At the same time, under the modernised treaty it will be possible for states to carve out fossil fuels from the investment protections altogether.  Indeed, a number of contracting parties (and observers) had called for the phasing out of fossil fuels from the scope of the treaty’s protections altogether.  This proved too controversial to attract the necessary support, and so instead the “flexibility” mechanism will allow states to adopt bespoke carve-outs.  For instance, the EU and UK have indicated they will carve out fossil-fuel-related investments from protection: (a) for new investments made after 15 August 2023, with limited exceptions; and (b) for existing investments, after 10 years from the entry into force of the relevant provisions in the new ECT which permit the carve-out.  The current ECT does not contain a definition of “fossil fuels” and the final text will need to include a formulation to clearly define specifically what may be carved out.  For instance, the EU’s proposal envisaged carving out protection for petroleum, gas and coal investments as well as power generated from those sources, with the exclusion of certain infrastructure investments powered by lower-emission natural gas (particularly where these replace coal).  

Further, practical questions regarding how the carve-outs will be drafted and effected, and when they will enter into force, remain to be addressed.  Subject to those points, one can envisage claims being brought by existing investors in fossil fuels perhaps earlier than planned, in an effort to avoid the effect of the carve-outs.  Those investors might also look to restructure their investments via ECT states that have not adopted any carve-out.  However, the prospects for successful structuring would appear to be limited by amendments restricting protections for “mailbox” companies discussed below, general investment treaty law principles prohibiting abusive “treaty shopping” and an envisaged special provision for the dismissal of claims submitted as a result of investment restructuring for the “sole purpose” of submitting a claim under the Treaty.

Focusing the investment protections

Agreement has also been reached in principle upon certain amendments and clarifications to the scope of the investment protections themselves.  Some of these are aimed at increasing legal certainty (by expressly setting out principles derived from case law).  Others seek to rectify perceived problems with these from the contracting parties’ perspective and redress the balance between investment protection and states’ ability to regulate.  The final text will warrant further review (and, no doubt, debate), but to highlight a few points of interest:

• Requirement for an investor to have “substantial business activities” in its home state: This is aimed at removing so-called “mailbox” companies from the ECT’s scope, thus ending effective protection for non-ECT state nationals who hold investments via such companies.  It remains to be seen what the timing will be for such a requirement to take effect.
• New definition of “fair and equitable treatment” (FET):  The ECT contains an FET provision, which is by far the most regularly invoked standard in ISDS.  International investment tribunals have found that FET encompasses multi-faceted protection covering a wide range of situations, sometimes creating uncertainty for states as to what actions are permissible.  The new FET provision will aim to clarify this, and avoid further expansion, through a list of specific measures that will be designated as violating the standard (although it appears the list will be indicative, not closed).  For instance, the new provision will contain a description of circumstances that give rise to legitimate expectations on investors’ part, and in what circumstances these may be considered by states in taking policy decisions. 
• New definition of “indirect expropriation”: Both the notions of “direct” and “indirect” expropriation will be clarified, with a new definition of “indirect expropriation” being introduced.  In investment treaty case law, this has been developed as covering cases where legal title to an investment is not taken away from the investor, but through a state measure or series of measures that substantially deprive the investor of its value, whereby it is unable in reality to benefit from its investment.  The new ECT definition will set out a list of factors to be considered when determining whether an indirect expropriation has occurred and will provide that, as a general rule, non-discriminatory measures adopted to protect legitimate policy objectives (including the environment) do not constitute indirect expropriation. 
• “Most constant protection and security”: It will be clarified that this standard relates (presumably exclusively) to the obligation for states to protect the physical security of investors and their investments, and not to provide other non-physical (or “legal”) protective measures, as certain investment arbitration tribunals have interpreted it.   

These and the other revisions to the investment protection provisions are likely to require greater focus by investors in formulating claims for their breach.  However, the more precise articulation of applicable standards in the ECT’s articles and the guidance this will provide to tribunals will likely lead to greater certainty of outcomes in ISDS (reducing the risk of wasted time and cost), which should be welcomed by states and investors alike.

Conclusion

The agreement in principle signals a rebalancing of focus from protecting the interests of investors in traditional energies (in furtherance of the ECT’s original aims) towards encouraging and protecting renewable energy investments, coupled with an increased freedom for states to regulate in order to reach their climate-related targets.  Though outside the scope of this post, changes to the dispute settlement provisions are further aligned with these goals, including increased transparency (to help combat the perception of secrecy around the treaty and its effects).  However, many questions remain as to the precise scope of the changes, how and when they will come into effect, and the number of contracting parties that will take advantage of the increased flexibility to depart from the treaty’s historical scope.  The efficiency with which these can be resolved will likely be determinative of the ECT’s ongoing pertinence in the years to come.    

Key points

• European Union requirements for certification of “green” hydrogen and other Power-to-X fuels continue to evolve.
• Most recently, the European Parliament has proposed a set of amendments to the criteria for renewable electricity used in hydrogen production which would:
  • remove the requirement for the renewable electricity to originate from a plant constructed within three years from the construction of the hydrogen plant; and
  • relax the timing and geographic linkage required between generation of renewable electricity and production of green hydrogen.
• The proposed amendments could facilitate rapid scaling-up of green hydrogen production and reduce production costs. However, they have proven contentious and we await to see whether they will be accepted and ratified by the European Council.

Background

Mandated emissions reduction targets and the need to replace natural gas from Russia in Europe’s energy mix continue to drive the European Union’s (EU) policies in relation to green hydrogen. Recent years have seen a rapid growth in the number of sectors in the EU subject to greenhouse gas emissions regulation^[1], which is driving demand for cleaner fuels such as green hydrogen.

For producers and consumers of green hydrogen (and other Power-to-X fuels) alike, regulatory certainty on the criteria for certification of the commodity as “green” is critical.

The EU’s requirements for production of “renewable fuels of non-biological origin” (RFNBOs), which include green hydrogen, are contained in the Renewable Energy Directive 2018/2001/EU (RED II). The RED II requirements have been subject to scrutiny and criticism in industry for defining a set of narrow parameters for accepting renewable electricity (RE) used to produce RFNBOs.

Procuring RE directly from source or from the grid

There are two options to source the RE required for an electrolyser to produce green hydrogen (or other RFNBO):

• directly, from a “captive” RE generation plant (located at the same site or connected directly by private wire); or
• from the electricity grid.

Electricity is taken from the grid where it is not possible to locate the electrolyser (or RFNBO installation close to the RE plant (e.g. a wind farm or solar PV plant)). However, as the grid can at any point in time contain a mix of renewable and non-renewable electricity, all of which is fungible in practical usage, this can make it difficult to identify whether the electricity consumed from the grid originated from an RE source.

Move to amend RED II

The scope of the RED II rules for production of RFNBOs was originally limited to use in the transport sector in the EU.

In the Fit for 55 package of measures introduced by the EU in July 2021 to achieve a 55% reduction in greenhouse gas (GHG) emissions by 2030, the European Commission (the Commission) extended the scope of RED II to apply more widely in industries such as cement, metals and chemicals, and set down minimum targets for use of RFNBOs in transport and in industry by 2030. The Commission also undertook to develop, through a subsequent Delegated Act, an EU-wide methodology to ensure that the electricity used to produce RFNBOs was of renewable origin (replacing the existing RED II rules).

Following the outbreak of war between Russia and Ukraine in February 2022 and the subsequent curtailment of natural gas flows from Russia to Europe, the Commission introduced the REPower EU Plan intended to end reliance on imported Russian fossil fuels, including through the production of 10 million tonnes per annum (tpa) of green hydrogen domestically (within the EU), with an additional 10 million tpa of imported green hydrogen. While this constituted a significant scaling-up in the Commission’s ambitions for the role of green hydrogen in the EU, it brought renewed focus on the limitations in RED II which could inhibit the realisation of the targets contained in the REPower EU Plan.

The European Commission’s Delegated Act

The Commission’s draft Delegated Act (published in May 2022) proposed the following requirements for RE used in production of an RFNBO:

1. Electricity from a direct connection with an RE source: the RE plant must not have come into operation earlier than 36 months prior to the RFNBO installation and is not connected to the electricity grid (to demonstrate additionality^[2]).
2. Electricity from the grid (with Power Purchase Agreement (PPA)): the RFNBO producer has concluded one or more PPAs with an RE generator(s) and each of the following criteria have been satisfied:
   • Additionality:
     • the RE plant must not have come into operation earlier than 36 months prior to the RFNBO installation;^[3] and
     • the RE plant has not received any state aid or subsidies (e.g. feed-in tariffs or CfDs);
   • Temporal correlation: the RFNBO must be produced within the same hour that the RE was generated (hourly matching); and
   • Geographic correlation: the RE plant must be located:
     • in the same “bidding zone”^[4] as the RFNBO installation; or
     • in a neighbouring bidding zone, provided the RE price is at least equal to the RE price in the bidding zone in which the RFNBO installation is situated; or
     • in an offshore location/bidding zone, adjacent to the bidding zone where the RFNBO installation is situated.

• Electricity from the grid (no PPA): electricity taken from the grid without a PPA with an RE generator can still be counted as fully renewable provided that the average amount of RE as a proportion of total electricity in the grid in the bidding zone in the previous calendar year was at least 90% (in reality, this will exclude most European electricity markets, for the time being)^[5].

Recognising the practical concerns about delays in building out new RE generation capacity in most European countries, the Commission proposed that the additionality requirements would be phased in from 2027 (i.e. older RE plants would be grandfathered for RFNBO production prior to 2027).

However, the Commission’s proposals did not go far enough to address industry’s concerns about the stringency of the RED II requirements.  

European Parliament’s Amendments to the Delegated Act

The European Parliament’s review of the draft Delegated Act resulted in an amendment, published on 14 September 2022 (the Amendment), proposing the following key changes:

• Additionality: the additionality requirement has been excluded in its entirety, meaning that the RE may be sourced from any RE installation (regardless of when it was constructed).
• Temporal correlation: the balancing period during which the production of the RFNBO is to be matched with RE production has been extended from hourly to quarterly.
• Geographic correlation: with regard to the location of the RFNBO installation, one of the following conditions must be satisfied:
  • the RE installation must be in the same country as the RFNBO installation or in a neighbouring country (without any reference to the “bidding zone” concept); or
  • the RE installation is located in an offshore bidding zone adjacent to the country where the RFNBO installation is situated.

The narrow margin with which the Amendment was passed through the European Parliament^[6] illustrates that finding an outcome which will balance the concerns of industry and the environmental lobby remains challenging. Whilst there is widespread support for increasing the production of RFNBOs to meet the GHG reduction targets set out in Recharge EU, it is increasingly challenging to achieve this while satisfying strict requirements on the sustainability of the energy consumed in their production.

The Amendment will go forward for further review by the European Council (the Council). If the Council approves the Amendment, it will be adopted into the Fit for 55 RED II amendments.

Importance

The ongoing flux in the RED II requirements is unhelpful to a nascent green hydrogen/Power-to-X industry in need of certainty around whether its fuel will be RED II compliant. This will impact project structuring and investment decisions.

However, if adopted, the Amendment would simplify the administrative burden for green hydrogen producers to certify their product and could also play a key role in reducing the marginal production costs because:

• the removal of the additionality requirement will significantly broaden the pool of eligible RE plants helping reduce power supply costs (the cost reductions will be greater where older plants, whose original PPAs have expired, are used); and
• the relaxation of the strict hourly matching requirements will help flatten the intermittency curve from the generation of RE, which will avoid electrolysers lying dormant during periods of low generation.

The RED II amendments would apply not just to RFNBOs produced and consumed within the EU, but also for RFNBOs produced outside the EU but exported into the EU and required to be recognised as “green”.

Therefore, project developers outside the EU, but who are targeting export to the EU market, or whose customers are supplying products to the EU (e.g. steel and cement) will need to ensure that their product is RED II compliant.

[1] Primarily the EU Emissions Trading System (ETS).

[2] The additionality principle requires the RE generation capacity supplying an electrolyser to be additional to the RE capacity that would have been built anyway under a business-as-usual scenario without the need to supply the electrolyser.

[3] Where additional production capacity is added to the initial RFNBO installation, it shall be considered to have come into being at the same time as the initial RFNBO installation, provided the capacity is added at the same site and came into being not later than 36 months after the initial installation.

[4] “Bidding zone” means the largest geographical area within which market participants are able to exchange energy without capacity allocation.

[5] RE taken from the grid may also be counted as fully renewable if consumed in an imbalance settlement period during which it can be proven that electricity from RE producers was curtailed or dispatched downwards.

[6] The Amendment was passed by a majority of 314 in favour and 310 against, with 20 abstentions.

Powering UK North Sea oil and gas platforms with renewable electricity from offshore wind turbines has long been an ambition of policymakers. Recently announced changes to the latest “windfall tax” on upstream operators could help to make this vision a reality.

Background

According to Offshore Energies UK, in 2018, the equivalent of 18.3 million tonnes of CO₂ were emitted from upstream oil and gas operations, representing 4% of the UK’s total emissions. Of these, 70% of emissions from offshore assets were associated with power or heat generation from gas-fired turbines, engines and heaters, with the remaining emissions from flares and vents^[1]. The North Sea Transition Deal of March 2021, an initiative between the UK Government and the UK’s oil and gas producers to help the industry reach net zero, set a target of reducing greenhouse gas emissions arising from upstream exploration and production activities on the UKCS and onshore processing, achieving 50% by 2030, against the 2018 baseline^[2].

Platform electrification is seen by the North Sea Transition Authority (NSTA) as key to meeting the North Sea Transition Deal targets. The NSTA also views cutting greenhouse gas emissions from oil and gas production as “critical to preserving the industry’s social licence to operate” whilst potentially extending the operating life of existing assets and generating cost efficiencies when developing new hydrocarbon projects.

The electrification of platforms is also a commercial opportunity for the renewables sector and, in particular, for those seeking to develop floating offshore wind – since many oil and gas platforms are in deeper waters unsuitable for fixed-bottom wind turbines. Indeed, as stated by the NSTA, offshore platform electrification “may unlock the faster growth of renewables, expansion of offshore transmission infrastructure and establishment of floating wind power technologies in the UK”. As well as reducing emissions, with, according to Wood Mackenzie, around 5% of offshore wellhead production globally used as fuel to power platforms^[3], platform electrification will allow gas usage to be optimised (key during an energy crisis) or, potentially, used elsewhere (for example, in the production of hydrogen).

The Scottish Government has specifically targeted the decarbonisation of offshore platforms through the Innovation & Targeted Oil & Gas leasing round (INTOG)^[4]. The deadline for INTOG bids was 18 November 2022 and the results are expected in February 2023, with a number of developers having announced their intention to participate. INTOG will allow developers to apply for licences to build offshore windfarms dedicated to providing electricity to oil and gas platforms in order to decarbonise the sector. Some developers will also look to oversize these projects so that they can sell excess power onshore, but INTOG rules limit the overall size of the project to five times the aggregate platform demand to balance this.

However, the goal of platform electrification will require significant investment. Xodus (a consultancy firm owned by Subsea 7) has reportedly estimated that it will require £3.5-5 billion in capital expenditure, depending on the number of assets to be electrified. According to Upstream Online, the other issue the industry could face is “bottlenecks in obtaining grid connections (with regards to connections to onshore transmission systems) and windfarm access if many players want access at the same time”.

Energy Profits Levy

The Energy Profits Levy (the Levy), originally a 25% temporary levy on ring-fenced profits of oil and gas companies which included a new 80% investment allowance, was introduced by the Energy (Oil and Gas) Profits Levy Act 2022 and was due to expire on 31 December 2025.

In imposing the Levy, the UK Government had stated its intention was to make oil and gas companies “pay their fair share” whilst they benefit from extraordinary oil and gas prices, and “to see the oil and gas sector reinvest its profits to support the economy, jobs and the UK’s energy security”.

The Levy was increased in November 2022 to 35% and will now apply until 31 March 2028. The investment allowance was also reduced to 29%, except for investment relating to expenditure on upstream decarbonisation (e.g. modifying existing installations to use power from offshore windfarms, installing bespoke wind turbines to power the installation or running electricity cables to the installation from shore)^[5]. At the same time, the Government announced an Electricity Generation Levy. This will be a new, temporary 45% levy on the extraordinary profits of electricity generators, being electricity sold above £75MWh^[6], replacing the Cost Plus Revenue Limit announced in October.

This additional tax is in addition to the Ring Fence Corporation Tax (30%) and the Supplementary Charge (10%) currently payable by oil and gas companies, bringing the headline rate of tax in the UK to 75%. According to the UK Government, this rate of tax is comparable with other North Sea tax regimes, including Norway.

Now, whilst the UK Government appears to be taking away from oil and gas companies with the one hand, it appears to be trying to give (or at least encourage investment) with the other, by maintaining the 80% investment allowance on expenditure relating to upstream decarbonisation. This will mean that an oil and gas company spending £100 on upstream decarbonisation projects, such as platform electrification, will be able to deduct £109.25 when calculating its levy profits^[7].

Summary

The UK Government states that the “changes to the Energy Profits Levy are not expected to have a significant macroeconomic impact on the level of business investment” as, while affected companies will pay more tax, they may also benefit from the investment allowance. However, there is a danger that the Levy will mean that oil and gas companies will have less capital to deploy in investing in new technologies, such as platform electrification, in the UK, making the UK less competitive.

[1] https://oeuk.org.uk/wp-content/uploads/2020/09/OGUK-Production-Emissions-Targets-Report-2020-1.pdf

[2] https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/972520/north-sea-transition-deal_A_FINAL.pdf

[3] https://www.woodmac.com/news/feature/why-power-oil-and-gas-platforms-with-renewables/

[4] https://www.crownestatescotland.com/resources/documents/intog-public-summary

[5] The changes related to decarbonisation expenditure will be legislated for in the Spring Finance Bill 2023.

[6] The levy relating to electricity generators will apply from 1 January 2023 and will be legislated for in in the next Finance Bill and apply until 2028. See further https://www.gov.uk/government/publications/electricity-generator-levy-technical-note.

[7] https://www.gov.uk/government/publications/autumn-statement-2022-energy-taxes-factsheet/energy-taxes-factsheet