Day: October 5, 2024

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